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Item 5. Market for Registrant’s Common Equity

2021-03-08 compared with 2020-03-25 · 5 added, 575 removed, 7 unchanged (99% of the section changed)

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

On July 22, 2019, we were notified by the New York Stock Exchange (NYSE) that due to “abnormally low”

trading price levels, pursuant to Section 802.01D of the NYSE Listed Company Manual, the NYSE determined to commence delisting proceedings to delist our Predecessor common stock under the symbol “HK”

and warrants exercisable for common stock.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

On February 20, 2020, our common stock commenced trading on the NYSE American exchange under the symbol “BATL.” Previously, on July 22, 2019, we were notified by the New York Stock Exchange (NYSE) that due to “abnormally low” trading price levels, pursuant to Section 802.01D of the NYSE Listed Company Manual, the NYSE determined to commence delisting proceedings to delist our Predecessor common stock under the symbol “HK” and warrants exercisable for common stock.

Trading in our securities was suspended on July 22, 2019.

On July 23, 2019, our Predecessor common stock commenced trading on the OTC Pink marketplace under the symbols “HKRS,”

“HKRSQ,”

and “HALC.”

On October 8, 2019, upon emergence from chapter 11 bankruptcy, all existing shares of our Predecessor common stock were cancelled and we, as the Successor Company, issued approximately 16.2 million shares of new common stock.

Effective February 20, 2020, we commenced trading on the NYSE American exchange under the symbol “BATL.”

On July 23, 2019, our Predecessor common stock commenced trading on the OTC Pink marketplace under the symbols “HKRS,” “HKRSQ,” and “HALC.” On October 8, 2019, upon emergence from chapter 11 bankruptcy, all existing shares of our Predecessor common stock were cancelled and we, as the Successor Company, issued approximately 16.2 million shares of new common stock.

We intend to retain earnings for use in the operation and expansion of our business and therefore do not anticipate declaring cash dividends on our common stock in the foreseeable future.

1 unchanged sentence

We are also restricted from paying cash dividends on common stock under our Senior Credit Agreement.

Approximately 56 registered stockholders of record as of March 4, 2021 held our common stock.

In most instances, a registered stockholder holds shares in street name for one or more customers who beneficially own the shares.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

The following table sets forth certain information with respect to the surrender of our common stock by employees in exchange for the payment of certain tax withholding obligations during the three months ended December 31, 2019 (Successor).

Purchased (1)

Average Price

Paid Per Share

Total Number of

Shares Purchased as

Part of Publicly

Announced Plans or

Maximum Number

(or Approximate

Dollar Value)

of Shares that

May Yet Be Purchased

Under the Plans or

November 2019

December 2019

All of the shares were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards.

The acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of our common stock.

SELECTED FINANCIAL DATA

Not applicable.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations and our current financial condition.

Our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10‑K contain additional information that should be referred to when reviewing this material.

Certain prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh‑start accounting.

References to “Successor”

or “Successor Company”

relate to the financial position and results of operations of the reorganized Company subsequent to October 1, 2019.

References to “Predecessor”

or “Predecessor Company”

relate to the financial position and results of operations of the Company prior to, and including, October 1, 2019.

Statements in this discussion may be forward‑looking.

These forward‑looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.

We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States.

During 2017 (Predecessor), we acquired certain properties in the Delaware Basin and divested our assets located in the Williston Basin in North Dakota (the Williston Divestiture) and in the El Halcón area of East Texas (the El Halcón Divestiture).

As a result, our properties and drilling activities are currently focused in the Delaware Basin, where we have an extensive drilling inventory that we believe offers attractive economics.

At December 31, 2019 (Successor), our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc.

(Netherland, Sewell), using Securities and Exchange Commission (SEC) prices for crude oil and natural gas, which are based on the West Texas Intermediate (WTI) crude oil spot price of $55.85 per Bbl and Henry Hub natural gas spot price of $2.578 per MMBtu, were approximately 62.1 MMBoe, consisting of 39.2 MMBbls of oil, 10.8 MMBbls of natural gas liquids, and 72.3 Bcf of natural gas.

Approximately 61% of our proved reserves were classified as proved developed as of December 31, 2019 (Successor).

We maintain operational control of approximately 99% of our proved reserves.

Substantially all of our proved reserves and production at December 31, 2019 (Successor) are associated with our Delaware Basin properties.

Our total operating revenues for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) were approximately $65.6 million and $159.1 million, respectively, or $224.7 million combined, compared to total operating revenues for 2018 (Predecessor) of $226.6 million.

During the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), production averaged 20,293 Boe/d and 17,209 Boe/d, respectively, or 17,986 Boe/d combined, compared to average daily production of 13,904 Boe/d during 2018 (Predecessor).

Our average daily oil and natural gas production increased year over year due to the acquisition of properties in West Quito Draw and our drilling activities in Monument Draw and West Quito Draw.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production.

Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production.

The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors.

Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

In 2019 (for the combined Successor and Predecessor periods), we spent approximately $187.8 million on capital expenditures for drilling and completions.

In 2019 (for the combined Successor and Predecessor periods), we ran an average of one to two operated rigs in the Delaware Basin and we drilled and cased 14 gross (12.5 net) operated wells, completed 17 gross (15.9 net) operated wells, and put online 17 gross (15.9 net) operated wells.

Our 2020 drilling and completion budget, approved by our board in December 2019, contemplated running one operated rig in the Delaware Basin during the year.

That budget contemplated spending approximately $123 million to $138 million in capital expenditures, including drilling, completion, support infrastructure and other costs, to drill seven to ten gross operated wells and to put online 12 to 14 gross operated wells during the year.

We continuously monitor changes in market conditions and adapt our operational plans as necessary in order to maintain financial flexibility, preserve acreage, and meet our contractual obligations.

As a result of recent changes in market conditions and commodity prices, we are considering revisions to our 2020 capital budget which would lower anticipated capital expenditures to approximately $60 million to $76 million and include drilling four to six gross operated wells and putting online six to seven gross operated wells during the year.

We expect to fund our budgeted 2020 capital expenditures with cash and cash equivalents on hand, cash flows from operations and borrowings under our Senior Credit Agreement.

In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may be required to curtail drilling, development, land acquisitions and other activities to reduce our capital spending.

However, significant or prolonged reductions in capital spending will adversely impact our production and may negatively affect our future cash flows.

Oil and natural gas prices are inherently volatile and sustained lower commodity prices could have a material impact upon our full cost ceiling test calculation.

The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date.

Using the first-day-of-the-month average for the 12-months ended March 31, 2020 of the WTI crude oil spot price of $55.96 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended March 31, 2020 of the Henry Hub natural gas price of $2.298 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling amount related to the net book value of our oil and natural gas properties would not have generated a full cost ceiling impairment, holding all other inputs and factors constant.

In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Recent Developments

Listing of our Common Stock on NYSE American

Our Predecessor common stock was previously listed on the New York Stock Exchange (NYSE) under the symbol “HK.”

