Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Summary of Significant Accounting Policies

Basis of Presentation

(a) Basis of Presentation

The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”).  In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2017 and 2018, and the results of its operations and its cash flows for the years ended December 31, 2016,  2017, and 2018.  The Company has no items of other comprehensive income or loss; therefore, its net income or loss is equal to its comprehensive income or loss.

As of the date these financial statements were filed with the SEC, the Company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified.

Principles of Consolidation

(b) Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Antero, its wholly-owned subsidiaries, any entities in which the Company owns a controlling interest, and variable interest entities (“VIEs”) for which the Company is the primary beneficiary.

For the years ended December 31, 2016, 2017 and 2018, we have determined that Antero Midstream is a VIE for which Antero is the primary beneficiary.  Therefore, Antero Midstream’s accounts are consolidated in the Company’s consolidated financial statements.  Antero is the primary beneficiary of Antero Midstream based on its power to direct the activities that most significantly impact Antero Midstream’s economic performance, and its obligation to absorb losses of, or right to receive benefits from, Antero Midstream that could be significant to Antero Midstream.  In reaching the determination that Antero is the primary beneficiary of Antero Midstream, the Company considered the following:

· Antero Midstream was formed to own, operate, and develop midstream energy assets to service Antero’s production and completion activities under long-term service contracts.

· Antero owned 52.8% of the outstanding limited partner interests in Antero Midstream at December 31, 2018.

· Antero’s officers and management group also act as management of Antero Midstream and AMGP under services and secondment agreements between the respective parties.

· Substantially all of Antero Midstream’s revenues are derived from services provided to Antero.

All significant intercompany accounts and transactions have been eliminated in the Company’s consolidated financial statements.  Noncontrolling interest in the Company’s consolidated financial statements represents the interests in Antero Midstream which are owned by the public and the incentive distribution rights in Antero Midstream.  Noncontrolling interests in consolidated subsidiaries is included as a component of equity in the Company’s consolidated balance sheets.

Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method.  Such investments are included in Investments in unconsolidated affiliates on the Company’s consolidated balance sheets.  Income from investees that are accounted for under the equity method is included in Equity in earnings of unconsolidated affiliates on the Company’s consolidated statements of operations and cash flows.

The Company accounts for distributions received from equity method investees under the “nature of the distribution” approach.  Under the nature of the distribution approach, distributions received from equity method investees are classified on the basis of the nature of the activity or activities of the investee that generated the distribution as either a return on investment (classified as cash inflows from operating activities) or a return of investment (classified as cash inflows from investing activities).

Use of Estimates

(c) Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions which affect revenues, expenses, assets, and liabilities, as well as the disclosure of contingent assets and liabilities.  Changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results could differ from those estimates.

The Company’s consolidated financial statements are based on a number of significant estimates including estimates of natural gas, NGLs, and oil reserve quantities, which are the basis for the calculation of depletion and impairment of oil and gas properties.  Reserve estimates, by their nature, are inherently imprecise.  Other items in the Company’s consolidated financial statements which involve the use of significant estimates include derivative assets and liabilities, accrued revenue, deferred income taxes, equity-based compensation, asset retirement obligations, depreciation, amortization, and commitments and contingencies.

Risks and Uncertainties

(d) Risks and Uncertainties

The markets for natural gas, NGLs, and oil have, and continue to, experience significant price fluctuations.  Price fluctuations can result from variations in weather, levels of production, availability of transportation capacity to other regions of the country, the level of imports to and exports from the United States, and various other factors.  Increases or decreases in the prices the Company receives for its production could have a significant impact on the Company’s future results of operations and reserve quantities.

Cash and Cash Equivalents

(e) Cash and Cash Equivalents

The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents.  The carrying value of cash and cash equivalents approximates fair value due to the short‑term nature of these instruments.  From time to time, the Company may be in the position of a “book overdraft” in which outstanding checks exceed cash and cash equivalents.  The Company classifies book overdrafts in accounts payable within its consolidated balance sheets, and classifies the change in accounts payable associated with book overdrafts as an operating activity within its consolidated statements of cash flows. As of December 31, 2018, the book overdraft included within accounts payable and revenue distributions payable was $10 million and $28 million, respectively.

