BERRY CORP (BRY) Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-Q)

Management's Discussion and Analysis of Financial Condition and Results of
Operations ("MD&A") should be read in conjunction with our interim unaudited
consolidated financial statements and related notes presented in this Quarterly
Report on Form 10-Q, as well as our audited consolidated financial statements
and related notes thereto contained in our Annual Report on Form 10-K for the
year ended December 31, 2021 (the "Annual Report") filed with the Securities and
Exchange Commission ("SEC"). When we use the terms "we," "us," "our," "Berry,"
the "Company" or similar words in this report, we are referring to, as the
context may require, (i) for periods prior to October 1, 2021, Berry Corporation
(bry), a Delaware corporation (formerly known as Berry Petroleum
Corporation,"Berry Corp."), together with its subsidiary Berry Petroleum, LLC, a
Delaware limited liability company ("Berry LLC"); and (ii) for periods on or
after October 1, 2021, Berry Corp. together with its subsidiaries, Berry LLC, CJ
Berry Well Services Management, LLC, a Delaware limited liability company ("C&J
Management"), and C&J Well Services, LLC, a Delaware limited liability company
("C&J").

Our Company

We are a western United States independent upstream energy company with a focus
on onshore, low geologic risk, long-lived conventional oil and gas reserves in
the San Joaquin basin of California and the Uinta basin of Utah, with well
servicing and abandonment capabilities in California. Since October 1, 2021, we
have operated in two business segments: (i) development and production ("D&P")
and (ii) well servicing and abandonment.

The assets in our D&P business, in the aggregate, are characterized by high oil
content (our California assets are 100% oil) and are predominantly located in
rural areas with low population. In California, we focus on conventional,
shallow oil reservoirs, the drilling and completion of which are relatively
low-cost in contrast to unconventional resource plays. The California oil market
has primarily Brent-influenced pricing which has typically realized premium
pricing to WTI. All of our California assets are located in the oil-rich
reservoirs in the San Joaquin basin, which has more than 150 years of production
history and substantial oil remaining in place. As a result of the substantial
data produced over the basin's long history, its reservoir characteristics are
well understood, which enables predictable, repeatable, low geological risk and
low-cost development opportunities. We also have upstream assets in the
low-operating cost, oil-rich reservoirs in the Uinta basin of Utah. In January
2022, we divested our natural gas properties in the Piceance basin of Colorado.

On October 1, 2021, we completed the acquisition of one of the largest upstream
well servicing and abandonment businesses in California, which operates as CJWS
and now constitutes our well servicing and abandonment business segment. CJWS
provides wellsite services in California to oil and natural gas production
companies, with a focus on well servicing, well abandonment services and water
logistics. CJWS' services include rig-based and coiled tubing-based well
maintenance and workover services, recompletion services, fluid management
services, fishing and rental services, and other ancillary oilfield services.
Additionally, CJWS performs plugging and abandonment services on wells at the
end of their productive life, which we believe creates a strategic growth
opportunity for Berry. CJWS is a synergistic fit with the services required by
our oil and gas operations and supports our commitment to be a responsible
operator and reduce our emissions, including through the proactive plugging and
abandonment of wells. Additionally, CJWS is critical to advancing our strategy
to work with the State of California to reduce fugitive emissions - including
methane and carbon dioxide - from idle wells. There are approximately 35,000
idle wells estimated to be in California according to third-party sources. We
believe that CJWS is uniquely positioned to capture both state and federal funds
to help remediate orphaned idle wells that are a burden of the State, in
addition to helping third-party customers safely plug and abandon their idle
wells.

Since our Initial Public Offering (IPO) in July 2018, we have demonstrated our
commitment to maximizing shareholder value and returning a substantial amount of
capital to shareholders through dividends and share purchases. In 2022, we
reinforced this commitment by initiating a shareholder return model, which is
further discussed below, designed to take advantage of our low decline rates and
strong visibility into our cost structure to maximize total shareholder value.
Under this well-defined shareholder return model, we have declared variable
dividends of $1.10 per share in aggregate based on our Discretionary Free Cash
Flow (defined and discussed below) generated in the first three quarters of
2022. We have also declared fixed dividends of $0.24 during 2022. Since our
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2018 IPO, we will have returned $282 million to our shareholders, which
represents 256% of our IPO proceeds, consisting of $188 million paid in fixed
and variable dividends and $94 million to repurchase 9.5 million shares
representing 12% of our outstanding shares as of September 30, 2022.

As referenced above, our shareholder return model went into effect January 1,
2022. Like our business model, this shareholder return model is simple and
further demonstrates our commitment to maximize total shareholder value. The
model is based on our Discretionary Free Cash Flow, which is defined as cash
flow from operations less regular fixed dividends and the capital needed to hold
oil and gas production flat, and provides for the allocation of Discretionary
Free Cash Flow on a quarterly basis as follows: (a) 60% predominantly in the
form of variable cash dividends to be paid quarterly, as well as opportunistic
debt repurchases; (b) 40% in the form of discretionary capital, to be used for
opportunistic growth, including from our extensive inventory of drilling
opportunities, advancing our short- and long-term sustainability initiatives,
share repurchases, and/or capital retention. Discretionary Free Cash Flow is a
non-GAAP financial measure used by management, as well as by external users of
our financial statements. Please see "Management's Discussion and
Analysis-Non-GAAP Financial Measures" for a reconciliation of Discretionary Free
Cash Flow to cash provided by operating activities, our most directly comparable
financial measure calculated and presented in accordance with GAAP.

We believe that the successful execution of our strategy across our
low-declining, oil-weighted production base coupled with extensive inventory of
identified drilling locations with attractive full-cycle economics will support
our objectives to generate Discretionary Free Cash Flow to fund our operations
and optimize capital efficiency, while maintaining a low leverage profile and
focusing on attractive organic and strategic growth through commodity price
cycles.

We have a progressive approach to growing and evolving our businesses in today's
dynamic oil and gas industry. Our strategy includes proactively engaging the
many forces driving our industry and impacting our operations, whether positive
or negative, to maximize the utility of our assets, create value for
shareholders, and support environmental goals that align with safe, more
efficient and lower emission operations. As part of our commitment to creating
long-term value for our stockholders, we are dedicated to conducting our
operations in an ethical, safe and responsible manner, to protecting the
environment, and to taking care of our people and the communities in which we
live and operate. We believe that oil and gas will remain an important part of
the energy landscape going forward and our goal is to conduct our business
safely and responsibly, while supporting economic stability and social equity
through engagement with our stakeholders. We recognize the oil and gas
industry's role in the energy transition and advocate a co-existence between
renewable and conventional energy, committed to being part of the energy
transition solution by continuing to provide safe and affordable energy to our
communities.

How We Plan and Evaluate Operations

We use the following metrics to manage and assess the performance of our
operations: (a) Adjusted EBITDA; (b) Discretionary Free Cash Flow for
shareholder returns; (c) operating expenses; (d) environmental, health & safety
("EH&S") results; (e) general and administrative expenses; (f) production from
our D&P business; and (g) the performance of our well servicing and abandonment
operations based on activity levels, pricing and relative performance for each
service provided.

Adjusted EBITDA

Adjusted EBITDA is the primary financial and operating measurement that our
management uses to analyze and monitor the operating performance of both our D&P
business and CJWS. We also use Adjusted EBITDA in planning our capital
allocation to sustain production levels and determining our strategic hedging
needs aside from the hedging requirements of the 2021 RBL Facility (defined
below in Liquidity and Capital Resources). Adjusted EBITDA is a non-GAAP
financial measure that we define as earnings before interest expense; income
taxes; depreciation, depletion, and amortization ("DD&A"); derivative gains or
losses net of cash received or paid for scheduled derivative settlements;
impairments; stock compensation expense; and unusual and infrequent items. See
"Management's Discussion and Analysis-Non-GAAP Financial Measures" for
reconciliation of Adjusted EBITDA to net (loss) income and to net cash provided
by operating activities, our most directly comparable financial

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measures calculated and presented in accordance with GAAP. This supplemental
non-GAAP financial measure is used by management, as well as by external users
of our financial statements.

Shareholder Returns

As discussed in "Management's Discussion and Analysis-Our Company," commencing
in 2022, we implemented a shareholder return model based on our Discretionary
Free Cash Flow, which is a non-GAAP measure that we define as cash flow from
operations less regular fixed dividends and the capital needed to hold
production flat year-over-year (see "Management's Discussion and
Analysis-Non-GAAP Financial Measures" for reconciliation of Discretionary Free
Cash Flow to cash provided by operating activities, our most directly comparable
financial measure calculated and presented in accordance with GAAP). Under the
shareholder return model, we intend to allocate a significant portion of the
Discretionary Free Cash Flow generated each quarter to pay variable quarterly
cash dividends, with the remaining Discretionary Free Cash Flow expected to be
allocated to fund opportunistic debt repurchases, opportunistic growth
(including from our extensive inventory of drilling opportunities), advancing
our short- and long-term sustainability initiatives, share repurchases, and/or
capital retention.

Our focus on shareholder returns is also demonstrated through our
performance-based restricted stock awards, which include performance metrics
based on the Company's average cash returned on invested capital and total
stockholder return on both a relative and absolute basis. Our 2022 short-term
incentive plan also includes Discretionary Free Cash Flow performance goals.

Operating Expenses

Overall, operating expense is used by management as a measure of the efficiency
with which operations are performing. With respect to our D&P business, we
define operating expenses as lease operating expenses, electricity generation
expenses, transportation expenses, and marketing expenses, offset by the
third-party revenues generated by electricity, transportation and marketing
activities, as well as the effect of derivative settlements (received or paid)
for gas purchases. Lease operating expenses include fuel, labor, field office,
vehicle, supervision, maintenance, tools and supplies, and workover expenses.
Taxes other than income taxes and costs of services are excluded from operating
expenses. Marketing revenues represent sales of natural gas purchased from and
sold to third parties. The electricity, transportation and marketing activity
related revenues are viewed and treated internally as a reduction to operating
costs when tracking and analyzing the economics of development projects and the
efficiency of our hydrocarbon recovery. Additionally, we strive to minimize the
variability of our fuel gas costs for our California steam operations with gas
hedges, as well as contracts for the transportation of fuel gas from the Rockies
which has historically been cheaper than the California markets.

Environmental, Health & Safety (EH&S)

Like other companies in the oil and gas industry, the operations of both our D&P
business and CJWS are subject to complex federal, state and local laws and
regulations that govern health and safety, the release or discharge of
materials, and land use or environmental protection that may restrict the use of
our properties and operations, increase our costs or lower demand for or
restrict the use of our products and services. Please see "Management's
Discussion and Analysis-Regulatory Matters" in this quarterly report as well as
"Part I, Item 1 "Regulatory Matters" and Part I, Item 1A. "Risk Factors" in our
Annual Report for a discussion of the potential impact that government
regulations, including those regarding EH&S matters, may have upon our business,
operations, capital expenditures, earnings and competitive position.

As part of our commitment to creating long-term stockholder value, we strive to
conduct our operations in an ethical, safe and responsible manner, to protect
the environment and to take care of our people and the communities in which we
live and operate. We also seek proactive and transparent engagement with
regulatory agencies, the communities in which we operate and our other
stakeholders in order to realize the full potential of our resources in a timely
fashion that safeguards people and the environment and complies with existing
laws and regulations. We monitor our EH&S performance through various measures,
and we hold our employees and contractors to high

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standards. Meeting corporate EH&S metrics, including with respect to EH&S incidents and spill prevention, is a part of our short-term incentive program for all employees.

General and Administrative Expenses

We monitor our cash general and administrative expenses as a measure of the
efficiency of our overhead activities and historically less than 10% of such
costs are capitalized, which we believe is significantly less than industry
norms. Such expenses are a key component of the appropriate level of support our
corporate and professional team provides to the development of our assets and
our day-to-day operations.

Production

Oil and gas production is a key driver of our operating performance, an
important factor to the success of our business, and used in forecasting future
development economics. We measure and closely monitor production on a continuous
basis, adjusting our property development efforts in accordance with the
results. We track production by commodity type and compare it to prior periods
and expected results.

Well Servicing and Abandonment Operations Performance

We consistently monitor our well servicing and abandonment operations performance with revenue and cost by service and customer, as well as Adjusted EBITDA for this business.

Business Environment, Market Conditions and Outlook

Our operating and financial results, and those of the oil and gas industry as a
whole, are heavily influenced by commodity prices. Oil and gas prices, including
the differentials between the relevant benchmarks and the prices we receive for
our oil and natural gas production in our D&P business, have fluctuated, and may
continue to fluctuate, significantly as a result of numerous market-related
variables, including geopolitical and global economic conditions and third-party
transportation and market takeaway infrastructure capacity. While oil prices
have significantly improved in 2022 relative to the lows experienced in 2020 and
recoveries through 2021, they are still subject to volatility. We utilize
derivatives to hedge a portion of our forecasted oil and gas production and gas
purchases to reduce exposure to fluctuations in oil and natural gas prices; our
2021 RBL Facility (defined below in Liquidity and Capital Resources) also has
hedging requirements.

Our well servicing and abandonment business is dependent on expenditures of oil
and gas companies, which tend to fluctuate in line with the volatility of
commodity prices. However, because existing oil and natural gas wells require
ongoing spending to maintain production, expenditures by oil and gas companies
for the maintenance of existing wells historically have been relatively stable
and predictable. Additionally, our customers' requirements to plug and abandon
wells are largely driven by regulatory requirements which are not dependent on
commodity prices.

