The following discussion and analysis should be read in conjunction with our
condensed consolidated financial statements and related notes included in Item
1. Financial Statements of this report. Further, we encourage you to review the
Special Note Regarding Forward-Looking Statements.

EXECUTIVE SUMMARY

March 31, 2022 Financial Overview of Operations and Liquidity

Market Conditions

The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. Commodity prices reflect global supply and demand dynamics as well as the geopolitical and macroeconomic environment.

Crude Oil Markets



In 2021, the global economy continued to recover due to the containment of
COVID-19 and related emerging variants, which resulted to an increase in crude
oil demand. Overall production from OPEC+ has not increased at the same pace of
the demand, creating upward pressure on crude oil prices and tightening of
global oil inventories. In February 2022, Russia, a major global crude oil
exporter, attacked and invaded Ukraine, driving the United States ("U.S.") and
other Western countries to apply sanctions over crude oil imports from Russia.
Additionally, many crude oil purchasers are boycotting Russian crude oil in
response to the attacks on Ukraine. All of these factors have led to lower
global oil supply and significantly higher crude oil prices in the first quarter
of 2022 when compared to 2021.

The commodity price environment may remain volatile for an extended period due
to, among other things, the continued invasion in Ukraine, outbreaks caused by
coronavirus variants, the recovery of the economy, unexpected supply disruptions
in key producing countries including the potential for higher U.S. crude oil
production, historically low storage inventories of petroleum products,
geopolitical disputes, weather conditions, and ongoing investor and regulatory
pressure to replace fossil fuel consumption with lower carbon emission
alternatives.

Natural Gas and NGL Markets



In addition to the crude oil market drivers noted above, natural gas and NGL
prices are also affected by structural changes in supply and demand, growth in
levels of liquified natural gas exports and deviations from seasonally normal
weather. Lower inventory levels and lack of reinvestment in supply growth have
driven natural gas and NGL prices higher.

Financial Matters

Three months ended March 31, 2022 compared to three months ended December 31, 2021



•Production volumes decreased to 17.9 MMboe in the first quarter of 2022, a
decrease of 8 percent compared to the fourth quarter of 2021, primarily driven
by the timing of our turn-in-line activities and two fewer days in the first
quarter of 2022.

•Crude oil, natural gas and NGLs sales increased to $882.4 million compared to
$848.2 million in the fourth quarter of 2021 primarily due to a 13 percent
increase in weighted average realized commodity prices partially offset by 8
percent decrease in production volumes between periods.

•Negative net settlements from our commodity derivative contracts decreased to
$161.6 million in the first quarter of 2022 compared to $194.8 million in the
fourth quarter of 2021 due to a lower volume of commodities hedged in the first
quarter of 2022.

•Combined revenue from crude oil, natural gas and NGLs sales and net settlements
from our commodity derivative instruments increased 10 percent to $720.8 million
from $653.3 million in the fourth quarter of 2021.
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                                PDC ENERGY, INC.

•Generated a net loss of $32.0 million, or $0.33 per diluted share for the first
quarter of 2022 and a net income of $473.1 million, or $4.78 per diluted share
for the fourth quarter of 2021 primarily due to a $568.1 million commodity price
risk management loss incurred in 2022 partially offset by an increase in crude
oil, natural gas and NGLs sales of $34.2 million between periods.

•Adjusted EBITDAX, a non-U.S. GAAP financial measure, was $549.3 million
compared to $487.7 million for the fourth quarter of 2021, primarily due to an
increase in sales of $67.5 million, net of negative net derivative settlements,
partially offset by an increase in costs experienced in operations.

•Cash flows from operations decreased to $489.0 million compared to $520.0
million in the fourth quarter of 2021. Adjusted cash flows from operations, a
non-U.S. GAAP financial measure, increased to $538.8 million compared to $473.1
million in fourth quarter of 2021. Adjusted free cash flows, a non-U.S. GAAP
financial measure, decreased to $318.7 million from $339.5 million in the fourth
quarter of 2021.

See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed
discussion of these non-U.S. GAAP financial measures and a reconciliation of
these measures to the most comparable U.S. GAAP measures.

Pending Acquisition



On February 26, 2022, we entered into the Acquisition Agreement to acquire Great
Western for approximately $1.4 billion, inclusive of Great Western's net debt.
Great Western is an independent oil and gas company focused on the exploration,
production and development of crude oil and natural gas in Colorado. We
anticipate acquiring approximately 54,000 net acres in the Core Wattenberg and
production of approximately 55,000 Boe per day. Under the terms of the
Acquisition Agreement, the purchase consideration for the Great Western
Acquisition will be made through the transfer of approximately 4.0 million
shares of our common stock and approximately $543 million in cash. The cash
portion of the purchase price is expected to be funded through a combination of
cash on hand and availability under our revolving credit facility. We anticipate
that the Great Western Acquisition will be completed in May 2022, subject to
certain customary closing conditions being met.

Drilling and Completion Overview



In the Wattenberg Field, we operated one full-time drilling rig, one spudder rig
and one full-time completion crew during the first quarter of 2022 and added a
second full-time drilling rig in mid-March 2022. In addition, we operated one
full-time drilling rig and one completion crew during the first quarter of 2022
in the Delaware Basin. Our total capital investments in crude oil and natural
gas properties for the three months ended March 31, 2022 were $220.2 million.

The following table summarize our drilling and completion activities for the three months ended March 31, 2022:



                                                                                         Operated Wells
                                                Wattenberg Field                            Delaware Basin                               Total
                                          Gross                   Net                  Gross                  Net               Gross              Net
In-process as of December 31,
2021                                        143                   133.0                      21                20.6               164              153.6
Wells spud                                   20                    17.8                       6                 5.9                26               23.7
Wells turned-in-line                        (40)                  (38.8)                     (9)               (9.0)              (49)             (47.8)

In-process as of March 31, 2022             123                   112.0                      18                17.5               141              129.5


Our in-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our in-process wells are generally completed and turned-in-line within two years of drilling.


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                                PDC ENERGY, INC.

Capital Returns



Stock Repurchase Program. In February 2022, our board of directors approved a
new stock repurchase program that reset the total repurchase value to $1.25
billion, which we currently anticipate fully utilizing by December 31, 2023. We
repurchased 1.3 million shares of outstanding common stock at a cost of $85.3
million for the three months ended March 31, 2022. As of March 31, 2022, $1.19
billion of our outstanding common stock remained available for repurchases under
the program.

Dividends. For the three months ended March 31, 2022, our dividends declared amounted to $0.25 per share of common stock or $24.5 million in the aggregate.

2022 Operational and Financial Outlook



On a PDC standalone basis (without consideration to the Great Western
Acquisition), we anticipate that our production for 2022 will range between
195,000 Boe to 205,000 Boe per day, approximately 62,000 Bbls to 65,000 Bbls of
which are expected to be crude oil. Our planned 2022 capital investments in
crude oil and natural gas properties, which we expect to be between $675 million
and $725 million, are focused on continued execution of our development plans in
the Wattenberg Field and the Delaware Basin. Our capital budget for 2022 is
likely to be impacted by cost inflation if crude oil and natural gas prices
remain at current levels or continue to increase. Our 2022 operational and
financial projections will be updated after we close the Great Western
Acquisition.

We have operational flexibility to control the pace of our capital spending. As
we execute our capital investment program, we continually monitor, among other
things, expected rates of return, the political environment and our remaining
inventory to best meet our short- and long-term corporate strategy. We may
revise our 2022 capital investment program during the year as a result of, among
other things, changes in commodity prices or our internal long-term outlook for
commodity prices, requirements to hold acreage, the cost of services for
drilling and well completion activities, drilling results, changes in our
borrowing capacity, a significant change in cash flows, regulatory issues, and
acquisition and divestiture opportunities.

Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in
the rural areas of the core Wattenberg Field, which is further delineated
between the Kersey, Prairie, Plains, and Summit development areas. Upon closing
the Great Western Acquisition, we plan to add a fifth development area called
Ranger. Our 2022 capital investment program for the Wattenberg Field, on a PDC
standalone basis, represents approximately 75 percent of our expected total
capital investments in crude oil and natural gas properties. In 2022, the
majority of the wells we plan to drill are 1.5 mile and 2.0 mile lateral wells.
Our plan includes spudding approximately 130 to 145 operated wells and
turning-in-line approximately 115 to 130 operated wells. We added a full-time
drilling rig in March 2022, bringing us to two full-time horizontal rigs and one
completion crew along with a part-time spudder rig planned for the rest of the
year.

Delaware Basin. Total capital investments in crude oil and natural gas
properties in the Delaware Basin for 2022 are expected to be approximately 25
percent, on a PDC standalone basis, of our total capital investments. In 2022,
we anticipate spudding and turning-in-line approximately 15 to 20 operated wells
with the majority of the wells being 2.0 mile lateral wells.

We are committed to our disciplined approach to managing our development plans.
Based on our current production forecast for 2022, we expect 2022 cash flows
from operations to exceed our capital investments in crude oil and natural gas
properties. Our first priority is to pay our quarterly base dividend of $0.25
per share. Then we expect to use approximately 60% or more of our remaining
adjusted free cash flows, a non-U.S. GAAP financial measure, for share
repurchases and special dividends, as needed. Any remaining adjusted free cash
flows will be used for reducing debt, building cash on our consolidated balance
sheet or other general corporate purposes.

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                                PDC ENERGY, INC.

Regulatory and Political Updates



In Colorado, certain interest groups opposed to oil and natural gas development
have proposed ballot initiatives that could hinder or eliminate the ability to
develop resources in the state. In 2019, the Colorado legislature passed Senate
Bill 19-181 ("SB 19-181") to address concerns underlying the ballot initiatives.
Pursuant to SB 19-181, a series of rulemaking hearings were conducted, which
focused on issues such as permitting requirements, setbacks and siting
requirements, and financial assurance, resulting in the adoption of new
regulatory requirements. We anticipate that future hearings will be conducted by
the COGCC on permit fees, worker certification and well site reclamation. These
proceedings could result in new rules that impose increased costs and
regulations on our operations.

A key component of SB 19-181 was the change in the COGCC mission from
"fostering" the industry to "regulating" the industry. As a result, changes were
made to the permitting process in Colorado. As of January 2021, permits are now
designed as Oil and Gas Development Plans ("OGDP"), which streamlines single pad
locations or proximate multi-pad locations into a single permitting package.

Operators also have an option to pursue a Comprehensive Area Plan ("CAP"). A CAP
is designed to represent an overview of oil and gas development over a larger
area over a longer period of time, including a comprehensive cumulative impact
analysis, an alternative location analysis, and extensive communication with
both local elected officials and communities. A CAP will include multiple OGDPs
within its boundaries. As both CAPs and OGDPs are new processes and the COGCC
staff is working to develop the appropriate requirements and adjusting to their
new operating plan, the time needed to obtain a permit has been prolonged. COGCC
rules provide that the permitting process could range between six to twelve
months or more from submission to approval.

In addition to the changes to the permitting process, the COGCC conducted a
rulemaking concerning financial assurance to be provided by operators in
Colorado. The rulemaking was designed to address and reduce the number of wells
that have not been properly plugged by their operators ("orphan wells") due to
financial constraints or bankruptcy. As part of that rulemaking, tiers of
operators were established based on identified metrics which results in varying
levels of financial assurance being required. For our tier, a bond of $40
million will be required in the second quarter of 2022 and will be secured
through our existing surety bond program. In addition to the financial
assurance, operators will be assessed a fixed fee per existing well that will
fund the plugging and abandonment of orphan wells identified by the COGCC. We do
not anticipate a material effect on our financial condition or results of
operations with meeting the outlined financial assurance requirements.

We cannot predict whether future ballot initiatives or other legislation or regulation will be proposed that would limit the areas of the state in which drilling is permitted to occur or impose other requirements or restrictions.



Wattenberg Permits Update. PDC was granted unanimous approval for an 8-well OGDP
located in rural Weld County in October 2021, our first approval under the new
permitting process resulting from a company-wide collaborative effort.
Additionally, in September 2021, we submitted our application for an OGDP
covering an approximate 70-well, multi-pad development plan. We anticipate a
COGCC determination on approval of this OGDP in the second quarter of 2022.

