SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of estimates: The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

The Partnership’s consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depreciation, depletion, amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. The Partnership’s reserve estimates are determined by an independent petroleum engineering firm. Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of derivative instruments, revenue accruals, asset retirement obligation (“ARO”) liabilities, and determination of the fair value of equity-based awards.

The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. A significant decline in natural gas or oil prices could result in a reduction in the Partnership’s fair value estimates and cause the Partnership to perform analyses to determine if its oil and natural gas properties are impaired. As future commodity prices cannot be predicted accurately, actual results could differ significantly from estimates.

Cash and cash equivalents: The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Concentration of credit risk: Financial instruments that potentially subject the Partnership to credit risk consist principally of cash and cash equivalent balances, accounts receivable, and commodity derivative financial instruments. The Partnership maintains cash and cash equivalent balances with major financial institutions. At times, those balances exceed federally insured limits; however, no losses have been incurred. The Partnership attempts to limit the amount of credit exposure to any one company through procedures that include credit approvals, credit limits and terms, and prepayments. The Partnership’s customer base is made up of its lessees, which are primarily major integrated and international oil and natural gas companies and other operators, though the Partnership’s credit risk may extend to the eventual purchasers of oil and natural gas produced from the Partnership’s properties. The Partnership believes the credit quality of its customer base is high and has not experienced significant write-offs in its accounts receivable balances. See Note 8 – Significant Customers for further discussion. Derivative instruments may expose the Partnership to credit risk. However, the Partnership monitors the creditworthiness of its counterparties.

Accounts receivable: The Partnership’s accounts receivable balance results primarily from operators’ sales of oil and natural gas to their customers. Accounts receivable is recorded at the contractual amounts and do not bear interest. Any concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions impacting the oil and natural gas industry.

Derivatives and financial instruments: The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the given commodity price risk associated with its operations, the Partnership uses derivative instruments. From time to time, such instruments may include variable–to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership does not enter into derivative instruments for speculative purposes.

Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivative instruments.

Oil and natural gas properties: The Partnership follows the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred. Acquired mineral and royalty interests and working interests are recorded at cost at the time of acquisition.

The costs of unproved leaseholds and mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved leaseholds are determined to be proved, the related costs are transferred to proved properties. Unproved and non-producing property costs are assessed periodically, on a property-by-property basis, and an impairment loss is recognized to the extent, if any, the recorded value has been impaired. Mineral interests are assessed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. This assessment is performed by comparing carrying values to valuation estimates and impairment is recognized to the extent that book value exceeds estimated recoverable value. Any impairment will generally be based on geographic or geologic data and our estimated future cash flows related to our properties.

As exploration and development work progresses and the reserves associated with the Partnership’s properties become proven, capitalized costs attributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties is recorded based on the units-of-production method. Acquisition costs of proved properties are amortized on the basis of all proved reserves, both developed and undeveloped, and capitalized development costs are amortized on the basis of proved developed reserves. Proved reserves are quantities of oil and natural gas that can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations. DD&A expense related to the Partnership’s producing oil and natural gas properties was $102.4 million, $102.7 million and $109.9 million for the years ended December 31, 2016, 2015, and 2014, respectively.

The Partnership evaluates impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. This evaluation is performed on a depletable unit basis. The Partnership compares the undiscounted projected future cash flows expected in connection with a depletable unit to the carrying amount to determine recoverability. When the carrying amount of a depletable unit exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future capital expenditures, and a risk-adjusted discount rate.

Impairment of proved oil and natural gas properties was $4.9 million, $127.8 million and $117.9 million for the years ended December 31, 2016, 2015, and 2014, respectively. The impairment primarily resulted from declines in future expected realizable net cash flows. The charges are included in impairment of oil and natural gas properties on the consolidated statements of operations and reflected in the net book value of oil and natural gas properties.

The carrying value of unproved properties, including unleased mineral rights, is periodically assessed for impairment using management’s assessment of fair value. The factors used to determine fair value are similar to those previously noted for proved properties. Impairment of unproved properties was $1.9 million and $121.8 million for the years ended December 31, 2016 and 2015, respectively. There was no impairment of unproved properties for the year ended December 31, 2014.

Upon the sale of complete fields of depreciable or depletable property, the book value thereof, less proceeds or salvage value is charged to income. On sale or retirement of an individual well, the proceeds are credited to accumulated DD&A.

Other property and equipment: Other property and equipment includes furniture, fixtures, office equipment, leasehold improvements, and computer software and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Depreciation and amortization expense totaled $0.1 million, $1.6 million, and $2.1 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Repairs and maintenance: The cost of normal maintenance and repairs is charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the shorter of the estimated remaining useful life of the asset or the term of the lease, if applicable.

Accrued liabilities: Accrued liabilities consisted of the following as of December 31, 2016 and 2015:



	As of December 31,
	2016		2015
Accrued liabilities:
Accrued capital expenditures	$	17,775	$	20,494
Accrued incentive compensation	20,898		16,554
Accrued legal	—		7,000
Accrued severance	—		3,889
Accrued property taxes	3,175		3,699
Accrued other	9,104		6,367
TOTAL ACCRUED LIABILITIES	$	50,952	$	58,003

Debt issuance costs: Debt issuance costs consist of costs directly associated with obtaining credit with financial institutions. These costs are capitalized and are amortized on a straight-line basis over the life of the credit agreement, which approximates the effective-interest method. Any unamortized debt issue costs are expensed in the year when the associated debt instrument is terminated. Amortization expense for debt issue costs was $0.9 million, $0.9 million, and $1.0 million for the years ended December 31, 2016, 2015, and 2014, respectively, and is included in interest expense in the consolidated statements of operations.

