Berry Annual Report 2019

FY2019 Annual Report · Berry
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FINDING WAYS TO PRODUCE ENERGY MORE EFFICIENTLY AND SAFELY

2019   
ANNUAL REPORT

$85m+

Capital returned to 
shareholders in dividends
and share buybacks  

15%

California
production growth
year over year

~300%

Replaced nearly 300%
of the California 
reserves produced

Our ﬂexible business model, which is focused 
on growing shareholder value, was validated 
by the top-tier industry returns, solid
production growth, and excess Levered Free
Cash Flow1 that we generated during the 
year. We paid our shareholders $39 million in 
dividends during 2019 and repurchased 6%
of Berry stock. We also maintained a strong 
ﬁnancial position with debt-to-EBITDA at 
about 1.4x, and we secured the ﬂexibility to
opportunistically repurchase our bonds.

We remained committed to California,
deploying 90% of our capital to the state in
2019. These assets responded well, with annual 
production growing 15% from 2018. We
also replaced nearly 300% of the California
reserves that we produced during the year
and replaced 159% of our total company 
proved undeveloped inventory, conﬁrming
we have robust development opportunities
on our existing California acreage. Since we
understand our long-term costs, decline
curves and the reinvestment capital required
to sustain ﬂat production, the risk is relatively
latively
low and the returns relatively high.

As part of our dedication to California, wwe
have and will continue to proactively engage
in legislative and regulatory issues. Wee intend
to be part of the energy solution in Califfornia 
as we believe that locally producing andd 
supplying affordable and reliable enerrgy
is critical to ensuring a safe and healthyy future 
for our communities. We are actively taking
measures to grow our business with great 
respect for the environment and are loook-
ing for opportunities to reduce our carrbon 
footprint while keeping our communities 
safe. As a responsive and responsible

1 Please see “Management’s Discussion and Analysis-
Non-GAAP Financial Measures” in the Form 10-K 
included in this Annual Report for the deﬁnition and 
reconciliation of Levered Free Cash Flow to the most
directly comparable ﬁnancial measure calculated 
and presented in accordance with GAAP.

energy partner, we increased our plugging 
and abandonment spending and activities
to go above and beyond the California state
requirements for idle well management. 
We also strengthened our environmental, 
social and governance (ESG) initiatives,
formalizing the strategies around which
we monitor ESG performance and engage 
with and report to our stakeholders. 
Our board of directors is actively engaged 
in this initiative, and our entire leadership
team remains committed to ensuring our 
continued progress in this area. 

2019 also marked our ﬁrst full year as a
public company. The transition to being 
a public company is just one hallmark of 
what we see as the company entering a 
new phase. As you will see incorporated
throughout this report, we recently 
rolled out a new logo and shortened name 
– Berry Corporation (bry) – to reﬂect our 
progressive business plans for the future. 
We also launched a new website, which
will feature more robust and ongoing
ESG-oriented disclosures. Furthermore, 
we enhanced our leadership across the
company with ﬁrst-class talent, and as part
of that, we demonstrated our commitment
to diversity and inclusion with the addition 
of two exceptional female executives to our 
senior leadership team.

Looking forward, we are well-positioned
for a successful 2020. The Company now
has 24,000 oil barrels, or approximately
80% of its B
at $59.85 B
Our busine
to the shor
long-term 
cycles. We
to return va
delivering
growth wit
and genera
Free Cash 

Brent-based production, hedged 
Brent through December 2020. 
ess model does not manage 
rt term, but focuses on creating 
value throughout energy market 
will stay the course, continuing 
alue to shareholders, while
year-over-year production 
th moderated capital spending 
ating attractive excess Levered
Flow.

A.T. (TREM) SMITH
Board Chair, Chief Executive
Ofﬁcer & President,
Berry Corporation (bry)

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, 2019 

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.   

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 

  Yes 

No 

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 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 

Accelerated filer 

Non-accelerated filer 

Smaller reporting company 

         Emerging Growth 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 is a shell company (as defined in Rule 12b-2 of the Act).  

  Yes 

    No 

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the 
common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $575.4 million.

Shares of common stock outstanding as of January 31, 2020 

  79,546,417

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DOCUMENTS INCORPORATED BY REFERENCE

The Company’s definitive proxy statement relating to the annual meeting of shareholders (to be held May 5, 2020) will be filed with the 
Securities and Exchange Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2019 and is 
incorporated by reference in Part III to the extent described herein.

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(cid:76)(cid:76)(cid:3)

Items 1 and 2. Business and Properties

Part I

Effective  February  18,  2020,  Berry  Petroleum  Corporation  changed  its  name  to  Berry  Corporation  (bry)  and 
introduced a new logo. We believe that the name Berry Corporation (bry) is a name that better represents  our progressive 
approach to evolving and growing the business in today’s dynamic oil and gas industry. 

When we use the terms “we,” “us,” “our,” the “Company,” or similar words in this report, unless the context 
otherwise requires, (i) on or after the Effective Date (as defined below in “Item 7. Management's Discussion and 
Analysis  of  Financial  Condition  and  Results  of  Operations—Liquidity  and  Capital  Resources—Commitments,  and 
Contingencies”),  we  are  referring  to  Berry  Corporation  (bry),  a  Delaware  corporation  formerly  known  as  Berry 
Petroleum Corporation ("Berry Corp."), together with its subsidiary Berry Petroleum LLC, a Delaware  limited liability 
company ("Berry LLC"), the successor company and(ii) prior to the Effective Date, we are referring to Berry LLC, as 
the predecessor company. 

Our Company

We are a western United States independent upstream energy company with a focus on onshore, low geologic risk, 

long-lived, oil reserves in conventional reservoirs. 

In the aggregate, the Company’s assets are characterized by high oil content. Most of our assets are located in the 
oil-rich reservoirs in the San Joaquin basin of California, which has more than 150 years of production history and 
substantial remaining oil in place. As a result of the substantial data produced over the basin’s long history, its reservoir 
characteristics are well understood, leading to predictable, repeatable, low geological risk and low-cost development 
opportunities. In California, we focus on conventional, shallow oil reservoirs, the drilling and completion of which are 
relatively low-cost in contrast to unconventional resource plays. For example, we estimate the cost to drill and complete 
our PUD wells in California will be less than $375,000 per well. In contrast, we estimate the cost to drill and complete 
our PUD wells in our Rockies (Utah and Colorado) operations will average $1.5 million per well.

We also have assets in the Uinta basin in Utah and in the Piceance basin in Colorado. 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. The Piceance basin in Colorado, which is a prolific low 
geologic risk natural gas play with trillions of cubic feet of natural gas in place where we produce from a conventional, 
tight sandstone reservoir using proven slick water stimulation techniques to increase recoveries.

As of December 31, 2019, we had estimated total proved reserves of 138 MMBoe, of which 122 MMBoe was 
in California. For the year ended December 31, 2019, we had average production of approximately 29.0 MBoe/d, of 
which  approximately  87%  was  oil.  For  the  three  months  ended  December 31,  2019,  we  had  average 
production  of  approximately  31.3  MBoe/d,  of  which  approximately  89%  was  oil.  In  California,  our  average 
production for the year ended  and  the  three  months  ended  December 31,  2019  was  22.6  MBoe/d  and  25.5  MBoe/
d, respectively, of which 100% was oil.

We  are  committed  to  creating  long-term  stockholder  value.    We  believe  that  the  successful  execution  of  our 
strategy across our extensive inventory of identified drilling opportunities with attractive full-cycle economics and 
stable, oil-weighed production base with low and predictable production decline rates will support our objectives to 
return capital to our stockholders, produce capital efficient growth, generate Levered Free Cash Flow to fund our 
operations while maintaining a low leverage profile through commodity price cycles. “Levered Free Cash Flow” is a 
non-GAAP  financial  measure  defined  as  Adjusted  EBITDA  less  capital  expenditures,  interest  expense  and 
dividends. “Adjusted EBITDA” is also a non-GAAP financial measure defined as earnings before interest expense; 
income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for 
scheduled  derivative  settlements;  impairments;  stock  compensation  expense;  and  other  unusual,  out-of-period  and 
infrequent items, including restructuring costs and reorganization items. Please see “Management’s Discussion and 
Analysis-“Non-GAAP Financial Measures” for reconciliations of Levered Free Cash Flow and Adjusted EBITDA to 

1

net  cash  provided  by  operating  activities  and  of  Adjusted  EBITDA  to  net  income  (loss),  our  most  directly 
comparable financial measure calculated and presented in accordance with GAAP.

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 believe 
that the oil and gas industry will remain an important part of the energy landscape going forward and our goal is to 
grow our business safely and with great support for the environment, while supporting economic growth and social 
equity through our operations and engagement with our stakeholders

The Berry Advantage

Our strategy is focused on creating long-term stockholder value by returning capital to stockholders, producing 
capital-efficient growth and generating positive Levered Free Cash Flow while maintaining a low leverage profile 
through commodity price cycles. We generated positive Levered Free Cash Flow in 2019 when Brent oil prices ranged 
from $54.91 to $74.57, and averaged $64.16 for the year. Factoring in current interest, dividend and production levels, 
our Levered Free Cash Flow is expected to be break even at approximately $50 Brent.

We believe the following competitive strengths will allow us to successfully execute our business strategy:

•

•

Extensive  inventory  of  low  geological  risk  identified  drilling  opportunities  with  attractive  full-cycle
economics, high operational control and a stable development and production cost environment provides
capital flexibility. We expect our operations to continue to generate attractive rates of return and positive
Levered Free Cash Flow, which, if sustained, would allow us to continue returning capital to stockholders,
sustain current production levels and fund organic growth, among other things. For example, our PUD reserves
in California are projected to average single-well rates of return of approximately 50% based on the assumptions
used in preparing our SEC reserves report as of December 31, 2019. We operate approximately 95% of our
producing wells and expect to operate a similar percentage of our identified gross drilling locations. In addition,
a substantial majority of our acreage is currently held by production and fee interest, including 94% 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 our peers, who operate primarily in unconventional
plays, our assets generally do not necessitate inventory-constrained and highly specialized equipment, which
provides us relative insulation from service cost inflation pressures. Our high degree of operational control
and relatively stable cost environment provide us significant visibility and understanding of our expected cash
flows.

Stable, long-lived, oil-weighted conventional asset base with low and predictable production decline rates.
The majority of our interests are in properties that have produced oil for decades. As a result, the geology and
reservoir characteristics are well understood, and new development well results are generally predictable,
repeatable and present lower risk than unconventional resource plays. The properties 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. The nature of our assets provides
us with significant capital flexibility and an ability to hedge efficiently material quantities of future expected
production. For example, our PDP reserves have an estimated annual decline rate of approximately 13% to
20% in the years between 2020 and 2025 based on total PDP Boe reserves as of December 31, 2019. Based
on the assumptions underlying our PUD estimates, we estimate that we will require slightly more than $11
per Boe in annual capital expenditures to keep production volumes consistent each year over the next three
years.

•

Brent-influenced crude oil pricing advantage. California oil prices are Brent-influenced as California refiners
import approximately 73% of the state’s demand from outside the state, most of which comes from OPEC

2

and other waterborne sources. There is a closer correlation of prices in California to Brent pricing than to WTI. 
Without  the  higher  costs  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, will allow us to 
continue to realize strong cash margins in California. Our highly oil-weighted production combined with a 
Brent-influenced  California  pricing  dynamic  has  resulted,  and  is  expected  to  continue  to  result,  in  strong 
operating margins at current commodity prices.

•

•

Simple  capital  structure  and  conservative  balance  sheet  leverage  with  ample  liquidity  and  minimal(cid:3)
contractual obligations. Since our 2018 initial public offering ("IPO"), our capital structure has consisted of(cid:3)
common stock and 7.0% senior unsecured notes due February 2026 (the "2026 Notes"). As of December 31,(cid:3)
2019, we had $391 million of available liquidity, defined as cash on hand plus availability under our reserves-
based lending facility we entered into on July 31, 2017 (as amended, the “RBL Facility”). In addition, we have(cid:3)
minimal long-term service or fixed-volume delivery commitments. This liquidity and flexibility permit us to(cid:3)
capitalize on opportunities that may arise to grow and increase stockholder value.

Experienced, principled and disciplined management team. Our management team has significant experience(cid:3)
operating and managing oil and gas businesses across numerous domestic and international basins, as well as(cid:3)
reservoir and recovery types. We use our deep technical, operational and strategic management experience to(cid:3)
optimize the value of our assets and the Company. We are focused on the principles of growing Levered Free(cid:3)
Cash Flows as well as the value of our production and reserves. In doing so, we take a disciplined approach(cid:3)
to development and operating cost management, field development efficiencies and the application of proven(cid:3)
technologies and processes new 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:

•

•

Return capital to our stockholders. Our objective is to maintain a disciplined value creation and returns-
focused approach to capital allocation in order to generate excess free cash flow. We have returned capital to(cid:3)
our shareholders, primarily in the form of a quarterly dividend, since our first quarter as a public company(cid:3)
and we continue to target an attractive dividend yield. Additionally, our stock repurchase program approved(cid:3)
by our Board of Directors in December 2018 provides an additional opportunity to return value to our existing(cid:3)
shareholders. As  of  December  31,  2019,  we  repurchased  approximately  6%  of  our  outstanding  shares  for(cid:3)
approximately $50 million and in February 2020 the Board authorized us to repurchase an additional $50(cid:3)
million of stock. If commodity prices increase for a sustained period of time, we would consider repaying(cid:3)
debt obligations or returning additional capital to stockholders. For a discussion of our dividend policy, as(cid:3)
well as our stock repurchase program, please see “Item 5. Market for the Registrant’s Common Equity, Related(cid:3)
Stockholder Matters and Issuer Purchases of Equity Securities.”

Grow production and reserves in a capital efficient manner while producing positive internally generated(cid:3)
Levered Free Cash Flow. We intend to allocate capital in a disciplined manner to projects that will produce(cid:3)
predictable  and  attractive  rates  of  return.  We  plan  to  direct  capital  to  our  oil-rich  and  low-geologic  risk(cid:3)
development opportunities while focusing on leveraging capital efficiencies across our asset base with the(cid:3)
primary  objective  of  internally  funding  our  capital  budget  and  growth  plan. We  may  also  use  our  capital(cid:3)
flexibility to pursue value-enhancing, bolt-on acquisitions to opportunistically improve our positions in existing(cid:3)
basins.

• Maintain  balance  sheet  strength  and  flexibility  through  commodity  price  cycles. We  intend  to  fund  our(cid:3)
capital program while producing positive internally generated Levered Free Cash Flow. Over time, we expect(cid:3)
to maintain low leverage through organic growth and with excess Levered Free Cash Flow. Our objective is(cid:3)
to achieve and maintain a long-term, through-cycle leverage ratio (as defined in our RBL Facility) between(cid:3)
1.0x and 2.0x, or lower.

3

•

Proactively  and  collaboratively  engage  in  matters  related  to  regulation,  safety,  the  environmental  and(cid:3)
community  relations. We  seek  to  work  closely  with  regulators  and  legislators  throughout  the  rulemaking(cid:3)
process to minimize adverse impacts that new legislation and regulations might have on our ability to maximize(cid:3)
our resources and to mitigate adverse impacts to our permitting process. We have found constructive dialogue(cid:3)
with legislative and regulatory agencies can help avert compliance and permitting issues. We also believe that(cid:3)
running our operations in a manner that protects the safety and health of our employees and is in compliance(cid:3)
with existing laws and regulations is not only the right way to run our business, but it helps us build and(cid:3)
maintain  relationships  with  the  communities  in  which  we  operate  as  well  as  credibility  with  the  relevant(cid:3)
agencies governing our operations. With ultimate oversight by our Board of Directors, Environmental, Health(cid:3)
& Safety (“EH&S”) considerations are an integral part of our day-to-day operations and are incorporated into(cid:3)
the strategic decision-making process across our business.

• Maximize ultimate hydrocarbon recovery from our assets by optimizing drilling, completion and production(cid:3)
techniques and investigating deeper reservoirs and areas beyond our known productive areas. While we(cid:3)
continue  to  utilize  proven  techniques  and  technologies,  we  will  also  continuously  seek  efficiencies  in  our(cid:3)
drilling, completion and production techniques in order to optimize ultimate resource recoveries, rates of return(cid:3)
and cash flows. We will continue to advance and use innovative EOR and other recovery techniques to unlock(cid:3)
additional value and will allocate capital towards these next generation technologies where applicable.  In(cid:3)
addition, we intend to take advantage of underdevelopment in basins where we operate by expanding our(cid:3)
geologic investigation of reservoirs on our acreage and adjacent acreage below existing producing reservoirs.(cid:3)
Through these studies, we will seek to expand our development beyond our known productive areas in order(cid:3)
to add probable and possible reserves to our inventory at attractive all-in costs.

•

Enhance future cash flow stability and visibility through an active and continuous hedging program. Our(cid:3)
hedging  strategy  is  designed  to  insulate  our  capital  program  from  price  fluctuations  by  securing  price(cid:3)
realizations and cash flows for production. We also seek to protect our operating expenses through fixed-price(cid:3)
gas purchase agreements and other hedging contracts. We have protected a significant portion of our anticipated(cid:3)
crude oil production realizations and gas purchases through 2020 and have begun to hedge anticipated crude(cid:3)
oil production and gas purchases for 2021. We will review our hedging program continuously as conditions(cid:3)
change.

4

Our Capital Program

For the years ended December 31, 2019 and 2018 our capital expenditures were approximately $211 million and 
$148 million, respectively, on an accrual basis excluding acquisitions. Our 2020 anticipated capital expenditure budget 
is approximately $125 to $145 million, which we expect to generate significant year-over-year oil production growth 
in California, while holding overall production close to flat throughout the year. We reduced our 2020 capital program 
compared to 2019 in response to current oil market volatility and the industry's focus on returning capital to shareholders, 
which we have been doing since our IPO in July 2018. We have been and continue to be a market leader in returning 
capital to shareholders, while continuing to generate production growth. We currently anticipate oil production will be 
approximately 90% of total production in 2020, compared to 87% in 2019 and 82% in 2018. Based on current commodity 
prices and our drilling success rate to date, we expect to be able to fund our 2020 capital development programs with 
cash  flow  from  operations  and  produce  positive  Levered  Free  Cash  Flow,  which  includes  continuing  to  target  an 
attractive dividend yield.

The  table  below  sets  forth  the  current  expected  allocation  of  our  2020  capital  expenditure  budget  by  area  as 

compared to the allocation of our 2019 capital expenditures.

California

Utah

Colorado

Corporate

Total

2020 Budget

2019 Actual

(in millions)

113-130

$

4-5

1-2

7-8

125-145

$

$

$

192

10

1

8

211

The amount and timing of capital expenditures is within our control and subject to our management’s discretion, 
and may be adjusted during the year depending on commodity prices and other factors. We retain the flexibility to defer 
planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling 
activities, prevailing and anticipated prices for oil, natural gas and NGLs, the receipt and timing of required regulatory 
permits and approvals, the availability of necessary equipment, infrastructure and capital, seasonal conditions, drilling 
and acquisition costs and the level of participation by other interest owners, as well as general market conditions. 

We currently expect to employ up to three drilling rigs in California during the last three quarters of 2020, and up 
to one rig throughout most, if not all, of the first quarter of 2020. Additionally, we currently expect to drill approximately 
195 to 225 gross development wells during 2020, almost all of which will be in California for oil production. However, 
the execution of these plans requires certain regulatory permits and approvals, and changes in laws and regulations, 
including those relating to the permit review and approval process, could impact our ability to successfully execute our 
plans. Any postponement or elimination of our development drilling program could result in a reduction of proved 
reserve volumes and materially affect our business, financial condition and results of operations. Please see “Regulation 
of Health, Safety and Environmental Matters” for additional discussion of the laws and regulations impacting our 
business. For additional information about the potential risks related to our capital program, see “Item 1A. Risk Factors” 
and for a more detailed discussion of capital expenditures, see “Item 7. Management’s Discussion and Analysis of 
Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Program”.

In addition to capital expenditures, we also incur costs associated with retiring assets and remediating property at 
the end of its useful life, both due to regulatory obligations and our focus on EH&S as we develop existing fields. Most 
of these obligations and activities are regulated by governmental agencies. During 2019, we spent approximately $27 
million in fulfilling these obligations and in 2020 we expect to spend approximately $20 million. A significant portion 
of these costs is a result of California's new idle well regulations which became effective in 2019 and accelerated the 
timing of abandonment of certain existing idle wells. In accordance with these regulations, we expect to plug and 
abandon a majority of our existing idle wells over the next eight years.

5

Our Areas of Operation

Our predominant operating area is in California, and we also have operations in Utah and Colorado, which we 

refer to collectively as our Rockies operating area. 

California

California is and has been one of the most productive oil and natural gas regions in the world. According to the 
U.S. Geological Survey as of 2012, the San Joaquin basin in California contained three of the 10 largest oil fields in 
the United States based on cumulative production and proved reserves. We have operations in two of those three fields 
—Midway-Sunset and South Belridge. 

We also have operations in the McKittrick and Poso Creek fields in the San Joaquin basin in Kern County as well 
as in the Placerita Field in the Ventura basin in Los Angeles County. According to the California Geologic Energy 
Management  Division  (“CalGEM”),  formerly  known  as  the  Division  of  Oil,  Gas,  and  Geothermal  Resources 
("DOGGR") of the California Department of Conservation, approximately 74% of California’s daily oil production of 
443 MBbl/d for 2018 was produced in the San Joaquin basin. We believe there are extensive existing field redevelopment 
opportunities in our areas of operation within the San Joaquin basin. We also believe that our California focus and 
strong balance sheet will allow us to take advantage of these opportunities.

We currently hold nearly 15,000 net acres in the San Joaquin and Ventura basins with a 99% average working 

interest, and our producing areas include:

•

•

Northwest San Joaquin operations: (i) our McKittrick Field property, which is a newer steamflood development(cid:3)
with potential for infill and extension drilling; (ii) our South Belridge Field Hill property, which is characterized(cid:3)
by  two  known  reservoirs  with  low  geological  risk  containing  a  significant  number  of  drilling  prospects,(cid:3)
including downspacing opportunities, as well as additional steamflood opportunities; (iii) our thermal North(cid:3)
Midway-Sunset Diatomite properties, where we utilize innovative EOR techniques to unlock significant value(cid:3)
and maximize recoveries; and (iv) our North Midway-Sunset sandstone properties, where we use cyclic and(cid:3)
continuous steam injection to develop these known reservoirs.

Southeast San Joaquin operations: (i) our South Midway-Sunset, properties, which are long-life, low-decline,(cid:3)
strong-margin thermal oil properties with additional development opportunities; (ii) our Poso Creek property,(cid:3)
which is an active mature shallow, heavy oil asset that we continue to develop across the property; and (iii)(cid:3)
our Placerita property, which is a mature shallow, heavy oil asset with additional recompletion opportunities.

Our California proved reserves represented approximately 88% of our total proved reserves at December 31, 2019. 
California accounted for 22.6 MBoe/d or 78% of our average daily production for the year ended December 31, 2019 
and 25.5 MBoe/d or 81% of our average daily production for the three months ended December 31, 2019.

Along with these upstream operations, we have extensive 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 five 
natural gas cogeneration plants that produce electricity and steam. These plants supply approximately 22% of our steam 
needs and approximately 48% of our field electricity needs in California generally at a discount to electricity market 
prices. To further help offset our costs, we currently also sell surplus power produced by three of our cogeneration 
facilities  under  power  purchase  agreement  (“PPA”)  contracts  with  California  utility  companies.  We  also  own  80
conventional steam generators to help satisfy the steam required by our operations. 

In addition, we own gathering, treatment, water recycling and softening facilities, and storage facilities in California 
that currently have excess capacity, reducing our need to spend capital to develop nearby assets and generally allowing 
us to control certain operating costs. Approximately 86% of our California oil production is sold through pipeline 
connections, and we have contracts in place with third-party purchasers of our crude. 

6

Commercial petroleum development began in the San Joaquin basin in the late 1860s when asphalt deposits were 
mined and shallow wells were hand dug and drilled. Rapid discovery of many of the largest oil accumulations followed 
during the next several decades. Operations on our properties began in 1909. In the 1960s, introduction of thermal 
techniques resulted in substantial new additions to reserves in heavy oil fields. The San Joaquin basin contains multiple 
stacked benches that have allowed continuing discoveries of stratigraphic, structural and non-structural traps. Most oil 
accumulations  discovered  in  the  San  Joaquin  basin  occur  in  the  Eocene  age  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. 

Rockies

Uinta Basin, Utah

Our Uinta basin operations in the Brundage Canyon, Ashley Forest and Lake Canyon areas in Utah target the Green 
River and Wasatch formations that produce oil and natural gas at depths ranging from 5,000 feet to 8,000 feet. We have 
high operational control of our existing acreage which has significant upside for additional vertical and or horizontal 
development and recompletions. 

Our Uinta basin proved reserves represented approximately 11% of our total proved reserves at December 31, 

2019 and accounted for 5.0 MBoe/d or 17% of our average daily production for the year ended December 31, 2019.

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 95% of the gas gathered at these facilities is produced from wells that we operate. Current 
throughput  at  the  processing  plant  is  16-18  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 15,621 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 production more than doubled from 36 
MBbl/d in 2003 to 102 MBbl/d in 2018. Approximately 84% of Utah’s production in 2018 came from the Uinta basin 
in Duchesne and Uintah counties.

Piceance Basin, Colorado

Our primary operating areas in the Piceance basin are Garden Gulch and North Parachute in northwestern Colorado 
where we target the Williams Fork formation of the Mesaverde Group and produce at depths ranging from 7,500 feet 
to 12,500 feet. We have utilized a proven slick water completion method that has resulted in lower costs and increased 
recoveries.  In  addition,  we  have  infrastructure  and  available  takeaway  capacity  in  place  to  support  additional 
development along with existing gas transportation contracts. 

Our Piceance basin proved reserves represented approximately 1% of our total proved reserves at December 31, 

2019 and accounted for 1.4 MBoe/d or 5% of our average daily production for the year ended December 31, 2019.

The Piceance basin is located in northwestern Colorado and is a low geologic risk gas play with trillions of cubic 
feet of natural gas in place. Natural gas generated from coals and carbonaceous shales in the Upper Cretaceous Mesaverde 
Group  migrated  into  low  permeability  Mesaverde  Group  fluvial  sandstones  resulting  in  a  basin-centered  gas 
accumulation, or what the U.S. Geological Survey terms a “continuous petroleum accumulation.” Operators recognized 

7

for years that the Mesaverde Group, and the Williams Fork formation in particular, contained significant quantities of 
gas over a large area, but the low permeability of the reservoir sandstones made it difficult to complete economic wells. 
Improvements in hydraulic stimulation design and completion fluids in the 1990s and 2000s, coupled with an increase 
in commodity prices, led to the economic development of the gas resources in the Piceance basin.

At year end 2019, we recorded an impairment charge for these properties due to the decline in our expectations of 

future gas prices, as such we have no plans to drill in these properties. 

Our Assets and Production Information

For the year ended December 31, 2019, we had average production of approximately 29.0 MBoe/d, of which 
approximately 87% was oil. In California, our average production for the year ended December 31, 2019 was 22.6(cid:3)
MBoe/d, of which 100% was oil.

The table below summarizes our average net daily production for the year ended December 31, 2019:

California

Utah

Colorado
East Texas(2)
Total

Average Net Daily Production(1)
for the Year Ended

December 31, 2019

December 31, 2018

(MBoe/d)

Oil (%)

(MBoe/d)

Oil (%)

22.6

5.0

1.4

—

29.0

100%

54%

2%

—%

87%

19.7

5.0

1.7

0.6

27.0

100%

48%

1%

—%

82%

__________
(1) Production represents volumes sold during the period.
(2) On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin

Production Data

The following table sets forth information regarding production for the years ended December 31, 2019 and 2018.

Average daily production(1)(3):

Oil (MBbl/d)

Natural gas (MMcf/d)

NGLs (MBbl/d)

Total (MBOE/d)(2)

Year Ended

December 31, 2019

December 31, 2018

25.3

20.0

0.4

29.0

22.0

26.3

0.6

27.0

__________
(cid:11)(cid:20)(cid:12) 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.
(cid:11)(cid:21)(cid:12) 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(cid:3)
corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2019, the average(cid:3)
prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4(cid:3)
to 1 on an energy equivalent basis.

(cid:11)(cid:22)(cid:12) On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.

8

Our Development Inventory

We have an extensive inventory of low-geologic risk, high-return development opportunities. As of December 31, 
2019, we identified 10,859 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 95% of our producing wells. In addition, a substantial majority of our acreage is currently 
held by production and fee interest, including 94% of our acreage in California. As of December 31, 2019, the combined 
net acreage covered by leases expiring in the next three years represented approximately 13% of our total net acreage 
of which 11% is in Utah. Our high degree of operational control, together with the large portion of our acreage that is 
held by production, 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, 2019:

Acreage

Gross

18,517

123,665

10,553

Net(1)

14,144

92,921

8,008

152,735

115,073

Net Acreage
Held By
Production and
Fee Interest(%)

Producing 
Wells, 
Gross(2)(3)

Average 
Working 
Interest 
(%)(3)(4)

Net 
Revenue 
Interest 
(%)(3)(5)

94%

70%

85%

80%

3,014

943

167

4,124

99%

95%

83%

98%

93%

62%

79%

90%

Identified Drilling 
Locations(6)

Gross

Net

10,822

10,785

37

—

29

—

10,859

10,814

California

Utah

Colorado

Total

__________
(cid:11)(cid:20)(cid:12) Represents our weighted-average interest in our acreage.
Includes 658 steamflood and waterflood injection wells in California.
(cid:11)(cid:21)(cid:12)
(cid:11)(cid:22)(cid:12) Excludes 90 wells in the Piceance basin each with a 5% working interest.
(cid:11)(cid:23)(cid:12) Represents our weighted-average working interest in our active wells.
(cid:11)(cid:24)(cid:12) Represents our weighted-average net revenue interest for the year ended December 31, 2019.
(cid:11)(cid:25)(cid:12) Our total identified drilling locations include approximately 1,289 gross (1,276 net) locations associated with PUDs as of December 31, 2019,(cid:3)
including 123 gross (121 net) steamflood injection wells. Please see “—Our Reserves—Determination of Identified Drilling Locations” for(cid:3)
more information regarding the process and criteria through which we identified our drilling locations.

Our Reserves

Reserve Data

As of December 31, 2019, we had estimated total proved reserves of 138 MBoe.

The majority of our reserves are composed of crude oil in shallow, long-lived reservoirs. As of December 31, 2019, 
approximately 88% of our proved reserves and approximately 96% of the PV-10 value of our proved reserves are 
derived from our assets in California. We also operate in the Uinta basin in Utah, a mature, light-oil-prone play with 
significant undeveloped resources, as well as in the Piceance basin in Colorado, a prolific natural gas play with low 
geologic risk.

As of December 31, 2019, the standardized measure of discounted future net cash flows of our proved reserves 
and the PV-10 of our proved reserves were approximately $1.5 billion and $1.8 billion, respectively. 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.

9

The tables below summarize our proved reserves and PV-10 by category as of December 31, 2019:

Oil
(MMBbl)

Natural
Gas (Bcf)

NGLs
(MMBbl)

Total 
(MMBoe)(2)

% of
Proved

% Proved
Developed

Capex(3) 
($MM)

PV-10(4) 
($B)

Proved Reserves as of December 31, 2019(1)

61

13

56

130

122

39

—

6

45

—

1

—

—

1

—

68

13

57

138

122

49%

10%

41%

100%

84%

16%

—%

100%

54

30

706

790

747

1.0

0.2

0.6

1.8

1.7

PDP

PDNP

PUD

Total

California

__________
(cid:11)(cid:20)(cid:12) Our  estimated  net  reserves  were  determined  using  average  first-day-of-the-month  prices  for  the  prior  12  months  in  accordance  with  SEC(cid:3)
guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $63.15 per Bbl Brent for oil and(cid:3)
natural gas liquids (“NGLs”) and $2.62 per MMBtu Henry Hub for natural gas at December 31, 2019. The volume-weighted average prices(cid:3)
over the lives of the properties were estimated at $58.88 per Bbl of oil and condensate, $16.93 per Bbl of NGLs and $2.84 per Mcf of gas. The(cid:3)
prices were held constant for the lives of the properties and we took into account pricing differentials reflective of the market environment.(cid:3)
Prices  were  calculated  using  oil  and  natural  gas  price  parameters  established  by  current  SEC  guidelines  and  accounting  rules,  including(cid:3)
adjustment by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the(cid:3)
price received at the wellhead. Please see “—Our Reserves and Production Information—PV-10”.

(cid:11)(cid:21)(cid:12) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(cid:11)(cid:22)(cid:12) Represents undiscounted future capital expenditures estimated as of December 31, 2019.
(cid:11)(cid:23)(cid:12) 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(cid:3)
measure of discounted future net cash flows, please see “—Our Reserves and Production Information—PV-10”. PV-10 does not give effect to(cid:3)
derivatives transactions.

The following table summarizes our estimated proved reserves and related PV-10 as of December 31, 2019. 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.

10

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)

Proved Reserves as of December 31, 2019(1)

California 
(San Joaquin and 
Ventura basins)

Utah
(Uinta basin)

Colorado
(Piceance basin)

Total

68

—

—

68

54

—

—

54

122

—

—

122

6

30

1

12

2

6

—

3

8

36

1

15

—

9

—

1

—

—

—

—

—

9

—

1

PV-10 ($billion)(4)

$

1.7

$

0.1 $

— $

74

39

1

82

56

6

—

57

130

45

1

138

1.8

__________
(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 $63.15 per Bbl Brent for oil and NGLs
and $2.62 per MMBtu Henry Hub for natural gas at December 31, 2019. The volume-weighted average prices over the lives of the properties
were $58.88 per Bbl of oil and condensate, $16.93 per Bbl of NGLs and $2.84 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 Business and Industry—Oil, natural gas and NGL 
prices are volatile and directly affect our results.”

(2) Approximately 18% of proved developed oil reserves, 0% of proved developed NGL reserves, 0% of proved developed natural gas reserves

and 16% of total proved developed reserves are non-producing.

(3) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does
not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the
corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2019, the average
prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4
to 1 on an energy equivalent basis.

(4) For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “—PV-10.” PV-10

does not give effect to derivatives transactions.

PV-10

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  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.  

11

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, 2019:

California PV-10

Utah PV-10

Colorado PV-10

Total Company PV-10

Less: present value of future income taxes discounted at 10%

Standardized measure of discounted future net cash flows

Proved Reserves Additions

At December 31, 2019

(in billions)

$

$

1.7

0.1
—
1.8

(0.3)

1.5

Our proved reserves in California increased 24 MMBoe, or 23% before production, resulting in a 299% replacement 
ratio. The decrease in the Colorado reserves of 17 MMBoe was a result of the current unfavorable gas market. The total 
changes to our proved reserves from December 31, 2018 to December 31, 2019 were as follows:

Beginning balance as of December 31, 2018

Extensions and discoveries

Revisions of previous estimates

Purchases of minerals in place

Current year production

Ending balance as of December 31, 2019

California 
(San Joaquin and 
Ventura basins)

Utah
(Uinta basin)

Colorado
(Piceance basin)

Total

(in MMBoe)(1)

106

13

11

—

(8)

122

19

—
(2)

—

(2)

15

18

—
(16)
—

(1)

1

143

13

(7)

—

(11)

138

__________
(1) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does 
not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the
corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2019, the average
prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4
to 1 on an energy equivalent basis.

Extensions and Discoveries. During 2019, we added 13 MMBoe of proved reserves from extensions and discoveries
principally  in  our  California  properties.  These  extensions  included  McKittrick  steamflood  expansions  based  on 
delineation wells drilled in 2019, Homebase Pliocene development, as well as expansion of our thermal Diatomite 
operations. 

Revisions of Previous Estimates.

Revisions related to impairment - At year end 2019, we performed impairment tests with respect to our proved and 
unproved properties triggered by the persistent decline in gas prices throughout 2019. As a result, we recorded an 
impairment charge for our Piceance gas properties. Our revisions of previous estimates total includes the removal of 
16 MMBoe of proved undeveloped reserves related to this impairment. 

Revisions related to price - Product price changes affect the proved reserves we record. For example, higher prices 
generally increase the economically recoverable reserves in all of our operations because the extra margin extends their 
expected lives and renders more projects economic. Conversely, when prices drop, we experience the opposite effects. 

12

In 2019, our total net negative price revision was 2 MMBoe in California and 2 MMBoe in Utah. This was primarily 
the result of lower prices in the current commodity price environment. 

Revisions related to performance - Performance-related revisions can include upward or downward changes to 
previous proved reserves estimates due to the evaluation or interpretation of recent geologic, production decline or 
operating performance data. In 2019, there were positive technical revisions of approximately 13 MMBoe primarily 
due to improved base performance and redevelopment in our thermal Diatomite area.

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 25 MMBoe in 2019 mainly due to extensions and technical 
revisions. These increases were offset by reclassifications to proved developed reserves of 10 MMboe. The Colorado 
proved undeveloped reserves were fully written down due to the worsening gas market there. The total changes to our 
proved undeveloped reserves from December 31, 2018 to December 31, 2019 were as follows:

Beginning balance as of December 31, 2018

Extensions and discoveries

Revisions of previous estimates

Reclassifications to proved developed

Ending balance as of December 31, 2019

__________

California 
(San Joaquin and 
Ventura basins)

Utah
(Uinta basin)

Colorado
(Piceance basin)

Total

(in MMBoe)(1)

40

12

13

(10)

55

1

—

1

—

2

14

—

(14)

—

0

55

12

—

(10)

57

(1) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does 
not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the
corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2019, the average
prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of approximately
4 to 1 on an energy equivalent basis.

Extensions and Discoveries. During 2019, we added 12 MMBoe of proved undeveloped reserves from extensions

and discoveries due to drilling unproven locations in the Midway Sunset and McKittrick fields. 

Revisions of previous estimates.

Revisions  related  to  price  -  In 2019,  our  net  negative  price  revision  on  proved  undeveloped  reserves  were 
approximately 1 MMBoe in California, which was primarily the result of lower prices due to the current commodity 
price environment. Oil prices have decreased by 12%, and gas prices have decreased by 15%. 

Revisions related to performance - In 2019, our net positive performance-related revision on proved undeveloped 
reserves was 13 MMBoe in California which resulted primarily from our thermal Diatomite area, and 1 MMBoe due 
to the improved type curve performance in our Uinta basin resulting from 2019 drilling activity.

Reclassifications to proved developed. Through the 2019 drilling program, we transferred 10 MMBoe of proved 
undeveloped reserves to the proved developed category in California. As a result, we converted 23% of our beginning-
of-the year inventory of proved undeveloped reserves, spending approximately $74 million of capital. The conversion 
rate reflected a gradual increase in capital spend from the lower pace of development in the prior year. At average Brent 
oil prices between $60 to $65 per barrel and average Henry Hub gas prices of at least $2.60 per mcf, we expect to have 

13

sufficient future capital to develop our proved undeveloped reserves at December 31, 2019 within five years. Prices 
substantially below these levels for a prolonged period of time may require us to reduce expected capital expenditures 
over the next five years, potentially impacting either the quantity or the development timing of proved undeveloped 
reserves. Our year-end proved undeveloped reserves are determined in accordance with SEC guidelines for development 
within five years. We believe we have management's commitment and sufficient future capital to develop all of our 
proved undeveloped reserves. 

Reserves Evaluation and Review Process

Independent engineers, DeGolyer and MacNaughton (“D&M”), prepared our reserve estimates reported herein. 
The process performed by D&M to prepare reserve amounts included their estimation of reserve quantities, future 
production rates, future net revenue and the present value of such future net revenue, based in part on data provided 
by us. When preparing the reserve estimates, D&M did not independently verify the accuracy and completeness of the 
information and data furnished by us with respect to ownership interests, production, well test data, historical costs of 
operation and development, product prices, or any agreements relating to current and future operations of the properties 
and sales of production. However, if in the course of D&M's work, something came to their attention that brought into 
question the validity or sufficiency of any such information or data, they did not rely on such information or data until 
they had satisfactorily resolved their related questions. The estimates of reserves conform to SEC guidelines, including 
the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years. 
Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual 
production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology 
that  establishes  reasonable  certainty.  Reliable  technology  is  a  grouping  of  one  or  more  technologies  (including 
computational methods) that have been field tested and have been demonstrated to provide reasonably certain results 
with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable 
certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of 
our proved reserves have been demonstrated to yield results with consistency and repeatability and include production 
and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, 
available seismic data and historical well cost, operating expense and commodity revenue data.

D&M also prepared estimates with respect to reserves categorization, using the definitions of proved reserves set 

forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.

Our internal control over the preparation of reserves estimates is designed to provide reasonable assurance regarding 
the reliability of our reserves estimates in accordance with SEC regulations. The preparation of reserve estimates was 
overseen by Kurt Neher, 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 32 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 was Gregory K. Graves, P.E. Mr. Graves is a Registered Professional Engineer in the 
State of Texas (License No. 70734), is a member of both the Society of Petroleum Engineers and the Society of Petroleum 
Evaluation Engineers and has in excess of 35 years of experience in oil and gas reservoir studies and reserves evaluations. 
Mr. Graves graduated from the University of Texas at Austin in 1984 with a Bachelor of Science degree in Petroleum 
Engineering.

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 
Business 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.”

14

Determination of Identified Drilling Locations

Proven Drilling Locations

Based on our reserves report as of December 31, 2019, we have approximately 1,289 gross (1,276 net) drilling 
locations attributable to our proved undeveloped reserves, compared to 1,071 gross (1,058 net) as of December 31, 
2018. The increases in drilling locations attributable to our proved undeveloped reserves is primarily due to development 
in the Homebase and McKittrick fields. We use production data and experience gained 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 will be commercially recoverable in accordance with SEC 
guidelines.  Management  considers  the  availability  of  local  infrastructure,  drilling  support  assets,  state  and  local 
regulations and other factors it deems relevant in determining such locations. 

Unproven Drilling Locations

We have also identified a multi-year inventory of 9,570 gross (9,379 net) drilling locations as of December 31, 
2019, compared to 5,959 gross (5,604 net) drilling locations as of December 31, 2018.  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) potential IOR and EOR 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.

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 EOR). 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 and greater than ten acres for a primary gas expansion development in our Piceance asset in Colorado.

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  profitably  drill  and  develop  our  identified  drilling  locations  depends  on  a  number  of  variables, 
including crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals, available 
transportation capacity and other factors. If future drilling results in these projects do not establish sufficient reserves 
to achieve an economic return, we may curtail drilling or development of these projects. For a discussion of the risks 
associated with our drilling program, see “Item 1A. Risk Factors—Risks Related to Our Business and Industry—We 
may not drill our identified sites at the times we scheduled or at all.”

15

The  table  below  sets  forth  our  proved  undeveloped  drilling  locations  and  unproven  drilling  locations  as  of 

December 31, 2019.