The COVID-19 pandemic resulted in a severe decrease in demand for oil, which
created significant volatility and uncertainty in the oil and gas industry
during 2020 and 2021. When combined with an excess supply of oil and related
products, oil prices declined significantly in the first half of 2020. Although
there has been some volatility, overall oil prices have steadily improved since
the lows experienced in 2020, in line with increasing demand despite the ongoing
pandemic and uncertainties surrounding the COVID-19 variants. Oil and natural
gas prices increased significantly during 2022, reaching a high of almost $128
per bbl during 2022, primarily due to global supply and demand imbalances. Brent
prices were 13% lower and 33% higher for the three months ended September 30,
2022 as compared to the three months ended June 30, 2022 and September 30, 2021,
respectively. Currently, global oil inventories are low relative to historical
levels and supply from OPEC+ and other oil producing nations are not expected to
be sufficient to meet forecasted oil demand growth for the next few years. It is
believed that many OPEC+ countries will be unable to increase their production
levels or even produce at expected levels due to their lack of capital
investments in developing incremental oil supplies over the past few years. In
October 2022, OPEC+ determined to reduce production beginning in November 2022
through December 2023 by 2 million bbls per day,

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due to the uncertainty surrounding the global economic and oil market outlooks.
Furthermore, sanctions and import bans on Russian oil have been implemented by
various countries in response to the war in Ukraine, further impacting global
oil supply. Still, oil and natural gas prices have recently declined from the
highs experienced in second quarter of 2022 and could decrease or increase with
any changes in demand due to, among other things, uncertainty and volatility
from global supply chain disruptions attributable to the pandemic, the ongoing
conflict in Ukraine, international sanctions, speculation as to future actions
by OPEC+, developing COVID-19 variants and the potential for a widespread
COVID-19 outbreak, higher gas prices, increasing inflation and government
efforts to reduce inflation, and possible changes in the overall health of the
global economy, including a prolonged recession. Further, the volatility in oil
and natural gas prices could accelerate a transition away from fossil fuels,
resulting in reduced demand over the longer term. To what extent these and other
external factors (such as government action with respect to climate change
regulation) ultimately impact our future business, liquidity, financial
condition, and results of operations is highly uncertain and dependent on
numerous factors, including future developments, that are not within our control
and cannot be accurately predicted.

Commodity Pricing and Differentials

Our revenue, costs, profitability, shareholder returns and future growth are
highly dependent on the prices we receive for our oil and natural gas
production, as well as the prices we pay for our natural gas purchases, which
are affected by a variety of factors in Part I, Item 1A. "Risk Factors" in our
Annual Report. We utilize derivatives to hedge a portion of our forecasted oil
and gas production and gas purchases to reduce exposure to fluctuations in oil
and natural gas prices.

Average Brent oil prices, as noted below, decreased by $14.28, or 13% for the
three months ended September 30, 2022 compared to the three months ended June
30, 2022 and increased by $24.47, or 33% compared to the three months ended
September 30, 2021. Though the California market generally receives
Brent-influenced pricing, California oil prices are determined ultimately by
local supply and demand dynamics, including third-party transportation and
market takeaway infrastructure capacity.

For our California steam operations, the price we pay for fuel gas purchases is
generally based on the Kern, Delivered Index for the purchases made in
California and based on the Northwest, Rocky Mountains Index for the purchases
made in the Rockies. The high price from these indices was $15.96 per mmbtu and
the low was $5.38 per mmbtu during the third quarter of 2022, while we paid an
average of $8.16 per mmbtu in this period. The price we paid on average
increased by $0.86 per mmbtu, or 12% for the three months ended September 30,
2022 compared to the three months ended June 30, 2022.

The following table presents the average Brent, WTI, Kern, Delivered, Northwest,
Rocky Mountains, and Henry Hub prices for the three months ended September 30,
2022, June 30, 2022 and September 30, 2021 and for the nine months ended
September 30, 2022 and September 30, 2021:

                                                       Three Months Ended                                        Nine Months Ended
                                     September 30,          June 30,           September 30,           September 30,           September 30,
                                         2022                 2022                 2021                    2022                    2021
Oil (bbl) - Brent                  $        97.70          $ 111.98          $        73.23          $       102.48          $        67.97
Oil (bbl) - WTI                    $        91.96          $ 108.71          $        70.63          $        98.39          $        64.87
Natural gas (mmbtu) - Kern,        $         8.74          $   7.36

$ 5.75 $ 6.99 $ 5.65 Delivered Natural gas (mmbtu) - Northwest, $ 7.79 $ 6.69

$ 3.97 $ 6.75 $ 3.23 Rocky Mountains Natural gas (mmbtu) - Henry Hub $ 8.03 $ 7.50

$ 4.35 $ 6.74 $ 3.61

As mentioned above, California oil prices are Brent-influenced as California
refiners import approximately 70% of the state's demand from OPEC+ countries and
other waterborne sources. Without the higher costs and potential environmental
impact associated with importing crude via rail or supertanker, we believe our
in-state production and low-cost crude transportation options, coupled with
Brent-influenced pricing, in appropriate oil price environments,

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should continue to allow us to realize positive cash margins in California over the cycle.

Utah oil prices have historically traded at a discount to WTI as the local
refineries are designed for Utah's unique oil characteristics and the remoteness
of the assets makes access to other markets logistically challenging. However,
we have high operational control of our existing acreage, which provides
significant upside for additional vertical and or horizontal development and
recompletions.

Natural gas prices and their differentials are strongly affected by local market
fundamentals, availability of third-party transportation and market takeway
infrastructure capacity from producing areas and seasonal impacts. We purchase
substantially more natural gas for our California steamfloods and cogeneration
facilities than we produce and sell in the Rockies. In recent history, the
California gas markets have generally had higher gas prices than the Rockies and
the rest of the United States. Higher gas prices have a negative impact on our
operating results. However, we mitigate a portion of this exposure by selling
excess electricity from our cogeneration operations to third parties at prices
linked to the price of natural gas. We also strive to minimize the variability
of our fuel gas costs for our steam operations by hedging a significant portion
of such gas purchases. In addition, we have entered into pipeline capacity
agreements for the shipment of natural gas from the Rockies to our assets in
California that help reduce our exposure to fuel gas purchase price
fluctuations. Additionally, the negative impact of higher gas prices on our
California operating expenses is partially offset by higher gas sales for the
gas we produce and sell in the Rockies.

Prices and differentials for NGLs are related to the supply and demand for the
products making up these liquids. Some of them more typically correlate to the
price of oil while others are affected by natural gas prices as well as the
demand for certain chemical products which are used as feedstock. In addition,
infrastructure constraints magnify pricing volatility.

Our earnings are also affected by the performance of our cogeneration
facilities. These cogeneration facilities generate both electricity and steam
for our properties and electricity for off-lease sales. While a portion of the
electric output of our cogeneration facilities is utilized within our production
facilities to reduce operating expenses, we also sell electricity produced by
two of our cogeneration facilities under contracts with terms ending in December
2023 through December 2026. The most significant input and cost of the
cogeneration facilities is natural gas. We generally receive significantly more
revenue from these cogeneration facilities in the summer months, most notably in
June through September, due to negotiated capacity payments we receive.

Regulatory Matters

Like other companies in the oil and gas industry, both our D&P business and CJWS
are subject to complex and stringent federal, state, and local laws and
regulations, and California, where most of our operations and assets are
located, is one of the most heavily regulated states in the United States with
respect to oil and gas operations. A combination of federal, state and local
laws and regulations govern most aspects of our activities in California.
Collectively, the effect of the existing laws and regulations is to limit the
number and location of our wells through restrictions on the use of our
properties, limit our ability to develop certain assets and conduct certain
operations, including through a restrictive and burdensome permitting and
approval process, and regulate the amount of oil and natural gas that we can
produce from our wells, potentially reducing below levels that would otherwise
be possible. Additionally, the regulatory burden on the industry in the past has
and in the future could result in increased costs and consequently may have an
adverse effect upon operations, capital expenditures, earnings and our
competitive position. Violations and liabilities with respect to these laws and
regulations could also result in significant administrative, civil, or criminal
penalties, remedial clean-ups, natural resource damages, permit modifications or
revocations, operational interruptions or shutdowns and other liabilities. The
costs of remedying such conditions may be significant, and remediation
obligations could adversely affect our financial condition, results of
operations and future prospects. Our operations in California are particularly
exposed to increased regulatory risks given the stringent environmental
regulations imposed on the oil and gas industry, and current political and
social trends in California continue to increase limitations on and impose
additional permitting, mitigation, and emission control obligations, amongst
others, upon the oil and gas industry. We cannot predict what new environmental
laws or regulations California may impose upon our operations in the future;
however, any such future laws or regulations

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could materially and adversely impact our business and results of operations.
For additional information about the potential impact that government
regulations, including those regarding environmental matters, may have upon our
business, operations, capital expenditures, earnings and competitive position,
please see Part I, Item 1 "Regulatory Matters," as well as Part I, Item 1A.
"Risk Factors" in our Annual Report.

Our oil and gas operations in California are subject to compliance with the
California Environmental Quality Act ("CEQA"), and we cannot receive certain
permits and other approvals required for our operations until we have
demonstrated compliance with CEQA. There have been a number of developments at
both the California state and local levels that have resulted in delays in the
issuance of new drilling permits for oil and gas activities in Kern County where
all of our California assets are located, as well as a more time- and cost-
intensive permitting process. Most notably, in Kern County, we historically have
satisfied CEQA by complying with the local oil and gas ordinance, which was
supported by an Environmental Impact Report (an "EIR") covering oil and gas
operations in Kern County ("Kern County EIR"). In 2020, a lawsuit was filed
challenging the Kern County EIR, and subsequently the California Fifth District
Court of Appeals issued a ruling invalidating a portion of the Kern County EIR
until Kern County made certain revisions to the Kern County EIR and recertified
it ("Kern County Ruling"). To address the Kern County Ruling, Kern County
prepared a supplemental EIR which was approved by the Kern County Board of
Supervisors in March 2021. Following further challenges by plaintiffs, a Kern
County Superior Court judge suspended use of the Kern County EIR as
supplemented, stopping the issuance of new oil and gas permits by Kern County in
October 2021 (the "Kern County Permit Suspension"), pending a determination by
the Kern County Superior Court that the Kern County EIR complied with the CEQA
requirements. In June 2022, the Kern County Superior Court ruled in favor of
Kern County in part but also found that the supplemental Kern County EIR still
failed to meet the minimum requirements of CEQA. In August 2022, the Kern County
Board of Supervisors approved changes which addressed four discrete issues
identified by the court in its June 2022 ruling. Following a hearing in
September 2022, the Kern County Superior Court subsequently issued a ruling in
October 2022 determining that the Kern County supplemental EIR was not
decertified, but ordered Kern County to address the four discrete issues
previously identified before the Kern County Permit Suspension could be lifted.
These four discrete issues included requirements for the removal of offsite
legacy equipment to mitigate agricultural land use impacts, revising emissions
reduction requirements to address particulate matter, the establishment of a
drinking water grant fund for disadvantaged communities in Kern County, and
updating the local oil and gas ordinance to reflect these requirements. Kern
County filed notice with the court of the changes on October 12, 2022. However,
the plaintiffs have objected to the adequacy of Kern County's changes and a
final decision from the Kern County Superior Court remains pending. Although we
are cautiously optimistic that this matter will be favorably resolved in the
near term, at this time, we cannot predict the timing of the Kern County
Superior Court's ruling nor the outcome, including the extent to which the
expected or other new additional requirements incorporated into the supplemental
Kern County EIR may impact our business, financial condition, results of
operation and future prospects. Importantly, neither the Kern County Ruling nor
the Kern County Permit Suspension invalidated existing permits and, in part due
to our contingency planning efforts, our operations have not been materially
impacted to date.

Until Kern County is able to resume the ability to issue permits, our ability to
obtain new permits and approvals to enable our future plans in Kern County
requires demonstrating compliance with CEQA to CalGEM. We were able to secure
some new drill permits from CalGEM in specific operational areas where the CEQA
environmental analyses had already been completed by a predecessor entity, which
CalGEM recognized as satisfying the CEQA compliance obligation. Demonstrating
CEQA compliance without being able to reference the Kern County EIR (which we
cannot currently do due to the Kern County Permit Suspension) or another
CEQA-compliant environmental analysis is a more technical, time and cost
intensive process and may, among other things, require that we conduct an
extensive environmental impact review. As a result of the Kern County Permit
Suspension, we together with other Kern County operators have experienced
significant delays in the issuance of permits for new wells by CalGEM, in part
due to the more intensive permitting process and CEQA compliance requirements
for new wells, which we expect will continue to be the case until the Kern
County Permit Suspension is resolved. We have submitted applications for
additional permits that we believe, if received on a timely basis together with
the permits already received, would enable us to execute our currently
anticipated 2023 drilling program. However, there is no assurance that such
additional permits will be approved in a timely manner or at all, even if the
Kern County Permit Suspension is lifted. Fortunately, we have not experienced
delays in the issuance of permits for the workover or recompletion of existing
wells or other activities re-using existing well bores, for which the
environmental review is

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expedited because the well already exists and the environmental impact analysis is simpler to conduct.

