BATTALION OIL : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-K)

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 upon our
emergence from chapter 11 bankruptcy on October 8, 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, the
convenience date applied for fresh-start accounting. 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. Refer to
Item 8. Consolidated Financial Statements and Supplementary Data - Note 2,
"Reorganization" and Note 3, "Fresh-start Accounting," for further details.

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.

Overview

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 and in the El Halcón area of East Texas. 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, 2020 (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
preceding 12-month first day of the month average prices of West Texas
Intermediate (WTI) crude oil spot price of $39.54 per Bbl and Henry Hub natural
gas spot price of $1.99 per MMBtu, were approximately 63.4 MMBoe, consisting of
38.2 MMBbls of oil, 12.1 MMBbls of natural gas liquids, and 78.5 Bcf of natural
gas. Approximately 57% of our proved reserves were classified as proved
developed as of December 31, 2020 (Successor). We maintain operational control
of 99.9% of our proved reserves. Substantially all of our proved reserves and
production at December 31, 2020 (Successor) are associated with our Delaware
Basin properties.

Our total operating revenues for the year ended December 31, 2020 (Successor)
were approximately $148.3 million. 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. Full year
2020 (Successor) production averaged 16,858 Boe/d. 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. The decrease in total
operating revenues and average daily production year over year was driven by our
temporary shut-in of a portion of producing wells across all our operating areas
in May and June 2020 (Successor) as a consequence of low oil prices as well as
average realized prices that were lower by approximately $10.25 per Boe. The
estimated production decrease associated with these temporary shut-ins was
approximately 1,300 Boe/d for 2020 (Successor). In December 2020 (Successor), we
divested properties that produced approximately 600 Boe/d during the nine months
ended September 30, 2020 (Successor).

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

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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 2020 (Successor), we spent approximately $101.8 million on oil and gas
capital expenditures. In early 2020, we ran one operated rig in the Delaware
Basin, and in March 2020, as a result of changes in market conditions and
commodity prices, we began to scale back our capital operations and spending and
eventually released the rig. We drilled and cased 4.0 gross (4.0 net) operated
wells, completed 5.0 gross (4.3 net) operated wells, and put online 7.0 gross
(6.3 net) operated wells during the year.

We expect to spend approximately $40.0 million to $50.0 million on capital
expenditures during 2021. Overall, we currently plan to drill two gross operated
wells during the year, complete six gross operated wells, and bring six gross
operated wells on production. Our 2021 capital budget currently contemplates
running one operated rig in the Delaware Basin at the beginning of the year. We
continuously monitor changes in market conditions and adapt our operational
plans as necessary in order to maintain financial flexibility, preserve core
acreage and meet contractual obligations, and therefore our capital budget is
subject to change.

We expect to fund our budgeted 2021 capital expenditures with cash and cash
equivalents on hand, cash flows from operations and, if necessary, borrowings
under our Senior Credit Agreement. In the event our cash flows are materially
less than anticipated or our costs are materially greater 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, 2021 of the WTI
crude oil spot price of $39.95 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, 2021 of the
Henry Hub natural gas price of $2.16 per MMBtu, adjusted by lease or field for
energy content, transportation fees, and regional price differentials, our
ceiling test calculation would not have generated an additional impairment at
December 31, 2020 (Successor), 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

Risk and Uncertainties

We are continuously monitoring the current and potential impacts of the novel
coronavirus (COVID-19) pandemic on our business, including how it has and may
continue to impact our operations, financial results, liquidity, contractors,
customers, employees and vendors, and taking appropriate actions in response,
including reducing capital expenditures, temporarily shutting-in producing
wells, and implementing various measures to ensure the continued operation of
our business in a safe and secure manner. COVID-19 and governmental actions to
contain the pandemic have contributed to an economic downturn, reduced demand
for oil and natural gas and, together with a price war between the Organization
of Petroleum Exporting Countries (OPEC)/Saudi Arabia and Russia, depressed oil
and natural gas prices to historically low levels. Although OPEC and Russia
subsequently agreed to reduce production, downward pressure on prices has
continued and could continue for the foreseeable future, particularly given
concerns over the impacts of the current economic downturn on demand. We are
unable to predict the ongoing effects that these events will have on our
business and financial condition due to numerous uncertainties, including the
severity and duration of the COVID-19 outbreak and the impacts that governmental
or other actions taken to limit the extent and duration of the outbreak, in
conjunction with economic conditions, will have on our business, demand for oil
and natural gas, and oil and natural gas prices. The health of our employees,
contractors and vendors, and our ability to meet staffing needs in our
operations and critical functions cannot be predicted, nor can the impact on our
customers, vendors and contractors. Any material effect on

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these parties could adversely impact us. These and other factors could affect
the Company's operations, earnings and cash flows and could cause our results to
not be comparable to those of the same period in previous years. For example, we
realized lower revenue as a result of commodity price declines, which began in
March 2020. In response to low commodity prices, we temporarily shut-in
producing wells in May and June 2020, which further contributed to lower
revenues in the current year. Additionally, we incurred ceiling test
impairments, which were primarily driven by a decline in the average pricing
used in the valuation of our reserves. The results presented in this Form 10-K
are not necessarily indicative of future operating results. For further
information regarding the actual and potential impacts of COVID-19 on us, see
"Risk Factors" in Item 1A of this Annual Report on Form 10-K.

Northern West Quito Assets Divestiture

On December 18, 2020 (Successor), we sold certain oil and gas properties and
related assets located in Ward County, Texas (the North West Quito Assets) to
Point Energy Partners Operating, LLC for a total sales price of $26.3 million in
cash, subject to customary post-closing adjustments as provided in the Purchase
and Sale Agreement. The effective date of the transaction was October 1, 2020
(Successor). Proceeds from the sale were recorded as a reduction to the carrying
value of our full cost pool with no gain or loss recorded. We used the net
proceeds from the sale to repay amounts outstanding under our Senior Credit
Agreement and for general corporate purposes. Estimated proved reserves
associated with the North West Quito Assets were approximately 2 MMBoe, or
approximately 3% of our year-end 2019 proved reserves. The North West Quito
Assets generated net production of approximately 600 Boe/d, or approximately 4%
of our average daily production for the nine months ended September 30, 2020
(Successor).

Successor Senior Revolving Credit Facility

On October 29, 2020 (Successor), we entered into the Third Amendment to Senior
Secured Revolving Credit Agreement and Limited Waiver (the Third Amendment). The
Third Amendment, among other things, set the borrowing base to $190.0 million as
of November 1, 2020, which eliminated the final monthly reduction of $5.0
million required under the Second Amendment (discussed below). The Third
Amendment also reduced the amount available for issuance of letters of credit to
$25.0 million and amended certain covenants including, but not limited to,
covenants relating to increasing the minimum mortgaged total value of proved
borrowing base properties from 85% to 90%. Additionally, the Third Amendment
provided for new covenants that, among other things, require us to enter into
swap agreements representing not less than 65% of our reasonably anticipated
projected production from proved reserves classified as developed producing
reserves for a period from the Third Amendment effective date through at least
December 31, 2022 and prohibit no more than $3.0 million of our uncontested
accounts payable or accrued expenses, liabilities or other obligations from
remaining outstanding for longer than 90 days. Pursuant to the Third Amendment,
the administrative agent and the lenders consented to a waiver of the Current
Ratio (as defined in the Senior Credit Agreement) for the fiscal quarter ended
September 30, 2020 and suspended testing of the Current Ratio until the fiscal
quarter ending December 31, 2021.



On July 31, 2020 (Successor), we entered into the Limited Waiver to Senior
Secured Revolving Credit Agreement (the Waiver) in which, the lenders consented
to waive maintenance of a Current Ratio (as defined in the Senior Credit
Agreement) of not less than 1.00 to 1.00 for the fiscal quarter ended June 30,
2020. Our failure to comply with the Current Ratio for the three months ended
June 30, 2020 (Successor) was primarily the result of our decision to shut in
certain production due to low oil prices coupled with capital spending required
to maintain certain of our oil and gas leasehold interests.



On April 30, 2020 (Successor), we entered into the Second Amendment to the
Senior Credit Agreement (Second Amendment) which, among other things, (i)
reduced the borrowing base to $200.0 million effective from April 30, 2020,
which was then reduced by $5.0 million monthly starting September 1, 2020 until
November 1, 2020, so that the borrowing base was scheduled to be $185.0 million
on November 1, 2020, provided the borrowing base redetermination scheduled for
November 1, 2020 occurred pursuant to the terms of the Senior Credit Agreement,
(ii) increased interest margins to 1.50% to 2.50% for ABR-based loans and 2.50%
to 3.50% for Eurodollar-based loans, (iii) provided that should our Consolidated
Cash Balance (as defined pursuant to the Second Amendment) exceed $10.0 million,
such amounts shall be used to prepay any borrowings under the Senior Credit
Agreement and thereafter, to the extent of any uncollateralized letters of
credit exposure, shall be cash collateralized in accordance with the Senior
Credit Agreement

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and (iv) allowed for a replacement benchmark rate to the London Interbank
Offered Rate (which may include SOFR, Compounded SOFR or Term SOFR). The Second
Amendment also added provisions related to a loan incurred by us under the
Paycheck Protection Program of the Coronavirus Aid, Relief, and Economic
Security Act (the CARES Act). We used, and the Second Amendment required us to
use, the loan proceeds for CARES Forgivable Uses under the CARES Act.
Additionally, the Second Amendment waived, for the fiscal quarter ended June 30,
2020, that we comply with the requirement under the Senior Credit Agreement that
we unwind certain swap agreements for which settlement payments were calculated
in such fiscal quarter to exceed 100% of actual production.

Paycheck Protection Program Loan

On April 16, 2020 (Successor), we entered into a promissory note (the PPP Loan)
for a principal amount of approximately $2.2 million from Bank of Montreal under
the Paycheck Protection Program of the CARES Act, which is administered by the
U.S. Small Business Administration (SBA). Pursuant to the terms of the CARES
Act, the proceeds of the PPP Loan may be used for payroll costs, mortgage
interest, rent or utility costs. The PPP Loan bears interest at a rate of 1.0%
per annum and, if not forgiven, has a maturity date of April 16, 2022. As long
as we make a timely application of forgiveness to the SBA, we are not required
to make any payments under the PPP Loan until the forgiveness amount is
communicated to us by the SBA.

Under the terms of the CARES Act, we can apply for and be granted forgiveness
for all or a portion of the PPP Loan. Such forgiveness will be determined,
subject to limitations, based on the use of loan proceeds in accordance with the
terms of the CARES Act during the covered period after loan origination and the
maintenance or achievement of certain employee levels. We believe we are
eligible for, and intend to pursue, forgiveness of the PPP Loan in accordance
with the requirements and limitations under the CARES Act; however, no assurance
can be provided that forgiveness of any portion of the PPP Loan will be
obtained.

Acid Gas Injection Well Permits

During the year ended December 31, 2020 (Successor), we received permits from
the Texas Railroad Commission and the Texas Commission on Environmental Quality
to construct and operate an acid gas injection well (AGI) by converting an
existing producing gas well. AGI can provide a more cost effective alternative
to sour gas treating. We are currently evaluating options for development of an
AGI facility, including, but not limited to, divestiture of the assets with an
associated third party treating arrangement for our sour gas production.

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."

Capital Resources and Liquidity

In March 2020 (Successor), the World Health Organization declared the outbreak
of COVID-19 a pandemic. The COVID-19 outbreak and associated government
restrictions significantly impacted economic activity and markets and
dramatically reduced current and anticipated demand for oil and natural gas at
the same time that supply was maintained at high levels due to a price and
market share war involving the OPEC/Saudi Arabia and Russia, all of which
adversely impacted the prices we received for our production during the year
ended December 31, 2020 (Successor). We realized lower revenue as a result of
these commodity price declines, which began in March 2020 (Successor). In
response to low commodity prices, we temporarily shut-in producing wells in May
and June 2020 (Successor), which further contributed to lower revenues in the
current year. Additionally, we incurred ceiling test impairments, which were
primarily driven by a decline in the average pricing used in the valuation of
our reserves.

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Continued actual or anticipated declines in domestic or foreign economic
activity or growth rates, regional or worldwide increases in tariffs or other
trade restrictions, turmoil affecting the U.S. or global financial system and
markets and a severe economic contraction either regionally or worldwide,
resulting from current efforts to contain the COVID-19 coronavirus or other
factors, could materially affect our business and financial condition and impact
our ability to finance operations by worsening the actual or anticipated future
drop in worldwide oil demand, negatively impacting the price received for oil
and natural gas production, adversely impacting our ability to comply with
covenants in our Senior Credit Agreement or causing our lenders to reduce the
borrowing base under our Senior Credit Agreement. Negative economic conditions
could also adversely affect the collectability of our trade receivables or
performance by our vendors and suppliers or cause our commodity hedging
arrangements to be ineffective if our counterparties are unable to perform their
obligations. All of the foregoing may adversely affect our business, financial
condition, results of operations, cash flows and, potentially, compliance with
the covenants contained in, and borrowing capacity under, our Senior Credit
Agreement.



We expect to spend approximately $40.0 million to $50.0 million in capital
expenditures, including drilling, completion, support infrastructure and other
capital costs, during 2021. 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, which has a current
borrowing base of $190.0 million. Amounts borrowed under our Senior Credit
Agreement will mature on October 8, 2024. At December 31, 2020 (Successor), we
had $158.0 million of indebtedness outstanding and approximately $4.7 million
letters of credit outstanding under our Senior Credit Agreement, resulting in
$27.3 million of borrowing capacity under the current borrowing base. The next
redetermination is scheduled for the spring of 2021. If our borrowing base is
reduced upon a redetermination, our resulting liquidity could be insufficient to
fund our business and operations and the reduction could result in a borrowing
base deficiency, which would require us to repay any amount outstanding in
excess of the borrowing base. As part of our ongoing efforts to manage our
business and liquidity, we are in regular contact with our lenders regarding
matters relating to the Senior Credit Agreement and we explore alternative means
to maintain our access to sufficient capital to fund our business, including
refinancings, asset sales, and additional means to reduce our capital
requirements. Bank of Montreal, who recently announced its plans to exit the
United States oil and gas investment banking business, currently holds
substantially all of the commitments under our Senior Credit Agreement. Bank of
Montreal's decision to exit its US investment banking business could lead to
similar decisions with regard to its participation in oil and gas lending in the
United States, resulting in the sale of our Senior Credit Agreement to another
financial institution, hedge fund, or other third party and could also lead us
to seek alternative forms of financing, the terms of which may be more costly,
provide less liquidity, or impose more restrictive covenants. While we believe
that alternatives to maintain liquidity under, or to replace, our Senior Credit
Agreement are available to us should they become necessary, there can be no
assurance in this regard.

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. We
have recently, and in the past, obtained amendments to the covenants under our
revolving credit agreements in circumstances where we anticipated that it might
be challenging for us to comply with the financial covenants for a particular
period of time. 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 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.

Depressions in oil and natural gas prices during 2020 and our decision to
temporarily shut-in a portion of our production in response to those market
conditions adversely impacted our cash flows, which, combined with cash
requirements associated with capital-intensive oil and gas development projects
undertaken in late 2019 and early 2020, led to challenges in compliance with the
Current Ratio under the Senior Credit Agreement for the fiscal quarter ended
June 30, 2020. Thus, on July 31, 2020 (Successor), we entered into the Waiver,
in which the lenders consented to waive maintenance of the Current Ratio (as
defined in the Senior Credit Agreement) of not less than 1.00 to 1.00 for the
fiscal quarter ended June 30, 2020. In conjunction with the fall borrowing base
redetermination process, and due to a decline in the value associated with our
derivative contracts, we pursued additional relief from our lenders in regards
to the Current Ratio. Pursuant to the Third Amendment, on October 29, 2020, the
lenders waived maintenance of the Current Ratio for

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the fiscal quarters ending September 30, 2020 and suspended testing of the
Current Ratio until the fiscal quarter ending December 31, 2021. As of December
31, 2020 (Successor), after giving effect to the Third Amendment, we were in
compliance with the financial covenants under the Senior Credit Agreement.

In prior years, we have also obtained waivers and amendments for optional
covenant violations. For instance, 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 once we acquired these assets required significant capital
expenditure outlays to replenish production and related EBITDA from the divested
producing properties. 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 difficulties that impacted our ability to comply, including,
elevated levels of hydrogen sulfide in the natural gas produced from our
Monument Draw wells and limited and expensive treatment and transportation
options. Severance payments to executives in 2019 also impacted our ability to
comply with our financial covenants.



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. As discussed above, the primary lender under the Senior Credit Agreement
has scaled back certain of its activities in the United States, and it is
unknown to what extent, if any, its oil and gas lending activities in the United
States may be impacted by that decision or whether that, or other factors, may
impact our ability to obtain covenant modifications in the future, if necessary.
In the event we are not successful in obtaining covenant modifications, if
needed, there is no assurance that we will be successful in implementing
alternatives that allow us to maintain compliance with our covenants or that we
will be successful in obtaining alternative financing that provides us with the
liquidity that we need to operate our business. Even if successful, alternative
sources of financing could prove more expensive than borrowing under our Senior
Credit Agreement.

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 30 months. These limitations result in our liquidity being
susceptible to commodity price declines. Additionally, while intended to reduce
the effects of volatile commodity prices, derivative transactions may limit our
potential gains and increase our potential losses if commodity prices were to
rise substantially over the price established by the hedge. Our Senior Credit
Agreement contains minimum hedging requirements. Pursuant to the Third
Amendment, we are required to utilize fixed price swaps to hedge at least 65% of
anticipated production from proved developed producing reserves through December
31, 2022. 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.

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
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.

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Cash Flow

In 2020 (Successor), cash generated by operating activities, borrowings under
our Senior Credit Agreement and proceeds from the North West Quito Assets
divestiture were used to fund our drilling and completion program. See "Results
of Operations" for a review of the impact of prices and volumes on operating
revenues.

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

                                                        Successor                                   Predecessor
                                                                  Period from            Period from
                                                                October 2, 2019        January 1, 2019
                                             Year Ended             through                through             Year Ended
                                          December 31, 2020    December 31, 2019       October 1, 2019      December 31, 2018
Cash flows provided by (used in)         $                     $                      $                    $
operating activities                                  50,197               13,654              (39,731)                 67,155
Cash flows provided by (used in)
investing activities                                (72,354)             (42,790)             (254,417)              (706,485)
Cash flows provided by (used in)
financing activities                                  16,177               10,026               276,667                262,125
Net increase (decrease) in cash, cash    $                     $                      $                    $
equivalents and restricted cash                      (5,980)             (19,110)              (17,481)              (377,205)




Operating Activities. Net cash flows provided by operating activities for the
year ended December 31, 2020 (Successor) was $50.2 million. 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 was $67.2 million for the year ended December 31, 2018 (Predecessor).

Operating cash flows for the year ended December 31, 2020 (Successor) increased
from the prior year due to decreases in our operating expenses associated with
our focus on efficiencies and cost savings and a decrease in interest expense
associated with lower outstanding debt due to our chapter 11 bankruptcy. In
addition, realized gains from derivative contracts were higher in the year ended
December 31, 2020 (Successor), which included the early termination of certain
derivative contracts. During the year ended December 31, 2020 (Successor), we
terminated certain derivative contracts in advance of their natural expiration
dates and received net proceeds of approximately $22.9 million during the
period. These increases to operating cash flows in 2020 were partially offset by
decreased oil and natural gas revenues as a result of lower realized commodity
prices and lower production volumes than the comparable prior year period.

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.

Investing Activities. Net cash flows used in investing activities for the year
ended December 31, 2020 (Successor) were approximately $72.4 million. 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.

During the year ended December 31, 2020 (Successor) we spent $101.8 million on
oil and natural gas capital expenditures, of which $65.1 million related to
drilling and completion costs and $33.9 million related to the development of
our treating equipment and gathering support infrastructure. We received $29.0
million in proceeds from

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the sale of oil and natural gas properties, primarily from the North West Quito Assets in December 2020. In addition, we received $0.5 million in insurance proceeds associated with a casualty loss on our support infrastructure.

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.

Financing Activities. Net cash flows provided by financing activities for the
year ended December 31, 2020 (Successor) were approximately $16.2 million. 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.

