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•	risks associated with drilling oil and natural gas wells;

•	the volatility of oil, natural gas and natural gas liquids (“NGL”) prices;

•	uncertainties in estimating oil, natural gas and NGL reserves;

•	the need to replace the oil, natural gas and NGL reserves the Company produces;

•	our ability to execute its growth strategy by drilling wells as planned;

•	the amount, nature and timing of capital expenditures, including future development costs, required to develop our undeveloped areas;

•	concentration of operations in the Mid-Continent region of the United States;

•	limitations of seismic data;

•	the potential adverse effect of commodity price declines on the carrying value of our oil and natural properties;

•	severe or unseasonable weather that may adversely affect production;

•	availability of satisfactory oil, natural gas and NGL marketing and transportation;

•	availability and terms of capital to fund capital expenditures;

•	amount and timing of proceeds of asset monetizations;

•	potential financial losses or earnings reductions from commodity derivatives;

•	potential elimination or limitation of tax incentives;

•	competition in the oil and natural gas industry;

•	general economic conditions, either internationally or domestically affecting the areas where we operate;

•	costs to comply with current and future governmental regulation of the oil and natural gas industry, including environmental, health and safety laws and regulations, and regulations with respect to hydraulic fracturing and the disposal of produced water; and

•	the need to maintain adequate internal control over financial reporting.

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(1)	Average daily net production for the month of December 2016.

(2)	Estimated net proved reserves as of December 31, 2016 divided by production for the month of December 2016 annualized.

(3)	Capital expenditures for the year ended December 31, 2016 on an accrual basis.

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•	the quality and quantity of available data and the engineering and geological interpretation of that data;

•	estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;

•	the accuracy of economic assumptions such as the future price of oil and natural gas; and

•	the judgment of the personnel preparing the estimates.

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•	the Corporate Reservoir Department follows comprehensive SEC-compliant internal policies to determine and report proved reserves including:

•	confirming that reserves estimates include all properties owned and are based upon proper working and net revenue interests;

•	reviewing and using data provided by other departments within the Company such as Accounting in the estimation process;

•	communicating, collaborating, analytical engineering with technical personnel of our business units;

•	comparing and reconciling the internally generated reserves estimates to those prepared by third parties.

•	reserves estimates are prepared by experienced reservoir engineers or under their direct supervision; and

•	no employee’s compensation is tied to the amount of reserves recorded.

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•	more than 25 years of practical experience in the estimation and evaluation of petroleum reserves;

•	a registered professional engineer in the state of Texas; and

•	Bachelor of Science Degree in Petroleum Engineering.

•	more than 30 years of practical experience in the estimation and evaluation of petroleum reserves;

•	a registered professional engineer in the states of Alaska, Colorado, Texas and Wyoming; and

•	Bachelor of Science Degree in Petroleum Engineering and MBA in Finance;

•	practicing consulting petroleum engineering since 2013 and over 15 years of prior industry experience;

•	licensed professional engineers in the state of Texas; and

•	Bachelor of Science Degree in Chemical Engineering

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(1)

Estimated proved reserves and the future net revenues, PV-10 and Standardized Measure were determined using a 12-month unweighted average of the first-day-of-the-month index price for each month of each year, and do not reflect actual prices at December 31, 2016 or current prices. All prices are held constant throughout the lives of the properties. The index prices and the equivalent weighted average wellhead prices used in the Company’s reserve reports are shown in the table below.

(a)	Index prices are based on average West Texas Intermediate posted prices for oil and average Henry Hub spot market prices for natural gas.

(b)	Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, and regional price differentials.

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(2)	Estimated total proved reserves and Standardized Measure attributable to noncontrolling interest for the years ended December 31, 2015 and 2014 are shown in the table below.

(3)

Standardized Measure represents the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions used to calculate PV-10. Standardized Measure differs from PV-10 as Standardized Measure includes the effect of future income taxes. At December 31, 2016, the present value of future income tax discounted at 10% was insignificant due to an excess of tax basis in the full cost pool over projected undiscounted future cash flows.