We timely submitted permit applications for the new wells contemplated by our
2022 capital development. However, due to the delays in permit issuance
discussed above and insufficient permit inventory, beginning in the second
quarter the execution of our remaining 2022 capital development program
ultimately required an increase in workovers, recompletions and other activities
re-using existing well bores and deployment of techniques to increase production
from existing producing wells (referred to as our "base production"), and
decrease in the number of new wells drilled in California contemplated by our
initial program. Our plans for the remainder of the year will depend on whether
and when we receive permits to drill new wells, as well as other key approvals
(such as UIC permits to support water disposal) required to support planned
activities. If we are unable to timely obtain those permits or approvals, our
planned 2022 production could be adversely impacted and we may need to further
modify our 2022 capital development program and alter our planned capital
expenditures or deploy that capital to other activities. However, at this time
we do not expect our planned 2022 production or results of operations to be
materially impacted even if we are unable to timely obtain those permits and
approvals because we currently believe we can continue to offset production from
planned new wells with increased production from workover and other activities
re-using existing well bores, as well as from our base production through field
optimization initiatives. At this time we expect that approximately 94% of our
planned 2022 production will come from our base production, with the remainder
from workovers and other activities related to existing well bores, as well as
from new wells drilled during the year.

Separately, on September 16, 2022, the Governor of California signed into law
Senate Bill No. 1137 which establishes 3,200 feet as the minimum distance
between new oil and gas production wells and certain sensitive receptors such as
homes, schools or parks effective January 1, 2023. Additional provisions, among
others, imposed EH&S controls applicable to wells located within this distance
of sensitive receptors related to noise, light, and dust pollution controls and
air emission monitoring, and the immediate suspension of operations at
production facilities determined not to be in compliance with certain air
emission requirements. These additional provisions are effective January 1,
2025. We are currently evaluating the impact of Senate Bill No. 1137 on our
assets (specifically including reserves) and development plans while actively
pursuing mitigation efforts with respect to the potential impacts on current and
planned wells.

Additionally, President Biden signed the Inflation Reduction Act ("IRA") into
law on August 16, 2022 which, among other provisions, imposes a fee on the
emissions of methane from certain sources in the oil and natural gas sector.
Beginning in 2024, the IRA's methane emissions charge imposes a fee on excess
methane emissions from certain oil and gas facilities, starting at $900 per
metric ton of leaked methane in 2024 and rising to $1,200 in 2025, and $1,500 in
2026 and thereafter. The imposition of this fee and other provisions of the IRA
could increase our operating costs and accelerate the transition away from oil
and gas, which could adversely affect our business and results of operations.

Inflation

The U.S. inflation rate has been steadily increasing since 2021 and throughout
2022. These inflationary pressures have resulted in and may result in additional
increases to the costs of our goods, services and personnel, which in turn cause
our capital expenditures and operating costs to rise. Sustained levels of high
inflation have likewise caused the U.S. Federal Reserve and other central banks
to increase interest rates, which could have the effects of raising the cost of
capital and depressing economic growth, either of which-or the combination
thereof-could adversely affect our business and results of operations.

Seasonality

Seasonal weather conditions can impact our drilling, production and well
servicing activities. These seasonal conditions can occasionally pose challenges
in our operations for meeting well-drilling and completion objectives and
increase competition for equipment, supplies and personnel, which could lead to
shortages and increase costs or delay operations. For example, our operations
have been and in the future may be impacted by ice and snow in the winter,
especially in Utah, by electrical storms and high temperatures in the spring and
summer, and by wild fires and rain.

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Natural gas prices fluctuate based on seasonal and other market-related impacts.
For example, natural gas prices increased significantly during the first three
quarters of 2022, reflecting a premium driven by European instability which
brought new demand for domestic production as a way to replace natural gas
previously produced by Russia, as well as lower storage levels and damage to the
Nord Stream pipeline connecting Russia to the rest of Europe for gas supplies.
We purchase significantly more gas than we sell to generate steam and
electricity in our cogeneration facilities for our production activities in our
D&P business. As a result, our key exposure to gas prices is in our costs. We
mitigate a substantial portion of this exposure by selling excess electricity
from our cogeneration operations to third parties. The pricing of these
electricity sales is closely tied to the purchase price of natural gas. These
sales are generally higher in the summer months as they include seasonal
capacity amounts. We also hedge a significant portion of the gas we expect to
consume and in 2021 we entered into new pipeline capacity agreements for the
shipment of natural gas from the Rockies to our operations in California to help
limit our exposure to fuel gas purchase price fluctuations.

Capital Expenditures

For the three and nine months ended September 30, 2022, our consolidated capital
expenditures were approximately $41 million and $103 million, respectively, on
an accrual basis including capitalized overhead and interest and excluding
acquisitions and asset retirement spending. Approximately 47% and 42% of capital
expenditures for the nine months ended September 30, 2022 was directed to
California oil and Utah operations, respectively.

Our budget for 2022 capital expenditures for D&P operations and corporate
activities was approximately $125 to $135 million, excluding $8 million for
CJWS, the planned use of which was expected to keep our annual production
relatively flat to 2021 after taking into account the impact of acquisitions and
divestitures completed in late 2021 and early 2022. Based on activity to date
and expected for the remainder of 2022, we currently anticipate our full year
capital expenditures will be slightly more than our initial budget and will be
between $140 and $145 million. We have adjusted our planned California capital
program in late 2022 based on the success of recent development activity. To
keep up the momentum into 2023, we are accelerating our development program
during the fourth quarter of 2022. Additionally, due to the results achieved
from mid-year workover and recompletion activity in Utah, we allocated
incremental funding to perform additional workovers in Utah. The increase in
full-year capital expenditures is also partially due to cost inflation in excess
of our initial expectations, which we began to experience mid-year.

The amount and timing of capital expenditures are within our control and subject
to our discretion, and due to the speed with which we are able to drill and
complete our wells in California, capital may be adjusted quickly during the
year depending on numerous factors, including permit inventory to support
planned activities, commodity prices, storage and third-party transportation
constraints, supply/demand considerations and attractive rates of return. We
believe it is important to retain the flexibility to defer planned capital
expenditures and may do so based on a variety of factors, including but not
limited to the success of our drilling activities, prevailing and anticipated
prices for oil, natural gas and NGLs, the receipt and timing of required
regulatory permits and approvals, the availability of necessary equipment,
infrastructure and capital, seasonal conditions, drilling and acquisition costs
and the level of participation by other interest owners, as well as general
market conditions. Any postponement or elimination of our development program
could result in a reduction of proved reserves volumes and materially affect our
business, financial condition and results of operations.

Additionally and not included in the capital expenditures noted above, for the
full year 2022, we plan to spend approximately $21 million to $24 million on
plugging and abandonment activities, including 280 to 320 wells and satisfying
our annual obligations under the California Idle Well Management Program. We
spent approximately $5 million and $16 million for plugging and abandonment
activities in the three months and nine months ended September 30, 2022,
respectively. Our well servicing and abandonment segment expects to plug and
abandon approximately 2,500 to 3,000 wells for their third-party customers in
2022, helping to safely address the environmental hazards and other risks from
California's number of idle wells. In the nine months ended September 30, 2022,
our wells servicing and abandonment segment plugged and abandoned 2,100 wells
for third-party customers.

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Summary by Area

The following table shows a summary by area of our selected historical financial
and operating information for our development and production operations for the
periods indicated.

                                                                                 California
                                                                    (San

Joaquin and Ventura basins)(3)

Three Months Ended

September 30, 2022

June 30, 2022 September 30, 2021

        ($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales   $        175,245               $     204,706          $         140,160
Operating income(1)                              $         57,864               $      63,608          $          26,652
Depreciation, depletion, and amortization (DD&A) $         33,979           

$ 34,074 $ 35,252

Average daily production (mboe/d)                            20.8                        21.0                       21.8
Production (oil % of total)                                   100   %                     100  %                     100  %
Realized sales prices:
Oil (per bbl)                                    $          91.67               $      107.31          $           69.92
NGLs (per bbl)                                   $              -               $           -          $               -
Gas (per mcf)                                    $              -               $           -          $               -
Capital expenditures(2)                          $         15,220               $      18,672          $          29,806



                                                       Utah                                                              Colorado
                                                   (Uinta basin)                                                    (Piceance basin)(4)
                                                Three Months Ended                                                  Three Months Ended
                              September 30,          June 30,          September 30,              September 30,           June 30,           September 30,
                                   2022                2022                 2021                      2022                  2022                 2021

($ in thousands, except

prices)

Oil, natural gas and natural
gas liquids sales            $      28,323          $ 35,338          $      18,118             $         -             $       -           $      2,779
Operating income(1)          $      11,123          $ 20,579          $       7,246             $         -             $       -           $      2,360
Depreciation, depletion, and
amortization (DD&A)          $       2,278          $    964          $         611             $         -             $       -           $         38

Average daily production
(mboe/d)                               5.0               5.2                    4.4                       -                     -                    1.2
Production (oil % of total)             57  %             57  %                  50  %                    -     %               -   %                  1  %
Realized sales prices:
Oil (per bbl)                $       73.83          $  94.47          $       60.09             $         -             $       -           $      66.97
NGLs (per bbl)               $       40.72          $  56.47          $       40.88             $         -             $       -           $          -
Gas (per mcf)                $        7.95          $   7.35          $        4.31             $         -             $       -           $       4.24
Capital expenditures(2)      $      21,196          $ 11,563          $       5,728             $         -             $       -           $          -


__________

(1)  Operating income (loss) includes oil, natural gas and NGL sales, marketing
revenues, other revenues, and scheduled oil derivative settlements, offset by
operating expenses (as defined elsewhere), general and administrative expenses,
DD&A, impairment of oil and gas properties, and taxes, other than income taxes.

(2) Excludes corporate capital expenditures.

(3) Our Placerita properties, in the Ventura basin, were divested in October 2021.

(4) Our properties in Colorado were in the Piceance basin, all of which were divested in January 2022.

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Production and Prices

The following table sets forth information regarding average daily production, total production and average prices for each of the periods indicated.

Three Months Ended

                                                 September 30, 2022           June 30, 2022           September 30, 2021
Average daily production:(1)
Oil (mbbl/d)                                                  23.7                    24.0                         24.1
Natural Gas (mmcf/d)                                          10.4                    11.0                         17.6
NGL (mbbl/d)                                                   0.4                     0.4                          0.4
Total (mboe/d)(2)                                             25.8                    26.2                         27.4
Total Production:
Oil (mbbl)                                                   2,171                   2,182                        2,211
Natural gas (mmcf)                                             953                     999                        1,615
NGLs (mbbl)                                                     39                      37                           39
Total (mboe)(2)                                              2,369                   2,386                        2,519
Weighted-average realized sales prices:
Oil without hedges ($/bbl)                     $             89.54          $       105.70          $             69.01
Effects of scheduled derivative settlements
($/bbl)                                        $            (13.13)         $       (21.92)         $            (14.66)
Oil with hedges ($/bbl)                        $             76.41          $        83.78          $             54.35
Natural gas ($/mcf)                            $              7.95          $         7.35          $              4.29
NGL ($/bbl)                                    $             40.72          $        56.47          $             40.88
Average Benchmark prices:
Oil (bbl) - Brent                              $             97.70          $       111.98          $             73.23
Oil (bbl) - WTI                                $             91.96          $       108.71          $             70.63
Natural gas (mmbtu) - Kern, Delivered(3)       $              8.74          $         7.36          $              5.75
Natural gas (mmbtu) - Northwest, Rocky         $              7.79          $         6.69          $              3.97

Mountains

Natural gas (mmbtu) - Henry Hub(4)             $              8.03          $         7.50          $              4.35


__________

(1) Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.

(2)  Natural gas volumes have been converted to boe based on energy content of
six mcf of gas to one bbl of oil. Barrels of oil equivalence does not
necessarily result in price equivalence. The price of natural gas on a barrel of
oil equivalent basis is currently substantially lower than the corresponding
price for oil and has been similarly lower for a number of years. For example,
in the three months ended September 30, 2022, the average prices of Brent oil
and Henry Hub natural gas were $97.70 per bbl and $8.03 per mmbtu.

(3) Kern, Delivered Index is the relevant index used for gas purchases in California.

(4) Henry Hub is the relevant index used for gas sales in the Rockies.

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The following table sets forth average daily production by operating area for
the periods indicated:

                                                                                 Three Months Ended
                                                September 30, 2022                   June 30, 2022               September 30, 2021
Average daily production (mboe/d):(1)
California(2)                                             20.8                              21.0                           21.8
Utah                                                       5.0                               5.2                            4.4
Colorado(3)                                                  -                                 -                            1.2

Total average daily production                            25.8                              26.2                           27.4


__________

(1) Production represents volumes sold during the period.

(2) In October 2021, we divested our Placerita (California) properties, exclusively oil production, which had average production of 0.8 mbbl/d in the third quarter 2021.

(3) In January 2022, we divested all of our natural gas properties in Colorado.

On a sequential basis, our average daily production decreased by 0.4 mboe/d for
the three months ended September 30, 2022, compared to the second quarter 2022.
Our California production was 20.8 mboe/d for the third quarter of 2022, a
decrease of 0.2 mboe/d from the second quarter 2022, which was largely due to
fewer new wells added in the third quarter than in the second quarter, partially
offset by workovers and other activities re-using existing well bores. Our Utah
production decreased largely due to fewer wells completed and placed on
production in the third quarter than in the second quarter.

Average daily production for the three months ended September 30, 2021 included
properties that have since been divested, specifically, Placerita properties in
California and Piceance properties in Colorado, which were our only assets in
Colorado. The combined production from these properties was 2.0 mboe/d in the
third quarter 2021 (1.2 mboe/d in Colorado and 0.8 mboe/d in California) and
there was no production from these properties in the second and third quarters
of 2022.

