PDC ENERGY, INC. 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
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. In 2022 and the first quarter of 2023, crude oil and natural gas prices continued to be volatile. NYMEX WTI spot prices for crude oil reached a high of$130.50 per barrel inMarch 2022 and a low of$64.12 per barrel inMarch 2023 . In addition, NYMEXHenry Hub spot prices for natural gas reached a high of$9.85 per MMBtu inAugust 2022 and a low of$1.93 per MMBtu inMarch 2023 .
Crude Oil Markets
During the first quarter of 2023, crude oil pricing has decreased due to the net impact of higher supply and accumulation of global oil inventories, recession concerns, instability in the banking industry, uncertainties relating to the Russian invasion ofUkraine and changes in production by non-OPEC countries. InApril 2023 , OPEC+ announced a production cut which resulted to an increase in crude oil prices. Inflation rates in the first quarter of 2023 have started to soften, however, theU.S. Federal Reserve may continue to increase the benchmark federal funds interest rate in an effort to combat inflation. The magnitude and overall effectiveness of these actions remains uncertain. Overall, monetary policy changes can increase the risk of economic slowdown and/or lead to a recession. A slowdown or recession can cause a decrease in short-term or long-term demand for commodities, resulting in industry oversupply and a potential for lower commodity prices, which could impact our drilling program and further increase the volatility of our common stock price.
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 and liquified petroleum gas exports and deviations from seasonally normal weather.Europe's shift away fromRussia's natural gas has led toEurope becoming increasingly dependent onU.S. LNG exports, creating new sources of demand forU.S. natural gas. During the first quarter of 2023, natural gas and NGLs prices declined compared to prices during 2022 due to high inventories as a result of a warm winter and lower heating demand and continued growth in natural gas production across theU.S. Financial Matters
Three months ended
•Production volumes decreased to 22.0 MMboe in the first quarter of 2023, a decrease of 3 percent compared to 22.7 MMboe in the fourth quarter of 2022, primarily driven by two fewer days in the first quarter of 2023 and the timing of our turn-in-line activities in both basins. •Crude oil, natural gas and NGLs sales decreased to$813 million compared to$976 million in the fourth quarter of 2022 primarily due to a 14 percent decrease in weighted average realized commodity prices and a 3 percent decrease in production volumes between periods. •Negative net cash settlements from our commodity derivative contracts decreased to$86 million in the first quarter of 2023 compared to$167 million in the fourth quarter of 2022 due to a decrease in commodity prices compared to our commodity derivative contract prices between periods. 20 --------------------------------------------------------------------------------
•Combined revenues from crude oil, natural gas and NGLs sales and net
settlements from our commodity derivative instruments decreased 10 percent to
•Net income increased to$414 million , or$4.64 per diluted share, for the first quarter of 2023 compared to$350 million , or$3.79 per diluted share, in the fourth quarter of 2022 primarily due to a$144 million commodity risk management gain in the first quarter of 2023 compared to a$100 million commodity risk management loss in the fourth quarter of 2022, partially offset by a decrease in crude oil, natural gas and NGLs sales of$163 million and increase in income tax expense of$17 million . •Cash flows from operations decreased to$588 million compared to$688 million in the fourth quarter of 2022 primarily due to lower sales partially offset by lower net derivative cash settlement losses. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, decreased to$518 million compared to$604 million in the fourth quarter of 2022. Adjusted free cash flows, a non-U.S. GAAP financial measure, decreased to$101 million from$258 million in the fourth quarter of 2022 due to a decrease in adjusted cash flows from operations and an increase in capital expenditures between periods. 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 comparableU.S. GAAP measures.
Drilling and Completion Overview
During the first quarter of 2023, we operated three full-time drilling rigs and two full-time completion crews in the Wattenberg Field and one full-time drilling rig and completion crew in theDelaware Basin . Our total capital investments in crude oil and natural gas properties and midstream assets for the first quarter of 2023 were$417 million .