(4)

PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using 12-month average prices for the years ended December 31, 2016, 2015 and 2014. PV-10 differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of the Company’s oil and natural gas properties. PV-10 is used by the industry and by management as a reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities. It is useful because its calculation is not dependent on the taxpaying status of the entity. The following table provides a reconciliation of our Standardized Measure to PV-10:

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(1)	Prices represent actual average prices for the periods presented and do not include effects of derivative transactions.

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(1)	The Successor Company transportation costs are presented as a deduction from revenues. See “Note 3 - Summary of Significant Accounting Policies” to the accompanying consolidated financial statements.

(2)	The years ended December 31, 2015 and 2014 include $34.9 million and $33.9 million, respectively, for amounts related to shortfalls in meeting annual CO2 delivery obligations under a CO2 treating agreement as described under “—2016 Divestiture and Release from Treating Agreement” above.

(3)	Net of severance tax refunds.

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(1)	Leases remaining in effect until development efforts or production on the developed portion of the particular lease has ceased.

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•	the location of wells;

•	the method of drilling and casing wells;

•	the timing of construction or drilling activities;

•	the rates of production, or “allowables”;

•	the use of surface or subsurface waters;

•	the surface use and restoration of properties upon which wells are drilled;

•	the plugging and abandoning of wells; and

•	the notice to surface owners and other third parties.

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(i)	Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)	Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii)	Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

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•	reductions in oil, natural gas and NGL prices;

•	delays imposed by or resulting from compliance with regulatory requirements including permitting;

•	unusual or unexpected geological formations and miscalculations;

•	shortages of or delays in obtaining equipment and qualified personnel;

•	shortages of or delays in obtaining water for hydraulic fracturing operations;

•	equipment malfunctions, failures or accidents;

•	lack of available gathering facilities or delays in construction of gathering facilities;

•	lack of available capacity on interconnecting transmission pipelines;

•	lack of adequate electrical infrastructure and water disposal capacity;

•	unexpected operational events and drilling conditions;

•	pipe or cement failures and casing collapses;

•	pressures, fires, blowouts and explosions;

•	lost or damaged drilling and service tools;

•	loss of drilling fluid circulation;

•	uncontrollable flows of oil, natural gas, brine, water or drilling fluids;

•	natural disasters;

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•	environmental hazards, such as oil spills and natural gas leaks, pipeline or tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

•	high costs, shortages or delivery delays of equipment, labor or other services, or water used in hydraulic fracturing;

•	compliance with environmental and other governmental requirements;

•	adverse weather conditions such as extreme cold, fires caused by extreme heat or lack of rain, and severe storms, tornadoes or hurricanes;

•	oil and natural gas property title problems; and

•	market limitations for oil, natural gas and NGLs.

•	changes in regional, domestic and foreign supply of, and demand for, oil, natural gas and NGLs, as well as perceptions of supply of, and demand for, oil, natural gas and NGLs generally;

•	the price and quantity of foreign imports;

•	the ability of other companies to complete and commission liquefied natural gas export facilities in the U.S.;

•	U.S. and worldwide political and economic conditions;

•	the level of global and U.S. inventories;

•	weather conditions and seasonal trends;

•	anticipated future prices of oil, natural gas and NGLs, alternative fuels and other commodities;

•	technological advances affecting energy consumption and energy supply;

•	the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity;

•	natural disasters and other extraordinary events;

•	domestic and foreign governmental regulations and taxation;

•	energy conservation and environmental measures; and

•	the price and availability of alternative fuels.

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•	the accuracy of our reserve estimates;

•	the actual cost of development and production expenditures;

•	the amount and timing of actual production;

•	supply of and demand for oil, natural gas and NGLs; and

•	changes in governmental regulation or taxation.