In December 2021, PDC submitted our first CAP. The application proposes
approximately 450 wells spread amongst 25 surface locations in Weld County, to
be developed over several years. We conducted a comprehensive analysis of
potential impacts and have committed to transport all water and commodity
production via pipeline and to provide electrical infrastructure to all
locations. These commitments will lessen the impact of traffic, noise, light and
emissions. Additionally, we developed a dashboard to analyze disproportionately
impacted communities in the area and developed a robust communication plan
designed to encourage communication with and garner feedback from these key
stakeholders. We anticipate a COGCC determination on approval of our CAP by year
end 2022 or early 2023, recognizing that there may be delays in this new
process.

Together, these applications represent our planned Wattenberg Field turn-in-line activity into 2027 on a PDC standalone basis.

Environmental, Social and Governance ("ESG")



We are committed to a meaningful and measurable ESG strategy. Our mission to be
a cleaner, safer and more socially responsible company begins with a sound
strategy, is supported in the boardroom and is overseen by our Environmental,
Social, Governance and Nominating Committee at the board of directors and is
considered at every level of our business.
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                                PDC ENERGY, INC.

During the first quarter of 2022, we completed our Environmental Protection
Agency annual filing for 2021. Our results outline that we have achieved a
reduction in greenhouse gas ("GHG") and methane emissions intensity from 2020
baseline targets, that puts us on track to meet our 60% and 50% GHG and methane
reduction levels by 2025, respectively. Additional information on our ESG
practices, including sustainability goals, key metrics and progress achieved,
can be found in our Sustainability Report available on our website at
www.pdce.com and is not incorporated by reference in this report.

The SEC and other regulatory bodies are proposing a number of climate-change
focused and broader ESG reporting requirements focused on emission reduction.
When adopted, we will modify our disclosures accordingly.


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                                PDC ENERGY, INC.

Results of Operations



In November 2020, the SEC issued Final Rule 33-10890, Management's Discussion
and Analysis, Selected Financial Data and Supplementary Financial Information,
which modernizes and simplifies certain disclosure requirements of Regulation
S-K. One of the updates to Item 303 of Regulation S-K allows registrants to
compare the results of the most recently completed quarter to the results of
either the immediately preceding quarter or the corresponding quarter of the
preceding year. We adopted presenting the results of operations with this
approach effective January 1, 2022, as we believe that comparing current quarter
results to those of the immediately preceding quarter is more useful in
identifying current business trends and provides a more meaningful comparison.
Accordingly, we have compared the results for the three months ended March 31,
2022 and December 31, 2021 below. Additionally, in the first filing after the
adoption of this rule change, we are required to disclose a comparison of the
results for the current quarter and the corresponding quarter of the preceding
fiscal year. Accordingly, the comparison between the results for the three
months ended March 31, 2022 and March 31, 2021 is also presented below.

Summary of Operating Results



The following table presents selected information regarding our operating
results:

                                                          Three Months Ended                                    Percent Change Between
                                        March 31,         December 31,                                March 31, 2022 -         March 31, 2022 -
                                           2022               2021             March 31, 2021         December 31, 2021         March 31, 2021
                                             (dollars in millions, except per unit data)
Production:
Crude oil (MBbls)                          5,853               6,325                   4,857                      (7) %                    21  %
Natural gas (MMcf)                        43,119              47,033                  40,152                      (8) %                     7  %
NGLs (MBbls)                               4,885               5,241                   4,192                      (7) %                    17  %
Crude oil equivalent (MBoe)               17,924              19,405                  15,740                      (8) %                    14  %
Average Boe per day (Boe)                199,156             210,924                 174,889                      (6) %                    14  %

Crude Oil, Natural Gas and NGLs Sales:
Crude oil                              $   549.7          $    483.9          $        273.7                      14  %                   101  %
Natural gas                                163.1               192.7                   105.6                     (15) %                    54  %
NGLs                                       169.6               171.6                    88.8                      (1) %                    91  %
Total crude oil, natural gas and NGLs
sales                                  $   882.4          $    848.2          $        468.1                       4  %                    89  %

Net Settlements on Commodity
Derivatives                                                                                   `
Crude oil                              $  (131.1)         $   (122.7)         $        (20.5)                      7  %                        *
Natural gas                                (30.5)              (72.1)                  (10.2)                    (58) %                   199  %

Total net settlements on derivatives $ (161.6) $ (194.8)

   $        (30.7)                    (17) %                        *

Average Sales Price (excluding net
settlements on derivatives):
Crude oil (per Bbl)                    $   93.93          $    76.50          $        56.34                      23  %                    67  %
Natural gas (per Mcf)                       3.78                4.10                    2.63                      (8) %                    44  %
NGLs (per Bbl)                             34.70               32.74                   21.19                       6  %                    64  %
Crude oil equivalent (per Boe)             49.23               43.71                   29.74                      13  %                    66  %

Average Costs and Expenses (per Boe):
Lease operating expense                $    3.02          $     2.62          $         2.66                      15  %                    14  %
Production taxes                            3.51                3.30                    1.87                       6  %                    88  %
Transportation, gathering and
processing expense                          1.56                1.34                    1.38                      16  %                    13  %
General and administrative expense          1.90                1.62                    2.08                      17  %                    (9) %
Depreciation, depletion and
amortization                                8.43                8.07                    9.32                       4  %                   (10) %


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                                PDC ENERGY, INC.

                                                          Three Months Ended                                        Percent Change Between
                                                             December 31,                                 March 31, 2022 -         March 31, 2022 -
                                      March 31, 2022             2021              March 31, 2021         December 31, 2021         March 31, 2021
                                              (dollars in millions, except per unit data)
Lease Operating Expense by
Operating Region (per Boe)
Wattenberg Field                    $          2.42          $     2.17          $          2.31                      12  %                     5  %
Delaware Basin                                 6.67                5.42                     5.27                      23  %                    27  %


____________

* Percent change is not meaningful.

