Founded on Value.
Focused on Growth.
2018 ANNUAL REPORT
Front and back photography courtesy of Nasdaq, Inc.
INVESTOR RELATIONS
Berry Petroleum Corporation
16000 N. Dallas Pkwy, Ste. 500
Dallas, TX 75248
(661) 616-3811
ir@bry.com
berrypetroleum.com
2018 Adjusted
EBITDA* of
$258M
2018 Cash Flows
from Operations of
$230M
(excluding $127 million for
hedge early termination)
California PV-10* of
$2 billion out of
$2.2 billion total
Replaced
275%
reserves* in
California
and 114%
of total
company
reserves
Letter to shareholders
Value Focused
2018 was monumental for Berry. By
executing our simple and clear business
model, Berry was and continues to be
wholly focused on value creation for
its shareholders. Our goal is always to
generate growth while operating within
our levered free cash flow. We manage
to value and not just to volume growth
and we did this in 2018 with excellence,
realizing operational efficiencies,
production growth and incident
prevention improvements.
Most notably on July 26, just a short
16 months after emerging from
bankruptcy, we began trading on the
Nasdaq, reinforcing our strong position
in the industry and value in the market.
California Focus
Last year was all about California,
where we produced 100% oil, spent
most of our capital, and realized
all of our production growth as
well as the preponderance of our
operating income. As a result, we
added more than $1 billion to our
PV-10* valuation and accomplished a
275% reserve* replacement ratio. Our
operations are focused in California,
too. Approximately 70% of our total
company production came from
the world-class super basin, the San
Joaquin Basin, and approximately
94% of the production is in Kern
County alone. Just three fields on
County alo
the west side of the Basin (Belridge,
the west s
McKittrick and Midway Sunset) made
McKittrick
up 80% o
up 80% of our production in California
and 59% of our total production. We
and 59%
remain focused on thermal recovery
remain fo
of heavy oil in shallow, conventional
of heavy
reservoir
reservoirs—perfect for the refineries in
California. Finally, we drilled 224 wells
California
in California in 2018, resulting in a 15%
in Califor
producti
production increase.
Further,
Further, our bolt-on strategy, the
addition
addition of low-risk acreage near
completed in 2018, increasing our
acreage position in the Midway
Sunset Field by about 20%.
Future Focus
Looking ahead, our focus isn’t changing
in 2019. We currently have, and expect
to continue to have, four rigs running,
all in California.
We will direct even more capital
to California than we did in 2018
where we expect a mid- to high-
teen production exit growth rate and
continued significant reserve growth.
In 2019, we forecast approximately
94% of our capital including 98%
of our development capital to be
spent in California and plan to drill
approximately 400 wells.
We are in a great position for continued
improvement to maximize the value of
our existing fields while continuously
looking for growth through bolt-ons
and strategic acquisitions. We have
several bolt-on opportunities under
negotiations, which, if fully executed,
could grow our acreage position in
Midway Sunset by more than 50%.
Berry’s future looks bright. Our
technical assessment of our current
resource and original oil in place
indicates that a simple 1% increase
in recovery factor could result in
the addition of more than 20 million
barrels of oil in California.
Berry First Focus
We are dedicated to our Berry First
approach—to be the leader in this
industry. With the commitment of
all 325+ employees, we will continue
to execute our plan with excellence,
growing our company and, as always,
creating value for our shareholders.
our existing production and
infrastructure, was effective.
We now have access to 879
new acres through bolt-ons
A.T. (TREM) SMITH
Board Chair, Chief Executive Officer
& President
Berry Petroleum Corporation
* For definitions and GAAP reconciliations, see Form 10-K “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations—Non-GAAP Financial Measures” and “Items 1 and 2. Business
and Properties—Our Reserves and Production Information”. Reserves replacement ratio is calculated by
dividing the sum of proved reserve extensions and discoveries, revisions of previous estimates, improved
recovery and purchases and sales of minerals in place for the year by current year production. There is no
guarantee that historical sources of reserves additions will continue.
DIRECTORS
A.T. (TREM) SMITH
Board Chair, Chief Executive Officer
& President
Berry Petroleum Corporation
CARY BAETZ
Executive Vice President
& Chief Financial Officer
Berry Petroleum Corporation
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
EXECUTIVE OFFICERS
A.T. (TREM) SMITH
Board Chair, Chief Executive Officer
& President
CARY BAETZ
Executive Vice President
& Chief Financial Officer
GARY GROVE
Executive Vice President
& Chief Operating Officer
KURT NEHER
Executive Vice President,
Business Development
KENDRICK ROYER
Executive Vice President,
General Counsel & Corporate Secretary
GENERAL SHAREHOLDER INFORMATION
Shareholders and members of the investment
community should direct inquiries to:
INVESTOR RELATIONS
Todd Crabtree
Berry Petroleum Corporation
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
United States
Shareholder Services
(718) 921-8200
www.astfinancial.com
SECURITIES
Berry Common Stock is traded on
Nasdaq under the symbol BRY.
FORM 10-K
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.
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/us/en/home
(C) Committee Chair
(1) Audit Committee (2) Compensation Committee
(3) Nominating & Corporate Governance Committee
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 acquisition
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 and meet working capital
requirements; price and availability of natural gas; ability to hedge
price risk; impact of governmental regulations, and of current, pending
or future legislation; proved reserves estimation uncertainties; ability
to replace our reserves; availability of permits; drilling risk; 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”.
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, 2018
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 PETROLEUM CORPORATION
(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
Name of Each Exchange on Which Registered
Nasdaq Global Select Market
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
No
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K.
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
As of June 30, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, the registrant’s equity was not listed
on any domestic exchange or over-the-counter market. The registrant’s common stock began trading on the Nasdaq Global Select Market
(“NASDAQ”) on July 26, 2018.
Shares of common stock outstanding as of February 28, 2019
82,061,650
DOCUMENTS INCORPORATED BY REFERENCE
The Company’s definitive proxy statement relating to the annual meeting of shareholders (to be held May 14, 2019) will be filed with the
Securities and Exchange Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2018 and is
incorporated by reference in Part III to the extent described herein.
(This page intentionally left blank)
Table of Contents
Part I
Item 1 and 2. Business and Properties .........................................................................................................
Our Company ..........................................................................................................................................
The Berry Advantage ..............................................................................................................................
Our Reserves and Assets .........................................................................................................................
Our Competitive Strengths......................................................................................................................
Our Business Strategy .............................................................................................................................
Our Capital Budget .................................................................................................................................
Our Areas of Operation ...........................................................................................................................
Methods of Recovery ..............................................................................................................................
Our Reserves and Production Information..............................................................................................
Title to Properties ....................................................................................................................................
Competition.............................................................................................................................................
Seasonality ..............................................................................................................................................
Regulation of Health, Safety and Environment Matters .........................................................................
Employees ...............................................................................................................................................
Emergence from Chapter 11 Bankruptcy................................................................................................
Corporate Information.............................................................................................................................
Item 1A. Risk Factors ..................................................................................................................................
Item 1B. Unresolved Staff Comments .........................................................................................................
Item 3. Legal Proceedings............................................................................................................................
Item 4. Mine Safety Disclosure ...................................................................................................................
Part II
Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities......................................................................................................................................
Item 6. Selected Financial Data ...................................................................................................................
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ..........
Executive Overview ................................................................................................................................
How We Plan and Evaluate Operations ..................................................................................................
Emergence from Chapter 11 Bankruptcy................................................................................................
Factors Affecting the Comparability of our Financial Condition and Results of Operations.................
Business Environment and Market Conditions.......................................................................................
Certain Operating and Financial Information .........................................................................................
Summary by Area....................................................................................................................................
Results of Operations ..............................................................................................................................
Liquidity and Capital Resources .............................................................................................................
Balance Sheet Analysis ...........................................................................................................................
Non-GAAP Financial Measures..............................................................................................................
Off Balance-Sheet Arrangements............................................................................................................
Critical Accounting Policies and Estimates ............................................................................................
Inflation ...................................................................................................................................................
1
1
2
3
4
6
7
7
10
12
22
23
23
23
32
32
33
33
49
49
49
50
53
55
55
55
56
56
60
62
65
65
75
81
82
85
86
90
i
Cautionary Note Regarding Forward-Looking Statements ....................................................................
Item 7A. Quantitative and Qualitative Disclosures About Market Risk......................................................
Item 8. Financial Statements and Supplementary Data ...............................................................................
Index to Financial Statements and Supplementary Data.........................................................................
Report of Independent Registered Public Accounting Firm ...................................................................
Consolidated Balance Sheets ..................................................................................................................
Consolidated Statements of Operations ..................................................................................................
Consolidated Statements of Equity .........................................................................................................
Consolidated Statements of Cash Flows .................................................................................................
Notes to Consolidated Financial Statements...........................................................................................
Supplemental Quarterly Financial Data (Unaudited)..............................................................................
Supplemental Oil & Natural Gas Data (Unaudited) ...............................................................................
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..........
Item 9A. Controls and Procedures ...............................................................................................................
Item 9B. Other Information .........................................................................................................................
Part III
Item 10. Directors, Executive Officers and Corporate Governance ............................................................
Item 11. Executive Compensation ...............................................................................................................
Item 12. Security Ownership of Certain Beneficial Owners and Management...........................................
Item 13. Certain Relationships and Related Transactions and Director Independence ...............................
Item 14. Principal Accounting Fees and Services........................................................................................
Part IV
Item 15. Exhibits..........................................................................................................................................
Item 16. Form 10-K Summary.....................................................................................................................
Glossary of Commonly Used Terms............................................................................................................
Signatures.....................................................................................................................................................
90
92
94
94
95
96
97
98
99
100
135
137
144
144
144
145
145
145
145
145
146
148
149
156
The financial information and certain other information presented in this report have been rounded to the nearest
whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the
total figure given for that column in certain tables in this report. In addition, certain percentages presented in this report
reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly
to the percentages that would be derived if the relevant calculations were based upon the rounded numbers, or may not
sum due to rounding.
ii
Items 1 and 2. Business and Properties
Part I
When we use the terms “we,” “us,” “our,” the “Company,” or similar words in this report, unless the context
otherwise requires, on or prior to 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—Lawsuits, Claims,
Commitments, and Contingencies”), we are referring to Berry LLC, our predecessor company, and following the
Effective Date, we are referring to Berry Corp. and its subsidiary, Berry LLC, together, the successor company, as
applicable.
Our Company
We are a western United States independent upstream energy company with a focus on the conventional, long-
lived oil reserves in the San Joaquin basin of California. Our long-lived, high-margin asset base is uniquely positioned
to support our objectives of generating top-tier corporate-level returns and positive levered free cash flow through
commodity price cycles. Successful execution of our strategy across our low-declining production base and extensive
inventory of identified drilling locations will result in long-term, capital efficient production growth as well as the
ability to continue returning capital to our stockholders.