Oil and Gas Properties

(f) Oil and Gas Properties

The Company accounts for its natural gas, NGLs, and oil exploration and development activities under the successful efforts method of accounting.  Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells, development wells, and undeveloped leases are capitalized.  Oil and gas lease acquisition costs are also capitalized.  Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred.  Exploratory drilling costs are initially capitalized, but charged to expense if and when the Company determines that the well does not contain reserves in commercially viable quantities.  The Company reviews exploration costs related to wells‑in‑progress at the end of each quarter and makes a determination, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense.  The Company incurred no such charges during the years ended December 31, 2016,  2017, and 2018.  The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units‑of‑production amortization rate.  A gain or loss is recognized for all other sales of producing properties.

Unproved properties are assessed for impairment on a property‑by‑property basis, and any impairment in value is charged to expense.  Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, and future plans to develop acreage.  Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property.  Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered.  Impairment of unproved properties for leases which have expired, or are expected to expire, was $163 million, $160 million, and $549 million for the years ended December 31, 2016,  2017, and 2018, respectively.

The Company evaluates the carrying amount of its proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable.  If the carrying amount exceeds the estimated undiscounted future cash flows, the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties.  Factors used to estimate fair value may include estimates of proved reserves, future commodity prices, future production estimates, anticipated capital expenditures, and a commensurate discount rate.  Because estimated undiscounted future cash flows have exceeded the carrying value of the Company’s proved properties at the end of each quarter, it has not been necessary for the Company to estimate the fair value of its properties under GAAP for successful efforts accounting.  As a result, the Company has not recorded any impairment expenses associated with its proved properties during the years ended December 31, 2016, 2017 and 2018.

At December 31, 2018, the Company did not have capitalized costs related to exploratory wells‑in‑progress which have been deferred for longer than one year pending determination of proved reserves.

The provision for depletion of oil and gas properties is calculated on a geological reservoir basis using the units‑of‑production method.  Depletion expense for oil and gas properties was $700 million, $694 million, and $832 million for the years ended December 31, 2016,  2017, and 2018, respectively.

Gathering Pipelines, Compressor Stations, and Water Handling and Treatment Systems

(g) Gathering Pipelines, Compressor Stations, and Water Handling and Treatment Systems

Expenditures for construction, installation, major additions, and improvements to property, plant, and equipment that is not directly related to production are capitalized, whereas minor replacements, maintenance, and repairs are expensed as incurred.  Gathering pipelines and compressor stations are depreciated using the straight‑line method over their estimated useful lives of 50 years.  Water handling and treatment systems are depreciated using the straight-line method over their estimated useful lives of 5 to 20 years.  Depreciation expense for gathering pipelines, compressor stations, and water handling and treatment systems was $101 million, $120 million, and $131 million for the years ended December 31, 2016,  2017, and 2018, respectively.  A gain or loss is recognized upon the sale or disposal of property and equipment.

Impairment of Long Lived Assets Other than Oil and Gas Properties

(h) Impairment of Long‑Lived Assets Other than Oil and Gas Properties

The Company evaluates its long‑lived assets other than natural gas properties for impairment when events or changes in circumstances indicate that the related carrying values of the assets may not be recoverable.  Generally, the basis for making such assessments is undiscounted future cash flow projections for the assets being assessed.  If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to the estimated fair values, which are based on discounted future cash flows using assumptions as to revenues, costs, and discount rates typical of third party market participants, which is a Level 3 fair value measurement.

There were no impairments for such assets during the year ended December 31, 2016.  Impairment of gathering systems and facilities of $23 million and $10 million during the years ended December 31, 2017 and 2018, respectively, relates to gathering facilities no longer or not expected to be utilized.