•	evacuation of personnel and curtailment of operations;

•	damage to drilling rigs or other facilities, resulting in suspension of operations;

•	inability to deliver materials to worksites; and

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•	damage to, or shutting in of, pipelines and other transportation facilities.

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•	the prices at which oil, natural gas and NGLs are sold;

•	our proved reserves;

•	the level of oil, natural gas and NGLs we are able to produce from existing wells;

•	our ability to acquire, locate and produce new reserves; and

•	our capital and operating costs.

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•	production is less than expected;

•	the counterparty to the derivative contract defaults on its contract obligations; or

•	the actual differential between the underlying price in the derivative contract and actual prices received is materially different from that expected.

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Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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(1)	Includes shares of common stock tendered by employees in order to satisfy tax withholding requirements upon vesting of their stock awards. Shares withheld are initially recorded as treasury shares, then immediately retired.

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(1)	Includes full cost ceiling limitation impairments of $319.1 million, $657.4 million, $4.5 billion and $164.8 million for the Successor 2016 Period, the Predecessor 2016 Period and the years ended December 31, 2015 and 2014, respectively. No full cost ceiling limitation impairments were recorded for the years ended December 31, 2013 or 2012.

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(1)

Reflects the reclassification of certain debt issuance costs from other assets to long-term debt of $69.1 million, $47.4 million, $54.5 million and $73.9 million for the years ended December 31, 2015, 2014, 2013 and 2012, respectively, as a result of the retrospective adoption of ASU 2015-03 on January 1, 2016. See “Note 3 - Accounting Policies and Procedures” included in Item 8 of this report for further discussion.

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•	Overview;

•	Consolidated Results of Operations;

•	Liquidity and Capital Resources;

•	Valuation Allowance; and

•	Critical Accounting Policies and Estimates.

•	Depreciation, depletion and amortization

•	Accretion of asset retirement obligations

•	Impairment

•	Interest Expense

•	Net (loss) income

•	First Lien Credit Agreement. All outstanding obligations under the senior secured revolving credit facility (the “senior credit facility”) were canceled, and claims under the senior credit facility received their proportionate share of (a) $35.0

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Cash Collateral Account. We deposited $50.0 million of cash in an account controlled by the administrative agent to the New First Lien Exit Facility (the “Cash Collateral Account”) from the Emergence Date until the first borrowing base redetermination in October 2018 (the “Protected Period”); provided that (a) (i) $12.5 million will be released to us upon delivery of an acceptable business plan to the administrative agent, (ii) $12.5 million will be released to us upon achievement for two consecutive quarters of certain milestones set forth in the business plan and (b) to the extent the foregoing amounts are not released to us, up to $25.0 million will be released to us upon meeting a minimum 2.00:1.00 ratio of proved developed producing reserves to aggregate principal loan commitments under the New First Lien Exit Facility at any time after July 4, 2017. The $50.0 million cash collateral account was subsequently released to us in February 2017 in conjunction with the refinancing of the New First Lien Exit Facility as discussed in “Liquidity and Capital Resources.”

•

Senior Secured Notes. All outstanding obligations under the Senior Secured Notes were canceled and exchanged for approximately 13.7 million of the 18.9 million shares of the Successor Company’s Common Stock, (the “New Common Stock”) issued at emergence. Additionally, claims under the Senior Secured Notes received approximately $281.8 million principal value of New Convertible Notes, which are mandatorily convertible into approximately 15.0 million shares of New Common Stock upon the first to occur of several triggering events, one of which was the refinancing of the First Lien Exit Facility.

•

General Unsecured Claims. The Predecessor Company’s general unsecured claims, including the 8.75% Senior Notes due 2020, 7.5% Senior Notes due 2021, 8.125% Senior Notes due 2022, and 7.5% Senior Notes due 2023 (collectively, the “Senior Unsecured Notes”) and the 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, the “Convertible Senior Unsecured Notes” and together with the Senior Unsecured Notes, the “Unsecured Notes”), became entitled to receive their proportionate share of (a) approximately $36.7 million in cash, (b) approximately 5.7 million shares of New Common Stock, 5.2 million of which was issued immediately upon emergence, and (c) 4.9 million Series A Warrants and 2.1 million Series B Warrants, with initial exercise prices of $41.34 and $42.03 per share, respectively, which expire on October 4, 2022, (the “Warrants”). Approximately 4.5 million Series A Warrants and 1.9 million Series B Warrants were issued immediately upon emergence.