As a result of our failure to satisfy the continued listing requirements of the NYSE, on July 22, 2019, our Predecessor common stock was delisted from the NYSE.

Effective February 20, 2020, we commenced trading on the NYSE American exchange under the symbol “BATL.”

Reorganization

On August 2, 2019, we entered into a Restructuring Support Agreement (the Restructuring Support Agreement) with certain holders of our 6.75% senior unsecured notes due 2025 (the Unsecured Senior Noteholders).

On August 7, 2019, we filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S.

Bankruptcy Court for the Southern District of Texas (the Bankruptcy Court) to effect a prepackaged plan of reorganization (the Plan) as contemplated in the Restructuring Support Agreement.

Our chapter 11 proceedings were administered under the caption In re Halcón Resources Corporation, et al.

On September 24, 2019, the Bankruptcy Court entered an order confirming the Plan and on October 8, 2019 (the Effective Date), we emerged from chapter 11 bankruptcy.

Pursuant to the terms of the Plan contemplated by the Restructuring Support Agreement, the Unsecured Senior Noteholders and other claim and interest holders received the following treatment in full and final satisfaction of their claims and interests:

borrowings outstanding under the Predecessor Credit Agreement, plus unpaid interest and fees, were repaid in full, in cash, including by a refinancing (see below for further details regarding the credit agreement);

the Unsecured Senior Noteholders received their pro rata share of 91% of the common stock of reorganized Battalion (New Common Shares), subject to dilution, issued pursuant to the Plan and participated in the Senior Noteholder Rights Offering (defined below);

our general unsecured claims were unimpaired and paid in full in the ordinary course;

all of our Predecessor Company’s outstanding shares of common stock were cancelled and the existing common stockholders received their pro rata share of 9% of the New Common Shares issued pursuant to the Plan, subject to dilution, together with Warrants (defined below) to purchase common stock of reorganized Battalion and participated in the Existing Equity Interests Rights Offering (defined below and, collectively, the Existing Equity Total Consideration);

provided, however, that registered holders of existing common stock with 2,000 shares or fewer of common stock received cash in an amount equal to the inherent value of such holder’s pro rata share of the Existing Equity Total Consideration (the Existing Equity Cash Out).

Each of the foregoing percentages of equity in the reorganized Company were as of October 8, 2019 and are subject to dilution by New Common Shares issued in connection with (i) a management incentive plan, (ii) the Warrants (defined below), (iii) the Equity Rights Offerings (defined below), and (iv) the Backstop Commitment Premium (defined below).

As a component of the Restructuring Support Agreement (i) certain Unsecured Senior Noteholders purchased their pro rata share of New Common Shares for an aggregate purchase price of $150.2 million (the Senior Noteholder Rights Offering) and (ii) certain existing common stockholders purchased their pro rata share of New Common Shares for an aggregate purchase price of $5.8 million (the Existing Equity Interests Rights Offering, and together with the Senior Noteholder Rights Offering, the Equity Rights Offerings), in each case, at a price per share equal to a 26% discount to the value of the New Common Shares based on an assumed total enterprise value of $425.0 million.

Certain of the Unsecured Senior Noteholders backstopped the Senior Noteholder Rights Offering and received as consideration (the Backstop Commitment Premium) New Common Shares equal to 6% of the aggregate amount of the Senior Noteholder Rights Offering subject to dilution by New Common Shares issued in connection with a management incentive plan and the Warrants.

If the backstop agreement had been terminated, we would have been obligated to make a cash payment equal to 6% of the aggregate amount of the Senior Noteholder Rights Offering.

We used the proceeds of the Equity Rights Offerings to (i) provide additional liquidity for working capital and general corporate purposes, (ii) pay reasonable and documented restructuring expenses, and (iii) fund Plan distributions.

Under the Restructuring Support Agreement, the existing common stockholders (subject to the Existing Equity Cash Out) were issued a series of warrants exercisable for cash for a three year period subsequent to the effective date of the Plan (Warrants).

The Warrants were issued with strike prices based upon stipulated rate-of-return levels achieved by the Unsecured Senior Noteholders.

The Warrants cumulatively represent 30% of the New Common Shares issued pursuant to the Plan.

Fresh-start Accounting

Upon emergence from chapter 11 bankruptcy, we adopted fresh-start accounting in accordance with the provisions set forth in Accounting Standards Codification (ASC) 852, Reorganizations , as (i) the reorganization value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity.

We elected to adopt fresh-start accounting effective October 1, 2019, to coincide with the timing of our normal fourth quarter reporting period, which resulted in us becoming a new entity for financial reporting purposes.

We evaluated and concluded that events between October 1, 2019 and October 8, 2019 were immaterial and use of an accounting convenience date of October 1, 2019 was appropriate.

As such, fresh-start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2019 (Successor) and related reorganization adjustments and fresh-start adjustments are included in the accompanying statement of operations for the period from January 1, 2019 through October 1, 2019 (Predecessor).

Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date.

Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date.

Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we have a new basis in our assets and liabilities.

As a result of the adoption of fresh-start reporting and the effects of the implementation of the Plan, our consolidated financial statements subsequent to October 1, 2019 are not comparable to our consolidated financial statements prior to October 1, 2019.

References to “Successor”

or “Successor Company”

relate to the financial position and results of operations of the reorganized Company subsequent to October 1, 2019.

References to “Predecessor”

or “Predecessor Company”

relate to the financial position and results of operations of the Company prior to, and including, October 1, 2019, and as such, “black-line”

financial statements are presented to distinguish between the Predecessor and Successor companies.

Refer to Item 8.

Consolidated Financial Statements and Supplementary Data—Note 3, “Fresh-Start Accounting,”

for further details.

On the Effective Date, pursuant to the terms of the Plan, all shares of our Predecessor Company were cancelled and we filed an amended and restated certificate of incorporation with the Delaware Secretary of State and adopted amended and restated bylaws.

Pursuant to the amended and restated certificate of incorporation, the number of authorized shares of common stock which we have the authority to issue was reduced from 1,001,000,000 to 101,000,000.

Of the 101,000,000 authorized shares, 100,000,000 are common stock, par value $0.0001 per share and 1,000,000 are preferred stock, par value $0.0001 per share.

On the Effective Date, pursuant to the terms of the Plan and the confirmation order, we issued:

421,827 shares of New Common Shares pursuant to the Existing Equity Interests Rights Offering;

8,059,111 shares of New Common Shares pursuant to the Senior Noteholder Rights Offering;

and 3,558,334 shares of New Common Shares in connection with the backstop commitment, which includes 657,590 shares of New Common Shares issued as the Backstop Commitment Premium;

3,790,247 shares of New Common Shares to the Senior Noteholders pursuant to a mandatory exchange;

374,421 shares of New Common Shares, 1,798,322 Series A Warrants (defined below), 2,247,985 Series B Warrants (defined below) and 2,890,271 Series C Warrants (defined below), to pre-emergence holders of our Existing Equity Interests pursuant to a mandatory exchange.