PUD Drilling Locations
(Gross)

Unproven Drilling
Locations (Gross)

Total Drilling Locations
(Gross)

Oil and
Natural Gas
Wells

Injection
Wells

Oil and
Natural Gas
Wells

Injection
Wells

Oil and
Natural Gas
Wells

Injection
Wells

California

Utah

Colorado

1,129

37

—

Total Identified Drilling Locations

1,166

123

—

—

123

8,099

1,471

9,228

1,594

—

—

—

—

37

—

—

—

8,099

1,471

9,265

1,594

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 Field
Total production(1):
Oil (MBbls)
Natural gas (Bcf)
NGLs (MBbls)

Total (MBoe)(2)

SJV Belridge Hill(3)

Total production(1):
Oil (MBbls)
Natural gas (Bcf)
NGLs (MBbls)

Total (MBoe)(2)

Piceance

Total production(1):
Oil (MBbls)
Natural gas (Bcf)
NGLs (MBbls)

Total (MBoe)(2)

Year Ended
December 31, 2019

Berry Corp.
(Successor)
Year Ended
December 31, 2018

Ten Months Ended
December 31, 2017

Berry LLC
(Predecessor)
Two Months Ended
February 28, 2017

5,543
—
—
5,543

4,495
—
—
4,495

3,560
—
—
3,560

693
—
—
693

Berry Corp.
(Successor)

Berry LLC
(Predecessor)

Year Ended
December 31, 2019

Year Ended
December 31, 2018

Ten Months Ended
December 31, 2017

Two Months Ended
February 28, 2017

1,312
—
—
1,312

1,196
—
—
1,196

609
—
—
609

35
—
—
35

Berry Corp.
(Successor)

Berry LLC
(Predecessor)

Year Ended
December 31, 2019

Year Ended
December 31, 2018

Ten Months Ended
December 31, 2017

Two Months Ended
February 28, 2017

*
*
*
*

*
*
*
*

14
3.6
—
610

2
0.8
—
138

__________
* 
(1) Production represents volumes sold during the period.

Represented less than 15% of our total proved reserves for the periods indicated.

16

(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, 2019, the average
prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4
to 1.
In July 2017, we acquired the remaining 84% working interest in the South Belridge Hill property located in Kern County, California, in which 
we previously owned a 16% working interest.

(3)

Productive Wells

As of December 31, 2019, we had a total of 3,666 gross (3,541 net) productive wells (including 610 gross and net
steamflood and waterflood injection wells), approximately 95% of which were oil wells. Our average working interests 
in our productive wells is approximately 98%. Many of our oil wells produce associated gas and some of our gas wells 
also produce condensate and NGLs.

The following table sets forth our productive oil and natural gas wells (both producing and capable of producing) 

as of December 31, 2019.

Oil

Gross(1)
Net(2)

Gas

Gross(1)
Net(2)

California 
(San Joaquin and 
Ventura basins)

Utah
(Uinta basin)

Colorado
(Piceance basin) 

Total

2,504
2,479

—
—

986
937

—
—

—
—

176
125

3,490
3,416

176
125

__________
(1) The total number of wells in which interests are owned. Includes 610 steamflood and waterflood injection wells in California.
(2) The sum of fractional interests.

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, 2019. 

California 
(San Joaquin and Ventura basins)

Utah and Other 
(Uinta and Piceance basins)

Total

Developed(1)
Gross(2)
Net(3)

Undeveloped(4)
Gross(2)
Net(3)

9,835

9,289

8,682

4,855

94,268

72,103

39,950

28,827

104,103

81,392

48,632

33,682

__________
(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.

17

Participation in Wells Being Drilled

As  of  December 31,  2019,  we  were  not  participating  in  any  development  or  exploratory  wells.  We  were 
participating  in  14  steamflood  and  waterflood  pressure  maintenance  projects  -  12  steamflood  projects  and  one 
waterflood project were located in the San Joaquin basin, and one waterflood project was located in the Uinta basin.

Drilling Activity 

The following table shows the net development wells we drilled during the periods indicated. We did not drill any 
exploratory  wells  during  the  periods  presented.  The  information  should  not  be  considered  indicative  of  future 
performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells 
drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of 
producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.

California 
(San Joaquin and 
Ventura basins)

Utah
(Uinta basin)

Colorado
(Piceance basin)

Total

2019

Oil(2)
Natural Gas

Dry

2018

Oil(1)
Natural Gas

Dry

2017

Oil(1)
Natural Gas

Dry

335

—

—

224

—

—

124

—

—

3
—
—

8

—

—

—
—
—

—
—
—

—

—

—

—

—

—

338

—

—

232

—

—

124

—

—

__________
(1)
(2)

Includes injector wells.
Includes 50 wells that had not yet been connected to gathering systems in California.

Delivery Commitments

We have contractual agreements to provide gas volumes for transportation, processing and sales, some of which
specify  fixed  and  determinable  quantities  and  all  of  which  were  in  Utah. As  of  December 31,  2019,  the  volumes 
contracted to be delivered were approximately 7,170 MMBtu/d of gas beginning in 2020 and will decrease over time 
to 4,560 MMBtu/d in 2022. We have significantly more production capacity than the amounts committed and have the 
ability to secure additional volumes in case of a shortfall.

18

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 98% working interest and 95% 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 and Piceance in Colorado, as noted in the 
following table. 

State

Project Type

Well Type

Completion Type

Recovery Mechanism

Total

Gross Drilling 
Locations(1)

California

California

California

Utah

Colorado

Total

Vertical /
Horizontal

Perforation/Slotted
liner/gravel pack

Continuous and cyclic
steam injection

Thermal
Sandstones

Thermal
Diatomite

Vertical

Short interval
perforations

Hill Diatomite
(non-thermal)

Vertical

Hydraulic stimulation,
low intensity pin point

Uinta

Vertical /
Horizontal

Low intensity hydraulic
stimulation

Pressure depletion

Piceance

Vertical

Proppantless slick
water stimulation

Pressure depletion

High-pressure cyclic
steam injection

Pressure depletion
augmented with water
injection

6,143

3,198

1,481

37

—

10,859

__________
(1) We had 1,289 gross (1,276 net) locations associated with PUDs as of December 31, 2019 including 123 gross (121 net) steamflood injection
wells. Of those 1,289 gross PUD locations, 1,252 are associated with projects in California, 37 are associated with the Uinta basin. Please see 
“—Our Reserves —Determination of Identified Drilling Locations” for more information regarding the process and criteria through which we
identified our drilling locations. During the year ended December 31, 2019, we drilled 292 gross (292 net) wells that were associated with
PUDs at December 31, 2018, including 25 gross (25 net) steamflood injection wells.

Thermal 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 and Ventura basins, primarily 
in Kern County and in fields such as Midway-Sunset, Poso Creek, McKittrick, South Belridge and Placerita. 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 (300 to 1,200 ft) than our other programs and the wells are relatively inexpensive 
to drill and complete at approximately $210,000 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 five 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,  (ii)  another  5MW  facility  (“21Z  Cogen”)  located  in  the 
McKittrick Field, and (iii) a 42 MW facility (“Cogen 42”) located in the Placerita Field. Cogeneration plants, also 
referred to as combined heat and power plants, use hot turbine exhaust to produce steam while generating electrical 

19

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 Business 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 80 fully permitted conventional steam generators. The number of generators operated at any point in time 
is dependent on (i) the steam volume required to achieve our targeted injection rate and (ii) the price of natural gas 
compared to our oil production rate and the realized price of oil sold. Ownership of these varied steam generation 
facilities allows for maximum operational control over the steam supply, location and, to some extent, the aggregated 
cost of steam generation. The natural gas we purchase to generate steam and electricity is primarily based on California 
price indexes, and in some cases includes transportation charges.

Hydraulic Stimulation 

Hydraulic stimulation is an important and common practice that is used to stimulate production of hydrocarbons 
from tight geologic formations. The process involves the injection of water, sand and trace amounts of chemicals under 
pressure into formations to enhance the permeability of the surrounding rock and stimulate production. Our California 
hydraulic stimulation projects use significantly lower fluid and sand volumes than is typical in other areas. For example, 
we expect to use approximately 150 thousand gallons of water per well for our Hill hydraulic stimulations compared 
to a median of nearly 4 million gallons for horizontal, unconventional shale wells hydraulically stimulated in the United 
States  in  2014.  Similarly,  we  expect  to  use  only  about  325  thousand  pounds  of  sand  per  Hill  well  compared  to  a 
nationwide average of over 4 million pounds of sand per well in 2015. We use low-volume hydraulic reservoir stimulation 
in the San Joaquin basin to stimulate our non-thermal Diatomite reservoir at the Hill property. We applied this technique 
in 2019 and plan to continue this stimulation method on our inventory of Hill non-thermal Diatomite development 
wells.

We use more traditional hydraulic stimulation techniques to complete our wells in the Piceance basin. However, 
in this area, we use a more advanced technique known as “proppantless stimulation” to stimulate the reservoir with 
water and no proppant, such as sand. 

Marketing Arrangements

We market crude oil, natural gas, NGLs, gas purchasing and electricity.

Crude Oil. Approximately 86% 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 73% 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. As of December 31, 2019, all of our oil production was sold 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 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. As of December 31, 2019, all of our natural gas and NGL 
production was sold under short-term contracts at market-sensitive or spot prices. In certain circumstances, we have 

20

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. The relatively small volumes of condensate produced in Colorado are sold under market-
based short-term contracts.

Gas Purchasing. We enter into hedges for gas purchases to protect our operating expenses from 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 five cogeneration facilities, 
which are centrally located on certain of our oil producing properties, is approximately 108 MW. The steam generated 
by each facility is capable of being delivered to numerous wells that require steam for our EOR processes. The main 
purpose of the cogeneration facilities is to reduce the steam and electricity costs in our heavy oil operations.

Electricity and steam produced from our Pan Fee and 21Z cogeneration facilities are used solely for field operations. 

For the year ended December 31, 2019, we sold approximately 1,700 megawatt-hours (“MWhs”) per day of cogen 
power into the grid and consumed approximately 700 MWhs per day of cogen power for lease operations. The five
cogeneration facilities produced an average of approximately 36,000 barrels of steam per day. Contracts for the sale 
of surplus electricity, economic market prices and regulatory conditions affect the economic value of these facilities to 
our operations.

Electricity Sales Contracts. We sell electricity produced by three of our cogeneration facilities under long-term 
PPAs approved by the California Public Utilities Commission (the “CPUC”) to two California investor-owned utilities, 
Southern California Edison Company (“Edison”) and Pacific Gas and Electric (“PG&E”). These PPAs expire in various 
years between 2021 and 2026.

Principal Customers

For  the  year  ended Year  Ended  December  31,  2019,  sales  to Andeavor,  Phillips  66  and  Kern  Oil  &  Refining
accounted for approximately 36%, 24%, and 13% respectively, of our sales. At December 31, 2019, trade accounts 
receivable from three customers represented approximately 40%, 17% and 11% of our receivables. 

If we were to lose any one of our major oil and natural gas purchasers, the loss could cease or delay production
and sale of our oil and natural gas in that particular purchaser’s service area and could have a detrimental effect on the 
prices and volumes of oil, natural gas and NGLs that we are able to sell. For more information related to marketing 
risks, see “Item 1A. Risk Factors—Risks Related to Our Business 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.

21

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other companies, 
including independent operators in acquiring properties, contracting for drilling and other related services, and securing 
trained personnel. We also are affected by competition for drilling rigs and the availability of related equipment. In the 
past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which 
has delayed development drilling and has caused significant price increases. The lower-cost, commoditized nature of 
our equipment and service providers partially insulates us from the cost inflation pressures experienced by producers 
in unconventional plays. We are unable to predict when, or if, such shortages may occur or how they would affect our 
drilling program. 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 Business 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 future legislation and regulation as California and the federal 
government develops renewable energy and climate-related policies. 

Seasonality

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

Natural gas prices can fluctuate based on seasonal and other market-related impacts. We purchase significantly 
more gas than we sell to generate steam and electricity in our cogeneration facilities for our producing activities. As a 
result, our key exposure to gas prices is in our costs. We mitigate a substantial portion of this exposure by selling excess 
electricity from our cogeneration operations to third parties. The pricing of these electricity sales is closely tied to the 
purchase price of natural gas. We also hedge a significant portion of the gas we expect to consume. 

Regulation of Health, Safety and Environmental Matters

Like other companies in the oil and gas industry, our operations are subject to stringent federal, state and local 
laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental 
protection. These laws and regulations:

•

•

•

•

•

Establish air, soil and water quality standards for a given region, such as the San Joaquin Valley, and attainment(cid:3)
plans to meet those regional standards, which may significantly restrict development, economic activity and(cid:3)
transportation in the region;

require the acquisition of various permits before drilling, workover production, underground fluid injection,(cid:3)
enhanced oil recovery methods, or waste disposal commences;

require notice to stakeholders of proposed and ongoing operations;

require the installation of expensive safety and pollution control equipment—such as leak detection, monitoring(cid:3)
and control systems—to prevent or reduce the release or discharge of regulated materials into the air, land,(cid:3)
surface water or groundwater;

restrict  the  types,  quantities  and  concentration  of  various  regulated  materials,  including  oil,  natural  gas,(cid:3)
produced water or wastes, that can be released into the environment in connection with drilling and production(cid:3)
activities, and impose energy efficiency or renewable energy standards on us or users of our products;

22

•

•

•

•

limit or prohibit drilling activities on lands located within coastal, wilderness, wetlands, groundwater recharge(cid:3)
or endangered species inhabited areas, and other protected areas, or otherwise restrict or prohibit activities(cid:3)
that could impact the environment, including water resources, and require the dedication of surface acreage(cid:3)
for habitat conservation;

establish waste management standards or require remedial measures to limit pollution from former operations,(cid:3)
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(cid:3)
on our current or former properties and operations and other locations where such materials generated by us(cid:3)
or our predecessors were released or discharged;

require comprehensive environmental analyses, recordkeeping and reports with respect to operations affecting(cid:3)
federal,  state,  and  private  lands  or  leases,  including  preparation  of  a  Resource  Management  Plan,  an(cid:3)
Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting(cid:3)
federal lands or leases.

CalGEM  is  California's  primary  regulator  of  the  oil  and  natural  gas  industry  on  private  and  state  lands,  with 
additional oversight from the State Lands Commission’s administration of state surface and mineral interests. 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. Government actions, including 
the issuance of certain permits or approval of projects, by state and local agencies or by federal agencies may be subject 
to environmental reviews, respectively, under the California Environmental Quality Act (“CEQA”) or the National 
Environmental Policy Act (“NEPA”), which may result in delays, imposition of mitigation measures or litigation.

In April 2019 new idle well regulations went into effect in California, which includes a comprehensive well testing 
regime to prevent leaks, a compliance schedule for testing or plugging and abandoning idle wells, the collection of data 
necessary  to  prioritize  testing  and  sealing  idle  wells,  requirements  for  a  long-term  idle  well  management  plan,  an 
engineering analysis for each well idled 15 years or longer, and requirements for active observation wells. 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. We have submitted our idle well management plan to meet our obligations.

CalGEM’s predecessor also finalized new Underground Injection Control (“UIC”) regulations, effective April 
2019, which affects two 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. Our California development and production activities are subject to UIC regulations. 

Also,  in  2019,  the  Governor  of  California  signed AB  1057,  legislation  that  required  state  agencies  to  review 
emissions from idle and abandoned wells, evaluate plugging and abandonment and restoration costs and associated 
bonding requirements. This legislation also expanded CalGEM’s duties effective on January 1, 2020 to include public 
health and safety and reducing or mitigating greenhouse gas emissions while meeting the state’s energy needs. Other 
2019 legislation specifically addressed oil and natural gas leasing by the State Lands Commission, including imposing 
conditions on assignment of state leases, requiring lessees to complete abandonment and decommissioning upon the 
termination of state leases, and prohibiting leasing or conveyance of state lands for new oil and natural gas infrastructure 
that would advance production on certain federal lands such as national monuments, parks, wilderness areas and wildlife 
refuges. 

Additionally, 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)  review  and  updating  of  regulations 
regarding public health and safety near oil and natural gas operations pursuant to additional duties assigned to CalGEM 

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by the Legislature in 2019; and (3) a performance audit of CalGEM's permitting processes for well stimulation treatment 
(“WST”) permits and project approval letters (“PALs”) for underground injection by the State Department of Finance 
and an independent review and approval 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  a  moratorium  to  prohibit  new  underground  oil-extraction  wells  from  using  high-
pressure  cyclic  steaming  process.  Only  our  undeveloped  thermal  diatomite  assets  are  currently  impacted  by  the 
moratorium.

CalGEM currently requires an operator to identify the manner in which CEQA has been satisfied prior to issuing 
various state permits or approval of projects, typically through either an environmental impact review (“EIR”) or an 
exemption by a state or local agency. In Kern County this requirement has typically been satisfied by complying with 
the local oil and gas ordinance, which was supported by an Environmental Impact Report (“Kern County EIR”) certified 
by the Kern County Board of Supervisors in 2015. A group of plaintiffs challenged the Kern County EIR and on February 
25, 2020, the California Fifth District Court of Appeals issued a ruling that invalidates a portion of the Kern County 
EIR, effective 30 days after entry of the ruling, until Kern County makes certain revisions to the Kern County EIR and 
recertifies it (“Kern County Ruling”). Other state agencies, including CalGEM, have relied on the Kern County EIR 
to satisfy the CEQA requirements in connection with permitting and project approval decisions for oil and gas projects 
in unincorporated Kern County. We cannot predict how long it will take Kern County to recertify the Kern County EIR 
or to conduct a new EIR, either of which could ultimately result in the imposition of more onerous permit application 
requirements and limits on exploration and production activities. It is not yet known how Kern County will resolve 
this issue, or how long it will take to do so, and we cannot predict how long it will take or what the requirements and 
costs will be to obtain new permits and project approvals in the interim. It is also not yet known whether there will be 
significant delays or a pause in the issuance of new permits and approvals in unincorporated Kern County pending 
resolution of this issue. While the near- and longer- term impacts of the Kern County Ruling on oil and gas activities 
in Kern County are not yet fully known, we are actively monitoring Kern County’s response, considering the potential 
impacts to the permitting process, and evaluating the potential impact to our operations. We do not currently expect 
the Kern County Ruling to materially affect our plans and operations in Kern County as the ruling does not invalidate 
existing permits.

Our 2019 results were not significantly impacted by the moratorium and we currently do not expect our 2020 
results to be impacted by the moratorium.  Our current 2020 development and production plans do not require new 
high–pressure cyclic steam injection and the moratorium does not impact existing production or previously approved 
permits.  Our 2020 plans anticipate primarily thermal sandstone development, which do not require us to use a high–
pressure cyclic steam steaming process. However, our 2020 plans may be impacted by existing and pending regulatory 
changes  or  other  government  activity  impacting  the  timing  of,  and  conditions  imposed  on,  required  permits  and 
approvals.

With the changes in the UIC regulations and its impact on the permitting process, we experienced delays in obtaining 
the permits required to continue our planned drilling operations over the latter half of 2019 and into 2020. In late 2019 
and in early 2020 we discontinued two drilling rigs and we are currently operating one rig. We are actively reviewing 
the UIC regulatory developments and considering the potential impacts of the Kern County Ruling, as well as our 
internal processes. As part of a contingency plan, we are preparing our internal resources to support a more time-
intensive and burdensome permitting application process and the potential environmental impact review requirements 
to mitigate the impact to our development and production plans. If we are unable to obtain the required permits on a 
timely basis or at all, we may not be able to continue operating this one rig or to redeploy the other two as planned and 
we may have to change our strategy and plans, which could adversely affect our financial and operating results.

Existing and potential future laws, rules and regulations may restrict the production rate of oil, natural gas and 
NGLs below the rate that would otherwise be possible. Additionally, the regulatory burden on the industry increases 
the  cost  of  doing  business  and  consequently  may  have  an  adverse  effect  upon  capital  expenditures,  earnings  or 
competitive position. Violations and liabilities with respect to these laws and regulations could result in significant 
administrative,  civil,  or  criminal  penalties,  remedial  clean-ups,  natural  resource  damages,  permit  modifications  or 
revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may 
be significant, and remediation obligations could adversely affect our financial condition, results of operations and 

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prospects. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, 
and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil 
and natural gas industry could have a significant impact on operations. For more information related to regulatory risks, 
see “Item 1A. Risk Factors—Risks Related to Our Business and Industry”.

The environmental laws and regulations applicable to us and our operations include, among others, the following 

U.S. federal laws and regulations:

•

•

•

•

•

•

•

•

•

Clean Air Act (the “CAA”), which governs air emissions;

Clean Water Act (the “CWA”), which governs discharges to and excavations within the waters of the United
States;

Comprehensive  Environmental  Response,  Compensation  and  Liability Act  (“CERCLA”),  which  imposes
liability  where  hazardous  substances  have  been  released  into  the  environment  (commonly  known  as
“Superfund”);

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;

Energy Independence and Security Act of 2007, which prescribes new fuel economy standards and other
energy saving measures;

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;

SDWA, which governs the underground injection and disposal of wastewater; and

U.S. Department of Interior regulations, which regulate oil and gas production activities on federal lands and
impose liability for pollution cleanup and damages.

Various states regulate the drilling for, and the production, gathering and sale of, oil, natural gas and NGL, including 
imposing production taxes and requirements for obtaining drilling permits. Our planned capital expenditures depend 
on a variety of factors, including but not limited to the receipt and timing of required regulatory permits and approvals. 
Any postponement or elimination of our development drilling program could result in a reduction of proved reserve 
volumes and materially affect our business, financial condition and results of operations. States also regulate the method 
of developing new fields, the spacing and operation of wells and the prevention of waste of resources. States may 
regulate rates of production and may establish maximum daily production allowables from wells based on market 
demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct 
economic regulations, but there can be no assurance that they will not do so in the future. The effect of these regulations 
may be to limit the amounts of oil, natural gas and NGLs that may be produced from our wells and to limit the number 
of wells or locations we can drill. The oil and natural gas industry is also subject to compliance with various other 
federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation 
and equal opportunity employment.

We believe that compliance with currently applicable 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 environmental regulations. 
Future regulatory issues that could impact us include new rules or legislation, or the reinterpretation of existing rules 
or legislation, relating to the items discussed below.

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Climate Change

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 greenhouse gases (“GHGs”) as 
well as to restrict or eliminate such future emissions. As a result, our oil and natural gas exploration and production 
operations are subject to a series of regulatory, political, litigation, and financial risks associated with the production 
and processing of fossil fuels and emission of GHGs.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. 
However, with the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the 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, 
implement New Source Performance Standards directing the reduction of methane from certain new, modified, or 
reconstructed facilities in the oil and natural gas sector, 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 emissions. 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. Similar regulations applicable to oil and gas 
facilities have been promulgated in Colorado.

In September 2018, California adopted a law committing California , the fifth largest economy in the world, to 
the  use  of  100%  zero-carbon  electricity  by  2045,  and  the  Governor  of  California  also  signed  an  executive  order 
committing California to total economy-wide carbon neutrality by 2045. 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, and therefore adversely effect our revenues and results 
of operations.

At the international level, there is a non-binding agreement, the United Nations-sponsored “Paris Agreement,” 
for  nations  to  limit  their  GHG  emissions  through  individually-determined  reduction  goals  every  five  years  after 
2020. Although the United States has announced its withdrawal from such agreement, effective November 4, 2020, 
several  U.S.  states  and  local  governments  have  announced  their  intention  to  adhere  to  the  goals  of  the  Paris 
Agreement.

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 seeking the office of the President of the United States in 2020. Two critical declarations made by one or 
more  candidates  running  for  the  Democratic  nomination  for  President  include  threats  to  take  actions  banning 
hydraulic  fracturing  of  oil  and  natural  gas  wells  and  banning  new  leases  for  production  of  minerals  on  federal 
properties. Our operations involve the use of hydraulic fracturing activities and we also have operations on federal 
lands under the jurisdiction of the U.S. Bureau of Land Management (“BLM”). Other actions that could be pursued 
by presidential candidates may include more restrictive requirements for the establishment of pipeline infrastructure 
or the permitting of LNG export facilities, as well as the reversal of the United States’ withdrawal from the Paris 
Agreement in November 2020.

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Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit 
against  the  largest  oil  and  natural  gas  exploration  and  production  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 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. Additionally,  the  lending  practices  of  institutional  lenders  have 
been  the  subject  of  intensive  lobbying  efforts  in  recent  years  by  environmental  activists,  proponents  of  the 
international  Paris Agreement,  and  other  groups  concerned  about  climate  change  to  restrict  fossil  fuel  producers’ 
access  to  capital.  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.

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.

For  more  information,  please  see  “Item  1A.  Risk  Factors—Risks  Related  to  Our  Business  and  Industry—
Concerns  about  climate  change  and  other  air  quality  issues  may  affect  our  operations  or  results;”  and  “—Our 
operations  are subject to a series of risks arising out of the threat of climate change that could result in increased 
operating costs, limit the areas in which we may conduct oil and natural gas exploration and production activities, 
and reduce demand for the oil and natural gas we produce.”

Hydraulic Stimulation 

Hydraulic stimulation is an important and common practice that is used to stimulate production of hydrocarbons 
from tight geologic formations. The process involves the injection of water, sand and trace amounts of chemicals under 
pressure into formations to enhance the permeability of the surrounding rock and stimulate production. Recently, as 
part of their oil and natural gas regulatory programs, state regulators have overseen hydraulic stimulation operations 
in more detail. However, the EPA has asserted federal regulatory authority pursuant to the federal SDWA over certain 
hydraulic stimulation activities involving the use of diesel fuels and published permitting guidance in February 2014 
addressing the performance of such activities using diesel fuels. The EPA has issued final regulations under the federal 
Clean Air Act establishing performance standards, including standards for the capture of air emissions released during 
hydraulic stimulation, and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic 
stimulation operations to publicly owned wastewater treatment plants. The BLM previously issued regulations regarding 
the public disclosure of chemicals used in stimulation treatments, well construction and integrity, and management of 
waste fluids resulting from hydraulic fracturing activities on federal and Tribal lands. While the BLM rescinded these 
regulations in 2017, the rescission is subject to ongoing legal challenge. If the rule is reinstated, the outcome of this 
litigation could materially impact our operations in the Uinta basin and other areas. 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 

27

operations. These permitting requirements and restrictions could result in delays in operations at well sites and also 
increased costs to make wells productive. 

There may be other attempts to further regulate hydraulic stimulation under the SDWA, the Toxic Substances 
Control Act and/or other regulatory mechanisms. In December 2016, the EPA released its final report on a wide ranging 
study on the effects of hydraulic stimulation on water resources. While no widespread impacts from hydraulic stimulation 
were found, the EPA identified a number of activities and factors that may have increased risk for future impacts.

Moreover, some states and local governments have adopted, and other states and local governments are considering 
adopting, regulations that could restrict hydraulic stimulation in certain circumstances or otherwise impose enhanced 
permitting, fluid disclosure, or well construction requirements on hydraulic stimulation activities. For example, in 
Colorado, there have been several initiatives underway to limit or ban crude oil and natural gas exploration, development 
or operations. In April 2019, Colorado adopted Senate Bill 19-181 (“SB 181”), which makes sweeping changes in 
Colorado oil and gas law, including, among other matters, requiring the Colorado Oil and Gas Conservation Commission 
(“COGCC”) to prioritize public health and environmental concerns in its decisions, instructing the COGCC to adopt 
rules to minimize emissions of methane and other air contaminants, and delegating considerable new authority to local 
governments to regulate surface impacts. Some local communities have adopted additional restrictions for oil and gas 
activities, such as requiring greater setbacks, and other groups have sought a cessation of permit issuances entirely until 
the COGCC publishes new rules in keeping with SB 181. Additionally, activist groups have submitted new ballot 
proposals  for  the  2020  election  year,  including  proposals  for  increased  drilling  setbacks  and  increased  bonding 
requirements.  Separately,  in  California, Assembly  Bill  345  was  introduced  but  failed  to  advance  in  the  California 
Legislature to impose a statewide setback distance of 2,500 feet between certain oil and natural gas operations and 
residences, schools and healthcare facilities. In January 2020, the State Assembly passed an amended version of AB 
345 that, if passed by the State Senate and signed by the Governor, would require CalGEM, to adopt a land use setback 
in its rulemaking by July 2022. As amended, the bill no longer specifies a mandatory setback distance, but would require 
CalGEM to consider a 2,500 foot setback as well as enhanced monitoring and maintenance requirements.

As described above, the regulation or prohibition of hydraulic stimulation is the subject of significant political 
activity in a number of jurisdictions, some of which have resulted in tighter regulation including recognition of local 
government authority to implement such restrictions. Many of these restrictions are being challenged in court cases. 
If new laws or regulations that significantly restrict hydraulic stimulation are adopted, such laws could make it more 
difficult or costly for us to perform work to stimulate production from tight formations or otherwise impact the value 
of our assets. In addition, any such added regulation could lead to operational delays, increased operating costs and 
additional  regulatory  burdens,  and  reduced  production  of  oil  and  natural  gas,  which  could  adversely  affect  our 
revenues, results of operations and net cash provided by operating activities.

Additionally, hydraulic stimulation operations require large volumes of water. Our inability to locate sufficient 
amounts  of  water  or  dispose  of  or  recycle  water  used  in  our  drilling  and  production  operations,  could  adversely 
impact  our  operations.  Drought  conditions,  competing  water  uses,  and  other  physical  disruptions  to  our  access  to 
water could adversely affect our operations. Moreover, new environmental initiatives and regulations could include 
restrictions on our ability to conduct certain operations such as hydraulic stimulation or disposal of waste, including 
but not limited to produced water, drilling fluids and other wastes associated with the development or production of 
natural gas.

The SDWA and the Underground Injection Control (the “UIC”) Program

The SDWA and the UIC program promulgated under the SDWA and relevant state laws regulate the drilling and 
operation  of  disposal  wells  that  manage  produced  water  (brine  wastewater  containing  salt  and  other  constituents 
produced by natural gas and oil wells). The EPA directly administers the UIC program in some states, and in others 
administration is delegated to the state. Permits must be obtained before developing and using deep injection wells 
for the disposal of produced water, and well casing integrity monitoring must be conducted periodically to ensure 
the well casing is not leaking produced water to groundwater. Contamination of groundwater by natural gas and oil 
drilling,  production  and  related  operations  may  result  in  fines,  penalties,  remediation  costs  and  natural  resource 
damages, among other sanctions and liabilities under the SDWA and other federal and state laws. In addition, third-
party claims may be 

28

filed by landowners and other parties claiming damages for groundwater contamination, alternative water supplies, 
property impacts and bodily injury.

Solid and Hazardous Waste

Although oil and natural gas wastes generally are exempt from regulation as hazardous wastes under the federal 
RCRA and some comparable state statutes, it is possible some wastes we generate presently or in the future may be 
subject to regulation under the RCRA or other similar statutes. The EPA and various state agencies have limited the 
disposal options for certain wastes, including hazardous wastes and there is no guarantee that the EPA or the states will 
not adopt more stringent requirements in the future. For example, in December 2016, the EPA and several environmental 
groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria 
regulations exempting certain exploration and production related oil and gas wastes from regulation as a hazardous 
waste under RCRA. In keeping with the consent decree, in April 2019, EPA signed a determination that revision of 
these regulations was not warranted at this time.  However, a loss of the RCRA exclusion for drilling fluids, produced 
waters and related wastes could result in an increase in the costs to manage and dispose of generated wastes.

In addition, the federal CERCLA can impose joint and several liability without regard to fault or legality of conduct 
on classes of persons who are statutorily responsible for the release of a hazardous substance into the environment. 
These persons can include the current and former owners or operators of a site where a release occurs, and anyone who 
disposes or arranges for the disposal of a hazardous substance released at a site. Under CERCLA, such persons may 
be subject to strict, joint and several liability for the entire cost of cleaning up hazardous substances that have been 
released into the environment and for other costs, including response costs, alternative water supplies, damage to natural 
resources and for the costs of certain health studies. Moreover, it is not uncommon for neighboring landowners and 
other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances 
released into the environment. Each state also has environmental cleanup laws analogous to CERCLA. Petroleum 
hydrocarbons or wastes may have been previously handled, disposed of, or released on or under the properties owned 
or leased by us or on or under other locations where such wastes have been taken for disposal. These properties and 
any materials disposed or released on them may subject us to liability under CERCLA, RCRA and analogous state 
laws.  Under  such  laws,  we  could  be  required  to  remove  or  remediate  previously  disposed  wastes  or  property 
contamination, to contribute to remediation costs, or to perform remedial activities to prevent future environmental 
harm.

Endangered Species Act

The federal Endangered Species Act (the “ESA”) restricts activities that may affect endangered and threatened 
species or their habitats. Some of our operations may be located in areas that are designated as habitats for endangered 
or threatened species. In February 2016, the U.S. Fish and Wildlife Service published a final policy which alters how 
it identifies critical habitat for endangered and threatened species. A critical habitat designation could result in further 
material restrictions to federal and private land use and could delay or prohibit land access or development. Moreover, 
the U.S. Fish and Wildlife Service continues its effort to make listing decisions and critical habitat designations where 
necessary for over 250 species, as required under a 2011 settlement approved by the U.S. District Court for the District 
of Columbia. The U.S. Fish and Wildlife Service agreed to complete the review by the end of the agency’s 2017 fiscal 
year. The agency missed the deadline but continues to review species for listing under the ESA. Similar protections 
are offered to migratory birds under the Migratory Bird Treaty Act (“MTBA”). The federal government in the past has 
pursued enforcement actions against oil and natural gas companies under the Migratory Bird Treaty Act after dead 
migratory  birds  were  found  near  reserve  pits  associated  with  drilling  activities.  However,  in  January  2020,  the 
Department of Interior proposed new regulations clarifying that only the intentional taking of protected migratory birds 
is subject to prosecution under the MTBA. The ESA and MBTA have not previously had a significant impact on our 
operations. Nevertheless, the designation of previously unprotected species, such as the Greater Sage Grouse, as being 
endangered or threatened could cause us to incur additional costs or become subject to operating restrictions in areas 
where the species are known to exist. If a portion of any area where we operate were to be designated as a critical or 
suitable habitat, it could adversely impact the value of our assets.

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Air Emissions

The CAA and comparable state laws restrict the emission of air pollutants from many sources (e.g., compressor 
stations), through the imposition of air emission standards, construction and operating permitting programs and other 
compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or 
modification of projects or facilities expected to produce or significantly increase air emissions, obtain and strictly 
comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of 
certain pollutants. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (the 
“NAAQS”) for ozone from 75 to 70 parts per billion and completed attainment/non-attainment designations in 2018. 
In 2016, EPA published a Federal Implementation Plan (“FIP”) to implement minor new source review for oil and gas 
production and processing on tribal lands. In April 2018, the EPA proposed revisions to reportedly streamline the FIP. 
Although neither the original FIP nor its revisions originally applied to areas of ozone non-attainment, a May 2019 rule 
extended the FIP to the Indian country portion of the Uinta Basin Ozone Nonattainment Area.

Implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability 
to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could 
be significant. Over the next several years we may be required to incur certain capital expenditures for air pollution 
control equipment or other air emissions related issues. In addition, the EPA has adopted new rules under the CAA that 
require the reduction of volatile organic compound and methane emissions from certain stimulated oil and natural gas 
wells for which well completion operations are conducted and further require that most wells use reduced emission 
completions, also known as “green completions.” These regulations also establish specific new requirements regarding 
emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage 
vessels. Subsequently, the Trump Administration has made several attempts to modify CAA regulations related to 
methane emissions from oil and gas sources. These attempts are subject to ongoing litigation. Most recently, in August 
2019, the EPA proposed amendments to the existing methane requirements that, among other things, could rescind 
methane-specific requirements applicable to upstream facilities but retain requirements for volatile organic compound 
emissions. Legal challenges to any final rule rescinding federal methane requirements are expected.

In addition, the regulations place new requirements to detect and repair volatile organic compound and methane 
at certain well sites and compressor stations. In May 2016, the EPA also finalized rules regarding criteria for aggregating 
multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. 
This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more 
stringent air permitting processes and requirements. Compliance with these and other air pollution control and permitting 
requirements  has  the  potential  to  delay  the  development  of  oil  and  natural  gas  projects  and  increase  the  costs  of 
development, which costs could be significant.

NEPA

Oil and natural gas exploration and production activities on federal lands are subject to NEPA. NEPA requires 
federal agencies to evaluate major agency actions having the potential to significantly impact the environment. The 
NEPA process involves public input through comments which can alter the nature of a proposed project either by 
limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through 
the court system by process participants. This process may result in delaying the permitting and development of projects, 
increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation 
of  existing  leases.  In  January  2020,  the  Council  on  Environmental  Quality  issued  a  proposed  revisions  to  NEPA 
regulations that seek to conform the scope of direct, indirect, and cumulative impact analyses for proposed projects 
subject to NEPA with existing case law; however, the final form or impact of any such revisions is uncertain at this 
time.

Water Resources

The CWA and analogous state laws restrict 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. Under the CWA, permits must be obtained for the discharge of pollutants into waters of the United States. 

30

The  CWA  provides  for  administrative,  civil  and  criminal  penalties  for  unauthorized  discharges,  both  routine  and 
accidental, of pollutants and of oil and hazardous substances. It imposes substantial potential liability for the costs of 
removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to 
water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge 
of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated 
regulations that may require permits to discharge storm water runoff, including discharges associated with construction 
activities. Pursuant to these laws and regulations, we may be required to develop and implement spill prevention, control 
and countermeasure plans, (“SPCC plans”) in connection with on-site storage of significant quantities of oil. Some 
states also maintain groundwater protection programs that require permits for discharges or operations that may impact 
groundwater conditions. The CWA also prohibits the discharge of fill materials to regulated waters including wetlands 
without a permit from the U.S. Army Corps of Engineers. The process for obtaining permits has the potential to delay 
our operations. SPCC plans and other federal requirements require appropriate containment berms and similar structures 
to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. Also, in 
June 2016, the EPA finalized new wastewater pretreatment standards that prohibit onshore unconventional oil and 
natural gas extraction facilities from sending wastewater to publicly owned treatment works.

In August 2015, the EPA and U.S. Army Corps of Engineers issued a rule expanding the scope of the federal 
jurisdiction over wetlands and other types of waters (the “Clean Water Rule”). However, there have been attempts to 
modify the Clean Water Rule by the Trump Administration. On January 23, 2020, the EPA and the Corps finalized the 
Navigable Waters Protection Rule, which narrows the definition of jurisdictional water relative to the Clean Water Rule. 
However, legal challenges to the new rule are expected, and multiple challenges to the EPA’s prior rulemakings remain 
pending. We cannot predict the outcome of any of this litigation. To the extent any 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.

In recent years, water districts and the California state government have implemented regulations and policies 
that may restrict groundwater extraction and water usage and increase the cost of water. 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, steamflooding 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.

Natural Gas Sales and Transportation

Section 1(b) of the Natural Gas Act (the “NGA”) exempts natural gas gathering facilities from regulation by the 
Federal Energy Regulatory Commission (“FERC”) as a natural gas company under the NGA. We believe that the 
natural  gas  pipelines  in  our  gathering  systems  meet  the  traditional  tests  FERC  has  used  to  establish  a  pipeline’s 
status as a gatherer not subject to regulation as a natural gas company, but the status of these lines has never been 
challenged  before  FERC.  The  distinction  between  FERC-regulated 
transmission  services  and  federally 
unregulated  gathering  services  is  subject  to  change  based  on  future  determinations  by  FERC,  the  courts,  or 
Congress,  and  application  of  existing  FERC  policies  to  individual  factual  circumstances.  Accordingly,  the 
classification  and  regulation  of  some  of  our  natural  gas  gathering  facilities  may  be  subject  to  challenge  before 
FERC  or  subject  to  change  based  on  future  determinations by FERC, the courts, or Congress. In the event our 
gathering facilities are reclassified to FERC-regulated  transmission  services,  we  may  be  required  to  charge  lower 
rates and our revenues could thereby be reduced.

FERC  requires  certain  participants  in  the  natural  gas  market,  including  natural  gas  gatherers  and  marketers 
which  engage  in  a  minimum  level  of  natural  gas  sales  or  purchases,  to  submit  annual  reports  regarding  those 
transactions  to  FERC.  Should  we  fail  to  comply  with  this  requirement  or  any  other  applicable  FERC-
administered  statute,  rule, regulation or order, it could be subject to substantial penalties and fines.

Federal Energy Regulations

      The enactment of the Public Utility Regulatory Policies Act (“PURPA”) and the adoption of regulations 
thereunder by the FERC provided incentives for the development of cogeneration facilities such as those we own. A domestic 

31

electricity generating project must be a Qualifying Facility (“QF”) under FERC regulations in order to benefit from 
certain rate and regulatory incentives provided by PURPA.

PURPA  provides  two  primary  benefits  to  QFs.  First,  QFs  and  entities  that  own  QFs  generally  are  relieved  of 
compliance with certain federal regulations pursuant to the Public Utility Holding Company Act of 2005. Second, 
FERC’s regulations promulgated under PURPA require that electric utilities purchase electricity generated by QFs at 
a  price  based  on  the  purchasing  utility’s  avoided  cost  and  that  the  utility  sell  back-up  power  to  the  QF  on  a 
nondiscriminatory basis. The Energy Policy Act of 2005 amended PURPA to allow a utility to petition FERC to be 
relieved of its obligation to enter into any new contracts with QFs if FERC determines that a competitive wholesale 
electricity  market  is  available  to  QFs  in  the  service  territory.  Effective  November  23,  2011,  the  California  utility 
companies have been relieved of their PURPA obligation to enter into new contracts with cogeneration QFs larger than 
20 MW. While the California utility companies are still required to enter into new contracts with smaller facilities, such 
as our Cogen 18 facility, there is no assurance that we will be able to secure new contracts upon the expiration of the 
existing contracts for our larger facilities. Even if new contracts are available for our larger facilities, there is no assurance 
that the prices and terms of such contracts will not adversely affect our financial condition, results of operations and 
net cash provided by operating activities.

State Energy Regulation

The CPUC has broad authority to regulate both the rates charged by, and the financial activities of, electric utilities 
operating in California and to promulgate regulation for implementation of PURPA. Since a power sales agreement 
becomes a part of a utility’s cost structure (generally reflected in its retail rates), power sales agreements between 
electric utilities and independent electricity producers, such as us, are under the regulatory purview of the CPUC. While 
we are not subject to direct regulation by the CPUC, the CPUC’s implementation of PURPA and its authority granted 
to the investor-owned utilities to enter into other PPAs are important to us, as is other regulatory oversight provided by 
the CPUC to the electricity market in California. The CPUC’s implementation of PURPA may be subject to change 
based on past and future determinations by the courts, or policy determinations made by the CPUC.

Operations on Indian Lands

A portion of our leases and drill-to-earn arrangements in the Uinta basin operating area and some of our future 
leases in this and other operating areas may be subject to laws promulgated by an Indian tribe with jurisdiction over 
such lands. In addition to potential regulation by federal, state and local agencies and authorities, an entirely separate 
and distinct set of laws and regulations may apply to lessees, operators and other parties on Indian 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 Indian 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 Indian lands.

