See accompanying notes to Consolidated Financial Statements.

See accompanying notes to Consolidated Financial Statements.

See accompanying notes to Consolidated Financial Statements.

See accompanying notes to Consolidated Financial Statements.

Note 1 – Organization

Carbon Natural Gas Company (“Carbon” or the “Company”) is an independent oil and gas company engaged in the exploration, development and production of oil and natural gas in the United States. The Company’s business is comprised of the assets and properties of Nytis Exploration (USA) Inc. (“Nytis USA”) and its subsidiary Nytis Exploration Company LLC (“Nytis LLC”) which conducts the Company’s operations in the Appalachian and Illinois Basins, in addition to its subsidiary, Carbon California Operating Company, LLC which conducts the Company’s operations in California and the Company’s equity investment in Carbon California Company, LLC. Collectively, Carbon California Operating Company, LLC and Carbon California Company, LLC are referred to as Carbon California and collectively Carbon, Nytis USA, Nytis LLC and Carbon California are referred to as the Company.

Note 2 – Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited Consolidated Financial Statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of March 31, 2017 and the Company’s results of operations and cash flows for the three months ended March 31, 2017 and 2016. Operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, the unaudited Consolidated Financial Statements and the notes thereto should be read in conjunction with the Company’s audited Consolidated Financial Statements for the year ended December 31, 2016 filed on Form 10-K with the Securities and Exchange Commission (“SEC”).

In the course of preparing the unaudited Consolidated Financial Statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and accordingly, actual results could differ from amounts initially established.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of Carbon, Nytis USA and its consolidated subsidiary. Carbon owns 100% of Nytis USA. Nytis USA owns approximately 99% of Nytis LLC.

Nytis LLC also holds an interest in various oil and gas partnerships. For partnerships where the Company has a controlling interest, the partnerships are consolidated. The Company is currently consolidating on a pro-rata basis 46 partnerships. In these instances, the Company reflects the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on its Consolidated Statements of Operations and also reflects the non-controlling ownership interests in the net assets of the partnerships as non-controlling interests within stockholders’ equity on its Consolidated Balance Sheets. All significant intercompany accounts and transactions have been eliminated.

In accordance with established practice in the oil and gas industry, the Company’s unaudited Consolidated Financial Statements also include its pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which the Company has a non-controlling interest.

Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when the Company has the ability to significantly influence the operating decisions of the investee. When the Company does not have the ability to significantly influence the operating decisions of an investee, the cost method is used. All transactions, if any, with investees have been eliminated in the accompanying Consolidated Financial Statements.

Note 2 – Summary of Significant Accounting Policies (continued)

Accounting for Oil and Gas Operations

The Company uses the full cost method of accounting for oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized.

Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. The Company assesses its unproved properties for impairment at least annually. Significant unproved properties are assessed individually.

Capitalized costs are depleted by an equivalent unit-of-production method, converting oil to gas at the ratio of one barrel of oil to six thousand cubic feet of natural gas. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.

No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.

The Company performs a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds the capitalized costs in future periods.

For the three months ended March 31, 2017, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitation. For the three months ended March 31, 2016, the Company recognized a ceiling test impairment of approximately $3.9 million as the Company’s full cost pool exceeded its ceiling limitation. Future declines in oil and natural gas prices, and increases in future operating expenses and future development costs could result in additional impairments of our oil and gas properties in future periods. The effects of low commodity prices may continue to impact the ceiling test value until such time prices stabilize or improve. Impairment charges are a non-cash charge and accordingly, do not affect cash flow, but adversely affect our net income and stockholders’ equity.

Investments in Affiliates

Investments in non-consolidated affiliates are accounted for under either the equity or cost method of accounting as appropriate. The cost method of accounting is used for investments in affiliates in which the Company has less than 20% of the voting interests of a corporate affiliate or less than a 3% to 5% interest of a partnership or limited liability company and does not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and impairment assessments for each investment are made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs. If the Company holds between 20% and 50% of the voting interest in non-consolidated corporate affiliates or greater than a 3% to 5% interest of a partnership or limited liability company and exercises significant influence or control, the equity method of accounting is used to account for the investment. The Company’s investment in affiliates that is accounted for using the equity method of accounting, increases or decreases by the Company’s share of the affiliate’s profits or losses and such profits or losses are recognized in the Company’s Consolidated Statements of Operations. The Company reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. The amount of the impairment is based on quoted market prices, where available, or other valuation techniques.