Warrant Agreement

On the Effective Date, by operation of the Plan and the confirmation order, all warrants of our Predecessor Company were cancelled and we entered into a warrant agreement (the Warrant Agreement) with Broadridge Corporate Issuer Solutions, Inc.

as the warrant agent, pursuant to which we issued three series of warrants (the Series A Warrants, the Series B Warrants and the Series C Warrants and together, the Warrants, and the holders thereof, the Warrant Holders), on a pro rata basis to pre-emergence holders of our Existing Equity Interests pursuant to the Plan.

Each Warrant represents the right to purchase one share of New Common Shares at the applicable exercise price, subject to adjustment as provided in the Warrant Agreement and as summarized below.

On the Effective Date, we issued (i) Series A Warrants to purchase an aggregate of 1,798,322 shares of New Common Stock, with an initial exercise price

of $40.17 per share, (ii) Series B Warrants to purchase an aggregate of 2,247,985 shares of New Common Stock, with an initial exercise price of $48.28 per share and (iii) Series C Warrants to purchase an aggregate of 2,890,271 shares of New Common Stock, with an initial exercise price of $60.45 per share.

Each series of Warrants issued under the Warrant Agreement has a three-year term, expiring on October 8, 2022.

The strike price of each series of Warrants issued under the Warrant Agreement increases monthly at an annualized rate of 6.75%, compounding monthly, as provided in the Warrant Agreement.

The Warrants do not grant the Warrant Holder any voting or control rights or dividend rights, or contain any negative covenants restricting the operation of our business.

Registration Rights Agreement

On the Effective Date, we and the other signatories thereto (the Demand Stockholders), entered into a registration rights agreement (the Registration Rights Agreement), pursuant to which, subject to certain conditions and limitations, we agreed to file with the SEC a registration statement concerning the resale of the registrable shares of our New Common Shares held by Demand Stockholders (the Registrable Securities), as soon as reasonably practicable but in no event later than the later to occur of (i) ninety (90) days after the Effective Date and (ii) a date specified by a written notice to us by Demand Stockholders holding at least a majority of the Registerable Securities, and thereafter to use commercially reasonable best efforts to cause the registration statement to be declared effective by the SEC as soon as reasonably practicable.

In addition, from time to time, the Demand Stockholders may request that additional Registrable Securities be registered for resale by us.

Subject to certain limitations, the Demand Stockholders also have the right to request that we facilitate the resale of Registrable Securities pursuant to firm commitment underwritten public offerings.

The Registration Rights Agreement contains other customary terms and conditions, including, without limitation, provisions with respect to suspensions of our registration obligations and indemnification.

Successor Senior Revolving Credit Facility

On the Effective Date, we entered into a senior secured revolving credit agreement, as amended on November 21, 2019, (the Senior Credit Agreement) with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility and the Predecessor Credit Agreement, discussed below.

The Senior Credit Agreement provides for a $750.0 million senior secured reserve-based revolving credit facility with a current borrowing base of $240.0 million.

A portion of the Senior Credit Agreement, in the amount of $50.0 million, is available for the issuance of letters of credit.

The maturity date of the Senior Credit Agreement is October 8, 2024.

The first redetermination will be in the spring of 2020 and redeterminations will occur semi-annually thereafter, with us and the lenders each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations.

The borrowing base takes into account the estimated value of the our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria.

Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.00% to 2.00% for ABR-based loans or at specified margins over LIBOR of 2.00% to 3.00% for Eurodollar-based loans, which margins may be increased one-time by not more than 50 basis points per annum if necessary in order to successfully syndicate the Senior Credit Agreement, which is currently in process.

These margins fluctuate based on our utilization of the facility.

We may elect, at our option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty, except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement.

We may be required to make mandatory prepayments of the outstanding borrowings under the Senior Credit Agreement in connection with certain borrowing base deficiencies, including deficiencies which may arise in connection with a borrowing base redetermination, an asset disposition or swap terminations attributable in the aggregate to more than ten percent (10%) of the then-effective borrowing base.

Amounts outstanding under the Senior Credit Agreement are guaranteed by our direct and indirect subsidiaries and secured by a security interest in substantially all of our assets and the assets of our subsidiaries.

The Senior Credit Agreement contains certain events of default, including non-payment;

breaches of representation and warranties;

non-compliance with covenants;

cross-defaults to material indebtedness;

voluntary or involuntary bankruptcy;

judgments and change in control.

The Senior Credit Agreement also contains certain financial covenants, including maintenance of (i) a Total Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) of not greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00:1.00, both commencing with the fiscal quarter ending March 31, 2020.

On November 21, 2019 (Successor), we entered into the First Amendment to the Senior Credit Agreement which, among other things, (i) reduced the borrowing base to $240.0 million and (ii) limited the Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) as of the last day of each fiscal quarter, commencing with the fiscal quarter ending March 31, 2020, of not greater than 3.50 to 1.00.

Debtor-in-Possession Financing

In connection with the chapter 11 proceedings and pursuant to an order of the Bankruptcy Court dated August 9, 2019 (the Interim Order), we entered into a Junior Secured Debtor-In-Possession Credit Agreement (the DIP Credit Agreement) with the Unsecured Senior Noteholders party thereto from time to time as lenders (the DIP Lenders) and Wilmington Trust, National Association, as administrative agent.

Under the DIP Credit Agreement, the DIP Lenders made available a $35.0 million debtor-in-possession junior secured term credit facility (the DIP Facility), of which $25.0 million was extended as an initial loan and the remainder of which was drawn on September 5, 2019 (Predecessor).

The DIP Facility was refinanced with the Senior Credit Agreement on October 8, 2019 (Successor).

We used the proceeds of the DIP Facility to, among other things, (i) provide working capital and other general corporate purposes, including to finance capital expenditures and make certain interest payments as and to the extent set forth in the Interim Order and/or the final order, as applicable, of the Bankruptcy Court and in accordance with our budget delivered pursuant to the DIP Credit Agreement, (ii) pay fees and expenses related to the transactions contemplated by the DIP Credit Agreement in accordance with such budget and (iii) cash collateralize any letters of credit.

The DIP Loans bore interest at a rate per annum equal to (i) adjusted LIBOR plus an applicable margin of 5.50% or (ii) an alternative base rate plus an applicable margin of 4.50%, in each case, as selected by us.

The DIP Facility was secured by (i) a junior secured perfected security interest on all assets that secured the Predecessor Credit Agreement and (ii) a senior secured perfected security interest on all our unencumbered assets and any subsidiary guarantors.

The security interests and liens were further subject to certain carve-outs and permitted liens, as set forth in the DIP Credit Agreement.

