The following discussion and analysis of our financial condition and results of
operations should be read in conjunction with the accompanying consolidated
financial statements and related notes in "Item 8. Financial Statements and
Supplementary Data" in this Annual Report. The following discussion and analysis
contains forward-looking statements that reflect our future plans, estimates,
beliefs and expected performance. The forward-looking statements are dependent
upon events, risks and uncertainties that may be outside our control. Our actual
results could differ materially from those discussed in these forward-looking
statements. Factors that could cause or contribute to such differences include,
but are not limited to, future market prices for oil, natural gas and NGLs,
future production volumes, estimates of proved reserves, capital expenditures,
economic and competitive conditions, regulatory changes, continued and future
impacts of COVID-19 and other uncertainties, as well as those factors discussed
in "Cautionary Statement Concerning Forward-Looking Statements" and "Item 1A.
Risk Factors" in this Annual Report, all of which are difficult to predict. In
light of these risks, uncertainties and assumptions, the forward-looking events
discussed may not occur. We do not undertake any obligation to publicly update
any forward-looking statements except as otherwise required by applicable law.
Overview
We are an independent oil and natural gas company focused on the development of
unconventional oil and associated liquids-rich natural gas reserves in the
Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of
the Permian Basin. Our capital programs are focused on projects that we believe
provide the highest return on capital.
Market Conditions
The recent worldwide outbreak of COVID-19 and various governmental actions taken
to mitigate the impact of COVID-19 have resulted in an unprecedented decline in
the demand for oil and natural gas. In addition in March 2020, the decision by
Saudi Arabia to drastically reduce export prices and increase oil production
(the "Saudi-Russia oil price war") followed by curtailment agreements among OPEC
and other countries such as Russia further increased uncertainty and volatility
around global oil supply-demand dynamics. As a result, there was a significant
decline in commodity prices starting at the end of the first quarter of 2020.
However, during the second quarter of 2020, OPEC and other oil producing
countries agreed to reduce their crude oil production, while U.S. producers
substantially reduced or suspended drilling activity and in most cases curtailed
production due to low oil prices and poor economics. The oil production cuts by
OPEC and other producing countries were agreed upon and continued during the
remainder of 2020, and U.S. drilling activity remained low throughout the second
half of 2020. These actions have aided in a partial recovery of global commodity
prices. Specifically, WTI spot prices for crude oil fell to a low of negative
$37.63 per barrel on April 20, 2020 (due to depressed demand and insufficient
storage capacity, particularly at the WTI physical settlement location in
Cushing, Oklahoma) and have since recovered to a high of $49.10 per barrel on
December 18, 2020.
The oil and natural gas industry is cyclical, and it is likely that commodity
prices, as well as commodity price differentials, will continue to be volatile
due to fluctuations in global supply and demand, inventory levels, the continued
effects of COVID-19, geopolitical events, weather conditions, global transition
to alternative energy sources and other factors. The following table highlights
the quarterly average NYMEX price trends for crude oil and natural gas since the
first quarter of 2018:
                                                         2018                                                                2019                                                                2020
                                 Q1               Q2               Q3               Q4               Q1               Q2               Q3               Q4               Q1               Q2               Q3               Q4
Crude Oil (per Bbl)          $ 62.91          $ 68.07          $ 69.50

$ 58.81 $ 54.90 $ 59.81 $ 56.45 $ 56.94 $ 46.19 $ 28.00 $ 40.93 $ 42.66 Natural Gas (per MMBtu) $ 3.08 $ 2.85 $ 2.93

$  3.77          $  2.88          $  2.51          $  2.33          $  2.34          $  1.88          $  1.65          $  1.95          $  2.47



A sustained drop in oil, natural gas and NGL prices, such as those we have
experienced during 2020, will not only decrease our revenues but can also reduce
the amount of oil, natural gas and NGLs that we can produce economically and can
therefore potentially lower our oil, natural gas and NGL reserve quantities.
Lower commodity prices (including our realized differentials) and lower futures
curves for oil and gas prices, can also result in further impairments of our
proved oil and natural gas properties or undeveloped acreage (such as the
impairments discussed below under "Results of Operations") and may materially
and adversely affect our future business, financial condition, results of
operations, operating cash flows, liquidity and/or ability to finance planned
capital expenditures. Lower realized prices may also reduce the borrowing base
under CRP's credit agreement (such as the reduction discussed below under
"Financing Highlights"), which is determined at the discretion of the lenders
and is based on the collateral value of our proved reserves that have been
mortgaged to the lenders. Upon a redetermination, if any borrowings in excess of
the revised borrowing capacity were outstanding, we could be forced to
immediately repay a portion of the debt outstanding under the credit agreement.
Additionally, the lower price environment and its impact to our operations could
impact our ability to comply with the covenants under our credit agreement and
senior notes.
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COVID-19 Outbreak
The COVID-19 outbreak and its development into a pandemic in March 2020 have
required that we take precautionary measures intended to help minimize the risk
to our business, employees, customers, contractors, suppliers and the
communities in which we operate. Our operational employees have been and are
currently able to work on site, while the vast majority of our non-operational
employees have worked remotely or reported to our offices on a limited basis
during 2020. We have taken various precautionary measures with respect to our
operational employees, direct contractors and employees who returned to our
offices or job sites during the year such as (i) requiring them to verify they
have not experienced any symptoms consistent with COVID-19, or been in close
contact with someone showing such symptoms, before reporting to the work site or
office, (ii) self-quarantining any employees or contractors who have shown signs
or symptoms of COVID-19 regardless of whether such person has been confirmed to
be infected, (iii) imposing social distancing requirements on work sites and at
our offices that are in accordance with the guidelines released by the Center
for Disease Control (the "CDC") as well as local and state authorities, (iv)
requiring all employees and contractors to have a fit-test for and wear KN-95
type respirators while in our offices and work sites, and (v) encouraging all
employees and contractors to follow the CDC recommended preventive measures
(including those mentioned above) to limit the spread of COVID-19. We have not
experienced any operational disruptions (including disruptions from our
suppliers or service providers) as a result of the COVID-19 outbreak.
2020 Highlights and Future Considerations
The changes in the macro environment and related volatility in commodity prices
that occurred during 2020 discussed above have significantly impacted our
results of operations for the year ended December 31, 2020, and we believe that
our future operating results and near-term financial condition could continue to
be impacted, until such time that oil supply and demand dynamics re-balance and
stabilize.
Operational Highlights
We operated a five-rig drilling program during the majority of the first quarter
of 2020, which enabled us to complete and bring online 26 gross operated wells
with an average effective lateral length of approximately 7,000 feet during the
first half of 2020. Due to the decline in crude oil prices and ongoing
uncertainty regarding the oil supply-demand macro environment, in the second
quarter of 2020, we suspended all drilling and completion activities in order to
preserve capital. Specifically, we reduced our operated drilling rig program to
zero rigs starting in April of 2020 and continued with no drilling rigs in
operation until the end of the third quarter. In addition, given the weakness in
realized oil prices, we voluntarily curtailed or shut-in approximately 20% of
our production during the month of May, but we were able to bring the majority
of this production back online in June as crude oil prices recovered, with
minimal incremental cost.

