Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

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, 2018 and 2017, and the results of its operations, comprehensive income (loss) and its cash flows for the years ended December 31, 2018, 2017, and 2016.

Cash and Cash Equivalents

(b) Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

Accounts Receivable

(c) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. The Company did not deem any of its accounts receivables to be uncollectable as of December 31, 2018 or December 31, 2017.

The Company accrues revenue due to timing differences between the delivery of natural gas, NGLs, and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices. The Company had $94.1 million and $52.9 million of accrued revenues, net of expenses at December 31, 2018 and December 31, 2017, respectively, which were included in accounts receivable within the Company’s consolidated balance sheets.

Property and Equipment

(d) Property and Equipment

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “ Depreciation, Depletion and Amortization ” below).

Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s consolidated balance sheets. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s consolidated statements of operations. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s consolidated statements of operations unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):

	December 31, 2018			December 31, 2017
Oil and natural gas properties:
Unproved	$	482,475		$	459,549
Proved		2,188,233			1,896,081
Gross oil and natural gas properties		2,670,708			2,355,630
Less accumulated depreciation, depletion and    amortization		(1,380,650	)		(1,248,200	)
Oil and natural gas properties, net		1,290,058			1,107,430
Other property and equipment		14,460			13,508
Less accumulated depreciation		(8,160	)		(6,566	)
Other property and equipment, net		6,300			6,942
Property and equipment, net	$	1,296,358		$	1,114,372

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves.

The Company capitalized interest expense totaling $1.7 million, $2.3 million and $1.1 million for the years ended December 31, 2018, 2017, and 2016, respectively.

Other Property and Equipment

Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition.

Accounts Payable and Accrued Liabilities

(e) Accounts Payable and Accrued Liabilities

A summary of accounts payable is as follows (in thousands):

	December 31, 2018		December 31, 2017
Trade payables	$	27,481	$	44,516
Royalty payables		70,019		17,483
Production & ad valorem taxes		1,811		967
Derivative payable		4,736		941
Other payables		12,688		12,267
Total accounts payable	$	116,735	$	76,174

A summary of accrued liabilities is as follows (in thousands):

	December 31, 2018		December 31, 2017
Ad valorem and production taxes	$	6,193	$	4,299
Employee compensation		6,595		8,667
Royalties		39,969		9,660
Short term derivatives		—		14,875
Other		4,152		4,161
Total accrued liabilities	$	56,909	$	41,662

Revenue Recognition

(f) Revenue Recognition

Product Revenue

The Company’s revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from the natural gas. Sales of natural gas, NGLs, and oil are recognized when the Company satisfies a performance obligation by transferring control of a product to a customer. Payment is generally received one month after the sale has occurred.

Natural Gas

Under the Company’s natural gas sales contracts, the Company delivers natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from the wellhead to delivery points specified under sales contracts. To deliver natural gas to these points, the Company uses third parties to gather, compress, process and transport the natural gas.  The Company maintains control of the natural gas during gathering, compression, processing, and transportation. The Company’s sales contracts provide that it receive a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as transportation, gathering and compression expense.

NGLs

The Company sells NGLs directly to the NGLs purchaser. For these NGLs, the sales contracts provide that the Company deliver the product to the purchaser at an agreed upon delivery point and that the Company receives a specific index price adjusted for pricing differentials.  The Company transfers control of the product to the purchaser at the delivery point and recognizes revenue based on the contract price. The costs to further process and transport NGLs are recorded as transportation, gathering and compression expense.

Oil

Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser from storage tanks at central stabilization facilities and well pads and collects a contractually agreed upon index price, net of pricing differentials. The Company transfers control of the product from the central stabilization facilities and well pads to the purchaser and recognizes revenue based on the contract price.

Marketing Revenue

Brokered natural gas and marketing revenues are derived from activities to purchase and sell third-party natural gas and to market excess firm transportation capacity to third parties. The Company retains control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that it is the principal in these arrangements and therefore the Company recognizes revenue on a gross basis, with costs to purchase and transport natural gas presented as brokered natural gas and marketing expense. Contracts to sell third party natural gas are generally subject to similar terms as contracts to sell the Company’s produced natural gas and NGLs.  The Company satisfies performance obligations to the purchaser by transferring control of the product at the delivery point and recognizes revenue based on the price received from the purchaser.