Asset retirement obligations: Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred and becomes determinable. When the liability is initially recorded, the Partnership capitalizes this cost by increasing the carrying amount of the related property and equipment. Over time, the liability is accreted for the change in its present value, and the capitalized cost in oil and natural gas properties is depleted based on units of production consistent with the related asset.

Revenue recognition: The Partnership recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.

The Partnership recognizes oil and natural gas revenue from its interests in producing wells when the associated production is sold. The volumes of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves, net to the Partnership, will not be sufficient to enable the under-produced owner to recoup its entitled share through production; however, such amounts are de minimis at December 31, 2016 and 2015. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis.

Other sources of revenue received by the Partnership includes mineral lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to other exploration and production companies. The lease agreements generally transfer the rights to any oil or natural gas discovered, grant the Partnership a right to a specified royalty interest, and require that drilling and completion operations commence within a specified time period. The Partnership recognizes such lease bonus revenue at which time the lease agreement has been executed, payment is determined to be collectable, and the Partnership has no further obligation to refund the payment. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been collected, and the Partnership has no further obligation to refund the payment.

Income taxes: The Partnership is organized as a pass-through entity for income tax purposes. As a result, the Partnership’s unitholders are responsible for federal and state income taxes attributable to their share of the Partnership’s taxable income. The Partnership is subject to other state-based taxes; however, those taxes are not material.

Limited partnerships that receive at least 90% of their gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are classified as “passive entities” and are generally exempt from the Texas margin tax. The Partnership believes that it meets the requirements for being considered a “passive entity” for Texas margin tax purposes. As a result, each unitholder that is considered a taxable entity under the Texas margin tax would generally be required to include its portion of the Partnership’s revenues in its own Texas margin tax computation. The Texas Administrative Code provides such income is sourced according to the principal place of business of the Partnership, which would be the state of Texas.

Fair value of financial instruments: The carrying values of the Partnership’s current financial instruments, which include cash and cash equivalents, accounts receivable and accounts payable, approximate their fair value at December 31, 2016 and 2015 due to the short-term maturity of these instruments. See Note 6 – Fair Value Measurement for further discussion.

Incentive compensation: Incentive compensation includes both equity-based awards and liability awards. The Partnership recognizes compensation expense associated with its incentive compensation awards using either straight-line or accelerated attribution over the requisite service period (generally the vesting period of the awards) depending on the given terms of the award, based on their grant-date fair values. Incentive compensation expense is charged to general and administrative expense.

Liability awards are awards that are expected to be settled in cash or an unknown number of common or subordinated units on their vesting dates. Liability awards are recorded as accrued liabilities based on the vested portion of the estimated fair value of the awards as of the grant date, which is subject to revision based on the impact of certain performance conditions associated with the incentive plans. The Partnership may also recognize liability awards as a result of repurchase options given to the recipients participating in certain incentive plans.

Compensation expense for unit-based awards subsequent to the Partnership’s initial public offering is measured by the price of the unit at the measurement date, which is generally the date of grant, and is recognized in general and administrative expense over the requisite service period. Prior to the initial public offering, the Predecessor was privately held and determining the fair value required the Predecessor to make complex and subjective judgments. The Board determined the fair value of the equity-based awards’ unit price prior to the Partnership’s initial public offering by considering various objective and subjective factors, along with input from management. To determine the fair value of the Predecessor, the Predecessor considered information provided by third-party consultants and relied on generally accepted valuation techniques, which included, but were not limited to, the net asset value method under the asset approach, the guideline public company method under the market approach, and the dividend discount method of the income approach. These methods were dependent upon various assumptions to develop the estimates in the Predecessor’s operating results, commodity prices, and market-based discount rates. The Predecessor also considered publicly available information on comparable public companies and the Predecessor’s historical transactions and performance in making these estimates. The Predecessor’s limited partnership agreement contained an annual repurchase obligation of 1% of the outstanding units. An annual valuation of the Predecessor was required to establish a value basis for the repurchase obligation. The Predecessor utilized the same valuation for repurchases and issuances of equity, if any, and as the basis for calculating the fair value of its equity awards under its long-term incentive plans.

New accounting pronouncements: The JOBS Act provides that an emerging growth company can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have irrevocably elected to “opt out” of this exemption and therefore will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.

In May 2014, the Financial Accounting Standards Board (the “FASB”) issued an accounting standards update on a comprehensive new revenue recognition standard that will supersede Accounting Standards Codification (“ASC”) 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up adjustment as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. In July 2015, the FASB decided to defer the original effective date by one year to be effective for annual reporting periods beginning after December 15, 2017 instead of December 15, 2016 for public entities, with early adoption permitted. The Partnership intends to use the modified retrospective adoption approach. Based on current evaluations to-date, the Partnership does not anticipate this new guidance will have a material impact on its consolidated financial statements. The Partnership is continuing to evaluate the disclosure requirements of this new guidance and does not plan on early adopting this guidance.

In February 2016, the FASB issued Accounting Standard Update (“ASU”) No. 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. The amendment will be effective for reporting periods beginning on or after December 15, 2018, and early adoption is permitted. The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-based payment accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, to address diversity in practice of how certain cash receipts and cash payments are currently presented and classified in the statement of cash flows. The ASU addresses the topic of separately identifiable cash flows and application of the predominance principle. Classification of cash receipts and payments that have aspects of more than one class of cash flows should be determined first by applying specific guidance, and then by the nature of each separately identifiable cash flow. In situations where there is an absence of specific guidance and the cash flow has aspects of more than one type of classification, the predominance principle should be applied whereby the cash flow classification should depend on the activity that is likely to be the predominant source or use of cash flows. The amendments in this ASU are effective for public business entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted. The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosure.