THE CORE VALUES THAT DEFINE OUR COMPANY.
THE CORE VALUES THAT DEFINE OUR COMPANY.
Sharpened focus.
Sharpened focus.
Renewed purpose.
Renewed purpose.
Shared vision.
Shared vision.
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Berry Corporation (bry) | 16000 N. Dallas Pkwy, Ste 500 | Dallas, TX 75248 | (661) 616 - 3811 | ir@bry.com
Berry Corporation (bry) | 16000 N. Dallas Pkwy, Ste 500 | Dallas, TX 75248 | (661) 616 - 3811 | ir@bry.com
I N V E STO R R E L AT I O N S
I N V E STO R R E L AT I O N S
In 2021, Berry embarked on a critical process to bolster
the foundation of the Company through strengthening
the Company’s core values. Berry is a values-based
company and believes that solid and robust core values
result in a strong and healthy culture.
As the Company evolves,
it is critical that it evolves
how its values are
communicated too.
THE CORE VALUES PROCESS
The leadership team worked with outside experts to
Berry dedicated a half a day for employees to do this work,
identify, update, and refine the Company’s core values, and
which demonstrates the depth of its commitment to being
starting in the fourth quarter of 2021, we rolled out values
a values-based organization and its strategic importance
workshops to our employees. The workshop first focused on
to the culture.
employees’ personal core values and then led a discussion of
the Company’s core values. This was an integral part of the
This work was especially timely because of Berry’s natural
process to ensure that employees’ core values aligned with
evolution as a company and its significant employee growth in
the Company’s core values and that employees felt connected
the fourth quarter of 2021.
to the values.
EXECUTIVE OFFICERS
DIRECTORS
Executive Vice President & Chief Financial Officer
Independent Director
RAJATH SHOURIE (1) (2)
CARY BAETZ
Berry Corporation (bry)
A.T. (TREM) SMITH
Board Chair, Chief Executive Officer & President
Berry Corporation (bry)
(C) Committee Chair
(1) Audit Committee
(2) Compensation Committee
(3) Nominating & Corporate Governance Committee
RENÉE HORNBAKER (1C) (2) (3)
Independent Director
Chief Executive Officer of Storey & Gates LLC
ANNE MARIUCCI (1) (2C) (3)
Lead Independent Director
DONALD PAUL (1) (2) (3C)
Independent Director
Executive Director of the Energy Institute,
the William M. Keck Chair of Energy Resources &
Research, Professor of Engineering at the University
of Southern California
FERNANDO ARAUJO
Executive Vice President
& Chief Operating Officer
CARY BAETZ
Executive Vice President
& Chief Financial Officer, Director
DANIELLE HUNTER
Executive Vice President,
General Counsel & Corporate Secretary
KURT NEHER
Executive Vice President, Corporate
Development & Geoscience
A.T. (TREM) SMITH
Board Chair, Chief Executive
Officer & President
INVESTOR RELATIONS
Todd Crabtree
Berry Corporation (bry)
16000 N. Dallas Pkwy, Ste 500
Dallas, TX 75248
(661) 616-3811
ir@bry.com
TRANSFER AGENT/REGISTRAR
American Stock Transfer
& Trust Company, LLC
6201 15th Avenue
Brooklyn, NY 11219
SHAREHOLDER SERVICES
(718) 921 - 8124
astfinancial.com
SECURITIES
Berry Common Stock is traded on
Nasdaq under the symbol BRY.
ANNUAL REPORT ON FORM 10-K FOR 2021
Our Form 10-K is included in this document in its entirety as filed with the SEC.
Upon request to Investor Relations, we will deliver free of charge a copy of our
Form 10-K.
TOTAL SHAREHOLDER RETURN PERFORMANCE GRAPH
Our Form 10-K includes a performance graph comparing the cumulative
total return to shareholders on our common stock relative to the
cumulative total returns of the S&P Smallcap 600, the Dow Jones U.S.
Exploration and Production indexes and the Vanguard Energy ETF (with
reinvestment of all dividends).
DIVIDEND PAYMENT DATES - 2022
Quarterly fixed dividends on common stock are paid, following declaration
by the Board of Directors, on approximately the 15th day of January, April,
July and October. Any variable dividends declared by the Board pursuant
to our new shareholder return model will be paid on such dates
established by the Board.
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
KPMG LLP
Dallas, TX
kpmg.com
2021 was a very productive year for the Berry
additional revenue streams, as well as assist us in realizing
team as we started to fulfill many of the promises
we made in 2020, and we find ourselves in a position
to deliver top-tier returns to our shareholders. With
our goal to be part of the energy transition by helping California
properly plug and decommission its significant portfolio of
orphan and idle wells.
our new shareholder return model in place and at
While we continue to grow and evolve as a company,
today’s oil and stock prices, we expect to deliver
cash returns in the mid to high teens.
Throughout 2020, we committed to all of our shareholders,
employees, and regulators that we would manage the down
cycle of 2020 in a way that would allow us to emerge in a
position of strength when the market improved. We were very
aggressive in improving our hedge position, reducing our
non-energy costs, and improving our safety and environmental
we remain focused on ensuring we have a strong and healthy
culture. We went through the process of revisiting our core
values and launched new values, along with a comprehensive
engagement and implementation program for our employees.
At the same time, our safety record remains exceptional. In
fact, we did not have a recordable incident in 2021. And, our
Total Recordable Incident Rate rate is 0.0, a company best.
All of this work is centered on creating
standards. Essentially, we began sowing the seeds for our
value for our shareholders. And in late
future success.
2021, we announced that in 2022 we would
In mid-2021, we started seeing positive signs in the industry
embark on a new shareholder return model
indicating that demand was increasing, and energy prices
were improving. And given our head-down, focused work the year
prior, we were in a terrific position to meet the improving
that was simple, easy, and predictable, just
like our business model. This new model
industry conditions. At the same time, we continued to reduce
puts Berry firmly in the top tier of returns
our non-energy costs on a sustainable basis – despite
increasing commodity prices – without compromising our
safety and environmental standards.
This brought us to very fruitful third and fourth quarters as we
started to deliver on our commitments that we made to our
shareholders: We completed a strategic value-adding acquisition,
we enhanced our environmental, social, and governance efforts,
and we launched our new shareholder return model to position
Berry to provide a consistent and valuable return on investment.
In addition to these external activities, we continued to focus
on strengthening our culture and enhancing our team.
In August 2021, we put in a bid to acquire C&J Well Services.
We closed the transaction in October, and welcomed approximately
900 new employees to the team. This is an exciting and important
acquisition for us. This will diversify our capabilities and create
for E&P companies of all sizes.
All in all, I am excited about where we are today, the
growth that we have realized, and the position we find
ourselves in for the future.
A.T. (TREM) SMITH
Board Chair,
Chief Executive Officer & President
Berry Corporation (bry)
1
CAUTIONARY NOTE ON FORWARD-LOOKING STATEMENTS
This report includes forward-looking statements involving risks and uncertainties that could materially affect our expected results of operations, financial position,
liquidity, cash flows, business strategy and business prospects, including potential growth opportunities, development and production plans, capital requirements,
expected production and costs, reserves, hedging activities, return of capital, and other guidance. Factors (but not necessarily all the factors) that could cause actual
results to differ from anticipated results include: oil and gas price volatility; inability to generate or to obtain financing to fund capital expenditures, meet working
capital requirements and fund planned investments; price and availability of natural gas; ability to hedge price risk; and the need to comply with the hedging
requirements under our credit agreement; availability and timing of required permits and approvals and our inability to meet existing or new conditions imposed on
those permits and approvals; ability to meet our planned drilling schedule and drilling risks; the impact of current laws and regulations, and of pending or future
legislative or regulatory changes, including those related to the drilling, completion, stimulation, operation, maintenance or abandonment of wells or facilities,
managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our
products; proved reserves estimation uncertainties; ability to replace our reserves; lower–than-expected production or reserves from development projects or
higher–than–expected decline rates; economic viability of drilled wells; changes in tax laws; competition; ability to make successful acquisitions; electricity price
fluctuations and steam costs; and other material risks that appear in “Item 1A – Risk Factors” of our Form 10-K and other periodic reports filed with the SEC.
New Return Model
Since going public in July 2018,
we have returned approximately
$82 million to shareholders through
our fixed dividend. Additionally,
we have returned over $52 million
to shareholders through share
repurchases. Current unhedged
commodity prices have improved
our expected cash flow, of which
a large portion will be returned to
shareholders.
In December of 2021, Berry
announced that the board approved a
shareholder return model to generate
industry-leading returns.
60% predominantly in the form of cash variable
dividends to be paid quarterly, as well as opportunistic
debt repurchases.
40%
60%
40% in the form of discretionary capital, to be used for
opportunistic growth, including from the Company’s
extensive inventory of drilling opportunities, advancing
short- and long-term sustainability initiatives, share
repurchases, and/or capital retention.
2
TYPICAL ANNUAL DEVELOPMENT CYCLE
NEW WELLS + NEW WORKOVERS
10% OF ANNUAL PRODUCTION
BERRY’S SHALLOW
TERMINAL DECLINE RATE 13%
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BASE PRODU CTION
DEVELOPMENT
Berry is uniquely positioned to implement
this new model successfully. The model’s
governing principles are predictability,
transparency, and simplicity, just like the
Berry business model. Berry has a proven,
simple business model, including a low
corporate decline rate; a predictable cost
structure; an abundance of inventory; a
simple, clean balance sheet; and extensive
levered free cash flow.
The foundation of Berry’s business model is its base production,
which is the production that comes from existing producing
wells. And on average, when it comes to maintaining production,
this accounts for 90% of the Company’s total production year in
and year out before it ever has to drill a new well. The terminal
decline rate of the base production is low, approximately 13% per
year to maintain production. Berry’s base production requires
no new permits and is predictable.
Berry’s 2022 goal is to maintain its production, which means
the Company plans to keep production flat in 2022 relative to
2021 totals.
TYPICAL ANNUAL DEVELOPMENT CYCLE
NEW WELLS + NEW WORKOVERS
10% OF ANNUAL PRODUCTION
BERRY’S SHALLOW
TERMINAL DECLINE RATE 13%
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BASE PRODU CTION
DEVELOPMENT
The base production accounts for
90% of Berry’s production needed
to maintain flat production. The
remaining 10%, which requires
new permits, is achieved by
drilling new wells for 6% of
the production and by doing
workovers in existing wells for
the remaining 4%.
When combining the Company’s production profile with the
current price forecast and running that through the new
shareholder return model, calculating Berry’s expected
returns to shareholders is easy and predictable.
This new model is expected to be one of the most robust
return models in the industry, providing shareholders with
visibility to significant returns of capital based on oil futures
prices, Berry’s hedging in place, and its free cash flow from
operations. Variable dividend payouts will be calculated and
subject to Board declaration, paid on such dates determined
by the Board.
3
Berry’s
Core Values
At Berry, the values we uphold as a company evolve as
we build upon the strength of our culture. Together with
our leadership team and each and every employee, we
have established these robust standards and principles
to empower our continued growth into the future.
HOW WE LIVE OUT OUR VALUES
• We are one team. One Berry.
• Having self-awareness and humility
drives us to leverage others’ expertise.
• Open, honest, respectful, and proactive
collaboration is required for our success.
• We expect clear and transparent
communication and information sharing
across the organization which builds
trust. This starts at the top.
• Move with a sense of urgency and own
• L.D.E.L. - Learn, Decide, Execute,
the results.
• We commit to well-communicated
expectations throughout the
organization.
• We believe in empowered individuals.
Knowledge, resources, discipline, trust,
and drive are foundational.
Learn. Better outcomes result from
informed decisions, strong execution,
and continuous learning.
• Value creation is not a random walk.
It is a result of having clear direction
and competence, and caring about
the outcomes.
4
• “To improve is to change; to be perfect
• We reward creative thinking, idea
is to change often.”
sharing, dynamic problem-solving,
and innovation.
• We embrace diversity of thought and
promote a learner mentality.
• Learning from our successes and
failures breeds excellence.
• Do the right thing even when it is
• We work ethically and assume
difficult; even when no one is looking.
responsibility for our actions.
• Selflessness, loyalty, honesty, and
• Our actions must follow our words.
responsiveness create trust.
• Be a responsible corporate citizen. This
• Each of us has the responsibility to
means we all demand an unwavering
protect and build on Berry’s reputation.
commitment to the safety and well-being
of our people, the environment, and the
• We strive for excellence in everything
communities we serve.
we do.
• We are always mindful of the impact of
our decisions on our stakeholders.
5
Core values provide a critical
foundation for company culture.
And cultivating a strong culture is
imperative to retaining talent and
maximizing results. Berry’s employees
are its most valuable differentiators
and assets. Berry knows that selecting,
developing, and fostering the best
talent, and providing an inclusive
culture are critical to Berry’s success.
The Company does this through
employee engagement, communication,
and prioritizing health and safety.
EMPLOYEE ENGAGEMENT
Employee engagement is vital in facilitating a healthy culture.
categories to make sure it is continuing to evolve and meeting
Each year, Berry seeks to make sure it is soliciting feedback
the needs of the employees. Berry tracks and reports the
from the teams using various methods including town halls,
progress on these initiatives. While Berry understands it cannot
employee surveys, and other forms of open communication.
immediately address every concern, it strives to recognize and
These feedback mechanisms are designed to give everyone
make measurable progress toward improvement.
an equal opportunity to give input and enable leadership to
identify trends that may need to be addressed or praised.
COMMUNICATION
Each year, Berry conducts an Employee Engagement Survey in
July, which this year had a 71% participation rate. The results
In addition to the employee engagement surveys and town
of the survey showed a 72% overall favorability rating. In
halls, Berry conducted a communication survey in late 2021
addition to the favorability ratings, the Company tracks other
to determine if it needed to fine-tune any of the actions it is
key indicators that reveal how it is doing as a company and
currently working through or has planned in the future.
how aligned it is as a team. From the surveys, the Company
creates a scorecard with metrics and goals in various
6
Core values provide a critical foundation for company culture. And cultivating a strong culture is imperative to retaining talent and maximizing results. Berry’s employees are its most valuable differentiators and assets. Berry knows that selecting, developing, and fostering the best talent, and providing an inclusive culture are critical to Berry’s success. The Company does this through employee engagement, communication, and prioritizing health and safety. MANDATORY REPORTING
RECORD LOW TRIR
Beginning in 2019, Berry launched a project to change
In 2021, Berry’s Total Recordable Incident Rate (TRIR) was
the safety culture by creating mandatory reporting
0.0, a new low record for the Company. The United States
guidelines for all incidents (regardless of size), establishing
oil industry's average annual TRIR is 0.5 and for all U.S.
investigation rules and methods and publishing key
construction operations the TRIR is 2.5. By embracing a
performance indicators. The goal was to shift the overall
“report everything” mindset, Berry’s Health and Safety
mindset to “every incident is preventable” and “one incident
team was able to detect weak signals and precursor events
is one too many.”
before an injury or illness occurred. This enabled a proactive
approach to risk mitigation and corrective action.
SAFETY FIRST
Berry’s safety-first culture and Environmental, Health & Safety
(EH&S) considerations are an integral part of Berry’s day-to-day
operations. Berry conducts routine and periodic drills and reviews
contractor training records and health and safety programs
before contractors enter the worksites, and it performs periodic
compliance audits.
HEALTH AND SAFETY AWARD FINALIST
In 2020, Berry’s Health and Safety team initiated new policies,
requiring all workers to report all hydrogen sulfide gas (H2S)
exposures, even if the exposure was below the Permissible
Exposure Limit (PEL) and there were no symptoms. Berry’s
Health and Safety team also installed personal H2S monitor
docking stations at each work location. Once each month,
the worker is required to dock and calibrate their personal
H2S monitor. The docking stations record all exposure data.
This resulted in an 80% reduction in exposure frequency
companywide. In addition, Berry was named a finalist for the
2021 National Safety Council Green Cross for Safety Award in
the Excellence category for this work.
7
IMPROVED DRIVING SAFETY
After a review of Berry’s Motor Vehicle Accidents (MVAs),
the Health and Safety team concluded that 71% of accidents
occurred in the autumn and winter months, and of those, 36%
of MVAs over the last five years were related to traction issues.
Berry’s Operations and Leadership teams implemented a new
initiative requiring all field vehicles to be fitted with studded
snow tires from October to April to reduce MVAs overall, and
specifically those related to traction issues. This change was
implemented in mid-2020 and preliminary results indicate an
overall reduction in incidents: Vehicle Incident Rates (VIRs)
for Berry’s Utah asset are down 71% from 2020, even though
exposure (miles driven) remained relatively constant. In
conclusion, this project has resulted in reduced MVA rates in
Berry’s Utah asset and has also resulted in cost savings due to
reduced vehicle claims.
In October 2021, we acquired one of the largest upstream well servicing and
abandonment businesses in California, which operates as C&J Well Services.
It 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, C&J Well Services 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.
The assets include well
servicing, specialized
completion and remedial
services, and water logistics
services. This acquisition
provides additional in-house
capabilities for optimizing
Berry’s accelerated workover
and abandonment program
and creates an additional
revenue stream with existing
energy services customers.
8
C&J Well Services, as it exists under Berry, evolved from
the roll-up of legacy companies: Pool Well Services, Nabors
Well Services (Nabors Industries), and most recently, C&J
Well Services and Basic Energy Services. These business
assets have a collective 74-year history of solid operations in
California with one of the best safety records, which aligns
with Berry’s commitment to be the best oil producer in the
state, while keeping the environment, employees, contractors,
and communities safe.
Berry welcomed its new Well Services team when the
acquisition closed on October 1, which significantly expanded
the Company’s employee base to more than 1,200. Given the
strategic alignment between the companies, the transition
has been seamless and smooth. Jack Renshaw, who served
as Senior Vice President of Basic’s Western Division, agreed
to join the Berry team and is leading this business as a
completely separate division from Berry’s D&P operations.
C&J Offerings
WELL SERVICES
C&J is an expert in well intervention services (downhole
wellbore equipment, plug and abandon wells, as well as
recompletions), using workover rigs and coil tubing units.
The secure sealing process of a well is critical in the
environmental protection. An idle well in California is
a well that has not been used for two years or more
and has not yet been properly plugged and abandoned
(sealed and closed). With C&J Well Services, Berry
will have the capability to plug and abandon wells and
ensure the wells are permanently sealed with a cement
plug. The plug insulates the hydrocarbon-bearing
formation from water sources and prevents leakage.
WATER LOGISTICS
C&J Advantages
C&J provides transportation of fluid required for
regular well maintenance servicing along with rental
equipment for portable storage tanks.
COMPLETION AND REMEDIAL
C&J offers specialized services and equipment used on
a non-routine basis for well servicing operations.
C&J has the capacity and expertise
to perform a high volume of well
plugging and abandonment. C&J
services an average of 1,000-1,500+
wells annually. This is equivalent to
taking about 2,000 cars and trucks
off the road.
C&J has one of the largest market
shares in the California well
servicing business with a strong
customer base. In fact, 95% of its
existing revenue comes from the
three largest operators
in California.
And lastly, C&J aligns with
Berry’s ESG standards.
9
Leader in California’s
Well Abandonment
and Fugitive Emission
Reduction Efforts
Berry’s acquisition of C&J Well Services reflects its commitment to be
a part of the solution to California’s orphan well problem.
A 2020 report stated that there were 35,000 abandoned and
which are known to produce more than 80 times the warming
idle wells in California, with about half of those wells sitting
power of carbon dioxide over the first 20 years of emission.
idle for more than a decade. Orphan wells are a long-term
Improperly plugged wells can leave a conduit for contamination
liability in California. With the addition of approximately 73
of shallower groundwater resources.
well servicing rigs and related equipment and approximately
900 employees, Berry is establishing itself as a significant
Berry’s deep understanding of California’s requirements
partner in the plugging and abandonment of orphaned and
for plugging long-term idle wells, combined with C&J
long-term idle wells.
Well Services team’s knowledge of and ability to address
With C&J Well Sevices, Berry will help remove orphan well
competencies for Berry, as well as synergies for business
hazards across California, reducing actual and potential
development with other operators who will increasingly need
methane emissions and protecting groundwater. Multiple
long-term idle well plugging services.
safe and economic well remediation, will create additional
studies have linked orphan wells to methane emissions,
Berry purchased the assets for approximately
$43 million, equating to approximately 1.5 times
legacy C&J’s 2021 EBITDA.
C&J is uniquely positioned to capture state and federal
Based on state and federal regulations, the market
funds estimated to be $300 to $400 million over the
potential for these services is currently estimated at
next two years to help remediate orphan wells.
approximately $6 billion.
10
Sustainability
Highlights
Berry’s ESG strategy is founded in its values,
strengthened by its vision, and empowered by
2021 EMISSIONS REDUCTION
HIGHLIGHTS
Reduced our GHG emissions by more than 13%, which is
equivalent to reducing more than 205,000 metric tons of
CO2 annually from bry properties.
Reduced the amount of natural gas we use for steam
its financial acumen and operational excellence.
and cogeneration facilities.
Berry engages in environmentally conscientious
practices throughout its operations and continues
to pursue opportunities for large-scale projects that
reduce emissions, optimize water usage, and utilize
renewable energy sources.
Berry aims to approach its sustainability efforts like a
tripod: the Company wants to make a positive impact
on the environment, while also improving Berry’s
operations efficiency, and ultimately increasing
value for shareholders.
California has set aggressive and
ambitious emission reduction
goals that include reducing carbon
emissions by 40% by 2030 and net
neutral by 2045.
Reduced the amount of nitrogen oxides (NOx) by more
than 63,000 pounds.
Acquired competencies in plugging and abandonment
of wells, a potentially large source of fugitive methane.
Methane is a powerful greenhouse gas, more than 25
times more impactful than CO2.
CORING UP ASSETS
Berry sold its Placerita assets in October 2021. With the sale
of Placerita, the Company’s last remaining producing property
in Los Angeles County, all of its California operations are now
concentrated in Kern County. Kern County is primarily a rural,
low-population area with about 103 people per square mile,
compared to Los Angeles County, which has more than 2,400
people per square mile.
Additionally with this divesture, Berry’s GHG emissions are
expected to fall significantly this year. This reduction is due
almost entirely to the removal of the cogeneration facilities
and the natural gas the facilities combust. The sale of
Placerita also reduces Berry’s contribution to the Los Angeles
Air Basin criteria air pollutants by more than 63,000 pounds
of NOx (nitrogen oxides) annually.
In a continuation of coring up our primary assets, in January
2022, we divested our Piceance gas field in Colorado, a
marginal asset and our only remaining property outside of
Utah and California.
11
WATER
2021 was a very productive year for the Berry
additional revenue streams, as well as assist us in realizing
team as we started to fulfill many of the promises
Water is always a precious resource and becoming even more scarce with California’s current drought. Berry
our goal to be part of the energy transition by helping California
we made in 2020, and we find ourselves in a position
properly plug and decommission its significant portfolio of
currently recycles almost 50% of the water it produces, reducing the need for sources of fresh water. Additionally,
orphan and idle wells.
to deliver top-tier returns to our shareholders. With
Berry has identified third parties who are interested in taking some of the Company’s produced water for beneficial
reuse in their operations, helping Californians cope with extreme drought conditions. Going forward, this could
our new shareholder return model in place and at
While we continue to grow and evolve as a company,
provide a significant precious resource to the Central Valley and additional revenue streams for the Company.
we remain focused on ensuring we have a strong and healthy
today’s oil and stock prices, we expect to deliver
cash returns in the mid to high teens.
Throughout 2020, we committed to all of our shareholders,
SOLAR
employees, and regulators that we would manage the down
cycle of 2020 in a way that would allow us to emerge in a
culture. We went through the process of revisiting our core
values and launched new values, along with a comprehensive
engagement and implementation program for our employees.
At the same time, our safety record remains exceptional. In
fact, we did not have a recordable incident in 2021. And, our
Total Recordable Incident Rate rate is 0.0, a company best.
position of strength when the market improved. We were very
Berry is implementing new solar projects to reduce the carbon emissions associated with the Hill lease. Additionally,
aggressive in improving our hedge position, reducing our
it is working on another solar project in the Poso Creek field.
non-energy costs, and improving our safety and environmental
All of this work is centered on creating
standards. Essentially, we began sowing the seeds for our
value for our shareholders. And in late
future success.
CARBON CAPTURE & SEQUESTRATION
In mid-2021, we started seeing positive signs in the industry
indicating that demand was increasing, and energy prices
were improving. And given our head-down, focused work the year
Activities at the federal level to enhance the
prior, we were in a terrific position to meet the improving
Sequestration Tax Credit (45Q) are creating further
opportunities for Carbon Capture and Sequestration
industry conditions. At the same time, we continued to reduce
(CCS) through economic incentives. This includes
our non-energy costs on a sustainable basis – despite
potentially increasing the tax credit. Furthermore, the
increasing commodity prices – without compromising our
safety and environmental standards.
bipartisan infrastructure bill expands federal initiatives
for CCS by about $12 billion.
This brought us to very fruitful third and fourth quarters as we
In addition to these external activities, we signed a
started to deliver on our commitments that we made to our
2021, we announced that in 2022 we would
MECHANICAL INTEGRITY UPGRADES
embark on a new shareholder return model
that was simple, easy, and predictable, just
Berry is executing a significant mechanical integrity
like our business model. This new model
program to further reduce the possibility of methane
puts Berry firmly in the top tier of returns
leakage and other spills in the future.
for E&P companies of all sizes.
C&J is upgrading the Company’s service rigs and
ancillary equipment with low-emission Tier 4 engines,
All in all, I am excited about where we are today, the
which use four gallons per hour less fuel, and reduce
growth that we have realized, and the position we find
emissions by 70% to 90%.
ourselves in for the future.
Letter of Intent (LOI) to pursue a carbon dioxide capture
shareholders: We completed a strategic value-adding acquisition,
Together, all these projects, which have their own
and continued to focus on strengthening our culture and
we enhanced our environmental, social, and governance efforts,
economic value, could further reduce the Company’s
and we launched our new shareholder return model to position
enhancing the sequestration project.
carbon footprint by almost 350,000 metric tons per year
Berry to provide a consistent and valuable return on investment.
or an additional 25%. This reduces the need to purchase
The Company’s opportunities are larger than its relative
In addition to these external activities, we continued to focus
GHG offsets by an equivalent amount, therefore reducing
on strengthening our culture and enhancing our team.
size in the industry and once the economics become
the Company’s taxes other than income taxes.
clear, Berry plans to leverage every possible revenue
stream and financial incentive associated with reducing
In August 2021, we put in a bid to acquire C&J Well Services.
We closed the transaction in October, and welcomed approximately
emissions. This may include selling storage, cap and
900 new employees to the team. This is an exciting and important
trade programs, tax credits, and Low Carbon Fuel
acquisition for us. This will diversify our capabilities and create
Standard benefits.
12
A.T. (TREM) SMITH
Board Chair,
Chief Executive Officer & President
Berry Corporation (bry)
CAUTIONARY NOTE ON FORWARD-LOOKING STATEMENTS
This report includes forward-looking statements involving risks and uncertainties that could materially affect our expected results of operations, financial position,
liquidity, cash flows, business strategy and business prospects, including potential growth opportunities, development and production plans, capital requirements,
expected production and costs, reserves, hedging activities, return of capital, and other guidance. Factors (but not necessarily all the factors) that could cause actual
results to differ from anticipated results include: oil and gas price volatility; inability to generate or to obtain financing to fund capital expenditures, meet working
capital requirements and fund planned investments; price and availability of natural gas; ability to hedge price risk; and the need to comply with the hedging
requirements under our credit agreement; availability and timing of required permits and approvals and our inability to meet existing or new conditions imposed on
those permits and approvals; ability to meet our planned drilling schedule and drilling risks; the impact of current laws and regulations, and of pending or future
legislative or regulatory changes, including those related to the drilling, completion, stimulation, operation, maintenance or abandonment of wells or facilities,
managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our
products; proved reserves estimation uncertainties; ability to replace our reserves; lower–than-expected production or reserves from development projects or
higher–than–expected decline rates; economic viability of drilled wells; changes in tax laws; competition; ability to make successful acquisitions; electricity price
fluctuations and steam costs; and other material risks that appear in “Item 1A – Risk Factors” of our Form 10-K and other periodic reports filed with the SEC.
EXECUTIVE OFFICERS
DIRECTORS
Executive Vice President & Chief Financial Officer
Independent Director
RAJATH SHOURIE (1) (2)
CARY BAETZ
Berry Corporation (bry)
A.T. (TREM) SMITH
Board Chair, Chief Executive Officer & President
Berry Corporation (bry)
(C) Committee Chair
(1) Audit Committee
(2) Compensation Committee
(3) Nominating & Corporate Governance Committee
RENÉE HORNBAKER (1C) (2) (3)
Independent Director
Chief Executive Officer of Storey & Gates LLC
ANNE MARIUCCI (1) (2C) (3)
Lead Independent Director
DONALD PAUL (1) (2) (3C)
Independent Director
Executive Director of the Energy Institute,
the William M. Keck Chair of Energy Resources &
Research, Professor of Engineering at the University
of Southern California
FERNANDO ARAUJO
Executive Vice President
& Chief Operating Officer
CARY BAETZ
Executive Vice President
& Chief Financial Officer, Director
DANIELLE HUNTER
Executive Vice President,
General Counsel & Corporate Secretary
KURT NEHER
Executive Vice President, Corporate
Development & Geoscience
A.T. (TREM) SMITH
Board Chair, Chief Executive
Officer & President
INVESTOR RELATIONS
Todd Crabtree
Berry Corporation (bry)
16000 N. Dallas Pkwy, Ste 500
Dallas, TX 75248
(661) 616-3811
ir@bry.com
TRANSFER AGENT/REGISTRAR
American Stock Transfer
& Trust Company, LLC
6201 15th Avenue
Brooklyn, NY 11219
SHAREHOLDER SERVICES
(718) 921 - 8124
astfinancial.com
SECURITIES
Berry Common Stock is traded on
Nasdaq under the symbol BRY.
ANNUAL REPORT ON FORM 10-K FOR 2021
Our Form 10-K is included in this document in its entirety as filed with the SEC.
Upon request to Investor Relations, we will deliver free of charge a copy of our
Form 10-K.
TOTAL SHAREHOLDER RETURN PERFORMANCE GRAPH
Our Form 10-K includes a performance graph comparing the cumulative
total return to shareholders on our common stock relative to the
cumulative total returns of the S&P Smallcap 600, the Dow Jones U.S.
Exploration and Production indexes and the Vanguard Energy ETF (with
reinvestment of all dividends).
DIVIDEND PAYMENT DATES - 2022
Quarterly fixed dividends on common stock are paid, following declaration
by the Board of Directors, on approximately the 15th day of January, April,
July and October. Any variable dividends declared by the Board pursuant
to our new shareholder return model will be paid on such dates
established by the Board.
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
KPMG LLP
Dallas, TX
kpmg.com
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒
☐
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2021
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the transition period from_______________ to _______________
Commission file number 001-38606
BERRY CORPORATION (bry)
(Exact name of registrant as specified in its charter)
Delaware
(State of incorporation or organization)
81-5410470
(I.R.S. Employer Identification Number)
16000 Dallas Parkway, Suite 500
Dallas, Texas 75248
(661) 616-3900
(Address of principal executive offices, including zip code
Registrant’s telephone number, including area code):
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, par value $0.001 per share
Trading Symbol
BRY
Name of each exchange on which
registered
Nasdaq Global Select Market
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to
Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit
such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting
company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and
“emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☐
Emerging growth company ☒
Accelerated filer ☐
Non-accelerated filer ☒
Smaller reporting company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its
internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public
accounting firm that prepared or issued its audit report. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which
the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $362.7
million.
Shares of common stock outstanding as of February 28, 2022:
80,313,320
DOCUMENTS INCORPORATED BY REFERENCE
The Company’s definitive proxy statement relating to the annual meeting of shareholders (to be held May 25, 2022) will be filed with the
Securities and Exchange Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2021 and is
incorporated by reference in Part III to the extent described herein.
Part I
Table of Contents
Item 1 and 2. Business and Properties .........................................................................................................
Our Company .........................................................................................................................................
The Berry Advantage .............................................................................................................................
Our Business Strategy ............................................................................................................................
Our Capital Program ..............................................................................................................................
Our Areas of Operation - Development and Production ........................................................................
Our Well Servicing and Abandonment Business ...................................................................................
Our Assets and Production Information ................................................................................................
Our Reserves ..........................................................................................................................................
Methods of Recovery and Marketing Arrangements .............................................................................
Title to Properties ...................................................................................................................................
Competition ............................................................................................................................................
Seasonality ..............................................................................................................................................
Regulatory Matters .................................................................................................................................
Human Capital Resources ......................................................................................................................
Corporate Information ............................................................................................................................
Item 1A. Risk Factors ..................................................................................................................................
Item 1B. Unresolved Staff Comments .........................................................................................................
Item 3. Legal Proceedings ...........................................................................................................................
Item 4. Mine Safety Disclosure ...................................................................................................................
Part II
Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities ......................................................................................................................................
Item 6. Selected Financial Data ...................................................................................................................
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ..........
Executive Overview ...............................................................................................................................
How We Plan and Evaluate Operations .................................................................................................
Business Environment and Market Conditions ......................................................................................
Certain Operating and Financial Information .........................................................................................
Summary by Area ...................................................................................................................................
Results of Operations .............................................................................................................................
Liquidity and Capital Resources ............................................................................................................
Balance Sheet Analysis ..........................................................................................................................
Non-GAAP Financial Measures .............................................................................................................
Critical Accounting Policies and Estimates ...........................................................................................
Inflation ..................................................................................................................................................
Cautionary Note Regarding Forward-Looking Statements ....................................................................
1
1
2
4
5
6
8
9
11
20
23
23
23
24
34
35
35
61
61
62
63
67
68
68
69
71
74
76
76
81
90
91
95
97
98
Item 7A. Quantitative and Qualitative Disclosures About Market Risk .....................................................
Item 8. Financial Statements and Supplementary Data ...............................................................................
Index to Financial Statements and Supplementary Data ........................................................................
Report of Independent Registered Public Accounting Firm ..................................................................
100
102
102
103
i
Consolidated Balance Sheets ..................................................................................................................
Consolidated Statements of Operations ..................................................................................................
Consolidated Statements of Stockholders' Equity ..................................................................................
Consolidated Statements of Cash Flows ................................................................................................
Notes to Consolidated Financial Statements ..........................................................................................
Supplemental Oil & Natural Gas Data (Unaudited) ...............................................................................
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .........
Item 9A. Controls and Procedures ...............................................................................................................
Item 9B. Other Information .........................................................................................................................
Part III
Item 10. Directors, Executive Officers and Corporate Governance ............................................................
Item 11. Executive Compensation ...............................................................................................................
Item 12. Security Ownership of Certain Beneficial Owners and Management ...........................................
Item 13. Certain Relationships and Related Transactions and Director Independence ...............................
Item 14. Principal Accounting Fees and Services .......................................................................................
Part IV
Item 15. Exhibits ..........................................................................................................................................
Item 16. Form 10-K Summary .....................................................................................................................
Glossary of Commonly Used Terms ...........................................................................................................
Signatures .....................................................................................................................................................
104
105
106
107
108
138
144
144
145
146
146
146
146
146
147
150
151
159
The financial information and certain other information presented in this report have been rounded to the nearest
whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to
the total figure given for that column in certain tables in this report. In addition, certain percentages presented in this
report reflect calculations based upon the underlying information prior to rounding and, accordingly, may not
conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded
numbers, or may not sum due to rounding.
ii
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Index to Financial Statements and Supplementary Data
Items 1 and 2. Business and Properties
Part I
“Berry Corp.” refers to Berry Corporation (bry), a Delaware corporation, which is the sole member of each of
its three Delaware limited liability company subsidiaries: (1) Berry Petroleum Company, LLC (“Berry LLC”), (2)
CJ Berry Well Services Management, LLC (“C&J Management”) and (3) C&J Well Services, LLC (“CJWS”). As
the context may require, the “Company”, “we”, “our” or similar words refer to Berry Corp. and its consolidated
subsidiary, Berry LLC, and as of October 1, 2021 this also includes CJWS and C&J Management.
As of October 1, 2021, we have operated in two business segments: (i) development and production (“D&P”)
(ii) well servicing and abandonment. The development and production segment is engaged in the development and
production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as
well as Utah. On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and
abandonment businesses in California, which became a reportable segment (well servicing and abandonment) under
U.S. GAAP.
Our Company
We are a western United States independent upstream energy company focused on the development and
production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California. As
further discussed below, in the fourth quarter of 2021, we diversified our operations with the acquisition of a
business with well servicing and abandonment capabilities.
Our upstream development and production assets, in the aggregate, are characterized by high oil content, with
100% oil content for our California assets, and are 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. For example, the cost to drill and complete the different types of our wells in
California is approximately $400,000 per well. The vertical wells in Utah operations cost approximately $1.5 million
per well. In contrast, wells in typical unconventional resource plays cost $5 million to $10 million to drill and
complete. The California oil market has Brent-linked pricing which in recent history realizes premium pricing to
WTI. In the past five years Brent pricing has averaged almost $5 above 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.
In the fourth quarter of 2021, we acquired one of the largest upstream well servicing and abandonment
businesses in California, which operates as C&J Well Services. This acquisition creates a strategic growth
opportunity for Berry. It 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, C&J Well Services 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. We believe that
C&J Well Services is uniquely positioned to capture both state and federal funds to help remediate orphan idle wells
(an idle well that has been abandoned by the operator and as a result becomes a burden of the State is referred to as
an orphan well), and there are approximately 35,000 idle wells estimated to be in California according to third-party
sources.
Since our Initial Public Offering in 2018, we have demonstrated our commitment to returning a substantial
amount of capital to shareholders, delivering $134 million to our shareholders through dividends and share
repurchases through 2021. In 2022, we initiated a new shareholder return model, which is designed to significantly
increase cash returns to our shareholders from our discretionary free cash flow, which we define as cash flow from
1
Table of Contents
Index to Financial Statements and Supplementary Data
operations less regular fixed dividends and the capital needed to hold production flat. Like our business model, this
new shareholder returns model is simple and further demonstrates our commitment to return capital to our
shareholders.
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 Levered Free Cash Flow to fund our operations, optimize capital efficiency, and return
meaningful capital to stockholders, while maintaining a low leverage profile and focusing on attractive organic and
strategic growth through commodity price cycles. “Levered Free Cash Flow” is a non-GAAP financial measure
defined as Adjusted EBITDA less capital expenditures, interest expense and dividends. “Adjusted EBITDA” is also
a non-GAAP financial measure defined 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 other unusual and infrequent items. These supplemental non-GAAP
financial measures are used by management and external users of our financial statements. Please see
“Management’s Discussion and Analysis—“Non-GAAP Financial Measures” for reconciliations of Levered Free
Cash Flow and Adjusted EBITDA to net cash provided by operating activities and of Adjusted EBITDA to net
income (loss), our most directly comparable financial measure calculated and presented in accordance with GAAP.
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 are determined to be part of the solution.
The Berry Advantage
Our business model is similar to that of a manufacturer. The foundation of our business model is our base
production, which is the production that comes from our existing, producing wells. In terms of maintaining
California production levels year over year, our base production, on average, accounts for 90% of our total annual
production, and the remaining 10% comes from the drilling of new wells or the workover of existing wells. We also
have a manageable annual corporate decline rate of approximately 13%, with abundant inventory of new drill and
workover opportunities and predictable costs, all which provides clear visibility to our potential cash flow. Over the
price cycle these advantages allow us to generate significant cash flow.
We believe the following competitive advantages will allow us to successfully execute our business strategy and
to meet our objectives to generate Levered Free Cash Flow to fund our operations, optimize capital efficiency, and
return meaningful capital to stockholders, while maintaining a low leverage profile and focusing on attractive
organic and strategic growth through commodity price cycles:
•
Stable, long-lived, oil-weighted conventional asset base with low and predictable production decline
rates. The overwhelming majority of our interests are in properties that have produced oil for decades. As a
result, the geology and reservoir characteristics are well understood, and new development well results are
generally predictable, repeatable and present lower risk than unconventional resource plays. The properties,
especially our California assets, are characterized by long-lived reserves with low production decline rates,
a stable development cost structure and low-geologic risk developmental drilling opportunities with
predictable production profiles. For example, our current corporate annual decline rate is approximately
13%. One advantage of our decline curve is that it provides strong visibility into our cash flows and it is
manageable. In California, production from existing wells, which requires little to no additional capital to
continue to produce, provides on average 90% of the production needed to maintain existing levels. The
2
Table of Contents
Index to Financial Statements and Supplementary Data
•
•
•
•
nature of our assets also provides us with significant capital flexibility (discussed further below) and an
ability to efficiently hedge material quantities of future expected production allowing for stronger viability
to our cash flow compared to the typical resource play.
Extensive inventory of low geological risk identified drilling opportunities with attractive full-cycle
economics, high operational control and a stable development and production cost environment provides
capital flexibility. We expect to be able to generate attractive rates of return and positive Levered Free Cash
Flow through typical commodity price cycles, which, if prolonged, would allow us to continue returning
meaningful capital to stockholders, maintain current production levels and fund organic and strategic
growth, among other things. For example, our proved undeveloped (“PUD”) reserves in California are
projected to average single-well rates of return of approximately 60% based on the assumptions prepared
by DeGolyer and MacNaughton in our SEC reserves report as of December 31, 2021. These margins would
be substantially greater based on the current strip prices which are more than 15% higher presently than the
prices used for the 2021 reserve calculation. We currently operate approximately 98% of our producing
wells and we expect this level of control to continue for our identified gross drilling locations. In addition, a
substantial majority of our acreage is currently held by production and fee interest, including 91% of our
acreage in California. Our high degree of control over our properties gives us flexibility in executing our
development program, including the timing, amount and allocation of our capital expenditures,
technological enhancements and marketing of production. Also, unlike many of our peers who operate
primarily in unconventional plays, our assets generally do not necessitate supply-constrained and highly
specialized equipment, which provides us relative insulation from service cost inflation pressures. Our high
degree of operational control and relatively stable and predictable cost environment provide us significant
visibility and understanding of our expected cash flow.
Brent-influenced crude oil pricing advantage. California oil prices are Brent-influenced as California
refiners import approximately 65% to 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 should continue to allow us to realize positive cash margins in
California over the typical commodity price cycles.
Simple capital structure and conservative balance sheet leverage with ample liquidity and minimal
contractual obligations. Since our 2018 IPO, our capital structure has consisted of common stock and $400
million of 7.0% senior unsecured notes due February 2026 (the “2026 Notes”). As of December 31, 2021,
we had $215 million of liquidity, consisting of $22 million of cash on hand and $193 million available for
borrowings under our 2021 RBL Facility. As of December 31, 2021, our unhedged Leverage Ratio (as
defined in our RBL Facility) was 2.0:1.0. In addition, we have minimal long-term service or fixed-volume
delivery commitments. This liquidity and flexibility permit us to capitalize on opportunities that may arise
to strategically grow and increase stockholder value.
Experienced, principled and disciplined management team. Our management team has significant
experience operating and managing oil and gas businesses across numerous domestic and international
basins, as well as reservoir and recovery types. We use our deep technical, operational and strategic
management experience to optimize the value of our assets and the Company. We are focused on the
principles of operating within Levered Free Cash Flows while maintaining or growing our production and
growing the value of our reserves. In doing so, we take a disciplined approach to development and
operating cost management, field development efficiencies and the application of proven technologies and
processes to our properties in order to generate a sustained life-cycle cost advantage.
3
Table of Contents
Index to Financial Statements and Supplementary Data
Our Business Strategy
The principal elements of our business strategy include the following:
•
•
•
•
Operate within Levered Free Cash Flow and maintain balance sheet strength and flexibility through
commodity price cycles. We are committed to operating within Levered Free Cash Flow, which includes
funding our capital program and paying interest and fixed dividends, as declared by our Board of Directors.
Additionally, our objective is to achieve and maintain a long-term, through-cycle unhedged Leverage Ratio
(as defined in our RBL Facility) between 1.0x and 2.0x, or lower.
Return capital to our stockholders. Our objective is to take advantage of our strong base production and
the visibility into our cash flow to maintain disciplined value creation and a returns-focused approach to
capital allocation in order to generate excess free cash flow. Since our 2018 IPO through December 31,
2021, we have returned approximately $134 million to our shareholders through dividends and share
repurchases, representing 122% of our IPO proceeds. Through December 31, 2021, we repurchased
approximately 7% of our outstanding shares for approximately $52 million leaving approximately $48
million authorized and available for future repurchases under the program. Additionally, in February 2020,
our Board of Directors adopted a program to spend up to $75 million for the opportunistic repurchase of
our 2026 Notes, although we have not yet repurchased any notes under this program. For a discussion of
our dividend policy, as well as our stock repurchase program, please see “Item 5. Market for the
Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.”
In the fourth quarter of 2021, we announced a new shareholder return model, which went into effect
January 1, 2022, designed to increase cash returns to our shareholders, further demonstrating our
commitment to be a leading returner of capital to its 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 production flat. Under this new model, we intend to allocate discretionary free cash flow on
a quarterly basis as follows:
◦
◦
60% predominantly in the form of cash variable dividends to be paid quarterly, as well as
opportunistic debt repurchases; and
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
Grow or maintain production and reserves in a capital efficient manner while producing positive
internally generated Levered Free Cash Flow. We intend to continue to allocate capital in a disciplined
manner to projects that will produce predictable and attractive rates of return and positive Levered Free
Cash Flow. We plan to direct capital to our oil-rich and low-geologic risk development opportunities,
primarily in California, while focusing on leveraging capital efficiencies across our asset base with the
primary objective of internally funding our capital budget and growth plan. We may also use our capital
flexibility to pursue value-enhancing, bolt-on acquisitions to opportunistically improve our positions in
existing basins.
Proactively and collaboratively engage in matters related to regulation, the environment and community
relations. We seek to continue to work closely with regulators and legislators throughout the rule making
process to minimize adverse impacts that new legislation and regulations might have on our ability to
maximize our resources and to mitigate adverse impacts to our permitting process. Additionally, we have
found that constructive dialogue with regulatory representatives can help avert compliance and permitting
issues. We believe that running our operations in a manner that protects the safety and health of the
environment and all those that may be impacted by our operations and is in compliance with existing laws
and regulations is not only the right way to run our business, but it helps us build and maintain credibility
with the relevant agencies governing our operations, as well as positive relationships with the communities
4
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Index to Financial Statements and Supplementary Data
in which we operate. With ultimate oversight by our Board of Directors, Environmental, Health & Safety
(“EH&S”) considerations are an integral part of our day-to-day operations and are incorporated into the
strategic decision-making process across our business.
• Maximize ultimate hydrocarbon recovery from our assets by optimizing drilling, completion and
production techniques and investigating deeper reservoirs and areas beyond our known productive
areas. While we continue to utilize proven techniques and technologies, we will also continuously seek
efficiencies in our drilling, completion and production techniques in order to optimize ultimate resource
recoveries, rates of return and cash flows. We will continue to advance and use innovative oil recovery and
other recovery techniques to unlock additional value and will allocate capital towards these next generation
technologies where applicable. In addition, we intend to take advantage of underdevelopment in basins
where we operate by expanding our geologic investigation of reservoirs on our acreage and adjacent
acreage below existing producing reservoirs. Through these studies, we will seek to expand our
development beyond our known productive areas in order to add probable and possible reserves to our
inventory at attractive all-in costs.
•
•
Enhance future cash flow stability and visibility through an active and continuous hedging program.
Our hedging strategy is designed to insulate our capital program from price fluctuations by securing price
realizations and cash flows for production. We use commodity pricing outlooks and our understanding of
market fundamentals to better protect our cash flows. We also seek to protect our operating expenses
through fixed-price gas purchase agreements, hedging contracts and 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. We protected a significant portion of our cash flows in 2021, and have
sought to protect a significant portion of our anticipated cash flows in 2022, as well as a portion in 2023
through 2024, using our commodity hedging program. We hedge crude oil and gas production to protect
against oil and gas price decreases and we also hedge gas purchases to protect against price increases. In
addition, we also hedge to meet the hedging requirements of the 2021 RBL Facility. We review our
hedging program continuously as market conditions change and make our hedging decisions using a wide
range of market data and analysis.
Contribute to the energy transition. We believe that oil and gas will remain an important part of the energy
landscape going forward. We recognize the oil and gas industry’s role in the energy transition and we are
determined to be part of the solution. This is the new energy reality. We have newly acquired capabilities to
support the State of California's orphaned wells and fugitive emissions initiatives. With the fourth quarter
2021 acquisition of CJWS, we can reduce state-wide fugitive emissions, which are primarily methane, the
most damaging of the greenhouse gases, by plugging and abandoning orphan and idle wells today.
Additionally, we are continuing to hone our medium and long-term environmental priorities as it relates to
ESG, including solar and water recycling projects and we are evaluating our acreage for carbon capture, use
and storage opportunities.
Our Capital Program
For the years ended December 31, 2021 and 2020 our total capital expenditures were approximately $133
million and $76 million, respectively, on an accrual basis including capitalized overhead and interest and excluding
acquisitions and asset retirement spending. Approximately 79% and 12% of capital expenditures for the year ended
December 31, 2021 was directed to California oil and Utah operations, respectively. We increased our 2021 capital
program compared to 2020, in response to the improved oil price environment and the improving global and national
economic environment.
Our 2021 capital program was heavily weighted in the middle of the year and resulted in increases in our
average daily production each quarter throughout 2021. As a result of capital deployed, production in the last quarter
of 2021 was 5% higher than the last quarter of 2020. This is indicative of the positive response we get from our
assets with strategic capital deployment. The year-over-year production results were impacted by the significant
5
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Index to Financial Statements and Supplementary Data
capital reduction in 2020 and measured ramp up in activity in early 2021. We drilled 191 wells in 2021, of which
181 were in California and consisted of 107 producing wells, 38 horizontal wells, 23 cyclic and other injectors wells
and 13 delineation wells. We also drilled 10 wells in Utah.
Our 2022 capital expenditure budget for D&P operations and corporate activities is approximately $125 to $135
million, excluding approximately $8 million for C&J Well Services, which we expect will keep our annual
production flat. We currently anticipate oil production will be approximately 92% of total production volume in
2022, compared to 88% in 2021 and 88% in 2020, with the change largely due to the Piceance natural gas properties
divestiture in January 2022. Based on current commodity prices and our drilling success rate to date, we expect to be
able to fund our 2022 capital development programs from cash flow from operations. The execution of these plans
requires that we timely obtain certain regulatory permits and approvals, which we may not be able to obtain on a
timely basis or at all. Please see “—Regulatory Matters” for additional discussion of the laws and regulations that
impact our ability to drill and develop our assets, including those impacting regulatory approval and permitting
requirements.
In 2021 we began to spend capital on environmental projects related to our sustainability or “ESG” initiatives.
We plan to increase capital spent on these ESG projects in 2022, which will include solar generation to power
operations and equipment efficiency improvements that will decrease our carbon emissions.
We currently expect to employ two to three drilling rigs in California during 2022. Additionally, we currently
expect to drill approximately 120 to 130 development wells and 5 to 10 delineation wells during 2022. Of the
development capital in 2022 we anticipate approximately 80-85% in California and 15-20% in Utah.
Exclusive of the capital expenditures noted above, for the full year 2021, we spent approximately $19 million
on plugging and abandonment activities, exceeding our annual obligation requirements under the California idle
well management plan. In 2022, we currently expect to spend approximately $21 million to $24 million for such
activities and we again plan to stay ahead of our annual plugging and abandonment obligations in keeping with our
commitments to be a responsible operator.
For information about the potential risks related to our capital program, see “Item 1A. Risk Factors”, as well as
“—Regulatory Matters”.
Our Areas of Operation - Development and Production
Our predominant development and production operating area is in California, and we also have operations in
Utah. In January 2022 we divested our Colorado operating area.
California
California is and has been one of the most productive oil and natural gas regions in the world. According to the
U.S. Energy Information Administration as of 2015, the San Joaquin basin in Kern County, California contained
three of the 20 largest oil fields in the United States based on proved reserves. We have operations in two of those
three fields —Midway-Sunset and South Belridge. All of our California operations are in the San Joaquin basin and
rural Kern County with low population density. We believe there are extensive existing field redevelopment
opportunities in our areas of operation within the San Joaquin basin, which also include the McKittrick and Poso
Creek fields. We also believe that our California focus and strong balance sheet will allow us to take advantage of
these opportunities. Commercial petroleum development began in the San Joaquin basin in the late 1860s when
asphalt deposits were mined and shallow wells were hand dug and drilled. Rapid discovery of many of the largest oil
accumulations followed during the next several decades. Operations on our properties began in 1909. In the 1960s,
introduction of thermal techniques resulted in substantial new additions to reserves in heavy oil fields. The San
Joaquin basin contains multiple stacked benches that have allowed continuing discoveries of stratigraphic, structural
and non-structural traps. Most oil accumulations discovered in the San Joaquin basin occur in the Eocene age
6
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Index to Financial Statements and Supplementary Data
through Pleistocene age sedimentary sections. Organic rich shales from the Monterey, Kreyenhagen and Tumey
formations form the source rocks that generate the oil for these accumulations.
We currently hold approximately 14,000 net acres in the San Joaquin basin in Kern County, of which 91% is
held by production and fee interest. Approximately 13% of our California acres are on Federal lands administered by
the Bureau of Land Management (“BLM”), of which 100% is held by production. We have a 97% average working
interest in our California assets, and our producing areas include:
• West California operations consist of: (i) our North Midway-Sunset sandstone properties, where we use
cyclic and continuous steam injection to develop these known reservoirs; (ii) our South Midway-Sunset,
properties, which are long-life, low-decline, strong-margin thermal oil properties with additional
development opportunities; (iii) our South Belridge Field Hill property, which is characterized by two
known reservoirs with low geological risk containing a significant number of drilling prospects, including
downspacing opportunities, as well as additional steamflood opportunities and our McKittrick Field
property, which is a newer steamflood development with potential for infill and extension drilling. Also
located here is our North Midway-Sunset thermal diatomite properties, which requires high pressure cyclic
steam techniques to unlock the significant value we believe is there and maximize recoveries. Following
the November 2019 moratorium on approval of new high–pressure cyclic steam wells pending a study co-
led by Lawrence Livermore National Laboratory and CalGEM of the practice to address surface
expressions experienced by certain operators, we have not included these properties in our plans through
2023. Please see “—Regulation of Health, Safety and Environmental Matters—Additional CalGEM
Actions on Oil and Gas Activities” for more information.
•
East California operations consist of our Poso Creek property, which is an active mature shallow, heavy oil
asset that we continue to develop across the property. We develop these sandstone properties with a
combination of cyclic and continuous steam injections, similar to many of our west California operations.
Our California proved reserves represented approximately 81% of our total proved reserves at December 31,
2021. California accounted for 22.0 mboe/d, or 80%, of our average daily production for the year ended December
31, 2021.
Along with these upstream operations, we have infrastructure and excess available takeaway capacity in place to
support additional development in California. We produce oil from heavy crude reservoirs using steam to heat the
oil so that it will flow to the wellbore for production. To help support this operation, we own and operate four
natural gas-fired cogeneration plants that produce electricity and steam. These plants supply approximately 18% of
our steam needs and approximately 65% of our field electricity needs to power our operations in California, on
average generally at a discount to electricity market prices. To further help offset our costs, we currently also sell
surplus power produced by two of our cogeneration facilities under power purchase agreement (“PPA”) contracts
with California utility companies. We also own 62 conventional steam generators to help satisfy the steam required
by our operations.
In addition, we own gathering, treatment, water recycling and softening facilities, as well as storage facilities, in
California that currently have excess capacity, reducing our need to spend capital to develop nearby assets and
generally allowing us to control certain operating costs. Approximately 92% of our California oil production is sold
through pipeline connections.
Uinta Basin, Utah
The Uinta basin is a mature, light-oil-prone play covering more than 15,000 square miles with significant
undeveloped resources where we have high operational control and additional behind pipe potential. Our Uinta basin
operations in the Brundage Canyon, Ashley Forest and Lake Canyon areas in Utah target the Green River and
Wasatch formations that produce oil and natural gas at depths ranging from 5,000 feet to 7,000 feet. We have high
operational control of our existing acreage, which provides significant upside for additional vertical and or
horizontal development and recompletions. We currently hold approximately 90,000 net acres in the Uinta basin, of
7
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Index to Financial Statements and Supplementary Data
which 83% is held by production. Approximately 32% of our Utah acreage is on Federal lands administered by the
BLM, of which 60% is held by production and approximately 58% of our Utah acreage is on tribal lands, of which
97% is held by production.
Our Uinta basin proved reserves represented approximately 15% of our total proved reserves at December 31,
2021 and accounted for 4.2 mboe/d or 15% of our average daily production for the year ended December 31, 2021.
We also have extensive gas infrastructure and available takeaway capacity in place to support additional
development along with existing gas transportation contracts. We have natural gas gathering systems consisting of
approximately 500 miles of pipeline and associated compression and metering facilities that connect to numerous
sales outlets in the area. We also own a natural gas processing plant in the Brundage Canyon area located in
Duchesne County, Utah with capacity of approximately 30 mmcf/d. This facility takes delivery from gathering and
compression facilities we operate. Approximately 93% of the gas gathered at these facilities is produced from wells
that we operate. Current throughput at the processing plant is 15-17 mmcf/d and sufficient capacity remains for
additional large-scale development drilling.
Formed during the late Cretaceous to Eocene periods, the Uinta basin is a mature, light-oil-prone play located
primarily in Duchesne and Uintah Counties of Utah and covers more than 15,000 square miles. Exploration efforts
immediately after the Second World War led to the first commercial oil discoveries in the Uinta basin. Oil was
discovered in, and produced from fluvial to lacustrine sandstones of the Green River formation in these early
discoveries. The application of improved hydraulic stimulation techniques in the mid-2000s greatly increased
production from the Uinta basin. As reported by the Utah Department of Natural Resources, total Utah oil
production more than doubled from 36 mbbl/d in 2003 to 85 mbbl/d in 2020. Approximately 84% of Utah’s oil
production in 2020 came from the Uinta basin in Duchesne and Uintah counties.
Piceance Basin, Colorado
The Piceance basin in northwestern Colorado is a natural gas play. In January 2022 we divested our Piceance
Basin assets. Our Piceance basin proved reserves represented approximately 4% of our total proved reserves at
December 31, 2021 and accounted for 1.2 mboe/d, or 4%, of our average daily production for the year ended
December 31, 2021.
Our Well Servicing and Abandonment Business
In late 2021, we acquired one of the largest upstream well servicing and abandonment businesses in California,
which operates as C&J Well Services, LLC. C&J Well Services provides wellsite services in California to oil and
natural gas production companies, with a focus on well servicing, well abandonment services, and water logistics
with a constant focus on maintaining the highest reliability standards and safety record. Our 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, we perform plugging and
abandonment services on wells at the end of their productive life, which creates a strategic growth opportunity for
Berry. C&J Well Services 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, C&J Well Services 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. We
believe that C&J Well Services is uniquely positioned to capture both state and federal funds to help remediate
orphan idle wells (an idle well that has been abandoned by the operator and as a result becomes a burden of the State
is referred to as an orphan well), and there are approximately 35,000 idle wells estimated to be in California
according to third-party sources.
Through C&J Well Services we operate a fleet of 73 well servicing rigs, also commonly referred to as a
workover rig, and related equipment. These services are performed to establish, maintain and improve production
throughout the productive life of an oil and natural gas well and to plug and abandon a well at the end of its
8
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Index to Financial Statements and Supplementary Data
productive life. Our well servicing business performs various services to establish, maintain and improve production
throughout the productive life of an oil and natural gas well, which include:
• Maintenance work involving removal, repair and replacement of down-hole equipment and components,
and returning the well to production after these operations are completed;
• Well workovers which potentially include deepening, sidetracks, adding productive zones, isolating
intervals, or repairing casings required by the operation into and out of the well, or removing equipment
from the well bore; and
•
Plugging and abandonment services when a well has reached the end of its productive life.
Regular maintenance is required throughout the life of a well to sustain optimal levels of oil and natural gas
production. Regular maintenance currently comprises the largest portion of our well services work, and because
ongoing maintenance spending is required to sustain production, we have historically experienced relatively stable
demand for these services.
In addition to periodic maintenance, producing oil and natural gas wells occasionally require major repairs or
modifications called workovers, which are typically more complex and more time consuming than maintenance
operations. The demand for workover services is sensitive to oil and natural gas producers’ intermediate and long-
term expectations for oil and natural gas prices. As oil and natural gas prices increase, the level of workover activity
tends to increase as oil and natural gas producers seek to increase output by enhancing the efficiency of their wells.
Well servicing rigs are also used in the process of permanently closing oil and natural gas wells no longer
capable of producing in economic quantities. Plugging and abandonment work can provide favorable operating
margins and is less sensitive to oil and natural gas prices than drilling and workover activity since well operators
must plug a well in accordance with state regulations when it is no longer productive.
Our Water Logistics business utilizes our fleet of 276 water logistics trucks and related assets, including
specialized tank trucks, storage tanks and other related equipment. These assets provide, transport, and store a
variety of fluids, as well as provide maintenance services. These services are required in most workover and
remedial projects and are routinely used in daily producing well operations. We also have approximately 1,630
pieces of rental equipment on our water logistics side.
Our Assets and Production Information
For the year ended December 31, 2021, we had average net production of approximately 27.4 mboe/d, of which
approximately 88% was oil and approximately 80% was in California. In California, our average production for the
year ended December 31, 2021 was 22.0 mboe/d, of which 100% was oil. Our California production in 2021
includes Placerita operations contributing average daily production in of over 800 boe/d through the end of October
2021 when those assets were divested. Additionally, we divested all of our properties in the Piceance basin of
Colorado in January 2022, which had production of 1.2 mboe/d in 2021.
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Index to Financial Statements and Supplementary Data
The table below summarizes our average net daily production for the years ended December 31, 2021 and 2020:
Average Net Daily Production(1)
for the Year Ended December 31,
2021
2020
(mboe/d)
Oil (%)
(mboe/d)
Oil (%)
22.0
4.2
26.2
1.2
27.4
100 %
51 %
88 %
2 %
88 %
22.9
4.3
27.2
1.3
28.5
100 %
50 %
88 %
2 %
88 %
California(2)
Utah
Colorado(3)
Total
__________
(1) Production represents volumes sold during the period.
(2)
Includes production for Placerita properties though the end of October 2021 when they were divested. These properties had average daily
production in 2021 of over 800 boe/d prior to the sale.
(3) Our properties in Colorado were in the Piceance basin, all of which were all divested in January 2022.
Production Data
The following table sets forth information regarding production for the years ended December 31, 2021 and
2020.
Average daily production(1):
Oil (mbbl/d)
Natural gas (mmcf/d)
NGLs (mbbl/d)
Total (mboe/d)(2)
__________
Year Ended December 31,
2021
2020
24.2
17.1
0.4
27.4
25.0
18.5
0.4
28.5
(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 year ended December 31, 2021, the
average prices of Brent oil and Henry Hub natural gas were $70.95 per bbl and $3.89 per mcf, respectively.
Our Development Inventory
We have an extensive inventory of low-geologic risk, high-return development opportunities. As of December
31, 2021, we identified 10,414 proven and unproven gross drilling locations across our asset base. For a discussion
of how we identify drilling locations, please see “—Our Reserves—Determination of Identified Drilling Locations.”
We operate approximately 98% of our producing wells. In addition, a substantial majority of our acreage is
currently held by production and fee interest, including 91% of our acreage in California. As of December 31, 2021,
the combined net acreage covered by leases expiring in the next three years represented approximately 11% of our
total net acreage, of which 91% is in Utah. Our high degree of operational control, together with the large portion of
our acreage that is held by production, and the speed with which we are able to drill and complete our wells in
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Index to Financial Statements and Supplementary Data
California gives us flexibility over the execution of our development program, including the timing, amount and
allocation of our capital expenditures, technological enhancements and marketing of production.
The following table summarizes certain information concerning our active producing and identified
development assets as of December 31, 2021:
Acreage
Gross
Net(1)(2)
18,823
107,069
9,259
14,111
90,108
6,780
Net Acreage
Held By
Production and
Fee Interest(%)
Producing
Wells,
Gross(3)(4)
Average
Working
Interest
(%)(4)(5)
Net
Revenue
Interest
(%)(4)(6)
Identified Drilling
Locations(7)
Gross
Net
91 %
83 %
100 %
2,448
970
169
97 %
95 %
72 %
95 %
94 %
9,981
9,942
79 %
62 %
433
—
369
—
90 % 10,414
10,311
135,151
110,999
85 %
3,587
California
Utah
Colorado
Total
__________
(1) Represents our weighted-average interest in our acreage.
(2) Of which approximately 13% are BLM acres in California and 32% are BLM acres in Utah.
(3)
Includes 483 steamflood and waterflood injection wells in California.
(4) Excludes 90 wells in the Piceance basin each with a 5% working interest. We divested all of our Colorado Piceance basin assets in January
2022.
(5) Represents our weighted-average working interest in our active wells.
(6) Represents our weighted-average net revenue interest for the year ended December 31, 2021.
(7) Our total identified drilling locations include approximately 719 gross (715 net) locations associated with PUDs as of December 31, 2021,
including 90 gross (90 net) steamflood injection wells. Please see “—Our Reserves—Determination of Identified Drilling Locations” for
more information regarding the process and criteria through which we identified our drilling locations.
Our Reserves
Reserve Data
As of December 31, 2021, we had estimated total proved reserves of 97 mmboe, an increase from 95 mmboe, as
of December 31, 2020. Our overall proved reserves increased 12 mmboe, or 13%, before production of 10 mmboe,
the majority of which is due to price revisions. We replaced 120% of our production with additional proved reserves.
Based on current Brent strip pricing we would expect a further improvement in the 2022 proved reserves.
The majority of our reserves are composed of crude oil in shallow, long-lived reservoirs. As of December 31,
2021, the standardized measure of discounted future net cash flows of our proved reserves and the PV-10 of our
proved reserves were approximately $1.2 billion and $1.5 billion, respectively. These values represent significant
increases from the prior year end of $516 million and $520 million. PV-10 is a financial measure that is not
calculated in accordance with U.S. generally accepted accounting principles (“GAAP”). For a definition of PV-10
and a reconciliation to the standardized measure of discounted future net cash flows, please see in “—PV-10” below.
As of December 31, 2021, approximately 81% of our proved reserves and approximately 91% of the PV-10 value of
our proved reserves are derived from our assets in California. We also have approximately 15% of our proved
reserves and approximately 8% of the PV-10 value in the Uinta basin in Utah, a mature, light-oil-prone play with
significant undeveloped resources. Approximately 4% of our proved reserves and only 1% of the related PV-10
11
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Index to Financial Statements and Supplementary Data
value at December 31, 2021 were located in the Piceance basin in Colorado. These Colorado properties consisted
entirely of natural gas and we divested these properties in January 2022.
The tables below summarize our estimated proved reserves and related PV-10 by category as of December 31,
2021:
PDP
PDNP
PUD
Berry total proved
reserves
California total
proved reserves
__________
Proved Reserves as of December 31, 2021(1)(5)
Oil
(mmbbl)
Natural
Gas (bcf)
NGLs
(mmbbl)
Total
(mmboe)(2)
% of
Proved
% Proved
Developed
Capex(3)
($MM)
PV-10(4)
($MM)
47
6
33
86
79
60
—
2
62
—
1
—
—
1
—
58
6
33
97
79
60 %
6 %
34 %
90 %
10 %
— %
14
17
451
911
128
474
100 %
100 %
482
1,513
455
1,374
(1) Our estimated net reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC
guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $69.47 per bbl Brent for oil and
natural gas liquids (“NGLs”) and $3.64 per mmbtu Henry Hub for natural gas at December 31, 2021. The volume-weighted average prices
over the lives of the properties were estimated at $65.10 per bbl of oil and condensate, $36.08 per bbl of NGLs and $3.98 per mcf of gas.
The prices were held constant for the lives of the properties and we took into account pricing differentials reflective of the market
environment. Prices were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules,
including adjustment by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors
affecting the price received at the wellhead. Please see “—Our Reserves—PV-10” below.
(2) Estimated using a conversion ratio of six mcf of natural gas to one bbl of oil.
(3) Represents undiscounted future capital expenditures estimated as of December 31, 2021.
(4) PV-10 is a financial measure that is not calculated in accordance with GAAP. For a definition of PV-10 and a reconciliation to the
standardized measure of discounted future net cash flows, please see “—Our Reserves—PV-10” below. PV-10 does not give effect to
derivatives transactions.
(5)
In January 2022 we divested our Piceance basin properties in Colorado.
The following table summarizes our estimated proved reserves and related PV-10 by area as of December 31,
2021. The reserve estimates presented in the table below are based on reports prepared by DeGolyer and
MacNaughton. The reserve estimates were prepared in accordance with current SEC rules and regulations regarding
oil, natural gas and NGL reserve reporting. Reserves are stated net of applicable royalties. We divested the Colorado
properties in the Piceance basin in January 2022.
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Proved Reserves as of December 31, 2021(1)
California
(San Joaquin
basin)
Utah
(Uinta basin)
Colorado
(Piceance basin)(5)
Total
47
—
—
47
32
—
—
32
79
—
—
79
6
35
1
13
1
2
—
1
7
37
1
14
—
25
—
4
—
—
—
—
—
25
—
4
53
60
1
64
33
2
—
33
86
62
1
97
$
1,374 $
124 $
15 $
1,513
Proved developed reserves:
Oil (mmbbl)
Natural Gas (bcf)
NGLs (mmbbl)
Total (mmboe)(2)(3)
Proved undeveloped reserves:
Oil (mmbbl)
Natural Gas (bcf)
NGLs (mmbbl)
Total (mmboe)(3)
Total proved reserves:
Oil (mmbbl)
Natural Gas (bcf)
NGLs (mmbbl)
Total (mmboe)(3)
PV-10 ($million)(4)
__________
(1) Our estimated net reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC
guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $69.47 per bbl Brent for oil and
NGLs and $3.64 per mmbtu Henry Hub for natural gas at December 31, 2021. The volume-weighted average prices over the lives of the
properties were $65.10 per bbl of oil and condensate, $36.08 per bbl of NGLs and $3.98 per mcf. The prices were held constant for the lives
of the properties and we took into account pricing differentials reflective of the market environment. Prices were calculated using oil and
natural gas price parameters established by current guidelines of the SEC and accounting rules including adjustments by lease for quality,
fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
For more information regarding commodity price risk, please see “Item 1A. Risk Factors—Risks Related to Our Operations and
Industry—Oil, natural gas and NGL prices are volatile and directly affect our results.”
(2) For proved developed reserves approximately 10% of total and 11% of oil are non-producing.
(3) 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 year ended December 31, 2021, the
average prices of Brent oil and Henry Hub natural gas were $70.95 per bbl and $3.89 per mcf, respectively.
(4) For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “—PV-10.”
PV-10 does not give effect to derivatives transactions.
(5) Our properties in Colorado were in the Piceance basin, all of which were all divested in January 2022.
PV-10
PV-10 is a non-GAAP financial measure, which is widely used by the industry to understand the present value
of oil and gas companies. It represents the present value of estimated future cash inflows from proved oil and gas
reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future
cash flows and does not give effect to derivative transactions or estimated future income taxes. Management
believes that PV-10 provides useful information to investors because it is widely used by analysts and investors in
evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual
company when estimating the amount of future income taxes to be paid, management believes the use of a pre-tax
measure is valuable for evaluating the Company. PV-10 should not be considered as an alternative to the
standardized measure of discounted future net cash flows as computed under GAAP.
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The following table provides a reconciliation of PV-10 of our proved reserves to the standardized measure of
discounted future net cash flows at December 31, 2021:
California PV-10
Utah PV-10
Colorado PV-10
Total Company PV-10
Less: present value of future income taxes discounted at 10%
Standardized measure of discounted future net cash flows
Proved Reserves Additions
At December 31, 2021
(in millions)
$
$
1,374
124
15
1,513
(280)
1,233
Our overall proved reserves increased 12 mmboe, or 13%, before production. A majority of this increase was a
result of the higher price environment and extensions. We replaced 120% of our production with additional proved
reserves. The total changes to our proved reserves from December 31, 2020 to December 31, 2021 were as follows:
Beginning balance as of December 31, 2020
Extensions and discoveries
Revisions of previous estimates
Purchases of minerals in place(2)
Sales of minerals in place(3)
Current year production
Ending balance as of December 31, 2021
__________
California
(San Joaquin
basin)
Utah
(Uinta basin)
Colorado
(Piceance basin)
Total
(in mmboe)(1)
87
1
(1)
—
—
(8)
79
7
2
7
—
—
(2)
14
1
—
3
—
—
—
4
95
3
9
—
—
(10)
97
(1) 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 year ended December 31, 2021, the
average prices of Brent oil and Henry Hub natural gas were $70.95 per bbl and $3.89 per mcf, respectively.
(2) Purchases of minerals in place were less than 1 mmboe.
(3) Sales of minerals in place were less than 1 mmboe.
Extensions. During 2021, we added 3 mmboe of proved reserves from extensions in our California and Utah
properties.
Revisions of Previous Estimates.
Revisions related to price - Product price changes affect the proved reserves we record. For example, higher
prices generally increase the economically recoverable reserves in all of our operations because the extra margin
extends their expected life and renders more projects economic. Conversely, when prices drop, we experience the
opposite effects. In 2021, our total net positive price revision was 9 mmboe in California, 6 mmboe in Utah, and 3
mmboe in Colorado.
Revisions related to performance - Performance-related revisions can include upward or downward changes to
previous proved reserves estimates due to the evaluation or interpretation of recent geologic, production decline or
operating performance data. In 2021, we had negative technical revisions of 10 mmboe in California, which was
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partially offset by positive technical revisions of 1 mmboe in the Rockies. The negative technical revisions resulted
primarily from a strategic change in development plans in our Hill Tulare properties to a more focused approach on
infill drilling rather than extending our proved developed area, as well as adjustments made to our thermal Diatomite
development plans.
Current Year Production - Please refer to “Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations—Certain Operating and Financial Information” for discussion of our
current year production.
Proved Undeveloped Reserves Changes
Our California proved undeveloped reserves decreased 7 mmboe in 2021 largely due to reclassifications to
proved developed reserves. Our development program in 2021 was focused on maintaining production with minimal
capital spent on growth limiting the proved undeveloped reserves additions. The total changes to our proved
undeveloped reserves from December 31, 2020 to December 31, 2021 were as follows:
Beginning balance as of December 31, 2020
Extensions and discoveries
Revisions of previous estimates
Reclassifications to proved developed
Ending balance as of December 31, 2021
__________
California
(San Joaquin and
Ventura basins)
Utah
(Uinta basin)
Colorado
(Piceance basin)
Total
39
1
(3)
(5)
32
(in mmboe)(1)
—
1
—
—
1
—
—
—
—
—
39
2
(3)
(5)
33
(1) 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 year ended December 31, 2021, the
average prices of Brent oil and Henry Hub natural gas were $70.95 per bbl and $3.89 per mcf, respectively.
Extensions. During 2021, we added 2 mmboe of proved undeveloped reserves from extensions based on drilling
results from unproven locations in Midway Sunset, McKittrick, and Utah.
Revisions of previous estimates.
Revisions related to price - In 2021, our net positive price revision on proved undeveloped reserves were
approximately 1 mmboe in California, which was the result of higher prices due to the current commodity price
environment.
Revisions related to performance - In 2021, our net negative performance-related revision on proved
undeveloped reserves was 4 mmboe in California which resulted primarily from our thermal Diatomite and Hill
Tulare areas.
Reclassifications to proved developed. During 2021, we transferred approximately 5 mmboe of proved
undeveloped reserves to the proved developed category due to development drilling activity in 2021. Our
development of proved undeveloped reserves during much of 2020 and 2021 was significantly limited by the severe
downturn in the industry, which impacted not only our capital over those two years but also our strategic
development approach. With our 2021 development program, we converted 4.5 mbbls of our beginning-of-the year
inventory of proved undeveloped reserves, spending approximately $48 million of capital. We expect to have
sufficient future capital to develop our proved undeveloped reserves at December 31, 2021 within five years. Prices
substantially below current levels for a prolonged period of time may require us to reduce expected capital
expenditures over the next five years, potentially impacting either the quantity or the development timing of proved
15
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undeveloped reserves. Our year-end proved undeveloped reserves are determined in accordance with SEC guidelines
for development within five years. We believe we have management's commitment and sufficient future capital to
develop all of our proved undeveloped reserves.
Reserves Evaluation and Review Process
Independent engineers, DeGolyer and MacNaughton (“D&M”), prepared our reserve estimates reported herein.
The process performed by D&M to prepare reserve amounts included their estimation of reserve quantities, future
production rates, future net revenue and the present value of such future net revenue, based in part on data provided
by us. When preparing the reserve estimates, D&M did not independently verify the accuracy and completeness of
the information and data furnished by us with respect to ownership interests, production, well test data, historical
costs of operation and development, product prices, or any agreements relating to current and future operations of
the properties and sales of production. However, if in the course of D&M's work, something came to their attention
that brought into question the validity or sufficiency of any such information or data, they would not rely on such
information or data until they had satisfactorily resolved their related questions. The estimates of reserves conform
to SEC guidelines, including the criteria of “reasonable certainty,” as it pertains to expectations about the
recoverability of reserves in future years. Under SEC rules, reasonable certainty can be established using techniques
that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or
by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping
of one or more technologies (including computational methods) that have been field tested and have been
demonstrated to provide reasonably certain results with consistency and repeatability in the formation being
evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved
reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated
to yield results with consistency and repeatability and include production and well test data, downhole completion
information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical
well cost, operating expense and commodity revenue data.
D&M also prepared estimates with respect to reserves categorization, using the definitions of proved reserves
set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.
Our internal control over the preparation of reserves estimates is designed to provide reasonable assurance
regarding the reliability of our reserves estimates in accordance with SEC regulations. The preparation of reserve
estimates was overseen by our Executive Vice President of Business Development, who has a Masters in Geology
from the University of South Carolina and a Bachelors in Geology from Carleton College, and more than 35 years of
oil and natural gas industry experience. The reserve estimates were reviewed and approved by our senior
engineering staff and management, and presented to our board of directors. Within D&M, the technical person
primarily responsible for reviewing our reserves estimates is a Registered Professional Engineer in the State of
Texas, has a Master of Science and Doctor of Philosophy degrees in Petroleum Engineering and has more than 10
years of experience in oil and gas reservoir studies and reserves evaluations.
Reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural
gas and NGLs that cannot be measured exactly. For more information, see “Item 1A. Risk Factors—Risks Related
to Our Operations and Industry—Estimates of proved reserves and related future net cash flows are not precise.
The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.”
Determination of Identified Drilling Locations
Proven Drilling Locations
Based on our reserves report as of December 31, 2021, we have approximately 719 gross (715 net) drilling
locations attributable to our proved undeveloped reserves, compared to 808 gross (805 net) as of December 31,
2020. The decrease in drilling locations attributable to our proved undeveloped reserves is primarily due to the 2021
drilling activity. We use production data and experience gains from our development programs to identify and
prioritize development of this proven drilling inventory. These drilling locations are included in our inventory only
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after they have been evaluated technically and are deemed to have a high likelihood of being drilled within a five-
year time frame. As a result of technical evaluation of geologic and engineering data, it can be estimated with
reasonable certainty that reserves from these locations are commercially recoverable in accordance with SEC
guidelines. Management considers the availability of local infrastructure, drilling support assets, state and local
regulations and other factors it deems relevant in determining such locations.
Unproven Drilling Locations
We have also identified a multi-year inventory of 9,695 gross (9,596 net) unproven drilling locations as of
December 31, 2021, compared to 9,565 gross (9,533 net) unproven drilling locations as of December 31, 2020. Our
unproven drilling locations are specifically identified on a field-by-field basis considering the applicable geologic,
engineering and production data. We analyze past field development practices and identify analogous drilling
opportunities taking into consideration historical production performance, estimated drilling and completion costs,
spacing and other performance factors. These drilling locations primarily include (i) infill drilling locations, (ii)
additional locations due to field extensions or (iii) thermal recovery project expansions, some of which are currently
in the pilot phase across our properties, but have yet to be determined to be proven locations. We believe the
assumptions and data used to estimate these drilling locations are consistent with established industry practices
based on the type of recovery process we are using. Please see “Regulation of Health, Safety and Environmental
Matters” for additional discussion of the laws and regulations that impact our ability to drill and develop our assets,
including regulatory approval and permitting requirements.
We plan to analyze our acreage for exploration drilling opportunities at appropriate levels. We expect to use
internally generated information and proprietary models consisting of data from analog plays, 3-D seismic data,
open hole and mud log data, cores and reservoir engineering data to help define the extent of the targeted intervals
and the potential ability of such intervals to produce commercial quantities of hydrocarbons.
Well Spacing Determination
Our well spacing determinations in the above categories of identified well locations are based on actual
operational spacing within our existing producing fields, which we believe are reasonable for the particular recovery
process employed (i.e., primary, waterflood and thermal recovery). Spacing intervals can vary between various
reservoirs and recovery techniques. Our development spacing can be less than one acre for a thermal steamflood
development in California.
Drilling Schedule
Our identified drilling locations have been scheduled as part of our current multi-year drilling schedule or are
expected to be scheduled in the future. However, we may not drill our identified sites at the times scheduled or at all.
We view the risk profile for our prospective drilling locations and any exploration drilling locations we may identify
in the future as being higher than for our other proved drilling locations.
Our ability to drill and develop our identified drilling locations profitably or at all depends on a number of
variables, many of which are outside of our control, including crude oil and natural gas prices, the availability of
capital, costs, drilling results, regulatory approvals and permits, available transportation capacity and other factors. If
future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may
curtail drilling or development of these projects. For a discussion of the risks associated with our drilling program,
see “Item 1A. Risk Factors—Risks Related to Our Operations and Industry—We may not drill our identified
sites at the times we scheduled or at all.”
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The table below sets forth our proved undeveloped drilling locations and unproven drilling locations as of
December 31, 2021.
PUD Drilling Locations
(Gross)
Unproven Drilling
Locations (Gross)
Total Drilling Locations
(Gross)
Oil and
Natural Gas
Wells
Injection
Wells
Oil and
Natural Gas
Wells
Injection
Wells
Oil and
Natural Gas
Wells
Injection
Wells
611
18
—
629
90
—
—
90
7,328
1,952
7,939
2,042
415
—
—
—
433
—
—
—
7,743
1,952
8,372
2,042
California
Utah
Colorado(1)
Total Identified Drilling Locations
__________
(1) Our properties in Colorado were in the Piceance basin, all of which were all divested in January 2022.
The following tables sets forth information regarding production volumes for fields with equal to or greater than
15% of our total proved reserves for each of the periods indicated:
Year Ended December 31,
2021
2020
2019
SJV Midway Sunset
Total production(1):
Oil (mbbls)
Natural gas (bcf)
NGLs (mbbls)
Total (mboe)(2)
SJV Belridge Hill
Total production(1):
Oil (mbbls)
Natural gas (bcf)
NGLs (mbbls)
Total (mboe)(2)
__________
5,666
—
—
5,666
5,933
—
—
5,933
Year Ended December 31,
2021
2020
2019
1,505
—
—
1,505
1,280
—
—
1,280
5,543
—
—
5,543
1,312
—
—
1,312
(1) Production represents volumes sold during the period.
(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 year ended December 31, 2021, the
average prices of Brent oil and Henry Hub natural gas were $70.95 per bbl and $3.89 per mcf, respectively.
Productive Wells
As of December 31, 2021, we had a total of 3,587 gross (3,417 net) productive wells (including 483 gross and
net steamflood and waterflood injection wells), approximately 95% of which were oil wells. Our average working
interests in our productive wells is approximately 96%. All of our Uinta basin oil wells produce associated gas and
NGLs and wells in our Piceance basin are primarily gas and also produce condensates. We were participating in 16
steamflood projects and one waterflood project located in the San Joaquin basin, and one waterflood project located
in the Uinta basin.
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The following table sets forth our productive oil and natural gas wells (both producing and capable of
producing) as of December 31, 2021.
California
(San Joaquin basin)
Utah
(Uinta basin)
Colorado
(Piceance basin)
Total
2,448
2,374
—
—
970
922
—
—
—
—
169
121
3,418
3,296
169
121
Oil
Gross(1)
Net(2)
Gas
Gross(1)(3)
Net(2)(3)
__________
(1) The total number of wells in which interests are owned. Includes 483 steamflood and waterflood injection wells in California.
(2) The sum of fractional interests.
(3) Excludes 90 wells in the Piceance basin each with a 5% working interest.
Acreage
The following table sets forth certain information regarding the total developed and undeveloped acreage in
which we owned an interest as of December 31, 2021.
Developed(1)
Gross(2)
Net(3)
Undeveloped(4)
Gross(2)
Net(3)
__________
California
(San Joaquin basin)
Utah and Other
(Uinta and Piceance basins)
Total
7,078
7,053
11,746
7,059
47,863
43,346
68,465
53,542
54,941
50,399
80,211
60,601
(1) Acres spaced or assigned to productive wells.
(2) Total acres in which we hold an interest.
(3) Sum of fractional interests owned based on working interests or interests under arrangements similar to production sharing contracts.
(4) Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and
natural gas, regardless of whether the acreage contains proved reserves.
Participation in Wells Being Drilled
As of December 31, 2021, we were not participating in any uncompleted wells.
Drilling Activity
The following table shows the net development wells we drilled during the periods indicated. We did not drill
any exploratory wells during the periods presented. The information should not be considered indicative of future
performance, nor should it be assumed that there is necessarily any correlation among the number of productive
wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable
of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.
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California
(San Joaquin and
Ventura basins(3))
Utah
(Uinta basin)
Colorado
(Piceance basin)
Total
181
—
—
45
—
—
335
—
—
10
—
—
—
—
—
3
—
—
—
—
—
—
—
—
—
—
—
191
—
—
45
—
—
338
—
—
2021
Oil(1)
Natural Gas
Dry
2020
Oil(1)
Natural Gas
Dry
2019
Oil(1)(2)
Natural Gas
Dry
__________
(1)
(2)
Includes injector wells.
Includes 50 wells that had not yet been connected to gathering systems in California.
(3) Effective October 2021, we completed the sale of our Placerita Field property in the Ventura Basin in Los Angeles County, California,
which included 1 well in 2019, 1 well in 2020 and zero wells in 2021.
Delivery Commitments
We have contractual agreements to provide gas volumes for processing, some of which specify fixed and
determinable quantities and all of which were in Utah. As of December 31, 2021, the volumes contracted to be
processed were approximately 4,560 mcf/d through February 2023. We have significantly more production than the
amounts committed for delivery and have the ability to secure additional volumes of products as needed.
Methods of Recovery and Marketing Arrangements
We seek to be the operator of our properties so that we can develop and implement drilling programs and
optimization projects that not only replace production but add value through reserve and production growth and
future operational synergies. We have an average of 95% working interest for operated wells and 98% operating
control in our properties.
Our California operations are primarily focused on the thermal Sandstones, thermal Diatomite and Hill
Diatomite, development areas. We also have operations in the Uinta basin in Utah, as noted in the following table.
State
Project Type
Well Type
Completion Type
California
Thermal Sandstones
Vertical /
Horizontal
Perforation/Slotted liner/
gravel pack
California
Thermal Diatomite
Vertical
Short interval perforations
California
Hill Diatomite (non-
thermal)
Utah
Uinta
Vertical
Vertical /
Horizontal
Hydraulic stimulation, low
intensity pin point
Low intensity hydraulic
stimulation
Recovery Mechanism
Continuous and cyclic steam
injection
High-pressure cyclic steam
injection
Pressure depletion augmented
with water injection
Pressure depletion
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Enhanced Oil Recovery
Most of our assets in California consist of heavy crude oil, which requires heat, supplied in the form of steam,
injected into the oil producing formations to reduce the oil viscosity, thereby allowing the oil to flow to the wellbore
for production. We have cyclic and continuous steam injection projects in the San Joaquin basin, primarily in Kern
County and in fields such as Midway-Sunset, South Belridge, McKittrick, and Poso Creek. This technique has many
years of demonstrated success in thousands of wells drilled by us and others. Historically, we start production from
heavy oil reservoirs with cyclic injection and then expand operations to include continuous injection in adjacent
wells. We intend to continue employing both recovery techniques as long as a favorable oil to gas price spread
exists. Full development of these projects typically takes multiple years and involves upfront infrastructure
construction for steam and water processing facilities and follow on development drilling. These thermal recovery
projects are generally shallower in depth (600 to 2,500 ft) than our other programs and the wells are relatively
inexpensive to drill and complete at approximately $400,000 per well. Therefore, we can normally implement a
drilling program quickly with attractive rates of return.
Cogeneration Steam Supply and Conventional Steam Generation
We produce oil from heavy crude reservoirs using steam to heat the oil so that it will flow to the wellbore for
production. To assist in this operation, we own and operate four natural gas burning cogeneration plants that produce
electricity and steam: (i) a 38 MW facility (“Cogen 38”), an 18 MW facility (“Cogen 18”) and a 5 MW facility
(“Pan Fee Cogen”), each located in the Midway-Sunset Field and (ii) another 5MW facility (“21Z Cogen”) located
in the McKittrick Field. Cogeneration plants, also referred to as combined heat and power plants, use hot turbine
exhaust to produce steam while generating electrical power. This combined process is more efficient than producing
power or steam separately. For more information please see “—Electricity.” and “Item 1A. Risk Factors—Risks
Related to Our Operations and Industry—We are dependent on our cogeneration facilities to produce steam for
our operations. Contracts for the sale of surplus electricity, economic market prices and regulatory conditions
affect the economic value of these facilities to our operations.”
We own 62 fully permitted conventional steam generators. The number of generators operated at any point in
time is dependent on (i) the steam volume required to achieve our targeted injection rate and (ii) the price of natural
gas compared to our oil production rate and the realized price of oil sold. Ownership of these varied steam
generation facilities allows for maximum operational control over the steam supply, location and, to some extent, the
aggregated cost of steam generation. The natural gas we purchase to generate steam and electricity is primarily
based on California price indexes, and in some cases includes transportation charges.
Marketing Arrangements
We market crude oil, natural gas, NGLs, gas purchasing and electricity.
Crude Oil. Approximately 92% of our California crude oil production is connected to California markets via
crude oil pipelines. We generally do not transport, refine or process the crude oil we produce and do not have any
long-term crude oil transportation arrangements in place. California oil prices are Brent-influenced as California
refiners import approximately 65% to 70% of the state’s demand from OPEC+ countries and other waterborne
sources. This dynamic has led to periods, including recent years, where the price for the primary benchmark,
Midway-Sunset, a 13° API heavy crude, has been equal to or exceeded the price for WTI, a light 40° API crude.
Without the higher costs associated with importing crude via rail or supertanker, we believe our in-state production
and low transportation costs, coupled with Brent-influenced pricing, will allow us to continue to realize strong cash
margins in California. Our oil production is primarily sold under market-sensitive contracts that are typically priced
at a differential to purchaser-posted prices for the producing area. We sell all of our oil production under short-term
contracts. The waxy quality of oil in Utah has historically limited sales primarily to the Salt Lake City market, which
is largely dependent on the supply and demand of oil in the area. The recent success of a tight oil play in the basin
has increased supply and put downward pressure on physical oil prices. Due to these circumstances, we are
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endeavoring to sell our crude to markets outside the basin. Export options to other markets via rail are available and
have been used in the past, but are comparatively expensive. We also entered into oil hedges to protect our operating
expenses from price fluctuations.
Natural Gas. Our natural gas production is primarily sold under market-sensitive contracts that are typically
priced at a differential to the published natural gas index price for the producing area. Our natural gas production is
sold to purchasers under seasonal spot price or index contracts. We sell all of our natural gas and NGL production
under short-term contracts at market-sensitive or spot prices. In certain circumstances, we have entered into natural
gas processing contracts whereby the residual natural gas is sold under short-term contracts but the related NGLs are
sold under long-term contracts. In all such cases, the residual natural gas and NGLs are sold at market-sensitive
index prices.
NGLs. We do not have long-term or long-haul interstate NGL transportation agreements. We sell substantially
all of our NGLs to third parties using market-based pricing. Our NGL sales are generally pursuant to processing
contracts or short-term sales contracts.
Gas Purchasing. We enter into hedges for gas purchases to protect our operating expenses from price
fluctuations. We also have long-term 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.
Electricity Generation. Our cogeneration facilities generate both electricity and steam for our properties and
electricity for off-lease sales. The total nameplate electrical generation capacity of our four cogeneration facilities,
which are centrally located on certain of our oil producing properties, is approximately 66 MW. The steam
generated by each facility is capable of being delivered to numerous wells that require steam for our thermal
recovery processes. The main purpose of the cogeneration facilities is to reduce the steam and electricity costs in our
heavy oil operations.
Electricity and steam produced from our Pan Fee and 21Z cogeneration facilities are used solely for field
operations.
For the year ended December 31, 2021, excluding the Placerita cogeneration facility which we divested in
October 2021, we sold approximately 383,000 megawatt-hours (“MWhs”) per day of cogen power into the grid and
on average consumed approximately 291 MWhs per day of cogen power for lease operations. The four cogeneration
facilities produced an average of approximately 25,000 barrels of steam per day. Contracts for the sale of surplus
electricity, economic market prices and regulatory conditions affect the economic value of these facilities to our
operations.
Electricity Sales Contracts. We sell electricity produced by two of our cogeneration facilities under long-term
PPAs approved by the California Public Utilities Commission (the “CPUC”) to two California investor-owned
utilities, Southern California Edison Company (“Edison”) and Pacific Gas and Electric (“PG&E”). These PPAs
expire in various years between 2022 and 2026.
Principal Customers
For the year ended December 31, 2021, sales to Tesoro Refining and Marketing, PBF Holding, Kern Oil &
Refining, and Phillips 66 accounted for approximately 30%, 16%, 14%, and 12% respectively, of our sales. At
December 31, 2021, trade accounts receivable from three customers represented approximately 28%, 13% and 11%
of our receivables.
If we were to lose any one of our major oil and natural gas purchasers, the loss could cease or delay production
and sale of our oil and natural gas in that particular purchaser’s service area and could have a detrimental effect on
the prices and volumes of oil, natural gas and NGLs that we are able to sell. For more information related to
marketing risks, see “Item 1A. Risk Factors—Risks Related to Our Operations and Industry”.
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Title to Properties
As is customary in the oil and natural gas industry, we initially conduct only a preliminary review of the title to
our properties at the time of acquisition. Prior to the commencement of drilling operations on those properties, we
conduct a more thorough title examination and perform curative work with respect to significant defects. We do not
commence drilling operations on a property until we have cured known title defects on such property that are
material to the project. Individual properties may be subject to burdens that we believe do not materially interfere
with the use or affect the value of the properties. Burdens on properties may include customary royalty interests,
liens incident to operating agreements and for current taxes, obligations or duties under applicable laws,
development obligations, or net profits interests.
Competition
The oil and natural gas industry is highly competitive. In our upstream development and production business,
we historically encounter strong competition from other companies, including independent operators in acquiring
properties, contracting for drilling and other related services, and securing trained personnel. We also are affected by
competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has
experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and
has caused significant price increases. The lower-cost, commoditized nature of our equipment and service providers
partially insulates us from the cost inflation pressures experienced by producers in unconventional plays. We are
unable to predict when, or if, such shortages may occur or how they would affect our drilling program.
Through CJWS we provide services in the California market where our competitors are comprised of both small
regional contractors as well as larger companies with international operations. Our revenues and earnings can be
affected by several factors, including changes in competition, fluctuations in drilling and completion activity,
perceptions of future prices of oil and gas, government regulation, disruptions caused by weather, pandemics and
general economic conditions. We believe that the principal competitive factors are price, performance, service
quality, safety, and response time. For more information regarding competition and the related risks in the oil and
natural gas industry, please see “Item 1A. Risk Factors—Risks Related to Our Operations and Industry—
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties,
market oil or natural gas and secure trained personnel. ”
We also face indirect competition from alternative energy sources, such as wind or solar power, and these
alternative energy sources could become even more competitive as California and the federal government develop
renewable energy and climate-related policies.
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 may have been and in the future may be impacted by ice and snow in
the winter, especially in Utah, and by electrical storms and high temperatures in the spring and summer, as well as
by wild fires and rain.
Natural gas prices can fluctuate based on seasonal and other market-related impacts. We purchase significantly
more gas than we sell to generate steam and electricity in our cogeneration facilities for our producing activities. 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. We recently
entered into new pipeline capacity agreements for the shipment of natural gas from the Rockies to our operations in
California, which are typically lower cost gas prices.
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Regulatory Matters
Regulation of the Oil and Gas Industry
Like other companies in the oil and gas industry, our operations are subject to a wide range of complex federal,
state and local laws and regulations. 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 exploration, development and production in California,
including:
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oil and natural gas production, including siting and spacing of wells and facilities on federal, state and
private lands with associated conditions or mitigation measures;
methods of constructing, drilling, completing, stimulating, operating, inspecting, maintaining and
abandoning wells;
the design, construction, operation, inspection, maintenance and decommissioning of facilities, such as
natural gas processing plants, power plants, compressors and liquid and natural gas pipelines or gathering
lines;
techniques for improved or enhanced recovery, such as steam or fluid injection for pressure management;
the sourcing and disposal of water used in the drilling, completion, stimulation, maintenance and improved
or enhanced recovery processes;
the posting of bonds or other financial assurance to drill, operate and abandon or decommission wells and
facilities; and
the transportation, marketing and sale of our products.
Collectively, the effect of the existing laws and regulations is to potentially 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, and reduce the amount of oil and natural gas that we can produce from our wells below levels that would
otherwise be possible. Additionally, the regulatory burden on the industry increases our 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 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.
The California Department of Conservation’s Geologic Energy Management Division (“CalGEM”) is
California's primary regulator of the oil and natural gas drilling and production activities on private and state lands,
with additional oversight from the State Lands Commission’s administration of state surface and mineral interests,
as well as other state and local agencies. The Bureau of Land Management (“BLM”) of the U.S. Department of the
Interior exercises similar jurisdiction on federal lands in California, on which CalGEM also asserts jurisdiction over
certain activities. The California Legislature has significantly increased the jurisdiction, duties and enforcement
authority of CalGEM, the State Lands Commission and other state agencies with respect to oil and natural gas
activities in recent years, and CalGEM and other state agencies have also significantly revised their regulations,
regulatory interpretations and data collection and reporting requirements. In addition, from time to time legislation
has been introduced in the California State Legislature seeking to further restrict or prohibit certain oil and gas
operations, and the U.S. Congress and federal agencies also regularly seek to revise environmental laws and
regulations.
A discussion of the potential impact that government regulations, including those regarding environmental
matters, may have upon our business, operations, capital expenditures, earnings and competitive position follows.
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For more information related to the regulatory risks that could potentially have a material effect on the Company,
see “Item 1A. Risk Factors—Risks Related to Our Operations and Industry”.
California Permitting Considerations
The issuance of permits and other approvals for drilling and production activities by state and local agencies or
by federal agencies may be subject to environmental reviews under the California Environmental Quality Act
(“CEQA”) or the National Environmental Policy Act (“NEPA”), respectively, which may result in delays in the
issuance of such permits and approvals and the imposition of mitigation measures or restrictions, among other
things. For example, before an operator can pursue drilling operations in California, they must first obtain local
government permission to engage in an oil and gas production land use, which requires the local government to
conduct a CEQA-compliant review to evaluate the environmental impact that the proposed land use may cause,
including on habitat, neighboring communities, air quality, water quality, and other environmental considerations.
CEQA imposes similar obligations on permitting decisions by state and local agencies. Prior to issuing the permits
necessary for the conduct of certain operations (for example, to drill a new well), CalGEM requires an operator to
identify the manner in which CEQA has been satisfied, typically through either an environmental review or an
exemption by a state or local agency.
In Kern County, where all of our California assets are now located, we historically have satisfied CEQA by
complying with the local oil and gas ordinance, which was supported by an Environmental Impact Report (“Kern
County EIR”) covering oil and gas operations in Kern County which was certified by the Kern County Board of
Supervisors in 2015. In addition to CalGEM, other state agencies have relied on the Kern County EIR to satisfy the
CEQA requirements in connection with permitting and project approval decisions for oil and gas projects in
unincorporated Kern County. In 2020, a group of plaintiffs challenged 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 elected to prepare a supplemental EIR which was approved by the Kern County
Board of Supervisors in March 2021. Following further challenges by plaintiffs in March 2021, a Kern County
Superior Court judge suspended use of the supplemental EIR, stopping the issuance of new oil and gas permits by
Kern County (the “Kern County Permit Suspension”) in October 2021, pending judicial review of the supplemental
EIR and a determination of its compliance with CEQA requirements by the Kern County Superior Court. A hearing
on the matter by the Kern County Superior Court is scheduled for April 2022. We cannot predict the outcome of this
hearing on the Kern County EIR or whether it will result in the imposition of more onerous permit requirements or
other requirements or restrictions on land use and exploration and production activities.
Importantly, the Kern County Ruling and the Kern County Permit Suspension did not invalidate existing
permits and our plans and operations have not been materially impacted to date. Until Kern County is able to
resolve the challenges regarding the sufficiency of the Kern County EIR and resume the ability to issue permits, our
ability to obtain new permits and approvals to enable our future plans in Kern County requires demonstrating to
CalGEM compliance with CEQA. Demonstrating compliance with CEQA without being able to reference the Kern
County EIR is a more technically, time and cost intensive process and may, among other things, require that we
conduct an environmental impact review. As a result, we together with other Kern County operators have
experienced delays in the issuance of permits by CalGEM, as well as a more time- and cost- intensive permitting
process. Approximately 10% of our current 2022 production plans is expected to come from the drilling of new
wells, which requires the issuance of new permits, and the workover of existing wells; our existing producing wells
are expected to contribute the other 90%. We believe that we have sufficient permit inventory to cover our drilling
plans through the first quarter of 2022. However, our drilling plans for the remainder of the year, and therefore our
current 2022 production goals, may be impacted by our ability to timely obtain the required permits and approvals to
support those planned activities, particularly if the Kern County Permit Suspension continues or if there are further
delays in or new restrictions imposed upon the issuance or renewal of permits and approvals required for oil and gas
activities in Kern County. If we are unable to obtain the permits required to support our current 2022 drilling plans,
we may reduce our planned capital expenditures or deploy that capital to other activities. Additionally, any
postponement or elimination of our development drilling program could result in a reduction of proved reserves
volumes and materially affect our business, financial condition and results of operations. In the future, if we are
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unable to obtain the required permits and approvals needed to conduct our operations, including our development
drilling program, on a timely basis or at all our business, financial condition and results of operations could be
adversely impacted.
Separately, in February 2021, the Center for Biological Diversity filed suit against CalGEM alleging that its
reliance on the Kern County EIR for oil and gas decisions violates CEQA, and that an independent environmental
impact review in compliance with CEQA is required by CalGEM before the agency can issue oil and gas permits
and approvals. The lawsuit is ongoing and we cannot predict its ultimate outcome or whether it could result in
changes to the requirements for demonstrating compliance with CEQA and permitting process, even if the Kern
County EIR is ultimately deemed sufficient and reinstated.
California Underground Injection Control Regulations
The federal Safe Drinking Water Act (“SDWA”) and the Underground Injection Control (“UIC”) program
promulgated under the SDWA and relevant state laws regulate the drilling and operation of injection and disposal
wells that manage produced water (brine wastewater containing salt and other constituents produced by oil and
natural gas wells). Permits must be obtained before developing and using deep injection wells for the disposal of
produced water or for enhanced oil recovery, and well casing integrity monitoring must be conducted periodically to
ensure the well casing is not leaking produced water to groundwater. The EPA directly administers the UIC program
in some states, and in others, such as California, administration is delegated to the state.
Effective April 2019, CalGEM finalized new UIC regulations, which affects specific types of wells: (i) those
that inject water or steam for enhanced oil recovery and (ii) those that return the briny groundwater that comes up
from oil formations during production. The key regulations include stronger testing requirements designed to
identify potential leaks, increased data requirements to ensure proposed projects are fully evaluated, continuous well
pressure monitoring, requirements to automatically cease injection when there is a risk to safety or the environment,
and requirements to disclose chemical additives for injection wells close to water supply wells. Notwithstanding
these changes, separately, in September 2021 the U.S. Environmental Protection Agency (“EPA”) issued a letter to
the California Natural Resources Agency and the State Water Resources Control Board regarding California’s
compliance with a 2015 compliance plan relating to the State’s process for approving aquifer exemptions under the
UIC regulations and submitting those approvals to EPA for review. The letter requested that California take
appropriate action by September 2022, or the EPA would consider taking additional action to impose limits on
California’s administration of the UIC program, withhold federal funds for the administration of the UIC program,
and direct orders to oil and gas operators injecting into formations not authorized by EPA, amongst other measures.
The State responded in October 2021 with a proposed compliance plan but, to date, EPA has not yet responded.
Additional limitations on injection well operations increased federal oversight of the UIC permitting process, or a
lack of funds for the State to administer permits under the UIC program all have the potential to adversely affect our
operations and result in increased operational and compliance costs.