Other Property and Equipment

(i) Other Property and Equipment

Other property and equipment assets are depreciated using the straight‑line method over their estimated useful lives, which range from 2 to 20 years.  Depreciation expense for other property and equipment was $9 million, $10 million, and $9 million for the years ended December 31, 2016,  2017, and 2018, respectively.  A gain or loss is recognized upon the sale or disposal of other property and equipment.

Deferred Financing Costs

(j) Deferred Financing Costs

Deferred financing costs represent loan origination fees and other initial borrowing costs.  Such costs are capitalized and included in Other assets on the consolidated balance sheets if related to the Company’s revolving credit facilities, and are included as a reduction to Long-term debt on the consolidated balance sheets if related to the issuance of the Company’s senior notes.  These costs are amortized over the term of the related debt instrument.  The Company charges expense for unamortized deferred financing costs if credit facilities are retired prior to their maturity date.  At December 31, 2018, the Company had $19 million of unamortized deferred financing costs included in other long‑term assets, and $35 million of unamortized deferred financing costs included as a reduction to long-term debt.  The amounts amortized and the write‑off of previously deferred debt issuance costs were $16 million, $13 million, and $13 million for the years ended December 31, 2016,  2017, and 2018, respectively.

Derivative Financial Instruments

(k) Derivative Financial Instruments

In order to manage its exposure to natural gas, NGLs, and oil price volatility, the Company enters into derivative transactions from time to time, which may include commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements related to the price risk associated with the Company’s production.  To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis.  The Company has exposure to credit risk to the extent that the counterparty is unable to satisfy its settlement obligations.  The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative positions.

The Company records derivative instruments on the consolidated balance sheets as either assets or liabilities measured at fair value and records changes in the fair value of derivatives in current earnings as they occur.  Changes in the fair value of commodity derivatives, including gains or losses on settled derivatives, are classified as revenues on the Company’s consolidated statements of operations.  The Company’s derivatives have not been designated as hedges for accounting purposes.

Asset Retirement Obligations Policy

(l) Asset Retirement Obligations

The Company is obligated to dispose of certain long‑lived assets upon their abandonment.  The Company’s asset retirement obligations (“AROs”) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their lives, as well as Antero Midstream’s future closure and postclosure costs associated with the landfill, fresh water impoundments and waste water pits at its wastewater treatment facility.  AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations, which is then discounted at the Company’s credit‑adjusted, risk‑free interest rate.  Revisions to estimated AROs often result from changes in retirement cost estimates or changes in the estimated timing of abandonment.  The fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset.  The liability is accreted at the end of each period through charges to operating expense. 

Antero Midstream is under no legal obligations, neither contractually nor under the doctrine of promissory estoppel, to restore or dismantle its gathering pipelines, compressor stations, water delivery pipelines and facilities and wastewater treatment facility upon abandonment. Antero Midstream’s gathering pipelines, compressor stations, fresh water delivery pipelines and facilities and wastewater treatment facility have an indeterminate life, if properly maintained. Accordingly, Antero Midstream is not able to make a reasonable estimate of when future dismantlement and removal dates of its pipelines, compressor stations and facilities will occur.

Environmental Liabilities

(m) Environmental Liabilities

Environmental expenditures that relate to an existing condition caused by past operations, and that do not contribute to current or future revenue generation, are expensed as incurred.  Liabilities are accrued when environmental assessments and/or clean up is probable and the costs can be reasonably estimated.  These liabilities are adjusted as additional information becomes available or circumstances change.  As of December 31, 2017 and 2018, the Company did not have a material amount accrued for any environmental liabilities, nor has the Company been cited for any environmental violations that it believes are likely to have a material adverse effect on its financial position, results of operations, or cash flows.