We did not experience any further curtailments to our production during the
remainder of 2020, and we recommenced drilling and completion activity in the
third quarter of 2020. We completed an additional 5 gross operated wells during
August of 2020 with an effective lateral length of approximately 9,000 feet,
which were previously drilled during the first quarter of 2020. Further, we
initiated a one-rig drilling program at the end of the third quarter, which we
operated through the remainder of the year and added a second drilling rig in
December. During the second half of 2020, we drilled six gross operated wells to
total depth and began drilling an additional three gross operated wells, all of
which we plan to complete in the first quarter of 2021.
Financing Highlights
On May 22, 2020, we completed an opportunistic private exchange of our debt
pursuant to which $110.6 million aggregate principal amount of CRP's 5.375%
senior unsecured notes due 2026 (the "2026 Senior Notes") and $143.7 million
aggregate principal amount of CRP's 6.875% senior unsecured notes due 2027 (the
"2027 Senior Notes" and, together with the 2026 Senior Notes, the "Senior
Unsecured Notes") were validly tendered and exchanged by certain eligible
bondholders for consideration consisting of $127.1 million aggregate principal
amount (the "Debt Exchange") of newly issued 8.00% second lien senior secured
notes due 2025 (the "Senior Secured Notes"). This transaction resulted in the
removal of $127.1 million in aggregate principal amount of Senior Unsecured
Notes from the long-term debt balance in our consolidated balance sheets.
On May 1, 2020, we entered into the second and third amendments to CRP's amended
and restated credit agreement (the "Q2 2020 Amendments") with the lenders to our
existing credit agreement. Pursuant to the Q2 2020 Amendments, the borrowing
base and level of elected commitments were both reduced to $700.0 million from
their previous amounts of $1.2 billion and $800.0 million, respectively. The Q2
2020 Amendments, which were approved by the lenders, permitted the issuance of
the Senior Secured Notes in connection with the Debt Exchange, and they
implemented an availability blocker of $31.8 million equal to 25% of the newly
issued and outstanding Senior Secured Notes. Among other things, the Q2 2020
Amendments also suspended the
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total funded debt to EBITDAX ratio (as specified in the existing credit
agreement) through year-end 2021 and introduced a new financial covenant testing
the ratio of first lien debt to EBITDAX.
In connection with the credit facility's fall 2020 semi-annual redetermination
process, the borrowing base and amount of elected commitments were reaffirmed at
$700.0 million.
Results of Operations
For the Year Ended December 31, 2020 Compared to the Year Ended December 31,
2019
The following table provides the components of our net revenues and net
production (net of all royalties, overriding royalties and production due to
others) for the periods indicated, as well as each period's average prices and
average daily production volumes:
                                                    Year Ended December 31,                         Increase/(Decrease)
                                                    2020                   2019                     $                      %
Net revenues (in thousands):
Oil sales                                   $     475,694              $ 810,655          $         (334,961)              (41) %
Natural gas sales                                  46,776                 44,556                       2,220                 5  %
NGL sales                                          57,986                 89,119                     (31,133)              (35) %
Oil and gas sales                           $     580,456              $ 944,330          $         (363,874)              (39) %

Average sales price:
Oil (per Bbl)                               $       36.02              $   52.02          $           (16.00)              (31) %
Effect of derivative settlements on average
price (per Bbl)                                     (3.15)                 (1.13)                      (2.02)             (179) %
Oil net of hedging (per Bbl)                $       32.87              $   50.89          $           (18.02)              (35) %

Average NYMEX price for oil (per Bbl)       $       39.44              $   57.03          $           (17.59)              (31) %
Oil differential from NYMEX                         (3.42)                 (5.01)                       1.59                32  %

Natural gas (per Mcf)                       $        1.13              $    1.07          $             0.06                 6  %
Effect of derivative settlements on average
price (per Mcf)                                     (0.12)                  0.29                       (0.41)             (141) %
Natural gas net of hedging (per Mcf)        $        1.01              $    1.36          $            (0.35)              (26) %

Average NYMEX price for natural gas (per
Mcf)                                        $        1.99              $    2.52          $            (0.53)              (21) %
Natural gas differential from NYMEX                 (0.86)                 (1.45)                       0.59                41  %

NGL (per Bbl)                               $       12.91              $   17.03          $            (4.12)              (24) %

Net production:
Oil (MBbls)                                        13,207                 15,582                      (2,375)              (15) %
Natural gas (MMcf)                                 41,302                 41,703                        (401)               (1) %
NGL (MBbls)                                         4,490                  5,234                        (744)              (14) %
Total (MBoe)(1)                                    24,581                 27,766                      (3,185)              (11) %

Average daily net production:
Oil (Bbls/d)                                       36,084                 42,692                      (6,608)              (15) %
Natural gas (Mcf/d)                               112,848                114,254                      (1,406)               (1) %
NGL (Bbls/d)                                       12,269                 14,338                      (2,069)              (14) %
Total (Boe/d)(1)                                   67,161                 76,072                      (8,911)              (12) %