Uncertainty surrounding compliance with UIC regulations has from time to time resulted in delays in obtaining
UIC permits for enhanced oil recovery, disposal of oilfield wastes and injection wells, which in turn can delay our
ability to obtain other permits needed to conduct for our planned operations. Moreover, concerns related to potential
groundwater contamination issues have resulted in increased scrutiny with respect to UIC permitting and other oil
and gas activities in California. It is possible that more stringent regulations or restrictions on our ability to obtain
UIC permits for enhanced oil recovery and disposal of oilfield wastes could be imposed upon our operations in the
future. Additionally, CalGEM has indicated that is coordinating with the State Water Resources Control Board to
propose rules regarding enhanced reviews for injection well permitting decisions. Any such changes could adversely
impact our operations. For example, while “infill drilling” has been considered exempt from certain CalGEM
permitting requirements in the past, such as the need to obtain a new project approval letter (“PAL“), CalGEM
appears to be limiting the instance where it considers proposed drilling as “infill” of areas already given over to
oilfield uses and impacts. An infill well occurs when an operator seeks to change the location of an active injection
well or add a new injection well not previously identified in the project application. Changes in the process for
approving infill wells has the potential to delay permitting injection and other activities, or otherwise result in
increased compliance costs on our operations. Our 2022 plans, as well as potentially our future plans, may be
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impacted by an inability to timely obtain certain permits needed to carry out our drilling and development plans due
to a delay in obtaining the requisite UIC permits. In the past, we have been able to modify our drilling and
development plans and obtain the permits necessary to support ongoing operations despite these permitting
uncertainties, but there can be no guarantee that we continue to successfully manage these issues in the future.
California Idle Well Regulations
In California, an idle well is one that has not been used for two years or more and has not yet been permanently
sealed pursuant to CalGEM regulations. An idle well that has been abandoned by the operator and as a result
becomes a burden of the State is referred to as an orphan well. In April 2019, CalgGEM issued updated idle well
regulations, including a comprehensive well testing regime to demonstrate the mechanical integrity of idle wells, a
compliance schedule for testing or plugging and abandoning idle wells, the collection of data necessary to prioritize
testing and plugging idle wells that will not return to service, an engineering analysis for each well idled 15 years or
longer, and requirements for active observation wells. Additionally, operators are required to either submit annual
idle well management plans describing how they will plug and abandon or reactivate a specified percentage of long-
term idle wells or pay additional annual fees and perform additional testing to retain greater flexibility to return
long-term idle wells to service in the future. Also, in 2019, the Governor of California signed AB 1057, legislation
requiring CalGEM to study and prioritize idle wells with emissions, evaluate costs of abandonment,
decommissioning and restoration, and review and update associated indemnity bond amounts from operators if
warranted, up to a specified cap. This legislation also expanded CalGEM’s duties, effective January 1, 2020, to
include public health and safety and reducing or mitigating greenhouse gas emissions while meeting the state’s
energy needs.
We have submitted an idle well management plan and are fulfilling the conditions of that plan to meet our
obligations. In 2021, we spent approximately $19 million on plugging and abandonment activities, exceeding our
annual obligation requirements under our idle well management plan. In 2022 we expect to spend approximately
$21 million to $24 million for such activities and we again plan to stay ahead of our annual plugging and
abandonment obligations in keeping with our commitments to be a responsible operator.
Additionally, in the fourth quarter of 2021, we acquired C&J Well Services, a profitable new business line, to
provide standard well services to the industry in California and to accelerate the reduction of fugitive emissions by
plugging and abandoning idle wells across California for ourselves and other operators, as well as the State of
California. We believe that C&J Well Services is uniquely positioned to capture both state and federal funds to help
remediate orphan idle wells (an idle well that has been abandoned by the operator and as a result becomes a burden
of the State is referred to as an orphan well), and there are approximately 35,000 idle wells estimated to be in
California according to third-party sources.
Additional Actions Impacting Oil and Gas Activities in California
In September 2020, the California Governor issued an executive order that seeks to reduce both the supply of
and demand for fossil fuels in the state. The executive order established several goals and directed several state
agencies to take certain actions with respect to reducing emissions of greenhouse gases, including, but not limited to:
phasing out the sale of emissions-producing vehicles; developing strategies for the closure and repurposing of oil
and gas facilities in California; and calling on the California State Legislature to enact new laws prohibiting
hydraulic fracturing in the state by 2024 (we currently do not perform any hydraulic fracturing in California and our
near term plans do not include the development of assets requiring hydraulic fracturing). The executive order also
directed CalGEM to finish its review of public health and safety concerns from the impacts of oil extraction
activities and propose significantly strengthened regulations. In response to the executive order, in October 2021,
CalGEM released for public comment a “discussion draft” proposed regulation that would prohibit new wells and
facilities within a 3,200-foot setback area from homes, schools, hospitals, nursing homes, and other sensitive
locations. The proposed regulation would also require pollution controls for existing wells and facilities within the
same 3,200-foot setback area. CalGEM is currently in the process of conducting an economic analysis of the
proposed rule. Following this analysis, CalGEM will submit a proposed rule to the Office of Administrative Law
and will begin an additional process of receiving formal comments and refinement of the proposal as needed before
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a final rule can be issued. We continue to assess the impacts of this rule, and we currently anticipate that
approximately 29% of our acreage could be impacted by the setback requirements if finalized as proposed.
Separately, in October 2020, the Governor issued an executive order that established a state goal to conserve at
least 30% of California’s land and coastal waters by 2030 and directed state agencies to implement other measures
to mitigate climate change and strengthen biodiversity. At this time, we cannot predict the potential future actions
that may result from this order or how such may potentially impact our operations.
Restrictions on Oil and Gas Developments on Federal Lands
As of December 31, 2021, approximately 13% and 32% of our net acreage in California and Utah, respectively,
is on federal land, which comprises approximately 14% and 22% of our total proved reserves in California and Utah,
respectively, and approximately 19% and 28% of our PUD locations in California and Utah, respectively. The
potential exists for additional federal restrictions on oil and gas activities on federal lands in the future. For example,
on January 27, 2021, President Biden issued an executive order that suspends the issuance of new leases for oil and
gas development on federal lands to the extent permitted by law and calls for a review of existing leasing and
permitting practices for such activities on federal lands (the order clarifies that it does not restrict such operations on
tribal lands including tribal lands that the federal government merely holds in trust). Although the order does not
apply to existing operations under valid leases, we cannot guarantee that further action will not be taken to curtail oil
and gas development on federal land. The suspension of these federal leasing activities prompted legal action by
several states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a
federal district judge in Louisiana in June 2021, effectively halting implementation of the leasing suspension. The
federal government is appealing the district court decision, but the BLM has scheduled a lease sale to occur in the
first quarter of 2022. Separately, the Department of the Interior (“DOI”) released its report on federal gas leasing
and permitting practices in November 2021, referencing a number of recommendations and an overarching intent to
modernize the federal oil and gas leasing program, including by adjusting royalty and bonding rates, prioritizing
leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife
habitat, conservation, and historical and cultural resources. Implementation of many of the recommendations in the
DOI report will require Congressional action and we cannot predict to the extent to which the recommendations may
be implemented now or in the future, but restrictions on federal oil and gas activities could result in increased costs
and adversely impact our operations.
Operations on Tribal Lands
As of December 31, 2021, approximately 74% of our net acreage in Utah is on tribal lands, which comprises
approximately 74% of our total proved reserves in Utah, and approximately 72% of our PUD locations in Utah;
none of our California assets or operations are located on tribal lands. In addition to potential regulation by federal,
state and local agencies and authorities, an entirely separate and distinct set of laws and regulations promulgated by
the Indian tribe with jurisdiction over such lands applies to lessees, operators and other parties on such lands, tribal
or allotted. These regulations include lease provisions, royalty matters, drilling and production requirements,
environmental standards, tribal employment and contractor preferences and numerous other matters. Further, lessees
and operators on tribal lands may be subject to the jurisdiction of tribal courts, unless there is a specific waiver of
sovereign immunity by the relevant tribe allowing resolution of disputes between the tribe and those lessees or
operators to occur in federal or state court. These laws, regulations and other issues present unique risks that may
impose additional requirements on our operations, cause delays in obtaining necessary approvals or permits, or
result in losses or cancellations of our oil and natural gas leases, which in turn may materially and adversely affect
our operations on tribal lands.
Restrictions on High-Pressure Cyclic Steam and Well Stimulation Treatments
Our California operations are primarily focused on the thermal Sandstones, thermal Diatomite and Hill
Diatomite development areas, of which only our undeveloped thermal diatomite assets require new high-pressure
cyclic steam wells. Our undeveloped thermal diatomite assets currently are not part of our near-term development
plans, nor are any areas in California that would require well stimulation treatments (“WST”) (also known as
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hydraulic stimulation, hydraulic fracturing or fracking). We do rely on other methods of well stimulation and
injection, including the use of cyclic and continuous steam injection, which is heavily regulated. Any restrictions on
the use of those well stimulation treatments or other forms of injection may adversely impact our operations,
including causing operational delays, increased costs, and reduced production. However, our ability to conduct such
activities has not been prohibited or otherwise restricted by recent regulatory actions like the moratorium on
permitting for new high–pressure cyclic steam wells and WST.
As referenced above, in November 2019, the State Department of Conservation issued a press release
announcing three actions by CalGEM: (1) a moratorium on approval of new high–pressure cyclic steam wells
pending a study of the practice to address surface expressions experienced by certain operators; (2) a review and
update of regulations regarding public health and safety near oil and natural gas operations pursuant to additional
duties assigned to CalGEM by the California State Legislature in 2019 (discussed above); (3) a performance audit of
CalGEM's permitting processes for issuing WST permits and PALs for underground injection activities by the State
Department of Finance; and (4) an independent review of the technical content of pending WST and PAL
applications by Lawrence Livermore National Laboratory. In September 2020, the Governor of California issued an
executive order which, among other actions, required CalGEM to complete its public health and safety review and
propose additional regulations and noted the Governor’s intent to seek legislation to end the issuance of new
hydraulic fracturing permits by 2024; the executive order is further discussed above under “- Additional Actions
Impacting Oil and Gas Activities in California.” In January 2020, CalGEM issued a formal notice to operators,
including us, that they had issued restrictions imposing the previously announced moratorium to prohibit new
underground oil-extraction wells from using high-pressure cyclic steaming process. In February of 2022, CalGEM
issued letters to operators who had conducted high pressure cyclic steam operations in the past, indicating that
CalGEM intended to revisit the moratorium on a field-by-field basis, but no further guidance has yet been received
by us to date. Importantly, the moratorium on high-pressure cyclic steam injection did not impact existing
production or previously approved permits and our plans and operations have not been materially impacted to date.
Only our undeveloped thermal diatomite assets require new high-pressure cyclic steam wells and those assets are
currently not in our near-term development plans. Our 2022 plans do not include new high-pressure cyclic steam
wells, nor did our 2020 and 2021 plans. Additionally, we have not been impacted by the hydraulic fracking
announcement as our current plans do not require the development of assets requiring hydraulic fracturing in
California.
Historically, state regulators have overseen hydraulic stimulation operations as part of their oil and natural gas
regulatory programs. However, from time to time, federal agencies have asserted regulatory authority over certain
aspects of the process. In 2016, the EPA issued final regulations regarding, among other things, certain hydraulic
stimulation activities involving the use of diesel fuels and standards for the capture of air emissions released during
hydraulic stimulation. In 2015, the BLM issued regulations regarding the public disclosure of chemicals used in
stimulation treatments, well construction and integrity and management of waste fluids resulting from hydraulic
fracturing activities on federal and tribal lands. While the BLM rescinded these regulations in 2017, the rescission is
subject to ongoing legal challenge. Additionally, the regulations may be reconsidered under the Biden
Administration. If the rule is reinstated, or a similar rule is promulgated, the outcome could materially impact our
operations in the Uinta basin, where as of December 31, 2021, approximately 22% of our proved reserves in Utah
were located on federal lands and approximately 74% were located on tribal lands. In addition, from time to time
legislation has been introduced before Congress that would provide for federal regulation of hydraulic stimulation
and would require disclosure of the chemicals used in the stimulation process. If enacted, these or similar bills could
result in additional permitting requirements for hydraulic stimulation operations as well as various restrictions on
those operations. These permitting requirements and restrictions could materially impact our operations in the Uinta
basin, including due to delays in operations at well sites and also increased costs to make wells productive.
Water Resources
Oil and gas exploration and development activities can be adversely affected by the availability of water.
Drought conditions, competing water uses and other physical disruptions to our access to water could adversely
affect our operations. In recent years, water districts and the California state government have implemented
regulations and policies that may restrict groundwater extraction and water usage and increase the cost of water.
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Water management, including our ability to recycle, reuse and dispose of produced water and our access to water
supplies from third-party sources, in each case at a reasonable cost, in a timely manner and in compliance with
applicable laws, regulations and permits, is an essential component of our operations. As such, any limitations or
restrictions on wastewater disposal or water availability could have an adverse impact on our operations. We treat
and reuse water that is co-produced with oil and natural gas for a substantial portion of our needs in activities such
as pressure management, steam flooding and well drilling, completion and stimulation. We use water supplied from
various local and regional sources, particularly for power plants and to support operations like steam injection in
certain fields. While our production to date has not been materially impacted by restrictions on access to third-party
water sources, we cannot guarantee that there may not be restrictions in the future.
Regulation of Health, Safety and Environmental Matters
The federal health, safety and environmental laws and regulations applicable to us and our operations include,
among others, the following:
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Occupational Safety and Heath Act (“OSHA”), which governs workplace safety and the protection of the
safety and health of workers;
Clean Air Act (the “CAA”), which restricts the emission of air pollutants from many sources through the
imposition of air emission standards, construction and operating permitting programs and other compliance
requirements;
Clean Water Act (the “CWA”), which restricts the discharge of pollutants, including produced waters and
other oil and natural gas wastes, into waters of the United States, a term broadly defined to include, among
other things, certain wetlands;
The Oil Pollution Act of 1990, which amends and augments the CWA and imposes certain duties and
liabilities related to the prevention of oil spills and damages resulting from such spills;
Safe Drinking Water Act (“SDWA”), which, amongst other matters, regulates the drilling and operation of
injection and disposal wells that manage produced water;
Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), which imposes
strict, joint and several liability where hazardous substances have been released into the environment
(commonly known as “Superfund”);
U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”)
regulates safety of oil and natural gas pipelines, including, with some specific exceptions, oil and natural
gas gathering lines;
Energy Independence and Security Act of 2007, which prescribes new fuel economy standards, mandates
for production of renewable fuels and other energy saving measures, which can indirectly affect demand for
our products;
National Environmental Policy Act (“NEPA”), which requires careful evaluation of the environmental
impacts of oil and natural gas production activities on federal lands;
Resource Conservation and Recovery Act (“RCRA”), which governs the management of solid waste
(broadly defined to include liquid and gaseous waste as well);
U.S. Department of Interior regulations, which regulate oil and gas production activities on federal lands
and impose liability for pollution cleanup and damages; and
Endangered Species Act, which restricts activities that may affect endangered and threatened species or
their habitats.
Federal, state and local agencies may assert overlapping authority to regulate in these areas. The State of
California imposes additional laws that are analogous to, and often more stringent than, the federal laws listed
above. Among other requirements and restrictions, these laws and regulations:
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require the acquisition of various permits, approvals and mitigation measures before drilling, workover,
production, underground fluid injection, enhanced oil recovery methods or waste disposal commences, or
before facilities are constructed or put into operation;
establish air, soil and water quality standards for a given region, such as the San Joaquin Valley, conduct
regional, community or field monitoring of air, soil or water quality, and require attainment plans to meet
those regional standards, which may include significant mitigation measures or restrictions on
development, economic activity and transportation in such region;
impose, on federal, state, and
lands, comprehensive environmental analyses,
recordkeeping and reports with respect to operations including preparation of various environmental impact
assessments for certain operations;
jurisdiction
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require the installation of sophisticated safety and pollution control equipment, such as leak detection,
monitoring and control systems, and implementation of inspection, monitoring and repair programs to
prevent or reduce releases or discharges of regulated materials to air, land, surface water or ground water;
restrict the use, types or sources of water, energy, land surface, habitat or other natural resources, require
conservation and reclamation measures;
restrict the types, quantities and concentrations of regulated materials, including oil, natural gas, produced
water or wastes, that can be released or discharged into the environment in connection with drilling and
production activities, or any other uses of those materials resulting from drilling, production, processing,
power generation, transportation or storage activities;
limit or prohibit drilling activities on lands located within coastal, wilderness, wetlands, groundwater
recharge or endangered species inhabited areas, and other protected areas, or otherwise restrict or prohibit
activities that could impact the environment, including water resources, and require the dedication of
surface acreage for habitat conservation;
establish waste management standards or require remedial measures to limit pollution from former
operations, such as pit closure, reclamation and plugging and abandonment of wells or decommissioning of
facilities;
impose substantial liabilities for pollution resulting from operations or for preexisting environmental
conditions on our current or former properties and operations and other locations where such materials
generated by us or our predecessors were released or discharged;
require notice to stakeholders of proposed and ongoing operations;
impose energy efficiency or renewable energy standards on us or users of our products and require the
purchase of allowances to account for our greenhouse gas (“GHG”) emissions if we are unable to reduce
our emissions below the California statewide maximum limit on covered GHG emissions;
restrict the use of oil, natural gas or certain petroleum–based products such as fuels and plastics; and
impose taxes or fees with respect to the foregoing matters;
We believe that maintaining compliance with currently applicable health, safety and environmental laws and
regulations is unlikely to have a material adverse impact on our business, financial condition, results of operations or
cash flows. However, we cannot guarantee this will always be the case given the historical trend of increasingly
stringent laws and regulations. We cannot predict how future laws and regulations, or the reinterpretation of existing
laws and regulations, may impact our properties or operations.
Violations and liabilities with respect to these laws and regulations could result in significant administrative,
civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, and
operational interruptions or shutdowns. among other sanctions and liabilities. The costs of remedying such
conditions may be significant, and remediation obligations could adversely affect our financial condition, results of
operations and prospects. In addition, certain of these laws and regulations may apply retroactively and may impose
strict or joint and several liability on us for events or conditions over which we and our predecessors had no control,
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without regard to fault, legality of the original activities, or ownership or control by third parties. For the year ended
December 31, 2021, we did not incur any material capital expenditures for installation of remediation or pollution
control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require
material capital expenditures during 2022 or that will otherwise have a material impact on our financial position,
results of operations or cash flows.
Regulation of Climate Change and Greenhouse Gas (GHG) Emissions
The potential threat of climate change due to human behaviors continues to attract considerable attention in the
United States and in foreign countries. Numerous proposals have been made and could continue to be made at the
international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as
well as to restrict or eliminate such future emissions. As a result, our development and production operations are
subject to a series of regulatory, political, litigation, and financial risks associated with the production and
processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level.
However, with the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the U.S.
Environmental Protection Agency (“EPA”) has adopted rules that, among other things, establish construction and
operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and
annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States and
together with the U.S. Department of Transportation (“DOT”), implement GHG emissions limits on vehicles
manufactured for operation in the United States.
Additionally, various states and groups of states have adopted or are considering adopting legislation,
regulations or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon
taxes, reporting and tracking programs, and restriction of GHG emissions, such as methane. For example, California,
through the California Air Resources Board (“CARB”) has implemented a cap-and-trade program for GHG
emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach
40% below 1990 levels by 2030. Covered entities must either reduce their GHG emissions or purchase allowances to
account for such emissions. Separately, California has implemented low carbon fuel standard (“LCFS”) and
associated tradable credits that require a progressively lower carbon intensity of the state's fuel supply than baseline
gasoline and diesel fuels. CARB has also promulgated regulations regarding monitoring, leak detection, repair and
reporting of methane emissions from both existing and new oil and gas production facilities.
In September 2018, California adopted a law committing California, the fifth largest economy in the world, to
the use of 100% zero-carbon electricity by 2045, and the Governor of California also signed an executive order
committing California to total economy-wide carbon neutrality by 2045. Additionally, Governor Newsom requested
that the CARB analyze pathways to phase out oil extraction across the state by no later than 2045. We cannot predict
how these various laws, regulations and orders may ultimately affect our operations. However, these initiatives
could result in decreased demand for the oil, natural gas, and NGLs that we produce, or otherwise restrict or prohibit
our operations altogether in California, and therefore adversely affect our revenues and results of operations.
At the international level, the United Nations-sponsored “Paris Agreement” requires member states to
individually determine and submit non-binding emissions reduction targets every five years after 2020. Although the
United States had withdrawn from the Paris Agreement, President Biden signed an executive order on his first day in
office recommitting the United States to the agreement. In February 2021, the United States formally rejoined the
Paris Agreement, and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52%
below 2005 levels by 2030. Additionally, at the 26th Conference of the Parties (“COP26”) in Glasgow in November
2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge, an
initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by
2030, including “all feasible reductions” in the energy sector. The full impact of these actions is uncertain at this
time and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects upon
our operations.
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Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has
resulted in increasing political risks in the United States, including climate change- related pledges made by certain
candidates for public office. These have included promises to pursue actions to limit emissions and curtail the
production of oil and gas, such as banning new leases for production of minerals on federal properties. On January
20, 2021, President Biden issued an executive order calling for increased regulation of methane emissions from the
oil and gas sector; for more information, see our regulatory disclosure titled “Air Emissions”. Subsequently, on
January 27, 2021, President Biden issued an executive order that called for substantial action on climate change,
including, among other things, the increased use of zero-emissions vehicles by the federal government, the
elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across
agencies and economic sectors. Other actions that could be pursued by President Biden may include more restrictive
requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as
other GHG emissions limitations for oil and gas facilities.
Litigation risks are also increasing, as a number of parties have sought to bring suit against oil and natural gas
companies in state or federal court, alleging, among other things, that such companies created public nuisances by
producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible
for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse
effects of climate change for some time but withheld material information from their investors or customers by
failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel
energy companies concerned about the potential effects of climate change may elect in the future to shift some or all
of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy
companies also have become more attentive to sustainable lending practices and some of them may elect not to
provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net
Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130
trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to
set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net
zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the
effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced that it
had joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused
on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve
issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-
related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and
financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs
or development or production activities. Additionally, the Securities and Exchange Commission announced its
intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements
is not yet known, this may result in additional costs to comply with any such disclosure requirements.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations
or other regulatory initiatives that impose more stringent standards for GHG emissions from oil and natural gas
producers such as ourselves or otherwise restrict the areas in which we may produce oil and natural gas or generate
GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for
or erode value for, the oil and natural gas that we produce. Additionally, political, litigation, and financial risks may
result in our restricting or canceling oil and natural gas production activities, incurring liability for infrastructure
damages as a result of climatic changes, or impairing our ability to continue to operate in an economic manner.
Moreover, climate change may also result in various physical risks, such as the increased frequency or intensity of
extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our
operations, as well as those of our operators and their supply chains. Such physical risks may result in damage to our
facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in
response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy
for heating purposes. Such physical risks may also impact our supply chain or infrastructure on which we rely to
produce or transport our products. One or more of these developments could have a material adverse effect on our
business, financial condition and results of operation.
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For more information, please see “Item 1A. Risk Factors—Risks Related to Our Operations and Industry—
Our business is highly regulated and governmental authorities can delay or deny permits and approvals or
change the requirements governing our operations, including the permitting approval process for oil and gas
exploration, extraction, operations and production activities, well stimulation, enhanced production techniques
and fluid injection or disposal, that could increase costs, restrict operations and delay our implementation of, or
cause us to change, our business strategy and plans” and “—Our operations are subject to a series of risks
arising out of the threat of climate change that could result in increased operating costs, limit the areas in which
we may conduct oil and natural gas exploration and production activities, and reduce demand for the oil and
natural gas we produce.”
Human Capital Resources
As of December 31, 2021, we had 1,224 employees, all of whom are located in the United States. Of those, 889
employees joined our organization in the fourth quarter of 2021 with the acquisition of CJWS. Currently, none of
our employees are covered under collective bargaining or union agreements. We also utilize the service of many
third party contractors throughout our operations.
We believe that developing the best talent, promoting a safe and healthy workplace, providing an inclusive
culture, and supporting the well-being of our employees and local communities are critical to the Company's
success. The Compensation Committee of the Board has oversight responsibilities for the Company’s human capital
management policies, processes and practices, including those related to workforce diversity, pay equity and
compensation and incentive structures, employee recruitment, retention and development, and succession planning.
Culture, Core Values and Employee Engagement
We are committed to the well-being of our employees and strive to foster a corporate culture that is reflective of
our core values. We provide development opportunities and financial rewards so that our employees are engaged
and focused on providing safe, affordable, reliable energy for the people of California.
We believe that fair and equitable pay is an essential element of any successful organization and we reward our
talented employees for their hard work, qualities, experience and passion. We offer comprehensive and competitive
benefits that support the health and well-being of our employees and their families, while consistently offering
opportunities for professional growth and development in line with our mission. In addition, the incentive
compensation program for our entire workforce, including our executive team, is tied to company performance on
safety and environmental responsibility, as well as financial stewardship.
We proactively work to make sure all employees are fully engaged and empowered to achieve their potential
and we are committed to attracting, developing and retaining a highly qualified, diverse and value-focused work
force. Our engagement approach centers on transparency and accountability and we use a variety of channels to
facilitate open, direct and honest communication, including open forums with executives through periodic town hall
meetings and continuous opportunities for discussion and feedback between employees and managers, including
performance conversations and reviews. We also survey our employees periodically to assess engagement levels and
satisfaction drivers; the results of the engagement surveys are reviewed by senior management and the Board.
We promote a workplace culture of inclusiveness, dignity and respect for all employees as well as a safe,
appropriate, and productive work environment. Accordingly, we prohibit unlawful harassment and discrimination at
our work facilities, as well as off-site, including business trips, business functions, and company-sponsored events.
In particular, our Code of Conduct prohibits any form of degrading, offensive, or intimidating conduct based on a
person’s race, color, ethnicity, national origin, ancestry, citizenship status, sex, gender identity and/or expression,
sexual orientation, mental disability, physical disability, medical condition, neuro(a)typicality, physical appearance,
genetic information, age, parental status or pregnancy, marital status, religion, creed, political affiliation, military or
veteran status, socioeconomic status or background, and any other characteristic protected by law.
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Berry is similarly dedicated to this policy with respect to recruitment, hiring, placement, promotion, transfer,
training, compensation, benefits, employee activities and general treatment during employment. Our goal is to
reflect the broad spectrum of cultural, demographic, and philosophical differences of the communities where we
operate, and foster a culture that supports and protects diversity. As a result of our efforts, we have attracted and
retained highly talented and experienced women to our workforce in positions across our organization. Currently,
our Board is approximately 33% women, our executive team is 17% women, our senior management team is 30%
women, and our total workforce is approximately 18% women, which we believe is higher than the U.S. industry
average based on available data.
Safe and Healthy Workplace
We promote a safety-first culture. Health and safety considerations are an integral part of our day-to-day
operations and incorporated into the decision-making process for our Board, management and all employees.
Meeting meaningful EH&S organizational metrics, including with respect to health and safety and spill prevention,
is a part of our incentive programs for our entire workforce.
Corporate Information
Our principal executive office is located at 16000 N. Dallas Pkwy, Ste. 500, Dallas, Texas 75248 and our
telephone number at that address is (214) 453-2920. Our web address is www.bry.com. We make certain filings with
the SEC, including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K,
and all amendments and exhibits to those reports. We make such filings available free of charge through our website
as soon as reasonably practicable after they are filed with the SEC. Information contained in or accessible through
our website is not, and should not be deemed to be, part of this report.
Item 1A. Risk Factors
If any of the following risks actually occur, our business, financial condition and results of operations could be
materially and adversely affected and we may not be able to achieve our goals. We cannot assure you that any of the
events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are
not the only risks and uncertainties we face. Additional risks and uncertainties not presently known to us or that we
currently deem immaterial may ultimately materially affect our business.
Summary Risk Factors
The exploration, development and production of oil and natural gas involve highly regulated, high-risk activities
with many uncertainties and contingencies that could adversely affect our business, financial condition, results of
operations and cash flows. The risks and uncertainties described below are among the items we have identified that
could materially adversely affect our business, financial condition, results of operations and cash flows. Before you
invest in our common stock, you should carefully consider the risk factors referenced below and as more fully
described in “Item 1A. Risk Factors” in this Annual Report.
Risks Related to Our Operations and Industry
There are significant uncertainties with respect to obtaining permits for oil and gas activities in Kern County,
where all of our California operations are located, which could impact our financial condition and results of
operations.
•
•
Attempts by the California state government to restrict the production of oil and gas could negatively impact
our operations and result in decreased demand for fossil fuels within the states where we operate.
Our ability to operate profitably and maintain our business and financial condition are highly dependent on
commodity prices, which historically have been very volatile and are driven by numerous factors beyond our
control. If oil prices were to significantly decline for a prolonged period our business, financial condition and
results of operations may be materially and adversely affected.
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•
•
•
•
The marketability of our production is dependent upon the availability of transportation and storage facilities,
most of which we do not control. If we are unable to access such facilities on commercially reasonable terms
or at all, our access to markets for the commodities we produce could be restricted, which would likely cause
interruption to operations, curtailment of production, and reduced revenues, among other adverse
consequences.
Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our
proved reserves and future net cash flows may prove to be lower than estimated.
Unless we replace oil and natural gas reserves, our future reserves and production will decline.
The drilling and production of oil and natural gas involves many uncertainties, some of which we do not
control, that could adversely affect our results.
• We may not drill our identified sites at the times we scheduled or at all.
•
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties,
market oil or natural gas and secure trained personnel.
• We may be unable to make attractive acquisitions or successfully integrate acquired businesses or assets or
enter into attractive joint ventures, and any inability to do so may disrupt our business and hinder our ability
to grow.
• We are dependent on our cogeneration facilities to produce steam for our operations. Contracts for the sale of
surplus electricity, economic market prices and regulatory conditions affect the economic value of these
facilities to our operations.
•
Our producing properties are located primarily in California, making us vulnerable to risks associated with
having operations concentrated in this highly regulated geographic area.
• Most of our operations are in California, much of which is conducted in areas that may be at risk of damage
from fire, mudslides, earthquakes or other natural disasters.
• We may incur substantial losses and be subject to substantial liability claims as a result of catastrophic events.
We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
• We may be involved in legal proceedings that could result in substantial liabilities.
•
•
•
The loss of senior management or technical personnel could adversely affect operations.
Information technology failures and cyberattacks could affect us significantly.
Increasing attention to environmental, social and governance (“ESG”) matters may impact our operations and
our business.
Risks Related to Our Financial Condition
• We may not be able to use a portion of our net operating loss carryforwards and other tax attributes to reduce
our future U.S. federal and state income tax obligations, which could adversely affect our cash flows.
•
•
•
•
Our business requires continual capital expenditures. We may be unable to fund these investments through
operating cash flow or obtain additional capital on satisfactory terms or at all, which could lead to a decline in
our oil and natural gas reserves or production.
Inflation could adversely impact our ability to control our costs, including our operating expenses and capital
costs.
Our hedging activities, including those required by our 2021 RBL facility, limit our ability to realize the full
benefits of increases in commodity prices. We may be unable to, or may choose not to, enter into sufficient
fixed-price purchase or other hedging agreements to fully protect against decreasing spreads between the
price of natural gas and oil on an energy equivalent basis or may otherwise be unable to obtain sufficient
quantities of natural gas to conduct our steam operations economically or at desired levels and our commodity
price risk management activities may prevent us from fully benefiting from price increases and may expose
us to other risks.
Our existing debt agreements have restrictive covenants that could limit our growth, financial flexibility and
our ability to engage in certain activities. In addition, the borrowing base under the RBL Facility is subject to
periodic redeterminations and our lenders could reduce capital available to us for investment.
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• We may not be able to generate sufficient cash to service our indebtedness and may be forced to take other
actions to satisfy our obligations under our debt arrangements, and these efforts may not be successful.
•
Declines in commodity prices, changes in expected capital development, increases in operating costs or
adverse changes in well performance may result in write-downs of the carrying amounts of our assets.
• We have significant concentrations of credit risk with our customers and the inability of one or more of our
customers to meet their obligations or the loss of any one of our major oil and natural gas purchasers may
have a material adverse effect on our business, financial condition, results of operations and cash flows.
Risks Related to Regulatory Matters
•
•
•
•
•
•
•
•
Our business is highly regulated and governmental authorities can delay or deny required permits and
approvals, or change the requirements governing our operations including the permitting approval process for
oil and gas activities that could increase costs, restrict operations, and delay our implementation of, or cause
us to change, our business strategy and plans.
Potential future legislation may generally affect the taxation of natural gas and oil exploration and
development companies and may adversely affect our operations and cash flows.
Derivatives legislation and regulations could have an adverse effect on our ability to use derivative
instruments to reduce the risks associated with our business.
Our operations are subject to a series of risks arising out of the threat of climate change that could result in
increased operating costs, limit the areas in which we may conduct oil and natural gas exploration and
production activities, and reduce demand for the oil and natural gas we produce.
Risks Related to our Capital Stock
There may be circumstances in which the interests of our significant stockholders could be in conflict with the
interests of our other stockholders.
Our significant stockholders and their affiliates are not limited in their ability to compete with us, and the
corporate opportunity provisions in the Certificate of Incorporation could enable our significant stockholders
to benefit from corporate opportunities that might otherwise be available to us.
Future sales of our common stock in the public market could reduce our stock price, and any additional
capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
The payment of dividends will be at the discretion of our board of directors.
• We may issue preferred stock, the terms of which could adversely affect the voting power or value of our
common stock.
•
• We are an “emerging growth company,” and are able to take advantage of reduced disclosure requirements
applicable to “emerging growth companies,” which could make our common stock less attractive to investors.
Our internal control over financial reporting is not currently required to meet all of the standards of Section
404 of the Sarbanes-Oxley Act, but failure to achieve and maintain effective internal control over financial
reporting in accordance with Section 404 of the Sarbanes-Oxley Act standards could adversely affect our
business and share price.
•
•
•
Certain provisions of our Certificate of Incorporation and Bylaws may make it difficult for stockholders to
change the composition of our board of directors and may discourage, delay or prevent a merger or
acquisition that some stockholders may consider beneficial.
Our Certificate of Incorporation designates the Court of Chancery of the State of Delaware as the sole and
exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which
could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors,
officers, employees or agents.
Changes in the method of determining London Interbank Offered Rate (“LIBOR”), or the replacement of
LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt.
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Risks Related to Our Operations and Industry
The risks and uncertainties described below are among the items we have identified that could materially
adversely affect our business, production, strategy, growth plans, acquisitions, hedging, reserves quantities or value,
operating or capital costs, financial condition, results of operations, liquidity, cash flows, our ability to meet our
capital expenditure plans and other obligations and financial commitments, and our plans to return capital.
There are significant uncertainties with respect to obtaining permits for oil and gas activities in Kern County,
where all of our California operations are located, which could impact our financial condition and results of
operations.
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 approval for our operations until a demonstration of
compliance with CEQA has been made. There have been a number of developments at both the California state and
local level that have resulted in delays in the issuance of permits for oil and gas activities in Kern County, as well as
a more time- and cost- intensive permitting process. In we are unable to timely receive the permits and other
approvals needed for our 2022 plans, or for our future plans, our financial condition, results of operations and
prospects could be adversely and materially impacted.
In Kern County, where all of our California assets are now located, we historically have satisfied CEQA by
complying with the local oil and gas ordinance, which was supported by an Environmental Impact Report (“Kern
County EIR”) covering oil and gas operations in Kern County which was certified by the Kern County Board of
Supervisors in 2015. In addition to CalGEM, other state agencies have relied on the Kern County EIR to satisfy the
CEQA requirements in connection with permitting and project approval decisions for oil and gas projects in
unincorporated Kern County. However, a group of plaintiffs challenged 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 elected to prepare a supplemental EIR which was approved by the Kern County
Board of Supervisors in March 2021. Following further challenges by plaintiffs in March 2021, a Kern County
Superior Court judge suspended use of the supplemental EIR, stopping the issuance of new oil and gas permits by
Kern County (the “Kern County Permit Suspension”) in October 2021, pending judicial review of the supplemental
EIR and a determination of its compliance with CEQA requirements by the Kern County Superior Court. A hearing
on the matter by the Kern County Superior Court is scheduled for April 2022. We cannot predict the outcome of this
hearing on the Kern County EIR as supplemented or whether it will result in the imposition of more onerous permit
application requirements or other requirements or restrictions on land use and exploration and production activities.
Importantly, the Kern County Ruling and the Kern County Permit Suspension did not invalidate existing
permits and our plans and operations have not been materially impacted to date. Until Kern County is able to
resolve the challenges regarding the sufficiency of the Kern County EIR and resume the ability to issue permits,
CalGEM is serving as lead agency for CEQA purposes and our ability to obtain new permits and approvals to enable
our future plans in Kern County requires demonstrating to CalGEM an alternative way of complying with CEQA.
Demonstrating compliance with CEQA independently - without being able to reference the Kern County EIR - is a
more technically, time and cost intensive process and may, among other things, require that we conduct an
environmental impact review. As a result, we together with other Kern County operators have experienced delays in
the issuance of permits by CalGEM, as well as a more time- and cost- intensive permitting process. We believe that
we currently have sufficient permit inventory to cover our drilling plan through the first quarter of 2022. However,
our 2022 plans may be impacted by our ability to timely obtain the required permits and approvals to conduct
planned operations through the remainder of the year, particularly if the Kern County Permit Suspension continues
or if there are further delays in or new restrictions imposed upon the issuance or renewal of permits covering oil and
gas activities in Kern County. If we are unable to obtain the required permits and approvals needed to conduct our
operations on a timely basis or at all our financial condition, results of operations and prospects could be adversely
and materially impacted.
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Separately, in February 2021, the Center for Biological Diversity filed suit against CalGEM alleging that its
reliance on the Kern County EIR for oil and gas decisions violates CEQA, and that an independent environmental
impact review in compliance with CEQA is required by CalGEM before the agency can issue oil and gas permits
and approvals. The lawsuit is ongoing and we cannot predict its ultimate outcome or whether it could result in
changes to CalGEM’s requirements for compliance with CEQA, even if the Kern County EIR is ultimately deemed
sufficient and reinstated. The potential impact of this and potentially future litigation contributes to the uncertainty
with respect to future requirements for demonstrating compliance with CEQA and therefore our ability to timely
obtain the permits and approvals needed to conduct our operations.
Changes to the CEQA compliance requirements or the other conditions and requirements for permit issuance or
renewal, including the imposition of new or more stringent environmental reviews or stricter operational or
monitoring requirements, or a prohibition on the issuance of new permits for oil and has activities in Kern County or
California as a whole, would have an adverse and material effect on our financial condition, results of operations and
prospects. For additional information, see “Items 1 and 2. Business and Properties—Regulation of Health, Safety
and Environmental Matters”.
Attempts by the California state government to restrict the production of oil and gas could negatively impact our
operations and result in decreased demand for fossil fuels within the states where we operate.
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. Federal, state and local laws and regulations govern most
aspects of exploration and production in California. Collectively, the effect of the existing laws and regulations is to
potentially 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, and reduce the amount of oil and natural gas that we
can produce from our wells below levels that would otherwise be possible. Several bills have been introduced
recently but failed to advance in the California State Legislature that restrict or prohibit the issuance or renewal of
permits for various well stimulation and recovery techniques. Although these legislative efforts have failed, we
cannot predict the outcome of future efforts. What's more, the regulatory burden on the industry increases our costs
and consequently may have an adverse effect upon capital expenditures, earnings or competitive position. Violations
and liabilities with respect to these laws and regulations could 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 prospects.
Additionally, the California state government recently has taken several actions that could adversely impact
future oil and gas production and other activities in the state. For example:
•
In November 2019, the State Department of Conservation issued a press release announcing three
actions by CalGEM: (1) a moratorium on approval of new high–pressure cyclic steam wells pending a
study of the practice to address surface expressions experienced by certain operators; (2) a review and
update of regulations regarding public health and safety near oil and natural gas operations pursuant to
additional duties assigned to CalGEM by the California State Legislature in 2019 (discussed above); (3) a
performance audit of CalGEM's permitting processes for issuing WST permits and project approval letters
(“PALs“) for underground injection activities by the State Department of Finance; and (4) an independent
review of the technical content of pending WST and PAL applications by Lawrence Livermore National
Laboratory. In January 2020, CalGEM issued a formal notice to operators, including us, that they had
issued restrictions imposing the previously announced moratorium to prohibit new underground oil-
extraction wells from using high-pressure cyclic steaming process. The moratorium on permitting for new
high–pressure cyclic steam wells and restrictions on WST remains in effect.
•
In September 2020, the California Governor issued an executive order that seeks to reduce both
the supply of and demand for fossil fuels in the state. The executive order established several goals and
directed several state agencies to take certain actions with respect to reducing emissions of greenhouse
gases, including, but not limited to: (1) phasing out the sale of emissions-producing vehicles; (2)
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developing strategies for the closure and repurposing of oil and gas facilities in California; and (3) calling
on the California State Legislature to enact new laws prohibiting hydraulic fracturing in the state by 2024.
The executive order also directed CalGEM to finish its review of public health and safety concerns from the
impacts of oil extraction activities and propose significantly strengthened regulations.
•
In October 2020, the California Governor issued an executive order that established a state goal to
conserve at least 30% of California’s land and coastal waters by 2030 and directed state agencies to
implement other measures to mitigate climate change and strengthen biodiversity. At this time, we cannot
predict the potential future actions that may result from this order or how such may potentially impact our
operations.
•
In October 2021, CalGEM released for public comment a “discussion draft” proposed regulation
that would prohibit new wells and facilities within a 3,200-foot setback area from homes, schools,
hospitals, nursing homes, and other sensitive locations. The proposed regulation would also require
pollution controls for existing wells and facilities within the same 3,200-foot setback area. CalGEM is
currently in the process of conducting an economic analysis of the proposed rule. Following this analysis,
CalGEM will submit a proposed rule to the Office of Administrative Law and will begin an additional
process of receiving formal comments and refinement of the proposal as needed before a final rule can be
issued. We continue to assess the impacts of this rule, and we currently anticipate that approximately 29%
of our acreage could be impacted by the setback requirements if finalized as proposed.
In February 2021, California State Senators Scott Wiener and Monique Limón introduced Senate Bill 467,
which proposes to halt the issuance or renewal of permits for hydraulic fracturing, acid well stimulation treatments,
cyclic steaming, and water and steam flooding starting January 1, 2022, and then prohibit these extraction methods
entirely starting January 1, 2027. SB 467 also would have prohibited all new or renewed permits for oil and gas
extraction within 2,500 feet of any homes, schools, healthcare facilities or long-term care institutions such as
dormitories or prisons, by January 1, 2022. However, SB 467 never made it out of committee and other bills to limit
well stimulation treatments have also previously been introduced and failed to pass through the California
legislature. Although these legislative efforts have failed, it is possible that SB 467 or similar legislation could be
reintroduced in the future and we cannot predict the results of such future efforts. While currently none of our
California operations rely on hydraulic fracturing stimulation they do rely on other methods of well stimulation and
injection, including cyclic steaming and water and steam flooding. Any restrictions on the use of those well
stimulation treatments or other forms of injection may adversely impact our operations, including causing
operational delays, increased costs, and reduced production, which could adversely affect our revenues, results of
operations and net cash provided by operating activities. For additional information on regulatory and legislative
risks in California that could adversely impact our operations. See “Items 1 and 2. Business and Properties—
Regulation of Health, Safety and Environmental Matters.”
The COVID-19 pandemic and related developments in the global oil markets had material adverse consequences
for general economic, business and industry conditions and impacted the Company's operations, financial
condition, results of operations, cash flows and liquidity and those of its purchasers, suppliers and other
counterparties.
The onset of the COVID-19 pandemic significantly affected the global economy, disrupted global supply chains
and created significant volatility in the financial markets. In addition, the onset of the pandemic resulted in
widespread travel restrictions, business closures and other restrictions that led to a significant reduction in demand
for oil, NGL and gas, resulting in oil prices declining significantly beginning in the first quarter or 2020. In response
to the reduced demand for, and prices of, crude oil, we reduced our 2020 planned capital expenditures by more than
50%, which negatively impacted production for that year.
While demand for and prices for oil, NGLs and gas generally improved during 2021 and into 2022 as travel
restrictions, business closures and other restrictions were lifted, an increase in infections or the onset of a new
variant of the virus could again reduce demand for and prices of oil, NGLs and gas. Persistently weak or additional
declines in commodity prices could adversely affect the economics of our existing wells and planned future wells,
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result in additional impairment charges to existing properties, and, similar to steps we took in 2020 after the onset of
the pandemic, cause us to reduce expenditures and delay or abandon planned drilling operations resulting in
production declines, which could have a material adverse effect on our operations, financial condition, cash flows,
and the quantity and value of estimated proved reserves that may be attributed to our properties.
Our operations also may be adversely affected if significant portions of our workforce - and that of our
customers and suppliers - are unable to work effectively, because of illnesses, quarantines, government actions, or
other restrictions in connection with the pandemic. Although we managed the transition to temporary work from
home arrangements and subsequent office re-openings without a significant loss in business continuity, we incurred
additional costs and experienced some inefficiencies during the year as a result. If the ongoing outbreak were to
worsen, and additional restrictions are implemented, certain operational and other business processes could slow
which may result in longer time to execute critical business functions, higher operating costs and uncertainties
regarding the quality of services and supplies, any of which could adversely affect our operating results for as long
as the current pandemic persists and potentially for some time after the pandemic subsides.
Our ability to operate profitably and maintain our business and financial condition are highly dependent on
commodity prices, which historically have been very volatile and are driven by numerous factors beyond our
control. The outbreak of COVID-19 followed by certain actions taken by OPEC+ caused crude oil prices to
decline significantly beginning in the first quarter of 2020, and prices remained below pre-pandemic levels for a
prolonged period before they recovered. If oil prices were to significantly decline again for a prolonged period of
time, our business, financial condition and results of operations may be materially and adversely affected.
The price we receive for our oil and natural gas production heavily influences our revenue, profitability, value
of our reserves, access to capital and future rate of growth, among other factors. However, the price we receive for
our oil and natural gas production depends on numerous factors beyond our control, including not limited to, the
following:
•
•
•
•
•
•
•
•
•
•
•
•
changes in global supply and demand for oil and natural gas, including changes in demand resulting from
general and specific economic conditions relating to the business cycle and other factors (e.g., global health
epidemics such as the recent COVID-19 pandemic);
the actions of OPEC and/or OPEC+;
the price and quantity of imports of foreign oil and natural gas;
political conditions, including embargoes, in or affecting other oil-producing activity;
the level of global oil and natural gas exploration and production activity
the level of global oil and natural gas inventories;
weather conditions;
domestic and foreign governmental legislative efforts, executive actions and regulations, including
environmental regulations, climate change regulations and taxation;
the effect of energy conservation efforts;
stockholder activism or activities by non-governmental organizations to limit certain sources of capital for
the energy sector or restrict the exploration, development and production of oil and gas;
technological advances affecting energy consumption; and
the price and availability of alternative fuels.
Historically, the markets for oil and natural gas have been extremely volatile and will likely continue to be
volatile in the future. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations
in response to relatively minor changes in supply and demand. Global economic growth drives demand for energy
from all sources, including fossil fuels. When the U.S. and global economies experience weakness, demand for
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energy will decline with accompanying declines in commodity prices; similarly, when growth in global energy
production outstrips demand, the excess supply results in commodity price declines.
Concerns over global economic conditions, energy costs, geopolitical issues, the impacts of the COVID-19
pandemic, inflation, the availability and cost of credit and slow economic growth in the United States have in the
past contributed to significantly reduced economic activity and diminished expectations for the global economy. If
the economic climate in the United States or abroad were deteriorate, worldwide demand for petroleum products
could further diminish, which could impact the price at which oil, natural gas and NGLs from our properties are
sold, affect our level of operations and ultimately materially adversely impact our results of operations, financial
condition and free cash flow.
Additionally, although the California market generally receives Brent-influenced pricing, California oil prices
are determined ultimately by local supply and demand dynamics. Even as Brent pricing reached a historic low
during the second quarter of 2020, we also experienced an adverse widening in the price differential between Brent
and the California benchmark due to the lack of local demand and storage capacity. Although market conditions and
the differential improved over the latter half of 2021, California pricing remained below pre-pandemic levels for a
prolonged period.
Past declines in pricing, and any declines that may occur in the future, can be expected to adversely affect our
business, financial condition and results of operations. Such declines adversely affect well and reserve economics
and may reduce the amount of oil and natural gas that we can produce economically, resulting in deferral or
cancellation of planned drilling and related activities until such time, if ever, as economic conditions improve
sufficiently to support such operations. Any extended decline in oil or natural gas prices may materially and
adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned
capital expenditures.
The marketability of our production is dependent upon transportation and storage facilities and other facilities,
most of which we do not control, and the availability of such transportation and storage capabilities. If we are
unable to access such facilities on commercially reasonable terms, our operations would likely be interrupted, our
production could be curtailed, and our revenues reduced, among other adverse consequences.
The marketing of oil, natural gas and NGLs production depends in large part on the availability, proximity and
capacity of trucks, pipelines and storage facilities, gas gathering systems and other transportation, processing and
refining facilities, as well as the existence of adequate markets. Storage and transportation capacity for our
production is limited and may become unavailable on commercially reasonable terms or at all. For example, storage
and transportation capacity became scarce during the second quarter of 2020 due to the unprecedented dual impact
of a severe global oil demand decline coupled with a substantial increase in supply. As traditional tanks filled, large
quantities of oil were being stored in offshore tankers around the world, including off the coast of California. Where
storage was available, such as offshore tankers, storage costs increased sharply. The potential risk remains that
storage for oil may be unavailable and our existing capacity may be insufficient to support planned production rates
in the event of another deterioration in demand or a supply surge or both.
Moreover, if the imbalance between supply and demand and the related shortage of storage capacity worsen, the
prices we receive for our production could deteriorate and could potentially even become negative. Additionally, if
we were unable to obtain the needed storage capacity, we could be forced to shut-in a significant amount of our
California production, which could have a material adverse effect on our financial condition, liquidity and
operational results. If we are forced to shut in production, we would incur additional costs to bring the associated
wells back online. While production is shut in, we would likely incur additional costs and operating expenses to,
among other things, maintain the health of the reservoirs, meet contractual obligations and protect our interests,
without the associated revenue. Additionally, depending on the duration of the shut-in, and whether we have also
shut in steam injection for the associated reservoirs rather than incur those costs, the wells may not, initially or at all,
come back online at similar rates to those at the time of shut-in. Depending on the duration of the steam injection
shut-in time, and the resulting inefficiency and economics of restoring the reservoir to its energetic and heated state,
our proved reserve estimates could be decreased and there could be potential additional impairments and associated
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charges to our earnings. A reduction in our reserves could also result in a reduction to our borrowing base under the
RBL Facility and our liquidity. The ultimate significance of the impact of any production disruptions, including the
extent of the adverse impact on our financial and operational results, will be dictated by the length of time that such
disruptions continue, which will in turn depend on how long storage remains filled and unavailable to us, which is
largely unpredictable and based on factors outside of our control.
In addition to the constraints we may face due to storage capacity shortages, the volume of oil and natural gas
that we can produce is subject to limitations resulting from pipeline interruptions due to scheduled and unscheduled
maintenance, excessive pressure, and physical damage to the gathering, transportation, storage, processing,
fractionation, refining or export facilities that we utilize. The curtailments arising from these and similar
circumstances may last from a few days to several months or longer and, in many cases, we may be provided only
limited, if any, advance notice as to when these circumstances will arise and their duration. Any such shut in or
curtailment, or any inability to obtain favorable terms for delivery of the oil and natural gas produced from our
fields, would adversely affect our financial condition and results of operations.
Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved
reserves and future net cash flows may prove to be lower than estimated.
Estimation of reserves and related future net cash flows is a partially subjective process of estimating
accumulations of oil and natural gas that includes many uncertainties. Our estimates are based on various
assumptions, which may ultimately prove to be inaccurate, including:
•
•
•
•
•
•
•
the similarity of reservoir performance in other areas to expected performance from our assets;
the quality, quantity and interpretation of available relevant data;
commodity prices;
production, operating costs, taxes and costs related to GHG regulations;
development costs;
the effects of government regulations; and
future workover and asset retirement costs.
Misunderstanding these variables, inaccurate assumptions, changed circumstances or new information could
require us to make significant negative reserves revisions.
We currently expect improved recovery, extensions and discoveries and, potentially acquisitions, to be our main
sources for reserves additions. However, factors such as the availability of capital, geology, government regulations
and permits, the effectiveness of development plans and other factors could affect the source or quantity of future
reserves additions. Any material inaccuracies in our reserves estimates could materially affect the net present value
of our reserves, which could adversely affect our borrowing base and liquidity under the RBL Facility, as well as our
results of operations.
Unless we replace oil and natural gas reserves, our future reserves and production will decline.
