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OFFON

CENTENNIAL RESOURCE DEVELOPMENT, INC.

(CDEV)
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CENTENNIAL RESOURCE DEVELOPMENT : Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-Q)

08/04/2021 | 04:35pm EDT
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. 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, 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
Coronavirus Disease 2019 ("COVID-19") and other uncertainties, as well as those
factors discussed above in "Cautionary Statement Regarding Forward-Looking
Statements" and under the heading "Item 1A. Risk Factors" in our 2020 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
Centennial Resource Development, Inc. ("Centennial," "we," "us," or "our") is an
independent oil and natural gas company focused on the development of 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. Unless otherwise specified or the context otherwise requires,
all references in these discussions to "Centennial," "we," "us," or "our" are to
Centennial Resource Development, Inc. and its consolidated subsidiary,
Centennial Resource Production, LLC ("CRP").
Market Conditions
  The 2020 worldwide outbreak of COVID-19, the uncertainty regarding its impact
and various governmental actions taken to mitigate the effects of COVID-19
resulted in an unprecedented decline in the demand for oil and natural gas
throughout 2020. In addition, the decision by Saudi Arabia to drastically reduce
export prices and increase oil production in March 2020 (the "Saudi-Russia oil
price war") followed by curtailment agreements among Organization of Petroleum
Exporting Countries ("OPEC") and other countries such as Russia further
increased uncertainty and volatility around global oil supply-demand dynamics.
However, in April of 2020, the members of OPEC and other oil producing countries
("OPEC+") agreed to reduce their crude oil production throughout the year, while
U.S. producers substantially reduced or suspended drilling and completion
activity due to low oil prices and poor economics.
The demand for oil and natural gas continued to remain low in early 2021 due to
continued uncertainty regarding the impacts of COVID-19. OPEC+ extended their
production cuts through the first quarter of 2021 and began to gradually
increase output during the second quarter of 2021. More recently, OPEC+
announced an agreement to increase production more substantially in August 2021
through September 2022. U.S. drilling activity began to increase in the fourth
quarter of 2020 and has continued to increase steadily since. The gradual
increase in overall oil supply paired with the ongoing recovery in global oil
demand due to the availability of COVID-19 vaccinations and less governmental
mandated restrictions have aided in the recovery of global commodity prices
during the first half of 2021. Specifically, WTI spot prices for crude oil
reached a high of $74.05 per barrel on June 25, 2021 from a low of negative
$37.63 per barrel on April 20, 2020 (which was due to depressed demand and
insufficient storage capacity, particularly at the WTI physical settlement
location in Cushing, Oklahoma).
  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 from COVID-19 and variant strains of the virus, geopolitical events,
weather conditions, the 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 2019:
                                                                 2019                                                                2020                                               2021
                                         Q1               Q2               Q3               Q4               Q1               Q2               Q3               Q4               Q1               Q2
Crude oil (per Bbl)                  $ 54.90$ 59.81$ 56.45$ 56.94$ 46.19$ 28.00$ 40.93$ 42.66$ 57.84$ 66.06
Natural gas (per MMBtu)              $  2.88$  2.51          $  

2.33 $ 2.34$ 1.88$ 1.65$ 1.95

$ 2.47$ 3.44$ 2.88



Lower commodity prices (including realized differentials) and lower futures
curves for oil and gas prices can result in further impairments of our proved
oil and natural gas properties or undeveloped acreage (such as the impairments
incurred in the first quarter of 2020) 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,
which is determined at the discretion of the lenders and is based on the
collateral value of our
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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.
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, vendors, 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 been
working remotely or reporting to our offices on a limited basis. We have taken
various precautionary measures with respect to our operational employees, direct
contractors and employees who returned to our offices or job sites such as (i)
requesting that 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 mask and social distancing
requirements on work sites and at our offices, and (iv) encouraging all
employees and contractors to follow the Center of Disease Control (the "CDC")
recommended preventive measures (including those mentioned above) to limit the
spread of COVID-19. We have continued to update our safety protocols in
alignment with CDC guidance and governmental mandates, and have been able to
reduce some requirements if employees, customers, vendors, or suppliers are
fully vaccinated. We have not experienced any operational disruptions (including
disruptions from our suppliers and service providers) as a result of the
COVID-19 outbreak.
2021 Highlights and Future Considerations
Operational Highlights
We operated a two-rig drilling program during the first half of 2021, which
enabled us to complete and bring online 23 gross operated wells with an average
effective lateral length of approximately 8,800 feet.
In February 2021, the Permian Basin was impacted by record-low temperatures and
a severe winter storm ("Winter Storm Uri") that caused multi-day electrical
outages and shortages, pipeline and infrastructure freezes, and transportation
disruptions, which further led to significant increases in gas prices,
gathering, processing and transportation fees and electrical rates during this
time. Our operations were impacted by Winter Storm Uri and led to a partial
shut-in of certain wells and associated production for about seven days during
the event. Refer to the discussion below for the current impacts from Winter
Storm Uri on our results of operations during the three and six months ended
June 30, 2021.
Financing Highlights
On March 19, 2021, we issued $150.0 million of 3.25% senior convertible notes
due 2028 (the "Convertible Senior Notes") in a public offering. On March 26,
2021, the Company issued an additional $20.0 million of Convertible Senior Notes
pursuant to the exercise of the underwriters' over-allotment option to purchase
additional Convertible Senior Notes. The issuance resulted in net proceeds of
$163.6 million, after deducting debt issuance costs of $6.4 million, and such
proceeds were used to fund the cost of entering into capped call spread
transactions totaling $14.7 million and to repay borrowing outstanding under
CRP's revolving credit facility. In April 2021, we redeemed at par all of our
2025 senior secured notes ($127.1 million), which was the intended use of
proceeds from the Convertible Senior Notes offering.
In connection with CRP's credit facility spring 2021 semi-annual borrowing base
redetermination, the borrowing base and amount of elected commitments were
reaffirmed at $700.0 million.
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Results of Operations
Three Months Ended June 30, 2021 Compared to Three Months Ended June 30, 2020
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:
                                               Three Months Ended June 30,                       Increase/(Decrease)
                                                 2021                  2020                      $                      %
Net revenues (in thousands):
Oil sales                                 $       177,105$   73,100          $          104,005               142  %
Natural gas sales                                  27,015               8,787                      18,228               207  %
NGL sales                                          28,457               8,622                      19,835               230  %
Oil and gas sales                         $       232,577$   90,509          $          142,068               157  %