Note 2 – Summary of Significant Accounting Policies (continued)

Related Party Transactions

On February 15, 2017, the Company entered into an amended and restated limited liability company agreement of Carbon California. Pursuant to the limited liability agreement, the Company was reimbursed $575,000 from Carbon California for due diligence costs incurred on behalf of Carbon California and allocated general and administrative expense in connection with its role of manager of Carbon California. This amount was recorded as a reduction of general and administrative expenses for the three months ended March 31, 2017. See Note 5 for additional information.

Warrant Derivative Liability

The Company issued a warrant related to its investment in Carbon California. The Company accounts for this warrant in accordance with guidance contained in ASC 815, Derivatives and Hedging , which requires this warrant to be recorded on the balance sheet as either an asset or a liability measured at its fair value, with changes in fair value recognized in earnings. Based on this guidance, the Company determined that the Company’s warrant does not meet the criteria for classification as equity. Accordingly, the Company classified the warrant as a liability. The warrant is subject to remeasurement at each balance sheet date, with any change in the fair value recognized as a component of other income or expense, net in the statement of operations.

Asset Retirement Obligations

The Company’s asset retirement obligations (“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability.

The estimated ARO liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3 fair value measurement inputs.

The following table is a reconciliation of the ARO for the three months ended March 31, 2017 and 2016:

Note 2 – Summary of Significant Accounting Policies (continued)

Earnings Per Common Share

Basic earnings or loss per common share is computed by dividing the net income or loss attributable to common shareholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to certain officers, directors and employees of the Company are included in the computation of basic net income or loss per share only after the shares become fully vested. Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of options and warrants to acquire common stock, computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of warrants (which were assumed to have been made at the average market price of the common shares during the reporting period).

The following table sets forth the calculation of basic and diluted income (loss) per share:

For the quarter ended March 31, 2017, the Company had net income and the diluted net income per share calculation for that period includes the dilutive effect of approximately 306,000 non-vested shares of restricted stock and approximately 432,000 in-the-money warrants. In addition, approximately 13,000 out-of-the-money warrants and approximately 296,000 restricted performance units, subject to future contingencies, were excluded from the basic and diluted loss per share calculations.

For the quarter ended March 31, 2016, the Company had a net loss and therefore, the diluted net loss per share calculation for that period excludes the anti-dilutive effect of approximately 13,000 warrants and approximately 289,000 non-vested shares of restricted stock. In addition, approximately 296,000 restricted performance units, subject to future contingencies, were excluded from the basic and diluted loss per share calculations.

Note 2 – Summary of Significant Accounting Policies (continued)

Adopted and Recently Issued Accounting Pronouncements

In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Improvements To Employee Share-Based Payment Accounting (“ASU 2016-09”). The objective of this ASU is to simplify several aspects of the accounting for employee share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities and classification in the statement of cash flows. ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Portions of this ASU must be applied prospectively while other portions may be applied either prospectively or retrospectively. The Company adopted this standard on January 1, 2017.

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”). The objective of this ASU is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and should be applied using a modified retrospective approach. Early adoption is permitted. The Company is currently evaluating the impact on its consolidated financial statements of adopting ASU 2016-02.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-20, which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. These ASUs are effective for fiscal years, and interim periods within those years beginning after December 31, 2017. The standards permit retrospective application using either of the following methodologies: (1) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect adjustment as of the date of initial application. The Company plans to adopt these ASUs effective January 1, 2018. Although the Company is still in the process of assessing its contracts with customers and evaluating the effect of adopting these standards, as well as the transition method to be applied, the adoption is not expected to have a significant impact on the Company’s consolidated financial statements other than additional disclosures.