We target onshore, low-cost, low-risk, oil-rich reservoirs in the San Joaquin basin of California and, to a lesser
extent, our Rockies assets including 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. In the aggregate, the Company’s assets are characterized by:
•
•
•
•
•
•
high oil content, which has grown to over 85% of our production;
favorable Brent-influenced crude oil pricing dynamics;
long-lived, conventional reserves with low and predictable production decline rates;
stable development and production cost structures;
an extensive inventory of low-risk identified development drilling opportunities with attractive full-cycle
economics; and
potential in-basin organic and strategic opportunities to expand our existing inventory with new locations of
substantially similar geology and economics.
California is and has been one of the most productive oil and natural gas regions in the world. Our asset base is
concentrated in the oil-rich San Joaquin basin in California, which has more than 100 years of production history,
substantial remaining oil in place, and is considered a super basin. As a result of the substantial data produced over the
basin's long history, its geological and reservoir characteristics are well understood, leading to predictable, repeatable,
low-risk development opportunities.
In California, we focus on conventional, shallow reservoirs, the drilling and completion of which are relatively
low-cost in contrast to unconventional resource plays. Our decades-old proven completion techniques in these reservoirs
include cyclic and continuous steam injection and low-volume hydraulic stimulation. 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 operations will average $1.3 million per well.
As noted, we own additional assets in the Uinta basin in Utah, a mature, light-oil-prone play with significant
undeveloped resources where we have high operational control and additional behind pipe potential, as well as in the
Piceance basin in Colorado, a prolific low geologic risk natural gas play where we produce from a conventional, tight
1
sandstone reservoir using proven slick water stimulation techniques to increase recoveries. On November 30, 2018,
we sold our non-core gas-producing properties and related assets located in the East Texas basin.
As of December 31, 2018, we had estimated total proved reserves of 142,720 MBoe. For the year ended
December 31, 2018, we had average production of approximately 27.0 MBoe/d, of which approximately 82% was oil.
For the three months ended December 31, 2018, we had average production of approximately 28.0 MBoe/d, of which
approximately 85% was oil. In California, our average production for the year and the quarter ended December 31,
2018 was 19.7 MBoe/d and 21.7 MBoe/d, respectively, of which approximately 100% was oil.
The Berry Advantage
We believe that our combination of low production decline rates, high-margin Brent-influenced oil-weighted
production, attractive development opportunities and a stable cost environment differentiates us from our competitors
and allows us to break even on a cash flow basis and maintain production at relatively low commodity prices. Our
advantages give us an ability to generate top-tier corporate level returns, positive Levered Free Cash Flow and capital-
efficient growth through commodity price cycles. “Levered Free Cash Flow” is a non-GAAP financial measure defined
as Adjusted EBITDA less interest expense, dividends and capital expenditures.
Our Low Declining Production Base
Our California reserves are predominantly long-lived and characterized by relatively low production decline rates
and development costs, affording us 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
19% to 11% in the years between 2019 and 2024 based on total PDP Boe reserves as of December 31, 2018 as reflected
in our SEC reserves report, which is attached as Exhibit 99.1. Our SEC reserves report is based on the estimated
individual well production profiles used to determine our PDP reserves. Based on the assumptions underlying our PUD
estimates, we estimate that we will require slightly more than $10 per Boe in annual capital expenditures to keep
production volumes consistent each year over the next three years. In addition to our low and stable cash operating
costs, which were approximately $26 per Boe in 2018, we can operate and maintain production at relatively low
commodity price levels. Considering our typical realized prices, we believe our operations break even when crude
prices are at or above $45 Brent.
Our High-Margin Brent-Influenced Oil-Weighted Production
Our highly oil-weighted production combined with a Brent-influenced California pricing dynamic and stable cost
structure has resulted, and is expected to continue to result, in strong operating margins at current commodity prices.
As of December 31, 2018, our California PUD reserves were 100% oil.
Our Stable California Operating and Development Cost Environment
The operating and development cost structures of our conventional California asset base are inherently stable and
predictable. Our California focus has insulated us from the cost inflation pressures experienced by our peers who operate
primarily in unconventional plays. This is the result of our established infrastructure, low-intensity service requirements
and lack of dependence on inventory-constrained and often highly specialized equipment. In addition, the majority of
our California assets are located in the fields of the San Joaquin basin and are characterized by heavy oil found in
shallow reservoirs. The costs to develop these reservoirs are lower when compared to the water flood fields of the Los
Angeles and Ventura basins.
2
Our Reserves and Assets
As of December 31, 2018, we had estimated total proved reserves of 142,720 MBoe. For the year ended
December 31, 2018, we had average production of approximately 27.0 MBoe/d, of which approximately 82% was oil.
For the three months ended December 31, 2018, we had average production of approximately 28.0 MBoe/d, of which
approximately 85% was oil. In California, our average production for the year and the quarter ended December 31,
2018 was 19.7 MBoe/d and 21.7 MBoe/d, respectively, of which approximately 100% was oil.
The majority of our reserves are composed of heavy crude oil in shallow, long-lived reservoirs. As of December 31,
2018, approximately three quarters of our proved reserves and approximately 94% 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. On November 30, 2018, we sold our non-core gas-producing properties and related assets
located in the East Texas basin.
As of December 31, 2018, the standardized measure of discounted future net cash flows of our proved reserves
and the PV-10 of our proved reserves were approximately $1.8 billion and $2.2 billion, respectively. PV-10 is a financial
measure that is not calculated in accordance with U.S. generally accepted accounting principles (“GAAP”). For a
definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see
“—Our Reserves and Production Information—PV-10”.
The tables below summarize our proved reserves and PV-10 by category as of December 31, 2018:
Proved Reserves as of December 31, 2018(1)
Oil
(MMBbl)
Natural
Gas (Bcf)
NGLs
(MMBbl)
Total
(MMBoe)
% of
Proved
% Proved
Developed
Capex(2)
($MM)
PV-10(3)
($MM)
62
11
42
115
106
76
—
85
161
—
1
—
—
1
—
76
11
56
143
106
53%
8%
39%
100%
N/A
87% $
13%
—%
100% $
35
24
683
742
N/A $
603
$
1,263
248
641
2,152
2,027
$
$
PDP
PDNP
PUD
Total
California
__________
(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 $71.54 per Bbl Intercontinental
Exchange (“ICE”) Brent oil (“Brent”) for oil and natural gas liquids (“NGLs”) and $3.10 per MMBtu New York Mercantile Exchange
(“NYMEX”) Henry Hub (“Henry Hub”) for natural gas at December 31, 2018. The volume-weighted average prices over the lives of the
properties were estimated at $66.49 per Bbl of oil and condensate, $32.87 per Bbl of NGLs and $2.806 per Mcf of gas. The prices were held
constant for the lives of the properties and we took into account pricing differentials reflective of the market environment. Prices were calculated
using oil and natural gas price parameters established by current SEC guidelines and accounting rules, including adjustment by lease for quality,
fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
Please see “—Our Reserves and Production Information—PV-10”.
(2) Represents undiscounted future capital expenditures estimated as of December 31, 2018.
(3) PV-10 is a financial measure that is not calculated in accordance with GAAP. For a definition of PV-10 and a reconciliation to the standardized
measure of discounted future net cash flows, please see “—Our Reserves and Production Information—PV-10”. PV-10 does not give effect to
derivatives transactions.
3
The table below summarizes our average net daily production by basin for the year ended December 31, 2018:
Average Net Daily Production(1)
for the Year Ended
December 31, 2018
(MBoe/d)
Oil (%)
19.7
7.3
27.0
100%
32%
82%
California
Rockies
Total
__________
(1) Production represents volumes sold during the period.
Our Development Inventory
We have an extensive inventory of low-risk, high-return development opportunities. As of December 31, 2018,
we identified 3,314 gross drilling locations company-wide that we anticipate drilling over the next 5 to 10 years, which
we refer to as our “Tier 1” locations, and 3,716 additional gross drilling locations that are currently under review. For
a discussion of how we identify drilling locations, please see “—Our Reserves and Production Information—
Determination of Identified Drilling Locations.”
We operate approximately 98% of our producing wells. In addition, approximately 75% of our acreage is held by
production, including 99% of our acreage in California. The combined net acreage covered by leases expiring in the
next three years represented approximately 5% of our total net acreage at December 31, 2018. 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 operations as of December 31, 2018:
Acreage
Gross
Net
11,268
8,333
134,470
100,126
145,738
108,459
Net Acreage
Held By
Production(%)
Producing
Wells,
Gross(1)(2)
Average
Working
Interest
(%)(2)(3)
Net
Revenue
Interest
(%)(2)(4)
Identified Drilling
Locations(5)
Gross
Net
99%
73%
75%
2,698
1,105
3,803
99%
94%
98%
93%
75%
89%
4,923
2,107
7,030
4,915
1,747
6,662
California
Rockies
Total
__________
(1)
Includes 540 steamflood and waterflood injection wells in California.
(2) Excludes 91 wells in the Piceance basin each with a 5% working interest.
(3) Represents our weighted-average working interest in our active wells.
(4) Represents our weighted-average net revenue interest for the year ended December 31, 2018.
(5) Our total identified drilling locations include approximately 1,071 gross (1,058 net) locations associated with PUDs as of December 31, 2018,
including 88 gross (88 net) steamflood injection wells. Please see “—Our Reserves and Production Information—Determination of Identified
Drilling Locations” for more information regarding the process and criteria through which we identified our drilling locations.
Our Competitive Strengths
We believe that the following competitive strengths will allow us to successfully execute our business strategy.
•
Stable, low-decline, predictable and oil-weighted conventional asset base. The majority of our interests are
in properties that have produced 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 cost structure and low-risk developmental drilling opportunities with
4
predictable production profiles. The nature of our assets provides us with a high degree of capital flexibility
through commodity cycles.
•
Substantial inventory of low-cost, low-risk and high-return development opportunities. We expect our
locations to generate highly attractive rates of return. For example, our PUD reserves in California are projected
to average single-well rates of return of approximately 39% based on the assumptions used in preparing our
SEC reserves report as of December 31, 2018.
• Brent-influenced pricing advantage. California oil prices are Brent-influenced as California refiners import
more than 50% of the state’s demand from foreign 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.
•
•
Substantial capital flexibility derived from a high degree of operational control and stable cost environment.
We operate over 95% of our producing wells and expect to operate a similar percentage of our identified gross
drilling locations. In addition, approximately 75% of our acreage is held by production, including 99% of our
acreage in California. Our high degree of operational control over our properties, together with the large portion
of our acreage that is held by production, gives us flexibility in executing our development program, including
the timing, amount and allocation of our capital expenditures, technological enhancements and marketing of
production. We expect our operations to continue to generate positive Levered Free Cash Flow at current
commodity prices allowing us to return capital to stockholders and fund maintenance operations and growth
among other things. 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 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.
Simple capital structure and conservative balance sheet leverage with ample liquidity and minimal
contractual obligations. In connection with our 2018 IPO, we converted all of our Series A Preferred Stock
(the “Series A Preferred Stock”) into common stock (the “Series A Preferred Stock Conversion”). Earlier in
2018, we closed a private offering 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. As of December 31, 2018, we had $462
million of available liquidity, defined as cash on hand plus availability under the $1.5 billion reserves-based
lending facility we entered into on July 31, 2017 (as amended, the “RBL Facility”). In addition, we have
minimal long-term service or fixed-volume delivery commitments. This liquidity and flexibility permit us to
capitalize on opportunities that may arise to grow and increase stockholder value.