•

New Building Note. A note with a principal amount of $35.0 million ($36.6 million fair value on the Emergence Date), which is secured by first priority mortgages on the Company’s headquarters facility and certain other non-oil and gas real property located in downtown Oklahoma City, Oklahoma (the “New Building Note”) was issued and purchased on the Emergence Date for $26.8 million in cash, net of certain fees and expenses, by certain holders of the Unsecured Senior Notes.

•	Preferred and Common Stock. The Predecessor Company’s 7.0% and 8.5% convertible perpetual preferred stock and common stock were canceled and released under the Plan without receiving any recovery on account thereof.

•	Total production for 2016 was comprised of approximately 28.5% oil, 49.0% natural gas and 22.5% NGLs compared to 32.0% oil, 51.2% natural gas and 16.8% NGLs in 2015.

•	Reduced the total rigs drilling to one at December 31, 2016 from four at December 31, 2015.

•	Drilled 16 wells in the Mid-Continent and 10 wells in the Rockies in 2016 compared to drilling 161 wells, excluding salt water disposal wells, in the Mid-Continent and no wells in the Rockies in 2015, respectively.

•	Discontinued all remaining drilling and oilfield services operations in 2016, and as a result, our drilling and oilfield services operations no longer constituted a reportable segment in 2016.

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Transferred substantially all oil and natural gas properties and midstream assets located in the Piñon field in the WTO and $11.0 million in cash to Occidental in January 2016 in exchange for the release from all past, current and future claims and obligations under an existing 30-year treating agreement between the companies. This resulted in a substantial decrease in our marketing and midstream operations throughout 2016, and accordingly, our midstream and marketing operations no longer constituted a reportable segment at December 31, 2016.

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(1)	Prices represent actual average prices for the periods presented and do not include the impact of derivative transactions.

(2)	Excludes settlements of commodity derivative contracts prior to their contractual maturity, if any.

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(1)	Includes $57.0 million and $150.4 million of revenues attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the years ended December 31, 2015 and 2014, respectively.

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(1)

Includes $679.9 million and $51.0 million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the years ended December 31, 2015 and 2014, respectively. The expenses attributable to noncontrolling interest in consolidated VIEs include $655.9 million and $29.9 million of allocated full cost ceiling impairment for the years ended December 31, 2015 and 2014, respectively.

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•	increased the principal amount of commitments to $600.0 million from $425.0 million;

•	extended the maturity date to March 31, 2020 from February 4, 2020;

•	borrowing base determinations now include the Company’s proportionately consolidated share of proved reserves held by the Royalty Trusts;

•	reduced the interest rate from a flat base rate of LIBOR plus 4.75% per annum to a pricing grid tied to borrowing base utilization of (A) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum, or (B) the base rate plus an applicable margin that varies from 2.00% to 3.00% per annum;

•	reduced the LIBOR floor from 1% to 0%;

•	eliminated the minimum proved developing producing reserves asset coverage ratio;

•	removed the requirement to maintain $50.0 million in a cash collateral account controlled by the administrative agent;

•	eliminated the holiday from borrowing base determinations and the maximum consolidated total net leverage ratio and the minimum consolidated interest coverage ratio covenants; and

•	eliminated certain negative covenants, such as the $20.0 million liquidity requirement and the limitation on capital expenditures.

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(1)	Includes interest on long-term debt (if any) in the years which it will be incurred, and assumes debt principal amounts are outstanding until their latest contractual maturity, with no additional conversions of New Convertible Notes to common stock.

