SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements include the accounts of Matador and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements, purchase price allocations and the reported amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.

The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

Change in Accounting Principles — Revenue Recognition

During the first quarter of 2018, the Company adopted Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”), which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve and converge with international standards, the financial reporting requirements for revenue from contracts with customers. The Company adopted the new guidance using the modified retrospective approach. The adoption did not require an adjustment to opening accumulated deficit for any cumulative effect adjustment and did not have a material impact on the Company’s consolidated balance sheets, statements of operations, statement of shareholders’ equity or statements of cash flows.

Prior to the adoption of ASC 606, the Company recorded oil and natural gas revenues at the time of physical transfer of such products to the purchaser. The Company followed the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.

The Company enters into contracts with customers to sell its oil and natural gas production. With the adoption of ASC 606, revenue from these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production.

The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil sales on the statements of operations as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations, as they represent payment for services performed outside of the contract with the customer.

The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, natural gas liquids (“NGL”) are extracted. The NGLs and remaining residue gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of operations.

The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in ASC 606 that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract.

The Company periodically enters into natural gas purchase transactions with third parties whereby the Company processes the third party’s natural gas at San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of operations as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold.

From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of operations.

The Company determined the impact on its consolidated financial statements as a result of adoption of ASC 606 was a $10.6 million decrease in oil and natural gas revenues and a $10.6 million decrease in production taxes, transportation and processing expenses for the year ended December 31, 2018, respectively, which was not material. As a result of adoption of this standard, the Company is now required to disclose the following information regarding total revenues and revenues from contracts with customers on a disaggregated basis for the year ended December 31, 2018 (in thousands).



	Year Ended December 31, 2018
Revenues from contracts with customers	$	829,691
Lease bonus - mineral acreage	2,489
Realized gain on derivatives	2,334
Unrealized gain on derivatives	65,085
Total revenues	$	899,599



	Year Ended December 31, 2018
Oil revenues	$	635,554
Natural gas revenues	165,146
Third-party midstream services revenues	21,920
Sales of purchased natural gas	7,071
Total revenues from contracts with customers	$	829,691

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Change in Accounting Principles — Cash Flows

During the first quarter of 2018, the Company adopted Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230), which specifies that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. The Company adopted ASU 2016-18 effective January 1, 2018 and determined that the adoption of this ASU changed the presentation of its beginning and ending cash balances and eliminated the presentation of changes in restricted cash balances from investing activities in its consolidated statements of cash flows. The Company adopted the new guidance using the retrospective transition method; as a result, approximately $6.0 million, $1.3 million and $44.4 million of restricted cash was added to the beginning cash balance for the years ended December 31, 2018, 2017 and 2016, respectively.

Change in Accounting Principles — Business Combinations

During the first quarter of 2018, the Company adopted ASU 2017-01, Business Combinations (Topic 805), which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the definition of a business. The Company adopted ASU 2017-01 prospectively, which did not have a material impact on its consolidated financial statements.

Restricted Cash

Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

Accounts Receivable

The Company sells its operated oil, natural gas and NGL production to various purchasers (See “—Change in Accounting Principles—Revenue Recognition” above.) In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and NGLs or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts.

The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented.

For the year ended December 31, 2018, four significant purchasers accounted for 60% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (19%), BP America Production Company (15%), Occidental Energy Marketing, Inc. (14%) and Western Refining Crude Oil (12%). For the year ended December 31, 2017, four significant purchasers accounted for 60% of the Company’s total oil, natural gas and NGL revenues: Occidental Energy Marketing, Inc. (23%), Plains Marketing, L.P. (14%), Shell Trading (US) Company (12%), and Western Refining Crude Oil (11%). For the year ended December 31, 2016, three significant purchasers accounted for 48% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (18%), Shell Trading (US) Company (17%) and Occidental Energy Marketing, Inc. (13%). If the Company lost one or more of these significant purchasers and were unable to sell its production to other purchasers on terms it considers acceptable, it could materially and adversely affect the Company’s business, financial condition, results of operations and cash flows. At December 31, 2018, 2017 and 2016, approximately 34%, 43% and 38%, respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers.

Lease and Well Equipment Inventory

Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations.

Oil and Natural Gas Properties

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $29.9 million, $23.1 million and $15.7 million of its general and administrative costs in 2018, 2017 and 2016, respectively. The Company capitalized $8.8 million, $7.3 million and $3.7 million of its interest expense for the years ended December 31, 2018, 2017 and 2016, respectively.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized.

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of:

(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less

(d) any income tax effects related to the properties involved.

Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The Company’s derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedge instruments for accounting purposes.

The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2018, these average oil and natural gas prices were $62.04 per Bbl and $3.10 per MMBtu, respectively. For the period from January through December 2017, these average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. For the period from January through December 2016, these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials.

During the years ended December 31, 2018 and December 31, 2017, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the years ended December 31, 2018 and 2017.