• Ability and intention to return capital to stockholders consistently through the commodity price cycle. We
generated positive Levered Free Cash Flow in 2018 when Brent oil prices ranged from a mid-year high of
$86.29 to a low of $50.47 toward the end of the year. In California, we believe our operations break even when
Brent crude prices are approximately $47 per barrel, meaning we expect to have positive Levered Free Cash
Flow at that level. We have paid a dividend on our common stock since our first quarter as a public company
and plan to continue paying a meaningful quarterly dividend.
• Experienced, principled and disciplined management team. Our management team has significant experience
operating and managing oil and gas businesses across numerous domestic and international basins, as well as
reservoir and recovery types. We use our deep technical, operational and strategic management experience to
optimize the value of our assets and the Company. We are focused on the principles of growing Levered Free
Cash Flows as well as the value of our production and reserves. In doing so, we take a disciplined approach
to development and operating cost management, field development efficiencies and the application of proven
technologies and processes new to our properties in order to generate a sustained cost advantage.
5
Our Business Strategy
The principal elements of our business strategy include the following:
• Grow production and reserves in a capital efficient manner while producing positive internally generated
Levered Free Cash Flow. We intend to allocate capital in a disciplined manner to projects that will produce
predictable and attractive rates of return. We plan to direct capital to our oil-rich and low-risk development
opportunities while focusing on driving cost efficiencies across our asset base with the primary objective of
internally funding our capital budget and growth plan. We may also use our capital flexibility to pursue value-
enhancing, bolt-on acquisitions to opportunistically improve our positions in existing basins.
• Maximize ultimate hydrocarbon recovery from our assets by optimizing drilling, completion and production
techniques and investigating deeper reservoirs and areas beyond our known productive areas. While we
continue to utilize proven techniques and technologies, we will also continuously seek efficiencies in our
drilling, completion and production techniques in order to optimize ultimate resource recoveries, rates of return
and cash flows. We will explore innovative EOR techniques to unlock additional value and have allocated
capital towards next generation technologies. For example, in our South Belridge Hill non-thermal and
Midway-Sunset thermal Diatomite properties, we employ both hydraulic stimulation and advanced thermal
techniques, and in our Piceance properties, we use advanced proppantless slick water well stimulation
techniques. In addition, we intend to take advantage of underdevelopment in basins where we operate by
expanding our geologic investigation of reservoirs on our acreage and adjacent acreage below existing
producing reservoirs. Through these studies, we will seek to expand our development beyond our known
productive areas in order to add probable and possible reserves to our inventory at attractive all-in costs.
• Proactively and collaboratively engage in matters related to regulation, safety, environmental and
community relations. We are committed to proactive engagement with regulatory agencies 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 work closely with regulators and legislators throughout the rule making
process to minimize adverse impacts that new legislation and regulations might have on our ability to maximize
our resources and to facilitate our permitting process. We have found constructive dialogue with regulatory
agencies can help avert compliance and permitting issues. By working with the legislators and regulators on
the front end of the regulatory process, our goal is to minimize the impact of new regulations and legislation
and to mitigate the risk of permitting delays.
• Return excess free cash flow to stockholders. Our objective is to implement a disciplined and returns-focused
approach to capital allocation in order to generate excess free cash flow. We intend to return portions of that
excess free cash flow to stockholders on a quarterly basis. If commodity prices increase for a sustained period
of time, we would consider repaying debt obligations or returning additional capital to stockholders. For a
discussion of our dividend policy, please see “Item 5. Market for the Registrant’s Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities—Dividend Policy.”
• Maintain balance sheet strength and flexibility through commodity price cycles. We intend to fund our
capital program while producing positive internally generated Levered Free Cash Flow. Over time, we expect
to de-lever through organic growth and with excess Levered Free Cash Flow. Our objective is to achieve and
maintain a long-term, through-cycle leverage ratio (as defined in our RBL Facility) between 1.5x and 2.0x.
• Enhance future cash flow stability and visibility through an active and continuous hedging program. Our
hedging strategy is designed to insulate our capital program from price fluctuations by securing price
realizations and cash flows for production. We also seek to protect our operating expenses through fixed-price
gas purchase agreements and other hedging contracts. We have protected a portion of our anticipated crude
oil production realizations into 2020. We will review our hedging program continuously as conditions change.
6
Our Capital Budget
Immediately following Berry LLC’s emergence from bankruptcy and separation from Linn Energy, LLC (“Linn
Energy”) and LinnCo, LLC (“LinnCo” and, together with Linn Energy, the “Linn Entities”) in 2017, we increased our
pace of development and have continued to do so throughout 2018 and into 2019. For the years ended December 31,
2018 and 2017, our capital expenditures were approximately $148 million and $73 million, respectively, on an accrual
basis excluding acquisitions. Our 2019 anticipated capital expenditure budget is approximately $195 to $225 million,
which represents an increase of approximately 42% over 2018 capital expenditures. Capital expenditures increased
103% from 2017 to 2018. Based on current commodity prices and a drilling success rate comparable to our historical
performance, we believe we will be able to fund our 2019 capital development programs while producing positive
Levered Free Cash Flow. Our 2019 capital program is focused on growing our oil production in California. We anticipate
oil production will be approximately 86% of total production in 2019, compared to 82% in 2018. This change in product
mix was also a factor in the divestiture of our non-core East Texas gas properties in late 2018. During 2019, we expect
to:
•
•
employ four drilling rigs in California throughout the year; and
drill approximately 370 to 420 gross development wells, all of which we expect will be in California for oil
production.
The amount and timing of these capital expenditures is within our control and subject to our management’s
discretion. We retain the flexibility to defer a portion of these 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 availability of necessary equipment, infrastructure and capital, the receipt and timing of required
regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by
other interest owners, as well as general market conditions. Any postponement or elimination of our development
drilling program could result in a reduction of proved reserve volumes and materially affect our business, financial
condition and results of operations. For additional information about the 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—Factors Affecting the Comparability of Our Financial
Condition and Results of Operations—Capital Expenditures and Capital Budget”.
Our Areas of Operation
Our predominant operating area is in California, and we also have operations in the Rockies. On November 30,
2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
California
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 the three fields —Midway-Sunset and South Belridge. California is and has been one of the most productive oil
regions in the world, and is currently ranked as the third largest state in reserves and sixth largest state in production
in the U.S.
In California, we actively operate and develop properties located in the Midway-Sunset, South Belridge, McKittrick
and Poso Creek fields in the San Joaquin basin in Kern County as well as the Placerita Field in the Ventura basin in
Los Angeles County. We currently hold 8,333 net acres in these basins with a 99% average working interest. The
producing areas in our Southeast San Joaquin operations include: (i) our South Midway-Sunset, properties, which are
long-life, low-decline, strong-margin thermal oil properties with additional development opportunities; (ii) our Poso
Creek property, which is an active mature shallow, heavy oil asset that we continue to develop across the property; and
(iii) our Placerita property, which is a mature shallow, heavy oil asset with additional recompletion opportunities. The
producing areas in our Northwest San Joaquin operations include: (i) our McKittrick Field property, which is a newer
steamflood development with potential for infill and extension drilling; (ii) our South Belridge Field Hill property,
7
which is characterized by two known reservoirs with low geological risk containing a significant number of drilling
prospects, including downspacing opportunities, as well as additional steamflood opportunities; (iii) our thermal North
Midway-Sunset Diatomite properties, where we utilize innovative EOR techniques to unlock significant value and
maximize recoveries; and (iv) our North Midway-Sunset sandstone properties, where we use cyclic and continuous
steam injection to develop these known reservoirs. Our California proved reserves represented approximately 74% of
our total proved reserves at December 31, 2018 and accounted for 19.7 MBoe/d or 73% of our average daily production
for the year ended December 31, 2018 and 21.7 MBoe/d or 78% of our average daily production for the three months
ended December 31, 2018.
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 assist in this operation, we own and operate five natural
gas cogeneration plants that produce steam. These plants supply approximately 24% of our steam needs and
approximately 63% of our field electricity needs in California at a discount to electricity market prices. To further 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 and operate 79 conventional steam
generators.
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 80% of our California oil production is sold through pipeline
connections, and we have contracts in place with third-party purchasers of our crude.
According to the Division of Oil, Gas, and Geothermal Resources of the California Department of Conservation
(“DOGGR”), approximately 76% of California’s daily oil production of 477 MBbl/d for 2017 was produced in the San
Joaquin basin. 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. We began operations in California 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. We believe there are extensive existing field redevelopment
opportunities in our areas of operation within the San Joaquin basin. We believe that our California focus and strong
balance sheet will allow us to take advantage of these opportunities.
Rockies
Uinta basin
Our Uinta basin operations in the Brundage Canyon, Ashley Forest and Lake Canyon areas 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 13% of our total proved
reserves at December 31, 2018 and accounted for 4.9 MBoe/d or 18% of our average daily production for the year
ended December 31, 2018.
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
8
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 93 MBbl/d in 2017. Approximately 82% of Utah’s production in 2017 came from the Uinta basin
in Duchesne and Uintah counties.
Piceance basin
Our primary operating areas in the Piceance basin are Garden Gulch and North Parachute 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 13% of our total
proved reserves at December 31, 2018 and accounted for 1.7 MBoe/d or 6% of our average daily production for the
year ended December 31, 2018.
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
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.
9
Methods of Recovery
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 a high working interest and operating control in our properties.
Our California operations are primarily focused on the Hill Diatomite, thermal Diatomite and thermal Sandstones
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
Tier 1
Additional
Total
Gross Drilling Locations(1)
California
California
California
Hill Diatomite
(non-thermal)
Thermal
Diatomite
Thermal
Sandstones
Utah
Uinta
Vertical
Vertical /
Horizontal
Vertical /
Horizontal
Colorado
Piceance
Vertical
Total
Vertical
Low intensity pin point
Pressure depletion
augmented with water
injection
Cyclic steam injection
Short interval
perforations
Perforation/Slotted
liner/gravel pack
Continuous and cyclic
steam injection
Low intensity hydraulic
stimulation
Pressure depletion
Proppantless slick
water stimulation
Pressure depletion
272
787
1,811
444
—
585
979
489
793
870
3,314
3,716
857
1,766
2,300
1,237
870
7,030
__________
(1) We had 1,071 gross (1,058 net) locations associated with PUDs as of December 31, 2018 including 88 gross (88 net) steamflood injection
wells. Of those 1,071 gross PUD locations, 977 are associated with projects in California, 55 are associated with the Piceance basin, and 39
are associated with the Uinta basin. Please see “—Our Reserves and Production Information—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,
2018, we drilled 121 gross (121 net) wells that were associated with PUDs at December 31, 2017, including 27 gross (27 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 steam injection 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 $350,000 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
10
referred to as combined heat and power plants, use hot turbine exhaust to produce steam while generating electrical
power. This combined process is more efficient than producing power or steam separately. For more information please
see “—Electricity.” and “Item 1A. Risk Factors—Risks Related to Our Business and Industry—We are dependent on
our cogeneration facilities to produce steam for our operations. Viable 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 79 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 147,000 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 325,000 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
2018 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 and electricity.