Unless we conduct successful development and exploration activities or acquire properties containing proved
reserves, our proved reserves will decline as those reserves are produced. Success requires us to deploy sufficient
capital to projects that are geologically and economically attractive which is subject to the capital, development,
operating and regulatory risks already discussed above under the heading “—Our business requires continual
capital expenditures. We may be unable to fund these investments through operating cash flow or obtain any needed
additional capital on satisfactory terms or at all, which could lead to a decline in our oil and natural gas reserves or
production. Our capital program is also susceptible to risks, including regulatory and permitting risks, that could
materially affect its implementation.” The Company reduced its planned capital expenditures in 2020 in response to
the effects of COVID-19 and the actions of OPEC+, which negatively impacted production during 2020. While we
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subsequently increased our planned capital expenditures for 2021, it is possible that lower-than-expected demand
and prices for commodities in the future could materially and adversely affect our future planned capital
expenditures. Over the long term, a continuing decline in our production and reserves would reduce our liquidity and
ability to satisfy our debt obligations by reducing our cash flow from operations and the value of our assets.
Drilling for and producing oil and natural gas involves many uncertainties that could adversely affect our
results.
The success of our development, production and acquisition activities are subject to numerous risks beyond our
control, including the risk that drilling will not result in commercially viable production or may result in a
downward revision of our estimated proved reserves due to:
•
•
•
•
poor production response;
ineffective application of recovery techniques;
increased costs of drilling, completing, stimulating, equipping, operating, maintaining and abandoning
wells;
delays or cost overruns caused by equipment failures, accidents, environmental hazards, adverse weather
conditions, permitting or construction delays, title disputes, surface access disputes and other matters; and
• misinterpretation of geophysical and geological analyses, production data and engineering studies.
Additional factors may delay or cancel our operations, including:
•
•
•
•
•
delays due to regulatory requirements and procedures, including unavailability or other restrictions limiting
permits and limitations on water disposal, emission of GHGs, steam injection and well stimulation, such as
California’s recent limitations on cyclic steaming above the fracture gradient;
pressure or irregularities in geological formations;
shortages of or delays in obtaining equipment, qualified personnel or supplies including water for steam
used in production or pressure maintenance;
delays in access to production or pipeline transmission facilities; and
power outages imposed by utilities which provide a portion of our electricity needs in order to avoid fire
hazards and inspect lines in connection with seasonal strong winds, which have begun to occur recently and
may impact our operations.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to property,
reserves and equipment, pollution, environmental contamination and regulatory penalties.
We may not drill our identified sites at the times we scheduled or at all.
We have specifically identified locations for drilling over the next several years, which represent a significant
part of our long-term growth strategy. Our actual drilling activities may materially differ from those presently
identified. Legislative and regulatory developments, such as the California moratorium on approval of new high-
pressure cyclic steam wells pending a study of the practice to address surface expressions experienced by certain
operators, could prevent us from planned drilling activities. Additionally, as discussed under “—Risks Related to
Regulatory Matters,” new regulations and legislative activity could result in a significant delay or decline in, and/or
the incurrence of additional costs for, the approval of the permits required to develop our properties in accordance
with our plans. If future drilling results in these projects do not establish sufficient reserves to achieve an economic
return, we may curtail drilling or development of these projects. Accordingly, we cannot guarantee that these
prospective drilling locations or any other drilling locations we have identified will ever be drilled or if we will be
able to economically produce oil or natural gas from these drilling locations. In addition, some of our leases could
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expire if we do not establish production in the leased acreage. The combined net acreage covered by leases expiring
in the next three years represented approximately 11% of our total net acreage at December 31, 2021.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties,
market oil or natural gas and secure trained personnel.
Our future success will depend on our ability to evaluate, select and acquire suitable properties, market our
production and secure skilled personnel to operate our assets in a highly competitive environment. Also, there is
substantial competition for capital available for investment in the oil and natural gas industry. Many of our
competitors possess and employ greater financial, technical and personnel resources than we do.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses or assets or enter
into attractive joint ventures, and any inability to do so may disrupt our business and hinder our ability to grow.
There is no guarantee we will be able to identify or complete attractive acquisitions. Our capital expenditure
budget for 2022 does not allocate any amounts for acquisitions of oil and natural gas properties. If we make
acquisitions, we would need to use cash flows or seek additional capital, both of which are subject to uncertainties
discussed in this section. Competition may also increase the cost of, or cause us to refrain from, completing
acquisitions. Our debt arrangements impose certain limitations on our ability to enter into mergers or combination
transactions and to incur certain indebtedness. See “—Our existing debt agreements have restrictive covenants that
could limit our growth, financial flexibility and our ability to engage in certain activities.” In addition, the success of
completed acquisitions will depend on our ability to integrate effectively the acquired business into our existing
operations, may involve unforeseen difficulties and may require a disproportionate amount of our managerial and
financial resources.
We are dependent on our cogeneration facilities to produce steam for our operations. Contracts for the sale of
surplus electricity, economic market prices and regulatory conditions affect the economic value of these facilities
to our operations.
We are dependent on four cogeneration facilities that, combined, provide approximately 18% of our steam
capacity and approximately 65% of our field electricity needs in California at a discount to market rates. To further
offset our costs, we sell surplus power to California utility companies produced by certain of our cogeneration
facilities under long-term contracts. Should we lose, be unable to renew on favorable terms, or be unable to replace
such contracts, we may be unable to realize the cost offset currently received. Our ability to benefit from these
facilities is also affected by our ability to consistently generate surplus electricity and fluctuations in commodity
prices. For example, during 2021 electricity sales increased by $10 million, or 38%, due to higher unit sales during
the summer when we receive peak pricing, and higher year–over–year gas pricing. Furthermore, market fluctuations
in electricity prices and regulatory changes in California could adversely affect the economics of our cogeneration
facilities and any corresponding increase in the price of steam could significantly impact our operating costs. If we
were unable to find new or replacement steam sources, lose existing sources or experience installation delays, we
may be unable to maximize production from our heavy oil assets. If we were to lose our electricity sources, we
would be subject to the electricity rates we could negotiate. For a more detailed discussion of our electricity sales
contracts, see “Items 1 and 2. Business and Properties—Operational Overview—Electricity.”
Our producing properties are located primarily in California, making us vulnerable to risks associated with
having operations concentrated in this geographic area.
We operate primarily in California, which is one of the most heavily regulated states in the United States with
respect to oil and gas operations. This geographic concentration disproportionately affects the success and
profitability of our operations exposing us to local price fluctuations, changes in state or regional laws and
regulations, political risks, limited acquisition opportunities where we have the most operating experience and
infrastructure, limited storage options, drought conditions, and other regional supply and demand factors, including
gathering, pipeline and transportation capacity constraints, limited potential customers, infrastructure capacity and
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availability of rigs, equipment, oil field services, supplies and labor. We discuss such specific risks to our California
operations in more detail elsewhere in this section.
Most of our operations are in California, much of which is conducted in areas that may be at risk of damage
from fire, mudslides, earthquakes or other natural disasters.
We currently conduct operations in California near known wildfire and mudslide areas and earthquake fault
zones. A future natural disaster, such as a fire, mudslide or an earthquake, could cause substantial interruption and
delays in our operations, damage or destroy equipment, prevent or delay transport of our products and cause us to
incur additional expenses, which would adversely affect our business, financial condition and results of operations.
In addition, our facilities would be difficult to replace and would require substantial lead time to repair or replace.
These events could occur with greater frequency as a result of the potential impacts from climate change. The
insurance we maintain against earthquakes, mudslides, fires and other natural disasters would not be adequate to
cover a total loss of our facilities, may not be adequate to cover our losses in any particular case and may not
continue to be available to us on acceptable terms, or at all.
Operational issues and inability or unwillingness of third parties to provide sufficient facilities and services to us
on commercially reasonable terms or otherwise could restrict access to markets for the commodities we produce.
Our ability to market our production of oil, gas and NGLs depends on a number of factors, including the
proximity of production fields to pipelines, refineries and terminal facilities, competition for capacity on such
facilities, damage, shutdowns and turnarounds at such facilities and their ability to gather, transport or process our
production. If these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be
forced to shut in some production or delay or discontinue drilling plans and commercial production following a
discovery of hydrocarbons. We rely, and expect to rely in the future, on third-party facilities for services such as
storage, processing and transmission of our production. Our plans to develop and sell our reserves could be
materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and
services to us on commercially reasonable terms or otherwise. If our access to markets for commodities we produce
is restricted, our costs could increase and our expected production growth may be impaired.
We may incur substantial losses and be subject to substantial liability claims as a result of catastrophic events.
We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not fully insured against all risks. Our oil and natural gas exploration and production activities, are
subject to risks such as fires, explosions, oil and natural gas leaks, oil spills, pipeline and tank ruptures and
unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the
surface and subsurface environment, equipment failures and industrial accidents. We are exposed to similar risks
indirectly through our customers and other market participants such as refiners. Other catastrophic events such as
earthquakes, floods, mudslides, fires, droughts, contagious diseases, terrorist attacks and other events that cause
operations to cease or be curtailed may adversely affect our business and the communities in which we operate. For
example, utilities have begun to suspend electric services to avoid wildfires during windy periods in California, a
business disruption risk that is not insured. We may be unable to obtain, or may elect not to obtain, insurance for
certain risks if we believe that the cost of available insurance is excessive relative to the risks presented.
We may be involved in legal proceedings that could result in substantial liabilities.
Like many oil and natural gas companies, we are from time to time involved in various legal and other
proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or
property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and
their results cannot be predicted. Regardless of the outcome, such proceedings could have a material adverse impact
on us because of legal costs, diversion of the attention of management and other personnel and other factors. In
addition, resolution of one or more such proceedings could result in liability, loss of contractual or other rights,
penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices.
Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine
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accruals or range of losses related to legal and other proceedings could change materially from one period to the
next.
The loss of senior management or technical personnel could adversely affect operations.
We depend on, and could be deprived of, the services of our senior management and technical personnel. We do
not maintain, nor do we plan to obtain, any insurance against the loss of services of any of these individuals.
Information technology failures and cyberattacks could affect us significantly.
We rely on electronic systems and networks to communicate, control and manage our operations and prepare
our financial management and reporting information. Without accurate data from and access to these systems and
networks, our ability to communicate and control and manage our business could be adversely affected.
We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive
information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-
party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Our
implementation of various procedures and controls to monitor and mitigate security threats and to increase security
for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there
can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring.
If security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or
capabilities essential to our operations. If we were to experience an attack and our security measures failed, the
potential consequences to our business and the communities in which we operate could be significant and could
harm our reputation and lead to financial losses from remedial actions, loss of business or potential liability.
Increasing attention to environmental, social and governance (ESG) matters may impact our business.
Increasing attention to, and social expectations on companies to address, climate change and other environmental
and social impacts, investor and societal explanations regarding voluntary ESG disclosures, and increased consumer
demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced
profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets.
Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for
oil and natural gas products and additional governmental investigations and private litigation against us. To the
extent that societal pressures or political or other factors are involved, it is possible that such liability could be
imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
While we may participate in various voluntary frameworks and certification programs to improve the ESG profile of
our operations and products, we cannot guarantee that such participation or certification will have the intended
results on our or our products’ ESG profile.
Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time,
many of the statements in those voluntary disclosures will be based on hypothetical expectations and assumptions
that may or may not be representative of current or actual risks or events or forecasts of expected risks or events,
including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be
prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single
approach to identifying, measuring, and reporting on many ESG matters. Additionally, while we may also announce
various voluntary ESG targets in the near future, such targets are aspirational. We may not be able to meet such
targets in the manner or on such a timeline as initially contemplated, including, but not limited to as a result of
unforeseen costs or technical difficulties associated with achieving such results. To the extent we do meet such
targets, it may be achieved through various contractual arrangements, including the purchase of various credits or
offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. Also,
despite these aspirational goals, we may receive pressure from investors, lenders, or other groups to adopt more
aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals
because of potential costs or technical or operational obstacles.
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In addition, organizations that provide information to investors on corporate governance and related matters
have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used
by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased
negative investor sentiment toward us or our customers and to the diversion of investment to other industries which
could have a negative impact on our stock price and/or our access to and costs of capital. Moreover, to the extent
ESG matters negatively impact our reputation, we may not be able to compete as effectively or recruit or retain
employees, which may adversely affect our operations.
Such ESG matters may also impact our customers or suppliers, which may adversely impact our business,
financial condition, or results of operations.
Risks Related to Our Financial Condition
We may not be able to use a portion of our net operating loss carryforwards and other tax attributes to reduce our
future U.S. federal and state income tax obligations, which could adversely affect our cash flows.
We currently have substantial U.S. federal and state net operating loss (“NOL”) carryforwards and U.S. federal
general business credits. Our ability to use these tax attributes to reduce our future U.S. federal and state income tax
obligations depends on many factors, including our future taxable income, which cannot be assured. In addition, our
ability to use NOL carryforwards and other tax attributes may be subject to significant limitations under Section 382
and Section 383 of the Internal Revenue Code of 1986, as amended (the “Code”). Under those sections of the Code,
if a corporation undergoes an “ownership change” (as defined in Section 382 of the Code), the corporation’s ability
to use its pre-change NOL carryforwards and other tax attributes may be substantially limited.
Determining the limitations under Section 382 of the Code is technical and highly complex. A corporation
generally will experience an ownership change if one or more stockholders (or groups of stockholders) who are each
deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points
over their lowest ownership percentage within a rolling three-year period. We may in the future undergo an
ownership change under Section 382 of the Code. If an ownership change occurs, our ability to use our NOL
carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations may be
materially limited, which could adversely affect our cash flows.
Our business requires continual capital expenditures. We may be unable to fund these investments through
operating cash flow or obtain any needed additional capital on satisfactory terms or at all, which could lead to a
decline in our oil and natural gas reserves or production. Our capital program is also susceptible to risks,
including regulatory and permitting risks, that could materially affect its implementation.
Our industry is capital intensive. We have a 2022 capital expenditure budget of approximately $125 to $135
million. The actual amount and timing of our future capital expenditures may differ materially from our estimates as
a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other
services and equipment, the availability of permits, and our ability to obtain them in a timely manner or at all, legal
and regulatory processes and other restrictions, and technological and competitive developments. A reduction or
sustained decline in commodity prices from current levels may force us to reduce our capital expenditures, which
would negatively impact our ability to grow production. Current and future laws and regulations may prevent us
from being able to execute our drilling programs and development and optimization projects.
We expect to fund our 2022 capital expenditures with cash flows from our operations, supplemented by cash on
hand which was built as excess Levered Free Cash Flow during 2020 and 2021; however, our cash flows from
operations, and access to capital should such cash flows and cash on hand prove inadequate, are subject to a number
of variables, including:
•
•
the volume of hydrocarbons we are able to produce from existing wells;
the prices at which our production is sold and our operating expenses;
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•
•
•
•
the success of our hedging program;
our proved reserves, including our ability to acquire, locate and produce new reserves;
our ability to borrow under the RBL Facility;
and our ability to access the capital markets.
If our revenues or the borrowing base under the RBL Facility decrease as a result of lower oil, natural gas and
NGL prices, lack of required permits and other operating difficulties, declines in reserves or for any other reason, we
may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If
additional capital were needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at
all. Any additional debt financing would carry interest costs, diverting capital from our business activities, which in
turn could lead to a decline in our reserves and production. If cash flows generated by our operations or available
borrowings under the RBL Facility were not sufficient to meet our capital requirements, the failure to obtain
additional financing could result in a curtailment of our operations relating to development of our properties. See
“Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and
Capital Resources.”
Inflation could adversely impact our ability to control our costs, including our operating expenses and capital
costs.
Although inflation in the United States has been relatively low in recent years, it rose significantly in the second
half of 2021. This is believed to be the result of the economic impact from the COVID-19 pandemic, including the
global supply chain disruptions and the government stimulus packages, among other factors. Global, industry-wide
supply chain disruptions caused by the COVID-19 pandemic have resulted in shortages in labor, materials and
services. Such shortages have resulted in inflationary cost increases for labor, materials and services and could
continue to cause costs to increase as well as scarcity of certain products and raw materials. We are experiencing
some inflationary pressure for certain costs, including employees and vendors, although such cost increases did not
materially impact our 2021 financial condition or results of operations, and we currently do not expect them to
materially impact our 2022 financial results or operations. However, to the extent elevated inflation remains, we
may experience further cost increases for our operations, including natural gas purchases and oilfield services and
equipment as increasing oil, natural gas and NGL prices increase drilling activity in our areas of operations, as well
as increased labor costs. An increase in oil, natural gas and NGL prices may cause the costs of materials and services
to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent
we are unable to recover higher costs through higher commodity prices and revenues, would negatively impact our
business, financial condition and results of operation.
Our hedging activities limit our ability to realize the full benefits of increases in commodity prices and our
potential gains.
We enter into hedges to manage our exposure to price risks in the marketing of our oil and natural gas, mitigate
our economic exposure to commodity price volatility and ensure our financial strength and liquidity by protecting
our cash flows. In addition, we also hedge to meet the hedging requirements of the 2021 RBL Facility. The 2021
RBL Facility requires us to maintain commodity hedges (other than three-way collars) on minimum notional
volumes of (i) at least 75% of our reasonably projected production of crude oil from our PDP reserves, for 24 full
calendar months after the effective date of the 2021 RBL Facility and after each May 1 and November 1 of each
calendar year (each, a “Minimum Hedging Requirement Date”) and (ii) at least 50% of our reasonably projected
production of crude oil from our PDP reserves, for each full calendar month during the period from and including
the 25th full calendar month following each such Minimum Hedging Requirement Date through and including the
36th full calendar month following each such Minimum Hedging Requirement Date; provided, that in the case of
each of the above clauses (i) and (ii), the notional volumes hedged are deemed reduced by the notional volumes of
any short puts or other similar derivatives having the effect of exposing us to commodity price risk below the
“floor”. In addition to minimum hedging requirements and other restrictions in respect of hedging described therein,
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the 2021 RBL Facility contains restrictions on our commodity hedging which prevent us from entering into hedging
agreements (i) with a tenor exceeding 48 months or (ii) for notional volumes which (when aggregated with other
hedges then in effect other than basis differential swaps on volumes already hedged) exceed, as of the date such
hedging agreement is executed, 90% of our reasonably projected production of crude oil from our PDP reserves, for
each month following the date such hedging agreement is entered into, provided that the volume limitations above
do not apply to short puts or put options contracts that are not related to corresponding calls, collars, or swaps.
While intended to reduce the effects of volatile oil and natural gas prices, such transactions, depending on the
hedging instrument used, may limit our potential gains if oil and natural gas prices were to rise substantially over the
price established by the hedge or expose us to the risk of financial losses depending on commodity price movements
and other circumstances. Our ability to realize the benefits of our hedges also depends in part upon the
counterparties to these contracts honoring their financial obligations. If any of our counterparties are unable to
perform their obligations in the future, we could be exposed to increased cash flow volatility that could affect our
liquidity.
We may be unable to, or may choose not to, enter into sufficient fixed-price purchase or other hedging
agreements to fully protect against decreasing spreads between the price of natural gas and oil on an energy
equivalent basis or may otherwise be unable to obtain sufficient quantities of natural gas to conduct our steam
operations economically or at desired levels, and our commodity price risk management activities may prevent us
from fully benefiting from price increases and may expose us to other risks.
To develop our heavy oil in California we must economically generate steam using natural gas. We seek to
reduce our exposure to the potential unavailability of, pricing increases for, and volatility in pricing of, natural gas
by entering into fixed-price purchase agreements and other hedging transactions. We seek to reduce our exposure to
potential price increases and volatility in pricing of oil by entering into swaps, calls and other hedging transactions.
We may be unable to, or may choose not to, enter into sufficient agreements to fully protect against decreasing
spreads between the price of natural gas and oil on an energy equivalent basis or may otherwise be unable to obtain
sufficient quantities of natural gas to conduct our steam operations economically or at desired levels.
In addition, we also hedge to meet the hedging requirements of the 2021 RBL Facility, which requires us to
maintain commodity hedges (other than three-way collars) on minimum notional volumes of (i) at least 75% of our
reasonably projected production of crude oil from our PDP reserves, for 24 full calendar months after the effective
date of the 2021 RBL Facility and after each May 1 and November 1 of each calendar year (each, a “Minimum
Hedging Requirement Date”) and (ii) at least 50% of our reasonably projected production of crude oil from our PDP
reserves, for each full calendar month during the period from and including the 25th full calendar month following
each such Minimum Hedging Requirement Date through and including the 36th full calendar month following each
such Minimum Hedging Requirement Date; provided, that in the case of each of the above clauses (i) and (ii), the
notional volumes hedged are deemed reduced by the notional volumes of any short puts or other similar derivatives
having the effect of exposing us to commodity price risk below the “floor”. In addition to minimum hedging
requirements and other restrictions in respect of hedging described therein, the 2021 RBL Facility contains
restrictions on our commodity hedging which prevent us from entering into hedging agreements (i) with a tenor
exceeding 48 months or (ii) for notional volumes which (when aggregated with other hedges then in effect other
than basis differential swaps on volumes already hedged) exceed, as of the date such hedging agreement is executed,
90% of our reasonably projected production of crude oil from our PDP reserves, for each month following the date
such hedging agreement is entered into, provided that the volume limitations above do not apply to short puts or put
options contracts that are not related to corresponding calls, collars, or swaps.
Our commodity price risk management activities as well as the hedging requirements of the 2021 RBL facility
may prevent us from fully benefiting from price increases. Additionally, our hedges are based on major oil and gas
indexes, which may not fully reflect the prices we realize locally. Consequently, the price protection we receive may
not fully offset local price declines.
As of December 31, 2021, we have hedged gas purchases at the following approximate volumes and prices:
34.9 mmbtu/d at $3.29 per mmbtu in 2022.
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Our commodity price risk management activities may also expose us to the risk of financial loss in certain
circumstances, including instances in which:
•
•
the counterparties to our hedging or other price-risk management contracts fail to perform under those
arrangements; and
an event materially impacts oil and natural gas prices in the opposite direction of our derivative positions.
Our existing debt agreements have restrictive covenants that could limit our growth, financial flexibility and our
ability to engage in certain activities. In addition, the borrowing base under the RBL Facility is subject to periodic
redeterminations and our lenders could reduce capital available to us for investment.
The RBL Facility and the indenture governing our 2026 Notes have restrictive covenants that could limit our
growth, financial flexibility and our ability to engage in activities that may be in our long-term best interests. Failure
to comply with these covenants could result in an event of default that, if not cured or waived, could result in the
acceleration of all of our indebtedness.These agreements contain covenants, that, among other things, limit our
ability to:
•
•
•
incur or guarantee additional indebtedness or issue certain types of preferred stock;
pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated
indebtedness;
transfer, sell or dispose of assets;
• make investments;
•
•
•
•
•
•
•
create certain liens securing indebtedness;
enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets;
hedge future production or interest rates;
repay or prepay certain indebtedness prior to the due date;
engage in transactions with affiliates; and
engage in certain other transactions without the prior consent of the lenders.
In addition, the RBL Facility requires us to maintain certain financial ratios or to reduce our indebtedness if we
are unable to comply with such ratios, which may limit our ability to borrow funds to withstand a future downturn in
our business, or to otherwise conduct necessary corporate activities. We may also be prevented from taking
advantage of business opportunities that arise because of these limitations.
In addition, the 2021 RBL Facility has hedging requirements which may limit our potential gains if oil and
natural gas prices were to rise substantially over the price established by the hedge or expose us to the risk of
financial loss in certain circumstances.
Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could
result in the acceleration of all of our indebtedness. If that occurs, we may not be able to make all of the required
payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that
time, it may not be on terms that are acceptable to us.
The amount available to be borrowed under the RBL Facility is subject to a borrowing base and will be
redetermined semiannually and will depend on the estimated volumes and cash flows of our proved oil and natural
gas reserves and other information deemed relevant by the administrative agent of, or two-thirds of the lenders
under, the RBL Facility.We, the administrative agent and lenders, each may request one additional redetermination
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between each regularly scheduled redetermination. Furthermore, our borrowing base is subject to automatic
reductions due to certain asset sales and hedge terminations, the incurrence of certain other debt and other events as
provided in the RBL Facility. For example, the RBL Facility currently provides that to the extent we incur certain
unsecured indebtedness, our borrowing base will be reduced by an amount equal to 25% of the amount of such
unsecured debt that exceeds the amount, if any, of certain other debt that is being refinanced by such unsecured debt.
Reduction of our borrowing base under the RBL Facility could reduce the capital available to us for investment in
our business. Additionally, we could be required to repay a portion of the RBL Facility to the extent that after a
redetermination our outstanding borrowings at such time exceed the redetermined borrowing base. For additional
details regarding the terms of the RBL Facility and our 2026 Notes, see “Liquidity and Capital Resources”.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other
actions to satisfy our obligations under our debt arrangements, which may not be successful.
As of December 31, 2021, we had $400 million outstanding on our 2026 Notes and no outstanding borrowings
under our 2021 RBL Facility, with approximately $193 million of available borrowings capacity. Our ability to
make scheduled payments on or to refinance our debt obligations, including the RBL Facility and our 2026 Notes,
depends on our financial condition and operating performance, which are subject to prevailing economic and
competitive conditions and certain financial, business and other factors that may be beyond our control. If oil and
natural gas prices remain at low levels for an extended period of time or further deteriorate, our cash flows from
operating activities may be insufficient to permit us to pay the principal, premium, if any, and interest on our
indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity
problems and might be required to dispose of material assets or operations to meet debt service and other
obligations. The RBL Facility and our 2026 Notes currently restrict our ability to dispose of assets and our use of the
proceeds from any such disposition. We may not be able to consummate dispositions, and the proceeds of any such
disposition may not be adequate to meet any debt service obligations then due.
Declines in commodity prices, changes in expected capital development, increases in operating costs or adverse
changes in well performance may result in write-downs of the carrying amounts of our assets.
We evaluate the impairment of our oil and natural gas properties whenever events or changes in circumstances
indicate that the carrying value may not be recoverable. Based on specific market factors and circumstances at the
time of prospective impairment reviews, and the continuing evaluation of development plans, production data,
economics and other factors, we may be required to write down the carrying value of our properties. A write down
constitutes a non-cash charge to earnings. For example, in the first quarter of 2020, we recorded a non-cash pre-tax
asset impairment charge of $289 million on proved properties in Utah and certain California locations.
Changes in the method of determining London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR
with an alternative reference rate, may adversely affect interest expense related to outstanding debt.
Amounts drawn under the RBL Facility may bear interest rates in relation to LIBOR, depending on our
selection of repayment options. On July 27, 2017, the Financial Conduct Authority in the U.K. announced that it
would phase out LIBOR as a benchmark by the end of 2021. If LIBOR ceases to exist, we may need to renegotiate
the RBL Facility and may not be able to do so with terms that are favorable to us. The overall financial market may
be disrupted as a result of the phase-out or replacement of LIBOR.
We have significant concentrations of credit risk with our customers and the inability of one or more of our
customers to meet their obligations or the loss of any one of our major oil and natural gas purchasers may have a
material adverse effect on our business, financial condition, results of operations and cash flows.
We have significant concentrations of credit risk with the purchasers of our oil and natural gas. For the year
ended December 31, 2021, sales to Tesoro Refining and Marketing, PBF Holding, Kern Oil & Refining, and Phillips
66accounted for approximately 30%, 16%, 14%, and 12% respectively, of our sales. This concentration may impact
our overall credit risk because our customers may be similarly affected by changes in economic conditions or
commodity price fluctuations. We do not require our customers to post collateral. If the purchasers of our oil and
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natural gas become insolvent, we may be unable to collect amounts owed to us. Also, if we were to lose any one of
our major customers, the loss could cause us to cease or delay both production and sale of our oil and natural gas in
the area supplying that customer.
Due to the terms of supply agreements with our customers, we may not know that a customer is unable to make
payment to us until almost two months after production has been delivered. We do not require our customers to post
collateral to protect our ability to be paid.
Risks Related to Regulatory Matters
Our business is highly regulated and governmental authorities can delay or deny permits and approvals or
change the requirements governing our operations, including the permitting approval process for oil and gas
exploration, extraction, operations and production activities; well stimulation and other enhanced production
techniques; and fluid injection or disposal activities, any of which could increase costs, restrict operations and
delay our implementation of, or cause us to change, our business strategy and plans.
Like other companies in the oil and gas industry, our operations are subject to a wide range of complex and
stringent federal, state and local laws and regulations. Federal, state and local agencies may assert overlapping
authority to regulate in these areas. See “Items 1 and 2. Business and Properties—Regulation of Health, Safety and
Environmental Matters” for a description of laws and regulations that affect our business. Collectively, the effect of
the existing laws and regulations is to potentially 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, and reduce the
amount of oil and natural gas that we can produce from our wells below levels that would otherwise be possible. To
operate in compliance with these laws and regulations, we must obtain and maintain permits, approvals and
certificates from federal, state and local government authorities for a variety of activities including siting, drilling,
completion, fluid injection and disposal, stimulation, operation, maintenance, transportation, marketing, site
remediation, decommissioning, abandonment and water recycling and reuse. These permits are generally subject to
protest, appeal or litigation, which could in certain cases delay or halt projects, production of wells and other
operations. Additionally, the regulatory burden on the industry increases our costs and consequently may have an
adverse effect upon capital expenditures, earnings or competitive position. Failure to comply may result in the
assessment of administrative, civil and criminal fines and penalties and liability for noncompliance, costs of
corrective action, cleanup or restoration, compensation for personal injury, property damage or other losses, and the
imposition of injunctive or declaratory relief restricting or limiting our operations.
California, where most of our assets are located, is one of the most heavily regulated states in the United States
with respect to oil and gas operations and our operations are subject to numerous and stringent state, local and other
laws and regulations that could delay or otherwise adversely impact our operations. The jurisdiction, duties and
enforcement authority of various state agencies have significantly increased with respect to oil and natural gas
activities in recent years, and these state agencies as well as certain cities and counties have significantly revised
their regulations, regulatory interpretations and data collection and reporting requirements and have indicated plans
to issue additional regulations of certain oil and natural gas activities in 2022. Moreover, certain of these laws and
regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions
over which we and our predecessors had no control, without regard to fault, legality of the original activities, or
ownership or control by third parties. Violations and liabilities with respect to these laws and regulations could 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 prospects.
In California, We are also increasingly impacted by policies designed to curtail the production and use of fossil
fuels. For example, in September 2020, Governor Gavin Newsom of California issued an executive order that seeks
to reduce both the supply of and demand for fossil fuels in the state. The executive order established several goals
and directed several state agencies to take certain actions with respect to reducing emissions of greenhouse gases,
including, but not limited to: phasing out the sale of emissions-producing vehicles; developing strategies for the
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closure and repurposing of oil and gas facilities in California; and calling on the California State Legislature to enact
new laws prohibiting hydraulic fracturing in the state by 2024. The executive order also directed CalGEM to finish
its review of public health and safety concerns from the impacts of oil extraction activities and propose significantly
strengthened regulations. At this time, we cannot predict how implementation of these actions and proposals may
impact our operations. For additional information, see “Items 1 and 2. Business and Properties—Regulation of
Health, Safety and Environmental Matters” and “Item 1A. Risk Factors—Risks Related to Our Operations and
Industry—There are significant uncertainties with respect to obtaining permits for oil and gas activities in Kern
County, where all of our California operations are located, which could adversely and materially impact our
financial condition, results of operations and Prospects" and “Item 1A. Risk Factors—Risks Related to Our
Operations and Industry—Attempts by the California state government to restrict the production of oil and gas could
negatively impact our operations and result in decreased demand for fossil fuels within the states where we operate."
Our operations may also be adversely affected by seasonal or permanent restrictions on drilling activities
imposed under the Endangered Species Act or similar state laws designed to protect various wildlife, such as the
Greater Sage Grouse. Such restrictions may limit our ability to operate in protected areas and can intensify
competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to
periodic shortages when drilling is allowed. Permanent restrictions imposed to protect threatened or endangered
species or their habitat could prohibit drilling in certain areas or require the implementation of expensive mitigation
measures.
Our customers, including refineries and utilities, and the businesses that transport our products to customers are
also highly regulated. For example, federal and state agencies have subjected or, proposed subjecting, more gas and
liquid gathering lines, pipelines and storage facilities to regulations that have increased business costs and otherwise
affect the demand, volatility and other aspects of the price we pay for fuel gas. Certain municipalities have enacted
restrictions on the installation of natural gas appliances and infrastructure in new residential or commercial
construction, which could affect the retail natural gas market for our utility customers and the demand and prices we
receive for the natural gas we produce.
Costs of compliance may increase, and operational delays or restrictions may occur as existing laws and
regulations are revised or reinterpreted, or as new laws and regulations become applicable to our operations, each of
which has occurred in the past. For example, our costs have recently begun to increase due to new fluid injection
regulations, data requirements for permitting, and idle well decommissioning regulations. For instance, in 2021 we
paid $19 million in asset retirement obligations, an increase from $18 million in 2020, largely due to the new idle
well regulations and EH&S focused costs and initiatives associated with developing existing fields. In addition, we
may experience delays, as we have in the past, due to insufficient internal processes and personnel resource
constraints at regulatory agencies that impede their ability to process permits in a timely manner that aligns with our
production projects.
Government authorities and other organizations continue to study health, safety and environmental aspects of
oil and natural gas operations, including those related to air, soil and water quality, ground movement or seismicity
and natural resources. Government authorities have also adopted, proposed, or otherwise considering new or more
stringent requirements for permitting, well construction and public disclosure or environmental review of, or
restrictions on, oil and natural gas operations. For example, there has been increased scrutiny with respect to
hydraulic fracturing over the years by various state and federal agencies, which scrutiny has extended to oil and gas
exploration and production activities more generally. This has resulted in more stringent regulation with respect to
air emissions from oil and gas operations, restrictions on water discharges and calls to remove exemptions for
certain oil and gas wastes from federal hazardous waste laws and regulations, amongst other restrictions. Separately,
as another example, the scope of the federal Clean Water Act (“CWA”) has been subject to substantial uncertainty in
recent years, which has the potential to increase permitting burdens. In 2015, the EPA and the U.S. Army Corps of
Engineers (“Corps”) issued a rule expanding the scope of the term “Waters of the United States” (“WOTUS”) to
include certain areas not traditionally considered to be subject to federal jurisdiction (the “Clean Water Rule”).
Subsequently, in January 2020, the EPA and the Corps finalized the Navigable Waters Protection Rule, which
narrowed the definition of jurisdictional WOTUS relative to the Clean Water Rule. Both of these rulemakings have
been subject to legal challenge, and the Biden Administration has announced plans to establish its own definition of
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WOTUS. Most recently, the EPA and the Corps published a proposed rulemaking to revoke the 2020 rule in favor of
a pre-2015 definition until a new definition is proposed which the Biden Administration has announced is underway.
Additionally, in January 2022, the Supreme Court agreed to hear a case on the scope and authority of the Clean
Water Act and the definition of WOTUS. As a result of these developments, the scope of the CWA is uncertain at
this time. To the extent any rule expands the range of properties subject to the CWA’s jurisdiction, we could face
increased costs and delays with respect to obtaining dredge and fill activity permits in wetland areas, which could
materially impact our operations in the San Joaquin basin and other areas. Such requirements or associated litigation
could result in potentially significant added costs to comply, delay or curtail our exploration, development, fluid
injection and disposal or production activities, and preclude us from drilling, completing or stimulating wells, which
could have an adverse effect on our expected production, other operations and financial condition.
Changes to elected or appointed officials or their priorities and policies could result in different approaches to
the regulation of the oil and natural gas industry. We cannot predict the actions the California governor or legislature
may take with respect to the regulation of our business, the oil and natural gas industry or the state's economic, fiscal
or environmental policies, nor can we predict what actions may be taken in states or at the federal level with respect
to environmental laws and policies, including those that may directly or indirectly impact our operations.
Potential future legislation may generally affect the taxation of natural gas and oil exploration and development
companies and may adversely affect our operations and cash flows.
In past years, federal and state level legislation has been proposed that would, if enacted into law, make
significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently
available to natural gas and oil exploration and development companies. For example, the Biden administration has
set forth several tax proposals that would, if enacted into law, make significant changes to U.S. tax laws. Such
proposals include, but are not limited to, (i) an increase in the U.S. income tax rate applicable to corporations and (ii)
the elimination of tax subsidies, generally in the form of accelerated deductions, for fossil fuels. Congress could
consider some or all of these proposals in connection with tax reform to be undertaken by the Biden administration.
It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take
effect. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income
tax laws could adversely affect our operations and cash flows.
Additionally, in California, there have been proposals for new taxes on profits that might have a negative impact
on us. Although the proposals have not become law, campaigns by various special interest groups could lead to
future additional oil and natural gas severance or other taxes. The imposition of such taxes could significantly reduce
our profit margins and cash flow and otherwise significantly increase our costs.
Derivatives legislation and regulations could have an adverse effect on our ability to use derivative instruments to
reduce the risks associated with our business.
The Dodd-Frank Act, enacted in 2010, establishes federal oversight and regulation of the over-the-counter
(“OTC”) derivatives market and entities, like us, that participate in that market. Rules and regulations applicable to
OTC derivatives transactions, and these rules may affect both the size of positions that we may hold and the ability
or willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, such
changes could materially reduce our hedging opportunities which could adversely affect our revenues and cash flow
during periods of low commodity prices. While many Dodd-Frank Act regulations are already in effect, the
rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and
any future rules and regulations on our business remains uncertain.
In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to
the derivatives market. To the extent we transact with counterparties in foreign jurisdictions or counterparties with
other businesses that subject them to regulation in foreign jurisdictions, we may become subject to, or otherwise be
affected by, such regulations. Even though certain of the European Union implementing regulations have become
effective, the ultimate effect on our business of the European Union implementing regulations (including future
implementing rules and regulations) remains uncertain.
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Our operations are subject to a series of risks arising out of the threat of climate change that could result in
increased operating costs, limit the areas in which we may conduct oil and natural gas exploration and
production activities, and reduce demand for the oil and natural gas we produce.
The threat of climate change continues to attract considerable attention in the United States and in foreign
countries. Numerous proposals have been made and could continue to be made at the international, national,
regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or
eliminate such future emissions. As a result, our oil and natural gas exploration and production operations are
subject to a series of regulatory, political, litigation, and financial risks associated with the production and
processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level.
However, with the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA
has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions
from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain
petroleum and natural gas system sources in the United States, and together with the DOT, implement GHG
emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and
gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration revised
prior regulations to rescind certain methane standards and remove the transmission and storage segments from the
source category for certain regulations. However, subsequently, the U.S. Congress approved, and President Biden
signed into a law, a resolution to repeal the September 2020 revisions to the methane standards, effectively
reinstating the prior standards. In response to President Biden’s executive order, in November 2021, the EPA issued
a proposed rule that, if finalized, would establish new source and first-time existing source standards of performance
for methane and volatile organic compound emissions for oil and gas facilities. Operators of affected facilities will
have to comply with specific standards of performance to include leak detection using optical gas imaging and
subsequent repair requirement, and reduction of emissions by 95% through capture and control systems. The EPA
plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November
2021 proposed rule and anticipates the issuance of a final rule by the end of the year. We cannot predict the scope of
any final methane regulatory requirements or the cost to comply with such requirements. However, given the long-
term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a
significant possibility.
Additionally, various states and groups of states have adopted or are considering adopting legislation,
regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon
taxes, reporting and tracking programs, and restriction of GHG emissions, such as methane. For example, California,
through the CARB has implemented a cap and trade program for GHG emissions that sets a statewide maximum
limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030. Covered
entities must either reduce their GHG emissions or purchase allowances to account for such emissions. Separately,
California has implemented LCFS and associated tradable credits that require a progressively lower carbon intensity
of the state's fuel supply than baseline gasoline and diesel fuels. CARB has also promulgated regulations regarding
monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and gas
production facilities.
In September 2018, California adopted a law committing California , the fifth largest economy in the world, to
the use of 100% zero-carbon electricity by 2045, and the Governor of California also signed an executive order
committing California to total economy-wide carbon neutrality by 2045. In furtherance of these goals, Governor
Newsom issued an order to CalGEM in April 2021, directing the agency to initiate regulatory action to end the
issuance of new permits for hydraulic fracturing by January 2024. Additionally, Governor Newsom requested that
the CARB analyze pathways to phase out oil extraction across the state by no later than 2045. We cannot predict
how these various laws, regulations and orders may ultimately affect our operations. However, these initiatives
could result in decreased demand for the oil, natural gas, and NGLs that we produce, or otherwise restrict or prohibit
our operations altogether in California, and therefore adversely affect our revenues and results of operations.
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At the international level, the United Nations-sponsored “Paris Agreement” requires member states to
individually determine and submit non-binding emissions reduction targets every five years after 2020. Although the
United States had withdrawn from the Paris Agreement, following an executive order signed by President Biden on
his first day in office, the United States rejoined the Paris Agreement in February 2021. In April 2021, the United
States established a goal of reducing economy-wide net GHG emissions 50-52% below 2005 levels by 2030.
Additionally, at the 26th Conference of the Parties (“COP26”) in Glasgow in November 2021, the United States and
the European Union jointly announced the launch of the Global Methane Pledge, an initiative committing to a
collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all
feasible reductions’ in the energy sector. The full impact of these actions is uncertain at this time and it is unclear
what additional initiatives may be adopted or implemented that may have adverse effects upon our operations.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has
resulted in increasing political risks in the United States, including climate change related pledges made by certain
candidates for public office. These have included promises to pursue actions to limit emissions and curtail the
production of oil and gas, such as through banning new leases for production of minerals on federal properties. On
January 20, 2021, President Biden issued an executive order calling for increased regulation of methane emissions
from the oil and gas sector; for more information, see our regulatory disclosure titled “Air Emissions”.
Subsequently, on January 27, 2021, President Biden issued an executive order that calls for substantial action on
climate change, including, among other things, the increased use of zero-emissions vehicles by the federal
government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-
related risk across agencies and economic sectors. The Biden Administration has also called for restrictions on
leasing on federal land, including the Department of Interior’s publication of a report in November 2021
recommending various changes to the federal leasing program, though any such changes would require
Congressional action; for more information, see our regulatory disclosure titled “Hydraulic Stimulation”. Our
operations involve the use of hydraulic fracturing activities and we also have operations on federal lands under the
jurisdiction of the BLM within the DOI. Other actions that could be pursued by President Biden may include more
restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as
well as other GHG emissions limitations for oil and gas facilities.
Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit
against oil and natural gas companies in state or federal court, alleging, among other things, that such companies
created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and
therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have
been aware of the adverse effects of climate change for some time but withheld material information from their
investors or customers by failing to adequately disclose those impacts.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel
energy companies concerned about the potential effects of climate change may elect in the future to shift some or all
of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy
companies also have become more attentive to sustainable lending practices and some of them may elect not to
provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net
Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130
trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to
set short term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero
emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the
effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced that it
had joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused
on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve
issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-
related challenges most relevant to central banks and supervisory authorities. Although we cannot predict the effects
of these actions, such limitation of investments in and financings for fossil fuel energy companies could result in the
restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the
Securities and Exchange Commission announced its intention to promulgate rules requiring climate disclosures.
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Although the form and substance of these requirements is not yet known, this may result in additional costs to
comply with any such disclosure requirements.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations
or other regulatory initiatives that impose more stringent standards for GHG emissions from oil and natural gas
producers such as ourselves or otherwise restrict the areas in which we may produce oil and natural gas or generate
GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for
or erode value for, the oil and natural gas that we produce. Additionally, political, litigation, and financial risks may
result in our restricting or canceling oil and natural gas production activities, incurring liability for infrastructure
damages as a result of climatic changes, or impairing our ability to continue to operate in an economic manner.
Moreover, there are increasing risks to operations resulting from the potential physical impacts of climate change,
such as drought, wildfires, damage to infrastructure and resources from flooding and other natural disasters and
other physical disruptions. One or more of these developments could have a material adverse effect on our business,
financial condition and results of operation.
Risks Related to our Capital Stock
There may be circumstances in which the interests of our significant stockholders could be in conflict with the
interests of our other stockholders.
A large portion of our common stock is beneficially owned by a relatively small number of stockholders.
Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions,
divestitures, hostile takeovers or other transactions, including the payment of dividends or the issuance of additional
equity or debt, that, in their judgment, could enhance their investment in us or in another company in which they
invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant
concentration of share ownership may adversely affect the trading price of our common stock because investors may
perceive disadvantages in owning shares in companies with significant stockholder concentrations.
Our significant stockholders and their affiliates are not limited in their ability to compete with us, and the
corporate opportunity provisions in the Certificate of Incorporation could enable our significant stockholders to
benefit from corporate opportunities that might otherwise be available to us.
Our governing documents provide that our stockholders and their affiliates are not restricted from owning assets
or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of
applicable law, the Certificate of Incorporation, among other things:
•
•
permits stockholders to make investments in competing businesses; and
provides that if one of our directors who is also an employee, officer or director of a stockholder (a “Dual
Role Person”), becomes aware of a potential business opportunity, transaction or other matter, they will
have no duty to communicate or offer that opportunity to us.
Our director who is a Dual Role Person may become aware, from time to time, of certain business opportunities
(such as acquisition opportunities) and may direct such opportunities to other businesses in which our stockholders
have invested, in which case we may not become aware of, or otherwise have the ability to pursue, such opportunity.
Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities
to be unavailable to us or causing them to be more expensive for us to pursue.
Future sales of our common stock in the public market could reduce our stock price, and any additional capital
raised by us through the sale of equity or convertible securities may dilute your ownership in us.
Certain of our largest stockholders were creditors of Berry LLC prior to the Chapter 11 Proceedings and we
cannot predict when or whether they will sell their shares of common stock. Future sales, or concerns about them,
may put downward pressure on the market price of our common stock
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We may sell or otherwise issue additional shares of common stock or securities convertible into shares of our
common stock. Our Certificate of Incorporation provides for authorized capital stock consisting of 750,000,000
shares of common stock and 250,000,000 shares of preferred stock. In addition, we registered shares of the great
majority of our common stock for resale. For more information see Exhibit 4.4 to our Annual Report on Form 10-K.
The issuance of any securities for acquisitions, financing, upon conversion or exercise of convertible securities,
or otherwise may result in a reduction of the book value and market price of our outstanding common stock. If we
issue any such additional securities, the issuance will cause a reduction in the proportionate ownership and voting
power of all current stockholders. We cannot predict the size of any future issuances of our common stock or
securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our
common stock will have on the market price of our common stock. Sales of substantial amounts of our common
stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may
adversely affect prevailing market prices of our common stock.
Shares of our common stock are also reserved for issuance as equity-based awards to employees, directors and
certain other persons under the second amended and restated 2017 Omnibus Incentive Plan (our “Omnibus Plan”).
We have filed a registration statement with the SEC on Form S-8 providing for the registration of shares of our
common stock issued or reserved for issuance under our Omnibus Plan. Subject to the satisfaction of vesting
conditions, the expiration of certain lock-up agreements and the requirements of Rule 144, shares registered under
the registration statement on Form S-8 may be made available for resale immediately in the public market without
restriction. Investors may experience dilution in the value of their investment upon the exercise of any equity awards
that may be granted or issued pursuant to the Omnibus Plan in the future.
The payment of dividends will be at the discretion of our board of directors.
We temporarily discontinued our quarterly dividends in the second quarter 2020 following the historic oil price
drop and economic impact of COVID-19. We reinstated a quarterly dividend at a reduced rate beginning the first
quarter of 2021 and then increased the rate 50% beginning with the third quarter of 2021. The Company's Board of
Directors declared a regular dividend of $0.06 per share on the Company’s outstanding common stock, payable on
April 15, 2022 to shareholders of record at the close of business on March 15, 2022. In addition, the Board
implemented a shareholder return strategy that contemplates additional dividends to shareholders from discretionary
cash flow, but there is no certainty that we will generate discretionary cash flow, nor is the Board obligated to make
any dividends and any dividends are subject to the restrictions in our debt documents as described below. The
payment and amount of future dividend payments, if any, are subject to declaration by our Board. Such payments
will depend on various factors, including actual results of operations, liquidity and financial condition, net cash
provided by operating activities, restrictions imposed by applicable law, our taxable income, our operating expenses
and other factors our Board deems relevant. Additionally, covenants contained in our RBL Facility and the
indentures governing our 2026 Notes could limit the payment of dividends. We are under no obligation to make
dividend payments on our common stock and cannot be certain when such payments may resume in the future.
We may issue preferred stock, the terms of which could adversely affect the voting power or value of our common
stock.
Our Certificate of Incorporation authorizes us to issue, without the approval of our stockholders, one or more
classes or series of preferred stock having such designations, preferences, limitations and relative rights, including
preferences over our common stock respecting dividends and distributions, as our Board of Directors may
determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or
value of our common stock. For example, we might grant holders of preferred stock the right to elect some number
of our directors in all events or on the happening of specified events or the right to veto specified transactions.
Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred
stock could affect the residual value of our common stock.
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We are an “emerging growth company,” and are able to take advantage of reduced disclosure requirements
applicable to “emerging growth companies,” which could make our common stock less attractive to investors.
We are an “emerging growth company” and, for as long as we continue to be an “emerging growth company,”
we intend to take advantage of certain exemptions from various reporting requirements, including auditor attestation
requirements or any new requirements adopted by the Public Company Accounting Oversight Board (the
“PCAOB”) requiring mandatory audit firm rotation, reduced disclosure obligations regarding executive
compensation in our periodic reports and proxy statements and exemptions from the requirements of holding a non-
binding advisory vote on executive compensation and stockholder approval of any golden parachute payments not
previously approved. We could be an “emerging growth company” for up to five years, or until the earliest of (i) the
last day of the first fiscal year in which our annual gross revenues exceed $1.07 billion, (ii) as of the end of the fiscal
year that we become a “large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934,
as amended (the “Exchange Act”), which would occur if the market value of our common stock that is held by non-
affiliates exceeds $700 million as of the last business day of our most recently completed second fiscal quarter, or
(iii) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year
period.
We intend to take advantage of the reduced reporting requirements and exemptions, including the longer phase-
in periods for the adoption of new or revised financial accounting standards which lasts until those standards apply
to private companies or we no longer qualify as an emerging growth company. Our election to use the phase-in
periods permitted by this election may make it difficult to compare our financial statements to those companies who
will comply with new or revised financial accounting standards. If we were to subsequently elect instead to comply
with these public company effective dates, such election would be irrevocable.
To the extent investors find our common stock less attractive as a result of our reduced reporting and
exemptions, there may be a less active trading market for our common stock, and our stock price may be more
volatile.
Our internal control over financial reporting is not currently required to meet all of the standards required by
Section 404 of the Sarbanes-Oxley Act, but failure to achieve and maintain effective internal control over
financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse
effect on our business and share price.
Section 404 of the Sarbanes-Oxley Act requires us to provide annual management assessments of the
effectiveness of our internal control over financial reporting. However, our independent registered public accounting
firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to
Section 404 of the Sarbanes-Oxley Act until we are no longer an “emerging growth company,” which could be up to
five years from our IPO.
Effective internal controls are necessary for us to provide reliable financial reports, safeguard our assets, and
prevent fraud. If we cannot provide reliable financial reports, safeguard our assets or prevent fraud, our reputation
and operating results could be harmed. The rules governing the standards that must be met for our management to
assess our internal control over financial reporting are complex and require significant documentation, testing and
possible remediation.
We may encounter problems or delays in completing the implementation of effective internal controls. Further,
failure to achieve and maintain an effective internal control environment could have a material adverse effect on our
business and share price and could limit our ability to report our financial results accurately and timely.
Certain provisions of our Certificate of Incorporation and Bylaws may make it difficult for stockholders to
change the composition of our Board of Directors and may discourage, delay or prevent a merger or acquisition
that some stockholders may consider beneficial.
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Certain provisions of our Certificate of Incorporation and Bylaws may have the effect of delaying or preventing
changes in control if our Board of Directors determines that such changes in control are not in the best interests of us
and our stockholders. For more information see Exhibit 4.4 to our Annual Report on Form 10-K.
For example, our Certificate of Incorporation and Bylaws include provisions that (i) authorize our Board to
issue “blank check” preferred stock and to determine the price and other terms, including preferences and voting
rights, of those shares without stockholder approval and (ii) establish advance notice procedures for nominating
directors or presenting matters at stockholder meetings.
These provisions could enable the Board to delay or prevent a transaction that some, or a majority, of the
stockholders may believe to be in their best interests and, in that case, may discourage or prevent attempts to remove
and replace incumbent directors. These provisions may also discourage or prevent any attempts by our stockholders
to replace or remove our current management by making it more difficult for stockholders to replace members of our
Board, which is responsible for appointing the members of our management.
Our Certificate of Incorporation designates the Court of Chancery of the State of Delaware as the sole and
exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which
could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors,
officers, employees or agents.