The following table summarize our drilling and completion activities for the
three months ended
Operated Wells
Wattenberg Field Delaware Basin Total
Gross Net Gross Net Gross Net
In-process as of December 31,
2022 200 185 12 12 212 197
Wells spud 64 60 9 9 73 69
Wells turned-in-line (55) (49) (6) (6) (61) (55)
In-process as of March 31, 2023 209 196 15 15 224 211
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.
Capital Returns
Stock Repurchase Program. InFebruary 2023 , our board of directors approved a$750 million increase in the size of our stock repurchase program resulting in an aggregate authorization of$2 billion , which we currently anticipate fully utilizing byDecember 31, 2025 . We repurchased 2.1 million shares of outstanding common stock at a cost of$134 million during the three months endedMarch 31, 2023 . EffectiveJanuary 1, 2023 , the cost of stock repurchases includes related excise taxes pursuant to the terms of the IRA. As ofMarch 31, 2023 ,$1.1 billion remained available for repurchases under the program.
Dividends. In
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PDC ENERGY, INC. 2023 Operational and Financial Outlook
We anticipate that our full-year 2023 production will range between 255,000 Boe and 265,000 Boe per day, of which approximately 82,000 Bbls to 86,000 Bbls is expected to be crude oil. Our planned 2023 capital investments in crude oil and natural gas properties, which we expect to be between$1,350 million to$1,450 million , are focused on continued execution of our development plans in the Wattenberg Field and theDelaware Basin . Our capital budget and operating costs for 2023 may continue to be impacted by the volatility of commodity prices. Additionally, inflation has declined sinceDecember 2022 , creating a modest decrease in certain capital costs during the first quarter of 2023; we anticipate this trend could continue through the second half of 2023. We continue to move towards electrification in our operations to allow us to forego using internal combustion-power engines, which further helps us reduce our emissions. However, with this continued shift to electrification, we become more reliant on local third party grid power, which can be susceptible to capacity constraints, blackouts and infrastructure delays. These hazards could have an impact on our well development program as well as our daily production on existing wells. 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 2023 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, 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, requirements to maintain continuous activity on leaseholds and acquisition and divestiture opportunities. Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in a mixture of urban, urban interfacing and rural areas of the core Wattenberg Field. Our 2023 capital investment program for the Wattenberg Field represents approximately 80 percent of our expected total capital investments in crude oil and natural gas properties. Our plan includes spudding and turning-in-line 200 to 225 operated wells. To meet our development plan, we intend on running three full-time horizontal drilling rigs and one full-time completion crew plus an intermittent completion crew during the year.Delaware Basin . Total capital investments in crude oil and natural gas properties in theDelaware Basin for 2023 are expected to be approximately 20 percent of our total capital investments. In 2023, we anticipate spudding 15 to 25 operated wells. We are committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2023, we expect 2023 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$0.40 per share. Then we expect to use approximately 60% or more of our remaining adjusted free cash flow, 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, and other general corporate purposes.
Regulatory and Political Updates
InMarch 2023 , theColorado Governor directed theColorado Oil and Gas Conservation Commission ("COGCC") and theColorado Department of Public Health and Environment ("CDPHE") to develop a rule or rules by the end of 2024 requiring the upstream oil and gas sector operating in the ozone nonattainment area to achieve minimum emissions reductions of nitrogen oxides ("NOx"), one of ground level ozone's primary precursors along with volatile organic compounds ("VOCs"), of 30% by 2025 and 50% by 2030; directing COGCC to solidify environmental best management practices addressing ozone; and directing COGCC to establish an environmental best practices program to incentivize operators to engage in greenhouse gas related environmental efforts. Substantially all of our producing properties in the Wattenberg Field are located in the nonattainment area.
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.