Note 3 – Acquisitions and Divestitures

In October 2016, Nytis LLC completed an acquisition (the “EXCO Acquisition”) consisting of producing natural gas wells and natural gas gathering facilities located in the Company’s Appalachian Basin operating area. The natural gas gathering facilities are primarily used to gather the Company’s natural gas production. The acquisition was pursuant to a purchase and sale agreement, effective October 1, 2016 (the “EXCO Purchase Agreement”) by and among EXCO Production Company (WV), LLC, BG Production Company (WV), LLC and EXCO Resources (PA) LLC (collectively, the “Sellers”) and Nytis LLC, as the buyer. The purchase price of the acquired assets pursuant to the EXCO Purchase Agreement was $9.0 million subject to customary closing adjustments plus certain assumed obligations.

The EXCO Acquisition provided the Company with proved developed reserves, production and operating cash flow in a location where the Company has similar assets.

EXCO Acquisition Unaudited Pro Forma Results of Operations

Below are consolidated results of operations for the quarters ended March 31, 2017 and 2016 as though the EXCO Acquisition had been completed as of January 1, 2016. The EXCO Acquisition closed October 3, 2016, and accordingly, the Company’s consolidated statement of operations for the quarter ended March 31, 2017 includes the results of operations for the three months ended March 31, 2017 of the EXCO properties acquired.

As of March 31, 2017 and December 31, 2016, the Company had approximately $2.0 million of unproved oil and gas properties not subject to depletion. The costs not subject to depletion relate to unproved properties that are excluded from amortized capital costs until it is determined whether or not proved reserves can be assigned to such properties. The excluded properties are assessed for impairment at least annually. Subject to industry conditions, evaluation of most of these properties and the inclusion of their costs in amortized capital costs is expected to be completed within five years.

During the three months ended March 31, 2017 and 2016, the Company capitalized general and administrative expenses applicable to development and exploration activities of approximately $75,000 and $133,000, respectively.

Depletion expense related to oil and gas properties for the three months ended March 31, 2017 and 2016 was approximately $533,000, or $0.41 per Mcfe, and $472,000, or $0.79 per Mcfe, respectively. Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the three months ended March 31, 2017 and 2016 was approximately $40,000 and $31,000, respectively.

Note 5 – Equity Method Investment

The Company has a 50% interest in Crawford County Gas Gathering Company, LLC (“CCGGC”) which owns and operates pipelines and related gathering and treatment facilities. The Company’s gas production located in Illinois is gathered by CCGGC’s gathering facilities. The Company’s investment in CCGGC is accounted for under the equity method of accounting, and its share of income or loss is recognized. During the three months ended March 31, 2017 and 2016, the Company recorded equity method income of approximately $7,000 and nil, respectively, related to this investment. During the first quarter of 2016, the Company received a cash distribution of $275,000 from CCGGC.

On February 15, 2017, the Company entered into an amended and restated limited liability company agreement (the “Carbon California LLC Agreement”) of Carbon California, a Delaware limited liability company established by the Company. Pursuant to the Carbon California LLC Agreement, Carbon acquired a 17.8% interest in Carbon California represented by Class B Units. The Class B Units were acquired for no cash consideration.

On February 15, 2017, Carbon California (i) issued and sold Class A Units to two institutional investors for an aggregate cash consideration of $22.0 million, (ii) entered into a Note Purchase Agreement (the “Note Purchase Agreement” ) with two institutional investors for the issuance and sale of up to $25.0 million of Senior Secured Revolving Notes (the “Senior Revolving Notes” ) due February 15, 2022 and (iii) entered into a Securities Purchase Agreement (the “ Securities Purchase Agreement” ) with one institutional investor for the issuance and sale of $10.0 million of Senior Subordinated Notes (the “Subordinated Notes” ) due February 15, 2024. The Company is not a guarantor of the Senior Revolving Notes or the Subordinate Notes. The closing of the Note Purchase Agreement and the Securities Purchase Agreement on February 15, 2017, resulted in the sale and issuance by Carbon California of (i) Senior Revolving Notes in the principal amount of $10.0 million and (ii) Subordinated Notes in the original principal amount of $10.0 million. The maximum principal amount available under the Senior Revolving Notes is based upon the borrowing base attributable to Carbon California’s proved oil and gas reserves which is to be determined at least semi-annually. The current borrowing base is $15.0 million.