(2)	Includes drilling contracts with third-party drilling rig operators at specified day or footage rates and termination fees associated with our hydraulic fracturing services agreements. All of our drilling rig contracts contain operator performance conditions that allow for pricing adjustments or early termination for operator nonperformance.

(3)	Includes the obligation for employee and employer match contributions to the participants of our non-qualified deferred compensation plan for eligible highly compensated employees who elect to defer income exceeding the Internal Revenue Service (“IRS”) annual limitations on qualified 401(k) retirement plans.

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First Lien Credit Agreement. All outstanding obligations under the senior secured revolving credit facility (the “senior credit facility”) were canceled, and claims under the senior credit facility received their proportionate share of (a) $35.0 million in cash and (b) participation in the newly established $425.0 million reserve-based revolving credit facility (the “New First Lien Exit Facility”). Refer to Note 11 for additional information.

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Cash Collateral Account. The Company deposited $50.0 million of cash in an account controlled by the administrative agent to the New First Lien Exit Facility (the “Cash Collateral Account”) from the Emergence Date until the first borrowing base redetermination in October 2018 (the “Protected Period”); provided that (a) (i) $12.5 million will be released to the Company upon delivery of an acceptable business plan to the administrative agent, (ii) $12.5 million will be released to the Company upon achievement for two consecutive quarters of certain milestones set forth in the business plan and (b) to the extent the foregoing amounts are not released to the Company, up to $25.0 million will be released to the Company upon meeting a minimum 2.00:1.00 ratio of proved developed producing reserves to aggregate principal loan commitments under the New First Lien Exit Facility at any time after July 4, 2017.

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Senior Secured Notes. All outstanding obligations under the 8.75% Senior Secured Notes due 2020 issued in June 2015 and the $78.0 million principal 8.75% Senior Secured Notes due 2020 issued to Piñon Gathering Company, LLC (“PGC) in October 2015, (the “PGC Senior Secured Notes”) (collectively, “Senior Secured Notes”) were canceled and exchanged for approximately 13.7 million of the 18.9 million shares of common stock in the Successor Company (the “New Common Stock”) issued at emergence. Additionally, claims under the Senior Secured Notes received approximately $281.8 million principal amount of newly issued, non-interest bearing 0.00% convertible senior subordinated notes due 2020, (the “New Convertible Notes”), which are mandatorily convertible into approximately 15.0 million shares of New Common Stock upon the first to occur of several triggering events, one of which is refinancing of the New First Lien Exit Facility. Refer to Note 11 and Note 15 for additional information.

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General Unsecured Claims. The Company’s general unsecured claims, including the 8.75% Senior Notes due 2020, 7.5% Senior Notes due 2021, 8.125% Senior Notes due 2022, and 7.5% Senior Notes due 2023 (collectively, the “Senior Unsecured Notes”) and the 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, the “Convertible Senior Unsecured Notes” and together with the Senior Unsecured Notes, the “Unsecured Notes”), became entitled to receive their proportionate share of (a) approximately $36.7 million in cash, (b) approximately 5.7 million shares of New Common Stock, 5.2 million of which was issued immediately upon emergence, and (c) 4.9 million Series A Warrants, 4.5 million issued immediately upon emergence, and 2.1 million Series B Warrants, 1.9 million

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New Building Note. A note with a principal amount of $35.0 million, which is secured by first priority mortgages on the Company’s headquarters facility and certain other non-oil and gas real property located in downtown Oklahoma City, Oklahoma (the “New Building Note”) was issued and purchased on the emergence date for $26.8 million in cash, net of certain fees and expenses, by certain holders of the Unsecured Senior Notes. Refer to Note 11 for additional information.

•	Preferred and Common Stock. The Company’s existing 7.0% and 8.5% convertible perpetual preferred stock and common stock were canceled and released under the Plan without receiving any recovery on account thereof. Refer to Note 15 for additional information.