Natural Gas, NGLs, and Oil Revenues

(n) Natural Gas, NGLs, and Oil Revenues

On May 28, 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers.  The ASU replaced most existing revenue recognition guidance in GAAP when it became effective and was incorporated into GAAP as Accounting Standards Codification (“ASC”) Topic 606.  The Company elected the modified retrospective transition method when new standard became effective for the Company on January 1, 2018.  The adoption of ASU 2014-09 did not have a material impact on the Company’s financial results. 

Our revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas.  Sales of natural gas, NGLs, and oil are recognized when we satisfy a performance obligation by transferring control of a product to a customer.  Payment is generally received in the month following the month that the sale occurred.  Variances between estimated sales and actual amounts received are recorded in the month payment is received and are not material.  The Company recognizes natural gas revenues based on its entitlement share of natural gas that is produced based on its working interests in the properties.  The Company records a revenue distribution payable to the extent it receives more than its proportionate share of production revenues.  At December 31, 2017 and 2018, the Company had no production imbalance positions.

Under our natural gas sales contracts, we deliver natural gas to purchasers at an agreed upon delivery point.  Natural gas is transported from our wellheads to delivery points specified under sales contracts.  To deliver natural gas to these points, Antero Midstream or third parties gather, compress, process and transport our natural gas.  We maintain control of the natural gas during gathering, compression, processing, and transportation.  Our sales contracts provide that we receive a specific index price adjusted for pricing differentials.  We transfer control of the product at the delivery point and recognize revenue based on the contract price.  The costs to gather, compress, process and transport the natural gas are recorded as Gathering, compression, processing and transportation expenses.

NGLs, which are extracted from natural gas through processing, are either sold by us directly or by the processor under processing contracts.  For NGLs sold by us directly, our sales contracts provide that we deliver the product to the purchaser at an agreed upon delivery point and that we receive a specific index price adjusted for pricing differentials.  We transfer control of the product to the purchaser at the delivery point and recognize revenue based on the contract price.  The costs to further process and transport NGLs are recorded as Gathering, compression, processing, and transportation expenses.  For NGLs sold by the processor, our processing contracts provide that we transfer control to the processor at the tailgate of the processing plant and we recognize revenue based on the price received from the processor.

Under our oil sales contracts, we generally sell oil to the purchaser and collect a contractually agreed upon index price, net of pricing differentials.  We recognize revenue based on the contract price when we transfer control of the product to the purchaser.

Marketing Revenues and Expenses

(o) Marketing Revenues and Expenses

Marketing revenues are derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties.  We retain control of the purchased natural gas and NGLs prior to delivery to the purchaser.  The Company has concluded that we are the principal in these arrangements and therefore we recognize revenue on a gross basis, with costs to purchase and transport natural gas and NGLs presented as marketing expenses.  Contracts to sell third party gas and NGLs are generally subject to similar terms as contracts to sell our produced natural gas and NGLs.  We satisfy performance obligations to the purchaser by transferring control of the product at the delivery point and recognize revenue based on the price received from the purchaser.

Marketing expenses include the cost of purchased third-party natural gas and NGLs.  The Company classifies firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize the capacity (excess capacity) as marketing expenses since it is marketing this excess capacity to third parties.  Firm transportation for which the Company has sufficient production capacity (even though it may not use the transportation capacity because of alternative delivery points with more favorable pricing) is considered unutilized capacity and is charged to transportation expense.

Gathering compression, water handling and treatment revenue

(p)  Gathering, compression, water handling and treatment revenue

Substantially all revenues from our gathering, compression, water handling and treatment operations are derived from intersegment transactions for services Antero Midstream provides to our exploration and production operations.  The portion of such fees shown in our consolidated financial statements represent amounts charged to interest owners in Antero-operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Antero Midstream or usage of Antero Midstream’s gathering and compression systems.  For gathering and compression revenue, Antero Midstream satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a compressor station, high pressure volumes are delivered to a processing plant or transmission pipeline, and compression volumes are delivered to a high pressure line.  Revenue is recognized based on the per Mcf gathering or compression fee charged by Antero Midstream in accordance with the gathering and compression agreement.  For water handling and treatment revenue, Antero Midstream satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the hydration unit of a specified well pad and the wastewater volumes have been delivered to its wastewater treatment facility.  For services contracted through third party providers, Antero Midstream’s performance obligation is satisfied when the service performed by the third party provider has been completed.  Revenue is recognized based on the per barrel fresh water delivery or wastewater treatment fee charged by Antero Midstream in accordance with the water services agreement.