Average sales prices:
Oil (per Bbl)                             $         60.99          $    21.47          $            39.52               184  %
Effect of derivative settlements on
average price (per Bbl)                            (12.59)              (1.60)                     (10.99)             (687) %
Oil net of hedging (per Bbl)              $         48.40          $    19.87          $            28.53               144  %

Average NYMEX price for oil (per Bbl) $ 66.06 $ 28.00 $

            38.06               136  %
Oil differential from NYMEX                         (5.07)              (6.53)                       1.46                22  %

Natural gas (per Mcf)                     $          2.55          $     0.87          $             1.68               193  %
Effect of derivative settlements on
average price (per Mcf)                             (0.09)              (0.14)                       0.05                36  %

Natural gas net of hedging (per Mcf) $ 2.46 $ 0.73 $

             1.73               237  %

Average NYMEX price for natural gas (per
Mcf)                                      $          2.88          $     1.65          $             1.23                75  %
Natural gas differential from NYMEX                 (0.33)              (0.78)                       0.45                58  %

NGL (per Bbl)                             $         30.37          $     7.72          $            22.65               293  %

Net production:
Oil (MBbls)                                         2,904               3,404                        (500)              (15) %
Natural gas (MMcf)                                 10,613              10,140                         473                 5  %
NGL (MBbls)                                           937               1,116                        (179)              (16) %
Total (MBoe)(1)                                     5,610               6,210                        (600)              (10) %

Average daily net production:
Oil (Bbls/d)                                       31,912              37,411                      (5,499)              (15) %
Natural gas (Mcf/d)                               116,629             111,419                       5,210                 5  %
NGL (Bbls/d)                                       10,297              12,264                      (1,967)              (16) %
Total (Boe/d)(1)                                   61,647              68,245                      (6,598)              (10) %



(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

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Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the three months
ended June 30, 2021 were $142.1 million (or 157%) higher than total net revenues
for the three months ended June 30, 2020. Revenues are a function of oil,
natural gas and NGL volumes sold and average commodity prices realized.
Average realized sales prices for oil, residue gas and NGLs increased in the
second quarter of 2021 compared to the same 2020 period by 184%, 193% and 293%
respectively. The 184% increase in the average realized oil price before the
effects of hedging was the result of higher NYMEX crude prices between periods
(average NYMEX prices increased 136%) and improved oil differentials (a decrease
of $1.46 per Bbl). The 193% increase in average realized sales price of natural
gas before the effects of hedging was due to higher NYMEX prices (average prices
increased 75%) and improved gas differentials ($0.45 per Mcf). The increase in
average realized NGL prices of 293% between periods was primarily attributable
to higher Mont Belvieu spot prices for plant products in the second quarter of
2021 as compared to the second quarter of 2020. The market prices for oil,
natural gas and NGLs have all been impacted by higher global demand for oil and
gas compared to the second quarter of 2020 when prices decreased significantly
as a result of COVID-19 and supply disruptions from the Saudi-Russia oil price
war, beginning in March 2020 as discussed in the market conditions section
above.
Net production volumes for oil and NGLs decreased 15% and 16%, respectively,
while natural gas increased 5% between periods. The crude oil production volume
decrease was primarily the result of less drilling and completion activity over
the past 12 months as a result of depressed oil and gas prices, which resulted
in only 28 wells being placed on production since the second quarter of 2020.
This added 872 MBbls of net oil production to the three months ended June 30,
2021 as compared to 70 wells brought online since the second quarter of 2019
that added 1,604 MBbls of net oil production to the second quarter of 2020. Oil
volume declines in the second quarter of 2021 were additionally impacted by
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 the second quarter of 2020, the main
processor of our raw gas operated in partial ethane-rejection for two thirds of
the quarter, as compared to operating in full ethane-rejection during the entire
2021 period. Additionally, the amount of gas flared as a percentage of wellhead
gas produced was significantly less during the second quarter of 2021 as
compared to the same 2020 period. Both of these factors resulted in an increase
in the amount of natural gas recovered and sold from our wet gas stream, while
the gas processing variations resulted in fewer NGLs being recovered during the
2021 period.
Operating Expenses. The following table sets forth selected operating expense
data for the periods indicated:
                                               Three Months Ended June 30,                      Increase/(Decrease)
                                                2021                  2020                      $                      %
Operating costs (in thousands):
Lease operating expenses                  $       22,976$   25,839          $           (2,863)              (11) %
Severance and ad valorem taxes                    15,784               5,696                      10,088               177  %
Gathering, processing and transportation
expenses                                          19,494              17,284                       2,210                13  %
Operating costs per Boe:
Lease operating expenses                  $         4.10          $     4.16          $            (0.06)               (1) %
Severance and ad valorem taxes                      2.81                0.92                        1.89               205  %
Gathering, processing and transportation            3.47                2.78
expenses                                                                                            0.69                25  %