Pipeline Safety Regulations

The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) 
regulates safety of oil and natural gas pipelines, including, with some specific exceptions, oil and natural gas gathering 
lines. From time to time, PHMSA, the courts or Congress may make determinations that affect PHMSA’s regulations 
or their applicability to our pipelines. These determinations may affect the costs we incur in complying with applicable 
safety regulations.

32

Worker Safety

The Occupational Safety and Health Act of 1970 (“OSHA”) and analogous state laws regulate the protection of 
the safety and health of workers. The OSHA hazard communication standard requires maintenance of information about 
hazardous materials used or produced in operations and provision of such information to employees. Other OSHA 
standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can 
lead to the imposition of penalties. In December 2015, the U.S. Departments of Justice and Labor announced a plan to 
more frequently and effectively prosecute worker health and safety violations, including enhanced penalties.

Future Impacts and Current Expenditures

We cannot predict how future environmental laws and regulations may impact our properties or operations. For 
the year ended December 31, 2019, 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 2020 or that will otherwise have a material impact on our financial position, 
results of operations or cash flows.

Employees

As of December 31, 2019, we had 355 employees. None of our employees are currently covered under collective 

bargaining/union agreements.

We consider employee relations to be good. We strive to create a corporate culture that is reflective of our core 
values, including accountability, ownership, communication, leadership and entrepreneurship. We are committed to 
the development of our employees and provide learning and engagement opportunities. 

Corporate Information

On May 11, 2016, our predecessor filed petitions for reorganization in the U.S. Bankruptcy Court (the “Bankruptcy 
Court”) for the Southern District of Texas (collectively, the “Chapter 11 Proceedings”). On February 28, 2017, Berry 
LLC  emerged  from  bankruptcy  as  a  stand-alone  company  and  wholly-owned  subsidiary  of  Berry  Corp.  with  new 
management, a new board of directors and new ownership. Berry Corp. was incorporated in Delaware in February 
2017 in connection with the Chapter 11 Proceedings. A final decree closing the Chapter 11 Proceedings was entered 
September 28, 2018, with the Court retaining jurisdiction as described in the confirmation order and without prejudice 
to the request of any party-in-interest to reopen the case including with respect to certain, immaterial remaining matters. 
Berry Corp. completed its IPO and its common stock has been trading on the Nasdaq Global Select Market ("NASDAQ") 
under the ticker symbol "BRY" since July 26, 2018. 

We have executive offices located at 11117 River Run Boulevard, Bakersfield, California 93311 and at 16000 N. 
Dallas Pkwy, Ste. 500, Dallas, Texas 75248, where we have our principal executive offices. Our telephone number is 
(661) 616-3900 and our web address is www.bry.com. Information contained in or accessible through our website is
not, and should not be deemed to be, part of this report.

Item 1A. Risk Factors

If any of the following risks actually occur, our business, financial condition and results of operations could be 
materially and adversely affected and we may not be able to achieve our goals. We cannot assure you that any of the 
events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not 
the only risks and uncertainties we face. Additional risks and uncertainties not presently known to us or that we currently 
deem immaterial may ultimately materially affect our business. 

33

Risks Related to Our Business 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.

Oil, natural gas and NGL prices are volatile and directly affect our results. 

The prices we receive for our oil, natural gas and NGL production and pay for natural gas purchases heavily 
influence our revenue, operating expenses, profitability, access to capital, future rate of growth and the carrying value 
of our properties. Prices for these commodities have, and may continue to, fluctuate widely in response to market 
uncertainty and to relatively minor changes in the supply of and demand for oil, natural gas and NGLs. For example, 
Brent crude oil contract prices ranged from $54.91 per Bbl at the beginning of 2019, to a high of $74.57 per Bbl and 
back to $56.23 per Bbl at the end of 2019. In California, the price we pay for fuel gas purchases is generally based on 
the Kern, Delivered Index, as well as the SoCal Index which were as low as $0.99 per MMBtu and as high as $22.38
per MMBtu for a short time in 2019 due to market disruptions. Prices remain volatile in 2020. The prices we receive 
for our production and pay for our gas purchases, and the levels of our production, depend on numerous factors beyond 
our control, which include the following:

•

worldwide and regional political, regulatory, economic and social conditions impacting the global supply and
demand for, and transportation costs of, oil and natural gas, including relaxation of rules against U.S. exports;

• military action, war, sanctions and other conflicts;

•

•

•

•

•

•

•

•

•

•

the price and quantity of foreign imports of oil, particularly in California which imports from foreign countries
more than half of the oil it consumes;

the impact of the U.S. dollar exchange rates on oil and expectations about future oil and gas prices;

prevailing prices on local price indexes in the areas in which we operate which are affected by local market
conditions and the proximity, capacity, cost and availability of gathering and transportation facilities as well
as refining and processing disruptions or bottlenecks;

the level of global exploration, development and production, and resulting inventories, including the significant
increase in U.S. activities over the past decade;

actions of OPEC, its members and other state-controlled oil companies relating to oil price and production
controls;

actions of other significant producers;

the cost of exploring for, developing, producing and transporting reserves;

weather conditions and natural disasters;

other irregular events that impact our ability to conduct business or demand for our products, such as the
coronavirus outbreak; and

technological  advances,  conservation  efforts  and  availability  of  alternative  fuels  affecting  oil  and  gas
consumption.

Lower oil prices and higher gas prices may reduce our cash flow, borrowing ability and access to capital needed 

to develop existing and future reserves.  

Lower oil prices and higher gas prices generally reduce the quantity of our oil reserves as those reserves expected 
to be produced in later years, which tend to be costlier on a per unit basis, become uneconomic. Lower gas prices may 
also reduce our gas reserves. In addition, a portion of our PUDs may no longer meet the economic producibility criteria 

34

under the applicable rules or may be removed due to a lower amount of capital available to develop these projects 
within the SEC-mandated five-year limit. 

In addition, oil and natural gas prices affect our drilling economics, and lower oil prices may require us to postpone 
or eliminate all or part of our development program, and result in the reduction of some of our proved undeveloped 
reserves, reducing the net present value of our proved reserves.

Our business requires continual capital expenditures. We may be unable to fund these investments through operating 
cash flow or obtain any needed additional capital on satisfactory terms or at all, which could lead to a decline in 
our oil and natural gas reserves or production. Our capital program is also susceptible to risks, including regulatory 
and permitting risks, that could materially affect its implementation.

Our industry is capital intensive. We have a 2020 capital expenditure budget of approximately $125 to $145 million. 
The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result 
of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and 
equipment, the availability of permits, and our ability to obtain them in a timely manner or at all, legal and regulatory 
processes and other restrictions, and technological and competitive developments. A reduction or sustained decline in 
commodity prices from current levels may force us to reduce our capital expenditures, which would negatively impact 
our ability to grow production. Current and future laws and regulations may prevent us from being able to execute our 
drilling programs and development and optimization projects. 

We expect to fund our capital expenditures with cash flows from our operations; however, our cash flows from 
operations, and access to capital should such cash flows prove inadequate, are subject to a number of variables, including:

•

•

•

•

•

•

the volume of hydrocarbons we are able to produce from existing wells;

the prices at which our production is sold and our operating expenses;

the success of our hedging program;

our proved reserves, including our ability to acquire, locate and produce new reserves;

our ability to borrow under the RBL Facility;

and our ability to access the capital markets.

If our revenues or the borrowing base under the RBL Facility decrease as a result of lower oil, natural gas and 
NGL prices, lack of required permits and other operating difficulties, declines in reserves or for any other reason, we 
may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional 
capital were needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. Any 
additional debt financing, would carry interest costs, diverting capital from our business activities, which in turn could 
lead to a decline in our reserves and production. If cash flows generated by our operations or available borrowings 
under the RBL Facility were not sufficient to meet our capital requirements, the failure to obtain additional financing 
could result in a curtailment of our operations relating to development of our properties. See “Item 7. Management’s 
Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”

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.

Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating 
to  environmental  protection  and 
the 
production,  transportation,  marketing  and  sale  of  our  products.  Federal,  state  and  local  agencies  may  assert 
overlapping authority to regulate in these areas. For example, the jurisdiction, duties and enforcement authority of 
various state agencies have 

the  exploration  and  development  of  our  properties,  as  well  as 

35

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 plan to issue additional regulations of certain oil and natural gas activities in 2020. 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.

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. 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, 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.

Our operations in California are subject to numerous and stringent state, local and other laws and regulations that 
could delay or otherwise adversely impact our operations.  For example, in 2019, new legislation expanded CalGEM’s 
duties to include public health and safety and reducing or mitigating greenhouse gas emissions while meeting the state’s 
energy needs, and will require CalGEM to study and prioritize controlling emissions from idle and abandoned wells, 
evaluate  plugging  and  abandonment  and  restoration  costs  and  associated  bonding  requirements. Additionally,  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) review and updating of regulations regarding public health and safety
near oil and natural gas operations pursuant to additional duties assigned to CalGEM by the Legislature in 2019; and
(3) a performance audit of CalGEM's permitting processes for WST permits and PALs for underground injection by
the State Department of Finance and an independent review and approval 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  a  moratorium  to  prohibit  new  underground  oil-
extraction wells from using high-pressure cyclic steaming process. Most recently, on February 24, 2020, a California
Court of Appeals effectively invalidated a Kern County ordinance that streamlined the permitting process for oil and
gas exploration, extraction, operations and production activities in unincorporated Kern County, until the County makes
certain revisions to the Kern County EIR supporting the ordinance and recertifies it. Other state agencies, including
CalGEM, have relied on the Kern County EIR to satisfy the CEQA requirements in connection with permitting and
project approval decisions for oil and gas projects in unincorporated Kern County. We cannot predict how long it will
take Kern County to recertify the Kern County EIR or to conduct a new EIR, either of which could ultimately result
in the imposition of more onerous permit application requirements and limits on exploration and production activities.
It is not yet known how Kern County will resolve this issue, or how long it will take to do so, and we cannot predict
how long it will take or what the requirements and costs will be to obtain new permits and project approvals in the
interim. It is also not yet known whether there will be significant delays or a pause in the issuance of new permits and
approvals in unincorporated Kern County pending resolution of this issue.

With these regulatory changes in 2019, we have experienced delays in obtaining the permits required to develop 
our properties in accordance with our existing development and production plans. In late 2019 and in early 2020, we 
discontinued two drilling rigs and we are currently operating one rig. We are actively reviewing the UIC developments 
and considering the potential impacts of the Kern County Ruling, as well as our internal internal processes. As part of 
a contingency plan, we are preparing our internal resources to support a more time-intensive and burdensome permitting 
application  process  and  the  potential  environmental  impact  review  requirements  to  mitigate  the  impact  to  our 
development and production plans. If we are unable to obtain the required permits on a timely basis or at all, we may 
not be able to continue operating this one rig or to redeploy the other two as planned. If we are unable to employ these 
rigs on a timely basis, or at all, or execute our drilling program, our financial and operating results could be adversely 
affected. 

36

Our operations may also be adversely affected by seasonal or permanent restrictions on drilling activities designed 
to  protect  various  wildlife.  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 2019 we paid $27 million in 
asset retirement obligations, an increase from $8 million in 2018, largely due to the new idle well regulations and our 
focus on EH&S as we develop 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  or  proposed  new  or  more  stringent  requirements  for 
permitting, well construction and public disclosure or environmental review of, or restrictions on, oil and natural gas 
operations. 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.

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 such 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. Our commodity-price risk-management 
activities 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.

37

As of December 31, 2019, we have hedged crude oil production at the following approximate volumes and Brent 
prices: 16.7 MBbl/d at $64 per barrel in 2020, and 1.0 MBbl/d at $59 per barrel in 2021. We have also hedged gas 
purchases at the following approximate volumes and prices: 51.7 MMbtu/d at $2.95 per in 2020, and 1.2 MMbtu/d at 
$2.50 in 2021. 

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.

Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved 
reserves and future net cash flows may prove to be lower than estimated. 

Estimation of reserves and related future net cash flows is a partially subjective process of estimating accumulations 
of oil and natural gas that includes many uncertainties. Our estimates are based on various assumptions, which may 
ultimately prove to be inaccurate, including:

•

•

•

•

•

•

•

the similarity of reservoir performance in other areas to expected performance from our assets;

the quality, quantity and interpretation of available relevant data;

commodity prices (see “—Oil, natural gas and NGL prices are volatile and directly affect our results.”);

production, operating costs, taxes and costs related to GHG regulations;

development costs;

the effects of government regulations; and

future workover and asset retirement costs.

Misunderstanding  these  variables,  inaccurate  assumptions,  changed  circumstances  or  new  information  could

require us to make significant negative reserves revisions.

We currently expect improved recovery, extensions and discoveries and, potentially acquisitions, to be our main 
sources for reserves additions. However, factors such as the availability of capital, geology, government regulations 
and permits, the effectiveness of development plans and other factors could affect the source or quantity of future 
reserves additions. Any material inaccuracies in our reserves estimates could materially affect the net present value of 
our reserves, which could adversely affect our borrowing base and liquidity under the RBL Facility, as well as our 
results of operations.

Unless we replace oil and natural gas reserves, our future reserves and production will decline.

Unless  we  conduct  successful  development  and  exploration  activities  or  acquire  properties  containing  proved 
reserves, our proved reserves will decline as those reserves are produced. Success requires us to deploy sufficient capital 
to projects that are geologically and economically attractive which is subject to the capital, development, operating and 
regulatory risks already discussed above under the heading “—Our business requires continual capital expenditures. 
We may be unable to fund these investments through operating cash flow or obtain any needed additional capital on 
satisfactory terms or at all, which could lead to a decline in our oil and natural gas reserves or production. Our capital 
program  is  also  susceptible  to  risks,  including  regulatory  and  permitting  risks,  that  could  materially  affect  its 
implementation.” 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.

38

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely 
affect our business.

The success of our development, production and acquisition activities are subject to numerous risks beyond our 
control, including the risk that drilling will not result in commercially viable production or may result in a downward 
revision of our estimated proved reserves due to:

•

•

•

•

poor production response;

ineffective application of recovery techniques;

increased costs of drilling, completing, stimulating, equipping, operating, maintaining and abandoning wells;

delays  or  cost  overruns  caused  by  equipment  failures,  accidents,  environmental  hazards,  adverse  weather
conditions, permitting or construction delays, title disputes, surface access disputes and other matters; and

• misinterpretation of geophysical and geological analyses, production data and engineering studies.

Additional factors may delay or cancel our operations, including:

•

•

•

•

•

delays due to regulatory requirements and procedures, including unavailability or other restrictions limiting
permits and limitations on water disposal, emission of GHGs, steam injection and well stimulation, such as
California’s recent limitations on cyclic steaming above the fracture gradient;

pressure or irregularities in geological formations;

shortages of or delays in obtaining equipment, qualified personnel or supplies including water for steam used
in production or pressure maintenance;

delays in access to production or pipeline transmission facilities; and

power outages imposed by utilities which provide a portion of our electricity needs in order to avoid fire
hazards and inspect lines in connection with seasonal strong winds, have begun to occur recently and may
impact our operations.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to property, reserves 

and equipment, pollution, environmental contamination and regulatory penalties.

We may not drill our identified sites at the times we scheduled or at all. 

We have specifically identified locations for drilling over the next several years, which represent a significant part 
of our long-term growth strategy. Our actual drilling activities may materially differ from those presently identified. 
Legislative and regulatory developments, such as the California moratorium on approval of new high-pressure cyclic 
steam wells pending a study of the practice to address surface expressions experienced by certain operators, could 
prevent us from planned drilling activities.  Additionally, as we experienced late in the fourth quarter and continuing 
to date, new regulations and legislative activity could result in a significant decline in the permits required to develop 
our properties in accordance with our plans. If future drilling results in these projects do not establish sufficient reserves 
to  achieve  an  economic  return,  we  may  curtail  drilling  or  development  of  these  projects. Accordingly,  we  cannot 
guarantee that these prospective drilling locations or any other drilling locations we have identified will ever be drilled 
or if we will be able to economically produce oil or natural gas from these drilling locations. In addition, some of our 
leases could 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 13% of our total net acreage at December 31, 2019.

39

Potential future legislation may generally affect the taxation of natural gas and oil exploration and development 
companies and may adversely affect our operations.

In past years, federal and state level legislation has been proposed that would, if enacted into law, make significant 
changes to tax laws, including to certain key U.S. federal and state income tax provisions currently available to natural 
gas and oil exploration and development companies.

For example, 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.

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 2020 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 five cogeneration facilities that, combined, provide approximately 22% of our steam capacity 
and approximately 48% 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 three 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 2019 
electricity sales decreased by $6 million, or 17%, due to lower unit sales resulting from unexpected downtime at our 
largest cogen during the summer when we receive peak pricing, and lower 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.”

40

Our existing debt agreements have restrictive covenants that could limit our growth, financial flexibility and our 
ability to engage in certain activities. In addition, the borrowing base under the RBL Facility is subject to periodic 
redeterminations and our lenders could reduce capital available to us for investment.

The RBL Facility and the indenture governing our 2026 Notes have restrictive covenants that could limit our 
growth, financial flexibility and our ability to engage in activities that may be in our long-term best interests. Failure 
to comply with these covenants could result in an event of default that, if not cured or waived, could result in the 
acceleration of all of our indebtedness. The amount available to be borrowed under the RBL Facility is subject to a 
borrowing base, which will be redetermined semiannually and will depend on the estimated volumes and cash flows 
of our proved oil and natural gas reserves and other information deemed relevant by the administrative agent of, or 
two-thirds of the lenders under, the RBL facility. Reduction of our borrowing base under the RBL Facility could reduce 
the capital available to us for investment in our business. For details regarding the terms of the RBL Facility and our 
2026 Notes, see "Liquidity and Capital Resources". 

These agreements contain covenants, that, among other things, limit our ability to:

•

•

•

incur or guarantee additional indebtedness or issue certain types of preferred stock;

pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;

transfer, sell or dispose of assets;

• make investments;

•

•

•

•

•

•

•

create certain liens securing indebtedness;

enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;

consolidate, merge or transfer all or substantially all of our assets;

hedge future production or interest rates;

repay or prepay certain indebtedness prior to the due date;

engage in transactions with affiliates; and

engage in certain other transactions without the prior consent of the lenders.

In addition, the RBL Facility requires us to maintain certain financial ratios or to reduce our indebtedness if we
are unable to comply with such ratios, which may limit our ability to borrow funds to withstand a future downturn in 
our business, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage 
of business opportunities that arise because of these limitations.

Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could 
result in the acceleration of all of our indebtedness. If that occurs, we may not be able to make all of the required 
payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, 
it may not be on terms that are acceptable to us.

The amount available to be borrowed under the RBL Facility is subject to a borrowing base and will be redetermined 
semiannually and will depend on the estimated volumes and cash flows of our proved oil and natural gas reserves and 
other information deemed relevant by the administrative agent of, or two-thirds of the lenders under, the RBL Facility. 
We, the administrative agent and lenders, each may request one additional redetermination between each regularly 
scheduled redetermination. Furthermore, our borrowing base is subject to automatic reductions due to certain asset 
sales and hedge terminations, the incurrence of certain other debt and other events as provided in the RBL Facility. For 
example, the RBL Facility currently provides that to the extent we incur certain unsecured indebtedness, our borrowing 
base will be reduced by an amount equal to 25% of the amount of such unsecured debt that exceeds the amount, if any, 
of certain other debt that is being refinanced by such unsecured debt. We could be required to repay a portion of the 
RBL Facility to the extent that after a redetermination our outstanding borrowings at such time exceed the redetermined 

41

borrowing base. Currently, we have elected to limit the amount we can borrow under the RBL Facility to an amount 
well below our borrowing base. 

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.

Our ability to make scheduled payments on or to refinance our debt obligations, including the RBL Facility and 
our 2026 Notes, depends on our financial condition and operating performance, which are subject to prevailing economic 
and competitive conditions and certain financial, business and other factors that may be beyond our control. If oil and 
natural gas prices were to deteriorate and remain at low levels for an extended period of time, our cash flows from 
operating activities may be insufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. 
In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might 
be required to dispose of material assets or operations to meet debt service and other obligations. The RBL Facility and 
our 2026 Notes currently restrict our ability to dispose of assets and our use of the proceeds from any such disposition. 
We may not be able to consummate dispositions, and the proceeds of any such disposition may not be adequate to meet 
any debt service obligations then due.

Declines in commodity prices, changes in expected capital development, increases in operating costs or adverse 
changes in well performance may result in write-downs of the carrying amounts of our assets.

We evaluate the impairment of our oil and natural gas properties whenever events or changes in circumstances 
indicate that the carrying value may not be recoverable. Based on specific market factors and circumstances at the time 
of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics 
and other factors, we may be required to write down the carrying value of our properties. A write down constitutes a 
non-cash charge to earnings. For example, for the year ended December 31, 2019, we recorded an impairment charge 
of $51 million for the Piceance gas properties in Colorado. 

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, 2019, sales to Andeavor, Phillips 66 and Kern Oil & Refining accounted for approximately 36%, 24%
and 13%, 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.

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.  This  geographic  concentration  disproportionately  affects  the  success  and 
profitability of our operations exposing us to local price fluctuations, changes in state or regional laws and regulations, 
political risks, limited acquisition opportunities where we have the most operating experience and infrastructure, limited 
storage options, drought conditions, and other regional supply and demand factors, including gathering, pipeline and 
transportation  capacity  constraints,  limited  potential  customers,  infrastructure  capacity  and  availability  of  rigs, 
equipment, oil field services, supplies and labor. We discuss such specific risks in more detail elsewhere in this section. 

42

Many of our operations are currently conducted in locations in California that may be at risk of damage from fire, 
mudslides, earthquakes or other natural disasters.

We currently conduct operations in California near known wildfire and mudslide areas and earthquake fault zones. 
A future natural disaster, such as a fire, mudslide or an earthquake, could cause substantial delays in our operations, 
damage or destroy equipment, prevent or delay transport of our products and cause us to incur additional expenses, 
which would adversely affect our business, financial condition and results of operations. In addition, our facilities 
would be difficult to replace and would require substantial lead time to repair or replace. These events could occur with 
greater  frequency  as  a  result  of  the  potential  impacts  from  climate  change.  The  insurance  we  maintain  against 
earthquakes, mudslides, fires and other natural disasters would not be adequate to cover a total loss of our facilities, 
may not be adequate to cover our losses in any particular case and may not continue to be available to us on acceptable 
terms, or at all.

Operational issues and inability or unwillingness of third parties to provide sufficient facilities and services to us 
on commercially reasonable terms or otherwise could restrict access to markets for the commodities we produce.

Our ability to market our production of oil, gas and NGLs depends on a number of factors, including the proximity 
of production fields to pipelines, refineries and terminal facilities, competition for capacity on such facilities, damage, 
shutdowns and turnarounds at such facilities and their ability to gather, transport or process our production. If these 
facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some 
production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. 
We rely, and expect to rely in the future, on third party facilities for services such as storage, processing and transmission 
of our production. Our plans to develop and sell our reserves could be materially and adversely affected by the inability 
or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or 
otherwise. If our access to markets for commodities we produce is restricted, our costs could increase and our expected 
production growth may be impaired.

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 exploration and production activities, 
and reduce demand for the oil and natural gas we produce.

The threat of climate change continues to attract considerable attention in the United States and in foreign countries. 
Numerous proposals have been made and could continue to be made at the international, national, regional and state 
levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future 
emissions. As a result, our oil and natural gas exploration and production operations are subject to a series of regulatory, 

43

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,  implement  New  Source  Performance  Standards  directing  the 
reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together 
with the 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 emissions. 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. Similar regulations applicable to oil 
and gas facilities have been promulgated in Colorado.  

In September 2018, California adopted a law committing California , the fifth largest economy in the world, to the 
use of 100% zero-carbon electricity by 2045, and the Governor of California also signed an executive order committing 
California to total economy-wide carbon neutrality by 2045. 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, and therefore adversely effect our revenues and results of operations.

At the international level, there is a non-binding agreement, the United Nations-sponsored “Paris Agreement,” for 
nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020. 
Although the United States has announced its withdrawal from such agreement, effective November 4, 2020, several 
U.S. states and local governments have announced their intention to adhere to the goals of the Paris Agreement.

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 seeking the office of the President of the United States in 2020.  Two critical declarations made by one or 
more candidates running for the Democratic nomination for President include threats to take actions banning hydraulic 
fracturing of oil and natural gas wells and banning new leases for production of minerals on federal properties.  Our 
operations involve the use of hydraulic fracturing activities and we also have operations on federal lands under the 
jurisdiction of the BLM.  Other actions that could be pursued by presidential candidates may include more restrictive 
requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as the 
reversal of the United States’ withdrawal from the Paris Agreement in November 2020.  

Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit 
against the largest oil and natural gas exploration and production 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 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 

44

funding for fossil fuel energy companies.  Additionally, the lending practices of institutional lenders have been the 
subject of intensive lobbying efforts in recent years by environmental activists, proponents of the international Paris 
Agreement,  and  other  groups  concerned  about  climate  change  to  restrict  fossil  fuel  producers’  access  to  capital. 
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.

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. 

We may incur substantial losses and be subject to substantial liability claims as a result of catastrophic events. We 
may not be insured for, or our insurance may be inadequate to protect us against, these risks. 

We are not fully insured against all risks. Our oil and natural gas exploration and production activities, are subject 
to risks such as fires, explosions, oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized 
discharges of  brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface 
environment,  equipment  failures  and  industrial  accidents.  We  are  exposed  to  similar  risks  indirectly  through  our 
customers  and  other  market  participants  such  as  refiners.  Other  catastrophic  events  such  as  earthquakes,  floods, 
mudslides, fires, droughts, contagious diseases, terrorist attacks and other events that cause operations to cease or be 
curtailed may adversely affect our business and the communities in which we operate. For example, utilities have begun 
to suspend electric services to avoid wildfires during windy periods in California, a risk that is not insured. We may be 
unable to obtain, or may elect not to obtain, insurance for certain risks if we believe that the cost of available insurance 
is excessive relative to the risks presented.

We may be involved in legal proceedings that could result in substantial liabilities.

Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, 
such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage 
matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot 
be predicted. Regardless of the outcome, such proceedings could have a material adverse impact on us because of legal 
costs, diversion of the attention of management and other personnel and other factors. In addition, resolution of one or 
more such proceedings could result in liability, loss of contractual or other rights, penalties or sanctions, as well as 
judgments, consent decrees or orders requiring a change in our business practices. Accruals for such liability, penalties 
or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal 
and other proceedings could change materially from one period to the next.

The loss of senior management or technical personnel could adversely affect operations.

We depend on, and could be deprived of, the services of our senior management and technical personnel. We do 

not maintain, nor do we plan to obtain, any insurance against the loss of services of any of these individuals. 

Information technology failures and cyberattacks could affect us significantly.

We rely on electronic systems and networks to communicate, control and manage our operations and prepare our 
financial management and reporting information. Without accurate data from and access to these systems and networks, 
our ability to communicate and control and manage our business could be adversely affected.

45

We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information 
or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-party facilities 
and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Our implementation of various 
procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities 
and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such 
procedures and controls will be sufficient to prevent security breaches from occurring. If security breaches were to 
occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations. 
If we were to experience an attack and our security measures failed, the potential consequences to our business and the 
communities in which we operate could be significant and could harm our reputation and lead to financial losses from 
remedial actions, loss of business or potential liability.

Risks Related to our Capital Stock

There may be circumstances in which the interests of our significant stockholders could be in conflict with the 
interests of our other stockholders. 

A  large  portion  of  our  common  stock  is  beneficially  owned  by  a  relatively  small  number  of  stockholders. 
Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, 
divestitures, hostile takeovers or other transactions, including the payment of dividends or the issuance of additional 
equity or debt, that, in their judgment, could enhance their investment in us or in another company in which they invest. 
Such  transactions  might  adversely  affect  us  or  other  holders  of  our  common  stock.  In  addition,  our  significant 
concentration of share ownership may adversely affect the trading price of our common stock because investors may 
perceive disadvantages in owning shares in companies with significant stockholder concentrations.

Our significant stockholders and their affiliates are not limited in their ability to compete with us, and the corporate 
opportunity provisions in the Certificate of Incorporation could enable our significant stockholders to benefit from 
corporate opportunities that might otherwise be available to us.

Our governing documents provide that our stockholders and their affiliates are not restricted from owning assets 
or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable 
law, the Certificate of Incorporation, among other things:

•

•

permits stockholders to make investments in competing businesses; and

provides that if one of our directors who is also an employee, officer or director of a stockholder (a “Dual
Role Person”), becomes aware of a potential business opportunity, transaction or other matter, they will have
no duty to communicate or offer that opportunity to us.

Our director who is a Dual Role Person may become aware, from time to time, of certain business opportunities 
(such as acquisition opportunities) and may direct such opportunities to other businesses in which our stockholders 
have invested, in which case we may not become aware of, or otherwise have the ability to pursue, such opportunity. 
Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities 
to be unavailable to us or causing them to be more expensive for us to pursue. 

Future sales of our common stock in the public market could reduce our stock price, and any additional capital 
raised by us through the sale of equity or convertible securities may dilute your ownership in us.

Certain of our largest stockholders comprised creditors of Berry LLC prior to the Chapter 11 Proceedings and we 
cannot predict when or whether they will sell their shares of common stock. Future sales, or concerns about them, may 
put downward pressure on the market price of our common stock

We may sell or otherwise issue additional shares of common stock or securities convertible into shares of our 
common stock. Berry Corp.'s Certificate of Incorporation provides for authorized capital stock consisting of 750,000,000 

46

shares of common stock and 250,000,000 shares of preferred stock. In addition, we registered shares of the great majority 
of our common stock for resale. For more information see Exhibit 4.4 to our Annual Report on Form 10-K. 

The issuance of any securities for acquisitions, financing, upon conversion or exercise of convertible securities, 
or otherwise may result in a reduction of the book value and market price of our outstanding common stock. If we issue 
any such additional securities, the issuance will cause a reduction in the proportionate ownership and voting power of 
all current stockholders. We cannot predict the size of any future issuances of our common stock or securities convertible 
into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the 
market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in 
connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market 
prices of our common stock.

Shares of our common stock are also reserved for issuance as equity-based awards to employees, directors and 
certain other persons under the second amended and restated 2017 Omnibus Incentive Plan (our “Omnibus Plan”). We 
have filed a registration statement with the SEC on Form S-8 providing for the registration of shares of our common 
stock issued or reserved for issuance under our Omnibus Plan. Subject to the satisfaction of vesting conditions, the 
expiration of certain lock-up agreements and the requirements of Rule 144, shares registered under the registration 
statement on Form S-8 may be made available for resale immediately in the public market without restriction. Investors 
may experience dilution in the value of their investment upon the exercise of any equity awards that may be granted 
or issued pursuant to the Omnibus Plan in the future.

The payment of dividends will be at the discretion of our Board of Directors.

While we have regularly declared a quarterly dividend since our July IPO, including a dividend of $0.12  per share 
for the first quarter of 2020, and we currently intend to continue to pay a dividend , the payment and amount of future 
dividend payments, if any, are subject to declaration by our Board of Directors. Such payments will depend on various 
factors, including actual results of operations, liquidity and financial condition, net cash provided by operating activities, 
restrictions imposed by applicable law, our taxable income, our operating expenses and other factors our board of 
directors deems relevant. Covenants contained in our RBL Facility and the indentures governing our 2026 Notes could 
limit the payment of dividends. We are under no obligation to make dividend payments on our common stock and may 
cease such payments at any time in the future.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

The 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.

We are an “emerging growth company,” and are able take advantage of reduced disclosure requirements applicable 
to “emerging growth companies,” which could make our common stock less attractive to investors.

We are an “emerging growth company” and, for as long as we continue to be an “emerging growth company,” we 
intend  to  take  advantage  of  certain  exemptions  from  various  reporting  requirements,  including  auditor  attestation 
requirements or any new requirements adopted by the Public Company Accounting Oversight Board (the “PCAOB”) 
requiring  mandatory  audit  firm  rotation,  reduced  disclosure  obligations  regarding  executive  compensation  in  our 
periodic reports and proxy statements and exemptions from the requirements of holding a non-binding advisory vote 
on executive compensation and stockholder approval of any golden parachute payments not previously approved. We 
could be an “emerging growth company” for up to five years, or until the earliest of (i) the last day of the first fiscal 
year in which our annual gross revenues exceed $1.07 billion, (ii) as of the end of the fiscal year that we become a 

47

“large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended (the “Exchange 
Act”), which would occur if the market value of our common stock that is held by non-affiliates exceeds $700 million 
as of the last business day of our most recently completed second fiscal quarter, or (iii) the date on which we have 
issued more than $1 billion in non-convertible debt during the preceding three-year period.

We intend to take advantage of the reduced reporting requirements and exemptions, including the longer phase-
in periods for the adoption of new or revised financial accounting standards which lasts until those standards apply to 
private companies or we no longer qualify as an emerging growth company. Our election to use the phase-in periods 
permitted by this election may make it difficult to compare our financial statements to those companies who will comply 
with new or revised financial accounting standards. If we were to subsequently elect instead to comply with these public 
company effective dates, such election would be irrevocable.

To the extent investors find our common stock less attractive as a result of our reduced reporting and exemptions, 

there may be a less active trading market for our common stock, and our stock price may be more volatile.

Our internal control over financial reporting is not currently required to meet all of the standards required by Section 
404 of the Sarbanes-Oxley Act, but failure to achieve and maintain effective internal control over financial reporting 
in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our business and 
share price.

Section 404 of the Sarbanes-Oxley Act requires us to provide annual management assessments of the effectiveness 
of our internal control over financial reporting. However, our independent registered public accounting firm will not 
be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the 
Sarbanes-Oxley Act until we are no longer an “emerging growth company,” which could be up to five years from our 
IPO.

Effective  internal  controls  are  necessary  for  us  to  provide  reliable  financial  reports,  safeguard  our  assets,  and 
prevent fraud. If we cannot provide reliable financial reports, safeguard our assets or prevent fraud, our reputation and 
operating results could be harmed. The rules governing the standards that must be met for our management to assess 
our internal control over financial reporting are complex and require significant documentation, testing and possible 
remediation.

We may encounter problems or delays in completing the implementation of effective internal controls. Further, 
failure to achieve and maintain an effective internal control environment could have a material adverse effect on our 
business and share price and could limit our ability to report our financial results accurately and timely.

Certain provisions of our Certificate of Incorporation and Bylaws, may make it difficult for stockholders to change 
the composition of our board of directors and may discourage, delay or prevent a merger or acquisition that some 
stockholders may consider beneficial.

Certain provisions of the 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, the Certificate of Incorporation and Bylaws include provisions that (i) authorize our board of directors 
to issue “blank check” preferred stock and to determine the price and other terms, including preferences and voting 
rights, of those shares without stockholder approval and (ii) establish advance notice procedures for nominating directors 
or presenting matters at stockholder meetings. 

These provisions could enable the board of directors 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 of directors, which is responsible for appointing the members of our management.

48

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.

Changes in the method of determining London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR 
with an alternative reference rate, may adversely affect interest expense related to outstanding debt.

Amounts  drawn  under  the  RBL  Facility  may  bear  interest  rates  in  relation  to  LIBOR,  depending  on  our 
selection  of  repayment  options.  On  July  27,  2017,  the  Financial  Conduct  Authority  in  the  U.K.  announced  that  it 
would phase out  LIBOR  as  a  benchmark  by  the  end  of  2021.  It  is  unclear  whether  new  methods  of  calculating 
LIBOR  will  be  established  such  that  it  continues  to  exist  after  2021.  If  LIBOR  ceases  to  exist,  we  may  need  to 
renegotiate the RBL Facility and may not be able to do so with terms that are favorable to us. The overall financial 
market may be disrupted as a result of the phase-out or replacement of LIBOR. 

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.

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.

49

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 Global Select Market ("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 33 stockholders of record at January 31, 2020.

Dividend Policy

We plan to use our operating cash flows to cover our interest requirements, fund  operations at sustained production 
levels, and consistently return meaningful capital to stockholders through quarterly dividends. We expect remaining 
cash flows will be allocated to fund internal growth opportunities. Our dividends will be determined by our board of 
directors in light of existing conditions, including our earnings, financial condition, restrictions in financing agreements, 
business conditions and other factors. 

Securities Authorized for Issuance Under Equity Compensation Plans 

On  June 27,  2018,  our  Board  approved  our  second  amended  and  restated  2017  Omnibus  Incentive  Plan  (the 
“Omnibus Plan”). A description of the plans can be found in Item 8. Financial Statements and Supplementary Data – 
Note  6–Equity. The  aggregate  number  of  shares  of  our  common  stock  authorized  for  issuance  under  stock-based 
compensation plans for our employees and non-employee directors is 10 million, of which 3.0 million have been issued 
or reserved through December 31, 2019.

The following table summarizes information related to our equity compensation plans under which our equity 

securities are authorized for issuance as of December 31, 2019. 

Plan Category

Equity compensation plans not 

approved by security 
holders(2)

Number of Securities to be 
Issued Upon Exercise of 
Outstanding Options and 
Rights (#)(1)

Weighted-Average Exercise
Price of Outstanding Options
and Rights ($)

Number of Securities 
Remaining Available for 
Future Issuance Under Equity 
Compensation Plans (#)(3)

2,348,334

N/A

6,954,454

________________
(cid:11)(cid:20)(cid:12) The number of securities to be issued upon vesting of unvested restricted stock units ("RSUs") subject to time vesting and performance-based(cid:3)

(cid:11)(cid:21)(cid:12)

restricted stock units ("PSUs"), assumes maximum achievement of certain market-based performance goals over a specified period of time(cid:17)
In connection with the IPO, our Board amended and restated the Company’s First Amended and Restated 2017 Omnibus Incentive Plan, which 
had amended and restated the Company’s 2017 Omnibus Incentive Plan (the “Prior Plans” and, collectively with the Omnibus Plan, the “Equity(cid:3)
Compensation Plans”), which allowed us to grant equity-based compensation awards with respect to up to 10,000,000 shares of common stock 
(which number includes the number of shares of common stock previously issued pursuant to an award (or made subject to an award that has 
not expired or been terminated) under the Prior Plans), to employees, consultants and directors of the Company and its affiliates who perform(cid:3)
services for the Company. The Omnibus Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock 
units, stock awards, dividend equivalents and other types of awards. 

(cid:11)(cid:22)(cid:12) The number of securities remaining available for future issuances has been reduced by the number of securities to be issued upon settlement 
of RSUs subject to time vesting and PSUs assuming maximum achievement of certain market-based performance goals over a specified period(cid:3)
of time(cid:17)

50

Sales of Unregistered Securities

In February 2019, we issued and sold 350,000 shares of our common stock to Berry LLC at par value for aggregate 
consideration of $350, and Berry LLC agreed to issue those shares on our behalf in satisfaction of any liability arising 
from the remaining unsecured claim pending related to the Chapter 11 Proceeding. The shares were issued pursuant to 
an exemption from registration under Section 1145(a) of the U.S. Bankruptcy Code. 

Stock Repurchase Program

In  December  2018,  we  announced  that  our  Board  of  Directors  had  adopted  a  program  for  the  opportunistic 
repurchase of up to $100 million of our common stock. Based on the Board’s evaluation of market conditions for our 
common stock they authorized repurchases of up to $50 million under the program at that time. Purchases may be made 
from time to time in the open market, in privately negotiated transactions or otherwise. The manner, timing and amount 
of  any  purchases  will  be  determined  based  on  our  evaluation  of  market  conditions,  stock  price,  compliance  with 
outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not 
obligate Berry Corp. to purchase shares during any period or at all. Any shares acquired will be available for general 
corporate purposes. As of December 31, 2019, we had purchased shares for the full $50 million initially authorized. In 
February 2020, the Board of Directors authorized the remaining $50 million of our $100 million repurchase program.

Our share repurchase activities for the three months ended December 31, 2019, were as follows:

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, 2019

November 1 - 30, 2019

December 1 - 31, 2019

Total

— $

1,252,696

156,163

1,408,859

$

$

$

—

7.60

7.98

7.64

—

1,252,696

156,163

1,408,859

$

—

In 2019, the Company repurchased 4,609,021 shares at an average price of $9.99. Since 2018, the Company has 
repurchased a total of 5,057,682 shares at an average price of $9.88 per share under the Stock Repurchase Program.

Performance Graph

The following graph compares the cumulative total return to stockholders on our common stock relative to the 
cumulative total returns of the S&P Smallcap 600, the Dow Jones U.S. Exploration and Production indexes and the 
Vanguard Energy ETF (with reinvestment of all dividends). The graph assumes that on July 26, 2018, the date our 
common stock began trading on the NASDAQ, $100 was invested in our common stock and in each index, and that 
all dividends were reinvested. The returns shown are based on historical results and are not intended to suggest future 
performance.

51

COMPARISON OF CUMULATIVE TOTAL RETURN(1)(2)
Among Berry Corporation (bry), the S&P Smallcap 600 Index, 
the Dow Jones U.S. Exploration & Production Index 
and the Vanguard Energy ETF

7/26/18

09/18

12/18

03/19

06/19

09/19

12/19

Berry Corporation (bry)

$ 100.00

$ 133.73

S&P Smallcap 600

$ 100.00

$ 104.71

Dow Jones U.S. Exploration & Production

$ 100.00

$ 102.81

Vanguard Energy ETF

$ 100.00

$

99.64

$

$

$

$

67.17

83.66

71.18

73.67

$

$

$

$

89.50

93.37

80.30

86.02

$

$

$

$

83.16

95.12

78.12

82.49

$

$

$

$

74.34

$

75.90

94.93

$ 102.72

72.14

76.35

$

$

79.29

80.50

__________
(1) The performance graph shall not be deemed “soliciting material” or to be “filed” with the SEC for purposes of Section 18 of the Exchange
Act, or otherwise subject to the liabilities under that Section, and shall not be deemed to be incorporated by reference into any filing of the
Company under the Securities Act of 1933, as amended (the "Securities Act") or the Exchange Act except to the extent that we specifically 
request it be treated as soliciting material or specifically incorporate it by reference.
$100 invested on July 26, 2018 in stock or June 30, 2018 in index, including reinvestment of dividends.

(2)

52

Item 6. Selected Financial Data

The following table shows the selected historical financial information, for the periods and as of the dates indicated, 
of Berry LLC, the predecessor company, and following the Effective Date, Berry Corp. and its subsidiary, Berry LLC, 
together, the successor company. The selected historical financial information as of and for the year ended December 
31, 2019, the year ended December 31, 2018, and the ten months ended December 31, 2017 is derived from audited 
consolidated financial statements of the successor company. The selected historical financial information as of and for 
the two months ended February 28, 2017 and the year ended December 31, 2016 is derived from the audited historical 
financial statements of our predecessor company. 

Berry LLC emerged from bankruptcy on February 28, 2017 ("the Effective Date") in connection with "the Plan", 
which is the reorganization plan approved and confirmed by the Bankruptcy Court in the Chapter 11 Proceeding.  On 
that date Berry LLC adopted fresh-start accounting and was recapitalized, which resulted in Berry LLC becoming a 
wholly-owned subsidiary of Berry Corp. and Berry Corp. being treated as the new entity for financial reporting. As a 
result,  our  consolidated  financial  statements  subsequent  to  the  Effective  Date  are  not  comparable  to  our  financial 
statements prior to such date. Our financial results for future periods following the application of fresh-start accounting 
will be different from historical trends and the differences may be material. 