Concentrations of Credit Risk

(q) Concentrations of Credit Risk

The Company’s revenues are derived principally from uncollateralized sales to purchasers in the oil and gas industry or the utilities industry.  The concentration of credit risk in two related industries affects the Company’s overall exposure to credit risk because purchasers may be similarly affected by changes in economic and other conditions.  The Company has not experienced significant credit losses on its receivables.

The Company’s sales to major customers (purchases in excess of 10% of total sales) for the years ended December 31, 2016,  2017, and 2018 are as follows:

	2016		2017		2018
Company A	1	%	—	%	16	%
Company B	29		22		14
Company C	13		15		7
All others	57		63		63
	100	%	100	%	100	%

The Company is also exposed to credit risk on its commodity derivative portfolio.  Any default by the counterparties to these derivative contracts when they become due could have a material adverse effect on the Company’s financial condition and results of operations.  The Company has economic hedges in place with sixteen different counterparties.  The fair value of the Company’s commodity derivative contracts of approximately $607 million (excluding short-term commodity derivatives related to our marketing activities) at December 31, 2018 includes the following values by bank counterparty: Morgan Stanley - $115 million; JP Morgan - $102 million; Scotiabank - $97 million; Citigroup - $91 million; Wells Fargo - $80 million; Canadian Imperial Bank of Commerce - $51 million; BNP Paribas - $24 million; Bank of Montreal - $14 million; Toronto Dominion - $8 million; PNC - $8 million; SunTrust - $7 million; Natixis - $7 million; and Capital One - $3 million.  The estimated fair value of commodity derivative assets has been risk-adjusted using a discount rate based upon the respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at December 31, 2018 for each of the European and American banks.  The Company believes that all of these institutions currently are acceptable credit risks.

The Company, at times, may have cash in banks in excess of federally insured amounts.

Income Taxes

(r) Income Taxes

The Company recognizes deferred tax assets and liabilities for temporary differences resulting from net operating loss carryforwards for income tax purposes and the differences between the financial statement and tax basis of assets and liabilities.  The effect of changes in tax laws or tax rates is recognized in income during the period such changes are enacted.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or all, of the deferred tax assets will not be realized.

Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained.  The Company recognizes interest expense related to unrecognized tax benefits in interest expense and fines and penalties for tax-related matters as income tax expense.

Fair Value Measurements

(s) Fair Value Measurements

FASB ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements.  This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties and other long‑lived assets).  Fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value.  An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement.  The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.  The highest priority (Level 1) is given to unadjusted, quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs.  Level 2 inputs are data, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.  Instruments which are valued using Level 2 inputs include non-exchange traded derivatives such as over‑the‑counter commodity price swaps.  Valuation models used to measure fair value of these instruments consider various Level 2 inputs including (i) quoted forward prices for commodities, (ii) time value, (iii) quoted forward interest rates, (iv) current market prices and contractual prices for the underlying instruments, (v) risk of nonperformance by the Company and the counterparty, and (vi) other relevant economic measures.

Industry Segments and Geographic Information

(t) Industry Segments and Geographic Information

Management has evaluated how the Company is organized and managed and has identified the following segments: (1) the exploration, development, and production of natural gas, NGLs, and oil; (2) gathering and processing; (3) water handling and treatment; and (4) marketing and utilization of excess firm transportation capacity.

All of the Company’s assets are located in the United States and substantially all of its production revenues are attributable to customers located in the United States; however, some of the Company’s production revenues are attributable to customers who resell the Company’s production to third parties located in foreign countries. 