(1)  Calculated by converting natural gas to oil equivalent barrels at a ratio
of six Mcf of natural gas to one Boe.
Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the year ended
December 31, 2020 were lower by $363.9 million, or 39%, compared to the year
ended December 31, 2019. Revenues are a function of oil, natural gas and NGL
volumes sold and average commodity prices realized.
Average realized sale prices for oil and NGLs decreased for the year ended
December 31, 2020 as compared to 2019. The average price for oil before the
effects of hedging decreased 31% and the average price for NGLs decreased 24%
between periods. The 31% decrease in the average realized oil price was the
result of lower NYMEX crude prices in 2020 (average NYMEX oil prices decreased
31%), which was minimally offset by improved oil differentials of $1.59 per Bbl
during 2020. The
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24% decrease in average realized NGL prices between periods was primarily
attributable to lower Mont Belvieu spot prices for plant products in 2020.
Conversely, the average realized sales price of natural gas before the effects
of hedging increased 6% in 2020 as compared to 2019. This increase was mainly
due to improved gas differentials ($0.59 per Mcf), which was partially offset by
lower average NYMEX gas prices (down $0.53 per Mcf) between periods. The
improvement in gas differentials is the result of higher natural gas prices
realized in West Texas as several producers shut-in wells and curtailed
production in the Permian Basin during the year and as new pipelines have been
placed into service. These pipelines have provided relief from the gas takeaway
capacity constraints experienced in 2019. The market prices for oil, natural gas
and NGLs have all been significantly impacted by lower demand globally for oil
and gas as a result of COVID-19 as well as by supply disruptions from the
Russia-Saudi oil price war early in 2020, which combined have resulted in
significant price declines starting in March 2020 as discussed in the market
conditions section above.
Net production volumes for oil, natural gas, and NGLs decreased 15%, 1% and 14%,
respectively, between periods. The oil production volume decrease between
periods was the result of (i) the temporary suspension of our drilling and
completion activity during most of the second and third quarters of 2020, which
resulted in only 31 new wells being completed and brought online during 2020 and
added 2,849 MBbls of net oil production during the year ended December 31, 2020
as compared to 84 wells completed and brought online during 2019 adding 5,611
MBbls of net oil production during the year ended December 31, 2019; (ii) the
curtailment of a portion of our production during the second quarter of 2020;
and (iii) normal field production declines across our existing wells. Natural
gas and NGLs are produced concurrently with our crude oil volumes, typically
resulting in a high correlation between fluctuations in oil quantities sold and
natural gas and NGL quantities sold. However, during 2020, we flared
significantly less wellhead gas as compared to 2019, resulting in a higher ratio
of natural gas and NGL sales compared to oil sales in the period. In addition,
for over half of 2020, the main processor of our raw gas operated in
ethane-rejection as compared to operating in ethane-recovery during the majority
of 2019. As a result, we sold an increased amount of natural gas from our wet
gas stream and recovered fewer NGLs during the 2020 period, resulting in a lower
decline in natural gas volumes (down 1%) as compared to the 14% decrease in NGL
volumes between periods.
Operating Expenses. The following table sets forth selected operating expense
data for the periods indicated:
                                                     Year Ended December 31,                        Increase/(Decrease)
                                                     2020                   2019                     $                     %
Operating costs (in thousands):
Lease operating expenses                     $     109,282              $ 145,976          $          (36,694)             (25) %
Severance and ad valorem taxes                      39,417                 63,200                     (23,783)             (38) %
Gathering, processing, and transportation
expense                                             71,309                 72,834                      (1,525)              (2) %
Operating costs per Boe:
Lease operating expenses                     $        4.45              $    5.26          $            (0.81)             (15) %
Severance and ad valorem taxes                        1.60                   2.28                       (0.68)             (30) %
Gathering, processing, and transportation
expense                                               2.90                   2.62                        0.28               11  %



Lease Operating Expenses. Lease operating expenses ("LOE") for the year ended
December 31, 2020 decreased $36.7 million compared to the year ended
December 31, 2019. Lower LOE for 2020 was primarily related to a $21.9 million
decrease in workover expense between periods as a result of less workover
activity and a $14.8 million decrease in well operating expenses associated with
cost reduction initiatives, described below, as well as lower variable and
semi-variable costs stemming from the 11% production decline between periods.
These decreases were partially offset by LOE costs associated with our higher
well count in 2020. We had 386 gross operated horizontal wells as of
December 31, 2020 compared to 349 gross operated horizontal wells as of
December 31, 2019. The net increase in well count was mainly the result of our
drilling activity adding 31 gross operated wells in 2020, which was further
adjusted for acquisitions and divestitures.
LOE on a per Boe basis decreased when comparing the year ended December 31, 2020
to the year ended December 31, 2019. LOE per Boe was $4.45 for the year ended
December 31, 2020, which represents a decrease of $0.81 per Boe (or 15%) from
2019. This decrease in rate was mainly due to the lower level of workover
activity discussed above as well as cost reduction initiatives we have
undertaken such as (i) moving multiple wells off generators to more
cost-efficient electrical line-power, (ii) switching wells away from electric
submersible pumps ("ESPs") to more reliable and lower cost gas lift, and (iii)
performing field reviews to reduce or eliminate various costs for contract
labor, oilfield equipment and supplies. These decreases were partially offset by
per BOE cost increases between periods associated with fixed and semi-variable
costs that don't decrease at the same rate as declines in production such as
monthly rental fees for compressors and other equipment, wellhead chemical
costs, and water handling costs.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the year
ended December 31, 2020 decreased $23.8 million compared to the year ended
December 31, 2019. Severance taxes are primarily based on the market value of
our
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production at the wellhead, while ad valorem taxes are generally based on the
assessed taxable value of proved developed oil and natural gas properties and
vary across the different counties in which we operate. Severance taxes for the
year ended 2020 decreased $17.9 million compared to the same 2019 period
primarily due to lower oil, natural gas and NGL revenues between periods. Ad
valorem taxes decreased $5.9 million between periods due to lower tax
assessments on our oil and gas reserve values. Severance and ad valorem taxes as
a percentage of total net revenues remained consistent between periods at 6.8%
and 6.7% for the years ended December 31, 2020 and 2019, respectively.
Gathering, Processing and Transportation Expenses. Gathering, processing and
transportation costs ("GP&T") for the year ended December 31, 2020 decreased
$1.5 million compared to the year ended December 31, 2019 due to an $8.3 million
decrease in plant processing, transportation and gathering fees incurred between
periods as a result of lower wellhead production in 2020. This was partially
offset by a $6.5 million decrease in reimbursements (net of related fees)
received from third parties for their usage of our available firm transportation
capacity.
On a per Boe basis, GP&T increased 11% from $2.62 for the year ended
December 31, 2019 to $2.90 per Boe for the year ended December 31, 2020. On a
natural gas and NGLs volume basis (i.e. excluding crude oil barrels) the Boe
rate likewise increased between periods from $5.98 to $6.27 for the year ended
December 31, 2019 and 2020, respectively. These rate increases were mainly
attributable to a lower amount of FT reimbursements (net of related fees) for
the usage of our available FT capacity as referenced above.
Depreciation, Depletion, and Amortization. The following table summarizes our
depreciation, depletion and amortization ("DD&A") for the periods indicated:
                                                            Year Ended 