Crude Oil. Approximately 80% 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
more than 50% of the state’s demand from foreign sources. This dynamic has led to periods 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, 2018, 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.
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, 2018, 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
entered into natural gas processing contracts whereby the residual natural gas is sold under short-term contracts but
11
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.
Electricity
Generation. Our cogeneration facilities generate both electricity and steam for our properties and electricity for
off-lease sales. The total 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 costs in our heavy oil operations and to secure operating control of our steam generation.
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 2019 and 2022.
Electricity and steam produced from our Pan Fee and 21Z cogeneration facilities are used solely for field operations
with one facility being run at a time and the other acting as 100% backup for the power produced on the lease.
For the year ended December 31, 2018, we sold approximately 1,800 megawatt-hours (“MWhs”) per day and
consumed approximately 300 MWhs per day of electricity generated by our five cogeneration facilities. In addition,
the five cogeneration facilities produced an average of approximately 35,000 barrels of steam per day.
Principal Customers
For the year ended December 31, 2018, sales to Andeavor, Phillips 66 and Kern Oil & Refining accounted for
approximately 35%, 28%, and 13% respectively, of our sales. At December 31, 2018, trade accounts receivable from
three customers represented approximately 26%, 22% and 10% 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”.
Our Reserves and Production Information
Reserve Data
The following table summarizes our estimated proved reserves and related PV-10 as of December 31, 2018. 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.
12
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, 2018(1)
California
(San Joaquin and Ventura basins)
Rockies
(Uinta and Piceance basins)
Total
66
—
—
66
40
—
—
40
106
—
—
106
7
76
1
21
2
85
—
16
9
161
1
37
73
76
1
87
42
85
—
56
115
161
1
143
PV-10 ($MM)(4)
$
2,027
$
125
$
2,152
__________
(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 $71.54 per Bbl ICE (Brent) for oil
and NGLs and $3.10 per MMBtu NYMEX (Henry Hub) for natural gas at December 31, 2018. The volume-weighted average prices over the
lives of the properties were $66.49 per Bbl of oil and condensate, $32.87 per Bbl of NGLs and $2.806 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 9% of proved developed oil reserves, 1% of proved developed NGL reserves, 0% of proved developed natural gas reserves
and 8% 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, 2018, the average
prices of ICE (Brent) oil and NYMEX (Henry Hub) natural gas were $71.53 per Bbl and $3.09 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. Calculation of PV-10 does not give effect to derivatives transactions. 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.
13
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, 2018:
California PV-10
Rockies 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, 2018
(in millions)
$
$
2,027
125
2,152
(390)
1,762
The total changes to our proved reserves from December 31, 2017 to December 31, 2018 were as follows:
California (San Joaquin
and Ventura basins)
Rockies (Uinta and
Piceance basins)
East Texas
basin(1)
Total
(in MMBoe)
Beginning balance as of December 31, 2017
Extensions and discoveries
Revisions of previous estimates
Purchases of minerals in place
Sales of minerals in place
Current year production
Ending balance as of December 31, 2018
93
19
—
1
—
(7)
106
46
3
(10)
—
—
(3)
37
2
—
—
—
(2)
—
—
141
22
(10)
1
(2)
(10)
143
__________
Note: 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, 2018, the average
prices of ICE (Brent) oil and NYMEX (Henry Hub) natural gas were $71.53 per Bbl and $3.09 per Mcf, respectively, resulting in an oil-to-
gas ratio of over 4 to 1 on an energy equivalent basis.
(1) On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
14
Extensions and Discoveries. During 2018 we added 22 MMBoe of proved reserves from extensions and discoveries
principally in our California properties, most of which was thermal Diatomite, as well as in Utah.
Revisions of Previous Estimates.
Revisions related to price - Product price changes affect the proved reserves we record. For example, higher
prices generally increase the economically recoverable reserves in all of our operations because the extra margin extends
their expected lives and renders more projects economic. Conversely, when prices drop, we experience the opposite
effects. In 2018, our total net positive price revision was 8 MMBoe, which was primarily the result of higher prices in
the commodity price environment in 2018 compared to 2017.
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 2018, our net negative performance-related revision of 18 MMBoe resulted from
negative revisions of 9 MMBoe to remove proved undeveloped reserves due to a downward adjustment of our committed
capital in the Piceance basin and technical revisions of 9 MMBoe due to a shift in the development strategy as laid out
in our 5-year capital plan, predominantly in the 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 Additions
The total changes to our proved undeveloped reserves from December 31, 2017 to December 31, 2018 were as
follows:
California (San Joaquin
and Ventura basins)
Rockies (Uinta and
Piceance basins)
East Texas
basin
Total
(in MMBoe)
Beginning balance as of December 31, 2017
Extensions and discoveries
Revisions of previous estimates
Reclassifications to proved developed
Purchases of minerals in place
Ending balance as of December 31, 2018
32
17
(1)
(9)
1
40
23
2
(10)
—
—
15
—
—
—
—
—
—
55
19
(11)
(9)
1
55
__________
Note: 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, 2018, the average
prices of ICE (Brent) oil and NYMEX (Henry Hub) natural gas were $71.53 per Bbl and $3.09 per Mcf, respectively, resulting in an oil-to-
gas ratio of approximately 4 to 1 on an energy equivalent basis.
Extensions and Discoveries. During 2018 we added 19 MMBoe of proved undeveloped reserves from extensions
and discoveries due to drilling unproven locations in Midway Sunset and Uinta. We also added proven undeveloped
reserves for our thermal Diatomite, Buena Fe and Uinta locations.
Revisions of previous estimates.
Revisions related to price - In 2018, our net positive price revision on proven undeveloped reserves was
1 MMBoe, which was primarily the result of higher prices due to the current commodity price environment.
15
Revisions related to performance - In 2018, our net negative performance-related revision on proven
undeveloped reserves was 12 MMBoe, which resulted primarily from the removal of 9 MMBoe in proved undeveloped
reserves due to a downward adjustment of our committed capital in the Piceance basin and technical revisions of 2
MMBoe due to a shift in the development strategy as laid out in our 5-year capital plan, predominantly in the thermal
Diatomite area.
Reclassifications to proved developed. Through the 2018 drilling program, we transferred 9 MMBoe of proved
undeveloped reserves to the proved developed category in California. As a result, we converted 16% of our beginning-
of-the year inventory of proved undeveloped reserves, spending approximately $36 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 $65 to $75 per barrel and average Henry Hub gas prices of at least $3.00 per mcf, we expect to have
sufficient future capital to develop our proved undeveloped reserves at December 31, 2018 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 realized 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, who has a Masters in Geology from the University of South Carolina and a Bachelors in
Geology from Carleton College, and more than 31 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 33 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.
16
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.”
Determination of Identified Drilling Locations
Proven Drilling Locations
Based on our reserves report as of December 31, 2018, we have approximately 1,071 gross (1,058 net) drilling
locations attributable to our proved undeveloped reserves. 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 5,959 gross (5,604 net) drilling locations that are not associated
with our proved undeveloped reserves but 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
17
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.”
The table below sets forth our PUD locations and total identified drilling locations as of December 31, 2018.
California
Rockies
Total Identified Drilling Locations
PUD Locations
(Gross)
Total Identified Drilling Locations
(Gross)(1)
Oil and Natural
Gas Wells
Injection
Wells
Oil and Natural
Gas Wells
Injection
Wells
889
94
983
88
—
88
4,141
2,107
6,248
782
—
782
__________
(1)
Includes 3,314 Tier 1 gross drilling locations company-wide that we anticipate drilling over the next 5 to 10 years and 3,716 additional gross
drilling locations that are currently under review.
Production and Operating Data
The following table sets forth information regarding production, realized and benchmark prices, and production
costs for the year ended December 31, 2018, the ten months ended December 31, 2017, the two months ended February
28, 2017, and the year ended December 31, 2016.
18
Production Data(3):
Oil (MBbl/d)
Natural gas (MMcf/d)
NGLs (MBbl/d)
Average daily combined production (MBoe/d)(1)
Oil (MBbl)
Natural gas (MMcf)
NGLs (MBbl)
Total combined production (MBoe)(1)
Weighted-average realized prices:
Oil with hedges (per Bbl)
Oil without hedges (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
Average Benchmark prices:
Oil (per Bbl) – Brent
Oil (per Bbl) – WTI
Natural gas (per MMBtu) – Henry Hub
Total operating expenses (per Boe)(2)
Taxes, other than income taxes (per Boe)
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31,
2018
Ten Months
Ended
December 31,
2017
Two Months
Ended
February 28,
2017
Year Ended
December 31,
2016
22.0
26.3
0.6
27.0
8,045
9,589
211
9,855
59.67
64.76
2.74
26.74
71.53
64.76
3.09
18.33
3.36
$
$
$
$
$
$
$
$
$
20.6
49.4
2.0
30.9
6,318
15,119
605
9,443
48.53
48.05
2.70
22.23
54.65
50.53
3.00
17.09
3.62
$
$
$
$
$
$
$
$
$
19.5
71.7
5.2
36.7
1,153
4,232
304
2,162
47.40
46.94
3.42
18.20
55.72
53.04
3.66
15.72
2.41
$
$
$
$
$
$
$
$
$
23.1
78.1
3.6
39.7
8,463
28,577
1,307
14,533
36.88
35.83
2.31
17.67
45.00
43.32
2.46
15.13
1.73
$
$
$
$
$
$
$
$
$
__________
(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, 2018, the average
prices of ICE (Brent) oil and NYMEX (Henry Hub) natural gas were $71.53 per Bbl and $3.09 per Mcf, respectively, resulting in an oil-to-
gas ratio of over 4 to 1 on an energy equivalent basis.
(2) 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. Taxes other than income taxes are excluded from operating expenses.
(3) Production represents volumes sold during the period.
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 South Midway Field
Total production(2):
Oil (MBbls)
Natural gas (Bcf)
NGLs (MBbls)
Total (MBoe)(3)
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31, 2018
Ten Months Ended
December 31, 2017
Two Months Ended
February 28, 2017
Year Ended
December 31, 2016
2,341
—
—
2,341
1,963
—
—
1,963
369
—
—
369
2,477
—
—
2,477
19
SJV Belridge Hill(4)
Total production(2):
Oil (MBbls)
Natural gas (Bcf)
NGLs (MBbls)
Total (MBoe)(3)
Piceance
Total production(2):
Oil (MBbls)
Natural gas (Bcf)
NGLs (MBbls)
Total (MBoe)(3)
Hugoton basin Field(1)
Total production(2):
Oil (MBbls)
Natural gas (Bcf)
NGLs (MBbls)
Total (MBoe)(3)
__________
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31, 2018
Ten Months Ended
December 31, 2017
Two Months Ended
February 28, 2017
Year Ended
December 31, 2016
*
*
*
*
609
—
—
609
35
—
—
35
*
*
*
*
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31, 2018
Ten Months Ended
December 31, 2017
Two Months Ended
February 28, 2017
Year Ended
December 31, 2016
*
*
*
*
14
3.6
—
610
2
0.8
—
138
*
*
*
*
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31, 2018
Ten Months Ended
December 31, 2017
Two Months Ended
February 28, 2017
Year Ended
December 31, 2016
*
*
*
*
*
*
*
*
*
*
*
*
—
14.6
1,020
3,457
Represented less than 15% of our total proved reserves for the periods indicated.