Note 5 – Equity Method Investment (continued)

Net proceeds from the Offering Transaction were used by Carbon California to complete the acquisitions of oil and gas assets in the Ventura Basin of California, which acquisitions also closed on February 15, 2017. The remainder of the net proceeds are being used to fund field development projects and to fund future complementary acquisitions and for general working capital purposes of Carbon California.

In connection with the Company entering into the Carbon California LLC Agreement described above and Carbon California engaging in the transactions also described above, the Company issued to an affiliate of one of the institutional investors which purchased Class A Units of Carbon California (which is also an affiliate of the Company’s largest stockholders), a warrant to purchase approximately 1.5 million shares of the Company’s common stock at an exercise price of $7.20 per share (the “Warrant”). The exercise price for the Warrant is payable exclusively with Class A Units of Carbon California and the number of shares of the Company’s common stock for which the Warrant is exercisable is determined, as of the time of exercise, by dividing (a) the aggregate unreturned capital of the warrantholder’s Class A Units of Carbon California by (b) the exercise price. The Warrant has a term of seven years and includes certain standard registration rights with respect to the shares of the Company’s common stock issuable upon exercise of the Warrant.

Based on its 17.8% interest in Carbon California and its role of manager of Carbon California, the Company is accounting for its investment in Carbon California under the equity method of accounting. For the period of February 15, 2017 through March 31, 2017, Carbon California had a net loss. Once Carbon California reports income, the Company will not record income (or losses) until the Company’s share of such income equals the amount of its share of losses not previously reported.

The Company accounts for the Warrant as the initial investment in Carbon California and a liability based on the fair value of the Warrant as of the date of grant (February 15, 2017). Future changes to the fair value of the Warrant will be recognized in earnings.

As of grant date of the Warrant, the Company estimated that the fair market value of the Warrant was approximately $5.8 million and recorded that amount to its investment in Carbon California and a long-term liability. This valuation is preliminary and may change in future time periods. As of March 31, 2017, the Company estimated that the fair value of the Warrant was approximately $4.9 million. The difference in the fair value of the Warrant from the grant date though March 31, 2017 was approximately $830,000 and was recognized in other income in the Company’s Consolidated Statements of Operations for the three months ended March 31, 2017.

Note 6 – Bank Credit Facility

In 2016, Carbon entered into a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank. LegacyTexas Bank is the initial lender and acts as administrative agent.

The credit facility has a maximum availability of $100.0 million (with a $500,000 sublimit for letters of credit), which availability is subject to the amount of the borrowing base. The initial borrowing base established under the credit facility was $17.0 million. The borrowing base is subject to semi-annual redeterminations in March and September commencing March 2017. On March 30, 2017, the borrowing base was increased to $23.0 million.

Note 6 – Bank Credit Facility (continued)

The credit facility is guaranteed by each existing and future direct or indirect subsidiary of Carbon (subject to certain exceptions). The obligations of Carbon and the subsidiary guarantors under the credit facility are secured by essentially all tangible and intangible personal and real property of the Company (subject to certain exclusions).

Interest is payable quarterly and accrues on borrowings under the credit facility at a rate per annum equal to either (i) the base rate plus an applicable margin between 0.50% and 1.50% or (ii) the Adjusted LIBOR rate plus an applicable margin between 3.50% and 4.50% at Carbon’s option. The actual margin percentage is dependent on the credit facility utilization percentage. Carbon is obligated to pay certain fees and expenses in connection with the credit facility, including a commitment fee for any unused amounts of 0.50%.

The credit facility contains certain affirmative and negative covenants that, among other things, limit the Company’s ability to (1) incur additional debt; (ii) incur additional liens; (iii) sell, transfer or dispose of assets; (iv) merge or consolidate, wind-up, dissolve or liquidate; (v) make dividends and distributions on, or repurchases of, equity; (vi) make certain investments; (vii) enter into certain transactions with its affiliates; (viii) enter into sales-leaseback transaction; (ix) make optional or voluntary payment of debt; (x) change the nature of its business; (xi) change its fiscal year to make changes to the accounting treatment or reporting practices; (xii) amend constituent documents; and (xiii) enter into certain hedging transactions.