Crude Oil, Natural Gas and NGLs Sales

The change in crude oil, natural gas and NGLs sales for the three months ended March 31, 2022 compared to the three months ended December 31, 2021 and March 31, 2021 were due to the following:



                                                                       Change Between
                                                        March 31, 2022 -            March 31, 2022 -
                                                        December 31, 2021            March 31, 2021
                                                                        (in millions)
Change in:
Production                                            $            (63.9)         $             78.6

Average crude oil price                                            102.0                       220.0
Average natural gas price                                          (13.5)                       49.7
Average NGLs price                                                   9.6                        66.0
Total change in crude oil, natural gas and NGLs sales
revenue                                               $             34.2          $            414.3


Crude Oil, Natural Gas and NGLs Production



The following table presents crude oil, natural gas and NGLs production for the
periods presented:

                                                                      Three Months Ended                                              Percent Change Between
                                                                                                                            March 31, 2022 -         March 31, 2022 -
Production by Operating Region             March 31, 2022               December 31, 2021           March 31, 2021          December 31, 2021         March 31, 2021
Crude oil (MBbls)
Wattenberg Field                                4,832                         5,306                      4,173                          (9) %                    16  %
Delaware Basin                                  1,021                         1,019                        684                           -  %                    49  %
Total                                           5,853                         6,325                      4,857                          (7) %                    21  %
 Natural gas (MMcf)
Wattenberg Field                               37,663                        40,870                     35,561                          (8) %                     6  %
Delaware Basin                                  5,456                         6,163                      4,591                         (11) %                    19  %
Total                                          43,119                        47,033                     40,152                          (8) %                     7  %
NGLs (MBbls)
Wattenberg Field                                4,291                         4,615                      3,800                          (7) %                    13  %
Delaware Basin                                    594                           626                        392                          (5) %                    52  %
Total                                           4,885                         5,241                      4,192                          (7) %                    17  %
Crude oil equivalent (MBoe)
Wattenberg Field                               15,400                        16,732                     13,900                          (8) %                    11  %
Delaware Basin                                  2,524                         2,673                      1,840                          (6) %                    37  %
Total                                          17,924                        19,405                     15,740                          (8) %                    14  %


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                                PDC ENERGY, INC.
                                                                      Three Months Ended                                              Percent Change Between
                                                                                                                            March 31, 2022 -         March 31, 2022 -
Production by Operating Region             March 31, 2022               December 31, 2021           March 31, 2021          December 31, 2021         March 31, 2021
Average crude oil equivalent per
day (Boe)
Wattenberg Field                              171,111                       181,870                    154,444                          (6) %                    11  %
Delaware Basin                                 28,045                        29,054                     20,445                          (3) %                    37  %
Total                                         199,156                       210,924                    174,889                          (6) %                    14  %



Net production volumes for oil, natural gas and NGLs decreased 8 percent during
the three months ended March 31, 2022 compared to the three months ended
December 31, 2021 primarily due to the timing of wells turned-in-line in both
basins and two fewer days in the first quarter of 2022 as well as normal decline
in production from our existing wells.

Net production volumes for oil, natural gas and NGLs increased 14 percent during
the three months ended March 31, 2022 compared to the same period in 2021. The
increase in production volume between periods was primarily due to a greater
number of wells turned-in-line since the first quarter of 2021 and a loss in
production from temporary shut-ins of a significant portion of our wells driven
by severe weather during the first quarter of 2021.

The following table presents our crude oil, natural gas and NGLs production ratio by operating region for the periods presented:


                                          Three Months Ended March 31, 2022
                         Crude Oil            Natural Gas              NGLs           Total
Wattenberg Field            31%                   41%                  28%             100%
Delaware Basin              40%                   36%                  24%             100%

                                        Three Months Ended December 31, 2021
                         Crude Oil            Natural Gas              NGLs           Total
Wattenberg Field            32%                   41%                  27%             100%
Delaware Basin              38%                   38%                  24%             100%

                                          Three Months Ended March 31, 2021
                         Crude Oil            Natural Gas              NGLs           Total
Wattenberg Field            30%                   43%                  27%             100%
Delaware Basin              37%                   42%                  21%             100%


Our production mix in both operating regions remained relatively consistent between all periods.

Midstream Capacity



Our ability to market our production depends substantially on the availability,
proximity and capacity of in-field gathering systems, compression, and
processing facilities, as well as transportation pipelines out of the basin, all
of which are owned and operated by third parties. If adequate midstream
facilities and services are not available on a timely basis and at acceptable
costs, our production and results of operations could be adversely affected.

The ultimate timing and availability of adequate infrastructure remains out of
our control. Weather, regulatory developments and other factors also affect the
adequacy of midstream infrastructure. Like other producers, from time to time,
we enter into volume commitments with midstream providers in order to
incentivize them to provide increased capacity to sufficiently meet our
projected volume growth from our areas of operation. If our production falls
below the level required under these agreements, we could be subject to
transportation charges or aid in construction payments for commitment
shortfalls.

Our production from the Wattenberg Field and Delaware Basin was not materially
affected by midstream or downstream capacity constraints during the three months
ended March 31, 2022. We continuously monitor infrastructure capacities versus
producer activity and production volume forecasts. Continued increases in crude
oil and natural gas prices
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                                PDC ENERGY, INC.
through early 2022 have incentivized producers in the Permian Basin to increase
the level of drilling and completion activities. The potential increase in
production levels may lead to natural gas transportation constraints out of the
Permian Basin by the end of 2022 through 2023, which may result to lower
realized WAHA natural gas prices. However, a majority of PDC's gas production in
the Delaware Basin is dedicated to Permian Highway Pipeline and is exposed to
Houston-based gas pricing.

Crude Oil, Natural Gas and NGLs Pricing

Our results of operations depend upon many factors. Key factors include market prices of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices have a high degree of volatility and our realizations can change substantially.

