Berry Corporation (bry) 16000 N. Dallas Pkwy, Ste 500 Dallas, Texas 75248 (661) 616 - 3811 ir@bry.com
INVESTOR R EL ATIONS
www.bry.com
THE CORE VALUES THAT DEFINE OUR COMPANY
2
LETTER FROM
THE CHAIRMAN
A. T. (TREM) SMITH
Executive Chairman of the Board
Berry Corporation (bry)
The past year was a transformative year for Berry: It was
for the Legal, Finance, Human Resources, and Health, Safety
the first full year executing our expanded shareholder return
and Environmental functions. Mike Helm, Berry’s Chief
model, which generated excellent returns for our shareholders;
Accounting Officer, has stepped into the role of Chief Financial
it was the first full year to have C&J Well Services under the
Officer and will continue to serve as the Company’s Chief
Berry umbrella and we announced and initiated the Berry
Accounting Officer. Cary Baetz, our former CFO, and a director
succession plan.
since 2017, served as a special advisor to Berry’s executive
team through February of 2023.
Berry is committed to providing solid returns to our shareholders.
Last year, through the utilization of its shareholder return model,
I am very proud that all of these critical leadership roles
Berry provided shareholders cash returns of $1.78 per share
were filled from within. This fulfills a commitment I made to
through fixed and variable dividends, plus share buybacks of
employees to ensure there were personal and professional
more than $51 million, positioning us as a leading returner
growth opportunities at Berry for those who demonstrated our
of capital. The current shareholder return model continues
Core Values and the ability to effectively meet our objectives.
to exemplify how Berry can evolve its model to benefit
The transition has been smooth, and I am excited for this team
shareholders without compromising the core business or
to take Berry forward into successful future years.
changing the operations strategy.
C&J Well Services continued to perform well, and in 2022,
the Company’s value-creating shareholder return model,
they plugged more than 2,800 wells. This important work is
ability to generate significant free cash flow, and portfolio of oil
key to the state and federal mandates designed to address the
producing assets are the keys to Berry’s continued success.
potential environmental and safety hazards associated with
abandoned oil wells at the end of their productive life. Our
It has been my privilege and honor to serve as
In addition to the deep talent pool and our dynamic leaders,
strategic acquisition of C&J Well Services not only aligns with
these important environmental goals, but also contributed to
our strong financial performance.
As we announced in November 2022, as of January 1, 2023,
I transitioned from President & CEO and Chairman of the
Board to Executive Chairman of the Board, while Berry’s Chief
Operating Officer (COO), Fernando Araujo, was elevated to
Berry’s President and CEO, and Chairman of the
Board for the last five years. I assume my role
as Executive Chairman of the Board confident
that Fernando and the new leadership team are
positioned to excel. The talent is strong, the
assets are strong, and the finances are strong.
Berry’s Chief Executive Officer (CEO). Fernando is a terrific
Berry will continue to do what it does best and
leader who has exhibited strong operational acumen, managing
our assets to deliver outstanding shareholder returns. His
strong technical innovation, flexibility, and leadership, as well
as his ability to deliver strong health, safety, and environmental
results, will be instrumental for the future success of Berry. In
addition, Danielle Hunter, Berry’s former General Counsel and
Corporate Secretary, is now our President, with responsibility
control what it can to continue to deliver on our
promises to all stakeholders.
A.T. (TREM) SMITH
Executive Chairman of the Board
Berry Corporation (bry)
33
( ) Financially and operationally, 2022 was a good
year for Berry. Once again, Berry was able to
demonstrate the incredible quality of its assets,
and ability to navigate through California’s unique
regulatory environment. Berry’s balance sheet
is strong, and the Company continued to produce
substantial returns for its shareholders.
4
FINANCIAL
In 2022, Berry generated $250 million of net
Since its IPO, Berry has returned a total of $328 million to its
income and $380 million of adjusted EBITDA(1).
Berry produced $361 million of cash flows from operating
activities and $200 million in adjusted free cash flow(1), which
was previously referred to as “discretionary free cash flow.”
This $200 million allowed the Company to return a total $189
million to its shareholders in the form of dividends and share
shareholders through dividends and buybacks. The Company
has proven that it can generate significant free cash flows, given
the quality of its assets and ability to efficiently manage its
operations to consistently deliver strong shareholder returns.
In 2022, the Company’s E&P and Corporate Capital
Expenditures totaled $145 million. C&J Well Services was
responsible for $8 million of the total CapEx, which was in line
repurchases. This equates to roughly 27% of our current market
capitalization returned in just one year. This is industry leading
with the annual guidance.
and a record for the Company.
Berry delivered these returns while maintaining flat production
levels, net of acquisition and divestiture activity, and by applying
the right technology and reservoir management practices and
increasing workover and sidetrack activity to access more of the
tremendous amount of oil resources in its assets. Berry also
achieved a reserve replacement ratio of 236%.
Since Berry launched its shareholder return model on January
1, 2022, it has provided shareholders, through fixed and variable
dividends, cash returns of $1.78 per share. Specifically for 2022,
Berry returned $138 million of fixed and variable dividends and
$51 million of share repurchases to shareholders.(1)
Berry was also able to efficiently manage its expenses. One
critical tactic the Company employed was hedging. In 2022,
hedges were successful for both oil sales and natural gas
purchases. The Company strategically used hedging to help
cover the fixed costs, including the capital to keep production
flat, interest on our notes, and dividends.
Berry finished 2022 with
$46 million in cash on the
balance sheet and $206 million
available for borrowing under
the Company’s revolving
credit facilities.
(1) See https://ir.bry.com/ for a discussion of these performance and non-GAAP measures, including a reconciliation of the most closely related GAAP measure.
3
The foundation of Berry’s business model continues to be its base
production, which is the production that comes from existing producing
wells, and on average, accounts for approximately 90% of the Company’s
total annual production before it drills a new well. The Company’s 2022
production results demonstrated the ability to leverage base
“optimization” efforts.
Through enhanced data gathering and surveillance activity,
The permitting environment in California for 2022 was an
Berry was able to identify opportunities and further optimize
evolving one, with the lead agency responsible for compliance
its steam injection strategies, which allowed the Company
with the environmental review process shifting during the
to improve recovery and production rates from its existing
year from the state to the county. Berry continuously rose
California oil fields.
to the challenge of a dynamic regulatory environment,
successfully securing new drill permits, in addition to
In 2022, Berry’s Hill Tulare property reached an all-time peak
permits for workovers and sidetracks, sustaining the ability
production rate attributed primarily to the new techniques
to access and develop our oil resources.
that were implemented, including a sizeable acid stimulation
program, injector workovers, and steam reallocation that
enhanced the property’s production capacity.
64
PRODUCTION( ) EMPLOYEES & WORK CULTURE
Berry’s people are its strongest
differentiator and primary
drivers of the Company’s
success. Because of this,
the Company understands
that employee engagement
is vital to creating a vibrant
work culture for its people.
It promotes commitment and
retention, which not only
creates a more productive
work environment, but also
helps reduce costs and increase
efficiencies by reducing
employee turnover.
The Company continued its Core Values work in 2022 by
engaging with its employees in intensive Core Values training.
CEO Trem Smith personally led most of the Core Values training
workshops. The training focused on both the employee’s
personal core values, as well as the Company’s Core Values.
Seventy-five percent of Berry employees have completed Core
Values training, and training will continue into 2023 to ensure
all employees have an opportunity to participate.
In 2022, Berry also promoted additional training programs
for leaders within the organization to develop greater skills to
help promote a better sense of community within the Company.
The goal of these training programs is to improve employee
relations and proactively manage possible performance
concerns. By the end of 2023, 97% of Berry’s managers (mid-
level and senior) have committed to attend at least one of these
critical training workshops.
Berry also recognized that while the economy was facing
pressure from inflationary challenges, this was creating
potential financial pressures for its employees. Berry offered
employees financial incentive opportunities to help offset
these burdens, including early bonus payouts from the short-
term incentive plan, as well as a fuel card program for the
Company’s field employees who live more than 30 miles from
their work location.
In 2022, Berry held employee engagement focus
groups to help identify potential issues or concerns
from employees that leadership could address.
As a result of the feedback received from the focus
groups, Berry implemented a new paid time off
policy, as well as a new well-being days off policy
for employees.
75
COMMUNITY
ENGAGEMENT
Berry is committed to
improving life in the
communities where it
operates and where
its employees work,
live, and play. This
commitment is driven by
one of Berry’s Core Values:
“Responsible.” Berry
strives to be a responsible
corporate citizen.
Berry supports its communities through engagement, direct
funding, in-kind donations, and employee participation and
volunteering. This robust approach to community engagement
creates a more meaningful impact for the communities where
it operates, but also with its employees.
The Company knows its employees play a vital role in taking
care of its communities. In keeping with its Core Values and
commitment to empowering employees, Berry has an employee
match program in place for employees who financially contribute
to local organizations, thereby maximizing the individual and
collective effort.
There are currently more than 70 organizations that have been
pre-approved for employee donation matching and/or opportunities
for employees to utilize volunteer paid time off (PTO) hours.
Berry annually provides 32 volunteer PTO hours for its full-time
employees. Growing visibility in the community helps build employee
morale and helps with recruitment and retention.
In 2022, Berry was proud to continue its investment in the local
communities. Berry's charitable giving across operational areas
increased 204% from 2021 levels. Berry participated in more
than 125 events, fundraisers, and community-supportive events
(such as local economic development meetings and conferences).
Berry amended its charitable giving policy to include a new
“Berry Impact Giving” strategy. In 2022, the first “B.I.G.” donation
was a pledge of $50,000 to Taft College in support of a new
vocational learning center, investing in the Taft community.
8
6 MEET FERNANDO ARAUJO,
BERRY’S NEW CEO
Fernando Araujo joined Berry in September 2020 as Executive Vice President
and Chief Operating Officer and assumed the role of Berry’s CEO in January 2023.
Left to Right:
SNEHA PATEL Corporate Reserves & Planning Director, TREENA BRODIE Vice President, Development and FERNANDO ARAUJO Chief Executive Officer
Fernando has had the opportunity to work with diverse people,
Two years as Berry’s EVP and COO has given Fernando
cultures, and political environments around the world, which
great insight into Berry’s challenges and opportunities. A top
has informed his leadership philosophy. He believes that the
priority will be to ensure the Company continues to be creative
key to success is staying focused on what you can control
in finding ways to maximize production and remain agile.
and not letting external uncertainties dictate your future. To
A key component of this is an operational excellence campaign
Fernando, this extends to where Berry allocates its capital, how
Fernando launched shortly after taking the reins as CEO in
it operates and is organized, the culture within the Company,
January. This campaign aims to directly involve all employees
and external communications. Developing and cultivating
as the organization looks to identify ways it can operate more
internal and external relationships is vital to the health of the
efficiently and optimize its assets, while continuing to deliver
organization. This means being available not only to those
value to shareholders and provide a critical resource that
within the office, but also the team members in the field. This
helps fuel our economy and way of life.
also extends to key external relationships, which have the
potential to open the door to collaborative solutions.
9
( )7 IDLE AND ORPHAN WELLS
Idle wells can pose a risk to both the environment and to the
communities in which they are found. Studies have linked
orphan and long-term idle wells to methane emissions, which
produce much greater warming power than carbon dioxide.
Improperly plugged wells can also be a potential source
of groundwater contamination. With Berry’s successful
integration of C&J Well Services (CJWS), the Company
is uniquely positioned to help California safely seal other
operators’ idle wells, as well as those that have been
orphaned throughout the state.
• In 2022, CJWS plugged
more than 2,800 wells.
• For each new well Berry
drills, it accounts for future
costs of abandonment and
decommissioning of both the
well and associated facilities.
108
ENVIRONMENTAL, SOCIAL
AND GOVERNANCE
Berry believes that the oil and gas industry will remain an important
part of the energy landscape, even as California sets ambitious climate
goals to reduce fossil fuel consumption over the course of the next two
decades. California-produced oil is generated under the cleanest and
safest standards in the world, and the Company is proud to produce
this critical resource, while supporting a clean environment and
protecting natural resources.
ADDITIONAL SUSTAINABILITY HIGHLIGHTS*
• In 2022, Berry commenced construction of a
• CJWS transitioned approximately 85% of its
2 MW solar field at the Company’s Hill property.
equipment to use renewable diesel fuel (RD99).
• CJWS purchased approximately $6 million in
• Berry converted its North Midway (NMW)
final Tier 4 engines, which significantly reduced two
interconnect from import to export, reducing the
key pollutants: particulate matter (PM) and nitrogen
amount of electricity Berry purchased for NMW by
oxides (NOx). NOx is known to contribute to the
approximately 70%, while returning electricity to
formation of ground-level ozone, and PM exposure
California’s grid.
has been shown to have adverse health effects on
the respiratory system.
*Updates on Berry’s progress towards its 2022 Sustainability Commitments will be publicly available on the Company’s website at www.bry.com during the third quarter of 2023.
119
SHAREHOLDER
RETURN MODEL
2022 marked the first full year of Berry’s shareholder return
model. The model, which took effect on January 1, 2022,
is designed to maximize shareholder value and returns,
and has successfully delivered on that promise.
The model’s governing principles remain predictability, transparency, and
simplicity, just like the Berry business model. Berry has a proven, simple business
model, which includes a low corporate decline rate; a predictable cost structure;
an abundance of inventory; Brent pricing; a simple, clean balance sheet; and
robust adjusted free cash flow.
In 2022, Berry’s shareholder return model was based on the
Going forward, subject to declaration by the Board, Berry intends
Company’s adjusted free cash flow, which is defined as cash
to double the fixed dividend to $0.12 per share quarterly or
flow from operations less regular fixed dividends and the
$0.48 per share annually. This enhancement to the shareholder
capital needed to hold production flat. Under this model, the
return model is a testament to Berry’s high-quality, low-declining
Company allocated adjusted free cash flow, which delivered
top-tier cash returns through fixed and variable dividends, as
well as significant share repurchases and acquisitions, which
provided immediate returns and growth opportunities.
$ 1 6 0
$ 1 6 0
$ 1 6 0
$ 1 6 0
After analyzing the value creation of the first year of our
shareholder return model and soliciting feedback from
$ 1 2 0
$ 1 2 0
$ 1 6 0
$160
$ 1 6 0
$ 1 2 0
$ 1 2 0
$ 1 6 0
$ 1 2 0
$120
$ 1 2 0
$ 8 0
$ 8 0
shareholders and the investor community, the Company is
$ 1 2 0
$ 8 0
$ 8 0
reserves, long-term view of executing on its business plan, and
COMPARISON OF 53 MONTH CUMULATIVE TOTAL RETURN*
COMPARISON OF 53 MONTH CUMULATIVE TOTAL RETURN*
COMPARISON OF 53 MONTH CUMULATIVE TOTAL RETURN*
COMPARISON OF 53 MONTH CUMULATIVE TOTAL RETURN*
the Company’s visibility into its cash flows.
Among Berry Corporation (bry), the S&P Smallcap 600 Index
Among Berry Corporation (bry), the S&P Smallcap 600 Index
The Dow Jones US Exploration & Production Index, and the Vanguard Energy ETF
The Dow Jones US Exploration & Production Index, and the Vanguard Energy ETF
Among Berry Corporation (bry), the S&P Smallcap 600 Index
COMPARISON OF 53 MONTH CUMULATIVE TOTAL RETURN*
Among Berry Corporation (bry), the S&P Smallcap 600 Index
The Dow Jones US Exploration & Production Index, and the Vanguard Energy ETF
COMPARISON OF 53 MONTH CUMULATIVE TOTAL RETURN*
The Dow Jones US Exploration & Production Index, and the Vanguard Energy ETF
COMPARISON OF 53 MONTH CUMULATIVE TOTAL RETURN*
Among Berry Corporation (bry), the S&P Smallcap 600 Index
The Dow Jones US Exploration & Production Index, and the Vanguard Energy ETF
Among Berry Corporation (bry), the S&P Smallcap 600 Index
The Dow Jones US Exploration & Production Index, and the Vanguard Energy ETF
Among Berry Corporation (bry), the S&P Smallcap 600 Index
The Dow Jones US Exploration & Production Index, and the Vanguard Energy ETF
adjusting the allocations effective for 2023. Berry is now
targeting a high single-digit dividend yield with the goal of
increasing the value of its shares and lowering its cost of
capital. As such, Berry is changing the proportions of the
shareholder return model distribution:
•
80% primarily in the form of opportunistic debt and
share repurchases
•
20% in the form of variable dividends
$ 8 0
$ 8 0
$80
$ 4 0
$ 4 0
$ 8 0
$ 4 0
$ 4 0
$ 4 0
$ 4 0
$40
$ 0
$ 0
$ 4 0
$ 0
$ 0
$ 0
$ 0
7/26/18
7/26/18
7/26/18
12/18
12/18
12/19
12/19
$ 0
$0
7/26/18
7/26/18
7/26/18
7/26/18
12/18
12/18
12/18
12/19
12/19
12/20
12/20
12/20
12/20
12/20
12/21
12/21
12/21
12/21
12/22
12/22
12/22
12/22
12/22
12/18
Berry Corporation (bry)
Berry Corporation (bry)
12/19
Dow Jones US Exploration & Production
Berry Corporation (bry)
Dow Jones US Exploration & Production
Berry Corporation (bry)
Berry Corporation (bry)
Dow Jones US Exploration & Production
Dow Jones US Exploration & Production
Dow Jones US Exploration & Production
Dow Jones US Exploration & Production
Berry Corporation (bry)
12/19
12/18
12/19
12/20
12/21
12/22
12/21
Vanguard Energy ETF
Vanguard Energy ETF
S&P SmallCap 600
Vanguard Energy ETF
S&P SmallCap 600
Vanguard Energy ETF
S&P SmallCap 600
S&P SmallCap 600
12/21
Vanguard Energy ETF
Vanguard Energy ETF
S&P SmallCap 600
S&P SmallCap 600
12/20
Berry Corporation (bry)
*$100 invested on 7/26/18 in stock or 6/30/18 in index, including reinvestment of dividens.
Fiscal year ending December 31.
*$100 invested on 7/26/18 in stock or 6/30/18 in index, including reinvestment of dividens.
*$100 invested on 7/26/18 in stock or 6/30/18 in index, including reinvestment of dividens.
Fiscal year ending December 31.
Fiscal year ending December 31.
*$100 invested on 7/26/18 in stock or 6/30/18 in index, including reinvestment of dividens.
Vanguard Energy ETF
*$100 invested on 7/26/18 in stock or 6/30/18 in index, including reinvestment of dividens.
*$100 invested on 7/26/18 in stock or 6/30/18 in index, including reinvestment of dividens.
Fiscal year ending December 31.
Fiscal year ending December 31.
Dow Jones US Exploration & Production
Fiscal year ending December 31.
Copyright© 2023 Standard & Poor's, a division of S&P Global. All rights reserved.
Copyright© 2023 Standard & Poor's, a division of S&P Global. All rights reserved.
Copyright© 2023 S&P Dow Jones Indices LLC, a division of S&P Global. All rights
Copyright© 2023 S&P Dow Jones Indices LLC, a division of S&P Global. All rights
Copyright© 2023 Standard & Poor's, a division of S&P Global. All rights reserved.
Copyright© 2023 Standard & Poor's, a division of S&P Global. All rights reserved.
*$100 invested on 7/26/18 in stock or 6/30/18 in index, including reinvestment of dividens.
Copyright© 2023 Standard & Poor's, a division of S&P Global. All rights reserved.
Copyright© 2023 S&P Dow Jones Indices LLC, a division of S&P Global. All rights
Copyright© 2023 S&P Dow Jones Indices LLC, a division of S&P Global. All rights
Fiscal year ending December 31.
Copyright© 2023 S&P Dow Jones Indices LLC, a division of S&P Global. All rights
Copyright© 2023 Standard & Poor's, a division of S&P Global. All rights reserved.
Copyright© 2023 S&P Dow Jones Indices LLC, a division of S&P Global. All rights
S&P SmallCap 600
12/22
1210
Copyright© 2023 Standard & Poor's, a division of S&P Global. All rights reserved.
Copyright© 2023 S&P Dow Jones Indices LLC, a division of S&P Global. All rights
( )
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, 2022
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 ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant
included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based
compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
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 $501.6
million.
Shares of common stock outstanding as of January 31, 2023:
75,767,503
DOCUMENTS INCORPORATED BY REFERENCE
The Company’s definitive proxy statement relating to the annual meeting of shareholders (to be held May 23, 2023) will be filed with the
Securities and Exchange Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2022 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 - E&P ...............................................................................................................
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. [Reserved] ........................................................................................................................................
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 .........................................................................................
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 ....................................................................
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 ..................................................................
Consolidated Balance Sheets ..................................................................................................................
1
1
2
4
6
7
9
10
12
22
24
24
25
25
37
38
39
67
67
68
69
71
72
72
73
76
79
81
86
97
98
103
106
107
109
111
111
112
113
i
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 .....................................................................................................................................................
114
115
116
117
150
156
156
157
158
158
158
158
158
159
162
163
170
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
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 (“C&J”). 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 C&J Management and C&J.
Our Company
We are a western United States independent upstream energy company with a focus on onshore, low geologic
risk, long-lived conventional reserves in the San Joaquin basin of California (100% oil) and the Uinta basin of Utah
(oil and gas), with well servicing and abandonment capabilities in California. Since October 1, 2021, we have
operated in two business segments: (i) exploration and production (“E&P”) and (ii) well servicing and abandonment
(“CJWS”).
The assets in our E&P business, in the aggregate, are characterized by high oil content (our California assets are
100% oil) and are predominantly located in rural areas with low population. In California, we focus on conventional,
shallow oil reservoirs, the drilling and completion of which are relatively low-cost in contrast to unconventional
resource plays. The California oil market has primarily Brent-influenced pricing which has typically realized
premium pricing to WTI. All of our California assets are located in the oil-rich reservoirs in the San Joaquin basin,
which has more than 150 years of production history and substantial oil remaining in place. As a result of the
substantial data produced over the basin’s long history, its reservoir characteristics and low geological risk
opportunities are well understood. We also have upstream assets in the oil-rich reservoirs in the Uinta basin of Utah.
On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and
abandonment businesses in California, which operates as C&J Well Services (“CJWS”) and constitutes our well
servicing and abandonment segment. CJWS provides wellsite services in California to oil and natural gas production
companies, with a focus on well servicing, well abandonment services and water logistics. CJWS’ services include
rig-based and coiled tubing-based well maintenance and workover services, recompletion services, fluid
management services, fishing and rental services, and other ancillary oilfield services. Additionally, CJWS performs
plugging and abandonment services on wells at the end of their productive life, which we believe creates a strategic
growth opportunity for Berry based on the significant market of idle wells.
Since our Initial Public Offering (IPO) in July 2018, we have demonstrated our commitment to maximizing
shareholder value and returning a substantial amount of capital to shareholders through dividends and share
purchases. In 2022, we reinforced this commitment by initiating a shareholder return model, which is further
discussed below, designed to take advantage of our low decline rates and strong visibility into our cost structure to
maximize returns to our shareholders. Under this well-defined shareholder return model, we declared variable
dividends of $1.54 per share in aggregate based on the $200 million of Adjusted Free Cash Flow (defined and
discussed below) that we generated in 2022. We also declared fixed dividends of $0.24 during 2022. Inclusive of the
fixed and variable dividends related to the fourth quarter of 2022, since our IPO, we will have returned $328 million
to our shareholders, which represents 298% of our IPO proceeds, consisting of $224 million in fixed and variable
dividends and $104 million to repurchase 10.5 million shares, which represents 14% of our outstanding shares as of
December 31, 2022.
Our shareholder return model went into effect January 1, 2022. Like our business model, this shareholder return
model is simple and demonstrates our commitment to optimize capital allocation and returns to our shareholders.
The model is based on our Adjusted Free Cash Flow (formerly called Discretionary Free Cash Flow), which is
defined as cash flow from operations less regular fixed dividends and maintenance capital. Maintenance capital,
which represents the capital expenditures needed to optimize production volumes for a given year, is defined as
1
capital expenditures, excluding, when applicable, (i) E&P capital expenditures that are related to strategic business
expansion, such as acquisitions and divestitures of oil and gas properties and any exploration and development
activities to increase production beyond the prior year’s annual production volumes, (ii) capital expenditures in our
well servicing and abandonment segment, (iii) corporate expenditures that are related to ancillary sustainability
initiatives and/or (iv) other expenditures that are discretionary and unrelated to maintenance of our core business.
The initial allocation of Adjusted Free Cash Flow in 2022 was contemplated as: (a) 60% predominantly in the form
of variable cash dividends to be paid quarterly, as well as opportunistic debt repurchases; and (b) 40% which could
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. Adjusted Free Cash Flow
does not represent the total increase or decrease in our cash balance, and it should not be inferred that the entire
amount of Adjusted Free Cash Flow is available for variable dividends, debt or share repurchase or other
discretionary expenditures, since we have non-discretionary expenditures that are not deducted from this measure.
Adjusted Free Cash Flow is a non-GAAP financial measure. See “Management’s Discussion and Analysis—Non-
GAAP Financial Measures” for a reconciliation of Adjusted Free Cash Flow to cash provided by operating
activities, our most directly comparable financial measure calculated and presented in accordance with GAAP.
Our Adjusted Free Cash Flow in 2022 was $200 million, of which we will have returned $189 million to
shareholders in the form of dividends and share repurchases, specifically, $119 million for the variable cash
dividends, (ii) $19 million for fixed cash dividends and (iii) $51 million for share repurchases.
In early February 2023, we updated our shareholder return model, including the plan to double our quarterly
fixed dividend to $0.12 per share. We also modified the allocations of Adjusted Free Cash Flow. Our goal is to
continue maximizing shareholder value through overall returns. Starting with the first quarter of 2023, the allocation
of Adjusted Free Cash will be (a) 80% primarily in the form of opportunistic debt or share repurchases; and (b) 20%
in the form of variable dividends. Any dividends (fixed or variable) actually paid will be determined by our Board of
Directors in light of then existing conditions, including our earnings, financial condition, restrictions in financing
agreements, business conditions and other factors.
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 free cash flow, which funds our operations, optimizes capital efficiency and maximizes
shareholder returns. We also strive to maintain a low leverage profile and explore attractive organic and strategic
growth through commodity price cycles. 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 shareholders, we are dedicated to
conducting our operations in an ethical, safe and responsible manner, to protecting the environment, and to taking
care of our people and the communities in which we live and operate. We believe that oil and gas will remain an
important part of the energy landscape going forward and our goal is to conduct our business safely and responsibly,
while supporting economic stability and social equity through engagement with our stakeholders. We recognize the
oil and gas industry’s role in the energy transition and advocate a co-existence between renewable and conventional
energy. We are committed to being part of the energy transition solution by continuing to provide safe and
affordable energy to our communities.
The Berry Advantage
The foundation of our business model is our base production, which is the production that comes from our
existing, producing wells. Our goal is to protect our base production and minimize its decline with the objective of
maintaining relatively stable production levels year over year. In terms of that goal, our base production on average,
typically accounts for greater than 90% of our total annual production, and the remaining 10% comes from a mixture
of drilling new wells, sidetrack wells, and the workover of existing wells. In 2022, our base production accounted
for 94% of our total production. We have a manageable annual corporate decline rate in the low teens, with
significant inventory of new drill and workover opportunities and predictable costs, which provides visibility to our
2
potential cash flow options. Our ability to pivot our capital allocation between new drills and sidetrack and
workovers in response to regulatory delays or other factors provides further stability in an uncertain market and
regulatory environment. These advantages, coupled with an ability to efficiently hedge material quantities of future
expected production, provides visibility to our cash flows compared to the typical resource play and can generate
significant cash flow through typical commodity price cycles.
We believe the following competitive advantages will allow us to successfully execute our business strategy and
meet our objectives to generate free cash flow to fund our operations, optimize capital efficiency and maximize
shareholder returns. We also strive to maintain a low leverage profile and explore attractive organic and strategic
growth through commodity price cycles:
•
•
•
•
Stable, long-lived, oil-weighted conventional asset base with low and predictable production decline
rates. Almost all of our interests are in properties that have produced oil for decades. As a result, most of
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. Our properties,
especially those in California, 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. Our current corporate annual decline rate is in the low teens, which is
manageable and provides greater visibility into our cash flows compared to unconventional resource plays.
In California, our base production from existing wells requires little to no additional capital to continue to
produce, and it typically provides at least 90% of the production needed to maintain relatively stable levels
year over year. The remaining 10% comes from a mixture of drilling new wells, side tracks, and the
workover of existing wells. The 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, further enhancing visibility to our cash flow.
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. Historically, we have been able to generate attractive rates of return and positive free
cash flow through typical commodity price cycles. Subject to our ability to obtain the necessary permits and
approvals to drill new wells and sidetracks and workover existing wells, we believe we will be able to
maintain current production levels and fund organic and strategic growth, among other things, while
returning capital to shareholders. For example, our proved undeveloped (“PUD”) reserves in California are
projected to average single-well rates of return of approximately 100% based on the assumptions prepared
by DeGolyer and MacNaughton in our SEC reserves report as of December 31, 2022. We currently operate
approximately 97% 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 some relative insulation from service cost
inflation pressures. Our high degree of operational control and relatively stable and predictable cost
environment provides us 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 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 IPO, our capital structure has consisted of common stock and $400
3
million of 7.0% senior unsecured notes due February 2026 (the “2026 Notes”). As of December 31, 2022,
we had $252 million of liquidity, consisting of $46 million of cash, $193 million available for borrowings
under our 2021 RBL Facility (as defined herein), and $13 million available for borrowings under the CJWS
2022 ABL Facility (as defined herein). As of December 31, 2022, our Leverage Ratio (as defined in our
2021 RBL Facility) was 1.2 to 1.0. In addition, we have minimal long-term service and purchase
commitments. We have fixed-volume delivery commitments for which we will purchase the gas needed for
operations at market rates. 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 technical, operational and strategic management
experience to optimize the value of our assets and the Company. We are committed to operating within
positive free cash flow and maintaining a low leverage profile, while exploring attractive organic and
strategic growth opportunities through commodity price cycles, and working to maintain our production
levels year over year and improve 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.
Our Business Strategy
The principal elements of our business strategy include the following:
•
•
Operate within the positive free cash flow generated by our operations and maintain balance sheet
strength and flexibility through commodity price cycles. 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 free
cash flow to fund our operations, optimize capital efficiency, and maximize shareholder returns. We also
strive to maintain a low leverage profile and maintain a long-term, through-cycle Leverage Ratio (as
defined in our 2021 RBL Facility) between 1.0x and 2.0x, or lower.