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1.	Reflects the net cash payments made upon emergence (in thousands):

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2.	Funding of $50.0 million Cash Collateral account and the funding of $2.8 million to be held in reserve by the Company for distribution to satisfy allowed general unsecured claims as specified under the Plan.

3.	Accrual for future reimbursement of the unused portion of the professional fees escrow account and other receivables.

4.	Write-off of prepaid expenses primarily related to $7.5 million of prepaid premium for the Predecessor Company’s directors and officers insurance policy.

5.	Application of a $3.8 million deposit held by a utility service toward the settlement of the utility service’s claims under the Plan.

6.	Includes a $43.8 million decrease in accrued liabilities as a result of funding an escrow account established for the payment of professional fees, partially offset by the reinstatement of certain liabilities subject to compromise as accounts payable and accrued expenses.

7.	Principal balances of $35.0 million of the New Building Note, $281.8 million of the New Convertible Notes, and the $415.0 million drawn on the New First Lien Exit Facility.

8.	Reclassification of non-qualified deferred compensation plan and gas balancing liabilities from liabilities subject to compromise to other long term obligations, as these liabilities became obligations of the Successor.

9.	Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):

10.	Release of a receivable from the Predecessor’s former director and officer as outlined in the Plan.

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11.	The following table reconciles reorganization adjustments made to Successor common stock, warrants and additional paid in capital (in thousands):

(1)	The fair value of the warrants was estimated using a Black-Scholes-Merton model with the following assumptions: implied stock price of the Successor Company; exercise price per share of $41.34 and $42.03 for Warrant classes A and B, respectively; expected volatility of 59.26%; risk free interest rate, continuously compounded, of 1.36%; and holding period of six years.

(2)

The fair value of the New Convertible Notes was estimated using a Monte Carlo simulation with the following assumptions; the implied Successor Company stock price; expected volatility of 56.06%; risk free interest rate, continuously compounded, of 1.08%; recovery rate of 15.00%; hazard rate of 12.41%; drop on default of 100.00%; and termination period after four years. The premium is the difference between the fair value of the New Convertible Notes of $445.7 million and the principal value of the New Convertible Notes of $281.8 million.

12.	Adjustments and reclassifications of derivative contracts based on their Emergence Date fair values, which were determined using the fair value methodology for commodity derivative contracts discussed in Note 6.

13.	Fair value adjustment to other current assets to record assets held for sale at their anticipated sales prices.

14.	Fair value adjustments to oil and natural gas properties, including asset retirement obligation, associated inventory, unproved acreage and seismic. See above for detailed discussion of fair value methodology.

15.

Adjustments to other property, plant and equipment to record the assets at their respective fair values on the Emergence Date. A combination of the cost approach and income approach were utilized to determine the fair values of the Company’s headquarters and other properties located in downtown Oklahoma City, Oklahoma, and the cost approach was utilized to determine the fair value of all other property, plant and equipment.

16.	Fair value adjustments to the Company’s asset retirement obligations as a result of applying fresh start accounting. Upon implementation of fresh start accounting, the Company revalued these obligations based upon updates to wells’ productive lives and application of the Successor Company’s credit adjusted risk fee rate.

17.	Fair value adjustment to record premium on the New Building Note.

18.	Cancellation of Predecessor Company’s common stock, preferred stock, treasury stock and paid-in capital.

19.	Adjustment to reset retained deficit to zero.

20.	Elimination of the Predecessor non-controlling interest.

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(1)	The Predecessor 2016 Period includes an addition for a joint interest account receivable after a determination that future collection was doubtful.

(2)	Deductions represent write-off of receivables and collections of amounts for which an allowance had previously been established. Deductions in 2015 are primarily due to the write-off of receivables in conjunction with a lawsuit settlement and deductions in 2014 are related to the sale of the Gulf Properties.

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(1)	No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately $48.9 million at December 31, 2015.

(2)	No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately $4.3 million at December 31, 2015.

(3)	No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately $20.4 million at December 31, 2015.