Earnings (Loss) Per Common Share

(u) Earnings (loss) Per Common Share

Earnings (loss) per common share—basic for each period is computed by dividing net income (loss) attributable to Antero by the basic weighted average number of shares outstanding during the period.  Earnings (loss) per common share—assuming dilution for each period is computed after giving consideration to the potential dilution from outstanding equity awards, calculated using the treasury stock method.  The Company includes performance share unit awards in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the period was also the end of the performance period required for the vesting of the awards.  During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards is antidilutive.  The following is a reconciliation of the Company’s basic weighted average shares outstanding to diluted weighted average shares outstanding during the periods presented (in thousands):

	Year Ended December 31,
	2016	2017	2018
Basic weighted average number of shares outstanding	294,945	315,426	316,036
Add: Dilutive effect of restricted stock units	—	817	—
Add: Dilutive effect of outstanding stock options	—	—	—
Add: Dilutive effect of performance stock units	—	40	—
Diluted weighted average number of shares outstanding	294,945	316,283	316,036
Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share (1):
Restricted stock units	6,740	1,521	2,844
Outstanding stock options	702	676	626
Performance stock units	659	1,054	1,705

(1)    The potential dilutive effects of these awards were excluded from the computation of earnings (loss) per common share—assuming dilution because the inclusion of these awards would have been anti-dilutive

Treasury Share Retirement

(v)  Treasury Share Retirement

The Company retires treasury shares acquired through share repurchases and returns those shares to the status of authorized but unissued.  When treasury shares are retired, the Company’s policy is to allocate the excess of the repurchase price over the par value of shares acquired first, to additional paid-in capital, and then to accumulated earnings.  The portion allocable to additional paid-in capital is determined by applying a percentage, determined by dividing the number of shares to be retired by the number of shares issued, to the balance of additional paid-in capital as of retirement.

Recently Issued Accounting Standard

(w)  Recently Issued Accounting Standard

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases, which replaced most existing lease guidance in GAAP when it became effective on January 1, 2019.  The standard requires lessees to record lease liabilities and right-of-use assets and we have elected to adopt the ongoing effects of the new standard prospectively.  The standard also provides for the election of practical expedients in applying and adopting the standard.  Practical expedients adopted by the Company include, (i) not reassessing whether expired or existing contracts contain leases under the new definition of a lease and retaining lease classification for expired or existing leases, (ii) the use of hindsight in determining the lease term, the likelihood that a lessee purchase option will be exercised, and impairment assessment, (iii) carrying forward the existing accounting treatment for land easements, and (iv) combining lease and non-lease components by asset class.      

Adoption of the standard will increase assets and liabilities on the Company’s consolidated balance sheet as well as result in additional disclosures regarding lease expenses, assets, and liabilities.  The Company will recognize right-of- use assets and lease liabilities related to certain contractual obligations for office space, processing plants, drilling rigs, gas gathering lines, compressor stations, and other office and field equipment.  The Company estimates that adoption of the standard will result in the recognition of right-of-use assets and related liabilities of approximately $2.0 billion.  The Company does not believe that adoption of the standard will impact its operational strategies, growth prospects, income or cash flows.  The Company has updated internal controls impacted by the new standard and acquired and implemented software to collect and account for lease data under the standard. 

Equity-Based Compensation

(x)  Equity-Based Compensation

We recognize compensation cost related to all equity-based awards in the financial statements based on their estimated grant date fair value.  We are authorized to grant various types of equity-based compensation awards including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent awards, and other types of awards.  The grant date fair values are determined based on the type of award and may utilize market prices on the date of grant, Black-Scholes option-pricing model, Monte Carlo simulations, or other acceptable valuation methodologies, as appropriate for the type of equity-based award.  Compensation cost is recognized ratably over the applicable vesting or service period.  Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period.  See Note 9 for additional information regarding our equity-based compensation.