Return capital to our shareholders. Our objective is to take advantage of our 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, 2022, we
will have returned approximately $328 million to our shareholders through dividends and share
repurchases, representing 298% of our IPO proceeds. From our IPO through December 31, 2022, we
repurchased approximately 14% of our outstanding shares. We currently have $200 million authorized and
available for future share repurchases. Additionally, our Board of Directors authorized up to $75 million for
the opportunistic repurchase of our 2026 Notes, although we have not yet repurchased any notes under this
program since its adoption in February 2020. 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 January 2022, we introduced our shareholder return model, which is 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 Adjusted Free Cash Flow (formerly called Discretionary Free
Cash Flow), which is defined as cash flow from operations less regular fixed dividends and maintenance
capital. Under this model, in 2022 we allocated Adjusted 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
4
•
40% 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
In early February 2023, we updated our shareholder return model, including the plan to double our
quarterly fixed dividend to $0.12 per share. We also modified the allocations of Adjusted Free Cash Flow.
Our goal is to continue maximizing shareholder value through overall returns. Starting with the first quarter
of 2023, the allocation of Adjusted Free Cash will be:
•
•
80% primarily in the form of opportunistic debt and share repurchases; and
20% in the form of variable dividends. Any dividends (fixed or variable) actually paid will be
determined by our Board of Directors in light of then existing conditions, including our earnings,
financial condition, restrictions in financing agreements, business conditions and other factors.
Adjusted Free Cash Flow does not represent the total increase or decrease in our cash balance, and it
should not be inferred that the entire amount of Adjusted Free Cash Flow is available for variable
dividends, debt or share repurchase or other discretionary expenditures, since we have non-discretionary
expenditures that are not deducted from this measure. Adjusted Free Cash Flow is a non-GAAP financial
measure. See “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for a
reconciliation of Adjusted Free Cash Flow to cash provided by operating activities, our most directly
comparable financial measure calculated and presented in accordance with GAAP.
• Maintain production and reserves in a capital efficient manner and generate Adjusted Free Cash Flow
to return to our shareholders through our shareholder return model . We intend to continue to allocate
capital in a disciplined manner to projects that will produce predictable and attractive rates of return. We
currently 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 development plan. As a result of ongoing regulatory
uncertainty impacting the availability of new drill permits in California, our current capital program for
2023 focuses on new wells drilled or to be drilled during the year for which we already have permits or
have existing California Environmental Quality Act (“CEQA”) analysis completed, and otherwise focuses
on workovers and other activities related to existing wellbores. We may also use our capital flexibility to
pursue value-enhancing, bolt-on acquisitions to opportunistically add to our positions in existing or nearby
basins.
•
Proactively and collaboratively engage in matters related to regulation, the environment and community
relations. We seek to work with regulators and legislators throughout the rule-making process in attempt to
minimize the adverse impacts that new legislation and regulations might have on our ability to maximize
our resources. We believe that running our operations in a manner that protects the safety and health of the
communities we serve and the greater environment is the right way to run our business. It also helps us
build and maintain credibility with the agencies that regulate our operations, as well as support positive
relationships with the communities in which we operate. With ultimate oversight by our Board of Directors,
health, safety and environmental (“HSE”) 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
5
•
•
•
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. We strive to optimize our production and grow our reserves by
leveraging the expertise of our people to find or create new opportunities within our robust assets.
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 hedge crude oil and gas production to protect
against oil and gas price decreases and we hedge gas purchases to protect our operating expenses against
price increases. We also seek to protect our operating expenses through fixed-price gas purchase
agreements 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. In addition, we hedge to
meet the hedging requirements of the 2021 RBL Facility. We protected a significant portion of our cash
flows in 2022, and have sought to protect a significant portion of our anticipated cash flows in 2023, as
well as a portion in 2024 through 2025, using our commodity hedging program. We review our hedging
program continuously as market conditions change and make our hedging decisions using a wide range of
market data and analysis.
Continuously optimize costs. Management is focused on cost reduction initiatives and optimizing our cost
structure across the company. We believe we will be able to identify and achieve cost reductions and
optimize our processes and cost structure while maintaining our HSE standards.
Continue to be compliant with strong HSE performance. As part of our commitments to being a good
corporate citizen and creating long-term stockholder value, we strive to conduct our operations in an
ethical, safe and responsible manner that safeguards people and the environment and complies with existing
laws and regulations and to take care of our people and the communities in which we live and operate. We
monitor our HSE performance through various measures, and we hold our employees and contractors to
high standards. Meeting corporate HSE metrics, including with respect to HSE incidents, is a part of our
short-term incentive program for all employees.
• Continue to improve our environment through our CJWS plugging and abandonment business and
other initiatives. We believe that oil and gas will remain an important part of the energy landscape going
forward and we are committed to being good corporate citizens, which includes minimizing our
environmental impact. Through CJWS, we have the capabilities to support the State's orphaned wells and
fugitive emissions initiatives related to its approximately 35,000 idle wells, of which approximately 5,000
are believed to be orphaned idle wells according to third party sources. CJWS is an active contributor to the
reduction of state-wide fugitive emissions, which are primarily methane, the most damaging of the
greenhouse gases, by plugging and abandoning orphan and idle wells. Additionally, we are continuing to
advance other environmental initiatives, 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, 2022 and 2021 our total capital expenditures were approximately $153
million and $133 million, respectively, including capitalized overhead and interest and excluding acquisitions and
asset retirement spending. We increased our 2022 capital program compared to 2021, in response to the improved
oil price environment and the improving global and national economic environment. E&P and corporate
expenditures were $145 million in 2022 (excluding well servicing and abandonment capital of $8 million) compared
to $132 million in 2021. Approximately 61% and 39% of these capital expenditures for the year ended December
31, 2022 was directed to California and Utah operations, respectively. The Company allocated more capital to the
Utah assets in 2022, compared to 2021, in part due to the opportunities in the newly acquired Antelope Creek
properties. Additionally, as a result of the significant challenges in receiving new drill permits in California, the
6
Company drilled fewer new wells and increased the sidetrack, workover and recompletion activity in California
compared to the prior year. The increase in full-year capital expenditures is also partially due to cost inflation in
excess of our initial expectations, which we began to experience mid-year.
Year-over-year our overall production was flat, excluding the effect of our acquisitions and divestitures in 2022
and 2021. We drilled 85 wells in 2022, of which 72 were in California and consisted of 51 producing wells 13
injector and other wells and 8 delineation wells. We also drilled 13 wells in Utah.
Our 2023 capital expenditure budget for E&P operations and corporate activities is between $95 to $105
million, which we expect will result in a slight decline in production year over year but that production levels will be
relatively flat to those experienced in the second half of 2022. This capital excludes approximately $8 million for
CJWS. We currently anticipate oil production will be approximately 92% of total production volume in 2023,
consistent with 2022. Based on current commodity prices and our drilling success rate to date, we expect to be able
to fund our 2023 capital development programs from cash flow from operations. Our current capital program for
2023 focuses on new wells drilled during the year for which we already have permits or have existing CEQA
analysis completed, and otherwise focuses on workovers, side tracks and other activities related to existing
wellbores. As a result of ongoing regulatory uncertainty in California impacting the permitting process in Kern
County where all of our California assets are located, the capital program has been prepared based on the
assumption that we will not receive additional new drill permits in California 2023, but that we will continue to
timely receive the other permits and approvals needed for planned activities. However, we are pursuing alternative
avenues to obtain additional permits for new wells that, if received could enable us to expand the 2023 drilling
program contemplated under our capital budget. 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.
Exclusive of the capital expenditures noted above, for the full year 2022, we spent approximately $20 million
on plugging and abandonment activities, exceeding our annual obligation requirements under California idle well
management plan. In 2023, 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 - E&P
Our predominant E&P operating area is in California, and we also have operations in Utah. In January 2022 we
divested our Colorado operating area.
California
California oil fields, including those in Kern County and the San Joaquin Basin, where our fields are located,
are some of most resource-rich in the world. According to the U.S. Energy Information Administration, 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 and around 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
7
allowed continuing discoveries of stratigraphic, structural and non-structural traps. Most oil accumulations
discovered in the San Joaquin basin occur in the Eocene age 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 15,000 net acres in the San Joaquin basin in Kern County, of which 91% is
held by production and fee interest. Approximately 12% 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:
•
California operations consist of:
◦
◦
◦
◦
(i) our North Midway-Sunset sandstone properties, where we use cyclic and continuous steam
injection to develop these known reservoirs; and our McKittrick Field property, which is a newer
steamflood development with potential for infill and extension drilling. Also located here are our
North Midway-Sunset thermal diatomite properties, which require 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
to address surface expressions experienced by certain operators, we continue to await approval of
our revised development plans from CalGEM, which we believe are in accordance with the results
of the study co-led by Lawrence Livermore National Laboratory and CalGEM. In the meantime,
we have plans to drill permitted wells in these thermal diatomite properties in 2023, which do not
require high-pressure cyclic steam. Please see “—Regulation of Health, Safety and Environmental
Matters—Additional CalGEM Actions on Oil and Gas Activities” for more information;
(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.
(iv) our Poso Creek property, which is an active mature shallow, heavy oil asset that we continue
to develop. 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 76% of our total proved reserves at December 31,
2022. California accounted for 21.3 mboe/d, or 82%, of our average daily production for the year ended December
31, 2022.
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, in the Midway-Sunset and
McKittrick fields, supply approximately 16% of our steam needs and approximately 55% 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 also sell electricity produced by two of our cogeneration facilities under long-term
contracts with terms ending in December 2023 and November 2026. We also own 62 conventional steam generators
to help satisfy the steam required by our operations.
In addition, we own gathering, storage, treatment, water recycling and softening facilities, reducing our need to
spend capital to develop nearby assets and generally allowing us to control certain operating costs. Approximately
8
92% of our California oil production is sold through pipeline connections, however, we can also sell our oil using
trucking during short-term pipeline market disruptions.
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, Lake Canyon and Antelope Creek areas in Utah target the Green
River and Wasatch formations that produce oil and natural gas at depths ranging from 4,000 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 101,000 net acres in the Uinta basin, of
which 92% is held by production. Approximately 28% of our Utah acreage is on Federal lands administered by the
BLM, of which 78% is held by production. Approximately 65% of our Utah acreage is on tribal lands, of which 98%
is held by production.
Our Uinta basin proved reserves represented approximately 24% of our total proved reserves at December 31,
2022 and accounted for 4.8 mboe/d or 18% of our average daily production for the year ended December 31, 2022.
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 88% of the gas gathered at these facilities is produced from wells
that we operate. Current throughput at the processing plant is 10-17 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 97 mbbl/d in 2021. Approximately 87% of Utah’s oil
production in 2021 came from the Uinta basin in Duchesne and Uintah counties.
In February 2022, we completed the acquisition of oil and gas producing assets in the Antelope Creek area of
Utah. These assets are adjacent to our existing Uinta assets.
Our Well Servicing and Abandonment Business
On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and
abandonment businesses in California, which operates as C&J Well Services and now constitutes our well servicing
and abandonment business segment. CJWS provides wellsite services in California to oil and natural gas production
companies, with a focus on well servicing, well abandonment services and water logistics. CJWS’ services include
rig-based and coiled tubing-based well maintenance and workover services, recompletion services, fluid
management services, fishing and rental services, and other ancillary oilfield services. Additionally, CJWS performs
plugging and abandonment services on wells at the end of their productive life, which we believe creates a strategic
growth opportunity for Berry. CJWS is a synergistic fit with the services required by our oil and gas operations and
supports our commitment to be a responsible operator and reduce our emissions, including through the proactive
plugging and abandonment of wells. Additionally, CJWS is critical to advancing our strategy to work with the State
of California to reduce fugitive emissions—including methane and carbon dioxide—from idle wells. According to
independent sources, there are approximately 35,000 idle wells estimated to be in California, of which
9
approximately 5,000 are believed to be orphaned idle wells. With CJWS’ expertise and experience in well
abandonment, we have an opportunity to capture both state and federal funds to help remediate orphaned idle wells
that are a burden on the State of California, in addition to safely plugging and abandoning idle wells for CJWS’
customers.
Through CJWS, we operate a fleet of 72 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 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 wellbore; 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 247 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 1,370
pieces of rental equipment on our water logistics side.
Our Assets and Production Information
For the year ended December 31, 2022, we had average net production of approximately 26.1 mboe/d, of which
approximately 92% was oil and approximately 82% was in California. In California, our average production for the
year ended December 31, 2022 was 21.3 mboe/d, of which 100% was oil. Our 2021 California production included
our previously owned Placerita operations, which contributed an average daily production of 0.7 mboe/d for 2021.
We divested the Placerita operations in late 2021. We also divested all of our properties in the Piceance basin of
Colorado in January 2022, which had production of 1.2 mboe/d in 2021. In February 2022, we completed the
acquisition of oil and gas producing assets in the Antelope Creek area of Utah. These assets are adjacent to our
existing Uinta assets and contributed an average daily production of approximately 1.0 mboe/d for 2022.
10
The table below summarizes our average net daily production for the years ended December 31, 2022 and 2021:
Average Net Daily Production(1)
for the Year Ended December 31,
2022
2021
(mboe/d)
Oil (%)
(mboe/d)
Oil (%)
21.3
4.7
26.0
0.1
26.1
100 %
58 %
92 %
— %
92 %
22.0
4.2
26.2
1.2
27.4
100 %
51 %
88 %
2 %
88 %
California(2)
Utah(3)
Colorado(4)
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 approximately 700 boe/d.
(3) Includes production for Antelope Creek area, which was acquired in February 2022. These properties had average production for 2022 of
approx 1.0 mboe/d.
(4) 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, 2022 and
2021.
Average daily production(1):
Oil (mbbl/d)
Natural gas (mmcf/d)
NGLs (mbbl/d)
Total (mboe/d)(2)
__________
Year Ended December 31,
2022
2021
24.0
10.2
0.4
26.1
24.2
17.1
0.4
27.4
(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, 2022, the
average prices of Brent oil and Henry Hub natural gas were $99.04 per bbl and $6.45 per mcf, respectively.
Our Development Inventory
We have an extensive inventory of low-geologic risk, high-return development opportunities. As of December
31, 2022, we identified 9,813 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 97% 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, 2022,
the combined net acreage covered by leases expiring in the next three years represented approximately 2% of our
total net acreage, of which 55% is in Utah. Our high degree of operational control, together with the large portion of
11
our acreage that is held by production, and the speed with which we are able to drill and complete our wells in
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, 2022:
Acreage
Gross
Net(1)(2)
19,421
15,098
111,930
101,494
131,351
116,592
Net Acreage
Held By
Production and
Fee Interest(%)
Producing
Wells,
Gross(3)
Average
Working
Interest
(%)(4)
Net
Revenue
Interest
(%)(5)
Identified Drilling
Locations(6)
Gross
Net
91 %
92 %
92 %
2,214
1,232
3,446
97 %
96 %
97 %
95 %
8,527
79 %
1,286
88 %
9,813
7,186
1,209
8,395
California
Utah
Total
__________
(1) Represents our weighted-average interest in our acreage.
(2) Of which approximately 12% are BLM acres in California and 28% are BLM acres in Utah.
(3)
Includes 406 steamflood and waterflood injection wells in California and Utah.
(4) Represents our weighted-average working interest in our active wells.
(5) Represents our weighted-average net revenue interest for the year ended December 31, 2022.
(6) Our total identified drilling locations include approximately 935 gross (928 net) locations associated with PUDs as of December 31, 2022,
including 200 gross (198 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, 2022, we had estimated total proved reserves of 110 mmboe, an increase from 97 mmboe,
as of December 31, 2021. Our overall proved reserves increased 23 mmboe, or 24% in 2022, before production of
10 mmboe, the majority of which is due to extensions, as we added significant PUD locations throughout our
properties. We replaced 236% of our 2022 production with additional proved reserves.
The majority of our reserves are composed of crude oil in shallow, long-lived reservoirs. As of December 31,
2022, the standardized measure of discounted future net cash flows of our proved reserves and the PV-10 of our
proved reserves were approximately $2.1 billion and $2.6 billion, respectively. These values represent significant
increases from the prior year end of $1.2 billion and $1.5 billion. PV-10 is a financial measure that is not calculated
in accordance with U.S. generally accepted accounting principles (“GAAP”). For a definition of PV-10 and a
reconciliation to the standardized measure of discounted future net cash flows, please see in “—PV-10” below. As
of December 31, 2022, approximately 76% of our proved reserves and approximately 85% of the PV-10 value of our
proved reserves are derived from our assets in California. We also have approximately 24% of our proved reserves
and approximately 15% of the PV-10 value in the Uinta basin in Utah, a mature, light-oil-prone play with significant
undeveloped resources.
12
The tables below summarize our estimated proved reserves and related PV-10 by category as of December 31,
2022:
PDP
PDNP
PUD
Berry total proved
reserves
California total
proved reserves
__________
Proved Reserves as of December 31, 2022(1)
Oil
(mmbbl)
Natural
Gas (bcf)
NGLs
(mmbbl)
Total
(mmboe)(2)
% of
Proved
% Proved
Developed
Capex(3)
($MM)
PV-10(4)
($MM)
46
8
45
99
84
38
6
15
59
—
1
—
1
2
—
53
9
48
49 %
8 %
43 %
86 %
14 %
— %
29
66
611
1,366
219
1,039
110
100 %
100 %
706
2,624
84
512
2,240
(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 $100.25 per bbl Brent for oil and
natural gas liquids (“NGLs”) and $6.40 per mmbtu Henry Hub for natural gas at December 31, 2022. The volume-weighted average
realized prices over the lives of the properties were estimated at $91.33 per bbl of oil and condensate, $48.76 per bbl of NGLs and $6.76 per
mcf of gas. The prices were held constant for the lives of the properties and we took into account pricing differentials reflective of the
market environment. Prices were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting
rules, including adjustment by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other
factors affecting the price received at the wellhead. Please see “—Our Reserves—PV-10” below.
(2) Estimated using a conversion ratio of six mcf of natural gas to one bbl of oil.
(3) Represents undiscounted future capital expenditures estimated as of December 31, 2022.
(4) PV-10 is a financial measure that is not calculated in accordance with GAAP. For a definition of PV-10 and a reconciliation to the
standardized measure of discounted future net cash flows, please see “—Our Reserves—PV-10” below. PV-10 does not give effect to
derivatives transactions.
The following table summarizes our estimated proved reserves and related PV-10 by area as of December 31,
2022. The reserve estimates presented in the table below are based on reports prepared by DeGolyer and
MacNaughton. The reserve estimates were prepared in accordance with current SEC rules and regulations regarding
oil, natural gas and NGL reserve reporting. Reserves are stated net of applicable royalties.
13
Proved developed reserves:
Oil (mmbbl)
Natural gas (bcf)
NGLs (mmbbl)
Total (mmboe)(2)(3)
Proved undeveloped reserves:
Oil (mmbbl)
Natural gas (bcf)
NGLs (mmbbl)
Total (mmboe)(3)
Total proved reserves:
Oil (mmbbl)
Natural gas (bcf)
NGLs (mmbbl)
Total (mmboe)(3)
PV-10 ($million)
__________
Proved Reserves as of December 31, 2022(1)
California
(San Joaquin
basin)
Utah
(Uinta basin)
Total
43
—
—
43
41
—
—
41
84
—
—
84
11
44
1
19
4
15
1
7
15
59
2
26
54
44
1
62
45
15
1
48
99
59
2
110
$
2,240 $
384 $
2,624
(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 $100.25 per bbl Brent for oil and
NGLs and $6.40 per mmbtu Henry Hub for natural gas at December 31, 2022. The volume-weighted average realized prices over the lives
of the properties were $91.33 per bbl of oil and condensate, $48.76 per bbl of NGLs and $6.76 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 14% of total and 14% 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 years ended December 31, 2022 and
December 31, 2021, the average prices of Brent oil and Henry Hub natural gas were $99.04 and $70.95 per bbl and $6.45 and $3.89 per
mcf, respectively.
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.
14
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, 2022:
California PV-10
Utah 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, 2022
(in millions)
$
$
2,240
384
2,624
(550)
2,074
Our overall proved reserves increased 23 mmboe, or 24%, before production. A majority of this increase was a
result of adding extensions, as we added significant PUD locations throughout our properties. We replaced 236% of
our production with additional proved reserves. The total changes to our proved reserves from December 31, 2021 to
December 31, 2022 were as follows:
Beginning balance as of December 31, 2021
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, 2022
__________
California
(San Joaquin
basin)
Utah
(Uinta basin)
Colorado
(Piceance basin)
Total
(in mmboe)(1)
79
20
(7)
—
—
(8)
84
14
6
1
7
—
(2)
26
4
—
—
—
(4)
—
—
97
26
(6)
7
(4)
(10)
110
(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 years ended December 31, 2022 and
December 31, 2021, the average prices of Brent oil and Henry Hub natural gas were $99.04 and $70.95 per bbl and $6.45 and $3.89 per
mcf, respectively.
(2)
(3)
In February 2022, we acquired Antelope Creek in Utah.
In January 2022, we divested our Piceance basin properties in Colorado.
Extensions. During 2022, we added 26 mmboe of proved reserves from extensions in our California and Utah
properties due to an increase in our proved acreage based on drilling results for the year.
Revisions of previous estimates.
Revisions related to price - Product price changes affect the proved reserves we record. For example, in certain
price environments, higher prices can increase the economically recoverable reserves in our operations when the
extra margin extends their expected life and renders more projects economic. Conversely, when prices drop, we can
experience the opposite effects. In 2022, our total net positive price revision was one mmboe in California and one
mmboe in Utah.
Other revisions - Other 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
15
data. In 2022, we had negative other revisions of seven mmboe in California. The negative other revisions resulted
primarily from a change in development plans in our thermal Diatomite in our North Midway-Sunset field.
Purchases of minerals in place. In February of 2022, we acquired Antelope Creek and we added seven mmboe
of proved reserves in Utah.
Sale of minerals in place. In January of 2022, we divested our Piceance basin properties and removed
approximately four mmboe of proved reserves in Colorado.
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 increased nine mmboe in 2022 largely due to extensions, partially
offset by revisions. The total changes to our proved undeveloped reserves from December 31, 2021 to December 31,
2022 were as follows:
California
(San Joaquin and
Ventura basins)
Utah
(Uinta basin)(2)
Colorado
(Piceance basin)(3)
Total
32
19
(8)
(2)
41
(in mmboe)(1)
1
6
—
—
7
—
—
—
—
—
33
25
(8)
(2)
48
Beginning balance as of December 31, 2021
Extensions and discoveries
Revisions of previous estimates
Reclassifications to proved developed
Ending balance as of December 31, 2022
__________
(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 years ended December 31, 2022 and
December 31, 2021, the average prices of Brent oil and Henry Hub natural gas were $99.04 and $70.95 per bbl and $6.45 and $3.89 per
mcf, respectively.
(2)
(3)
In February 2022, we acquired Antelope Creek of which all proved reserves were evaluated as proved developed.
In January 2022, we divested our Piceance basin properties in Colorado.
Extensions. During 2022, we added 25 mmboe of proved undeveloped reserves from extensions based on
drilling results from unproven locations in Hill Tulare, McKittrick, and Utah due to an increase in our proved
acreage based on drilling results for the year.
Revisions of previous estimates.
Other revisions - In 2022, we had negative other revisions of eight mmboe, primarily as a result of our change
in development plans of our thermal Diatomite operations in our California North Midway-Sunset field.
Reclassifications to proved developed. Compared to recent years, in 2022, we shifted a large portion of our
development efforts from drilling to workovers, sidetracks and recompletions, which have high returns and capital
efficiency. Additionally, we transferred approximately two mmboe of proved undeveloped reserves to the proved
developed category in 2022, in connection with our development drilling activity, spending approximately $30
million of capital. This 2022 capital intensity was higher than recent years as we increased our development focus in
Utah based on the economic opportunities there, and Utah has deeper wells and thus higher drilling costs compared
to California. The California development averaged under $11 per boe in 2022. We expect to have sufficient future
16
capital to develop our proved undeveloped reserves at December 31, 2022 within five years. If prices decrease
substantially below current levels for a prolonged period of time may we may be required to reduce expected capital
expenditures over the next five years, potentially impacting either the quantity or the development timing of proved
undeveloped reserves. Our year-end proved undeveloped reserves are determined in accordance with SEC guidelines
for development within five years. Management has made the necessary commitment and we expect to have
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. Proved reserves estimates are established using standard geological and
engineering technologies and computational methods, which are generally accepted by the petroleum industry. The
proved reserves additions are primarily prepared by production history or analogy, which use historical production
and analogous type curves that are based on decline curve analysis. We further establish reasonable certainty of our
proved reserves estimates using geological and geophysical information to establish reservoir continuity between
penetrations, downhole completion information, 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 Licensed 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.”
17
Determination of Identified Drilling Locations
Proven Drilling Locations
Based on our reserves report as of December 31, 2022, we have approximately 935 gross (928 net) drilling
locations attributable to our proved undeveloped reserves. We increased our drilling locations attributable to proved
undeveloped reserves in 2022, primarily due to an increase in our proved acreage based on drilling results. 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 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 8,878 gross (7,467 net) unproven drilling locations as of
December 31, 2022. 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,
18
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.”
The table below sets forth our proved undeveloped drilling locations and unproven drilling locations as of
December 31, 2022.
PUD Drilling Locations
(Gross)
Unproven Drilling
Locations (Gross)
Total Drilling Locations
(Gross)
Oil, Natural Gas Wells and
Injection Wells
Oil, Natural Gas and
Injection Wells
Oil, Natural Gas and
Injection Wells
California
Utah
Total Identified Drilling Locations
847
88
935
7,680
1,198
8,878
8,527
1,286
9,813
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:
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)
Uinta
Total production(1):
Oil (mbbls)
Natural gas (bcf)
NGLs (mbbls)
Total (mboe)(2)
__________
5,933
—
—
5,933
1,280
—
—
1,280
Year Ended December 31,
2022
2021
2020
5,630
—
—
5,630
5,666
—
—
5,666
Year Ended December 31,
2022
2021
2020
1,551
—
—
1,551
1,505
—
—
1,505
Year Ended December 31,
2022
2021
2020
1,010
3,502
144
1,737
*
*
*
*
*
*
*
Represented less than 15% of our total proved reserves for the periods indicated.
(1) Production represents volumes sold during the period.
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(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 years ended December 31, 2022 and
December 31, 2021, the average prices of Brent oil and Henry Hub natural gas were $99.04 and $70.95 per bbl and $6.45 and $3.89 per
mcf, respectively.
Productive Wells
As of December 31, 2022, we had a total of 3,450 gross (3,332 net) productive wells (including 406 gross and
405 net steamflood and waterflood injection wells), approximately 100% of which were oil wells. Our average
working interests in our productive wells is approximately 97%. All of our Uinta basin oil wells produce associated
gas and NGLs. 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 as of the end of 2022.
The following table sets forth our productive oil and natural gas wells (both producing and capable of
producing) as of December 31, 2022.
Oil
Gross(1)
Net(2)
Gas(4)
Gross(1)
Net(2)
__________
California
(San Joaquin basin)
Utah
(Uinta basin)(3)
Total
2,215
2,144
—
—
1,235
1,188
—
—
3,450
3,332
—
—
(1) The total number of wells in which interests are owned. Includes a total of 406 steamflood and waterflood injection wells with 395 in
California and 11 in Utah.
(2) The sum of fractional interests.
(3)
(4)
Includes wells in the Antelope Creek area that were acquired in February 2022.
In Utah we have associated gas in a portion of our oil wells, which are reported as oil wells.
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, 2022.
Developed(1)
Gross(2)
Net(3)
Undeveloped(4)
Gross(2)
Net(3)
__________
California
(San Joaquin basin)
Utah
(Uinta)
Total
7,135
7,110
12,286
7,988
46,987
45,227
64,943
56,267
54,122
52,337
77,229
64,255
(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.
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Participation in Wells Being Drilled
As of December 31, 2022, we were not participating in any uncompleted wells.
Drilling Activity
The following table shows the net development wells we drilled during the periods indicated, which include
delineation and temperature observation wells per our development plan. 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.
California
(San Joaquin and
Ventura basins(3))
Utah
(Uinta basin)
Colorado
(Piceance basin(4))
Total
2022
Oil(1)(2)
Natural Gas
Dry
2021
Oil(1)
Natural Gas
Dry
2020
Oil(1)(2)
Natural Gas
Dry
__________
72
—
—
181
—
—
45
—
—
13
—
—
10
—
—
—
—
—
—
—
—
—
—
—
—
—
—
85
—
—
191
—
—
45
—
—
(1)
(2)
Includes injector wells.
Includes 12 and 50 wells that had not yet been connected to gathering systems in California in 2022 and 2020, respectively.
(3) Effective October 2021, we completed the sale of our Placerita Field property in the Ventura Basin in Los Angeles County, California,
which included one well in 2020 and zero wells in 2021.
(4)
In January 2022, we divested our Piceance basin properties in Colorado.
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, 2022, the volumes contracted to be
processed were approximately 4,560 mcf/d through March 2024. We have significantly more production than the
amounts committed for delivery and have the ability to secure additional volumes of products as needed.
21
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 97% 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
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, all 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 $500,000 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
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aggregated cost of steam generation. The natural gas we purchase to generate steam and electricity is primarily
based on Rockies price indexes, including transportation charges, as we currently purchase a substantial majority of
our gas needs from the Rockies, with the balance purchased in California.
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 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
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 and other costs 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 Cogen and 21Z Cogen facilities are used solely for field
operations.
For the year ended December 31, 2022, we sold approximately 1,005 megawatt-hours (“MWhs”) per day of
cogeneration power into the grid and on average consumed approximately 293 MWhs per day of cogeneration
power for lease operations. The four cogeneration facilities produced an average of approximately 24,000 barrels of
23
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 one of our cogeneration facilities under a long-term
PPA approved by the California Public Utilities Commission (the “CPUC”) to a California investor-owned utility,
Pacific Gas and Electric (“PG&E”). The PPA expires in November 2026.
Principal Customers
For the year ended December 31, 2022, sales to PBF Holding, Tesoro Refining and Marketing, and Phillips 66,
accounted for approximately 33%, 16%, and 10%, respectively, of our sales. At December 31, 2022, trade accounts
receivable from three customers represented approximately 33%, 16%, and 13% 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”.
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 E&P 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 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. CJWS’ revenues and earnings can be
affected by several factors, including changes in competition, fluctuations in drilling and completion activity by its
customers, 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.