Berry Corp.
(Successor)

Berry LLC 
(Predecessor)

Year Ended
December 31,
2019

Year Ended
December 31,
2018

Ten Months
Ended
December 31,
2017

Two Months
Ended
February 28,
2017

Year Ended
December 31,
2016

(in thousands, except per share amounts)

Statements of Operations Data:

Revenues and other

Net income (loss) attributable to common 

stockholders(1)(4)

Net income (loss) per share of common

stock
Basic

Diluted

Dividends per common share

Weighted-average common stock 

outstanding(2)
Basic
Diluted(2)

Cash Flow Data:

Operating activities(3)
Capital expenditures

Balance Sheet Data (at period end):

Total assets

Long-term debt, net

$

$

$

$

$

$

$

559,405

43,539

0.54

0.53

0.48

$

$

$

$

$

586,557

49,160

0.85

0.85

0.21

$

$

$

$

$

319,669

(39,316)

$

$

92,718

$

410,991

(502,964) $ (1,283,196)

(1.02)

(1.02)

n/a

n/a

— $

— $

81,379

81,951

57,743

57,932

38,644

38,644

n/a

n/a

241,829

$

105,471

$

107,399

(223,154) $

(129,652) $

(65,479)

$

$

22,431

$

13,197

(3,158) $

(34,796)

$ 1,690,198

$ 1,692,263

$ 1,546,402

$ 1,561,038

$ 2,652,050

$

394,319

$

391,786

$

379,000

$

400,000

$

—

n/a

n/a

—

n/a

n/a

__________
(cid:11)(cid:20)(cid:12) Refer  to  “Item  7.  Management's  Discussion  and Analysis  of  Financial  Condition  and  Results  of  Operations—Results  of  Operations”  for(cid:3)

discussion regarding factors in comparability, such as, impairment of its Piceance gas properties and income taxes in 2019. 

(cid:11)(cid:21)(cid:12) The Series A Preferred Stock was not a participating security; therefore, we calculated diluted earnings per share using the “if-converted”(cid:3)
method, under which the preferred dividends are added back to the numerator and the Series A Preferred Stock is assumed to be converted at(cid:3)
the beginning of the period. No incremental shares of Series A Preferred Stock were included in the diluted EPS calculation for the years ended(cid:3)
December 31, 2019 or 2018, as all outstanding shares of our Series A Preferred (the "Series A Preferred Stock") were converted to common 
shares (the "Series A Preferred Stock Conversion") in connection with the IPO of our common stock in July 2018. No incremental shares of(cid:3)
Series A Preferred Stock were included in the diluted earnings per share calculation for the ten months ended December 31, 2017 as their effect(cid:3)
was antidilutive under the “if-converted” method. Please see Note 6 for further detail.

53

(cid:11)(cid:22)(cid:12)

2018 includes a one-time payment of $127 million in the second quarter to early terminate unsettled derivative contracts. The elective cancellation(cid:3)
was effected to realign our hedging pricing with current market rates and move from WTI to Brent underlying.

(cid:11)(cid:23)(cid:12) Net Income Attributable to Common Stockholders for year ended December 31, 2019 includes a $51 million non-cash impairment charge for(cid:3)

the Piceance gas properties, and $39 million in income tax credits from prior periods.

54

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 2019 and 2018 items and year-to-year comparisons between 
those years. For discussion of our ten months ended December 31, 2017 and two months ended February 28, 2017, as 
well as the year ended 2018 compared to ten months ended December 31, 2017 and two months ended February 28, 
2017,  refer  to  Part  II,  Item  7—  "Management's  Discussion  and  Analysis  of  Financial  Condition  and  Results  of 
Operations" of our 2018 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, oil reserves in conventional reservoirs. 

Most of our assets are located in the oil-rich reservoirs in the San Joaquin basin of California, which has more than 
100 years of production history and substantial remaining oil in place. As a result of the substantial data produced over 
the  basin's  long  history,  its  reservoir  characteristics  are  well  understood,  leading  to  predictable,  repeatable,  low 
geological risk and low-c and, to a lesser extent, in our Rockies assets which include low-cost, oil-rich reservoirs in 
the Uinta basin of Utah and low geologic risk natural gas resource plays in the Piceance basin in Colorado. Successful 
execution  of  our  strategy  across  our  low-declining  production  base  and  extensive  inventory  of  identified  drilling 
locations will result in our ability to continue returning capital to our stockholders and demonstrate long-term, capital 
efficient, consistent, and predictable production growth while living within levered free cash flow.

Effective  February  18,  2020,  Berry  Petroleum  Corporation  changed  its  name  to  Berry  Corporation  (bry)  and 
introduced a new logo. We believe that the name Berry Corporation (bry) is a name that better represents our progressive 
approach to evolving and growing the business in today’s dynamic oil and gas industry. We are proactively engaging 
the many forces driving our industry to maximize our assets, create value for shareholders, and support environmental 
goals that align with a more positive future. One of the more visible elements of our business is our publicly traded 
stock, and our new logo echoes the public value of the company by using our ticker symbol as an identifiable element 
of our brand.

How We Plan and Evaluate Operations

We use Levered Free Cash Flow in planning our capital allocation to sustain production levels and fund internal 
growth opportunities, as well as determine hedging needs. We define Levered Free Cash Flow as Adjusted EBITDA 
less capital expenditures, interest expense, and dividends.

We use the following metrics to manage and assess the performance of our operations and are part of our incentive 
program for all employees: (a) Adjusted EBITDA; (b) operating expenses; (c) environmental, health & safety (“EH&S”) 
results; (d) general and administrative expenses; and (e) production. 

Adjusted EBITDA

Adjusted EBITDA is the primary financial and operating measurement that our management uses to analyze and 
monitor the operating performance of our business. We define Adjusted EBITDA as earnings before interest expense; 
income taxes; depreciation, depletion, and amortization (“DD&A”); derivative gains or losses net of cash received or 

55

paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period 
and infrequent items, including restructuring costs and reorganization items.

Operating expenses

We define operating expenses as lease operating expenses, electricity generation expenses, transportation expenses, 
and  marketing  expenses,  offset  by  the  third-party  revenues  generated  by  electricity,  transportation  and  marketing 
activities, as well as the effect of derivative settlements (received or paid) for gas purchases. Lease operating expenses 
include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Taxes 
other than income taxes are excluded from operating expenses. The electricity, transportation and marketing activity 
related revenues are viewed and treated internally as a reduction to operating costs when tracking and analyzing the 
economics of development projects and the efficiency of our hydrocarbon recovery. Additionally, we strive to minimize 
the variability of our fuel gas costs for our steam operations with gas hedges. Overall, operating expense is used by 
management as a measure of the efficiency with which operations are performing.

Environmental, health & safety

Like other companies in the oil and gas industry, our operations are subject to stringent federal, state and local 
laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental 
protection. Current and future laws and regulations can materially impact our exploration, development and production 
plans.

We  are  committed  to  good  corporate  citizenship  in  our  communities,  operating  safely  and  protecting  the 
environment and our employees. We monitor our EH&S performance through various measures, holding our employees 
and contractors to high standards. 

General and administrative expenses

We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead activities. 
Such expenses are a key component of the appropriate level of support our corporate and professional team provides 
to the development of our assets and our day-to-day operations.

Production

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

Business Environment and Market Conditions 

The  oil  and  gas  industry  is  heavily  influenced  by  commodity  prices. Average  oil  prices  were  lower  for  2019 
compared to 2018 . Brent crude oil contract prices ranged during 2019 from $54.91 per Bbl at the beginning, to a high 
of $74.57 per Bbl and back to $56.23 per Bbl.  In California, the price we pay for fuel gas purchases is generally based 
on the Kern, Delivered Index, as well as the SoCal Index which were as low as $0.99 per MMBtu and as high as $22.38
per MMBtu for a short time in 2019 due to market disruptions, while we paid an average of $3.14 for the year. The 
Henry Hub spot price for natural gas fluctuated between $1.75 per MMBtu and $4.25 per MMBtu, with an average of 
$2.56 during 2019. Our revenue, costs, profitability and future growth are highly dependent on the prices we receive 
for our oil and natural gas production and the prices we pay for our natural gas purchases which will continue to be 
affected by a variety of factors. Please see “Item 1A. Risk Factors—Risks Related to Our Business and Industry—Oil, 
natural gas and NGL prices are volatile and directly affect our results.”

56

The following table presents the average Brent, WTI, Kern, and Henry Hub prices for the years ended December 31, 

2019 and 2018:

Brent oil ($/Bbl)

WTI oil ($/Bbl)

Kern, Delivered natural gas ($/MMBtu)

Henry Hub natural gas ($/MMBtu)

Year Ended

December 31, 2019

December 31, 2018

$

$

$

$

64.16

57.03

3.14

2.56

$

$

$

$

71.69

64.81

3.36

3.15

California oil prices are Brent-influenced as California refiners import approximately 73% of the state’s demand 
from OPEC countries and other waterborne sources, primarily the Middle East and South America. There is a closer 
correlation of prices in California to Brent pricing than to WTI. Without the higher costs 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, will allow us to continue to realize strong cash margins in California.

Utah oil prices have historically traded at a discount to WTI as the local refineries are designed for oil's unique 

characteristics and the remoteness of the assets makes access to other markets logistically challenging. 

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  for  which  they  are  used  as  feedstock.  In  addition,  infrastructure  constraints 
magnify pricing volatility.

Natural gas prices and differentials are strongly affected by local market fundamentals, availability of transportation 
capacity from producing areas and seasonal impacts. We purchase substantially more natural gas for our steamfloods 
and cogeneration facilities, than we produce and sell. Consequently, higher gas prices have a negative impact on our 
operating costs. However, we mitigate a portion of this exposure by selling excess electricity from our cogeneration 
operations to third parties at prices linked to the price of natural gas. Additionally, we strive to minimize the variability 
of our fuel gas costs for our steam operations by hedging a significant portion of such gas purchases. Also, the negative 
impact of higher gas prices is partially offset by higher gas sales for the gas we produce. 

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. We have negotiated terms of a 
new power purchase agreement for our 18 MW cogeneration facility which began in December 2019 for a period of 
seven years. 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 three of our cogeneration facilities under long-term 
contracts with terms ending in July 1, 2021 through December 1, 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, June through September, due to negotiated capacity payments we receive.

Natural gas prices can fluctuate based on seasonal and other market-related impacts. We purchase significantly 
more gas than we sell to generate steam and electricity in our cogeneration facilities for our producing activities. As a 
result, our key exposure to gas prices is in our costs. We mitigate a substantial portion of this exposure by selling excess 
electricity from our cogeneration operations to third parties. The pricing of these electricity sales is closely tied to the 
purchase price of natural gas. We also hedge a significant portion of the gas we expect to consume. 

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

57

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 Business and Industry”

58

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, 2019 and 2018.

December 31, 2019

December 31, 2018

Year Ended

Average daily production:(1)(3)

Oil (MBbl/d)

Natural Gas (MMcf/d)

NGLs (MBbl/d)

Total (MBoe/d)(2)

Total Production:(3)
Oil (MBbl)

Natural gas (MMcf)

NGLs (MBbl)

Total (MBoe)(2)

Weighted-average realized prices:

Oil with hedges (Bbl)

Oil without hedges (Bbl)

Natural gas (Mcf)

NGLs (Bbl)

Average Benchmark prices:

Oil (Bbl) – Brent

Oil (Bbl) – WTI
Gas (MMBtu) – Kern, Delivered(4)
Natural gas (MMBtu) – Henry Hub(5)

$

$

$

$

$

$

$

$

25.3

20.0

0.4

29.0

9,226

7,302

151

10,594

63.61

58.93

2.66

17.02

64.16

57.03

3.14

2.56

$

$

$

$

$

$

$

$

22.0

26.3

0.6

27.0

8,045

9,589

211

9,855

59.67

64.76

2.74

26.74

71.69

64.81

3.36

3.15

__________
(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, 2019, the average
prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per MMBtu respectively, resulting in an oil-to-gas ratio of
approximately 4 to 1 on an energy equivalent basis. 

(3) On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
(4) Kern, Delivered Index is the relevant index used for gas purchases in California.
(5) Henry Hub is the relevant index used for gas sales in the Rockies.

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

Average daily production (MBoe/d)(1):

California

Utah

Colorado
East Texas(2)

Total average daily production

December 31, 2019

December 31, 2018

Year Ended

22.6

5.0

1.4

—

29.0

19.7

4.9

1.7

0.7

27.0

59

__________
(1) Production represents volumes sold during the period.
(2) On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.

Average daily oil production increased 15% for the year ended December 31, 2019 compared to the year ended 
December  31,  2018.   Year-over-year  daily  overall  production  increased  7%  due  to  production  response  from  the 
development capital spending throughout 2019 and 2018, which more than offset the natural decline of our properties 
and the sale of our East Texas properties in November 2018

California production increased 15% year-over-year in response to the deployment of the substantial majority of 
our development capital. This increase strongly demonstrated the ability of our California properties to respond to 
capital investment. The 2019 development activities accelerated our California production growth during the year, 
resulting in a 17% increase from 21.7 MBoe/d in the three months ended December 31, 2018 to 25.5 MBoe/d in the 
three months ended December 31, 2019. Additionally, our 2019 capital program contributed to the increase in our 
California proved reserves of 24.5 MMBoe, or 23% before production, resulting in a 299% replacement ratio. We also 
replaced 159% of our total company proved undeveloped drilling location inventory.

The production in Utah and Colorado declined 3% year-over-year. The overall decline is primarily due to no capital 
allocated to Colorado, while there was a slight increase in Utah due to the deployed capital there. Additionally, we sold 
our East Texas gas properties in November 2018.

60

Summary by Area

The following table shows a summary by area of our selected historical financial information and operating data 

for the periods indicated.

($ in thousands, unless noted otherwise)

Oil, natural gas and natural gas liquids sales
Operating income(1)
Depreciation, depletion, and amortization

(DD&A)

Impairment of oil and gas properties

Average daily production (MBoe/d)

Production (oil % of total)

Realized sales prices:

Oil (per Bbl)

NGLs (per Bbl)

Gas (per Mcf)

Capital expenditures(2)

$

$

$

$

California
(San Joaquin and Ventura
basins)

Utah
(Uinta basin)

Colorado
(Piceance basin)

Year Ended
December
31, 2019

Year Ended
December
31, 2018

Year Ended
December
31, 2019

Year Ended
December
31, 2018

Year Ended
December
31, 2019

Year Ended
December
31, 2018

$ 498,325

$ 471,802

$ 59,383

$ 65,605

$

7,740

$ 10,657

$ 230,500

$ 185,965

$

7,624

$ 15,066

$ (48,955) $

6,346

$ 93,025

$ 72,260

$ 11,754

$ 10,420

$

1,055

— $

— $

— $

— $ 51,081

22.6

100%

19.7

100%

5.0

54%

5.0

48%

1.4

2%

$

$

646

—

1.7

1%

60.51

$

65.64

$

— $

— $

— $

— $

45.72

17.08

2.94

$

$

$

57.30

26.95

2.68

$ 191,955

$ 125,565

$ 10,229

$ 16,738

$

$

$

$

52.36

$

61.50

— $

$

$

2.26

603

1

—

2.75

613

18

Total proved reserves (MMBoe)

122

106

15

19

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

(2) Excludes corporate capital expenditures. 

Results of Operations

Year Ended
December 31,
2019

Year Ended
December 31,
2018

(in thousands)

$ Change

% Change

$

$

565,596

$

552,874

$

29,397

(37,998)

2,410

35,208

(4,621)

3,096

12,722

(5,811)

(33,377)

(686)

559,405

$

586,557

$

(27,152)

2 %

(17)%

722 %

(22)%

(5)%

Revenues and other:

Oil, natural gas and natural gas liquid sales

Electricity sales

(Losses) gains on oil derivatives

Marketing and other revenues

Total revenues and other

Revenues and Other

Oil, natural gas and NGL sales increased $13 million to $566 million for the year ended December 31, 2019 from 
$553 million for the year ended December 31, 2018.  The increase was driven by $76 million of higher oil volumes 
that was partially offset by $54 million of lower oil prices and $8 million of lower gas and natural gas liquid sales, 
mainly volume-related.

61

Electricity sales represent sales to utilities which decreased by $6 million or 17%, to approximately $29 million
for the year ended December 31, 2019 when compared to the year ended December 31, 2018. The decrease was due 
to lower unit sales that were affected by unexpected downtime at our largest cogen during the summer when we receive 
peak pricing, and lower year-over-year gas pricing.

Included in the results of our oil derivatives for the year ended December 31, 2019 were $43 million of settlement 
gains reflecting the positions that expired during the year with hedge prices below the respective Brent index prices. 
During 2019, the change in Brent prices relative to our remaining positions at year end resulted in reduced value, 
resulting in mark-to-market losses in 2019. Losses on oil derivatives were $4.6 million for the year ended December 
31, 2018. Our losses in 2018 were due to the mark-to-market losses incurred on oil derivatives prior to being terminated 
in May 2018 and settled with a $127 million payment. We terminated these derivatives and entered into new hedges 
to better align our hedge pricing with the then prevailing market pricing. These early-2018 losses were offset by gains 
on oil derivatives in the latter portion of the year, primarily due to the decline in oil prices in the fourth quarter compared 
to the higher hedge pricing.

Marketing and other revenues were comparable for the year ended December 31, 2019 and the year ended December 

31, 2018. Marketing revenues in these periods represented sales of natural gas purchased from third-parties.

Expenses and other:

Lease operating expenses

Electricity generation expenses

Transportation expenses

Marketing expenses

General and administrative expenses

Depreciation, depletion and amortization
Impairment of oil and gas properties(6)
Taxes, other than income taxes

Losses (gains) on natural gas derivatives

Other operating expense (income) 

Total expenses and other

Other income (expenses):

Interest expense

Other, net

Total other income (expenses)

Reorganization items, net

Income (loss) before income taxes

Income tax expense (benefit)

Net (loss) income

Series A Preferred Stock dividends and 

conversion to common stock

Net (loss) income attributable to common 

stockholders
Adjusted EBITDA(7)
Adjusted Net Income (Loss)(7)

Year Ended
December 31,
2019

Year Ended
December 31,
2018

(in thousands)

$

216,294

$

188,776

$

19,490

8,059

2,073

62,643

106,006

51,081

40,645

6,957

4,588

517,836

(34,234)

80

(34,154)

(426)

6,989

(36,550)

43,539

—

20,619

9,860

2,140

54,026

86,271

—

33,117

(6,357)

(2,747)

385,705

(35,648)

243

(35,405)

24,690

190,137

43,035

147,102

(97,942)

$

$
$

43,539

302,184
110,228

$

$
$

49,160

257,924
100,001

$

$
$

62

$ Change

% Change

27,518

(1,129)

(1,801)

(67)

8,617

19,735

51,081

7,528

13,314

7,335

132,131

1,414

(163)

1,251

(25,116)

(183,148)

(79,585)

(103,563)

97,942

(5,621)

44,260
10,227

15 %

(5)%

(18)%

(3)%

16 %

23 %

100 %

23 %

n/a

(267)%

34 %

(4)%

(67)%

(4)%

(102)%

(96)%

(185)%

(70)%

(100)%

(11)%

17 %
10 %

Expenses per Boe:(1)

Lease operating expenses

Electricity generation expenses

Electricity sales

Transportation expenses

Transportation sales

Marketing expenses

Marketing revenues

Gas purchase derivatives settlement (gains)

losses

Total operating expenses
Total unhedged operating expenses(2)

Total non-energy operating expenses(3)
Total energy operating expenses(4)

General and administrative expenses(5)
Depreciation, depletion and amortization

Taxes, other than income taxes

$

$

$

$

$

$

$

$

20.42

$

19.16

$

1.84

(2.77)

0.76

(0.03)

0.20

(0.20)

0.10

20.32

20.22

14.80

5.51

5.91

10.01

3.84

$

$

$

$

$

$

$

2.09

(3.57)

1.00

(0.08)

0.22

(0.24)

(0.24)

18.33

18.57

13.80

4.53

5.48

8.75

3.36

$

$

$

$

$

$

$

1.26

(0.25)

0.80

(0.24)

0.05

(0.02)

0.04

0.34

1.99

1.65

1.00

0.98

0.43

1.26

0.48

7 %

(12)%

(22)%

(24)%

(63)%

(9)%

(17)%

(142)%

11 %

9 %

7 %

22 %

8 %

14 %

14 %

__________
(1) We report electricity, transportation and marketing sales separately in our financial statements as revenues in accordance with GAAP. 

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

(2) Total unhedged operating expenses equals total operating expenses less the derivatives settlements paid for gas purchases.
(3) Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivatives 

settlement (gains) losses.

(4) Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.
(5)

Includes restructuring and other non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.08 per
Boe and $1.36 per Boe for the year ended December 31, 2019 and December 31, 2018, respectively. 

(6) For the year ended December 31, 2019, we recorded an impairment charge of $51 million for the Piceance gas properties in Colorado.
(7) Adjusted EBITDA and Adjusted Net Income (Loss) are financial measures that are not calculated in accordance with GAAP. For definitions

and a reconciliation to the Net Cash Provided by Operating Activities and Net Income (Loss), please see “Item 7 — Non-GAAP Financial
Measures”

Expenses

Operating expenses increased to $20.32 per Boe for the year ended December 31, 2019 from $18.33 for the year
ended December 31, 2018. This increase included approximately $1.26 per Boe of increased repair and maintenance 
expenses, $0.80 decreased electricity sales, and $0.18 increased hedged fuel cost. This was partially offset by $0.24 
lower transportation expense. On an unhedged basis, operating expenses increased $1.65 per Boe to $20.22 for the year 
ended December 31, 2019 from $18.57 for the year ended December 31, 2018. Operating expenses are defined above 
in "How We Plan And Evaluate Operations". 

Lease operating expenses increased $1.26 per Boe to $20.42 for the year ended December 31, 2019 from $19.16
for the year ended December 31, 2018. The increase included repair and maintenance costs of $0.66 per Boe for facility 
tanks and vessels, and $0.61 for well servicing maintenance. These increases in maintenance costs for facilities and 
wells during 2019 resulted from our continuing efforts to aggressively manage repair and maintenance activities, in 

63

particular, long-term delayed maintenance on some equipment. Lease operating expenses include fuel, maintenance, 
labor including supervision, vehicles, workover expenses, field office, and tools and supplies.

Electricity generation expenses decreased $0.25 to $1.84 per Boe for the year ended December 31, 2019 from 
$2.09 for the year ended December 31, 2018 mostly due to higher downtime and lower natural gas costs. These fuel 
costs exclude the effects of natural gas derivative settlements mentioned elsewhere.

Losses on natural gas derivatives of $7 million for the year ended December 31, 2019 included $6 million of mark-
to-market valuation losses and $1 million, or $0.10 per Boe of gas hedge settlements. For the year ended December 
31, 2018, gains on natural gas derivatives were $6 million including $4 million of mark-to-market valuation gains and 
$2 million, or $0.24 per Boe of gas hedge settlements.

In late 2018 we began hedging a portion of our internal consumption of natural gas used primarily to fuel our 
cogeneration units. Early in 2019 we increased the volume of natural gas volume hedged given the increase in natural 
gas prices at that time. Gains on natural gas derivatives in 2018 and in early 2019 reflected relatively high gas prices 
in California, compared to the strike price of our derivatives. However, the price decrease towards the end of the year 
resulted in mark-to-market hedging losses in 2019.

Transportation expenses decreased $0.24 per Boe to $0.76 for the year ended December 31, 2019 from $1.00 for 
the year ended December 31, 2018, mainly due to the impact from selling our East Texas asset during the fourth quarter 
of 2018 and lower volumes shipped from our Rockies assets.

Marketing expenses were comparable for the year ended December 31, 2019 and the year ended December 31, 
2018. Marketing expenses in these periods, which exclude the effects of hedging, represented the cost of natural gas 
purchased from third-parties.

General and administrative expenses increased by $9 million or 16%, to approximately $63 million for the year 
ended  December  31,  2019  compared  to  the  year  ended  December  31,  2018.  General  and  administrative  expenses 
included restructuring and other non-recurring costs that decreased year over year to approximately $3.1 million from 
$6.8 million due to the completion of those activities in early 2019. For the same periods non-cash stock compensation 
costs increased to approximately $8.4 million from $6.6 million due to increased headcount.

Adjusted general and administrative expenses, which exclude restructuring and other non-recurring costs and non-
cash stock compensation costs, were approximately $51 million  or $4.84 per Boe for the year ended December 31, 
2019 compared to $41 million or $4.13 per Boe for  the year ended December 31, 2018. The increases in both general 
and administrative expenses and adjusted general and administrative expenses were primarily due to increased costs 
associated with our growth and public company status, and the continuing development and growth of our corporate 
affairs department and activities whose purpose is to support our efforts and participation in the regulatory, political 
and legislative process primarily in California.

DD&A  increased  by  approximately  $20  million  or  23%,  to  approximately  $106  million,  for  the  year  ended 
December 31, 2019 compared to the year ended December 31, 2018. On a per Boe basis, DD&A increased $1.26 to 
$10.01  year  over  year  primarily  due  to  higher  2019  depreciation  and  depletion  rates  caused  by  increasing  capital 
development programs in 2018 and 2019.

Impairment of Oil and Gas Properties

At year end 2019, we evaluated our proved and unproved natural gas properties in regards to the decline in our 
expectations of future gas prices. As a result, we recorded a non-cash pre-tax asset impairment charge of $51 million for 
our Piceance gas properties in Colorado, of which $23 million was for proved properties and $28 million for unproved 
properties.  

64

Taxes, Other Than Income Taxes

Year Ended
December 31, 2019

Year Ended
December 31, 2018

$ Change

% Change

Severance taxes

Ad valorem taxes

Greenhouse gas allowances

Total taxes other than income taxes

$

$

(per Boe)

0.63

1.38

1.83

3.84

$

$

0.95

1.38

1.03

3.36

$

$

(0.32)

0.00

0.80

0.48

(34)%

0 %

78 %

14 %

Taxes, other than income taxes, increased to $3.84 per Boe for the year ended December 31, 2019 from $3.36 for 
the year ended December 31, 2018 due to higher greenhouse gas allowance costs, partially offset by lower severance 
taxes than in the year ended December 31, 2018. Greenhouse gas allowance costs increased as a result of fewer free 
allowances from the state of California and higher spot prices for those allowances purchased, both of which increased 
the average unit cost of emissions incurred. The lower severance taxes in the year ended December 31, 2019 were the 
result of increased exemptions.

Other Operating Expense (Income) 

Other operating expenses were $5 million in the year ended December 31, 2019 and mainly consisted of excess 
abandonment costs. The gains in 2018 included a $4 million gain from the sale of our East Texas property, offset by a 
$1 million loss on settlement of asset retirement obligations, largely due to a change in timing of the retirements.

Interest Expense

Interest expense decreased slightly due to less borrowings throughout 2019 compared to 2018. 

Reorganization Items, Net

Reorganization  items,  net,  consisted  of  less  than  $1  million  expense  for  the  year  ended  December  31,  2019, 
compared to $25 million of income primarily from the return of undistributed funds reserved for settlement of claims 
of general unsecured creditors for the year ended December 31, 2018.

Income Tax Expense (Benefit)

For the year ended December 31, 2019 we had an income tax benefit of approximately $37 million and for the 
year ended December 31, 2018 we had an income tax provision of approximately $43 million. The key contributor to 
the year-over-year change in income taxes and our effective rate from 23% for the year ended December 31, 2018 to 
(523)% for the year ended December 31, 2019 is due to the recognition of US federal general business credits in 2019 
and are related to the 2017 and 2018 tax periods. These credits 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.

Series A Preferred Stock dividends and conversion to common stock

There were no Series A Preferred Stock dividends in 2019. Series A Preferred Stock (the "Series A Preferred Stock") 
was converted to common stock (the "Series A Preferred Stock Conversion") in 2018 when a $60 million payment was 
made to preferred stockholders in the Series A Preferred Stock Conversion in conjunction with our IPO, and the $27 
million conversion value assigned to the additional 1.9 million shares of common stock received by the preferred 
stockholders, and $11 million of dividends paid prior to the conversion.

65

Liquidity and Capital Resources 

Currently, we expect our primary sources of liquidity and capital resources will be Levered Free Cash Flow, and 
as needed, borrowings under the RBL Facility. Depending upon market conditions and other factors, we have issued 
and may issue additional equity and debt securities; however, we expect our operations to continue to generate positive 
Levered Free Cash Flow at current commodity prices allowing us to fund operations at sustained production levels and 
organic growth. Remaining excess cash flow could be used in various ways, including additional return of capital to 
shareholders, debt repurchases, bolt-on acquisitions and maintained as cash. As of December 31, 2019, we have available 
liquidity of $391 million under our RBL Facility. We believe our liquidity and capital resources will be sufficient to 
conduct our business and operations for the next 12 months.

Cash Dividends

Our Board of Directors approved a $0.12 per share quarterly cash dividend on our common stock each quarter in 
2019. We paid the fourth quarter dividend in January 2020 and declared the first quarter 2020 dividend of $0.12 per 
share in February 2020, which is payable in April 2020. Since our IPO in July 2018 through February 2020, we have 
returned $65 million in regular quarterly dividends.

2026 Notes Offering

In February 2018, we issued our 7.0% 2026 Notes through our operating subsidiary, Berry LLC, which resulted 
in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers’ discount. We 
used the net proceeds from the issuance to repay the $379 million outstanding balance on the RBL Facility and used 
the remainder for general corporate purposes.

We may, at our option, redeem all or a portion of the 2026 Notes at any time on or after February 15, 2021. We 
are also entitled to redeem up to 35% of the aggregate principal amount of the 2026 Notes before February 15, 2021, 
with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price 
equal to 107% of the principal amount of the 2026 Notes being redeemed, plus accrued and unpaid interest, if any. In 
addition, prior to February 15, 2021, we may redeem some or all of the 2026 Notes at a price equal to 100% of the 
principal amount thereof, plus a “make-whole” premium, plus any accrued and unpaid interest. If we experience certain 
kinds of changes of control, holders of the 2026 Notes may have the right to require us to repurchase their notes at 
101% of the principal amount of the 2026 Notes, plus accrued and unpaid interest, if any.

The 2026 Notes are our senior unsecured obligations and rank equally in right of payment with all of our other 
senior  indebtedness  and  senior  to  any  of  our  subordinated  indebtedness.  The  notes  are  fully  and  unconditionally 
guaranteed on a senior unsecured basis by us and will also be guaranteed by certain of our future subsidiaries (other 
than Berry LLC). The 2026 Notes and related guarantees are effectively subordinated to all of our secured indebtedness 
(including all borrowings and other obligations under the RBL Facility) to the extent of the value of the collateral 
securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness 
and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the 2026 Notes.

The indenture governing the 2026 Notes contains restrictive covenants and customary events of default, including, 
among  others,  (a)  non-payment;  (b)  non-compliance  with  covenants  (in  some  cases,  subject  to  grace  periods);  (c) 
payment default under, or acceleration events affecting, material indebtedness and (d) bankruptcy or insolvency events 
involving us or certain of our subsidiaries.

The 2026 Notes do not restrict us from making open market and other purchases of such notes.(cid:3)

66

(cid:37)(cid:82)(cid:81)(cid:71)(cid:3)(cid:53)(cid:72)(cid:83)(cid:88)(cid:85)(cid:70)(cid:75)(cid:68)(cid:86)(cid:72)(cid:3)(cid:51)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)

In  February  2020,  our  Board  of  Directors  adopted  a  program  for  the  opportunistic  repurchase  of  up  to  $75 
million(cid:3) 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.  

The RBL Facility

On July 31, 2017, we entered into the RBL Facility. The RBL Facility provides for a revolving loan with up to 

$1.5 billion of commitments, subject to a reserve borrowing base.

The RBL Facility also provides a letter of credit subfacility for the issuance of letters of credit in an aggregate 
amount not to exceed $25 million. Issuances of letters of credit reduce the borrowing availability for revolving loans 
under the RBL Facility on a dollar for dollar basis. Borrowing base redeterminations become effective each May and 
November, although each of the administrative agent and Berry LLC may make one interim redetermination between 
scheduled redeterminations. The RBL Facility has an elected commitment feature that allows us to increase commitments 
to the amount of our borrowing base with lender approval. In late 2019, we completed a borrowing base redetermination 
under our RBL Facility that set our borrowing base to $500 million and reaffirmed our elected commitment amount 
at$400 million. The RBL Facility matures on July 29, 2022, unless terminated earlier in accordance with the  RBL 
Facility terms. As of December 31, 2019, we had approximately $7 million in letters of credit outstanding, $2 million 
borrowed  and  borrowing  availability  of  $391  million  under  the  RBL  Facility.  As  of  January  31,  2020,  we  had  no 
borrowings outstanding,  $7  million in  letters  of  credit  outstanding,  and  approximately  $393  million  of  available 
borrowings capacity under the RBL Facility. 

The outstanding borrowings under the RBL Facility bear interest at a rate equal to either (i) a customary London 
interbank offered rate plus an applicable margin ranging from 2.50% to 3.50% per annum, and (ii) a customary base 
rate  plus  an  applicable  margin  ranging  from  1.50%  to  2.50%  per  annum,  in  each  case  depending  on  levels  of 
borrowing base utilization. In addition, we must pay the lenders a quarterly commitment fee of 0.50% on the average 
daily  unused  amount  of  the  borrowing  availability  under  the  RBL  Facility.  We  have  the  right  to  prepay  any 
borrowings under the RBL Facility with prior notice at any time without a prepayment penalty, other than customary 
“breakage” costs with respect to eurodollar loans.

The RBL Facility contains events of default and remedies customary for this type of credit facility. If we do not 
comply with the financial and other covenants in the RBL Facility, the lenders may, subject to customary cure rights, 
require immediate payment of all amounts outstanding under the RBL Facility and exercise all of their other rights 
and remedies, including foreclosure on all of the collateral.

The RBL Facility requires us to maintain on a consolidated basis as of each quarter-end (i) a Leverage Ratio of 
no  more  than  4.00  to  1.00  and  (ii)  a  Current  Ratio  of  at  least  1.00  to  1.00.  The  RBL  Facility  also  contains 
customary restrictions. As of  December 31, 2019, our Leverage Ratio and Current Ratio were 1.4:1.00 and 3.2:1.00, 
respectively. As of December 31, 2019, we were in compliance with the financial covenants under the RBL Facility. 

The RBL Facility permits us to repurchase equity and indebtedness, among other things, if availability is equal 
to  or  greater  than  15%  of  the  elected  commitments  or  borrowing  base,  whichever  is  in  effect,  and  our  pro  forma 
leverage ratio is less than or equal to 2.75 to 1.00.

Berry  Corp.  guarantees,  and  each  future  subsidiary  of  Berry  Corp.  (other  than  Berry  LLC),  with  certain 
exceptions, is required to guarantee, our obligations and obligations of the other guarantors under the RBL Facility and 
under certain hedging  transactions  and  banking  services  arrangements  (the  “Guaranteed  Obligations”).  In  addition, 
pursuant to a Guaranty Agreement dated as of July 31, 2017, Berry LLC guarantees the Guaranteed Obligations. The 
lenders under the RBL Facility hold a mortgage on at least 85% 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. The RBL Facility, with certain exceptions, also requires that any future 
subsidiaries of Berry LLC are required to grant mortgages, security interests and equity pledges.

67

Corporate Organization 

Berry Corp., as Berry LLC's parent company, has no independent assets or operations. Any guarantees of potential 
future registered debt securities by Berry Corp. or Berry LLC would be full and unconditional. Berry Corp. and Berry 
LLC currently do not have any other subsidiaries. In addition, there are no significant restrictions upon the ability of 
Berry LLC to distribute funds to Berry Corp. by distribution or loan other than under the RBL Facility. None of the 
assets of Berry Corp. or Berry LLC represent restricted net assets.  

The RBL permits Berry LLC to make distributions to Berry Corp. so long as both before and after giving pro forma 
effect to such distribution no default or borrowing base deficiency exists, availability equals or exceeds 15% of the 
then effective borrowing base, and Berry Corp. demonstrates a pro forma leverage ratio less than or equal to 2.75 to 
1.00. The conditions are currently met with significant margin. 

Hedging

We have protected a significant portion of our anticipated cash flows through our commodity hedging program, 
including through fixed-price derivative contracts for oil production and gas purchases. For information regarding risks 
related to our hedging program, see  “Item 1A. Risk Factors—Risks Related to Our Business and Industry”. 

We  currently  have  hedged  a  significant  portion  of  our  crude  oil  production  through  2020  and  into  2021.  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. Oil derivative settlements increased for the year ended December 
31, 2019 when compared to the year ended December 31, 2018, as a result of an increase in realized oil prices with 
hedges, as well as, an increase in oil volumes hedged. 

As of December 31, 2019, we had the following crude oil production and gas purchases hedges. 

Fixed Price Oil Swaps (Brent):

Hedged volume (MBbls)

Weighted average price ($/Bbl)

Fixed Price Oil Swaps (WTI):

Hedged volume (MBbls)

Weighted average price ($/Bbl)

Fixed Price Gas Purchase Swaps (Kern, Delivered):

Hedged volume (MMBtu)

Weighted average price ($/MMBtu)

Fixed Price Gas Purchase Swaps (SoCal Citygate):

Hedged volume (MMBtu)

Weighted average price ($/MMBtu)

Q1 2020

Q2 2020

Q3 2020

Q4 2020

FY 2021

1,729

1,456

1,472

1,472

730

$

63.92

$

64.30

$

64.21

$

64.21

$

58.50

91

30

—

—

$

61.75

$

61.75

$

— $

— $

—

—

5,005,000

5,005,000

5,060,000

2,315,000

900,000

$

$

2.89

$

2.89

$

2.89

$

2.79

$

2.50

455,000

455,000

460,000

155,000

3.80

$

3.80

$

3.80

$

3.80

$

—

—

After December 31, 2019 we added fixed price gas purchase swaps (Kern, Delivered) of 5,000 MMBtu/d at 

$2.55 beginning November 2020 through October 2021.  

68

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

Natural Gas (per MMBtu):

Purchase price, before the effects of derivative settlements

Effects of derivative settlements

Year Ended

December 31, 2019

December 31, 2018

$

$

$

$

58.93

4.69

3.18

0.04

$

$

$

$

64.76

(5.09)

3.27

(0.10)

In 2019, our gas purchase derivative settlements resulted in payments as the strike price of our hedges were higher 
than the index price. In 2018, our gas purchase derivative settlements resulted in receipts as the strike price of our 
hedges were lower than the index price.

In May 2018, we elected to terminate outstanding commodity derivative contracts for all WTI oil swaps and certain 
WTI/Brent basis swaps for July 2018 through December 2019 and all WTI oil sold call options for July 2018 through 
June 2020. Termination costs totaled approximately $127 million and were calculated in accordance with a bilateral 
agreement on the cost of elective termination included in these derivative contracts; the present value of the contracts 
using the forward price curve as of the date termination was elected. No penalties were charged as a result of the elective 
termination. 

Capital Program

For the years ended December 31, 2019 and 2018 our capital expenditures were approximately $211 million and 
$148 million, respectively, on an accrual basis excluding acquisitions. California production increased 15% year-over-
year  in  response  to  the  deployment  of  the  substantial  majority  of  our  development  capital. This  increase  strongly 
demonstrated the ability of our California properties to respond to capital and perform as expected. Additionally, our 
2019 capital program contributed to the increase in our California proved reserves of 24.5 MMBoe, or 23% before 
production, resulting in a 299% replacement ratio. We also replaced 159% of our total company proved undeveloped 
drilling location inventory.

Our 2020 anticipated capital expenditure budget is approximately $125 to $145 million. Using the mid-point of 
this range, we expect to have a decrease of approximately 36% over 2019 capital expenditures. Our 2020 capital program 
is focused on generating strong year-over-year oil production growth in California, while holding overall production 
close to flat throughout the year, and continue returning capital to our shareholders. Based on current commodity prices 
and our drilling success rate, we expect to be able to fund our 2020 capital development programs while producing 
positive  Levered  Free  Cash  Flow  and  continue  to  pay  quarterly  dividends.  We  anticipate  oil  production  will  be 
approximately 90% of total production in 2020, compared to 87% in 2019 and 82% in 2018. During 2020, we expect 
to employ up to three drilling rigs in California throughout the last three quarters of the year, and averaging up to one 
rig in the first quarter. For the year, we expect to drill 195 to 225 gross development wells, almost all of which will be 
in California for oil production. However, the execution of these plans requires certain regulatory review and approvals, 
and current and future laws and regulations could impact our ability to successfully execute our plans. Please see 
“Regulation of Health, Safety and Environmental Matters” for additional discussion. 

In addition to capital expenditures, we also incur costs associated with retiring assets and remediating property at 
the end of its useful life, both due to regulatory obligations and our focus on EH&S as we develop existing fields. Most 
of these obligations and activities are regulated by governmental agencies. During 2019, we spent approximately $27 
million in fulfilling these obligations and in 2020 we expect to spend approximately $20 million. A significant portion 
of these costs is a result of California's new idle well regulations which became effective in 2019 and accelerated the 
timing of abandonment of certain existing idle wells. In accordance with these regulations, we expect to plug and 
abandon a majority of our existing idle wells over the next eight years.

69

The amount and timing of capital expenditures is within our control and subject to our management’s discretion, 
and may be adjusted during the year depending on commodity prices and other factors. We retain the flexibility to defer 
planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling 
activities, prevailing and anticipated prices for oil, natural gas and NGLs, the receipt and timing of required regulatory 
permits and approvals, the availability of necessary equipment, infrastructure and capital, seasonal conditions, drilling 
and acquisition costs and the level of participation by other interest owners, as well as general market conditions.

IPO and Preferred Stock Conversion

In July 2018, we completed the IPO and as a result, on July 26, 2018, our common stock began trading on the 
NASDAQ under the ticker symbol BRY. We received approximately $110 million of net proceeds, after deducting 
underwriting discounts and offering expenses payable by us, for the 8,695,653 shares of common stock issued for our 
benefit in the IPO, net of the shares sold for the benefit of certain selling stockholders. The price to the public for the 
shares sold in our IPO was $14.00 per share.

Of the approximately $110 million of net proceeds we received in the IPO, we used approximately $105 million 
to repay borrowings under our RBL Facility, which included $60 million we borrowed to make the payment due to the 
holders of our Series A Preferred Stock in connection with the conversion of preferred stock to common stock. We used 
the remainder for general corporate purposes. 

In connection with the IPO, on July 17, 2018, we entered into stock purchase agreements with certain funds affiliated 
with Oaktree Capital Management and Benefit Street Partners, pursuant to which we purchased an aggregate of 410,229 
and 1,391,967 shares of our common stock, respectively, or 1,802,196 in total. In addition to the 8,695,653 shares of 
common stock issued and sold for our benefit in the IPO, we simultaneously received $24 million for issuing and selling 
1,802,196 shares to the public and paid $24 million to purchase 1,802,196 shares under the stock purchase agreements. 
We purchased the shares immediately following the closing of the IPO and retired and returned them to the status of 
authorized but unissued shares. 