Lease Operating Expenses. Lease operating expenses ("LOE") for the three months
ended June 30, 2021 decreased $2.9 million compared to the three months ended
June 30, 2020. Lower LOE for the second quarter of 2021 was primarily related to
(i) a significant decrease in electricity costs as a result of credits realized
during the second quarter of 2021 related to Winter Storm Uri; (ii) lower well
operating expenses due to cost reduction initiatives, which included moving
multiple wells off generators to more cost-efficient electrical line-power and
switching wells away from electric submersible pumps to more reliable and lower
cost gas lift; and (iii) lower variable and semi-variable costs stemming from
the 10% production decline between periods. These decreases were partially
offset by higher workover activity costs of $1.1 million between periods and
increased LOE associated with our higher well count, which increased to 409
gross operated horizontal wells as of June 30, 2021 from 381 gross operated
horizontal wells as of June 30, 2020.
LOE per Boe was $4.10 for the second quarter of 2021, which represents a
decrease of $0.06 per Boe (or 1%) from the second quarter of 2020. This decrease
was primarily driven by per BOE cost decreases between periods associated with
lower electricity charges between periods as well as cost-reduction initiatives
we have undertaken, both of which are discussed above. These decreases were
partially offset by the higher level of workover activity between periods and by
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.
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Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three
months ended June 30, 2021 increased $10.1 million compared to the three months
ended June 30, 2020. Severance taxes are primarily based on the market value of
our 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 second quarter of 2021 increased $9.2 million compared to the same 2020
period primarily due to higher oil, natural gas and NGL revenues between
periods.
Severance and ad valorem taxes as a percentage of total net revenues increased
to 6.8% for the second quarter of 2021 as compared to 6.3% for the same prior
year quarter. This increase in rate between periods was mainly due to a higher
blended tax rate paid on oil, natural gas, and NGL revenues in 2021 due to a
greater percentage of our commodity sales being generated in New Mexico, which
has higher severance tax rates than Texas.
Gathering, Processing and Transportation Expenses. Gathering, processing and
transportation expenses ("GP&T") for the three months ended June 30, 2021
increased $2.2 million as compared to the three months ended June 30, 2020. On a
per Boe basis, GP&T likewise increased from $2.78 for the second quarter of 2020
to $3.47 for the second quarter of 2021. These increases were mainly related to
substantially higher natural gas and NGL prices between periods, as these
products are cost inputs into the percent-of-proceeds ("POP") portion of our gas
plant processing fees.
Depreciation, Depletion and Amortization. The following table summarizes our
depreciation, depletion and amortization ("DD&A") for the periods indicated:
                                                                     Three Months Ended June 30,
(in thousands, except per Boe data)                                   2021                   2020
Depreciation, depletion and amortization                        $       73,429$    93,020
Depreciation, depletion and amortization per Boe                $        

13.09 $ 14.98



For the three months ended June 30, 2021, DD&A expense amounted to $73.4
million, a decrease of $19.6 million over the same 2020 period. The primary
factor contributing to lower DD&A expense in 2021 was the decrease in our DD&A
rates between periods, which lowered our DD&A expense by $10.7 million, while
our lower overall production volumes between periods decreased DD&A expense by
an additional $8.9 million during the three months ended June 30, 2021.
Our DD&A rate can fluctuate as a result of finding and development costs
incurred, acquisitions, impairments, as well as changes in proved developed and
proved undeveloped reserves. DD&A per Boe was $13.09 for the second quarter of
2021 compared to $14.98 for the same period in 2020. This decrease in DD&A rate
was primarily due to net upward revisions in our proved developed reserves since
the second quarter of 2020 related to lower operating costs realized and higher
SEC reserve pricing.
Impairment and Abandonment Expense. During the three months ended June 30, 2021
impairment and abandonment expense was $9.2 million as compared to $19.4 million
during the three months ended June 30, 2020 both of which related to the
amortization of leasehold expiration costs associated with individually
insignificant unproved properties.
Exploration and Other Expenses. The following table summarizes our exploration
and other expenses for the periods indicated:
                                                      Three Months Ended 

June 30,

 (in thousands)                                            2021             

2020

 Geological and geophysical costs              $        1,173$ 1,081
 Rig termination fees                                       -                     1,547
 Severance payments                                         -                       722
 Stock-based compensation - equity awards                 221               

457

 Stock-based compensation - liability awards              239               

-

 Other expenses                                           131               

244

 Exploration and other expenses                $        1,764

$ 4,051



Exploration and other expenses were $1.8 million for the three months ended June
30, 2021 compared to $4.1 million for the three months ended June 30, 2020.
Exploration and other expenses mainly consist 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 decrease
was primarily related to $1.5 million in rig termination fees and $0.7 million
in nonrecurring severance payments to G&G personnel in the second quarter of
2020, which were not similarly incurred in the second quarter of 2021.
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General and Administrative Expenses. The following table summarizes our general
and administrative ("G&A") expenses for the periods indicated:
                                                       Three Months Ended 

June 30,

  (in thousands)                                           2021                   2020
  Cash general and administrative expenses      $       10,126$ 10,840
  Stock-based compensation - equity awards               4,260                    4,270
  Stock-based compensation - liability awards           14,421                        -
  Severance payments                                         -                    2,884
  General and administrative expenses           $       28,807$ 17,994