Our Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative
forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the
sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a
claim of breach of a fiduciary duty owed by any of our directors, officers or other employees to us or our
stockholders, (iii) any action asserting a claim against us, our directors, officers or employees arising pursuant to any
provision of the Delaware General Corporation Law, our Certificate of Incorporation or our Bylaws or (iv) any
action asserting a claim against us, our directors, officers or employees that is governed by the internal affairs
doctrine, in each such case subject to such Court of Chancery having subject matter jurisdiction and personal
jurisdiction over the indispensable parties named as defendants therein. This choice of forum provision may limit a
stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors,
officers or other employees, which may discourage such lawsuits against us and such persons. Alternatively, if a
court were to find these provisions of our Certificate of Incorporation inapplicable to, or unenforceable in respect of,
one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving
such matters in other jurisdictions.
Item 1B. Unresolved Staff Comments
None.
Item 3. Legal Proceedings
We are involved in various legal and administrative proceedings in the normal course of business, the ultimate
resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of
operations, liquidity or financial condition.
Securities Litigation Matter
On November, 20, 2020, Luis Torres, individually and on behalf of a putative class, filed a securities class
action lawsuit (the “Torres Lawsuit”) in the United States District Court for the Northern District of Texas against
Berry Corp. and certain of its current and former directors and officers (collectively, the “Defendants”). The
complaint asserts violations of Sections 11 and 15 of the Securities Act of 1933, and Sections 10(b) and 20(a) of the
Exchange Act, on behalf of a putative class of all persons who purchased or otherwise acquired (i) common stock
pursuant and/or traceable to the Company’s 2018 IPO; or (ii) Berry Corp.'s securities between July 26, 2018 and
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November 3, 2020 (the “Class Period”). In particular, the complaint alleges that the Defendants made false and
misleading statements during the Class Period and in the offering materials for the IPO, concerning the Company’s
business, operational efficiency and stability, and compliance policies, that artificially inflated the Company’s stock
price, resulting in injury to the purported class members when the value of Berry Corp.’s common stock declined
following release of its financial results for the third quarter of 2020 on November 3, 2020.
On January 21, 2021, multiple plaintiffs filed motions in the Torres Lawsuit seeking to be appointed lead
plaintiff and lead counsel. After briefing and a stipulation between the remaining movants, the Court appointed Luis
Torres and Allia DeAngelis as co-lead plaintiffs on August 18, 2021. On November 1, 2021, the co-lead plaintiffs
filed an amended complaint asserting claims on behalf of the same putative class under Sections 11 and 15 of the
Securities Act of 1933 and Sections 10(b) and 20(a) of the Exchange Act, alleging, among other things, that the
Company and the individual Defendants made false and misleading statements between July 26, 2018 and
November 3, 2020 regarding the Company’s permits and permitting processes. The amended complaint does not
quantify the alleged losses but seeks to recover all damages sustained by the putative class as a result of these
alleged securities violations, as well as attorneys’ fees and costs. The Defendants filed a Motion to Dismiss on
January 24, 2022; plaintiffs’ opposition is due on March 21, 2022 and Defendants' reply is due on May 16, 2022.
We dispute these claims and intend to defend the matter vigorously. Given the uncertainty of litigation, the
preliminary stage of the case, and the legal standards that must be met for, among other things, class certification
and success on the merits, we cannot reasonably estimate the possible loss or range of loss that may result from this
action.
Other Matters
For additional information regarding legal proceedings, see “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations—Liquidity and Capital Resources—Commitments, and
Contingencies” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations—Liquidity and Capital Resources—Contractual Obligations.”
Item 4. Mine Safety Disclosure
Not applicable.
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Part II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
Market Information
Our common stock has been trading on the NASDAQ under the ticker symbol “bry” since July 26, 2018. Prior
to that there was no established public trading market for our common stock.
Holders of Record
Our common stock was held by 31 stockholders of record at January 31, 2022.
Dividend Policy
We historically have, and plan to continue using our operating cash flows to cover our interest requirements,
fund operations at sustained production levels, and routinely return meaningful capital to stockholders in the form of
quarterly fixed dividends through commodity price cycles. .
We first began paying a quarterly dividend paying in our first quarter as a public company in 2018, which we
paid regularly through the first quarter of 2020. We temporarily discontinued our quarterly dividends in the second
quarter 2020 following the historic oil price drop and economic impact of COVID-19. We reinstated a quarterly
dividend at a reduced rate beginning the first quarter of 2021 and then increased the rate 50% beginning with the
third quarter of 2021. Our Board declared a regular dividend at a rate of $0.06 per share on the Company’s
outstanding common stock, payable on April 15, 2022 to shareholders of record at the close of business on March
15, 2022.
In early 2022, we implemented a new shareholder return model, for which we intend to allocate a significant
portion of discretionary free cash flow to cash variable dividends to be paid quarterly. We expect remaining cash
flows will 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. This new model is designed to significantly increase cash returns to our shareholders,
further demonstrating Berry's commitment to be a leading returner of capital to its shareholders. Any dividends
actually paid will be determined by our Board of Directors in light of existing conditions, including our earnings,
financial condition, restrictions in financing agreements, business conditions and other factors.
Securities Authorized for Issuance Under Equity Compensation Plans
On June 27, 2018, our Board approved our second amended and restated 2017 Omnibus Incentive Plan (the
“Omnibus Plan”). A description of the plans can be found in Item 8. Financial Statements and Supplementary Data –
Note 6–Equity. The aggregate number of shares of our common stock authorized for issuance under stock-based
compensation plans for our employees and non-employee directors is 10 million, of which 8.6 million have been
issued or reserved through December 31, 2021.
The following table summarizes information related to our equity compensation plans under which our equity
securities are authorized for issuance as of December 31, 2021.
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Plan Category
Equity compensation plans not
approved by security
holders(2)
________________
Number of Securities to be
Issued Upon Exercise of
Outstanding Options and
Rights (#)(1)
Weighted-Average Exercise
Price of Outstanding Options
and Rights ($)
Number of Securities
Remaining Available for
Future Issuance Under Equity
Compensation Plans (#)(3)
6,998,815
N/A
1,368,778
(1) The number of securities to be issued upon vesting of unvested restricted stock units (“RSUs”) subject to time vesting and performance-
based restricted stock units (“PSUs”), assumes maximum achievement of certain market-based performance goals over a specified period of
time.
(2)
In connection with the IPO, our Board amended and restated the Company’s First Amended and Restated 2017 Omnibus Incentive Plan,
which had amended and restated the Company’s 2017 Omnibus Incentive Plan (the “Prior Plans” and, collectively with the Omnibus Plan,
the “Equity Compensation Plans”), which allowed us to grant equity-based compensation awards with respect to up to 10,000,000 shares of
common stock (which number includes the number of shares of common stock previously issued pursuant to an award (or made subject to
an award that has not expired or been terminated) under the Prior Plans), to employees, consultants and directors of the Company and its
affiliates who perform services for the Company. The Omnibus Plan provides for grants of stock options, stock appreciation rights,
restricted stock, restricted stock units, stock awards, dividend equivalents and other types of awards.
(3) The number of securities remaining available for future issuances has been reduced by the number of securities to be issued upon settlement
of RSUs subject to time vesting and PSUs assuming maximum achievement of certain market-based performance goals over a specified
period of time.
Sales of Unregistered Securities
None
Stock Repurchase Program
In December 2018, our Board of Directors adopted a program for the opportunistic repurchase of up to
$100 million of our common stock. Based on the Board’s evaluation of market conditions for our common stock at
the time, they authorized repurchases of up to $50 million under the program. In 2018 and 2019, the Company
repurchased a total of 5,057,682 shares under the stock repurchase program for approximately $50 million in
aggregate. In February 2020, the Board of Directors authorized the repurchase of the remaining $50 million
available under the repurchase program. We did not repurchase any common stock in 2020. For the year ended
December 31, 2021, we repurchased 471,022 shares at an average price of $5.18 per share for approximately
$2 million in the third quarter. All shares repurchased are reflected as treasury stock. Accordingly, as of December
31, 2021, the Company has repurchased a total of 5,528,704 shares under the stock repurchase program for
approximately $52 million in aggregate, leaving approximately $48 million authorized and available for future
repurchases under the program. The new shareholder return model that we implemented in January 2022
contemplates the potential use of a portion of discretionary free cash flow to opportunistically repurchase common
stock.
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 Berry Corp. to
purchase shares during any period or at all. Any shares acquired will be available for general corporate purposes.
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Performance Graph
The following graph compares the cumulative total return to stockholders on our common stock relative to the
cumulative total returns of the S&P Smallcap 600, the Dow Jones U.S. Exploration and Production indexes and the
Vanguard Energy ETF (with reinvestment of all dividends). The graph assumes that on July 26, 2018, the date our
common stock began trading on the NASDAQ, $100 was invested in our common stock and in each index, and that
all dividends were reinvested. The returns shown are based on historical results and are not intended to suggest
future performance.
COMPARISON OF CUMULATIVE TOTAL RETURN(1)(2)
Among Berry Corporation (bry), the S&P Smallcap 600 Index,
the Dow Jones U.S. Exploration & Production Index
and the Vanguard Energy ETF
7/26/18
12/18
06/19
12/19
06/20
12/20
06/21
12/21
Berry Corporation (bry)
S&P Smallcap 600
$ 100.00 $ 67.17 $ 83.16 $ 75.90 $ 40.66 $ 30.98 $ 57.25 $ 72.98
$ 100.00 $ 83.66 $ 95.12 $ 102.72 $ 84.38 $ 114.32 $ 141.26 $ 144.98
Dow Jones U.S. Exploration & Production $ 100.00 $ 71.18 $ 78.12 $ 79.29 $ 49.00 $ 52.61 $ 81.45 $ 89.92
Vanguard Energy ETF
__________
$ 100.00 $ 73.67 $ 82.49 $ 80.50 $ 51.03 $ 53.89 $ 80.32 $ 84.17
(1) The performance graph shall not be deemed “soliciting material” or to be “filed” with the SEC for purposes of Section 18 of the Exchange
Act, or otherwise subject to the liabilities under that Section, and shall not be deemed to be incorporated by reference into any filing of the
65
Period EndingCumulative Total ReturnBerry Corporation (bry)S&P Smallcap 600Dow Jones U.S. Exploration & ProductionVanguard Energy ETF7/26/1812/1806/1912/1906/2012/2006/2112/21$25$50$75$100$125$150$175 Table of Contents
Index to Financial Statements and Supplementary Data
Company under the Securities Act of 1933, as amended (the “Securities Act”) or the Exchange Act except to the extent that we specifically
request it be treated as soliciting material or specifically incorporate it by reference.
(2) $100 invested on July 26, 2018 in stock or June 30, 2018 in index, including reinvestment of dividends.
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Item 6. Selected Financial Data
Not applicable
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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in
conjunction with the financial statements and related notes included elsewhere in this report. The following
discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected
performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be
outside our control. Our actual results could differ materially from those discussed in these forward-looking
statements. Factors that could cause or contribute to such differences are described in “Item 1A. Risk Factors”
included earlier in this report. Please see “—Cautionary Note Regarding Forward-:Looking Statements.”
This section of the Form 10-K generally discusses 2021 and 2020 items and year-to-year comparisons between
those years. For discussion of our year ended December 31, 2019, as well as the year ended 2020 compared to year
ended 2019, refer to Part II, Item 7— “Management's Discussion and Analysis of Financial Condition and Results
of Operations” of our 2020 Annual Report on Form 10-K.
Executive Overview
We are a western United States independent upstream energy company focused on the development and
production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California. As
further discussed below, in the fourth quarter of 2021, we diversified our operations with the acquisition of a
business with well servicing and abandonment capabilities. As of October 1, 2021, we have operated in two business
segments: (i) development and production (“D&P”) (ii) well servicing and abandonment. The development and
production segment is engaged in the development and production of onshore, low geologic risk, long-lived
conventional oil reserves primarily located in California, as well as Utah. On October 1, 2021, we completed the
acquisition of one of the largest upstream well servicing and abandonment businesses in California, which became a
reportable segment (well servicing and abandonment) under U.S. GAAP.
Our upstream development and production assets, in the aggregate, are characterized by high oil content, with
100% oil content for our California assets, and are 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. For example, the cost to drill and complete the different types of our wells in
California is approximately $400,000 per well. The vertical wells in Utah operations cost approximately $1.5 million
per well. In contrast, wells in typical unconventional resource plays cost $5 million to $10 million to drill and
complete. The California oil market has Brent-linked pricing which in recent history realizes premium pricing to
WTI. In the past five years Brent pricing has averaged almost $5 above 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.
In the fourth quarter of 2021, we acquired one of the largest upstream well servicing and abandonment
businesses in California, which operates as C&J Well Services. This acquisition creates a strategic growth
opportunity for Berry. It 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, C&J Well Services 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. We believe that
C&J Well Services is uniquely positioned to capture both state and federal funds to help remediate orphan idle wells
(an idle well that has been abandoned by the operator and as a result becomes a burden of the State is referred to as
an orphan well), and there are approximately 35,000 idle wells estimated to be in California according to third-party
sources.
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Since our Initial Public Offering in 2018, we have demonstrated our commitment to returning a substantial
amount of capital to shareholders, delivering $134 million to our shareholders through dividends and share
repurchases through 2021. In 2022, we initiated a new shareholder return model, which is designed to significantly
increase cash returns to our shareholders from our discretionary free cash flow, which we define as cash flow from
operations less regular fixed dividends and the capital needed to hold production flat. Like our business model, this
new shareholder returns model is simple and further demonstrates our commitment to return capital to our
shareholders.
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 Levered Free Cash Flow to fund our operations, optimize capital efficiency, and return
meaningful capital to stockholders, while maintaining a low leverage profile and focusing on attractive organic and
strategic growth through commodity price cycles.
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.
How We Plan and Evaluate Operations
We use “Levered Free Cash Flow” in planning our capital allocation to sustain production levels and fund
internal growth opportunities, as well as determine our strategic hedging needs (we also hedge to meet the hedging
requirements of the 2021 RBL Facility). Levered Free Cash Flow is a non-GAAP financial measure that we define
as Adjusted EBITDA less capital expenditures, interest expense and dividends. Adjusted EBITDA is also a non-
GAAP financial measure that is discussed and defined below.
We use the following metrics to manage and assess the performance of our operations: (a) Adjusted EBITDA;
(b) shareholder returns; (c) operating expenses; (d) environmental, health & safety (“EH&S”) results; (e) general and
administrative expenses; (f) production; and (g) well servicing and abandonment operations performance. With
respect to our development and production business, we also measure oil and gas production levels. For our well
services and abandonment business, we measure their performance through 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 our business. 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.
Shareholder Returns
In early 2022, we implemented a new shareholder return model, for which we intend to allocate a significant
portion of discretionary free cash flow to cash variable dividends to be paid quarterly. 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 production flat. We expect remaining cash flows will 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 are based on the
Company's average cash returned on invested capital.
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Operating Expenses
Overall, operating expense is used by management as a measure of the efficiency with which operations are
performing. With respect to our production 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, and more recently agreements to transport fuel gas from the
Rockies which have historically been cheaper than the California markets.
Environmental, Health & Safety
Like other companies in the oil and gas industry, both our production and well services operations are subject to
complex and stringent federal, state and local laws and regulations relating to drilling, completion, well stimulation,
well servicing, operation, maintenance or abandonment of wells or facilities, managing energy, water use, land use,
managing greenhouse gases or other emissions, governing the discharge of materials into the environment or
otherwise relating to environmental protection, including air quality, and the transportation, marketing, and sale of
our products.
With respect to our production operations, current and future laws and regulations, as well as legislative and
regulatory changes and other government activities, can materially impact our development, production, well
servicing and abandonment plans, including by restricting the production rate of oil, natural gas and NGLs below the
rate that would otherwise be possible. Additionally, the regulatory burden on the industry increases the cost of doing
business and consequently effects capital expenditures and earnings.
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 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 safer, more efficient and lower emission operations. 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 monitor our EH&S performance through various measures, holding our employees and contractors
to high standards. Meeting corporate EH&S metrics, including with respect to health and safety 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 approximately 9% of such costs are capitalized, which 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.
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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 by service
and customer, as well as Adjusted EBITDA for this business.
Business Environment and Market Conditions
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 and differentials have, and may continue to, fluctuate significantly as a result
of numerous market-related variables, including global geopolitical and economic conditions. While oil prices have
improved in 2021 and into 2022, they still remain volatile.
Our well services and abandonment business is dependent on expenditures of oil and gas companies, which can
in part reflect the volatility of commodity prices. 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 is largely driven by regulatory requirements that is less dependent on commodity prices.
The recent recovery in the oil and gas industry has improved with increasing oil prices as demand increases
with more states and countries re-opening and national and global economies continuing to recover from the global
COVID-19 pandemic. The demand for oil, while improving as the ability of the global industry to grow supply
diminishes, could again decline if there is a widespread resurgence of the COVID-19 outbreak. The extent to which
our operating and financial results of future periods will be adversely impacted by the ongoing COVID-19 pandemic
and the actions of foreign oil and gas producers will depend largely on future developments, which are highly
uncertain and cannot be accurately predicted. Further, to what extent these events do ultimately impact our future
business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous
factors that are not within our control and cannot be predicted, including the duration and extent of the pandemic and
speculation as to future actions by OPEC+. We were proactive in taking steps to address the challenges and mitigate
repercussions from both the COVID-19 pandemic and industry downturns on our operations, our financial condition
and our people.
As we focused on managing our business and operations in response to this health and economic crisis, the
safety and well-being of our employees and the communities in which we operate remained our top priority. We are
committed to being a good corporate citizen and demonstrated this commitment by focusing on the well-being of
our employees and communities, including maintaining our strong safety and environmental standards and investing
in community impact initiatives.
Because the visibility of the long-term supply and demand for oil has improved, we reinstated the quarterly
dividend in the first quarter of 2021, which had been temporarily suspended in 2020, increased the dividend
beginning the third quarter of 2021, and repurchased treasury shares during the year. Since our Initial Public
Offering in 2018, we have demonstrated our commitment to returning a substantial amount of capital to
shareholders, delivering $134 million to our shareholders through dividends and share repurchases through 2021. In
2022, we initiated a new shareholder return model, which is designed to significantly increase cash returns to our
shareholders from our discretionary free cash flow, which we define as cash flow from operations less regular fixed
dividends and the capital needed to hold production flat. Like our business model, this new shareholder returns
model is simple and further demonstrates our commitment to return capital to our shareholders.
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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, including those discussed in Part I, Item 1A. “Risk Factors” in this Annual Report.
Average oil prices were higher for the year ended December 31, 2021 compared to the year ended December
31, 2020. Brent crude oil contract prices ranged from $51.09 per bbl to $86.40 per bbl and averaged $70.95 per bbl
during the year. Though the California market generally receives Brent-influenced pricing, California oil prices are
determined ultimately by local supply and demand dynamics.
In California, the price we have typically paid for fuel gas purchases is generally based on the Kern, Delivered
Index, which was as high as $120.13 per mmbtu in February due to the effects of Winter Storm Uri, and as low as
$2.37 per mmbtu during 2021, while we paid an average of $5.64 per mmbtu for the year.
The following table presents the average Brent, WTI, Kern Delivered, and Henry Hub prices for the years ended
December 31, 2021 and 2020:
Brent oil ($/bbl)
WTI oil ($/bbl)
Kern, Delivered natural gas ($/mmbtu)
Henry Hub natural gas ($/mmbtu)
Year Ended December 31,
2021
2020
70.95 $
67.90 $
5.65 $
3.89 $
43.21
39.59
2.46
2.03
$
$
$
$
As mentioned above, California oil prices are Brent-influenced as California refiners import approximately 65%
to 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, 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 differentials are strongly affected by local market fundamentals, availability of
transportation 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. Natural gas prices
were strong in 2021 and we expect will continue to exhibit strength in 2022 based on current and projected supply
and demand balances. 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 recently
entered into new pipeline capacity agreements for the shipment of natural gas from the Rockies to our assets in
California that help limit 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
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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 long-term contracts with terms ending in
July 2022 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. In October 2021 we sold
Placerita, which included a cogeneration facility requiring significant fuel gas purchases, and generated significant
amount of electricity throughout the year, especially in the summer months.
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 may have been and in the future may be impacted by ice and snow in
the winter, especially in Utah, and by electrical storms and high temperatures in the spring and summer, as well as
by wild fires and rain.
Additionally, like other companies in the oil and gas industry, our operations are subject to stringent federal,
state and local laws and regulations relating to drilling, completion, well stimulation, operation, maintenance or
abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of
health, safety and the environment, or transportation, marketing, and sale of our products. Federal, state and local
agencies may assert overlapping authority to regulate in these areas. See “Items 1 and 2. Business and Properties-
Regulation of Health, Safety and Environmental Matters” for a description of laws and regulations that affect our
business. For more information related to regulatory risks, see “Item 1A. Risk Factors—Risks Related to Our
Operations and Industry”.
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Certain Operating and Financial Information
The following tables set forth information regarding average daily production, total production, and average
prices for the years ended December 31, 2021 and 2020.
Year Ended December 31,
2021
2020
Average daily production:(1)
Oil (mbbl/d)
Natural Gas (mmcf/d)
NGLs (mbbl/d)
Total (mboe/d)(2)
Total Production:
Oil (mbbl)
Natural gas (mmcf)
NGLs (mbbl)
Total (mboe)(2)
Weighted-average realized prices:
Oil without hedges ($/bbl)
Effects of scheduled derivative settlements ($/bbl)
Oil with hedges ($/bbl)
Natural gas ($/mcf)
NGLs ($/bbl)
Average Benchmark prices:
Oil (bbl) – Brent
Oil (bbl) – WTI
Gas (mmbtu) – Kern, Delivered(3)
Natural gas (mmbtu) – Henry Hub(4)
__________
$
$
$
$
$
$
$
$
$
24.2
17.1
0.4
27.4
8,825
6,224
141
10,004
66.57 $
(16.45) $
50.12 $
5.27 $
36.64 $
70.95 $
67.90 $
5.65 $
3.89 $
25.0
18.5
0.4
28.5
9,176
6,766
131
10,435
39.56
16.51
56.07
2.08
12.57
43.21
39.59
2.46
2.03
(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 year ended December 31, 2021, the
average prices of Brent oil and Henry Hub natural gas were $70.95 per bbl and $3.89 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:
Average daily production (mboe/d)(1):
California(2)
Utah
Colorado(3)
Total average daily production
__________
(1) Production represents volumes sold during the period.
Year Ended December 31,
2021
2020
22.0
4.2
26.2
1.2
27.4
22.9
4.3
27.2
1.3
28.5
(2)
Includes production for Placerita properties though the end of October 2021 when they were divested. These properties had average daily
production in 2021 of over 800 boe/d prior to the sale.
(3) Our properties in Colorado were in the Piceance basin, all of which were all divested in January 2022.
Average daily production increased each quarter throughout 2021 and the last quarter of 2021 was 5% higher
than the last quarter of 2020. This is indicative of the positive response from our assets with strategic capital
deployment. The year-over-year production results were impacted by a significant capital reduction in 2020 in
response to the significant decline in oil price and the measured ramp up in activity in early 2021. Oil production
decreased 4% for the year ended December 31, 2021 compared to the year ended December 31, 2020, however the
fourth quarter 2021 exit rate was 6% higher than the prior year. As a result of the 2021 development campaign in
Utah, the year-over-year production in Utah was essentially flat compared to the decline of 14% in 2020.
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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.
California
(San Joaquin and Ventura
basins)(3)
Utah
(Uinta basin)
Colorado
(Piceance basin)(4)
Year Ended December 31,
Year Ended December 31,
Year Ended December 31,
2021
2020
2021
2020
2021
2020
($ in thousands, unless noted otherwise)
Oil, natural gas and natural gas
liquids sales
Operating income (loss)(1)
Depreciation, depletion, and
amortization (DD&A)
Impairment of oil and gas properties
Average daily production (mboe/d)
Production (oil % of total)
Realized sales prices:
Oil (per bbl)
NGLs (per bbl)
Gas (per mcf)
Capital expenditures(2)
Total proved reserves (mmboe)
__________
$
$
$
$
$
$
$
$
540,782 $
335,642 $
69,968 $
37,481 $
14,705 $
5,537
74,247 $
(7,915) $
30,128 $
(126,289) $
11,570 $
(357)
138,969 $
130,388 $
1,795 $
7,058 $
— $
163,879 $
— $
125,206 $
22.0
100 %
22.9
100 %
4.2
51 %
4.3
50 %
152 $
— $
1.2
2 %
324
—
1.3
2 %
67.27 $
40.01 $
— $
— $
— $
— $
59.49 $
36.64 $
4.94 $
12.57 $
2.22 $
104,485 $
65,456 $
16,289 $
1,247 $
79
87
14
7
— $
5.76 $
1 $
4
—
1.87
206
1
34.81 $
53.22 $
24.01
(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)
Includes production for Placerita properties, in the Ventura basin, though the end of October 2021 when they were divested. These
properties had average daily production in 2021 of over 800 boe/d prior to the sale.
(4) Our properties in Colorado were in the Piceance basin, all of which were all divested in January 2022.
Results of Operations
Revenues and other:
Year Ended December 31,
2021
2020
$ Change
% Change
(in thousands)
Oil, natural gas and natural gas liquid sales
$
625,475 $
378,663 $
246,812
Services revenue
Electricity sales
(Losses) gains on oil and gas sales derivatives
Marketing and other revenues
Total revenues and other
35,840
35,636
(156,399)
4,398
—
25,813
117,781
1,576
$
544,950 $
523,833 $
35,840
9,823
(274,180)
2,822
21,117
65 %
100 %
38 %
n/a
179 %
4 %
Revenues and Other
We hedge a significant portion of our oil sales in order to protect our anticipated cash flows from oil price
decreases, as well as to meet the hedging requirements of the 2021 RBL Facility. In 2021, our unhedged realized oil
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price was $66.57 per bbl and the hedged price was $50.12 per bbl. By comparison, in 2020, our unhedged realized
oil price was $39.56 per bbl and our hedged price was $56.07 per bbl.
Oil, natural gas and NGL sales increased by $247 million, or 65%, to approximately $625 million for the year
ended December 31, 2021 when compared to the year ended December 31, 2020. The increase was driven by $242
million and $20 million of higher prices for oil and natural gas, respectively, partially offset by a $15 million
decrease in volumes.
Services revenue in 2021 consisted entirely of revenue from the Well Servicing and Abandonment business we
acquired on October 1, 2021.
Electricity sales which represent sales to utilities increased by $10 million, or 38%, to approximately $36
million for the year ended December 31, 2021 when compared to the year ended December 31, 2020. The increase
was largely a result of 59% higher unit sales prices that were driven by higher natural gas prices, partially offset by
slightly lower volumes sold.
Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains
and losses. In the year ended December 31, 2021, settlement losses were $143 million and in 2020 settlements gains
were $152 million. The change was due to higher prices relative to the derivative fixed prices in 2021 compared to
2020. The mark-to-market non-cash losses for the years ended December 31, 2021 and 2020 of $14 million and $34
million, respectively, were due to higher future prices relative to the derivative fixed prices at each year end.
Marketing and other revenues were higher for the year ended December 31, 2021, compared to the year ended
December 31, 2020 due to higher average gas prices.
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Expenses and other:
Lease operating expenses
Costs of services
Electricity generation expenses
Transportation expenses
Marketing expenses
General and administrative expenses
Depreciation, depletion and amortization
Impairment of oil and gas properties
Taxes, other than income taxes
(Gains) losses on natural gas purchase
derivatives
Other operating expense
Total expenses and other
Other (expenses) income:
Interest expense
Other, net
Total other (expenses) income
Loss before income taxes
Income tax expense (benefit)
Net loss
Adjusted EBITDA(6)
Adjusted Net Income (Loss)(6)
Expenses per boe:(1)
Lease operating expenses
Electricity generation expenses
Electricity sales
Transportation expenses
Transportation sales
Marketing expenses
Marketing revenues
Derivative settlements (received) paid for gas
purchases(1)
Total operating expenses
Total unhedged operating expenses(2)
Total non-energy operating expenses(3)
Total energy operating expenses(4)
General and administrative expenses(5)
Depreciation, depletion and amortization
Taxes, other than income taxes
Year Ended December 31,
2021
2020
$ Change
% Change
(in thousands)
$
236,048 $
186,348 $
28,339
23,148
6,897
3,811
73,106
144,495
—
46,500
(38,577)
3,101
526,868
(31,964)
(247)
(32,211)
(14,129)
1,413
—
16,608
6,938
1,380
77,696
139,180
289,085
35,572
1,035
5,781
759,623
(34,295)
(28)
(34,323)
(270,113)
(7,218)
(15,542) $
212,146 $
21,072 $
(262,895) $
244,430 $
44,816 $
23.60 $
17.86 $
1.59
(2.47)
0.66
(0.01)
0.13
(0.14)
0.89
18.51 $
17.62 $
13.63 $
4.88 $
7.45 $
13.34 $
3.41 $
2.31
(3.56)
0.69
(0.05)
0.38
(0.39)
(5.09)
17.89 $
22.98 $
13.12 $
4.77 $
7.31 $
14.44 $
4.65 $
78
$
$
$
$
$
$
$
$
$
$
$
49,700
28,339
6,540
(41)
2,431
(4,590)
5,315
(289,085)
10,928
(39,612)
(2,680)
(232,755)
(2,331)
219
(2,112)
(255,984)
8,631
(247,353)
(32,284)
(23,745)
5.74
0.72
1.09
0.03
0.04
0.25
0.25
(5.98)
(0.62)
5.36
(0.51)
(0.11)
(0.14)
1.10
1.24
27 %
100 %
39 %
(1) %
176 %
(6) %
4 %
(100) %
31 %
n/a
(46) %
(31) %
(7) %
782 %
(6) %
(95) %
120 %
(94) %
(13) %
(53) %
32 %
45 %
44 %
5 %
400 %
192 %
179 %
n/a
(3) %
30 %
(4) %
(2) %
(2) %
8 %
36 %
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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
settlements (gains) losses.
(4) Total energy operating expenses equals fuel and gas purchase derivative settlements (gains) losses less electricity sales.
(5)
Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.61 per boe and $1.94 per boe for
the year ended December 31, 2021 and December 31, 2020, respectively.
(6) Adjusted EBITDA and Adjusted Net Income (Loss) are financial measures that are not calculated in accordance with GAAP. For definitions
and a reconciliation to the Net Cash Provided by Operating Activities and Net Income (Loss), please see “Item 7 — Non-GAAP Financial
Measures”.
Expenses
Operating expenses, including hedge effects, decreased 3% or $0.62 per boe for the year ended December 31,
2021 from $18.51 for the year ended December 31, 2020 due to lower non-energy operating expenses and energy
operating expenses. Operating expenses are defined above in “How We Plan And Evaluate Operations.”
As a result of our efficiency initiatives implemented beginning in the second quarter of 2020, we achieved a
positive and substantial impact on operating expenses throughout 2021 without compromising our safety standards.
Through these initiatives, non-energy operating expense decreased approximately $11 million, $0.51 per boe, when
compared to the prior year. Primary year-over-year cost reductions in lease operating expenses were driven by lower
facility costs of $0.63 per boe and outside services of $0.21, partially offset by higher recompletions and well
maintenance of $0.21 and other expenses. Energy operating expenses decreased $0.11 per boe in 2021 due to higher
electricity revenue of $1.09 per boe partially offset by higher hedged fuel costs of $0.97 per boe. Fuel costs impact
both lease operating expenses and electricity generation expenses. Average natural gas purchase price increased
$3.10 per mmbtu, 2.2 times higher than that of 2020, which resulted in higher fuel expense, net of the benefit from
lower consumption. Settled hedges in 2021 had an average fixed price of $2.80 and notional quantities of 46,000
mmbtu per day, resulting in hedge effects that offset a large portion unhedged fuel cost. Higher natural gas prices in
2021 resulted in increased electricity unit revenue compared to 2020.
Cost of services in 2021 consisted entirely of costs from the Well Servicing and Abandonment business we
acquired on October 1, 2021.
Electricity generation expenses increased 45% to $2.31 per boe for the year ended December 31, 2021 from
$1.59 for the year ended December 31, 2020 primarily driven by higher fuel cost. Increased fuel costs included in
electricity generation expenses exclude the effects of natural gas derivative settlements discussed elsewhere.
Gain or loss on natural gas purchase derivatives for the year ended December 31, 2021 and 2020 were a gain of
$39 million and a loss of $1 million, respectively. The settlement gain for the year ended December 31, 2021 was
$51 million, or $5.09 per boe, compared to a settlement loss of $9 million, or $0.89 per boe for same period in 2020,
driven by higher gas prices in 2021 compared to 2020. The mark-to-market valuation gain or loss for each of the
years ended December 31, 2021 and December 31, 2020 was a loss of $13 million and a gain of $8 million,
respectively, consistent with the changes in futures prices at the end of each period. While, we allocate fuel costs to
electricity generation and lease operating expenses, we do not allocate hedge effects specifically to these line items.
Transportation expenses decreased 5% to $0.69 per boe for the year ended December 31, 2021, compared to
$0.66 for the year ended December 31, 2020, mainly due to lower volumes shipped from our Rockies assets.
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Marketing expenses increased 192% to $0.38 per boe for the year ended December 31, 2021, compared to $0.13
per boe for the year ended December 31, 2020 due to higher gas prices. Marketing expenses in these periods, which
exclude the effects of hedging, represented the cost of natural gas purchased and sold to third parties.
General and administrative expenses decreased by approximately $5 million or 6%, for the year ended
December 31, 2021 compared to the year ended December 31, 2020. This decrease includes lower non-cash stock
compensation costs and non-recurring costs. For the year ended December 31, 2021 and 2020, non-cash stock
compensation costs were approximately $13 million and $14 million, respectively, and non-recurring costs were
approximately $3 million and $6 million, respectively. Non-recurring costs in 2021 consisted of legal and other
professional services costs related to acquisition activity. In 2020, these costs primarily consisted of employee
reorganization and termination costs and to a lesser degree costs associated with the volatile and depressed price
environment.
Adjusted general and administrative expenses, which excluded non-cash stock compensation costs and non-
recurring costs, were flat year-over-year, at $57 million despite the additional $3 million CJWS general and
administrative expenses in the fourth quarter of 2021. Excluding the impact of CJWS, the $3 million year-over-year
decrease in adjusted general and administrative expenses was primarily due to lower employee costs. Please 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 calculated and presented in accordance
with GAAP.
DD&A increased by $5 million, or 4%, to approximately $144 million, for the year ended December 31, 2021
compared to the year ended December 31, 2020, due to the higher depreciation and depletion rates for 2021. On a
per boe basis, year-over-year DD&A increased $1.10 to $14.44 from $13.34.
Impairment of Oil and Gas Properties
During 2021, we did not have any impairment charges. In the first quarter of 2020, we performed impairment
tests with respect to our proved and unproved oil and gas properties as a result of significant declines in oil prices.
As a result, we recorded a non-cash pre-tax asset impairment charge of $289 million on proved properties in Utah
and certain California locations.
Taxes, Other Than Income Taxes
Severance taxes
Ad valorem taxes
Greenhouse gas allowances
Total taxes other than income taxes
$
$
Year Ended December 31,
2021
2020
$ Change
% Change
(per boe)
0.83 $
1.73
2.09
0.77 $
1.62
1.02
4.65 $
3.41 $
0.06
0.11
1.07
1.24
8 %
7 %
105 %
36 %
Taxes, other than income taxes, increased $1.24 to $4.65 per boe for the year ended December 31, 2021
compared to $3.41 for the year ended December 31, 2020. The increase was largely due to higher greenhouse gas
mark-to-market prices during 2021. GHG prices began 2021 at $18 per metric ton and increased to $32 at year-end,
and averaged $24 during 2021. During 2021, we experienced an increase in property taxes, as well as higher
severance taxes due to increased revenue driven by higher product prices.
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Other Operating Expense (Income)
For the years ended December 31, 2021 and 2020 other operating expenses were $3 million and $6 million,
respectively. For the year ended December 31, 2021, other operating expenses mainly consisted of expensing
approximately $3 million of unamortized debt issuance costs related to the 2017 RBL Facility, approximately $3
million of supplemental property tax assessments, royalty audit charges and tank rental costs, and $2 million of
various other costs such as excess abandonment costs and legal fees, partially offset by approximately $2 million of
gain on the sale of properties and over $2 million of income from employee retention credits. For the year ended
December, 31 2020, other operating expenses included $3 million of excess abandonment costs, $2 million of oil
tank storage fees, and $1 million of drilling rig standby charges, partially offset by $1 million of tax and other
refunds.
Interest Expense
Interest expense was comparable for the years ended December 31, 2021 and 2020.
Income Tax Expense (Benefit)
For the year ended December 31, 2021, we had income tax expense of approximately $1 million and a tax
benefit of $7 million in 2020. The rates in 2021 and 2020 were impacted as we recorded valuation allowances on a
large portion of our tax credits, net operating loss carryforwards and on other deferred tax assets as a result of
estimated future realizability. The tax expense in 2021 included minimum taxes paid in California. Refer to Note 8
of the consolidated financial statements for more information about our income taxes.
Liquidity and Capital Resources
Currently, we expect to fund our 2022 capital expenditures with cash flows from our operations. As of
December 31, 2021, we had liquidity of $215 million, consisting of $22 million cash on hand and $193 million
available for borrowings under our 2021 RBL Facility. The 2021 RBL Facility has a borrowing base of $200 million
with no further borrowing restrictions beyond the covenants summarized elsewhere. We also have $400 million in
aggregate principal amount of 7.0% senior unsecured notes due February 2026 (the “2026 Notes”) outstanding, as
further discussed below.
In the fourth quarter of 2021, we announced a new shareholder return model, which went into effect January 1,
2022, designed to increase cash returns to our shareholders, further demonstrating our commitment to be a leading
returner of capital to its 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 production flat. Under this new
model, the company intends to allocate discretionary free cash flow on a quarterly basis as follows: (a) 60%
predominantly in the form of cash variable 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 Levered 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 I, 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.
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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 commitments, subject to a reserve
borrowing base (“2021 RBL Facility”). Our initial borrowing base is $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.
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 December 31, 2021, our leverage
ratio and current ratio were 2.0 to 1.0 and 2.2 to 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 December 31, 2021.
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 if
availability is equal to or greater than 20% of the borrowing base, whichever is in effect, and our pro forma leverage
ratio is less than or equal to 2.0 to 1.0.
We can repurchase equity or make other distributions to our equity holders in an amount equal to (i) 100% of
Free Cash Flow (as defined under the 2021 RBL Facility) for the fiscal quarter most recently ended prior to such
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repurchase or distribution minus (ii) the amount of certain investments made, so long as, in addition to other
conditions and limitations as described in the 2021 RBL Facility, availability is equal to or greater than 20% of the
elected commitments or borrowing base, whichever is in effect, 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
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 December 31, 2021, we had no borrowings outstanding, $7 million in letters of credit outstanding, and
approximately $193 million of available borrowings capacity under the 2021 RBL Facility.
2017 RBL Facility
On July 31, 2017, we entered into a credit agreement that provided for a revolving loan with up to $1.5 billion
of commitment, subject to a reserve borrowing base (“2017 RBL Facility”). In April 2021, we completed our
scheduled semi-annual borrowing base redetermination under our 2017 RBL Facility, which resulted in a reaffirmed
borrowing base at $200 million. On August 26, 2021, we cancelled the 2017 RBL Facility agreement. There were no
borrowings outstanding at the time of cancellation.
Senior Unsecured Notes Offering
In February 2018, we completed a private issuance of $400 million in aggregate principal amount of 7.0%
senior unsecured notes due February 2026 (the “2026 Notes”), which resulted in net proceeds to us of approximately
$391 million after deducting expenses and the initial purchasers’ discount.
We may, at our option, redeem all or a portion of the 2026 Notes at any time on or after February 15, 2021. If
we experience certain kinds of changes of control, holders of the 2026 Notes may have the right to require us to
repurchase their notes at 101% of the principal amount of the 2026 Notes, plus accrued and unpaid interest, if any.
The 2026 Notes are our senior unsecured obligations and rank equally in right of payment with all of our other
senior indebtedness and senior to any of our subordinated indebtedness. The notes are fully and unconditionally
guaranteed on a senior unsecured basis by us and will also be guaranteed by certain of our future subsidiaries;
whereas Berry LLC, C&J Management and CJWS are not guarantors. The 2026 Notes and related guarantees are
effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under the
RBL Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in
right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future
subsidiaries that do not guarantee the 2026 Notes.
The indenture governing the 2026 Notes contains restrictive covenants and customary events of default,
including, among others, (a) non-payment; (b) non-compliance with covenants (in some cases, subject to grace
periods); (c) payment default under, or acceleration events affecting, material indebtedness and (d) bankruptcy or
insolvency events involving us or certain of our subsidiaries.
The 2026 Notes do not restrict us from making open market and other purchases of such notes.
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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 does 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.
Hedges
We have protected a significant portion of our anticipated cash flows through our commodity hedging program,
including swaps, puts and calls. We hedge crude oil and gas production to protect against oil and gas price decreases
and we also hedge gas purchases to protect against price increases.
In addition, we also hedge to meet the hedging requirements of the 2021 RBL Facility. The 2021 RBL Facility
requires us to maintain commodity hedges (other than three-way collars) on minimum notional volumes of (i) at
least 75% of our reasonably projected production of crude oil from our PDP reserves, for 24 full calendar months
after the effective date of the 2021 RBL Facility and after each May 1 and November 1 of each calendar year (each,
a “Minimum Hedging Requirement Date”) and (ii) at least 50% of our reasonably projected production of crude oil
from our PDP reserves, for each full calendar month during the period from and including the 25th full calendar
month following each such Minimum Hedging Requirement Date through and including the 36th full calendar
month following each such Minimum Hedging Requirement Date; provided, that in the case of each of the above
clauses (i) and (ii), the notional volumes hedged are deemed reduced by the notional volumes of any short puts or
other similar derivatives having the effect of exposing us to commodity price risk below the “floor”.
In addition to minimum hedging requirements and other restrictions in respect of hedging described therein, the
2021 RBL Facility contains restrictions on our commodity hedging which prevent us from entering into hedging
agreements (i) with a tenor exceeding 48 months or (ii) for notional volumes which (when aggregated with other
hedges then in effect other than basis differential swaps on volumes already hedged) exceed, as of the date such
hedging agreement is executed, 90% of our reasonably projected production of crude oil from our PDP reserves, for
each month following the date such hedging agreement is entered into, provided that the volume limitations above
do not apply to short puts or put options contracts that are not related to corresponding calls, collars, or swaps.
We have also entered into Utah gas transportation contracts to help reduce the price fluctuation exposure,
however these do not qualify as hedges. 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”.
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As of February 11, 2022, we had the following crude oil production and gas purchases hedges.
Q1 2022
Q2 2022
Q3 2022
Q4 2022
FY 2023
FY 2024
Brent
Swaps
Hedged volume (bbls)
Weighted-average price ($/bbl)
Put Spreads
Long $50/$40 Put Spread hedged
volume (bbls)
Short $50/$40 Put Spread hedged
volume (bbls)
Collars
Purchased Puts hedged volume
(bbls)
976,500
$
69.79 $
1,117,500
1,104,000
1,104,000
3,055,750
71.87 $
71.84 $
71.84 $
71.55 $
732,000
61.78
405,000
409,500
414,000
414,000
2,555,000
1,647,000
45,000
45,500
46,000
46,000
365,000
366,000
270,000
—
—
—
1,095,000
Weighted-average price ($/bbl)
$
40.00 $
— $
— $
— $
40.00 $
Sold Calls hedged volume (bbls)
270,000
—
—
—
1,095,000
Weighted-average price ($/bbl)
$
80.00 $
— $
— $
— $ 106.33 $
Henry Hub
Purchased Puts
Hedged volume (mmbtu)
Weighted-average price ($/mmbtu) $
1,800,000
2.75 $
—
— $
—
— $
—
— $
—
— $
Purchased Calls
Hedged volume (mmbtu)
Weighted-average price ($/mmbtu) $
2,700,000
2,730,000
2,760,000
2,760,000
4.00 $
4.00 $
4.00 $
4.00 $
—
—
—
—
—
—
Sold Puts
Hedged volume (mmbtu)
Weighted-average price ($/mmbtu) $
2,700,000
2,730,000
2,760,000
2,760,000
2.75 $
2.75 $
2.75 $
2.75 $
10,950,000 9,150,000
4.00
4.00 $
10,950,00
0
2.75 $
9,150,000
2.75
The following table summarizes the historical results of our hedging activities.
Crude Oil (per bbl):
Realized sales price, before the effects of derivative settlements
Effects of derivative settlements
Realized sales price, after the effects of derivative settlements
Purchased Natural Gas (per mmbtu):
Purchase price, before the effects of derivative settlements
Effects of derivative settlements
Purchase price, after the effects of derivative settlements
Cash Dividends
Year Ended December 31,
2021
2020
$
$
$
$
$
$
66.57 $
(16.45) $
50.12 $
5.64 $
(2.16) $
3.48 $
39.56
16.51
56.07
2.55
0.35
2.90
Our Board of Directors approved regular cash dividends on our common stock of $0.04 per share for each of the
first and second quarters of 2021 and $0.06 per share for each of the third and fourth quarters of 2021. For the year
ended December 31, 2021 we paid approximately $11 million in cash dividends on our common stock. For the year
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ended December 31, 2020 we paid approximately $19 million in cash dividends on our common stock, which
included payment of the dividend declared for the fourth quarter of 2019 and a $0.12 per share cash dividend for the
first quarter of 2020. For the year ended December 31, 2019 we declared a cash dividend of $0.12 per share each
quarter for a total of $0.48 per share and paid approximately $39 million in cash dividends on our common stock.
Stock Repurchase Program
In December 2018, our Board of Directors adopted a program for the opportunistic repurchase of up to
$100 million of our common stock. Based on the Board’s evaluation of market conditions for our common stock at
the time, they authorized repurchases of up to $50 million under the program. In 2018 and 2019, the Company
repurchased a total of 5,057,682 shares under the stock repurchase program for approximately $50 million in
aggregate. In February 2020, the Board of Directors authorized the repurchase of the remaining $50 million
available under the repurchase program. We did not repurchase any common stock in 2020. For the year ended
December 31, 2021, we repurchased 471,022 shares at an average price of $5.18 per share for approximately
$2 million in the third quarter. All shares repurchased are reflected as treasury stock. Accordingly, as of December
31, 2021, the Company has repurchased a total of 5,528,704 shares under the stock repurchase program for
approximately $52 million in aggregate, leaving approximately $48 million authorized and available for future
repurchases under the program. 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 Berry Corp. to purchase shares during any period or at all. Any shares acquired will be available
for general corporate purposes.
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Capital Program
Refer to Part II, Item 1 and 2. — “Our Capital Program” for details.
Acquisitions and Divestitures
C&J Well Services Acquisition (2021)
On October 1, 2021, we acquired one of the largest upstream well servicing and abandonment business in
California, which operates as C&J Well Services, LLC. The purchase price was $53 million, including closing
adjustments mainly related to working capital, which we funded with cash on hand of $51 million in 2021 and $2
million in 2022. The C&J Well Services transaction costs were approximately $3 million. The acquired business
activities are owned and operated by C&J Well Services, a wholly-owned subsidiary of Berry Corp. formed for the
purposes of acquiring these businesses and establishing an independent well services and abandonment company.
The C&J Well Services Acquisition creates a strategic growth opportunity and further aligns Berry with the State of
California's energy transition goals, including to help reduce fugitive emissions, especially methane and carbon
dioxide, from orphan and idle wells.
Placerita Divestiture (2021)
In October 2021, we completed the sale of our Placerita Field property in the Ventura Basin in Los Angeles
County, California for approximately $14 million. We have recorded a gain on the sale of approximately $2 million.
Piceance Divestiture (2022)
In January 2022, we completed the divestiture of all of our natural gas properties in Colorado, which were in the
Piceance basin. The divestiture closed with no material impact to the financial statements.
Antelope Creek Acquisition (2022)
In February 2022, we completed the acquisition of oil and gas producing assets in the Antelope Creek area of
Utah for approximately $18 million. These assets are adjacent to our existing Uinta assets and prior to our
acquisition produced approximately 700 boe/d.
Statements of Cash Flows
The following is a comparative cash flow summary:
Net cash:
Provided by operating activities
Used in investing activities
Used in financing activities
Net (decrease) increase in cash and cash equivalents
Operating Activities
Year Ended December 31,
2021
2020
(in thousands)
$
$
122,488 $
(168,787)
(18,975)
(65,274) $
196,529
(93,620)
(22,352)
80,557
Cash provided by operating activities decreased for the year ended December 31, 2021 by approximately $74
million when compared to the year ended December 31, 2020, and the most significant decreases consisted of a
$234 million change in derivatives settlements paid and received, an increase of $56 million in unhedged operating
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expenses, which was mostly fuel gas costs on an unhedged basis, an increase of $28 million in cost of services
related to CJWS, and a decrease of $51 million in working capital changes and other items. These cash decreases
were mostly offset by increased sales, including CJWS sales, of $295 million.
Investing Activities
The following provides a comparative summary of cash flow from investing activities:
Capital expenditures (1)
Capital expenditures
Changes in capital expenditures accruals
Acquisitions, net of cash received
Acquisition of properties and equipment and other
Proceeds received from divestitures
Proceeds from sale of property and equipment and other
Year Ended December 31,
2021
2020
(in thousands)
(132,719)
482
(50,568)
(876)
14,025
869
(76,480)
(11,336)
—
(5,981)
—
177
Net cash used in investing activities
$
(168,787) $
(93,620)
__________
(1) Based on actual cash payments rather than accrual.
Cash used in investing activities increased $75 million for the year ended December 31, 2021 when compared
to the year ended December 31, 2020, primarily due to a $44 million increase in cash used for capital spending as
we reinstated our development program in 2021. In 2021, we also had approximately $45 million more in
expenditures for acquisitions than we did in 2020. These increases were partially offset by approximately $14
million of proceeds from divestitures in 2021.
Financing Activities
Cash used by financing activities decreased $3 million for the year ended December 31, 2021 when compared
to the year ended December 31, 2020. In 2021, the cash used was primarily for dividends paid of $11 million, debt
issuance costs related to the 2017 RBL Facility of $3 million, and the purchase of treasury stock of $2 million. In
2020, the cash used was primarily for dividends paid of $19 million.
Commitments, and Contingencies
In the normal course of business, we, or our subsidiary, are the subject of, or party to, pending or threatened
legal proceedings, contingencies and commitments involving a variety of matters that seek, or may seek, among
other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive
damages, fines and penalties, remediation costs, or injunctive or declaratory relief.
We accrue for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has
been incurred and the liability can be reasonably estimated. We have not recorded any reserve balances at December
31, 2021 and December 31, 2020. We also evaluate the amount of reasonably possible losses that we could incur as
a result of these matters. We believe that reasonably possible losses that we could incur in excess of accruals on our
balance sheet would not be material to our consolidated financial position or results of operations.
We, or our subsidiaries, or both, have indemnified various parties against specific liabilities those parties might
incur in the future in connection with transactions that they have entered into with us. As of December 31, 2021, we
are not aware of material indemnity claims pending or threatened against us.
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We have certain commitments under contracts, including purchase commitments for goods and services. Prior
to our 2017 emergence, Berry entered into a Carry and Earning Agreement with Encana, effective June 7, 2006, in
connection with our Piceance assets which, among other things, required us to either build a road or secure a license
for alternative access, in lieu of paying a $6 million penalty. As of December 31, 2019, we fulfilled the obligation by
delivering the access license pursuant to the agreement. On January 30, 2020, Caerus Piceance LLC, the successor
of Encana's interests filed a claim in the City and County of Denver District Court challenging the sufficiency of
such access, which we dispute. We settled the lawsuit and the case was dismissed with prejudice on February 1,
2022 , which also satisfied the road obligation.
Securities Litigation Matter
On November, 20, 2020, Luis Torres, individually and on behalf of a putative class, filed a securities class
action lawsuit (the “Torres Lawsuit”) in the United States District Court for the Northern District of Texas against
Berry Corp. and certain of its current and former directors and officers (collectively, the “Defendants”). The
complaint asserts violations of Sections 11 and 15 of the Securities Act of 1933, and Sections 10(b) and 20(a) of the
Exchange Act, on behalf of a putative class of all persons who purchased or otherwise acquired (i) common stock
pursuant and/or traceable to the Company’s 2018 IPO; or (ii) Berry Corp.'s securities between July 26, 2018 and
November 3, 2020 (the “Class Period”). In particular, the complaint alleges that the Defendants made false and
misleading statements during the Class Period and in the offering materials for the IPO, concerning the Company’s
business, operational efficiency and stability, and compliance policies, that artificially inflated the Company’s stock
price, resulting in injury to the purported class members when the value of Berry Corp.’s common stock declined
following release of its financial results for the third quarter of 2020 on November 3, 2020.