The DIP Credit Agreement contained certain customary (i) representations and warranties;

(ii) affirmative and negative covenants, including delivery of financial statements;

conduct of business;

reserve reports;

title information;

indebtedness;

dividends and distributions;

sale or discount of receivables;

sale of properties;

termination of swap agreements;

transactions with affiliates;

negative pledges;

dividend restrictions;

gas imbalances;

take-or-pay or other prepayments and swap agreements;

and (iii) events of default, including non-payment;

breaches of representations and warranties;

non-compliance with covenants or other agreements;

cross-default to material indebtedness;

change of control;

dismissal (or conversion to chapter 7) of the chapter 11 proceedings;

and failure to satisfy certain bankruptcy milestones.

Predecessor Senior Revolving Credit Facility

On October 8, 2019 (Successor), borrowings outstanding under the Predecessor Company’s Amended and Restated Senior Secured Revolving Credit Agreement (Predecessor Credit Agreement) were repaid and refinanced with proceeds from the Equity Rights Offerings and borrowings under the Senior Credit Agreement.

On May 9, 2019 (Predecessor), we entered into the Eighth Amendment, Consent and Waiver to Amended and Restated Senior Secured Credit Agreement (the Eighth Amendment) which, among other things, (i) temporarily waived any default or event of default directly resulting from the potential Leverage Ratio Default (as defined in the Eighth Amendment) for the fiscal quarter ended March 31, 2019, (ii) increased interest margins to 1.75% to 2.75% for ABR-based loans and 2.75% to 3.75% for Eurodollar-based loans, (iii) reduced our Consolidated Cash Balance (as defined in the Eighth Amendment) to $5.0 million, and (iv) provided for periodic reporting of projected cash flows and accounts payable agings to the lenders.

Under the Eighth Amendment, the waiver would have terminated and an Event of Default (as defined in the Predecessor Credit Agreement) would have occurred on August 1, 2019.

On July 31, 2019 (Predecessor), we entered into the Waiver to Amended and Restated Senior Secured Credit Agreement, pursuant to which the termination date for the waiver granted by the Eighth Amendment was extended to August 8, 2019.

Capital Resources and Liquidity

We expect to spend approximately $60 million to $76 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs, during 2020.

These near-term capital spending requirements are expected to be funded with cash and cash equivalents on hand, cash flows from operations and borrowings under our Senior Credit Agreement.

On the Effective Date, we entered into the Senior Credit Agreement with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility and the Predecessor Credit Agreement.

The Senior Credit Agreement provides for a $750.0 million senior secured reserve-based revolving credit facility, with a current borrowing base of $240.0 million.

The first redetermination will be in the spring of 2020 and redeterminations will occur semi-annually thereafter, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations.

The borrowing base takes into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria.

The effect of these and other factors may result in an increase or a decrease in the amount of our borrowing base.

A reduction in our borrowing base would reduce our ability to borrow under the Senior Credit Agreement and could require us to repay borrowings, if any, in excess of the borrowing base and may negatively impact our liquidity and our ability to fund our operations.

The Senior Credit Agreement contains certain financial covenants, including maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) of not greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00:1.00, both commencing with the fiscal quarter ending March 31, 2020.

As of December 31, 2019, there were no financial covenants in effect under the Senior Credit Agreement.

At December 31, 2019 (Successor), we had $144 million of indebtedness outstanding, $2.3 million letters of credit outstanding and approximately $93.7 million of borrowing capacity available under our Senior Credit Agreement.

We have in the past obtained amendments to the covenants under our Predecessor Credit Agreements under circumstances where we anticipated that it might be challenging for us to comply with our financial covenants for a particular period of time.

As part of our plan to manage liquidity risks, we scaled back our capital expenditures budget, focused our drilling program on our highest return projects, continued to explore opportunities to divest non-core properties, entered into a Restructuring Support Agreement to restructure our indebtedness and, on August 7, 2019, filed a voluntary petition for relief under chapter 11 of the United States Bankruptcy Code in the U.S.

Bankruptcy Court for the Southern District of Texas to pursue a prepackaged plan of reorganization.

On September 24, 2019, the Bankruptcy Court entered an order confirming our plan of reorganization and on October 8, 2019, we emerged from chapter 11 bankruptcy.

Our strategic decision to transform into a pure-play, single basin company focused on the Delaware Basin in West Texas resulted in us divesting our producing properties located in other areas and acquiring primarily undeveloped acreage in the Delaware Basin.

Our drilling activities since acquiring the assets required significant capital expenditure outlays to replenish production and related EBITDA.

These and other factors adversely impacted our ability to comply with our debt covenants under the Predecessor Credit Agreement by reducing our production, reserves and EBITDA on a current and a pro forma historical basis, while making us more susceptible to fluctuations in performance and compliance more challenging.

In addition, we encountered certain operational challenges that impacted our ability to comply, including, elevated levels of hydrogen sulfide in the natural gas produced from our Monument Draw wells,

limited and expensive treatment and transportation options.

Severance payments to executives in 2019 also impacted our ability to comply with our financial covenants.

Changes in the level and timing of our production, drilling and completion costs, the cost and availability of transportation for our production and other factors varying from our expectations can cause our EBITDA to change significantly and affect our ability to comply with the covenants under our Senior Credit Agreement.

As a consequence, we endeavor to anticipate potential covenant compliance issues and work with the lenders under our Senior Credit Agreement to address any such issues ahead of time.

While we have largely been successful in obtaining modifications of our covenants as needed, there can be no assurance that we will be successful in the future.

Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves.

Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas industry.

We therefore continuously monitor our liquidity and evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources, acquisition opportunities and drilling successes.

We strive to maintain financial flexibility while pursuing our drilling plans and may access capital markets, pursue joint ventures, sell assets and engage in other transactions as necessary to, among other things, maintain borrowing capacity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage.

Our ability to complete such transactions and maintain or increase our borrowing base is subject to a number of variables, including our level of oil and natural gas production, proved reserves and commodity prices, the amount and cost of our indebtedness, as well as various economic and market conditions that have historically affected the oil and natural gas industry.

Even if we are otherwise successful in growing our proved reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.

When commodity prices decline significantly, as they have recently, our ability to finance our capital budget and operations may be adversely impacted.

While we use derivative instruments to provide partial protection against declines in oil, natural gas and natural gas liquids prices, the total volumes we hedge are less than our expected production, varies from period to period based on our view of current and future market conditions and generally extends up to approximately 36 months.

This variation in hedged volumes may result in our liquidity being more susceptible to commodity price declines.

As of October 8, 2019, the Senior Credit Agreement contained minimum hedging requirements.

Specifically, for the first twelve months and for months 13 to 24 following October 8, 2019, that 75% and 50%, respectively, of anticipated production from proved developed producing reserves be covered by hedges.

While production volumes naturally decrease over time, we currently have approximately 90%, 84%, and 88% of 2020, 2021, and 2022 anticipated production from proved developed producing reserves hedged at weighted average prices of $56.11, $53.44 and $52.38 per barrel, respectively.

Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change.

We do not enter into derivative contracts for speculative trading purposes.

For the period of October 2, 2019 through December 31, 2019 (Successor), cash generated by operating activities and borrowing under our Senior Credit Agreement were used to fund our drilling and completion program.

