The condensed consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.  The Company prepares its condensed consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("(“US GAAP"GAAP”).

In our opinion, the unaudited condensed consolidated financial statements contained herein reflect all adjustments, consisting solely of normal recurring items, which are necessary for the fair presentation of the Company's financial position, results of operations, and cash flows on a basis consistent with that of its prior audited financial statements.  However, the results of operations for interim periods may not be indicative of results to be expected for the full fiscal year.

Based on the current demand for oil and natural gas, the availability of other buyers and the Company having the option to sell to other buyers if conditions warrant, the Company believes that itsour oil, natural gas, and gasNGL production can be sold in the market in the event that it is not sold to the Company’s existing customers.

Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table:

The Company operates exclusively within the United States of America, and except for cash and short-term investments,cash equivalents, all of the Company’s assets are utilized in, and all of itsour revenues are derived from, the oil and gas industry.

In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, "Improvements“Improvements to Employee Share-Based Payment Accounting" ("Accounting” (“ASU 2016-09"2016-09”), which intends to improve the accounting for share-based payment transactions. The ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We adopted this pronouncement effective January 1, 2017. Upon adoption of this standard, we no longer estimate the total number of awards for which the requisite service period will not be rendered, and effective January 1, 2017, we began accounting for forfeitures when they occur. We applied this accounting change on a modified retrospective basis with a cumulative-effect adjustment of $0.1 million to retained earnings as of the date of adoption. The adoption of the other provisions did not materially impact the consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASU 2016-02"), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees

In May 2014, the FASB issued ASU 2014-09, "Revenue“Revenue from Contracts with Customers (Topic 606)" ("” (“ASU 2014-09"2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 (collectively with ASU 2014-09, allowsthe "Revenue ASUs") to clarify principal versus agent considerations. The Revenue ASUs allow for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period, with early adoption permitted for annual reporting periods beginning after December 15, 2016. Currently, we have not identified any contracts that would require a change from the entitlements method, historically used for certain domestic natural gas sales, to the sales method of accounting. We are currently evaluating which transition approachcontinuing to useevaluate the provisions of these ASUs as pertinent to certain sales contracts and, the impact of the adoption of this standard on our condensed consolidated financial statements.in particular, as they relate to disclosure requirements.

There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.

The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):

The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds

As a strategy, theThe Company seeks to acquire developed and undeveloped oil and gas properties, primarily in the core Wattenberg Field. The objective of these acquisitions is to provide additional mineral acres upon which the Company can drill wells and produce hydrocarbons.

In June 2017, we executed a purchase and sale agreement with a private party for the acquisition of approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $21 million, net of customary closing adjustments. The Company acquired certaintransaction is expected to close in the third quarter of 2017. We also entered into a separate agreement with another party to trade approximately 4,000 net acres of the Company's non-contiguous acreage for approximately 4,000 net acres within the Company's core operating area. This transaction is also expected to close

In March 2017, we closed an acquisition comprised primarily of developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.0 million, composed of cash and other assets that affect the comparability between the nine months ended September 30, 2016 and 2015, as described below.assumed liabilities.

DuringIn August and October 2016, the Company completed twofour acquisitions of certain assets for a total purchase price of $3.9$13.5 million, composed of cash, forgiven receivables, and assumed liabilities. The acquired properties were comprised primarily of undeveloped oil and gas leasehold interests.interests and additional interests in developed properties operated by the Company.

OnIn May 2, 2016, we entered into a purchase and sale agreement ("GC(the "GC Agreement") with a large publicly-traded company pursuant to which we agreed to acquire a total of approximately 72,000 gross (33,100 net) acres in an area referred to as the Greeley-Crescent project in the Wattenberg Field for $505 million (the "GC Acquisition").  Estimated net daily production from the acquired properties was approximately 2,400 barrels of oil equivalent ("BOE")BOE at the time of entering into the GC Agreement.

The following table presents the unaudited pro forma combined results of operations for the three and ninesix months ended SeptemberJune 30, 2016 as if the first closing had occurred on January 1, 2015.2016.  The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired.  The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired.  The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

On February 4, 2016, the Company completed the acquisition of undeveloped oil and gas leasehold interests for a total purchase price of $10.0 million. The purchase price has been allocated as $8.6 million to proved oil and gas properties and $1.4 million to unproved oil and gas properties on a preliminary basis.properties. This allocation reflects significant use of estimates.

Depletion, depreciation, and accretionDD&A consisted of the following (in thousands):

Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter. For the three and ninesix months ended SeptemberJune 30, 2016,2017, production of 9932,969 MBOE and 3,0504,566 MBOE, respectively, represented 0.8%1.9% and 2.4%2.9% of estimated total proved reserves, respectively. For the three and ninesix months ended SeptemberJune 30, 2015,2016, production of 1,1021,010 MBOE and 2,4902,057 MBOE, respectively, represented 1.9%1.0% and 4.3%2.0% of estimated total proved reserves, respectively. DD&A expense was $9.70$8.90 per BOE and $16.71$11.16 per BOE for the three months ended SeptemberJune 30, 2017 and 2016, respectively, and 2015, respectively. For the nine months ended September 30, 2016 and 2015, DD&A expense was $10.82$8.69 per BOE and $19.37$11.36 per BOE for the six months ended June 30, 2017 and 2016, respectively.