Average daily production in California for the three months ended September 30,
2022 decreased 0.2 mboe/d compared to the same period in 2021, when excluding
the production from the Placerita properties for 2021. The decrease was due to
decreased development activity in California during 2022. The year-over-year
increase in the Utah production was driven by the addition of the Antelope Creek
properties we acquired in February 2022.


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The following table sets forth information regarding average daily production, total production and average prices for each of the periods indicated.

Nine Months Ended

                                                                September 30, 2022           September 30, 2021
Average daily production:(1)
Oil (mbbl/d)                                                                 24.0                         24.0
Natural Gas (mmcf/d)                                                         11.0                         17.3
NGL (mbbl/d)                                                                  0.4                          0.4
Total (mboe/d)(2)                                                            26.2                         27.3
Total Production:
Oil (mbbl)                                                                  6,551                        6,545
Natural gas (mmcf)                                                          2,990                        4,728
NGLs (mbbl)                                                                   111                          105
Total (mboe)(2)                                                             7,160                        7,438
Weighted-average realized sales prices:
Oil without hedges ($/bbl)                                     $            95.83          $             63.59
Effects of scheduled derivative settlements ($/bbl)            $           (16.81)         $            (15.03)
Oil with hedges ($/bbl)                                        $            79.02          $             48.56
Natural gas ($/mcf)                                            $             6.99          $              5.16
NGL ($/bbl)                                                    $            47.98          $             32.97
Average Benchmark prices:
Oil (bbl) - Brent                                              $           102.48          $             67.97
Oil (bbl) - WTI                                                $            98.39          $             64.87
Gas (mmbtu) - Kern, Delivered(3)                               $             6.99          $              5.65
Natural gas (mmbtu) - Northwest, Rocky Mountains               $             6.75          $              3.23
Natural gas (mmbtu) - Henry Hub(4)                             $             6.74          $              3.61


__________

(1) Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.

(2)  Natural gas volumes have been converted to boe based on energy content of
six mcf of gas to one bbl of oil. Barrels of oil equivalence does not
necessarily result in price equivalence. The price of natural gas on a barrel of
oil equivalent basis is currently substantially lower than the corresponding
price for oil and has been similarly lower for a number of years. For example,
during the nine months ended September 30, 2022, the average prices of Brent oil
and Henry Hub natural gas were $102.48 per bbl and $6.74 per mmbtu respectively.

(3) Kern, Delivered Index is the relevant index used for gas purchases in California.

(4)  Henry Hub is the relevant index used for gas sales in the Rockies.








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The following table sets forth average daily production by operating area for
the periods indicated:

                                                                                  Nine Months Ended
                                                                September 30, 2022                 September 30, 2021
Average daily production (mboe/d):(1)
California(2)                                                             21.3                               21.8
Utah                                                                       4.8                                4.3
Colorado(3)                                                                0.1                                1.2

Total average daily production                                            26.2                               27.3


__________

(1) Production represents volumes sold during the period.

(2) In October 2021, we divested our Placerita (California) properties, exclusively oil production, which had average production of 0.8 mbbl/d in the third quarter 2021.

(3) In January 2022, we divested all of our natural gas properties in Colorado.

Average daily production for the nine months ended September 30, 2022 included
0.9 mboe/d of production from the Antelope Creek (Utah) asset acquired in the
first quarter of 2022 and 0.1 mboe/d of production from the Piceance (Colorado)
asset, which was divested in the first quarter of 2022. The nine months ended
September 30, 2021 included 1.2 mboe/d of production from the Colorado assets,
as well as 0.8 mboe/d of production from the Placerita asset in California,
which was divested in the fourth quarter of 2021.

On a comparable basis, when excluding the volumes from these acquisitions and
divestitures, California produced 21.3 mboe/d for the nine months ended
September 30, 2022, a 0.3 mboe/d increase when compared to the nine months ended
September 30, 2021. When excluding the volumes from these transactions, our
total production was essentially flat for the nine months ended September 30,
2022 compared to the nine months ended September 30, 2021. We drilled 51 wells
in California in the first nine months of 2022, of which 39 were producing
wells, eight were delineation wells and four were observation wells. We also
drilled 12 wells in Uinta, all of which were producing wells.



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Results of Operations

Three Months Ended September 30, 2022 compared to Three Months Ended June 30,
2022.

                                                Three Months Ended
                                       September 30,
                                           2022               June 30, 2022           $ Change              % Change
                                                  (in thousands)
Revenues and other:
Oil, natural gas and NGL sales        $    203,585          $      240,071          $ (36,486)                     (15) %
Service revenue                             48,594                  46,178              2,416                        5  %
Electricity sales                            9,711                   7,419              2,292                       31  %
Gain (losses) on oil and gas sales
derivatives                                114,279                 (40,658)           154,937                         n/a
Marketing and other revenues                   277                     120                157                      131  %

Total revenues and other              $    376,446          $      253,130          $ 123,316                       49  %


Revenues and Other

Oil, natural gas and NGL sales decreased by $36 million, or 15%, to
approximately $204 million for the three months ended September 30, 2022,
compared to the three months ended June 30, 2022. The decrease was driven by $35
million lower unhedged oil prices, including the approximate $2 per bbl impact
from discounts applied to approximately 25% of third quarter California volumes
due to an unexpected third-party pipeline outage for unplanned repairs during
most of the third quarter of 2022, as well as $1 million decrease due to lower
oil volumes. The unplanned repairs on the pipeline are ongoing and the Company
currently expects the outage to extend into the first quarter of 2023, which may
require additional volumes to be sold at a discount until resolved.

Service revenue consisted entirely of revenue from the well servicing and
abandonment business. Service revenue increased by $2 million or 5% to
approximately $49 million in the third quarter 2022, due to increased activity,
which is partially seasonal, and rate increases effective late second quarter to
offset a portion of cost inflation.

Electricity sales represent sales to utilities and increased $2 million, or 31%,
to approximately $10 million for the three months ended September 30, 2022
compared to the three months ended June 30, 2022. This increase was largely due
to higher unit sales prices driven by higher natural gas prices.

Gain or loss on oil and gas sales derivatives consists of settlement gains and
losses and mark-to-market gains and losses. Our settlement loss for the three
months ended September 30, 2022 was $29 million and the loss for the three
months ended June 30, 2022 was $48 million. The quarter-over-quarter decrease in
settlement losses was driven by an approximately $14 per bbl decline in index
prices. The mark-to-market non-cash gain was $143 million and $7 million for the
three months ended September 30, 2022 and June 30, 2022, respectively, due to a
narrower spread between future market prices and the fixed price at the end of
the quarter compared to that of the respective previous quarter. Because we are
the floating price payer on these swaps, generally, period to period decreases
(increases) in the associated price index create valuation gains (losses).

Marketing and other revenues, which included third-party marketing activities,
were not material for the three months ended September 30, 2022 and June 30,
2022.

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                                                      Three Months Ended
                                          September 30, 2022            June 30, 2022                 $ Change              % Change
                                            (in thousands, except expenses per boe)
Expenses and other:
Lease operating expenses                $        79,141               $       72,455                $   6,686                        9  %
Costs of services                                37,628                       36,709                      919                        3  %
Electricity generation expenses                   6,055                        6,122                      (67)                      (1) %
Transportation expenses                           1,277                        1,108                      169                       15  %

General and administrative expenses              23,388                       23,183                      205                        1  %
Depreciation, depletion and                      39,506                     

38,055

amortization                                                                                            1,451                        4  %

Taxes, other than income taxes                    7,335                       11,214                   (3,879)                     (35) %

(Gains) losses on natural gas purchase
derivatives                                     (28,942)                      10,661                  (39,603)                        n/a
Other operating expenses                            623                          353                      270                       76  %
Total expenses and other                        166,011                      199,860                  (33,849)                     (17) %
Other (expenses) income:
Interest expense                                 (7,867)                      (7,729)                    (138)                       2  %
Other, net                                          (24)                         (42)                      18                      (43) %

Total other (expenses) income                    (7,891)                      (7,771)                    (120)                       2  %
Income before income taxes                      202,544                       45,499                  157,045                      345  %
Income tax expense                               10,884                        2,145                    8,739                      407  %
Net income                              $       191,660               $       43,354                $ 148,306                      342  %

Expenses per boe:(1)
Lease operating expenses                $         33.40               $        30.37                $    3.03                       10  %
Electricity generation expenses                    2.56                         2.57                    (0.01)                       -  %
Electricity sales(1)                              (4.10)                       (3.11)                   (0.99)                      32  %
Transportation expenses                            0.54                         0.46                     0.08                       17  %
Transportation sales(1)                           (0.12)                       (0.05)                   (0.07)                     140  %

Derivatives settlements received for
gas purchases(1)                                  (5.82)                       (4.27)                   (1.55)                      36  %
Total operating expenses                $         26.46               $        25.97                $    0.49                        2  %
Total unhedged operating expenses(2)    $         32.28               $        30.24                $    2.04                        7  %

Total non-energy operating expenses(3)  $         17.59               $        16.10                $    1.49                        9  %
Total energy operating expenses(4)      $          8.87               $         9.87                $   (1.00)                     (10) %

General and administrative expenses(5)  $          9.87               $         9.72                $    0.15                        2  %
Depreciation, depletion and             $         16.67               $        15.95
amortization                                                                                        $    0.72                        5  %
Taxes, other than income taxes          $          3.10               $         4.70                $   (1.60)                     (34) %


__________

(1)  We report electricity, transportation and marketing sales separately in our
financial statements as revenues in accordance with GAAP. However, these
revenues are viewed and used internally in calculating operating expenses which
is used to track and analyze the economics of development projects and the
efficiency of our hydrocarbon recovery. We purchase third-party gas to generate
electricity through our cogeneration facilities to be used in our field
operations activities and view the added benefit of any excess electricity sold
externally as a cost reduction/benefit to generating steam for our thermal
recovery operations. Marketing revenues and expenses mainly relate to natural
gas purchased from third parties that moves through our gathering and processing
systems and then is sold to third parties. Transportation sales relate to water
and other liquids that we transport on our systems on behalf of third parties
and have not been significant to date. Operating expenses also include the
effect of derivative settlements (received or paid) for gas purchases.

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(2) Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.

(3) Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.

(4) Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.

(5)  Includes non-recurring costs and non-cash stock compensation expense, in
aggregate, of approximately $1.81 per boe and $1.77 per boe for the three months
ended September 30, 2022 and June 30, 2022, respectively.

Expenses and Other

In accordance with GAAP, we report sales of electricity, marketing and transportation activities (as applicable) separately in our financial statements as revenues. However, these revenues are viewed and used internally in calculating operating expenses, which are used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery.

Operating expenses are defined above in "How We Plan and Evaluate Operations",
which include electricity, marketing and transportation revenues. On a hedged
basis, operating expenses increased by $0.49 per boe, or 2%, to $26.46 for the
third quarter of 2022 compared to the second quarter of 2022. During the third
quarter, non-energy operating expenses increased $1.49 per boe due to higher
seasonal power rates and other field operating costs. A portion of the increased
costs in non-energy operating expenses were driven by inflation. Energy
operating expense decreased $1.00 per boe in the third quarter compared to the
second quarter of 2022 due to higher electricity sales. Higher gas purchase
settlements mitigated the impact of higher purchase prices.

Unhedged lease operating expenses per boe increased by 10%, or $3.03, to $33.40
for the three months ended September 30, 2022, compared to $30.37 per boe for
the three months ended June 30, 2022, generally for the same reasons noted above
for non-energy expense. Unhedged average fuel purchase price per mmbtu increased
12% while consumption declined 3% in the third quarter compared to the second
quarter, which when combined resulted in a $1.09 per boe higher unhedged higher
fuel costs for our California steam operations.

Cost of services in 2022 consisted entirely of costs from the well servicing and
abandonment business. Cost of services increased by $1 million, or 3%, to $38
million in the third quarter of 2022, mainly due to higher activity, which is
partially driven by a seasonal impact.

Electricity generation expenses were relatively flat at $2.56 per boe for the
three months ended September 30, 2022, compared to $2.57 per boe for the three
months ended June 30, 2022.

Gains and losses on natural gas purchase derivatives resulted in a $29 million
gain for the three months ended September 30, 2022 and a loss of $11 million in
the three months ended June 30, 2022. Settlement gains for the three months
ended September 30, 2022 and June 30, 2022 were $14 million, or $5.82 per boe,
and $10 million, or $4.27 per boe, respectively, and increased due to higher
index prices relative to the derivative fixed prices of settled positions in the
third quarter of 2022 compared to the second quarter. The mark-to-market
valuation gain was $15 million for the three months ended September 30, 2022 and
a loss of $21 million for the three months ended June 30, 2022. Because we are
the fixed price payer on these natural gas swaps, generally, period to period
increases (decreases) in the associated price index create valuation gains
(losses).

Transportation expenses were comparable for the periods presented.

General and administrative expenses were flat at $23 million for the three
months ended September 30, 2022 and the three months ended June 30, 2022. For
the three months ended September 30, 2022 and June 30, 2022, general and
administrative expenses included non-cash stock compensation costs of
approximately $4.3 million. We incurred no non-recurring costs for the three
months ended September 30, 2022 and June 30, 2022. Less than 10% of our overhead
is capitalized and thus excluded from general and administrative expenses.

Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, were $19 million for the three months ended September 30, 2022, and was flat compared to the three months ended June 30, 2022. See "-Non-GAAP Financial Measures" for a reconciliation of adjusted general and administrative expense to general and administrative expenses, the most directly comparable financial measures

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calculated and presented in accordance with GAAP.