*
(1) On July 31, 2017, we sold our approximately 78% non-operated working interest in the Hugoton natural gas field. No production data is
available for periods following the disposition.
(2) Production represents volumes sold during the period.
(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, 2018, the average
prices of ICE (Brent) oil and NYMEX (Henry Hub) natural gas were $71.53 per Bbl and $3.09 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.
(4)
Productive Wells
As of December 31, 2018, we had a total of 4,029 gross (3,743 net) productive wells (including 540 gross and net
steamflood and waterflood injection wells), approximately 96% 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.
20
The following table sets forth our productive oil and natural gas wells (both producing and capable of producing)
as of December 31, 2018.
Oil
Gross(1)
Net(2)
Gas
Gross(1)
Net(2)
California
(San Joaquin and Ventura basins)
Rockies
(Uinta and Piceance basins)
Total
2,921
2,775
—
—
935
844
173
124
3,856
3,619
173
124
__________
(1) The total number of wells in which interests are owned. Includes 540 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, 2018. Approximately 75% of our leased acreage was held by production at
December 31, 2018.
Developed(1)
Gross(2)
Net(3)
Undeveloped(4)
Gross(2)
Net(3)
California
(San Joaquin and Ventura basins)
Rockies
(Uinta and Piceance basins)
Total
11,148
8,212
120
120
95,103
72,944
39,366
27,182
106,251
81,156
39,486
27,302
__________
(1) Acres spaced or assigned to productive wells.
(2) Total acres in which we hold an interest.
(3) Sum of fractional interests owned based on working interests or interests under arrangements similar to production sharing contracts.
(4) Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural
gas, regardless of whether the acreage contains proved reserves.
Participation in Wells Being Drilled
The following table sets forth our participation in wells being drilled as of December 31, 2018.
California
(San Joaquin and Ventura basins)
Rockies
(Uinta and Piceance basins)
Total
Development wells
Gross
Net
Exploratory wells
Gross
Net
—
—
—
—
3
3
—
—
3
3
—
—
21
At December 31, 2018, 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)
Rockies
(Uinta and Piceance basins)
Total
2018
Oil(2)
Natural Gas
Dry
2017
Oil(1)
Natural Gas
Dry
2016
Oil(1)
Natural Gas
Dry
224
—
—
124
—
—
11
—
—
8
—
—
—
—
—
—
—
—
232
—
—
124
—
—
11
—
—
__________
(1)
(2)
Includes injector wells.
Includes 40 drilled uncompleted wells in California, 12 wells that had not yet been connected to gathering systems in California and six wells
that had not yet been connected to gathering systems in the Rockies.
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, 2018, the volumes
contracted to be delivered were approximately 9,460 MMBtu/d of gas beginning in 2019 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.
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.
22
Competition
The oil and natural gas industry is highly competitive. We encounter strong competition from other independent
operators and master limited partnerships 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.”
Seasonality
Seasonal weather conditions can impact a portion of 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 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 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 portion of the gas we expect to consume.
Regulation of Health, Safety and Environmental Matters
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. Our operations are subject to the same
environmental laws and regulations as other companies in the oil and natural gas industry. These laws and regulations
may:
• Establish air, soil and water quality standards for a given region, such as the San Joaquin Valley, and attainment
plans to meet those regional standards, which may significantly restrict development, economic activity and
transportation in the region;
•
•
•
•
•
require the acquisition of various permits before drilling, workover production, underground fluid injection,
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
and control systems—to prevent or reduce the release or discharge of regulated materials into the air, land,
surface water or groundwater;
restrict the types, quantities and concentration of various regulated materials, including oil, natural gas,
produced water or wastes, that can be released into the environment in connection with drilling and production
activities, and impose energy efficiency or renewable energy standards on us or users of our products;
limit or prohibit drilling activities on lands located within coastal, wilderness, wetlands, groundwater recharge
or endangered species inhabited areas, and other protected areas, or otherwise restrict or prohibit activities
23
•
•
•
that could impact the environment, including water resources, and require the dedication of surface acreage
for habitat conservation;
establish waste management standards or require remedial measures to limit pollution from former operations,
such as pit closure, reclamation and plugging and abandonment of wells or decommissioning of facilities;
impose substantial liabilities for pollution resulting from operations or for preexisting environmental conditions
on our current or former properties and operations and other locations where such materials generated by us
or our predecessors were released or discharged;
require comprehensive environmental analyses, recordkeeping and reports with respect to operations affecting
federal, state, and private lands or leases, including preparation of a Resource Management Plan, an
Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting
federal lands or leases.
For example, in 2014, DOGGR began a detailed review of the multi-decade practice of permitting underground
injection wells under the Safe Drinking Water Act (the “SDWA”). The purpose of the review was to ensure that
wastewater is not injected into formations that could be a future source of drinking water supply. In 2015, the state set
deadlines to obtain confirmation of aquifer exemptions under the SDWA in certain formations in certain fields from
the United States Environmental Protection Agency (the “EPA”). Several industry groups challenged DOGGR’s
implementation of its aquifer exemption regulations, and, in March 2017, the Kern County Superior Court issued an
injunction barring the blanket enforcements of DOGGR’s aquifer exemption regulations. The court held that DOGGR
must show that an underground injection well’s operations have caused an actual harm and go through a hearing process
before the agency can issue fines or shut down operations.
In addition, DOGGR has proposed new underground injection regulations in July 2018. The proposed rules would
impose additional requirements related to injection approvals, project data requirements, mechanical integrity testing
of injection wells, monitoring requirements, prevention of surface expressions, incident response, and monitoring
seismic activity. To date, restrictions on underground injection have not affected our oil and natural gas production in
any material way. Separately, the state began a review in 2015 of permitted surface discharge of produced water, which
led to additional permitting requirements in 2017 for surface discharge of produced water. Government authorities may
ultimately restrict injection of produced water or other fluids in additional formations or certain wells, restrict the
surface discharge or use of produced water or take other administrative actions. The foregoing reviews could also give
rise to litigation with government authorities and third parties.
These laws, rules and regulations may also restrict the production rate of oil, natural gas and NGLs below the rate
that would otherwise be possible. 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 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;
24
• 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. 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.
Climate Change
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other greenhouse gases
(“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according
to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the
EPA began adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA.
The EPA has adopted three sets of rules regulating GHG emissions under the CAA, one that requires a reduction in
emissions of GHGs from motor vehicles, a second that regulates emissions of GHGs from certain large stationary
sources under the CAA’s Prevention of Significant Deterioration and Title V permitting programs, and a third that
regulates GHG emissions from fossil fuel-burning power plants, although future implementation of this rule as it applies
to existing power plants is uncertain at this time due to ongoing litigation and reconsideration of the rule by the current
administration.
The EPA and the California Air Resources Board (“CARB”) have also expanded direct regulation of methane
emissions. In June 2016, the EPA finalized rules that establish new controls for emissions of methane (a GHG considered
25
more potent than carbon dioxide) from new, modified or reconstructed sources in the oil and natural gas source category,
including production, processing, transmission and storage activities. The EPA has also adopted rules requiring the
monitoring and reporting of GHG emissions from specified sources in the United States, including, among other things,
certain onshore oil and natural gas production facilities, on an annual basis. However, in March 2018 EPA finalized
several amendments to the 2016 rule, including rolling back a requirement to repair leaking components during
unplanned or emergency shutdowns. Also, in September 2018, the EPA issued proposed revisions to the 2016 methane
rules, which would reduce the monitoring obligations for wells and compressor stations and exempting previously
covered equipment at certain locations. Separately, the U.S. Bureau of Land Management (the “BLM”) previously
finalized similar limitations on methane emissions from venting and flaring and leaking equipment from oil and natural
gas activities on public lands, but issued a final rule repealing those standards in September 2018. Several states and
environmental groups have announced their intent to file judicial challenges against any attempt to repeal or revise the
EPA and BLM methane rules. As a result, future implementation of both the EPA and BLM methane rules is uncertain
at this time.
Additionally, CARB has promulgated regulations regarding monitoring, leak detection, repair and reporting of
methane emissions from both existing and new oil and gas production, pipeline gathering and boosting station assets,
and natural gas processing plant operations beginning in 2018 and additional controls such as vapor recovery to capture
methane emissions in subsequent years. Colorado has also imposed similar regulations governing methane emissions
that could impact our operations in the Piceance basin.
In addition, on September 10, 2018, the Governor of California signed into law a bill that would commit California,
the fifth largest economy in the world, to the use of 100% zero-carbon electricity by 2045. The same day, the Governor
also signed an executive order committing California to total economy-wide carbon neutrality by 2045, including in
transportation, building heating and cooling, and industry. The law does not directly affect the oil and gas industry, and
it remains unclear what actions state agencies may take in response to executive order. In any event, these recent actions
could result in decreased future demand for our products to meet energy needs and in turn have an adverse effect on
our business and results of operations. Legislation and regulation to address climate change could also increase the
cost of consuming, and thereby reduce demand for, oil, natural gas and other products produced by us, and potentially
lower the value of our reserves. Recently, activists concerned about the potential effects of climate change have directed
their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions,
funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately,
this could make it more difficult to secure funding for exploration and production activities. In addition, several
municipalities and counties in various states have filed lawsuits against fossil fuel energy companies to address concerns
such as coastal erosion and other alleged climate-related damage.
In addition, in 2015, the United States participated in the United Nations Conference on Climate Change, which
led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a
progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every
five years beginning in 2020. However, in 2017 the Trump administration indicated that the United States would be
withdrawing from participation in the Paris Agreement. There has not been significant activity in the form of adopted
legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation,
almost one half of the states, including California, have begun taking actions to control and/or reduce emissions of
GHGs, including by means of cap-and-trade programs. These programs typically require major sources of GHG
emissions to acquire and surrender emission allowances in return for emitting those GHGs. See “—California GHG
Regulations” below for additional details on current GHG regulations in the State of California. Although it is not
possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would
impact our business, any such future laws and regulations imposing reporting obligations on or limiting emissions of
GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with
our operations. Substantial limitations on GHG emissions could also adversely affect demand for the oil and natural
gas we produce.
Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce
climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts,
floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our
26
operations. 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 business
is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements
governing our operations, including 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.”
California GHG Regulations
In October 2006, California adopted the Global Warming Solutions Act of 2006, which established a statewide
“cap-and-trade” program with an enforceable compliance obligation beginning with 2013 GHG emissions and ending
in 2020. The state has also established a low carbon fuel standard that encourages the use of fuels with lower carbon
intensities instead of traditional fossil fuels. In July 2017, California extended its cap-and-trade program through 2030.