During the year ended December 31, 2020 (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. We also borrowed $2.2 million under the PPP Loan to fund
payroll costs, rent and utilities.

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 a rights offering to our unsecured senior noteholders and $5.8 million from
a rights offering to our previous common stockholders, both related to our
chapter 11 bankruptcy. 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. 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.

Senior Revolving Credit Facility

On October 8, 2019, we entered into the Senior Credit Agreement with Bank of
Montreal, as administrative agent, and certain other financial institutions
party thereto, as lenders. The Senior Credit Agreement, as amended, provides for
a $750.0 million senior secured reserve-based revolving credit facility with a
current borrowing base of $190.0 million. A portion of the Senior Credit
Agreement, in the amount of $25.0 million, is available for the issuance of
letters of credit. The maturity date of the Senior Credit Agreement is October
8, 2024. Redeterminations will occur semi-annually on May 1 and November 1, with
the lenders and us each having the right to one interim unscheduled
redetermination

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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. Amounts outstanding under the
Senior Credit Agreement bear interest at specified margins over the base rate of
1.50% to 2.50% for ABR-based loans or at specified margins over LIBOR of 2.50%
to 3.50% 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. 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 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.

On October 29, 2020 (Successor),we entered into the Third Amendment. The Third
Amendment, among other things, set the borrowing base to $190.0 million as of
November 1, 2020, which eliminated the final monthly reduction of $5.0 million
required under the Second Amendment. The Third Amendment also reduced the amount
available for issuance of letters of credit to $25.0 million and amended certain
covenants including, but not limited to, covenants relating to increasing the
minimum mortgaged total value of proved borrowing base properties from 85% to
90%. Additionally, the Third Amendment provided for new covenants that, among
other things, require us to enter into swap agreements representing not less
than 65% of our reasonably anticipated projected production from proved reserves
classified as developed producing reserves for a period from the Third Amendment
effective date through at least December 31, 2022 and prohibit no more than
$3.0 million of our uncontested accounts payable or accrued expenses,
liabilities or other obligations from remaining outstanding for longer than 90
days. Pursuant to the Third Amendment, the administrative agent and the lenders
consented to a waiver of the Current Ratio (as defined in the Senior Credit
Agreement) for the fiscal quarter ended September 30, 2020 and suspended testing
of the Current Ratio until the fiscal quarter ending December 31, 2021.

On July 31, 2020 (Successor), we entered into the Waiver which waived maintenance of the Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00 for the fiscal quarter ended June 30, 2020.

On April 30, 2020 (Successor), we entered into the Second Amendment which, among
other things, (i) reduced the borrowing base to $200.0 million effective from
April 30, 2020, which was then to be reduced by $5.0 million monthly starting
September 1, 2020 until November 1, 2020, so that the borrowing base was
scheduled to be $185.0 million on November 1, 2020, provided the borrowing base
redetermination scheduled for November 1, 2020 occurred pursuant to the terms of
the Senior Credit Agreement, (ii) increased interest margins to 1.50% to 2.50%
for ABR-based loans and 2.50% to 3.50% for Eurodollar-based loans, (iii)
provided that should our Consolidated Cash Balance (as defined pursuant to the
Second Amendment) exceed $10.0 million, such amounts shall be used to prepay any
borrowings under the Senior Credit Agreement and thereafter, to the extent of
any uncollateralized letters of credit exposure, shall be cash collateralized in
accordance with the Senior Credit Agreement and (iv) allowed for a replacement
benchmark rate to the London Interbank Offered Rate (which may include SOFR,
Compounded SOFR or Term SOFR). The Second Amendment also added provisions
related to a loan incurred by us under the Paycheck Protection Program of the
CARES Act. We used, and the Second Amendment required us to use, the loan
proceeds for CARES Forgivable Uses under the CARES Act. Additionally, the Second
Amendment waived, for the fiscal quarter ended June 30, 2020, that we

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comply with the requirement under the Senior Credit Agreement that we unwind
certain swap agreements for which settlement payments were calculated in such
fiscal quarter to exceed 100% of actual production.

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, to not
greater than 3.50 to 1.00.

As of December 31, 2020 (Successor), after giving effect to the Third Amendment, we were in compliance with the financial covenants under the Senior Credit Agreement.

Paycheck Protection Program Loan

On April 16, 2020 (Successor), we entered into the PPP Loan for a principal
amount of approximately $2.2 million from Bank of Montreal under the Paycheck
Protection Program of the CARES Act, which is administered by the SBA. Pursuant
to the terms of the CARES Act, the proceeds of the PPP Loan may be used for
payroll costs, mortgage interest, rent or utility costs. The PPP Loan bears
interest at a rate of 1.0% per annum and, if not forgiven, has a maturity date
of April 16, 2022. As long as we make a timely application of forgiveness to the
SBA, we are not required to make any payments under the PPP Loan until the
forgiveness amount is communicated to us by the SBA.

We may elect, at our option, to prepay 20% or less of the borrowings outstanding
under the PPP Loan without premium or penalty, and without notice. Prepayments
of more than 20% of the outstanding borrowings require written advanced notice
and payment of accrued interest. The PPP Loan contains certain events of default
including non-payment, breach of representations and warranties, cross-defaults
to other loans with the lender or to material indebtedness, voluntary or
involuntary bankruptcy, judgments and change in control.