On January 21, 2021, multiple plaintiffs filed motions in the Torres Lawsuit seeking to be appointed lead
plaintiff and lead counsel. After briefing and a stipulation between the remaining movants, the Court appointed Luis
Torres and Allia DeAngelis as co-lead plaintiffs on August 18, 2021. On November 1, 2021, the co-lead plaintiffs
filed an amended complaint asserting claims on behalf of the same putative class under Sections 11 and 15 of the
Securities Act of 1933 and Sections 10(b) and 20(a) of the Exchange Act, alleging, among other things, that the
Company and the individual Defendants made false and misleading statements between July 26, 2018 and
November 3, 2020 regarding the Company’s permits and permitting processes. The amended complaint does not
quantify the alleged losses but seeks to recover all damages sustained by the putative class as a result of these
alleged securities violations, as well as attorneys’ fees and costs. The Defendants filed a Motion to Dismiss on
January 24, 2022; plaintiffs’ opposition is due on March 21, 2022 and Defendants' reply is due on May 16, 2022.
We dispute these claims and intend to defend the matter vigorously. Given the uncertainty of litigation, the
preliminary stage of the case, and the legal standards that must be met for, among other things, class certification
and success on the merits, we cannot reasonably estimate the possible loss or range of loss that may result from this
action.
Contractual Obligations
The following is a summary of our commitments and contractual obligations as of December 31, 2021:
Total
Less Than 1
Year
Payments Due
1-3
Years
(in thousands)
3-5
Years
Thereafter
Off-Balance Sheet arrangements:
Processing and transportation contracts(1)
Operating lease obligations
Other purchase obligations(2)
$
97,082 $
9,835 $
19,478 $
16,165 $
51,604
10,091
23,100
2,279
20,700
3,771
2,400
3,105
—
936
—
Total
$ 130,273 $
32,814 $
25,649 $
19,270 $
52,540
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__________
(1) Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of
business to secure pipeline transportation of natural gas to market and between markets, as well as gathering and processing of natural gas.
(2) Amounts included a purchase commitment of $6 million to build a road, which was classified as current. In January 2022 the purchase
commitment of $6 million was fully resolved without any payment. Additionally, we have a drilling commitment in California, for which
we are required to drill 57 wells with an estimated cost and minimum commitment of $17.1 million by April 2023. 49 of those wells are
estimated at $14.7 million and are required to be drilled by December 2022.
Balance Sheet Analysis
The changes in our balance sheet from December 31, 2020 to December 31, 2021 are discussed below.
Cash and cash equivalents
Accounts receivable, net
Derivative instruments assets - current and long-term
Other current assets
Property, plant & equipment, net
Other non-current assets
Accounts payable and accrued expenses
Derivative instruments liabilities - current and long-term
Long-term debt
Deferred income taxes liability - long-term
Asset retirement obligation - long-term
Other non-current liabilities
Stockholders' equity
December 31, 2021
December 31, 2020
$
$
$
$
$
$
$
$
$
$
$
$
$
(in thousands)
15,283 $
86,269 $
1,070 $
45,946 $
80,557
52,027
2,507
19,400
1,301,349 $
1,258,084
6,562 $
157,524 $
48,202 $
394,566 $
1,831 $
143,926 $
17,782 $
692,648 $
7,235
151,985
23,321
393,480
1,011
135,192
785
714,036
See “—Liquidity and Capital Resources” for discussions about the changes in cash and cash equivalents.
The $34 million increase in accounts receivable was driven mostly by $25 million in higher sales prices period-
over-period and $18 million of accounts receivable related to CJWS which was acquired in the fourth quarter of
2021, partially offset by $9 million in lower hedge settlements outstanding at each period end.
The $26 million increase in net derivative assets and liabilities was due to the change from a net liability of
$21 million in 2020 to a net liability of $47 million in 2021. Changes to mark-to-market derivative values at the end
of each period result from differences in the forward curve prices relative to the contract fixed prices, changes in
positions held and settlements received and paid throughout the periods.
The $26 million increase in other current assets was primarily due to $10 million of current assets from newly-
acquired CJWS, $7 million of prepayments for development permits, $3 million of collateral for commitments, $6
million of prepaid deposits, $2 million of various other prepaid items, partially offset by a decrease in materials
inventory of $2 million.
The $43 million increase in property, plant and equipment was largely the result of the $133 million in capital
investments along with $35 million in asset retirement obligation and other additions, and $45 million of CJWS
property, plant and equipment, offset by depreciation expense of $134 million as well as divestitures of $35 million.
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The $1 million decrease in other non-current assets was primarily due to $3 million of unamortized debt
issuance costs related to the cancellation of the 2017 RBL Facility, $3 million of amortization expense related to the
2021 RBL Facility and 2017 RBL Facility, offset by $4 million of cost incurred related to the issuance of the 2021
RBL Facility.
The $6 million increase in accounts payable and accrued expenses included $26 million of increased accruals
and spending for various capital and operating costs due to the increased level of these activities at the end of each
year, a $10 million increase in royalties accrued due to increased sales, and a $5 million increase in dividends
payable, partially offset by a decrease of approximately $28 million in the current portion of the greenhouse gas
liability due to a significant, scheduled payment in 2021, a decrease of $5 million in the current portion of asset
retirement obligation and a decrease of $2 million taxes other than income tax liability.
The increase in long-term deferred income taxes liability was due to the income tax expense during the year.
The $9 million increase in the long-term portion of the asset retirement obligation from $135 million at
December 31, 2020 to $144 million at December 31, 2021 was due to revised cost estimates of $32 million,
$11 million of accretion, $5 million reclassified from short to long-term, and $1 million of liabilities incurred. These
increases were partially offset by $22 million of reduction due to property sales and $18 million of liabilities settled
during the period.
The $17 million increase in other non-current liabilities was driven by additional non-current greenhouse gas
liabilities compared to prior year. At year-end 2020, the non-current portion of greenhouse gas liabilities was
reclassified to current as the payments were due and paid in 2021.
The $21 million decrease in stockholders' equity was due to the net loss of $16 million, $16 million of common
stock dividends declared, $2 million of treasury stock, and $2 million of shares withheld for payment of taxes on
equity awards. These decreases were partially offset by $14 million of stock-based equity awards, net of taxes.
Non-GAAP Financial Measures
Adjusted EBITDA, Levered Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and
Administrative Expenses
Adjusted Net Income (Loss) is not a measure of net income (loss), Levered 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 Levered 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. We define Levered Free Cash Flow as
Adjusted EBITDA less capital expenditures, interest expense and fixed dividends.
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. Levered Free Cash Flow is used by
management as a primary metric to plan capital allocation to sustain production levels and for internal growth
opportunities, as well as hedging needs. It also serves as a measure for assessing our financial performance and our
ability to generate excess cash from operations to service debt, pay fixed dividends and accelerate our asset
retirement activity.
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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,
unusual and infrequent items, and the income tax expense or benefit of these adjustments using our effective tax
rate.
While Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow are non-GAAP measures,
the amounts included in the calculation of Adjusted EBITDA, Adjusted Net Income (Loss) and Levered 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. 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) and Levered Free Cash Flow may not be comparable to other
similarly titled measures used by other companies. Adjusted EBITDA, Adjusted Net Income (Loss) and Levered
Free Cash Flow should be read in conjunction with the information contained in our financial statements prepared in
accordance with GAAP.
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. Adjusted General and Administrative Expenses
should not be considered as an alternative to, or more meaningful than, general and administrative expenses as
determined in accordance with GAAP. Our computations of Adjusted General and Administrative Expenses may not
be comparable to other similarly titled measures of other companies.
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The following tables present reconciliations of the non-GAAP financial measures Adjusted EBITDA and
Levered Free Cash Flow 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.
Adjusted EBITDA reconciliation to net income (loss):
Net loss
Add (Subtract):
Interest expense
Income tax expense (benefit)
Depreciation, depletion, and amortization
Impairment of oil and gas properties
Losses (gains) on derivatives
Net cash (paid) received for scheduled derivative settlements
Other operating expenses
Stock compensation expense
Non-recurring costs
Adjusted EBITDA
Year Ended December 31,
2021
2020
(in thousands)
$
(15,542) $
(262,895)
31,964
1,413
144,495
—
117,822
(87,625)
3,101
13,783
2,735
$
212,146 $
34,295
(7,218)
139,180
289,085
(116,746)
142,292
5,781
14,630
6,026
244,430
Year Ended December 31,
2021
2020
(in thousands)
Adjusted EBITDA reconciliation to net cash provided by operating activities and Levered Free Cash Flow calculation:
Net cash provided by operating activities
$
122,488 $
196,529
Add (Subtract):
Cash interest payments
Cash income tax payments
Non-recurring costs
Other changes in operating assets and liabilities
Adjusted EBITDA
Subtract:
Capital expenditures - accrual basis(1)
Interest expense
Fixed cash dividends declared
Levered Free Cash Flow(2)
__________
29,211
699
2,735
57,013
$
212,146 $
(132,719)
(31,964)
(16,297)
$
31,166 $
29,962
222
6,026
11,691
244,430
(76,480)
(34,295)
(9,564)
124,091
(1) Capital expenditures on an accrual basis includes capitalized overhead and interest and excludes acquisitions. Also excluded is asset
retirement spending of $19 million and $18 million for the years ended December 31, 2021 and 2020, respectively.
(2) Levered Free Cash Flow includes cash paid for scheduled derivative settlements of $88 million and cash received for scheduled derivative
settlements of $142 million for the years ended December 31, 2021 and 2020, respectively.
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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).
Adjusted Net Income (Loss) reconciliation to net (loss) income:
Net loss
Add (Subtract): discrete income tax items
$
(15,542) $
581
(262,895)
61,030
Year Ended December 31,
2021
2020
(in thousands)
Add (Subtract):
Losses (gains) on derivatives
Net cash (paid) received for scheduled derivative settlements
Other operating expenses
Impairment of oil and gas properties
Non-recurring costs
Total additions (subtractions), net
Income tax expense of adjustments at effective tax rate(1)
Adjusted Net Income (Loss)
Basic EPS on Adjusted Net Income
Diluted EPS on Adjusted Net Income
Weighted average shares outstanding - basic
Weighted average shares outstanding - diluted
__________
117,822
(87,625)
3,101
—
2,735
36,033
—
21,072 $
0.26 $
0.25 $
80,209
83,496
(116,746)
142,292
5,781
289,085
6,026
326,438
(79,757)
44,816
0.56
0.56
79,802
79,902
$
$
$
(1) Excludes discrete income tax items from the total additions (subtractions), net line item and the tax effect the discrete income tax items have
on the current rate.
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.
Year Ended December 31,
2021
2020
(in thousands)
$/boe
$/boe
73,106
(13,356)
(2,735)
57,015
$
$
77,696
(14,264)
(6,026)
57,406
53,822 $ 5.38 $
57,406 $ 5.50
3,193
$
—
Adjusted General and Administrative Expense
reconciliation to general and administrative expenses:
General and administrative expenses
Subtract:
Non-cash stock compensation expense (G&A portion)
Non-recurring costs
Adjusted general and administrative expenses
Development and production segment, and corporate
Well servicing and abandonment segment
$
$
$
$
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Critical Accounting Policies and Estimates
The process of preparing financial statements in accordance with generally accepted accounting principles
requires management to select appropriate accounting policies and to make informed estimates and judgments
regarding certain items and transactions. Changes in facts and circumstances or discovery of new information may
result in revised estimates and judgments, and actual results may differ from these estimates upon settlement. We
consider the following to be our most critical accounting policies and estimates that involve management’s judgment
and that could result in a material impact on the financial statements due to the levels of subjectivity and judgment.
Oil and Natural Gas Properties
Proved Properties
We account for oil and natural gas properties in accordance with the successful efforts method. Under this
method, all acquisition costs of proved properties are capitalized and amortized on a unit-of-production basis over
the remaining life of the proved reserves. All development costs of proved properties are capitalized and amortized
on a unit-of-production basis over the remaining life of the proved developed reserves. Costs of retired, sold or
abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to
accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production
amortization rate, in which case a gain or loss is recognized in the current period. Gains or losses from the disposal
of other properties are recognized in the current period. For assets acquired, we base the capitalized cost on fair
value at the acquisition date. We expense expenditures for maintenance and repairs necessary to maintain properties
in operating condition, as well as annual lease rentals, as they are incurred. Estimated dismantlement and
abandonment costs are capitalized at their estimated net present value and amortized over the remaining lives of the
related assets. Interest is capitalized only during the periods in which these assets are brought to their intended use.
We only capitalize the interest on borrowed funds related to our share of costs associated with qualifying capital
expenditures.
We evaluate the impairment of our proved oil and natural gas properties generally on a field by field basis or at
the lowest level for which cash flows are identifiable, whenever events or changes in circumstance indicate that the
carrying value may not be recoverable. We reduce the carrying values of proved properties to fair value when the
expected undiscounted future cash flows are less than net book value. We measure the fair values of proved
properties using valuation techniques consistent with the income approach, converting future cash flows to a single
discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i)
reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a risk-adjusted discount
rate. These inputs require significant judgments and estimates by our management at the time of the valuation. The
most significant financial statement effect from a change in our oil and gas reserves or impairment of its proved
properties would be to the DD&A rate. For example, a 5% increase or decrease in the amount of oil and gas reserves
would change the DD&A rate by approximately $0.64 per mmboe, which would increase or decrease pre-tax income
by approximately $6 million annually at current production rates. In addition, the underlying commodity prices are
embedded in our estimated cash flows and are the product of a process that begins with the relevant forward curve
pricing, adjusted for estimated location and quality differentials, as well as other factors our management believes
will impact realizable prices. The fair value was estimated using inputs characteristic of a Level 3 fair value
measurement.
Unproved Properties
A portion of the carrying value of our oil and gas properties was attributable to unproved properties. At
December 31, 2021 and 2020, the net capitalized costs attributable to unproved properties was approximately $292
million and $311 million, respectively. The unproved amounts were not subject to depreciation, depletion and
amortization until they were classified as proved properties and amortized on a unit-of-production basis. We
evaluate the impairment of our unproved oil and gas properties whenever events or changes in circumstances
indicate the carrying value may not be recoverable. If the exploration and development work were to be
unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity
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prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of such
properties would be expensed. The timing of any write-downs of unproved properties, if warranted, depends upon
management’s plans, the nature, timing and extent of future exploration and development activities and their results.
We believe our current plans and exploration and development efforts will allow us to realize the carrying value of
our unproved property balance at December 31, 2021.
Acquisition Purchase Price Allocations
We account for acquisitions of businesses using the acquisition method of accounting, which requires the
allocation of the purchase price consideration based on the fair values of the assets and liabilities acquired. We
estimate the fair values of the assets and liabilities acquired using accepted valuation methods, and, in many cases,
such estimates are based on our judgments as to the future operating cash flows expected to be generated from the
acquired assets throughout their estimated useful lives. Following the October 1, 2021 acquisition of CJWS, we
accounted for the various assets and liabilities acquired and issued as consideration based on our estimates of their
fair values. Our estimates and judgments of the fair value of acquired businesses could prove to be inexact, and the
use of inaccurate fair value estimates could result in the improper allocation of the acquisition purchase price
consideration to acquired assets and liabilities, which could result in asset impairments, the recording of previously
unrecorded liabilities, and other financial statement adjustments. The difficulty in estimating the fair values of
acquired assets and liabilities is increased during periods of economic uncertainty.
Asset Retirement Obligation
We recognize the fair value of asset retirement obligations (“AROs”) in the period in which a determination is
made that a legal obligation exists to dismantle an asset and remediate the property at the end of its useful life and
the cost of the obligation can be reasonably estimated.
The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as
time to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate. When the
liability is initially recorded, we capitalize the cost by increasing the related property, plant and equipment
(“PP&E”) balances. If the estimated future cost of the AROs changes, we record an adjustment to both the ARO and
PP&E. Over time, the liability is increased, and expense is recognized through accretion, and the capitalized cost is
depreciated over the useful life of the asset.
Fair Value Measurements
We have categorized our assets and liabilities that are measured at fair value in a three-level fair value
hierarchy, based on the inputs to the valuation techniques: Level 1—using quoted prices in active markets for the
assets or liabilities; Level 2—using observable inputs other than quoted prices for the assets or liabilities; and Level
3—using unobservable inputs. Transfers between levels, if any, are recognized at the end of each reporting period.
We primarily apply the market approach for recurring fair value measurement, maximize our use of observable
inputs and minimize use of unobservable inputs. We generally use an income approach to measure fair value when
observable inputs are unavailable. This approach utilizes management’s judgments regarding expectations of
projected cash flows and discounts those cash flows using a risk-adjusted discount rate.
We determine the fair value of our oil and gas sales and natural gas purchase derivatives using valuation
techniques which utilize market quotes and pricing analysis. Inputs include publicly available prices and forward
price curves generated from a compilation of data gathered from third parties. We classify these measurements as
Level 2.
Income Taxes
We account for income taxes using the asset and liability approach for financial accounting and reporting. The
amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing
authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax
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carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a
valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit
in the future does not meet the more likely than not criteria for recognition.
We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only
after determining that the relevant tax authority would more likely than not sustain the position following an audit.
For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the
benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax
authority. See Note 8 in the Notes to Consolidated Financial Statements in Part II—Item 8. Financial Statements and
Supplementary Data of this report for a discussion of new accounting matters
Stock-based Compensation
We have issued restricted stock units (“RSUs”) that vest over time and performance-based restricted stock units
(“PSUs”) that include (i) awards with a market objective measured against both absolute total stockholder return
(“Absolute TSR”) and a relative total stockholder return (“Relative TSR”) (the “TSR PSUs”) over the performance
period and (ii) awards based on the Company's average cash returned on invested capital (“CROIC PSUs”) over the
performance period. The fair value of the stock-based awards is determined at the date of grant and is not
remeasured. The fair value of the RSUs and CROIC PSUs was determined using the grant date stock price. The fair
value of the TSR PSUs was determined using a Monte Carlo simulation analysis to estimate the total shareholder
return ranking of the Company, including a comparison against the peer group over the performance periods.
Estimates used in the Monte Carlo valuation model are considered highly complex and subjective. Compensation
expense, net of actual forfeitures, for the RSUs and PSUs is recognized on a straight-line basis over the requisite
service periods, which is over the awards’ respective vesting or performance periods which range from one to three
years.
Significant Accounting and Disclosure Changes
See Note 1 in the Notes to Consolidated Financial Statements in Part II—Item 8. Financial Statements and
Supplementary Data of this report for a discussion of new accounting matters.
Inflation
Although inflation in the United States has been relatively low in recent years, it rose significantly in the second
half of 2021. This is believed to be the result of the economic impact from the COVID-19 pandemic, including the
global supply chain disruptions and the government stimulus packages, among other factors. Global, industry-wide
supply chain disruptions caused by the COVID-19 pandemic have resulted in shortages in labor, materials and
services. Such shortages have resulted in inflationary cost increases for labor, materials and services and could
continue to cause costs to increase as well as scarcity of certain products and raw materials. We are experiencing
some inflationary pressure for certain costs, including employees and vendors, although such cost increases did not
materially impact our 2021 financial condition or results of operations, and we currently do not expect them to
materially impact our 2022 financial results or operations. However, to the extent elevated inflation remains, we
may experience further cost increases for our operations, including natural gas purchases and oilfield services and
equipment as increasing oil, natural gas and NGL prices increase drilling activity in our areas of operations, as well
as increased labor costs. An increase in oil, natural gas and NGL prices may cause the costs of materials and services
to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent
we are unable to recover higher costs through higher commodity prices and revenues, would negatively impact our
business, financial condition and results of operation.
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
The information included or incorporated by reference in this report includes forward-looking statements that
involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows
and business prospects. Such statements specifically include our expectations as to our future financial position,
liquidity, cash flows, results of operations and business strategy, potential acquisition opportunities, other plans and
objectives for operations, capital for sustained production levels, expected production and operating costs, reserves,
hedging activities, capital expenditures, return of capital, improvement of recovery factors and other guidance.
Actual results may differ from anticipated results, sometimes materially, and reported results should not be
considered an indication of future performance. You can typically identify forward-looking statements by words
such as aim, anticipate, achievable, believe, budget, continue, could, effort, estimate, expect, forecast, goal,
guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or
would and other similar words that reflect the prospective nature of events or outcomes. For any such forward-
looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement,
we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed
facts or bases almost always vary from actual results, sometimes materially. Material risks that may affect us are
discussed above in “Item 1A. Risk Factors” in this prospectus, in any applicable prospectus supplement and in the
documents incorporated by reference.
Factors (but not necessarily all the factors) that could cause results to differ include among others:
•
•
•
•
•
•
•
•
•
•
•
the regulatory environment, including availability or timing of, and conditions imposed on, obtaining and/
or maintaining permits and approvals, including those necessary for drilling and/or development projects;
the impact of current, pending and/or future laws and regulations, and of legislative and regulatory changes
and other government activities, including those related to permitting, drilling, completion, well
stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land,
greenhouse gases or other emissions, protection of health, safety and the environment, or transportation,
marketing and sale of our products;
inflation levels, particularly the recent rise to historically high levels;
the length, scope and severity of the ongoing COVID-19 pandemic or the emergence of a new pandemic,
including the effects of related public health concerns and the impact of actions taken by governmental
authorities and other third parties in response to the pandemic and its impact on commodity prices, supply
and demand considerations, global supply chain disruptions and labor constraints;
global economic trends, geopolitical risks and general economic and industry conditions, such as the
economic impact from the COVID-19 pandemic, including the global supply chain disruptions and the
government interventions into the financial markets and economy, among other factors;
those resulting from the COVID-19 pandemic and from the actions of foreign producers, importantly
including OPEC+ and change in OPEC+'s production levels;
volatility of oil, natural gas and NGL prices;
the California and global energy future, including the factors and trends that are expected to shape it, such
as concerns about climate change and other air quality issues, the transition to a low-emission economy and
the expected role of different energy sources;
supply of and demand for oil, natural gas and NGLs, including due to the actions of foreign producers,
importantly including OPEC+ and change in OPEC+'s production levels;;
disruptions to, capacity constraints in, or other limitations on the pipeline systems that deliver our oil and
natural gas and other processing and transportation considerations;
inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital
expenditures, meet our working capital requirements or fund planned investments;
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•
•
•
•
•
•
•
•
•
•
•
•
price fluctuations and availability of natural gas and electricity and the cost of steam;
our ability to use derivative instruments to manage commodity price risk;
our ability to meet our planned drilling schedule, including due to our ability to obtain permits on a timely
basis or at all, and to successfully drill wells that produce oil and natural gas in commercially viable
quantities;
concerns about climate change and other air quality issues;
uncertainties associated with estimating proved reserves and related future cash flows;
our ability to replace our reserves through exploration and development activities;
drilling and production results, lower–than–expected production, reserves or resources from development
projects or higher–than–expected decline rates;
our ability to obtain timely and available drilling and completion equipment and crew availability and
access to necessary resources for drilling, completing and operating wells;
changes in tax laws;
effects of competition;
uncertainties and liabilities associated with acquired and divested assets;
our ability to make acquisitions and successfully integrate any acquired businesses;
• market fluctuations in electricity prices and the cost of steam;
•
•
•
•
•
•
•
•
•
•
•
•
asset impairments from commodity price declines;
large or multiple customer defaults on contractual obligations, including defaults resulting from actual or
potential insolvencies;
geographical concentration of our operations;
the creditworthiness and performance of our counterparties with respect to our hedges;
impact of derivatives legislation affecting our ability to hedge;
failure of risk management and ineffectiveness of internal controls;
catastrophic events, including wildfires, earthquakes and pandemics;
environmental risks and liabilities under federal, state, tribal and local laws and regulations (including
remedial actions);
potential liability resulting from pending or future litigation;
our ability to recruit and/or retain key members of our senior management and key technical employees;
information technology failures or cyberattacks; and.
governmental actions and political conditions, as well as the actions by other third parties that are beyond
our control.
Except as required by law, we undertake no responsibility to publicly release the result of any revision of our
forward-looking statements after the date they are made.
All forward-looking statements, expressed or implied, included in this report are expressly qualified in their
entirety by this cautionary statement. This cautionary statement should also be considered in connection with any
subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Our primary market risks are attributable to fluctuations in commodity prices and interest rates, which can affect
our business, financial condition, operating results and cash flows. The following should be read in conjunction with
the financial statements and related notes included elsewhere in this report.
Price Risk
Our most significant market risk relates to prices for oil, natural gas, and NGLs. Management expects energy
prices to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues,
certain costs such as fuel gas, and cash flows are likewise affected. Additional non-cash impairment charges for our
oil and gas properties may be required if commodity prices experience significant decline.
We have historically hedged a large portion of our expected crude oil and our natural gas production, as well as
our natural gas purchase requirements to reduce exposure to fluctuations in commodity prices. We use derivatives
such as swaps, calls, puts and collars to hedge. We do not enter into derivative contracts for speculative trading
purposes and we have not accounted for our derivatives as cash-flow or fair-value hedges. We continuously consider
the level of our oil production and gas purchases that is appropriate to hedge based on a variety of factors, including,
among other things, current and future expected commodity prices, our expected capital and operating costs, our
overall risk profile, including leverage, size and scale, as well as any requirements for, or restrictions on, levels of
hedging contained in any credit facility or other debt instrument applicable at the time.
We determine the fair value of our oil and gas sales and natural gas purchase derivatives using valuation
techniques which utilize market quotes and pricing analysis. Inputs include publicly available prices and forward
price curves generated from a compilation of data gathered from third parties. We validate data provided by third
parties by understanding the valuation inputs used, obtaining market values from other pricing sources, analyzing
pricing data in certain situations and confirming that those instruments trade in active markets. At December 31,
2021, the fair value of our hedge positions was a net liability of approximately $47 million. A 10% increase in the
oil and natural gas index prices above the December 31, 2021 prices would result in a net liability of approximately
$76 million; conversely, a 10% decrease in the oil and natural gas index prices below the December 31, 2021 prices
would result in a net asset of approximately $2 million. For additional information about derivative activity, see
Note 4, Derivatives, in the Notes to the Consolidated Financial Statements in Part II, Item 8 of this Annual Report.
Actual gains or losses recognized related to our derivative contracts depend exclusively on the price of the
underlying commodities on the specified settlement dates provided by the derivative contracts. Additionally, we
cannot be assured that our counterparties will be able to perform under our derivative contracts. If a counterparty
fails to perform and the derivative arrangement is terminated, our cash flows could be negatively impacted.
Credit Risk
Our credit risk relates primarily to trade and other receivables and derivative financial instruments. Credit
exposure for each customer is monitored for outstanding balances and current activity. For derivative instruments
entered into as part of our hedging program, we are subject to counterparty credit risk to the extent the counterparty
is unable to meet its settlement commitments. We actively manage this credit risk by selecting customers that we
believe to be financially strong and continue to monitor their financial health. Concentration of credit risk is
regularly reviewed to ensure that customer credit risk is adequately diversified.
We had five commodity derivative counterparties at December 31, 2021 and nine at December 31, 2020. We
did not receive collateral from any of our counterparties. We minimize the credit risk of our derivative instruments
by limiting our exposure to any single counterparty. In addition, with certain limited exceptions, the 2021 RBL
Facility prevents us from entering into hedging arrangements that are secured (except with our lenders and their
affiliates), that have margin call requirements, that otherwise require us to provide collateral or with a non-lender
counterparty that does not have an A or A2 credit rating or better from Standard & Poor’s or Moody’s, respectively.
In accordance with our standard practice, our commodity derivatives are subject to counterparty netting under
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agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is
somewhat mitigated. Considering these factors together, we believe exposure to credit losses related to our business
at December 31, 2021 was not material and losses associated with credit risk have not been been material for all
periods presented.
Interest Rate Risk
Our 2021 RBL Facility has a variable interest rate on outstanding balances. As of December 31, 2021, we had
no borrowings under our RBL Facility and thus we had no interest rate risk exposure. The 2026 Notes have a fixed
interest rate and thus we are not exposed to interest rate risk on these instruments. See Note 3, Debt, in the Notes to
the Consolidated Financial Statements in Part II, Item 8 of this Annual Report for additional information regarding
interest rates on our outstanding debt.
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Item 8. Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm .....................................................................
Consolidated Balance Sheets as of December 31, 2021 and December 31, 2020 ....................................
Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019 .........
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2021, 2020 and
2019 .......................................................................................................................................................
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019 ........
Notes to Consolidated Financial Statements .............................................................................................
Supplemental Oil & Natural Gas Data (Unaudited) ..................................................................................
Page
103
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105
106
107
108
138
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors
Berry Corporation (bry):
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Berry Corporation (bry) and subsidiaries (the
Company) as of December 31, 2021 and 2020, the related consolidated statements of operations, stockholders'
equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes
(collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present
fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the
results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, in
conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is
to express an opinion on these consolidated financial statements based on our audits. We are a public accounting
firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to
be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of
material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to
perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an
understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the
effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures
included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that
our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company’s auditor since 2013.
Los Angeles, California
March 4, 2022
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BERRY CORPORATION (bry)
CONSOLIDATED BALANCE SHEETS
Current assets:
ASSETS
Cash and cash equivalents
Accounts receivable, net of allowance for doubtful accounts of $866 at
December 31, 2021 and $2,215 at December 31, 2020
Derivative instruments
Other current assets
Total current assets
Noncurrent assets:
Oil and natural gas properties
Accumulated depletion and amortization
Total oil and natural gas properties, net
Other property and equipment
Accumulated depreciation
Total other property and equipment, net
Derivative instruments
Other noncurrent assets
Total assets
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses
Derivative instruments
Total current liabilities
Noncurrent liabilities:
Long-term debt
Derivative instruments
Deferred income taxes
Asset retirement obligation
Other noncurrent liabilities
Commitments and Contingencies - Note 5
Stockholders' Equity:
December 31, 2021
December 31, 2020
(in thousands, except share amounts)
$
15,283 $
86,269
—
45,946
147,498
1,537,894
(340,328)
1,197,566
140,710
(36,927)
103,783
1,070
6,562
80,557
52,027
2,507
19,400
154,491
1,412,566
(235,259)
1,177,307
112,145
(31,368)
80,777
—
7,235
$
$
1,456,479 $
1,419,810
157,524 $
29,625
187,149
394,566
18,577
1,831
143,926
17,782
151,985
23,321
175,306
393,480
—
1,011
135,192
785
Common stock ($0.001 par value; 750,000,000 shares authorized; 85,590,417
and 85,041,581 shares issued; and 80,007,149 and 79,929,335 shares
outstanding, at December 31, 2021 and December 31, 2020, respectively)
Additional paid-in capital
Treasury stock, at cost (5,583,268 shares at December 31, 2021 and 5,112,246
shares at December 31, 2020)
Retained deficit
Total stockholders' equity
86
85
912,471
(52,436)
(167,473)
692,648
915,877
(49,995)
(151,931)
714,036
Total liabilities and stockholders' equity
$
1,456,479 $
1,419,810
The accompanying notes are an integral part of these financial statements.
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BERRY CORPORATION (bry)
CONSOLIDATED STATEMENTS OF OPERATIONS
Revenues and other:
Oil, natural gas and natural gas liquid sales
$
625,475 $
378,663 $
565,596
Year Ended December 31,
2021
2020
2019
(in thousands, except per share amounts)
Services revenue
Electricity sales
(Losses) gains on oil and gas sales derivatives
Marketing revenues
Other revenues
Total revenues and other
Expenses and other:
Lease operating expenses
Costs of services
Electricity generation expenses
Transportation expenses
Marketing expenses
General and administrative expenses
Depreciation, depletion and amortization
Impairment of oil and gas properties
Taxes, other than income taxes
(Gains) losses on natural gas purchase derivatives
Other operating expense
Total expenses and other
Other (expenses) income:
Interest expense
Other, net
Total other (expenses) income
Reorganization items, net
(Loss) income before income taxes
Income tax expense (benefit)
Net (loss) income
Net (loss) earnings per share:
Basic
Diluted
35,840
35,636
(156,399)
3,921
477
544,950
236,048
28,339
23,148
6,897
3,811
73,106
144,495
—
46,500
(38,577)
3,101
526,868
(31,964)
(247)
(32,211)
—
(14,129)
1,413
—
25,813
117,781
1,426
150
523,833
186,348
—
16,608
6,938
1,380
77,696
139,180
289,085
35,572
1,035
5,781
759,623
(34,295)
(28)
(34,323)
—
(270,113)
(7,218)
(15,542) $
(262,895) $
—
29,397
(37,998)
2,094
316
559,405
216,294
—
19,490
8,059
2,073
62,643
106,006
51,081
40,645
6,957
4,588
517,836
(34,234)
80
(34,154)
(426)
6,989
(36,550)
43,539
(0.19) $
(0.19) $
(3.29) $
(3.29) $
0.54
0.53
$
$
$
The accompanying notes are an integral part of these financial statements.
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BERRY CORPORATION (bry)
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
December 31, 2018
Shares withheld for payment of taxes on equity awards
and other
Stock based compensation
Purchase of rights to common stock
Purchase of treasury stock
Common stock issued to settle unsecured claims
Dividends declared on common stock, $0.48/share
Net income
December 31, 2019
Shares withheld for payment of taxes on equity awards
Stock based compensation
Dividends declared on common stock, $0.12/share
Net loss
December 31, 2020
Shares withheld for payment of taxes on equity awards
Stock based compensation
Issuance of common stock
Purchase of treasury stock
Dividends declared on common stock, $0.20/share
Net loss
December 31, 2021
$
Common
Stock
Additional
Paid-in
Capital
Treasury
Stock
Retained
(Deficit)
Earnings
Total
Equity
(in thousands)
82 $ 914,540 $ (24,218) $
$
116,042 $ 1,006,446
—
—
—
—
3
—
—
85
—
—
—
—
85
—
—
1
—
—
(1,268)
8,826
—
—
(20,265)
20,265
—
(3)
—
—
901,830
(1,039)
15,086
—
—
915,877
(1,543)
14,434
—
—
(16,297)
(46,042)
—
—
—
(49,995)
—
—
—
—
(49,995)
—
—
—
(2,441)
—
—
86 $ 912,471 $ (52,436) $
—
—
—
—
—
—
—
(39,053)
43,539
120,528
—
—
(9,564)
(262,895)
(151,931)
—
—
—
—
—
(1,268)
8,826
—
(46,042)
—
(39,053)
43,539
972,448
(1,039)
15,086
(9,564)
(262,895)
714,036
(1,543)
14,434
1
(2,441)
(16,297)
(15,542)
(15,542)
(167,473) $ 692,648
The accompanying notes are an integral part of these financial statements.
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BERRY CORPORATION (bry)
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flow from operating activities:
Net (loss) income
Adjustments to reconcile net (loss) income to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization
Amortization of debt issuance costs
Impairment of oil and gas properties
Stock-based compensation expense
Deferred income taxes
(Decrease) increase in allowance for doubtful accounts
Other operating expenses
Derivatives activities:
Total losses (gains)
Cash settlements on derivatives
Changes in assets and liabilities:
(Increase) decrease in accounts receivable
Increase in other assets
Decrease in accounts payable and accrued expenses
Decrease in other liabilities
Net cash provided by operating activities
Cash flow from investing activities:
Capital expenditures:
Capital expenditures
Changes in capital expenditures accruals
Acquisitions, net of cash received
Acquisition of properties and equipment and other
Proceeds received from divestitures
Proceeds from sale of property and equipment and other
Net cash used in investing activities
Cash flow from financing activities:
Borrowings under RBL credit facility
Repayments on RBL credit facility
Dividends paid on common stock
Purchase of treasury stock
Shares withheld for payment of taxes on equity awards and other
Debt issuance costs
Net cash used in financing activities
Net (decrease) increase in cash and cash equivalents
Cash and cash equivalents:
Beginning
Ending
$
$
Year Ended December 31,
2021
2020
2019
(in thousands)
$
(15,542) $
(262,895) $
43,539
144,495
4,430
—
13,783
819
(1,349)
(487)
117,822
(91,634)
(15,614)
(24,824)
4,045
(13,456)
122,488
(132,719)
482
(50,568)
(876)
14,025
869
(168,787)
139,180
5,351
289,085
14,630
(8,045)
1,112
5,083
(116,746)
142,292
18,767
(2)
(14,172)
(17,111)
196,529
(76,480)
(11,336)
—
(5,981)
—
177
(93,620)
119,000
(119,000)
(11,486)
(2,440)
(1,543)
(3,506)
(18,975) $
(65,274)
228,900
(230,750)
(19,463)
—
(1,039)
—
(22,352) $
80,557
106,006
5,059
51,081
8,647
(36,778)
153
5,518
44,955
42,197
(14,597)
(5,136)
(917)
(7,898)
241,829
(211,995)
(11,159)
—
(2,840)
—
969
(225,025)
355,132
(353,282)
(39,157)
(46,909)
(1,268)
—
(85,484)
(68,680)
80,557
15,283 $
—
80,557 $
68,680
—
The accompanying notes are an integral part of these financial statements.
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BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1—Basis of Presentation and Significant Accounting Policies
“Berry Corp.” refers to Berry Corporation (bry), a Delaware corporation, which is the sole member of each of
its three Delaware limited liability company subsidiaries: (1) Berry Petroleum Company, LLC (“Berry LLC”), (2)
CJ Berry Well Services Management, LLC (“C&J Management”) and (3) C&J Well Services, LLC (“CJWS”). As
the context may require, the “Company”, “we”, “our” or similar words refer to Berry Corp. and its consolidated
subsidiary, Berry LLC, and as of October 1, 2021 this also includes CJWS and C&J Management.
As of October 1, 2021, we now operate in two business segments: (i) development and production (ii) well
servicing and abandonment. The development and production segment is engaged in the development and
production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as
well as Utah. On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and
abandonment businesses in California, which became a reportable segment (wells servicing and abandonment) under
U.S. GAAP.
Nature of Business
We are an independent upstream energy company focused on the development and production of onshore, low
geologic risk, long-lived conventional oil reserves, primarily located in California, with newly acquired well
servicing and abandonment capabilities in California.
Berry Corp. was incorporated under Delaware law in February 2017 and its common stock began trading on
NASDAQ under the symbol “bry” in July 2018. Berry Corp. operates through its three wholly owned subsidiaries.
Berry LLC owns and operates our oil and gas assets, all of which are located onshore in the United States (the
“U.S.”), in California (in the San Joaquin basin) and Utah (in the Uinta basin). In January 2022, we divested our
natural gas properties in the Piceance basin of Colorado. Effective as of October 1, 2021, we completed the
acquisition of one of the largest upstream well servicing and abandonment businesses in California (the “C&J Well
Services Acquisition”), this business is owned and operated through CJWS.
Principles of Consolidation and Reporting
The consolidated financial statements have been prepared in conformity with U.S. generally accepted
accounting principles (“GAAP”), which requires management to make estimates and assumptions that affect the
amounts reported in the financial statements and accompanying notes. We eliminated all significant intercompany
transactions and balances upon consolidation. For oil and gas exploration and production joint ventures in which we
have a direct working interest, we account for our proportionate share of assets, liabilities, revenue, expense and
cash flows within the relevant lines of the financial statements.
Segment Reporting
The Company has two reportable segments. Reportable segments are defined as components of an enterprise for
which separate financial information is evaluated regularly by the chief operating decision maker (“CODM”), our
Chief Executive Officer, in deciding how to allocate resources and assess performance.
The Development and Production segment consists of the development and production of onshore, low geologic
risk, long-lived conventional oil reserves, primarily located in California, as well as Utah.
The Well Servicing and Abandonment segment provides wellsite services in California to oil and natural gas
production companies, with a focus on well servicing, well abandonment services and water logistics.
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BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Use of Estimates
The preparation of the accompanying consolidated financial statements in conformity with GAAP required
management of the Company to make informed estimates and assumptions about future events. These estimates and
the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets
and liabilities, and reported amounts of revenues and expenses.
Estimates that are particularly significant to the financial statements include estimates of our reserves of oil and
gas; future cash flows from oil and gas properties; depreciation, depletion and amortization; asset retirement
obligations; fair values of commodity derivatives; stock-based compensation; fair values of assets acquired and
liabilities assumed; and income taxes.
Cash Equivalents
We consider all highly liquid short-term investments with original maturities of three months or less to be cash
equivalents.
Inventories
Inventories were included in other current assets. Oil and natural gas inventories were valued at the lower of
cost or net realizable value. Materials and supplies were valued at their weighted-average cost and are reviewed
periodically for obsolescence.
Oil and Natural Gas Properties
Proved Properties
We account for oil and natural gas properties in accordance with the successful efforts method. Under this
method, all acquisition costs of proved properties are capitalized and amortized on a unit-of-production basis over
the remaining life of the proved reserves. All development costs of proved properties are capitalized and amortized
on a unit-of-production basis over the remaining life of the proved developed reserves. Costs of retired, sold or
abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to
accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production
amortization rate, in which case a gain or loss is recognized in the current period. Gains or losses from the disposal
of other properties are recognized in the current period. For assets acquired, we base the capitalized cost on fair
value at the acquisition date. We expense expenditures for maintenance and repairs necessary to maintain properties
in operating condition, as well as annual lease rentals, as they are incurred. Estimated dismantlement and
abandonment costs are capitalized at their estimated net present value and amortized over the remaining lives of the
related assets. Interest is capitalized only during the periods in which these assets are brought to their intended use.
The amount of capitalized interest was approximately $2 million in 2021, $1 million in 2020, and $2 million in
2019. We only capitalize the interest on borrowed funds related to our share of costs associated with qualifying
capital expenditures. The amount of capitalized exploratory well costs was zero for all periods and the amount of
capitalized overhead was approximately $7 million, $6 million and $2 million in 2021, 2020 and 2019, respectively.
We evaluate the impairment of our proved oil and natural gas properties and other property and equipment
generally on a field-by-field basis or at the lowest level for which cash flows are identifiable, whenever events or
changes in circumstance indicate that the carrying value may not be recoverable. We reduce the carrying values of
proved properties to fair value when the expected undiscounted future cash flows are less than net book value. We
measure the fair values of proved properties using valuation techniques consistent with the income approach,
converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of
proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future
commodity prices; and (iv) a risk-adjusted discount rate. These inputs require significant judgments and estimates by
our management at the time of the valuation which can change significantly over time. The underlying commodity
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
prices are embedded in our estimated cash flows and are the product of a process that begins with the relevant
forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors our
management believes will impact realizable prices. The fair value was estimated using inputs characteristic of a
Level 3 fair value measurement.
Unproved Properties
A portion of the carrying value of our oil and gas properties was attributable to unproved properties. At
December 31, 2021 and 2020, the net capitalized costs attributable to unproved properties was approximately $292
million and $311 million, respectively. The unproved amounts were not subject to depreciation, depletion and
amortization until they were classified as proved properties and amortized on a unit-of-production basis.
We evaluate the impairment of our unproved oil and gas properties whenever events or changes in
circumstances indicate the carrying value may not be recoverable. If the exploration and development work were to
be unsuccessful, or management decided not to pursue development of these properties as a result of lower
commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized
costs of such properties would be expensed. The timing of any write-downs of unproved properties, if warranted,
depends upon management’s plans, the nature, timing and extent of future exploration and development activities
and their results.
Impairment
In 2021 we did not record any impairment charges for proved and unproved properties.
As of March 31, 2020, we performed impairment tests with respect to our proved and unproved oil and gas
properties and other property and equipment as a result of significant declines in oil prices during the latter part of
the first quarter 2020. We recorded a non-cash pre-tax asset impairment charge of $289 million during the first
quarter of 2020 on proved properties in Utah and certain California locations and other property and equipment. We
evaluated our proved properties in accordance with accounting guidance and fair value techniques utilizing the
period-end forward price curve, as well as assessing projects we determine we would not pursue in the foreseeable
future given the current environment. We determined based on plans and exploration and development efforts no
impairment was necessary for our unproved property balance in 2020.
At year end 2019, we evaluated our proved and unproved natural gas properties in regards to the decline in our
expectations of future gas prices. As a result, we recorded a non-cash pre-tax asset impairment charge of $51
million for our Piceance gas properties in Colorado, of which $23 million was for proved properties and other
property and equipment and $28 million for unproved properties.
Other Property and Equipment
Other property and equipment includes natural gas gathering systems, pipelines, cogeneration facilities,
buildings, well servicing and abandonment vehicles and equipment, software, data processing and
telecommunications equipment, office furniture and equipment, and other fixed assets. These assets are recorded at
cost, depreciated using the straight-line method based on expected useful lives ranging from 15 to 39 years for
buildings and improvements, 20 to 30 years for cogens, natural gas plants and pipelines, 1 to 10 years furniture and
equipment, 1 to 10 years for well servicing and abandonment vehicles and equipment and other equipment, and the
salvage value is considered as applicable. Other property and equipment assets are evaluated for impairment
whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
Business Combinations
The Company records business combinations using the acquisition method of accounting. Under the acquisition
method of accounting, identifiable assets acquired and liabilities assumed are recorded at their acquisition-date fair
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
values. The excess of the purchase price over the estimated fair value, if any, is recorded as goodwill. Changes in the
estimated fair values of net assets recorded for acquisitions prior to the finalization of more detailed analysis, but not
to exceed one year from the date of acquisition, will adjust the amount of the purchase price allocations accordingly.
Measurement period adjustments are reflected in the period in which they occur.
We account for acquisitions of businesses using the acquisition method of accounting, which requires the
allocation of the purchase price consideration based on the fair values of the assets and liabilities acquired. We
estimate the fair values of the assets and liabilities acquired using accepted valuation methods, and, in many cases,
such estimates are based on our judgments as to the future operating cash flows expected to be generated from the
acquired assets throughout their estimated useful lives. Following the October 1, 2021 acquisition of CJWS, we
accounted for the various assets acquired and liabilities assumed based on our estimates of their fair values. Our
estimates and judgments of the fair value of acquired businesses could prove to be inexact, and the use of inaccurate
fair value estimates could result in the improper allocation of the acquisition purchase price consideration to
acquired assets and liabilities, which could result in asset impairments, the recording of previously unrecorded
liabilities, and other financial statement adjustments. The difficulty in estimating the fair values of acquired assets
and liabilities is increased during periods of economic uncertainty.
Asset Retirement Obligation
We recognize the fair value of asset retirement obligations (“AROs”) in the period in which a determination is
made that a legal obligation exists to dismantle an asset and remediate the property at the end of its useful life and
the cost of the obligation can be reasonably estimated. The liability amounts were based on future retirement cost
estimates and incorporate many assumptions such as time to abandonment, technological changes, future inflation
rates and the risk-adjusted discount rate. When the liability is initially recorded, we capitalized the cost by increasing
the related property, plant and equipment (“PP&E”) balances. If the estimated future cost of the AROs changes, we
record an adjustment to both the ARO and PP&E. Over time, the liability is increased and the capitalized cost is
depreciated over the useful life of the asset. Accretion expense is also recognized over time as the discounted
liabilities are accreted to their expected settlement value and is included in depreciation, depletion and amortization
in the statement of operations.
The following table summarizes activity in our ARO account in which approximately $144 million and $135
million were included in long term liabilities as of December 31, 2021 and December 31, 2020, respectively, with
the remaining current portion included in accrued liabilities:
Beginning balance
Liabilities incurred including from acquisitions
Settlements and payments
Accretion expense
Reduction due to property sales
Revisions
Ending balance
Revenue Recognition
Year Ended December 31,
2021
2020
(in thousands)
$
160,192 $
1,350
(17,900)
10,936
(22,199)
31,546
149,227
5,919
(14,931)
9,996
—
9,981
$
163,925 $
160,192
The majority of the Company's revenue is from the development and production business, which includes the
sale of crude oil, natural gas and NGLs, as well as electricity from its cogeneration plants. The remaining revenue
is generated from the well servicing and abandonment business. See Note 12 for information regarding the
Company’s revenue recognition policy.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Fair Value Measurements
We have categorized our assets and liabilities that are measured at fair value in a three-level fair value
hierarchy, based on the inputs to the valuation techniques: Level 1—using quoted prices in active markets for the
assets or liabilities; Level 2—using observable inputs other than quoted prices for the assets or liabilities; and Level
3—using unobservable inputs. Transfers between levels, if any, are recognized at the end of each reporting period.
We primarily apply the market approach for recurring fair value measurement, maximize our use of observable
inputs and minimize use of unobservable inputs. We generally use an income approach to measure fair value when
observable inputs are unavailable. This approach utilizes management’s judgments regarding expectations of
projected cash flows and discounts those cash flows using a risk-adjusted discount rate.
The only item on our balance sheet that would be affected by recurring fair value measurements is derivatives.
We determine the fair value of our oil and gas sales and natural gas purchase derivatives using valuation techniques
which utilize market quotes and pricing analysis. Inputs include publicly available prices and forward price curves
generated from a compilation of data gathered from third parties. We classify these measurements as Level 2.
We use market-observable prices for assets when comparable transactions can be identified that are similar to
the asset being valued. When we are required to measure fair value and there is not a market-observable price for the
asset or for a similar asset then the income approach is based on management’s best assumptions regarding
expectations of future net cash flows. PP&E is written down to fair value if we determine that there has been an
impairment in its value. The fair value is determined as of the date of the assessment using discounted cash flow
models based on management’s expectations for the future. Inputs include estimates of future production, prices
based on commodity forward price curves as of the date of the estimate, estimated future operating and development
costs and a risk-adjusted discount rate. However, assumptions used reflect assets highest and best use and a market
participant’s view of long-term prices, costs and other factors and are consistent with assumptions used in our
business plans and investment decisions. We classify these measurements as Level 3.
Stock-based Compensation
We have issued restricted stock units (“RSUs”) that vest over time and performance-based restricted stock units
(“PSUs”) that include (i) awards with a market objective measured against both absolute total stockholder return
(“Absolute TSR”) and a relative total stockholder return (“Relative TSR”) (the “TSR PSUs”) over the performance
period and (ii) awards based on the Company's average cash returned on invested capital (“CROIC PSUs”) over the
performance period. The fair value of the stock-based awards is determined at the date of grant and is not
remeasured. The fair value of the RSUs and CROIC PSUs was determined using the grant date stock price. The fair
value of the TSR PSUs was determined using a Monte Carlo simulation analysis to estimate the total shareholder
return ranking of the Company, including a comparison against the peer group over the performance periods.
Estimates used in the Monte Carlo valuation model are considered highly complex and subjective. Compensation
expense, net of actual forfeitures, for the RSUs and PSUs is recognized on a straight-line basis over the requisite
service periods, which is over the awards’ respective vesting or performance periods which range from one to three
years.
Other Loss Contingencies
In the normal course of business, we are involved in lawsuits, claims and other environmental and legal
proceedings and audits. We accrue reserves for these matters when it is probable that a liability has been incurred
and the liability can be reasonably estimated. In addition, we disclose, if material, in aggregate, our exposure to loss
in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional
material loss may be incurred. We review our loss contingencies on an ongoing basis.
Loss contingencies are based on judgments made by management with respect to the likely outcome of these
matters and are adjusted as appropriate. Management’s judgments could change based on new information, changes
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
in, or interpretations of, laws or regulations, changes in management’s plans or intentions, opinions regarding the
outcome of legal proceedings, or other factors.
Electricity Cost Allocation
We own several cogeneration facilities. Our investment in cogeneration facilities has been for the express
purpose of lowering steam costs in our heavy oil operations in California and securing operating control of the
respective steam generation. Cogeneration, also called combined heat and power, extracts energy from the exhaust
of a turbine, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce
electricity. We allocate steam and electricity costs to lease operating expenses based on the conversion efficiency of
the cogeneration facilities plus certain direct costs of producing steam. We also allocate a portion of the electricity
production costs related to the power we sell to third parties, which is reported in “electricity generation expenses”
in the statement of operations.
Income Taxes
Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to
differences between the financial statement carrying amounts of assets and liabilities and their tax basis. Deferred
tax assets are recognized when it is more likely than not that they will be realized. We periodically assess our
deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some
portion, or all, of the deferred tax assets will not be realized. We recognize a tax benefit from an uncertain tax
position when it is more likely than not that the position will be sustained upon examination, based on the technical
merits of the position. Interest and penalties related to unrecognized tax benefits are recognized in income tax
expense (benefit).
Earnings per Share
We computed basic and diluted earnings per share (EPS) using the two-class method required for participating
securities. Common stock awards are considered participating securities when such shares have non-forfeitable
dividend rights at the same rate as common stock.
Under the two-class method, undistributed earnings allocated to participating securities are subtracted from net
income attributable to common stock in determining net income attributable to common stockholders. In loss
periods, no allocation is made to participating securities because the participating securities do not share in losses.
For basic EPS, the weighted-average number of common shares outstanding excludes outstanding shares related to
unvested restricted stock awards. For diluted EPS, the basic shares outstanding are adjusted by adding potentially
dilutive securities, unless their effect is anti-dilutive.
Business and Credit Concentrations
We maintain our cash in bank deposit accounts which, at times, may exceed federally insured amounts. We
have not experienced any losses in such accounts. We believe we are not exposed to any significant credit risk on
our cash.