For the period of January 1, 2019 through October 1, 2019 (Predecessor), cash on hand supplemented with borrowings under our Predecessor Credit Agreement and the DIP Facility were used to fund our drilling and completion program.

Results of Operations ”

for a review of the impact of prices and volumes on operating revenues.

The period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) are distinct reporting periods as a result of our emergence from chapter 11 bankruptcy and are not comparable to prior periods.

Net increase (decrease) in cash, cash equivalents and restricted cash is summarized as follows (in thousands):

October 2, 2019

January 1, 2019

Years Ended December 31,

December 31, 2019

October 1, 2019

Cash flows provided by (used in) operating activities

Cash flows provided by (used in) investing activities

Cash flows provided by (used in) financing activities

Net increase (decrease) in cash, cash equivalents and restricted cash

Operating Activities.

Net cash flows provided by operating activities for the period of October 2, 2019 through December 31, 2019 (Successor) were $13.7 million and net cash flows used in operating activities for the period of January 1, 2019 through October 1, 2019 (Predecessor) were $39.7 million.

Net cash flows provided by operating activities were $67.2 million and $114.6 million for the years ended December 31, 2018 and 2017 (Predecessor), respectively.

For the period of October 2, 2019 through December 31, 2019 (Successor), operating cash flows increased due to higher oil and natural gas revenues resulting from increased average daily production, as well as decreases in our operating expenses.

For the period of January 1, 2019 through October 1, 2019 (Predecessor), operating cash flows decreased from the prior year due to increases in our operating expenses, primarily from third party water hauling and disposal costs, reorganization costs and severances paid to executives.

Operating cash flows for the year ended December 31, 2018 (Predecessor) decreased from prior year primarily due to our divestitures in 2017, in which we divested non-core producing properties in other areas for primarily undeveloped acreage in the Delaware Basin.

This decrease was partially offset by $35.2 million of proceeds related to hedge monetizations that occurred during the year.

The $114.6 million of operating cash flows for the year ended December 31, 2017 (Predecessor) were lower than the prior year primarily due to a decrease in realized settlements on derivatives.

Realized settlements on derivative contracts decreased $312.7 million over the prior year period.

Our oil and natural gas revenues also decreased approximately $42.2 million over the prior year period due to a decrease in our average daily production.

Average realized prices (excluding the effects of hedging arrangements) were $37.58 per Boe, $35.87 per Boe and $28.53 per Boe for the year ended December 31, 2017, for the period September 10, 2016 through December 31, 2016 and the period of January 1, 2016 through September 9, 2016, respectively.

Investing Activities.

Net cash flows used in investing activities for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) were approximately $42.8 million and $254.4 million, respectively.

Net cash flows used in investing activities for the year ended December 31, 2018 (Predecessor) were approximately $706.5 million.

Net cash flows provided by investing activities for the year ended December 31, 2017 (Predecessor) were approximately $598.6 million.

During the period of October 2, 2019 through December 31, 2019 (Successor), we spent $43.2 million on oil and natural gas capital expenditures, of which $29.2 million related to drilling and completion costs and $13.2 million related to the development of our treating equipment and our gathering support infrastructure.

During the period of January 1, 2019 through October 1, 2019 (Predecessor), we spent $167.2 million on oil and natural gas expenditures, of which $158.6 million related to drilling and completion costs.

During the period of January 1, 2019 through October 1, 2019 (Predecessor), we spent approximately $85.6 million on capital expenditures to develop our treating equipment and our gathering support infrastructure.

In 2018 (Predecessor), we incurred cash expenditures of $333.9 million on acquisition activities, the majority of which related to the acquisitions of acreage and related assets in the Delaware Basin located in Ward County, Texas (the West Quito Draw Properties) and in the northern tract of the Monument Draw area of the Delaware Basin, located in

Ward and Winkler Counties, Texas (the Ward County Assets).

Additionally, we spent $475.7 million on oil and natural gas capital expenditures, of which $444.4 million related to drilling and completion costs.

We also spent approximately $117.0 million on capital expenditures primarily to develop our water recycling facilities and gas gathering and treating infrastructure.

These cash outflows were offset by proceeds from the sale of our water infrastructure assets located in the Delaware Basin (the Water Assets) of $213.8 million.

In 2017 (Predecessor), we incurred cash expenditures of $700.1 million to acquire acreage and related assets in the Hackberry Draw area of the Delaware Basin located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets) of which $674.6 million related to the oil and natural gas properties acquired and $25.5 million related to the other operating property and equipment acquired.

In addition to the acquisition of the Pecos County Assets, we spent approximately $344.0 million on other acquisitions, primarily in the Delaware Basin to increase our position in the area.

We spent $331.3 million on oil and natural gas capital expenditures, of which $309.6 million related to drilling and completion costs.

These cash outflows for acquisitions and our drilling and completion activities were more than offset by cash inflows from our non-core asset sales.

Approximately $1.39 billion of the proceeds from Williston Divestiture were allocated to the oil and natural gas properties divested and $10.9 million of the proceeds were allocated to the other operating property and equipment divested.

Proceeds from the El Halcón Divestiture were $494.3 million, of which $484.1 million related to the oil and natural gas properties divested and $10.2 million related to the other operating property and equipment divested.

In November 2017 (Predecessor), proceeds from the sale of our non-operated oil and natural gas properties and related assets located in the Williston Basin in North Dakota and Montana (the Non-Operated Williston Assets) totaled approximately $105.2 million.

Financing Activities.

Net cash flows provided by financing activities for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) were $10.0 million and $276.7 million, respectively.

Net cash flows provided by financing activities for the year ended December 31, 2018 (Predecessor) were approximately $262.1 million.

Net cash flows used in financing activities for the year ended December 31, 2017 (Predecessor) were $289.1 million.

During the period of October 2, 2019 through December 31, 2019 (Successor), net borrowings of $14.0 million under our Senior Credit Agreement were used to fund our drilling and completions program and the development of our treating equipment and gathering support facilities.

During the period of January 1, 2019 through October 1, 2019 (Predecessor), we received proceeds of $150.2 million from our Senior Noteholders Rights Offering and $5.8 million from our Existing Equity Interest Rights Offering.

In addition, we borrowed $130.0 million under our Senior Credit Agreement.

The proceeds from our offerings and borrowings under our Senior Credit Agreement were used to refinance our DIP Facility and the Predecessor Credit Agreement.

Borrowings under our DIP Facility and under our Predecessor Credit Agreement were used to fund our drilling and completions program, as well as the development of our treating equipment and our gathering infrastructure.

In 2018 (Predecessor), we issued an additional $200.0 million aggregate principal amount of our 6.75% senior notes due 2025 (the Additional 2025 Notes).

Proceeds from the private placement were approximately $202.4 million after initial purchasers’

premiums and deducting commissions and offering expenses.

Additionally, we sold 9.2 million shares of common stock in a public offering at a price of $6.90 per share.

The net proceeds from the offering were approximately $60.4 million after deducting underwriters’

discounts and offering expenses.