24
Seasonality
Seasonal weather conditions have in the past, and in the future likely will, impact our drilling, production and
well servicing activities. Extreme weather conditions can pose challenges to meeting well-drilling and completion
objectives and production goals. Seasonal weather can also lead to increased competition for equipment, supplies
and personnel, which could lead to shortages and increased costs or delayed operations. Our operations have been,
and in the future could 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 wildfires and rain. Additionally, unusually heavy rains or
extreme temperatures can cause flooding and power outages which could adversely impact our ability to operate,
particularly in California. For example, in December of 2022, unusually poor weather caused operational challenges,
production downtime, and much higher natural gas prices in California. The extreme, adverse weather conditions
have continued in the first quarter of 2023 and impacted our production.
Among other factors, extreme cold weather conditions drove high natural gas prices in 2022. In California we
experienced a significant increase in mid-December 2022, with gas prices briefly as high as $50.79 per mmbtu. We
quickly pivoted and reduced our gas consumption in California by temporarily shutting-down one of our
cogeneration facilities and reducing steam generation in other parts of our operation, which negatively impacted
production. We seek to mitigate a substantial portion of the gas purchase exposure for our cogeneration plants by
selling excess electricity from our cogeneration operations to third parties at prices linked to the price of natural gas.
Aside from the impact gas prices have on electricity prices, these sales are generally higher in the summer months as
they include seasonal capacity amounts. Based on market prices and current and projected supply and demand
balances, our current expectation is that natural gas prices in California will continue to remain elevated through the
first half of 2023 and begin to weaken in the middle of 2023. Our hedging strategy coupled with our midstream
access to gas from the Rockies also helps mitigate the impact of the high natural gas prices on our cost structure.
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:
•
•
•
•
•
•
•
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.
25
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, reputational damage, 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 California 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.
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 in the past has resulted, and in
the future may result, in delays in the issuance of necessary permits and approvals and the imposition of onerous
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, which is
typically through either an environmental impact review or an exemption by a state or local agency.
Over the last few years, there has been a number of developments at both the California state and local levels
that resulted in delays in the issuance of new drilling permits for oil and gas activities in Kern County where all of
our California assets are located, as well as a more time- and cost-intensive permitting process. Most notably, in
Kern County, we historically have satisfied CEQA by complying with the local oil and gas ordinance, which was
supported by an Environmental Impact Report (an “EIR”) covering oil and gas operations in Kern County (the
“Kern County EIR”). In 2020, a lawsuit was filed challenging the Kern County EIR, and subsequently the California
Fifth District Court of Appeals issued a ruling invalidating a portion of the Kern County EIR until Kern County
made certain revisions to the Kern County EIR and recertified it (“Kern County Ruling”). To address the Kern
County Ruling, Kern County prepared a supplemental EIR (the “Supplemental EIR”) which was approved by the
Kern County Board of Supervisors in March 2021. Following further challenges by plaintiffs, a Kern County
26
Superior Court judge suspended use of the Supplemental EIR in October 2021 pending further review by the Court.
In June 2022, the Kern County Superior Court ruled in favor of Kern County in part but also found that the
Supplemental EIR still failed to meet the minimum requirements of CEQA. In August 2022, the Kern County Board
of Supervisors approved changes which addressed four discrete issues identified by the court in its June 2022 ruling.
The Kern County Superior Court subsequently issued a ruling in October 2022 determining that the Kern County
Supplemental EIR was not decertified, but ordered Kern County to address the four discrete issues previously
identified before the Supplemental EIR could become effective. Kern County then filed notice with the court of the
changes and on November 2, 2022, the trial court lifted the order preventing reliance on the Supplemental EIR. In
December 2022, the Kern County Superior Court denied a motion to stay this action and the plaintiffs appealed. On
January 26, 2023, the California Fifth District Court of Appeal issued a preliminary order which again suspended
use of the Supplemental EIR to meet CEQA requirements pending the outcome of a final order on Kern County’s
ability to rely on the Supplemental EIR during the appeals process. While the court has not issued a final order to
date, it is possible that use of the Supplemental EIR will remain suspended through the duration of the appeals
process, which would result in significant ongoing disruption to the permitting process in Kern County for an
extended period of time. Furthermore, if the Supplemental EIR is ultimately determined to be deficient upon
resolution of the appeals process, use of the Supplemental EIR to satisfy CEQA requirements for drilling permits
may be suspended until such deficiencies are resolved, which could extend such disruptions for the foreseeable
future. In addition, CalGEM provided notice to operators on February 2, 2023 that, in light of the preliminary order,
it would no longer recognize job cards issued by Kern County as CEQA lead agency in reliance on the Supplemental
EIR between November 2, 2022 and January 26, 2023 (the “CalGEM Notice”). Even if the California Fifth District
Court of Appeal lifts the suspension on reliance on the Supplemental EIR, there is no assurance that we will be able
to use the job cards issued by Kern County during that period or how quickly any new permits may be issued by
CalGEM.
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. Most recently, the Alameda County Superior Court denied CalGEM’s motion for judgment on the
pleadings and the lawsuit remains ongoing. 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
Supplemental EIR is ultimately deemed sufficient and reinstated.
As a result of this ongoing uncertainty, we have experienced significant delays in the issuance of permits for
new wells by CalGEM. CalGEM has not issued any new drill permits to any producer since December 2022. Until
Kern County is able to resume the ability to utilize the Supplemental EIR to demonstrate CEQA compliance, our
ability to obtain new permits and approvals to enable our future plans in Kern County requires demonstrating
compliance with CEQA to CalGEM. We were able to secure some new drill permits in 2022 from CalGEM in
specific operational areas where we did not have to rely on the Kern County EIR because the CEQA environmental
analyses had already been separately completed by a predecessor entity, which CalGEM recognized as satisfying the
CEQA compliance obligation. We believe we may have the ability to procure additional permits within these
operational areas in 2023. Demonstrating CEQA compliance without being able to reference the Supplemental EIR
or another CEQA-compliant environmental analysis is a more technical, time- and cost-intensive process and may,
among other things, require that we conduct an extensive environmental impact review.
At this time, we expect greater than 90% of our planned 2023 production will come from our base production,
with the remainder from workovers, sidetracks and other activities related to existing wellbores, as well as from
limited number of new wells drilled during the year for which we already have permits or expect to receive permits
because the wells are in areas where CEQA analysis has already been completed. As a result of the CalGEM Notice
and the Kern County EIR legal challenges, our current capital budget for 2023 has been prepared on the assumption
that no additional permits for new wells will be issued in 2023 in areas for which CEQA analysis has not already
been completed separate from the currently suspended Kern County EIR. However, we are pursuing other avenues
to obtain additional permits for new wells that, if received could enable us to expand the 2023 drilling program
contemplated under our capital budget.
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Among other things, if we are unable to obtain new well drill permits through 2024, it could result in the loss of
some amount of the proved undeveloped reserves that expire on December 31, 2024 identified in our December 31,
2022 reserve report.
Setbacks
Separately, on September 16, 2022, the California Governor signed into law Senate Bill No. 1137 which
prohibits CalGEM from permitting any new wells, or the rework of existing wells, if the proposed new drill or
rework is within 3,200 feet of certain sensitive receptors such as homes, schools or parks effective January 1, 2023.
On January 6, 2023, CalGEM’s emergency regulations to support implementation of Senate Bill No. 1137 were
approved by the Office of Administrative Law and final regulations were published. The regulations include
applicable requirements of notice to property owners and tenants regarding the work performed and offering the
sampling of test water wells or surface water before and after drilling; the contents of required notices for new
production facilities; the annual submission of a sensitive receptor inventory and sensitive receptor map and the
contents and format of the same; and the requirements of statements where operators have determined a location not
to be within a health protection zone. Additional provisions of Senate Bill No. 1137, include, among others, the
imposition of HSE controls applicable to wells located within this distance of sensitive receptors related to noise,
light, and dust pollution controls and air emission monitoring, and the immediate suspension of operations at
production facilities determined not to be in compliance with certain air emission requirements. The latter provisions
are effective January 1, 2025.
In December 2022, proponents of a voter referendum (the Referendum) collected more than the requisite
number of signatures required to put Senate Bill No. 1137 on the 2024 ballot. On February 3, 2023, the Secretary of
State of California certified the signatures and confirmed that the Referendum qualifies for the November 2024
ballot. Accordingly, Senate Bill No. 1137 is stayed until it is put to a vote, although any stay could be delayed if
there are legal challenges to the Secretary of State’s certification. However, we cannot predict any future actions by
CalGEM, the State of California, or other interested parties may take that could further limit our ability to drill in
certain areas.
The majority of our production is in rural areas in the San Joaquin basin and is unlikely to be affected by Senate
Bill No. 1137 should it permanently stay effective. We are actively pursuing mitigation efforts with respect to the
potential impacts on current and planned wells, but it is possible that we are unable to ultimately develop those
properties. We continue to assess the impacts of this rule, but we currently estimate that approximately 13% of our
overall proved reserves are within the setbacks established by Senate Bill No. 1137. We do not expect this law to
result in any material change in our overall existing proved developed producing reserves or current production
rates.
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
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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 the EPA, amongst other
measures. The State responded in October 2021 with a proposed compliance plan and a follow-up letter in August
2022 providing a mid-year update, but, to date, the 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 California 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 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 California 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. In March 2022,
CalGEM issued a Notice to Operators informing operators of new checklist documentation used in connection with
the approval of injection wells, which includes adding non-expansion infill wells. Changes in the process for
approving infill wells has the potential to delay permitting injection and other activities, and could result in increased
compliance costs on our operations. Our 2023 plans, as well as our future plans, may be 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 is no guarantee that
we can 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, CalGEM 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.
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To date, we have fulfilled the conditions of our prior idle well management plans and we will do so again in
2023 based on the submitted plan. In 2022, we spent approximately $20 million on our plugging and abandonment
activities. In 2023, we currently estimate spending will be approximately $21 million to $24 million for such
activities in order to meet our annual plugging and abandonment obligations.
Additionally, in the fourth quarter of 2021, we acquired CJWS and started a profitable new business line to
provide standard well services to the industry in California, including plugging and abandoning idle wells across
California for ourselves and other operators, as well as the State of California. We believe that CJWS is well
positioned to capture both state and federal funds to help remediate idle wells; 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 recent years the California Governor and Legislature have taken a series of actions that seek to reduce both
the supply of and demand for fossil fuels in the state. For example, in September 2022, the Governor signed Senate
Bill No. 1279 into law, which codifies an executive order previously issued by the Governor’s Office requiring the
state to achieve carbon neutrality by 2045. In addition, Governor Newsom previously issued an executive order that
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).
Separately, 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.
Additionally, President Biden signed the Inflation Reduction Act (“IRA”) into law on August 16, 2022 which,
among other things, imposes a fee on the emissions of methane from certain sources in the oil and natural gas sector
and provides significant incentives for renewable energy and low or zero carbon products. Beginning in 2024, the
IRA’s methane emissions charge imposes a fee on excess methane emissions from certain oil and gas facilities,
starting at $900 per metric ton of leaked methane in 2024 and rising to $1,200 in 2025, and $1,500 in 2026 and
thereafter. The imposition of this fee and other provisions of the IRA could increase our operating costs and
accelerate the transition away from oil and gas, which could adversely affect our business and results of operations.
Restrictions on Oil and Gas Developments on Federal Lands
As of December 31, 2022, approximately 12% and 28% of our net acreage in California and Utah, respectively,
is on federal land, which comprises approximately 10% and 12% of our total proved reserves in California and Utah,
respectively, and approximately 8% and 7% of our PUD locations in California and Utah, respectively. Additional
federal restrictions on oil and gas activities on federal lands may be imposed 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 and a permanent injunction in August 2022, effectively halting
implementation of the leasing suspension with respect to leases canceled or postponed prior to March 24, 2021.
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
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and gas leasing program, including prioritizing leasing in areas with known resource potential, and avoiding leasing
that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. The IRA
responded to one of the report’s recommendations and increased onshore royalty rates to 16⅔%. Several of the
report’s other recommendations, however, will require further 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.
With respect to major federal actions pursuant to NEPA, recent modifications may also impose further
restrictions on oil and gas activities on federal lands. In October 2021, the Biden Administration announced three
significant changes to a 2020 rule finalized under the Trump Administration. These changes included authorizing
agencies to consider the direct, indirect and cumulative effects of major federal actions including upstream and
downstream GHG emissions impacts of fossil fuel projects, allowing agencies to determine the purpose and need of
a project (thereby allowing consideration of less-harmful alternatives), and affording agencies greater flexibility in
crafting their own NEPA procedures, consistent with Council of Environmental Quality (“CEQ”) regulations, so as
to meet the agencies’ and public’s needs. To that end, in April 2022, the CEQ issued a final rule in line with the
proposed changes, a move considered as “Phase I” of the Biden Administration’s two-phased approach to modifying
NEPA. “Phase 2” of this process includes the release of a new rule proposing broader changes to NEPA regulations.
Operations on Tribal Lands
As of December 31, 2022, approximately 65% of our net acreage in Utah is on tribal lands, which comprises
approximately 69% of our total proved reserves in Utah, and approximately 88% 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 and Belridge Hill Diatomite potentially require well stimulation treatments (“WST”) (also known
as hydraulic stimulation, hydraulic fracturing or fracking). We have limited our plan in 2023 for our undeveloped
thermal Diatomite assets and we do not have any near term plans that would require WST in our Belridge Hill
Diatomite assets. 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 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 project approval letters (“PALs”) for underground
injection activities by the State Department of Finance; and (4) an independent review of the technical content of
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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. In 2023 we have plans to drill permitted wells in these thermal diatomite properties.
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. And while the BLM previously rescinded regulations imposing certain requirements on
hydraulic fracturing on federal lands in 2017, the rescission is subject to ongoing legal challenge and the regulations
may be reconsidered under the Biden Administration. Relatedly, the Biden Administration has released proposed
rules mandating that operators maintain leak detection and repair plans for operations on federal or Native American
leased land and, in November 2022, proposed a rule that would limit flaring from well sites on federal lands as well
as allow the delay or denial of permits if the agency finds an operator’s methane waste minimization plan
insufficient. The outcome of these rules could materially impact our operations in the Uinta basin, where as of
December 31, 2022, approximately 12% of our proved reserves in Utah were located on federal lands and
approximately 69% 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, California and Utah have experienced persistent and severe drought
conditions. As a result 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. Various local governments
in Utah have implemented water restrictions too. 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.
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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 Health 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 the safe and secure transportation of energy, including, with some specific exceptions, natural gas
pipelines;
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);
DOI regulations, which impose requirements on oil and gas production activities on federal lands and
establish 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:
•
•
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;
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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
local
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,
without regard to fault, legality of the original activities, or ownership or control by third parties. For the year ended
December 31, 2022, 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 2023 or that will otherwise have a material impact on our financial position,
results of operations or cash flows.
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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 E&P 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 addition to the actions described above requiring California to achieve total economy-wide carbon neutrality
by 2045, California has separately adopted a law requiring the use of 100% zero-carbon electricity within the state
by 2045. Additionally, Governor Newsom requested that the CARB analyze pathways to phase out oil extraction
across the state by no later than 2045; however, CARB’s 2022 Final Scoping Plan, the blueprint for the state’s
carbon neutrality goals, determined such a phase out was not feasible because of continued projected demand for
fossil fuels in the transportation sector notwithstanding significant projected decreases in demand for fossil fuels for
such uses by 2045. Notwithstanding this, CARB will continue to assess opportunities for phase down in its next five
year scoping plan. The 2022 Final Scoping Plan also outlines a plan to phase out natural gas use in buildings,
amongst other carbon emission reduction matters. 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. At COP27 in Sharm El-Sheik in November 2022,
countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of
inefficient fossil fuel subsidies. The United States also announced in conjunction with the European Union and other
partner countries that it would develop standards for monitoring and reporting methane emissions to help create a
market for low methane-intensity gas. Although no firm commitment or timeline to phase out or phase down all
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fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase
out in the future. 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 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 and in September 2022, the Federal Reserve announced
that six of the largest banks in the U.S. will participate in a pilot climate scenario analysis to enhance the ability of
firms and supervisors to measure and manage climate-related financial risk. The Federal Reserve began its pilot
exercise in January 2023 which is designed to analyze the impact of both physical and transition risks related to
climate change on specific assets of the banks’ portfolios. Limitation of investments in and financings for fossil fuel
energy companies could result in the restriction, delay or cancellation of drilling programs or E&P activities.
Additionally, in March 2022, the Securities and Exchange Commission (“SEC”) released a proposed rule that would
establish a framework for the reporting of climate risks, targets, and metrics. A final rule is expected to be released
in Q2 2023, but we cannot predict the final form and substance of the rule and its requirements. The ultimate impact
of the rule on our business is uncertain and, upon finalization may result in additional costs to comply with any such
disclosure requirements alongside increased costs of and restrictions on access to capital.
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.
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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.
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 E&P activities, and reduce demand for the oil and natural gas we produce.”
Human Capital Resources
As of December 31, 2022, we had 1,372 employees, all of whom are located in the United States. Of those, 889
employees are employed in our C&J Well Services business and the remainder are corporate or employed in our
E&P business. 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 and 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.
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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, neurotypicality, 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.
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 leadership team is 25% women, and Berry’s total workforce
is approximately 9% women, with the E&P segment being approximately 19% women and CJWS being
approximately 5% women.
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 HSE 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. In addition to reports filed or furnished with the
SEC, we publicly disclose material information from time to time in press releases, at annual meetings of
shareholders, in publicly accessible conferences and investor presentations, and through our website. Information
contained in or accessible through our website is not, and should not be deemed to be, part of this report.
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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
•
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•
•
•
•
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 be profitable and maintain our financial condition is highly dependent on commodity prices.
The conflict in Ukraine, related price volatility and geopolitical instability could negatively impact our
business.
The marketability of our production is dependent upon the availability of transportation and storage facilities,
most of which we do not control.
Our proved reserves and related 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.
Drilling for and producing oil and natural gas involves many uncertainties.
• 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.
• We may be unable to make attractive acquisitions or successfully integrate acquired businesses or assets or
enter into attractive joint ventures.
• We are dependent on our cogeneration facilities to produce steam for our operations. 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 commodity markets.
• 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 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 ESG matters may impact our operations and our business.
• We are subject to economic downturns and effects of public health events, such as the COVID-19 pandemic.
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.
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•
•
•
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Our business requires continual capital expenditures that we may be unable to fund.
Inflation could adversely impact our ability to control our costs.
Our hedging activities limit our ability to realize the full benefits of increases in commodity prices and may
not fully protect us against the price decreases.
Our existing debt agreements have restrictive covenants that could limit our growth, financial flexibility and
our ability to engage in certain activities and our lenders could reduce capital available to us for investment.
• We may not be able to generate sufficient cash to service our indebtedness.
•
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.
Risks Related to Regulatory Matters
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•
Our business is highly regulated and governmental authorities can delay or deny required permits and
approvals, or change the requirements governing 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.
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 E&P activities, and
reduce demand for the oil and natural gas we produce.
The Inflation Reduction Act could accelerate the transition to a low-carbon economy and could impose new
costs on our operations.
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 excise tax on repurchases of corporate stock included in the Inflation Reduction Act of 2022 could
increase our tax burden and influence our share repurchase decisions.
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.
•
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Due to losing emerging growth company status in 2023, we expect to incur additional costs.
Our internal control over financial reporting is not currently required to meet all of the standards of Section
404 of the Sarbanes-Oxley Act.
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.
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.
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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.
The timeline for obtaining permits for our operations in California, including from CalGEM, is and from time to
time has been subject to significant delays and uncertainties, and we can provide no assurance that we will always be
able to successfully navigate these risks and timely obtain permits or obtain them on favorable terms. In addition,
third parties, including individual citizens and non-governmental organizations, may challenge or appeal any permits
we receive, leading to further delays. 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. As a result of
ongoing regulatory uncertainty in California, our capital program for 2023 has been prepared based on the
assumption that no permits for new wells will be issued under the Kern County EIR in 2023. If we are unable to
timely receive the permits and other approvals needed 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 located, we historically have satisfied CEQA by
complying with the local oil and gas ordinance, which was supported by an Environmental Impact Report (an
“EIR”) covering oil and gas operations in Kern County (the “Kern County EIR”). In 2020, a lawsuit was filed
challenging the Kern County EIR, and subsequently the California Fifth District Court of Appeals issued a ruling
invalidating a portion of the Kern County EIR until Kern County made certain revisions to the Kern County EIR and
recertified it (“Kern County Ruling”). To address the Kern County Ruling, Kern County prepared a supplemental
EIR (the “Supplemental EIR”) which was approved by the Kern County Board of Supervisors in March 2021.
Following further challenges by plaintiffs, a Kern County Superior Court judge suspended use of the Supplemental
EIR in October 2021 pending further review by the Court. In June 2022, the Kern County Superior Court ruled in
favor of Kern County in part but also found that the Supplemental EIR still failed to meet the minimum
requirements of CEQA. In August 2022, the Kern County Board of Supervisors approved changes which addressed
four discrete issues identified by the court in its June 2022 ruling. The Kern County Superior Court subsequently
issued a ruling in October 2022 determining that the Kern County Supplemental EIR was not decertified, but
ordered Kern County to address the four discrete issues previously identified before the Supplemental EIR could
become effective. Kern County then filed notice with the court of the changes and on November 2, 2022, the trial
court lifted the order preventing reliance on the Supplemental EIR. In December 2022, the Kern County Superior
Court denied a motion to stay this action and the plaintiffs appealed. On January 26, 2023, the California Fifth
District Court of Appeal issued a preliminary order reinstating the suspension of the Supplemental EIR to meet
CEQA requirements pending the outcome of a final order on Kern County’s ability to rely on the Supplemental EIR
during the appeals process. While the court has not issued a final order to date, it is possible that use of the
Supplemental EIR will remain suspended through the duration of the appeals process, which would result in
significant ongoing disruption to the permitting process in Kern County for an extended period of time. Furthermore,
if the Supplemental EIR is ultimately determined to be deficient upon resolution of the appeals process, use of the
Supplemental EIR to satisfy CEQA requirements for drilling permits may be suspended until such deficiencies are
resolved, which could extend such disruptions for the foreseeable future. In addition, CalGEM provided notice to
operators on February 2, 2023 that, in light of the preliminary order, it would no longer recognize job cards issued
by Kern County as CEQA lead agency in reliance on the Supplemental EIR between November 2, 2022 and January
26, 2023 (the “CalGEM Notice”). We were issued a number of job cards from Kern County during this period that
we expected would be available for our drilling program in 2023. Even if the California Fifth District Court of
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Appeal lifts the suspension on reliance on the Supplemental EIR, there is no assurance that we will be able to use
those previously-issued permits or how quickly any new permits may be issued by CalGEM. For additional
information, see “Regulatory Matters – California Permitting Considerations.”
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. Most recently, the Alameda County Superior Court denied CalGEM’s motion for judgment on the
pleadings and the lawsuit remains ongoing. We cannot predict its ultimate outcome or whether it could result in
changes to the requirements for demonstrating compliance with CEQA and the permitting process, even if the
Supplemental EIR is ultimately deemed sufficient and reinstated. The potential impact of this and potentially future
litigation contributes to the uncertainty with respect to our ability to timely obtain the permits and approvals needed
to conduct our operations.
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. At
this time we expect that greater than 90% of our planned 2023 production will come from our base production, with
the remainder from workovers and other activities related to existing wellbores, as well as from a limited number of
new wells drilled during the year for which we already have permits. As a result of the CalGEM Notice and the Kern
County EIR legal challenges, our current capital budget for 2023 has been prepared on the assumption that no
permits for new wells will be issued in the area covered by the Kern County EIR in 2023. Furthermore, if we are
unable to obtain new well drill permits through the Supplemental EIR or other avenues for CEQA compliance
through 2024, we expect there to be a material impact on our 2024 capital plan and certain of our proved
undeveloped reserves will expire at the end of 2024. Based on our reserves as of December 31, 2022, if we are
unable to obtain permits for new wells through 2024, it will likely result in the loss of some amount of the proved
undeveloped reserves expiring at the end of 2024. In addition, any 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 E&P 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. 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, reputational damage 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.
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
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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 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 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 September 2022, the California Governor signed Senate Bill No. 1279 into law, codifying an
executive order previously issued by the Governor’s Office requiring the state to achieve carbon neutrality
by 2045. In addition, Governor Newsom previously issued an executive order that 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 vehicles with internal combustion engines;
(2) 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.
•
In September 2022, the California Governor signed into law Senate Bill No. 1137 which prohibits
CalGEM from permitting any new wells, or the rework of existing wells, if the proposed new drill or
rework is within 3,200 feet of certain sensitive receptors such as homes, schools or parks effective January
1, 2023. On January 6, 2023, CalGEM’s emergency regulations to support implementation of Senate Bill
No. 1137 were approved by the Office of Administrative Law and final regulations were published. The
regulations include applicable requirements of notice to property owners and tenants regarding the work
performed and offering the sampling of test water wells or surface water before and after drilling; the
contents of required notices for new production facilities; the annual submission of a sensitive receptor
inventory and sensitive receptor map and the contents and format of the same; and the requirements of
statements where operators have determined a location not to be within a health protection zone. Additional
provisions of Senate Bill No. 1137 would also require pollution controls for existing wells and facilities
within the same 3,200-foot setback area. Senate Bill No. 1137 is currently stayed pending a vote of the
California General Election in November 2024. However, the stay could be delayed if there are legal
challenges to the Secretary of State’s certification. We continue to assess the impacts of Senate Bill No.
1137 and CalGEM’s regulations, but we currently estimate that approximately 13% of our overall proved
reserves are within the setbacks established by Senate Bill No. 1137. We do not expect this law to result in
any material change in our overall existing proved developed producing reserves or current production
rates.
The clear trend in California is to impose increasingly stringent restrictions on oil and natural gas activities. We
cannot predict what actions the Governor of California, the Legislature, or state agencies may take in the future, but
we could face increased compliance costs, delays in obtaining the approvals necessary for our operations, exposure
to increased liability, or other limitations as a result of future actions by these parties. Moreover, new developments
resulting from the current and future actions of these parties could also materially and adversely affect our ability to
operate, successfully execute drilling plans, or otherwise develop our reserves. Accordingly, recent and future
actions by the Governor of California, the Legislature, and state agencies could materially and adversely affect our
business, results of operations, and financial condition.
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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 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:
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•
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overall domestic and global political and economic conditions, including the imposition of tariffs or trade
or other economic sanctions, political instability or armed conflict, including the ongoing conflict in
Ukraine, rising inflation levels and government efforts to reduce inflation, or a prolonged recession;
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;
the actions of OPEC and/or OPEC+;
the price and quantity of imports of foreign oil and natural gas;
the level of global oil and natural gas E&P 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
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, such as the ongoing conflict in
Ukraine, 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. Refer to Item 7—“Management’s Discussion and
Analysis of Financial Condition and Results of Operations—Business Environment and Market Conditions”.
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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 conflict in Ukraine and related price volatility and geopolitical instability could negatively impact our
business.
In late February 2022, Russia launched significant military action against Ukraine. The conflict has caused, and
could intensify, volatility in the prices of natural gas, oil and NGLs, and the extent and duration of the military
action, sanctions and resulting market disruptions have been significant and could continue to have a substantial
impact on the global economy and our business for an unknown period of time. There is evidence that the increase
in crude oil prices during the first half of calendar year 2022 was partially due to the impact of the conflict between
Russia and Ukraine on the global commodity and financial markets, and in response to economic and trade sanctions
that certain countries have imposed on Russia. Alternatively, a cessation of the hostilities between Russia and
Ukraine as a result of a negotiated withdrawal or otherwise could cause commodity prices to decline, which would
reduce the revenues we receive for our oil and gas production. Any such volatility and disruptions may also magnify
the impact of the other risks described in this “Risk Factors” section.
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
charges to our earnings. A reduction in our reserves could also result in a reduction to our borrowing base under the
2021 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
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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:
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•
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•
•
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, including our ability to obtain permits in a timely manner, or at all,
for proved undeveloped reserves; 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 our ability to obtain 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 2021 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
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
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expenditures. Furthermore, beginning in the second quarter of 2022, we adjusted our 2022 capital development
program due to the delays in permit issuance and insufficient permit inventory. As a result of ongoing regulatory
uncertainty in California, our 2023 capital program has been prepared based on the assumption that no permits for
new wells will be issued under the Kern County EIR in 2023. If we are unable to obtain new well drill permits
through 2024, it will likely result in the loss of some amount of the proved undeveloped reserves expiring at the end
of 2024.
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:
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•
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:
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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 California’s recently adopted setback rules, 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
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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
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 3% of our total net acreage at December 31, 2022.
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 2023 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 16% of our steam
capacity and approximately 55% 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
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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
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, floods or other natural disasters or extreme weather events.
We currently conduct operations in California near known wildfire and mudslide areas and earthquake fault
zones. A future natural disaster, or extreme weather event, such as a fire, mudslide, flood, drought 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. For example, in December of 2022, severe winter storms caused
operational challenges, production downtime, and much higher natural gas prices in California. Extreme, adverse
weather conditions, including flooding, have continued in the first quarter of 2023 and impacted our operations and
production levels. 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, floods 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 E&P 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
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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
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, or our inability to successfully adapt to the new executive
leadership team, could adversely affect our results and 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.
In November 2022, we announced a significant change to our management team, including effective January 1,
2023, the Chief Executive Officer transitioning to the role of Executive Chair, the Chief Financial Officer
temporarily retaining his role as member of the Board and serving as strategic advisor to the new management team
(to terminate March 4, 2023), and the promotion of a new Chief Executive Officer (our former Chief Operating
Officer, which position was eliminated), President (our former General Counsel and Corporate Secretary), Chief
Financial Officer (our Chief Accounting Officer, which position he also has maintained) and General Counsel and
Corporate Secretary (our former Associate General Counsel). Although the newly appointed executive team has
extensive experience with the Company and our industry, this leadership transition may result in changes to our
management style, operations and strategies. Any significant leadership change or senior management transition
involves inherent risk and any failure to ensure a smooth transition could hinder our strategic planning, business
execution and future performance. In particular, this or any future leadership transition may result in a loss of
personnel with deep institutional or technical knowledge and changes in business strategy or objectives, and has the
potential to disrupt our operations and relationships with employees and customers due to added costs, operational
inefficiencies, changes in strategy, decreased employee morale and productivity and increased turnover. Failure to
successfully transition to the new leadership team could affect our ability to attract and retain skilled personnel and
could have an adverse effect on our results of operations, business and financial position.