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(1)	Includes $16.7 million of pipe inventory costs incurred ($2.1 million in 2016, $9.6 million in 2015 and $5.0 million in 2014 and prior years).

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(1)

Impairment recorded in the Successor 2016 Period resulted from the application of fresh start accounting. Upon the application of fresh start accounting, the value of the Successor Company full cost pool was determined based upon forward strip oil and natural gas prices as of the Emergence Date. Because these prices were higher than the 12-month weighted average prices used in the full cost ceiling limitation calculation at December 31, 2016, the Successor Company incurred a ceiling test impairment.

(2)

Impairment recorded for the Predecessor Company in 2016 was due to full cost ceiling limitations recognized in each of the first three quarters of 2016. The impairments recorded in 2015 and the first two quarters of 2016 resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued throughout 2015 and the first half of 2016. The impairment recorded in the third quarter of 2016 resulted primarily from downward revisions to forecasted reserves due to a decrease in projected Mid-Continent production volumes.

(3)	Impairment in 2014 resulted from the divestiture of the Gulf Properties.

(4)

Impairment recorded in the Predecessor 2016 Period and the year ended December 31, 2015, resulted from discontinued drilling operations in its Permian region which resulted in an impairment on certain drilling assets after determining their future use was limited. During 2014, the Company recorded a $24.3 million impairment on its drilling and oilfield services assets in the Permian region as a result of fulfilling its drilling obligation with the Permian Trust in 2014 and the downward trend in oil prices that began in the second half of 2014.

(5)	Impairment in the Predecessor 2016 Period resulted from a decrease in projected Mid-Continent production volumes supporting the system’s usage.

(6)	Impairment in the Predecessor 2016 Period and the years ended December 31, 2015 and 2014 resulted from the evaluation of certain midstream pipe inventory, natural gas compressors, gas treating plants and a carbon dioxide (“CO2”) compressor station after determining that their future use was limited.

(7)	Impairment recorded on other assets in 2015, includes a $15.4 million impairment on property located in downtown Oklahoma City, Oklahoma to adjust the carrying value of the property to the agreed upon sales price for which it was later sold in 2016.

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(1)	Revisions for the Successor 2016 Period and the year ended December 31, 2015 relate primarily to changes in estimated well lives.

(2)	Liability settled or disposed for the Predecessor 2016 Period includes $34.1 million associated with the WTO Properties sold in January 2016. Liability settled or disposed for the year ended December 31, 2014, includes $366.0 million associated with the Gulf Properties sold in February 2014. For further discussion of the sale of properties see Note 5.

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•	the securities must be issued under a plan of reorganization by the debtor, its successor under a plan, or an affiliate participating in a joint plan of reorganization with the debtor;

•	the recipients of the securities must hold a claim against, an interest in, or a claim for administrative expense in the case concerning the debtor or such affiliate; and

•	the securities must be issued either (a) in exchange for the recipient’s claim against, interest in or claim for administrative expense in the case concerning the debtor or such affiliate or (b) principally in such exchange and partly for cash or property.

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(1)

For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 18.6 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending July 29, 2015. Based upon the common stock’s closing price on August 17, 2015, the common stock issued had a market value of approximately $9.5 million, ($3.58 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $1.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying consolidated statement of operations.

(2)

For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 5.7 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending April 28, 2015. Based upon the common stock’s closing price on May 15, 2015, the common stock issued had a market value of approximately $6.7 million, ($2.23 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $3.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying consolidated statement of operations.

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(1)	Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts.

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(1)	No incremental shares of potentially dilutive restricted stock awards or warrants were included for the Successor 2016 Period as their effect was antidilutive.

(2)	Potential common shares related to the New Convertible Notes covering 14.6 million shares for the Successor 2016 Period were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

(3)	No incremental shares of potentially dilutive restricted stock awards or units were included for the Predecessor 2016 Period and the year ended December 31, 2015 as their effect was antidilutive under the treasury stock method.