Under the terms of the CARES Act, we can apply for and be granted forgiveness
for all or a portion of the PPP Loan. Such forgiveness will be determined,
subject to limitations, based on the use of loan proceeds in accordance with the
terms of the CARES Act during the covered period after loan origination and the
maintenance or achievement of certain employee levels. We believe we are
eligible for, and intend to pursue, forgiveness of the PPP Loan in accordance
with the requirements and limitations under the CARES Act; however, no assurance
can be provided that forgiveness of any portion of the PPP Loan will be
obtained.

Off-Balance Sheet Arrangements

At December 31, 2020 (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. See Item 8. 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.

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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 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
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.

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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, 2020 (Successor),
2019 (Successor) and 2018 (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, 2020 (Successor), a five percent positive revision to proved reserves would
decrease the depletion rate by approximately $0.40 per Boe and a five percent
negative revision to proved reserves would increase the depletion rate by
approximately $0.44 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 excess. 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, 2020
(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 $93.0 million and would have increased
our full cost ceiling impairment by the same amount.

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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,
2020 (Successor), a five percent increase in future development and abandonment
costs would increase the depletion rate by approximately $0.23 per Boe and a
five percent decrease in future development and abandonment costs would decrease
the depletion rate by $0.24 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.

Income Taxes

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 $10.8
million to our valuation allowance as a result of increases to deferred tax
assets for deferred deductions and net operating losses offset by the write-off
of deferred tax assets for oil and gas properties and other deferred tax assets
during 2020 (Successor). A valuation allowance of $489.5 million has been
applied against our deferred tax assets as of December 31, 2020 (Successor).

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

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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.





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Comparison of Results of Operations

Year Ended December 31, 2020 (Successor) Compared to Year Ended December 31, 2019 (Successor)

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.




                                                     Successor                      Predecessor
                                                            Period from             Period from
                                                          October 2, 2019         January 1, 2019
                                          Year Ended          through                 through
In thousands (except per unit and per      December
Boe amounts)                               31, 2020      December 31, 2019        October 1, 2019
Net income (loss)                        $   (229,707)   $         (10,460)      $     (1,156,053)
Operating revenues:
Oil                                            125,985               58,325                145,024
Natural gas                                      5,818                1,719                    107
Natural gas liquids                             14,972                5,071                 13,229
Other                                            1,514                  467                    743
Operating expenses:
Production:
Lease operating                                 42,106               12,804                 39,617
Workover and other                               3,709                1,655                  5,580
Taxes other than income                         10,056                3,730                  9,213
Gathering and other                             56,016               10,812                 36,057
Restructuring                                    2,580                1,175                 15,148
General and administrative:
General and administrative                      15,878                5,111                 44,585
Stock-based compensation                         2,578                    -                (8,035)
Depletion, depreciation and
accretion:
Depletion - Full cost                           60,543               19,476                 84,579
Depreciation - Other                               925                  376                  6,026
Accretion expense                                  585                  144                    307
Full cost ceiling impairment                   215,145                    -                985,190
(Gain) loss on sale of Water Assets                  -                (506)                  3,618
Other income (expenses):
Net gain (loss) on derivative
contracts                                       38,759             (16,692)               (34,332)
Interest expense and other                     (6,634)              (1,275)               (37,606)
Reorganization items, net                            -              (3,298)              (117,124)
Income tax benefit (provision)                       -                    -                 95,791

Production:
Crude oil - MBbls                                3,446                1,057                  2,723
Natural gas - MMcf                               8,769                2,755                  6,381
Natural gas liquids - MBbls                      1,262                  351                    911
Total MBoe(1)                                    6,170                1,867                  4,698
Average daily production - Boe(1)               16,858               20,293                 17,209

Average price per unit (2):
Crude oil price - Bbl                    $       36.56   $            55.18      $           53.26
Natural gas price - Mcf                           0.66                 0.62                   0.02
Natural gas liquids price - Bbl                  11.86                14.45                  14.52
Total per Boe(1)                                 23.79                34.88                  33.71

Average cost per Boe:
Production:
Lease operating                          $        6.82   $             6.86      $            8.43
Workover and other                                0.60                 0.89                   1.19
Taxes other than income                           1.63                 2.00                   1.96
Gathering and other                               9.08                 5.79                   7.67
Restructuring                                     0.42                 0.63                   3.22
General and administrative:
General and administrative                        2.57                 2.74                   9.49
Stock-based compensation                          0.42                    -                 (1.71)
Depletion                                         9.81                10.43                  18.00

--------------------------------------------------------------------------------

(1) 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.

(2) Amounts exclude the impact of cash paid/received on settled contracts as we

    did not elect to apply hedge accounting.