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PDC ENERGY, INC. Environmental, Social and Governance
We are committed to meaningful and measurable sustainability progress, focused on being a cleaner, safer and more socially responsible company. Our strategy is integrated into every level of our business and is overseen by ourEnvironmental, Social, Governance and Nominating Committee at the board of directors and our internal Steering Committee, comprised of our senior leaders. A core component of our sustainability initiatives is a dedicated drive to reduce our emissions. We have set aggressive targets to (i) reduce Scope 1 greenhouse gas emissions intensity, as defined by theSustainability Accounting Standards Board , by 60% from 2020 levels by 2025 and 74% by 2030, (ii) reduce methane emissions intensity by 50% from 2020 levels by 2025 and 70% by 2030, and (iii) eliminate routine flaring, as defined byWorld Bank , by 2025. InMarch 2023 , we completed ourEPA annual filing for 2022 emissions and reported a 32% reduction in Scope 1 GHG emissions intensity and a 58% reduction in methane emissions intensity since 2021. Additionally, we eliminated routine flaring. As a result of our strong performance, we have exceeded our 2025 goal for methane emissions intensity and reached our 2025 goal of eliminating routine flaring. Accordingly, we are now reassessing our longer-term goals. Additional information on our ESG practices, including sustainability goals, key metrics and progress achieved, can be found on the Sustainability page of our website at www.pdce.com. The information on our website, including the Sustainability reports, is not incorporated by reference in this report. TheSEC 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. 23 --------------------------------------------------------------------------------
PDC ENERGY, INC.
Results of Operations
Summary of Operating Results
The following table presents selected information regarding our operating
results:
Three Months Ended
March 31, 2023 December 31, 2022 Percent Change
(dollars in millions, except per unit data)
Production:
Crude oil (MBbls) 6,938 7,380 (6) %
Natural gas (MMcf) 52,487 53,479 (2) %
NGLs (MBbls) 6,286 6,430 (2) %
Crude oil equivalent (MBoe) 21,971 22,723 (3) %
Average Boe per day (Boe) 244,122 246,989 (1) %
Crude Oil, Natural Gas and NGLs Sales:
Crude oil $ 514 $ 607 (15) %
Natural gas 161 224 (28) %
NGLs 138 145 (5) %
Total crude oil, natural gas and NGLs sales $ 813 $ 976 (17) %
Net Settlements on Commodity Derivatives
Crude oil $ (35) $ (105) (66) %
Natural gas (51) (62) (18) %
Total net settlements on derivatives $ (86) $ (167) (48) %
Average Sales Price (excluding net settlements on
derivatives):
Crude oil (per Bbl) $ 74.13 $ 82.24 (10) %
Natural gas (per Mcf) 3.07 4.20 (27) %
NGLs (per Bbl) 21.95 22.49 (2) %
Crude oil equivalent (per Boe) 37.02 42.95 (14) %
Average Costs and Expense (per Boe):
Lease operating expense $ 3.33 $ 3.04 10 %
Production taxes 2.54 2.71 (6) %
Transportation, gathering and processing expense 1.48 1.53 (3) %
General and administrative expense 1.89 1.60 18 %
Depreciation, depletion and amortization 9.43 8.89 6 %
Lease Operating Expense by Operating Region (per
Boe)
Wattenberg Field $ 2.83 $ 2.52 12 %
Delaware Basin 7.14 7.03 2 %
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PDC ENERGY, INC. Crude Oil, Natural Gas and NGLs Sales
Crude oil, natural gas and NGLs sales for the three months endedMarch 31, 2023 decreased compared to the three months endedDecember 31, 2022 due to the following factors: December 31, 2022 - March 31, 2023 (in millions) Change in: Production $ (44) Average crude oil price (56) Average natural gas price (59) Average NGLs price (4)
Total change in crude oil, natural gas and NGLs sales revenue $
(163)
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
Production by Operating Region March 31, 2023 December 31, 2022 Percent Change
Crude oil (MBbls)
Wattenberg Field 6,005 6,406 (6) %
Delaware Basin 933 974 (4) %
Total 6,938 7,380 (6) %
Natural gas (MMcf)
Wattenberg Field 46,720 47,502 (2) %
Delaware Basin 5,767 5,977 (4) %
Total 52,487 53,479 (2) %
NGLs (MBbls)
Wattenberg Field 5,628 5,799 (3) %
Delaware Basin 658 631 4 %
Total 6,286 6,430 (2) %
Crude oil equivalent (MBoe)
Wattenberg Field 19,420 20,122 (3) %
Delaware Basin 2,551 2,601 (2) %
Total 21,971 22,723 (3) %
Average crude oil equivalent per day (Boe)
Wattenberg Field 215,778 218,717 (1) %
Delaware Basin 28,344 28,272 - %
Total 244,122 246,989 (1) %
Net production volumes for oil, natural gas and NGLs decreased 3 percent during
the three months ended March 31, 2023 compared to the three months ended
December 31, 2022 , primarily driven by two fewer days in the first quarter of
2023 compared to the fourth quarter of 2022 and timing of our turn-in-line
activities in both basins. Average crude oil equivalent per day was relatively
flat between the three months ended March 31, 2023 and December 31, 2022 .