Information technology and operational 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. User access and security of our sites and systems are critical
elements of our operations, as are cloud security and protection against cybersecurity incidents. 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. We have
experienced cybersecurity incidents but have not suffered any material adverse impacts to our business and
operations as a result of such incidents. 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, misdirected wire transfers,
or other adverse events. 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, including
regulatory enforcement, violation of privacy or securities laws and regulations, and individual or class action claims.
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The energy industry has become increasingly dependent on digital technologies to conduct day-to-day
operations, and the use of mobile communication devices has rapidly increased. Industrial control systems such as
supervisory control and data acquisition (“SCADA”) systems now control large-scale processes that can include
multiple sites across long distances. The Company’s technologies, systems, networks, including its SCADA system,
and those of its business partners may become the target of cyber-attacks or security breaches.
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.
However, we cannot guarantee that there will be sufficient offsets available for purchase given the increased demand
from numerous businesses implementing net zero goals, or that, notwithstanding our reliance on any reputable third
party registries, that the offsets we do purchase will successfully achieve the emissions reductions they represent.
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.
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.
Public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets,
or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny
from public and governmental authorities related to the risk of potential “greenwashing,” i.e. misleading information
or false claims overstating potential ESG benefits. For example, in March 2021, the SEC established the Climate and
ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including
greenwashing. Certain non-governmental organizations and other private actors have also filed lawsuits under
various securities and consumer protection laws alleging that certain ESG statements, goals, or standards were
misleading, false, or otherwise deceptive. As a result, we may face increased litigation risks from private parties and
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governmental authorities related to our ESG efforts. In addition, any alleged claims of greenwashing against us or
others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could
face increasing costs as we attempt to comply with and navigate further ESG-related focus and scrutiny.
Such ESG matters may also impact our customers or suppliers, which may adversely impact our business,
financial condition, or results of operations.
We are subject to economic downturns and the effects of public health events, such as the COVID-19 pandemic,
which may materially and adversely affect the demand and the market price for our products.
The COVID-19 pandemic has adversely affected the global economy, and has resulted in, among other things,
travel restrictions, business closures and the institution of quarantining and other mandated and self-imposed
restrictions on movement. The severity, magnitude and duration of COVID-19 or another pandemic, the extent of
actions that have been or may be taken to contain or treat their impact, and the impacts on the economy generally
and oil prices in particular, are uncertain, rapidly changing and hard to predict. This uncertainty could force us to
reduce costs, including by decreasing operating expenses and lowering capital expenditures, and such actions could
negatively affect future production and our reserves. We may experience labor shortages if our employees are
unwilling or unable to come to work because of illness, quarantines, government actions or other restrictions in
connection with the pandemic. If our suppliers cannot deliver the materials, supplies and services we need, we may
need to suspend operations. In addition, we are exposed to changes in commodity prices which have been and will
likely remain volatile. We cannot predict the duration and extent of the pandemic's adverse impact on our operating
results.
Additionally, to the extent the COVID-19 pandemic or any resulting worsening of the global business and
economic environment adversely affects our business and financial results, it may also have the effect of heightening
or exacerbating many of the other risks described in the “Risk Factors” herein.
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
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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 2023 capital expenditure budget of between $95 to $105 million,
excluding CJWS capital of approximately $8 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. Our current capital program for 2023 focuses on new wells drilled
during the year for which we already have permits or have existing CEQA analysis completed, and otherwise
focuses on workovers and other activities related to existing wellbores. As a result of ongoing regulatory uncertainty
in California, the capital program has been prepared based on the assumption that no permits for new wells will be
issued under the Kern County EIR in 2023. In addition, 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 2023 capital expenditures with cash flows from our operations, supplemented by cash
which was built as excess free cash flow 2022; however, our cash flows from operations, and access to capital
should such cash flows and cash prove inadequate, are subject to a number of variables, including:
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the volume of hydrocarbons we are able to produce from existing wells and our ability to bring those to
market;
the prices at which our production is sold and our operating expenses;
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 2021 RBL Facility;
and our ability to access the capital markets.
If our revenues or the borrowing base under the 2021 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 2021 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.
The U.S. inflation rate has been steadily increasing since 2021 and throughout much of 2022. Such inflationary
pressures have resulted from supply chain disruptions caused by the COVID pandemic, increased demand, labor
shortages and other factors, including the conflict between Russia and the Ukraine which began in late February
2022. Similar to other companies in our industry, we have experienced inflationary pressures on our operating costs
- namely inflationary pressures have resulted in increases to the costs of our goods, services and personnel, which in
turn, have caused our capital expenditures and operating costs to rise. Although inflation rates started to stabilize in
late 2022 and even decrease from the levels experienced earlier in the year, we are unable to accurately predict if
such inflationary pressures and contributing factors will continue into 2023. To the extent elevated inflation remains,
we may experience further cost increases for our operations, including natural gas purchases and oilfield services
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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 proved developed
producing (“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.
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
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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 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, 2022, we have hedged gas purchases at the following approximate volumes and prices:
45,800 mmbtu/d at $5.14 per mmbtu in 2023.
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 2021 RBL Facility is subject to
periodic redeterminations and our lenders could reduce capital available to us for investment.
The 2021 RBL Facility, the 2022 ABL 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;
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•
•
•
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 2021 RBL Facility and the 2022 ABL Facility require us and CJWS, respectively, 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 2021 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 2021 RBL Facility. We, the administrative agent and lenders, each may request one additional
redetermination 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 2021 RBL Facility. For example, the 2021 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 2021 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 2021
RBL Facility to the extent that after a redetermination our outstanding borrowings at such time exceed the
redetermined borrowing base. The 2022 ABL Facility is also subject to adjustments to the borrowing base.
For additional details regarding the terms of the 2021 RBL Facility, the 2022 ABL 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, 2022, 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. As of December
31, 2022, CJWS had no borrowings outstanding with $13 million of available borrowing capacity under the 2022
ABL Facility. Our ability to make scheduled payments on or to refinance our debt obligations, including the 2021
RBL Facility, the 2022 ABL 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 2021 RBL Facility, the 2022 ABL 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.
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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.
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, 2022, sales to PBF Holding, Tesoro Refining and Marketing, and Phillips 66 accounted for
approximately 33%, 16%, and 10%, 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 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.
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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 2023. 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 vehicles with internal combustion engines; 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. 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 prospects. For additional information, see 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 2022 we
paid $20 million in asset retirement obligations, an increase from $19 million in 2021, largely due to the new idle
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well regulations and HSE 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 are 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
E&P 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 CWA has been subject to substantial uncertainty in recent years, which has the potential to
increase permitting burdens. The EPA and the U.S. Army Corps of Engineers (“Corps”) under the Obama, Trump
and Biden Administrations have pursued multiple rulemakings since 2015 in an attempt to determine the scope of
the term “Waters of the United States” (“WOTUS”), and, in several instances, federal courts have vacated these
rulemakings. In December 2022, the EPA and Corps released a final revised definition of WOTUS founded upon a
pre-2015 definition and including updates to incorporate existing Supreme Court decisions and agency guidance.
The new rule was officially published on January 18, 2023, to be effective on March 20, 2023. However, the new
rule has already been challenged with the State of Texas and industry groups filing separate suits in federal court in
Texas on January 18, 2023. Moreover, in October 2022, the Supreme Court heard arguments in Sackett v. EPA,
which involves issues relating to the legal tests used to determine whether wetlands are WOTUS. The Supreme
Court is expected to release an opinion in this case in 2023, which could impact the regulatory definition and its
implementation. As a result of these developments, the scope of the CWA remains uncertain at this time. To the
extent the final 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. Such proposed legislation has included, but
has not been limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii)
repealing the percentage depletion allowance for oil and natural gas properties, (iii) extending the amortization
period for certain geological and geophysical expenditures, (iv) eliminating certain other tax deductions and relief
previously available to oil and natural gas companies, and (v) increasing the U.S. federal income tax rate applicable
to corporations (such as us). 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.
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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.
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 E&P 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 E&P 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 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 published a
supplemental proposal in November 2022 for public comment. Among other items, the proposal sets forth specific
revisions strengthening the first nationwide emissions guidelines for states to limit methane from existing oil and gas
facilities, revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the
frequency of monitoring surveys, establishes a “super-emitter” program to timely mitigate emissions events, and
provides additional options for the use of advanced monitoring to encourage the deployment of innovative
technologies to detect and reduce methane emissions. The proposal is expected to be finalized in 2023, though it will
likely be challenged in court. We cannot predict 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
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significant possibility. Additionally, the IRA, signed into law on August 16, 2022, imposes a fee on the emissions of
methane from certain sources in the oil and natural gas sector. Beginning in 2024, the methane emissions charge
would begin at $900 per metric ton of leaked methane, rising to $1,200 in 2025, and $1,500 in 2026 and thereafter.
Calculation of the fee is based on certain thresholds established in the IRA. The imposition of this fee and other
provisions of the IRA could increase our operating costs and accelerate the transition away from oil and gas, which
could adversely affect our business and results of operations.
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 addition to the various actions described requiring California to achieve total economy-wide carbon neutrality
by 2045 California has separately adopted a law requiring the use of 100% zero-carbon electricity within the state by
2045. Additionally, Governor Newsom requested that the CARB analyze pathways to phase out oil extraction across
the state by no later than 2045; however, CARB’s 2022 Final Scoping Plan, the blueprint for the state’s carbon
neutrality goals, determined such a phase out was not feasible because of continued projected demand for fossil fuels
in the transportation sector notwithstanding significant projected decreases in demand for fossil fuels for such uses
by 2045. Notwithstanding this, CARB will continue to assess opportunities for phase down in its next five year
scoping plan. The 2022 Final Scoping Plan also outlines a plan to phase out natural gas use in buildings, amongst
other carbon emission reduction matters. 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, 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. At COP27 in Sharm El-Sheik in November 2022, countries reiterated the
agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel
subsidies. The United States also announced in conjunction with the European Union and other partner countries
that it would develop standards for monitoring and reporting methane emissions to help create a market for low
methane-intensity gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was
made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future.
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”.
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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 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 NGFS, a consortium of financial
regulators focused on addressing climate-related risks in the financial sector and in September 2022, announced that
six of the U.S.’ largest banks will participate in a pilot climate scenario analysis to enhance the ability of firms and
supervisors to measure and manage climate-related financial risk. The Federal Reserve began its pilot exercise in
January 2023 which is designed to analyze the impact of both physical and transition risks related to climate change
on specific assets of the banks’ portfolios. 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, in March 2022, the SEC released a
proposed rule that would establish a framework for the reporting of climate risks, targets, and metrics. A final rule is
expected to be released in Q2 2023, but we cannot predict the final form and substance of the rule and its
requirements. The ultimate impact of the rule on our business is uncertain and, upon finalization, may result in
additional costs to comply with any such disclosure requirements, alongside increased costs of and restrictions on
access to capital.
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.
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The Inflation Reduction Act could accelerate the transition to a low-carbon economy and could impose new costs
on our operations.
In August 2022, President Biden signed the IRA into law. The IRA contains hundreds of billions of dollars in
incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting
infrastructure and CCS, amongst other provisions. In addition, the IRA imposes the first ever federal fee on the
emission of GHGs through a methane emissions charge. The IRA amends the Clean Air Act to impose a fee on the
emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the
onshore petroleum and natural gas production categories. The methane emissions charge would start in calendar year
2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year thereafter.
Calculation of the fee is based on certain thresholds established in the IRA. In addition, the multiple incentives
offered for various clean energy industries referenced above could further accelerate the transition of the economy
away from fossil fuels towards lower- or zero-carbon emission alternatives. The methane charges and various
incentives for clean energy industries could decrease demand for crude oil and natural gas, increase our compliance
and operating costs and consequently materially and adversely affect our business and results of operations.
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.
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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.
A large portion of our common stock is beneficially owned by a relatively small number of stockholders. 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
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 “2017 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 2017 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. On March 1, 2022, our
board of directors approved the 2022 Omnibus Incentive Plan (the “2022 Omnibus Plan”), which was subsequently
approved by stockholders on May 25, 2022. The plan authorized the issuance of 2,300,000 shares of common stock.
The maximum number of shares remaining that may be issued is 1,573,402 as of December 31, 2022.
The excise tax on repurchases of corporate stock included in the Inflation Reduction Act of 2022 could increase
our tax burden and influence our share repurchase decisions.
Beginning January 1, 2023, a 1% federal excise tax is imposed on certain publicly traded corporations that
repurchase stock from their shareholders. The amount subject to the excise tax is the fair market value of stock
repurchased by such corporation net of the fair market value of any stock issued by such corporation during such
taxable year. Any redemptions made in connection with our stock repurchase program, or otherwise, may be subject
to this excise tax. There can be no assurance that there will be sufficient new issuances during the same taxable year
to offset the fair market value of the redemptions. Consequently, if we are subject to this excise tax, it could
influence our share repurchase decisions and increase our tax burden.
The payment of dividends will be at the discretion of our board of directors.
We temporarily discontinued our quarterly dividends in the second quarter of 2020 following the historic oil
price drop and economic impact of COVID-19. We reinstated a quarterly dividend at a reduced rate beginning with
the first quarter of 2021 and then increased the rate 50% to $0.06 per share beginning with the third quarter of 2021,
which continued through the end of 2022. In 2022, the Company's Board of Directors approved quarterly fixed
dividends totaling $0.24 per share in 2022. In addition, the Board of Directors implemented a shareholder return
strategy that contemplates additional dividends to shareholders from Adjusted Free Cash Flow. As a result of the
implementation of this shareholder return strategy, the Company's Board of Directors declared variable cash
dividends of $1.54 per share, which were based on the results in 2022. The Company's Board of Directors declared a
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regular fixed and variable dividend of $0.50 per share on the Company’s outstanding common stock, payable on
March 23, 2023 to shareholders of record at the close of business on March 15, 2023. There is no certainty that we
will generate Adjusted Free 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, and other factors our Board deems relevant. Additionally, covenants
contained in our 2021 RBL Facility, 2022 ABL Facility and the indenture 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.
Due to losing emerging growth company status on December 31, 2023, we expect to incur additional costs and
demands will be placed upon management in connection with complying with non-emerging growth company
requirements.
As an emerging growth company, we have benefited from certain temporary exemptions from various reporting
requirements. On December 31, 2023, we will lose emerging growth company status due reaching the fifth
anniversary of our IPO. This transition from emerging growth company status will require us to, among other things,
allow our independent registered public accounting firm to attest to the effectiveness of our internal controls as
required by Section 404(b) of the Sarbanes-Oxley Act in our Annual Report on Form 10-K for the year ending
December 31, 2023.
In addition, as an emerging growth company we had elected under the JOBS Act to delay adoption of new or
revised accounting pronouncements applicable to public companies until such pronouncements are made applicable
to private companies. As a result of losing emerging growth company status as of December 31 2023, we will no
longer be eligible to delay adoption of such new or revised accounting pronouncements applicable to public
companies. In addition to some immaterial expenses, mainly for our independent registered public accounting firm
to attest to the effectiveness of our internal controls over financial reporting, our management may need to devote
significant time and efforts to implement and comply with the additional standards, rules and regulations that will
apply to us losing our emerging growth company status, which may divert such time from the day-to-day conduct of
our business operations. Also, due to the complexity and logistical difficulty of implementing the standards, rules
and regulations that apply to non-emerging growth companies, such as Section 404(b) of the Sarbanes-Oxley Act, on
an accelerated timeframe, the risk of our non-compliance with such standards, rules and regulations or of significant
deficiencies or material weaknesses in our internal controls over financial reporting is increased.
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
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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 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.
In addition, we expect to lose “emerging growth company” status in 2023 as a result of passing the fifth
anniversary of our IPO. This transition from “emerging growth company” status will require, among other things,
that our independent registered public accounting firm attest to the effectiveness of our internal controls as required
by Section 404(b) of the Sarbanes-Oxley Act in our Annual Report on Form 10-K for the year ending December 31,
2023. In addition, we will no longer be eligible to delay adoption of such new or revised accounting pronouncements
applicable to public companies. In addition to additional expenses, our management may need to devote significant
time and efforts to implement and comply with the additional standards, rules and regulations that will apply to us
losing our “emerging growth company” status, which may divert such time from the day-to-day conduct of our
business operations.
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. We expect to lose
“emerging growth company” status on December 31, 2023.
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.
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
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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
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.
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On November 1, 2021, the court-appointed 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 and on September 13, 2022, the Court issued an
order denying that motion. The case is now in discovery.
We dispute these claims and intend to defend the matter vigorously. Given the uncertainty of litigation, the early
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.
On October 20, 2022, a shareholder derivative lawsuit was filed in the United States District Court for the
Northern District of Texas by putative stockholder George Assad, allegedly on behalf of the Company, that piggy-
backs on the securities class action referenced above and which is currently pending before the same Court. The
derivative complaint names certain current and former officers and directors as defendants, and generally alleges
that they breached their fiduciary duties by causing or failing to prevent the securities violations alleged in the
securities class action. The derivative complaint also alleges claims for unjust enrichment as against all defendants,
and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act. On January 27,
2023, the court granted the parties’ joint stipulated request to stay the derivative action pending resolution of the
related securities class action. The Company and the individual defendants believe the claims in the shareholder
derivative action are without merit and intend to defend vigorously against them, but there can be no assurances as
to the outcome. At this time, we are unable to estimate the probability or the amount of liability, if any, related to
this matter.
On January 20, 2023, a second shareholder derivative lawsuit was filed, this time in the United States District
Court for the District of Delaware, by putative stockholder Molly Karp allegedly on behalf of the Company, again
piggy-backing on the securities class action referenced above. This complaint, similar to the first derivative
complaint, is brought against certain current and former officers and directors of the Company, asserting breach of
fiduciary duty, aiding and abetting, and contribution claims based on the defendants allegedly having caused or
failed to prevent the securities violations alleged in the securities class action. In addition, the complaint asserts a
claim under Section 14(a) of the Exchange Act, alleging that Berry’s 2022 Proxy Statement was false and
misleading in that it suggested the Company’s internal controls were sufficient and the board of directors was
adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the
case. The defendants believe the claims in the shareholder derivative action are without merit and intend to defend
vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate
the probability or the amount of liability, if any, related to this matter.
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, 2023.
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 dividends through commodity price cycles.
We first began paying a quarterly dividend 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 of 2020 following the historic oil price drop and economic impact of COVID-19. We reinstated a quarterly
dividend at a reduced rate beginning with the first quarter of 2021 and then increased the rate 50% to $0.06 per share
beginning with the third quarter of 2021, which continued through the end of 2022. In February 2023, our Board of
Directors declared a fixed dividend of $0.06 per share, as well as, the variable cash dividend of $0.44 per share
based on the fourth quarter of 2022 results. The dividends are payable on March 23, 2023 to shareholders of record
at the close of business on March 15, 2023. 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, and other factors our Board deems relevant. See “Item 1A. Risk Factors— Risks
Related to our Capital Stock—The payment of dividends will be at the discretion of our board of directors.”
Our shareholder return model went into effect January 1, 2022. Like our business model, this shareholder return
model is simple and demonstrates our commitment to optimize capital allocation and returns to our shareholders.
The model is based on our Adjusted Free Cash Flow (formerly called Discretionary Free Cash Flow), which is
defined as cash flow from operations less regular fixed dividends and maintenance capital. Maintenance capital,
which represents the capital expenditures needed to optimize production volumes for a given year, is defined as
capital expenditures, excluding, when applicable, (i) E&P capital expenditures that are related to strategic business
expansion, such as acquisitions and divestitures of oil and gas properties and any exploration and development
activities to increase production beyond the prior year’s annual production volumes, (ii) capital expenditures in our
well servicing and abandonment segment, (iii) corporate expenditures that are related to ancillary sustainability
initiatives and/or (iv) other expenditures that are discretionary and unrelated to maintenance of our core business.
The initial allocation of Adjusted Free Cash Flow in 2022 was contemplated as: (a) 60% predominantly in the form
of variable cash dividends to be paid quarterly, as well as opportunistic debt repurchases; and (b) 40% which could
be used for opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our
short- and long-term sustainability initiatives, share repurchases, and/or capital retention.Our Adjusted Free Cash
Flow in 2022 was $200 million. In accordance with our shareholder return model in 2022 we will have paid a total
of $189 million related to 2022 performance which consisted of: (i) $119 million for the variable cash dividends, (ii)
$19 million for fixed cash dividends and (iii) $51 million for share repurchases.
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In early February 2023, we updated our shareholder return model, including the plan to double our quarterly
fixed dividend to $0.12 per share. We also modified the allocations of Adjusted Free Cash Flow. Our goal is to
continue maximizing shareholder value through overall returns. Starting with the first quarter of 2023, the allocation
of Adjusted Free Cash will be (a) 80% primarily in the form of opportunistic debt or share repurchases; and (b) 20%
in the form of variable dividends. Any dividends (fixed or variable) actually paid will be determined by our Board of
Directors in light of then existing conditions, including our earnings, financial condition, restrictions in financing
agreements, business conditions and other factors.
Securities Authorized for Issuance Under Equity Compensation Plans
On June 27, 2018, our Board approved our second amended and restated 2017 Omnibus Incentive Plan (the
“2017 Omnibus Plan”). A description of the plans can be found in Item 8. Financial Statements and Supplementary
Data – Note 6–Equity. On March 1, 2022, our Board approved the 2022 Omnibus Incentive Plan (the “2022
Omnibus Plan”), which was subsequently approved by stockholders on May 25, 2022. The plan authorized the
issuance of an additional 2,300,000 shares of common stock, bringing the total between the 2017 Omnibus Plan and
the 2022 Omnibus Plan to 12,300,000 shares. There have been approximately 10,700,000 million shares issued or
reserved through December 31, 2022.
The following table summarizes information related to our equity compensation plans under which our equity
securities are authorized for issuance as of December 31, 2022.
Plan Category
Number of Securities to be
Issued Upon Exercise of
Outstanding Options and
Rights (#)(1)
Weighted-Average Exercise
Price of Outstanding Options
and Rights ($)(2)
Number of Securities
Remaining Available for
Future Issuance Under Equity
Compensation Plans (#)(3)
Equity compensation plans not
approved by security holders(4)
Equity compensation plans
approved by security holders(5)
Total
________________
5,810,302
2,300,000
8,110,302
N/A
N/A
N/A
—
1,573,402
1,573,402
(1) This column reflects the number of shares of our common stock subject to outstanding restricted stock units (“RSU”) awards and
performance-based restricted stock unites (“PSU”) awards as of December 31, 2022, after counting the outstanding PSU awards at the
maximum payout level. Because the number of shares to be issued upon settlement of outstanding PSU awards is subject to performance
conditions, the number of shares actually issued may be substantially less than the number reflected in this column. No options or warrants
have been granted under the 2022 Omnibus Plan.
(2) No options or warrants have been granted under the 2022 Omnibus Plan, and the RSU and PSU awards reflected in column (a) are not
reflected in this column, as they do not have an exercise price.
(3) This column reflects the total number of shares of our common stock remaining available for issuance under the 2022 Omnibus Plan as of
December 31, 2022, after counting the number of securities to be issued upon vesting of outstanding RSU and PSU awards as of December
31, 2022, and counting PSUs at the maximum payout level. Shares reserved at maximum payout that do not vest at max are made available
for future grants.
(4)
In connection with our initial public offering, our Board approved the Berry Petroleum Corporation Second Amended and Restated 2017
Omnibus Incentive Plan, effective June 27, 2018. The 2017 Omnibus Incentive Plan allows us to grant equity-based compensation awards
(including stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents and other types
of 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 prior plans), to
employees, consultants and directors of the Company and its affiliates who perform services for the Company.
(5) On March 1, 2022 our Board approved the 2022 Omnibus Plan, which was subsequently approved by stockholders on May 25, 2022. The
plan authorized the issuance of and additional 2,300,000 shares of common stock.
70
Sales of Unregistered Securities
None.
Stock Repurchase Program
For the year ended December 31, 2022, we repurchased 5 million shares for approximately $51 million. As of
December 31, 2022, the Company had repurchased a total of 10,528,704 shares under the share repurchase program
for approximately $104 million in aggregate, which is 14% of outstanding shares as of December 31, 2022. As
previously disclosed, the Company implemented a shareholder return model in early 2022, for which the Company
intends to allocate a portion of Adjusted Free Cash Flow to opportunistic share repurchases.
In April 2022, our Board of Directors approved an increase of $102 million to the Company’s share repurchase
authorization, bringing the Company’s remaining share repurchase authority to $150 million. As of December 31,
2022, the Company’s remaining total share repurchase authority was $98 million. In February 2023, the Board of
Directors approved an increase of $102 million to the Company’s share repurchase authorization bringing the
Company’s remaining share authority to $200 million. The Board’s authorization permits the Company to make
purchases of its common stock from time to time in the open market and in privately negotiated transactions, subject
to market conditions and other factors, up to the aggregate amount authorized by the Board. The Board’s
authorization has no expiration date.
The Company’s 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.
Period
Total Number
of Shares
Purchased
Average Price
Paid per
Share
Total Number of Shares
Purchased as Part of Publicly
Announced Plans or Programs
Approximate Dollar Value of
Shares that May Yet Be Purchased
Under the Plan
October 1 – 31, 2022
— $
November 1 – 30, 2022
1,000,000 $
December 1 – 31, 2022
— $
Total
1,000,000 $
—
9.60
—
9.60
— $
1,000,000 $
— $
1,000,000 $
—
98,261,000
—
98,261,000
Item 6. [Reserved]
71
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 2022 and 2021 items and year-to-year comparisons between
those years. For discussion of our year ended December 31, 2020, as well as the year ended 2021 compared to year
ended 2020, refer to Part II, Item 7— “Management's Discussion and Analysis of Financial Condition and Results
of Operations” of our 2021 Annual Report on Form 10-K.
Executive Overview
We are a western United States independent upstream energy company with a focus on onshore, low geologic
risk, long-lived conventional reserves in the San Joaquin basin of California (100% oil) and the Uinta basin of Utah
(oil and gas), with well servicing and abandonment capabilities in California. Since October 1, 2021, we have
operated in two business segments: (i) exploration and production (“E&P”) and (ii) well servicing and abandonment
(“CJWS”).
The assets in our E&P business, in the aggregate, are characterized by high oil content (our California assets are
100% oil) and are predominantly located in rural areas with low population. In California, we focus on conventional,
shallow oil reservoirs, the drilling and completion of which are relatively low-cost in contrast to unconventional
resource plays. The California oil market has primarily Brent-influenced pricing which has typically realized
premium pricing to WTI. All of our California assets are located in the oil-rich reservoirs in the San Joaquin basin,
which has more than 150 years of production history and substantial oil remaining in place. As a result of the
substantial data produced over the basin’s long history, its reservoir characteristics and low geological risk
opportunities are well understood. We also have upstream assets in the oil-rich reservoirs in the Uinta basin of Utah.
On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and
abandonment businesses in California, which operates as C&J Well Services (“CJWS”) and constitutes our well
servicing and abandonment segment. CJWS provides wellsite services in California to oil and natural gas production
companies, with a focus on well servicing, well abandonment services and water logistics. CJWS’ services include
rig-based and coiled tubing-based well maintenance and workover services, recompletion services, fluid
management services, fishing and rental services, and other ancillary oilfield services. Additionally, CJWS performs
plugging and abandonment services on wells at the end of their productive life, which we believe creates a strategic
growth opportunity for Berry based on the significant market of idle wells.
Our shareholder return model went into effect January 1, 2022. Like our business model, this shareholder return
model is simple and demonstrates our commitment to optimize capital allocation and returns to our shareholders.
The model is based on our Adjusted Free Cash Flow (formerly called Discretionary Free Cash Flow), which is
defined as cash flow from operations less regular fixed dividends and maintenance capital. Maintenance capital,
which represents the capital expenditures needed to optimize production volumes for a given year, is defined as
capital expenditures, excluding, when applicable, (i) E&P capital expenditures that are related to strategic business
expansion, such as acquisitions and divestitures of oil and gas properties and any exploration and development
activities to increase production beyond the prior year’s annual production volumes, (ii) capital expenditures in our
well servicing and abandonment segment, (iii) corporate expenditures that are related to ancillary sustainability
initiatives and/or (iv) other expenditures that are discretionary and unrelated to maintenance of our core business.
The initial allocation of Adjusted Free Cash Flow in 2022 was contemplated as: (a) 60% predominantly in the form
of variable cash dividends to be paid quarterly, as well as opportunistic debt repurchases; and (b) 40% which could
72
be used for opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our
short- and long-term sustainability initiatives, share repurchases, and/or capital retention. Our Adjusted Free Cash
Flow in 2022 was $200 million. In accordance with our shareholder return model in 2022 we will have paid a total
of $189 million related to 2022 performance which consisted of: (i) $119 million for the variable cash dividends, (ii)
$19 million for fixed cash dividends and (iii) $51 million for share repurchases.
In early February 2023, we updated our shareholder return model, including the plan to double our quarterly
fixed dividend to $0.12 per share. We also modified the allocations of Adjusted Free Cash Flow. Our goal is to
continue maximizing shareholder value through overall returns. Starting with the first quarter of 2023, the allocation
of Adjusted Free Cash will be (a) 80% primarily in the form of opportunistic debt or share repurchases; and (b) 20%
in the form of variable dividends. Any dividends (fixed or variable) actually paid will be determined by our Board of
Directors in light of then existing conditions, including our earnings, financial condition, restrictions in financing
agreements, business conditions and other factors.
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 free cash flow, which funds our operations, optimizes capital efficiency and maximizes
shareholder returns. We also strive to maintain a low leverage profile and explore attractive organic and strategic
growth through commodity price cycles. 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 shareholders, we are dedicated to
conducting our operations in an ethical, safe and responsible manner, to protecting the environment, and to taking
care of our people and the communities in which we live and operate. We believe that oil and gas will remain an
important part of the energy landscape going forward and our goal is to conduct our business safely and responsibly,
while supporting economic stability and social equity through engagement with our stakeholders. We recognize the
oil and gas industry’s role in the energy transition and advocate a co-existence between renewable and conventional
energy. We are committed to being part of the energy transition solution by continuing to provide safe and
affordable energy to our communities.
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 the following metrics to manage and assess the performance of our operations: (a) Adjusted EBITDA;
(b) Adjusted Free Cash Flow for shareholder returns; (c) production from our E&P business (d) E&P field
operations measures; (e) HSE results; (f) general and administrative expenses; and (g) the performance of our well
servicing and abandonment operations based on activity levels, pricing and relative performance for each service
provided.