DD&A increased 4% to $40 million for the three months ended September 30, 2022
compared to the three months ended June 30, 2022. The increase was driven by the
mix of production in the D&P segment.

Taxes, Other Than Income Taxes

                                                   Three Months Ended
                                       September 30, 2022           June 30, 2022           $ Change               % Change
                                                        (per boe)
Severance taxes                       $        1.45               $         1.54          $    (0.09)                      (6) %
Ad valorem and property taxes                  1.48                         1.49               (0.01)                      (1) %
Greenhouse gas allowances                      0.17                         1.67               (1.50)                     (90) %

Total taxes other than income taxes   $        3.10               $         4.70          $    (1.60)                     (34) %


Taxes, other than income taxes, decreased in the three months ended September
30, 2022 by $1.60 per boe, or 34%, to $3.10. The reduction in third quarter 2022
greenhouse gas ("GHG") costs was a result of lower mark-to-market prices
compared to the second quarter of 2022. Severance taxes were lower in the third
quarter of 2022 due to lower revenue.

Other Operating Expenses

Other operating expenses were comparable for periods presented.

Interest Expense

Interest expense was relatively flat at $8 million for each of the three months ended September 30, 2022 and June 30, 2022.

Income Taxes

Our effective tax rate was comparable at approximately 5% for the three months ended September 30, 2022, and June 30, 2022.

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Three Months Ended September 30, 2022 compared to Three Months Ended September
30, 2021.

                                              Three Months Ended
                                                 September 30,
                                           2022                 2021              $ Change              % Change
                                                (in thousands)
Revenues and other:
Oil, natural gas and NGL sales        $   203,585          $   161,058          $  42,527                       26  %
Service revenue                            48,594                    -             48,594                      100  %
Electricity sales                           9,711               12,371             (2,660)                     (22) %
Gains (losses) on oil and gas sales
derivatives                               114,279              (30,864)           145,143                         n/a
Marketing and other revenues                  277                  849               (572)                     (67) %
Total revenues and other              $   376,446          $   143,414          $ 233,032                      162  %


Revenues and Other

Oil, natural gas and NGL sales increased by $43 million, or 26%, to approximately $204 million for the three months ended September 30, 2022 when compared to the three months ended September 30, 2021. This variance was principally the result of higher unhedged commodity prices.

Service revenue in the third quarter 2022 was $49 million and there was no corresponding revenue in the third quarter 2021 as we acquired this business on October 1, 2021.

Electricity sales represent sales to utilities, and decreased by approximately
$3 million, or 22%, to approximately $10 million for the three months ended
September 30, 2022 when compared to the three months ended September 30, 2021.
The decrease was largely due to lower unit sales volumes driven by the sale of
our Placerita asset, which included our largest electricity-generating
cogeneration facility ("cogen"), in the fourth quarter 2021. For the three years
prior to divestiture the Placerita cogen accounted for approximately 41% of our
electrical sales.

Gain or loss on oil and gas sales derivatives consists of settlement gains and
losses and mark-to-market gains and losses. Our settlement losses for the three
months ended September 30, 2022 and the three months ended September 30, 2021
were $29 million and $32 million, respectively. The quarter-over-quarter
decrease in settlement losses were driven by lower oil prices relative to our
derivative fixed prices in the third quarter of 2022 than that of the same
period in 2021. Notional volumes were 15 mbbl/d in the third quarter 2022 and 14
mbbls/d in the third quarter 2021. The mark-to-market non-cash gain was $143
million and $1 million for the three months ended September 30, 2022 and
September 30, 2021, respectively, due to a narrower spread between future market
prices and the fixed price at the end of the quarter compared to that of the
respective previous quarter. Because we are the floating price payer on these
swaps, generally, period to period decreases (increases) in the associated price
index create valuation gains (losses).

Marketing and other revenues were not material for the three months ended September 30, 2022 and September 30, 2021.

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                                                  Three Months Ended
                                                     September 30,
                                               2022                   2021              $ Change              % Change
                                        (in thousands, except expenses per boe)
Expenses and other:
Lease operating expenses                $        79,141          $    60,930          $  18,211                       30  %
Costs of services                                37,628                    -             37,628                      100  %
Electricity generation expenses                   6,055                7,128             (1,073)                     (15) %
Transportation expenses                           1,277                1,806               (529)                     (29) %
Marketing expenses                                    -                  715               (715)                    (100) %
General and administrative expenses              23,388               17,614              5,774                       33  %
Depreciation, depletion and                      39,506               35,902                                          10  %
amortization                                                                              3,604

Taxes, other than income taxes                    7,335               13,420             (6,085)                     (45) %

Gains on natural gas purchase
derivatives                                     (28,942)             (14,980)           (13,962)                      93  %
Other operating expenses                            623                3,986             (3,363)                     (84) %
Total expenses and other                        166,011              126,521             39,490                       31  %
Other (expenses) income:
Interest expense                                 (7,867)              (7,810)               (57)                       1  %
Other, net                                          (24)                  (5)               (19)                     380  %

Total other (expenses) income                    (7,891)              (7,815)               (76)                       1  %
Income before income taxes                      202,544                9,078            193,466                    2,131  %
Income tax expense (benefit)                     10,884                 (758)            11,642                   (1,536) %
Net income                              $       191,660          $     9,836          $ 181,824                   (1,849) %

Expenses per boe:(1)
Lease operating expenses                $         33.40          $     24.20          $    9.20                       38  %
Electricity generation expenses                    2.56                 2.83              (0.27)                     (10) %
Electricity sales(1)                              (4.10)               (4.91)              0.81                      (16) %
Transportation expenses                            0.54                 0.72              (0.18)                     (25) %
Transportation sales(1)                           (0.12)               (0.05)             (0.07)                     140  %
Marketing expenses                                    -                 0.28              (0.28)                    (100) %
Marketing revenues(1)                                 -                (0.29)              0.29                     (100) %
Derivatives settlements received for                                                                                   4  %
gas purchases(1)                                  (5.82)               (5.60)             (0.22)
Total operating expenses                $         26.46          $     17.18          $    9.28                       54  %

Total unhedged operating expenses(2) $ 32.28 $ 22.78 $ 9.50

                       42  %

Total non-energy operating expenses(3) $ 17.59 $ 13.59 $ 4.00

                       29  %

Total energy operating expenses(4) $ 8.87 $ 3.59 $ 5.28

                      147  %

General and administrative expenses(5) $ 9.87 $ 6.99 $ 2.88

                       41  %
Depreciation, depletion and             $         16.67          $     14.25          $    2.42                       17  %

amortization

Taxes, other than income taxes          $          3.10          $      5.33          $   (2.23)                     (42) %


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(1)  We report electricity, transportation and marketing sales separately in our
financial statements as revenues in accordance with GAAP. However, these
revenues are viewed and used internally in calculating operating expenses which
is used to track and analyze the economics of development projects and the
efficiency of our hydrocarbon recovery. We purchase third-party gas to generate
electricity through our cogeneration facilities to be used in our field
operations activities and view the added benefit of any excess electricity sold
externally as a cost reduction/benefit to generating steam for our thermal
recovery operations. Marketing revenues and expenses mainly relate to natural
gas purchased from third parties that moves through our gathering and processing
systems and then is sold to third parties. Transportation sales relate to water
and other liquids that we transport on our systems on behalf of third parties
and have not been significant to date. Operating expenses also include the
effect of derivative settlements (received or paid) for gas purchases.

(2) Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.

(3) Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.

(4) Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.

(5)  Includes non-recurring costs and non-cash stock compensation expense, in
aggregate, of approximately $1.81 per boe and $1.66 per boe for the three months
ended September 30, 2022 and September 30, 2021, respectively.

Expenses and Other

On a hedged basis, operating expenses, increased by 54%, or $9.28 per boe, to
$26.46 per boe for the third quarter of 2022 compared to $17.18 per boe for the
third quarter of 2021. This increase was due to higher energy operating expense
of $5.28 per boe and non-energy operating expense of $4.00 per boe. Energy
operating expense increased largely due to higher hedged natural gas purchase
prices. Non-energy operating expense increased due to higher power rates and
other field operating costs. A portion of the increased costs in non-energy
operating expenses were driven by inflation.

Unhedged lease operating expenses were $33.40 per boe for the three months ended
September 30, 2022, a 38% or $9.20 per boe increase compared to $24.20 for the
three months ended September 30, 2021. Unhedged fuel costs for our California
steam operations increased $4.97 per boe. Unhedged average fuel purchase price
per mmbtu increased 41% in the third quarter of 2022 compared to the third
quarter of 2021 and gas volumes purchased were down 11%. Non-fuel lease
operating expense increased $4.23 per boe, generally for the same reasons noted
above for non-energy operating expense.

Cost of services in the third quarter of 2022 were $38 million and there were no costs of services in the third quarter of 2021, as we acquired the well servicing and abandonment business on October 1, 2021.

Electricity generation expenses decreased approximately 10% to $2.56 per boe for
the three months ended September 30, 2022 from $2.83 per boe for the same period
in 2021 due to the Placerita properties sale, partially offset by higher natural
gas costs. Fuel costs included in electricity generation expenses exclude the
effects of natural gas derivative settlements.

Gains and losses on natural gas purchase derivatives for the three months ended
September 30, 2022 and September 30, 2021 resulted in a gain of $29 million and
$15 million, respectively. Settlement gains for the three months ended September
30, 2022 and September 30, 2021 were $14 million in each period, or $5.82 per
boe and $5.60 per boe, respectively. The mark-to-market non-cash gain was $15
million and $1 million for the three months ended September 30, 2022 and
September 30, 2021, respectively, due to a larger spread between future market
prices and the derivative fixed price at the end of the quarter compared to that
of the respective previous quarter. Because we are the fixed price payer on
these natural gas swaps, generally, period to period increases (decreases) in
the associated price index create valuation gains (losses).

Transportation expenses decreased to $0.54 per boe for the three months ended
September 30, 2022 compared to $0.72 per boe for the three months ended
September 30, 2021, primarily due to the sale of our Piceance operations the
first quarter of 2022.

Marketing expenses were not material for the three months ended September 30, 2022 and September 30, 2021.

General and administrative expenses increased $6 million, or 33%, to
approximately $23 million for the three months ended September 30, 2022 compared
to the three months ended September 30, 2021. For the three months ended
September 30, 2022 and September 30, 2021, general and administrative expenses
included non-cash stock

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compensation costs of approximately $4 million in each period. We incurred approximately $0.7 million related to the CJWS acquisition which have been categorized as non-recurring for the three months ended September 30, 2021. There were no non-recurring expenses in the same period of 2022. The third quarter of 2022 also included $3 million of general and administrative expenses from the well servicing and abandonment segment which had no corresponding amount in 2021 as we purchased CJWS in the fourth quarter of 2021.

Adjusted general and administrative expenses, which exclude non-cash stock
compensation costs and non-recurring costs, increased 46% to $19 million for the
three months ended September 30, 2022 compared to $13 million for the three
months ended September 30, 2021. The substantial majority of the increase was
due to the acquisition of CJWS, as well as higher legal and other professional
service expenses and employee costs.

DD&A for the third quarter of 2022 increased approximately $4 million to $40
million when compared to the third quarter of 2021 driven primarily by CJWS and
slightly higher DD&A rates for the D&P segment, partially offset by lower
production.

Taxes, Other Than Income Taxes

                                             Three Months Ended
                                               September 30,
                                              2022             2021       $ Change      % Change
                                                 (per boe)
Severance taxes                        $     1.45            $ 0.80      $   0.65           81  %
Ad valorem and property taxes                1.48              1.73         (0.25)         (14) %
Greenhouse gas allowances                    0.17              2.80         (2.63)         (94) %
Total taxes other than income taxes    $     3.10            $ 5.33      $  

(2.23) (42) %

Taxes, other than income taxes decreased 42% to $3.10 per boe for the three
months ended September 30, 2022 compared to $5.33 per boe for the three months
ended September 30, 2021. Severance taxes increased due to higher production and
prices in Utah, while property taxes were lower due to the divestitures of
Piceance and Placerita. GHG expense was significantly lower, largely due to
lower emissions which resulted from the divestiture of Placerita and its
cogeneration facility, as well as lower prices.

Other Operating Expenses (Income)

Other operating expenses decreased $3 million or 84% to less than $1 million for
the three months ended September 30, 2022 when compared to the same quarter in
2021. The decrease is primarily due to $3 million of unamortized debt issuance
costs related to the termination of the 2017 RBL facility incurred in three
months ended September 30, 2021.

Interest Expense

Interest expense was comparable in the three months ended September 30, 2022 and September 30, 2021.

Income Taxes

Our effective tax rate was approximately 5% for the three months ended September
30, 2022 compared to (8)% for the three months ended September 30, 2021. The
rates were impacted by changes in the valuation allowance recorded against
deferred tax assets.

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Nine Months Ended September 30, 2022 compared to Nine Months Ended September 30,
2021.
                                              Nine Months Ended
                                                September 30,
                                             2022           2021         $ Change       % Change
                                                (in thousands)
Revenues and other:
Oil, natural gas and NGL sales            $ 654,007      $ 444,098      $ 209,909           47  %
Service revenue                             134,608              -        134,608          100  %
Electricity sales                            22,549         29,328         (6,779)         (23) %
Losses on oil and gas sales derivatives     (88,237)      (140,021)        51,784          (37) %
Marketing and other revenues                    731          3,459         (2,728)         (79) %
Total revenues and other                  $ 723,658      $ 336,864      $ 386,794          115  %


Revenues and Other

Oil, natural gas and NGL sales increased by $210 million, or 47%, to
approximately $654 million for the nine months ended September 30, 2022 when
compared to the nine months ended September 30, 2021. The increase was driven by
higher realized prices, partially offset by pricing discounts applied to
approximately 25% of third quarter California volumes due to an unexpected third
party pipeline outage for unplanned repairs during most of the third quarter of
2022.