The program is designed to reduce the state’s GHG emissions to 1990 levels by 2020 and to reduce the state’s GHG
emissions to at least 40% below 1990 levels by 2030. The California cap-and-trade program sets maximum limits or
caps on total emissions of GHGs from industrial sectors of which we are a part, as our California operations emit GHGs.
The cap will decline annually through 2030. We are required to remit compliance instruments for each metric ton of
GHG that we emit, in the form of allowances (each the equivalent of one ton of carbon dioxide) or qualifying offset
credits. The availability of allowances will decline over time in accordance with the declining cap, and the cost to
acquire such allowances may increase over time. Under the cap-and-trade program, we will be granted a certain number
of California carbon allowances (“CCA”) and we will need to purchase CCAs and/or offset credits to cover the remaining
amount of our emissions. Compliance with the California cap-and-trade program laws and regulations could
significantly increase our capital, compliance and operating costs and could also reduce demand for the oil and natural
gas we produce. The cost to acquire compliance instruments will depend on the market price for such instruments at
the time they are purchased, the distribution of cost-free allowances among various industry sectors by the CARB and
our ability to limit our GHG emissions and implement cost-containment measures.
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. Further, in March 2015, the BLM adopted a rule
requiring, among other things, public disclosure to the BLM of chemicals used in hydraulic stimulation operations after
activity has been completed and would strengthen standards for well-bore integrity and management of fluids that
return to the surface during and after stimulations on federal and Indian lands. On December 29, 2017 the BLM formally
rescinded the 2015 rule governing hydraulic stimulation operations on public and tribal lands. The 2015 rule included
a comprehensive set of well-bore integrity requirements, standards for the interim storage of recovered waste fluids,
mandatory notifications and waiting periods for key parts of the stimulation process, and chemical disclosure
requirements. On January 24, 2018, California and a coalition of environmental and tribal groups each filed lawsuits
in the Northern District of California to challenge BLM’s rescission of the 2015 rule. 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
operations. These permitting requirements and restrictions could result in delays in operations at well sites and also
increased costs to make wells productive.
27
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, certain
states in which we operate have adopted disclosure regulations requiring varying degrees of disclosure of the constituents
in hydraulic stimulation fluids. In addition, 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,
most recently, new regulations in California requiring a permit to conduct well stimulation), bans on hydraulic
stimulation in certain locations, and/or 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.
We use water in our hydraulic stimulation operations. 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. 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
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. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision
of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the
regulations is not necessary. Were the EPA to propose a rulemaking, the consent decree requires that EPA take final
action by no later than July 15, 2021. 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.
28
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. 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 December 2017, the Department of
Interior issued a new opinion revoking its prior enforcement policy and concluded that an incidental take is not a
violation of the Migratory Bird Treaty Act. Various environmental groups have filed lawsuits challenging this opinion.
The ESA has not previously had a significant impact on our operations. Nevertheless, the designation of previously
unprotected species 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.
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. In November 2017, the EPA published a list of areas that are in
compliance with the new ozone standard, and separately, in December 2017, issued responses to state recommendations
for designating non-attainment areas. In April 2018, the EPA issued final attainment status designations for most of the
remaining portions of the United States.
State 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
29
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.
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.
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.
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”). Currently, the Clean Water Rule and the
scope of federal jurisdiction under the CWA are the subject of several legal challenges, and implementation of the rule
has been blocked in some states. The EPA is also considering revising the scope of the 2015 rule, but any changes to
the rule are likely to face judicial challenges from certain states and environmental groups. At this time we cannot
predict how the original 2015 rule will be revised or whether it will be fully implemented as originally finalized. 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.
30
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
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
31
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.
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, 2018, 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 2019 or that will otherwise have a material impact on our financial position,
results of operations or cash flows.
Employees
As of December 31, 2018, we had 322 employees.
Emergence from Chapter 11 Bankruptcy
On May 11, 2016, our predecessor company 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. Through the Chapter 11 Proceedings, the Company
significantly improved its financial position from that of Berry LLC while it was owned by the Linn Entities. A final
decree closing the Chapter 11 Proceedings were 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.
32
Corporate Information
We were incorporated in Delaware in February 2017. We have executive offices located at 5201 Truxtun Ave.,
Bakersfield, California 93309 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.berrypetroleum.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.
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, our plans to return capital and other obligations and financial commitments.
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 heavily influence our revenue, profitability,
access to capital, 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 during 2018 from $62.59
per Bbl at the beginning, to a high of $86.29 per Bbl and back to $50.47 per Bbl at the end of the year. The Henry Hub
spot price for natural gas also fluctuated during 2018 between $2.55 per MMBtu and $3.23 per MMBtu and are currently
higher in markets where we purchase gas. The prices we receive for our production, and the levels of our production,
depend on numerous factors beyond our control, which include the following:
• worldwide and regional economic conditions impacting the global supply and demand for, and transportation
costs of, oil and natural gas;
the price and quantity of foreign imports of oil;
prevailing prices on local price indexes in the areas in which we operate;
political and economic conditions in, or affecting, other producing regions or countries, including the Middle
East, Africa, South America and Russia;
the level of global exploration, development and production, and resulting inventories;
actions of the Organization of the Petroleum Exporting Countries (“OPEC”), its members and other state-
controlled oil companies relating to oil price and production controls;
actions of other significant producers;
the proximity, capacity, cost and availability of gathering and transportation facilities;
the cost of exploring for, developing, producing and transporting reserves;
•
•
•
•
•
•
•
•
• weather conditions and natural disasters;
•
technological advances, conservation efforts and availability of alternative fuels affecting oil and gas
consumption;
33
•
•
•
•
refining and processing disruptions or bottlenecks;
the impact of U.S. dollar exchange rates on oil;
expectations about future oil and gas prices; and
Foreign and U.S. federal, state and local and non-U.S. governmental regulation and taxes, including the recent
relaxation of U.S. export restrictions.
Lower oil prices may reduce our cash flow and borrowing ability. If we are unable to obtain needed capital or
financing on satisfactory terms, our ability to develop future reserves could be adversely affected.
Also, lower prices generally adversely affect the quantity of our reserves as those reserves expected to be produced
in later years, which tend to be costlier on a per unit basis, become uneconomic. However, increased gas prices could
negatively impact our oil reserves to the extent it made them more costly to extract. In addition, a portion of our PUDs
may no longer meet the economic producibility criteria 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, sustained periods with oil and natural gas prices at levels lower than current prices also may adversely
affect our drilling economics, which 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, which would reduce the net present value of
our 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 make and expect to continue to make capital expenditures for the development
and exploration of our oil and natural gas reserves. 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 regulatory, 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. We have a 2019
capital expenditure budget of approximately $195 million to $225 million. 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, 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. If we are able to obtain debt financing,
it would require that a portion of our cash flows from operations be used to service such indebtedness, thereby reducing
our ability to use cash flows from operations to fund working capital, capital expenditures and acquisitions. 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
34
development of our properties, which in turn could lead to a decline in our reserves and production. See “Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital
Resources.”
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.
The development of our heavy oil in California is subject to our ability to generate sufficient quantities of steam
using natural gas at an economically effective cost. As a result, we need access to natural gas at prices sufficiently lower
than oil prices on an energy equivalent basis to economically produce our heavy oil. 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 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 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.
We may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to
further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities,
financial condition and results of operations, and our commodity-price risk-management activities may prevent us
from fully benefiting from price increases and may expose us to other risks.
As of December 31, 2018, we have hedged crude oil production at the following approximate volumes and prices:
17.5 MBbl/d at $70 per barrel in 2019, and 1.2 MBbl/d at $65 per barrel in 2020. In the future, we may be unable to
hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity
price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results
of operations.
Our current commodity-price risk-management activities may prevent us from realizing the full benefits of price
increases above the levels determined under the derivative instruments we use to manage price risk. In addition, our
commodity-price risk-management activities may expose us to the risk of financial loss in certain circumstances,
including instances in which:
•
the counterparties to our hedging or other price-risk management contracts fail to perform under those
arrangements; and
•
an event materially impacts oil and natural gas prices in the opposite direction of our derivative positions.
Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change
legal requirements governing our operations, including 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.
Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating to
environmental protection and the exploration and development of our properties, as well as the production,
transportation, marketing and sale of our products. Federal, state and local agencies may assert overlapping authority
to regulate in these areas. 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.
35
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 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 pipeline safety agencies have adopted or proposed regulations to
expand their jurisdiction to include more gas and liquid gathering lines and pipelines and to impose additional mechanical
integrity requirements. The State of California has adopted additional regulations on the storage of natural gas that
could affect the demand or availability of such storage, increase seasonal volatility, or otherwise affect the prices we
pay for fuel gas.
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 increased fluid injection regulation
and idle well decommissioning. In addition, we may experience delays, as we have in the past, due to 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.
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 and operating costs;
ad valorem, excise, and income taxes and costs related to GHG regulations;
36
•
•
•
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. Reduced capital expenditures may result in
a decline in our reserves. Our ability to make the necessary long-term capital expenditures or acquisitions needed to
maintain or expand our reserves may be impaired to the extent cash flow from operations or external sources of capital
are insufficient. We may not be successful in developing, exploring for or acquiring additional reserves. Over the long-
term, a continuing decline in our production and reserves would reduce our liquidity and ability to satisfy our debt
obligations by reducing our cash flow from operations and the value of our assets.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely
affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our development, production
and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will
not result in commercially viable or economically desirable oil and natural gas 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;
and
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.
Our decisions to develop or purchase prospects or properties will depend, in part, on the evaluation of data obtained
through geophysical and geological analyses, production data and engineering studies, the results of which are often
inconclusive or subject to varying interpretations as well as the uncertainties of drilling noted above. For a discussion
of the uncertainty involved in these processes, see “—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.”
Further, many additional factors may curtail, delay or cancel our scheduled drilling projects and ongoing operations,
including the following:
•
•
delays imposed by, or resulting from, compliance with regulatory requirements, including limitations on water
disposal, emission of GHGs, steam injection and well stimulation;
pressure or irregularities in geological formations;
37
•
•
•
•
shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for steam used in
production or pressure maintenance;
lack of available gathering facilities or delays in construction of gathering facilities;
lack of available capacity on interconnecting transmission pipelines; and
other market limitations in our industry.
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. 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. We make assumptions that may prove inaccurate about the consistency and
accuracy of data when we identify these locations. 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 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 5%
of our total net acreage at December 31, 2018.
Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and
development may be eliminated as a result of future legislation. In addition, 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, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax
laws, including to certain key U.S. federal income tax provisions currently available to natural gas and oil exploration
and development companies. Such legislative proposals have included, but not been limited to, (i) the repeal of the
percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible
drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical
expenditures. The future passage of any legislation as a result of these proposals or other changes in U.S. federal income
tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and natural
gas development or otherwise significantly increase our costs.