In 2017 (Predecessor), we issued $850.0 million aggregate principal amount of our new 6.75% senior notes due 2025 (the 2025 Notes).

Proceeds from the private placement were approximately $834.1 million after deducting initial purchasers’

discounts and commissions and offering expenses.

We utilized the majority of the net proceeds from the private placement to fund the repurchase and redemption of the then outstanding 8.625% senior secured second lien notes due 2020 (the 2020 Second Lien Notes).

The net cash to make these repurchases and redemptions was approximately $736.8 million and we recognized a loss on the extinguishment of debt, representing a $30.9 million loss on the repurchase for the tender premium paid and a $26.0 million loss on the write-off of the discount on the notes.

During 2017 (Predecessor), we also utilized a portion of the proceeds from the Williston Divestiture to repay borrowings outstanding under our Predecessor Credit Agreement, repurchase approximately $425.0 million principal amount of our 2025 Notes and redeem all of our then outstanding 12.0% senior secured second lien notes due 2022 (the 2022 Second Lien Notes).

The net cash used to make the repurchase of the 2025 Notes was approximately $437.8 million and we

recognized a loss on the extinguishment of debt, representing a $12.8 million loss on the repurchase for the tender premium paid, an $8.3 million loss on the write-off of the discount on the notes, and a $7.8 million loss on the write-off of the debt issuances costs on the notes.

The net cash used to make the redemption of the 2022 Second Lien Notes was approximately $137.8 million and we recognized a loss on the extinguishment of debt, representing a $23.0 million loss on the redemption for the make whole premium paid and a $6.2 million loss on the write-off of the discount on the notes.

We also paid a consent fee of approximately $16.9 million to the holders of our 2025 Notes.

Additionally, we issued 5,518 shares of preferred stock at $72,500 per share.

Gross proceeds from this issuance were approximately $400.1 million.

Successor Senior Revolving Credit Facility

The Senior Credit Agreement provides for a $750.0 million senior secured reserve-based revolving credit facility with a current borrowing base of $240.0 million.

A portion of the Senior Credit Agreement, in the amount of $50.0 million, is available for the issuance of letters of credit.

The maturity date of the Senior Credit Agreement is October 8, 2024.

The first redetermination will be in the spring of 2020 and redeterminations will occur semi-annually thereafter, with the lenders and us each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations.

The borrowing base takes into account the estimated value of our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria.

These margins fluctuate based on our utilization of the facility.

Amounts outstanding under the Senior Credit Agreement are guaranteed by our direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of us and our subsidiaries.

The Senior Credit Agreement contains certain events of default, including non-payment;

breaches of representation and warranties;

non-compliance with covenants;

cross-defaults to material indebtedness;

voluntary or involuntary bankruptcy;

judgments and change in control.

The Senior Credit Agreement also contains certain financial covenants, including maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) of not greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00:1.00, both commencing with the fiscal quarter ending March 31, 2020.

As of December 31, 2019, there were no financial covenants in effect under the Senior Credit Agreement.

Off-Balance Sheet Arrangements

At December 31, 2019 (Successor), we did not have any material off-balance sheet arrangements.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.

The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves.

Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used.

Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.

Described below are the significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States.

We also describe the significant estimates and assumptions we make in applying these policies.

We discussed the development, selection and disclosure of each of these with our audit committee.

Consolidated Financial Statements and Supplementary Data —Note 1, “

Summary of Significant Events and Accounting Policies,”

for a discussion of additional accounting policies and estimates made by management.

Fresh‑start Accounting

Upon our emergence from chapter 11 bankruptcy, on October 8, 2019, we adopted fresh-start accounting in accordance with the provisions set forth in ASC 852, Reorganizations, as (i) the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances.

Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date.

We evaluated and concluded that events between October 1, 2019 and October 8, 2019 were immaterial and use of an accounting convenience date of October 1, 2019 was appropriate.

As such, fresh-start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2019 (Successor) and related fresh-start adjustments are included in the accompanying consolidated statement of operations for the period from January 1, 2019 through October 1, 2019 (Predecessor).

Fresh-start accounting requires an entity to present its assets, liabilities, and equity as if it were a new entity upon emergence from bankruptcy.

The new entity is referred to as “Successor”

or “Successor Company.”

However, we will continue to present financial information for any periods before adoption of fresh-start accounting for the Predecessor Company.

The Predecessor and Successor companies may lack comparability, as required in ASC Topic 205, Presentation of Financial Statements (ASC 205).

ASC 205 states financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed.

Therefore, “black-line”

financial statements are presented to distinguish between the Predecessor and Successor Companies.

Refer to Item 8.

Consolidated Financial Statements and Supplementary Data—Note 3, “Fresh-Start Accounting,”

for further details.

Oil and Natural Gas Activities

Accounting for oil and natural gas activities is subject to unique rules.

Two generally accepted methods of accounting for oil and natural gas activities are available-successful efforts and full cost.

The most significant differences between these two methods are the treatment of unsuccessful exploration costs and the manner in which the carrying value of oil and natural gas properties are amortized and evaluated for impairment.

The successful efforts method requires unsuccessful exploration costs to be expensed as they are incurred upon a determination that the well is uneconomical while the full cost method provides for the capitalization of these costs.

Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities.

Impairment of oil and natural gas properties under the successful efforts method is based on an evaluation of the carrying value of individual oil and natural gas properties against their estimated fair value, while impairment under the full cost method requires an

evaluation of the carrying value of oil and natural gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using the unweighted arithmetic average of the first day of the month for each of the 12-month prices for oil and natural gas within the period, holding prices and costs constant and applying a 10% discount rate.

Full Cost Method

We use the full cost method of accounting for our oil and natural gas activities.

Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized into a cost center (the amortization base or full cost pool).

Such amounts include the cost of drilling and equipping productive wells, treating equipment and gathering support facilities costs, dry hole costs, lease acquisition costs and delay rentals.

All general and administrative costs unrelated to drilling activities are expensed as incurred.

The capitalized costs of our evaluated oil and natural gas properties, plus an estimate of our future development and abandonment costs are amortized on a unit-of-production method based on our estimate of total proved reserves.

Our financial position and results of operations could have been significantly different had we used the successful efforts method of accounting for our oil and natural gas activities.

Proved Oil and Natural Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States and SEC guidelines.

Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and accretion expense and the full cost ceiling test limitation.

Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions.

The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir.

The accuracy of a reserve estimate is a function of (i) the quality and quantity of available data;

(ii) the interpretation of that data;

(iii) the accuracy of various mandated economic assumptions;

and (iv) the judgment of the persons preparing the estimate.

The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

Our estimated proved reserves for the years ended December 31, 2019 (Successor), 2018 (Predecessor) and 2017 (Predecessor) were prepared by Netherland, Sewell, an independent oil and natural gas reservoir engineering consulting firm.

For more information regarding reserve estimation, including historical reserve revisions, refer to Item 8.