The selling stockholders sold an additional 2,545,630 shares at a price to the public of $14.00 per share, for which 

we did not receive any proceeds.  

In  connection  with  the  IPO,  each  of  the  37.7  million  shares  of  our  Series A  Preferred  Stock  outstanding  was 
automatically converted to common stock in the Series A Preferred Stock Conversion. The cash payment was to be 
reduced in respect of any cash dividend paid by the Company on such share of Series A Preferred Stock for any period 
commencing on or after April 1, 2018. Because we paid the second quarter preferred dividend of $0.15 per share in 
June, the cash payment for the conversion was reduced to $1.60 per share, or approximately $60 million in aggregate. 
In connection with the IPO, we assigned the additional 1.9 million shares of common stock issued in the Series A 
Preferred Stock Conversion a value of $14.00 per share, which was equal to the value of shares sold in the IPO. The 
approximate $27 million value assigned to the 1.9 million shares and the $60 million cash payment for the Series A 
Preferred Stock Conversion reduced the income available to common stockholders by approximately $87 million.

Stock Repurchase Program

In December 2018, our Board of Directors adopted a program for the opportunistic repurchase of up to $100 million
of  our  common  stock.  Based  on  the  Board’s  evaluation  of  current  market  conditions  for  our  common  stock  they 
authorized current repurchases of up to $50 million under the program. Purchases may be made from time to time in 
the open market, in privately negotiated transactions or otherwise. The manner, timing and amount of any purchases 
will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements 
and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to 
purchase shares during any period or at all. Any shares acquired will be available for general corporate purposes. 

In 2019 the Company repurchased 4,609,021 shares at an average price of $9.99. Since 2018 the Company has 
repurchased a total of 5,057,682 shares at an average price of $9.88 per share under the Stock Repurchase Program, 

70

which is reflected as treasury stock.  In February 2020, the Board of Directors authorized the remaining $50 million 
of our $100 million repurchase program.

Preferred Stock Dividends

In March 2018, our board of directors approved a cumulative paid-in-kind dividend on the Series A Preferred Stock 
for the periods through December 31, 2017. The cumulative dividend was 0.050907 new shares per outstanding share 
or approximately 1,825,000 shares in total. Also in the first and second quarter of 2018 the board of directors approved 
a $0.158 per share and a $0.15 per share cash dividend on the Series A Preferred Stock, respectively, for a total of $11.3 
million.

Statements of Cash Flows

The following is a comparative cash flow summary:

Net cash:

Provided by operating activities(1)

Used in investing activities

(Used in) provided by financing activities

Net decrease in cash, cash equivalents and restricted cash

Year Ended

December 31, 2019

December 31, 2018

(in thousands)

$

$

241,829

$

(225,025)

(85,484)

(68,680) $

105,471

(121,440)

15,911

(58)

__________
(1) The amounts provided by operating activities in 2018 were negatively impacted by a one-time $127 million payment in May 2018 for early

termination on derivatives.

Operating Activities

Cash provided by operating activities increased for the year ended December 31, 2019 by approximately $136
million when compared to the year ended December 31, 2018, due to the early termination of certain hedge contracts 
paid during the second quarter of 2018 of $127 million, the year-over-year increase in oil derivative cash settlements 
received of $84 million, and the increase in oil, natural gas and natural gas liquids sales of approximately $13 million, 
offset by increased operating expenses of $35 million, increased taxes, other than income of approximately $8 million, 
increased general and administrative expenses of $9 million and working capital changes of approximately $39 million.

71

Investing Activities

The following provides a comparative summary of cash flow from investing activities:

Capital expenditures (1)

Development of oil and natural gas properties

Changes in capital investment accruals

Purchase of other property and equipment

Acquisition of properties and equipment

Proceeds from sale of properties and equipment and other

Cash used in investing activities:

__________
(1) Based on actual cash payments rather than accrual.

Year Ended

December 31, 2019

December 31, 2018

(in thousands)

$

$

(219,176) $

12,814

(16,792)

(2,840)

969

(94,225)

(20,371)

(15,056)

—

8,212

(225,025) $

(121,440)

Cash used in investing activities increased $104 million for the year ended December 31, 2019 when compared
to the year ended December 31, 2018, primarily due to an increase in capital spending in accordance with the 2019 
capital program. 

Financing Activities

Cash used in financing activities was approximately $85 million for the year ended December 31, 2019 and was 
primarily used to purchase treasury stock of $47 million and pay dividends on common stock of approximately $39 
million, offset by approximately $2 million of net borrowings under the RBL Facility for monthly working capital 
fluctuations. 

Cash provided by financing activities was approximately $16 million for the year ended December 31, 2018 and 
was due to the net proceeds of $391 million from the issuance of our 2026 Notes and $110 million from our IPO in 
July 2018, offset by $379 million in payments on our RBL Facility, a $60 million payment to preferred stockholders 
in connection with the Series A Preferred Stock Conversion, $20 million payments to repurchase the rights to our 
common stock from certain claimholders originating from the bankruptcy process, $11 million in cash dividends declared 
on our Series A Preferred Stock, $7 million in dividends paid on our common stock and $3 million to acquire treasury 
shares under our stock repurchase program. 

Commitments, and Contingencies 

In the normal course of business, we, or our subsidiary, are subject to lawsuits, environmental and other claims 
and other contingencies that seek, or may seek, among other things, compensation for alleged personal injury, breach 
of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.

On May 11, 2016 our predecessor company filed the Chapter 11 Proceeding. Our bankruptcy case was jointly 
administered with that of Linn Energy and its affiliates under the caption In re Linn Energy, LLC, et al., Case No. 
16-60040. On January 27, 2017, the Bankruptcy Court approved and confirmed our plan of reorganization in the Chapter
11 Proceeding. On February 28, 2017, the Effective Date occurred and the Plan became effective and was implemented.
A final decree closing the Chapter 11 Proceeding was entered September 28, 2018, with the Court retaining jurisdiction
as described in the confirmation order and without prejudice to the request of any party-in-interest to reopen the case
including with respect to certain, immaterial remaining matters.

We accrue reserves 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 

72

December 31, 2019 and December 31, 2018. 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 reserves 
accrued on our balance sheet would not be material to our consolidated financial position or results of operations. 

We  have  certain  commitments  under  contracts,  including  purchase  commitments  for  goods  and  services.  We 
previously had an obligation to a counterparty in connection with our Piceance assets to either build a road or secure 
a  license  for  alternative  access,  in  lieu  of  paying  a  $6  million  penalty. As  of  December 31,  2019,  we  fulfilled  the 
obligation by delivering the access license pursuant to the agreement. The counterparty has since filed a claim challenging 
the sufficiency of such access. 

We, or our subsidiary, 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, 2019, we are not 
aware of material indemnity claims pending or threatened against us.

Contractual Obligations 

The following is a summary of our commitments and contractual obligations as of December 31, 2019:

Total

2020

2021-2022

2023-2024

Thereafter

Payments Due

(in thousands)

Debt obligations:

RBL Facility

2026 Notes
Interest(1)

Other:

$

1,850

$

— $

1,850

$

400,000

171,529

—

—

28,000

56,000

56,000

— $

—

—

400,000

31,529

Asset retirement obligations(2)
Off-Balance Sheet arrangements:

Processing and transportation contracts(3)
Operating lease obligations
Other(4) 

149,227

21,434

—

—

127,793

13,462

11,969

6,000

7,136

1,723

6,000

5,265

3,471

—

1,061

3,067

—

—

3,708

—

Total contractual obligations

$

754,037

$

64,293

$

66,586

$

60,128

$

563,030

__________
(cid:11)(cid:20)(cid:12) Represents interest on the 2026 Notes computed at 7.0% through contractual maturity in 2026.
(cid:11)(cid:21)(cid:12) Represents the estimated future asset retirement obligations on a discounted basis. We do not show the long-term asset retirement obligations 
by year as we are not able to precisely predict the timing of these amounts. Because these costs typically extend many years into the future,(cid:3)
estimating these future costs requires management to make estimates and judgments that are subject to revisions based on numerous factors,(cid:3)
including the rate of inflation, changing technology, and changes to federal, state and local laws and regulations. See Note 1 in the Notes to 
Consolidated Financial Statements in Part II—Item 8. Financial Statements and Supplementary Data for more information.

(cid:11)(cid:22)(cid:12) Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of(cid:3)

business to secure transportation of our natural gas production to market as well as pipeline and processing capacity. 

(cid:11)(cid:23)(cid:12) We have certain commitments under contracts, including purchase commitments for goods and services. We previously had an obligation to 
a counterparty in connection with our Piceance assets to either build a road or secure a license for alternative access, in lieu of paying a $6(cid:3)
million  penalty.  As  of  December 31,  2019,  we  fulfilled  the  obligation  by  delivering  the  access  license  pursuant  to  the  agreement.  The(cid:3)
counterparty has since filed a claim challenging the sufficiency of such access. 

73

Balance Sheet Analysis

The changes in our balance sheet from December 31, 2018 to December 31, 2019 are discussed below.

Cash and cash equivalents

Accounts receivable, net

Derivative instruments - current and long-term

Other current assets

Property, plant & equipment, net

Other non-current assets

Accounts payable and accrued liabilities

Derivative instruments - current and long-term

Long-term debt

Asset retirement obligation

Other non-current liabilities

Equity

December 31, 2019

December 31, 2018

$

$

$

$

$

$

$

$

$

$

$

$

(in thousands)

— $

71,867

9,691

19,399

1,576,267

12,974

151,811

4,958

394,319

124,019

33,586

972,448

$

$

$

$

$

$

$

$

$

$

$

68,680

57,379

91,885

14,367

1,442,708

17,244

144,118

—

391,786

89,176

14,902

1,006,446

See “—Liquidity and Capital Resources” for discussions about the changes in cash and cash equivalents.

The $14 million increase in accounts receivable was driven mostly by higher sales period-over-period, partially 

offset by lower hedge settlements outstanding at each period-end. 

The $77 million decrease in derivative assets and liabilities reflected the reduction in the mark-to-market values 
relative to the strike price of the derivatives at the end of each period presented, as well as the change in positions held 
at the end of each period and the settlements received throughout the period. 

The $5 million increase in other current assets was mainly due to purchases of materials inventory related to our 

capital development program.

The $134 million increase in property, plant and equipment was largely the result of increased capital investments 
in oil and gas properties, as well as revisions to timing and cost estimates in our asset retirement obligations noted 
below, partially offset by increased accumulated depreciation of all properties and the Piceance property impairment.

The $4 million decrease in other non-current assets was primarily due to amortization of debt issuance costs.

The $8 million increase in accounts payable and accrued liabilities included approximately $19 million for the 
increased current portion of the asset retirement obligation partially offset by decreased accruals for various capital 
and operating costs of $10 million due to the level of these costs at the end of each year.

The $3 million increase in long-term debt primarily represented borrowing and repayment activity from our RBL 

Facility for monthly working capital fluctuations.

The $35 million increase in the long-term portion of the asset retirement obligation reflected revisions to timing 
and cost estimates of $57 million, $12 million for new wells, and $8 million of accretion expense. A significant portion 
of the change in estimate was a result of California's new idle well regulations which became effective in 2019. These 
regulations accelerated the abandonment timing of certain long existing idle wells. These increases were partially offset 
by increased liability settlements of $22 million and a $19 million change from long to short-term asset retirement 
obligation.

74

The $19 million increase in other non-current liabilities primarily represented increases to the greenhouse gas 

liability, which is due for payment more than one year from December 31, 2019.

The $34 million decrease in equity was due to the purchase of treasury stock for $46 million and common stock 
dividends declared of $39 million. These decreases were offset by $44 million of net income and $8 million related to 
our stock-based incentive awards. 

Non-GAAP Financial Measures 

Adjusted EBITDA, Levered Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and 

Administrative Expenses

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

We  define Adjusted  EBITDA  as  earnings  before  interest  expense;  income  taxes;  depreciation,  depletion,  and 
amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; 
stock compensation expense; and other unusual, out-of-period and infrequent items, including restructuring costs and 
reorganization items. We define Levered Free Cash Flow as Adjusted EBITDA less capital expenditures, interest expense 
and dividends. 

Our management believes Adjusted EBITDA provides useful information in assessing our financial condition, 
results of operations and cash flows and is widely used by the industry and the investment community. The measure 
also allows our management to more effectively evaluate our operating performance and compare the results between 
periods without regard to our financing methods or capital structure. Levered Free Cash Flow is used by management 
as a primary metric to plan capital allocation to sustain production levels and for internal growth opportunities, as well 
as hedging needs. It also serves as a measure for assessing our financial performance and our ability to generate excess 
cash from operations to service debt and pay dividends. 

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

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

Adjusted General and Administrative Expenses is a supplemental non-GAAP financial measure that is used by 
management and external users of our financial statements, such as industry analysts, investors, lenders and rating 
agencies. We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted 
for  restructuring  and  other  non-recurring  costs  and  non-cash  stock  compensation  expense.  Management  believes 

75

Adjusted  General  and Administrative  Expenses  is  useful  because  it  allows  us  to  more  effectively  compare  our 
performance from period to period. 

We exclude the items listed above from general and administrative expenses in arriving at Adjusted General and 
Administrative Expenses because these amounts can vary widely and unpredictably in nature, timing, amount and 
frequency and stock compensation expense is non-cash in nature. Adjusted General and Administrative Expenses should 
not be considered as an alternative to, or more meaningful than, general and administrative expenses as determined in 
accordance with GAAP. Our computations of Adjusted General and Administrative Expenses may not be comparable 
to other similarly titled measures of other companies.

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

Adjusted EBITDA reconciliation to net income (loss):

Net (loss) income

Add (Subtract):

Interest expense

Income tax expense (benefit)

Depreciation, depletion, and amortization

Impairment of oil and gas properties

Derivative losses (gains)
Net cash received (paid) for scheduled derivative settlements(1)

Other operating expenses (income)

Stock compensation expense

Restructuring and other non-recurring costs

Reorganization items, net

Adjusted EBITDA

Year Ended

December 31, 2019

December 31, 2018

(in thousands)

$

43,539

$

147,102

34,234

(36,550)

106,006

51,081

44,955

42,197

4,588

8,647

3,061

426

$

302,184

$

35,648

43,035

86,271

—

(1,735)

(38,482)

(2,747)

6,750

6,773

(24,690)

257,924

__________
(1) Net cash received (paid) for scheduled derivative settlements does not include the $127 million in cash paid for early terminated derivatives

in 2018.

76

Adjusted EBITDA and Levered Free Cash Flow reconciliation to net cash provided by (used in) operating activities:

Net cash provided by operating activities

$

241,829

$

105,471

Year Ended

December 31, 2019

December 31, 2018

(in thousands)

Add (Subtract):

Cash interest payments

Cash income tax refunds

Cash reorganization item payments

Restructuring and other non-recurring costs

Derivative early termination payment

Other changes in operating assets and liabilities

Adjusted EBITDA

Subtract:

Capital expenditures - accrual basis

Interest expense
Cash dividends declared(1)

Levered Free Cash Flow(2)

30,720

(2)

—

3,061

—

26,576

302,184

$

(211,095)

(34,234)

(39,053)

17,802

$

19,761

(1,901)

832

6,773

126,949

39

257,924

(147,831)

(35,648)

(28,658)

45,787

$

$

__________
(1) Cash dividends declared in 2018 include $11 million of dividends for Series A Preferred Stock for the first two quarters of 2018 and $17 million
of dividends for common stock. In connection with our IPO in July 2018, all of our outstanding Series A Preferred Stock was automatically
converted into common stock. Common stock dividends were $0.09 per share for the third quarter of 2018, which was pro-rated from the date
of our IPO through September 30, 2018, and $0.12 per share for the fourth quarter of 2018 and each quarter in 2019.

(2) Levered Free Cash Flow includes cash received for scheduled derivative settlements of $42 million for the year ended December 31, 2019,

and cash paid for scheduled derivative settlements $38 million for the year ended December 31, 2018.

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).

Year Ended

December 31, 2019

December 31, 2018

(in thousands)

Adjusted Net Income (Loss) reconciliation to net income (loss):

Net (loss) income

Subtract: prior year income tax credits

$

43,539

$

(38,653)

147,102

—

Add (Subtract):

Losses (gains) on oil and natural gas derivatives

Net cash received (paid) for scheduled derivative settlements

Other operating expenses (income)

Impairment of oil and gas properties

Restructuring and other non-recurring costs

Reorganization items, net

Total additions (subtractions), net

Income tax (expense) benefit of adjustments at effective tax rate(1)

44,955

42,197

4,588

51,081

3,061

426

146,308

(40,966)

Adjusted Net Income (Loss)

$

110,228

$

(1,735)

(38,482)

(2,747)

—

6,773

(24,690)

(60,881)

13,780

100,001

77

__________
(1) Excludes prior year income tax credits from the total additions (subtractions), net line item and the tax effect the prior tax credits have on the

current year effective tax rate.

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

Adjusted General and Administrative Expense reconciliation to general and administrative expenses:

Year Ended

December 31, 2019

December 31, 2018

(in thousands)

General and administrative expenses

Subtract:

Restructuring and other non-recurring costs

Non-cash stock compensation expense (G&A portion)

Adjusted general and administrative expenses

Adjusted general and administrative expenses ($/MBoe)

Off-Balance Sheet Arrangements

$

$

$

62,643

$

54,026

(3,061)

(8,356)

51,226

4.84

$

$

(6,773)

(6,585)

40,668

4.13

See “—Liquidity and Capital Resources—Commitments, and Contingencies” and “—Contractual Obligations ” 

for information regarding our off-balance sheet arrangements.

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, net of salvage, 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. 

78

We evaluate the impairment of our proved oil and natural gas properties generally on a field by field basis or at 
the lowest level for which cash flows are identifiable, whenever events or changes in circumstance indicate that the 
carrying value may not be recoverable. We reduce the carrying values of proved properties to fair value when the 
expected undiscounted future cash flows are less than net book value. We measure the fair values of proved properties 
using valuation techniques consistent with the income approach, converting future cash flows to a single discounted 
amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) 
future operating and development costs; (iii) future commodity prices; and (iv) a risk-adjusted discount rate. These 
inputs require significant judgments and estimates by our management at the time of the valuation and are the most 
sensitive estimates that we make and the most likely to change. 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, 
2019 and 2018, the net capitalized costs attributable to unproved properties were approximately $314 million and $388 
million, respectively. The unproved amounts were not subject to depreciation, depletion and amortization until they 
were classified as proved properties and amortized on a unit-of-production basis. We evaluate the impairment of our 
unproved oil and gas properties whenever events or changes in circumstances indicate the carrying value may not be 
recoverable. If the exploration and development work were to be unsuccessful, or management decided not to pursue 
development  of  these  properties  as  a  result  of  lower  commodity  prices,  higher  development  and  operating  costs, 
contractual conditions or other factors, the capitalized costs of such properties would be expensed. The timing of any 
write-downs of unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of 
future  exploration  and  development  activities  and  their  results. 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, 2019.

At year end 2019, we evaluated our proved and unproved natural gas properties in regards to the decline in our 
expectations of future gas prices. As a result, we recorded a non-cash pre-tax asset impairment charge of $51 million for 
our Piceance gas properties in Colorado, of which $23 million was for proved properties and $28 million for unproved 
properties. 

Asset Retirement Obligation

We recognize the fair value of asset retirement obligations (“AROs”) in the period in which a determination is 
made that a legal obligation exists to dismantle an asset and remediate the property at the end of its useful life and the 
cost of the obligation can be reasonably estimated.

The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as time 
to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is 
initially recorded, we capitalize the cost by increasing the related property, plant and equipment (“PP&E”) balances. 
If the estimated future cost of the AROs changes, we record an adjustment to both the ARO and PP&E. Over time, the 
liability is increased, and expense is recognized through accretion, and the capitalized cost is depreciated over the useful 
life of the asset.

In certain cases, we do not know or cannot estimate when we may settle these obligations and therefore we cannot 
reasonably estimate the fair value of the liabilities. We will recognize these AROs in the periods in which sufficient 
information becomes available to reasonably estimate their fair values.

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 

79

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 most significant items on our balance sheet that would be affected by recurring fair value measurements are 
derivatives. We determine the fair value of our oil and natural gas 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.

Stock-based Compensation

We have issued restricted stock units (“RSUs”) that vest over time and performance-based restricted stock units 
(“PSUs”) that vest based on our achievement of certain average prices per share or total shareholder return, to certain 
employees and non-employee directors. The fair value of the stock-based awards is determined at the date of grant and 
is not remeasured. Prior to our IPO in July 2018, we determined the fair value of the RSUs based on an estimate of the 
fair value of our equity using an income approach. We used a discounted cash flow method to value the estimated future 
cash flows at an appropriate discount rate. Subsequent to our IPO, since the underlying shares are now trading in the 
public markets, these estimates are no longer necessary. For PSUs, compensation value is measured on the grant date 
using payout values derived from a Monte-Carlo valuation model. 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. 

80

Fresh-Start Accounting

Upon our emergence from Chapter 11 bankruptcy, we adopted fresh-start accounting which resulted in our becoming 
a new entity for financial reporting purposes. We were required to adopt fresh-start accounting upon our emergence 
from Chapter 11 bankruptcy because (i) the holders of existing voting ownership interests of Berry LLC received less 
than  50%  of  the  voting  shares  of  Berry  Corp.  and  (ii)  the  reorganization  value  of  our  assets  immediately  prior  to 
confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims, as shown below:

Liabilities subject to compromise

Pre-petition debt not classified as subject to compromise

Post-petition liabilities

Total post-petition liabilities and allowed claims

Reorganization value of assets immediately prior to implementation of the Plan

Excess post-petition liabilities and allowed claims

(in thousands)

1,000,336

891,259

245,702

2,137,297

(1,722,585)

414,712

$

$

Upon adoption of fresh-start accounting, the reorganization value derived from the enterprise value was allocated 
to our assets and liabilities based on their fair values in accordance with GAAP. The Effective Date fair values of our 
assets and liabilities differed materially from their recorded values as reflected on the historical balance sheet. The 
effects of the Plan and the application of fresh-start accounting were reflected in the financial statements as of February 
28, 2017, and the related adjustments thereto were recorded on the statement of operations for the two months ended 
February 28, 2017.

As  a  result  of  the  adoption  of  fresh-start  accounting  and  the  effects  of  the  implementation  of  the  Plan,  our 
consolidated financial statements subsequent to February 28, 2017 are not comparable to our financial statements prior 
to February 28, 2017.

Our consolidated financial statements and related footnotes are presented with a black line division, which delineates 
the lack of comparability between amounts presented after February 28, 2017, and amounts presented on or prior to 
February 28, 2017. Our financial results for future periods following the application of fresh-start accounting will be 
different from historical trends and the differences may be material.

Reorganization Value

Under GAAP, Berry Corp. determined a value to be assigned to the equity of the emerging entity as of the date of 
adoption of fresh-start accounting. The Plan and disclosure statement approved by the Bankruptcy Court did not include 
an enterprise value or reorganization value, nor did the Bankruptcy Court approve a value as part of its confirmation 
of the Plan. Our reorganization value was derived from an estimate of enterprise value, or the fair value of our long-
term debt, stockholders’ equity and working capital. Reorganization value approximates the fair value of the entity 
before  considering  liabilities  and  approximates  the  amount  a  willing  buyer  would  pay  for  the  assets  of  the  entity 
immediately after the restructuring. Based on the various estimates and assumptions necessary for fresh-start accounting, 
we estimated our enterprise value as of the Effective Date to be approximately $1.3 billion. The enterprise value was 
estimated using a sum of parts approach. The sum of parts approach represents the summation of the indicated fair 
value of the component assets of the Company. The fair value of our assets was estimated by relying on a combination 
of the income, market and cost approaches.

The estimated enterprise value, reorganization value and equity value are highly dependent on the achievement of 
the financial results contemplated in our underlying projections. While we believe the assumptions and estimates used 
to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates 
could materially impact the analysis and resulting conclusions. Additionally, the assumptions used in estimating these 
values are inherently uncertain and require judgment. The primary assumptions for which there is a reasonable possibility 

81

of the occurrence of a variation that would have significantly affected the reorganization value include those regarding 
pricing, discount rates and the amount and timing of capital expenditures.

Our principal assets are our oil and natural gas properties. The fair values of oil and natural gas properties were 
estimated using a valuation technique consistent with the income approach, specifically the discounted cash flows 
method. We also used the market approach to corroborate the valuation results from the income approach. We used a 
market-based weighted-average cost of capital discount rate of 10% for proved and unproved reserves, with further 
risk adjustment factors applied to the discounted values. The underlying commodity prices embedded in our estimated 
cash flows are based on the Brent and Henry Hub forward curve pricing, adjusted for estimated location and quality 
differentials, as well as other factors that we believe will impact realizable prices. Forward curve pricing was used for 
years 2017 through 2019 and then was escalated at approximately 2.0%.

The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date:

Enterprise value

Plus: Fair value of non-debt liabilities

Reorganization value of the successor’s assets

(in thousands)

$

$

1,278,527

282,511

1,561,038

The fair value of non-debt liabilities consists of liabilities assumed by Berry Corp. on the Effective Date and 

excludes the fair value of long-term debt.

Consolidated Balance Sheet

The adjustments included in the fresh-start consolidated balance sheet in the accompanying financial statements 
reflect the effects of the transactions contemplated by the Plan and executed on the Effective Date as well as fair value 
and other required accounting adjustments resulting from the adoption of fresh-start accounting. The explanatory notes 
provide additional information with regard to the adjustments recorded, methods used to determine the fair values and 
significant assumptions.

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

Inflation in the United States has been relatively low in recent years and did not have a material impact on our 
results of operations for the periods discussed. Although the impact of inflation has been insignificant in recent years, 
it is still a factor in the United States economy and we may experience inflationary pressure on the cost of oilfield 
services and equipment as increasing oil, natural gas and NGL prices increase drilling activity in our areas of operations. 
An increase in oil, natural gas and NGL prices may cause the costs of materials and services to rise.

82

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  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: 

•

•

•

•

•

•

•

•

•

•

•

•

•

•

•

volatility of oil, natural gas and NGL prices;

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 and availability of natural gas;

our ability to use derivative instruments to manage commodity price risk;

availability or timing of, or conditions imposed on, permits and approvals;

our  ability  to  meet  our  planned  drilling  schedule,  including  due  to  our  ability  to  obtain  permits,  and  to
successfully drill wells that produce oil and natural gas in commercially viable quantities;

the impact of current laws and regulations, and of pending or future legislative and regulatory changes and
other  government  activities,  including  those  related  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;

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;

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;

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;

83

•

•

•

•

•

•

•

•

•

large or multiple customer defaults on contractual obligations, including defaults resulting from actual or
potential insolvencies;

geographical concentration of our operations;

our ability to improve our financial results and profitability following our emergence from bankruptcy and
other risks and uncertainties related to our emergence from bankruptcy;

impact of derivatives legislation affecting our ability to hedge;

ineffectiveness of internal controls;

catastrophic events;

litigation;

our ability to retain key members of our senior management and key technical employees; and

information technology failures or cyber attacks.

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. 

84

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Our primary market risks are attributable to fluctuations in commodity prices and interest rates, which can affect 
our business, financial condition, operating results and cash flows. The following should be read in conjunction with 
the financial statements and related notes included elsewhere in this report.

Price Risk

Our most significant market risk relates to prices for oil, natural gas, and NGLs. Management expects energy prices 
to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues, certain costs 
such as fuel gas, and cash flows are likewise affected. In addition, a non-cash write-down of our oil and gas properties 
may be required if commodity prices experience a significant decline.

We have hedged a large portion of our expected crude oil production and our natural gas purchase requirements 
to reduce exposure to fluctuations in commodity prices. We use derivatives such as swaps, calls and puts 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 natural gas 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. At December 31, 2019, the fair value of our hedge positions was a net 
asset of approximately $5 million. A 10% increase in the oil and natural gas index prices above the December 31, 2019 
prices would result in a net liability of approximately $31 million, which represents a decrease in the fair value of our 
derivative position of approximately $36 million; conversely, a 10% decrease in the oil and natural gas index prices 
below the December 31, 2019 prices would result in a net asset of approximately $46 million, which represents an 
increase in the fair value of approximately $42 million. For additional information about derivative activity, see Note 
4 to our consolidated financial statements.

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.

Counterparty Credit Risk

Our credit risk relates primarily to trade receivables and derivative financial instruments. Credit exposure for each 
customer is monitored for outstanding balances and current activity. 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 seven commodity derivative counterparties at December 31, 2019 and nine at December 31, 2018. 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, the 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 A3 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, 2019 was not material and losses associated with credit risk 
have been insignificant for all periods presented.

85

Interest Rate Risk

Our  RBL  Facility  has  a  variable  interest  rate  on  outstanding  balances.  As  of  December 31,  2019,  we  had 
approximately $2 million in borrowings under our RBL Facility and thus the interest rate risk exposure is not material. 
The 2026 Notes have a fixed interest rate and thus we are not exposed to interest rate risk on these instruments. See 
Note 3 to our consolidated financial statements for additional information regarding interest rates on our outstanding 
debt.

86

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, 2019 and December 31, 2018 ....................................

Consolidated Statements of Operations for the Year Ended December 31, 2019, the Year Ended December 
31, 2018, the Ten Months Ended December 31, 2017, and the Two Months Ended February 28, 2017 

Consolidated Statements of Equity for the Year Ended December 31, 2019, the Year Ended December 
31, 2018, the Ten Months Ended December 31, 2017, and the Two Months Ended February 28, 2017

Consolidated  Statements  of  Cash  Flows  for  the  Year  Ended  December  31,  2019,  the  Year  Ended 
December 31, 2018, the Ten Months Ended December 31, 2017, and the Two Months Ended February 
28, 2017 .................................................................................................................................................

Notes to the Consolidated Financial Statements.......................................................................................

Supplemental Quarterly Financial Data (Unaudited)................................................................................

Supplemental Oil & Natural Gas Data (Unaudited) .................................................................................

Page

88

89

90

91

93

95

132

134

87

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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 its subsidiary (the 
“Company”) as of December 31, 2019 and 2018 (Successor), the related consolidated statements of operations, equity, 
and cash flows for the year ended December 31, 2019 and 2018 (Successor), the ten months ended December 31, 2017 
(Successor),  and  the  two  months  ended  February  28,  2017  (Predecessor),  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, 2019 and 2018 (Successor) and the results of its 
operations  and  its  cash  flows  for  the  year  ended  December 31,  2019  and  2018  (Successor), the  ten  months  ended 
December 31, 2017 (Successor), and the two months ended February 28, 2017 (Predecessor), in conformity with U.S. 
generally accepted accounting principles.

Basis of Presentation

As discussed in Note 14 to the consolidated financial statements, the Company emerged from bankruptcy on February 
28, 2017. Accordingly, the accompanying consolidated financial statements have been prepared in conformity with 
Accounting Standards Codification Subtopic 852-10, Reorganizations, for the Successor as a new entity with assets, 
liabilities, and a capital structure having carrying amounts not comparable with prior periods as described in Note 14.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to 
express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm 
registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be 
independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules 
and regulations of the Securities and Exchange Commission and the PCAOB. 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and 
perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material 
misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, 
an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding 
of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the 
Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial 
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures 
included  examining,  on  a  test  basis,  evidence  regarding  the  amounts  and  disclosures  in  the  consolidated  financial 
statements.  Our  audits  also  included  evaluating  the  accounting  principles  used  and  significant  estimates  made  by 
management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that 
our audits provide a reasonable basis for our opinion. 

/s/ KPMG LLP

We have served as the Company’s auditor since 2013.
Los Angeles, California
February 27, 2020

88

BERRY CORPORATION (bry)
CONSOLIDATED BALANCE SHEETS

Current assets:

Cash and cash equivalents

ASSETS

Accounts receivable, net of allowance for doubtful accounts of $1,103 at

December 31, 2019 and $950 at December 31, 2018

Derivative instruments

Other current assets

Total current assets

Non-current assets:

Oil and natural gas properties

Accumulated depletion and amortization

Total oil and natural gas properties, net

Other property and equipment

Accumulated depreciation

Total other property and equipment, net

Derivative instruments

Other non-current assets

Total assets

LIABILITIES AND EQUITY

Current liabilities:

Accounts payable and accrued expenses

Derivative instruments

Total current liabilities

Non-current liabilities:

Long term debt

Derivative instruments

Deferred income taxes

Asset retirement obligation

Other non-current liabilities

Commitments and Contingencies - Note 5
Equity:

Common  stock  ($.001  par  value;  750,000,000  shares  authorized;  84,655,222  and 
81,651,098 shares issued; and 79,542,976 and 81,202,437 shares outstanding, at 
December 31, 2019 and December 31, 2018, respectively)

Additional paid-in capital

Treasury  stock,  at  cost  (5,112,246  shares  at  December  31,  2019  and  448,661 

December 31, 2018)

Retained earnings

Total equity

Total liabilities and equity

Berry Corp.
(Successor)
December 31, 2019 December 31, 2018

(in thousands, except share amounts)

$

— $

71,867

9,166

19,399

100,432

1,675,717

(209,105)

1,466,612

135,117

(25,462)

109,655

525

12,974

68,680

57,379

88,596

14,367

229,022

1,461,993

(123,217)

1,338,776

119,710

(15,778)

103,932

3,289

17,244

$

$

1,690,198

$

1,692,263

151,811

$

144,118

4,817

156,628

394,319

141

9,057

124,019

33,586

—

144,118

391,786

—

45,835

89,176

14,902

85

82

901,830

(49,995)

120,528

972,448

$

1,690,198

$

914,540

(24,218)

116,042

1,006,446

1,692,263

The accompanying notes are an integral part of these financial statements.

89

BERRY CORPORATION (bry)
CONSOLIDATED STATEMENTS OF OPERATIONS

Berry Corp.
(Successor)

Year Ended
December 31,
2018

Year Ended
December 31,
2019

Berry LLC
(Predecessor)

Two Months
Ended February
28, 2017

Ten Months
Ended
December 31,
2017

(in thousands, except per share amounts)

Revenues and other:

Oil, natural gas and natural gas liquid sales

$

565,596

$

552,874

$

357,928

$

Electricity sales

(Losses) gains on oil derivatives

Marketing revenues

Other revenues

Total revenues and other

Expenses and other:

Lease operating expenses

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

Losses (gains) on natural gas derivatives

Other operating expense (income)

Total expenses and other

Other income (expenses):

Interest expense

Other, net

Total other income (expenses)

Reorganization items, net

Income (loss) before income taxes

Income tax expense (benefit)

Net (loss) income

35,208

(4,621)

2,322

774

21,972

(66,900)

2,694

3,975

586,557

319,669

29,397

(37,998)

2,094

316

559,405

216,294

19,490

8,059

2,073

62,643

106,006

51,081

40,645

6,957

4,588

188,776

20,619

9,860

2,140

54,026

86,271

—

33,117

(6,357)

(2,747)

517,836

385,705

(34,234)

80

(34,154)

(426)

6,989

(36,550)

43,539

(35,648)

243

(35,405)

24,690

190,137

43,035

147,102

149,599

14,894

19,238

2,320

56,009

68,478

—

34,211

—

(22,930)

321,819

(18,454)

4,071

(14,383)

(1,732)

(18,265)

2,803

74,120

3,655

12,886

633

1,424

92,718

28,238

3,197

6,194

653

7,964

28,149

—

5,212

—

(183)

79,424

(8,245)

(63)

(8,308)

(507,720)

(502,734)

230

(21,068)

$

(502,964)

Series A Preferred Stock dividends and

conversion to common stock

Net (loss) income attributable to common

stockholders

Net (loss) income per share attributable to

common stockholders:

Basic

Diluted

$

$

$

—

(97,942)

(18,248)

43,539

$

49,160

$

(39,316)

0.54

0.53

$

$

0.85

$

0.85

(1.02)

(1.02)

n/a

n/a

n/a
n/a

The accompanying notes are an integral part of these financial statements.

90

BERRY CORPORATION (bry)
CONSOLIDATED STATEMENTS OF EQUITY

December 31, 2016

Net loss

Other

Balance before cancellation of Predecessor Equity

Cancellation of Predecessor Equity

Predecessor February 28, 2017

Berry LLC (Predecessor)

Member’s
Capital

Retained Earnings
(Accumulated Deficit)

Total Member’s
Equity

(in thousands)

$

2,798,713

$

(2,295,750) $

502,963

(502,964)

(502,964)

—

1

2,798,714

(2,798,714)

—

(2,798,714)

2,798,714

$

— $

— $

1

—

—

—

The accompanying notes are an integral part of these financial statements.

91

Berry Corp. (Successor)

Series A
Preferred
Stock

Common
Stock

Additional
Paid-in
Capital

Treasury
Stock

Retained
Earnings
(Accumulated
Deficit)

Total
Equity

(in thousands)

Issuance of Series A convertible preferred

stock

$ 335,000

$

— $

— $

— $

— $ 335,000

Issuance of Common Stock

Successor February 28, 2017

Net loss

Stock based compensation

December 31, 2017

Cash dividends declared on Series A Preferred

Stock, $0.308/share

Conversion of Series A Preferred Stock into

common stock

Cash payment to Series A Preferred

Stockholders

Issuance of common stock in initial public

offering

Repurchase of common stock

Shares withheld for payment of taxes on equity

awards

Stock based compensation

Purchase of rights to common stock

Purchase of treasury stock

Dividends declared on common stock, $0.21/

share

Net income (loss)
December 31, 2018

Shares withheld for payment of taxes on equity

awards

Stock based compensation

Purchase of rights to common stock

Purchase of treasury stock

Common stock issued to settle unsecured

claims

Dividends declared on common stock, $0.48/

—

335,000

—

—

335,000

—

(335,000)

—

—

—

—

—

—

—

—

—
—

—

—

—

—

—

share

Net income (loss)
December 31, 2019

—
—
— $

$

33

33

—

—

33

—

40

—

10

543,494

543,494

—

1,851

545,345

(11,301)

334,960

(60,273)

133,795

(2)

(23,710)

(3,700)

6,789

—

—

—

—

—

—

—

—

—

—

—

—

—

—

543,527

878,527

(21,068)

(21,068)

—

1,851

(21,068)

859,310

—

—

—

—

—

—

—

—

—

(11,301)

—

(60,273)

133,805

(23,712)

(3,699)

6,789

(20,265)

(3,953)

1

—

—

—

—

—
82

—

—

—

—

3

—
—
85

—

—

(20,265)

(3,953)

(7,365)

—

(9,992)

(17,357)

—
914,540

—
(24,218)

147,102
116,042

147,102
1,006,446

(1,268)

8,826

—

—

(20,265)

20,265

—

(3)

—
—
$ 901,830

(46,042)

—

—
—

$ (49,995) $

—

—

—

—

—

(1,268)

8,826

—

(46,042)

—

(39,053)
43,539
120,528

(39,053)
43,539
$ 972,448

The accompanying notes are an integral part of these financial statements.

92

BERRY CORPORATION (bry)
CONSOLIDATED STATEMENTS OF CASH FLOWS

Cash flow from operating activities:

Net (loss) income
Adjustments to reconcile net (income) loss to net cash

provided by (used in) operating activities:
Depreciation, depletion and amortization
Amortization of debt issuance costs
Impairment of oil and gas properties
Stock-based compensation expense
Deferred income taxes
Increase (decrease) in allowance for doubtful accounts
Other operating expenses (income)
Reorganization expenses, net (non-cash)
Derivatives activities:
Total losses (gains)
Cash settlements on derivatives
Cash payments on early-terminated derivatives

Changes in assets and liabilities:

(Increase) decrease in accounts receivable
(Increase) decrease in other assets
Increase (decrease) in accounts payable and accrued

expenses

(Decrease) increase in other liabilities
Net cash provided by operating activities

Cash flow from investing activities:

Capital expenditures:

Development of oil and natural gas properties
Changes in capital investment accruals
Purchases of other property and equipment

Acquisition of properties and equipment
Proceeds from sale of property and equipment and other

Net cash (used in) investing activities

Cash flow from financing activities:

Borrowings under RBL credit facility
Repayments on RBL credit facility
Dividends paid on common stock
Purchase of treasury stock
Shares withheld for payment of taxes on equity awards and

other

Issuance of 2026 Senior Unsecured Notes
Debt issuance costs
IPO proceeds net of issuance costs
Repurchase of common stock
Payment to preferred stockholders in conversion
Dividends paid on Series A Preferred Stock
Borrowings on emergence credit facility
Repayments on emergence credit facility
Proceeds from sale of Series A Preferred Stock
Repayments on pre-emergence credit facility

Berry Corp.
(Successor)

Year Ended
December 31,
2019

Year Ended
December 31,
2018

Ten Months
Ended
December 31,
2017

(in thousands)

Berry LLC
(Predecessor)
Two Months
Ended
February 28,
2017

$

43,539

$

147,102

$

(21,068)

$

(502,964)

106,006
5,059
51,081
8,647
(36,778)
153
5,518
—

44,955
42,197
—

(14,597)
(5,136)

(917)

(7,898)
241,829

(219,176)
12,814
(16,792)
(2,840)
969
(225,025)

355,132
(353,282)
(39,157)
(46,909)

(1,268)
—
—
—
—
—
—
—
—
—
—

86,271
5,430
—
6,750
43,946
(20)
(2,747)
(25,523)

(1,735)
(38,482)
(126,949)

(1,683)
(819)

19,526

(5,596)
105,471

(94,225)
(20,371)
(15,056)
—
8,212
(121,440)

203,510
(582,510)
(7,365)
(23,351)

(3,699)
400,000
(9,193)
133,805
(23,712)
(60,273)
(11,301)
—
—
—
—

68,478
1,988
—
1,851
1,888
970
(22,930)
—

66,900
3,068
—

(7,022)
(13,175)

6,619

19,832
107,399

(50,229)
(2,483)
(12,767)
(249,338)
234,292
(80,525)

402,285
(23,285)
—
—

—
—
(22,170)
—
—
—
—
51,000
(451,000)
—
—

28,149
416
—
—
9
—
(25)
501,872

(12,886)
534
—

(9,152)
(2,842)

18,330
990
22,431

(247)
(2,249)
(662)
—
25
(3,133)

—
—
—
—

—
—
—
—
—
—
—
—
—
335,000
(497,668)

The accompanying notes are an integral part of these financial statements.

93

Net cash (used in) provided by financing activities
Net decrease in cash and cash equivalents
Cash, cash equivalents and restricted cash:

Beginning
Ending

Berry Corp.
(Successor)

Year Ended
December 31,
2019

Year Ended
December 31,
2018

Ten Months
Ended
December 31,
2017

Berry LLC
(Predecessor)
Two Months
Ended
February 28,
2017

(85,484)
(68,680)

68,680

$

— $

(in thousands)

15,911
(58)

(43,170)
(16,296)

(162,668)
(143,370)

68,738
68,680

$

85,034
68,738

228,404
85,034

$

The accompanying notes are an integral part of these financial statements.