Disaggregation of Revenue

The following table illustrates the revenue disaggregated by type for the periods indicated:

	For the Year Ended December 31,
	2018		2017		2016
Revenues (in thousands)
Natural gas sales	$	274,239	$	241,379	$	134,618
NGL sales		86,152		64,109		38,204
Oil sales		138,202		74,690		50,193
Brokered natural gas and marketing revenue		16,552		3,481		12,019
Total revenues	$	515,145	$	383,659	$	235,034

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less.  For those contracts, the Company has utilized the practical expedient allowed in the revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligations are part of a contract that has an original expected duration of one year or less.

For any product sales that have a contract term greater than one year, the Company has also utilized the practical expedient that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.  Under these product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.  Currently, any product sales that have a contractual term greater than one year have no long-term fixed considerations.

Contract Balances

Under the Company’s sales contracts, customers are invoiced once performance obligations have been satisfied, at which point payment is unconditional.  Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities.  Accounts receivable attributable to the Company’s revenue contracts with customers was $94.1 million and $52.9 million at December 31, 2018 and December 31, 2017, respectively.

Major Customers

(g) Major Customers

The Company sells production volumes to various purchasers. For the years ended December 31, 2018, 2017, and 2016, there were one, two and four customers, respectively, that accounted for 10% or more of the total natural gas, NGLs and oil sales. The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated:

	For the Year Ended December 31,
	2018		2017		2016
Purchaser
Antero Resources		—		—	14%
Concord Energy		—		—	12%
Emera Energy Services		—	17%			—
EnLink Midstream		—		—	17%
Marathon Petroleum	25%		10%			—
Sequent Energy Management		—		—	20%
Total	25%		27%		63%

Management believes that the loss of any one customer would not have a material adverse effect on the Company’s ability to sell natural gas, NGLs and oil production because it believes that there are potential alternative purchasers although it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Company can establish such relationships or that those relationships will result in an increased number of purchasers.

Concentration of Credit Risk

(h) Concentration of Credit Risk

The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2018 and December 31, 2017 (in thousands):

	December 31, 2018		December 31, 2017
Receivables by product or service:
Sale of oil and natural gas and related products    and services	$	94,107	$	52,908
Joint interest owners		24,830		23,154
Derivatives		372		1,528
Other		23		19
Total	$	119,332	$	77,609

Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the State of Ohio. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. The fair value of the Company’s commodity unsettled derivative contracts was a net asset position of $5.7 million and a net liability position of ($5.1) million at December 31, 2018 and 2017, respectively. Other than, as provided by the revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contracts, nor are they required to provide credit support to the Company. As of December 31, 2018, the Company did not have past-due receivables from or payables to any of the counterparties.

Depreciation, Depletion and Amortization

(i) Depreciation, Depletion and Amortization

Oil and Natural Gas Properties

Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties for the years ended December 31, 2018, 2017, and 2016 totaled approximately $132.5 million, $116.8 million and $91.0 million, respectively.

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation for the years ended December 31, 2018, 2017, and 2016 totaled approximately $1.8 million, $2.0 million and $1.9 million, respectively. This amount is included in DD&A expense in the consolidated statements of operations.

Impairment of Long-Lived Assets

(j) Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Company’s oil and gas properties is done by determining if the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.  As a result of the decline in commodity prices, the Company recognized impairment expenses of approximately $17.7 million for the year ended December 31, 2016 relating to proved properties in the Marcellus Shale.

The aforementioned impairment charges represented a significant Level 3 measurement in the fair value hierarchy. The primary input used was the Company’s forecasted discount net cash flows.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of $27.6 million, $28.3 million, and $29.8 million for the years ended December 31, 2018, 2017, and 2016, respectively. These costs are included in exploration expense in the consolidated statements of operations.

Income Taxes

(k) Income Taxes

The Company accounts for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax 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.

ASC Topic 740 “ Income Taxes ” provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date.

Fair Value of Financial Instruments

(l) Fair Value of Financial Instruments

The Company has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 —Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 —Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market date for substantially the entire contractual term of the asset or liability.  The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

Level 3 —Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Derivative Financial Instruments

(m) Derivative Financial Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells.

Derivatives are recorded at fair value and are included on the consolidated balance sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying consolidated balance sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities.