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PDC ENERGY, INC.The following table presents our crude oil, natural gas and NGLs production ratio by operating region for the periods presented:
Three Months Ended
Production Ratio by Operating Region March 31, 2023 December 31, 2022
Wattenberg Field
Crude oil 31 % 32 %
Natural gas 40 % 39 %
NGLs 29 % 29 %
Total 100 % 100 %
Delaware Basin
Crude oil 36 % 37 %
Natural gas 38 % 39 %
NGLs 26 % 24 %
Total 100 % 100 %
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, preventative routine maintenance
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 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 the Delaware Basin was not
materially affected by midstream or downstream capacity constraints during the
three months ended March 31, 2023 . We continuously monitor infrastructure
capacities versus producer activity and production volume forecasts. Increases
in crude oil and natural gas prices in 2022 have incentivized producers in the
Permian Basin to increase the level of drilling and completion activities.
Despite the recent volatility in commodity prices, the number of drilling rigs
has not materially declined, and the pace of production growth may lead to
natural gas transportation constraints out of the Permian Basin in 2023. This
may result in lower realized Waha natural gas prices, however, approximately
half of our gas production in the Delaware Basin is dedicated to the Permian
Highway Pipeline and is exposed to Houston -based gas pricing. This price
diversification reduces the risk of a decrease in realized natural gas prices
related to transportation constraints.
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PDC ENERGY, INC.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
Weighted Average Realized Sales Price by
Operating Region
(excluding net settlements on derivatives) March 31, 2023 December 31, 2022 Percent Change
Crude oil (per Bbl)
Wattenberg Field $ 74.25 $ 82.10 (10) %
Delaware Basin 73.35 83.15 (12) %
Weighted average price 74.13 82.24 (10) %
Natural gas (per Mcf)
Wattenberg Field $ 3.28 $ 4.46 (26) %
Delaware Basin 1.33 2.07 (36) %
Weighted average price 3.07 4.20 (27) %
NGLs (per Bbl)
Wattenberg Field $ 21.17 $ 21.24 - %
Delaware Basin 28.58 34.04 (16) %
Weighted average price 21.95 22.49 (2) %
Crude oil equivalent (per Boe)
Wattenberg Field $ 36.99 $ 42.79 (14) %
Delaware Basin 37.20 44.17 (16) %
Weighted average price 37.02 42.95 (14) %
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.
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PDC ENERGY, INC.
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 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, 2023 NYMEX Price Expense TGP Expense Expense (1) Expense Expense
Crude oil (per Bbl) $ 76.13 $ 74.13 97 % $ 2.66 $ 71.47 94 %
Natural gas (per
MMBtu) 3.42 3.07 90 % 0.18 2.89 85 %
NGLs (per Bbl) 76.13 21.95 29 % - 21.95 29 %
Crude oil equivalent
(per Boe) 54.00 37.02 69 % 1.28 35.74 66 %
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, 2022 NYMEX Price Expense TGP Expense Expense (1) Expense Expense
Crude oil (per Bbl) $ 82.64 $ 82.24 100 % $ 2.55 $ 79.69 96 %
Natural gas (per
MMBtu) 6.26 3.94 63 % 0.21 3.73 60 %
NGLs (per Bbl) 82.64 22.49 27 % - 22.49 27 %
Crude oil equivalent
(per Boe) 64.95 42.34 65 % 1.32 41.02 63 %
____________
(1)Average TGP expense excludes unutilized firm transportation fees of $0.20 per
Boe and $0.21 per Boe for the three months ended March 31, 2023 and December 31,
2022 , respectively.