G&A expenses for the three months ended June 30, 2021 were $28.8 million
compared to $18.0 million for the three months ended June 30, 2020. Higher
G&A in the second quarter of 2021 was primarily the result of $14.4 million in
stock compensation expense related to liability awards granted to G&A employees
in the third quarter of 2020 that are settleable 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 for additional information regarding the liability
awards). This increase was partially offset by $2.9 million in severance
payments made to G&A employees in the 2020 period that did not similarly reoccur
in the second quarter of 2021.
Other Income and Expenses.
Interest Expense. The following table summarizes our interest expense for the
periods indicated:
                                                                    Three Months Ended June 30,
(in thousands)                                                       2021                   2020
Credit facility                                                $        2,762$     3,159
8.00% Senior Secured Notes due 2025                                       367                1,129
5.375% Senior Notes due 2026                                            3,889                4,732
6.875% Senior Notes due 2027                                            6,125                7,524
3.25% Convertible Senior Notes due 2028                                 1,381                    -
Amortization of debt issuance costs and debt discount                   1,040                1,535
Interest capitalized                                                     (382)                (708)
Total                                                          $       15,182$    17,371


Interest expense was $2.2 million lower for the three months ended June 30, 2021
as compared to the three months ended June 30, 2020 primarily due to (i) $2.2
million lower interest expense incurred on our Senior Unsecured Notes during the
second quarter of 2021, as $110.6 million of the Senior Notes due 2026 and
$143.7 million of the Senior Notes due 2027 were extinguished in our 2020 debt
exchange transaction; (ii) $0.8 million lower interest incurred on our Senior
Secured Notes due 2025 as these notes were redeemed in April 2021; and (iii)
$0.4 million in decreased interest expense incurred on our credit facility
borrowings. These decreases were partially offset by higher interest expense
incurred on our Convertible Senior Notes that were issued in March of 2021.
Refer to Note 4-Long-Term Debt under Part I, Item I of this Quarterly Report for
additional information on our senior notes and debt transactions.
Our weighted average borrowings outstanding under our credit facility were
$289.8 million versus $344.7 million for the three months ended June 30, 2021
and 2020, respectively. Our credit facility's weighted average effective
interest rate (which is a LIBOR-based rate) was 3.3% and 3.1% for the three
months ended June 30, 2021 and 2020, respectively.
Gain (loss) on extinguishment of debt. During the three months ended June 30,
2021, we redeemed at par all of our $127.1 million aggregate principal amount of
Senior Secured Notes outstanding. In connection with this redemption, we
recorded a loss on debt extinguishment of $22.2 million related to the write-off
of all unamortized debt issuance costs and debt discounts associated with these
notes.
A gain of $143.4 million was recognized in the second quarter of 2020 related to
our 2020 debt exchange transaction. 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 for additional information regarding
the debt extinguishment transactions discussed above.
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Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function
of (i) changes in derivative fair values associated with fluctuations in the
forward price curves for the commodities underlying our hedge contracts
outstanding and (ii) monthly cash settlements on any closed out hedge positions
during the period.
The following table presents gains and losses on our derivative instruments for
the periods indicated:
                                                                     Three Months Ended June 30,
(in thousands)                                                        2021                   2020
Realized cash settlement gains (losses)                         $      (37,513)$    (6,894)
Non-cash mark-to-market derivative gain (loss)                         (17,446)             (22,963)
Total                                                           $      (54,959)$   (29,857)

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

                                                 Three Months Ended June 

30,

      (in thousands)                                  2021                 

2020

      Income (loss) before income taxes   $        (25,055)

$ 3,414

      Income tax (expense) benefit                       -                 

1,916



Our provisions for income taxes for the three months ended June 30, 2021 and
2020 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) state income taxes, (ii) permanent differences, and (iii) any changes
during the period in our deferred tax asset valuation allowance.
For the three months ended June 30, 2021, we recognized a deferred tax asset
valuation allowance of $7.6 million against net operating losses ("NOLs") we
generated during the quarter, and such NOLs are estimated as unlikely to be
realized in future periods. The increase in the valuation allowance was the
primary factor reducing our income tax benefit (based on the U.S. statutory
rate) in the quarter to zero for the second quarter of 2021. We recognized an
income tax benefit of $1.9 million for the three months ended June 30, 2020
primarily due to the release of a portion of our deferred tax asset valuation
allowance relating to our conversion of Class C shares to Class A shares during
the period.

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Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
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:
                                                Six Months Ended June 30,                       Increase/(Decrease)
                                                2021                  2020                      $                      %
Net revenues (in thousands):
Oil sales                                 $      310,831$  243,605          $           67,226                 28  %
Natural gas sales                                 62,466              17,145                      45,321                264  %
NGL sales                                         51,671              22,528                      29,143                129  %
Oil and gas sales                         $      424,968$  283,278          $          141,690                 50  %

Average sales prices:
Oil (per Bbl)                             $        57.08$    33.92          $            23.16                 68  %
Effect of derivative settlements on
average price (per Bbl)                           (11.12)              (0.76)                     (10.36)            (1,363) %
Oil net of hedging (per Bbl)              $        45.96$    33.16          $            12.80                 39  %

Average NYMEX price for oil (per Bbl) $ 61.95$ 37.09 $

            24.86                 67  %
Oil differential from NYMEX                        (4.87)              (3.17)                      (1.70)               (54) %

Natural gas (per Mcf)                     $         3.13          $     0.82          $             2.31                282  %
Effect of derivative settlements on
average price (per Mcf)                             0.01               (0.07)                       0.08                114  %