Upon completion or acquisition of a well, the Company recognizes obligations for its oil and natural gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling site to its original use.  The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in regulations.  Changes in estimates are reflected in the obligations as they occur.  If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost.  The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands).:

Certain of the Company’s assets, including substantially all of the producing wells and developed oil and gas leases, have been designated as collateral under the Revolver. The borrowing commitment is subject to scheduled redeterminations on a semi-annual basis. If certain events occur or if the bank syndicate or the Company so elects, an unscheduled redetermination could be prepared.undertaken.

The Revolver contains covenants that, among other things, restrict the payment of dividends and limitslimit our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of estimated proved developed producing or total proved reserves as projected in the semi-annual reserve report.

  

At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes subject toat the Make-Whole Price (as defined in the Indenture) and accrued and unpaid interest.  On and after December 14, 2018, the Company may redeem all or a part of the Senior Notes at the redemption price at a specified percentage of the principal amount of the redeemed notes (104.50% for 2018, 102.25% for 2019, and 100.0%100% for 2020 and thereafter, during the twelve-month period beginning on December 14 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 109.00%109% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.

The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations:things: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities.  These covenants are subject to a number of exceptions and qualifications.

The Company has entered into commodity derivative instruments as described below. Our commodity derivative instruments may include but are not limited to "collars," "swaps," and "put" positions. Our derivative strategy, including the volume amounts, whether we utilize oil and/or natural gas instruments,volumes and commodities covered and the relevant commoditystrike prices, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in the Revolver.

A "put" option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may,

A "call" option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period.

Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price over a specified term.

The Company may, from time to time, add incremental derivatives to cover additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with fourfive counterparties and an exchange. TwoThree of

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying condensed consolidated balance sheets as commodity derivative assets or liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from contract settlement of derivatives are recorded in the condensed consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in it making or receiving a payment to or from the counterparty. Actual cash settlements can occur at either the scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s condensed consolidated statements of cash flows.

Subsequent to SeptemberJune 30, 2016,2017, the Company added the following positions:

As of SeptemberJune 30, 20162017 and December 31, 2015,2016, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of either party, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that, in the event of an early termination, each party has the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its condensed consolidated balance sheets.

The amount of gain (loss) recognized in the condensed consolidated statements of operations related to derivative financial instruments was as follows (in thousands):

Realized gains and losses include cash received from the monthly settlement of derivative contracts at their scheduled maturity date the proceeds from early liquidation of in-the-money derivative contracts, and the previously incurred premiums attributable to settled commodity contracts. During the nine months ended September 30, 2015, the Company liquidated oil derivatives with an average strike price of $82.79 and covering 372,500 bbls of oil and received cash settlements of approximately $20.5 million. The following table summarizes derivative realized gains and losses during the periods presented (in thousands):

As of SeptemberJune 30, 2016, two2017, three of the fivesix counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the credit facility and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with the third and fourth counterparties,counterparty, which areis not lendersa lender under the credit facility, areis unsecured and dodoes not require the posting of collateral. The agreement with the fifth counterparty, which is not a lender under the credit facility, may require the posting of collateral if in a liability position. The agreement with the sixth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The Company’s non-recurring fair value measurements include unproved properties, asset retirement obligations, and purchase price allocations for the fair value of assets and liabilities acquired through business combinations. Please refer to Notes 2, 3, and 5 for further discussion of unproved properties, business combinations, and asset retirement obligations, respectively.

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free rate, inflation rates, and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period, and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. See Note 5 for additional information.

The acquisition of a group of assets in a business combination transaction requires fair value estimates for assets acquired and liabilities assumed.  The fair value of assets and liabilities acquired through business combinations is calculated using a net discounted cash flow approach for the producing properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future.  Unobservable inputs include estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, fair value is determined using market comparables. For the asset retirement liability assumed, the fair value is determined using the same inputs as described in the paragraph above. See Note 3 for additional information.

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At SeptemberJune 30, 2016,2017, derivative instruments utilized by the Company consist of puts and collars. The crude oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are primarily traded with third-party counterparties. As such, the Company has classified these instruments as Level 2.

The Company’s financial instruments consist primarily of cash and cash equivalents, cash held in escrow, accounts receivable, accounts payable, commodity derivative instruments (discussed above), notes payable, and credit facility borrowings. The carrying values of cash and cash equivalents, cash held in escrow, accounts receivable, and accounts payable are representative of their fair values due to their short-term maturities. Due to the variable interest rate paid on the credit facility borrowings, the carrying value is representative of its fair value.

The components of interest expense are (in thousands):

In addition to cash compensation, the Company may compensate employees and directors with equity-based compensation in the form of stock options, performance-vested stock units, restricted stock units, stock bonus shares, warrants, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting phase").  The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock.  Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo Model. For the periods presented, all stock-based compensation was either classified either as a component within general and administrative expense in the Company's condensed consolidated statements of operations or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool. As of June 30, 2017, there were 4,500,000 common shares authorized for grant under the 2015 Plan, of which 1,150,015 shares were remaining for future issuance.

The amount of stock-based compensation was as follows (in thousands):