(4)	Potential common shares related to the Predecessor Company’s then-outstanding 8.5% and 7.0% convertible perpetual preferred stock covering 71.2 million and 71.7 million shares for the years ended December 31, 2015 and 2014, respectively, were excluded from the computation of (loss) earnings per share because their effect would have been antidilutive under the if-converted method.

(5)	Potential common shares related to the Predecessor Company’s then-outstanding 8.125% and 7.5% Convertible Senior Unsecured Notes covering 48.5 million shares for the year ended December 31, 2015 were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

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•	increased the principal amount of commitments to $600.0 million from $425.0 million;

•	extended the maturity date to March 31, 2020 from February 4, 2020;

•	borrowing base determinations now include the Company’s proportionately consolidated share of proved reserves held by the Royalty Trusts;

•	reduced the interest rate from a flat base rate of LIBOR plus 4.75% per annum to a pricing grid tied to borrowing base utilization of (A) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum, or (B) the base rate plus an applicable margin that varies from 2.00% to 3.00% per annum;

•	reduced the LIBOR floor from 1% to 0%;

•	eliminated the minimum proved developing producing reserves asset coverage ratio;

•	removed the requirement to maintain $50.0 million in a cash collateral account controlled by the administrative agent;

•	eliminated the holiday from borrowing base determinations and the maximum consolidated total net leverage ratio and the minimum consolidated interest coverage ratio covenants; and

•	eliminated certain negative covenants, such as the $20.0 million liquidity requirement and the limitation on capital expenditures.

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(1)	Includes seismic costs of $7.1 million and $10.8 million for the years ended December 31, 2015 and 2014, respectively.

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(1)	Reflects the Company’s effective tax rate for each period.

•	the quality and quantity of available data and the engineering and geological interpretation of that data;

•	estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;

•	the accuracy of mandated economic assumptions such as the future prices of oil, natural gas and NGLs; and

•	the judgment of the personnel preparing the estimates.

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(1)	Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

(2)	Includes proved reserves attributable to noncontrolling interests as shown in the table below:

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•	the standardized measure includes the Company’s estimate of proved oil, natural gas and NGL reserves and projected future production volumes based upon economic conditions;

•	pricing is applied based upon 12-month average market prices at December 31, 2016, 2015 and 2014 adjusted for fixed or determinable contracts that are in existence at year-end. The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:

•	future development and production costs are determined based upon actual cost at year-end;

•	the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and

•	a discount factor of 10% per year is applied annually to the future net cash flows.

(1)	Includes abandonment costs.

(2)	Includes approximately $224.6 million and $643.3 million attributable to noncontrolling interests at December 31, 2015 and 2014 respectively.

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(1)	The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.

(2)	Includes approximately $224.6 million and $643.3 million attributable to noncontrolling interests at December 31, 2015, and 2014 respectively.

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(1)	Includes impairment of $110.1 million, $253.6 million, $354.5 million and $319.1 million for the first, second, and third quarters and Successor 2016 Period, respectively. See Note 9 for further discussion of impairment.

(2)	Includes loss on settlement of contract of $89.1 million and gain on extinguishment of $41.3 million for the first quarter.

(3)	Includes (loss) gain on reorganization items related to the Company’s restructuring under Chapter 11 filings of $(200.9) million, $(42.8) million, and $2.7 billion for the second and third quarters and Predecessor fourth quarter, respectively. See Note 2 for further discussion of reorganization items.

(4)	Includes impairment of $1.1 billion, $1.5 billion, $1.1 billion and $886.8 million for the first, second, third and fourth quarters, respectively. See Note 9 for further discussion of impairment.

(5)	Includes (gain) loss on derivative contracts of $(49.8) million, $33.0 million, $(42.2) million and $(14.0) million for the first, second, third and fourth quarters, respectively.

(6)

Loss applicable per share to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of loss applicable per share to common stockholders for each of the four quarters may not equal the fiscal year amount.

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