Furthermore, in California, there have been, and currently are, proposals for new taxes on oil and natural gas
production. 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 for acquisitions,
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. In California, where
we have the most experience operating, we have few competitors. However, most are larger than us. Our competitors
may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a
greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies
may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.
The cost to attract and retain qualified personnel has historically continually increased due to competition and may
increase substantially in the future.
38
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 2019 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 variables 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, which could indirectly limit our ability to acquire assets and businesses. 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. Viable 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 24% of our steam capacity
and approximately 63% 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. These facilities are dependent on viable contracts for the sale of electricity. 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. Furthermore, market fluctuations in electricity prices and regulatory changes in California could adversely
affect the economics of our cogeneration facilities and any corresponding increase in the price of steam could
significantly impact our operating costs. If we were unable to find new or replacement steam sources, lose existing
sources or experience installation delays, we may be unable to maximize production from our heavy oil assets. If we
were to lose our electricity sources, we would be subject to the electricity rates we could negotiate . For a more detailed
discussion of our electricity sales contracts, see “Items 1 and 2. Business and Properties—Operational Overview—
Electricity.”
Our existing debt agreements have restrictive covenants that could limit our growth, financial flexibility and our
ability to engage in certain activities.
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. These
agreements contain covenants, that, among other things, limit our ability to:
•
incur or guarantee additional indebtedness;
• make investments (including certain loans to others);
• merge or consolidate with another entity;
• make dividends and certain other payments in respect of our equity;
•
•
•
•
•
•
hedge future production or interest rates;
create liens that secure indebtedness or certain other obligations;
transfer, sell or otherwise dispose of assets;
repay or prepay certain indebtedness prior to the due date;
enter into transactions with affiliates; and
engage in certain other transactions without the prior consent of the lenders.
39
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 borrowing base under the RBL Facility is subject to periodic redetermination.
The amount available to be borrowed under the RBL Facility is subject to a borrowing base and will be redetermined
semiannually on or about each May 1 and November 1 and will depend on the volumes of our estimated proved oil
and natural gas reserves and estimated cash flows from these reserves and other information deemed relevant by the
administrative agent of, or two-thirds of the lenders under, the RBL Facility. We, and 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 borrowing base.
We may not have sufficient funds to make such repayments, which could result in a default under the terms of the
facility and an acceleration of the loans outstanding under the facility, requiring us to negotiate renewals, arrange new
financing or sell significant assets, all of which could have a material adverse effect on our business and financial
results.
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.
If our cash flows and capital resources were insufficient to fund debt service obligations, we may be forced to
reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance
indebtedness. Our ability to restructure or refinance indebtedness would depend on the condition of the capital markets
and our financial condition at such time, including the view of the markets of our credit risk after recent defaults. Any
refinancing of indebtedness could be at higher interest rates and may require us to comply with new covenants that
further restrict business operations and opportunities. 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.
Future 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.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment.
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
40
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 the year ended December 31, 2016, we recorded non-cash impairment charges of
approximately $1.0 billion.
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, 2018, sales to Andeavor, Phillips 66 and Kern Oil & Refining accounted for approximately 35%, 28%
and 13% respectively, of our sales.
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. This concentration of purchasers may
impact our overall credit risk in that these entities 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 due to this significant customer concentration, if we were to lose any one of our major purchasers, the loss
could cause us to cease or delay both production and sale of our oil and natural gas in the area supplying that purchaser.
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. Because of this geographic concentration, the success and profitability of our
operations may be disproportionately influenced by conditions there. These conditions include local price fluctuations,
changes in state or regional laws and regulations affecting our operations, political risks, limited acquisition opportunities
where we have the most operating experience and infrastructure 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. For a discussion of regulatory risks, see “—Our
business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal
requirements governing our operations, including 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.” The concentration of our operations in California and limited local storage options also increase our
exposure to events such as natural disasters, including wildfires, mechanical failures, industrial accidents or labor
difficulties.
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, refinery
shutdowns and turnarounds and the ability of such facilities 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. The amount of oil, gas and NGLs that can be produced is subject to limitation in certain circumstances, such
as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, damage to the gathering,
transportation, refining or processing facilities, or lack of capacity on such facilities. If our access to markets for
commodities we produce is restricted, our costs could increase and our expected production growth may be impaired.
41
If our assets become subject to FERC regulation or federal, state or local regulations or policies change, or if we
fail to comply with market behavior rules, our financial condition, results of operations and cash flows could be
materially and adversely affected.
Our gathering and transportation operations are exempt from regulation by FERC, under the NGA. We believe
that the natural gas pipelines in our gathering systems meet the traditional tests the FERC has used to establish that a
pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC- regulated transmission
services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the
FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation
of our gathering facilities may be subject to change based on future determinations by the FERC, the courts, or Congress.
If the FERC were to determine that one of our facilities or the services it provides were not exempt from FERC regulation
under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to
regulation, which could decrease revenue, increase operating costs and otherwise adversely affect our results of
operations and cash flows. Should we fail to comply with any applicable FERC administered statutes, rules, regulations
and orders, we could be subject to substantial penalties and fines. The FERC has civil penalty authority under the NGA
and NGPA to impose penalties for current violations in excess of $1 million per day for each violation and disgorgement
of profits associated with any violation.
Moreover, FERC regulations indirectly impact our businesses and the markets for products derived from these
businesses. The FERC’s policies and practices across the range of its natural gas regulatory activities, including, for
example, its policies on open access transportation, market manipulation, ratemaking, gas quality, capacity release and
market center promotion, indirectly affect the intrastate natural gas market.
In addition, State regulation of natural gas gathering facilities and intrastate transportation pipelines generally
includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser
requirements, as well as complaint-based rate regulation. Other state regulations may not directly apply to our business,
but may nonetheless affect the availability of natural gas for purchase, compression and sale.
For more information regarding federal and state regulation of our operations, please see “Items 1 and 2. Business
and Properties—Regulation of Health, Safety and Environmental Matters.”
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. The Dodd-Frank Act required the Commodity
Futures Trading Commission to promulgate a range of 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.
42
Concerns about climate change and other air quality issues may affect our operations or results.
Concerns about climate change and regulation of GHGs and other air quality issues may materially affect our
business in many ways, including by increasing the costs to provide our products and services, and reducing demand
for, and consumption of, the oil and gas we produce. We may be unable to recover or pass through all or any of these
costs. In addition, legislative and regulatory responses to such issues may increase our operating costs and render certain
wells or projects uneconomic. To the extent financial markets view climate change and GHG emissions as a financial
risk, this could adversely impact our cost of, and access to, capital. Both California and the EPA have adopted laws
and policies that seek to reduce GHG emissions as discussed in “Items 1 and 2. Business and Properties—Regulation
of Health, Safety and Environmental Matters—Climate Change” and “—California GHG Regulations.” Compliance
with California cap-and-trade program laws and regulations could significantly increase our capital, compliance and
operating costs and could also reduce demand for the oil and natural gas we produce. The cost of acquiring GHG
emissions allowances will depend on the market price for such instruments at the time they are purchased, the distribution
of cost-free allowances among various industry sectors by the California Air Resources Board, and our ability to limit
GHG emissions and implement cost-containment measures. In addition, on September 10, 2018, the Governor of
California signed into law a bill that would commit California to the use of 100% zero-carbon electricity by 2045. The
same day, the Governor also signed an executive order committing California to total economy-wide carbon neutrality
by 2045. While the law does not directly affect the oil and gas industry, and it remains unclear what actions state agencies
may take in response to the executive order, these recent actions could result in decreased future demand for the oil
and gas we produce and in turn have an adverse effect on our business and results of operations.
In addition, other current and proposed international agreements and federal and state laws, regulations and policies
seek to restrict or reduce the use of petroleum products in transportation fuels and electricity generation, impose
additional taxes and costs on producers and consumers of petroleum products, and require or subsidize the use of
renewable energy. For example, the International Maritime Organization has imposed global sulfur caps on ships sailing
in emissions control areas, which are set to take effect by January 2020, and may decrease demand, or the prices we
can obtain, for our products.
Governmental authorities can impose administrative, civil and criminal penalties for non-compliance with air
permits or other requirements of the federal Clean Air Act (the “CAA”) and associated state laws and regulations. For
example, the San Joaquin Valley will be required to adopt more rigorous attainment plans under the CAA to comply
with federal ozone and particulate matter standards, and these efforts could affect our activities in the region. In addition,
California air quality laws and regulations, particularly in southern and central California where most of our operations
are located, are in most instances more stringent than analogous federal laws and regulations.
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, including
well drilling, completion, stimulation, maintenance, water disposal, marketing and transportation and abandonment
activities, are subject to operational 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, 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. 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
43
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. If we record inaccurate data or experience infrastructure outages, our
ability to communicate and control and manage our business could be adversely affected.
We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information
or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-party facilities
and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Our implementation of various
procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities
and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such
procedures and controls will be sufficient to prevent security breaches from occurring. If security breaches were to
occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations.
If we were to experience an attack and our security measures failed, the potential consequences to our business and the
communities in which we operate could be significant and could harm our reputation and lead to financial losses from
remedial actions, loss of business or potential liability.
Risks Related to Emergence
Our financial condition or results of operations are not comparable to the financial condition or results of operations
reflected in our historical financial statements.
Since February 28, 2017, we have been operating under a new capital structure. In addition, we adopted fresh-start
accounting and, as a result, at February 28, 2017 our assets and liabilities were recorded at fair value, which resulted
in values that are materially different than the values that were recorded in our historical financial statements.
Accordingly, our financial condition and results of operations from and after the Effective Date are not comparable to
the financial condition or results of operations reflected in our historical financial statements. Further, as a result of the
implementation of the Plan and the transactions contemplated thereby, our historical financial information may not be
indicative of our future financial performance.
Due to our limited operating history as an independent company following our emergence from bankruptcy in
February 2017, we have been in the process of establishing our accounting and other management systems and
resources. We may be unable to effectively complete the development of a mature system of internal controls, and
a failure of our control systems to prevent error or fraud may materially harm our company.
Our predecessor company was an indirect, wholly owned subsidiary of Linn Energy, and we utilized Linn Energy’s
systems, software and personnel to prepare our financial information and to ensure that adequate internal controls over
financial reporting were in place. Following our emergence from bankruptcy in February 2017, we assumed
responsibility for these functions. In the course of transitioning these functions, we put in place a new executive
management team and continue to add personnel, upgrade our systems, including information technology, and
implement additional financial and managerial controls, reporting systems and procedures. These activities place
44
significant demands on our management, administrative and operational resources, including accounting resources,
and involve risks relating to our failure to manage this transition adequately.
Proper systems of internal controls over financial accounting and disclosure controls and procedures are critical
to our business. If we are unable to effectively complete the development of a mature system of internal controls, we
may be unable to continue reliably assimilating and compiling financial information about our company, which would
significantly impair our ability to prevent error, detect fraud or access capital markets.
A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance
that the control system’s objectives will be met. Further, the design of a control system must reflect resource constraints
and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control
systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any,
have been detected. Failure of our control systems to prevent error or fraud could materially adversely impact us.