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Oil, natural gas and natural gas liquids revenues were $146.8 million, $65.1
million and $158.4 million for the year ended December 31, 2020 (Successor), the
period of October 2, 2019 through December 31, 2019 (Successor) and the period
of January 1, 2019 through October 1, 2019 (Predecessor), respectively. For the
year ended December 31, 2020 (Successor), production averaged 16,858 Boe/d.
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. Our average daily oil,
natural gas and natural gas liquids production decreased year over year due
primarily to the temporary shut-in of a portion of producing wells across all
operating areas during the months of May and June 2020 (Successor). Estimated
production decreases associated with these temporary shut-ins was approximately
1,300 Boe/d for the year ended December 31, 2020 (Successor). Average realized
prices (excluding the effects of hedging arrangements) were $23.79 per Boe,
$34.88 per Boe and $33.71 per Boe for the year ended December 31, 2020
(Successor), the period of October 2, 2019 through December 31, 2019 (Successor)
and the period of January 1, 2019 through October 1, 2019 (Predecessor),
respectively. 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, quality of production,
basis differentials and other factors.

Lease operating expenses were $42.1 million, $12.8 million and $39.6 million for
the year ended December 31, 2020 (Successor), the period of October 2, 2019
through December 31, 2019 (Successor) and the period of January 1, 2019 through
October 1, 2019 (Predecessor), respectively. On a per unit basis, lease
operating expenses were $6.82 per Boe, $6.86 per Boe and $8.43 per Boe for the
year ended December 31, 2020 (Successor), the period of October 2, 2019 through
December 31, 2019 (Successor) and the period of January 1, 2019 through October
1, 2019 (Predecessor), respectively. The decrease in lease operating expenses in
2020 results from our focus on optimization of production operations and
decreased salt water disposal costs due to lower production volumes and less
produced water.

Workover and other expenses were $3.7 million, $1.7 million and $5.6 million for
the year ended December 31, 2020 (Successor), the period of October 2, 2019
through December 31, 2019 (Successor) and the period of January 1, 2019 through
October 1, 2019 (Predecessor), respectively. On a per unit basis, workover and
other expenses were $0.60 per Boe, $0.89 per Boe and $1.19 per Boe for the year
ended December 31, 2020 (Successor), the period of October 2, 2019 through
December 31, 2019 (Successor) and the period of January 1, 2019 through October
1, 2019 (Predecessor), respectively. The decreased costs in 2020 relate to
recent strides in improving well and completion designs and fewer workovers
performed.

Taxes other than income were $10.1 million, $3.7 million and $9.2 million for
the year ended December 31, 2020 (Successor), the period of October 2, 2019
through December 31, 2019 (Successor) and the period of January 1, 2019 through
October 1, 2019 (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 $1.63 per Boe, $2.00
per Boe and $1.96 per Boe for the year ended December 31, 2020 (Successor), the
period of October 2, 2019 through December 31, 2019 (Successor) and the period
of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

Gathering and other expenses were $56.0 million, $10.8 million and $36.1 million
for the year ended December 31, 2020 (Successor), the period of October 2, 2019
through December 31, 2019 (Successor) and the period of January 1, 2019 through
October 1, 2019 (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 $13.9 million, $2.7
million and $9.6 million for the year ended December 31, 2020 (Successor), the
period of October 2, 2019 through December 31, 2019 (Successor) and the period
of January 1, 2019 through October 1, 2019 (Predecessor), respectively, relate
to gathering and marketing fees paid to third parties on our oil and natural gas
production. Oil and natural gas production volumes were lower in 2020 due to the
temporary shut-in of certain producing wells during the months of May and June
2020 (Successor). Approximately $38.7 million, $8.1 million and $24.8 million
for the year ended December 31, 2020 (Successor), the period of October 2, 2019
through December 31, 2019 (Successor) and the period of January 1, 2019 through
October 1, 2019 (Predecessor), respectively, relate to operating expenses on our
treating equipment and gathering support facilities. In April 2019
(Predecessor), we installed a hydrogen sulfide treating plant that more
efficiently removes hydrogen sulfide from our produced natural gas and reduces
our reliance on expensive wellhead-level treating. Until the treating plant was
operational, we incurred $10.9 million of wellhead-level costs to remove
hydrogen sulfide from natural gas

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produced from our Monument Draw properties during the period of January 1, 2019
through October 1, 2019 (Predecessor). Our produced natural gas from the
Monument Draw area increased in the current year due to our development
activities, despite a decrease in our overall production volumes. These natural
gas volumes are processed through our hydrogen sulfide treating plant in the
area, which led to higher operating expenses, such as chemical costs, associated
with our treating equipment during the current year. Also included are $3.4
million and $0.8 million of rig termination and stacking charges for the year
ended December 31, 2020 (Successor) and the period of January 1, 2019 through
October 1, 2019 (Predecessor), respectively.

Restructuring expense was approximately $2.6 million, $1.2 million and $15.1
million for the year ended December 31, 2020 (Successor), the period of October
2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019
through October 1, 2019 (Predecessor), respectively. During the year ended
December 31, 2020 (Successor), we incurred restructuring charges related to the
consolidation into one corporate office and had reductions in our workforce due
to efforts to improve efficiencies and reduce future costs. In May 2020
(Successor), in furtherance of the consolidation into one corporate office, we
exercised a one-time early termination option under the lease agreement for our
office space in Denver, Colorado. During 2019 (for both the Successor and
Predecessor periods), several senior executives resigned from their positions.
These were considered terminations without cause under their respective
employment agreements, which entitled them to certain benefits. Additionally, in
2019 (Predecessor), when the decision was made to consolidate into one corporate
office, we began to incur restructuring charges which included both severance
and relocation costs as well as incremental costs associated with hiring new
employees to replace key positions.