We sell oil, natural gas and NGLs to various types of customers, including pipelines, refineries and other oil and
natural gas companies and electricity to utility companies. We also perform well servicing and abandonment for oil
and natural gas companies. Based on the current demand for oil, natural gas, NGLs, as well as our well servicing and
abandonment services and the availability of other purchasers, we believe that the loss of any one of our major
purchasers would not have a material adverse effect on our financial condition, results of operations or net cash
provided by operating activities.
For the year ended December 31, 2021, our four largest customers represented approximately 30%, 16%, 14%,
and 12% of our sales, which are all customers of the development and production segment. For the year ended
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2020, our three largest customers represented 44%, 20%, and 12% of our sales. For the year ended
December 31, 2019, our three largest customers represented approximately 36%, 24%, and 13% of our sales.
At December 31, 2021, trade accounts receivable from three customers represented approximately 28%, 13%,
and 11% of our receivables, which are all customers of the development and production segment. At December 31,
2020, trade accounts receivable from three customers represented approximately 38%, 15%, and 11% of our
receivables.
Recently Adopted Accounting Standards
In December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update
(“ASU”) 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which simplified the
accounting for income taxes. We adopted these rules in the first quarter of 2021 which did not have a material
impact on our financial statements.
New Accounting Standards Issued, But Not Yet Adopted
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize
assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than
12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty
of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842), which is an
update to the lease standard providing an optional transition approach for land easements allowing entities to
evaluate only new or modified land easements. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842),
which provided optional transition relief allowing a prospective approach in applying the new rules by not adjusting
comparative period financial information for the effects of the new rules and not requiring disclosures for periods
before the effective date. As an emerging growth company, we have elected to delay the adoption of these rules until
they are applicable to non-SEC issuers. During the second quarter of 2020, this adoption date was further delayed by
FASB until fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. We
will adopt these rules in 2022, which we expect to apply prospectively. We are currently evaluating the impact of the
adoption of the new lease standard on our consolidated financial statements, including identifying all leases as
defined under the new lease standards.
In March 2020, the FASB issued issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the
Effects of Reference Rate Reform on Financial Reporting, which provided optional expedients and exceptions for
applying GAAP to contracts, hedging relationships and other transactions affected by the reference rate reform, if
certain criteria are met. The optional expedient for contract modifications applies to contract modifications that
replace a reference rate affected by the reference rate reform, such as the London Interbank Offered Rate
(“LIBOR”). Entities may elect to apply the amendments for contract modifications as of any date from the beginning
of an interim period that includes or is subsequent to March 12, 2020 through December 31, 2022. To date, these
rules have not had any impact on our consolidated financial statements and we continue to assess the future impact
of these rules on our consolidated financial statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 2—Oil and Natural Gas Properties and Other Property and Equipment
Oil and Natural Gas Capitalized Costs
Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable
accumulated depletion and amortization are presented below:
Proved properties
Unproved properties
Total proved and unproved properties
Less accumulated depletion and amortization
Total proved and unproved properties, net
Other Property and Equipment
Other property and equipment consisted of the following:
Year Ended December 31,
2021
2020
(in thousands)
$
1,246,380 $
1,101,371
291,514
1,537,894
(340,328)
311,195
1,412,566
(235,259)
$
1,197,566 $
1,177,307
Year Ended December 31,
2021
2020
(in thousands)
Cogens, natural gas plants and pipelines
Vehicles and service equipment(1)
Furniture and equipment
Land
Buildings and leasehold improvements
Total other property and equipment
Less: accumulated depreciation
$
54,237 $
55,521
22,665
6,101
2,186
140,710
(36,927)
Total other property and equipment, net
$
103,783 $
__________
(1)
Includes CJWS vehicles and service equipment in 2021.
72,999
8,878
21,515
6,512
2,241
112,145
(31,368)
80,777
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 3—Debt
The following table summarizes our outstanding debt:
December 31,
2021
December 31,
2020
(in thousands)
Interest Rate
Maturity
Security
2021 RBL Facility
$
—
n/a
variable rates
5.3% (2021)
August 26, 2025
2017 RBL Facility
n/a
$
—
variable rates
4.0% (2020)
July 29, 2022
(Cancelled
August 26, 2021)
Mortgage on 90% of
Present Value of proven
oil and gas reserves and
lien on certain other
assets
Mortgage on 85% of
Present Value of proven
oil and gas reserves and
lien on certain other
assets
2026 Notes
400,000
400,000
7%
February 15, 2026
Unsecured
Long-Term Debt -
Principal Amount
400,000
400,000
Less: Debt Issuance Costs
(5,434)
(6,520)
Long-Term Debt, net
$
394,566 $
393,480
Deferred Financing Costs
We incurred legal and bank fees related to the issuance of debt. At December 31, 2021 and 2020, debt issuance
costs for the 2021 RBL Facility and 2017 RBL Facility (each as defined below) reported in “other noncurrent assets”
on the balance sheet were approximately $5 million and $7 million, net of amortization, respectively. In 2021, we
expensed $3 million of unamortized debt issuance costs related to the modification of the 2017 RBL Facility. Also
in 2021, we incurred approximately $4 million of legal and bank fees related to the issuance of the 2021 RBL
Facility. At December 31, 2021 and 2020, debt issuance costs, net of amortization, for the unsecured notes due
February 2026 (the “2026 Notes”) reported in “Long-Term Debt, net” on the balance sheet were approximately $5
million and $7 million, respectively.
For the years ended December 31, 2021, 2020, and 2019, the amortization expense for the 2021 RBL Facility,
the 2017 RBL Facility and the 2026 Notes combined, was approximately $4 million, $5 million, and $5 million,
respectively. The amortization of debt issuance costs is presented in “interest expense” on the consolidated
statements of operations.
Fair Value
Our debt is recorded at the carrying amount on the balance sheets. The carrying amount of each RBL Facility
approximated fair value because the interest rates are variable and reflect market rates. The fair value of the 2026
Notes was approximately $400 million and $337 million at December 31, 2021 and 2020, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 commitments, subject to a reserve
borrowing base (“2021 RBL Facility”). Our initial borrowing base is $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.
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 December 31, 2021, our leverage
ratio and current ratio were 2.0 to 1.0 and 2.2 to 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 December 31, 2021.
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 if
availability is equal to or greater than 20% of the borrowing base, whichever is in effect, and our pro forma leverage
ratio is less than or equal to 2.0 to 1.0.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
We can repurchase equity or make other distributions to our equity holders in an amount equal to (i) 100% of
Free Cash Flow (as defined under the 2021 RBL Facility) for the fiscal quarter most recently ended prior to such
repurchase or distribution minus (ii) the amount of certain investments made, so long as, in addition to other
conditions and limitations as described in the 2021 RBL Facility, availability is equal to or greater than 20% of the
elected commitments or borrowing base, whichever is in effect, 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
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 December 31, 2021, we had no borrowings outstanding, $7 million in letters of credit outstanding, and
approximately $193 million of available borrowings capacity under the 2021 RBL Facility.
Corporate Organization
Berry Corp., as Berry LLC’s parent company, has no independent assets or operations and is subject to a
passive holding company covenant under the 2021 RBL Facility. Any guarantees of potential future registered debt
securities by Berry Corp. or Berry LLC would be full and unconditional. In addition, there are no significant
restrictions upon the ability of Berry LLC to distribute funds to Berry Corp. by distribution or loan other than
restrictions under the 2021 RBL Facility. None of the assets of Berry Corp. or Berry LLC represent restricted net
assets.
The 2021 RBL Facility permits Berry Corp. to make dividends so long as both before and after giving pro
forma effect to such distribution, no default or event of defaults exists, availability exceeds 20% of the borrowing
base, whichever is in effect, and Berry Corp. demonstrates a pro forma leverage ratio less than or equal to 2.0 to 1.0.
The conditions are currently met with significant margin.
2017 RBL Facility
On July 31, 2017, we entered into a credit agreement that provided for a revolving loan with up to $1.5 billion
of commitment, subject to a reserve borrowing base (“2017 RBL Facility”). In April 2021, we completed our
scheduled semi-annual borrowing base redetermination under our 2017 RBL Facility, which resulted in a reaffirmed
borrowing base at $200 million. On August 26, 2021, we cancelled the 2017 RBL Facility agreement. There were no
borrowings outstanding at the time of cancellation.
Senior Unsecured Notes Offering
In February 2018, we completed a private issuance of $400 million in aggregate principal amount of 7.0%
senior unsecured notes due February 2026 (the “2026 Notes”), which resulted in net proceeds to us of approximately
$391 million after deducting expenses and the initial purchasers’ discount.
We may, at our option, redeem all or a portion of the 2026 Notes at any time on or after February 15, 2021. If
we experience certain kinds of changes of control, holders of the 2026 Notes may have the right to require us to
repurchase their notes at 101% of the principal amount of the 2026 Notes, plus accrued and unpaid interest, if any.
The 2026 Notes are our senior unsecured obligations and rank equally in right of payment with all of our other
senior indebtedness and senior to any of our subordinated indebtedness. The notes are fully and unconditionally
guaranteed on a senior unsecured basis by us and will also be guaranteed by certain of our future subsidiaries;
whereas Berry LLC, C&J Management and CJWS are not guarantors. The 2026 Notes and related guarantees are
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BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our
RBL Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in
right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future
subsidiaries that do not guarantee the 2026 Notes.
The indenture governing the 2026 Notes contains restrictive covenants that may limit our ability to, among
other things:
•
•
•
incur or guarantee additional indebtedness or issue certain types of preferred stock;
pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated
indebtedness;
transfer, sell or dispose of assets;
• make investments;
•
•
•
•
create certain liens securing indebtedness;
enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets; and
engage in transactions with affiliates.
The indenture governing the 2026 Notes contains customary events of default, including, among others, (a) non-
payment; (b) non-compliance with covenants (in some cases, subject to grace periods); (c) payment default under, or
acceleration events affecting, material indebtedness and (d) bankruptcy or insolvency events involving us or certain
of our subsidiaries. We were in compliance with all covenants as of December 31, 2021.
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 does 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.
Note 4—Derivatives
We utilize derivatives, such as swaps, puts, calls and collars 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, which addresses our
market risk. In addition to the hedging requirements of the 2021 RBL Facility, we target covering our operating
expenses and a majority of our fixed charges, which includes capital needed to sustain production levels, as well as
interest and fixed dividends as applicable, with the oil and gas sales hedges for a period of up to three years out.
Additionally, we target fixing the price for a large portion of our natural gas purchases used in our steam operations
for up to two years. We have also entered into Utah gas transportation contracts to help reduce the price fluctuation
exposure, however these do not qualify as hedges. We also, from time to time, have entered into agreements to
purchase a portion of the natural gas we require for our operations, which we do not record at fair value as
derivatives because they qualify for normal purchases and normal sales exclusions. We had no such transactions in
the periods presented.
For fixed-price oil and gas sales swaps, we are the seller, so we make settlement payments for prices above the
indicated weighted-average price per barrel and per mmbtu, respectively, and receive settlement payments for prices
below the indicated weighted-average price per barrel and per mmbtu, respectively.
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BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
For our purchased oil puts, we would receive settlement payments for prices below the indicated weighted-
average price per barrel of Brent. For most of our options we paid or received a premium at the time the positions
were created and for others, the premium payment or receipt is deferred until the time of settlement. As of December
31, 2021 we have net payable deferred premiums of approximately $21 million, which is reflected in the mark-to-
market valuation and will be payable beginning in 2022 through 2024, in approximately the same amount each year.
For our put spreads, in addition to any deferred premium payments, we would receive settlement payments for
prices below the indicated highest price of the long put with the maximum payment received per barrel equal to the
difference between the indicated prices of the long and short put. No payment would be made or received for prices
above the highest indicated price of the long put. The short put spreads offset the long put spreads.
For our sold oil and gas puts, we would make settlement payments for prices below the indicated weighted-
average price. No payment would be due for prices above the indicated weighted-average price.
For our sold oil and gas calls, we would make settlement payments for prices above the indicated weighted-
average price. No payment would be due for prices below the indicated weighted-average price.
For our purchased gas puts, we would receive settlement payments for prices below the indicated weighted-
average price. No payment would be received for prices above the indicated weighted-average price.
For our purchased gas calls, we would receive settlement payments for prices above the indicated weighted-
average price. No payment would be received for prices below the indicated weighted-average price.
We use oil and gas swaps and puts to protect our sales against decreases in oil and gas prices. We also use
swaps to protect our natural gas purchases against increases in prices. We do not enter into derivative contracts for
speculative trading purposes and have not accounted for our derivatives as cash-flow or fair-value hedges. The
changes in fair value of these instruments are recorded in current earnings. Gains (losses) on oil and gas sales hedges
are classified in the revenues and other section of the statement of operations, while natural gas purchase hedges are
included in expenses and other section of the statement of operations.
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BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2021, we had the following crude oil production and gas purchases hedges.
Q1 2022
Q2 2022
Q3 2022
Q4 2022
FY 2023
FY 2024
Brent
Swaps
Hedged volume (bbls)
796,500
753,500
736,000
736,000
1,595,750
732,000
Weighted-average price ($/bbl)
$
67.02 $
66.59 $
66.36 $
66.36 $
65.26 $
61.78
Put Spreads
Long $50/$40 Put Spread hedged
volume (bbls)
Short $50/$40 Put Spread hedged
volume (bbls)
Collars
405,000
409,500
414,000
414,000
2,555,000
1,647,000
45,000
45,500
46,000
46,000
365,000
366,000
Purchased Puts hedged volume (bbls)
270,000
—
—
—
—
Weighted-average price ($/bbl)
$
40.00 $
— $
— $
— $
— $
Sold Calls hedged volume (bbls)
270,000
—
—
—
—
Weighted-average price ($/bbl)
$
80.00 $
— $
— $
— $
— $
Henry Hub
Purchased Puts
Hedged volume (mmbtu)
1,800,000
—
—
—
—
Weighted-average price ($/mmbtu)
$
2.75 $
— $
— $
— $
— $
Purchased Calls
—
—
—
—
—
—
Hedged volume (mmbtu)
2,700,000
2,730,000
2,760,000
2,760,000
10,950,000
9,150,000
Weighted-average price ($/mmbtu)
$
4.00 $
4.00 $
4.00 $
4.00 $
4.00 $
4.00
Sold Puts
Hedged volume (mmbtu)
2,700,000
2,730,000
2,760,000
2,760,000
10,950,000
9,150,000
Weighted-average price ($/mmbtu)
$
2.75 $
2.75 $
2.75 $
2.75 $
2.75 $
2.75
Our long put spread position ($50/$40) is presented in the table above on a gross basis as originally established.
Subsequently, we have entered into additional transactions that exactly offset a portion of the original long put
spread position and these are shown as short put spread ($50/$40).
In 2022 we added sold fixed price oil swaps (Brent) of 2,000 bbl/d at $80.40 beginning February 2022 through
December 2022, 2,000 bbl/d at $85.20 beginning March 2022 through December 2022, and 4,000 bbl/d at $78.42
beginning January 2023 through December 2023. We also added Brent collars of 3,000 bbl/d for calendar year 2023
buying $40.00 put options and selling $106.33 call options.
Our commodity derivatives are measured at fair value using industry-standard models with various inputs including
publicly available underlying commodity prices and forward curves, and all are classified as Level 2 in the required
fair value hierarchy for the periods presented. These commodity derivatives are subject to counterparty netting. The
following tables present the fair values (gross and net) of our outstanding derivatives as of December 31, 2021 and
2020.The following tables present the fair values (gross and net) of our outstanding derivatives as of December 31,
2021 and 2020.
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BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2021
Balance Sheet
Classification
Gross Amounts
Recognized at
Fair Value
Gross Amounts Offset
in the Balance Sheet
Net Fair Value
Presented in the
Balance Sheet
(in thousands)
Assets:
Commodity Contracts
Current assets
$
Commodity Contracts
Non-current assets
5,360 $
29,828
(5,360) $
(28,758)
Liabilities:
Commodity Contracts
Current liabilities
Commodity Contracts
Non-current liabilities
(34,985)
(47,335)
5,360
28,758
Total derivatives
$
(47,132) $
— $
—
1,070
(29,625)
(18,577)
(47,132)
December 31, 2020
Balance Sheet
Classification
Gross Amounts
Recognized at
Fair Value
Gross Amounts Offset
in the Balance Sheet
Net Fair Value
Presented in the
Balance Sheet
(in thousands)
Assets:
Commodity Contracts
Current assets
Liabilities:
Commodity Contracts
Current liabilities
Total derivatives
$
$
15,217 $
(12,710) $
2,507
(36,031)
(20,814) $
12,710
— $
(23,321)
(20,814)
By using derivative instruments to economically hedge exposure to changes in commodity prices, we expose
ourselves to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative
contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk.
We do not receive collateral from our counterparties.
We minimize the credit risk in derivative instruments by limiting our exposure to any single counterparty. In
addition, our 2021 RBL Facility prevents us from entering into hedging arrangements that are secured, except with
our lenders and their affiliates that have margin call requirements, that otherwise require us to provide collateral or
with a non-lender counterparty that does not have an A or A2 credit rating or better from Standards & Poor’s or
Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to
counterparty netting under agreements governing such derivatives which partially mitigates the counterparty
nonperformance risk.
(Losses) Gains on Derivatives
A summary of gains and losses on the derivatives included on the statements of operations is presented below:
(Losses) gains on oil and gas sales derivatives
Gains (losses) on natural gas purchase derivatives
Total (losses) gains on derivatives
$
$
(156,399) $
117,781 $
38,577
(1,035)
(117,822) $
116,746 $
(37,998)
(6,957)
(44,955)
Year Ended December 31,
2021
2020
(in thousands)
2019
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BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
For the year ended December 31, 2021, we paid net cash settlements of approximately $92 million. For the
years ended December 31, 2020 and 2019 we received net cash scheduled settlements of approximately $142
million and $42 million respectively.
Note 5—Commitments and Contingencies
In the normal course of business, we, or our subsidiary, are the subject of, or party to, pending or threatened
legal proceedings, contingencies and commitments involving a variety of matters that seek, or may seek, among
other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive
damages, fines and penalties, remediation costs, or injunctive or declaratory relief.
We accrue for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has
been incurred and the liability can be reasonably estimated. We have not recorded any reserve balances at December
31, 2021 and December 31, 2020. We also evaluate the amount of reasonably possible losses that we could incur as
a result of these matters. We believe that reasonably possible losses that we could incur in excess of accruals on our
balance sheet would not be material to our consolidated financial position or results of operations.
We, or our subsidiaries, or both, have indemnified various parties against specific liabilities those parties might
incur in the future in connection with transactions that they have entered into with us. As of December 31, 2021, we
are not aware of material indemnity claims pending or threatened against us.
We have certain commitments under contracts, including purchase commitments for goods and services. Prior
to our 2017 emergence, Berry entered into a Carry and Earning Agreement with Encana, effective June 7, 2006, in
connection with our Piceance assets which, among other things, required us to either build a road or secure a license
for alternative access, in lieu of paying a $6 million penalty. As of December 31, 2019, we fulfilled the obligation by
delivering the access license pursuant to the agreement. On January 30, 2020, Caerus Piceance LLC, the successor
of Encana's interests filed a claim in the City and County of Denver District Court challenging the sufficiency of
such access, which we dispute. We settled the lawsuit and the case was dismissed with prejudice on February 1,
2022, which also satisfied the road obligation.
Securities Litigation Matter
On November, 20, 2020, Luis Torres, individually and on behalf of a putative class, filed a securities class
action lawsuit (the “Torres Lawsuit”) in the United States District Court for the Northern District of Texas against
Berry Corp. and certain of its current and former directors and officers (collectively, the “Defendants”). The
complaint asserts violations of Sections 11 and 15 of the Securities Act of 1933, and Sections 10(b) and 20(a) of the
Exchange Act, on behalf of a putative class of all persons who purchased or otherwise acquired (i) common stock
pursuant and/or traceable to the Company’s 2018 IPO; or (ii) Berry Corp.'s securities between July 26, 2018 and
November 3, 2020 (the “Class Period”). In particular, the complaint alleges that the Defendants made false and
misleading statements during the Class Period and in the offering materials for the IPO, concerning the Company’s
business, operational efficiency and stability, and compliance policies, that artificially inflated the Company’s stock
price, resulting in injury to the purported class members when the value of Berry Corp.’s common stock declined
following release of its financial results for the third quarter of 2020 on November 3, 2020.
On January 21, 2021, multiple plaintiffs filed motions in the Torres Lawsuit seeking to be appointed lead
plaintiff and lead counsel. After briefing and a stipulation between the remaining movants, the Court appointed Luis
Torres and Allia DeAngelis as co-lead plaintiffs on August 18, 2021. On November 1, 2021, the co-lead plaintiffs
filed an amended complaint asserting claims on behalf of the same putative class under Sections 11 and 15 of the
Securities Act of 1933 and Sections 10(b) and 20(a) of the Exchange Act, alleging, among other things, that the
Company and the individual Defendants made false and misleading statements between July 26, 2018 and
November 3, 2020 regarding the Company’s permits and permitting processes. The amended complaint does not
quantify the alleged losses but seeks to recover all damages sustained by the putative class as a result of these
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
alleged securities violations, as well as attorneys’ fees and costs. The Defendants filed a Motion to Dismiss on
January 24, 2022; plaintiffs’ opposition is due on March 21, 2022 and Defendants' reply is due on May 16, 2022.
We dispute these claims and intend to defend the matter vigorously. Given the uncertainty of litigation, the
preliminary stage of the case, and the legal standards that must be met for, among other things, class certification
and success on the merits, we cannot reasonably estimate the possible loss or range of loss that may result from this
action.
Other Commitments
We entered into certain firm commitments to secure transportation of our production and third-party natural gas
to market as well as processing which require a minimum monthly charge regardless of whether the contracted
capacity is used or not. We also entered into a drilling commitment associated with our property acquisition. We
also have operating lease agreements mainly for office space. Office rent payments are generally expensed as part of
general and administrative expenses and were approximately $2.0 million, $1.5 million and $1.5 million in 2021,
2020 and 2019, respectively.
At December 31, 2021, future net minimum payments for non-cancelable purchase obligations and operating
leases (excluding oil and natural gas and other mineral leases, utilities, taxes and insurance and maintenance
expense) were as follows:
Processing and transportation
contracts(1)
Operating lease obligations
Other purchase obligations(2)
Total
__________
2022
2023
2024
2025
2026
Thereafter
Total
(in thousands)
$
9,835 $
10,348 $
9,130 $
8,083 $
8,082 $
51,604 $
97,082
2,279
20,700
2,122
2,400
1,649
1,551
1,554
936
10,091
—
—
—
—
23,100
$
32,814 $
14,870 $
10,779 $
9,634 $
9,636 $
52,540 $ 130,273
(1) Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of
business to secure pipeline transportation of natural gas to market and between markets, as well as gathering and processing of natural gas.
(2) Amounts included a purchase commitment of $6 million to build a road, which was classified as current. In January 2022 the purchase
commitment of $6 million was fully resolved without any payment. Additionally, we have a drilling commitment in California, for which
we are required to drill 57 wells with an estimated cost and minimum commitment of $17.1 million by April 2023. 49 of those wells are
estimated at $14.7 million and are required to be drilled by December 2022.
Note 6—Stockholders' Equity
Cash Dividends
Our Board of Directors approved regular cash dividends on our common stock of $0.04 per share for each of the
first and second quarters of 2021 and $0.06 per share for each of the third and fourth quarters of 2021. For the year
ended December 31, 2021 we paid approximately $11 million in cash dividends on our common stock. For the year
ended December 31, 2020 we paid approximately $19 million in cash dividends on our common stock, which
included payment of the dividend declared for the fourth quarter of 2019 and a $0.12 per share cash dividend for the
first quarter of 2020. For the year ended December 31, 2019 we declared a cash dividend of $0.12 per share each
quarter for a total of $0.48 per share and paid approximately $39 million in cash dividends on our common stock.
Our Board of Directors declared a regular dividend for the first quarter of 2022 at a rate of $0.06 per share on
the Company’s outstanding common stock, payable on April 15, 2022 to shareholders of record at the close of
business on March 15, 2022.
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BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Common Stock
On February 28, 2017 (the “Effective Date”), 32,920,000 shares of common stock in Berry Corp. were
distributed in accordance with our plan of reorganization in the Chapter 11 Proceeding (the “Plan”). In addition
7,080,000 shares of Berry Corp. common stock reserved for future issuance in the event that the holders of such
rights chose cash distributions instead. We negotiated with the claimants to settle their claims and in 2019 we issued
approximately 2,770,000 shares of Berry Corp. common stock instead of 7,080,000 to resolve these claims for
approximately $20 million.
Voting Rights. Each share of common stock is entitled to one vote with respect to each matter on which holders
of common stock are entitled to vote. Holders of common stock do not have cumulative voting rights.
Dividend Rights. Holders of common stock will be entitled to receive dividends, if any, as may be declared
from time to time by our board of directors (the “Board”) out of legally available funds.
Liquidation Rights. Upon liquidation, dissolution or winding up of the Company, holders of our common stock
will be entitled to share ratably in the assets of the Company that are legally available for distribution to holders of
our common stock after payment of the Company’s debts and other liabilities.
Preemptive and Conversion Rights. Holders of common stock have no preemptive, conversion or other rights
to subscribe for additional shares.
Registration Rights Agreement
On the Effective Date, Berry Corp. entered into a registration rights agreement (the “Registration Rights
Agreement”) with certain holders of the Unsecured Notes. Subsequently, the registration rights agreement was
amended and restated in connection with our IPO.
In accordance with the Registration Rights Agreement, Berry Corp. filed a shelf registration statement with the
SEC subsequent to the Effective Date. The shelf registration statement registered the resale, on a delayed or
continuous basis, of all Registrable Securities that have been timely designated for inclusion by specified Holders
(as defined in the Registration Rights Agreement). Generally, “Registrable Securities” includes (i) common stock
issued or to be issued by Berry Corp. under the Plan (defined in Note 13), (ii) preferred stock that was purchased by
the participants in the rights offering noted above and (iii) common stock into which the preferred stock converts,
except that “Registrable Securities” does not include securities that have been sold under an effective registration
statement or Rule 144 under the Securities Act. The Registration Rights Agreement will terminate when there are no
longer any Registrable Securities outstanding.
Shares Outstanding
As of December 31, 2021, there were 80,007,149 shares of common stock outstanding. Up to an additional
6,998,815 shares were issuable for unvested restricted stock units and performance restricted stock units (assuming
maximum achievement of performance goals) under the Company's 2017 Omnibus Incentive Plan as of December
31, 2021.
Stock Repurchase Program
In December 2018, our Board of Directors adopted a program for the opportunistic repurchase of up to
$100 million of our common stock. Based on the Board’s evaluation of market conditions for our common stock at
the time, they authorized repurchases of up to $50 million under the program. In 2018 and 2019, the Company
repurchased a total of 5,057,682 shares under the stock repurchase program for approximately $50 million in
aggregate. In February 2020, the Board of Directors authorized the repurchase of the remaining $50 million
available under the repurchase program. We did not repurchase any common stock in 2020. For the year ended
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BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2021, we repurchased 471,022 shares at an average price of $5.18 per share for approximately
$2 million in the third quarter. All shares repurchased are reflected as treasury stock. Accordingly, as of December
31, 2021, the Company has repurchased a total of 5,528,704 shares under the stock repurchase program for
approximately $52 million in aggregate, leaving approximately $48 million authorized and available for future
repurchases under the program. 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 Berry Corp. to purchase shares during any period or at all. Any shares acquired will be available
for general corporate purposes.
Stock-Based Compensation
The Company has awarded restricted stock units (“RSUs”) that are solely time-based awards and performance-
based restricted stock units (“PSUs”) that include (i) awards with a market objective measured against both absolute
total stockholder return (“Absolute TSR”) and a relative total stockholder return (“Relative TSR”) (the “TSR
PSUs”) over the performance period and (ii) awards based on the Company's average cash returned on invested
capital (“CROIC PSUs”) over the performance period. Depending on the results achieved during the three-year
performance period, the actual number of shares that a grant recipient receives at the end of the period may range
from 0% to 250% of the TSR PSUs granted in 2021, 0% to 200% of the TSR PSUs granted in prior years and from
0% to 200% of the CROIC PSUs granted in 2021. No CROIC PSUs were granted prior to 2021.
The fair value of the RSUs and CROIC PSUs was determined using the grant date stock price. The fair value of
the TSR PSUs was determined using a Monte Carlo simulation analysis to estimate the total shareholder return
ranking of the Company, including a comparison against the peer group over the performance periods. The expected
volatility of the Company’s common stock at the date of grant was estimated based on average volatility rates for the
Company and selected guideline public companies. The dividend yield assumption was based on the then current
annualized declared dividend. The risk-free interest rate assumption was based on observed interest rates consistent
with the three-year performance measurement period.
On June 27, 2018, our board of directors adopted the second amended and restated 2017 Omnibus Incentive
Plan (“Omnibus Plan”), as amended and restated (our “Restated Incentive Plan”). This plan constitutes an
amendment and restatement of the plan (the “Prior Plan”) as in effect immediately prior to the adoption of the
Restated Incentive Plan. The Prior Plan constituted an amendment and restatement of the plan originally adopted as
of June 15, 2017 (the “2017 Plan”). The Restated Incentive Plan provides for the grant, from time to time, at the
discretion of the board of directors or a committee thereof, of stock options, stock appreciation rights (“SARs”),
restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards
and substitute awards. The maximum number of shares of common stock that may be issued pursuant to an award
under the Restated Incentive Plan is 10,000,000 inclusive of the number of shares of common stock previously
issued pursuant to awards granted under the Prior Plan or the 2017 Plan. The maximum number of shares remaining
that may be issued is 1,368,778 as of December 31, 2021.
For the years ended December 31, 2021, 2020, and 2019 the stock-based compensation expense was
approximately $14 million, $15 million, and $9 million, respectively. For the years ended December 31, 2021, 2020
and 2019 the stock-based compensation the income tax benefit was not material.
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BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The table below summarizes the activity relating to RSUs issued under the Restated Incentive Plan during the
year ended December 31, 2021. The RSUs vest ratably over three years. Unrecognized compensation cost associated
with the RSUs at December 31, 2021 was approximately $8 million which will be recognized over a weighted-
average period of approximately two years.
Non-vested at December 31, 2020
Granted
Vested
Forfeited
Non-vested at December 31, 2021
Number of shares
Weighted-average
Grant Date Fair Value
(shares in thousands)
1,939 $
1,833 $
(774) $
(418) $
2,580 $
7.52
4.65
7.97
5.54
5.67
The table below summarizes the activity relating to the PSUs issued under the Revised Incentive Plan during the
year ended December 31, 2021. Unrecognized compensation cost associated with the PSUs at December 31, 2021 is
approximately $10 million which will be recognized over a weighted-average period of approximately two years.
Non-vested at December 31, 2020
Granted
Vested
Forfeited
Non-vested at December 31, 2021
Note 7—Defined Contribution Plan
Number of shares
Weighted-average
Grant Date Fair Value
(shares in thousands)
1,652 $
998 $
(75) $
(490) $
2,085 $
14.77
5.96
12.75
13.17
11.00
We sponsor a defined contribution retirement plan under section 401(k) of the Internal Revenue Code to assist
all full-time employees in providing for retirement or other future financial needs. Employees are eligible to
participate in the 401(k) plan on their date of hire. The 401(k) plan provided for a matching contribution of up to 6%
of an employee’s eligible compensation until June 2020. The Company temporarily suspended matching due to
COVID-19. As of January 2021, the Company reinstated the Plan's matching contributions to 100% of the first 3%
of compensation deferred by the participant. As of July 2021, the Company increased the Plan's matching
contributions to 100% of the first 6% of compensation deferred by the participant.
We expensed approximately $1.6 million, $1.0 million, and $1.7 million for the years ended December 31,
2021, 2020, and 2019, respectively, under the provisions of the 401(k) plan.
Note 8—Income taxes
The change in our effective rate from 2.8% in the year ended December 31, 2020 to (10.0)% for the year ended
December 31, 2021 is primarily due to nondeductible stock compensation, adjustments to our tax credit
carryforward balances, and changes in the valuation allowance. The key contributor to the change in our effective
rate from (523)% in the year ended December 31, 2019 to 2.8% for the year ended December 31, 2020 is due to the
valuation allowance recorded in 2020 and the recognition of U.S. federal general business credits in 2019 related to
the 2017 and 2018 tax periods.
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BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Income tax expense (benefit) consisted of the following:
Year Ended December 31,
2021
2020
(in thousands)
2019
Current taxes:
Federal
State
Total current taxes
Deferred taxes:
Federal
State
Total deferred taxes
$
— $
— $
581
581
832
—
832
828
828
2,653
(10,699)
(8,046)
Total current and deferred taxes
$
1,413 $
(7,218) $
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
—
227
227
(36,756)
(21)
(36,777)
(36,550)
Federal statutory rate
State, net of federal tax benefit
Nondeductible compensation
Effect of permanent differences
Tax credits - Prior Year
Tax credits - Current Year
State return to provision
Change in valuation allowance
Effective tax rate
Year Ended December 31,
2021
2020
2019
21.0 %
3.7 %
(24.5) %
(4.7) %
(29.5) %
21.5 %
(0.2) %
2.7 %
(10.0) %
21.0 %
6.3 %
— %
(0.6) %
4.9 %
1.1 %
(1.1) %
(28.8) %
2.8 %
21.0 %
8.9 %
— %
0.2 %
(546.4) %
— %
(6.6) %
0.0 %
(522.9) %
128
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Index to Financial Statements and Supplementary Data
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Significant components of the deferred tax assets and liabilities are as follows:
Deferred tax assets:
Net operating loss carryforwards
Accruals
Asset retirement obligations
Derivative instruments
Tax credits
Other
Subtotal
Valuation allowance
Total deferred tax assets
Deferred tax liabilities:
Book tax differences in property basis
Total deferred tax liabilities
Net deferred tax liability
Year Ended December 31,
2021
2020
(in thousands)
$
40,846 $
11,731
44,437
12,776
61,044
3,551
174,385
(77,546)
96,839
(98,670)
(98,670)
$
(1,831) $
21,205
14,208
43,518
5,654
62,058
4,946
151,589
(77,923)
73,666
(74,677)
(74,677)
(1,011)
As of December 31, 2021, the Company had approximately $181 million of federal net operating loss (“NOL”)
carryforwards and $49 million of state NOL carryforwards. The vast majority of the federal net operating loss
carryovers have no expiration date. State net operating loss carry forwards will expire in varying amounts beginning
after taxable year ended 2027. In addition, as of December 31, 2021, the Company had US federal general business
tax credit carryforwards totaling $54 million and state tax credits of $9 million ($7 million net of federal benefit),
which, if unused, will expire after taxable years ended 2037 and 2033, respectively.
In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all
of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent
upon the generation of future taxable income of the appropriate character during the periods in which those deferred
income tax assets would be deductible. We consider the scheduled reversal of deferred income tax liabilities and
projected future income for this determination. Due to the history of losses in recent years, management continues to
believe that it is more likely than not that a large portion of our deferred tax assets would not be realized.
Accordingly, we recorded a valuation allowance on our deferred tax assets for the years ended December 31, 2021
and 2020 in the amount of $78 million.
Unrecognized tax benefits - January 1
Prior year - change
Current year - change
Unrecognized tax benefits - December 31
Year Ended December 31,
2021
2020
(in thousands)
— $
—
—
— $
13,892
(13,892)
—
—
$
$
During the third quarter 2020, the Internal Revenue Service issued final regulations implementing interest
expense deduction limitation rules under section 163(j) of the Internal Revenue Code. The final regulations changed
certain rules on the computation and limitation of interest expense amounts and are applicable for tax years
beginning on or after November 13, 2020. Early adoption is permitted for tax years beginning after December 31,
2017. We assessed the impact of these regulations being issued in 2020. As a result, we recognized the entirety of its
129
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Index to Financial Statements and Supplementary Data
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
$14 million of uncertain tax benefits that were recorded as of December 31, 2019. The recognition of these uncertain
tax benefits did not affect the effective tax rate. No penalties or interest expense have been accrued on unrecognized
tax benefits in the periods presented.
We had no material uncertain tax positions at December 31, 2021 or 2020. We do not believe that the total
unrecognized benefits will significantly increase within the next 12 months.
We are subject to taxation in the United States and various state jurisdictions. We are not currently under audit
by any federal or state income tax authority. The 2018 thru 2021 federal and 2017 thru 2021 state tax years generally
remain open to examination under the respective statute of limitations.
Note 9—Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows
Other current assets reported on the consolidated balance sheets included the following:
Prepaid expenses
Materials and supplies
Prepaid deposits
Oil inventories
Other
Year Ended December 31,
2021
2020
(in thousands)
$
26,840 $
9,533
6,415
2,933
225
Total other current assets
$
45,946 $
3,580
11,666
12
3,490
652
19,400
Other non-current assets at December 31, 2021 and December 31, 2020 included approximately $5 million and
$7 million of deferred financing costs, net of amortization, respectively. During the year ended December 31, 2021
the allowance for doubtful accounts decreased by approximately $1.3 million, which represented collection of past
due amounts and the reversal of that portion of the allowance to the consolidated statements of operations.
130
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Index to Financial Statements and Supplementary Data
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Accounts payable and accrued expenses on the consolidated balance sheets included the following:
Year Ended December 31,
2021
2020
(in thousands)
Accounts payable - trade
Accrued expenses
Royalties payable
Greenhouse gas liability - current portion
Taxes other than income tax liability
Accrued interest
Dividends payable
Asset retirement obligation - current portion
Other
$
17,699 $
62,962
24,816
7,513
8,273
10,736
4,800
20,000
725
Total accounts payable and accrued expenses
$
157,524 $
11,055
43,452
15,150
35,554
10,118
10,783
—
25,000
873
151,985
At December 31, 2021 other non-current liabilities included approximately $18 million non-current greenhouse
gas liability, which is due 2024. At December 31, 2020 we had no non-current greenhouse gas liability as the entire
amount was due in 2021 and thus classified as a current liability in accounts payable and accrued expenses.
Supplemental Information on the Statement of Operations
For the years ended December 31, 2021, 2020, and 2019 other operating expenses were $3 million, $6 million,
and $5 million respectively. For the year ended December 31, 2021, other operating expenses mainly consisted of
expensing $3 million of unamortized debt issuance costs related to the 2017 RBL facility, approximately $3 million
of supplemental property tax assessments, royalty audit charges and tank rental costs, and $2 million of various
other costs such as excess abandonment costs and legal fees, partially offset by approximately $2 million of gain on
the sale of properties and over $2 million of income from employee retention credits. For the year ended December
31, 2020, other operating expenses included of $3 million of excess abandonment costs, $2 million of oil tank
storage fees, and $1 million of drilling rig standby charges. For the year ended December 31, 2019 other operating
income was $5 million, which mainly consisted of the costs in excess of the liability, due to earlier than anticipated
abandonment and spending, related to our long-term abandonment activities and obligation.
131
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Index to Financial Statements and Supplementary Data
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Supplemental Cash Flow Information
Supplemental disclosures to the consolidated statements of cash flows are presented below:
Supplemental Disclosures of Significant Non-Cash Operating
Activities:
Greenhouse gas liability - reclassification from long-term to
current liability
$
Supplemental Disclosures of Significant Non-Cash Investing
Activities:
Year Ended December 31,
2021
2020
(in thousands)
2019
— $
33,376 $
—
Material inventory transfers to oil and natural gas properties $
3,424 $
1,596 $
10,056
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized
Income taxes payments (refunds)
$
$
29,211 $
699 $
29,962 $
222 $
30,720
(2)
Cash and cash equivalents consists primarily of highly liquid investments with original maturities of three
months or less and are stated at cost, which approximates fair value. As part of our cash management system, we use
a controlled disbursement account to fund cash distribution checks presented for payment by the holder. Checks
issued but not yet presented to banks may result in overdraft balances for accounting purposes, and if so, are
included in accounts payable and accrued expenses in the consolidated balance sheets. Such amounts are immaterial
as of December 31, 2021 and December 31, 2020.
Note 10—Acquisitions and Divestitures
2021
C&J Well Services Acquisition
On October 1, 2021, we acquired one of the largest well servicing and abandonment business in California,
which operates as CJWS. The purchase price was $53 million, including closing adjustments mainly related to
working capital, which we funded with cash on hand of $51 million in 2021 and $2 million in 2022. The CJWS
transaction costs were approximately $3 million. The acquired business activities are owned and operated by C&J
Well Services, a wholly-owned subsidiary of Berry Corp. formed for the purposes of acquiring these businesses and
establishing an independent well services and abandonment company.
The CJWS transaction was accounted for as a business combination under the acquisition method of
accounting. When determining the fair values of assets acquired and liabilities assumed, management made
significant estimates, judgments and assumptions. The assets acquired and liabilities assumed are included in the
Well Servicing and Abandonment segment. The Company's preliminary allocation of the purchase price, including
preliminary working capital adjustments, to the estimated fair value of the CJWS net assets is as follows:
132
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Index to Financial Statements and Supplementary Data
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Accounts receivable
Property and equipment
Other assets
Total assets acquired
Accounts payable and accrued expenses assumed
Net assets acquired
October 1, 2021
(in thousands)
$
$
$
17,254
45,099
1,700
64,053
(10,927)
53,126
The allocation of the purchase price to C&J Well Services net tangible assets and liabilities as of October 1,
2021, is preliminary and subject to revisions to the fair value calculations for the identifiable assets and liabilities.
The final purchase price allocation could differ from the preliminary allocation noted in the summary above. The
acquired property and equipment is stated at fair value, and depreciation on the acquired property and equipment is
computed using the straight-line method over the estimated useful lives of each asset.
The unaudited pro forma information presented below has been prepared to give effect to the C&J Well
Services Acquisition as if it had occurred at the beginning of the periods presented. The unaudited pro forma
information includes the effects from the allocation of the acquisition purchase price on depreciation and
amortization as well as the CJWS acquisition costs charged to earnings during the 2021 period. The unaudited pro
forma information is presented for illustration purposes only and is based on estimates and assumptions the
Company deemed appropriate. The following unaudited pro forma information is not necessarily indicative of the
results that would have been achieved if the C&J Well Services Acquisition had occurred in the past, and should not
be relied upon as an indication of the operating results that the Company would have achieved if the acquisition had
occurred at the beginning of the periods presented, and our operating results, or the future results.
Pro Forma
Year Ended December 31,
2021
2020
$
$
(unaudited)
(in thousands)
664,549 $
740 $
657,796
(250,884)
Revenue
Net income (loss)
Placerita Divestiture
In October 2021, our development and production segment completed the sale of our Placerita Field property in
the Ventura Basin in Los Angeles County, California for approximately $14 million. We have recorded a gain on the
sale of approximately $2 million.
2020
In May 2020, we acquired approximately 740 net acres in the North Midway Sunset Field for approximately
$5 million. We paid $2 million at closing and the remaining $3 million was paid following our first production from
this property, in the fourth quarter 2020. This property is adjacent to, and extends, our existing producing area and
we have identified numerous future drilling locations. We believe additional opportunities exist in other productive
reservoirs of this property. We also acquired all existing idle wells on this property, some of which we plan to return
to production in the near future as price and strategy dictate. We will plug and abandon the remaining idle wells
pursuant to our California idle well management plan. We recorded a $6 million liability for asset retirement
obligations of the existing wells on this property.
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BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
We also acquired approximately 267 acres in McKittrick Field which will allow us to continue development of
the 21Z mineral fee and leases without requiring written approval from a third party surface fee owner for
infrastructure on or across the surface fee property. The purchase price was not material.
2019
During 2019 we had various property acquisitions of approximately $2.9 million that individually were not
significant.
Note 11—Earnings Per Share
We calculate basic earnings (loss) per share by dividing net income (loss) by the weighted-average number of
common shares outstanding for each period presented. Common shares issuable upon the satisfaction of certain
conditions pursuant to a contractual agreement, are considered common shares outstanding and are included in the
computation of net earnings (loss) per share.
The RSUs and PSUs are not a participating security as the dividends are forfeitable. No incremental RSU or
PSU shares were included in the diluted EPS calculation as their effect was anti-dilutive under the “if-converted”
method for the years ended December 31, 2021 and 2020. The incremental RSU and PSU shares of 572,000 for the
year ended December 31, 2019 were included in the diluted EPS calculation as their effect was dilutive under the
“if-converted” method.
Basic EPS calculation
Net (loss) income
Weighted-average shares of common stock outstanding
Basic (loss) earnings per share
Diluted EPS calculation
Net (loss) income
Weighted-average shares of common stock outstanding
Dilutive effect of potentially dilutive securities(1)
Weighted-average common shares outstanding - diluted
Diluted (loss) earnings per share
__________
Year Ended December 31,
2021
2020
2019
(in thousands except per share amounts)
$
$
$
$
(15,542) $
(262,895) $
80,209
79,802
(0.19) $
(3.29) $
(15,542) $
(262,895) $
80,209
—
80,209
79,802
—
79,802
(0.19) $
(3.29) $
43,539
81,379
0.54
43,539
81,379
572
81,951
0.53
(1) We excluded 3.3 million and 0.1 million of combined RSUs and PSUs from the diluted weighted-average common shares outstanding
because their effect was anti-dilutive for the years ended December 31, 2021 and 2020, respectively.
Note 12—Revenue Recognition
We account for revenue in accordance with the Accounting Standards Codification 606, Revenue from
Contracts with Customers, using the modified retrospective method.
We adopted the practical expedient related to disclosing the aggregate amount of the transaction price allocated
to performance obligations that are unsatisfied at the end of the reporting period. The performance obligations that
are unsatisfied at the end of a reporting period relate solely to future volumes that we have yet to sell. As such, these
are wholly unsatisfied performance obligations as each unit of product represents a separate performance obligation
as well as a wholly unsatisfied promise to transfer a distinct good that forms part of a single performance obligation.
134
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Index to Financial Statements and Supplementary Data
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
We derive revenue from sales of oil, natural gas and natural gas liquids (“NGL”), with the remaining revenue
generated from sales of electricity and marketing activities. Effective October 1, 2021, we completed the acquisition
of CJWS, a well servicing and abandonment business. Revenue from CJWS is primarily generated from well
servicing and abandonment business.
The following is a description of our principal activities from which we generate revenue. Revenues are
recognized when a customer obtains control of promised goods or services, in an amount that reflects the
consideration we expect to receive in exchange for those goods or services.
Oil, Natural Gas and NGLs
We recognize revenue from the sale of our oil, natural gas and NGL production when delivery has occurred and
control passes to the customer. Our oil and natural gas contracts are short term, typically less than a year and our
NGL contracts are both short and long term. We consider our performance obligations to be satisfied upon transfer
of control of the commodity. Our commodity sales contracts are indexed to a market price or an average index price.
We recognize revenue in the amount that we expect to receive once we are able to adequately estimate the
consideration (i.e., when market prices are known). Our contracts with customers typically require payment within
30 days following invoicing.
Service Revenue
We recognize service revenue from the upstream well servicing and abandonment business upon delivery of the
service to the customer. These services are consumed by our customers when they are provided on their sites.
Revenue is recognized as performance obligations have been completed on a daily basis, when all of the proper
customer approvals are obtained. We do not have any long-term service contracts; nor do we have revenue expected
to be recognized in any future year related to remaining performance obligations or contracts with variable
consideration related to undelivered performance obligations. Our contracts with customers typically require
payment within 30-60 days following invoicing.
Electricity Sales
The electrical output of our cogeneration facilities that is not used in our operations is sold to the California
market based on market pricing, which includes capacity payments. The majority of the portion sold from certain of
our cogeneration facilities is sold under contracts to California utility companies, based on the market pricing.
Revenue is recognized over time when obligations under the terms of a contract with our customer are satisfied;
generally, this occurs upon delivery of the electricity. Revenue is measured as the amount of consideration we
expect to receive based on average index pricing with payment due the month following delivery. Capacity
payments are based on a fixed annual amount per kilowatt hour and monthly rates vary based on seasonality, which
is consistent with how we earn the capacity payment. Capacity payments are settled monthly. We consider our
performance obligations to be satisfied upon delivery of electricity or as the contracted amount of energy is made
available to the customer in the case of capacity payments. We report electricity revenue as electricity sales on our
consolidated statements of operations.
Marketing Revenue
Marketing revenue primarily includes our activities associated with transporting and marketing third-party
volumes. These sales are made under the same agreements with the same purchaser as our natural gas sales
discussed above. We consider our performance obligations to be satisfied upon transfer of control of the commodity.
Revenues are presented excluding costs incurred prior to transferring control of these volumes to the customer, or
the costs to purchase these volumes when we are acting as the principal. The revenues and expenses related to the
sale and purchase of third-party volumes are presented separately as marketing revenue and marketing expenses on
the consolidated statements of operations.
135
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Index to Financial Statements and Supplementary Data
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Disaggregated Revenue
As a result of adoption of this standard, we are now required to disclose the following information regarding
revenue from contracts with customers on a disaggregated basis.
Oil sales
Natural gas sales
Natural gas liquids sales
Service revenue
Electricity sales
Marketing revenues
Other revenues
Revenues from contracts with customers
(Losses) gains on oil and gas sales derivatives
Year Ended December 31,
2021
2020
(in thousands)
2019
$
587,613 $
362,976 $
543,634
32,679
5,183
35,840
35,636
3,921
477
701,349
(156,399)
14,041
1,646
—
25,813
1,426
150
406,052
117,781
19,391
2,571
—
29,397
2,094
316
597,403
(37,998)
559,405
Total revenues and other
$
544,950 $
523,833 $
Note 13—Segment Information
As of October 1, 2021, we have operated in two business segments: (i) development and production (ii) well
servicing and abandonment. The development and production segment is engaged in the development and
production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as
well as Utah. On October 1, 2021, we completed the acquisition of an upstream well servicing and abandonment
businesses in California, which became a reportable segment (wells servicing and abandonment) under U.S. GAAP.
Prior to October 1, 2021, we did not have more than one reportable segment, thus no prior period segment
information has been presented.
The following table represents selected financial information for the periods presented regarding the Company's
business segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the
financial information for the Company on a consolidated basis.
Revenues - excluding hedges
Net income (loss) before income taxes
Adjusted EBITDA
Capital expenditures
Total assets
Year Ended December 31, 2021
Development &
Production
Well Servicing and
Abandonment
Corporate/
Eliminations
Consolidated
Company
665,509 $
82,826 $
251,146 $
129,479 $
(in thousands)
35,840 $
1 $
4,310 $
1,029 $
— $
(96,956) $
(43,310) $
2,211 $
701,349
(14,129)
212,146
132,719
1,450,157 $
81,093 $
(74,771) $
1,456,479
$
$
$
$
$
Adjusted EBITDA is the measure reported to the chief operating decision maker (CODM) for purposes of
making decisions about allocating resources to and assessing performance of each segment. Adjusted EBITDA is
calculated 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.
136
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Index to Financial Statements and Supplementary Data
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Year Ended December 31, 2021
Development &
Production
Well Servicing and
Abandonment
Corporate/
Eliminations
Consolidated
Company
(in thousands)
$
82,825 $
1 $
(98,368) $
(15,542)
—
—
136,915
117,822
(87,625)
109
1,100
—
—
—
2,974
—
—
—
—
1,335
31,964
1,413
4,606
—
—
2,992
12,683
1,400
31,964
1,413
144,495
117,822
(87,625)
3,101
13,783
2,735
$
251,146 $
4,310 $
(43,310) $
212,146
Adjusted EBITDA reconciliation to net
income (loss):
Net income (loss)
Add (Subtract):
Interest expense
Income tax expense
Depreciation, depletion, and
amortization
Losses on derivatives
Net cash paid for scheduled derivative
settlements
Other operating expenses
Stock compensation expense
Non-recurring costs
Adjusted EBITDA
Note 14—Subsequent Events
Piceance Divestiture
In January 2022, we completed the divestiture of all of our natural gas properties in Colorado, which were in the
Piceance basin. The divestiture closed with no material impact to the financial statements.
Antelope Creek Acquisition
In February 2022, we completed the acquisition of oil and gas producing assets in the Antelope Creek area of
Utah for approximately $18 million. These assets are adjacent to our existing Uinta assets and prior to our
acquisition produced approximately 700 boe/d.
137
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BERRY CORPORATION (bry)
SUPPLEMENTAL OIL & NATURAL GAS DATA
(Unaudited)
The following should be read in conjunction with our Consolidated Financial Statements and Notes to
Consolidated Financial Statements.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or
expensed, are presented below:
Property acquisition costs:
Proved(1)
Unproved
Exploration costs
Development costs(2)
Total costs incurred
__________
2021
Year Ended December 31,
2020
(in thousands)
2019
$
$
1,256 $
11,597 $
—
—
—
—
153,821
96,971
155,077 $
108,568 $
5,382
—
—
277,511
282,893
(1)
Included in proved property acquisition costs for the year ended December 31, 2021, 2020 and 2019 are non-cash additions related to the
estimated future asset retirement obligations of the Company's oil and gas properties of $0.4 million, $5.7 million and $2.4 million,
respectively.