Our average realization percentage for natural gas increased for the three
months ended March 31, 2023 as compared to the three months ended December 31,
2022 primarily due to higher first of the month Colorado Interchange Gas ("CIG")
basis in January and February of 2023.
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 ofMarch 31, 2023 . 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. 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. 28 --------------------------------------------------------------------------------PDC ENERGY, INC.
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 ,
2023
(in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil collars and fixed price exchanges $ (35) $ (105)
Natural gas collars and fixed price exchanges (5) (69)
Natural gas basis protection exchanges (46) 7
Total net settlements of commodity derivative instruments (86) (167)
Change in fair value of unsettled commodity derivative instruments: Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments
110 156
Crude oil collars and fixed price exchanges 69 (153)
Natural gas collars and fixed price exchanges 80 93
Natural gas basis protection exchanges (29) (29)
Net change in fair value of unsettled commodity derivative instruments
230 67
Total commodity price risk management gain (loss), net
$ (100)
The decrease in commodity prices during the three months ended March 31, 2023
compared to the three months ended December 31, 2022 resulted in an unrealized
commodity risk management gain in the first quarter of 2023.
Lease Operating Expense
Lease operating expense ("LOE") increased by 6 percent to $73 million for the
three months ended March 31, 2023 compared to $69 million for the three months
ended December 31, 2022 . The period-over-period increase in LOE was primarily
attributable to a $2 million increase in chemicals, power and fuel and a $1
million increase in regulatory and abandonment costs. LOE per Boe increased 10
percent to $3.33 for the three months ended March 31, 2023 from $3.04 for the
three months ended December 31, 2022 . The increase in LOE per Boe was primarily
due to the factors outlined above and a 3 percent decrease in production volumes
between periods.
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 9 percent to $56 million for the three months ended
March 31, 2023 compared to $61 million for the three months ended December 31,
2022 . Production taxes per Boe decreased 6 percent to $2.54 for the three months
ended March 31, 2023 compared to $2.71 for the three months ended December 31,
2022 . The decrease in production taxes was primarily due to a 14 percent
decrease in weighted average realized sales prices between periods and a 3
percent decrease in production volumes between periods. The decrease in
production taxes per Boe was primarily due to a decrease in weighted average
realized sales prices between periods.
Transportation, Gathering and Processing Expense
TGP expense decreased 6 percent to$33 million for the three months endedMarch 31, 2023 compared to$35 million for the three months endedDecember 31, 2022 . The decrease in TGP expense between periods was primarily due to a 3 percent decrease in production volumes and a$1 million decrease in shortfall fees relating to our delivery commitments. TGP expense per Boe decreased 3 percent to$1.48 for the three months endedMarch 31, 2023 compared to$1.53 for the three months endedDecember 31, 2022 . 29 --------------------------------------------------------------------------------PDC ENERGY, INC.
General and Administrative Expense
General and administrative expense increased 14 percent to$41 million for the three months endedMarch 31, 2023 compared to$36 million for the three months endedDecember 31, 2022 . The increase between periods was primarily due to a$2 million release of our accrual related to our consent decree which terminated in the fourth quarter of 2022 and a$2 million increase in salaries, wages and benefits related to the timing of our employee incentive programs.
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$205 million for the three months endedMarch 31, 2023 compared to$200 million for the three months endedDecember 31, 2022 . The increase in DD&A expense was primarily due to a 6 percent increase in the weighted average depletion expense rate partially offset by a 3 percent decrease in production volumes between periods.