Adjusted EBITDA
Adjusted EBITDA is the primary financial and operating measurement that our management uses to analyze
and monitor the operating performance of both our E&P business and CJWS. We also use Adjusted EBITDA in
planning our capital allocation to sustain production levels and determining our strategic hedging needs aside from
the hedging requirements of the 2021 RBL Facility (defined below in Liquidity and Capital Resources). Adjusted
EBITDA is a non-GAAP financial measure that we define as earnings before interest expense; income taxes;
depreciation, depletion, and amortization (“DD&A”); derivative gains or losses net of cash received or paid for
scheduled derivative settlements; impairments; stock compensation expense; and unusual and infrequent items. See
“Management’s Discussion and Analysis—Non-GAAP Financial Measures” for reconciliation of Adjusted EBITDA
to net (loss) income and to net cash provided by operating activities, our most directly comparable financial
73
measures calculated and presented in accordance with GAAP. This supplemental non-GAAP financial measure is
used by management and external users of our financial statements, such as industry analysts, investors, lenders and
rating agencies.
Shareholder Returns
Commencing in 2022, we implemented a shareholder return model based on our Adjusted Free Cash Flow,
which is a non-GAAP measure that we define as cash flow from operations less regular fixed dividends and
maintenance capital. Maintenance capital represents the capital expenditures needed to maintain the same volume of
annual oil and gas production and is defined as capital expenditures, excluding, when applicable, E&P capital
expenditures that are related to strategic business expansion, such as acquisitions and divestitures of oil and gas
properties and any exploration and development activities to increase production beyond the prior year’s annual
production volumes and capital expenditures in our well servicing and abandonment segment and corporate
expenditures that are related to ancillary sustainability initiatives or other expenditures that are discretionary and
unrelated to maintenance of our core business. Adjusted Free Cash Flow does not represent the total increase or
decrease in our cash balance, and it should not be inferred that the entire amount of Adjusted Free Cash Flow is
available for variable dividends, debt or share repurchase or other discretionary expenditures, since we have non-
discretionary expenditures that are not deducted from this measure. Refer to (“Management’s Discussion and
Analysis—Non-GAAP Financial Measures” for a reconciliation of Adjusted Free Cash Flow to cash provided by
operating activities, our most directly comparable financial measure calculated and presented in accordance with
GAAP). Under our shareholder return model, which was revised in February 2023, we plan to pay a fixed dividend
of $0.12 per quarter. We also modified the allocations of Adjusted Free Cash Flow to be (a) 80% primarily in the
form of opportunistic debt or share repurchases; and (b) 20% in the form of variable dividends. Any dividends (fixed
or variable) actually paid will be determined by our Board of Directors in light of then existing conditions, including
our earnings, financial condition, restrictions in financing agreements, business conditions and other factors.
Our focus on shareholder returns is also demonstrated through our performance-based restricted stock awards,
which include performance metrics based on the Company's average cash returned on invested capital and total
stockholder return on both a relative and absolute basis. Our short-term incentive plan also includes Adjusted Free
Cash Flow performance goals.
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.
74
E&P Field Operations (Formerly Operating Expenses)
We have changed the presentation of what we formerly referred to as Opex or operating expenses. Overall,
management assesses the efficiency of our E&P field operations by considering core E&P operating expenses
together with our cogeneration, marketing and transportation activities. In particular, a core component of our E&P
operations in California is steam, which we use to lift heavy oil to the surface. We operate several cogeneration
facilities to produce some of the steam needed in our operations. In comparing the cost effectiveness of our
cogeneration plants against other sources of steam in our operations, management considers the cost of operating the
cogeneration plants, including the cost of the natural gas purchased to operate the facilities, against the value of the
steam and electricity used in our E&P field operations and the revenues we receive from sales of excess electricity to
the grid. We strive to minimize the variability of our fuel gas costs for our California steam operations with natural
gas purchase hedges. Consequently, the efficiency of our E&P field operations are impacted by the cash settlements
we receive or pay from these derivatives. We also have contracts for the transportation of fuel gas from the Rockies
which has historically been cheaper than the California markets. With respect to transportation and marketing,
management also considers opportunistic sales of incremental capacity in assessing the overall efficiencies of E&P
operations.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies,
and workover expenses. Electricity generation expenses include the portion of fuel, labor, maintenance, and tools
and supplies from two of our cogeneration facilities allocated to electricity generation expense; the remaining
cogeneration expenses are included in lease operating expense. Transportation expenses relate to our costs to
transport the oil and gas that we produce within our properties or move it to the market. Marketing 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. Electricity revenue is from the sale of excess electricity from two of our cogeneration
facilities to a California utility company under long-term contracts at market prices. These cogeneration facilities are
sized to satisfy the steam needs in their respective fields, but the corresponding electricity produced is more than the
electricity that is currently required for the operations in those fields. Transportation sales relate to water and other
liquids that we transport on our systems on behalf of third parties and marketing revenues represent sales of natural
gas purchased from and sold to third parties.
Health, Safety & Environmental
Like other companies in the oil and gas industry, the operations of both our E&P business and CJWS are subject
to complex federal, state and local laws and regulations that govern health and safety, the release or discharge of
materials, and land use or environmental protection that may restrict the use of our properties and operations,
increase our costs or lower demand for or restrict the use of our products and services. Please see “Part I, Item 1
“Regulatory Matters” and Part I, Item 1A. “Risk Factors” in this Annual Report for a discussion of the potential
impact that government regulations, including those regarding HSE matters, may have upon our business,
operations, capital expenditures, earnings and competitive position.
As part of our commitment to creating long-term stockholder value, we strive to conduct our operations in an
ethical, safe and responsible manner, to protect the environment and to take care of our people and the communities
in which we live and operate. We also seek proactive and transparent engagement with regulatory agencies, the
communities in which we operate and our other stakeholders in order to realize the full potential of our resources in
a timely fashion that safeguards people and the environment and complies with existing laws and regulations. We
monitor our HSE performance through various measures, and we hold our employees and contractors to high
standards. Meeting corporate HSE metrics, including with respect to HSE incidents and spill prevention, is a part of
our short-term incentive program for all employees.
General and Administrative Expenses
We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead
activities and less than 10% of such costs are capitalized, which is significantly less than industry norms. Such
75
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.
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, including differentials, which have and may continue to, fluctuate significantly as a result of
numerous market-related variables, including global geopolitical, economic conditions, and local and regional
market factors and dislocations. While oil prices greatly improved in 2022, they have and can 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 are largely driven by regulatory requirements that is less dependent on commodity prices.
Currently, global oil inventories are low relative to historical levels and supply from OPEC+ and other oil
producing nations are not expected to be sufficient to meet forecasted oil demand growth for the next few years. It is
believed that many OPEC+ countries will be unable to increase their production levels or even produce at expected
levels due to their lack of capital investments in developing incremental oil supplies over the past few years. In
October 2022, OPEC+ determined to reduce production beginning in November 2022 through December 2023 by
two million bbls per day, due to the uncertainty surrounding the global economic and oil market outlooks.
Furthermore, sanctions and import bans on Russian oil have been implemented by various countries in response to
the war in Ukraine, further impacting global oil supply. Still, oil and natural gas prices have recently declined from
the highs experienced in the first half of 2022 and could decrease or increase with any changes in demand due to,
among other things, China lifting COVID-19 restrictions in December 2022, the ongoing conflict in Ukraine,
international sanctions, speculation as to future actions by OPEC+, developing COVID-19 variants and the potential
for a widespread COVID-19 outbreak, higher gas prices, inflation and government efforts to reduce inflation, and
possible changes in the overall health of the global economy, including a prolonged recession. Further, the volatility
in oil and natural gas prices could accelerate a transition away from fossil fuels, resulting in reduced demand over
the longer term. To what extent these and other external factors (such as government action with respect to climate
change regulation) ultimately impact our future business, liquidity, financial condition, and results of operations is
highly uncertain and dependent on numerous factors, including future developments, that are not within our control
and cannot be accurately predicted.
In the past few years, there have been numerous global events that have greatly impacted the oil and gas
environment, such as the COVID-19 pandemic, the impacts of the Russia and Ukraine war, and OPEC+’s actions.
The COVID-19 pandemic resulted in a severe decrease in demand for oil, which created significant volatility and
uncertainty in the oil and gas industry beginning in 2020. When combined with an excess supply of oil and related
products, oil prices declined significantly in the first half of 2020. Although there has been some volatility, overall
oil prices have steadily improved since the lows experienced in 2020, in line with increasing demand despite the
ongoing pandemic and uncertainties surrounding the COVID-19 variants. Oil and natural gas prices increased
significantly during 2022, reaching a high of almost $128 per bbl, primarily due to global supply and demand
imbalances, including as a result of the war in Ukraine. Brent prices were 40% higher for the year ended December
31, 2022 as compared to the year ended December 31, 2021.
76
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.
We utilize derivatives to hedge a portion of our forecasted oil and gas production and gas purchases to reduce
exposure to fluctuations in oil and natural gas prices.
Average Brent oil prices, as noted below, increased by $28.09 or 40% for the year ended December 31, 2022
compared to the year ended December 31, 2021. Though the California market generally receives Brent-influenced
pricing, California oil prices are determined ultimately by local supply and demand dynamics, including third-party
transportation and market takeaway infrastructure capacity.
For our California steam operations, the price we pay for fuel gas purchases is generally based on the
Northwest, Rocky Mountains index for the purchases made in the Rockies and the Kern, Delivered index for the
purchases made in California. We currently buy most of our gas in the Rockies. The high price from the Northwest,
Rocky Mountain index was $11.39 per mmbtu and as low as $4.38 mmbtu in 2022. The high price from the Kern,
Delivered index was $50.79 per mmbtu and as low as $3.70 mmbtu in 2022. We paid an average of $7.86 per
mmbtu for the year. The price we paid on average increased by $2.22 per mmbtu, or 39% for the year ended
December 31, 2022, compared to the year ended December 31, 2021.
The following table presents the average Brent; WTI; Kern, Delivered; Northwest, Rocky Mountains; and
Henry Hub prices for the years ended December 31, 2022 and 2021:
Year Ended December 31,
2022
2021
Oil (bbl) – Brent
Oil (bbl) – WTI
Natural gas (mmbtu) – Kern, Delivered
Natural gas (mmbtu) – Northwest, Rocky Mountains
Natural gas (mmbtu) – Henry Hub
$
$
$
$
$
99.04 $
94.39 $
8.99 $
6.95 $
6.45 $
70.95
67.90
5.65
3.90
3.89
As mentioned above, California oil prices are Brent-influenced as California refiners import approximately 70%
of the state’s demand from OPEC+ countries and other waterborne sources. Without the higher costs and potential
environmental impact associated with importing crude via rail or supertanker, we believe our in-state production and
low-cost crude transportation options, coupled with Brent-influenced pricing, in appropriate oil price environments,
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. Our key exposure to gas prices is in our costs.
We purchase substantially more natural gas for our California steamfloods and cogeneration facilities than we
produce and sell in the Rockies. In May 2022, we began purchasing most of our gas in the Rockies and transport it
to our California operations using our Kern River pipeline capacity. In 2022, we purchased approximately 60,000
mmbtu/d, of which 12,000 mmbtu/d was purchased in California beginning when we entered into the Kern River
pipeline capacity agreement for 48,000 mmbtu/d. The natural gas we purchase in the Rockies is shipped to our
operations in California to help limit our exposure to California fuel gas purchase price fluctuations. We strive to
further minimize the variability of our fuel gas costs for our steam operations by hedging a significant portion of gas
77
purchases. 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.
Among other factors, extreme cold weather conditions drove high natural gas prices in 2022. In California we
experienced a significant increase in mid-December 2022, with gas prices briefly as high as $50.79 per mmbtu. We
quickly pivoted and reduced our gas consumption in California by temporarily shutting-down one of our
cogeneration facilities and reducing steam generation in other parts of our operation, which negatively impacted
production. We seek to mitigate a substantial portion of the gas purchase exposure for our cogeneration plants by
selling excess electricity from our cogeneration operations to third parties at prices linked to the price of natural gas.
Aside from the impact gas prices have on electricity prices, these sales are generally higher in the summer months as
they include seasonal capacity amounts. Based on market prices and current and projected supply and demand
balances, our current expectation is that natural gas prices in California will continue to remain elevated through the
first half of 2023 and begin to weaken in the middle of 2023. Our hedging strategy coupled with our midstream
access to gas from the Rockies also helps mitigate the impact of the high natural gas prices on our cost structure.
Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids.
Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the
demand for certain chemical products which are used as feedstock. In addition, infrastructure constraints magnify
pricing volatility.
Our earnings are also affected by the performance of our cogeneration facilities. These cogeneration facilities
generate both electricity and steam for our properties and electricity for off-lease sales. While a portion of the
electric output of our cogeneration facilities is utilized within our production facilities to reduce operating expenses,
we also sell electricity produced by two of our cogeneration facilities under long-term contracts with terms ending in
December 2023 and November 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.
Seasonal weather conditions have in the past, and in the future likely will, impact our drilling, production and
well servicing activities. Extreme weather conditions can pose challenges to meeting well-drilling and completion
objectives and production goals. Seasonal weather can also lead to increased competition for equipment, supplies
and personnel, which could lead to shortages and increased costs or delayed operations. Our operations have been,
and in the future could 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 wildfires and rain. Additionally, unusually heavy rains or
extreme temperatures can cause flooding and power outages which could adversely impact our ability to operate,
particularly in California. For example, in December of 2022, unusually poor weather caused operational
challenges, production downtime, and much higher natural gas prices in California. The extreme, adverse weather
conditions have continued in the first quarter of 2023 and impacted our production.
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”.
78
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, 2022 and 2021.
Year Ended December 31,
2022
2021
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) – Northwest, Rocky Mountains(4)
Natural gas (mmbtu) – Henry Hub(4)
__________
$
$
$
$
$
$
$
$
$
$
24.0
10.2
0.4
26.1
8,770
3,706
144
9,532
91.98 $
(14.39) $
77.59 $
7.96 $
43.85 $
99.04 $
94.39 $
8.99 $
6.95 $
6.45 $
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
3.90
3.89
(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, 2022, the
average prices of Brent oil and Henry Hub natural gas were $99.04 per bbl and $6.45 per mmbtu respectively.
(3) The natural gas we purchase to generate steam and electricity is primarily based on Rockies price indexes, including transportation charges,
as we currently purchase a substantial majority of our gas needs from the Rockies, with the balance purchased in California. Kern,
Delivered Index is the relevant index used only for the portion of gas purchases in California
(4) Northwest, Rocky Mountains and Henry Hub are the relevant indices used for gas sales and purchases in the Rockies.
79
The following table sets forth average daily production by operating area for the periods indicated:
Average daily production (mboe/d)(1):
California(2)
Utah(3)
Colorado(4)
Total average daily production
__________
(1) Production represents volumes sold during the period.
Year Ended December 31,
2022
2021
21.3
4.7
26.0
0.1
26.1
22.0
4.2
26.2
1.2
27.4
(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 approximately 700 boe/d.
(3)
Includes production for Antelope Creek area from February 2022, when it was acquired, through the end of 2022.
(4) In January 2022, we divested all of our natural gas properties in Colorado.
Year-over-year our overall production was flat, excluding the effect of our acquisitions and divestitures in 2022
and 2021. Utah production increased 0.5 mboe/d, or 12% due to new drilling activity and the Antelope Creek
purchase, which more than offset natural decline. Antelope Creek’s exit production rate was 1.2 mboe/d,
approximately double that upon acquisition as we identified underperforming wells and executed an extensive
workover campaign to maximize their performance. The year ended December 31, 2021 included 1.2 mboe/d of
production from the Colorado assets, as well as 0.7 mboe/d of production from the Placerita asset in California,
which was divested in the fourth quarter of 2021.
Year-over-year California production, on a comparable basis, excluding Placerita volumes, was flat at 21.3
mboe/d.
80
Results of Operations
Revenues and other:
Year Ended December 31,
2022
2021
$ Change
% Change
(in thousands)
Oil, natural gas and natural gas liquid sales
$
842,449 $
625,475 $
Services revenue
Electricity sales
181,400
30,833
35,840
35,636
(Losses) gains on oil and gas sales derivatives
(137,109)
(156,399)
216,974
145,560
(4,803)
19,290
(3,630)
35 %
406 %
(13) %
(12) %
(83) %
69 %
768
4,398
$
918,341 $
544,950 $
373,391
Marketing and other revenues
Total revenues and other
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 2022, our realized oil price was
$91.98 per bbl and the hedged price was $77.59 per bbl. By comparison, in 2021, our realized oil price was $66.57
per bbl and our hedged price was $50.12 per bbl.
Oil, natural gas and NGL sales increased by $217 million, or 35%, to approximately $842 million for the year
ended December 31, 2022 when compared to the year ended December 31, 2021. The increase was driven by $223
million and $10 million of higher prices for oil and natural gas, respectively, partially offset by a $16 million
decrease in volumes. Of this volume variance, natural gas accounted for $13 million, the result of the sale of our
exclusively natural gas properties in Colorado in January 2022, and the remaining $3 million variance was from the
sale of Placerita late in 2021, net of the additional volumes from Antelope Creek. The well servicing and
abandonment segment occasionally provides services to our E&P segment, as such, we recorded an intercompany
elimination of $3 million in revenue and expense during consolidation. The intercompany elimination in 2021 was
immaterial.
Services revenue in 2022 consisted entirely of revenue from our well servicing and abandonment business.
Since we acquired the business on October 1, 2021, 2022 is our first full year of activity and 2021 had only one
quarter of activity.
Electricity sales which represent sales to utilities decreased by $5 million, or 13%, to approximately $31 million
for the year ended December 31, 2022 when compared to the year ended December 31, 2021. The decrease was due
to lower sales volume as a result of the sale of a cogeneration facility which was part of the Placerita divestiture in
late 2021. Year-over-year cogen revenue on comparable basis, excluding Placerita’s cogen sales from 2021,
increased $6 million dollars, or 22%, due to higher unit revenue.
Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains
and losses. In the years ended December 31, 2022 and December 31, 2021, settlement losses were $126 million and
$143 million, respectively. The change was due to lower volume hedged in 2022 compared to 2021. The mark-to-
market non-cash losses for the years ended December 31, 2022 and 2021 of $11 million and $14 million,
respectively, were due to higher future prices relative to the derivative fixed prices at each year end.
Marketing and other revenues were lower for the year ended December 31, 2022, compared to the year ended
December 31, 2021 due to the sale of our Piceance Colorado operations in January 2022, which included third-party
marketing activities. Piceance has historically accounted for nearly all of our marketing revenues.
81
Expenses and other:
Lease operating expenses
Costs of services
Electricity generation expenses
Transportation expenses
Marketing expenses
General and administrative expenses
Depreciation, depletion and amortization
Taxes, other than income taxes
Gains on natural gas purchase derivatives
Other operating expense
Total expenses and other
Other (expenses) income:
Interest expense
Other, net
Total other (expenses) income
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
Adjusted EBITDA(1)
Adjusted Net Income (Loss)(1)
__________
Year Ended December 31,
2022
2021
$ Change
% Change
(in thousands)
$
302,321 $
236,048 $
142,819
21,839
4,564
299
96,439
156,847
39,495
(88,795)
3,722
679,550
(30,917)
(142)
(31,059)
207,732
(42,436)
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
$
$
$
250,168 $
379,948 $
226,463 $
(15,542) $
212,146 $
10,722 $
66,273
114,480
(1,309)
(2,333)
(3,512)
23,333
12,352
(7,005)
(50,218)
621
152,682
(1,047)
(105)
(1,152)
(221,861)
(43,849)
(265,710)
167,802
215,741
28 %
404 %
(6) %
(34) %
(92) %
32 %
9 %
(15) %
130 %
20 %
29 %
(3) %
(43) %
(4) %
1,570 %
3,103 %
1,710 %
79 %
2,012 %
(1) 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
Lease operating expense increased 28% on an absolute dollar basis, when compared to the prior year. Of this
increase, approximately 60% was the result of higher natural gas (fuel) costs for our California steam facilities.
Average natural gas purchase price increased 39% per mmbtu compared to 2021, which increased fuel expense 34%,
net of the benefit from lower consumption. Lease operating expense excluding fuel increased 23% on an absolute
dollar basis due to higher well servicing and workover costs, outside services, chemicals and power. While the
activity level increased from 2021, particularly so for well servicing and workovers, we also experienced
inflationary pressure from service providers and for materials and supplies which ranged from 5% to 15%.
Cost of services consisted entirely of costs from the well servicing and abandonment business we acquired on
October 1, 2021. Since 2022 was our first full year of operations the prior period is not comparable.
Electricity generation expenses decreased 1% to $2.29 per boe for the year ended December 31, 2022 from
$2.31 for the year ended December 31, 2021 due to lower volumes sold resulting from the previously discussed sale
of a cogeneration facility in late 2021, more than offsetting the increase in fuel prices. Fuel costs included in
electricity generation expenses exclude the effects of natural gas derivative settlements discussed elsewhere.
Transportation expenses decreased 30% to $0.48 per boe for the year ended December 31, 2022, compared to
$0.69 for the year ended December 31, 2021, mainly due to the divestiture of our Piceance properties.
82
Marketing expenses decreased 92% to $0.03 per boe for the year ended December 31, 2022, compared to $0.38
per boe for the year ended December 31, 2021 due to the sale of our Piceance Colorado operations in the first
quarter of 2022, which included third-party marketing activities. Piceance has historically accounted for nearly all
of our marketing revenue.
Gain or loss on natural gas purchase derivatives for the year ended December 31, 2022 and 2021 was a gain of
$89 million and $39 million, respectively. The settlement gain for the year ended December 31, 2022 was $38
million, or $4.00 per boe, compared to gain of $51 million, or $5.09 per boe for same period in 2021, primarily due
to lower hedged volumes in 2022 compared to 2021. Settled hedges in 2022 had an average fixed price of $4.21 and
notional quantities of 38,000 mmbtu per day, compared to $2.80 and 46,000 in 2021. The mark-to-market valuation
gain or loss for the years ended December 31, 2022 and December 31, 2021 was a gain of $51 million and a loss of
$13 million, respectively, consistent with the changes in futures prices at the end of each period.
General and administrative expenses increased by approximately $23 million or 32%, for the year ended
December 31, 2022 compared to the year ended December 31, 2021. The year-over-year increase was due to a full
year of CJWS expense, employee cost inflation including non-cash stock compensation, and higher professional
services. For the year ended December 31, 2022 and 2021, non-cash stock compensation costs were approximately
$16 million and $13 million, respectively, and non-recurring costs were flat at $3 million, respectively. The non-
recurring costs in 2022 consisted primarily of management succession costs and in 2021 these were legal and other
professional services costs related to acquisition activity.
We define “Adjusted General and Administrative Expenses” as general and administrative expenses adjusted
for non-cash stock compensation expense and unusual and infrequent costs (“Adjusted General and Administrative
Expenses”). Adjusted general and administrative expenses, which excluded non-cash stock compensation costs and
non-recurring costs, increased $19 million to $76 million compared to $57 million in 2021. The year-over-year
increase was due to a full year of CJWS expense, employee cost inflation and higher professional services. 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 $12 million, or 9%, to approximately $157 million, for the year ended December 31, 2022
compared to the year ended December 31, 2021. The CJWS acquisition increased depreciation by $10 million with
the balance of the increase from slightly higher depletion rates in the E&P segment. On a per boe basis, year-over-
year DD&A increased $2.02 to $16.46 from $14.44.
Taxes, Other Than Income Taxes
Severance taxes
Ad valorem taxes
Greenhouse gas allowances
Total taxes other than income taxes
$
$
Year Ended December 31,
2022
2021
$ Change
% Change
(per boe)
1.46 $
1.68
1.00
0.83 $
1.73
2.09
4.14 $
4.65 $
0.63
(0.05)
(1.09)
(0.51)
76 %
(3) %
(52) %
(11) %
Taxes, other than income taxes, decreased $0.51 to $4.14 per boe for the year ended December 31, 2022
compared to $4.65 for the year ended December 31, 2021. Severance taxes increased as a result of higher unit
revenue and higher sales volume in Utah. Ad valorem taxes declined slightly, net of higher rates on existing
properties, from the sale of Placerita in late 2021 and Piceance in January 2022. The decrease in GHG expense was
due to the sale of Placerita in the fourth quarter of 2021, which lowered GHG emissions, as well as lower GHG
mark-to-market prices on remaining operations.
83
Other Operating Expense (Income)
For the years ended December 31, 2022 and 2021 other operating expenses were $4 million and $3 million,
respectively. For the year ended December 31, 2022, other operating expenses mainly consisted of $2 million in
charges from a royalty audit related to activity prior to our emergence and restructuring in 2017 and approximately
$2 million loss on the divestiture of the Piceance properties. 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.
Interest Expense
Interest expense decreased 3% or $1 million for year ended December 31, 2022 compared to the same period in
2021 as we had lower intra-period working capital borrowings on the 2021 RBL Facility in 2022.
Income Tax Expense (Benefit)
For the year ended December 31, 2022, we had income tax benefits of approximately $42 million and a tax
expense of approximately $1 million in 2021. The change in our effective tax rate from (10.0)% for the year ended
December 31, 2021 to (20)% for the year ended December 31, 2022 is primarily due to recognition of U.S. federal
general business credits in 2022 related to the 2021 tax period and release of the valuation allowance. The credits
recorded in 2022 are available to offset future federal income tax liabilities. Refer to Note 8 of the consolidated
financial statements for more information about our income taxes.
84
E&P Field Operations
Expenses from field operations
Lease operating expenses
Electricity generation expenses
Transportation expenses
Marketing expenses
Total
Cash settlements received for gas purchase
hedges
E&P non-production revenues
Electricity sales
Transportation sales
Marketing revenues
Total
Year Ended December 31,
2022
2021
$ Change
% Change
(per boe)
$
31.72 $
23.60 $
2.29
0.48
0.03
2.31 $
0.69 $
0.38
34.52 $
26.98 $
8.12
(0.02)
(0.21)
(0.35)
7.54
34 %
(1) %
(30) %
(92) %
28 %
(4.00) $
(5.09) $
1.09
(21) %
$
$
3.24
0.05
0.03
$
3.32 $
3.56 $
0.05 $
0.39
4.00 $
(0.32)
0.00
(0.36)
(0.68)
(9) %
0 %
(92) %
(17) %
We have changed the presentation of what we formerly referred to as Opex or operating expenses. Overall,
management assesses the efficiency of our E&P field operations by considering core E&P operating expenses
together with our cogeneration, marketing and transportation activities. In particular, a core component of our E&P
operations in California is steam, which we use to lift heavy oil to the surface. We operate several cogeneration
facilities to produce some of the steam needed in our operations. In comparing the cost effectiveness of our
cogeneration plants against other sources of steam in our operations, management considers the cost of operating the
cogeneration plants, including the cost of the natural gas purchased to operate the facilities, against the value of the
steam and electricity used in our E&P field operations and the revenues we receive from sales of excess electricity to
the grid. We strive to minimize the variability of our fuel gas costs for our California steam operations with natural
gas purchase hedges. Consequently, the efficiency of our E&P field operations are impacted by the cash settlements
we receive or pay from these derivatives. We also have contracts for the transportation of fuel gas from the Rockies
which has historically been cheaper than the California markets. With respect to transportation and marketing,
management also considers opportunistic sales of incremental capacity in assessing the overall efficiencies of E&P
operations.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies,
and workover expenses. Electricity generation expenses include the portion of fuel, labor, maintenance, and tools
and supplies from two of our cogeneration facilities allocated to electricity generation expense; the remaining
cogeneration expenses are included in lease operating expense. Transportation expenses relate to our costs to
transport the oil and gas that we produce within our properties or move it to the market. Marketing 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. Electricity revenue is from the sale of excess electricity from two of our cogeneration
facilities to a California utility company under long-term contracts at market prices. These cogeneration facilities are
sized to satisfy the steam needs in their respective fields, but the corresponding electricity produced is more than the
electricity that is currently required for the operations in those fields. Transportation sales relate to water and other
liquids that we transport on our systems on behalf of third parties and marketing revenues represent sales of natural
gas purchased from and sold to third parties.
85
Liquidity and Capital Resources
Currently, we expect to fund our 2023 capital expenditures with cash flows from our operations. As of
December 31, 2022, we had liquidity of $252 million, consisting of $46 million cash, $193 million available for
borrowings under our 2021 RBL Facility and CJWS had $13 million available for borrowings under our 2022 ABL
Facility (as defined below). We also have $400 million in aggregate principal amount 7% senior unsecured notes
due February 2026 outstanding as further discussed below.
Our shareholder return model went into effect January 1, 2022. Like our business model, this shareholder return
model is simple and demonstrates our commitment to optimize capital allocation and returns to our shareholders.
The model is based on our Adjusted Free Cash Flow (formerly called Discretionary Free Cash Flow), which is
defined as cash flow from operations less regular fixed dividends and maintenance capital. Maintenance capital,
which represents the capital expenditures needed to optimize production volumes for a given year, is defined as
capital expenditures, excluding, when applicable, (i) E&P capital expenditures that are related to strategic business
expansion, such as acquisitions and divestitures of oil and gas properties and any exploration and development
activities to increase production beyond the prior year’s annual production volumes, (ii) capital expenditures in our
well servicing and abandonment segment, (iii) corporate expenditures that are related to ancillary sustainability
initiatives and/or (iv) other expenditures that are discretionary and unrelated to maintenance of our core business.
The initial allocation of Adjusted Free Cash Flow in 2022 was contemplated as: (a) 60% predominantly in the form
of variable cash dividends to be paid quarterly, as well as opportunistic debt repurchases; and (b) 40% which could
be used for opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our
short- and long-term sustainability initiatives, share repurchases, and/or capital retention. Our Adjusted Free Cash
Flow in 2022 was $200 million. In accordance with our shareholder return model in 2022 we will have paid a total
of $189 million related to 2022 performance which consisted of: (i) $119 million for the variable cash dividends, (ii)
$19 million for fixed cash dividends and (iii) $51 million for share repurchases.
In early February 2023, we updated our shareholder return model, including the plan to double our quarterly
fixed dividend to $0.12 per share. We also modified the allocations of Adjusted Free Cash Flow. Our goal is to
continue maximizing shareholder value through overall returns. Starting with the first quarter of 2023, the allocation
of Adjusted Free Cash will be (a) 80% primarily in the form of opportunistic debt or share repurchases; and (b) 20%
in the form of variable dividends. Any dividends (fixed or variable) actually paid will be determined by our Board of
Directors in light of then existing conditions, including our earnings, financial condition, restrictions in financing
agreements, business conditions and other factors.