Natural gas net of hedging (per Mcf) $ 3.14 $ 0.75 $

             2.39                319  %

Average NYMEX price for natural gas (per
Mcf)                                      $         3.15          $     1.76          $             1.39                 79  %
Natural gas differential from NYMEX                (0.02)              (0.94)                       0.92                 98  %

NGL (per Bbl)                             $        30.10$    10.79          $            19.31                179  %

Net production:
Oil (MBbls)                                        5,446               7,182                      (1,736)               (24) %
Natural gas (MMcf)                                19,956              20,855                        (899)                (4) %
NGL (MBbls)                                        1,717               2,088                        (371)               (18) %
Total (MBoe)(1)                                   10,488              12,746                      (2,258)               (18) %

Average daily net production:
Oil (Bbls/d)                                      30,086              39,461                      (9,375)               (24) %
Natural gas (Mcf/d)                              110,253             114,585                      (4,332)                (4) %
NGLs (Bbls/d)                                      9,484              11,474                      (1,990)               (17) %
Total (Boe/d)(1)                                  57,945              70,333                     (12,388)               (18) %



(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

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Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the six months
ended June 30, 2021 were $141.7 million, or 50%, higher than total net revenues
for the six months ended June 30, 2020. Revenues are a function of oil, natural
gas and NGL volumes sold and average commodity prices realized.
Average realized sales prices for oil, natural gas and NGLs for the first half
of 2021 all increased when compared to the same 2020 period. The average price
for oil before the effects of hedging increased 68%, the average price for
natural gas before the effects of hedging increased 282%, and the average price
for NGLs increased 179% between periods. The 68% increase in the average
realized oil price was mainly the result of higher NYMEX crude prices between
periods (average NYMEX prices increased 67%), which was minimally offset by
wider oil differentials ($1.70 per Bbl wider). The average realized sales price
of natural gas increased 282% due to higher average NYMEX gas prices between
periods (average NYMEX prices increased 79%), as well as improved gas
differentials ($0.92 per Mcf). The 179% increase in average realized NGL prices
between periods was primarily attributable to higher Mont Belvieu spot prices
for plant products for the first half of 2021 compared to the first half of
2020. The market prices for oil, natural gas and NGLs have all been impacted by
higher global demand for oil and gas compared to the first half of 2020 when
prices decreased significantly as a result of COVID-19 and supply disruptions
from the Russia-Saudi oil price war, beginning in March 2020 as discussed in the
market conditions section above. Additionally, the first quarter 2021 realized
price for natural gas in the Permian Basin was impacted by Winter Storm Uri,
which caused gas pipeline and supply disruptions and resulted in significant
increases in Permian natural gas prices during this period.
Net production volumes for oil, natural gas, and NGLs decreased 24%, 4%, and
18%, respectively. The oil production volume decrease was primarily the result
of less drilling and completion activity over the past 12 months as a result of
depressed oil and gas prices, which resulted in only 28 wells being placed on
production since the second quarter of 2020. This added 1,214 MBbls of net oil
production to the six months ended June 30, 2021 as compared to 70 wells brought
online since the second quarter of 2019 that added 3,207 MBbls of net oil
production to the six months ended June 30, 2020. Oil volume declines in the
first half of 2021 were additionally impacted by the temporary shut-in of our
wells during mid-February as a result of Winter Storm Uri and 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 the first half of 2021, the amount of gas
flared as a percentage of wellhead gas produced was significantly less as
compared to the same 2020 period, resulting in a higher ratio of natural gas and
NGL volumes produced compared to oil volumes during the period.
Operating Expenses. The following table summarizes our operating expenses for
the periods indicated:
                                                Six Months Ended June 30,                      Increase/(Decrease)
                                                 2021                 2020                      $                     %
Operating costs (in thousands):
Lease operating expenses                   $      48,837$   58,478          $           (9,641)             (16) %
Severance and ad valorem taxes                    28,367              22,269                       6,098               27  %
Gathering, processing and transportation
expenses                                          40,119              34,223                       5,896               17  %
Operating costs per Boe:
Lease operating expenses                   $        4.66$     4.59          $             0.07                2  %
Severance and ad valorem taxes                      2.70                1.75                        0.95               54  %
Gathering, processing and transportation
expenses                                            3.83                2.68                        1.15               43  %


Lease Operating Expenses. LOE for the six months ended June 30, 2021 decreased
$9.6 million as compared to the six months ended June 30, 2020. Lower LOE for
the first half of 2021 was primarily related to (i) a $3.6 million decrease in
workover expense between periods; (ii) decreases in electricity costs as a
result of credits realized in the current year period related to Winter Storm
Uri; (iii) lower well operating expenses due to cost reduction initiatives,
which included moving multiple wells off generator to more cost-efficient
electrical line-power and switching wells away from electric submersible pumps
to more reliable and lower cost gas lift; and (iv) lower variable and
semi-variable costs stemming from the 18% production decline between periods.
These decreases were partially offset by additional LOE associated with our
higher well count, which increased to 409 gross operated horizontal wells as of
June 30, 2021 from 381 gross operated horizontal wells as of June 30, 2020.
LOE per Boe was $4.66 for the six months ended June 30, 2021, which represents
an increase of $0.07 per Boe (or 2%) from the comparable 2020 period. This
increase in rate was primarily driven 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. These
increases were partially offset by the lower level of workover activity in the
2021 period, decreased electricity costs, as well as cost reduction initiatives
we have undertaken, all of which are discussed above.
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Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the six
months ended June 30, 2021 increased $6.1 million compared to the six months
ended June 30, 2020. Severance taxes are primarily based on the market value of
our production at the wellhead, while ad valorem taxes are generally based on
the assessed taxable value of our proved developed oil and natural gas
reserves and vary across the different counties in which we operate. Severance
taxes for the first half of 2021 increased $8.5 million compared to the same
2020 period primarily due to higher oil, natural gas and NGL revenues between
periods. These increases were partially offset by a $2.4 million decrease in ad
valorem taxes 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 decreased to 6.7% for the first half of 2021 as compared to 7.9% for
the same 2020 period as a result of the 2021 ad valorem tax assessments that
were $2.4 million lower in the current period, as discussed above.
Gathering, Processing and Transportation Expenses. GP&T for the six months ended
June 30, 2021 increased $5.9 million compared to the six months ended June 30,
2020. On a per Boe basis, GP&T likewise increased from $2.68 for the first half
of 2020 to $3.83 for the same 2021 period. These increases were mainly
attributable to (i) higher gas plant processing costs, whose POP fee portion is
based on natural gas and NGL prices, both of which increased substantially
between periods as discussed above, and (ii) a $1.5 million decrease in
reimbursements received from third parties for their usage of our available firm
transport capacity.
Depreciation, Depletion and Amortization. The following table summarizes our
DD&A for the periods indicated:
                                                          Six Months Ended June 30,
(in thousands, except per Boe data)                          2021           