94

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Basis of Presentation and Significant Accounting Policies

Effective  February  18,  2020,  Berry  Petroleum  Corporation  changed  its  name  to  Berry  Corporation  (bry)  and 
introduced a new logo. We believe that the name Berry Corporation (bry) is a name that better represents our progressive 
approach to evolving and growing the business in today’s dynamic oil and gas industry. 

“Berry Corp.” refers to Berry Corporation (bry), a Delaware corporation which, on and after February 28, 2017 is 

the sole member of Berry Petroleum Company, LLC.

“Berry LLC” refers to Berry Petroleum Company, LLC, a Delaware limited liability company.

As the context may require, the “Company”, “we”, “our” or similar words refer to (i) Berry Corp. (the “Successor”) 
and Berry LLC, its consolidated subsidiary, as of and after February 28, 2017, as a whole or (ii) either Berry Corp. or 
Berry LLC on an individual basis as of and after February 28, 2017. References to historical activities of the “Company” 
prior to February 28, 2017, refer to activities of Berry LLC (the “Predecessor”).

“Linn Energy” refers to Linn Energy, LLC, a Delaware limited liability company of which Berry LLC was formerly 
a wholly-owned, indirect subsidiary and LinnCo, LLC (“LinnCo” and, together with Linn Energy, the “Linn Entities”), 
until February 28, 2017.

Nature of Business

Berry  Corp.  is  an  independent  oil  and  natural  gas  company  that  was  incorporated  under  Delaware  law  on 
February 13, 2017. Berry Corp. operates through its wholly-owned subsidiary, Berry LLC. Our properties are located 
in the United States (the “U.S.”), in California (in the San Joaquin and Ventura basins), Utah (in the Uinta basin), and 
Colorado (in the Piceance basin).

In July 2018, we completed the initial public offering (the “IPO”) of our common stock and as a result, on July 
26, 2018, our common stock began trading on the Nasdaq Global Select Market (“NASDAQ”) under the ticker symbol 
BRY.

As discussed further in Note 14, on May 11, 2016 (the “Petition Date”), the Linn entities and, consequently, Berry 
LLC, filed voluntary petitions for relief under Chapter 11 (“Chapter 11”) of the U.S. Bankruptcy Code. Berry LLC 
emerged  from  bankruptcy  as  a  stand-alone  company  separate  from  Linn  Energy  effective  February  28,  2017  (the 
“Effective Date”).

Principles of Consolidation and Reporting

The consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting 
principles (“GAAP”), which requires management to make estimates and assumptions that affect the amounts reported 
in  the  financial  statements  and  accompanying  notes.  We  eliminated  all  significant  intercompany  transactions  and 
balances upon consolidation. For oil and gas exploration and production joint ventures in which we have a direct 
working interest, we account for our proportionate share of assets, liabilities, revenue, expense and cash flows within 
the relevant lines of the financial statements. 

Reclassification

We reclassified certain prior year amounts in the cash flow statements to conform to the current year presentation. 

These reclassifications had no material impact on the financial statements. 

95

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Use of Estimates

The  preparation  of  the  accompanying  consolidated  financial  statements  in  conformity  with  GAAP  required 
management of the Company to make informed estimates and assumptions about future events. These estimates and 
the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and 
liabilities, and reported amounts of revenues and expenses.

Estimates that are particularly significant to the financial statements include estimates of our reserves of oil and 
gas, future cash flows from oil and gas properties, depreciation, depletion and amortization, asset retirement obligations, 
fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. In addition, as part of 
fresh-start accounting, we made estimates and assumptions related to our reorganization value, liabilities subject to 
compromise and the fair value of assets and liabilities recorded.

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, net of salvage, 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 in 
2019 was approximately $2 million, and in 2018 and 2017 these costs were not significant. The amount of capitalized 
exploratory well costs was zero for all periods. We only capitalize the interest on borrowed funds related to our share 
of costs associated with qualifying capital expenditures. 

We evaluate the impairment of our proved oil and natural gas properties generally on a field by field basis or at 
the lowest level for which cash flows are identifiable, whenever events or changes in circumstance indicate that the 
carrying value may not be recoverable. We reduce the carrying values of proved properties to fair value when the 
expected undiscounted future cash flows are less than net book value. We measure the fair values of proved properties 
using valuation techniques consistent with the income approach, converting future cash flows to a single discounted 
amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) 
future operating and development costs; (iii) future commodity prices; and (iv) a risk-adjusted discount rate. These 
inputs require significant judgments and estimates by our management at the time of the valuation and are the most 
96

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

sensitive estimates we make and the most likely to change. 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, 
2019 and 2018, the net capitalized costs attributable to unproved properties were approximately $314 million and $388 
million, respectively. The unproved amounts were not subject to depreciation, depletion and amortization until they 
were classified as proved properties and amortized on a unit-of-production basis. We evaluate the impairment of our 
unproved oil and gas properties whenever events or changes in circumstances indicate the carrying value may not be 
recoverable. If the exploration and development work were to be unsuccessful, or management decided not to pursue 
development  of  these  properties  as  a  result  of  lower  commodity  prices,  higher  development  and  operating  costs, 
contractual conditions or other factors, the capitalized costs of such properties would be expensed. The timing of any 
write-downs of unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of 
future  exploration  and  development  activities  and  their  results. 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, 2019.

At year end 2019, we evaluated our proved and unproved natural gas properties in regards to the decline in our 
expectations of future gas prices. As a result, we recorded a non-cash pre-tax asset impairment charge of $51 million for 
our Piceance gas properties in Colorado, of which $23 million was for proved properties and $28 million for unproved 
properties. 

Other Property and Equipment

Other  property  and  equipment  includes  natural  gas  gathering  systems,  pipelines,  buildings,  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 5 to 30 years
for buildings and leasehold improvements and 2 to 30 years for plant and pipeline, drilling and other equipment, and 
the salvage value is considered as applicable.

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 was 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 $124 million and $89 million
were included in long term liabilities as of December 31, 2019 and December 31, 2018, respectively, with the remaining 
current portion included in accrued liabilities:

97

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Beginning balance

Liabilities incurred

Settlements and payments

Accretion expense

Reduction due to property sales

Revisions

Ending balance

Berry Corp.
(Successor)

Year Ended
December 31, 2019

Year Ended
December 31, 2018

(in thousands)

$

95,548

$

11,534

(22,036)

7,570

—

56,611

$

149,227

$

97,422

4,901

(3,555)

6,258

(4,145)

(5,333)

95,548

The increase in the long-term portion of the asset retirement obligation largely reflected revisions to timing and 
cost estimates of $57 million, $12 million for new wells, and accretion expense of $8 million. A significant portion of 
the change in estimate was a result of California's new idle well regulations which became effective in the second 
quarter and accelerated the timing of abandonment of certain long existing idle wells. These increases were partially 
offset by liabilities settled or paid during the period of $22 million and an increase to the current portion of the asset 
retirement obligation of $19 million due to the change in timing and estimated costs

Revenue Recognition

Substantially all of the Company’s revenue is from the sale of crude oil, natural gas and NGLs. See Note 13 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 most significant items on our balance sheet that would be affected by recurring fair value measurements are 
derivatives. We determine the fair value of our oil and natural gas 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.

Our 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. We classify these measurements as Level 3.

98

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Stock-based Compensation

We have issued restricted stock units (“RSUs”) that vest over time and performance-based restricted stock units 
(“PSUs”) that vest based on our achievement of certain average prices per share or total shareholder return, to certain 
employees and non-employee directors. The fair value of the stock-based awards is determined at the date of grant and 
is not remeasured. Prior to our IPO in July 2018, we determined the fair value of the RSUs based on an estimate of the 
fair value of our equity using an income approach. We used a discounted cash flow method to value the estimated future 
cash flows at an appropriate discount rate. Subsequent to our IPO, since the underlying shares are now trading in the 
public markets, these estimates are no longer necessary. For PSUs, compensation value is measured on the grant date 
using payout values derived from a Monte-Carlo valuation model. 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 five cogeneration facilities. Our investment in cogeneration facilities has been for the express purpose of 
lowering steam costs in our heavy oil operations in California and securing operating control of the respective steam 
generation. Cogeneration, also called combined heat and power, extracts energy from the exhaust of a turbine, which 
would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. We allocate steam 
and electricity costs to lease operating expenses based on the conversion efficiency of the cogeneration facilities plus 
certain direct costs of producing steam. We also allocate a portion of the electricity production costs related to the power 
we sell to third parties, which is reported in “electricity generation expenses” in the statement of operations.

Income Taxes

Prior to the consummation of the Plan, as defined below, the Predecessor was a limited liability company treated 
as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas, in which 
income tax liabilities and/or benefits of the company are passed through to its members. Limited liability companies 
are subject to Texas margin tax. As such, with the exception of the state of Texas, the Predecessor was not a taxable 
entity, it did not directly pay federal and state income taxes and recognition was not given to federal and state income 
taxes for the operations of the company.

On the Effective Date, upon consummation of the Plan, the Successor became a C Corporation subject to federal 
and state income taxes. The impact of changes in tax regulation are reflected when enacted. 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 bases. 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 
99

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

not be realized. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position 
will be sustained upon examination, based on the technical merits of the position. Interest and penalties related to 
unrecognized tax benefits are recognized in income tax expense (benefit).

Earnings per Share

We computed basic and diluted earnings per share (EPS) using the two-class method required for participating 
securities. Restricted and performance stock awards are considered participating securities when such shares have non-
forfeitable dividend rights at the same rate as common stock.

Under the two-class method, undistributed earnings allocated to participating securities are subtracted from net 
income attributable to common stock in determining net income attributable to common stockholders. In loss periods, 
no allocation is made to participating securities because the participating securities do not share in losses. For basic 
EPS, the weighted-average number of common shares outstanding excludes outstanding shares related to unvested 
restricted  stock  awards.  For  diluted  EPS,  the  basic  shares  outstanding  are  adjusted  by  adding  potentially  dilutive 
securities, unless their effect is anti-dilutive.

Business and Credit Concentrations

We maintain our cash in bank deposit accounts which, at times, may exceed federally insured amounts. We have 
not experienced any losses in such accounts. We believe we are not exposed to any significant credit risk on our cash.

We also 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. Based on the current demand for oil, natural gas and 
NGLs 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, 2019, our three largest customers represented approximately 36%, 24% and 13%
of our sales. For the year ended December 31, 2018, our three largest customers represented 35%, 28%, and 13% of 
our sales. For the ten months ended December 31, 2017, our three largest customers represented approximately 36%, 
29%  and  13%  of  our  sales.  For  the  two  months  ended  February  28,  2017,  our  two  largest  customers  represented 
approximately 34% and 29% of our sales. 

At December 31, 2019, trade accounts receivable from three customers represented approximately 40%, 17%, and 
11%  of  our  receivables.  At  December 31,  2018,  trade  accounts  receivable  from  three  customers  represented 
approximately 26%, 22% and 10% of our receivables.

Bankruptcy Accounting

The consolidated financial statements have been prepared as if the Company will continue as a going concern and 
reflect the application of GAAP. GAAP requires that the financial statements, for periods subsequent to filing of the 
bankruptcy proceedings, distinguish transactions and events that are directly associated with the reorganization from 
the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in 
connection with the bankruptcy proceedings are recorded in “reorganization items, net” on our consolidated statements 
of operations. In addition, pre-petition unsecured and under-secured obligations that may be impacted by the bankruptcy 
reorganization process have been classified as “liabilities subject to compromise” on our balance sheet. These liabilities 
are reported at the amounts allowed as claims by the Bankruptcy Court, although they may be settled for less.

Upon emergence from bankruptcy on February 28, 2017, we adopted fresh-start accounting which resulted in Berry 
Corp. becoming the financial reporting entity. As a result of the application of fresh-start accounting and the effects of 
the implementation of the Plan (see Note 14 for definition), the financial statements on or after February 28, 2017 are 
not comparable to the financial statements prior to that date. See Note 14 for additional information.

100

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Recently Adopted Accounting Standards

During 2016, the FASB issued rules clarifying the new revenue recognition standard issued in 2014. The new rules 
are intended to improve and converge the financial reporting requirements for revenue from contracts with customers. 
We are an emerging growth company and elected to delay adoption of these rules until they are applicable to non-SEC 
issuers which is for fiscal years beginning after December 31, 2018. As such, we adopted these rules in the first quarter 
of 2019 and applied the modified retrospective approach, meaning the cumulative effect of initially applying the standard 
is recognized in the most current period presented in the financial statements. We have performed an analysis of existing 
contracts and determined adoption did not have a material impact on our condensed consolidated financial statements. 
In addition, we have evaluated the changes to relevant business practices, accounting policies and control activities 
and we did not experience a material change in our revenue accounting as a result of the adoption of these rules. Refer 
to Note 13 for additional disclosure information.

New Accounting Standards Issued, But Not Yet Adopted

In February 2016, the FASB issued rules requiring 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. As an 
emerging growth company, we have elected to delay the adoption of these rules until they are applicable to non-SEC 
issuers which is for fiscal years beginning after December 15, 2020, including interim periods within those fiscal years. 
We are currently identifying our lease population in accordance with the new lease standard. We expect the adoption 
of these rules to increase other assets and other liabilities on our balance sheet and we are currently evaluating the 
impact on our consolidated results of operations.

In December 2019, the FASB issued rules which simplifies the accounting for income taxes. As an emerging growth 
company, we have elected to delay the adoption of these rules until they are applicable to non-SEC issuers which is 
for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. We are currently 
evaluating the impact of these rules on our consolidated financial statements.

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:

Berry Corp. (Successor)

December 31,
2019

December 31,
2018

(in thousands)

$

1,361,814

$

1,073,959

313,903

1,675,717

(209,105)

388,034

1,461,993

(123,217)

$

1,466,612

$

1,338,776

Proved properties

Unproved properties

Total proved and unproved properties

Less accumulated depletion and amortization

Total proved and unproved properties, net

101

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Other Property and Equipment

Other property and equipment consisted of the following:

Cogens, natural gas plants and pipelines

Buildings and leasehold improvements

Vehicles and service equipment

Furniture and equipment

Land

Total other property and equipment

Less: accumulated depreciation

Total other property and equipment, net

Note 3—Debt

Berry Corp. (Successor)

December 31,
2019

December 31,
2018

(in thousands)

$

94,619

$

3,752

9,124

20,078

7,544

135,117

(25,462)

$

109,655

$

86,562

3,359

6,753

14,964

8,073

119,710

(15,778)

103,932

The following table summarizes our outstanding debt:

December 31,
2019

December 31,
2018

(in thousands)

Interest Rate

Maturity

Security

RBL Facility

$

1,850

$

—

variable rates of 5.5%
(2019) and 4.5%
(2018), respectively

June 29, 2022

Mortgage on 85% of
Present Value of proven
oil and gas reserves

2026 Notes

400,000

400,000

7.0%

February 15, 2026

Unsecured

Long-Term Debt -
Principal Amount

401,850

400,000

Less: Debt Issuance Costs

(7,531)

(8,214)

Long-Term Debt, net

$

394,319

$

391,786

Deferred Financing Costs

We incurred legal and bank fees related to the issuance of debt. At December 31, 2019 and December 31, 2018, 
debt issuance costs for the RBL Facility (as defined below) reported in “other non-current assets” on the balance sheet 
were approximately $11 million and $16 million net of amortization, respectively. At December 31, 2019 and 2018, 
debt issuance costs, net of amortization, for the 2026 Senior Unsecured Notes were both approximately $8 million.

 The amortization of debt issuance costs is presented in interest expense on the consolidated statements of operations. 
For the year ended December 31, 2019, the year ended December 31, 2018, the ten months ended December 31, 2017, 
and the two months ended February 28, 2017, the amortization expense for the RBL Facility and 2026 Senior Unsecured 
Notes were approximately $5 million, $5 million, $2 million and zero, respectively.

Fair Value

Our  debt  is  recorded  at  the  carrying  amount  on  the  balance  sheets. The  carrying  amount  of  the  RBL  Facility 
approximates fair value because the interest rates are variable and reflect market rates. The fair value of the 2026 Senior 

102

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Unsecured Notes was approximately $376 million and $368 million at December 31, 2019 and December 31, 2018, 
respectively.

The RBL Facility

On July 31, 2017, we entered into the RBL Facility. The RBL Facility provides for a revolving loan with up to  
$1.5 billion of commitments, subject to a reserve borrowing base. The RBL Facility also provides a letter of credit 
subfacility for the issuance of letters of credit in an aggregate amount not to exceed $25 million. Issuances of letters 
of credit reduce the borrowing availability for revolving loans under the RBL Facility on a dollar for dollar basis. 
Borrowing base redeterminations become effective each May and November, although each of the administrative agent 
and Berry LLC may make one interim redetermination between scheduled redeterminations. The RBL Facility has an 
elected commitment feature that allows us to increase commitments to the amount of our borrowing base with lender 
approval. In late 2019, we completed a borrowing base redetermination under our RBL Facility that set our borrowing 
base to $500 million and reaffirmed our elected commitment amount at $400 million. The RBL Facility matures on 
July 29, 2022, unless terminated earlier in accordance with the RBL Facility terms. 

As of December 31, 2019, we had approximately $2 million in borrowings outstanding, $7 million in letters of 

credit outstanding, and approximately $391 million of available borrowings capacity under the RBL Facility. 

The outstanding borrowings under the RBL Facility bear interest at a rate equal to either (i) a customary London 
interbank offered rate plus an applicable margin ranging from 2.50% to 3.50% per annum, and (ii) a customary base 
rate plus an applicable margin ranging from 1.50% to 2.50% per annum, in each case depending on levels of borrowing 
base utilization. In addition, we must pay the lenders a quarterly commitment fee of 0.50% on the average daily unused 
amount of the borrowing availability under the RBL Facility. We have the right to prepay any borrowings under the 
RBL Facility with prior notice at any time without a prepayment penalty, other than customary “breakage” costs with 
respect to euro-dollar loans.

The RBL Facility contains customary events of default and remedies for credit facilities of a similar nature. If we 
do not comply with the financial and other covenants in the RBL Facility, the lenders may, subject to customary cure 
rights, require immediate payment of all amounts outstanding under the RBL Facility and exercise all of their other 
rights and remedies, including foreclosure on all of the collateral. 

The RBL Facility requires us to maintain on a consolidated basis as of each quarter-end (i) a Leverage Ratio of no 
more than 4.00 to 1.00 and (ii) a Current Ratio of at least 1.00 to 1.00. The RBL Facility also contains customary 
restrictions. As of December 31, 2019, our Leverage Ratio and Current Ratio were 1.4:1.00 and 3.2:1.00, respectively. 
In addition, the RBL Facility currently provides that to the extent we incur unsecured indebtedness, including any 
mounts 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 RBL Facility as of December 31, 2019.

The RBL Facility permits us to repurchase equity and indebtedness, among other things, if availability is equal to 
or greater than 15% of the elected commitments or borrowing base, whichever is in effect, and our pro forma leverage 
ratio is less than or equal to 2.75 to 1.00.

Berry Corp. guarantees and each future subsidiary of Berry Corp. (other than Berry LLC), with certain exceptions, 
is required to guarantee, our obligations and obligations of the other guarantors under the RBL Facility and under certain 
hedging transactions and banking services arrangements (the “Guaranteed Obligations”). In addition, pursuant to a 
Guaranty Agreement dated as of July 31, 2017, Berry LLC guarantees the Guaranteed Obligations. The lenders under 
the RBL Facility hold a mortgage on 85% 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. The RBL Facility, with certain exceptions, also requires that any future subsidiaries of Berry LLC will also 
have to grant mortgages, security interests and equity pledges.

103

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Senior Unsecured Notes Offering

In February 2018, we completed a private issuance of $400 million in aggregate principal amount of 7.0% senior 
unsecured notes due February 2026 (the “2026 Notes”), which resulted in net proceeds to us of approximately $391 
million after deducting expenses and the initial purchasers’ discount. We used a portion of the net proceeds from the 
issuance of the 2026 Notes to repay the $379 million outstanding balance on the RBL Facility and used the remainder 
for general corporate purposes.

We may, at our option, redeem all or a portion of the 2026 Notes at any time on or after February 15, 2021. We 
are also entitled to redeem up to 35% of the aggregate principal amount of the 2026 Notes before February 15, 2021, 
with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price 
equal to 107% of the principal amount of the 2026 Notes being redeemed, plus accrued and unpaid interest, if any. In 
addition, prior to February 15, 2021, we may redeem some or all of the 2026 Notes at a price equal to 100% of the 
principal amount thereof, plus a “make-whole” premium, plus any accrued and unpaid interest. If we experience certain 
kinds of changes of control, holders of the 2026 Notes may have the right to require us to repurchase their notes at 
101% of the principal amount of the 2026 Notes, plus accrued and unpaid interest, if any.

The 2026 Notes are our senior unsecured obligations and rank equally in right of payment with all of our other 
senior  indebtedness  and  senior  to  any  of  our  subordinated  indebtedness.  The  notes  are  fully  and  unconditionally 
guaranteed on a senior unsecured basis by us and will also be guaranteed by certain of our future subsidiaries (other 
than Berry LLC). The 2026 Notes and related guarantees are effectively subordinated to all of our secured indebtedness 
(including all borrowings and other obligations under our RBL Facility) to the extent of the value of the collateral 
securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness 
and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the 2026 Notes.

The indenture governing the 2026 Notes contains restrictive covenants that may limit our ability to, among other 

things:

•

•

•

incur or guarantee additional indebtedness or issue certain types of preferred stock;

pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;

transfer, sell or dispose of assets;

• make investments;

•

•

•

•

create certain liens securing indebtedness;

enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;

consolidate, merge or transfer all or substantially all of our assets; and

engage in transactions with affiliates.

The indenture governing the 2026 Notes contains customary events of default, including, among others, (a) non-
payment; (b) non-compliance with covenants (in some cases, subject to grace periods); (c) payment default under, or 
acceleration events affecting, material indebtedness and (d) bankruptcy or insolvency events involving us or certain of 
our subsidiaries. We were in compliance with all covenants as of December 31, 2019. 

Bond Repurchase Program

In February 2020, our Board of Directors adopted a program for the opportunistic repurchase of up to $75 million
of our bonds. 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 bonds during any period or at all.  

104

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Corporate Organization 

Berry Corp., as Berry LLC's parent company, has no independent assets or operations. Any guarantees of potential 
future registered debt securities by Berry Corp. or Berry LLC would be full and unconditional. Berry Corp. and Berry 
LLC currently do not have any other subsidiaries. In addition, there are no significant restrictions upon the ability of 
Berry LLC to distribute funds to Berry Corp. by distribution or loan other than under the RBL Facility. None of the 
assets of Berry Corp. or Berry LLC represent restricted net assets.  

The RBL permits Berry LLC to make distributions to Berry Corp. so long as both before and after giving pro forma 
effect to such distribution no default or borrowing base deficiency exists, availability equals or exceeds 15% of the 
then effective borrowing base, and Berry Corp. demonstrates a pro forma leverage ratio less than or equal to 2.75 to 
1.00. The conditions are currently met with significant margin. 

Note 4—Derivatives

We utilize derivatives, such as swaps, puts and calls, to hedge a portion of our forecasted oil production and gas 
purchases to reduce exposure to fluctuations in oil and natural gas prices. We target covering our operating expenses 
and a majority of our fixed charges, including capital for sustained production levels, interest and dividends, with the 
oil hedges for a period of up to two years out. We have hedged a portion of our exposure to differentials between ICE 
Brent oil (“Brent”) and NYMEX West Texas Intermediate oil (“WTI”). Additionally, we target fixing the price for a 
large portion of our natural gas purchases used in our steam operations for up to two years. We 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.

For fixed-price oil swaps, we make settlement payments for prices above the indicated weighted-average price per 
barrel of Brent or WTI and receive settlement payments for prices below the indicated weighted average price per 
barrel of Brent or WTI.

For oil basis swaps, we make settlement payments if the difference between Brent and WTI is greater than the 
indicated weighted-average price per barrel of our contracts and receive settlement payments if the difference between 
Brent and WTI is below the indicated weighted-average price per barrel.

For our purchased oil puts, we would receive settlement payments for prices below the indicated weighted-average 
price per barrel of Brent. For some of our purchased puts we paid a premium at the time the positions were created and 
for others, the premium payment is deferred until the time of settlement. We have mitigated the exposure to a substantial 
portion of the deferred premium payments by entering into offsetting put positions. We paid approximately $17 million
of the net deferred premiums during the year ended December 31, 2019, which included premiums we received during 
these periods. As of December 31, 2019 we have offsetting put positions with an outstanding net deferred premium of 
approximately $55,000, which is reflected in the mark-to-market valuation and will be payable through the first quarter 
of 2020. 

For our sold oil calls, we would make settlement payments for prices above the indicated weighted-average price 

per barrel of Brent. 

For fixed-price gas purchase swaps, we are the buyer so we make settlement payments for prices below the weighted-
average price per MMBtu and receive settlement payments for prices above the weighted-average price per MMBtu.

We use oil swaps and puts to protect against decreases in the oil price and natural gas swaps to protect against 
increases in natural gas prices. We do not enter into derivative contracts for speculative trading purposes and have not 
accounted for our derivatives as cash-flow or fair-value hedges. The changes in fair value of these instruments are 
recorded in current earnings. (Gains) losses on oil hedges are classified in the revenues and other section of the statement 

105

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

of operations and (gains) losses on natural gas hedges are presented in the expenses and other section of the statement 
of operations.

As of December 31, 2019, we had the following crude oil production and gas purchases hedges.

Fixed Price Oil Swaps (Brent):

Hedged volume (MBbls)

Weighted-average price ($/Bbl)

Fixed Price Oil Swaps (WTI):

Hedged volume (MBbls)

Weighted-average price ($/Bbl)

Fixed Price Gas Purchase Swaps (Kern, Delivered):

Hedged volume (MMBtu)

Weighted-average price ($/MMBtu)

Fixed Price Gas Purchase Swaps (SoCal Citygate):

  Hedged volume (MMBtu)

  Weighted-average price ($/MMBtu)

Q1 2020

Q2 2020

Q3 2020

Q4 2020

FY 2021

1,729

1,456

1,472

1,472

730

$

63.92

$

64.30

$

64.21

$

64.21

$

58.50

91

30

—

—

$

61.75

$

61.75

$

— $

— $

—

—

5,005,000

5,005,000

5,060,000

2,315,000

900,000

$

$

2.89

$

2.89

$

2.89

$

2.79

$

2.50

455,000

455,000

460,000

155,000

3.80

$

3.80

$

3.80

$

3.80

$

—

—

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, 2019 and 
December 31, 2018:

Berry Corp. (Successor)

December 31, 2019

Balance Sheet
Classification

Gross Amounts
Recognized at Fair Value

Gross Amounts Offset
on Balance Sheet

Net Fair Value Presented
on Balance Sheet

Assets:

Commodity Contracts

Current assets

Commodity Contracts

Non-current assets

Liabilities:

Commodity Contracts

Current liabilities

Commodity Contracts

Non-current liabilities

Total derivatives

$

$

(in thousands)

17,799

$

773

(13,450)

(389)

4,733

$

(8,633) $

(248)

8,633

248

— $

9,166

525

(4,817)

(141)

4,733

106

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Berry Corp. (Successor)

December 31, 2018

Balance Sheet
Classification

Gross Amounts
Recognized at Fair Value

Gross Amounts Offset
in the Balance Sheet

Net Fair Value Presented
in the Balance Sheet

Assets:

Commodity Contracts

Current assets

Commodity Contracts

Non-current assets

Liabilities:

Commodity Contracts

Current liabilities

Total derivatives

$

$

(in thousands)

89,981

$

3,289

(1,385)

91,885

$

(1,385) $

—

1,385

— $

88,596

3,289

—

91,885

In May 2018, we elected to terminate outstanding commodity derivative contracts for all WTI oil swaps and certain 
WTI/Brent basis swaps for July 2018 through December 2019 and all WTI oil sold call options for July 2018 through 
June 2020. Termination costs totaled approximately $127 million and were calculated in accordance with a bilateral 
agreement on the cost of elective termination included in these derivative contracts; the present value of the contracts 
using the forward price curve as of the date termination was elected. No penalties were charged as a result of the elective 
termination. Concurrently, Berry Corp. entered into commodity derivative contracts consisting of Brent oil swaps for 
July 2018 through March 2019.

By  using  derivative  instruments  to  economically  hedge  exposure  to  changes  in  commodity  prices,  we  expose 
ourselves to credit risk and market 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 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 A3  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 mitigates the counterparty nonperformance risk somewhat.

(Losses) Gains on Derivatives

A summary of losses and gains on the derivatives included on the statements of operations is presented below:

Year Ended
December 31,
2019

Berry Corp.
(Successor)

Year Ended
December 31,
2018

Ten Months
Ended
December 31,
2017

Berry LLC
(Predecessor)

Two Months
Ended
February 28,
2017

(in thousands)

(Losses) gains on oil derivatives

(Losses) gains on natural gas derivatives

Total (losses) gains on oil and natural gas

derivatives

$

$

(37,998) $

(4,621) $

(66,900)

$

12,886

(6,957)

6,357

—

—

(44,955) $

1,735

$

(66,900)

$

12,886

For the year ended December 31, 2019, we received net cash scheduled settlements of approximately $42 million. 
For the year ended December 31, 2018, we paid net cash scheduled settlements of approximately $38 million, excluding 

107

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

the payments for the early terminated derivatives. For the ten months ended December 31, 2017, and the two months 
ended February 28, 2017, we received net cash settlements of approximately $3 million, and $0.5 million, respectively.

Note 5—Commitments and Contingencies

In the normal course of business, we, or our subsidiary, are subject to lawsuits, environmental and other claims 
and other contingencies that seek, or may seek, among other things, compensation for alleged personal injury, breach 
of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.

We accrue reserves 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, 2019 and December 31, 2018. 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 reserves 
accrued on our balance sheet would not be material to our consolidated financial position or results of operations.

We, or our subsidiary, 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, 2019, we are not 
aware of material indemnity claims pending or threatened against us.

On May 11, 2016 our predecessor company filed the Chapter 11 Proceeding. Our bankruptcy case was jointly 
administered with that of Linn Energy and its affiliates under the caption In re Linn Energy, LLC, et al., Case No. 
16-60040. On January 27, 2017, the Bankruptcy Court approved and confirmed the Plan. On February 28, 2017, the(cid:3)
Effective Date occurred and the Plan became effective and was implemented. A final decree closing the Chapter 11(cid:3)
Proceeding was entered September 28, 2018, with the Court retaining jurisdiction as described in the confirmation(cid:3)
order and without prejudice to the request of any party-in-interest to reopen the case including with respect to certain,(cid:3)
immaterial remaining matters.

We  have  certain  commitments  under  contracts,  including  purchase  commitments  for  goods  and  services.  We 
previously had an obligation to a counterparty in connection with our Piceance assets to either build a road or secure 
a  license  for  alternative  access,  in  lieu  of  paying  a  $6  million  penalty. As  of  December 31,  2019,  we  fulfilled  the 
obligation  by  delivering  the  access  license  pursuant  to  the  agreement.  The  counterparty  has  since  filed  a  claim 
challenging the sufficiency of such access. 

In addition, we entered into certain firm commitments to secure transportation of our natural gas production to 
market as well as pipeline and processing capacity which require a minimum monthly charge regardless of whether 
the contracted capacity is used or not. We have also entered into operating lease agreements mainly for office space. 
Lease payments are generally expensed as part of general and administrative expenses. At December 31, 2019, future 
net minimum payments for non-cancelable purchase obligations and operating leases (excluding oil and natural gas 
and other mineral leases, utilities, taxes and insurance and maintenance expense) were as follows:

2020

2021

2022

2023

2024

Thereafter

Total

(in thousands)

Minimum purchase obligations(1)
Minimum lease payments

$

$

7,136 $

1,723 $

2,675 $

1,731 $

2,590 $

1,740 $

1,061 $

1,647 $

— $

— $

13,462

1,420 $

3,708 $

11,969

__________
(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 transportation of our natural gas production to market as well as pipeline and processing capacity.

108

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6—Equity

On the Effective Date, Berry Corp. filed with the Secretary of State of the State of Delaware the Amended and 
Restated  Certificate  of  Incorporation  of  Berry  Corp.  (the  “Certificate  of  Incorporation”)  and  the  Certificate  of 
Designation of Series A Convertible Preferred Stock of Berry Corp. (the “Series A Certificate of Designation”). Berry 
Corp.  also  adopted  the Amended  and  Restated  Bylaws  of  Berry  Corp.  (the  “Bylaws”)  on  the  Effective  Date. The 
Certificate of Incorporation provides that Berry Corp.’s authorized capital stock consists of 750,000,000 shares of 
common stock, par value $0.001 per share, and 250,000,000 shares of undesignated preferred stock, par value $0.001
per share.

Cash Dividends

Our board of directors approved a $0.12 per share quarterly cash dividend on our common stock each quarter in 
2019 for a total of $0.48 per share. We paid the fourth quarter dividend in January 2020 and declared the first quarter 
dividend of $0.12 per share in February 2020, which is payable in April 2020. For the year ended December 31, 2019 
we paid approximately $39 million in cash dividends on our common stock. 

For the year ended December 31, 2018, we declared cash dividends on our common stock beginning at our IPO, 

resulting in $0.21 per share. In 2018 we paid approximately $7 million in cash dividends on our common stock. 

Common Stock

The Plan contemplated the distribution of 40,000,000 shares of common stock in Berry Corp. On the Effective 
Date, 32,920,000 shares of common stock were distributed, pro rata, to holders of Unsecured Notes claims. The holders 
of Unsecured Claims received a right to receive their pro rata share of either (i) 7,080,000 shares of common stock in 
Berry Corp. or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from 
the Cash Distribution Pool. Since the Effective Date we have negotiated with all claimants to settle their claims and in 
2019 we issued approximately 2,770,000 shares instead of 7,080,000 to resolve these claims for approximately $20 
million.

Voting Rights. Each share of common stock is entitled to one vote with respect to each matter on which holders 

of common stock are entitled to vote. Holders of common stock do not have cumulative voting rights.

Dividend Rights. Holders of common stock will be entitled to receive dividends, if any, as may be declared from 

time to time by our board of directors (the “Board”) out of legally available funds.

Liquidation Rights. Upon liquidation, dissolution or winding up of the Company, subject to the rights of the holders 
of outstanding preferred stock, 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.

Holders of preferred stock that is outstanding may be entitled to dividend or liquidation preferences over holders 
of our common stock, which means that the Company would have to pay distributions to holders of preferred stock 
before paying any distributions to holders of our common stock.

Preemptive and Conversion Rights. Holders of common stock have no preemptive, conversion or other rights to 

subscribe for additional shares.

Preferred Stock

On the Effective Date, we issued 35,845,001 shares of preferred stock to participants in the rights offerings extended 
by the Company to certain holders of claims and in satisfaction of a backstop commitment fee for proceeds of $335 
109

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

million. In July 2018, all shares of our Series A Preferred Stock, approximately 37.7 million in total, were converted 
to approximately 39.6 million common shares and, as a result, there were no shares of our Series A Preferred Stock 
outstanding as of December 31, 2018 and December 31, 2019. 

Dividend Rights. Holders of Series A Preferred Stock were entitled to receive, when, as and if declared by the 
board of directors, cumulative dividends at a rate of 6.0% per annum either in cash or in additional shares of Series A 
Preferred Stock at the discretion of the board of directors. No dividends had been declared or paid as of December 31, 
2017. The accreted cumulative and per share value of the dividends as of December 31, 2017 was approximately $18 
million and $0.51, respectively.

In 2018, the board of directors approved a 0.050907 per share cumulative paid-in-kind dividend on the Series A 
Preferred Stock of approximately 1,825,000 shares for the periods through December 31, 2017. Also in 2018, the board 
approved $0.308 per share, or approximately $11.3 million in cash dividends on the Series A Preferred Stock.

A beneficial conversion feature exists when the effective conversion price of a convertible security is less than the 
fair value per share on the commitment date. The conversion price of the preferred stock on the date of issuance was 
less than the estimated fair value of the common stock distributable under the Plan. Since the preferred stock is not 
mandatorily redeemable and is immediately convertible, the entire amount of the beneficial conversion feature was 
recognized immediately. In accordance with GAAP, we recorded a non-cash deemed dividend and a corresponding 
increase to additional paid in capital of approximately $27 million that is attributable to this beneficial conversion 
feature. The financial statement impact of the deemed dividend is eliminated in the consolidated statement of equity 
as adopting fresh-start accounting results in an entity with no beginning retained earnings or accumulated deficit.

Registration Rights Agreement

On  the  Effective  Date,  Berry  Corp.  entered  into  a  registration  rights  agreement  (the  “Registration  Rights 
Agreement”) with certain holders of the Unsecured Notes. Subsequently, the registration rights agreement was amended 
and restated in connection with our IPO.

In accordance with the Registration Rights Agreement, Berry Corp. filed a shelf registration statement with the 
SEC subsequent to the Effective Date. The shelf registration statement registered the resale, on a delayed or continuous 
basis, of all Registrable Securities that have been timely designated for inclusion by specified Holders (as defined in 
the Registration Rights Agreement). Generally, “Registrable Securities” includes (i) common stock issued or to be 
issued by Berry Corp. under the Plan, (ii) preferred stock that was purchased by the participants in the Berry Rights 
Offerings 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.

Initial Public Offering of Common Stock

In July 2018, we completed our IPO and as a result, on July 26, 2018, our common stock began trading on the 
NASDAQ under the ticker symbol BRY. We received approximately $110 million of net proceeds, after deducting 
underwriting discounts and offering expenses payable by us, for the 8,695,653 shares of common stock issued for our 
benefit in the IPO, net of the shares sold for the benefit of certain selling stockholders. The price to the public for the 
shares sold in our IPO was $14.00 per share. See “—Use of IPO proceeds” below for additional information. 

In connection with the IPO, each of the 37.7 million shares of our Series A Preferred Stock was automatically 
converted into 1.05 shares of our common stock or 39.6 million shares in aggregate and the right to receive a cash 
payment of $1.75 (the “Series A Preferred Stock Conversion”). The cash payment was reduced in respect of any cash 
dividend paid by the Company on such share of Series A Preferred Stock for any period commencing on or after April 
1, 2018. Because we paid the second quarter preferred dividend of $0.15 per share in June, the cash payment for the 
conversion was reduced to $1.60 per share, or approximately $60 million. In connection with the IPO, we assigned the 
110

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

additional 1.9 million shares of common stock issued in the Series A Preferred Stock Conversion a value of $14.00 per 
share, which was equal to the value of shares sold in the IPO. This approximate $27 million value and the $60 million
conversion cash payment reduced the income attributable to common stockholders by approximately $87 million for 
the year ended December 31, 2018. 

Shares Outstanding

As  of  December 31,  2019,  there  were  79,542,976  shares  of  common  stock  outstanding.  Up  to  an  additional 
2,348,334 shares were issuable for unvested restricted stock units and performance restricted stock units under the 
Company's 2017 Omnibus Incentive Plan as of December 31, 2019. 

Stock Repurchase Program

In December 2018, our Board of Directors adopted a program for the opportunistic repurchase of up to $100 million
of  our  common  stock.  Based  on  the  Board’s  evaluation  of  current  market  conditions  for  our  common  stock  they 
authorized current repurchases of up to $50 million under the program. Purchases may be made from time to time in 
the open market, in privately negotiated transactions or otherwise. The manner, timing and amount of any purchases 
will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements 
and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to 
purchase shares during any period or at all. Any shares acquired will be available for general corporate purposes. 

In 2019 the Company repurchased 4,609,021 shares at an average price of $9.99. Since 2018 the Company has 
repurchased a total of 5,057,682 shares at an average price of $9.88 per share under the Stock Repurchase Program, 
which is reflected as treasury stock.  In February 2020, the Board of Directors authorized the remaining $50 million
of our $100 million repurchase program.

Stock-Based Compensation

The RSUs awarded are service based awards. The performance-based restricted stock units PSUs awarded include 
(i) awards that vest if the Company's stock price reaches certain levels over defined periods of time and (ii) awards
with  a market objective measured against both absolute total stockholder return (“Absolute TSR”) and total stockholder
return relative (“Relative TSR”), to the Vanguard World Fund - Vanguard Energy ETF index (the “Index”) over the
performance period, assuming the reinvestment of dividends. Depending on the results achieved during the two or 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 200% of the Target Shares granted.

The fair value of the PSUs was determined using a Monte Carlo simulation analysis to estimate the total shareholder 
return ranking of the Company, including a comparison against the Index over the performance periods. The expected 
volatility of the Company’s common stock at the date of grant was estimated based on blended historical average 
volatility rates for the Company and selected guideline public companies. The dividend yield assumption was based 
on the current annualized declared dividend. The risk-free interest rate assumption was based on observed interest rates 
consistent with the approximate two and three year performance measurement period.

As of July 2018, the fair value of our common stock underlying our stock-based compensation awards granted 
will no longer be based on complex models using inputs and assumptions, but will be based on the price of our stock 
at the date of grant.

On June 27, 2018, our board of directors adopted the second amended and restated 2017 Omnibus Incentive Plan, 
as amended and restated (our “Restated Incentive Plan”). This plan constitutes an amendment and restatement of the 
plan (the “Prior Plan”) as in effect immediately prior to the adoption of the Restated Incentive Plan. The Prior Plan 
constituted an amendment and restatement of the plan originally adopted as of June 15, 2017 (the “2017 Plan”). The 
Restated Incentive Plan provides for the grant, from time to time, at the discretion of the board of directors or a committee 
111

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

thereof, of stock options, stock appreciation rights (“SARs”), restricted stock, restricted stock units, stock awards, 
dividend equivalents, other stock-based awards, cash awards and substitute awards. The maximum number of shares 
of common stock that may be issued pursuant to an award under the Restated Incentive Plan is 10,000,000 inclusive 
of the number of shares of common stock previously issued pursuant to awards granted under the Prior Plan or the 
2017 Plan. The maximum number of shares remaining that may be issued is 6,954,454 as of December 31, 2019.

For the year ended December 31, 2019, year ended December 31, 2018, ten months ended December 31, 2017 
and two months ended February 28, 2017 the stock-based compensation expense was approximately $9 million, $7 
million, $2 million and zero, respectively. For the years ended December 31, 2019 and year ended December 31, 2018 
the stock-based compensation had an income tax benefit of approximately zero and $1.5 million, respectively.

The table below summarizes the activity relating RSUs issued under the Restated Incentive Plan during the year 
ended December 31, 2019. The RSUs vest ratably over three years. Unrecognized compensation cost associated with 
the RSUs at December 31, 2019 was approximately $8 million which will be recognized over a weighted-average 
period of approximately two years. 

Non-vested at December 31, 2018

Granted

Vested

Forfeited

Non-vested at December 31, 2019

Number of shares

Weighted-average
Grant Date Fair Value

(shares in thousands)

641

767

$

$

(308) $

(86) $

1,014

$

10.82

12.62

10.87

12.19

12.05

The table below summarizes the activity relating to the PSUs issued under the Revised Incentive Plan during the 
year ended December 31, 2019. Unrecognized compensation cost associated with the PSUs at December 31, 2019 is 
approximately $5 million which will be recognized over a weighted-average period of approximately two years. 