The period-over-period change in DD&A expense related to crude oil and natural gas properties was primarily due to the following:
December 31, 2022 -
March 31, 2023
(in millions)
Increase (decrease) in production $ (7)
Increase (decrease) in weighted average depletion rates 12
Total increase (decrease) in DD&A expense related to crude oil and natural gas properties
$ 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, 2023 December 31, 2022
(per Boe)
Operating Region /Area
Wattenberg Field $ 9.04 $ 8.56
Delaware Basin 11.50 10.66
Total weighted average DD&A expense rate 9.32 8.80
Interest Expense, net
Interest expense, net decreased 6 percent to $15 million for the three months
ended March 31, 2023 compared to $16 million for the three months ended December
31, 2022 . The decrease between periods was primarily due to an increase in
capitalized interest as a result of an increase in interest rates and drilling
activity in both basins.
Provision for Income Taxes
We recorded income tax expense of $113 million and $96 million for the three
months ended March 31, 2023 and December 31, 2022 , respectively, resulting in an
effective income tax rate of 21.4 percent and 20.3 percent on the respective
pre-tax income. For the three months ended March 31, 2023 , our effective income
tax rate was different from the statutory U.S. statutory tax rate of 21 percent
primarily due to the effects of state income taxes, partially offset by the
benefit of excess stock-based compensation deductions and a change in the state
effective tax rate. For the three months ended December 31, 2022 , our effective
income tax rate was different from the U.S. statutory tax rate of 21 percent
primarily due to changes in our valuation allowance against our deferred tax
assets and due to the effects of state income taxes.
In August 2022 , the IRA was enacted into law. The provisions of the IRA include
(i) a new 15 percent corporate alternative minimum tax on corporations with
average annual adjusted financial statement income over a three-year period in
excess of $1.0 billion , (ii) a nondeductible 1 percent excise tax on the value
of certain stock that a company repurchases, and (iii) various tax incentives
for energy and climate initiatives. Each of these provisions are effective for
tax years beginning after December 31, 2022 . We continue to monitor updates to
the IRA and the impact to our financial position, results of operations
30
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PDC ENERGY, INC.and liquidity, however, we do not believe it will have a material impact on our cash taxes for the 2023 tax year, and we are still assessing the impact for subsequent years.
Net Income (Loss)/Adjusted Net Income (Loss)
The factors impacting a net income of
Adjusted net income, a non-U.S. GAAP financial measure, was$233 million and$297 million for the three months endedMarch 31, 2023 andDecember 31, 2022 , respectively. With the exception of the tax-affected (when applicable) net change in fair value of unsettled derivatives, the same factors impacted adjusted net income. 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 comparableU.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. These activities typically result in a working capital deficit; however, we do not believe that our working capital deficit as ofMarch 31, 2023 is an indication of a lack of liquidity. We had working capital deficits of$751 million as ofMarch 31, 2023 and$826 million as ofDecember 31, 2022 . The decrease in working capital deficit sinceDecember 31, 2022 was primarily due to a decrease in fair value of our current net derivative liabilities between periods. 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. 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$17 million atMarch 31, 2023 and availability under our revolving credit facility was$1.1 billion , providing for a total liquidity position of$1.1 billion as ofMarch 31, 2023 . 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, income taxes and working capital obligations. If commodity prices 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. 31 --------------------------------------------------------------------------------PDC ENERGY, INC. Based on our current production forecast for 2023, we expect 2023 cash flows from operations 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 long-term cash requirements relate to 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 sinceDecember 31, 2022 . 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 underU.S. GAAP, includes, among other things, unused commitments under the revolving credit facility and excludes the fair value of commodity derivative assets. Additionally, the current ratio covenant calculation allows us to exclude the fair value of commodity derivative liabilities and the current portion of our long-term debt and other short-term loans from theU.S. GAAP total current liabilities amount. Accordingly, the existence of a working capital deficit underU.S. GAAP is not necessarily indicative of a violation of the current ratio covenant. AtMarch 31, 2023 , we were in compliance with all covenants in the revolving credit facility with a current ratio of 1.4:1.0 and a leverage ratio of 0.5:1.0. 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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