2020

Depreciation, depletion and amortization            $      137,212$ 194,278
Depreciation, depletion and amortization per Boe    $        13.08

$ 15.24



For the six months ended June 30, 2021, DD&A expense amounted to $137.2 million,
a decrease of $57.1 million over the same 2020 period. The primary factor
contributing to lower DD&A expense in 2021 was the decrease in our overall
production volumes between periods, which lowered DD&A expense by $34.3 million
during the first half of 2021, while lower DD&A rates between periods decreased
DD&A expense by $22.8 million during the six months ended June 30, 2021.
Our DD&A rate can fluctuate as a result of finding and development costs
incurred, acquisitions, impairments, as well as changes in proved developed and
proved undeveloped reserves. DD&A per Boe was $13.08 for the first half of 2021
compared to $15.24 for the same period in 2020. 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) net upward revisions in our proved developed reserves
since the second quarter of 2020 related to lower operating costs realized and
higher SEC reserve pricing.
Impairment and Abandonment Expense. During the six months ended June 30, 2021,
$18.4 million of impairment and abandonment expense was incurred related to the
amortization of leasehold expiration costs associated with individually
insignificant unproved properties. During the six months ended June 30, 2020,
impairment and abandonment expense was $630.7 million and consisted of (i) a
$591.8 million non-cash impairment of our proved oil and gas properties as a
result of depressed NYMEX oil and gas forward curves as of March 31, 2020; and
(ii) $38.9 million related to the amortization of leasehold expiration costs
associated with individually insignificant unproved properties.
Exploration and Other Expenses. The following table summarizes our exploration
and other expenses for the periods indicated:
                                                        Six Months Ended 

June 30,

   (in thousands)                                           2021                 2020
   Geological and geophysical costs              $       1,786$ 3,074
   Rig termination fees                                      -                   3,046
   Severance payments                                        -                     722
   Stock-based compensation - equity awards                429                     974
   Stock-based compensation - liability awards             406                       -
   Other expenses                                          238                     244
   Exploration and other expenses                $       2,859$ 8,060

Exploration and other expenses were $2.9 million for the six months ended June 30, 2021 compared to $8.1 million for the same prior year period. Exploration and other expenses mainly consist of topographical studies, G&G projects, salaries and expenses of G&G personnel and includes other operating costs. The period over period decrease was primarily due to (i) rig

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termination fees that went from $3.0 million in the first half of 2020 (when we
reduced our drilling program from five rigs to none) to zero in the 2021 period;
(ii) $1.0 million in lower ongoing G&G personnel costs related to the 2020
workforce reduction; and (iii) $0.7 million in severance payments to G&G
employees in the 2020 period that did not reoccur in the first half of 2021.
General and Administrative Expenses. The following table summarizes our G&A
expenses for the periods indicated:
                                                                      Six Months Ended June 30,
(in thousands)                                                        2021                  2020
Cash general and administrative expenses                        $      20,758$    23,818
Stock-based compensation expense - equity awards                        8,637               10,162
Stock-based compensation expense - liability awards                    24,668                    -
Severance payments                                                          -                2,884
General and administrative expenses                             $      

54,063 $ 36,864



G&A expenses for the six months ended June 30, 2021 were $54.1 million compared
to $36.9 million for the six months ended June 30, 2020. The higher G&A expenses
incurred in the first six months of 2021 were primarily the result of $24.7
million in stock compensation expense related to liability awards granted to G&A
employees in the third quarter of 2020 that are settleable in cash upon vesting.
These liability stock-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 for additional information regarding the liability
awards). This increase was partially offset by (i) $2.9 million in severance
payments to G&A employees in the 2020 period that did not reoccur in the first
half of 2021; and (ii) $1.8 million in lower payroll and other personnel related
costs and a $1.5 million decrease in equity-based stock compensation expense
between periods; both of which were primarily the result of the reduction in
workforce.
Other Income and Expenses.
Interest Expense. The following table summarizes our interest expense for the
periods indicated:
                                                                     Six Months Ended June 30,
(in thousands)                                                       2021                  2020
Credit facility                                                $       6,077$     5,326
8.00% Senior Secured Notes due 2025                                    2,908                1,129
5.375% Senior Notes due 2026                                           7,778               10,106
6.875% Senior Notes due 2027                                          12,250               16,118
3.25% Convertible Senior Notes due 2028                                1,553                    -
Amortization of debt issuance costs and debt discount                  2,887                2,334
Interest capitalized                                                    (786)              (1,221)
Total                                                          $      32,667$    33,792