Adjusted Free Cash Flow does not represent the total increase or decrease in our cash balance, and it should not
be inferred that the entire amount of Adjusted Free Cash Flow is available for variable dividends, debt or share
repurchase or other discretionary expenditures, since we have non-discretionary expenditures that are not deducted
from this measure. Adjusted Free Cash Flow is a non-GAAP financial measure. See “Management’s Discussion and
Analysis—Non-GAAP Financial Measures” for a reconciliation of Adjusted Free Cash Flow to cash provided by
operating activities, our most directly comparable financial measure calculated and presented in accordance with
GAAP.
We currently believe that our liquidity, capital resources and cash 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 Adjusted Free Cash Flow we are currently
generating and our liquidity and capital resources may not be sufficient to conduct our business and operations until
commodity prices recover. Please see Part II, Item 1A “Risk Factors” for a discussion of known material risks, many
of which are beyond our control, that could adversely impact our business, liquidity, financial condition, and results
of operations.
2021 RBL Facility
On August 26, 2021, Berry Corp, as a guarantor, together with Berry LLC, as the borrower, entered into a credit
agreement that provided for a revolving loan with up to $500 million of commitments, subject to a reserve
86
borrowing base (as amended by the First Amendment, the Second Amendment and the Third Amendment, each as
defined below, the “2021 RBL Facility”). Our initial borrowing base 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.
In May 2022, Berry Corp., as a guarantor, and Berry LLC, as the borrower, entered into that certain Second
Amendment to Credit Agreement and Limited Consent and Waiver (the “Second Amendment”) pursuant to which,
among other things, the requisite lenders under the 2021 RBL Facility (i) consented to certain dividends and
distributions and to certain investments made by Berry LLC in C&J and/or C&J Management, in each case, as
further described therein, (ii) waived certain minimum hedging requirements for the time periods described therein,
(iii) waived any breach, default or event of default which may have arisen as a result of any of the foregoing, (iv)
amended the restricted payments covenant to give us additional flexibility to make restricted payments, subject to
satisfaction of certain leverage and availability conditions and other conditions described below and in the Second
Amendment and (v) amended the minimum hedging covenant to not, until October 1, 2022, require hedges for any
full calendar month from and after January 1, 2025, as further described in the Second Amendment. In May 2022,
we also completed our semi-annual borrowing base redetermination and entered into the Third Amendment to the
Credit Agreement (the “Third Amendment”), which among other things (1) increased the borrowing base from
$200 million to $250 million; (2) established the Aggregate Elected Commitment Amounts (as defined in the 2021
RBL Facility) at $200 million initially; and (3) converted all outstanding Eurodollar Loans (into Term Benchmark
Loans (each as defined in the 2021 RBL Facility) with an initial interest period of one-month’s duration and
otherwise give effect to the transition from the London interbank offered rate (“LIBOR”) to the secured overnight
financing rate (“SOFR”) by replacing the adjusted LIBOR rate with the term SOFR rate for one, three or six months
plus 0.1% (subject to a floor of 0.5%).
In December 2022, we completed our scheduled semi-annual borrowing base redetermination, which resulted in
a reaffirmed borrowing base at $250 million and $200 million elected commitment amount.
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.
87
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, 2022, our leverage
ratio and current ratio were 1.2 to 1.0 and 1.7 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, 2022.
The 2021 RBL Facility contains usual and customary events of default and remedies for credit facilities of a
similar nature. The 2021 RBL Facility also places restrictions on the borrower and its restricted subsidiaries with
respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions
of our common stock, redemptions of the borrower’s senior notes, investments, acquisitions, mergers, asset
dispositions, transactions with affiliates, hedging transactions and other matters.
From and after August 26, 2022, the 2021 RBL Facility permits us to repurchase certain indebtedness so long as
both before and after giving pro forma effect to such repurchase, no default or event of default exists, availability is
equal to or greater than 20% of the borrowing base and our pro forma leverage ratio is less than or equal to 2.0 to
1.0. The 2021 RBL Facility also permits us to make restricted payments so long as both before and after giving pro
forma effect to such distribution, no default or event of default exists, availability exceeds 75% of the borrowing
base, and our pro forma leverage ratio is less than or equal to 1.5 to 1.0. In addition, we can make other restricted
payments in an aggregate amount not to exceed 100% of Free Cash Flow (as defined under the 2021 RBL Facility)
for the fiscal quarter most recently ended prior to such distribution so long as, in addition to other conditions and
limitations as described in the 2021 RBL Facility, both before and after giving pro forma effect to such distribution,
no default or event of default exists, availability is greater than 20% of the borrowing base and our pro forma
leverage ratio is less than or equal to 2.0 to 1.0.
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, 2022, 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.
2022 ABL Facility
On August 9, 2022, C&J and C&J Management, which are the two entities that constitute the well servicing and
abandonment segment referred to as CJWS, as borrowers, entered into a credit agreement with Tri Counties Bank, as
lender, that provides for a revolving loan facility, subject to satisfaction of customary conditions precedent to
borrowing, of up to the lesser of (x) $15 million and (y) the borrowing base (“the “2022 ABL Facility”). The
“borrowing base” is an amount equal to 80% percent of the balance due on eligible accounts receivable, subject to
reserves that Tri Counties Bank may implement in its reasonable discretion. Interest on the outstanding principal
amount of the revolving loans under the 2022 ABL Facility accrues at a per annum rate equal to 1.25% in excess of
The Wall Street Journal Prime Rate. The “Wall Street Journal Prime Rate” is the variable rate of interest, on a per
annum basis, which is announced and/or published in the “Money Rates” section of The Wall Street Journal from
time to time as its “Prime Rate”. The rate will be redetermined whenever The Wall Street Journal Prime Rate
88
changes. Interest is due quarterly, in arrears, starting on September 30, 2022 and will continue to be due and payable
in arrears on the last day of each calendar quarter thereafter. On June 5, 2025 the entire unpaid principal balance of
the revolving loans under the 2022 ABL Facility, and all unpaid interest thereon, will be due and payable. The 2022
ABL Facility provides a letter of credit sub-facility for the issuance of letters of credit in an aggregate amount not to
exceed $7.5 million.
The 2022 ABL Facility requires CJWS to comply with the following financial covenants (i) maintain on a
consolidated basis a ratio of total liabilities to tangible net worth of no greater than 1.5 to 1.0 at any time; (ii) reduce
the amount of revolving advances outstanding under the 2022 ABL Facility to not more than 90% of the lesser of (a)
the maximum revolving advance amount, or (b) the borrowing base, as of Tri Counties Bank’s close of business on
the last day of each fiscal quarter; and (iii) maintain net income before taxes of not less than $1.00 as of each fiscal
year end. As of December 31, 2022, CJWS had a ratio of total liabilities to tangible net worth of 0.23 to 1.0, no
advances outstanding, and net income for fiscal year end 2022 was $15 million.
The 2022 ABL Facility contains usual and customary events of default and remedies for credit facilities of a
similar nature. The 2022 ABL Facility also places restrictions on CJWS with respect to additional indebtedness,
liens, dividends and other distributions, investments, acquisitions, mergers, asset dispositions and other matters.
CJWS’s obligations under the 2022 ABL Facility are not guaranteed by Berry Corp. or Berry LLC and Berry Corp.
and Berry LLC do not and are not required to provide any credit support for such obligations. CJWS was in
compliance with all financial covenants under the 2022 ABL Facility as of December 31, 2022.
As of December 31, 2022, CJWS had no borrowings and $2 million letters of credit outstanding with
$13 million of available borrowing capacity under the 2022 ABL Facility.
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, which resulted in net proceeds to us of approximately $391 million after
deducting expenses and the initial purchasers’ discount.
The 2026 Notes are Berry LLC’s 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 2026 Notes are fully and
unconditionally guaranteed on a senior unsecured basis by Berry Corp. and will also be guaranteed by certain of our
future subsidiaries; C&J Management and C&J 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
2021 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, including the obligations of C&J
Management and C&J under the 2022 ABL Facility.
Berry LLC may, at its option, redeem all or a portion of the 2026 Notes at any time. If we experience certain
kinds of change 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 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.
89
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 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”.
90
As of January 31, 2023, we had the following crude oil production and gas purchases hedges.
Q1 2023
Q2 2023
Q3 2023
Q4 2023
FY 2024
FY 2025
FY 2026
Brent - Crude Oil production
Swaps
Hedged volume (bbls)
Weighted-average price
($/bbl)
Put Spreads
1,385,278
1,387,750
1,211,717
1,196,000
3,392,048
—
$
77.15 $
77.01 $
76.26 $
76.18 $
76.12 $
— $
Hedged volume (bbls)
Weighted-average price
($/bbl)
540,000
$50.00/
$40.00
546,000
$50.00/
$40.00
552,000
$50.00/
$40.00
552,000
$50.00/
$40.00
1,281,000
$50.00/
$40.00 $
—
— $
Producer Collars
—
—
—
—
Hedged volume (bbls)
Weighted-average price
($/bbl)
360,000
$40.00/
$106.00
364,000
$40.00/
$106.00
368,000
$40.00/
$106.00
368,000
$40.00/
$106.00
1,098,000
$40.00/
$105.00
2,486,127
$58.53/
$91.11
472,500
$60.00/
$82.21
Henry Hub - Natural Gas purchases
Consumer Collars
Hedged volume (mmbtu)
Weighted-average price
($/mmbtu)
2,110,000
1,820,000
—
—
—
—
$4.00/$2.75 $4.00/$2.75 $
— $
— $
— $
— $
NWPL - Natural Gas purchases
Swaps
Hedged volume (mmbtu)
Weighted-average price
($/mmbtu)
1,800,000
3,640,000
3,680,000
3,680,000
7,320,000
6,080,000
$
6.40 $
5.34 $
5.34 $
5.34 $
4.27 $
4.27 $
Gas Basis Differentials
NWPL/HH - Natural Gas Purchases
Hedged volume (mmbtu)
Weighted-average price
($/mmbtu)
1,180,000
—
—
610,000
—
—
$
1.12 $
— $
— $
1.12 $
— $
— $
—
—
—
—
—
—
91
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,
2022
2021
$
$
$
$
$
$
91.98 $
(14.39) $
77.59 $
7.86 $
(1.74) $
6.12 $
66.57
(16.45)
50.12
5.64
(2.16)
3.48
For 2022, the Company will have paid $1.78 per share in cash dividends including both fixed and variable cash
dividends. This includes the variable cash dividend approved by our Board of Directors in February 2023 of $0.44
per share which was earned in the fourth quarter of 2022. In addition, in February 2023 our Board of Directors
approved a fixed cash dividend of $0.06 per share.
The following table represents the regular fixed cash dividends on our common stock and variable cash
dividends approved by our Board of Directors.
Fixed Dividends
Variable Dividends(1)
Total
__________
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Year-to-Date
$
$
0.06 $
0.13
0.19 $
0.06 $
0.56
0.62 $
0.06 $
0.41
0.47 $
0.06 $
0.44
0.50 $
0.24
1.54
1.78
(1) Variable Dividends are declared the quarter following the period of results (the period used to determine the variable dividend based on the
shareholder return model). The table notes total dividends earned in each quarter.
The Company anticipates that it will continue to pay quarterly cash dividends in the future. However, the
payment and amount of future dividends remain within the discretion of the Board and will depend upon the
Company’s future earnings, financial condition, capital requirements and other factors.
Stock Repurchase Program
For the year ended December 31, 2022, we repurchased 5 million shares for approximately $51 million. As of
December 31, 2022, the Company had repurchased a total of 10,528,704 shares under the stock repurchase program
for approximately $104 million in aggregate, which is 14% of outstanding shares as of December 31, 2022. As
previously disclosed, the Company implemented a shareholder return model in early 2022, for which the Company
intends to allocate a portion of Adjusted Free Cash Flow to opportunistic share repurchases.
In April 2022, our Board of Directors approved an increase of $102 million to the Company’s stock repurchase
authorization bringing the Company’s remaining share repurchase authority to $150 million. As of December 31,
2022, the Company’s remaining total share repurchase authority is $98 million, after the repurchases made in 2022.
In February 2023, the Board of Directors approved an increase of $102 million to the Company’s stock repurchase
authorization bringing the Company’s remaining share authority to $200 million.
92
The Board’s authorization permits the Company to make purchases of its common stock from time to time in
the open market and in privately negotiated transactions, subject to market conditions and other factors, up to the
aggregate amount authorized by the Board. The Board’s authorization has no expiration date.
Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other
means, as determined in the Company's sole discretion. The manner, timing and amount of any purchases will be
determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and
other factors, may be commenced or suspended at any time without notice and does not obligate the company to
purchase shares during any period or at all. Any shares repurchased are reflected as treasury stock and any shares
acquired will be available for general corporate purposes.
Capital Program
Refer to Part II, Item 1 and 2. — “Our Capital Program” for details.
Acquisitions and Divestitures
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 a loss of approximately $2 million. Our 2021 production from these
properties was 1.2 mboe/d.
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 0.6 mboe/d.
Purchases of Various Oil and Gas Properties
During 2022, we also acquired various oil and gas properties, most of which consisted of unproved properties
for approximately $8 million in aggregate.
C&J Well Services Acquisition (2021)
On October 1, 2021, we acquired one of the largest 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 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.
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.
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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 increase (decrease) in cash and cash equivalents
Operating Activities
Year Ended December 31,
2022
2021
(in thousands)
$
$
360,941 $
(164,552)
(165,422)
30,967 $
122,488
(168,787)
(18,975)
(65,274)
Cash provided by operating activities increased for the year ended December 31, 2022 by approximately $238
million when compared to the year ended December 31, 2021. The most significant increases were sales of $209
million (excluding CJWS), an increase in working capital of $70 million, an increase of $23 million related to net
margin for CJWS, and a decrease in taxes, other than income taxes of $7 million, partially offset by an increase of
$59 million in operating expenses, and an increase of $12 million in general and administrative costs (excluding
CJWS).
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,
2022
2021
(in thousands)
(152,921)
14,286
(25,917)
—
—
—
(132,719)
482
(50,568)
(876)
14,025
869
Net cash used in investing activities
$
(164,552) $
(168,787)
__________
(1) Based on actual cash payments rather than accrual.
Cash used in investing activities decreased $4 million for the year ended December 31, 2022 when compared to
the year ended December 31, 2021, primarily due to a decrease in cash used for acquisitions of $25 million, partially
offset by a decrease in proceeds from divestiture and sale of property and equipment and other proceeds received of
$15 million and an increase in cash used for capital expenditures and related accruals of $6 million.
94
Financing Activities
Cash used in financing activities increased $146 million for the year ended December 31, 2022 when compared
to the year ended December 31, 2021. In 2022, the cash used was primarily for dividends paid of $109 million, the
purchase of treasury stock of $51 million, and shares withheld for payment of taxes on equity awards and other of $4
million. In 2021, the cash used was primarily for dividends paid of $11 million, debt issuance costs related to the
2017 RBL Facility of $4 million, the purchase of treasury stock for $2 million, and shares withheld for payment of
taxes on equity awards and other of approximately $1 million.
Commitments, and Contingencies
In the normal course of business, we, or our subsidiaries, 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, 2022 and December 31, 2021. 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, 2022, we
are not aware of material indemnity claims pending or threatened against us.
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 November 1, 2021, the court-appointed 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 and on September 13, 2022, the Court issued an
order denying that motion. The case is now in discovery.
We dispute these claims and intend to defend the matter vigorously. Given the uncertainty of litigation, the early
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.
95
On October 20, 2022, a shareholder derivative lawsuit was filed in the United States District Court for the
Northern District of Texas by putative stockholder George Assad, allegedly on behalf of the Company, that piggy-
backs on the securities class action referenced above and which is currently pending before the same Court. The
derivative complaint names certain current and former officers and directors as defendants, and generally alleges
that they breached their fiduciary duties by causing or failing to prevent the securities violations alleged in the
securities class action. The derivative complaint also alleges claims for unjust enrichment as against all defendants,
and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act. On January 27,
2023, the court granted the parties’ joint stipulated request to stay the derivative action pending resolution of the
related securities class action. The Company and the individual defendants believe the claims in the shareholder
derivative action are without merit and intend to defend vigorously against them, but there can be no assurances as
to the outcome. At this time, we are unable to estimate the probability or the amount of liability, if any, related to
this matter.
On January 20, 2023, a second shareholder derivative lawsuit was filed, this time in the United States District
Court for the District of Delaware, by putative stockholder Molly Karp allegedly on behalf of the Company, again
piggy-backing on the securities class action referenced above. This complaint, similar to the first derivative
complaint, is brought against certain current and former officers and directors of the Company, asserting breach of
fiduciary duty, aiding and abetting, and contribution claims based on the defendants allegedly having caused or
failed to prevent the securities violations alleged in the securities class action. In addition, the complaint asserts a
claim under Section 14(a) of the Exchange Act, alleging that Berry’s 2022 Proxy Statement was false and
misleading in that it suggested the Company’s internal controls were sufficient and the board of directors was
adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the
case. The defendants believe the claims in the shareholder derivative action are without merit and intend to defend
vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate
the probability or the amount of liability, if any, related to this matter.
Contractual Obligations
In the ordinary course of our business, we enter 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. At December 31, 2022, future net minimum payments
for non-cancelable purchase obligations (excluding oil and natural gas and other mineral leases, utilities, taxes and
insurance expense) were as follows:
Off-Balance Sheet arrangements:
Processing and transportation contracts(1)
Drilling commitment(2)
Total
__________
Total
Less Than 1
Year
Payments Due
1-3
Years
(in thousands)
3-5
Years
Thereafter
$
88,816 $
11,343 $
17,787 $
16,165 $
43,521
17,100
8,400
8,700
—
—
$ 105,916 $
19,743 $
26,487 $
16,165 $
43,521
(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 include 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 June 2024. In November 2022, the drilling commitment was revised to require 28 of those wells to be
drilled by October 2023, with a minimum commitment of $8.4 million.
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Balance Sheet Analysis
The changes in our balance sheet from December 31, 2021 to December 31, 2022 are discussed below.
Cash and cash equivalents
Accounts receivable, net
Derivative instruments assets - current and long-term
Other current assets
Property, plant & equipment, net
Deferred income taxes asset - long-term
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, 2022
December 31, 2021
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(in thousands)
46,250 $
101,713 $
36,443 $
33,725 $
15,283
86,269
1,070
45,946
1,359,813 $
1,301,349
42,844 $
10,242 $
203,101 $
44,748 $
395,735 $
— $
158,491 $
28,470 $
800,485 $
—
6,562
157,524
48,202
394,566
1,831
143,926
17,782
692,648
See “—Liquidity and Capital Resources” for discussions about the changes in cash and cash equivalents.
The $15 million increase in accounts receivable was driven by higher selling prices in the E&P segment and
higher activity in CJWS.
The net derivative liability changed from $47 million in 2021 to a net liability of $8 million in 2022. 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 $12 million decrease in other current assets was primarily due to a $4 million decrease in prepaid
permitting fees, a $8 million decrease in acquisition and divestiture receivables, a $3 million return of collateral for
commitments, all partially offset by an increase in prepaid insurance of $2 million and an increase in oil inventory of
$1 million.
The $58 million increase in property, plant and equipment was largely the result of the $153 million in capital
investments and $24 million of additional assets related to asset retirement obligation and $26 million in acquisition
activity, offset by depreciation expense of $146 million.
The $43 million increase in long-term deferred income tax asset was due to the fact that we have determined
that there is sufficient positive evidence to realize our deferred assets in future years and have reversed the
previously recorded valuation allowance.
The $4 million increase in other non-current assets was primarily due to the adoption of new lease accounting
rules in the first quarter for $6 million, net of accumulated amortization, partially offset by amortization of debt
issuance costs of $1 million and a $1 million adjustment to the provisional amount assigned to intangible assets for
CJWS acquisition.
97
The $46 million increase in accounts payable and accrued expenses included $45 million of increased accruals
and spending for capital and operating costs due to the increased level of these activities at the end of each year, a
$13 million increase in royalties accrued due to increased sales prices, partially offset by a decrease of
approximately $8 million in the current portion of the greenhouse gas obligation which was reclassified to long-term
liabilities based on the expected due date and a $5 million decrease in dividends payable due to declaration date
timing.
The $2 million decrease in long-term deferred income taxes liability was due to the income tax benefit during
the year.
The $15 million increase in the long-term portion of the asset retirement obligation from $144 million at
December 31, 2021 to $158 million at December 31, 2022 was due to revised cost estimates of $21 million,
$11 million of accretion, and $3 million of liabilities incurred. Revised cost estimates reflect the impact of inflation
and idle well regulation compliance. These increases were partially offset by $1 million of reduction due to property
sales and $20 million of liabilities settled during the period.
The $11 million increase in other non-current liabilities was driven by additional non-current greenhouse gas
liabilities compared to prior year, including the $8 million reclassification from current liabilities.
The $108 million increase in stockholders' equity was due to net income of $250 million and $18 million of
stock-based equity awards, net of taxes. These increases were partially offset by $105 million of common stock
dividends declared, $51 million of treasury stock purchased, and $4 million of shares withheld for payment of taxes
on equity awards.
Non-GAAP Financial Measures
Adjusted EBITDA, Adjusted 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), Adjusted Free Cash Flow is not a measure of
cash flow, and Adjusted EBITDA is not a measure of either net income (loss) or cash flow, in all cases, as
determined by GAAP. Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted
General and Administrative Expenses are supplemental non-GAAP financial measures used by management and
external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.
We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, and
amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements;
impairments; stock compensation expense; and unusual and infrequent items. Our management believes Adjusted
EBITDA provides useful information in assessing our financial condition, results of operations and cash flows and is
widely used by the industry and the investment community. The measure also allows our management to more
effectively evaluate our operating performance and compare the results between periods without regard to our
financing methods or capital structure. We also use Adjusted EBITDA in planning our capital allocation to sustain
production levels and to determine our strategic hedging needs aside from the hedging requirements of the 2021
RBL Facility.
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 statutory tax rate. 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
believe Adjusted Net Income (Loss) is useful to investors because it reflects how management evaluates the
Company’s ongoing financial and operating performance from period-to-period after removing certain transactions
98
and activities that affect comparability of the metrics and are not reflective of the Company’s core operations. We
believe this also makes it easier for investors to compare our period-to-period results with our peers.
We define Adjusted Free Cash Flow, which is a non-GAAP financial measure, as cash flow from operations
less regular fixed dividends and maintenance capital. Maintenance capital represents the capital expenditures needed
to maintain the same volume of annual oil and gas production and is defined as capital expenditures, excluding,
when applicable, E&P capital expenditures that are related to strategic business expansion, such as acquisitions and
divestitures of oil and gas properties and any exploration and development activities to increase production beyond
the prior year’s annual production volumes and capital expenditures in our Well Servicing and Abandonment and
Corporate segments that are related to ancillary sustainability initiatives or other expenditures that are discretionary
and unrelated to maintenance of our core business. Management believes Adjusted Free Cash Flow may be useful in
an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base
after maintaining the existing production volumes of that asset base to return capital to stockholders, fund further
business expansion through acquisitions or investments in our existing asset base to increase production volumes
and pay other non-discretionary expenses. Management also uses Adjusted Free Cash Flow as the primary metric to
determine the quarterly variable dividend. Under our shareholder return model, in 2022, we expected to allocate
60% of Adjusted Free Cash Flow to direct shareholder returns, predominantly in the form of cash variable
dividends, as well as opportunistic debt repurchases. We expected to use the remaining 40% for opportunistic
growth, including from our extensive inventory of drilling opportunities, advancing our short- and long-term
sustainability initiatives, share repurchases, capital retention and funding mandatory debt service requirements or
other non-discretionary expenditures. In early 2023, we updated our shareholder return model, including to double
our quarterly fixed dividend to $0.12 per share. 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. We also modified the allocations of Adjusted Free Cash Flow.
Our goal is to continue maximizing shareholder value through overall returns. The allocation beginning in 2023 will
be (a) 80% primarily in the form of debt or share repurchases; and (b) 20% in the form of variable cash dividends.
Adjusted Free Cash Flow does not represent the total increase or decrease in our cash balance, and it should not
be inferred that the entire amount of Adjusted Free Cash Flow is available for variable dividends, debt or share
repurchase or other discretionary expenditures, since we have mandatory debt service requirements and other non-
discretionary expenditures that are not deducted from this measure.
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 believe Adjusted General and Administrative Expenses is useful to investors because it reflects how
management evaluates the Company’s ongoing general and administrative expenses from period-to-period after
removing non-cash stock compensation, as well as unusual or infrequent costs that affect comparability of the
metrics and are not reflective of the Company’s administrative costs. We believe this also makes it easier for
investors to compare our period-to-period results with our peers.
While Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and
Administrative Expenses are non-GAAP measures, the amounts included in the calculation of Adjusted EBITDA,
Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses were
computed in accordance with GAAP. These measures are provided in addition to, and not as an alternative for,
income and liquidity measures calculated in accordance with GAAP and should not be considered as an alternative
to, or more meaningful than income and liquidity measures calculated in accordance with GAAP. Certain items
excluded from Adjusted EBITDA are significant components in understanding and assessing our financial
performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable
assets. Our computations of Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and
Adjusted General and Administrative Expenses may not be comparable to other similarly titled measures used by
other companies. Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General
and Administrative Expenses should be read in conjunction with the information contained in our financial
statements prepared in accordance with GAAP.
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The following tables present reconciliations of the non-GAAP financial measure Adjusted EBITDA to the
GAAP financial measures of net income (loss) and net cash provided (used) by operating activities, as applicable,
for each of the periods indicated.
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)
Add (Subtract):
Interest expense
Income tax (benefit) expense
Depreciation, depletion, and amortization
Losses on derivatives
Net cash paid for scheduled derivative settlements
Other operating expenses
Stock compensation expense
Non-recurring costs(1)
Adjusted EBITDA
Year Ended December 31,
2022
2021
(in thousands)
$
250,168 $
(15,542)
31,964
1,413
144,495
117,822
(87,625)
3,101
13,783
2,735
212,146
30,917
(42,436)
156,847
48,314
(88,023)
3,722
16,973
3,466
$
379,948 $
Year Ended December 31,
2022
2021
(in thousands)
Adjusted EBITDA reconciliation to net cash provided by operating activities:
Net cash provided by operating activities
$
360,941 $
122,488
Add (Subtract):
Cash interest payments
Cash income tax payments
Non-recurring costs(1)
Changes in operating assets and liabilities - working capital(2)
Other operating expenses, net (noncash portion)(3)
Adjusted EBITDA
__________
29,792
3,633
3,466
(21,446)
3,562
29,211
699
2,735
53,425
3,588
$
379,948 $
212,146
(1) Non-recurring costs include legal and professional service expenses related to acquisition and divestiture activity for the fourth quarter of
2021 and the first quarter of 2022 and the executive transition costs in the fourth quarter of 2022.
(2) Changes in other assets and liabilities consists of working capital and various immaterial items.
(3) Represents other operating expenses (income) from the income statement, net of the non-cash portion in the cash flow statement.
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The following table presents a reconciliation of the non-GAAP financial measure Adjusted Free Cash Flow to
the GAAP financial measure of operating cash flow in the period indicated. We use Adjusted Free Cash Flow for
our shareholder return model, which began in 2022.
Adjusted Free Cash Flow:
Net cash provided by operating activities(1)
Subtract:
Maintenance capital(2)
Fixed dividends(3)
Adjusted Free Cash Flow(4)
__________
(1) On a consolidated basis.
Year Ended December 31, 2022
(in thousands)
$
$
360,941
(141,930)
(19,245)
199,766
(2) Maintenance capital is the capital required to keep annual production flat, and is calculated as follows:
Consolidated capital expenditures(a)
Excluded items(b)
Maintenance capital
__________
Year Ended December 31, 2022
(in thousands)
$
$
(152,921)
10,991
(141,930)
(a) Capital expenditures include capitalized overhead and interest and excludes acquisitions and asset retirement spending.
(b) Comprised of the capital expenditures in our E&P segment that are related to strategic business expansion, such as acquisitions and
divestitures of oil and gas properties and any exploration and development activities to increase production beyond the prior year’s
annual production volumes and capital expenditures in our well servicing and abandonment segment and corporate expenditures that
are related to ancillary sustainability initiatives or other expenditures that are discretionary and unrelated to maintenance of our core
business. For the year ended December 31, 2022, we excluded approximately $8 million of capital expenditures in our well servicing
and abandonment segment. In this period, we also excluded approximately $3 million of corporate capital expenditures, which we
determined was not related to the maintenance of our baseline production.
(3) Represents fixed dividends declared which are included in the “Dividends declared on common stock” line in the consolidated statement of
stockholders’ equity.
(4) Adjusted Free Cash Flow was not a metric utilized by the Company prior to 2022.
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The following table presents a reconciliation of the non-GAAP financial measure Adjusted Net Income (Loss)
to the GAAP financial measure of net income (loss) and Adjusted Net Income (Loss) per share — diluted to net
income per share — diluted.
Year Ended December 31,
2022
2021
(in thousands)
per share - diluted
(in thousands)
per share - diluted
Adjusted Net Income (Loss) reconciliation to net income (loss):
Net income (loss)
$
250,168 $
3.03 $
(15,542) $
(0.19)
Add (Subtract):
Losses on derivatives
Net cash paid for scheduled derivative
settlements
Other operating expenses
Non-recurring costs(1)
48,314
0.59
117,822
(88,023)
(1.07)
(87,625)
3,722
3,466
0.04
0.04
3,101
2,735
36,033
Total additions (subtractions), net
(32,521)
(0.40)
Income tax benefit (expense) of
adjustments(2)
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
__________
8,816
226,463 $
0.11
2.74 $
(9,769)
10,722 $
2.88
2.74
78,517
82,586
$
$
0.13
0.13
80,209
83,496
1.41
(1.05)
0.05
0.03
0.44
(0.12)
0.13
(1) Non-recurring costs include legal and professional service expenses related to acquisition and divestiture activity for the fourth quarter of
2021 and the first quarter of 2022 and the executive transition costs in the fourth quarter of 2022.
(2) The federal and state statutory rate was utilized in both 2022 and 2021. We updated the disclosure for 2021 to reflect the statutory rate,
instead of the effective tax rate previously utilized.
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The following table presents a reconciliation of the non-GAAP financial measure Adjusted General and
Administrative Expenses to the GAAP financial measure of general and administrative expenses for each of the
periods indicated.