Consolidated Financial Statements and Supplementary Data—“Supplemental Oil and Gas Information (Unaudited).

Depletion Expense

Our rate of recording depletion expense is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation.

If the estimates of proved reserves were to be reduced, the rate at which we record depletion expense would increase, reducing net income.

Such a reduction in reserves may result from calculated lower market prices, which may make it non-economic to drill for and produce higher cost reserves.

At December 31, 2019 (Successor), a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.49 per Boe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.53 per Boe.

Full Cost Ceiling Test Limitation

Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet.

If the net capitalized costs of our oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down to the extent of such

If required, it would reduce earnings and impact stockholders’

equity in the period of occurrence and could result in lower amortization expense in future periods.

The present value of our estimated proved reserves (discounted at 10%) is a major component of the ceiling calculation and represents the component that requires the most subjective judgments.

However, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment.

The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date.

If average oil and natural gas prices decline, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of our oil and natural gas properties could occur in the future.

If the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ended December 31, 2019 (Successor) had been 10% lower while all other factors remained constant, our ceiling amount related to our net book value of oil and natural gas properties would have been reduced by approximately $128.9 million and would have generated a full cost ceiling impairment.

Future Development Costs

Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment.

Future abandonment costs include costs to dismantle and relocate or dispose of our production facilities, gathering systems and related structures and restoration costs.

We develop estimates of these costs for each of our properties based upon their geographic location, type of production facility, well depth, currently available procedures and ongoing consultations with construction and engineering consultants.

Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment.

We review our assumptions and estimates of future development and future abandonment costs on an annual basis.

At December 31, 2019 (Successor), a five percent increase in future development and abandonment costs would increase the depletion rate by approximately $0.19 per Boe and a five percent decrease in future development and abandonment costs would decrease the depletion rate by $0.20 per Boe.

Accounting for Derivative Instruments and Hedging Activities

We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815).

ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value.

From time to time, in accordance with our policy, we may hedge a portion of our forecasted oil, natural gas, and natural gas liquids production.

We elected to not designate any of our positions for hedge accounting.

Accordingly, we record the net change in the mark‑to‑market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts”

on the consolidated statements of operations.

Our provision for taxes includes both state and federal taxes.

We account for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis.

Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled.

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized.

We classify all deferred tax assets and liabilities, along with any related valuation allowance, as noncurrent on the consolidated balance sheets.

In assessing the need for a valuation allowance on our deferred tax assets, we consider possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies.

We consider all available evidence (both positive and negative) in determining whether a valuation allowance is required.

Based upon the evaluation of available evidence we recorded an increase of $1.5 million and $186.9 million for the

period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively, to our valuation allowance as a result of increases to deferred tax assets for deferred deductions, capital losses and oil and gas properties offset by the write-off of deferred tax assets for net operating loss carryforwards and other tax attributes.

A valuation allowance of $478.7 million has been applied against our deferred tax assets as of December 31, 2019.

We follow ASC 740, Income Taxes (ASC 740).

ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements.

We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes.

During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain.

The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows.

The evaluation of a tax position in accordance with ASC 740 is a two‑step process.

The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position.

In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information.

The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements.

The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

Comparison of Results of Operations

Year Ended December 31, 2019 (Successor) Compared to Year Ended December 31, 2018 (Predecessor)

The table included below sets forth financial information for the periods presented.

The period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) are distinct reporting periods as a result of our adoption of fresh-start accounting upon our emergence from chapter 11 bankruptcy and are not comparable to prior periods.

Refer to the paragraphs following the table below for a discussion around our results of operations.

October 2, 2019

January 1, 2019

In thousands (except per unit and per Boe amounts)

December 31, 2019

October 1, 2019

December 31, 2018

Net income (loss)

Operating revenues:

Natural gas liquids

Operating expenses:

Lease operating

Workover and other

Taxes other than income

Gathering and other

Restructuring

General and administrative:

General and administrative

Stock-based compensation

Depletion, depreciation and accretion:

Depletion –

Depreciation –

Accretion expense

Full cost ceiling impairment

(Gain) loss on sale of oil and natural gas properties

(Gain) loss on sale of Water Assets

Other income (expenses):

Net gain (loss) on derivative contracts

Interest expense and other

Reorganization items, net

Gain (loss) on extinguishment of debt

Income tax benefit (provision)

Crude oil –

Natural gas –

Natural gas liquids –

Total MBoe (1)

Average daily production –

Average price per unit (2) :

Crude oil price - Bbl

Natural gas price - Mcf

Natural gas liquids price - Bbl

Total per Boe (1)

Average cost per Boe:

Lease operating

Workover and other

Taxes other than income

Gathering and other

Restructuring

General and administrative:

General and administrative

Stock-based compensation

Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil.

This ratio is based on energy equivalency, not price equivalency.

The price for a barrel of oil equivalent for natural gas is substantially lower than the price for a barrel of oil.

Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

Oil, natural gas and natural gas liquids revenues were $65.1 million, $158.4 million and $225.5 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

During the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), production averaged 20,293 Boe/d and 17,209 Boe/d, respectively, compared to average daily production of 13,904 Boe/d during 2018 (Predecessor).

Our average daily oil, natural gas and natural gas liquids production increased year over year due to the acquisition of properties in West Quito Draw and our drilling activities in Monument Draw and West Quito Draw.

Average realized prices (excluding the effects of hedging arrangements) were $34.88 per Boe, $33.71 per Boe and $44.44 per Boe for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

Lease operating expenses were $12.8 million, $39.6 million and $25.1 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

On a per unit basis, lease operating expenses were $6.86 per Boe, $8.43 per Boe and $4.94 per Boe for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

The increase in lease operating expenses from 2018 levels results from higher third party water hauling and disposal costs resulting from our divestiture of the Water Assets and an increase in our inventory of wells due to our drilling and acquisition activities.

Workover and other expenses were $1.7 million, $5.6 million and $8.6 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

On a per unit basis, workover and other expenses were $0.89 per Boe, $1.19 per Boe and $1.69 per Boe for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

The decreased costs in 2019 relate to recent strides in improving well and completion designs and fewer workovers performed in 2019 due to our focus on spending on our most economic projects.

Taxes other than income were $3.7 million, $9.2 million and $12.8 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

Most production taxes are based on realized prices at the wellhead.

As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease.

On a per unit basis, taxes other than income were $2.00 per Boe, $1.96 per Boe and $2.52 per Boe for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively

Gathering and other expenses were $10.8 million, $36.1 million and $60.1 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production, operating expenses of our oil and gas gathering infrastructure, gas treating fees, rig stacking charges and other.

Approximately $2.7 million, $9.6 million and $7.3 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production.

Approximately $8.1 million, $24.8 million and $51.8 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively, relate to operating expenses on our treating equipment and gathering support facilities and in the 2018 period, on our water recycling and disposal facilities.

Included in the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 are $10.9 million and $32.5 million, respectively, of wellhead-level costs to remove hydrogen sulfide from natural gas produced from our Monument Draw properties.