General and administrative expense was $15.9 million, $5.1 million and $44.6
million for the year ended December 31, 2020 (Successor), the period of October
2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019
through October 1, 2019 (Predecessor), respectively. The decrease in general and
administrative expense primarily results from a reduction in our payroll and
employee-related benefits due to a reduction in our workforce since the prior
year period and other administrative cost reductions as part of our continued
focus on efficiencies and cost savings. The decrease in general and
administrative expenses is also attributed to prepetition costs incurred in 2019
associated with our chapter 11 bankruptcy that year. On a per unit basis,
general and administrative expense were $2.57 per Boe, $2.74 per Boe and $9.49
per Boe for the year ended December 31, 2020 (Successor), the period of October
2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019
through October 1, 2019 (Predecessor), respectively.

Stock-based compensation expense was $2.6 million and a credit of $8.0 million
for the year ended December 31, 2020 (Successor) and the period of January 1,
2019 through October 1, 2019 (Predecessor). During 2019 (for both the Successor
and Predecessor periods), several 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. Stock-based compensation expense also decreased in the current
year due to a reduction in our workforce.

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 $60.5 million, $19.5 million and $84.6 million
for the year ended December 31, 2020 (Successor), the period of October 2, 2019
through December 31, 2019 (Successor) and the period of January 1, 2019 through
October 1, 2019 (Predecessor), respectively. On a per unit basis, depletion
expense was $9.81 per Boe, $10.43 per Boe and $18.00 per Boe for the year ended
December 31, 2020 (Successor), the period of October 2, 2019 through December
31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019
(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 and the full cost ceiling test impairments incurred in
2020.

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

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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 2020, the
net book value of our oil and gas properties at June 30, September 30 and
December 31 (Successor) exceeded the ceiling amount and we recorded full cost
ceiling test impairments before income taxes of $60.1 million, $128.3 million
and $26.7 million, respectively, for the periods. The ceiling test impairments
during 2020 (Successor) were primarily driven by decreases in the
first-day-of-the-month 12-month average prices for crude oil used in the ceiling
test calculation. Additionally, during the three months ended September 30, 2020
(Successor), the transfer of $23.6 million of unevaluated property costs to the
full cost pool due to our intent to focus available capital on Monument Draw
also contributed to the impairment recorded for the period. During the three
months ended December 31, 2020 (Successor), proved undeveloped reserves
additions as a result of changes to our five year development plan partially
offset the impact on the impairment of the average price decline for the period.
During 2019, the net book value of our oil and gas properties at March 31, June
30 and September 30 (Predecessor) exceeded the ceiling amount and we recorded
full cost ceiling test impairments before income taxes of $275.2 million, $664.4
million, and $45.6 million, respectively, for the periods. The ceiling test
impairments during 2019 (Predecessor) were driven by transfers of unevaluated
property to the full cost pool that occurred during the year and decreases in
the first-day-of-the-month 12-month average prices for crude oil used in the
ceiling test calculation. For the three months ended June 30, 2019
(Predecessor), we transferred approximately $481.7 million of unevaluated
property costs to the full cost pool, the majority of which were associated with
our Hackberry Draw area. For the three months ended March 31, 2019
(Predecessor), we identified certain leases in our Hackberry Draw area with
near-term expirations and transferred approximately $51.0 million of associated
unevaluated property costs to the full cost pool. These transfers of unevaluated
property to the full cost pool in 2019 (Predecessor) were the result of our
intent to focus available capital on our Monument Draw area. 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.

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, 2020 (Successor), we had a $12.6 million derivative asset, $8.6 million of
which was classified as current, and we had a $26.4 million derivative
liability, $22.1 million of which was classified as current. We recorded a net
derivative gain of $38.8 million ($6.1 million net unrealized loss and $44.9
million net realized gain on settled and early terminated contracts) for the
year ended December 31, 2020 (Successor). During 2020, we terminated certain
derivative contracts in advance of their natural expiration dates and received
net proceeds of approximately $22.9 million, which were included in the $44.9
million realized gains for the year. 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.

Interest expense and other was $6.6 million, $1.3 million and $37.6 million for
the year ended December 31, 2020 (Successor), the period of October 2, 2019
through December 31, 2019 (Successor) and the period of January 1, 2019 through
October 1, 2019 (Predecessor), respectively. Interest expense for the Successor
periods represents interest associated with borrowings under the Senior Credit
Agreement and the PPP Loan. Interest expense in the Predecessor period
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.

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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):


                                                       Successor             Predecessor
                                                      Period from            Period from
                                                    October 2, 2019        January 1, 2019
                                                        through                through
                                                   December 31, 2019       October 1, 2019
Gain on settlement of liabilities subject to
compromise                                         $                -     $ 

481,777

Fresh start adjustments                                             -       

(591,300)

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

20,274

Write-off debt discount/premium and debt
issuance costs                                                      -       

(10,953)

Reorganization professional fees and other                    (3,298)       

(16,922)

Gain (loss) on reorganization items                $          (3,298)     $       (117,124)




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."

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