The following table presents weighted average sales prices of crude oil, natural gas and NGLs for the periods presented:



                                                                Three Months Ended                                       Percent Change Between
Weighted Average Realized Sales
Price by Operating Region
(excluding net settlements on                                      December 31,                                March 31, 2022 -         March 31, 2022 -
derivatives)                                March 31, 2022             2021             March 31, 2021         December 31, 2021         March 31, 2021
Crude oil (per Bbl)
Wattenberg Field                           $        93.52          $    76.59          $        56.54                      22  %                    65  %
Delaware Basin                                      95.86               76.05                   55.13                      26  %                    74  %
Weighted-average price                              93.93               76.50                   56.34                      23  %                    67  %
Natural gas (per Mcf)
Wattenberg Field                           $         3.82          $     4.18          $         2.73                      (9) %                    40  %
Delaware Basin                                       3.56                3.53                    1.88                       1  %                    89  %
Weighted-average price                               3.78                4.10                    2.63                      (8) %                    44  %
NGLs (per Bbl)
Wattenberg Field                           $        32.37          $    31.52          $        20.47                       3  %                    58  %
Delaware Basin                                      51.54               41.74                   28.23                      23  %                    83  %
Weighted-average price                              34.70               32.74                   21.19                       6  %                    64  %
Crude oil equivalent (per Boe)
Wattenberg Field                           $        47.69          $    43.19          $        29.55                      10  %                    61  %
Delaware Basin                                      58.59               46.93                   31.17                      25  %                    88  %
Weighted-average price                              49.23               43.71                   29.74                      13  %                    66  %



Crude oil, natural gas and NGLs revenues are recognized when we transfer control
of crude oil, natural gas or NGLs production to the purchaser. We consider the
transfer of control to occur when the purchaser has the ability to direct the
use of, and obtain substantially all of the remaining benefits from the crude
oil, natural gas or NGLs production.

Our crude oil, natural gas and NGLs sales are recorded using either the
"net-back" or "gross" method of accounting, depending upon the related purchase
agreement. We use the net-back method when control of the crude oil, natural gas
or NGLs has been transferred to the purchasers of these commodities that are
providing transportation, gathering or processing services. In these situations,
the purchaser pays us based on a percent of proceeds or a sales price fixed at
index less specified deductions. The net-back method results in the recognition
of a net sales price that is lower than the index on which the production is
based because the operating costs and profit of the midstream facilities are
embedded in the net price we are paid. We use the gross method of accounting
when control of the crude oil, natural gas or NGLs is not transferred to the
purchaser and the purchaser does not provide transportation, gathering or
processing services as a function of the price we receive. Rather, we contract
separately with midstream providers for the applicable transportation and
processing on a per unit basis. Under this method, we recognize revenues based
on the gross selling price and recognize transportation, gathering and
processing ("TGP") expense.

Information related to the components and classifications of TGP expense on the
condensed consolidated statements of operations is shown below. For crude oil,
the average NYMEX prices shown below are based on average daily prices
throughout each month and, for natural gas, the average NYMEX pricing is based
on first-of-the-month index prices, as in each case this is the method used to
sell the majority of these commodities pursuant to terms of the relevant sales
agreements. For
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                                PDC ENERGY, INC.
NGLs, we use the NYMEX crude oil price as a reference for presentation purposes.
The average realized price both before and after TGP expense shown in the table
below represents our approximate composite per barrel price for NGLs for the
periods presented.

                                               Average Realized       Average Realization                             Average Realized       Average Realization
Three Months Ended            Average          Price Before TGP        Percentage Before          Average TGP         Price After TGP        Percentage After TGP
March 31, 2022              NYMEX Price            Expense                TGP Expense             Expense (1)             Expense                  Expense
Crude oil (per Bbl)         $   94.29          $       93.93                        100  %       $      2.69          $       91.24                         97  %
Natural gas (per
MMBtu)                           4.95                   3.78                         76  %              0.23                   3.55                         72  %
NGLs (per Bbl)                  94.29                  34.70                         37  %                 -                  34.70                         37  %
Crude oil equivalent
(per Boe)                       68.40                  49.23                         72  %              1.42                  47.81                         70  %

                                               Average Realized       Average Realization                             Average Realized       Average Realization
Three Months Ended            Average          Price Before TGP        Percentage Before          Average TGP         Price After TGP        Percentage After TGP
December 31, 2021           NYMEX Price            Expense                TGP Expense             Expense (1)             Expense                  Expense
Crude oil (per Bbl)         $   77.19          $       76.50                         99  %       $      2.72          $       73.78                         96  %
Natural gas (per
MMBtu)                           5.50                   4.10                         75  %              0.13                   3.97                         72  %
NGLs (per Bbl)                  77.19                  32.74                         42  %                 -                  32.74                         42  %
Crude oil equivalent
(per Boe)                       59.33                  43.71                         74  %              1.19                  42.52                         72  %

                                               Average Realized       Average Realization                             Average Realized       Average Realization
Three Months Ended            Average          Price Before TGP        Percentage Before          Average TGP         Price After TGP        Percentage After TGP
March 31, 2021              NYMEX Price            Expense                TGP Expense             Expense (1)             Expense                  Expense
Crude oil (per Bbl)         $   57.84          $       56.34                         97  %       $      3.32          $       53.02                         92  %
Natural gas (per
MMBtu)                           2.69                   2.63                         98  %              0.11                   2.52                         94  %
NGLs (per Bbl)                  57.84                  21.19                         37  %                 -                  21.19                         37  %
Crude oil equivalent
(per Boe)                       40.12                  29.74                         74  %              1.32                  28.42                         71  %


____________
(1)Average TGP expense excludes unutilized firm transportation fees of $0.14 per
Boe, $0.15 per Boe, and $0.06 per BOE for the three months ended March 31, 2022,
December 31, 2021, and March 31, 2021, respectively.

Our average realization percentages for crude oil, natural gas and NGLs were
relatively flat for the three months ended March 31, 2022 as compared to the
three months ended December 31, 2021.

Our average realization percentage for crude oil increased for the three months
ended March 31, 2022 as compared to the same period in 2021 primarily due to an
increased demand for crude oil due to the containment of COVID-19. In addition,
we realized improved differentials from our 2022 crude oil sales contracts.
Average realization percentage for natural gas decreased for the three months
ended March 31, 2022 compared to the three months ended March 31, 2021 due to
strong pricing in February 2021 as a result of severe weather conditions.

Commodity Price Risk Management



We use commodity derivative instruments to manage fluctuations in crude oil and
natural gas prices, including collars, fixed-price exchanges, and basis
protection exchanges on a portion of our estimated crude oil and natural gas
production. For our commodity exchanges, we ultimately realize the fixed price
value related to the swaps. See Note 5 - Commodity Derivative Financial
Instruments in Item 1. Financial Statements included elsewhere in this report
for a summary of our derivative positions as of March 31, 2022.