The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy.

Asset Retirement Obligation

(n) Asset Retirement Obligation

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with Topic ASC 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate, which was 10.33% for the years ended December 31, 2018 and 2017, respectively.

Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration.  Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

The following table sets forth the changes in the Company’s ARO liability for the periods indicated (in thousands):

	For the Year Ended December 31,
	2018		2017		2016
Asset retirement obligations, beginning of period	$	6,029	$	4,806	$	3,401
Additional liabilities incurred		418		679		1,014
Accretion		663		544		391
Asset retirement obligations, end of period	$	7,110	$	6,029	$	4,806

The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.

Lease Obligations

(o) Lease Obligations

The Company leases office space under an operating lease that expires in 2024. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease terms unless the renewals are deemed to be reasonably assured at lease inception.

Off-Balance Sheet Arrangements

(p) Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

Segment Reporting

(q) Segment Reporting

The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

Debt Issuance Costs

(r) Debt Issuance Costs

The expenditures related to issuing debt are capitalized and reported as a reduction of the Company’s debt balance in the accompanying balance sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.

Recent Accounting Pronouncements

(s) Recent Accounting Pronouncements

Recently Adopted

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, “Property, Plant and Equipment”, and intangible assets within the scope of Topic 350, “Intangibles—Goodwill and Other”) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The Company adopted this standard effective January 1, 2018 using the modified retrospective method.  The Company did not recognize a significant impact on its financial position or results of operations.  Upon adoption of this new standard, the Company did not record a cumulative effect adjustment nor did the Company alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify the impact of future revenue contracts entered into by the Company.  Additional disclosures have been included to provide further detail regarding the Company’s revenue recognition policies.  

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.”  The new standard provides guidance on how certain cash receipts and cash payments are presented and classified on the statement of cash flows.  These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. The Company adopted this standard effective January 1, 2018 and did not recognize a significant impact on its financial position, results of operations, or statement of cash flows.

In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.”  Currently under the standard, there are three elements of a business: inputs, processes and outputs.  The revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets.  If that screen is met, the set of assets is not a business.  The new framework also specifies the minimum required inputs and processes necessary to be a business.  This amendment is effective for periods after December 15, 2017, with early adoption permitted.  The Company adopted this standard effective January 1, 2018 and considered the new guidance in its assessment of the accounting treatment for the Flat Castle Acquisition. (See Note 3— Acquisition).

Accounting Pronouncements Not Yet Adopted

In February 2016, the FASB issued Update 2016-02, “Leases (Topic 842)”, which increases transparency and comparability among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Update 2016-02 maintains a distinction between finance leases and operating leases, which is substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous lease guidance. Retaining this distinction allows the recognition, measurement and presentation of expenses and cash flows arising from a lease to remain similar to the previous accounting treatment. A lessee is permitted to make an accounting policy election by class of underlying asset to exclude from balance sheet recognition any lease assets and lease liabilities with a term of 12 months or less, and instead to recognize lease expense on a straight-line basis over the lease term. For both financing and operating leases, the ROU asset and lease liability will be initially measured at the present value of the lease payments in the statement of financial position. For public business entities, the amendments in this update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In

transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach with the option to adopt certain practical expedients. In July 2018, the FASB issued Update 2018-11 which provides entities with the option to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption.

The Company will adopt Topic 842 guidance as of January 1, 2019 using the transition method that allows a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company has elected the transition relief package of practical expedients by applying previous accounting conclusions under ASC 840 to all of its leases that existed prior to the transition date. As a result, the Company will not reassess 1) whether existing or expired contracts contain leases 2) lease classification for any existing or expired leases and 3) whether lease origination costs qualified as initial direct costs. The Company will not elect the practical expedient to use hindsight in determining a lease term and impairment of ROU assets at the adoption date. Additionally, the Company will elect the short-term practical expedient for all of its asset classes by establishing an accounting policy to exclude leases with a term of 12 months or less. The Company will not separate lease components from non-lease components for its specified asset classes. Lastly, the Company will adopt the easement practical expedient which allows the Company to apply ASC 842 prospectively to land easements after the adoption date. Easements that existed or expired prior to the adoption date that were not previously assessed under ASC 840 will not be reassessed. The Company has implemented a third-party supported lease accounting system to account for the identified leases and is currently in the process of performing final testing of this system.