December 31,


  (in thousands, except per Boe data)                         2020               2019
  Depreciation, depletion and amortization            $     358,554           $ 444,243
  Depreciation, depletion and amortization per Boe    $       14.59           $   16.00



Our DD&A rate can fluctuate as a result of finding and development costs
incurred, acquisitions, impairments, as well as changes in proved developed
reserves and proved undeveloped reserves. For the year ended December 31, 2020,
DD&A expense amounted to $358.6 million, a decrease of $85.7 million over 2019.
The primary factor contributing to lower DD&A expense in 2020 was the decrease
in our overall production volumes between periods, which decreased DD&A expense
by $51.0 million for the year ended December 31, 2020, while lower DD&A rates
between periods lowered DD&A expense by $34.7 million.
DD&A per Boe was $14.59 for the year ended December 31, 2020 compared to $16.00
in 2019. This decrease in DD&A rate was primarily due to (i) the proved property
impairment recognized in the first quarter of 2020, which lowered the carrying
value of our depletion base by $591.8 million and (ii) upward revisions to
proved developed reserves of 18.3 MMBoe for the year ended December 31, 2020
related to lower operating costs that we realized during 2020, which were
partially offset by downward revisions associated with lower SEC reserve
pricing.
Impairment and Abandonment Expense. For the year ended December 31, 2020, $691.2
million of impairment and abandonment expense was incurred related to certain of
our oil and gas properties. This expense consisted of (i) a $591.8 million
non-cash impairment of our proved properties in the first quarter as a result of
the depressed NYMEX oil and gas futures curves as of March 31, 2020; (ii) $78.8
million related to the amortization of leasehold expiration costs associated
with individually insignificant unproved properties, and (iii) a $20.6 million
non-cash impairment of other noncurrent assets, which represented advances paid
to a third-party broker to acquire exploratory leasehold acres on our behalf,
which acres are not currently included in our current development plan.
We review our proved oil and natural gas properties for impairment whenever
events and circumstances indicate that the fair value of these assets may be
below their carrying value. Fair values of our oil and natural gas properties
are estimated using an income approach that is based on the discounted expected
future net cash flows from these assets. These valuations are based on inputs
which require significant judgment and include estimates of: (i) oil and gas
reserves quantities; (ii) future production decline rates; (iii) future
operating and development costs; (iv) future commodity prices, including price
differentials; and (v) a market participant-based weighted-average cost of
capital discount rate.
We performed an impairment assessment of all our proved oil and gas properties
as of March 31, 2020. Two of our fields were subject to impairment write-downs
as quantified above, but the remaining five fields were not impaired due to
their undiscounted cash flows exceeding their carrying values by 30% to over
100%. This impairment assessment was performed using commodity price futures
curves as of March 31, 2020. If future oil, natural gas and NGL prices were to
decline to lower levels, or other estimates impacting future net cash flows
deteriorate (e.g. reserves, price differentials, future operating and/or
development costs), our proved oil and gas properties could be subject to
additional impairment write-downs in future periods. We did not recognize any
additional impairment write-downs with respect to our proved oil and gas
properties for the remainder of 2020.
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For the year ended December 31, 2019, $47.2 million of impairment and
abandonment expense was incurred related to undeveloped leasehold acreage. This
expense consisted of (i) $19.1 million related to non-core acreage that expired
during 2019 after efforts to extend, sell or trade these leases were
unsuccessful, (ii) $16.6 million for impaired acreage following an acreage sale
initiated in the first quarter of 2019, and (iii) $11.5 million related to the
amortization of leasehold expiration costs associated with individually
insignificant unproved properties.
Exploration and Other Expenses. The following table summarizes exploration and
other expenses for the periods indicated:
                                                    Year Ended December 31,
(in thousands)                                         2020                

2019


Geological and geophysical costs              $       4,533             $  

8,424


Stock-based compensation - equity awards              1,433                

2,682


Stock-based compensation - liability awards              90                    -
Exploratory dry hole costs                            6,615                    -
Rig termination fees                                  3,046                  284
Severance payments                                      722                    -
Other expenses                                        1,916                    -
Exploration and other expenses                $      18,355             $ 

11,390





Exploration and other expenses were $18.4 million for the year ended
December 31, 2020 compared to $11.4 million for the year ended December 31,
2019. Exploration and other expenses mainly consists of topographical studies,
geographical and geophysical ("G&G") projects, salaries and expenses of G&G
personnel and includes other operating costs. The period over period increase
was primarily related to (i) $6.6 million in exploratory dry hole costs incurred
in 2020; (ii) $2.8 million in higher rig termination fees as a result of
temporarily suspending drilling activity in 2020; and (iii) $1.7 million in
environmental remediation costs incurred in 2020 associated with a recently
acquired proved property. These increases were partially offset by (i) a $1.7
million decrease in G&G project and seismic costs incurred between periods, and
(ii) $2.2 million in lower G&G personnel costs and $1.2 million in lower
stock-based compensation in the 2020 period, both of which were associated with
the lower headcount from our 2020 workforce reduction (as further described
below under General and Administrative Expenses).
General and Administrative Expenses. The following table summarizes our general
and administrative ("G&A") expenses for the periods indicated:
                                                    Year Ended December 31,
(in thousands)                                         2020                