Service revenue consisted entirely of revenue from the well servicing and abandonment business we acquired on October 1, 2021, thus no prior period revenue.

Electricity sales, which represent sales to utilities, decreased $7 million, or
23%, to $23 million for the nine months ended September 30, 2022 when compared
to the nine months ended September 30, 2021. The decrease was primarily due to
lower sales volume as a result of the sale of a cogeneration facility which was
part of the Placerita divestiture in late 2021.

Gain or loss on oil and gas sales derivatives consists of settlement gains and
losses and mark-to-market gains and losses. We had settlement losses of $110
million and $96 million for the nine months ended September 30, 2022 and the
nine months ended September 30, 2021, respectively. The period over period
increase in settlement losses was driven by a wider spread between the settled
derivative fixed prices and index oil prices in the nine months ended September
30, 2022 compared to the same period of 2021. Partially offsetting this effect,
notional volumes decreased to 14 mbbl/d in the nine months ended September 30,
2022 from 17 mbbl/d in the nine months ended September 30, 2021. The
mark-to-market non-cash gain of $22 million for the nine months ended September
30, 2022 was the result of lower futures prices relative to the derivative fixed
prices. Conversely, the $44 million loss in the same period of 2021 was due to
higher futures prices relative to the derivative fixed prices, as measured at
the end of their respective periods. Because we are the floating price payer on
these swaps, generally, period to period decreases (increases) in the associated
price index create valuation gains (losses).

Marketing and other revenues decreased approximately $3 million for the nine
months ended September 30, 2022 when compared to the nine months ended September
30, 2021 due to the sale of our Piceance Colorado operations in the fourth
quarter of 2021, which included third-party marketing activities. Piceance has
historically accounted for nearly all of our marketing revenues.

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                                                  Nine Months Ended
                                                    September 30,
                                              2022                  2021              $ Change              % Change
                                         (in thousands, except expenses per
                                                        boe)
Expenses and other:
Lease operating expenses                $     214,720          $   168,756          $  45,964                       27  %
Costs of services                             107,809                    -            107,809                      100  %
Electricity generation expenses                16,640               19,488             (2,848)                     (15) %
Transportation expenses                         3,543                5,139             (1,596)                     (31) %
Marketing expenses                                299                2,986             (2,687)                     (90) %
General and administrative expenses            69,513               50,749             18,764                       37  %
Depreciation, depletion and                   117,338              105,592
amortization                                                                           11,746                       11  %

Taxes, other than income taxes                 25,154               34,580             (9,426)                     (27) %

Gains on natural gas purchase
derivatives                                   (47,335)             (54,349)             7,014                      (13) %
Other operating expenses                        4,745                4,827                (82)                      (2) %
Total expenses and other                      512,426              337,768            174,658                       52  %
Other (expenses) income:
Interest expense                              (23,271)             (24,513)             1,242                       (5) %
Other, net                                        (79)                (156)                77                      (49) %

Total other (expenses) income                 (23,350)             (24,669)             1,319                       (5) %
Income (loss) before income taxes             187,882              (25,573)           213,455                     (835) %
Income tax expense (benefit)                    9,678               (1,206)            10,884                     (902) %
Net income (loss)                       $     178,204          $   (24,367)         $ 202,571                     (831) %

Expenses per boe:(1)
Lease operating expenses                $       29.99          $     22.69          $    7.30                       32  %
Electricity generation expenses                  2.32                 2.62              (0.30)                     (11) %
Electricity sales(1)                            (3.15)               (3.94)              0.79                      (20) %
Transportation expenses                          0.49                 0.69              (0.20)                     (29) %
Transportation sales(1)                         (0.06)               (0.05)             (0.01)                      20  %
Marketing expenses                               0.04                 0.40              (0.36)                     (90) %
Marketing revenues(1)                           (0.04)               (0.42)              0.38                      (90) %
Derivatives settlements received for            (3.58)               (5.68)              2.10                      (37) %
gas purchases(1)
Total operating expenses                $       26.01          $     16.31          $    9.70                       59  %

Total unhedged operating expenses(2) $ 29.59 $ 21.99

         $    7.60                       35  %

Total non-energy operating expenses(3) $ 15.74 $ 13.02

         $    2.72                       21  %

Total energy operating expenses(4) $ 10.27 $ 3.29

         $    6.98                      212  %

General and administrative expenses(5) $ 9.71 $ 6.82

         $    2.89                       42  %
Depreciation, depletion and             $       16.39          $     14.20          $    2.19                       15  %

amortization

Taxes, other than income taxes $ 3.51 $ 4.65

        $   (1.14)                     (25) %


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(1)  We report electricity, transportation and marketing sales separately in our
financial statements as revenues in accordance with GAAP. However, these
revenues are viewed and used internally in calculating operating expenses which
is used to track and analyze the economics of development projects and the
efficiency of our hydrocarbon recovery. We purchase third-party gas to generate
electricity through our cogeneration facilities to be used in our field
operations activities and view the added benefit of any excess electricity sold
externally as a cost reduction/benefit to generating steam for our thermal
recovery operations. Marketing revenues and expenses mainly relate to natural
gas purchased from third parties that moves through our gathering and processing
systems and then is sold to third parties. Transportation sales relate to water
and other liquids that we transport on our systems on behalf of third parties
and have not been significant to date. Operating expenses also include the
effect of derivative settlements (received or paid) for gas purchases.

(2) Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.

(3) Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.

(4) Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.

(5)  Includes non-recurring costs and non-cash stock compensation expense, in
aggregate, of approximately $1.71 per boe and $1.43 per boe for the nine months
ended September 30, 2022 and September 30, 2021, respectively.

Expenses and Other

On a hedged basis, operating expenses increased 59%, or $9.70 per boe, to $26.01
for the nine months ended September 30, 2022 from $16.31 per boe for the nine
months ended September 30, 2021. This increase was due to higher energy
operating expense of $6.98 per boe and non-energy operating expense of $2.72 per
boe. Energy operating expense increased primarily due to higher hedged purchased
natural gas costs. Non-energy operating expense increased largely due to higher
power rates and other lease operating expenses noted below, including inflation,
in the nine months ended September 30, 2022 compared to same period of 2021.

Unhedged lease operating expenses were $29.99 per boe for the nine months ended
September 30, 2022, a 32% or $7.30 per boe increase compared to $22.69 for the
nine months ended September 30, 2021, driven by higher unhedged fuel costs for
our California steam operations. Unhedged average fuel purchase price per mmbtu
increased 36% in the nine months ended September 30, 2022 compared to the nine
months ended September 30, 2021. Non-fuel lease operating expense increased
$3.12 per boe in the nine months ended September 30, 2022 when compared to the
same period of 2021. Key increases included higher workover and field monitoring
activity associated with our field optimization program, and higher well and
surface facilities maintenance and power costs. A portion of these higher costs
were driven by inflation.

Cost of services in 2022 consisted entirely of costs from the well servicing and abandonment business we acquired on October 1, 2021, thus no prior period costs.

Electricity generation expenses decreased approximately 11% to $2.32 per boe for
the nine months ended September 30, 2022 from $2.62 per boe for the same period
in 2021 due to lower volumes sold resulting from the previously discussed sale
of a cogeneration facility, more than offsetting the increase in fuel prices.
Fuel costs included in electricity generation expenses exclude the effects of
natural gas derivative settlements.

Gains and losses on natural gas purchase derivatives for the nine months ended
September 30, 2022 and September 30, 2021 consisted of gains of $47 million and
$54 million, respectively. The settlement gain for the nine months ended
September 30, 2022 was $26 million, or $3.58 per boe, compared to a gain of $42
million, or $5.68 per boe, for same period in 2021, driven by lower hedged
volumes in 2022 compared to that of 2021. The mark-to-market valuation gain for
the nine months ended September 30, 2022 was $22 million compared to $12 million
for the same period in 2021 due to more open notional volumes at September 30,
2022 and higher futures prices relative to our derivative fixed prices compared
to those at September 30, 2021. Because we are the fixed price payer on these
natural gas swaps, generally, increases in the associated price index above the
swap fixed price creates valuation gains.

Transportation expenses declined primarily due to the divestiture of our Piceance properties in early 2022.

Marketing expenses decreased approximately $3 million for the nine months ended
September 30, 2022 when compared to the nine months ended September 30, 2021 due
to the sale of our Piceance Colorado operations in the fourth quarter 2021,
which included third-party marketing activities. Piceance has historically
accounted for nearly all of our marketing revenues.

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General and administrative expenses increased $19 million, or 37%, to
approximately $70 million for the nine months ended September 30, 2022 compared
to the nine months ended September 30, 2021. The majority of the increase was
from the acquisition of CJWS in October of 2021; therefore, the comparable
period of last year had no such expenses. For the nine months ended September
30, 2022 and September 30, 2021, general and administrative expenses included
non-cash stock compensation costs of approximately $12 million and $10 million,
respectively. We incurred approximately $0.7 million related to the CJWS
acquisition which have been categorized as non-recurring for the nine months
ended September 30, 2021. There was approximately $0.2 million of non-recurring
expenses in the same period of 2022.

Adjusted general and administrative expenses, which exclude non-cash stock
compensation costs and non-recurring costs, increased $17 million, or 42%, to
$57 million for the nine months ended September 30, 2022 compared to $40 million
for the nine months ended September 30, 2021. A substantial majority of the
year-over-year increase was due to the CJWS acquisition, as well as employee
cost inflation and higher professional services expenses.

DD&A increased $12 million, or 11%, to approximately $117 million for the nine
months ended September 30, 2022 compared to the nine months ended September 30,
2021. The CJWS acquisition increased depreciation by $9 million with the balance
of the increase from slightly higher depletion rates in the D&P segment.

Taxes, Other Than Income Taxes

                                             Nine Months Ended
                                               September 30,
                                             2022             2021       $ Change      % Change
                                                 (per boe)
Severance taxes                        $     1.42           $ 0.92      $   0.50           54  %
Ad valorem and property taxes                1.49             1.91         (0.42)         (22) %
Greenhouse gas allowances                    0.60             1.82         (1.22)         (67) %
Total taxes other than income taxes    $     3.51           $ 4.65      $  

(1.14) (25) %

Taxes, other than income taxes decreased 25% to $3.51 per boe for the nine
months ended September 30, 2022 compared to $4.65 per boe for the nine months
ended September 30, 2021. Severance taxes increased due to higher production and
prices in Utah, while property taxes were lower due to the divestitures of
Piceance and Placerita. GHG expense decreased due to lower emissions from the
divestiture of Placerita and its cogeneration facility and allowances we
acquired at comparatively lower prices.

Other Operating Expenses (Income)

For the nine months ended September 30, 2022, other operating expenses were
$5 million and mainly consisted of over $2 million in royalty audit charges
incurred prior to our emergence and restructuring in 2017 and approximately
$2 million loss on the divestiture of the Piceance properties. For the nine
months ended September 30, 2021, other operating expenses were $5 million and
mainly consisted of approximately $3 million of unamortized debt issuance costs
related to the termination of the 2017 RBL Facility, approximately $3 million of
supplemental property tax assessments, royalty audit charges and tank rental
costs and $1 million of various other costs such as abandonment costs and legal
fees, partially offset by $2 million of income from employee retention credits.

Interest Expense

Interest expense decreased 5% in the nine months ended September 30, 2022 compared to the same period in 2021 as we had lower intra-period working capital borrowings on the 2021 RBL Facility in 2022.

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Income Taxes

Our effective tax rate was 5% for the nine months ended September 30, 2022 and September 30, 2021, respectively. The rates were impacted by changes in the valuation allowance recorded against deferred tax assets.

Non-GAAP Financial Measures

Adjusted EBITDA, Adjusted Net Income (Loss), Adjusted General and Administrative Expenses and Discretionary Free Cash Flow

Adjusted Net Income (Loss) is not a measure of net income (loss), and
Discretionary Free Cash Flow is not a measure of cash flow, and Adjusted EBITDA
is not a measure of either, in all cases, as determined by GAAP. Adjusted
EBITDA, Adjusted Net Income (Loss) and Discretionary Free Cash Flow are
supplemental non-GAAP financial measures used by management and external users
of our financial statements, such as industry analysts, investors, lenders and
rating agencies.

We define Adjusted EBITDA as earnings before interest expense; income taxes;
depreciation, depletion, and amortization; derivative gains or losses net of
cash received or paid for scheduled derivative settlements; impairments; stock
compensation expense; and unusual and infrequent items.

Our management believes Adjusted EBITDA provides useful information in assessing
our financial condition, results of operations and cash flows and is widely used
by the industry and the investment community. The measure also allows our
management to more effectively evaluate our operating performance and compare
the results between periods without regard to our financing methods or capital
structure. We also use Adjusted EBITDA in planning our capital allocation to
sustain production levels and to determine our strategic hedging needs aside
from the hedging requirements of the 2021 RBL Facility.

Adjusted Net Income (Loss) excludes the impact of unusual and infrequent items
affecting earnings that vary widely and unpredictably, including non-cash items
such as derivative gains and losses. This measure is used by management when
comparing results period over period. We define Adjusted Net Income (Loss) as
net income (loss) adjusted for derivative gains or losses net of cash received
or paid for scheduled derivative settlements, other unusual and infrequent
items, and the income tax expense or benefit of these adjustments using our
effective tax rate.