The affirmative and negative covenants are subject to various exceptions, including certain basket amounts and acceptable transaction levels. In addition, the credit facility requires Carbon’s compliance, on a consolidated basis, with (i) maximum funded Debt/EBITDA ratio of 3.5 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0, commencing with the quarter ended March 31, 2017. The Company was in compliance with the financial covenants associated with the credit facility as of March 31, 2017.

Carbon may at any time repay the loans under the credit facility, in whole or in part, without penalty. Carbon must pay down borrowings under the credit facility or provide mortgages of additional oil and natural gas properties to the extent that outstanding loan and letters of credit exceed the borrowing base.

As required under the terms of the credit facility, the Company established pricing for a certain percentage of its production through the use of derivative contracts. The Company is party to an ISDA Master Agreement with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility.

As of March 31, 2017, there were approximately $15.5 million in outstanding borrowings and approximately $7.5 million of additional borrowing capacity available under the credit facility. The Company’s effective borrowing rate at March 31, 2017 was approximately 5.75%.

Note 7 – Income Taxes

The Company recognizes deferred income tax assets and liabilities for the estimated future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. The Company has net operating loss carryforwards available in certain jurisdictions to reduce future taxable income. Future tax benefits for net operating loss carryforwards are recognized to the extent that realization of these benefits is considered more likely than not. To the extent that available evidence raises doubt about the realization of a deferred income tax asset, a valuation allowance is established.

At March 31, 2017, the Company has established a full valuation allowance against the balance of net deferred tax assets.

Note 8 – Stockholders’ Equity

Authorized and Issued Capital Stock

Effective March 15, 2017 and pursuant to a reverse stock split approved by the shareholders and Board of Directors, each 20 shares of issued and outstanding common stock became one share of common stock and no fractional shares were issued. References to the number of shares and price per share give retroactive effect to the reverse stock split for all periods presented.

As of March 31, 2017, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which approximately 5.5 million were issued and outstanding and 1,000,000 shares of preferred stock authorized with a par value of $0.01 per share, none of which were issued and outstanding. During the first three months of 2017, the increase in the Company’s issued and outstanding common stock was a result of restricted stock that vested during the period.

Equity Plans Prior to Merger

Pursuant to the merger of Nytis USA with and into the Company in 2011, all options, warrants and restricted stock were adjusted to reflect the conversion ratio used in the merger. As of March 31, 2017, the Company has 12,500 warrants outstanding and exercisable related to these plans.

Nytis USA Restricted Stock Plan

As of March 31, 2017, all of restricted stock issued under the Nytis USA Restricted Stock Plan (“Nytis USA Plan”) have vested. The Company accounted for these grants at their intrinsic value. From the date of grant through March 31, 2013, the Company estimated that none of these shares would vest and accordingly, no compensation cost had been recorded through March 31, 2013.

In June 2013, the vesting terms of these restricted stock grants were modified so that 25% of the shares would vest on the first of January from 2014 through 2017. As such, the Company recognized compensation expense for those restricted stock grants based on the fair value of the shares on the date the vesting terms were modified. Compensation expense recognized for those restricted stock grants was nil and approximately $84,000 for the three months ended March 31, 2017 and 2016, respectively. As of March 31, 2017, compensation costs relative to those restricted stock grants were fully recognized.

Carbon Stock Incentive Plans

The Company has two stock plans, the Carbon 2011 and 2015 Stock Incentive Plans (collectively the “Carbon Plans”). The Carbon Plans were approved by the shareholders of the Company and in the aggregate provide for the issuance of approximately 1.1 million shares of common stock to Carbon officers, directors, employees or consultants eligible to receive these awards under the Carbon Plans.

The Carbon Plans provide for granting Director Stock Awards to non-employee directors and for granting Incentive Stock Options, Non-qualified Stock Options, Restricted Stock Awards, Performance Awards and Phantom Stock Awards, or a combination of the foregoing, as is best suited to the circumstances of the particular employee, officer, director or consultant.