(2)
Included in development costs for the year ended December 31, 2021, 2020 and 2019 are non-cash additions related to the estimated future
asset retirement obligations of the Company's oil and gas properties of $32.5 million, $10.2 million and $65.7 million, respectively.
Oil and Natural Gas Capitalized Costs
Aggregate capitalized costs related to oil, natural gas and NGL production activities, support equipment and
facilities, and natural gas plants and pipelines with applicable accumulated depreciation, depletion and amortization
are presented below:
Proved properties
Unproved properties
Total proved and unproved properties
Less accumulated depreciation, depletion and amortization
Year Ended December 31,
2021
2020
(in thousands)
$
1,308,378 $
1,181,865
291,514
1,599,892
(356,509)
311,195
1,493,060
(252,325)
Net capitalized costs
$
1,243,383 $
1,240,735
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BERRY CORPORATION (bry)
SUPPLEMENTAL OIL & NATURAL GAS DATA (Continued)
(Unaudited)
Results of Oil and Natural Gas Producing Activities
The results of operations for oil, natural gas and NGL producing activities (excluding items such as corporate
overhead, interest costs and reorganization items, net) are presented below:
Net revenues from production:
Oil, natural gas and NGL sales
Electricity sales
Other production-related revenue
Total net revenues from production(1)
Operating costs for production:
Lease operating expenses
Electricity generation expenses
Transportation expenses
Production-related general and administrative expenses
Taxes, other than income taxes
Other production-related costs
Year Ended December 31,
2021
2020
(in thousands)
2019
$
625,475 $
378,663 $
565,596
35,636
4,245
665,356
236,048
23,148
6,897
1,338
46,278
3,811
25,813
1,431
405,907
186,348
16,608
6,938
1,766
34,987
1,380
29,397
2,258
597,251
216,294
19,490
8,059
2,735
40,254
2,073
Total operating costs for production
317,520
248,027
288,905
Other costs:
Depreciation, depletion and amortization
Impairment of long-lived assets
Other operating expenses
Total other costs
Pretax income (loss)
Income tax expense (benefit)
Results of operations
__________
137,991
—
2,353
140,344
207,492
57,117
135,361
289,085
5,673
430,119
(272,239)
(83,467)
$
150,375 $
(188,772) $
101,816
51,081
4,545
157,442
150,904
10,084
140,820
(1) Excludes cash paid for derivative settlements of $92 million for the year ended December 31, 2021 and excludes cash received for
scheduled derivative settlements of $142 million and $42 million for the years ended December 31, 2020 and 2019.
Income tax is calculated as if the results presented above represented a stand-alone tax filing entity by applying
the current federal and state statutory tax rates to the revenues after deducting costs, which include DD&A
allowances, after giving effect to permanent differences. See Note 8 for additional information about income taxes.
139
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Index to Financial Statements and Supplementary Data
BERRY CORPORATION (bry)
SUPPLEMENTAL OIL & NATURAL GAS DATA (Continued)
(Unaudited)
Proved Oil, Natural Gas and NGL Reserves
The Company's proved oil, natural gas and NGL reserve quantities and the related discounted future net cash
flows before income taxes are based on estimates prepared by the independent engineering firm, DeGolyer and
MacNaughton. In accordance with SEC regulations, proved reserves at December 31, 2021, 2020 and 2019 were
estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-
of-the-month price for each month, excluding escalations based upon future conditions. An analysis of the change in
the Company's net interests in estimated quantities of proved oil, natural gas, and NGL reserves, all of which are
attributable to properties located in the United States, is shown below:
Total proved reserves:
Beginning of year
Extensions and discoveries
Revisions of previous estimates
Purchases of minerals in place
Sales of minerals in place
Production
End of year
Proved developed reserves:
Beginning of year
End of year
Proved undeveloped reserves:
Beginning of year
End of year
Total proved reserves:
Beginning of year
Extensions and discoveries
Revisions of previous estimates
Purchases of minerals in place
Sales of minerals in place
Production
End of year
Proved developed reserves:
Beginning of year
End of year
Proved undeveloped reserves:
Beginning of year
End of year
Oil
mbbls
Year Ended December 31, 2021
Natural Gas
mmcf
NGLs
mbbls
Total
mboe
89,935
2,937
1,734
48
(24)
(8,829)
85,801
51,249
53,452
38,686
32,349
742
60
598
—
—
(141)
1,259
742
1,209
—
50
25,599
2,593
40,574
—
—
(6,312)
62,454
25,599
60,351
—
2,103
94,943
3,429
9,094
48
(24)
(10,022)
97,469
56,257
64,720
38,686
32,749
Oil
mbbls
Year Ended December 31, 2020
Natural Gas
mmcf
NGLs
mbbls
Total
mboe
1,180
—
(307)
—
—
(131)
742
1,054
742
127
—
44,815
—
138,422
733
(12,352)
(33,860)
—
—
(6,864)
25,599
39,063
25,599
5,752
—
104
—
(10,456)
94,943
81,667
56,257
56,756
38,686
129,773
733
(31,494)
104
—
(9,181)
89,935
74,102
51,249
55,670
38,686
140
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Index to Financial Statements and Supplementary Data
BERRY CORPORATION (bry)
SUPPLEMENTAL OIL & NATURAL GAS DATA (Continued)
(Unaudited)
Total proved reserves:
Beginning of year
Extensions and discoveries
Revisions of previous estimates
Purchases of minerals in place
Sales of minerals in place
Production
End of year
Proved developed reserves:
Beginning of year
End of year
Proved undeveloped reserves:
Beginning of year
End of year
Oil
mbbls
Year Ended December 31, 2019
Natural Gas
mmcf
NGLs
mbbls
Total
mboe
114,765
13,321
10,759
159
—
(9,231)
129,773
73,203
74,102
41,562
55,670
1,147
160,849
142,720
—
160
24
—
(151)
1,180
1,047
1,054
100
127
—
(109,323)
701
—
(7,412)
44,815
76,331
39,063
84,518
5,752
13,321
(7,302)
300
—
(10,617)
138,422
86,971
81,667
55,749
56,756
The tables above include changes in estimated quantities of natural gas reserves shown in boe using the ratio of
six mcf to one barrel.
Proved reserves increased by approximately 2 mmboe to approximately 97 mmboe for the year ended
December 31, 2021. The year ended December 31, 2021, includes 9 mmboe of positive overall revisions of previous
estimates. Positive price-driven revisions were 18 mmboe, due to the increase in commodity prices. In 2021, we
experienced negative technical revisions of 10 mmboe in California, which was partially offset by positive technical
revisions of 1 mmboe in the Rockies. The negative technical revisions resulted primarily from a strategic change in
development plans in our Hill Tulare properties to a more focused approach on infill drilling rather than extending
our proved developed area, as well as adjustments made to our thermal Diatomite development plans. Extensions
and discoveries added 3 mmboe to proved reserves.
Proved reserves decreased by approximately 43 mmboe to approximately 95 mmboe for the year ended
December 31, 2020. The year ended December 31, 2020, includes 34 mmboe of negative revisions of previous
estimates. Price-driven revisions were 31 mmboe, 91% of total revisions, and were due to the dramatic decline in
commodity prices experienced in 2020. Performance revisions were a decrease of 3 mmboe, 9% of total revisions.
Extensions and discoveries, exclusively in our California properties, added 1 mmboe to proved reserves. Negative
performance revisions as well as modest increases to extensions and discoveries were the result of very limited
development capital investment in 2020 which was necessitated by market conditions created by the COVID-19
pandemic and exacerbated by OPEC+'s dispute over production cuts.
Proved reserves decreased by approximately 4 mmboe to approximately 138 mmboe for the year ended
December 31, 2019. Extensions and discoveries, principally in our California properties, contributed 13 mmboe to
the overall change in proved reserves. These extensions included McKittrick steamflood expansions based on
delineation wells drilled in 2019, Homebase Pliocene development, as well as expansion of our thermal Diatomite
operations. The year ended December 31, 2019, includes 7 mmboe of negative revisions of previous estimates.
Negative revisions due to price were 7 mmboe and this was caused by the current commodity price environment.
Performance revisions included a decrease of 14 mmboe due to the impairment of our Piceance gas properties and
the removal of the proved undeveloped reserves related to this impairment. However, there were positive technical
141
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Index to Financial Statements and Supplementary Data
BERRY CORPORATION (bry)
SUPPLEMENTAL OIL & NATURAL GAS DATA (Continued)
(Unaudited)
revisions of 13 mmboe primarily related to the improved base performance and redevelopment in our thermal
Diatomite area.
Standardized Measure of Discounted Future Net Cash Flows
Information with respect to the standardized measure of discounted future net cash flows relating to proved
reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the
Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site
restoration and abandonment costs are derived based on current costs assuming continuation of existing economic
conditions. See Note 8 for additional information about income taxes.
Future cash inflows
Future production costs
Future development costs(1)
Future income tax expenses(2)
Future net cash flows
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future net cash flows
Representative prices:(3)
Brent Oil (bbl)
Henry Hub Natural gas (mmbtu)
__________
$
$
$
(1) Future development costs includes site restoration and abandonment costs.
Year Ended December 31,
2021
2020
2019
(in thousands, except for prices)
$
5,879,599 $
3,657,907 $
7,788,647
(2,589,043)
(2,091,021)
(808,295)
(484,358)
1,997,903
(764,632)
(830,028)
(1,646)
735,212
(219,033)
(3,623,688)
(1,106,333)
(587,487)
2,471,139
(1,005,002)
1,233,271 $
516,179 $
1,466,137
69.47 $
3.64 $
41.77 $
2.03 $
63.15
2.62
(2) Future income tax expenses are based on current statutory rates, adjusted for the tax basis of oil and gas properties and applicable tax
credits, deductions and allowances.
(3)
In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an
unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average
price used to estimate reserves is held constant over the life of the reserves.
142
(309,347)
(120,688)
(300,261)
180,825
2,649
—
11,621
1,668
—
(329,680)
(124,110)
2,762
180,673
(69,293)
339,653
116,921
215,153
(5,939)
49,388
(949,958)
(295,409)
Table of Contents
Index to Financial Statements and Supplementary Data
BERRY CORPORATION (bry)
SUPPLEMENTAL OIL & NATURAL GAS DATA (Continued)
(Unaudited)
The following table summarizes the changes in the standardized measure of discounted future net cash flows:
Standardized measure—beginning of year
$
516,179 $
1,466,137 $
1,761,546
Year Ended December 31,
2021
2020
2019
(in thousands)
Net change in sales and transfer prices and production costs
related to future production
Changes in estimated future development costs
Sales and transfers of oil, natural gas and NGLs produced during
the period
1,140,342
(1,135,565)
8,215
198,009
(336,031)
(149,806)
Net change due to extensions, discoveries and improved recovery
56,504
Purchase of minerals in place
Sales of minerals in place
Net change due to revisions in quantity estimates
Previously estimated development costs incurred during the period
Accretion of discount
Changes in production rates and other
Net change in income taxes
Net increase (decrease)
Standardized measure—end of year
830
(5)
217,921
48,488
52,015
(195,093)
(276,094)
717,092
$
1,233,271 $
516,179 $
1,466,137
The standardized measure of discounted future net cash flows is not intended to represent the replacement cost
or fair value of the Company's oil and gas properties. The data presented should not be viewed as representing the
expected cash flow from, or current value of, existing proved reserves since the computations are based on a large
number of estimates and assumptions. The required projection of production and related expenditures over time
requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual
future prices and costs are likely to be substantially different from the current prices and costs utilized in the
computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific
recognition to the computational methods utilized and the limitations inherent therein.
The following table summarizes the average sales price and production costs:
Weighted-average realized prices:
Oil without hedges (bbl)
Natural gas ($/mcf)
NGLs ($/bbl)
Production costs (per boe):
Lease operating expenses
Year Ended December 31,
2021
2020
2019
66.57 $
5.27 $
36.64 $
39.56 $
2.08 $
12.57 $
58.93
2.66
17.02
23.60 $
17.86 $
20.42
$
$
$
$
143
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Index to Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
In accordance with Exchange Act Rules 13a-15 and 15d-15, our President and Chief Executive Officer and our
Executive Vice President and Chief Financial Officer supervised and participated in our evaluation of our disclosure
controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31,
2021. Our disclosure controls and procedures are designed to provide reasonable assurance that the information
required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to
our management, including our principal executive officer and principal financial officer, as appropriate, to allow
timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time
periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and
principal financial officer concluded that our disclosure controls and procedures were effective as of December 31,
2021 at the reasonable assurance level.
Management’s Annual Report on Internal Control Over Financial Reporting and Attestation Report of the
Registered Public Accounting Firm
Our management, including our principal executive officer and principal financial officer, is responsible for
establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) under
the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of our consolidated financial statements for
external purposes in accordance with GAAP.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of the effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies
or procedures may deteriorate.
Our management assessed the effectiveness of the Company's internal control over financial reporting as of
December 31, 2021, using the criteria in Internal Control-Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this evaluation, our management
concluded that our internal control over financial reporting was effective as of December 31, 2021.
Management’s report was not subject to attestation by our independent registered public accounting firm
pursuant to rules of the Securities and Exchange Commission that permit us to provide only management’s report in
this Annual Report on Form 10-K. Therefore, this Annual Report on Form 10-K does not include such an attestation.
Changes in the Company’s Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over
financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Except as described below,
there has been no change in Berry’s internal control over financial reporting (as defined in Rules 13a-15(f) and
15d-15(f) of the Exchange Act) during the fourth quarter of 2021 that has materially affected, or is reasonably likely
to materially affect, Berry’s internal control over financial reporting.
144
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Index to Financial Statements and Supplementary Data
In the fourth quarter of 2021, Berry acquired C&J Well Services and implemented a new Enterprise Resource
Planning (ERP) system for that subsidiary following the acquisition, resulting in modifications to C&J Well Services
historical internal controls over financial reporting.
Item 9B. Other Information
None
145
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Index to Financial Statements and Supplementary Data
Item 10. Directors, Executive Officers and Corporate Governance
Part III
The information required by this Item 10 is incorporated herein by reference to our definitive Proxy Statement,
for the 2022 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2021.
Our board of directors has adopted a code of business conduct applicable to all officers, directors and
employees, which is available on our website (www.bry.com/sustainability/governance). We intend to satisfy the
disclosure requirement under Item 5.05 of Form 8-K regarding amendment to, or waiver from, a provision of our
code of business conduct by posting such information on our website at the address specified above.
Item 11. Executive Compensation
The information required by this Item 11 is incorporated herein by reference to our definitive Proxy Statement,
for the 2022 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2021.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required by this Item 12 is incorporated herein by reference to our definitive Proxy Statement,
for the 2022 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2021. See also Part II—Item 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities — Securities Authorized for Issuance Under Equity Compensation
Plans.
Item 13. Certain Relationships and Related Transactions and Director Independence
The information required by this Item 13 is incorporated herein by reference to our definitive Proxy Statement,
for the 2022 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2021.
Item 14. Principal Accounting Fees and Services
Our independent registered public accounting firm is KPMG LLP, Los Angeles, CA, Auditor Firm ID: 185.
The information required by this Item 14 is incorporated herein by reference to our definitive Proxy Statement,
for the 2022 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2021.
146
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Index to Financial Statements and Supplementary Data
Part IV
Item 15. Exhibits
Exhibit
Number
Description
2.1 Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry
Petroleum Company, LLC, dated January 25, 2017 (incorporated by reference to Exhibit 2.1 to the
Company’s Registration Statement on Form S-1 (File No. 333-226011))
3.1 Second Amended and Restated Certificate of Incorporation of Berry Petroleum Corporation
(incorporated by reference to Exhibit 3.1 of Form 8-K filed February 19, 2020)
3.2 Third Amended and Restated Bylaws of Berry Corporation (bry) (incorporated by reference to
Exhibit 3.2 of Form 8-K filed February 19, 2020)
3.3 Certificate of Designation of Series A Convertible Preferred Stock of Berry Petroleum Corporation
(incorporated by reference to Exhibit 3.4 to the Company’s Registration Statement on Form S-1 (File
No. 333-226011))
3.4 Certificate of Amendment to Certificate of Designation (incorporated by reference to Exhibit 3.1 of
Form 8-K filed July 30, 2018)
4.1 Form of Common Stock Certificate of Berry Petroleum Corporation (incorporated by reference to
Exhibit 4.1 to the Company’s Registration Statement on Form S-1 (File No. 333-226011))
4.2 Form of Series A Convertible Preferred Stock Certificate of Berry Petroleum Corporation
(incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (File
No. 333-226011))
4.3 Indenture dated as of February 8, 2018, among Berry Petroleum Company, LLC, Berry Petroleum
Corporation and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the
Company’s Registration Statement on Form S-1 (File No. 333-226011))
4.4 Description of Registrant’s Securities Registered Under Section 12 of the Exchange Act of 1834
(incorporated by reference to Exhibit 4.4 to the Company’s Annual Report on Form 10-K filed
February 27, 2020)
10.1 Assignment Agreement, dated February 28, 2017, between Linn Acquisition Company, LLC and
Berry Petroleum Corporation (incorporated by reference to Exhibit 10.1 to the Company’s
Registration Statement on Form S-1 (File No. 333-226011))
10.2 Transition Services and Separation Agreement, dated February 28, 2017, by and among Berry
Petroleum Company, LLC, Linn Energy, LLC and certain of its affiliates and subsidiaries
(incorporated by reference to Exhibit 10.2 to the Company’s Annual Report on Form 10-K filed
March 8, 2019)
10.3 Amended and Restated Stockholders Agreement between Berry Petroleum Corporation and certain
holders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed July 30, 2018)
10.4 Amended and Restated Registration Rights Agreement, dated June 28, 2018, among Berry Petroleum
Corporation and the holder party thereto (incorporated by reference to Exhibit 10.4 to the Company’s
Registration Statement on Form S-1 (File No. 333-226011))
10.5† Second Amended and Restated Executive Employment Agreement, dated March 1, 2020, between
Berry Petroleum Company, LLC and Arthur “Trem” Smith (incorporated by reference to Exhibit
10.13 to the Company’s Annual Report on Form 10-K filed February 27, 2020)
147
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Index to Financial Statements and Supplementary Data
Exhibit
Number
Description
10.6† Second Amended and Restated Executive Employment Agreement by and between Berry Petroleum
Company, LLC and Cary D. Baetz, effective March 1, 2020 (incorporated by reference to Exhibit
10.1 of Form 8-K filed March 30, 2020)
10.7† Amended and Restated Executive Employment Agreement by and between Berry Petroleum
Company, LLC and Danielle Hunter, effective March 1, 2020 (incorporated by reference to Exhibit
10.7 to the Company’s Annual Report on Form 10-K filed February 24, 2021)
10.8† Employment Agreement by and between Berry Petroleum Company, LLC and Fernando Araujo,
effective August 14, 2020 (incorporated by reference to Exhibit 10.1 of Form 8-K filed August 20,
2020)
10.9† Second Amended and Restated Executive Employment Agreement by and between Berry Petroleum
Company, LLC and Gary A. Grove, effective March 1, 2020 (incorporated by reference to Exhibit
10.2 of Form 8-K filed March 30, 2020)
10.10† Transition and Separation Agreement and General Release of Claims entered into effective July 31,
2020 by and between Gary A. Grove and Berry Petroleum Company, LLC (incorporated by reference
to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed August 5, 2020)
10.11† Amended and Restated Berry Petroleum Corporation 2017 Omnibus Incentive Plan, dated March 7,
2018 (incorporated by reference to Exhibit 10.8 to the Company’s Registration Statement on Form
S-1 (File No. 333-226011))
10.12† Berry Petroleum Corporation Form of Restricted Stock Unit Award Agreement for Employees other
than Executive Vice Presidents (incorporated by reference to Exhibit 10.9 to the Company’s
Registration Statement on Form S-1 (File No. 333-226011))
10.13† Berry Petroleum Corporation Form of Restricted Stock Unit Award Agreement for Executive Vice
Presidents (incorporated by reference to Exhibit 10.10 to the Company’s Registration Statement on
Form S-1 (File No. 333-226011))
10.14† Berry Petroleum Corporation Form of Director Restricted Stock Unit Award Agreement (incorporated
by reference to Exhibit 10.11 to the Company’s Registration Statement on Form S-1 (File No.
333-226011))
10.15† Berry Petroleum Corporation Form of Performance-Based Restricted Stock Unit Award Agreement
for Employees other than Executive Vice Presidents (incorporated by reference to Exhibit 10.12 to the
Company’s Registration Statement on Form S-1 (File No. 333-226011)
10.16† Berry Petroleum Corporation Form of Performance-Based Restricted Stock Unit Award Agreement
for Executive Vice Presidents (incorporated by reference to Exhibit 10.13 to the Company’s
Registration Statement on Form S-1 (File No. 333-226011)
10.17† Second Amended and Restated Berry Petroleum Corporation 2017 Omnibus Incentive Plan, dated
June 27, 2018 (incorporated by reference to Exhibit 4.3 of S-8 Registration Statement (File No.
333-226582))
10.18† Berry Petroleum Corporation 2017 Omnibus Incentive Plan dated June 15, 2017 (incorporated by
reference to Exhibit 10.15 to the Company’s Registration Statement on Form S-1 (File No.
333-226011))
10.19† Berry Petroleum Corporation Form of Restricted Stock Unit Award Agreement for Employees other
than Executive Officers (incorporated by reference to Exhibit 10.19 to the Company’s Annual Report
on Form 10-K filed March 8, 2019)
10.20† Berry Petroleum Corporation Form of Restricted Stock Unit Award Agreement for Executive Officers
(incorporated by reference to Exhibit 10.20 to the Company’s Annual Report on Form 10-K filed
March 8, 2019)
148
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Index to Financial Statements and Supplementary Data
Exhibit
Number
Description
10.21† Berry Petroleum Corporation Form of Restricted Stock Unit Award Agreement for Directors
(incorporated by reference to Exhibit 10.21 to the Company’s Annual Report on Form 10-K filed
March 8, 2019)
10.22† Berry Petroleum Corporation Form of Performance-Based Restricted Stock Unit Award Agreement
for Employees other than Executive Officers (incorporated by reference to Exhibit 10.22 to the
Company’s Annual Report on Form 10-K filed March 8, 2019)
10.23† Berry Petroleum Corporation Form of Performance-Based Restricted Stock Unit Award Agreement
for Executive Officers (incorporated by reference to Exhibit 10.23 to the Company’s Annual Report
on Form 10-K filed March 8, 2019)
10.24 Form of Indemnification Agreement (incorporated by reference to Exhibit 10.16 to the Company’s
Registration Statement on Form S-1 (File No. 333-226011))
10.25 Stock Purchase Agreement by and between Berry Petroleum Corporation, Oaktree Value
Opportunities Fund Holdings, L.P. and Oaktree Opportunities X Fund Holdings (Delaware), L.P.
dated July 17, 2018 (incorporated by reference to Exhibit 10.2 of Form 8-K filed July 30, 2018)
10.26 Stock Purchase Agreement by and between Berry Petroleum Corporation and certain funds affiliated
with Benefit Street Partners named in Schedule I thereto, dated July 17, 2018 (incorporated by
reference to Exhibit 10.3 of Form 8-K filed July 30, 2018)
10.27 Credit Agreement, dated August 26, 2021, by and among Berry Petroleum Company, LLC, as
borrower, Berry Petroleum Corporation, as guarantor, JPMorgan Chase Bank, N.A., as administrative
agent and issuing bank, and certain lenders and other parties thereto (incorporated by reference to
Exhibit 10.1 of Form 8-K filed August 27, 2021)
10.28 First Amendment to Credit Agreement, dated December 8, 2021, by and among Berry Petroleum
Company, LLC, as borrower, Berry Petroleum Corporation, as guarantor, JPMorgan Chase Bank,
N.A., as administrative agent and issuing bank, and certain lenders and other parties thereto
(incorporated by reference to Exhibit 10.1 of Form 8-K filed December 10, 2021)
21.1* List of Subsidiaries of Berry Corporation (bry)
23.1* Consent of KPMG LLP
23.2* Consent of DeGolyer and MacNaughton
31.1* Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2* Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1* Certifications of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
99.1* Report as of December 31, 2021 of DeGolyer and MacNaughton
101.INS* Inline XBRL Instance Document (the Instance Document does not appear in the Interactive Data File
because its XBRL tags are embedded within the Inline XBRL document)
101.SCH* Inline XBRL Taxonomy Extension Schema Document
101.CAL* Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* Inline XBRL Taxonomy Extension Label Linkbase Data Document
101.PRE* Inline XBRL Taxonomy Extension Presentation Linkbase Document
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
__________
(*) Filed herewith.
(†) Indicates a management contract or compensatory plan or arrangement.
149
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Index to Financial Statements and Supplementary Data
Item 16. Form 10-K Summary
Not applicable.
150
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Index to Financial Statements and Supplementary Data
GLOSSARY OF COMMONLY USED TERMS
The following are abbreviations and definitions of certain terms that may be used in this report, which are
commonly used in the oil and natural gas industry:
“AROs” means asset retirement obligations.
“Adjusted EBITDA” is a non-GAAP financial measure defined 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.
“Adjusted G&A” or “Adjusted General and Administrative Expenses” is a non-GAAP financial measure defined
as general and administrative expenses adjusted for non-cash stock compensation expense and unusual and
infrequent costs.
“Adjusted Net Income (Loss)” is a non-GAAP financial measure defined as net income (loss) adjusted for
derivative gains or losses net of cash received or paid for scheduled derivative settlements, unusual and infrequent
items, and the income tax expense or benefit of these adjustments using our effective tax rate.
“API” gravity means the relative density, expressed in degrees, of petroleum liquids based on a specific gravity
scale developed by the American Petroleum Institute.
“basin” means a large area with a relatively thick accumulation of sedimentary rocks.
“bbl” means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid
hydrocarbons.
“bcf” means one billion cubic feet, which is a unit of measurement of volume for natural gas.
“BLM” means for the U.S. Bureau of Land Management.
“boe” means barrel of oil equivalent, determined using the ratio of one bbl of oil, condensate or natural gas
liquids to six mcf of natural gas.
“boe/d” means boe per day.
“Break even” means the Brent price at which we expect to generate positive Levered Free Cash Flow.
“Brent” means the reference price paid in U.S. dollars for a barrel of light sweet crude oil produced from the
Brent field in the UK sector of the North Sea.
“btu” means one British thermal unit—a measure of the amount of energy required to raise the temperature of a
one-pound mass of water one degree Fahrenheit at sea level.
“Cap-and-trade” is a statewide program in California established by the Global Warming Solutions Act of 2006
which outlined an enforceable compliance obligation beginning with 2013 GHG emissions and currently extended
through 2030.
“CCA” or “CCAs” is an abbreviation for California carbon allowances.
151
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“Clean Water Rule” refers to the rule issued in August 2015 by the EPA and U.S. Army Corps of Engineers
which expanded the scope of the federal jurisdiction over wetlands and other types of waters.
“Completion” means the installation of permanent equipment for the production of oil or natural gas.
“Condensate” means a mixture of hydrocarbons that exists in the gaseous phase at original reservoir
temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
“CPUC” is an abbreviation for the California Public Utilities Commission.
“DD&A” means depreciation, depletion & amortization.
“Development drilling” or “Development well” means a well drilled to a known producing formation in a
previously discovered field, usually offsetting a producing well on the same or an adjacent oil and natural gas lease.
“Diatomite” means a sedimentary rock composed primarily of siliceous, diatom shells.
“Differential” means an adjustment to the price of oil or natural gas from an established spot market price to
reflect differences in the quality and/or location of oil or natural gas.
“Downspacing” means additional wells drilled between known producing wells to better develop the reservoir.
“EH&S” is an abbreviation for Environmental, Health & Safety.
“EPA” is an abbreviation for the United States Environmental Protection Agency.
“EPS” is an abbreviation for earnings per share.
“ESA” is an abbreviation for the federal Endangered Species Act.
“Exploration activities” means the initial phase of oil and natural gas operations that includes the generation of
a prospect or play and the drilling of an exploration well.
“FASB” is an abbreviation for the Financial Accounting Standards Board.
“FERC” is an abbreviation for the Federal Energy Regulatory Commission.
“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the
same individual geological structural feature or stratigraphic condition.
“FIP” is an abbreviation for Federal Implementation Plan.
“Formation” means a layer of rock which has distinct characteristics that differ from those of nearby rock.
“Fracturing” means mechanically inducing a crack or surface of breakage within rock not related to foliation or
cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.
“GAAP” is an abbreviation for U.S. generally accepted accounting principles.
“Gas” or “Natural gas” means the lighter hydrocarbons and associated non-hydrocarbon substances occurring
naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may
contain liquids.
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“GHG” or “GHGs” is an abbreviation for greenhouse gases.
“Gross Acres” or “Gross Wells” means the total acres or wells, as the case may be, in which we have a working
interest.
“Held by production” means acreage covered by a mineral lease that perpetuates a company’s right to operate a
property as long as the property produces a minimum paying quantity of oil or natural gas.
“Henry Hub” is a distribution hub on the natural gas pipeline system in Erath, Louisiana.
“Hydraulic fracturing” means a procedure to stimulate production by forcing a mixture of fluid and proppant
(usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which
increases permeability.
“Horizontal drilling” means a wellbore that is drilled laterally.
“ICE” means Intercontinental Exchange.
“Infill drilling” means drilling of an additional well or wells at less than existing spacing to more adequately
drain a reservoir.
“Injection Well” means a well in which water, gas or steam is injected, the primary objective typically being to
maintain reservoir pressure and/or improve hydrocarbon recovery.
“IOR” means improved oil recovery.
“IPO” is an abbreviation for initial public offering.
“LCFS” is an abbreviation for low carbon fuel standard.
“Leases” means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for,
produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are
generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by
them.
“Levered Free Cash Flow” is a non-GAAP financial measure defined as Adjusted EBITDA less interest
expense, dividends and capital expenditures.
“LIBOR” is an abbreviation for London Interbank Offered Rate.
“mbbl” means one thousand barrels of oil, condensate or NGLs.
“mbbl/d” means mbbl per day.
“mboe” means one thousand barrels of oil equivalent.
“mboe/d” means mboe per day.
“mcf” means one thousand cubic feet, which is a unit of measurement of volume for natural gas.
“mmbbl” means one million barrels of oil, condensate or NGLs.
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“mmboe” means one million barrels of oil equivalent.
“mmbtu” means one million btus.
“mmbtu/d” means mmbtu per day.
“mmcf” means one million cubic feet, which is a unit of measurement of volume for natural gas.
“mmcf/d” means mmcf per day.
“MTBA” is an abbreviation for Migratory Bird Treaty Act.
“MW” means megawatt.
“MWHs” means megawatt hours.
“NAAQS” is an abbreviation for the National Ambient Air Quality Standard.
“NASDAQ” means Nasdaq Global Select Market.
“NEPA” is an abbreviation for the National Environmental Policy Act, which requires careful evaluation of the
environmental impacts of oil and natural gas production activities on federal lands.
“Net Acres” or “Net Wells” is the sum of the fractional working interests owned in gross acres or wells, as the
case may be, expressed as whole numbers and fractions thereof.
“Net revenue interest” means all of the working interests, less all royalties, overriding royalties, non-
participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.
“NGA” is an abbreviation for the Natural Gas Act.
“NGL” or “NGLs” means natural gas liquids, which are the hydrocarbon liquids contained within natural gas.
“NRI” is an abbreviation for net revenue interest.
“NYMEX” means New York Mercantile Exchange.
“Oil” means crude oil or condensate.
“OPEC” is an abbreviation for the Organization of the Petroleum Exporting Countries.
“Operator” means the individual or company responsible to the working interest owners for the exploration,
development and production of an oil or natural gas well or lease.
“OSHA” is an abbreviation for the Occupational Safety and Health Act of 1970.
“OTC” means over-the-counter
“PALs” is an abbreviation for project approval letters.
“PCAOB” is an abbreviation for the Public Company Accounting Oversight Board.
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“PDNP” is an abbreviation for proved developed non-producing.
“PDP” is an abbreviation for proved developed producing.
“Permeability” means the ability, or measurement of a rock’s ability, to transmit fluids.
“PHMSA” is an abbreviation for the U.S. Department of Transportation’s Pipeline and Hazardous Materials
Safety Administration.
“Play” means a regionally distributed oil and natural gas accumulation. Resource plays are characterized by
continuous, aerially extensive hydrocarbon accumulations.
“PPA” is an abbreviation for power purchase agreement.
“Production costs” means costs incurred to operate and maintain wells and related equipment and facilities,
including depreciation and applicable operating costs of support equipment and facilities and other costs of
operating and maintaining those wells and related equipment and facilities. For a complete definition of production
costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).
“Productive well” means a well that is producing oil, natural gas or NGLs or that is capable of production.
“Proppant” means sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing
treatment.
“Prospect” means a specific geographic area which, based on supporting geological, geophysical or other data
and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential
for the discovery of commercial hydrocarbons.
“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods.
“Proved developed producing reserves” means reserves that are being recovered through existing wells with
existing equipment and operating methods.
“Proved reserves” means the estimated quantities of oil, gas and gas liquids, which, by analysis of geoscience
and engineering data, can be estimated with reasonable certainty to be economically producible from a given date
forward, from known reservoirs, and under existing economic conditions, operating methods, and government
regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that
renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the
estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably
certain that it will commence the project within a reasonable time.
“Proved undeveloped drilling location” means a site on which a development well can be drilled consistent with
spacing rules for purposes of recovering proved undeveloped reserves.
“Proved undeveloped reserves” or “PUDs” means proved reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably
certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable
certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved
undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled
within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves
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are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an
analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
“PSUs” means performance-based restricted stock units
“PURPA” is an abbreviation for the Public Utility Regulatory Policies Act.
“PV-10” is a non-GAAP financial measure and represents the present value of estimated future cash inflows
from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to
reflect the timing of future cash flows and using SEC-prescribed pricing assumptions for the period. While this
measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it
does provide an indicative representation of the relative value of the company on a comparative basis to other
companies and from period to period.
“QF” means qualifying facility.
“RCRA” is an abbreviation for the Resource Conservation and Recovery Act, which governs the management of
solid waste.
“Realized price” means the cash market price less all expected quality, transportation and demand adjustments.
“Reasonable certainty” means a high degree of confidence. For a complete definition of reasonable certainty,
refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).
“Recompletion” means the completion for production from an existing wellbore in a formation other than that in
which the well has previously been completed.
“Relative TSR” means relative total stockholder return.
“Reserves” means estimated remaining quantities of oil and natural gas and related substances anticipated to be
economically producible, as of a given date, by application of development projects to known accumulations. In
addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or
a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market
and all permits and financing required to implement the project. Reserves should not be assigned to adjacent
reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as
economically producible. Reserves should not be assigned to areas that are clearly separated from a known
accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test
results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered
accumulations).
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of
producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and
separate from other reservoirs.
“Resources” means quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A
portion of the resources may be estimated to be recoverable and another portion may be considered to be
unrecoverable. Resources include both discovered and undiscovered accumulations.
“Royalty” means the share paid to the owner of mineral rights, expressed as a percentage of gross income from
oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating
of the affected well.
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“Royalty interest” means an interest in an oil and natural gas property entitling the owner to shares of oil and
natural gas production, free of costs of exploration, development and production operations.
“RSUs” is an abbreviation for restricted stock units.
“SARs” is an abbreviation for stock appreciation rights.
“SEC Pricing” means pricing calculated using oil and natural gas price parameters established by current
guidelines of the SEC and accounting rules based on the unweighted arithmetic average of oil and natural gas prices
as of the first day of each of the 12 months ended on the given date.
“Seismic Data” means data produced by an exploration method of sending energy waves into the earth and
recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. 2-D
seismic provides two-dimensional information and 3-D seismic provides three-dimensional views.
“Spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in
terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“SPCC plans” means spill prevention, control and countermeasure plans.
“Steamflood” means cyclic or continuous steam injection.
“Standardized measure” means discounted future net cash flows estimated by applying year-end prices to the
estimated future production of proved reserves. Future cash inflows are reduced by estimated future production and
development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable,
are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and
natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
“Stimulating” means mechanically inducing a crack or surface of breakage within rock not related to foliation or
cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.
“Strip Pricing” means pricing calculated using oil and natural gas price parameters established by current
guidelines of the SEC and accounting rules with the exception of pricing that is based on average annual forward-
month ICE (Brent) oil and NYMEX Henry Hub natural gas contract pricing in effect on a given date to reflect the
market expectations as of that date.
“Superfund” is a commonly known term for CERLA.
“UIC” is an abbreviation for the Underground Injection Control program.
“Unconventional resource plays” means a resource play that uses methods other than traditional vertical well
extraction. Unconventional resources are trapped in reservoirs with low permeability, meaning little to no ability for
the oil or natural gas to flow through the rock and into a wellbore. Examples of unconventional oil resources include
oil shales, oil sands, extra-heavy oil, gas-to-liquids and coal-to-liquids.
“Undeveloped acreage” means lease acres on which wells have not been drilled or completed to a point that
would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage
contains proved reserves.
“Unit” means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to
provide for development and operation without regard to separate property interests. Also, the area covered by a
unitization agreement.
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“Unproved reserves” means reserves that are considered less certain to be recovered than proved reserves.
Unproved reserves may be further sub-classified to denote progressively increasing uncertainty of recoverability and
include probable reserves and possible reserves.
“Wellbore” means the hole drilled by the bit that is equipped for natural resource production on a completed
well. Also called well or borehole.
“Working interest” means an interest in an oil and natural gas lease entitling the holder at its expense to conduct
drilling and production operations on the leased property and to receive the net revenues attributable to such interest,
after deducting the landowner’s royalty, any overriding royalties, production costs, taxes and other costs.
“Workover” means maintenance on a producing well to restore or increase production.
“WST” is an abbreviation for well stimulation treatment.
“WTI” means West Texas Intermediate.
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
Date:
March 4, 2022
BERRY CORPORATION (bry)
/s/ A. T. Smith
A. T. “Trem” Smith
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date
Signature
Title
March 4, 2022
/s/ A. T. Smith
President and Chief Executive Officer, and Director
A. T. “Trem” Smith
(Principal Executive Officer)
Executive Vice President and Chief
Financial Officer, and Director
(Principal Financial Officer)
Chief Accounting Officer
(Principal Accounting Officer)
Director
Director
Director
Director
March 4, 2022
March 4, 2022
March 4, 2022
March 4, 2022
March 4, 2022
March 4, 2022
/s/ Cary Baetz
Cary Baetz
/s/ M. S. Helm
Michael S. Helm
/s/ Brent S. Buckley
Brent S. Buckley
/s/ Renée Hornbaker
Renée Hornbaker
/s/ Anne L. Mariucci
Anne L. Mariucci
/s/ Donald L. Paul
Donald L. Paul
159
2021 was a very productive year for the Berry
2021 was a very productive year for the Berry
additional revenue streams, as well as assist us in realizing
additional revenue streams, as well as assist us in realizing
team as we started to fulfill many of the promises
team as we started to fulfill many of the promises
we made in 2020, and we find ourselves in a position
we made in 2020, and we find ourselves in a position
to deliver top-tier returns to our shareholders. With
to deliver top-tier returns to our shareholders. With
our goal to be part of the energy transition by helping California
our goal to be part of the energy transition by helping Califor-
properly plug and decommission its significant portfolio of
nia properly plug and decommission its significant portfolio of
orphan and idle wells.
orphan and idle wells.
our new shareholder return model in place and at
our new shareholder return model in place and at
While we continue to grow and evolve as a company,
While we continue to grow and evolve as a company, we remain
industry conditions. At the same time, we continued to reduce
industry conditions. At the same time, we continued to reduce
puts Berry firmly in the top tier of returns
puts Berry firmly in the top tier of returns
we remain focused on ensuring we have a strong and healthy
focused on ensuring we have a strong and healthy culture. We
culture. We went through the process of revisiting our core
went through the process of revisiting our core values and
values and launched new values, along with a comprehensive
launched new values, along with a comprehensive engagement
engagement and implementation program for our employees.
and implementation program for our employees. At the same
At the same time, our safety record remains exceptional. In
time, our safety record remains exceptional. In fact, we did not
fact, we did not have a recordable incident in 2021. And, our
have a recordable incident in 2021. And, our Total Recordable
Total Recordable Incident Rate rate is 0.0, a company best.
Incident Rate rate is 0.0, a company best.
All of this work is centered on creating
All of this work is centered on creating
value for our shareholders. And in late
value for our shareholders. And in late
2021, we announced that in 2022 we would
2021, we announced that in 2022 we would
embark on a new shareholder return model
embark on a new shareholder return model
that was simple, easy, and predictable, just
that was simple, easy, and predictable, just
like our business model. This new model
like our business model. This new model
for E&P companies of all sizes.
for E&P companies of all sizes.
All in all, I am excited about where we are today, the growth
All in all, I am excited about where we are today, the
that we have realized, and the position we find ourselves in for
growth that we have realized, and the position we find
the future.
ourselves in for the future.
today’s oil and stock prices, we expect to deliver
today’s oil and stock prices, we expect to deliver
cash returns in the mid to high teens.
cash returns in the mid to high teens.
Throughout 2020, we committed to all of our shareholders,
Throughout 2020, we committed to all of our shareholders,
employees, and regulators that we would manage the down
employees, and regulators that we would manage the down
cycle of 2020 in a way that would allow us to emerge in a
cycle of 2020 in a way that would allow us to emerge in a
position of strength when the market improved. We were very
position of strength when the market improved. We were very
aggressive in improving our hedge position, reducing our
aggressive in improving our hedge position, reducing our
non-energy costs, and improving our safety and environmental
non-energy costs, and improving our safety and environmental
standards. Essentially, we began sowing the seeds for our
standards. Essentially, we began sowing the seeds for our
future success.
future success.
In mid-2021, we started seeing positive signs in the industry
In mid-2021, we started seeing positive signs in the industry
indicating that demand was increasing, and energy prices
indicating that demand was increasing, and energy prices
were improving. And given our head-down, focused work the year
were improving. And given our head-down, focused work the year
prior, we were in a terrific position to meet the improving
prior, we were in a terrific position to meet the improving
our non-energy costs on a sustainable basis – despite
our non-energy costs on a sustainable basis – despite
increasing commodity prices – without compromising our
increasing commodity prices – without compromising our
safety and environmental standards.
safety and environmental standards.
This brought us to very fruitful third and fourth quarters as we
This brought us to very fruitful third and fourth quarters as we
started to deliver on our commitments that we made to our
started to deliver on our commitments that we made to our
shareholders: We completed a strategic value-adding acquisition,
shareholders: We completed a strategic value-adding acquisition,
we enhanced our environmental, social, and governance efforts,
we enhanced our environmental, social, and governance efforts,
and we launched our new shareholder return model to position
and we launched our new shareholder return model to position
Berry to provide a consistent and valuable return on invest-
Berry to provide a consistent and valuable return on investment.
ment. In addition to these external activities, we continued to
In addition to these external activities, we continued to focus
focus on strengthening our culture and enhancing our team.
on strengthening our culture and enhancing our team.
In August 2021, we put in a bid to acquire C&J Well Services.
In August 2021, we put in a bid to acquire C&J Well Services.
We closed the transaction in October, and welcomed approximately
We closed the transaction in October, and welcomed approximately
900 new employees to the team. This is an exciting and important
900 new employees to the team. This is an exciting and important
acquisition for us. This will diversify our capabilities and create
acquisition for us. This will diversify our capabilities and create
EXE CU TI VE O FFI CERS
EXE CU TI VE OFFI CE R S
DIR ECTO RS
DIR ECTO RS
FERNANDO ARAUJO
FERNANDO ARAUJO
Executive Vice President
Executive Vice President
& Chief Operating Officer
& Chief Operating Officer
CARY BAETZ
CARY BAETZ
Executive Vice President
Executive Vice President
& Chief Financial Officer, Director
& Chief Financial Officer, Director
DANIELLE HUNTER
DANIELLE HUNTER
Executive Vice President,
Executive Vice President,
General Counsel & Corporate Secretary
General Counsel & Corporate Secretary
KURT NEHER
KURT NEHER
Executive Vice President, Corporate
Executive Vice President, Corporate
Development & Geoscience
Development & Geoscience
A.T. (TREM) SMITH
A.T. (TREM) SMITH
Board Chair, Chief Executive
Board Chair, Chief Executive
Officer & President
Officer & President
INVESTOR RELATIONS
INVESTOR RELATIONS
Todd Crabtree
Todd Crabtree
Berry Corporation (bry)
Berry Corporation (bry)
16000 N. Dallas Pkwy, Ste 500
16000 N. Dallas Pkwy, Ste 500
Dallas, TX 75248
Dallas, TX 75248
(661) 616-3811
(661) 616-3811
ir@bry.com
ir@bry.com
TRANSFER AGENT/REGISTRAR
TRANSFER AGENT/REGISTRAR
American Stock Transfer
American Stock Transfer
& Trust Company, LLC
& Trust Company, LLC
6201 15th Avenue
6201 15th Avenue
Brooklyn, NY 11219
Brooklyn, NY 11219
SHAREHOLDER SERVICES
SHAREHOLDER SERVICES
(718) 921 - 8124
(718) 921 - 8124
astfinancial.com
astfinancial.com
SECURITIES
SECURITIES
Berry Common Stock is traded on
Berry Common Stock is traded on
Nasdaq under the symbol BRY.
Nasdaq under the symbol BRY.
CARY BAETZ
CARY BAETZ
Executive Vice President & Chief Financial Officer
Executive Vice President & Chief Financial Officer
Berry Corporation (bry)
Berry Corporation (bry)
RAJATH SHOURIE (1) (2)
RAJATH SHOURIE (1) (2)
Independent Director
Independent Director
A.T. (TREM) SMITH
A.T. (TREM) SMITH
Board Chair, Chief Executive Officer & President
Board Chair, Chief Executive Officer & President
Berry Corporation (bry)
Berry Corporation (bry)
(C) Committee Chair
(C) Committee Chair
(1) Audit Committee
(1) Audit Committee
(2) Compensation Committee
(2) Compensation Committee
(3) Nominating & Corporate Governance Committee
(3) Nominating & Corporate Governance Committee
RENÉE HORNBAKER (1C) (2) (3)
RENÉE HORNBAKER (1C) (2) (3)
Independent Director
Independent Director
Chief Executive Officer of Storey & Gates LLC
Chief Executive Officer of Storey & Gates LLC
ANNE MARIUCCI (1) (2C) (3)
ANNE MARIUCCI (1) (2C) (3)
Lead Independent Director
Lead Independent Director
DONALD PAUL (1) (2) (3C)
DONALD PAUL (1) (2) (3C)
Independent Director
Independent Director
Executive Director of the Energy Institute,
Executive Director of the Energy Institute,
the William M. Keck Chair of Energy Resources &
the William M. Keck Chair of Energy Resources &
Research, Professor of Engineering at the University
Research, Professor of Engineering at the University
of Southern California
of Southern California
ANNUAL REPORT ON FORM 10-K FOR 2021
ANNUAL REPORT ON FORM 10-K FOR 2021
Our Form 10-K is included in this document in its entirety as filed with the SEC.
Our Form 10-K is included in this document in its entirety as filed with the SEC.
Upon request to Investor Relations, we will deliver free of charge a copy of our
Upon request to Investor Relations, we will deliver free of charge a copy of our
Form 10-K.
Form 10-K.
TOTAL SHAREHOLDER RETURN PERFORMANCE GRAPH
TOTAL SHAREHOLDER RETURN PERFORMANCE GRAPH
Our Form 10-K includes a performance graph comparing the cumulative
Our Form 10-K includes a performance graph comparing the cumulative
total return to shareholders on our common stock relative to the
total return to shareholders on our common stock relative to the
cumulative total returns of the S&P Smallcap 600, the Dow Jones U.S.
cumulative total returns of the S&P Smallcap 600, the Dow Jones U.S.
Exploration and Production indexes and the Vanguard Energy ETF (with
Exploration and Production indexes and the Vanguard Energy ETF (with
reinvestment of all dividends).
reinvestment of all dividends).
DIVIDEND PAYMENT DATES - 2022
DIVIDEND PAYMENT DATES - 2022
Quarterly fixed dividends on common stock are paid, following declaration
Quarterly fixed dividends on common stock are paid, following declaration
by the Board of Directors, on approximately the 15th day of January, April,
by the Board of Directors, on approximately the 15th day of January, April,
July and October. Any variable dividends declared by the Board pursuant
July and October. Any variable dividends declared by the Board pursuant
to our new shareholder return model will be paid on such dates
to our new shareholder return model will be paid on such dates
established by the Board.
established by the Board.
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
KPMG LLP
KPMG LLP
Dallas, TX
Dallas, TX
kpmg.com
kpmg.com
A.T. (TREM) SMITH
Board Chair,
Chief Executive Officer & President
A.T. (TREM) SMITH
Berry Corporation (bry)
Board Chair,
Chief Executive Officer & President
Berry Corporation (bry)
CAUTIONARY NOTE ON FORWARD-LOOKING STATEMENTS
CAUTIONARY NOTE ON FORWARD-LOOKING STATEMENTS
This report includes forward-looking statements involving risks and uncertainties that could materially affect our expected results of operations, financial position,
This report includes forward-looking statements involving risks and uncertainties that could materially affect our expected results of operations, financial position,
liquidity, cash flows, business strategy and business prospects, including potential growth opportunities, development and production plans, capital requirements,
liquidity, cash flows, business strategy and business prospects, including potential growth opportunities, development and production plans, capital requirements,
expected production and costs, reserves, hedging activities, return of capital, and other guidance. Factors (but not necessarily all the factors) that could cause actual
expected production and costs, reserves, hedging activities, return of capital, and other guidance. Factors (but not necessarily all the factors) that could cause actual
results to differ from anticipated results include: oil and gas price volatility; inability to generate or to obtain financing to fund capital expenditures, meet working
results to differ from anticipated results include: oil and gas price volatility; inability to generate or to obtain financing to fund capital expenditures, meet working
capital requirements and fund planned investments; price and availability of natural gas; ability to hedge price risk; and the need to comply with the hedging
capital requirements and fund planned investments; price and availability of natural gas; ability to hedge price risk; and the need to comply with the hedging
requirements under our credit agreement; availability and timing of required permits and approvals and our inability to meet existing or new conditions imposed on
requirements under our credit agreement; availability and timing of required permits and approvals and our inability to meet existing or new conditions imposed on
those permits and approvals; ability to meet our planned drilling schedule and drilling risks; the impact of current laws and regulations, and of pending or future
those permits and approvals; ability to meet our planned drilling schedule and drilling risks; the impact of current laws and regulations, and of pending or future
legislative or regulatory changes, including those related to the drilling, completion, stimulation, operation, maintenance or abandonment of wells or facilities,
legislative or regulatory changes, including those related to the drilling, completion, stimulation, operation, maintenance or abandonment of wells or facilities,
managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our
managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our
products; proved reserves estimation uncertainties; ability to replace our reserves; lower–than-expected production or reserves from development projects or
products; proved reserves estimation uncertainties; ability to replace our reserves; lower–than-expected production or reserves from development projects or
higher–than–expected decline rates; economic viability of drilled wells; changes in tax laws; competition; ability to make successful acquisitions; electricity price
higher–than–expected decline rates; economic viability of drilled wells; changes in tax laws; competition; ability to make successful acquisitions; electricity price
fluctuations and steam costs; and other material risks that appear in “Item 1A – Risk Factors” of our Form 10-K and other periodic reports filed with the SEC.
fluctuations and steam costs; and other material risks that appear in “Item 1A – Risk Factors” of our Form 10-K and other periodic reports filed with the SEC.
THE CORE VALUES THAT DEFINE OUR COMPANY.
THE CORE VALUES THAT DEFINE OUR COMPANY.
Sharpened focus.
Sharpened focus.
Renewed purpose.
Renewed purpose.
Shared vision.
Shared vision.
B
B
E
E
R
R
R
R
Y
Y
C
C
O
O
R
R
P
P
O
O
R
R
A
A
T
T
I
I
O
O
N
N
|
|
2
2
0
0
2
2
1
1
A
A
N
N
N
N
U
U
A
A
L
L
R
R
E
E
P
P
O
O
R
R
T
T
Berry Corporation (bry) | 16000 N. Dallas Pkwy, Ste 500 | Dallas, TX 75248 | (661) 616 - 3811 | ir@bry.com
Berry Corporation (bry) | 16000 N. Dallas Pkwy, Ste 500 | Dallas, TX 75248 | (661) 616 - 3811 | ir@bry.com
I N V E STO R R E L AT I O N S
I N V E STO R R E L AT I O N S