Non-vested at December 31, 2018

Granted

Vested

Forfeited

Non-vested at December 31, 2019

Use of IPO Proceeds

Number of shares

Weighted-average
Grant Date Fair Value

(shares in thousands)

282

554

$

$

— $

(38) $

798

$

6.73

12.75

—

9.69

10.77

Of the approximately $110 million of net proceeds received by us in the IPO, we used approximately $105 million
to repay borrowings under our RBL Facility. This included the $60 million we borrowed on the RBL Facility to make 
the payment due to the holders of our Series A Preferred Stock in connection with the conversion of preferred stock to 
common stock. We used the remainder for general corporate purposes. 

112

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In connection with the IPO, on July 17, 2018, we entered into stock purchase agreements with certain funds affiliated 
with Oaktree Capital Management and Benefit Street Partners, pursuant to which we purchased an aggregate of 410,229
and 1,391,967 shares of our common stock, respectively, or 1,802,196 in total. In addition to the 8,695,653 shares of 
common stock issued and sold for our benefit in the IPO, we simultaneously received $24 million for selling 1,802,196
shares  to  the  public  and  paid  $24  million  to  purchase  1,802,196  shares  under  the  stock  purchase  agreements. We 
purchased  the  shares  immediately  following  the  closing  of  the  IPO  and  retired  and  returned  them  to  the  status  of 
authorized but unissued shares. The selling stockholders also directly sold an additional 2,545,630 shares at a price to 
the public of $14.00 per share for which we did not receive any proceeds.

Note 7—Defined Contribution Plan

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. The 401(k) plan provides for a matching 
contribution of up to 6% of an employee’s eligible compensation. Employees are eligible to participate in the 401(k) 
plan on their date of hire.

We expensed approximately $1.7 million, $1.4 million, $0.8 million, and zero for the year ended December 31, 
2019, year ended December 31, 2018, the ten months ended December 31, 2017, and the two months ended February 
28, 2017, respectively, under the provisions of the 401(k) plan.

Note 8—Income taxes   

Prior to the Effective Date, Berry LLC was a limited liability company treated as a disregarded entity for federal 
and state income tax purposes, with the exception of the state of Texas. Limited liability companies are subject to Texas 
margin tax. As such, with the exception of the state of Texas, Berry LLC was not a taxable entity, it did not directly 
pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations 
of Berry LLC. Upon emergence from bankruptcy, Berry Corp. acquired the assets of Berry LLC in a taxable asset 
acquisition as part of the restructuring. Consequently, we are now taxed as a corporation and have no net operating loss 
carryforwards for the periods prior to February 28, 2017.

On  December  22,  2017,  the  U.S. Tax  Cuts  and  Jobs Act  (the  “Act”)  made  significant  changes  to  the  Internal 
Revenue Code of 1986, including lowering the maximum federal corporate income tax rate from 35% to 21% and 
imposing limitations on the use of net operating losses arising in taxable years ending after December 31, 2017. The 
SEC permitted the recognition of provisional amounts based on a reasonable estimate, subject to adjustments in a one-
year measurement period. For the ten months ended December 31, 2017, we recorded provisional estimates for the 
remeasurement of our net deferred tax asset before valuation allowance of $2.7 million for the reduction in the corporate 
tax rate and a $1.9 million increase in the valuation allowance as a result of the Act. During 2018, we completed our 
accounting related to the income tax effects of the Act, resulting in no significant adjustments to the provisional amounts 
recorded.

The key contributor to the change in our effective rate from 23% in the year ended December 31, 2018 to (523)%
for the year ended December 31, 2019 is due to the recognition of US federal general business credits in 2019 and are 
related to the 2017 and 2018 tax periods.  These credits are available to offset future federal income tax liabilities.

113

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Income tax expense (benefit) consisted of the following:

Berry Corp.
(Successor)

Berry LLC
(Predecessor)

Year Ended
December 31, 2019

Year Ended
December 31, 2018

Ten Months Ended
December 31, 2017

Two Months Ended
February 28, 2017

(in thousands)

Current taxes:

Federal

State

Total current taxes

Deferred taxes:

Federal

State

Total deferred taxes

$

— $

(465) $

227

227

(36,756)

(21)

(36,777)

(446)

(911)

33,227

10,719

43,946

Total current and deferred taxes

$

(36,550) $

43,035

$

A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:

465

450

915

1,888

—

1,888

2,803

$

$

—

221

221

—

9

9

230

Berry Corp.
(Successor)

Berry LLC
(Predecessor)

Year Ended
December 31, 2019

Year Ended 
December 31, 2018

Ten Months Ended
December 31, 2017

Two Months Ended
February 28, 2017

Federal statutory rate

State, net of federal tax benefit

Effect of permanent differences

Tax credits and federal return to provision

State return to provision

Tax reform—rate change(1)
Income excluded from nontaxable entities

Change in valuation allowance

Effective tax rate

21.0 %

8.9 %

0.2 %

(546.4)%

(6.6)%

— %

— %

— %

(522.9)%

21.0 %

6.3 %

(0.6)%

— %

— %

— %

— %

(4.1)%

22.6 %

35.0 %

7.2 %

(0.4)%

— %

— %

(14.7)%

— %

(42.4)%

(15.3)%

35.0 %

— %

— %

— %

— %

— %

(35.0)%

— %

— %

__________
(1) For the ten months ended December 31, 2017, includes the tax rate reduction. The impact of the rate change is fully offset in the “Change in 

valuation allowance” item.

114

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

Tax credits and federal return to provision

Interest limitation carryforward

Other

Total deferred tax assets

Deferred tax liabilities:

Book tax differences in property basis

Derivative instruments

Total deferred tax liabilities

Net deferred tax asset (liability)

Berry Corp. (Successor)

December 31,
2019

December 31,
2018

(in thousands)

$

14,542

$

12,218

41,382

47,803

13,892

5,154

134,991

(143,896)

(152)

(144,048)

$

(9,057) $

14,310

2,993

26,383

—

7,486

2,033

53,205

(95,348)

(3,692)

(99,040)

(45,835)

As of December 31, 2019, the Company had approximately $56 million of federal net operating loss (“NOL”) 
carryforwards and $33 million of state net operating loss carryforwards. The federal net operating loss carryovers have 
no expiration date. State net operating loss carry forwards will expire in varying amounts beginning after taxable year 
ended 2027. In addition, as of December 31, 2019, the Company had US federal general business tax credit carryforwards 
totaling $48 million, which, if unused, will expire after taxable years ended 2037.

The Act signed into law in 2017 imposed new limitations on the ability to deduct interest paid or accrued.  As of 
December 2019, we recorded a deferred tax asset related to the $66 million tax benefit of interest expense that was not 
currently deductible in tax years 2018 and 2019. This attribute can be carried forward indefinitely but utilized subject 
to certain annual limitations.  

We assessed the available positive and negative evidence to estimate whether sufficient future taxable income will 
be generated to permit use of the existing deferred tax assets. As of December 31, 2019, due to the positive evidence 
of cumulative income since the Effective Date and the reversal of existing federal and state temporary differences, we 
determined there is sufficient positive evidence to conclude that it is more likely than not that our deferred tax assets 
are realizable.

Unrecognized tax benefits - January 1

Prior year - increase

Current year - increase

Unrecognized tax benefits - December 31

115

Berry Corp. (Successor)

December 31,
2019

December 31,
2018

(in thousands)

— $

6,720

7,172

13,892

$

$

$

—

—

—

—

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The $13.9 million of unrecognized tax benefits as of December 31, 2019 do not affect the effective tax rate if 
recognized. We believe it is reasonably possible that the total unrecognized benefits may significantly decrease within 
the next 12 months as new guidance and regulations related to the Act are issued. No penalties or interest expense have 
been accrued on unrecognized tax benefits as of December 31, 2019.  

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  2017,  2018,  and  2019  federal  and  state  tax  returns  remain  open  to 
examination under the respective statute of limitations.

Note 9—Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows

Other current assets reported on the balance sheets included the following:

Prepaid expenses

Materials and supplies

Oil inventories

Other

Other current assets

Berry Corp. (Successor)

December 31, 2019 December 31, 2018

$

$

(in thousands)

4,577

$

10,544

3,432

846

4,656

5,461

3,786

464

19,399

$

14,367

Other non-current assets at December 31, 2019 and December 31, 2018 included approximately $11 million and 

$16 million of deferred financing costs, net of amortization, respectively.

Accounts payable and accrued expenses on the balance sheets included the following:

Accounts payable-trade

Accrued expenses

Royalties payable

Taxes other than income tax liability

Accrued interest

Dividends payable

Asset retirement obligation - current portion

Other

Berry Corp. (Successor)

December 31, 2019 December 31, 2018

(in thousands)

$

25,475

$

45,589

25,385

9,150

10,500

9,888

25,208

616

13,564

66,417

26,189

10,766

10,500

9,992

6,372

318

Total accounts payable and accrued expenses

$

151,811

$

144,118

Other non-current liabilities at December 31, 2019 and December 31, 2018 included approximately $33 million 

and $15 million of greenhouse gas liability, respectively. 

Supplemental  Information on the Statement of Operations

Other operating (income) expenses mainly consist of excess abandonment costs, as well as gain (loss) on sale of 

assets.

116

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Supplemental Cash Flow Information

Supplemental disclosures to the statements of cash flows are presented below:

Supplemental Disclosures of Significant Non-Cash

Investing Activities:
Material inventory transfers to oil and natural gas
properties

Supplemental Disclosures of Cash Payments (Receipts):

Interest, net of amounts capitalized

Income taxes

Reorganization items, net

Berry Corp.
(Successor)

Year Ended
December 31,
2019

Year Ended
December 31,
2018

Ten Months
Ended
December 31,
2017

(in thousands)

Berry LLC
(Predecessor)

Two Months
Ended February
28, 2017

$

$

$

$

10,056

30,720

$

$

(2) $

— $

2,371

19,761

$

$

(1,901) $

832

$

— $

—

14,276

1,994

1,732

$

$

$

8,057

—

11,838

The  following  table  provides  a  reconciliation  of  cash,  cash  equivalents  and  restricted  cash  as  reported  in  the 

consolidated statements of cash flows to the line items within the consolidated balance sheets:

Beginning of Period

Cash and cash equivalents

Restricted cash

Restricted cash in other noncurrent assets

Cash, cash equivalents and restricted cash

Ending of Period

Cash and cash equivalents

Restricted cash

Restricted cash in other noncurrent assets

Cash, cash equivalents and restricted cash

Berry Corp.
(Successor)

Year Ended
December 31,
2019

Year Ended
December 31,
2018

Ten Months
Ended
December 31,
2017

(in thousands)

Berry LLC
(Predecessor)

Two Months
Ended February
28, 2017

$

$

$

$

68,680

$

33,905

$

—

—

34,833

—

$

32,049

52,860

125

30,483

197,793

128

68,680

$

68,738

$

85,034

$

228,404

— $

68,680

$

—

—

—

—

$

33,905

34,833

—

— $

68,680

$

68,738

$

32,049

52,860

125

85,034

Restricted cash is associated with cash reserved to settle claims with general unsecured creditors. Cash and cash 
equivalents consists primarily of highly liquid investments with original maturities of three months or less and are 
stated at cost, which approximates fair value. As part of our cash management system, we use a controlled disbursement 
account to fund cash distribution checks presented for payment by the holder. Checks issued but not yet presented to 
banks may result in overdraft balances for accounting purposes in the accounts payable and accrued expenses account.

117

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10—Certain Relationships and Related Party Transactions

In connection with our emergence from bankruptcy, we entered into agreements with certain of our affiliates and 

with parties who received shares of our common stock and Series A Preferred Stock in exchange for their claims. 

Transition Services and Separation Agreement (“TSSA”)

On the Effective Date, Berry LLC entered into a TSSA with Linn Energy and certain of its subsidiaries to facilitate 
the separation of Berry LLC’s operations from Linn Energy’s operations. Under the TSSA, Berry LLC reimbursed Linn 
Energy for third-party out-of-pocket costs and expenses actually incurred by Linn Energy in connection with providing 
certain transition services. For the ten months ended December 31, 2017, we incurred management fee expenses of 
approximately $17 million under the TSSA. Since the agreement commenced on the Effective Date, no expenses were 
incurred for the periods ended February 28, 2017. 

Note 11—Acquisitions and Divestitures

During  2019  we  had  various  property  acquisitions  of  approximately  $2.9  million  that  individually  were  not 

significant.

Disposition of East Texas Properties

On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas 
basin for approximately $7 million, before purchase price adjustments, which resulted in a gain of approximately $4 
million. Production comprised approximately 0.7 MBoe per day of natural gas in the third quarter of 2018.

Acquisition of Chevron North Midway-Sunset

In April 2018, we acquired 2 leases on an aggregate of 214 acres of land owned by Chevron U.S.A. in the north 
Midway-Sunset  field  immediately  adjacent  to  assets  we  currently  operate. We  assumed  a  drilling  commitment  of 
approximately $35 million to drill 115 wells on or before April 1, 2020, which we extended to April 1, 2022. We drilled 
18 wells of these wells as of December 31, 2019. We paid no other consideration for the acquisition. Our drilling 
commitment will be tolled for a month for each consecutive 30-day period for which the posted price of WTI is less 
than $45 per barrel. This transaction is consistent with our business strategy to investigate areas beyond our known 
productive areas.

Disposition of Hugoton Properties

On July 31, 2017, we divested our 78% working interest in the Hugoton natural gas field located in Southwest 
Kansas and the Oklahoma Panhandle (the “Hugoton Disposition”) because we deemed it a non-core asset. This resulted 
in approximately $234 million of proceeds and a $23 million gain.

Acquisition of Hill Properties

On July 31, 2017, we acquired the remaining 84% working interest in the South Belridge Hill property located in 
Kern County, California, in which we previously owned a 16% working interest (the “Hill Acquisition”). We purchased 
the properties for approximately $249 million.

Note 12—Earnings Per Share

The Predecessor was organized as a limited liability company and, as such, did not issue any stock. Accordingly, 

we have not presented earnings per share calculations for the predecessor company periods. 

118

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We calculate basic earnings (loss) per share by dividing net income (loss) attributable to common stockholders by 
the weighted-average number of common shares outstanding during the year ended December 31, 2019, year ended 
December 31, 2018, and ten months ended December 31, 2017 which is approximately 81 million, 58 million, and 39 
million shares, respectively. 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 income (loss) per 
share. Our initial capitalization included the issuance of 32,920,000 shares of common stock and another 7,080,000
shares reserved to settle claims of unsecured creditors, all of which were included in our computation of net income 
(loss) per share until the claims were settled and the shares issued. In March 2019, we finalized settlement of these 
claims, issuing approximately 2,770,000 shares. In all prior periods presented we retrospectively adjusted the weighted 
average shares in our earnings per share calculations for the ultimate shares issued, instead of the 7,080,000 shares that 
had been reserved.

In July 2018, all outstanding shares of our Series A Preferred Stock were converted to common shares in connection 
with the IPO of our common stock (see Note 6). The conversion was characterized as an induced conversion that 
required a deduction in our EPS calculation, from net income, of approximately $87 million in determining income 
attributable to common stockholders. This deduction represents the excess of fair value of the total consideration given 
to preferred stockholders in the transaction over the fair value of the common stock issuable under the original conversion 
terms. Included in the $87 million is a $60 million cash payment and approximately $27 million of value from the 1.9 
million  additional  common  shares  received  by  preferred  stockholders  as  a  result  of  the  automatic  conversion  that 
occurred in conjunction with our IPO.

The Series A Preferred Stock was not a participating security, therefore, we calculated diluted EPS using the “if-
converted” method under which the preferred dividends are added back to the numerator and the convertible preferred 
stock is assumed to be converted at the beginning of the period. No incremental shares of Series A Preferred Stock 
were included in the diluted EPS calculation for the year ended December 31, 2019 as all outstanding shares of our 
Series A Preferred Stock were converted to common shares in connection with the IPO of our common stock in July 
2018. No Series A Preferred Stock were included in the diluted EPS calculations for the year ended December 31, 2018
and for the ten months ended December 31, 2017 as their effect was anti-dilutive under the “if-converted” method. 

The RSUs and PSUs are not a participating security as the dividends are forfeitable. The incremental RSU and 
PSU shares of 572,000 for the year ended December 31, 2019 and the incremental RSU shares of 189,000  for the year 
ended December 31, 2018 were included in the diluted EPS calculation for those respective years, as their effect was 
dilutive under the “if-converted” method. No incremental shares of RSUs were included in the diluted EPS calculation 
for the ten months ended December 31, 2017 as their effect was anti-dilutive under the “if-converted” method. No
PSUs were included in the EPS calculations for the year end December 31, 2018, the ten months ended December 21, 
2017, and the two months ended February 28, 2017, due to their contingent nature.

119

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Berry Corp.
(Successor)

Year Ended
December 31,
2019

Year Ended
December 31,
2018

Ten Months
Ended
December 31,
2017

Berry LLC
(Predecessor)

Two Months
Ended
February 28,
2017

(in thousands except per share amounts)

Basic EPS calculation

Net income (loss)

less: Series A Preferred Stock dividends and conversion

to common stock

Net income (loss) attributable to common stockholders
Weighted-average shares of common stock outstanding(1)
Basic earnings (loss) per share(2)
Diluted EPS calculation

Net income (loss)

less: Series A Preferred Stock dividends and conversion

to common stock

Net income (loss) attributable to common stockholders
Weighted-average shares of common stock outstanding(1)
Dilutive effect of potentially dilutive securities(3)
Weighted-average common shares outstanding - diluted
Diluted earnings (loss) per share(2)

$

$

$

$

$

$

43,539

$

147,102

$

(21,068)

—

43,539

81,379

0.54

43,539

$

$

$

(97,942)

49,160

57,743

0.85

147,102

$

$

$

(18,248)

(39,316)

38,644

(1.02)

(21,068)

—

(97,942)

(18,248)

43,539

$

49,160

$

(39,316)

81,379

572

81,951

57,743

189

57,932

38,644

—

38,644

0.53

$

0.85

$

(1.02)

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

__________
(1) For the year ended December 31, 2018, we retrospectively adjusted the weighted average shares in our earnings per share calculations for the
2,770,000 shares issued instead of 7,080,000 shares that had been reserved for the year ended December 31, 2018 and the ten months ended
December 31, 2017.

(2) Per share amounts are stated net of tax.
(3) No potentially dilutive securities were included in computing earnings (loss) per share for the ten months ended December 31, 2017 because 

the effect of inclusion would have been anti-dilutive.

120

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 13—Revenue Recognition

We account for revenue in accordance with the Accounting Standards Codification 606, Revenue from Contracts 
with Customers, which we adopted on January 1, 2019, using the modified retrospective method, which was applied 
to all contracts that were not completed as of that date. Prior period results were not adjusted and continue to be reported 
under the accounting standards in effect for the prior period. The new standard did not affect the timing of our revenue 
recognition and did not impact net income; accordingly, we did not record an adjustment to the opening balance of 
retained earnings. 

We adopted the practical expedient related to disclosing the aggregate amount of the transaction price allocated to 
performance obligations that are unsatisfied at the end of the reporting period. The performance obligations that are 
unsatisfied at the end of a reporting period relate solely to future volumes that we have yet to sell. As such, these are 
wholly unsatisfied performance obligations as each unit of product represents a separate performance obligation as 
well as a wholly unsatisfied promise to transfer a distinct good that forms part of a single performance obligation. 

We derive substantially all of our revenue from sales of oil, natural gas and natural gas liquids ("NGL"), with the 

remaining revenue generated from sales of electricity and marketing activities.

The following is a description of our principal activities from which we generate revenue. Revenues are recognized 
when a customer obtains control of promised goods or services, in an amount that reflects the consideration we expect 
to receive in exchange for those goods or services. 

Oil, Natural Gas and NGLs

We recognize revenue from the sale of our oil, natural gas and NGLs production when delivery has occurred and 
control passes to the customer. Our oil and natural gas contracts are short term, typically less than a year and our NGL 
contracts are both short and long term. We consider our performance obligations to be satisfied upon transfer of control 
of the commodity. Our commodity sales contracts are indexed to a market price or an average index price. We recognize 
revenue in the amount that we expect to receive once we are able to adequately estimate the consideration (i.e., when 
market prices are known). Our contracts with customers typically require payment within 30 days following invoicing. 

Electricity Sales

The electrical output of our cogeneration facilities that is not used in our operations is sold to the California market 
based  on  market  pricing,  which  includes  capacity  payments.  The  majority  of  the  portion  sold  from  three  of  our 
cogeneration facilities is sold under long-term contracts to two 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. 
We  recognize  revenue  in  the  amount  that  we  have  a  right  to  invoice  once  we  are  able  to  adequately  estimate  the 
consideration (i.e., when market prices are known).

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 
121

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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  condensed  consolidated 
statements of operations.

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.

Berry Corp.
(Successor)

Year Ended
December 31, 2019

Year Ended
December 31, 2018

Ten Months
Ended December
31, 2017

(in thousands)

Berry LLC
(Predecessor)

Two Months
Ended February
28, 2017

Oil sales

Natural gas sales

Natural gas liquids sales

Electricity sales

Marketing revenues

Other revenues

Revenues from contracts with customers

(Losses) gains on oil derivatives

$

543,634

$

520,979

$

303,589

$

19,391

2,571

29,397

2,094

316

597,403

(37,998)

26,244

5,651

35,208

2,322

774

591,178

(4,621)

40,887

13,452

21,972

2,694

3,975

386,569

(66,900)

Total revenues and other

$

559,405

$

586,557

$

319,669

$

54,110

14,476

5,534

3,655

633

1,424

79,832

12,886

92,718

Note 14—Emergence from Voluntary Reorganization under Chapter 11

On May 11, 2016 our predecessor company filed bankruptcy. Our bankruptcy case was jointly administered with 
that of Linn Energy and its affiliates under the caption In re Linn Energy, LLC, et al., Case No. 16–60040 (the “Chapter 
11 Proceeding”). On January 27, 2017, the Bankruptcy Court approved and confirmed our plan of reorganization in 
the Chapter 11 Proceeding (the “Plan”). On February 28, 2017 (the “Effective Date”), the Plan became effective and 
was implemented. A final decree closing the Chapter 11 Proceeding was entered September 28, 2018, with the Court 
retaining jurisdiction as described in the confirmation order and without prejudice to the request of any party–in–interest 
to reopen the case including with respect to certain, immaterial remaining matters. 

Plan of Reorganization

On the Effective Date, the Company consummated the following reorganization transactions in accordance with 

the Plan:

•

•

Linn Acquisition Company, LLC transferred 100% of the outstanding membership interests in Berry LLC to
Berry  Corp.  pursuant  to  an  assignment  agreement,  dated  February  28,  2017  between  Linn Acquisition
Company, LLC and Berry Corp. (the “Assignment Agreement”). Under the Assignment Agreement, Berry
LLC became a wholly-owned operating subsidiary of Berry Corp.

The holders of claims under the Company’s Second Amended and Restated Credit Agreement, dated November
15, 2010, by and among Berry LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent, and certain
lenders, (as amended, the “Pre-Emergence Credit Facility”), received (i) their pro-rated share of a cash paydown
and (ii) pro-rated participation in the new facility (the “Emergence Credit Facility”). As a result, all outstanding
obligations  under  the  Pre-Emergence  Credit  Facility  were  canceled  and  the  agreements  governing  these
obligations were terminated.

122

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

•

•

•

•

Berry LLC, as borrower, entered into the Emergence Credit Facility with the holders of claims under the Pre-
Emergence Credit Facility, as lenders, and Wells Fargo Bank, N.A, as administrative agent, providing for a
new reserves-based revolving loan with up to $550 million in borrowing commitments. This facility was
replaced with the RBL Facility in July 2017 noted above.

The  holders  of  Berry  LLC’s  6.75%  senior  notes  due  2020,  issued  by  Berry  LLC  pursuant  to  a  Second
Supplemental Indenture, dated November 1, 2010, and 6.375% senior notes due 2022, issued by Berry LLC
pursuant  to  a Third  Supplemental  Indenture,  dated  March  9,  2012  (collectively,  the  “Unsecured  Notes”),
received a right to their pro-rated share of either (i) 32,920,000 shares of common stock in Berry Corp. or, for
those non-accredited investors holding the Unsecured Notes that irrevocably elected to receive a cash recovery,
cash distributions from a $35 million cash distribution pool (the “Cash Distribution Pool”) and (ii) specified
rights to participate in a two-tranche offering of rights to purchase Series A Preferred Stock at an aggregate
purchase price of $335 million (as further defined in the Plan, the “Berry Rights Offerings”). As a result, all
outstanding obligations under the Unsecured Notes were canceled and the indentures and related agreements
governing these obligations were terminated.

The  holders  of  unsecured  claims  against  Berry  LLC,  (other  than  the  Unsecured  Notes)  (the  “Unsecured
Claims”) received a right to their pro-rated share of either (i) 7,080,000 shares of common stock in Berry
Corp. or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions
from the Cash Distribution Pool. After the Effective Date we have negotiated with claimants to settle their
claims. As a result, in early 2019, we issued 2,770,000 shares to settle these claims for which we had originally
reserved 7,080,000 shares.

Berry LLC settled all intercompany claims against Linn Energy and its affiliates pursuant to a settlement
agreement approved as part of the Plan and the Confirmation Order. The settlement agreement provided Berry
LLC with a $25 million general unsecured claim against Linn Energy which Berry LLC has fully-reserved.

Bank RSA

Prior to the Petition Date, on May 10, 2016, the Debtors entered into a restructuring support agreement (the “Bank 
RSA”) with certain holders (the “Consenting Bank Creditors”). The Bank RSA set forth, subject to certain conditions, 
the commitment of the Consenting Bank Creditors to support a comprehensive restructuring of the Debtors’ long-term 
debt. The Bank RSA required the Debtors and the Consenting Bank Creditors to, among other things, support and not 
interfere with consummation of the restructuring transactions contemplated by the Bank RSA and, as to the Consenting 
Bank Creditors, vote their claims in favor of the Plan.

Liabilities Subject to Compromise

Through the claims resolution process, many claims were disallowed by the Bankruptcy Court because they were 
duplicative, amended or superseded by later filed claims, were without merit, or were otherwise overstated. Throughout 
the Chapter 11 proceedings, the Debtors also resolved many claims through settlements or by Bankruptcy Court orders 
following the filing of an objection. As a result, in early 2019, we issued 2,770,000 shares to settle these claims for 
which we had originally reserved 7,080,000 shares. We settled all liabilties subject to compromise through cash recovery 
as of December 31, 2018, resulting in a significant recognition of gains due to the return of undistributed funds. See 
“Reorganization Items, net” below. 

123

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Reorganization Items, Net

We have incurred expenses associated with the reorganization. Reorganization items, net represents costs and 
income directly associated with the Chapter 11 proceedings since the Petition Date, and also includes adjustments to 
reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such 
adjustments were determined. The following table summarizes the components of reorganization items included in the 
consolidated statements of operations:

Return of undistributed funds from cash distribution 

pool(1)

Gains on resolution of pre-emergence liabilities and

claims

Legal and other professional advisory fees
Gains on settlement of liabilities subject to compromise
Fresh-start valuation adjustments
Other

Reorganization items, net

$

Berry Corp.
(Successor)

Year Ended
December 31,
2019

Year Ended
December 31,
2018

Ten Months
Ended
December 31,
2017

(in thousands)

Berry LLC
(Predecessor)

Two Months
Ended
February 28,
2017

$

— $

22,855

$

— $

—

—
(426)
—
—
—
(426) $

3,713
(3,083)
—
—
1,205
24,690

$

—
(1,027)
—
—
(705)
(1,732)

$

—
(19,481)
421,774
(920,699)
10,686
(507,720)

__________
(1) This amount was reclassed from restricted cash to general cash, thus does not represent a cash transaction.

Effect of Filing on Creditors

Subject to certain exceptions, under the Bankruptcy Code, the filing of Bankruptcy Petitions automatically enjoined,
or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors 
or their property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order of the Bankruptcy 
Court, substantially all of the Debtors’ pre-petition liabilities were subject to settlement under the Bankruptcy Code. 
Although the filing of Bankruptcy Petitions triggered defaults on the Debtors’ debt obligations, creditors were stayed 
from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted 
by the Bankruptcy Code. The Predecessor did not record interest expense on its senior notes for the period from January 
1, 2017 through February 28, 2017. For this period, unrecorded contractual interest was approximately $9 million.

Covenant Violations

The  Predecessor’s  filing  of  the  Bankruptcy  Petitions  constituted  an  event  of  default  that  accelerated  the 
Predecessor’s obligations under its Pre-Emergence Credit Facility and its senior notes. Additionally, other events of 
default, including cross-defaults, occurred, including the failure to make interest payments on the Predecessor’s senior 
notes. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against 
the Predecessor as a result of any default. 

Prior Credit Facility

The Pre-Emergence Credit Facility contained a requirement to deliver audited financial statements without a going 
concern or like qualification or exception. Consequently, the filing of the Predecessor’s 2015 Annual Report on Form 
10-K which included a going concern explanatory paragraph resulted in a default under the Pre-Emergence Credit
Facility as of the filing date, March 28, 2016, subject to a 30-day grace period.

124

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On  April  12,  2016,  the  Predecessor  entered  into  an  amendment  to  the  Pre-Emergence  Credit  Facility.  The 
amendment provided for, among other things, an agreement that (i) certain events would not become defaults or events 
of default until May 11, 2016, (ii) the borrowing base would remain constant until May 11, 2016, unless reduced as a 
result of swap agreement terminations or collateral sales, (iii) the Predecessor would have access to $45 million in cash 
that was previously restricted in order to fund ordinary course operations and (iv) the Predecessor, the administrative 
agent and the lenders would negotiate in good faith the terms of a restructuring support agreement in furtherance of a 
restructuring of the capital structure of the Predecessor. As a condition to closing the amendment, the Predecessor 
provided control agreements over certain deposit accounts.

The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Predecessor’s obligations 
under the Pre-Emergence Credit Facility. However, under the Bankruptcy Code, the creditors under this debt agreement 
were stayed from taking any action against the Predecessor as a result of the default.

Senior Notes

The Predecessor deferred making an interest payment totaling approximately $18 million due March 15, 2016, on 
the Predecessor’s 6.375% senior notes due September 2022, which resulted in the Predecessor being in default under 
these senior notes. The indenture governing the notes provided the Predecessor a 30-day grace period to make the 
interest payment.

On April 14, 2016, within the 30-day interest payment grace period provided for in the indenture governing the 

notes, the Predecessor made an interest payment of approximately $18 million in satisfaction of its obligations.

The Predecessor failed to make interest payments due on its senior notes subsequent to April 14, 2016.

The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Predecessor’s obligations 
under the indentures governing the senior notes. However, under the Bankruptcy Code, holders of the senior notes were 
stayed from taking any action against the Predecessor as a result of the default.

Note 15—Fresh-Start Accounting

Upon  our  emergence  from  bankruptcy,  we  were  required  to  adopt  fresh-start  accounting,  which,  with  the 
recapitalization described above, resulted in Berry Corp. being treated as the new entity for financial reporting purposes. 
We were required to adopt fresh-start accounting upon our emergence from bankruptcy because (i) the holders of 
existing voting ownership interests of our predecessor company received less than 50% of the voting shares of Berry 
Corp. and (ii) the reorganization value of our assets immediately prior to confirmation of the Plan was less than the 
total of all post-petition liabilities and allowed claims. An entity applying fresh-start accounting upon emergence from 
bankruptcy  is  viewed  as  a  new  reporting  entity  from  an  accounting  perspective,  and  accordingly,  may  select  new 
accounting policies.

The reorganization value of our assets immediately prior to confirmation of the Plan was less than the total of all 

post-petition liabilities and allowed claims, as shown below:

Liabilities subject to compromise

Pre-petition debt not classified as subject to compromise

Post-petition liabilities

Total post-petition liabilities and allowed claims

Reorganization value of assets immediately prior to implementation of the Plan

Excess post-petition liabilities and allowed claims

125

(in thousands)

$

1,000,336

891,259

245,702

2,137,297

(1,722,585)

$

414,712

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Upon adoption of fresh-start accounting, the reorganization value derived from the enterprise value was allocated 
to our assets and liabilities based on their fair values in accordance with GAAP. The Effective Date fair values of our 
assets and liabilities differed materially from their recorded values as reflected on the historical balance sheet. The 
effects of the Plan and the application of fresh-start accounting were reflected in the financial statements as of February 
28, 2017, and the related adjustments thereto were recorded on the statement of operations for the two months ended 
February 28, 2017.

As  a  result  of  the  adoption  of  fresh-start  accounting  and  the  effects  of  the  implementation  of  the  Plan,  our 
consolidated financial statements subsequent to February 28, 2017, are not comparable to our financial statements prior 
to February 28, 2017.

Our consolidated financial statements and related footnotes are presented with a black line division, which delineates 
the lack of comparability between amounts presented after February 28, 2017, and amounts presented on or prior to 
February 28, 2017. Our financial results for future periods following the application of fresh-start accounting will be 
different from historical trends and the differences may be material.

Reorganization Value

Under GAAP, a value was assigned to the equity of the emerging entity as of the date of adoption of fresh-start 
accounting. The Plan and disclosure statement approved by the Bankruptcy Court did not include an enterprise value 
or reorganization value, nor did the Bankruptcy Court approve a value as part of its confirmation of our Plan. Our 
reorganization  value  was  derived  from  an  estimate  of  enterprise  value,  or  the  fair  value  of  our  long-term  debt, 
stockholders’  equity  and  working  capital.  Reorganization  value  approximates  the  fair  value  of  the  entity  before 
considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately 
after  the  restructuring.  Based  on  the  various  estimates  and  assumptions  necessary  for  fresh-start  accounting,  our 
enterprise value as of the Effective Date was estimated to be approximately $1.3 billion. The enterprise value was 
estimated using a sum of parts approach. The sum of parts approach represents the summation of the indicated fair 
value of the component assets of the Company. The fair value of our assets was estimated by relying on a combination 
of the income, market and cost approaches.

The estimated enterprise value, reorganization value and equity value are highly dependent on the achievement of 
the financial results contemplated in our underlying projections. While we believe the assumptions and estimates used 
to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates 
could materially impact the analysis and resulting conclusions. Additionally, the assumptions used in estimating these 
values are inherently uncertain and require judgment. The primary assumptions for which there is a reasonable possibility 
of the occurrence of a variation that would have significantly affected the reorganization value include those regarding 
pricing, discount rates and the amount and timing of capital expenditures.

Our principal assets are our oil and natural gas properties. The fair values of oil and natural gas properties were 
estimated using a valuation technique consistent with the income approach; specifically, the discounted cash flows 
method. We also used the market approach to corroborate the valuation results from the income approach. We used a 
market-based weighted-average cost of capital discount rate of 10% for proved and unproved reserves, with further 
risk adjustment factors applied to the discounted values. The underlying commodity prices embedded in our estimated 
cash flows were based on the New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated 
location and quality differentials, as well as other factors that we believe will impact realizable prices. NYMEX forward 
curve pricing was used for years 2017 through 2019 and then was escalated at approximately 2.0%.

See below under “Fresh-Start Adjustments” for additional information regarding assumptions used in the valuation 

of our various other significant assets and liabilities.

126

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date:

Enterprise value

Plus: Fair value of non-debt liabilities

Reorganization value of the Successor’s assets

(in thousands)

$

$

1,278,527

282,511

1,561,038

The fair value of non-debt liabilities consists of liabilities assumed by the Successor on the Effective Date and 

excludes the fair value of long-term debt.

Consolidated Balance Sheet

The  adjustments  included  in  the  following  fresh-start  consolidated  balance  sheet  reflect  the  effects  of  the 
transactions contemplated by the Plan and executed on the Effective Date (reflected in the column “Reorganization 
Adjustments”) as well as fair value and other required accounting adjustments resulting from the adoption of fresh-
start  accounting  (reflected  in  the  column  “Fresh-Start  Adjustments”).  The  explanatory  notes  provide  additional 
information  with  regard  to  the  adjustments  recorded,  methods  used  to  determine  the  fair  values  and  significant 
assumptions.

127

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

ASSETS

Current assets:

Cash and cash equivalents

Accounts receivable

Derivative instruments

Restricted cash

Other current assets

Total current assets

Non-current assets:

Oil and natural gas properties

Less accumulated depletion and amortization

Total oil and natural gas properties, net

Other property and equipment

Less accumulated depreciation

Total other property and equipment, net

Derivative instruments

Restricted cash

Other non-current assets

Total assets

As of February 28, 2017

Berry LLC
(Predecessor)

Reorganization 
Adjustments(1)

Fresh-Start
Adjustments

Berry Corp.
(Successor)

(in thousands)

$

27,407

$

4,642 (2) $

76,027

243

128

18,437

122,242

5,031,498

(2,814,999)

2,216,499

124,379

(22,107)

102,273

57

197,939

16,076

(15,700) (3)
—
52,732 (4)
(5,558) (5)
36,116

—

—

—

—

—

—

—

(197,814) (2)
151 (6)

$

—
(816) (14)
—

—
3,873 (15)
3,057

32,049

59,511

243

52,860

16,752

161,415

(3,787,898) (16)
(16)
2,814,999

(972,899)
(15,576) (17)
22,107 (17)
6,530

—

—
30,811 (18)

1,243,600

—

1,243,600

108,803

—

108,803

57

125

47,038

$ 2,655,086

$

(161,547)

$

(932,501)

$ 1,561,038

LIABILITIES AND EQUITY

Current liabilities:

Accounts payable and accrued expenses

$

60,323

$

Derivative instruments

Current portion of long-term debt, net

Other accrued liabilities

Total current liabilities

Non-current liabilities:

Derivative instruments

Long-term debt

Other non-current liabilities

Liabilities subject to compromise

Equity:

Predecessor additional paid-in capital

Predecessor accumulated deficit

Successor preferred stock

Successor common stock

Successor additional paid-in capital

Total equity

5,355

891,259

7,335

964,272

1,710

—

170,979

1,000,336

2,798,714

(2,280,925)

—

—

—

517,789

52,371 (7) $
—
(891,259) (8)
(3,760) (9)

(842,648)

—
400,000 (10)
—

(1,000,336) (11)

(2,798,714) (12)
375,159 (13)
335,000 (12)
33 (12)
3,369,959 (12)
1,281,437

3,818 (19) $

116,512

—

—
1,295 (20)
5,113

—

—
(16,915) (21)
—

—
1,905,766 (22)
—

—

(2,826,465) (22)
(920,699)

5,355

—

4,870

126,737

1,710

400,000

154,064

—

—

—

335,000

33

543,494

878,527

Total liabilities and equity

$ 2,655,086

$

(161,547)

$

(932,501)

$ 1,561,038

128

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

__________
Reorganization Adjustments:
(1) Represent amounts recorded as of the Effective Date for the implementation of the Plan, including, among other items, settlement of the
Predecessor’s  liabilities  subject  to  compromise,  repayment  of  certain  of  the  Predecessor’s  debt,  cancellation  of  the  Predecessor’s  equity,
issuances  of  the  Successor’s  common  stock  and  preferred  stock,  proceeds  received  from  the  Berry  Rights  Offerings  and  issuance  of  the
Successor’s debt.

(2) Changes in cash and cash equivalents included the following:

Borrowings under the Emergence Credit Facility
Proceeds from issuance of preferred stock pursuant the Berry Rights Offerings
Cash receipt from Linn Energy, LLC for ad valorem taxes
Removal of restriction on cash balance (includes $128 previously recorded as short term)
Payment to the holders of claims under the Pre-Emergence Credit Facility (including $29 in bank

fees and $3,760 in interest)

Payment of professional fees
Payment of Emergence Credit Facility fee that was capitalized
Funding of the general unsecured claims Cash Distribution Pool
Funding of the professional fees escrow account

Changes in cash and cash equivalents

(in thousands)

400,000
335,000
23,366
197,942

(897,663)

(992)
(151)
(35,000)
(17,860)
4,642

$

$

(3) Collection of overpayment to Linn Energy, LLC for ad valorem taxes.
(4) Primarily reflects the transfer to restricted cash to fund the Predecessor’s professional fees escrow account and general unsecured claims Cash

Distribution Pool.

(5) Primarily reflects the write-off of the Predecessor’s deferred financing fees.
(6) Reflects the capitalization of deferred financing fees related to the Emergence Credit Facility.
(7) Net increase in accounts payable and accrued expenses reflects:

Recognition of payables for the general unsecured claims Cash Distribution Pool
Recognition of payables for the professional fees escrow account
Recognition of payable for ad valorem tax liability
Net change of other professional fees payable
Other

Net increase in accounts payable and accrued expenses

(8) Reflects the repayment of the Pre-Emergence Credit Facility.
(9) Reflects the payment of accrued interest on the Pre-Emergence Credit Facility.
(10) Reflects borrowings under the Emergence Credit Facility.
(11) Settlement of liabilities subject to compromise and the resulting net gains were determined as follows:

Accounts payable and accrued expenses
Accrued interest payable
Debt

Total liabilities subject to compromise

Funding of the general unsecured claims Cash Distribution Pool
Common stock to holders of Unsecured Notes and general unsecured creditors

Gains on settlement of liabilities subject to compromise

(12) Net increase in capital accounts reflects:

(in thousands)

35,000
17,860
7,666
(8,161)
6
52,371

(in thousands)

151,298
15,238
833,800
1,000,336
(35,000)
(543,562)
421,774

$

$

$

$

129

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Common stock to holders of Unsecured Notes and general unsecured creditors
Payment of issuance costs
Dividend related to beneficial conversion feature of preferred stock
Cancellation of the Predecessor’s additional paid-in capital
Par value of common stock

Change in additional paid-in capital
Proceeds from issuance of preferred stock
Par value of common stock
Predecessor’s additional paid-in capital
Net increase in capital accounts

See Note 6 for additional information on the issuances and distributions of the Successor’s common and preferred stock.
(13) Net decrease in accumulated deficit reflects:

Recognition of gains on settlement of liabilities subject to compromise
Recognition of professional fees
Write-off of deferred financing fees
Total reorganization items, net

Dividend related to beneficial conversion feature of preferred stock

Net decrease in accumulated deficit

(in thousands)

543,562
(35)
27,751
2,798,714
(33)
3,369,959
335,000
33
(2,798,714)
906,278

(in thousands)

421,774
(13,667)
(5,197)
402,910
(27,751)
375,159

$

$

$

$

Fresh-Start Adjustments:
(14) Reflects a change in accounting policy from the entitlements method to the sales method for natural gas production imbalances.
(15) Primarily reflects an increase in the current portion of greenhouse gas allowances.
(16) Reflects a decrease of oil and natural gas properties, based on the methodology discussed in Note 2, and the elimination of accumulated depletion

and amortization. The following table summarizes the components of oil and natural gas properties as of the Effective Date:

Proved properties

Unproved properties

Total proved and unproved properties

Less accumulated depletion and amortization

Total proved and unproved properties, net

Berry Corp.
(Successor)

Fair Value

Berry LLC
(Predecessor)

Historical Book
Value

(in thousands)

712,400

$

531,200

1,243,600

4,266,843

764,655

5,031,498

—

(2,814,999)

1,243,600

$

2,216,499

$

$

(17) Reflects a decrease of other property and equipment and the elimination of accumulated depreciation. The following table summarizes the

components of other property and equipment as of the Effective Date:

130

BERRY CORPORATION (bry)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Natural gas plants and pipelines

Land

Furniture and office equipment

Buildings and leasehold improvements

Vehicles

Drilling and other equipment

Total other property and equipment

Less accumulated depreciation

Berry Corp.
(Successor)

Fair Value

Berry LLC
(Predecessor)

Historical Book
Value

(in thousands)

$

91,427

$

109,675

8,262

5,040

2,740

1,156

178

108,803

—

201

3,879

5,884

4,542

198

124,379

(22,107)

102,273

Total other property and equipment, net

$

108,803

$

In estimating the fair value of other property and equipment, we used a combination of cost and market approaches. A cost approach was used 
to value our natural gas plants and pipelines, buildings, and furniture and office equipment based on current replacement costs of the assets 
less depreciation based on the estimated economic useful lives of the assets and age of the assets. A market approach was used to value our 
vehicles, drilling and other equipment, and land, using recent transactions of similar assets to determine the fair value from a market participant 
perspective.