We define Discretionary Free Cash Flow as cash flow from operations less regular
fixed dividends and the capital needed to hold production flat. We expect to
allocate 60% of Discretionary Free Cash Flow predominantly in the form of cash
variable dividends, as well as opportunistic debt repurchases. The remaining 40%
will be used for opportunistic growth, including from our extensive inventory of
drilling opportunities, advancing our short- and long-term sustainability
initiatives, share repurchases, and/or capital retention. Our management
believes Discretionary Free Cash Flow provides useful information in assessing
our financial condition, and is the primary metric to determine the quarterly
variable dividend.

Adjusted General and Administrative Expenses is a supplemental non-GAAP
financial measure that is used by management and external users of our financial
statements, such as industry analysts, investors, lenders and rating
agencies. We define Adjusted General and Administrative Expenses as general and
administrative expenses adjusted for non-cash stock compensation expense and
unusual and infrequent costs. Management believes Adjusted General and
Administrative Expenses is useful because it allows us to more effectively
compare our performance from period to period.

We exclude the items listed above from general and administrative expenses in
arriving at Adjusted General and Administrative Expenses because these amounts
can vary widely and unpredictably in nature, timing, amount and frequency and
stock compensation expense is non-cash in nature.

While Adjusted EBITDA, Adjusted Net Income (Loss), Adjusted General and Administrative Expenses and Discretionary Free Cash Flow are non-GAAP measures, the amounts included in the calculation of Adjusted

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EBITDA, Adjusted Net Income (Loss), Adjusted General and Administrative Expenses
and Discretionary Free Cash Flow were computed in accordance with GAAP. These
measures are provided in addition to, and not as an alternative for, income and
liquidity measures calculated in accordance with GAAP and should not be
considered as an alternative to, or more meaningful than income and liquidity
measures calculated in accordance with GAAP. Certain items excluded from
Adjusted EBITDA are significant components in understanding and assessing our
financial performance, such as our cost of capital and tax structure, as well as
the historic cost of depreciable and depletable assets. Our computations of
Adjusted EBITDA, Adjusted Net Income (Loss), Adjusted General and Administrative
Expenses and Discretionary Free Cash Flow may not be comparable to other
similarly titled measures used by other companies. Adjusted EBITDA, Adjusted Net
Income (Loss), Adjusted General and Administrative Expenses and Discretionary
Free Cash Flow should be read in conjunction with the information contained in
our financial statements prepared in accordance with GAAP.

The following tables present reconciliations of the non-GAAP financial measures
Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash
provided or used by operating activities, as applicable, for each of the periods
indicated.

                                                          Three Months Ended                                        Nine Months Ended
                                       September 30,           June 30,           September 30,           September 30,           September 30,
                                           2022                  2022                 2021                    2022                    2021
                                                                                    (in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)                    $      191,660          $  43,354          $        9,836          $      178,204          $      (24,367)
Add (Subtract):
Interest expense                              7,867              7,729                   7,810                  23,271                  24,513
Income tax expense (benefit)                 10,884              2,145                    (758)                  9,678                  (1,206)
Depreciation, depletion and                  39,506             38,055                  35,902                 117,338                 105,592

amortization

(Gains) losses on derivatives              (143,221)            51,319                  15,885                  40,902                  85,672
Net cash paid for scheduled                 (14,739)           (37,628)                (17,622)                (84,519)                (54,204)
derivative settlements
Other operating expenses                        623                353                   3,986                   4,745                   4,827
Stock compensation expense                    4,401              4,420                   3,580                  12,623                  10,219
Non-recurring costs                               -                  -                     705                     198                     705

Adjusted EBITDA                      $       96,981          $ 109,747          $       59,324          $      302,440          $      151,751


                                                          Three Months Ended                                        Nine Months Ended
                                       September 30,           June 30,           September 30,           September 30,           September 30,
                                           2022                  2022                 2021                    2022                    2021
                                                                                    (in thousands)
Adjusted EBITDA reconciliation to net cash provided by operating activities:
Net cash provided by operating       $       95,762          $ 111,242          $       22,399          $      255,534          $       82,258
activities
Add (Subtract):
Cash interest payments                       14,493                449                  14,189                  29,481                  29,114
Cash income tax payments                        321              2,484                     294                   2,805                     294

Non-recurring costs                               -                  -                     705                     198                     705

Other changes in operating assets           (13,595)            (4,428)                 21,737                  14,422                  39,380
and liabilities

Adjusted EBITDA                      $       96,981          $ 109,747          $       59,324          $      302,440          $      151,751


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The following table presents a reconciliation of the non-GAAP financial measure
Discretionary Free Cash Flow to the GAAP financial measure of operating cash
flow for each of the periods indicated.

                                          Three Months Ended                Nine Months Ended
                                September 30, 2022      June 30, 2022       September 30, 2022
                                                        (in thousands)
Discretionary Free Cash Flow:
Operating cash flow(1)         $           95,762      $      111,242      $          255,534
Subtract:
Maintenance capital(2)(3)                 (38,312)            (32,134)                (96,883)
Fixed dividends(4)                         (4,726)             (4,726)                (14,688)
Discretionary Free Cash Flow   $           52,724      $       74,382      $          143,963


__________
(1)  On a consolidated basis.

(2)  D&P business only.

(3)  Maintenance capital is the capital required to keep annual production flat,
calculated as the capital expenditures for the D&P business during the period
presented.

(4) Represents fixed dividends declared which are included in the "Dividends declared on common stock" line in the the consolidated statement of stockholders' equity.

Discretionary Free Cash Flow was $53 million in the third quarter of 2022
compared to $74 million in the second quarter of 2022. The key drivers of the
lower Discretionary Free Cash Flow in the third quarter included the $14 million
semi-annual interest payment and a $6 million increase in maintenance capital.
The quarterly variable dividend is 60% of Discretionary Free Cash Flow based on
our shareholder return model which began in 2022.

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The following table presents a reconciliation of the non-GAAP financial measure
Adjusted Net Income (Loss) to the GAAP financial measure of net income (loss).

                                                         Three Months Ended                                        Nine Months Ended
                                       September 30,          June 30,           September 30,           September 30,           September 30,
                                           2022                 2022                 2021                    2022                    2021
                                                                                   (in thousands)
Adjusted Net Income (Loss) reconciliation to net income (loss):
Net income (loss)                    $      191,660          $ 43,354          $        9,836          $      178,204          $      (24,367)

Add (Subtract):
(Gains) losses on derivatives              (143,221)           51,319                  15,885                  40,902                  85,672
Net cash paid for scheduled                 (14,739)          (37,628)                (17,622)                (84,519)                (54,204)
derivative settlements
Other operating expenses                        623               353                   3,986                   4,745                   4,827

Non-recurring costs                               -                 -                     705                     198                     705

Total additions, net                       (157,337)           14,044                   2,954                 (38,674)                 37,000
Income tax benefit (expense) of
adjustments and discrete income tax          11,192            (4,262)                 (1,254)                  1,992                  (1,765)
items
Adjusted Net Income                  $       45,515          $ 53,136          $       11,536          $      141,522          $       10,868

Basic EPS on Adjusted Net Income $ 0.58 $ 0.67

$ 0.14 $ 1.78 $ 0.14 Diluted EPS on Adjusted Net Income $ 0.55 $ 0.64

$ 0.14 $ 1.70 $ 0.13

Weighted average shares of common               78,044            79,596                  80,242               79,304                  80,277
stock outstanding - basic
Weighted average shares of common               82,045            83,015                  82,898               83,472                  82,715
stock outstanding - diluted


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The following table presents a reconciliation of the non-GAAP financial measure
Adjusted General and Administrative Expenses to the GAAP financial measure of
general and administrative expenses for each of the periods indicated.

                                                           Three Months Ended                                           Nine Months Ended
                                         September 30,          June 30,           September 30,              September 30,           September 30,
                                             2022                 2022                 2021                       2022                    2021
                                                                              (in thousands)
Adjusted General and Administrative Expense reconciliation to general and
administrative expenses:
General and administrative expenses    $       23,388          $ 23,183          $       17,614             $       69,513          $       50,749

Subtract:

Non-cash stock compensation expense            (4,281)           (4,263)                 (3,467)                   (12,250)                 (9,899)
(G&A portion)
Non-recurring costs                                 -                 -                    (705)                      (198)                   (705)

Adjusted general and administrative $ 19,107 $ 18,920

      $       13,442             $       57,065          $       40,145

expenses

Development and production segment, $ 15,783 $ 15,635

      $       13,442             $       47,386          $       40,145
and corporate
Development and production segment,    $         6.66          $   6.55          $         5.34             $         6.62          $         5.40
and corporate per $/boe
Well servicing and abandonment segment $        3,324          $  3,285          $            -             $        9,679          $            -



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Liquidity and Capital Resources

Currently, we expect to fund the remainder of our 2022 capital expenditures with
cash flows from our operations. As of September 30, 2022, we had liquidity of
$256 million, consisting of $48 million cash on hand, $193 million available for
borrowings under our 2021 RBL Facility and $15 million available for borrowings
under our 2022 ABL Facility (as defined below). We also have $400 million in
aggregate principal amount 7% senior unsecured notes due February 2026 (the
"2026 Notes") outstanding as further discussed below.

In accordance with our shareholder return model, which went into effect January
1, 2022, we increased cash returns to our shareholders, further demonstrating
our commitment to be a leading returner of capital to our shareholders. The
model is based on our Discretionary Free Cash Flow, which is defined as cash
flow from operations less regular fixed dividends and the capital needed to hold
oil and gas production flat. See "Management's Discussion and Analysis-Non-GAAP
Financial Measures" for reconciliation of Discretionary Free Cash Flow to cash
provided by operating activities, our most directly comparable financial measure
calculated and presented in accordance with GAAP. Under this model, the company
intends to allocate Discretionary Free Cash Flow on a quarterly basis as
follows: (a) 60% predominantly in the form of variable cash dividends to be paid
quarterly, as well as opportunistic debt repurchases; (b) 40% in the form of
discretionary capital, to be used for opportunistic growth, including from our
extensive inventory of drilling opportunities, advancing our short- and
long-term sustainability initiatives, share repurchases, and/or capital
retention.

We currently believe that our liquidity, capital resources and cash on hand will
be sufficient to conduct our business and operations for at least the next 12
months. In the longer term, if oil prices were to significantly decline and
remain weak, we may not be able to continue to generate the same level of
Discretionary Free Cash Flow we are currently generating and our liquidity and
capital resources may not be sufficient to conduct our business and operations
until commodity prices recover. Please see Part II, Item 1A "Risk Factors" for a
discussion of known material risks, many of which are beyond our control, that
could adversely impact our business, liquidity, financial condition, and results
of operations.

2021 RBL Facility

On August 26, 2021, Berry Corp, as a guarantor, together with Berry LLC, as the
borrower, entered into a credit agreement that provided for a revolving loan
with up to $500 million of commitment, subject to a reserve borrowing base (as
amended by the First Amendment, the Second Amendment and the Third Amendment,
each as defined below, the "2021 RBL Facility"). Our initial borrowing base was
$200 million. The 2021 RBL Facility provides a letter of credit subfacility for
the issuance of letters of credit in an aggregate amount not to exceed
$20 million. Issuances of letters of credit reduce the borrowing availability
for revolving loans under the 2021 RBL Facility on a dollar for dollar basis.
The 2021 RBL Facility matures on August 26, 2025, unless terminated earlier in
accordance with the 2021 RBL Facility terms. Borrowing base redeterminations
generally become effective each May and November, although the borrower and the
lenders may each make one interim redetermination between scheduled
redeterminations. In December 2021, we completed the first scheduled semi-annual
borrowing base redetermination and entered into that certain First Amendment to
Credit Agreement (the "First Amendment"), which resulted in a reaffirmed
borrowing base at $200 million and changes to the hedging covenants in respect
of the exclusion of short puts or similar derivatives in the calculation of
minimum and maximum hedging requirements.

In May 2022, Berry Corp., as a guarantor, and Berry LLC, as the borrower,
entered into that certain Second Amendment to Credit Agreement and Limited
Consent and Waiver (the "Second Amendment") pursuant to which, among other
things, the requisite lenders under the 2021 RBL Facility (i) consented to
certain dividends and distributions and to certain investments made by Berry LLC
in C&J and/or C&J Management, in each case, as further described therein, (ii)
waived certain minimum hedging requirements for the time periods described
therein, (iii) waived any breach, default or event of default which may have
arisen as a result of any of the foregoing, (iv) amended the restricted payments
covenant to give us additional flexibility to make restricted payments, subject
to satisfaction of certain leverage and availability conditions and other
conditions described below and in the Second Amendment and (v) amended the
minimum hedging covenant to not, until October 1, 2022, require hedges for any
full calendar month from and after January 1, 2025, as further described in the
Second Amendment. In May 2022, we also completed our semi-annual borrowing base
redetermination and entered into the Third Amendment to the

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Credit Agreement (the "Third Amendment"), which among other things (1) increased
the borrowing base from $200 million to $250 million; (2) established the
Aggregate Elected Commitment Amounts (as defined in the 2021 RBL Facility) at
$200 million initially; and (3) converted all outstanding Eurodollar Loans (into
Term Benchmark Loans (each as defined in the 2021 RBL Facility) with an initial
interest period of one-month's duration and otherwise give effect to the
transition from the London interbank offered rate ("LIBOR") to the secured
overnight financing rate ("SOFR") by replacing the adjusted LIBOR rate with the
term SOFR rate for one, three or six months plus 0.1% (subject to a floor of
0.5%).