Commodity price risk management, net, includes cash settlements upon maturity of
our derivative instruments, and the change in fair value of unsettled commodity
derivatives related to our crude oil and natural gas production.
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                                PDC ENERGY, INC.

Net settlements of commodity derivative instruments are based on the difference
between the crude oil and natural gas index prices at the settlement date of our
commodity derivative instruments compared to the respective strike prices
contracted for the settlement months that were established at the time we
entered into the commodity derivative transaction. The net change in fair value
of unsettled commodity derivatives is comprised of the net increase or decrease
in the beginning-of-period fair value of commodity derivative instruments that
settled during the period and the net change in fair value of unsettled
commodity derivatives during the period or from inception of any new contracts
entered into during the applicable period. The net change in fair value of
unsettled commodity derivatives during the period is primarily related to shifts
in the crude oil and natural gas forward price curves and changes in certain
differentials.

The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net:



                                                                            Three Months Ended
                                                    March 31, 2022           December 31, 2021           March 31, 2021
                                                                               (in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative
instruments:
Crude oil collars and fixed price exchanges       $        (131.1)         $           (122.7)         $         (20.5)
Natural gas collars and fixed price exchanges               (28.1)                      (80.0)                    (2.8)
Natural gas basis protection exchanges                       (2.3)                        7.9                     (7.4)
Total net settlements of commodity derivative
instruments                                                (161.5)                     (194.8)                   (30.7)
Change in fair value of unsettled commodity
derivative instruments:
Reclassification of settlements included in prior
period changes in fair value of commodity
derivative instruments                                      100.2                       198.5                     (0.7)
Crude oil collars and fixed price exchanges                (373.6)                      (38.9)                  (137.8)
Natural gas collars and fixed price exchanges              (140.6)                       46.7                     (2.1)
Natural gas basis protection exchanges                        7.4                        (5.8)                   (10.0)
Net change in fair value of unsettled commodity
derivative instruments                                     (406.6)                      200.5                   (150.6)
Total commodity price risk management gain
(loss), net                                       $        (568.1)         $              5.7          $        (181.3)

The continued increase in commodity prices during the three months ended March 31, 2022, December 31, 2021 and March 31, 2021 had an overall unfavorable impact on the fair value and settlements of our commodity derivatives.

Lease Operating Expense



Lease operating expense ("LOE") increased by 7 percent to $54.2 million for the
three months ended March 31, 2022 compared to $50.8 million for the three months
ended December 31, 2021. The period-over-period increase in LOE was primarily
attributable to a $1.7 million increase in workover expense due to the timing of
workover activities in the Delaware Basin and $1.5 million in additional
chemical treatments and power costs in both basins. LOE per Boe increased 15
percent to $3.02 for the three months ended March 31, 2022 from $2.62 for the
three months ended December 31, 2021. The increase is primarily driven by the
cost increases outlined above as well as a decrease in production of 8 percent
period-over-period.

LOE increased by 30 percent to $54.2 million for the three months ended
March 31, 2022 compared to $41.8 million for the three months ended March 31,
2021. The period-over-period increase in LOE was primarily due to (i) increased
activities and payroll costs of $4.8 million at our operated and non-operated
well locations resulting from an increase in completion activities in both
basins, (ii) a $3.2 million increase in chemical treatments, environmental and
regulatory costs and (iii) a $2.4 million increase in workover expense due to
the timing of workover activities focused in the Delaware Basin. LOE per Boe
increased 14 percent to $3.02 for the three months ended March 31, 2022 from
$2.66 for the three months ended March 31, 2021.

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                                PDC ENERGY, INC.

Production Taxes



Production taxes are comprised mainly of severance tax and ad valorem tax, and
are directly related to crude oil, natural gas and NGLs sales and are generally
assessed as a percentage of net revenues. From time to time, there are
adjustments to the statutory rates for these taxes based upon certain credits
that are determined based upon activity levels and relative commodity prices
from year-to-year.

Production taxes decreased 2 percent to $62.9 million for the three months ended
March 31, 2022 compared to $64.1 million for the three months ended December 31,
2021. Production taxes per Boe increased 6 percent to $3.51 for the three months
ended March 31, 2022 compared to $3.30 for the three months ended December 31,
2021. The increase in production taxes per Boe was primarily due to an increase
in crude oil and NGLs prices between periods.

Production taxes increased 113 percent to $62.9 million for the three months
ended March 31, 2022 compared to $29.5 million for the three months ended
March 31, 2021. Production taxes per Boe increased 88 percent to $3.51 for the
three months ended March 31, 2022 compared to $1.87 for the three months ended
March 31, 2021. The increase in production taxes was primarily due to an
increase in crude oil, natural gas and NGLs prices between periods.

Transportation, Gathering and Processing Expense



TGP expense increased 8 percent to $28.0 million for the three months ended
March 31, 2022 compared to $26.0 million for the three months ended December 31,
2021. TGP expense per Boe increased 16 percent to $1.56 for the three months
ended March 31, 2022 compared to $1.34 for the three months ended December 31,
2021. The increase in TGP expense was primarily due to an increase in gas
processing costs in the Delaware Basin between periods.

TGP expense increased 29 percent to $28.0 million for the three months ended
March 31, 2022 compared to $21.7 million for the three months ended March 31,
2021. TGP expense per Boe increased 13 percent to $1.56 for the three months
ended March 31, 2022 compared to $1.38 for the three months ended March 31,
2021. The overall increase in TGP expense for the three months ended March 31,
2022 compared to the same period in 2021 was driven by a $5.6 million increase
relating to gas processing costs and a $1.8 million increase in shortfall fees
relating to our delivery commitment, both in the Delaware Basin.

Impairment of Properties and Equipment



There were no significant impairment charges recognized related to our proved
and unproved oil and gas properties during the three months ended March 31,
2022, December 31, 2021, and March 31, 2021. If crude oil prices decline, or we
change other estimates impacting future net cash flows (e.g. reserves, price
differentials, future operating and/or development costs), our proved and
unproved oil and gas properties could be subject to additional impairments in
future periods.