(18) Primarily reflects an increase in greenhouse gas allowances of approximately $30 million and a joint venture investment of approximately $1
million. Greenhouse gas allowances were valued using a market approach based on trading prices for carbon credits on February 28, 2017.
Our joint venture investment was valued based on a market approach using a market EBITDA multiple.

(19) Reflects increases for greenhouse gas emissions liabilities of approximately $4 million and a change in accounting policy from the entitlements 
method to the sales method for gas production imbalances of approximately $200,000, partially offset by a decrease for the current portion of
intangibles liabilities of approximately $500,000.

(20) Reflects an increase of the current portion of asset retirement obligations.
(21) Primarily reflects a decrease for asset retirement obligations of approximately $30 million and for intangible liabilities of approximately$6
million, partially offset by an increase for greenhouse gas emissions liabilities of approximately $19 million. The fair value of asset retirement
obligations was estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the
valuation include estimates of: (i) plugging and abandonment costs per well based on existing regulatory requirements; (ii) remaining life per
well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. The intangible liabilities identified on the Effective Date
were valued based on a combination of market and incomes approaches and will be amortized over the remaining life of the respective contract.
Greenhouse gas emissions liabilities were valued using a market approach based on trading prices for greenhouse gas allowances on February
28, 2017.

(22) Reflects the cumulative impact of the fresh-start accounting adjustments discussed above and the elimination of the Predecessor’s accumulated

deficit.

131

BERRY CORPORATION (bry)
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(Unaudited)

Berry Corp. (Successor)

Quarters Ended

March 31

June 30

September 30

December 31

(in thousands, except per share amounts)

131,102

9,729

$

$

136,908

5,364

(65,239) $

27,276

830

117

114,853

$

$

$

414

104

116,886

$

$

$

$

$

$

141,250

7,460

45,509

413

40

113,008

$

$

$

$

$

$

156,336

6,844

(45,544)

437

55

173,089

(8,651) $

(8,961) $

(8,674) $

(7,868)

(231) $

(26) $

(170) $

(34,098) $

(34,098) $

31,972

31,972

(0.42) $

(0.42) $

0.39

0.39

$

$

$

$

52,649

52,649

0.65

0.65

$

$

$

$

—

(6,984)

(6,984)

(0.09)

(0.09)

Berry Corp. (Successor)

Quarters Ended

March 31

June 30

September 30

December 31

(in thousands)

125,624

5,453

$

$

137,385

5,971

$

$

147,004

14,268

$

$

142,861

9,517

(34,644) $

(78,143) $

(18,994) $

127,160

534

274

101,473

(8,712)

1,498

131,768

785

66

91,121

$

$

$

518

251

90,581

$

$

$

486

183

102,530

$

$

$

(7,769) $

(9,394) $

(9,530) $

8,955

6,410

760

0.02

0.02

$

$

$

$

$

456

$

(28,061) $

13,781

36,985

$

$

(33,711) $

(49,657) $

131,768

(0.94) $

(0.94) $

(0.70) $

(0.70) $

1.56

1.56

2019:

Oil, natural gas and natural gas liquid sales

Electricity sales

(Losses) gains on oil derivatives

Marketing revenues

Other revenues
Total expenses(2)
Total other (expenses) income

Reorganization items, net, (income) expense

Net (loss) income

Net (loss) income attributable to common stockholders

(Loss) earnings per share attributable to common

stockholders:
Basic(1)
Diluted(1)

2018:

Oil, natural gas and natural gas liquid sales

Electricity sales

(Losses) gains on oil derivatives

Marketing revenues

Other revenues

Total expenses

Total other (expenses) income

Reorganization items, net, expense (income)

Net income (loss)

Net income (loss) attributable to common stockholders

Earnings (loss) per share attributable to common

stockholders:
Basic(1)
Diluted(1)

$

$

$

$

$

$

$

$

$

$

$

$

$

$

$

$

$

$

$

$

$

$

$

$

132

BERRY CORPORATION (bry)
SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Continued)
(Unaudited)

__________
(1)

In March 2019, we finalized settlement of claims from unsecured creditors, issuing approximately 2,770,000 shares. We retrospectively adjusted
the weighted average shares in our earnings per share calculations for the 2,770,000 shares issued instead of the 7,080,000 shares that had been 
reserved. See Note 12 of our consolidated financial statements for further information.

(2) Total expenses for the fourth quarter of 2019 includes an impairment charge of $51 million for the Piceance gas properties in Colorado.

133

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

Unproved

Exploration costs
Development costs(1)

Total costs incurred

Berry Corp.
(Successor)

Year Ended
December 31,
2019

Year Ended
December 31,
2018

Ten Months
Ended
December 31,
2017

(in thousands)

Berry LLC
(Predecessor)

Two Months
Ended
February 28,
2017

$

2,939

$

— $

249,338

$

—

—

—

—

—

—

279,954

143,002

60,381

$

282,893

$

143,002

$

309,719

$

—

—

—

4,544

4,544

__________
(1)

Included in development costs for the year ended December 31, 2019 and 2018 are non-cash additions related to the estimated future asset
retirement obligations of the Company's oil and gas properties of $68.1 million and $3.4 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

Net capitalized costs

Berry Corp. (Successor)

December 31, 2019

December 31, 2018

(in thousands)

1,465,383

$

1,168,245

313,903

1,779,286

(223,919)

388,034

1,556,279

(132,587)

1,555,367

$

1,423,692

$

$

134

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:

Berry Corp.
(Successor)

Year Ended
December 31,
2019

Year Ended
December 31,
2018

Ten Months
Ended
December 31,
2017

(in thousands)

Berry LLC
(Predecessor)

Two Months
Ended
February 28,
2017

$

565,596

$

552,874

$

357,928

$

74,120

29,397

2,258

35,208

2,908

21,972

6,569

3,655

2,003

79,778

Net revenues from production:

Oil, natural gas and NGL sales

Electricity sales

Other production-related revenue

Total net revenues from production

597,251

590,990

386,469

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

216,294

19,490

8,059

2,735

40,254

2,073

188,776

20,619

9,860

1,876

33,117

2,140

149,599

28,238

14,894

19,238

5,786

34,211

2,320

3,197

6,194

—

5,212

653

Total operating costs for production

288,905

256,388

226,048

43,494

Other costs:

Depreciation, depletion and amortization

Impairment of long-lived assets

Other operating (income) expenses

Total other costs

Pretax income (loss)

Income tax expense

Results of operations

101,816

51,081

4,545

157,442

150,904

10,084

81,927

—

(2,747)

79,180

255,422

69,807

67,051

—

(22,930)

44,121

116,300

45,887

$

140,820

$

185,615

$

70,412

$

26,743

—

—

26,743

9,541

230

9,311

Income tax is calculated as if the results presented above represented a stand-alone tax filing entity by applying 
the current federal and state statutory tax rates to the revenues after deducting costs, which include DD&A allowances, 
after giving effect to permanent differences. There is no federal tax provision included in the Predecessors results above 
because the Predecessor was not subject to federal income taxes during those periods. The income tax amount included 
in the Predecessor’s results above relates to Texas margin tax expense. Limited liability companies are subject to Texas 
margin tax. See Note 8 for additional information about income taxes.

135

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, 2019, December 31, 2018 and December 31, 
2017 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

Year Ended December 31, 2019

Oil 
MBbls

NGLs
MBbls

Natural Gas
MMcf

Total 
MBoe

114,765

13,321

10,759

159

—

(9,231)

129,773

73,203

74,102

41,562

55,670

1,147

—

160

24

—

(151)

1,180

1,047

1,054

100

127

160,849

—

(109,323)

701

—

(7,412)

44,815

76,331

39,063

84,518

5,752

142,720

13,321

(7,302)

300

—

(10,617)

138,422

86,971

81,667

55,749

56,756

136

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

Total proved reserves:

Beginning of year (Predecessor)

Revisions of previous estimates

Sales of proved reserves in place

Purchase of proved reserves in place

Extensions and discoveries

Production

End of year

Proved developed reserves:

Beginning of year (Predecessor)

End of year

Proved undeveloped reserves:

Beginning of year (Predecessor)

End of year

Year Ended December 31, 2018

Oil
MBbls

NGLs
MBbls

Natural Gas
MMcf

Total
MBoe

100,596

21,276

80

865

(7)

(8,045)

114,765

68,490

73,203

32,106

41,562

1,271

126

211

—

(250)

(211)

1,147

1,271

1,047

—

100

237,104

5,762

(62,141)

—

(10,287)

(9,589)

160,849

100,384

76,331

136,720

84,518

141,385

22,362

(10,066)

865

(1,972)

(9,855)

142,720

86,492

86,971

54,893

55,749

Year Ended December 31, 2017

Oil
MBbls

NGLs
MBbls

Natural Gas
MMcf

Total
MBoe

55,876

9,089

(13)

24,332

18,783

(7,471)

100,596

55,422

68,490

454

32,106

15,078

431

372,760

32,144

(13,329)

(285,168)

—

—

(909)

1,271

15,078

1,271

—

—

—

136,719

(19,351)

237,104

372,760

100,384

—

136,720

133,080

14,878

(60,870)

24,332

41,570

(11,605)

141,385

132,626

86,492

454

54,893

The tables above include changes in estimated quantities of natural gas reserves shown in Boe using the ratio of 

six Mcf to one barrel.

137

BERRY CORPORATION (bry)
SUPPLEMENTAL OIL & NATURAL GAS DATA (Continued)
(Unaudited)

Proved reserves decreased by approximately 4,298 MBoe to approximately 138,422 MBoe for the year ended 
December 31, 2019, from 142,720 MBoe for the year ended December 31, 2018. Extensions and discoveries, principally 
in our California properties, contributed 13,321 MMBoe to the overall change in proved reserves. These extensions 
included  McKittrick  steamflood  expansions  based  on  delineation  wells  drilled  in  2019,  Homebase  Pliocene 
development, as well as expansion of our thermal Diatomite operations. The year ended December 31, 2019, includes 
7,302 MBoe of negative revisions of previous estimates. Negative revisions due to price were 6,829 MMBoe and this 
was caused by the current commodity price environment. Performance revisions included a decrease of 13,532 MMBoe 
due to the impairment of our Piceance gas properties and the removal of the proved undeveloped reserves related to 
this impairment. However, there were positive technical revisions of 13,329 MMBoe primarily related to the improved 
base performance and redevelopment in our thermal Diatomite area. 

to 

for 

from 141,385 MBoe 

Proved  reserves increased by  approximately 1,335 MBoe  to  approximately 142,720 MBoe  for  the year  ended 
the year  ended  December  31,  2017.  Extensions  and 
December  31,  2018, 
discoveries, principally in our California properties, most of which was thermal Diatomite, as well as in Utah, contributed 
22,362 MBoe 
includes 
reserves.  The year 
approximately 10,066 MBoe  of negative revisions  of  previous  estimates  (17,992 MBoe  of  negative  performance-
related revisions resulting from 9,411 MBoe to remove proved undeveloped reserves due to a downward adjustment 
of our committed capital in the Piceance basin and technical revisions of 8,581 MBoe due to a shift in the development 
strategy as laid out in our 5-year capital plan offset by 7,926 MBoe of positive revisions due to higher commodity 
prices). 

ended  December  31,  2018, 

the increase in  proved 

Proved reserves increased by approximately 8,305 MBoe to approximately 141,385 MBoe for the year ended 
December 31, 2017, from 133,080 MBoe for the year ended December 31, 2016. The year ended December 31, 2017, 
includes approximately 14,878 MBoe of positive revisions of previous estimates due to higher commodity prices. 
Extensions and discoveries, contributed approximately 41,570 MBoe to the increase in proved reserves, primarily due 
to the certainty attained in the Company’s future commitment to capital as a result of its emergence from bankruptcy 
allowing inclusion of PUDs previously excluded due to the SEC five-year development limitation on PUDs, as well 
as from 93 productive wells drilled during the year. Lastly, the Hugoton Disposition and Hill Acquisition had a net 
negative impact on proved reserves of approximately 36,538 MBoe (negative impact on reserves from the Hugoton 
Disposition of approximately 60,870 MBoe offset by the positive impact on reserves from the Hill Acquisition of 
approximately 24,332 MBoe).

138

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
Future income tax expenses(1)
Future net cash flows

Berry Corp. (Successor)

December 31,
2019

December 31,
2018

December 31,
2017

(in thousands, except for prices)

$

7,788,647

$ 8,119,309

$

5,580,448

(3,623,688)

(3,357,149)

(2,725,548)

(1,106,333)

(587,487)

(884,055)

(757,470)

(678,312)

(365,330)

2,471,139

3,120,635

1,811,258

10% annual discount for estimated timing of cash flows

(1,005,002)

(1,359,089)

(833,910)

Standardized measure of discounted future net cash flows
Representative prices:(2)
Brent Oil (Bbl)

Henry Hub Natural gas (MMBtu)

$

1,466,137

$ 1,761,546

$

977,348

$
$

63.15
2.62

$

$

71.54

3.10

$

$

54.42

2.98

__________
(1) Future income tax expenses are based on current statutory rates, adjusted for the tax basis of oil and gas properties and applicable tax credits,

(2)

deductions and allowances. 
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.

139

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:

Berry Corp. (Successor)

December 31,
2019

December 31,
2018

December 31,
2017

(in thousands)

Standardized measure—beginning of year

$

1,761,546

$

977,348

$

596,222

Net change in sales and transfer prices and production costs related to

future production

Changes in estimated future development costs

Sales and transfers of oil, natural gas and NGLs produced during the

period

(309,347)

(120,688)

818,705

35,313

224,064

6,399

(300,261)

(321,148)

(189,355)

Net change due to extensions, discoveries and improved recovery

180,825

363,450

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

2,649

—

5,240

(5,593)

(124,110)

(175,947)

116,921

215,153

(5,939)

49,388

(295,409)

78,803

111,416

127,135

(253,176)

784,198

$

1,466,137

$

1,761,546

$

157,717

317,616

(141,998)

124,609

6,913

59,622

(47,651)

(136,810)

381,126

977,348

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.

140

(cid:37)(cid:40)(cid:53)(cid:53)(cid:60)(cid:3)(cid:38)(cid:50)(cid:53)(cid:51)(cid:50)(cid:53)(cid:36)(cid:55)(cid:44)(cid:50)(cid:49)(cid:3)(cid:11)(cid:69)(cid:85)(cid:92)(cid:12)
(cid:54)(cid:56)(cid:51)(cid:51)(cid:47)(cid:40)(cid:48)(cid:40)(cid:49)(cid:55)(cid:36)(cid:47)(cid:3)(cid:50)(cid:44)(cid:47)(cid:3)(cid:9)(cid:3)(cid:49)(cid:36)(cid:55)(cid:56)(cid:53)(cid:36)(cid:47)(cid:3)(cid:42)(cid:36)(cid:54)(cid:3)(cid:39)(cid:36)(cid:55)(cid:36)(cid:3)(cid:11)(cid:38)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:88)(cid:72)(cid:71)(cid:12)
(cid:11)(cid:56)(cid:81)(cid:68)(cid:88)(cid:71)(cid:76)(cid:87)(cid:72)(cid:71)(cid:12)

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

Berry Corp. 
(Successor)

Year Ended
December 31,
2019

Year Ended
December 31,
2018

Ten Months
Ended
December 31,
2017

Berry LLC
(Predecessor)

Two Months
Ended
February 28,
2017

$

$

$

$

58.93

2.66

17.02

$

$

$

64.76

2.74

26.74

$

$

$

48.05

2.70

22.23

$

$

$

46.94

3.42

18.20

20.42

$

19.16

$

15.84

$

13.06

141

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, our President and Chief Executive Officer and our 
Executive Vice President and Chief Financial Officer supervised and participated in our evaluation of our disclosure 
controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 
2019.  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, 
2019 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, 2019, using the criteria in Internal Control-Integrated Framework (2013) issued by the Committee of 
Sponsoring  Organizations  of  the  Treadway  Commission  ("COSO").  Based  on  this  evaluation,  our  management 
concluded that our internal control over financial reporting was effective as of December 31, 2019.

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, 2019 that materially 
affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

142

Item 9B. Other Information

Amended and Restated Employment Agreement with Arthur T. Smith

On February 26, 2020, the Compensation Committee of our Board of Directors approved an amended and restated 
employment agreement to be entered into by Berry LLC, a wholly-owned subsidiary of Berry Corp., with our Chief 
Executive Officer, Arthur T. “Trem” Smith (the “Amended Agreement”), to replace and supersede Mr. Smith’s previous 
employment agreement with the Company (the “Prior Agreement”). The Amended Agreement will become effective 
as of March 1, 2020, subject to Mr. Smith’s continued employment through that date.  

The Amended Agreement modifies certain terms of the Prior Agreement, including the following:

•

The  initial  term  of  the Amended Agreement  is  three  years,  with  automatic  one-year  extensions  on  each
anniversary of the effective date, unless either party gives notice of non-renewal at least 60 days prior to the
such anniversary date.

• Mr. Smith’s base salary remains $650,000, which will be reviewed at least annually by the Board of Directors
(or a committee thereof) and may be increased, but not decreased without Mr. Smith’s consent; provided,
however, that Mr. Smith’s consent will not be required on a determination by the Board (or a committee thereof)
that a decrease of no more than 10% is necessary and appropriate, and such decreases are part of similar
reductions applicable to the Company’s similarly situated executive officers.

• Mr. Smith is eligible to receive an annual equity award in an amount and under terms to be determined in the
sole discretion of the Board of Directors (or a committee thereof). It is contemplated that the amount will be
equal to but not less than three times the sum of Mr. Smith’s base salary and target bonus amount for the
applicable year, but ultimately subject to determination in the sole discretion of the Board of Directors (or a
committee thereof).

• Mr. Smith must give 90 days’ notice in the event he voluntarily resigns from employment.

•

Upon a termination of Mr. Smith’s employment under certain circumstances, including termination without
Cause (as defined in the Amended Agreement) by the Company, his voluntary resignation on the basis of Good
Reason (as defined in the Amended Agreement), his death or disability, he is eligible to receive, among other
payments and benefits, severance in an amount equal to two times (or, if such termination occurs within 12
months following a Sale of Berry (as defined in the Amended Agreement), three times) the sum of Mr. Smith’s
base salary and target annual bonus amount for the year of termination, plus an additional cash payment to
cover health insurance premiums in certain circumstances.

All  other  material  terms  contained  in  the  Prior Agreement  remains  substantially  unchanged  in  the Amended 
Agreement. A copy of the Amended Agreement is filed as Exhibit 10.13 to this Annual Report on Form 10-K and is 
incorporated herein by reference. The description of the material changes to the Prior Agreement contained herein is 
qualified in its entirety by reference to the full text of the Amended Agreement.

Employment Agreement with Danielle Hunter

Effective January 28, 2020, the Board of Directors appointed Danielle Hunter to the office of Executive Vice 
President, General Counsel and Corporate Secretary.  In connection with her appointment as an executive officer, the 
Board  approved  entry  into  a  definitive  employment  agreement  to  be  entered  into  by  Berry  LLC,  a  wholly-owned 
subsidiary of Berry Corp., with Ms. Hunter.  A copy of the employment agreement is filed as Exhibit 10.11 to this 
Annual Report on Form 10-K and is incorporated herein by reference.

143

Employment Agreement with Megan Silva

Effective February 4, 2020, the Board of Directors appointed Megan Silva to the office of Executive Vice President, 
Corporate Affairs.  In connection with her appointment as an executive officer, the Board approved entry into a definitive 
employment agreement to be entered into by Berry LLC, a wholly-owned subsidiary of Berry Corp., with Ms. Silva. 
A copy of the employment agreement is filed as Exhibit 10.13 to this Annual Report on Form 10-K and is incorporated 
herein by reference.

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 2020 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days 
of December 31, 2019.

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.ir.berrypetroleum.com/corporate-governance).  We  intend  to  satisfy  the 
disclosure requirement under Item 5.05 of Form 8-K regarding amendment to, or waiver from, a provision of our code 
of business conduct by posting such information on our website at the address specified above.

Item 11. Executive Compensation

The information required by this Item 11 is incorporated herein by reference to our definitive Proxy Statement, 
for the 2020 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days 
of December 31, 2019. 

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 2020 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days 
of December 31, 2019.

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 2020 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days 
of December 31, 2019.

Item 14. Principal Accounting Fees and Services

The information required by this Item 14 is incorporated herein by reference to our definitive Proxy Statement, 
for the 2020 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days 
of December 31, 2019.

144

Item 15. Exhibits

Exhibit
Number

Part IV

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
10.1 Assignment Agreement, dated February 28, 2017, between Linn Acquisition Company, LLC and Berry 
Petroleum  Corporation  (incorporated  by  reference  to  Exhibit  10.1  to  the  Company’s  Registration 
Statement on Form S-1 (File No. 333-226011))

10.2 Transition Services and Separation Agreement, dated February 28, 2017, by and among Berry Petroleum 
Company, LLC, Linn Energy, LLC and certain of its affiliates and subsidiaries (incorporated by reference 
to Exhibit 10.2 to the Company’s Annual Report on Form 10-K filed March 8, 2019)

10.3 Amended  and  Restated  Stockholders Agreement  between  Berry  Petroleum  Corporation  and  certain 
holders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed July 30, 2018)

10.4 Amended and Restated Registration Rights Agreement, dated June 28, 2018, among Berry Petroleum 
Corporation and the holder party thereto (incorporated by reference to Exhibit 10.4 to the Company’s 
Registration Statement on Form S-1 (File No. 333-226011))

10.5† Executive Employment Agreement, dated March 1, 2017, between Berry Petroleum Company, LLC and 
Arthur “Trem” Smith (incorporated by reference to Exhibit 10.5 to the Company’s Registration Statement 
on Form S-1 (File No. 333-226011))

10.6† Executive Employment Agreement, dated June 28, 2017 between Berry Petroleum Company, LLC and 
Cary D. Baetz (incorporated by reference to Exhibit 10.6 to the Company’s Registration Statement on 
Form S-1 (File No. 333-226011))

10.7† Executive Employment Agreement, dated June 28, 2017 between Berry Petroleum Company, LLC and 
Gary A. Grove (incorporated by reference to Exhibit 10.7 to the Company’s Registration Statement on 
Form S-1 (File No. 333-226011))

10.8† Amended and Restated Employment Agreement, Arthur “Trem” Smith (incorporated by reference to 

Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q filed August 23, 2018)

10.9† Amended and Restated Employment Agreement, Cary D. Baetz (incorporated by reference to Exhibit 

10.15 to the Company’s Quarterly Report on Form 10-Q filed August 23, 2018)

10.10† Amended and Restated Employment Agreement, Gary A. Grove (incorporated by reference to Exhibit 

10.16 to the Company’s Quarterly Report on Form 10-Q filed August 23, 2018)

145

Exhibit
Number
10.11†* Executive Employment Agreement, dated January 28, 2020, between Berry Petroleum Company, LLC 

Description

and Danielle Hunter

10.12†* Executive Employment Agreement, dated February 4, 2020, between Berry Petroleum Company, LLC 

and Megan Silva

10.13†* Second Amended and Restated Executive Employment Agreement, dated March 1, 2020, between Berry 

Petroleum Company, LLC and Arthur “Trem” Smith

10.14† 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))

10.15† 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))

10.16† 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))

10.17† 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))

10.18† 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)

10.19† 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)

10.20† 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))

10.21† 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))
10.22† 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)

10.23† 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)

10.24† 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)

10.25† 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)

10.26† 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)

10.27 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))

10.28 Credit Agreement, dated July 31, 2017, by and among Berry Petroleum Company, LLC, as borrower, 
Berry Petroleum Corporation, as guarantor, Wells Fargo Bank, N.A., as administrative agent and issuing 
lender, and certain lenders (incorporated by reference to Exhibit 10.17 to the Company’s Registration 
Statement on Form S-1 (File No. 333-226011))

146

Exhibit
Number

Description

10.29 Amendment No. 1, dated as of November 16, 2017, to the Credit Agreement, dated July 31, 2017, by 
and among Berry Petroleum Company, LLC, as borrower, Berry Petroleum Corporation, as guarantor, 
Wells Fargo Bank, N.A., as administrative agent and issuing lender, and certain lenders (incorporated 
by  reference  to  Exhibit  10.18  to  the  Company’s  Registration  Statement  on  Form  S-1  (File  No. 
333-226011))

10.30 Amendment No. 2, dated as of March 8, 2018, to the Credit Agreement, dated July 31, 2017, by and 
among Berry Petroleum Company, LLC, as borrower, Berry Petroleum Corporation, as guarantor, Wells 
Fargo  Bank,  N.A.,  as  administrative  agent  and  issuing  lender,  and  certain  lenders  (incorporated  by 
reference to Exhibit 10.19 to the Company’s Registration Statement on Form S-1 (File No. 333-226011))

10.31 Amendment No. 3, dated November 14, 2018, to the Credit Agreement, dated July 31, 2017, by and 
among Berry Petroleum Company, LLC, as borrower, Berry Petroleum Corporation, as guarantor, Wells 
Fargo  Bank,  N.A.,  as  administrative  agent  and  issuing  lender,  and  certain  lenders  (incorporated  by 
reference to Exhibit 10.1 of Form 8-K filed November 15, 2018)

10.32 Amendment No. 4, dated December 17, 2019, to the Credit Agreement, dated July 31, 2017, by and 
among Berry Petroleum Company, LLC, as borrower, Berry Petroleum Corporation, as guarantor, Wells 
Fargo  Bank,  N.A.,  as  administrative  agent  and  issuing  lender,  and  certain  lenders  (incorporated  by 
reference to Exhibit 10.1 of Form 8-K filed December 18, 2019)

10.33 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)

10.34 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)

21.1* List of Subsidiaries of Berry Corporation (bry)

23.1* Consent of KPMG LLP

23.2* Consent of DeGolyer and MacNaughton

31.1* Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2* Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1* Certifications of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the 

Sarbanes-Oxley Act of 2002.

99.1* Report as of December 31, 2019 of DeGolyer and MacNaughton

101.INS* XBRL Instance Document

101.SCH* XBRL Taxonomy Extension Schema Document

101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* XBRL Taxonomy Extension Label Linkbase Data Document

101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document

__________
(*)  Filed herewith.
(†)    Indicates a management contract or compensatory plan or arrangement.

Item 16. Form 10-K Summary

Not applicable.

147

GLOSSARY OF COMMONLY USED TERMS

The following are abbreviations and definitions of certain terms used in this report, which are commonly used in 

the oil and natural gas industry:

"Absolute TSR" means absolute total stockholder return.

"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 other unusual, out-of-period and infrequent items, including 
gains and losses on sale of assets, restructuring costs and reorganization items.

“Adjusted G&A” or “Adjusted General and Administrative Expenses” is a non-GAAP financial measure defined 
as general and administrative expenses adjusted for restructuring and other non-recurring costs and non-cash stock 
compensation expense.

“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, other unusual, out-of-period and 
infrequent items, including restructuring costs and reorganization items and the income tax expense or benefit of these 
adjustments using our effective tax rate.

“API” gravity means the relative density, expressed in degrees, of petroleum liquids based on a specific gravity 

scale developed by the American Petroleum Institute.

“basin” means a large area with a relatively thick accumulation of sedimentary rocks.

“Bbl”  means  one  stock  tank  barrel,  or  42  U.S.  gallons  liquid  volume,  used  in  reference  to  oil  or  other  liquid 

hydrocarbons.

“Bcf” means one billion cubic feet, which is a unit of measurement of volume for natural gas.

“BLM” means for the U.S. Bureau of Land Management.

“Boe” means barrel of oil equivalent, determined using the ratio of one Bbl of oil, condensate or natural gas liquids 

to six Mcf of natural gas.

“Boe/d” means Boe per day.

“Break even” means the Brent price at which we expect to generate positive Levered Free Cash Flow. 

“Brent” means the reference price paid in U.S. dollars for a barrel of light sweet crude oil produced from the Brent 

field in the UK sector of the North Sea.

“Btu” means one British thermal unit—a measure of the amount of energy required to raise the temperature of a 

one-pound mass of water one degree Fahrenheit at sea level.

“CAA” is an abbreviation for the Clean Air Act, which governs air emissions.

“CalGEM” is an abbreviation for the California Geologic Energy Management Division.

148

“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.

“CARB” is an abbreviation for the California Air Resources Board.

“CCA” or “CCAs” is an abbreviation for California carbon allowances.

“CERCLA” is an abbreviation for the Comprehensive Environmental Response, Compensation and Liability Act, 
which imposes liability where hazardous substances have been released into the environment (commonly known as 
“Superfund”).

“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.

"COGCC" is an abbreviation for the Colorado Oil and Gas Conservation Commission.

“Completion” means the installation of permanent equipment for the production of oil or natural gas.

“Condensate” means a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature 

and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

“CPUC” is an abbreviation for the California Public Utilities Commission.

“CWA” is an abbreviation for the Clean Water Act, which governs discharges to and excavations within the waters 

of the United States.

“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.

“DOGGR” is an abbreviation for the Division of Oil, Gas, and Geothermal Resources of the California Department 

of Conservation.

“Downspacing” means additional wells drilled between known producing wells to better develop the reservoir.

"EH&S" is an abbreviation for Environmental, Health & Safety.

“Enhanced oil recovery” means a technique for increasing the amount of oil that can be extracted from a field.

“EOR” means enhanced oil recovery.

“EPA” is an abbreviation for the United States Environmental Protection Agency.

"EPS" is an abbreviation for earnings per share.

“ESA” is an abbreviation for the federal Endangered Species Act.

149

“Exploration activities” means the initial phase of oil and natural gas operations that includes the generation of a 

prospect or play and the drilling of an exploration well.

“FASB” is an abbreviation for the Financial Accounting Standards Board.

“FERC” is an abbreviation for the Federal Energy Regulatory Commission.

“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same 

individual geological structural feature or stratigraphic condition.

"FIP" is an abbreviation for Federal Implementation Plan.

“Formation” means a layer of rock which has distinct characteristics that differ from those of nearby rock.

“Fracturing” means mechanically inducing a crack or surface of breakage within rock not related to foliation or 

cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.

“GAAP” is an abbreviation for U.S. generally accepted accounting principles.

“Gas” or “Natural gas” means the lighter hydrocarbons and associated non-hydrocarbon substances occurring 
naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain 
liquids.

“GHG” or “GHGs”  is an abbreviation for greenhouse gases.

“Gross Acres” or “Gross Wells” means the total acres or wells, as the case may be, in which we have a working 

interest.

“Held by production” means acreage covered by a mineral lease that perpetuates a company’s right to operate a 

property as long as the property produces a minimum paying quantity of oil or natural gas.

“Henry Hub” is a distribution hub on the natural gas pipeline system in Erath, Louisiana.

“Hydraulic fracturing” means a procedure to stimulate production by forcing a mixture of fluid and proppant 
(usually  sand)  into  the  formation  under  high  pressure. This  creates  artificial  fractures  in  the  reservoir  rock,  which 
increases permeability.

“Horizontal drilling” means a wellbore that is drilled laterally.

“ICE” means Intercontinental Exchange.

“Infill drilling” means drilling of an additional well or wells at less than existing spacing to more adequately drain 

a reservoir.

“Injection Well” means a well in which water, gas or steam is injected, the primary objective typically being to 

maintain reservoir pressure and/or improve hydrocarbon recovery.

“IOR” means improved oil recovery.

"IPO" is an abbreviation for initial public offering. 

"LCFS" is an abbreviation for low carbon fuel standard.

150

“Leases” means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for, produce 
and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally 
acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.

“Levered Free Cash Flow” is a non-GAAP financial measure defined as Adjusted EBITDA less interest expense, 

dividends and capital expenditures.

"LIBOR" is an abbreviation for London Interbank Offered Rate.

“MBbl” means one thousand barrels of oil, condensate or NGLs.

“MBbl/d” means MBbl per day.

“MBoe” means one thousand barrels of oil equivalent.

“MBoe/d” means MBoe per day.

“Mcf” means one thousand cubic feet, which is a unit of measurement of volume for natural gas.

“MMBbl” means one million barrels of oil, condensate or NGLs.

“MMBoe” means one million barrels of oil equivalent.

“MMBtu” means one million Btus.

“MMcf” means one million cubic feet, which is a unit of measurement of volume for natural gas.

“MMcf/d” means MMcf per day.

"MTBA" is an abbreviation for Migratory Bird Treaty Act.

“MW” means megawatt.

"MWHs" means megawatt hours. 

“NAAQS” is an abbreviation for the National Ambient Air Quality Standard.

"NASDAQ" means Nasdaq Global Select Market.

“NEPA” is an abbreviation for the National Environmental Policy Act, which requires careful evaluation of the 

environmental impacts of oil and natural gas production activities on federal lands.

“Net Acres” or “Net Wells” is the sum of the fractional working interests owned in gross acres or wells, as the case 

may be, expressed as whole numbers and fractions thereof.

“Net revenue interest” means all of the working interests, less all royalties, overriding royalties, non-participating 

royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.

“NGA” is an abbreviation for the Natural Gas Act.

“NGL” or “NGLs” means natural gas liquids, which are the hydrocarbon liquids contained within natural gas.

"NRI" is an abbreviation for net revenue interest. 

151

“NYMEX” means New York Mercantile Exchange.

“Oil” means crude oil or condensate.

“OPEC” is an abbreviation for the Organization of the Petroleum Exporting Countries.

“Operator”  means  the  individual  or  company  responsible  to  the  working  interest  owners  for  the  exploration, 

development and production of an oil or natural gas well or lease.

“OSHA” is an abbreviation for the Occupational Safety and Health Act of 1970.

"OTC" means over-the-counter

"PALs" is an abbreviation for project approval letters.

“PCAOB” is an abbreviation for the Public Company Accounting Oversight Board.

“PDNP” is an abbreviation for proved developed non-producing.

“PDP” is an abbreviation for proved developed producing.

“Permeability” means the ability, or measurement of a rock’s ability, to transmit fluids.

“PHMSA” is an abbreviation for the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety 

Administration.

“Play”  means  a  regionally  distributed  oil  and  natural  gas  accumulation.  Resource  plays  are  characterized  by 

continuous, aerially extensive hydrocarbon accumulations.

“PPA” is an abbreviation for power purchase agreement.

“Production  costs”  means  costs  incurred  to  operate  and  maintain  wells  and  related  equipment  and  facilities, 
including depreciation and applicable operating costs of support equipment and facilities and other costs of operating 
and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer 
to the SEC’s Regulation S-X, Rule 4-10(a)(20).

“Productive well” means a well that is producing oil, natural gas or NGLs or that is capable of production.

“Proppant” means sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing 

treatment.

“Prospect” means a specific geographic area which, based on supporting geological, geophysical or other data and 
also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the 
discovery of commercial hydrocarbons.

“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with 

existing equipment and operating methods.

“Proved developed producing reserves” means reserves that are being recovered through existing wells with existing 

equipment and operating methods.

“Proved reserves” means the estimated quantities of oil, gas and gas liquids, which, by analysis of geoscience and 
engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, 
from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior 

152

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

“PURPA” is an abbreviation for the Public Utility Regulatory Policies Act.

“PV-10” is a non-GAAP financial measure and represents the present value of estimated future cash inflows from 
proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the 
timing of future cash flows  and using SEC-prescribed pricing assumptions for the period. While this measure does not 
include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an 
indicative representation of the relative value of the company on a comparative basis to other companies and from 
period to period.

"QF" means qualifying facility.

“RCRA” is an abbreviation for the Resource Conservation and Recovery Act, which governs the management of 

solid waste.

“Realized price” means the cash market price less all expected quality, transportation and demand adjustments.

“Reasonable certainty” means a high degree of confidence. For a complete definition of reasonable certainty, refer 

to the SEC’s Regulation S-X, Rule 4-10(a)(24).

“Recompletion” means the completion for production from an existing wellbore in a formation other than that in 

which the well has previously been completed.

"Relative TSR" means relative total stockholder return.

“Reserves” means estimated remaining quantities of oil and natural gas and related substances anticipated to be 
economically producible, as of a given date, by application of development projects to known accumulations. In addition, 
there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue 
interest in the production, installed means of delivering oil and natural gas or related substances to market and all 
permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated 
by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. 
Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive 
reservoir  (i.e.,  absence  of  reservoir,  structurally  low  reservoir  or  negative  test  results).  Such  areas  may  contain 
prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

153

“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. 

“SDWA” is an abbreviation for the Safe Drinking Water Act, which governs the underground injection and disposal 

of wastewater;.

“SEC Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines 
of the SEC and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first 
day of each of the 12 months ended on the given date.

“Seismic Data” means data produced by an exploration method of sending energy waves into the earth and recording 
the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. 2-D seismic provides 
two-dimensional information and 3-D seismic provides three-dimensional views.

“Spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in 

terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“SPCC plans” means spill prevention, control and countermeasure plans.

“Steamflood” means cyclic or continuous steam injection.

“Standardized measure” means discounted future net cash flows estimated by applying year-end prices to the 
estimated future production of proved reserves. Future cash inflows are reduced by estimated future production and 
development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are 
computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural 
gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

“Stimulating” means mechanically inducing a crack or surface of breakage within rock not related to foliation or 

cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.

“Strip Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines 
of the SEC and accounting rules with the exception of pricing that is based on average annual forward-month ICE 
(Brent) oil and NYMEX Henry Hub natural gas contract pricing in effect on a given date to reflect the market expectations 
as of that date.

“Superfund” is a commonly known term for CERLA.

“UIC” is an abbreviation for the Underground Injection Control program.

154

“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.

155

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, 2020

BERRY CORPORATION (bry)

/s/ A. T. Smith

A. T. “Trem” Smith

President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the 

following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date

Signature

Title

February 27, 2020

/s/ A. T. Smith

President and Chief Executive Officer, and Director

A. T. “Trem” Smith

(Principal Executive Officer)

February 27, 2020

/s/ Cary Baetz

Cary Baetz

February 27, 2020

February 27, 2020

February 27, 2020

February 27, 2020

February 27, 2020

February 27, 2020

/s/ M. S. Helm

Michael S. Helm

/s/ E. J. Voiland

Eugene J. Voiland

/s/ Brent S. Buckley

Brent S. Buckley

/s/ C K Potter

C. Kent Potter

/s/ Anne L. Mariucci

Anne L. Mariucci

/s/ Donald L. Paul

Donald L. Paul

Executive Vice President and Chief

Financial Officer, and Director

(Principal Financial Officer)

Chief Accounting Officer

(Principal Accounting Officer)

Director

Director

Director

Director

Director

156

DIRECTORS

A.T. (TREM) SMITH
Board Chair, Chief Executive Ofﬁcer & President  
Berry Corporation (bry)

CARY BAETZ
Executive Vice President & Chief Financial Ofﬁcer  
Berry Corporation (bry)

BRENT BUCKLEY (1) (2)
Independent Director  
Managing Director with Beneﬁt Street Partners

ANNE MARIUCCI (3C) (2)
Lead Independent Director 
Former President of Del Webb Corporation

DONALD PAUL (1) (3)
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. KENT POTTER (1C) (3) 
Independent Director 
Former Executive Vice President &  
Chief Financial Ofﬁcer of LyondellBasell Industries

EUGENE (GENE) VOILAND (2C) (1) 
Independent Director
Former President & Chief Executive Ofﬁcer  
of Aera Energy LLC

(C) Committee Chair  
(1) Audit Committee  
(2) Compensation Committee  
(3) Nominating & Corporate Governance Committee

EXECUTIVE OFFICERS

A.T. (TREM) SMITH
Board Chair, Chief Executive Ofﬁcer  
& President

CARY BAETZ
Executive Vice President  
& Chief Financial Ofﬁcer, Director

GARY GROVE
Executive Vice President  
& Chief Operating Ofﬁcer

DANIELLE HUNTER
Executive Vice President,  
General Counsel & Corporate Secretary

MEGAN SILVA
Executive Vice President,  
Corporate Affairs

KURT NEHER
Executive Vice President,  
Business Development

INVESTOR RELATIONS
Todd Crabtree 
Berry Corporation (bry)  
16000 N. Dallas Pkwy, Ste 500  
Dallas, TX 75248 
(661) 616-3811  
ir@bry.com

TRANSFER AGENT/REGISTRAR
American Stock Transfer & Trust Company, LLC 
6201 15th Avenue 
Brooklyn, NY 11219 

Shareholder Services  
(718) 921-8200  
astﬁnancial.com

SECURITIES
Berry Common Stock is traded on Nasdaq  
under the symbol BRY.

ANNUAL REPORT ON FORM 10-K FOR 2019
Our Form 10-K is included in this document in its entirety as 
ﬁled with the SEC. Upon request to Investor Relations, we will 
deliver free of charge a copy of our Form 10-K.

TOTAL SHAREHOLDER RETURN PERFORMANCE GRAPH
Our Form 10-K includes a performance graph comparing the 
cumulative total return to shareholders on our common stock 
relative to the cumulative total returns of the S&P Smallcap 600, 
the Dow Jones U.S. Exploration and Production indexes and the 
Vanguard Energy ETF (with reinvestment of all dividends).

DIVIDEND PAYMENT DATES
Quarterly Dividends on common stock are paid, following  
declaration by the Board of Directors, on approximately the  
15th day of January, April, July and October.

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM  
KPMG LLP, Los Angeles, California  
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, liquidity, cash ﬂows  
and business prospects, including our expectations as to our future ﬁnancial position, 
liquidity, cash ﬂows, results of operations and business strategy, potential acquisi-
tion opportunities, other plans and objectives for operations, maintenance capital 
requirements, expected production and costs, reserves, hedging activities, capital 
expenditures, return of capital, improvement of recovery factors and other guidance. 
Factors (but not necessarily all the factors) that could cause 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; 
availability and the 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 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; 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.

THE  C ORE VA LUE S TH AT DEFINE 
OUR C OMPA N Y CULT URE:

ACCOUNTABILIT Y       

OWNERSHIP     

COMMUNICATION       

LE ADERSHIP     

ENTREPRENEURSHIP   

INVESTOR REL ATIONS   Berry Corporation (bry)   16000 N. Dallas Pkwy, Ste 500   Dallas, Texas 75248  
 ir@bry.com  br y.com