2019


Cash general and administrative expenses      $      46,356             $ 

52,841


Stock-based compensation - equity awards             19,533               

26,315


Stock-based compensation - liability awards           3,512                 

-


Severance payments                                    3,466                 

-


General and administrative expenses           $      72,867             $ 

79,156





G&A expenses for the year ended December 31, 2020 were $72.9 million compared to
$79.2 million for the year ended December 31, 2019. Lower G&A expenses incurred
in 2020 were primarily the result of a reduction to our workforce and reduced
salaries effective May 1, 2020 for employees that were retained. These two
factors combined resulted in a $5.4 million decrease in payroll and other
personnel related costs and a $6.8 million decrease in equity-based stock
compensation expense between periods. In addition, in 2019 we incurred a $1.8
million charge for the settlement of a water disposal contract dispute that did
not re-occur in 2020. These decreases were partially offset by 2020 charges
related to (i) $3.5 million of nonrecurring severance payments paid to G&A
employees who were included in our workforce reduction and (ii) $3.5 million in
stock compensation expense related to liability awards granted to G&A employees
in the third quarter of 2020 that we will settle in cash upon vesting. These
liability stock-based awards are recorded at their respective fair values, and
such fair values are re-measured each balance sheet date (refer to Note
6-Stock-Based Compensation under Part II, Item 8 of this Annual Report for
additional information regarding the liability awards).
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Other Income and Expense.
Interest Expense. The following table summarizes interest expense for the
periods indicated:
                                                                      Year Ended December 31,
(in thousands)                                                        2020                 2019
Credit facility                                                 $      12,973          $    8,371
6.875% Senior Notes due 2027                                           28,368              27,309
5.375% Senior Notes due 2026                                           17,884              21,500
8.000% Senior Secured Notes due 2025                                    6,185                   -
Amortization of debt issuance costs and debt discount                   5,923               2,861
Interest capitalized                                                   (2,141)             (4,050)
Total                                                           $      69,192          $   55,991



Interest expense was $13.2 million higher for the year ended December 31, 2020
compared to the year ended December 31, 2019. Higher interest expense incurred
during the year ended 2020 was mainly due to (i) $6.2 million in interest
incurred on our new Senior Secured Notes issued in May of 2020 in connection
with our Debt Exchange (refer to Note 4-Long-Term Debt under Part II, Item 8 of
this Annual Report), (ii) $4.6 million in higher interest expense incurred on
our credit facility borrowings, (iii) $3.1 million in higher amortization of
debt issuance costs and the debt discount recognized in May 2020 in connection
with our Debt Exchange and (iv) $1.9 million in lower capitalized interest due
to our decreased capital spend in 2020. These increases were partially offset by
lower interest expense incurred on our 2026 Senior Notes during the 2020 period,
as $110.6 million of the 2026 Senior Notes were extinguished in our Debt
Exchange transaction.
Our weighted average borrowings outstanding under our credit facility were
$334.2 million during 2020 compared to $154.8 million in 2019. Our credit
facility's weighted average effective interest rate (which is a LIBOR-based
rate) was 3.3% for 2020 as compared to 3.7% during 2019 as a result of lower
LIBOR in 2020.
Gain on exchange of debt. A gain of $143.4 million was recognized for the year
ended December 31, 2020 related to our opportunistic Debt Exchange that was
executed in the second quarter of 2020. This gain was determined based on the
difference between the carrying value of the Senior Unsecured Notes extinguished
less the fair value of our newly issued Senior Secured Notes on their date of
issuance. Refer to Note 4-Long-Term Debt under Part II, Item 8 of this Annual
Report for additional information regarding the gain on exchange of debt.
Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function
of (i) fluctuations in mark-to-market derivative fair values associated with
changes in the forward price curves for the commodities underlying our hedge
contracts outstanding and (ii) monthly settlements of our hedged derivative
positions.
The following table presents gains and losses on our derivative instruments for
the periods indicated:
                                                         Year Ended December 31,
(in thousands)                                             2020                2019
Realized cash settlement gains (losses)            $     (46,651)           $ (5,655)
Non-cash mark-to-market derivative gain (loss)           (17,884)              4,094
Total                                              $     (64,535)           $ (1,561)

Income Tax (Expense) Benefit: The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated.


                                          Year Ended December 31,
(in thousands)                              2020                2019

Income (loss) before income taxes $ (770,323) $ 22,211 Income tax (expense) benefit

                85,124             (5,797)



Our provision for income taxes for the years ended December 31, 2020 and 2019
differs from the amounts that would be provided by applying the statutory U.S.
federal income tax rate of 21% to pre-tax book income (loss) primarily due to
(i) permanent differences; (ii) state income taxes; and (iii) any changes during
the period in our deferred tax asset valuation allowance.
For the year ended December 31, 2020, we recognized a deferred tax asset
valuation allowance of $77.0 million against net operating losses that we
generated during the period, which are estimated as unlikely to be realized in
future periods. This
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increase in valuation allowance was the primary factor reducing our income tax
benefit for the year ended December 31, 2020 from the U.S. statutory rate to
$85.1 million.
For the year ended December 31, 2019, we recognized a discrete permanent item of
$1.7 million for lower deductions on stock awards that vested during the period,
which was partially offset by a decrease in a projected permanent item of $0.8
million related to future stock compensation not expected to be deductible.
These items were the primary factors increasing our income tax expense for the
year ended December 31, 2019 from the U.S. statutory rate to $5.8 million.