Interest expense was $1.1 million lower for the six months ended June 30, 2021
compared to the same 2020 period mainly due to $6.2 million of lower interest
incurred on our Senior Unsecured Notes during the 2021 period, as $110.6 million
of the Senior Notes due 2026 and $143.7 million of the Senior Notes due 2027
were extinguished in our debt exchange transaction in May 2020. This decrease
was partially offset by (i) $1.8 million in increased interest expense on our
Senior Secured Notes due 2025 that were issued in May of 2020 and then
subsequently redeemed in April of 2021; (ii) $1.6 million in additional interest
incurred on our Convertible Senior Notes that were issued in March of 2021; and
(iii) $0.8 million in higher interest expense incurred on our credit facility
borrowings. Refer to Note 4-Long-Term Debt under Part I, Item I of this
Quarterly Report for additional information on our senior notes and debt
transactions.
Our weighted average borrowings outstanding under our credit facility were
$310.2 million and $311.6 million for the first half of 2021 and 2020,
respectively. Our credit facility's weighted average effective interest rate
(which is a LIBOR-based rate) was 3.4% and 3.0% for the six months ended
June 30, 2021 and 2020, respectively.
Gain (loss) on extinguishment of debt. During the three months ended June 30,
2021, we redeemed at par all of our $127.1 million aggregate principal amount of
Senior Secured Notes outstanding. In connection with this redemptions, we
recorded a loss on debt extinguishment of $22.2 million related to the write-off
of all unamortized debt issuance costs and debt discounts associated with these
notes.
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A gain of $143.4 million was recognized in the first half of 2020 related to our
2020 debt exchange transaction. 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 for additional information regarding the debt
extinguishment transactions discussed above.
Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function
of (i) changes in derivative fair values associated with fluctuations in the
forward price curves for the commodities underlying our hedge contracts
outstanding and (ii) monthly cash settlements on any closed out hedge positions
during the period.
The following table presents gains and losses for derivative instruments for the
periods indicated:
                                                         Six Months Ended June 30,
(in thousands)                                              2021                2020
Realized cash settlement gains (losses)            $      (60,399)$  (6,947)
Non-cash mark-to-market derivative gain (loss)            (45,759)             (31,415)
Total                                              $     (106,158)$ (38,362)

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

                                                   Six Months Ended June 30,
         (in thousands)                              2021                 2020
         Income (loss) before income taxes   $     (59,700)           $

(630,139)

         Income tax (expense) benefit                    -                

85,124



Our provisions for income taxes for the first half of 2021 and 2020 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) state income
taxes; (ii) permanent differences; and (iii) any changes during the period in
our deferred tax asset valuation allowance.
For the six months ended June 30, 2021 and 2020, we recognized deferred tax
asset valuation allowances of $20.0 million and $49.7 million, respectively,
against net operating losses ("NOLs") we generated during those respective
periods, and such NOLs are estimated as unlikely to be realized in future
periods. These increases in the valuation allowance were the primary factor
reducing our income tax benefits (based on the U.S. statutory rate) in each
respective quarter to zero for the first six months of 2021 and to $85.1 million
for the first six months of 2020.

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Liquidity and Capital Resources
Overview
Our drilling and completion 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, which
have been and will likely continue to be volatile. Lower commodity prices can
negatively impact our 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 the acquisition
of oil and natural gas properties. The following table summarizes our capital
expenditures ("capex") incurred for the six months ended June 30, 2021:
      (in millions)                           Six Months Ended June 30, 

2021

      Drilling, completion and facilities    $                         

152.9

      Infrastructure, land and other                                     

3.2


      Total capital expenditures incurred    $                         

156.1



  We continually evaluate our capital needs and compare them to our capital
resources. We operated a two-rig drilling program during the first half of 2021
and plan to continue with two rigs for the remainder of the year. 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 funded our capital expenditures for the six months ended June 30,
2021 entirely from cash flows from operations, and we expect to fund the
remainder of our 2021 capex budget entirely from cash flows from operations as
well, given current commodity price levels and our commodity hedge position. We
were free cash flow positive during the first half of 2021 such that we were
able to partially pay down borrowings under our credit agreement during the
period, and based upon current commodity prices, we expect to continue to pay
down borrowings with expected free cash flow generation during the remainder of
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.
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, to manage our future maturities, lower interest expense, and improve
our liquidity position, we issued 3.25% Convertible Senior Notes in March 2021,
which resulted in net proceeds of $163.6 million. The proceeds were used to
repay borrowing outstanding under CRP's revolving credit facility and to fund
the cost of entering into capped call spread transactions of $14.7 million. In
April 2021, we redeemed at par all of our 2025 senior secured notes ($127.1
million) that bore interest at 8% per year and paid accrued interest of $3.8
million on these notes, which was the intended use of proceeds from the
Convertible Senior Notes offering.
Analysis of Cash Flow Changes
The following table summarizes our cash flows for the periods indicated:
                                                                      Six Months Ended June 30,
(in thousands)                                                       2021                   2020
Net cash provided by operating activities                      $      179,625$     84,503
Net cash used in investing activities                                (127,076)             (277,050)
Net cash (used in) provided by financing activities                   (53,644)              189,558