General and Administrative Expense



General and administrative expense slightly increased 9 percent to $34.1 million
for the three months ended March 31, 2022 compared to $31.4 million for the
three months ended December 31, 2021, primarily due to an increase in charitable
contributions and an increase in professional fees relating to the Great Western
Acquisition in the first quarter of 2022.

General and administrative expense remained relatively flat with an increase of
4 percent to $34.1 million for the three months ended March 31, 2022 compared to
$32.7 million for the three months ended March 31, 2021.

Depreciation, Depletion and Amortization Expense



DD&A expense related to crude oil and natural gas properties is directly related
to proved reserves and production volumes. DD&A expense related to crude oil and
natural gas properties was $149.3 million for the three months ended March 31,
2022 compared to $154.7 million for the three months ended December 31, 2021.
The decrease in DD&A expense was primarily due to an 8 percent decrease in
production volumes between periods partially offset by an increase in the
weighted average DD&A expense rate as a result of capitalized costs of wells
turned-in-line in the first quarter of 2022.

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                                PDC ENERGY, INC.
DD&A expense related to crude oil and natural gas properties was $149.3 million
for the three months ended March 31, 2022 compared to $144.8 million for the
comparable period in 2021. The increase in total DD&A expense was primarily due
to a 14 percent increase in production volumes between periods primarily due to
a greater number of wells turned-in-line since the second quarter of 2021
partially offset by a decrease in the weighted average DD&A expense rate.

The period-over-period change in DD&A expense related to crude oil and natural gas properties was primarily due to the following:

Change Between


                                                                 March 31, 2022 -             March 31, 2022 -
                                                                 December 31, 2021             March 31, 2021
                                                                                 (in millions)
Increase (decrease) in production                              $            (11.7)         $              20.0

Increase (decrease) in weighted-average depreciation, depletion and amortization rates

                                              6.3                        (15.5)

Total increase (decrease) in DD&A expense related to crude oil and natural gas properties

                           $             (5.4)         $               4.5



The following table presents our per Boe DD&A expense rates for crude oil and natural gas properties for the periods presented:



                                                                       Three Months Ended
                                                       March 31, 2022            December 31, 2021                 March 31, 2021
                                                                            (per Boe)
Operating Region/Area
Wattenberg Field                                    $       8.00               $             7.70                $          9.22
Delaware Basin                                             10.33                             9.71                           9.01
Total weighted average DD&A expense
rate                                                        8.33                             7.97                           9.20


Interest Expense, net

Interest expense, net decreased $10.6 million to $12.9 million for the three
months ended March 31, 2022 compared to $23.5 million for the three months ended
December 31, 2021. The decrease was primarily related to (i) reduced borrowings
under our revolving credit facility between periods, (ii) a full redemption of
our 2025 Senior Notes and a partial redemption of our 2024 Senior Notes in
December and November 2021, respectively, and (iii) a $6.9 million loss on
extinguishment recognized in the fourth quarter of 2021 as a result of
aforementioned redemptions of our Senior Notes.

Interest expense, net decreased $6.1 million to $12.9 million for the three
months ended March 31, 2022 compared to $19.0 million for the three months ended
March 31, 2021. The decrease was primarily related to (i) reduced borrowings
under our revolving credit facility between periods, (ii) expiration and
redemption of our 2021 Convertible Notes in September 2021, and (iii) a full
redemption of our 2025 Senior Notes and a partial redemption of our 2024 Senior
Notes in December and November 2021, respectively.

Provision for Income Taxes



We recorded income tax expense of $1.2 million, $26.5 million and $0.1 million
for the three months ended March 31, 2022, December 31, 2021, and March 31,
2021, resulting in an effective income tax rate of 3.9 percent provision on
pre-tax losses, 5.3 percent provision on pre-tax income and 0.6 percent
provision on pre-tax losses, respectively. The effective tax rates differ from
the amount that would be provided by applying the statutory U.S. federal income
tax rate of 21 percent to pre-tax loss due to the effect of a valuation
allowance against our deferred income tax assets.

The ultimate realization of deferred tax assets ("DTAs") is dependent upon the
generation of future taxable income during the periods in which those temporary
differences become deductible. At each reporting period, management considers
the scheduled reversal of deferred tax liabilities, available taxes in carryback
periods, tax planning strategies and projected future taxable income in making
this assessment. Our oil and gas property impairments and cumulative pre-tax
losses were key considerations that led us to continue to provide a valuation
allowance against our DTAs as of December 31, 2021 and March 31, 2022 since we
cannot conclude that it is more likely than not that our DTAs will be fully
realized in future periods.
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                                PDC ENERGY, INC.

Future events or new evidence which may lead us to conclude that it is more
likely than not that our DTAs will be realized include, but are not limited to,
cumulative historical pre-tax earnings, sustained or continued improvements in
oil prices, and taxable events that could result from one or more transactions.
Given recent improvements in oil and gas prices and improvements in our current
earnings, we believe there is a reasonable possibility that, if oil and natural
gas prices remain similar to March 31, 2022 pricing levels, sufficient positive
evidence may become available within the next 12 months to allow us to reach a
conclusion that all or a significant portion of the valuation allowance will no
longer be needed. Release of the valuation allowance would result in the
recognition of certain deferred tax assets and a decrease to income tax expense
in the period the release is recorded. However, the exact timing and amount of
the valuation allowance release are subject to change based on the level of
profitability that we actually achieve.

Given recent improvements in oil and gas prices and assumptions based on our
current production forecasts, we
estimate that we will begin to incur cash federal and state income taxes again
later in 2022 and 2023.

Net Income (Loss)/Adjusted Net Income (Loss)



The factors impacting a net loss of $32.0 million, net income of $473.1 million,
and net loss of $9.0 million for the three months ended March 31, 2022, December
31, 2021, and March 31, 2021, respectively, are discussed above.

Adjusted net income, a non-U.S. GAAP financial measure, was $358.6 million,
$283.1 million, and $141.6 million for the three months ended March 31, 2022,
December 31, 2021, and March 31, 2021, respectively. With the exception of the
tax-affected net change in fair value of unsettled commodity derivatives, when
applicable, the same factors impacted adjusted net income (loss). See
Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed
discussion of these non-U.S. GAAP financial measures and a reconciliation of
these measures to the most comparable U.S. GAAP measures.