For the Year Ended December 31, 2019 Compared to the Year Ended December 31,
2018
Refer to Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations in the 2019 Annual Report on Form 10-K filed with the SEC
for a discussion of the results of operations for the year ended December 31,
2019 compared to the year ended December 31, 2018.
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Liquidity and Capital Resources
Overview
Our drilling and completion and land acquisition activities require us to make
significant capital expenditures. Historically, our primary sources of liquidity
have been cash flows from operations, borrowings under CRP's revolving credit
facility, and proceeds from offerings of debt or equity securities. Future cash
flows are subject to a number of variables, including oil and natural gas
prices. Prices for oil and natural gas began to decline significantly in March
2020 and have remained volatile since. These lower commodity prices negatively
impact our operating cash flows and our ability to access debt or equity
markets, and sustained low oil and natural gas prices could have a material and
adverse effect on our liquidity position. To date, our primary use of capital
has been for drilling and development capital expenditures and for the
acquisition of oil and natural gas properties. The following table summarizes
our capital expenditures ("capex") incurred during the year:
   (in millions)                                    Year Ended December 31, 

2020


   Drilling and completion capital expenditures    $                      

212.0


   Facilities, infrastructure and other                                    

38.2


   Land                                                                     

4.6


   Total capital expenditures                      $                      

254.8





We continually evaluate our capital needs and compare them to our capital
resources. As a result of the decline in crude oil prices and ongoing
uncertainty regarding the oil supply-demand macro environment, we temporarily
suspended all drilling and completion activities at the end of the first quarter
of 2020 in order to preserve capital. Specifically, we reduced our operated
drilling rig program to zero rigs starting in April of 2020 and continued with
no drilling rigs in operation until the end of September 2020 when we resumed
drilling activity with a one-rig program. Of our $212.0 million in drilling and
completion capital expenditures incurred during the year ended December 31,
2020, approximately 70% was incurred during the first quarter of 2020. We
operated one drilling rig during the entire fourth quarter, added a second
drilling rig in late December 2020, and we plan to continue to operate a two rig
program through 2021. We expect our total capex budget for 2021 to be between
$260 million to $310 million, of which $250 million to $290 million is allocated
to drilling, completion and facilities activity. We expect to fund our capex
budget entirely from cash flows from operations given current commodity price
levels. We were free cash flow positive during the second half of 2020 such that
we were able to partially pay down borrowings under our credit agreement during
the third and fourth quarters of 2020. Based upon current commodity prices, we
expect to continue to pay down borrowings through expected free cash flow
generation during 2021.
Because we are the operator of a high percentage of our acreage, we can control
the amount and timing of our capital expenditures. We can choose to defer or
accelerate a portion of our planned capex depending on a variety of factors,
including but not limited to: prevailing and anticipated prices for oil and
natural gas; oil storage or transportation constraints; the success of our
drilling activities; the availability of necessary equipment, infrastructure and
capital; the receipt and timing of required regulatory permits and approvals;
seasonal conditions; property or land acquisition costs; and the level of
participation by other working interest owners.
Given the weakness in realized oil prices, we voluntarily curtailed or shut-in a
portion of our second quarter 2020 production volumes. Specifically, we
curtailed approximately 20% of our production during the month of May but were
able to bring the majority of our production back online in June as crude oil
prices recovered. We did not experience any further curtailments of our
production during the remainder of the year, but curtailments could occur in the
future as a result of depressed market conditions, storage and transportation
constraints and weather. Any decision in the future to curtail or shut-in our
production or reduce our drilling and completion activity could adversely affect
our business, financial condition, results of operations, liquidity, and ability
to finance planned capital expenditures.
We cannot ensure that cash flows from operations will be available or other
sources of needed capital on acceptable terms or at all. Further, our ability to
access the public or private debt or equity capital markets at economic terms in
the future will be affected by general economic conditions, the domestic and
global oil and financial markets, our operational and financial performance, the
value and performance of our debt or equity securities, prevailing commodity
prices and other macroeconomic factors outside of our control.
Moreover, in order to manage our future financing cash outflows and improve our
liquidity position, we completed the Debt Exchange with respect to our Senior
Unsecured Notes in May 2020, which reduced the total principal amounts due of
our aggregated secured and unsecured notes by $127.1 million and also reduced
future interest payments.

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Analysis of Cash Flow Changes
The following table summarizes our cash flows for the periods indicated:
                                                       Year Ended December 

31,


(in thousands)                                  2020           2019         

2018

Net cash provided by operating activities $ 171,376 $ 564,173 $ 670,011 Net cash used in investing activities (326,323) (932,989)

(1,068,664)