If the outstanding principal balance of the revolving loans and the aggregate
face amount of all letters of credit under the 2021 RBL Facility exceeds the
borrowing base at any time as a result of a redetermination of the borrowing
base, we have the option within 30 days to take any of the following actions,
either individually or in combination: make a lump sum payment curing the
deficiency, deliver reserve engineering reports and mortgages covering
additional oil and gas properties sufficient in certain lenders' opinion to
increase the borrowing base and cure the deficiency or begin making equal
monthly principal payments that will cure the deficiency within the next
six-month period. Upon certain adjustments to the borrowing base other than a
result of a redetermination, we are required to make a lump sum payment in an
amount equal to the amount by which the outstanding principal balance of the
revolving loans and the aggregate face amount of all letters of credit under the
2021 RBL Facility exceeds the borrowing base. In addition, the 2021 RBL Facility
provides that if there are any outstanding borrowings and the consolidated cash
balance exceeds $20 million at the end of each calendar week, such excess
amounts shall be used to prepay borrowings under the credit agreement.
Otherwise, any unpaid principal will be due at maturity.

The outstanding borrowings under the revolving loan bear interest at a rate
equal to either (i) a customary base rate plus an applicable margin ranging from
2.0% to 3.0% per annum, and (ii) a customary benchmark rate plus an applicable
margin ranging from 3.0% to 4.0% per annum, and in each case depending on levels
of borrowing base utilization. In addition, we must pay the lenders a quarterly
commitment fee of 0.5% on the average daily unused amount of the borrowing
availability under the 2021 RBL Facility. We have the right to prepay any
borrowings under the 2021 RBL Facility with prior notice at any time without a
prepayment penalty.

The 2021 RBL Facility requires us to maintain on a consolidated basis as of each
quarter-end (i) a leverage ratio of not more than 3.0 to 1.0 and (ii) a current
ratio of not less than 1.0 to 1.0. As of September 30, 2022, our leverage ratio
and current ratio were 1.2:1.0 and 2.3:1.0, respectively. In addition, the 2021
RBL Facility currently provides that, to the extent we incur unsecured
indebtedness, including any amounts raised in the future, the borrowing base
will be reduced by an amount equal to 25% of the amount of such unsecured debt.
We were in compliance with all financial covenants under the 2021 RBL Facility
as of September 30, 2022.

The 2021 RBL Facility contains usual and customary events of default and
remedies for credit facilities of a similar nature. The 2021 RBL Facility also
places restrictions on the borrower and its restricted subsidiaries with respect
to additional indebtedness, liens, dividends and other payments to shareholders,
repurchases or redemptions of our common stock, redemptions of the borrower's
senior notes, investments, acquisitions, mergers, asset dispositions,
transactions with affiliates, hedging transactions and other matters.

From and after August 26, 2022, the 2021 RBL Facility permits us to repurchase
certain indebtedness so long as both before and after giving pro forma effect to
such repurchase, no default or event of default exists, availability is equal to
or greater than 20% of the borrowing base and our pro forma leverage ratio is
less than or equal to 2.0 to 1.0. The 2021 RBL Facility also permits us to make
restricted payments so long as both before and after giving pro forma effect to
such distribution, no default or event of default exists, availability exceeds
75% of the borrowing base, and our pro forma leverage ratio is less than or
equal to 1.5 to 1.0. In addition, we can make other restricted payments in an
aggregate amount not to exceed 100% of Free Cash Flow (as defined under the 2021
RBL Facility) for the fiscal quarter most recently ended prior to such
distribution so long as, in addition to other conditions and limitations as
described in the 2021 RBL Facility, both before and after giving pro forma
effect to such distribution, no default or event of default exists, availability
is greater than 20% of the borrowing base and our pro forma leverage ratio is
less than or equal to 2.0 to 1.0.

Berry LLC is the borrower on the 2021 RBL Facility and Berry Corp. is the guarantor. Each future subsidiary of

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Berry Corp., with certain exceptions, is required to guarantee our obligations
and obligations of the other guarantors under the 2021 RBL Facility and under
certain hedging transactions and banking services arrangements (the "Guaranteed
Obligations"). The lenders under the 2021 RBL Facility hold a mortgage on at
least 90% of the present value of our proven oil and gas reserves. The
obligations of Berry LLC and the guarantors are also secured by liens on
substantially all of our personal property, subject to customary exceptions.

As of September 30, 2022, we had no borrowings outstanding, $7 million in letters of credit outstanding and approximately $193 million of available borrowing capacity under the 2021 RBL Facility.

2022 ABL Facility

On August 9, 2022, C&J and C&J Management, which are the two entities that
constitute the well servicing and abandonment segment referred to as CJWS, as
borrowers, entered into a credit agreement with Tri Counties Bank, as lender,
that provides for a revolving loan facility, subject to satisfaction of
customary conditions precedent to borrowing, of up to the lesser of (x)
$15 million and (y) the borrowing base ("the "2022 ABL Facility"). The
"borrowing base" is an amount equal to 80% percent of the balance due on
eligible accounts receivable, subject to reserves that Tri Counties Bank may
implement in its reasonable discretion. Interest on the outstanding principal
amount of the revolving loans under the 2022 ABL Facility accrues at a per annum
rate equal to 1.25% in excess of The Wall Street Journal Prime Rate. The "Wall
Street Journal Prime Rate" is the variable rate of interest, on a per annum
basis, which is announced and/or published in the "Money Rates" section of The
Wall Street Journal from time to time as its "Prime Rate". The rate will be
redetermined whenever The Wall Street Journal Prime Rate changes. Interest is
due quarterly, in arrears, starting on September 30, 2022 and will continue to
be due and payable in arrears on the last day of each calendar quarter
thereafter. On June 5, 2025 the entire unpaid principal balance of the revolving
loans under the 2022 ABL Facility, and all unpaid interest thereon, will be due
and payable. The 2022 ABL Facility provides a letter of credit sub-facility for
the issuance of letters of credit in an aggregate amount not to exceed
$7.5 million.

The 2022 ABL Facility requires CJWS to comply with the following financial
covenants (i) maintain on a consolidated basis a ratio of total liabilities to
tangible net worth of no greater than 1.5 to 1.0 at any time; (ii) reduce the
amount of revolving advances outstanding under the 2022 ABL Facility to not more
than 90% of the lesser of (a) the maximum revolving advance amount, or (b) the
borrowing base, as of Tri Counties Bank's close of business on the last day of
each fiscal quarter; and (iii) maintain net income before taxes of not less than
$1.00 as of each fiscal year end.

The 2022 ABL Facility contains usual and customary events of default and
remedies for credit facilities of a similar nature. The 2022 ABL Facility also
places restrictions on CJWS with respect to additional indebtedness, liens,
dividends and other distributions, investments, acquisitions, mergers, asset
dispositions and other matters. CJWS's obligations under the 2022 ABL Facility
are not guaranteed by Berry Corp. or Berry LLC and Berry Corp. and Berry LLC do
not and are not required to provide any credit support for such obligations. We
were in compliance with all financial covenants under the 2022 ABL Facility as
of September 30, 2022.

As of September 30, 2022, CJWS had no borrowings and no letters of credit outstanding with $15 million of available borrowing capacity under the 2022 ABL Facility.

Hedging

We have protected a significant portion of our anticipated cash flows in 2022
through 2024, using our commodity hedging program, including swaps, puts, calls
and collars. We hedge crude oil and gas production to protect against oil and
gas price decreases and we also hedge natural gas purchases to protect against
price increases. In addition, we also hedge to meet the hedging requirements of
the 2021 RBL Facility. Our generally low-decline production base, coupled with
our stable operating cost environment, affords an ability to hedge a material
amount of our future expected production. We expect our operations to generate
sufficient cash flows at current commodity prices including our current hedging
positions. For information regarding risks related to our hedging program, see
"Item 1A. Risk Factors-Risks Related to Our Operations and Industry" in our
Annual Report.

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As of October 31, 2022, we had the following hedges for our crude oil production
and gas purchases.

                                                                                 Q4 2022                 FY 2023                 FY 2024                  FY 2025
Brent
Swaps
Hedged volume (bbls)                                                             1,516,750               5,165,028               3,367,610                         -
Weighted-average price ($/bbl)                                              $        78.24          $        76.67          $        76.07          $              -

Put Spreads

Hedged volume (bbls)                                                               368,000               2,190,000               1,281,000                         -
Weighted-average price ($/bbl)                                                  $50.00/$40.00           $50.00/$40.00           $50.00/$40.00       $              -

Producer Collars
Hedged volume (bbls)                                                                     -               1,460,000               1,098,000                   365,000
Weighted-average price ($/bbl)                                              $            -             $40.00/$106.00          $40.00/$105.00

$50.00/$98.50

Henry Hub - Natural Gas purchases

Consumer Collars
Hedged volume (mmbtu)                                                            3,680,000               5,430,000                       -                         -
Weighted-average price ($/mmbtu)                                                  $4.00/$2.75             $4.00/$2.75       $            -          $              -
NWPL - Natural Gas purchases
Swaps
Hedged volume (mmbtu)                                                      

     1,220,000              12,800,000               7,320,000             

6,080,000

Weighted-average price ($/mmbtu)                                            

$ 6.40 $ 5.48 $ 4.27 $

4.27

The following table summarizes the historical results of our hedging activities.

                                                        Three Months Ended                                        Nine Months Ended
                                      September 30,          June 30,           September 30,           September 30,           September 30,
                                          2022                 2022                 2021                    2022                    2021
Crude Oil (per bbl):
Realized sales price, before the    $        89.54          $ 105.70

$ 69.01 $ 95.83 $ 63.59 effects of derivative settlements Effects of derivative settlements $ (13.13) $ (21.92)

$ (14.66) $ (16.81) $ (15.03) Oil with hedges ($/bbl)

$        76.41          $  83.78

$ 54.35 $ 79.02 $ 48.56 Purchased Natural Gas (per mmbtu): Purchase price, before the effects $ 8.16 $ 7.30

$ 5.79 $ 7.24 $ 5.32 of derivative settlements Effects of derivative settlements $ (2.53) $ (1.89)

$ (2.30) $ (1.53) $ (2.34) Purchased Natural Gas with hedges $ 5.63 $ 5.41

  $         3.49          $         5.71          $         2.98


Cash Dividends

For the nine months ended September 30, 2022, our Board of Directors declared
quarterly fixed cash dividends totaling $0.18 per share, as well as variable
cash dividends of $0.69 per share which were based on the results of the first
two quarters of 2022, for a total of $0.87 per share. In October 2022, the Board
of Directors approved the fourth quarter $0.06 per share fixed cash dividend, as
well as a variable dividend of $0.41 based on the third quarter results.

The Company anticipates that it will continue to pay quarterly cash dividend in
the future. However, the payment and amount of future dividends remain within
the discretion of the Board and will depend upon the Company's future earnings,
financial condition, capital requirements, and other factors.

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The following table represents the regular fixed cash dividends on our common stock and variable dividends approved by our Board of Directors.

                                   First Quarter           Second Quarter           Third Quarter           Fourth Quarter          Year-to-Date
Fixed Dividends                  $         0.06          $          0.06          $         0.06          $          0.06          $       0.24
Variable Dividends(1)                      0.13                     0.56                    0.41                        -                  1.10
Total                            $         0.19          $          0.62          $         0.47          $          0.06          $       1.34


__________

(1) Variable Dividends are declared the quarter following the period of results (the period used to determine the variable divided based on the shareholder return model). The table notes total dividends earned in each quarter.

Stock Repurchase Program

We repurchased 2,000,000 shares during the three months ended September 30, 2022
for approximately $19 million. For the nine months ended September 30, 2022, we
repurchased 4,000,000 shares for approximately $42 million. As of September 30,
2022, the Company had repurchased a total of 9,528,704 shares under the stock
repurchase program for approximately $94 million in aggregate, which is 12% of
outstanding shares. As previously disclosed, the Company implemented a
shareholder return model in early 2022, for which the Company intends to
allocate a portion of Discretionary Free Cash Flow to opportunistic share
repurchases.

In April 2022, our Board of Directors approved an increase of $102 million to
the Company's stock repurchase authorization bringing the Company's remaining
share repurchase authority to $150 million. As of September 30, 2022, the
Company's remaining total share repurchase authority is $108 million, after the
repurchases made in the second and third quarters of 2022. The Board's
authorization permits the Company to make purchases of its common stock from
time to time in the open market and in privately negotiated transactions,
subject to market conditions and other factors, up to the aggregate amount
authorized by the Board. The Board's authorization has no expiration date.

Repurchases may be made from time to time in the open market, in privately
negotiated transactions or by other means, as determined in the Company's sole
discretion. The manner, timing and amount of any purchases will be determined
based on our evaluation of market conditions, stock price, compliance with
outstanding agreements and other factors, may be commenced or suspended at any
time without notice and does not obligate the company to purchase shares during
any period or at all. Any shares repurchased are reflected as treasury stock and
any shares acquired will be available for general corporate purposes.

Debt Repurchase Program

In February 2020, our Board of Directors adopted a program to spend up to
$75 million for the opportunistic repurchase of our 2026 Notes. The manner,
timing and amount of any purchases will be determined based on our evaluation of
market conditions, compliance with outstanding agreements and other factors, may
be commenced or suspended at any time without notice and do not obligate Berry
Corp. to purchase the 2026 Notes during any period or at all. We have not yet
repurchased any notes under this program.

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