Restricted Stock

During the three months ended March 31, 2017, approximately 81,000 shares of restricted stock were granted under the terms of the Carbon Plan in addition to 462,000 shares granted during previous years. For employees, these restricted stock awards either vest ratably over a three-year service period or cliff vest after a three year service period. For non-employee directors the awards vest upon the earlier of a change in control of the Company or the date their membership on the Board of Directors is terminated other than for cause. The Company recognizes compensation expense for these restricted stock grants based on the estimated grant date fair value of the shares, amortized ratably over three years for employee awards (based on the required service period for vesting) and seven years for non- employee director awards (based on a market survey of the average tenure of directors among U.S. public companies). As of March 31, 2017, approximately 236,000 of these restricted stock grants have vested.

Note 8 – Stockholders’ Equity (continued)

Restricted Stock (continued)

Compensation costs recognized for these restricted stock grants were approximately $188,000 and $201,000 for the three months ended March 31, 2017 and 2016, respectively. As of March 31, 2017, there was approximately $1.1 million of unrecognized compensation costs related to these restricted stock grants. This cost is expected to be recognized over the next six years.

Restricted Performance Units

As of March 31, 2017, approximately 401,000 shares of restricted performance units have been granted under the terms of the Carbon Plan. The performance units represent a contractual right to receive one share of the Company’s common stock subject to the terms and conditions of the agreements including the achievement of certain performance measures relative to a defined peer group or the growth of certain performance measures over a defined period of time for the Company as well as the lapse of forfeiture restrictions pursuant to the terms and conditions of the agreements, including for certain of the grants, the requirement of continuous employment by the grantee prior to a change in control of the Company. Based on the relative achievement of performance, approximately 296,000 restricted performance units are outstanding as of March 31, 2017.

The Company accounts for the performance units granted during 2012 and 2014 through 2016 at their fair value determined at the date of grant. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At March 31, 2017, the Company estimated that none of the performance units granted in 2012 and 2016 would vest due to change in control and other performance provisions and accordingly, no compensation cost has been recorded for these performance units. At September 30, 2016, the Company estimated that it was probable that certain of the performance units granted in 2014 and 2015 would vest. Compensation costs of approximately $132,000 and nil related to these performance units were recognized for the three months ended March 31, 2017 and 2016, respectively. As of March 31, 2017, if change in control and other performance provisions pursuant to the terms and conditions of these agreements are met in full, the estimated unrecognized compensation cost related to the performance units granted in 2012 and 2014 through 2016 would be approximately $1.9 million.

The performance units granted in 2013 contain specific vesting provisions, no change in control provisions nor any performance conditions other than stock price performance. Due to different earning requirements compared to the performance units granted in 2012 and 2014 through 2016, the Company recognized compensation expense for the performance units granted in 2013 based on the grant date fair value of the performance units, amortized ratably over three years (the performance period). The fair value of the performance units granted in 2013 was estimated using a Monte Carlo simulation (“MCS”) valuation model using the following key assumptions: no expected dividends, volatility of our stock and those of defined peer companies used to determine our performance relative to the defined peer group, a risk free interest rate and an expected life of three years. Compensation costs recognized for these performance unit grants were approximately nil and $86,000 for the three months ended March 31, 2017 and 2016, respectively. As of March 31, 2017, compensation costs relative to these performance units have been fully recognized.

Note 10 – Fair Value Measurements

Authoritative guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available under the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s policy is to recognize transfers in and/or out of the fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below for all periods presented.

As of March 31, 2017, the Company’s commodity derivative financial instruments are comprised of eight natural gas and nine oil swap agreements. The fair values of these agreements are determined under an income valuation technique. The valuation requires a variety of inputs, including contractual terms, published forward prices, volatilities for options, and discount rates, as appropriate. The Company’s estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value of money. The consideration of these factors resulted in an estimated exit-price for each derivative asset or liability under a market place participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy. The counterparty for all of the Company’s commodity financial instruments as of March 31, 2017 is BP Energy Company.

Level 3 Fair Value Measurements

A third-party valuation specialist is utilized to determine the fair value of the Company’s warrant designated as Level 3. The Company reviews this valuation, including the related model inputs and assumptions, and analyzes changes in fair value measurements between periods. The Company corroborates such inputs, calculations and fair value changes using various methodologies, and reviews unobservable inputs for reasonableness utilizing relevant information from other published sources.