Financial Condition, Liquidity and Capital Resources

Overview



Our primary sources of liquidity are cash and cash equivalents, cash flows from
operating activities, unused borrowing capacity from our revolving credit
facility, proceeds raised in debt and equity capital market transactions, and
other sources, such as asset sales.

Our primary source of cash flows from operating activities is the sale of crude
oil, natural gas and NGLs. Fluctuations in our operating cash flows are
principally driven by commodity prices and changes in our production volumes.
Commodity prices have historically been volatile and we manage a portion of this
volatility through our use of commodity derivative instruments. We enter into
commodity derivative instruments with maturities of no greater than five years
from the date of the instrument. Our revolving credit facility imposes limits on
the amount of our production we can hedge, and we may choose not to hedge the
maximum amounts permitted. Therefore, we may still have fluctuations in our cash
flows from operating activities due to the remaining non-hedged portion of our
future production.

We may use our available liquidity for operating activities, capital
investments, working capital requirements, acquisitions, capital returns and for
general corporate purposes. We maintain a significant capital investment program
to execute our development plans, which requires capital expenditures to be made
in periods prior to initial production from newly developed wells. From time to
time, these activities may result in a working capital deficit; however, we do
not believe that our working capital deficit as of March 31, 2022 is an
indication of a lack of liquidity. We had working capital deficits of $541.7
million as of March 31, 2022 and $461.5 million as of December 31, 2021. The
increase in working capital deficit since December 31, 2021 was primarily due to
an increase in the fair value of net derivative liabilities of $272.5 million
and an increase in accounts payable of $64.4 million partially offset by an
increase in receivables of $138.5 million and an increase in cash and cash
equivalents of $137.3 million. We intend to continue to manage our liquidity
position by a variety of means, including through the generation of cash flows
from operations, investment in projects with favorable rates of return,
protection of cash flows on a portion of our anticipated sales through the use
of an active commodity derivative hedging program, utilization of the borrowing
capacity under our revolving credit facility and, if warranted, capital markets
transactions from time to time.

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                                PDC ENERGY, INC.
From time to time, we may seek to pay down, retire or repurchase our outstanding
debt using cash or through exchanges of other debt or equity securities, in open
market purchases, privately negotiated transactions or otherwise.

Liquidity


Our cash and cash equivalents were $171.2 million at March 31, 2022 and
availability under our revolving credit facility was $1.5 billion, providing for
a total liquidity position of $1.65 billion as of March 31, 2022. The borrowing
base is primarily based on the loan value assigned to the proved reserves
attributable to our crude oil and natural gas interests.

Our material short-term and long-term cash requirements consist primarily of
capital expenditures, payments of contractual obligations, dividends, share
repurchases and working capital obligations. As commodity prices continue to
increase, our working capital requirements may increase due to higher operating
costs and negative settlements on our outstanding commodity derivative
contracts. Funding for these requirements may be provided by any combination of
our capital resources previously outlined.

On February 26, 2022, we entered into the Acquisition Agreement to acquire Great
Western for approximately $1.4 billion, inclusive of Great Western's net debt.
Under the terms of the Acquisition Agreement, the purchase consideration for the
Great Western Acquisition will be made through the transfer of approximately 4.0
million shares of our common stock and approximately $543 million in cash. The
cash portion of the purchase price is expected to be funded through a
combination of cash on hand and availability under our revolving credit
facility. We anticipate that the Great Western Acquisition will be completed in
May 2022, subject to certain customary closing conditions being met.

Upon closing the Great Western Acquisition, we will be required to pay off and
terminate Great Western's revolving credit facility, which had an outstanding
balance of approximately $227.0 million as of March 31, 2022. At closing, we are
also expecting to pay off Great Western's $311.9 million of 12.0% Senior Notes
due September 1, 2025, plus a redemption premium. The payments of the debt
balances is expected to be funded through the availability under our revolving
credit facility.

Based on our current production forecast for 2022, we expect 2022 cash flows
from operations, which are net of expected cash federal and state income taxes,
to exceed our capital investments in crude oil and natural gas properties. In
addition, based on our expected cash flows from operations, our cash and cash
equivalents and availability under our revolving credit facility, we believe
that we will have sufficient capital available to fund our planned activities
through the 12-month period following the filing of this report. We also believe
that we will have sufficient expected cash flows from operations to allow us to
execute our capital return plan. Future repurchases of common stock or dividend
payments will be subject to approval by our board of directors and will depend
on our level of earnings, financial requirements, and other factors considered
relevant by our board.

Our material cash requirements greater than twelve months from various
contractual and other obligations include debt obligations and interest
payments; commodity derivative contract liabilities; production taxes; operating
and finance leases; asset retirement obligations; and firm transportation and
processing agreements. There are no significant changes to our material cash
requirements arising from contractual obligations since December 31, 2021.

The revolving credit facility contains covenants customary for agreements of
this type, with the most restrictive being certain financial tests on a
quarterly basis. The financial tests, as defined per the revolving credit
facility, include requirements (a) to maintain a minimum current ratio of
1.0:1.0 and (b) not exceed a maximum leverage ratio of 3.5:1.0. For purposes of
the current ratio covenant, the revolving credit facility's definition of total
current assets, in addition to current assets as presented under U.S. GAAP,
includes, among other things, unused commitments under the revolving credit
facility. Additionally, the current ratio covenant calculation allows us to
exclude the current portion of our long-term debt and other short-term loans
from the U.S. GAAP total current liabilities amount. Accordingly, the existence
of a working capital deficit under U.S. GAAP is not necessarily indicative of a
violation of the current ratio covenant. At March 31, 2022, we were in
compliance with all covenants in the revolving credit facility with a current
ratio of 3.1:1.0 and a leverage ratio of 0.4:1.0.
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                                PDC ENERGY, INC.

In April 2022, as part of our credit facility 2022 semi-annual redetermination, our borrowing base increased from $2.4 billion to $3.0 billion; however, we maintained our elected commitment amount of $1.5 billion.



We expect to remain in compliance with the covenants under our credit facility
and our Senior Notes throughout the 12-month period following the filing of this
report.

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