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(1)
Adjusted general and administrative expenses
E&P segment, and corporate
Well servicing and abandonment segment
__________
Year Ended December 31,
2022
2021
(in thousands)
$
$
$
$
$/boe
$/boe
96,439
(16,498)
(3,466)
76,475
$
$
73,106
(13,356)
(2,735)
57,015
63,500 $ 6.66 $
12,975
$
53,822 $ 5.38
3,193
(1) Non-recurring costs include legal and professional service expenses related to acquisition and divestiture activity for the fourth quarter of
2021 and the first quarter of 2022 and the executive transition costs in the fourth quarter of 2022.
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
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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 $0.70 per mmboe, which would increase or decrease pre-tax income
by approximately $7 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, 2022 and 2021, the net capitalized costs attributable to unproved properties was approximately $248
million for both periods. 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. 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, 2022.
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
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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
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” and
“ROIC PSUs”) over the performance period. CROIC PSUs are awarded to certain Berry employees, while ROIC
PSUs are awarded to certain CJWS employees. 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, CROIC PSUs and ROIC 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.
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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
The U.S. inflation rate has been steadily increasing since 2021 and throughout much of 2022. The Company,
similar to other companies in our industry, has experienced inflationary pressures on our costs - namely inflationary
pressures have resulted in increases to the costs of our goods, services and personnel, which in turn, have caused our
capital expenditures and operating costs to rise. Such inflationary pressures have resulted from supply chain
disruptions caused by the COVID pandemic, increased demand, labor shortages and other factors, including the
conflict between Russia and the Ukraine which began in late February 2022. In late 2022, inflation rates have begun
to stabilize and even decrease from the levels experienced earlier in the year. We are unable to accurately predict if
such inflationary pressures and contributing factors will continue into 2023.
Such inflationary pressures on our operating costs have, in turn, impacted our cash flows and results of
operations. While we are not able to accurately measure with precision the impact of inflation without unreasonable
efforts, we have noted an overall increase in costs from our plans throughout 2022, which is due, in part, to inflation.
For example, the Company’s 2022 drilling costs per well, excluding our well servicing and abandonment segment,
were approximately 13% higher than the prior year, including an approximately 25% increase in capital costs for our
Utah drilling program in 2022 compared to our initial plans. Key components driving these cost increases compared
to the prior year were steel costs (approximately 50% increase) and service costs (approximately 5% to 10%
increase). We were able to mitigate a portion of the steel cost inflation by purchasing a significant portion of the
steel used in 2022 prior to the most significant inflation impacts. However, our ability to mitigate the effects of
inflation vary from project to project and depend on the timing of necessary capital expenditures. In addition, our
E&P operating costs excluding fuel were approximately 23% higher in 2022 than 2021, due to a combination of
inflation and increased activity of certain costs. Our fuel costs were approximately 39% higher in 2022 than in 2021
due to the significant increase in natural gas prices. We were able to mitigate a significant portion of this increase
through our hedging program. However, our ability to mitigate the effects of inflation on fuel prices may vary
depending on market volatility and the terms of our hedge agreements.
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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, and government efforts to reduce
inflation, including increased interest rates;
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, including as a result of political instability, armed-conflict or
economic sanctions;
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;
107
•
•
•
•
•
•
•
•
•
•
•
•
•
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;
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.
108
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. The Company continually monitors its
market risk exposure, including the impact and developments related to the armed conflict in Ukraine, increase in
interest rate and inflation trend, which introduced significant volatility and uncertainties in the financial markets
during 2022.
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,
2022, the fair value of our hedge positions was a net liability of approximately $8 million. A 10% increase in the oil
and natural gas index prices above the December 31, 2022 prices would result in a net liability of approximately
$126 million; conversely, a 10% decrease in the oil and natural gas index prices below the December 31, 2022
prices would result in a net asset of approximately $17 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 six commodity derivative counterparties at December 31, 2022 and five at December 31, 2021. 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
109
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
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, 2022 was not material and losses associated with credit risk have not 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, 2022, we had
no borrowings under our 2021 RBL Facility and 2022 ABL 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.
110
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, 2022 and December 31, 2021 ....................................
Consolidated Statements of Operations for the Years Ended December 31, 2022, 2021 and 2020 .........
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2022, 2021 and
2020 .......................................................................................................................................................
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020 ........
Notes to Consolidated Financial Statements .............................................................................................
Supplemental Oil & Natural Gas Data (Unaudited) ..................................................................................
Page
112
113
114
115
116
117
150
111
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, 2022 and 2021, the related consolidated statements of operations, stockholders’
equity, and cash flows for each of the years in the three-year period ended December 31, 2022, 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, 2022 and 2021, and the
results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2022, 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.
Dallas, Texas
February 27, 2023
112
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, 2022 and December 31, 2021
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
Deferred income taxes
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, 2022
December 31, 2021
(in thousands, except share amounts)
$
46,250 $
101,713
36,367
33,725
218,055
1,725,864
(465,889)
1,259,975
155,619
(55,781)
99,838
42,844
76
10,242
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
$
$
1,631,030 $
1,456,479
203,101 $
31,106
234,207
395,735
13,642
—
158,491
28,470
157,524
29,625
187,149
394,566
18,577
1,831
143,926
17,782
Common stock ($0.001 par value; 750,000,000 shares authorized; 86,350,771
and 85,590,417 shares issued; and 75,767,503 and 80,007,149 shares
outstanding, at December 31, 2022 and December 31, 2021, respectively)
Additional paid-in capital
Treasury stock, at cost (10,583,268 shares at December 31, 2022 and 5,583,268
shares at December 31, 2021)
Retained earnings (accumulated deficit)
Total stockholders' equity
86
86
821,443
(103,739)
82,695
800,485
912,471
(52,436)
(167,473)
692,648
Total liabilities and stockholders' equity
$
1,631,030 $
1,456,479
The accompanying notes are an integral part of these financial statements.
113
BERRY CORPORATION (bry)
CONSOLIDATED STATEMENTS OF OPERATIONS
Revenues and other:
Oil, natural gas and natural gas liquid sales
$
842,449 $
625,475 $
378,663
Year Ended December 31,
2022
2021
2020
(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
Income (loss) before income taxes
Income tax (benefit) expense
Net income (loss)
Net income (loss) per share:
Basic
Diluted
181,400
30,833
(137,109)
289
479
918,341
302,321
142,819
21,839
4,564
299
96,439
156,847
—
39,495
(88,795)
3,722
679,550
(30,917)
(142)
(31,059)
207,732
(42,436)
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)
$
$
$
250,168 $
(15,542) $
(262,895)
3.19 $
3.03 $
(0.19) $
(0.19) $
(3.29)
(3.29)
The accompanying notes are an integral part of these financial statements.
114
BERRY CORPORATION (bry)
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
December 31, 2019
$
85 $ 901,830 $ (49,995) $
120,528 $ 972,448
Common
Stock
Additional
Paid-in
Capital
Treasury
Stock
Retained
Earnings
(Accumulated
Deficit)
Total
Equity
(in thousands)
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
Shares withheld for payment of taxes on equity awards
Stock based compensation
Purchase of treasury stock
Dividends declared on common stock, $1.34/share
Net income
December 31, 2022
$
—
—
—
—
85
—
—
1
—
—
—
86
—
—
—
(1,039)
15,086
—
—
915,877
(1,543)
14,434
—
—
(16,297)
—
912,471
(4,136)
17,762
—
—
—
—
—
(49,995)
—
—
—
(2,441)
—
—
(52,436)
—
—
(51,303)
(104,654)
—
—
—
86 $ 821,443 $ (103,739) $
—
—
—
—
(1,039)
15,086
(9,564)
(262,895)
(151,931)
(9,564)
(262,895)
714,036
—
—
—
—
(1,543)
14,434
1
(2,441)
—
(15,542)
(167,473)
(16,297)
(15,542)
692,648
—
—
—
(4,136)
17,762
(51,303)
—
250,168
(104,654)
250,168
82,695 $ 800,485
The accompanying notes are an integral part of these financial statements.
115
BERRY CORPORATION (bry)
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flow from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by
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
Decrease (increase) in other assets
Increase (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
Borrowings under 2022 ABL credit facility
Repayments on 2022 ABL 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 increase (decrease) in cash and cash equivalents
Cash and cash equivalents:
Year Ended December 31,
2022
2021
2020
(in thousands)
$
250,168 $
(15,542) $
(262,895)
156,847
2,590
—
16,973
(45,566)
—
160
48,314
(88,023)
(15,409)
6,725
36,100
(7,938)
360,941
(152,921)
14,286
(25,917)
—
—
—
(164,552)
247,000
(247,000)
2,000
(2,000)
(109,455)
(51,303)
(4,136)
(528)
(165,422)
30,967
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)
119,000
(119,000)
—
—
(11,486)
(2,440)
(1,543)
(3,506)
(18,975)
(65,274)
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)
228,900
(230,750)
—
—
(19,463)
—
(1,039)
—
(22,352)
80,557
Beginning
Ending
15,283
46,250 $
80,557
15,283 $
—
80,557
$
The accompanying notes are an integral part of these financial statements.
116
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 (“C&J”). As the
context may require, the “Company”, “we”, “our” or similar words refer to Berry Corp. and its subsidiary, Berry
LLC, and as of October 1, 2021 this also includes C&J Management and C&J.
Nature of Business
We are a western United States independent upstream energy company with a focus on onshore, low geologic
risk, long-lived conventional reserves in the San Joaquin basin of California (100% oil) and the Uinta basin of Utah
(oil and gas), with well servicing and abandonment capabilities in California. Since October 1, 2021, we have
operated in two business segments: (i) exploration and production (“E&P”) and (ii) well servicing and abandonment.
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 E&P 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 E&P segment consists of the development and production of onshore, low geologic risk, long-lived
conventional oil and gas 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.
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.
117
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 $1 million, $2 million and $1 million in 2022, 2021 and 2020,
respectively. 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 $6 million, $7 million and $6 million in 2022, 2021 and 2020,
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
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, 2022 and 2021, the net capitalized costs attributable to unproved properties was approximately $248
million and $292 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.
118
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, adverse change in regulatory environment, 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 2022 and 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.
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 cogeneration facilities, natural gas plants and pipelines, 1 to 10 years
for 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
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. 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.
119
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 $158 million and $144
million were included in long term liabilities as of December 31, 2022 and December 31, 2021, 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,
2022
2021
(in thousands)
$
163,925 $
3,028
(19,558)
10,848
(1,210)
21,458
$
178,491 $
160,192
1,350
(17,900)
10,936
(22,199)
31,546
163,925
The majority of the Company's revenue is from the E&P 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.
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.
120
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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” and
“ROIC PSUs”) over the performance period. CROIC PSUs are awarded to certain Berry employees, while ROIC
PSUs are awarded to certain CJWS employees. 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, CROIC PSUs and ROIC 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
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.
121
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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
Basic earnings (loss) per share is calculated as net income (loss) divided by the weighted-average shares of
common stock outstanding during the period. Diluted earnings (loss) per share is calculated by dividing net income
(loss) by the weighted-average shares of common stock outstanding, including the effect of potentially dilutive
securities. For basic earnings per share (“EPS”), the weighted-average number of common stock 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. We did not have
any participating securities in the periods presented.
We compute basic and diluted 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. Our dividend rights are forfeitable, and are not considered participating securities.
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.
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, 2022, our three largest customers represented approximately 33%, 16%, and
10% of our sales. For the year ended December 31, 2021, our four largest customers represented 30%, 16%, 14%,
and 12% of our sales. For the year ended December 31, 2020, our three largest customers represented approximately
44%, 20%, and 12% of our sales. All such customers were customers of our E&P segment.
At December 31, 2022, trade accounts receivable from three customers represented approximately 33%, 16%,
and 13% of our receivables. At December 31, 2021, trade accounts receivable from three customers represented
approximately 28%, 13%, and 11% of our receivables.
122
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Recently Adopted Accounting Standards
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
adopted these rules in the first quarter of 2022 prospectively. The impacts of adoption were immaterial.
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,
2022
2021
(in thousands)
$
1,477,791 $
1,246,380
248,073
1,725,864
(465,889)
291,514
1,537,894
(340,328)
$
1,259,975 $
1,197,566
Year Ended December 31,
2022
2021
(in thousands)
Cogeneration facilities, 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
$
58,357 $
65,195
23,779
6,102
2,186
155,619
(55,781)
Total other property and equipment, net
$
99,838 $
54,237
55,521
22,665
6,101
2,186
140,710
(36,927)
103,783
123
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
__________
(1)
Includes CJWS vehicles and service equipment.
Note 3—Debt
The following table summarizes our outstanding debt:
December 31,
2022
December 31,
2021
(in thousands)
Interest Rate
Maturity
Security
2021 RBL Facility
$
— $
—
variable rates
9.5% (2022) and
5.3% (2021)
August 26, 2025
2022 ABL Facility
—
n/a
variable rates
8.3% (2022)
June 5, 2025
Mortgage on 90% of
Present Value of proven
oil and gas reserves and
lien on certain other
assets
Personal property assets,
other than excluded
accounts
2026 Notes
400,000
400,000
7.0%
February 15, 2026
Unsecured
Long-Term Debt -
Principal Amount
400,000
400,000
Less: Debt Issuance Costs
(4,265)
(5,434)
Long-Term Debt, net
$
395,735 $
394,566
Deferred Financing Costs
We incurred legal and bank fees related to the issuance of debt. At December 31, 2022 and 2021, debt issuance
costs for the 2021 RBL Facility and the 2022 ABL Facility (each as defined below) reported in “other noncurrent
assets” on the balance sheet were approximately $4 million and $5 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 and also incurred approximately $4 million of legal and bank fees related to the issuance of the 2021 RBL
Facility. At December 31, 2022 and 2021, 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 $4
million and $5 million, respectively.
For the years ended December 31, 2022, 2021, and 2020, the amortization expense for the 2021 RBL Facility,
2022 ABL Facility, the 2017 RBL Facility and the 2026 Notes combined, was approximately $2 million, $4 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 amounts of the 2021 RBL
Facility and the 2022 ABL Facility approximate fair value because the interest rates are variable and reflect market
rates. The fair value of the 2026 Notes was approximately $369 million and $400 million at December 31, 2022 and
2021, respectively.
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BERRY CORPORATION (bry)
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 (as amended by the First Amendment, the Second Amendment and the Third Amendment, each as
defined below, the “2021 RBL Facility”). Our initial borrowing base 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.
In May 2022, Berry Corp., as a guarantor, and Berry LLC, as the borrower, entered into that certain Second
Amendment to Credit Agreement and Limited Consent and Waiver (the “Second Amendment”) pursuant to which,
among other things, the requisite lenders under the 2021 RBL Facility (i) consented to certain dividends and
distributions and to certain investments made by Berry LLC in C&J and/or C&J Management, in each case, as
further described therein, (ii) waived certain minimum hedging requirements for the time periods described therein,
(iii) waived any breach, default or event of default which may have arisen as a result of any of the foregoing, (iv)
amended the restricted payments covenant to give us additional flexibility to make restricted payments, subject to
satisfaction of certain leverage and availability conditions and other conditions described below and in the Second
Amendment and (v) amended the minimum hedging covenant to not, until October 1, 2022, require hedges for any
full calendar month from and after January 1, 2025, as further described in the Second Amendment. In May 2022,
we also completed our semi-annual borrowing base redetermination and entered into the Third Amendment to the
Credit Agreement (the “Third Amendment”), which among other things (1) increased the borrowing base from
$200 million to $250 million; (2) established the Aggregate Elected Commitment Amounts (as defined in the 2021
RBL Facility) at $200 million initially; and (3) converted all outstanding Eurodollar Loans (into Term Benchmark
Loans (each as defined in the 2021 RBL Facility) with an initial interest period of one-month’s duration and
otherwise give effect to the transition from the London interbank offered rate (“LIBOR”) to the secured overnight
financing rate (“SOFR”) by replacing the adjusted LIBOR rate with the term SOFR rate for one, three or six months
plus 0.1% (subject to a floor of 0.5%).
In December 2022, we completed our scheduled semi-annual borrowing base redetermination, which resulted
in a reaffirmed borrowing base at $250 million and $200 million elected commitment amount.
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
125
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2022, our leverage
ratio and current ratio were 1.2 to 1.0 and 1.7 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, 2022.
The 2021 RBL Facility contains usual and customary events of default and remedies for credit facilities of a
similar nature. The 2021 RBL Facility also places restrictions on the borrower and its restricted subsidiaries with
respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions
of our common stock, redemptions of the borrower’s senior notes, investments, acquisitions, mergers, asset
dispositions, transactions with affiliates, hedging transactions and other matters.
From and after August 26, 2022, the 2021 RBL Facility permits us to repurchase certain indebtedness so long as
both before and after giving pro forma effect to such repurchase, no default or event of default exists, availability is
equal to or greater than 20% of the borrowing base and our pro forma leverage ratio is less than or equal to 2.0 to
1.0. The 2021 RBL Facility also permits us to make restricted payments so long as both before and after giving pro
forma effect to such distribution, no default or event of default exists, availability exceeds 75% of the borrowing
base, and our pro forma leverage ratio is less than or equal to 1.5 to 1.0. In addition, we can make other restricted
payments in an aggregate amount not to exceed 100% of Free Cash Flow (as defined under the 2021 RBL Facility)
for the fiscal quarter most recently ended prior to such distribution so long as, in addition to other conditions and
limitations as described in the 2021 RBL Facility, both before and after giving pro forma effect to such distribution,
no default or event of default exists, availability is greater than 20% of the borrowing base and our pro forma
leverage ratio is less than or equal to 2.0 to 1.0.
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, 2022, 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.
2022 ABL Facility
On August 9, 2022, C&J and C&J Management, which are the two entities that constitute the well servicing and
abandonment segment referred to as CJWS, as borrowers, entered into a credit agreement with Tri Counties Bank, as
lender, that provides for a revolving loan facility, subject to satisfaction of customary conditions precedent to
borrowing, of up to the lesser of (x) $15 million and (y) the borrowing base (“the “2022 ABL Facility”). The
126
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
“borrowing base” is an amount equal to 80% percent of the balance due on eligible accounts receivable, subject to
reserves that Tri Counties Bank may implement in its reasonable discretion. Interest on the outstanding principal
amount of the revolving loans under the 2022 ABL Facility accrues at a per annum rate equal to 1.25% in excess of
The Wall Street Journal Prime Rate. The “Wall Street Journal Prime Rate” is the variable rate of interest, on a per
annum basis, which is announced and/or published in the “Money Rates” section of The Wall Street Journal from
time to time as its “Prime Rate”. The rate will be redetermined whenever The Wall Street Journal Prime Rate
changes. Interest is due quarterly, in arrears, starting on September 30, 2022 and will continue to be due and payable
in arrears on the last day of each calendar quarter thereafter. On June 5, 2025 the entire unpaid principal balance of
the revolving loans under the 2022 ABL Facility, and all unpaid interest thereon, will be due and payable. The 2022
ABL Facility provides a letter of credit sub-facility for the issuance of letters of credit in an aggregate amount not to
exceed $7.5 million.
The 2022 ABL Facility requires CJWS to comply with the following financial covenants (i) maintain on a
consolidated basis a ratio of total liabilities to tangible net worth of no greater than 1.5 to 1.0 at any time; (ii) reduce
the amount of revolving advances outstanding under the 2022 ABL Facility to not more than 90% of the lesser of (a)
the maximum revolving advance amount, or (b) the borrowing base, as of Tri Counties Bank’s close of business on
the last day of each fiscal quarter; and (iii) maintain net income before taxes of not less than $1.00 as of each fiscal
year end. As of December 31, 2022, CJWS had a ratio of total liabilities to tangible net worth of 0.2 to 1.0, no
advances outstanding, and net income for fiscal year end 2022 was $15 million.
The 2022 ABL Facility contains usual and customary events of default and remedies for credit facilities of a
similar nature. The 2022 ABL Facility also places restrictions on CJWS with respect to additional indebtedness,
liens, dividends and other distributions, investments, acquisitions, mergers, asset dispositions and other matters.
CJWS’s obligations under the 2022 ABL Facility are not guaranteed by Berry Corp. or Berry LLC and Berry Corp.
and Berry LLC do not and are not required to provide any credit support for such obligations. CJWS was in
compliance with all financial covenants under the 2022 ABL Facility as of December 31, 2022.
As of December 31, 2022, CJWS had no borrowings and $2 million letters of credit outstanding with
$13 million of available borrowing capacity under the 2022 ABL 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”). On August 26, 2021, we cancelled the
2017 RBL Facility agreement, which had a borrowing base of $200 million and there were no borrowings
outstanding at the time of cancellation.
Senior Unsecured Notes
In February 2018, Berry LLC 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.
The 2026 Notes are Berry LLC’s 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 2026 Notes are fully and
unconditionally guaranteed on a senior unsecured basis by Berry Corp. and will also be guaranteed by certain of our
future subsidiaries; C&J Management and C&J 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 our
2021 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 subsidiaries that do not guarantee the 2026 Notes, including the obligations of C&J Management
and C&J under the 2022 ABL Facility.
127
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Berry LLC may, at its option, redeem all or a portion of the 2026 Notes at any time. 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 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, 2022.
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 satisfying the oil hedging requirements in our 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 three 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.
128
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
For our long 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 bbl 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.
A producer collar is used for the sale of our produced oil and is the combination of buying a put option and
selling a call option. We would receive settlement payments for prices below the indicated weighted-average price
per bbl of the put option and we would make settlement payments for prices above the indicated weighted-average
price of the call option. No payment would be made or received for prices in between the indicated weighted-
average price of the put and call.
A consumer collar is used for the purchase of fuel gas and is the combination of buying a call option and
selling a put option. We would receive settlement payments for prices above the indicated weighted-average price of
the call option and we would make settlement payments for prices below the indicated weighted-average price of the
put option. No payment would be made or received for prices in between the indicated weighted-average price of the
put and call.
For natural gas basis swaps, we make settlement payments if the difference between NWPL and Henry Hub is
below the indicated weighted-average price of our contracts and receive settlement payments if the difference
between NWPL and Henry Hub is above the indicated weighted-average price.
For some 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, 2022 we have net payable
deferred premiums of approximately $5 million, which is reflected in the mark-to-market valuation and will be
payable through December 31, 2024.
129
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2022, we had the following crude oil production and gas purchases hedges.
Q1 2023
Q2 2023
Q3 2023
Q4 2023
FY 2024
FY 2025
Brent - Crude Oil Production
Swaps
Hedged volume (bbls)
1,385,278
1,387,750
1,211,717
1,196,000
3,392,048
Weighted-average price ($/bbl)
$
77.15 $
77.01 $
76.26 $
76.18 $
76.12 $
Put Spreads
Long $50/$40 Put Spread hedged
volume (bbls)
Short $50/$40 Put Spread hedged
volume (bbls)
Producer Collars
630,000
637,000
644,000
644,000
1,647,000
90,000
91,000
92,000
92,000
366,000
—
—
—
—
Hedged volume (bbls)
360,000
364,000
368,000
368,000
1,098,000
2,212,500
Weighted-average price ($/bbl)
Henry Hub - Natural Gas Purchases
Consumer Collars
Hedged volume (mmbtu)
Weighted-average price ($/mmbtu)
NWPL - Natural Gas Purchases
$40.00/
$106.00
$40.00/
$106.00
$40.00/
$106.00
$40.00/
$106.00
$40.00/
$105.00
$58.35/
$91.45
2,110,000
$4.00/
$2.75
1,820,000
$4.00/
$2.75
—
—
—
$
— $
— $
— $
—
—
Hedged volume (mmbtu)
1,800,000
3,640,000
3,680,000
3,680,000
7,320,000
6,080,000
Weighted-average price ($/mmbtu)
$
6.40 $
5.34 $
5.34 $
5.34 $
4.27 $
4.27
Gas Basis Differentials
NWPL/HH - basis swaps
Hedged volume (mmbtu)
1,800,000
1,820,000
1,840,000
1,840,000
—
Weighted-average price ($/mmbtu)
$
1.12 $
1.12 $
1.12 $
1.12 $
— $
—
—
In addition to the table above, in January 2023, we terminated the following basis swaps (NWPL/HH):
4,900,000 mmbtu (20,000 mmbtu/d) at $1.12 beginning March 2023 through October 2023, and 610,000 mmbtu
(10,000 mmbtu/d) at $1.12 beginning November 2023 through December 2023.
In January 2023 we also added the following Producer Collars (Brent): 3,627 bbl (117 bbl/d) at $60.00/$88.50
for January 2025, 270,000 bbl (3,000 bbl/d) at $60.00/$88.35 for January 2025 through March of 2025, and 472,500
bbl (5,250 bbl/d) at $60.00/$82.21 for January 2026 through March of 2026, which are in addition to the table
above. These Producer Collars (Brent) were cashless.
130
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2022 and 2021. The following tables present the fair values (gross and net) of our outstanding derivatives as of
December 31, 2022 and 2021.
December 31, 2022
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
66,974 $
39,886
(30,607) $
(39,810)
Liabilities:
Commodity Contracts
Current liabilities
Commodity Contracts
Non-current liabilities
(61,713)
(53,452)
30,607
39,810
Total derivatives
$
(8,305) $
— $
36,367
76
(31,106)
(13,642)
(8,305)
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)
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.
131
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Losses) Gains on Derivatives
A summary of gains and losses on the derivatives included on the statements of operations is presented below:
Year Ended December 31,
2022
2021
(in thousands)
2020
(Losses) gains on oil and gas sales derivatives
Gains (losses) on natural gas purchase derivatives
Total (losses) gains on derivatives
$
$
(137,109) $
(156,399) $
88,795
38,577
(48,314) $
(117,822) $
117,781
(1,035)
116,746
For the years ended December 31, 2022 and 2021 we paid net cash settlements of approximately $88 million
and $92 million, respectively. For the year ended December 31, 2020, we received net cash scheduled settlements of
approximately $142 million.
Note 5—Commitments and Contingencies
In the normal course of business, we, or our subsidiaries, 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, 2022 and December 31, 2021. 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, 2022, we
are not aware of material indemnity claims pending or threatened against us.
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 November 1, 2021, the court-appointed 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
132
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 and on September 13, 2022, the Court issued an
order denying that motion. The case is now in discovery.
We dispute these claims and intend to defend the matter vigorously. Given the uncertainty of litigation, the early
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.
On October 20, 2022, a shareholder derivative lawsuit was filed in the United States District Court for the
Northern District of Texas by putative stockholder George Assad, allegedly on behalf of the Company, that piggy-
backs on the securities class action referenced above and which is currently pending before the same Court. The
derivative complaint names certain current and former officers and directors as defendants, and generally alleges
that they breached their fiduciary duties by causing or failing to prevent the securities violations alleged in the
securities class action. The derivative complaint also alleges claims for unjust enrichment as against all defendants,
and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act. On January 27,
2023, the court granted the parties’ joint stipulated request to stay the derivative action pending resolution of the
related securities class action. The Company and the individual defendants believe the claims in the shareholder
derivative action are without merit and intend to defend vigorously against them, but there can be no assurances as
to the outcome. At this time, we are unable to estimate the probability or the amount of liability, if any, related to
this matter.
On January 20, 2023, a second shareholder derivative lawsuit was filed, this time in the United States District
Court for the District of Delaware, by putative stockholder Molly Karp allegedly on behalf of the Company, again
piggy-backing on the securities class action referenced above. This complaint, similar to the first derivative
complaint, is brought against certain current and former officers and directors of the Company, asserting breach of
fiduciary duty, aiding and abetting, and contribution claims based on the defendants allegedly having caused or
failed to prevent the securities violations alleged in the securities class action. In addition, the complaint asserts a
claim under Section 14(a) of the Exchange Act, alleging that Berry’s 2022 Proxy Statement was false and
misleading in that it suggested the Company’s internal controls were sufficient and the board of directors was
adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the
case. The defendants believe the claims in the shareholder derivative action are without merit and intend to defend
vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate
the probability or the amount of liability, if any, related to this matter.
Other Commitments
In the ordinary course of our business, we enter 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. At December 31, 2022, future net minimum payments
for non-cancelable purchase obligations (excluding oil and natural gas and other mineral leases, utilities, taxes and
insurance expense) were as follows:
Processing and transportation
contracts(1)
Drilling commitment(2)
Total
__________
2023
2024
2025
2026
2027
Thereafter
Total
(in thousands)
$
11,343 $
9,553 $
8,234 $
8,082 $
8,083 $
43,521 $
88,816
8,400
8,700
—
—
—
—
17,100
$
19,743 $
18,253 $
8,234 $
8,082 $
8,083 $
43,521 $ 105,916
(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.
133
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(2) Amounts include 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 June 2024. In November 2022, the drilling commitment was revised to require 28 of those wells to be
drilled by October 2023, with a minimum commitment of $8.4 million.
Note 6—Stockholders' Equity
Cash Dividends
Our Board of Directors approved quarterly fixed cash dividends totaling $0.24 per share in 2022, as well as
variable cash dividends of $1.10 per share, which were based on the results in 2022, for a total of $1.34 per share. In
February 2023, our Board of Directors approved a fixed cash dividend of $0.06 per share, as well as, the variable
cash dividend of $0.44 per share based on the fourth quarter of 2022 results.
For the year ended December 31, 2022, December 31, 2021, December 31, 2020 we paid approximately
$109 million, $11 million and $19 million, respectively, in cash dividends on our common stock.
The Company anticipates that it will continue to pay quarterly cash dividend in the future. However, the
payment and amount of future dividends remain within the discretion of the Board and will depend upon the
Company’s future earnings, financial condition, capital requirements, and other factors.
Common Stock
On March 1, 2022, our Board of Directors approved the 2022 Omnibus Incentive Plan (the “2022 Omnibus
Plan”), which was subsequently approved by stockholders on May 25, 2022. The plan authorized the issuance of
2,300,000 shares of common stock. The maximum number of shares remaining that may be issued is 1,573,402 as of
December 31, 2022, which is the total number of shares of our common stock remaining available for issuance after
counting the number of securities to be issued upon vesting of outstanding RSU and PSU awards, and counting
PSUs at the maximum payout level. Shares reserved at maximum payout that do not vest at maximum are made
available for future grants.
On June 27, 2018, our board of directors adopted the second amended and restated 2017 Omnibus Incentive
Plan (“2017 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 Omnibus 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.
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.
134
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Registration Rights Agreement
On June 28, 2018, Berry Corp. entered into an amended and restated registration rights agreement (the
“Registration Rights Agreement”) with certain holders of our Common Stock and Preferred Stock in connection
with our IPO.