The Company estimated the fair value of the Company’s warrant designated as Level 3 on February 15, 2017, the grant date of the warrant, to be approximately $5.8 million, using a call option pricing model with the following assumptions: a seven-year term, exercise price of $7.20, volatility rate of 41.8% and a risk free rate of 2.3%. The Company remeasured the warrant as of March 31, 2017, using the same call option pricing model, using the following assumptions: a term of 6.9 years, exercise price of $7.20, volatility rate of 39.3% and a risk free rate of 2.2%. As of March 31, 2017, the fair value of the warrant was approximately $4.9 million.

Assets Measured and Recorded at Fair Value on a Non-recurring Basis

The fair value of the following liabilities measured and recorded at fair value on a non-recurring basis are based on unobservable pricing inputs and therefore, are included within the Level 3 fair value hierarchy.

The Company uses the income valuation technique to estimate the fair value of asset retirement obligations using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money. During the three months ended March 31, 2017 and 2016, the Company recorded asset retirement obligations for additions of approximately $3,000 and $5,000 respectively. See Note 2 for additional information.

Note 11 – Physical Delivery Contracts and Oil and Gas Derivatives

The Company has historically used commodity-based derivative contracts to manage exposures to commodity price on certain of its oil and natural gas production. The Company does not hold or issue derivative financial instruments for speculative or trading purposes. The Company also enters into, on occasion, oil and natural gas physical delivery contracts to effectively provide commodity price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded at fair value in the unaudited Consolidated Financial Statements.

Pursuant to the terms of the Company’s credit facility with LegacyTexas Bank, the Company has entered into swap derivative agreements to hedge certain of its oil and natural gas production for 2017 through 2019. As of March 31, 2017, these derivative agreements consisted of the following:

(a) NYMEX Henry Hub Natural Gas futures contract for the respective delivery month.

(b) NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective delivery month

For its swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

The following table summarizes the fair value of the derivatives recorded in the unaudited Consolidated Balance Sheets.

These derivative instruments are not designated as cash flow hedging instruments for accounting purposes:

The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the three months ended March 31, 2017 and 2016. These commodity derivative settlements and unrealized gains and losses are recorded and included in commodity derivative income or loss in the accompanying Consolidated Statements of Operations.

Note 11 – Physical Delivery Contracts and Oil and Gas Derivatives (continued)

Commodity derivative settlement gains and losses are included in cash flows from operating activities in the Company’s unaudited Consolidated Statements of Cash Flows.

The counterparty in all of the Company’s derivative instruments is BP Energy Company. The Company has entered into an ISDA Master Agreement with BP Energy Company that establishes standard terms for the derivative contracts and an inter-creditor agreement with LegacyTexas Bank and BP Energy Company whereby any credit exposure related to the derivative contracts entered into by the Company and BP Energy Company is secured by the collateral and backed by the guarantees supporting the credit facility.

The Company nets its derivative instrument fair value amounts executed with is its counterparty pursuant to an ISDA master agreement, which provides for the net settlement over the term of the contracts and in the event of default or termination of the contracts. The following table summarizes the location and fair value amounts of all derivative instruments in the unaudited Consolidated Balance Sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited Consolidated Balance Sheet as of March 31, 2017.

Due to the volatility of oil and natural gas prices, the estimated fair values of the Company’s derivatives are subject to large fluctuations from period to period.

Note 12 – Commitments

The Company has entered into employment agreements with certain executives and officers of the Company. The term of the agreements generally range from one to two years and provide for renewal provisions in one year increments thereafter. The agreements provide for, among other items, severance and continuation of benefit payments upon termination of employment or certain change of control events.

The Company has entered into long-term firm transportation contracts to ensure the transport for certain of its gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at March 31, 2017 are summarized in the table below.

A liability of approximately $682,000 related to firm transportation contracts assumed in asset acquisitions, which represents the remaining commitment, is reflected on the Company’s unaudited Consolidated Balance Sheet as of March 31, 2017. The fair value of these firm transportation obligations were determined based upon the contractual obligations assumed by the Company and discounted based upon the Company’s effective borrowing rate. These contractual obligations are being amortized on a monthly basis as the Company pays these firm transportation obligations in the future.