In April 2019 (Predecessor), we installed an H2S treating plant that more efficiently removes hydrogen sulfide from our produced natural gas and reduces our reliance on expensive wellhead-level treating.

Also included are $0.8 million and $1.9 million of rig stacking charges for

the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

Restructuring expense was approximately $1.2 million, $15.1 million and $0.1 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

During 2019 (for both the Successor and Predecessor periods), senior executives resigned from their positions.

These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits.

Additionally, during the third quarter of 2019 (Predecessor), we made the decision to consolidate into one corporate office located in Houston, Texas in an effort to improve efficiencies and go forward costs.

The transition includes both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions.

General and administrative expense was $5.1 million, $44.6 million and $46.8 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

The increase in general and administrative expenses results from prepetition costs incurred associated with our chapter 11 bankruptcy, partially offset by a reduction in our payroll and employee related benefits due to a reduction in our workforce and other administrative cost reductions as part of our continued focus on efficiencies and cost savings.

On a per unit basis, general and administrative expenses were $2.74 per Boe, $9.49 per Boe and $9.22 per Boe for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

Stock-based compensation expense was a credit of $8.0 million for the period of January 1, 2019 through October 1, 2019 (Predecessor) and an expense of $15.3 million for the year ended December 31, 2018 (Predecessor).

During 2019 (for both the Successor and Predecessor periods), senior executives resigned from their positions.

In accordance with the terms of these senior executives’

employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon termination.

For the period of January 1, 2019 through October 1, 2019 (Predecessor), we recognized an incremental reduction to stock-based compensation expense of $9.5 million associated with these modifications.

There was no stock-based compensation in the Successor period because all outstanding awards under the Predecessor incentive plan were cancelled or vested on the Effective Date and no new awards were issued in 2019 under the Successor incentive plan.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period.

Depletion expense was $19.5 million, $84.6 million and $69.8 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

On a per unit basis, depletion expense was $10.43 per Boe, $18.00 per Boe and $13.75 per Boe for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

The lower depletion rate in the Successor period is attributable to the change in our depletable base as a result of the adoption of fresh-start accounting.

Under the full cost method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling”, based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves.

Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense.

During 2019, the net book value of our oil and gas properties at March 31, June 30 and September 30 (Predecessor) exceeded the respective ceiling amounts for each period.

We recorded a full cost ceiling test impairment charge of $45.6 million for the three months ended September 30, 2019 (Predecessor).

The ceiling test impairment at September 30, 2019 (Predecessor) was driven by decreases in the first-day-of-the-month 12-month average price for crude oil used in the ceiling test calculation since June 30, 2019 (Predecessor), when the first-day-of-month 12-month average price for crude oil was $61.45 per barrel.

At June 30, 2019 (Predecessor), we recorded a full cost ceiling impairment of $664.4 million.

The ceiling test impairment at June 30, 2019 (Predecessor) was primarily driven by our focus on our most economic area, Monument Draw.

Accordingly, we transferred approximately $481.7 million of unevaluated property costs to the full cost pool as of June 30, 2019 (Predecessor), the majority of which was

associated with our Hackberry Draw area.

At March 31, 2019 (Predecessor), we recorded a full cost ceiling impairment of $275.2 million.

The ceiling test impairment at March 31, 2019 (Predecessor) was driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation and our intent to expend capital only on our most economic areas.

As such, we identified certain leases in the Hackberry Draw area with near-term expirations and transferred approximately $51.0 million of associated unevaluated property costs to the full cost pool during the three months ended March 31, 2019 (Predecessor).

Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves.

If the Williston Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and estimated proved reserves.

Accordingly, we recognized a reduction to the gain on the sale of the oil and natural gas properties associated with the Williston Divestiture of $7.2 million during the year ended December 31, 2018 (Predecessor), as a result of customary post-closing adjustments.

The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values.

On December 20, 2018 (Predecessor), we sold our water infrastructure assets located in the Delaware Basin for a total adjusted purchase price of $210.9 million.

We recognized a cumulative $115.9 million gain on the sale which includes the $0.5 million addition and $3.6 million reduction in the period of October 2, 2019 through December 31, 2019 (Successor) and January 1, 2019 through October 1, 2019 (Predecessor), respectively, due to customary closing adjustments.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids production.

Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations.

At December 31, 2019 (Successor), we had a $5.2 million derivative asset, $5.0 million of which was classified as current, and we had a $12.9 million derivative liability, $8.1 million of which was classified as current.

We recorded a net derivative loss of $16.7 million ($18.7 million net unrealized loss and $2.0 million net realized gain on settled and early terminated contracts) and a net derivative loss of $34.3 million ($45.8 million net unrealized loss and $11.5 million net realized gain on settled and early terminated contracts) for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively, compared to a net derivative gain of $92.6 million ($84.3 million net unrealized gain and $8.3 million net realized gain on settled and early terminated contracts) for the year ended December 31, 2018 (Predecessor).

Interest expense and other was $1.3 million, $37.6 million and $43.0 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

Interest expense for the Successor period represents interest associated with borrowings under the Senior Credit Agreement.

Interest expense in the Predecessor periods represents interest associated with the Predecessor Credit Agreement, the DIP Facility and the 6.75% senior notes for the respective periods in which borrowings were outstanding under each type of credit facility or senior notes.

In addition to interest expense, in the period from January 1, 2019 through October 1, 2019 (Predecessor), we paid fees associated with consents and amendments to our Predecessor Credit Agreement.

Reorganization items represent (i) expenses or income incurred subsequent to August 7, 2019 (when we filed voluntary petitions for relief under chapter 11) as a direct result of the reorganization Plan, (ii) gains or losses from liabilities settled, and (iii) fresh-start accounting adjustments.

The following table summarizes the net reorganization items (in thousands):

October 2, 2019

January 1, 2019

December 31, 2019

October 1, 2019

Gain on settlement of liabilities subject to compromise

Fresh start adjustments

Gain on adjustment of prepetition liabilities subject to compromise to the allowed claims amount

Write-off debt discount/premium and debt issuance costs

Reorganization professional fees and other

Gain (loss) on reorganization items

We recorded an income tax benefit of $95.8 million using the discrete effective rate method for the period of January 1, 2019 through October 1, 2019 (Predecessor), resulting from the reduction to the deferred tax liability generated by the impact of the full cost ceiling impairment on oil and natural gas properties and the deferred tax asset created by the tax loss from operations.

The 7.7% effective tax rate for the period from January 1, 2019 through October 1, 2019 (Predecessor) differs from the 21% statutory rate because of non-deductible executive compensation, non-deductible realized built in losses, and valuation allowances on deferred tax assets.

Recently Issued Accounting Pronouncements

We discuss recently adopted and issued accounting standards in Item 8.

Consolidated Financial Statements and Supplementary Data —Note 1, “

Summary of Significant Events and Accounting Policies .”

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 5. Market for Registrant’s Common Equity