The adoption of Topic 842 will have a material impact on the Company’s Consolidated Balance Sheet due to the initial recognition of ROU assets and lease liabilities. In 2019, the Company expects to recognize a ROU asset and corresponding lease liability between $10 million to $15 million on its Consolidated Balance Sheet.  Due to the BRMR Merger closing subsequent to the year ended December 31, 2018, the initial analysis in relation to BRMR’s adoption of Topic 842 is in process and will be accounted for in the period it closed.

Change in Estimates

(t) Change in Estimates

During the year ended December 31, 2016, the Company reduced its estimate of amounts due from a non-operated partner related to the sale of natural gas and NGLs, net of associated costs, based on revised information received from the non-operated partner during the period.  As a result, the Company decreased accounts receivable by approximately $4 million, increased revenue from oil and natural gas sales by approximately $1.5 million, and increased transportation, gathering and compression expense by approximately $5.8 million, which increased the net loss for the year ended December 31, 2016 by approximately $4 million, or $0.02 per common share.

During the year ended December 31, 2016, the Company reduced its estimate for production and ad valorem tax expense based on recent historical experience and additional information received during the period. As a result, the Company decreased the accrual for production and ad valorem taxes to be paid by approximately $4 million, which decreased the net loss for the year ended December 31, 2016 by a corresponding amount, or $0.30 per common share.

Correction of Immaterial Error

(u) Correction of Immaterial Error

During the three months ended March 31, 2017, the Company determined that its estimated accrual for production and ad valorem tax expense was overstated for prior periods. The Company evaluated the materiality of this error on both a quantitative and qualitative basis under the guidance of ASC 250 “Accounting Changes and Errors Corrections,” and determined that it did not have a material impact to previously issued financial statements.

Although the error was immaterial to prior periods, the prior period financial statements were revised, in accordance with SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, due to the significance of the out-of-period correction to the current period. Immaterial errors related to periods prior to the year ended December 31, 2016 are reflected as an adjustment to beginning accumulated deficit for that year. Periods not presented herein will be revised, as applicable, in future filings.

A reconciliation of the effects of the revision to amounts in the previously reported consolidated financial statements is as follows (in thousands, except per share amounts):

	As of  December 31, 2016
	As Reported			Adjustment			As Adjusted
Balance Sheet
Accounts receivable	$	43,638		$	785		$	44,423
Total current assets		249,630			785			250,415
Total assets		1,197,859			785			1,198,644
Accrued liabilities		64,150			(9,106	)		55,044
Total current liabilities		140,625			(9,106	)		131,519
Total liabilities		651,143			(9,106	)		642,037
Accumulated deficit		(1,414,561	)		9,891			(1,404,670	)
Total stockholders' equity		546,716			9,891			556,607
Total liabilities and stockholders' equity		1,197,859			785			1,198,644

	As of  December 31, 2016
	As Reported			Adjustment		As Adjusted
Statement of Stockholders' Equity
Accumulated deficit	$	(1,414,561	)	$	9,891	$	(1,404,670	)
Total stockholders' equity		546,716			9,891		556,607

	As of  December 31, 2016
	As Reported			Adjustment			As Adjusted
Statement of Operations
Production and ad valorem taxes	$	4,998		$	2,929		$	7,927
Total operating expenses		349,507			2,929			352,436
Operating loss		(114,473	)		(2,929	)		(117,402	)
Loss before income taxes		(203,260	)		(2,929	)		(206,189	)
Net loss		(203,806	)		(2,929	)		(206,735	)
Basic and diluted loss per share	$	(12.60	)	$	(0.24	)	$	(12.84	)

	As of  December 31, 2016
	As Reported			Adjustment			As Adjusted
Statement of Comprehensive Loss
Net loss	$	(203,806	)	$	(2,929	)	$	(206,735	)
Total Comprehensive loss		(203,806	)		(2,929	)		(206,735	)

	As of December 31, 2016
	As Reported			Adjustment			As Adjusted
Statement of Cash Flows
Net loss	$	(203,806	)	$	(2,929	)	$	(206,735	)
Accounts receivable		(20,563	)		(714	)		(21,277	)
Accounts payable and accrued liabilities		(2,849	)		3,643			794