During the year ended December 31, 2016, the Company’s net capitalized costs less related deferred income taxes periodically exceeded the full-cost ceiling. As a result, in the first six months of 2016, the Company recorded an impairment charge of $158.6 million, exclusive of tax effect, to its consolidated statement of operations with the related deferred income tax credit recorded net of a valuation allowance.

As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods.

Midstream and Other Property and Equipment

Midstream and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life (five to 30 years) using the straight-line method. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream and other property and equipment.

Asset Retirement Obligations

The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or midstream and other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations.

Derivative Financial Instruments

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in the consolidated statements of operations. See Note 11 for additional information about the Company’s derivative instruments.

Stock-Based Compensation

The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors and certain employees, contractors and advisors. All equity-based awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the consolidated statements of operations on a straight-line basis over the awards’ vesting periods. Awards that are expected to be settled in cash are liability-based awards, which are measured at fair value at each reporting date and are generally recognized as a component of general and administrative expenses in the consolidated statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the Company’s 2003 Stock and Incentive Plan (the “2003 Plan”) as liability instruments as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options. As the stock options accounted for as liability-based awards are fully vested, changes in the fair value of the awards are generally recognized as a component of general and administrative expenses in the consolidated statements of operations until the awards are settled.

The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options, the closing stock price on the date of grant to measure the fair value of restricted stock and restricted stock unit awards and the Monte Carlo simulation method to measure the fair value of performance units.

The Company’s consolidated statements of operations for the years ended December 31, 2018, 2017 and 2016 include a stock-based compensation (non-cash) expense of $17.2 million, $16.7 million and $12.4 million, respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $1.6 million, $3.0 million and $1.0 million in 2018, 2017 and 2016, respectively, paid to independent members of the Board of Directors and advisors as compensation for their services to the Company.

Income Taxes

The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized.

The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2018, 2017 and 2016, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions.

When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2018, 2017 and 2016.

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act. The legislation significantly changed U.S. tax law by, among other things, lowering corporate income tax rates, implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries. The Tax Cuts and Jobs Act reduced the U.S. corporate income tax rate from a maximum of 35% to a flat rate of 21% effective January 1, 2018.

Allocation of Purchase Price in Business Combinations

As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

Earnings (Loss) Per Common Share

The Company reports basic earnings (loss) attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings (loss) attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.

The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2018, 2017 and 2016 (in thousands, except per share data).



	Year Ended December 31,
	2018		2017		2016
Net income (loss) attributable to Matador Resources Company shareholders — numerator	$	274,207	$	125,867	$	(97,421	)

Weighted average common shares outstanding — denominator
Basic	113,580		102,029		91,273
Dilutive effect of options and restricted stock units	111		514		—
Diluted weighted average common shares outstanding	113,691		102,543		91,273
Earnings (loss) per common share attributable to Matador Resources Company shareholders
Basic	$	2.41	$	1.23	$	(1.07	)
Diluted	$	2.41	$	1.23	$	(1.07	)

Options to purchase a total of 1.6 million and 1.0 million shares of the Company’s common stock were excluded from the calculations above for the years ended December 31, 2018 and 2017, respectively, because their effects were anti-dilutive.

Options to purchase a total of 2.9 million shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2016 because their effects were anti-dilutive. Additionally, 1.0 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2016 as the security holders do not have the obligation to share in the losses of the Company.

Credit Risk

The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and NGL price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2018 were with The Bank of Nova Scotia and SunTrust Bank (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s revolving credit agreement.

Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners.

Recent Accounting Pronouncements

Leases. In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases (Topic 842), which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842), which is a land easement practical expedient. The Company plans to use this practical expedient, and as a result, the Company will evaluate new or modified land easements under this ASU beginning at the date of adoption. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842), which is a targeted improvement for comparative reporting requirements for initial adoption of ASU 2016-02. The Company plans to use the optional transition method to adopt ASU 2016-02, and the amendments provided for in ASU 2018-11 will allow the Company to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of accumulated deficit in the period of adoption. Adoption of ASU 2016-02 will result in increased reported assets and liabilities. The Company has evaluated the impact of the adoption of these ASUs on its consolidated financial statements, including identifying all leases as defined under the new lease standards, and estimates that adoption of these standards will result in assets and liabilities related to leases of approximately $55 million to $65 million to be reflected on the Company’s consolidated balance sheet. The Company adopted these ASUs as of January 1, 2019.

Stock Compensation. In June 2018, the FASB issued ASU 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting. This ASU extends the scope of Topic 718 to include share-based payment transactions related to the acquisition of goods and services from nonemployees. Currently, the Company accounts for stock-based awards to special advisors and contractors under ASC 505-50 as liability instruments, and the fair value of the awards is recalculated each reporting period. Upon adoption, all such awards will be measured at fair value on the grant date and the resulting expense will be recognized on a straight-line basis over the awards’ vesting period. The transitional guidance requires entities to remeasure all unvested awards that are being accounted for under ASC 505-50 as liability instruments as of the beginning of the year in which this ASU is adopted. The Company adopted this ASU as of January 1, 2019. Adoption of this ASU will not have a material impact on the Company’s consolidated financial statements.