For the six months ended June 30, 2021, we generated $179.6 million of cash from
operating activities, an increase of $95.1 million from the same period in 2020.
Cash provided by operating activities increased primarily due to higher realized
prices for all commodities, lower lease operating expenses, lower exploration
expense, lower cash G&A expenses and the timing of our
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supplier payments during the six months ended June 30, 2021. These increasing
factors were partially offset by lower production volumes, higher GP&T and
severance and ad valorem costs, the timing of our receivable collections, and
cash settlement losses from derivatives for the six months ended June 30, 2021
as compared to the same 2020 period. Refer to "Results of Operations" for more
information on the impact of volumes and prices on revenues and on fluctuations
in our operating expenses between periods.
During the six months ended June 30, 2021, cash flows from operating activities
and net proceeds from the issuance of the Convertible Senior Notes were used to
finance $126.7 million of drilling and development cash expenditures, repay net
borrowings of $75.0 million under our credit facility, redeem $127.1 million of
our 2025 senior secured notes outstanding and to fund $14.7 million in capped
call spread transactions.
During the six months ended June 30, 2020, cash flows from operating activities,
cash on hand, and net borrowings of $195.0 million under our credit facility
were used to finance $271.4 million of drilling and development cash
expenditures, to fund $6.1 million in oil and gas property acquisitions, and to
finance $5.1 million of debt issuance and exchange costs.
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"). As of June 30, 2021, we had $255.0
million in borrowings outstanding and $441.0 million in available borrowing
capacity, which was net of $4.0 million in letters of credit. The borrowing base
had previously been reduced by an availability blocker of $31.8 million,
however, the blocker was removed as a result of the Senior Secured Note
redemption discussed above. In connection with the Credit Agreement's spring
2021 semi-annual borrowing base redetermination, the borrowing base and amount
of elected commitments were 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 us to maintain compliance with the
following financial ratios:
(i) a current ratio, which is the ratio of CRP's consolidated current assets
(including unused commitments under its revolving credit facility and excluding
non-cash derivative assets and certain restricted cash) to its consolidated
current liabilities (excluding any current portion of long-term debt due 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
(iii) a leverage ratio, as defined with 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 the applicable financial ratios
described above as of June 30, 2021 and through the filing of this Quarterly
Report.
For further information on the Credit Agreement, refer to Note 4-Long-Term Debt
under Part I, Item I of this Quarterly Report.
Convertible Senior Notes
On March 19, 2021, CRP issued $150.0 million in aggregate principal amount of
Convertible Senior Notes. On March 26, 2021, CRP issued an additional $20.0
million of Convertible Senior Notes pursuant to the exercise of the
underwriters' over-allotment option to purchase additional Convertible Senior
Notes. The Convertible Senior Notes bear interest at an annual rate of 3.25% and
are due on April 1, 2028. Interest is payable semi-annually in arrears on each
April 1 and October 1, commencing on October 1, 2021. CRP can settle the
Convertible Senior Notes by paying or delivering cash, shares of the Company's
Class A common stock (the "Common Stock"), or a combination of cash and Common
Stock, at CRP's election.
The Convertible Senior Notes are fully and unconditionally guaranteed on a
senior unsecured basis by the Company and each of CRP's current subsidiaries
that guarantee CRP's outstanding Senior Unsecured Notes as defined below.
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Senior Notes
On November 30, 2017, CRP issued $400.0 million of 5.375% senior notes due 2026
(the "2026 Senior Notes") and on March 15, 2019, CRP issued $500.0 million of
6.875% senior notes due 2027 (the "2027 Senior Notes" and, together with the
2026 Senior Notes, the "Senior Unsecured Notes") in 144A private placements. In
May 2020, $110.6 million aggregate principal amount of the 2026 Senior Notes and
$143.7 million aggregate principal amount of the 2027 Senior Notes were validly
tendered and exchanged by certain eligible bondholders for consideration
consisting of $127.1 million aggregate principal amount of 8.00% second lien
senior secured notes due (the "Senior Secured Notes"). The Senior Secured Notes
were fully redeemed at par in connection with the Convertible Senior Notes
issuance during the second quarter of 2021.
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.
The indentures governing the Senior Unsecured 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 June 30, 2021 and through the filing of
this Quarterly Report.
For further information on our Convertible Senior Notes and Senior Unsecured
Notes, refer to Note 4-Long-Term Debt under Part I, Item I of this Quarterly
Report.
Contractual Obligations
Our contractual obligations include operating and transportation agreements,
drilling rig contracts, office and equipment leases, asset retirement
obligations, long-term debt obligations and cash interest expense on long-term
debt obligations, which we routinely enter into, modify or extend. Since
December 31, 2020, there have not been any significant, non-routine changes in
our contractual obligations, other than the changes to certain of our operating
lease commitments and principal and interest due under our senior notes
discussed above. Refer to Note 13-Leases under Part I, Item I of this Quarterly
Report for updated contractual obligations associated with our operating leases
as of June 30, 2021.
Critical Accounting Policies and Estimates
There have been no material changes during the six months ended June 30, 2021 to
the critical accounting policies previously disclosed in our 2020 Annual Report.
Please refer to Part II, Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations-Critical Accounting Policies and
Estimates in our 2020 Annual Report for a discussion of our critical accounting
policies and estimates.
New Accounting Pronouncements
Please refer to Note 1-Basis of Presentation and Summary of Significant
Accounting Policies under Part I, Item 1. of this Quarterly Report for a
discussion of recently adopted accounting standards and the potential effects of
new accounting pronouncements.
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08/03INSIDER TRENDS : Centennial Resource Development Insider Sells Stock for Taxes Interruptin..
MT
08/03INSIDER TRENDS : Centennial Resource Development Insider Disposes of Shares for Tax Slowin..
MT
08/03INSIDER TRENDS : Centennial Resource Development Insider Makes Shares Sale for Tax Slowing..
MT
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