Net cash provided by financing activities 147,743 362,937

294,160





Cash Flows from 2020 Compared to 2019. For the year ended December 31, 2020, we
generated $171.4 million of cash from operating activities, a decrease of $392.8
million from 2019. Cash provided by operating activities decreased primarily due
to lower realized prices for oil and NGLs, lower production volumes for crude
oil, residue gas and NGLs, higher exploration and other expenses, interest
payments, cash settlement losses on derivatives, and the timing of vendor
payments during 2020 as compared to 2019. These declining factors were partially
offset by higher realized natural gas prices, lower lease operating expenses,
production taxes, GP&T costs, cash G&A expenses, and the timing of our
receivable collections during 2020 as compared to the same 2019 period. Refer to
"Results of Operations" for more information on the impact of volumes and prices
on revenues and on fluctuations in our operating costs periods.
For the year ended December 31, 2020, cash flows from operating activities, cash
on hand, and net borrowings of $155.0 million under our credit facility were
used to finance $318.5 million of drilling and development cash expenditures, to
fund $8.5 million in oil and gas property acquisitions, and to finance $6.7
million of debt issuance and exchange costs.
Cash Flows from 2019 Compared to 2018. For the year ended December 31, 2019, we
generated $564.2 million of cash from operating activities, a decrease of $105.8
million from 2018. Cash provided by operating activities decreased primarily due
to lower realized prices for crude oil, natural gas and NGLs, higher lease
operating expenses, severance and ad valorem taxes, GP&T costs, exploration
expense, cash G&A expenses, interest payments, cash settlement losses from
derivatives and the timing of our supplier payments during 2019. These declining
factors were partially offset by higher crude oil, natural gas and NGL
production volumes and the timing of our receivable collections during 2019 as
compared to the 2018 period.
For the year ended December 31, 2019, cash flows from operating activities, cash
on hand, proceeds from sales of oil and gas properties and proceeds from the
issuance of our 2027 Senior Notes were used to repay net borrowings of $125.0
million under our credit facility, to finance $855.2 million of drilling and
development capex, to fund $103.7 million in oil and gas property acquisitions
and to purchase $8.9 million of other property and equipment.
Credit Agreement
CRP, our consolidated subsidiary, has a credit agreement with a syndicate of
banks that provides for a five-year secured revolving credit facility, maturing
on May 4, 2023 (the "Credit Agreement"). On May 1, 2020, CRP as borrower and we,
as parent guarantor, entered into the Q2 2020 Amendments, which among other
things established a new borrowing base of $700.0 million and a new level of
elected commitments also $700.0 million. The Q2 2020 Amendments that the lenders
approved permitted the issuance of the Senior Secured Notes in connection with
the Debt Exchange (discussed below), and they implemented an availability
blocker equal to 25% of the newly issued amount of Senior Secured Notes. As of
December 31, 2020, we had $330.0 million in borrowings outstanding and $333.9
million in available borrowing capacity, which was net of $4.3 million in
letters of credit outstanding and the availability blocker of $31.8 million. In
connection with the Credit Agreement's fall 2020 semi-annual borrowing base
redetermination, the borrowing base and amount of elected commitments were both
reaffirmed at $700.0 million.
CRP's Credit Agreement contains restrictive covenants that limit its ability to,
among other things: (i) incur additional indebtedness; (ii) make investments and
loans; (iii) enter into mergers; (iv) make or declare dividends; (v) enter into
commodity hedges exceeding a specified percentage of our expected production;
(vi) enter into interest rate hedges exceeding a specified percentage of its
outstanding indebtedness; (vii) incur liens; (viii) sell assets; and (ix) engage
in transactions with affiliates.
CRP's credit agreement also requires it to maintain compliance with the
following financial ratios:
(i) a current ratio, which is the ratio of CRP's consolidated current assets
(including an add back of unused commitments under the revolving credit facility
and excluding non-cash derivative assets and certain restricted cash) to its
consolidated current liabilities (excluding the current portion of long-term
debt under the Credit Agreement and non-cash derivative liabilities), of not
less than 1.0 to 1.0;
(ii) a first lien leverage ratio, as defined within the Credit Agreement as the
ratio of first lien debt to EBITDAX for the rolling four fiscal quarter period,
which may not exceed 2.75 to 1.00 beginning with the quarter ending June 30,
2020 and extending through the quarter ending December 31, 2021, after which the
maximum ratio shall decrease to 2.50 to 1.00 for each of the quarters ending in
2022; and
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(iii) a leverage ratio, as defined within the Credit Agreement as the ratio of
total funded debt to consolidated EBITDAX for the rolling four fiscal quarter
period. Pursuant to the Q2 2020 Amendments, the leverage ratio is suspended
until March 31, 2022, at which time, the ratio may not exceed 5.00 to 1.00, with
such maximum ratio declining at a rate of 0.25 for each succeeding quarter until
March 31, 2023 when the ratio is set at not greater than 4.0 to 1.0.
CRP was in compliance with the covenants and applicable financial ratios
described above as of December 31, 2020 and through the filing of this Annual
Report.
For further information on the Credit Agreement, refer to Note 4-Long-Term Debt
under Part II, Item 8 of this Annual Report.
Senior Unsecured Notes Debt Exchange and Senior Secured Notes
On May 22, 2020, CRP completed the Debt Exchange pursuant to which $110.6
million aggregate principal amount of CRP's 2026 Senior Notes and $143.7 million
aggregate principal amount of CRP's 2027 Senior Notes were validly tendered and
exchanged by certain eligible bondholders for consideration consisting of $127.1
million aggregate principal amount of newly issued Senior Secured Notes. The
Senior Secured Notes bear interest at an annual rate of 8% and are due on June
1, 2025. Interest is payable semi-annually in arrears on each June 1 and
December 1, commencing on December 1, 2020.
The Debt Exchange was accounted for as an extinguishment of debt in accordance
with Financial Accounting Standards Board's Accounting Standard Codification
Topic 470-50, Modifications and Extinguishments. As a result, a gain on the
exchange of debt of $143.4 million was recognized in the consolidated statement
of operations, which consisted of the carrying values of the Senior Unsecured
Notes exchanged less the aggregate principal amount of new Senior Secured Notes
issued, net of their associated debt discount of $21.0 million (which was based
on the Senior Secured Notes' estimated fair value on the exchange date).
The Senior Secured Notes are guaranteed, subject to certain exceptions, by us
and each of CRP's subsidiaries and are secured on a second-priority basis
(subject in priority only to certain exceptions) by substantially all of CRP's
and our assets, including deposit accounts and substantially all proved reserves
and undeveloped acreage.
Senior Unsecured Notes
On November 30, 2017, CRP issued $400.0 million of 5.375% senior notes due 2026
and on March 15, 2019, CRP issued $500.0 million of 6.875% senior notes due 2027
in 144A private placements. The Senior Unsecured Notes are fully and
unconditionally guaranteed on a senior unsecured basis by Centennial and each of
CRP's current subsidiaries that guarantee CRP's revolving credit facility. In
May 2020, a portion of the Senior Unsecured Notes were exchanged for Senior
Secured Notes (see above discussion for details of the Debt Exchange).
The indentures governing the Senior Unsecured Notes and Senior Secured Notes
(collectively, the "Senior Notes") contain covenants that, among other things
and subject to certain exceptions and qualifications, limit CRP's ability and
the ability of CRP's restricted subsidiaries to: (i) incur or guarantee
additional indebtedness or issue certain types of preferred stock; (ii) pay
dividends on capital stock or redeem, repurchase or retire capital stock or
subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments;
(v) create certain liens; (vi) enter into agreements that restrict dividends or
other payments from their subsidiaries to them; (vii) consolidate, merge or
transfer all or substantially all of their assets; (viii) engage in transactions
with affiliates; and (ix) create unrestricted subsidiaries. CRP was in
compliance with these covenants as of December 31, 2020 and through the filing
of this Annual Report.
For further information on our Senior Notes, refer to Note 4-Long-Term Debt
under Part II, Item 8 of this Annual Report.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give
rise to material off-balance sheet obligations. As of December 31, 2020, we had
no off-balance sheet arrangements.
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Contractual Obligations
We routinely enter into or extend operating and transportation agreements,
office and equipment leases, drilling rig contracts, among others, in the
ordinary course of business. The following table summarizes our obligations and
commitments as of December 31, 2020 to make future payments under long-term
contracts for the time periods specified below.
(in thousands)                      2021              2022               2023              2024               2025            Thereafter             Total
Operating leases(1)              $  3,260          $    425          $       -          $      -          $       -          $        -          $     3,685
Water disposal agreements(2)        1,825               100                  -                 -                  -                   -                1,925