In accordance with the Registration Rights Agreement, Berry Corp. filed a shelf registration statement with the
SEC on December 10, 2018, which was declared effective on December 13, 2018. 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 and preferred stock issued by Berry Corp. in connection with the IPO to
stockholders party to the Registration Rights Agreement, and (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, 2022, there were 75,767,503 shares of common stock outstanding. Up to an additional
8,110,302 shares were issuable for unvested restricted stock units and performance restricted stock units (assuming
maximum achievement of performance goals) under the Company's 2022 Omnibus Incentive Plan as of December
31, 2022.
Repurchase Program
For the year ended December 31, 2022, we repurchased 5 million shares for approximately $51 million. As of
December 31, 2022, the Company had repurchased a total of 10,528,704 shares under the stock repurchase program
for approximately $104 million in aggregate. As previously disclosed, the Company implemented a shareholder
return model in early 2022, for which the Company intends to allocate a portion of Adjusted Free Cash Flow to
opportunistic share repurchases.
In April 2022, our Board of Directors approved an increase of $102 million to the Company’s stock repurchase
authorization bringing the Company’s remaining share repurchase authority to $150 million. As of December 31,
2022, the Company’s remaining total share repurchase authority is $98 million, after the repurchases made in the
second, third, and fourth quarters of 2022. In February 2023, the Board of Directors approved an increase of $102
million to the Company’s stock repurchase authorization bringing the Company’s remaining share authority to $200
million. The Board’s authorization permits the Company to make purchases of its common stock from time to time
in the open market and in privately negotiated transactions, subject to market conditions and other factors, up to the
aggregate amount authorized by the Board. The Board’s authorization has no expiration date.
We repurchased approximately $2 million of shares in 2021 and none in 2020.
Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other
means, as determined in the Company's sole discretion. The manner, timing and amount of any purchases will be
determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and
other factors, may be commenced or suspended at any time without notice and does not obligate the company to
purchase shares during any period or at all. Any shares repurchased are reflected as treasury stock and any shares
acquired will be available for general corporate purposes.
135
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 2022 and 2021, 0% to 200% of the TSR PSUs granted in 2020, 0% to
200% of the CROIC PSUs granted in 2022 and 2021, and 0% to 200% of the ROIC PSUs granted in 2022. No
CROIC PSUs were granted prior to 2021 and no ROIC PSUs were granted prior to 2022.
The fair value of the RSUs, CROIC PSUs and ROIC 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.
The PSUs awarded in February 2022 were accounted for as liability awards in the first quarter of 2022, but were
converted to equity awards during the second quarter of 2022 due to the approval of the 2022 Omnibus Plan by the
stockholders in May 2022.
For the years ended December 31, 2022, 2021, and 2020 the stock-based compensation expense was
approximately $18 million, $14 million, and $15 million, respectively. For the year ended December 31, 2022, the
income tax benefit was $2 million. For the years ended December 31 2021 and 2020 the stock-based compensation
income tax benefit was not material.
The table below summarizes the activity relating to RSUs issued under the Restated Incentive Plan during the
year ended December 31, 2022. The RSUs vest ratably over three years. Unrecognized compensation cost associated
with the RSUs at December 31, 2022 was approximately $10 million which will be recognized over a weighted-
average period of approximately two years.
Non-vested at December 31, 2021
Granted
Vested
Forfeited
Non-vested at December 31, 2022
Number of shares
Weighted-average
Grant Date Fair Value
(shares in thousands)
2,580 $
1,317 $
(1,145) $
(233) $
2,519 $
5.67
8.92
6.36
6.97
6.94
The table below summarizes the activity relating to the PSUs issued under the Revised Incentive Plan during the
year ended December 31, 2022. Unrecognized compensation cost associated with the PSUs at December 31, 2022 is
approximately $8 million which will be recognized over a weighted-average period of approximately two years.
136
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Non-vested at December 31, 2021
Granted
Vested
Forfeited
Non-vested at December 31, 2022
Note 7—Defined Contribution Plan
Number of shares
Weighted-average
Grant Date Fair Value
(shares in thousands)
2,085 $
611 $
(36) $
(59) $
2,601 $
11.00
12.03
12.75
12.51
11.18
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 when 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 $6.2 million, $1.6 million, and $1.0 million for the years ended December 31,
2022, 2021, and 2020, respectively, under the provisions of the 401(k) plan.
Note 8—Income Taxes
The change in our effective rate from (10.0)% in the year ended December 31, 2021 to (20.4)% for the year
ended December 31, 2022 is primarily due to recognition of U.S. federal general business credits in 2022 related to
the 2021 tax period and release of the valuation allowance. The credits are available to offset future federal income
tax liabilities. 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.
137
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Income tax expense (benefit) consisted of the following:
Year Ended December 31,
2022
2021
(in thousands)
2020
Current taxes:
Federal
State
Total current taxes
Deferred taxes:
Federal
State
Total deferred taxes
$
642 $
— $
1,597
2,239
(44,053)
(622)
(44,675)
581
581
832
—
832
Total current and deferred taxes
$
(42,436) $
1,413 $
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
—
828
828
2,653
(10,699)
(8,046)
(7,218)
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,
2022
2021
2020
21.0 %
6.2 %
1.8 %
(0.3) %
(11.5) %
— %
(0.3) %
(37.3) %
(20.4) %
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 %
138
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 asset (liability)
Year Ended December 31,
2022
2021
(in thousands)
$
22,402 $
10,728
48,994
2,280
88,908
2,882
176,194
—
176,194
(133,350)
(133,350)
$
42,844 $
40,846
11,731
44,437
12,776
61,044
3,551
174,385
(77,546)
96,839
(98,670)
(98,670)
(1,831)
As of December 31, 2022, the Company had approximately $107 million of federal net operating loss (“NOL”)
carryforwards and no state net operating loss carryforwards. The federal net operating loss carryovers have no
expiration date. In addition, as of December 31, 2022, the Company had US federal general business tax credit
carryforwards totaling $82 million and state tax credits of $8 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. As of December 31, 2022, due to the positive evidence of current
year income, fair value of proved reserves and related future income projections, commodity price forecasts based
on published market quotes, and the reversal of existing federal and state temporary differences, and based on the
preponderance of that evidence, we determined there is sufficient positive evidence to conclude that is is more likely
than not that our deferred tax assets are realizable. Therefore, we have fully released the valuation allowance in
2022, resulting in an income tax benefit of $78 million. We previously recorded a valuation allowance on our
deferred tax assets for the year ended December 31, 2021 in the amount of $78 million.
We had no material uncertain tax positions at December 31, 2022 or 2021. 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 2019 through 2022 federal and 2018 through 2022 state tax years
generally remain open to examination under the respective statute of limitations.
139
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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,
2022
2021
(in thousands)
$
12,330 $
26,840
8,976
7,266
4,036
1,117
9,533
6,415
2,933
225
Total other current assets
$
33,725 $
45,946
Other non-current assets at December 31, 2022 included approximately $6 million of operating lease right-of-
use assets, net of amortization and $4 million of deferred financing costs, net of amortization. At December 31, 2021
other non-current assets included approximately $5 million of deferred financing costs, net of amortization.
Accounts payable and accrued expenses on the consolidated balance sheets included the following:
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
Operating lease liability
Other
Year Ended December 31,
2022
2021
(in thousands)
$
40,286 $
85,360
38,264
—
6,640
10,885
—
20,000
1,666
—
17,699
62,962
24,816
7,513
8,273
10,736
4,800
20,000
—
725
Total accounts payable and accrued expenses
$
203,101 $
157,524
At December 31, 2022 other non-current liabilities included approximately $23 million non-current greenhouse
gas liability, which is due 2024, and $5 million of non-current operating lease liability. At December 31, 2021 we
had $18 million non-current greenhouse gas liability, which is due in 2024.
Supplemental Information on the Statement of Operations
For the years ended December 31, 2022, 2021, and 2020 other operating expenses were $4 million, $3 million,
and $6 million respectively. For the year ended December 31, 2022, other operating expenses mainly consisted of
approximately $2 million in royalty audit charges incurred prior to our emergence and restructuring in 2017, and
approximately $2 million loss on the divestiture of the Piceance properties. For the 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
140
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
offset by approximately $2 million on 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.
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 current
liability to long-term
Greenhouse gas liability - reclassification from long-term to
current liability
$
$
Supplemental Disclosures of Significant Non-Cash Investing
Activities:
Year Ended December 31,
2022
2021
(in thousands)
2020
8,000 $
— $
—
— $
— $
33,376
Material inventory transfers to oil and natural gas properties $
2,707 $
3,424 $
1,596
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized
Income taxes payments
$
$
29,792 $
3,633 $
29,211 $
699 $
29,962
222
Note 10—Acquisitions and Divestitures
2022
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 a loss of approximately $2 million. Our 2021 production from these
properties was 1.2 mboe/d.
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 0.6 mboe/d.
Purchases of Various Oil and Gas Properties
During 2022, we also acquired various oil and gas properties, most of which consisted of unproved properties
for approximately $8 million in aggregate.
2021
C&J Well Services Acquisition
On October 1, 2021, we acquired one of the largest well servicing and abandonment businesses in California,
which operates as CJWS. The purchase price was $53 million, including closing adjustments mainly related to
141
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 unaudited pro forma information presented below has been prepared to give effect to the CJWS 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 CJWS 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 E&P segment completed the sale of our Placerita Field property in the Ventura Basin in
Los Angeles County, California for approximately $14 million. We recorded a gain on the sale of approximately
$2 million in 2021.
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.
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.
142
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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. For the year ended
December 31, 2022, 4,069,000 incremental RSU and PSU shares were included in the diluted EPS calculation. For
the years ended December 2021 and 2020, no incremental RSU or PSU shares were included in the diluted EPS
calculation as their effect was anti-dilutive under the “if-converted” method.
Basic EPS calculation
Net income (loss)
Weighted-average shares of common stock outstanding
Basic income (loss) per share
Diluted EPS calculation
Net income (loss)
Weighted-average shares of common stock outstanding
Dilutive effect of potentially dilutive securities(1)
Weighted-average common shares outstanding - diluted
Diluted income (loss) per share
__________
Year Ended December 31,
2022
2021
2020
(in thousands except per share amounts)
$
$
$
$
250,168 $
(15,542) $
(262,895)
78,517
80,209
3.19 $
(0.19) $
79,802
(3.29)
250,168 $
(15,542) $
(262,895)
78,517
4,069
82,586
80,209
—
80,209
3.03 $
(0.19) $
79,802
—
79,802
(3.29)
(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 (“ASC”) 606, Revenue from
Contracts with Customers, using the modified retrospective method.
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.
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.
143
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 or estimated). Our contracts with customers typically require
payment within 30 days following invoicing.
Service Revenue
We recognize service revenue from the 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 portion sold from 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. In January 2022, we sold our Piceance Colorado operations, which
included third-party marketing activities. Historically, these activities accounted for nearly all of our marketing
revenues.
144
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
Year Ended December 31,
2022
2021
(in thousands)
2020
$
806,631 $
587,613 $
362,976
29,515
6,303
181,400
30,833
289
479
32,679
5,183
35,840
35,636
3,921
477
14,041
1,646
—
25,813
1,426
150
406,052
117,781
523,833
Revenues from contracts with customers
(Losses) gains on oil and gas sales derivatives
1,055,450
(137,109)
701,349
(156,399)
Total revenues and other
$
918,341 $
544,950 $
Note 13—Segment Information
As of October 1, 2021, we have operated in two business segments: (i) E&P and (ii) well servicing and
abandonment. The E&P 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 well servicing and abandonment segment occasionally provides services to our E&P segment, as such, we
recorded an intercompany elimination of $3 million in revenue and expense during consolidation. The intercompany
elimination in 2021 was immaterial.
145
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
Year Ended December 31, 2022
E&P
Well Servicing and
Abandonment
Corporate/
Eliminations
Consolidated
Company
874,190 $
303,178 $
411,811 $
141,930 $
1,563,251 $
(in thousands)
184,448 $
(3,188) $
1,055,450
14,747 $
26,113 $
8,455 $
83,461 $
(110,193) $
(57,976) $
2,536 $
207,732
379,948
152,921
(15,682) $
1,631,030
Year Ended December 31, 2021
E&P
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
$
$
$
$
$
$
$
$
$
$
Revenues(1)
Net income (loss) before income taxes
Adjusted EBITDA
Capital expenditures
Total assets
Revenues(1)
Net income (loss) before income taxes
Adjusted EBITDA
Capital expenditures
Total assets
__________
(1) These revenues do not include hedge settlements.
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.
146
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Year Ended December 31, 2022
Well Servicing and
Abandonment
Corporate/
Eliminations
Consolidated
Company
(in thousands)
Adjusted EBITDA reconciliation to net
income (loss):
Net income (loss)
Add (Subtract):
Interest expense
Income tax benefit
Depreciation, depletion, and
amortization
Losses on derivatives
Net cash paid for scheduled derivative
settlements
Other operating expenses (income)
Stock compensation expense
Non-recurring costs(1)
$
303,178 $
14,747 $
(67,757) $
250,168
—
—
139,886
48,314
(88,023)
3,827
1,361
3,268
23
—
12,548
—
—
(1,690)
287
198
30,894
(42,436)
4,413
—
—
1,585
15,325
—
30,917
(42,436)
156,847
48,314
(88,023)
3,722
16,973
3,466
Adjusted EBITDA
$
411,811 $
26,113 $
(57,976) $
379,948
__________
(1) Non-recurring costs include legal and professional service expenses related to acquisition and divestiture activity for the first quarter of
2022 and the executive transition costs in the fourth quarter of 2022.
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(1)
Year Ended December 31, 2021
E&P
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
Adjusted EBITDA
$
251,146 $
4,310 $
(43,310) $
212,146
__________
(1) Non-recurring costs include legal and professional service expenses related to acquisition and divestiture activity for the fourth quarter of
2021.
147
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 14—Leases
In the first quarter of 2022, we adopted ASC 842, Leases using the modified retrospective approach that
requires us to determine our lease balances as of the date of adoption. Prior periods continue to be reported under
accounting standards in effect for those periods.
The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease,
the present value of the related lease payments is recorded as a liability and an equal amount is capitalized as a right
of use asset on the Company’s balance sheet. Right of use assets represent the Company’s right to use an underlying
asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from
the lease. We have long-term operating leases generally for offices. The Company’s estimated incremental
borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate,
is used to calculate present value.
Leases with an initial term of 12 months or less are not recorded on the balance sheet and the Company
recognizes lease expense for these leases on a straight-line basis over the lease term.
The components of lease expense are as follows:
Lease Cost
Operating lease cost
Total net lease cost
Year Ended December 31, 2022
(in thousands)
$
$
1,992
1,992
The following table presents the consolidated balance sheet information related to leases as of December 31,
2022.
Leases
Assets
As of December 31, 2022
Balance Sheet Classification
(in thousands)
Operating lease assets
Total assets
Liabilities
Operating lease liability
Operating lease noncurrent liability
Total liabilities
$
$
$
$
Other noncurrent assets
Accounts payable and accrued
expenses
Other noncurrent liabilities
6,325
6,325
1,666
5,213
6,879
148
BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Long-Term and Discount Rate
Weighted-average remaining lease term:
Operating Lease
Weighted-average discount rate:
Operating Lease
As of December 31, 2022
4.3 years
5 %
The following table presents a schedule of future minimum lease payments required under all operating lease
agreements as of December 31, 2022.
2023
2024
2025
2026
2027
Total lease payments
Less imputed interest
Total lease obligations
Less current obligations
Long-term lease obligations
As of December 31, 2022
Operating Leases
(in thousands)
1,963
1,650
1,542
1,549
935
7,639
(760)
6,879
(1,666)
5,213
$
$
Supplemental consolidated statement of cash flow information related to leases is as follows:
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases
ROU assets obtained in exchange for operating lease liabilities
Year Ended December 31, 2022
(in thousands)
$
$
2,128
7,956
149
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
__________
2022
Year Ended December 31,
2021
(in thousands)
2020
$
$
28,144 $
1,256 $
11,597
—
—
—
—
148,465
153,821
176,609 $
155,077 $
—
—
96,971
108,568
(1)
Included in proved property acquisition costs for the year ended December 31, 2022, 2021 and 2020 are non-cash additions related to the
estimated future asset retirement obligations of the Company's oil and gas properties of $2.2 million, $0.4 million and $5.7 million,
respectively.
(2)
Included in development costs for the year ended December 31, 2022, 2021 and 2020 are non-cash additions related to the estimated future
asset retirement obligations of the Company's oil and gas properties of $22.3 million, $32.5 million and $10.2 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,
2022
2021
(in thousands)
$
1,545,056 $
1,308,378
248,073
1,793,129
(500,578)
291,514
1,599,892
(356,509)
Net capitalized costs
$
1,292,551 $
1,243,383
150
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,
2022
2021
(in thousands)
2020
$
842,449 $
625,475 $
378,663
30,833
601
873,883
302,321
21,839
4,564
962
39,145
299
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
Total operating costs for production
369,130
317,520
248,027
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
__________
141,022
—
734
141,756
362,997
74,295
137,991
—
2,353
140,344
207,492
57,117
$
288,702 $
150,375 $
135,361
289,085
5,673
430,119
(272,239)
(83,467)
(188,772)
(1) Excludes cash paid for derivative settlements of $88 million and $92 million for the years ended December 31, 2022 and December 31,
2021, respectively, and cash received of $142 million for the year ended December 31, 2020.
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, and after deductions and tax
credits and allowances relating to oil and gas activities that are reflected in our consolidated income tax for the
period. See Note 8 for additional information about income taxes.
151
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, 2022, 2021 and 2020 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, 2022
Natural Gas
mmcf
NGLs
mbbls
Total
mboe
85,801
22,787
(6,474)
5,300
(61)
(8,776)
98,577
53,452
53,632
32,349
44,945
1,259
546
359
—
—
(144)
2,020
1,209
1,413
50
607
62,454
13,102
1,481
10,706
(24,861)
(3,724)
59,158
60,351
44,601
2,103
14,557
97,469
25,517
(5,868)
7,084
(4,205)
(9,541)
110,456
64,720
62,478
32,749
47,978
Oil
mbbls
Year Ended December 31, 2021
Natural Gas
mmcf
NGLs
mbbls
Total
mboe
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
89,935
2,937
1,734
48
(24)
(8,829)
85,801
51,249
53,452
38,686
32,349
152
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, 2020
Natural Gas
mmcf
NGLs
mbbls
Total
mboe
129,773
733
(31,494)
104
—
(9,181)
89,935
74,102
51,249
55,670
38,686
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
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 13 mmboe to approximately 110 mmboe for the year ended
December 31, 2022. The year ended December 31, 2022, includes 6 mmboe of negative overall revisions of
previous estimates. In 2022, we experienced negative revisions of 7 mmboe in California, which was partially offset
by positive revisions of 1 mmboe in the Rockies. The negative other revisions resulted primarily from a change in
development plans in our thermal Diatomite in our North Midway-Sunset field. Positive price-driven revisions were
2 mmboe, due to the increase in commodity prices. Extensions and discoveries added 26 mmboe to proved reserves.
In January of 2022, we divested our Piceance basin properties and removed approximately 4 mmboe of proved
reserves in Colorado. In February of 2022, we acquired Antelope Creek and we added 7 mmboe of proved reserves
in Utah.
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.
153
BERRY CORPORATION (bry)
SUPPLEMENTAL OIL & NATURAL GAS DATA (Continued)
(Unaudited)
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,
2022
2021
2020
(in thousands, except for prices)
$
9,501,374 $
5,879,599 $
3,657,907
(2,589,043)
(2,091,021)
(3,909,452)
(1,068,890)
(1,000,268)
3,522,764
(1,448,999)
(808,295)
(484,358)
1,997,903
(764,632)
2,073,765 $
1,233,271 $
(830,028)
(1,646)
735,212
(219,033)
516,179
100.25 $
6.40 $
69.47 $
3.64 $
41.77
2.03
(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.
154
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:
Year Ended December 31,
2022
2021
2020
(in thousands)
Standardized measure—beginning of year
$
1,233,271 $
516,179 $
1,466,137
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
830,294
42,747
1,140,342
(1,135,565)
8,215
198,009
the period
(496,069)
(336,031)
(149,806)
Net change due to extensions, discoveries and improved recovery
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
476,114
139,637
(14,684)
(182,173)
30,358
151,334
132,917
(269,981)
840,494
56,504
830
(5)
217,921
48,488
52,015
(195,093)
(276,094)
717,092
11,621
1,668
—
(329,680)
2,762
180,673
(69,293)
339,653
(949,958)
$
2,073,765 $
1,233,271 $
516,179
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,
2022
2021
2020
91.98 $
7.96 $
43.85 $
66.57 $
5.27 $
36.64 $
39.56
2.08
12.57
31.72 $
23.60 $
17.86
$
$
$
$
155
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 Chief Executive Officer and our Vice
President, Chief Financial Officer and Chief Accounting 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, 2022. 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, 2022 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, 2022, using the criteria in Internal Control-Integrated Framework (2013) issued by the COSO. Based
on this evaluation, our management concluded that our internal control over financial reporting was effective as of
December 31, 2022.
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. There have been no changes in
the Company’s internal control over financial reporting during the quarter ended December 31, 2022 that materially
affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.
156
Item 9B. Other Information
In November 2022, we announced a transformative leadership succession in connection with a new strategy and
sharpened focus on shareholder maximization. The succession plan, which was effective as of January 1, 2023,
included a transition in the roles of President and Chief Executive Officer, Chief Financial Officer, and Chief
Operating Officer. Former Board Chair, Chief Executive Officer and President, Arthur “Trem” Smith, stepped down
from his roles as President and Chief Executive Officer of Berry Corp. and transitioned to the position of Executive
Chair. In conjunction with Mr. Smith’s transition to Executive Chair, the Board appointed our then-Executive Vice
President and Chief Operating Officer, Fernando Araujo, as Chief Executive Officer, effective January 1, 2023. The
position of Chief Operating Officer was eliminated.
Simultaneously with Mr. Smith’s transition from President, our then-Executive Vice President, General Counsel
and Corporate Secretary, Danielle Hunter, was promoted, effective January 1, 2023, to President with oversight of
the financial (including internal audit and IT), legal, human resources (HR) and health, safety, and environmental
(HSE) functions.
Additionally, Mr. Cary Baetz, our then-Executive Vice President and Chief Financial Officer and member of the
Board, stepped down from his role of Executive Vice President, Chief Financial Officer and Mike Helm, our then-
Chief Accounting Officer, was promoted to Vice President, Chief Financial Officer, each effective January 1, 2023.
Mr. Helm also continues to serve as Chief Accounting Officer. Since January 1, 2023, Mr. Baetz has served as a
strategic advisor to Mr. Helm during a transition period. On February 21, 2023, the Board determined it was
appropriate to terminate Mr. Baetz’s employment effective March 3, 2023; simultaneous with his termination, he
will resign from the Board of Directors. His resignation from the Board of Directors is not due to any disagreement
with us. Mr. Baetz will receive the severance and equity award vesting to which he is entitled in the event of a
termination by the Company for reasons other than cause under his employment agreement and the restricted stock
units and performance share awards he has entered into with Berry Corp, noting that Mr. Baetz and Berry Corp have
mutually agreed for the equity awards which vest due to this termination, at least a portion will be settled in the form
of cash instead of shares of common stock.
157
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 2023 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2022.
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 within four business days following the date of the
amendment or waiver 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 2023 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2022.
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 2023 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2022. 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 2023 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2022.
Item 14. Principal Accounting Fees and Services
Our independent registered public accounting firm is KPMG LLP, Dallas, TX, Auditor Firm ID: 185.
The information required by this Item 14 is incorporated herein by reference to our definitive Proxy Statement,
for the 2023 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2022.
158
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 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)
10.2 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))
10.3† Executive Chair Agreement by and between Berry Petroleum Company, LLC and Arthur “Trem”
Smith, effective January 1, 2023. (incorporated by reference to Exhibit 10.1 of Form 8-K filed
November 30, 2022).
10.4† 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)
10.5† Second Amended and Restated Executive Employment Agreement by and between Berry Petroleum
Company, LLC and Danielle Hunter, effective January 1, 2023. (incorporated by reference to Exhibit
10.3 of Form 8-K filed November 30, 2022)
10.6† Amended and Restated Employment Agreement by and between Berry Petroleum Company, LLC
and Fernando Araujo, effective January 1, 2023. (incorporated by reference to Exhibit 10.2 of Form
8-K filed November 30, 2022)
159
Exhibit
Number
Description
10.7† Amended and Restated Employment Agreement by and between Berry Petroleum Company, LLC
and Mike Helm, effective January 1, 2023. (incorporated by reference to Exhibit 10.4 of Form 8-K
filed November 30, 2022)
10.8† 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))
10.9† 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))
10.10† 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))
10.11† 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))
10.12† 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)
10.13† 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)
10.14† 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))
10.15† 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))
10.16† 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)
10.17† 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)
10.18† 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)
10.19† 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)
10.20† 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)
10.21† Berry Corporation (bry) 2022 Omnibus Incentive Plan, dated March 1, 2022 (incorporated by
reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed May 4, 2022)
160
Exhibit
Number
Description
10.22† Berry Corporation (bry) 2022 Omnibus Incentive Plan - Form of Performance-Based Restricted Stock
Unit Award Agreement with Total Shareholder Return Performance Criteria (incorporated by
reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed May 4, 2022)
10.23† Berry Corporation (bry) 2022 Omnibus Incentive Plan - Form of Performance-Based Restricted Stock
Unit Award Agreement with CROIC Performance Criteria (incorporated by reference to Exhibit 10.3
to the Company’s Quarterly Report on Form 10-Q filed May 4, 2022)
10.24† Berry Corporation (bry) 2022 Omnibus Incentive Plan - Form of Performance-Based Restricted Stock
Unit Award Agreement with C&J Well Services ROCI Performance Criteria (Executive Employment
Agreement) (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form
10-Q filed May 4, 2022)
10.25† Berry Corporation (bry) 2022 Omnibus Incentive Plan - Form of Performance-Based Restricted Stock
Unit Award Agreement with C&J Well Services ROCI Performance Criteria (incorporated by
reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q filed May 4, 2022)
10.26†* Berry Corporation (bry) 2022 Omnibus Incentive Plan - Form of Restricted Stock Unit Award
Agreement for Executives
10.27†* Berry Corporation (bry) 2022 Omnibus Incentive Plan - Form of Performance-Based Restricted Stock
Unit Award Agreement with Absolute Total Shareholder Return Performance Criteria
10.28 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))
10.29 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)
10.30 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)
10.31 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)
10.32 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)
10.33 Second Amendment to Credit Agreement, dated May 2, 2022, by and among Berry Petroleum
Company, LLC, as borrower, Berry Corporation (bry), as guarantor, JP Morgan Chase Bank, N.A., as
administrative agent and the lenders parties thereto (incorporated by reference to Exhibit 10.6 of the
Quarterly Report on Form 10-Q filed May 4, 2022)
10.34 Third Amendment to Credit Agreement dated May 27, 2022, by and among Berry Corporation (bry),
as a guarantor, together with Berry Petroleum Company, LLC, as Borrower, JPMorgan Chase Bank,
N.A., as administrative agent and as an issuing bank, and the lenders from time-to-time party thereto
(incorporated by reference to Exhibit 10.1 of Form 8-K filed June 1, 2022)
10.35* Revolving Loan and Security Agreement, dated August 9, 2022 between C&J Well Services, LLC
and CJ Berry Well Services Management, LLC, as borrower, and Tri Counties Bank, as lender, and
related Promissory Note, dated August 9, 2022
21.1* List of Subsidiaries of Berry Corporation (bry)
161
Exhibit
Number
Description
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, 2022 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.
Item 16. Form 10-K Summary
Not applicable.
162
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 Free Cash Flow” which is defined as cash flow from operations less regular fixed dividends and
maintenance capital.
“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.
“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.
“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.
163
“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.
“HSE” is an abbreviation for Health, Safety, and Environmental.
“EPA” is an abbreviation for the United States Environmental Protection Agency.
“EPS” is an abbreviation for earnings per share.
“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.
“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.
“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.
“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.
164
“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.
“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.
“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.
“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.
“MW” means megawatt.
“MWHs” means megawatt hours.
“NASDAQ” means Nasdaq Global Select Market.
165
“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.
“OTC” means over-the-counter
“PALs” is an abbreviation for project approval letters.
“PCAOB” is an abbreviation for the Public Company Accounting Oversight Board.
“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.
“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.
166
“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
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
“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.
“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.
167
“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.
“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.
“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.
168
“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.
“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.
169
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:
February 27, 2023
Berry Corporation (bry)
/s/ Fernando Araujo
Fernando Araujo
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
Chief Executive Officer
(Principal Executive Officer)
Vice President, Chief Financial Officer and
Chief Accounting Officer
(Principal Financial Officer and
Principal Accounting Officer)
Executive Chairman
Director
Director
Director
Director
Director
February 27, 2023
February 27, 2023
February 27, 2023
February 27, 2023
February 27, 2023
February 27, 2023
February 27, 2023
February 27, 2023
/s/ Fernando Araujo
Fernando Araujo
/s/ M. S. Helm
Michael S. Helm
/s/ A. T. Smith
A. T. “Trem” Smith
/s/ Cary Baetz
Cary Baetz
/s/ Renée Hornbaker
Renée Hornbaker
/s/ Anne L. Mariucci
Anne L. Mariucci
/s/ Donald L. Paul
Donald L. Paul
/s/ Rajath Shourie
Rajath Shourie
170
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EXECUTIVE OFFICERS
DIRECTORS
FERNANDO ARAUJO
Chief Executive Officer
DANIELLE HUNTER
President
MIKE HELM
Vice President, Chief Financial Officer &
Chief Accounting Officer
A.T. (TREM) SMITH
Executive Chairman
RENÉE HORNBAKER (1C) (2) (3)
Independent Director
Chief Executive Officer of Storey & Gates LLC
RAJATH SHOURIE (1) (2)
Independent Director
Retired
ANNE MARIUCCI (1) (2C) (3)
Lead Independent Director
General Partner of MFLP
A.T. (TREM) SMITH
Executive Chairman
DONALD PAUL (1) (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
(C) Committee Chair
(1) Audit Committee
(2) Compensation Committee
(3) Nominating & Corporate Governance Committee
INVESTOR RELATIONS
ANNUAL REPORT ON FORM 10-K FOR 2022
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.
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
Page 10 of this annual report 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 - 2023
Quarterly fixed dividends on common stock are paid, following declaration by
the Board of Directors, on approximately the 25th day of March, May, August
and November. 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
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.
13
INVESTO R REL ATIONS
Berry Corporation (bry) 16000 N. Dallas Pkwy, Ste 500 Dallas, Texas 75248 (661) 616 - 3811 ir@bry.com
www.bry.com