Asset retirement obligations(3)       384                 -                  -               457                  -              16,168               

17,009


Long term debt obligations(4)           -                 -            330,000                 -            127,073             645,799            

1,102,872


Cash interest expense on
long-term debt obligations(5)      62,319            62,319             58,749            50,223             44,290              30,547             

308,447


Transportation agreements(6)        9,060             1,770                  -                 -                  -                   -               10,830
Total                            $ 76,848          $ 64,614          $ 388,749          $ 50,680          $ 171,363          $  692,514          $ 1,444,768





(1)  Operating leases include our office rental agreements and other wellhead
equipment. Please refer to Note 15-Leases under Part II, Item 8 of this Annual
Report for details on our operating lease commitments.
(2)  Water disposal agreements consist of contracts for transportation and
disposal of produced water from our operated wells. Under the terms of these
agreements, we are obligated to deliver a minimum volume of produced water or
else pay for any deficiencies at the prices stipulated in the contracts. The
obligations reported above represent our remaining minimum financial commitments
pursuant to the terms of these contracts as of December 31, 2020. Actual
expenditures under these contracts may exceed the minimum commitments presented
above.
(3)  Asset retirement obligations reflect the present value of the estimated
future costs associated with the plugging and abandonment of oil and gas wells
and the related land restoration in accordance with applicable laws and
regulations.
(4)  Long-term debt consists of the principal amounts of the Senior Notes due
and borrowings outstanding under the Credit Agreement maturing on May 4, 2023.
(5)  Cash interest expense on the Senior Notes is estimated assuming no
principal repayment until the maturity of the instruments. Cash interest expense
on the Credit Agreement includes unused commitment fees and assumes no
additional principal borrowings, repayments or changes to commitments under the
agreement through the instrument due date.
(6)  Transportation agreements include various firm natural gas transportation
contracts whereby we are required to pay fixed pipeline capacity reservation
fees over the contractual terms. The obligations reported above represent
minimum financial commitments pursuant to the terms of these contracts. However,
our expenditures under these contracts are likely to exceed the minimum
commitments presented above.
Recently Issued Accounting Standards
There were no significant new accounting standards adopted or new accounting
pronouncements that would have a potential effect on us as of December 31, 2020.
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 GAAP. The preparation of these statements requires us to make
certain assumptions, judgments and estimates that affect the reported amounts of
assets, liabilities, revenues and expenses, as well as, the disclosure of
contingent assets, contingent liabilities and commitments as of the date of our
financial statements. We base our assumptions and estimates on historical
experience and other sources that we believe to be reasonable at the time.
Actual results may vary from our estimates due to changes in circumstances,
weather, politics, global economics, commodity prices, production performance,
drilling results, mechanical problems, general business conditions and other
factors. A summary of our significant accounting policies can be found in Note
1-Basis of Presentation and Summary of Significant Accounting Policies, Item 8.
Financial Statements and Supplementary Data in this Annual Report.
We have outlined certain of our accounting policies below which require the
application of significant judgment by our management.
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Oil and Natural Gas Reserve Quantities
We use the successful efforts method of accounting for our oil and gas producing
activities. The successful efforts method inherently relies on the estimation of
proved crude oil, natural gas and NGL reserves. Reserve quantities and the
related estimates of future net cash flows are used as inputs to our calculation
of depletion, evaluation of proved properties for impairment, assessment of the
expected realizability of our deferred income tax assets, and the standardized
measure of discounted future net cash flows computations.
 The process of estimating quantities of proved reserves is inherently imprecise
and relies on the following: i) interpretations and judgment of available
geological, geophysical, engineering and production data; ii) certain economic
assumptions, some of which are mandated by the SEC, such as commodity prices;
and iii) assumptions and estimates of underlying inputs such as operating
expenses, capital expenditures, plug and abandonment costs and taxes. All of
these assumptions may differ substantially from actual results, which could
result in a significant change in our estimated quantities of proved reserves
and their future net cash flows. We continually make revisions to reserve
estimates throughout the year as additional information becomes available, and
we make changes to depletion rates in the same period that changes to reserve
estimates are made.
Impairment of Oil and Natural Gas Properties
We assess our proved properties for impairment when events or changes in
circumstances indicate that the carrying value of such proved property assets
may not be recoverable. For purposes of an impairment evaluation, our proved oil
and natural gas properties must be grouped at the lowest level for which
independent cash flows can be identified. If the sum of the undiscounted
estimated cash flows from the use of the asset group and its eventual
disposition is less than the carrying value of an asset group, the carrying
value is written down to its estimated fair value. Fair value for the purpose of
testing impairment is calculated using the present value of expected future cash
flows that are estimated to be generated from the asset group. Fair value
estimates are based on projected financial information which we believe to be
reasonably likely to occur, as of the date that the impairment write-down is
being measured. However, such future cash flow estimates are based on numerous
assumptions that can materially affect our estimates, and such assumptions are
subject to change with variations in commodity prices, production performance,
drilling results, operating and development costs, underlying oil and gas
reserve quantities, and other internal or external factors.
Unproved properties consist of the costs we incurred to acquire undeveloped
leasehold acreage as well as the costs we incurred to acquire unproved reserves.
Unproved properties with individually significant acquisition costs are
periodically assessed for impairment based on remaining lease term, drilling
results, reservoir performance, seismic interpretation or changes in future
plans to develop acreage. Unproved properties which are not individually
significant are amortized by prospect, based on our historical experience,
current drilling plan, existing geological data and average remaining lease
terms. Changes in our assumptions as to the estimated nonproductive portion of
our undeveloped leases could result in additional impairment charges.

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