Our limited operating history makes it difficult to evaluate our business plan and our long-term viability cannot be
assured.
Our prospects for financial success are difficult to assess because we have a limited operating history since
emergence from bankruptcy. There can be no assurance that our business will be successful, that we will be able to
maintain a profitable operation, or that we will not encounter unforeseen difficulties that may deplete our capital
resources more rapidly than anticipated. There can be no assurance that we will sustain profitability or positive cash
flows from our operating activities.
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 Amended and Restated Certificate of Incorporation of Berry Corp. (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.
45
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. In addition, our stockholders and their
affiliates may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us
the opportunity to purchase any of those assets. Our business and prospects could be adversely affected if attractive
business opportunities are procured by our stockholders for their own benefit rather than for ours.
Certain of our stockholders and their affiliates have resources greater than ours, which may make it more difficult
for us to compete with such persons with respect to commercial activities as well as for potential acquisitions. As a
result, competition from certain stockholders and their affiliates could adversely impact our results of operations.
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.
We may sell or otherwise issue additional shares of common stock or securities convertible into shares of our
common stock. The Certificate of Incorporation provides that Berry Corp.’s authorized capital stock consists of
750,000,000 shares of common stock and 250,000,000 shares of preferred stock. In addition, we registered shares of
the great majority of our common stock for resale and conditions limiting such resales expired January 21, 2019. The
holders of those shares largely comprised creditors of Berry LLC prior to its bankruptcy and we cannot predict when
or whether they will sell such shares. Such sales, or concerns about them, may put downward pressure on the market
price of our common stock.
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 Berry Petroleum Corporation 2017 Omnibus Incentive Plan, as amended and restated
(our “Restated Incentive 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 Restated Incentive 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 Restated Incentive Plan 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 the common stock.
46
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
“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.
“Emerging growth companies” can also delay adopting new or revised accounting standards until such time as
those standards apply to private companies. 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
under Section 107 of the JOBS Act until we are no longer 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 pursuant to Section 107 of the JOBS
Act.
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.
We will incur significant costs and devote substantial management time as a result of operating as a public company,
particularly after we are no longer an “emerging growth company.”
Our management and other personnel are required to divert attention from operational and other business matters
to devote substantial time to public company requirements. After we no longer qualify as an “emerging growth company,”
we expect to incur additional management time and cost to comply with the more stringent reporting requirements
applicable to companies that are deemed accelerated filers or large accelerated filers, including complying with the
auditor attestation requirements of Section 404(b) of the Sarbanes-Oxley Act. We currently do not have an internal
audit function, and we have needed, and will continue to need, to hire or contract for additional accounting and financial
staff with appropriate public company experience and technical accounting knowledge.
If we do not adequately develop or maintain all required financial reporting and disclosure procedures and controls,
we may be unable to provide the financial information required of a U.S. publicly traded company in a timely and
reliable manner.
As a private company we were not required to adopt or maintain all of the financial reporting and disclosure
procedures and controls required of a U.S. publicly traded company. If we fail to adequately develop and maintain
effective internal controls and procedures and disclosure procedures and controls, we may be unable to provide the
financial information and SEC reports that a U.S. publicly traded company is required to provide in a timely and reliable
fashion. Any such delays or deficiencies could penalize us, including by limiting our ability to obtain financing, either
in the public capital markets or from private sources and hurt our reputation and could thereby impede our ability to
implement our growth strategy.
Our internal control over financial reporting is not currently required to meet the standards required by Section
404 of the Sarbanes-Oxley Act, but failure to achieve and maintain effective internal control over financial reporting
47
in accordance with Section 404 of the Sarbanes-Oxley Act in the future could have a material adverse effect on our
business and share price.
Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the effectiveness of our internal
control over financial reporting, starting with the second annual report that we file with the SEC after the consummation
of the IPO, and generally requires a report by our independent registered public accounting firm on the effectiveness
of our internal control over financial reporting. However, under the JOBS Act, 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, prevent
fraud and operate successfully as a public company. 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.
In connection with the implementation of the necessary procedures and practices related to internal control over
financial reporting, we may identify deficiencies that we may not be able to timely remediate. In addition, we may
encounter problems or delays in completing the implementation of any remediation of control deficiencies and receiving
a favorable attestation in connection with the attestation provided by our independent registered public accounting firm.
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 the Certificate of Incorporation and Bylaws, as well as our stockholders agreement, 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 the Form of the Second Amended and Restated Bylaws
of Berry Corp. (the “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 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. Additionally, we and many of the largest holders of our equity securities are bound
by a stockholders agreement that requires us to nominate for election and take all other necessary actions to cause an
individual designated by Benefit Street Partners to be included in the slate of nominees recommended by the board of
directors to be elected to the board of directors.
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.
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
48
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. Any person or entity purchasing or otherwise acquiring any interest in shares of our
common stock will be deemed to have notice of, and consented to, the provisions of our Certificate of Incorporation
described in the preceding sentence. 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.
If securities or industry analysts do not publish research or reports about our business, if they adversely change
their recommendations regarding our common stock or if our operating results do not meet their expectations, our
stock price could decline.
The trading market for our common stock will be influenced by the research and reports that industry or securities
analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to
publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock
price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our
common stock or if our operating results do not meet their expectations, our stock price could decline.
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—Lawsuits, Claims, 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 began trading on the NASDAQ under the ticker symbol “BRY” on July 26, 2018. Prior to that,
there was no public market for our common stock.
Holders of Record
Our common stock was held by 102 stockholders of record at January 31, 2019, and by approximately 2,100
additional stockholders whose shares were held for them in street name or nominee accounts.
Dividend Policy
We plan to use our operating cash flows to cover our interest requirements, fund our maintenance capital
requirements, 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 the Second Amended and Restated Berry Petroleum Corporation 2017
Omnibus Incentive Plan (the “Omnibus Plan”). A description of the plans can be found in Item 8. Financial Statements
and Supplementary Data – Note 8–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
approximately 1.6 million have been issued or reserved through December 31, 2018.
The following table summarizes information related to our equity compensation plans under which our equity
securities are authorized for issuance as of December 31, 2018.
Plan Category
Equity compensation plans not
approved by security
holders(2)
________________
Number of Securities to be
Issued Upon Exercise of
Outstanding Options and Rights
(#)(3)
Weighted-Average
Exercise Price of
Outstanding Options
and Rights ($)
Number of Securities Remaining
Available for Future Issuance
Under Equity Compensation Plans
(#)(1)
922,952
N/A
8,381,902
(1)
(2)
The number of securities remaining available for future issuances has been reduced by the number of securities to be issued upon RSUs subject
to time vesting and PSUs upon the maximum achievement of certain market-based performance goals over a specified period of time.
In connection with the IPO, our Board amended and restated the Company’s First Amended and Restated 2017 Omnibus Incentive Plan, which
had amended and restated the Company’s 2017 Omnibus Incentive Plan (the “Prior Plans” and, collectively with the Omnibus Plan, the “Equity
Compensation Plans”), which allowed us to grant equity-based compensation awards with respect to up to 10,000,000 shares of common stock
(which number includes the number of shares of common stock previously issued pursuant to an award (or made subject to an award that has
not expired or been terminated) under the Prior Plans), to employees, consultants and directors of the Company and its affiliates who perform
services for the Company. The Omnibus Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock
units, stock awards, dividend equivalents and other types of awards.
(3) Represents common stock to be issued based upon continuous employment and the maximum achievement of certain performance goals over
a specified period of time as described in the applicable Equity Compensation Plan and associated award agreements. We did not have any
options or rights with an exercise price.
50
Sales of Unregistered Securities
Between January 1, 2018 and August 3, 2018, we issued 895,422 RSUs and 754,539 PSUs to certain of our
employees and directors in connection with services provided to us, which issuances were not registered under the
Securities Act of 1933, as amended (the “Securities Act”). In connection with our IPO, on August 3, 2018, we filed a
Registration Statement on Form S-8 registering future issuances of common stock underlying our RSUs and PSUs.
The offers, sales and issuances of the securities described in the preceding paragraph were deemed to be exempt
from registration either under Rule 701 promulgated under the Securities Act in that the transactions were under
compensatory benefit plans and contracts relating to compensation, or under Section 4(a)(2) of the Securities Act in
that the transactions were between an issuer and members of its senior executive management and did not involve any
public offering within the meaning of Section 4(a)(2).
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.
On February 8, 2018, we completed the 2026 Notes offering. The 2026 Notes were issued at a price of 100% of
par, and the sale resulted in net proceeds (after deducting the initial purchasers’ discounts and commissions and estimated
offering expenses and excluding accrued interest) to the Company of approximately $391 million. We used the net
proceeds to repay borrowings under our RBL Facility and for general corporate purposes.
The 2026 Notes were issued and sold to the initial purchasers in a private placement exempt from the registration
requirements of the Securities Act. The initial purchasers sold the 2026 Notes to qualified institutional buyers inside
the United States in reliance on Rule 144A of the Securities Act and to persons outside the United States under Regulation
S of the Securities Act.
Stock Repurchase Program
On December 13, 2018, our Board of Directors announced it had 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 Petroleum to purchase shares during any period or at all. Any shares acquired will be available for general
corporate purposes. In December 2018, we repurchased 448,661 shares at an average price of $8.81 per share. The
Company repurchased 1,932,096 shares from January 1, 2019 through February 28, 2019, resulting in a total of
2,380,757 shares repurchased under the Stock Repurchase Program as of February 28, 2019.
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
December 1 - 31, 2018
448,661
$
8.81
448,661
$
46,047,000
51
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 600, the Dow Jones U.S. Exploration and Production indexes and the Vanguard
Energy ETF (with reinvestment of all dividends). The graph assumes that on July 26, 2018, the date our common stock
began trading on the NASDAQ, $100 was invested in our common stock and in each index, and that all dividends were
reinvested. The returns shown are based on historical results and are not intended to suggest future performance.
COMPARISON OF 6 MONTH CUMULATIVE TOTAL RETURN(1)(2)
Among Berry Petroleum Corporation, the S&P Smallcap 600 Index,
the Dow Jones U.S. Exploration & Production Index
and the Vanguard Energy ETF
07/26/18
07/18
08/18
09/18
10/18
11/18
12/18
01/19
Berry Petroleum Corporation
$ 100.00
$ 103.77
$ 123.70
$ 133.73
$ 106.25
$ 94.04
S&P Smallcap 600
$ 100.00
$ 103.16
$ 108.15
$ 104.71
Dow Jones U.S. Exploration & Production
$ 100.00
$ 103.39
$ 100.56
$ 102.81
Vanguard Energy ETF
$ 100.00
$ 100.06
$
97.10
$ 99.64
$
$
$
93.74
$ 95.15
88.00
$ 82.46
87.58
$ 85.09
$
$
$
$
67.17
83.66
71.18
73.67
$
$
$
$
90.51
92.56
80.76
82.30
__________
(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 or the Exchange Act except to the extent that we specifically request it be treated as soliciting material or
specifically incorporate it by reference.
(2) $100 invested on July 26, 2018 in stock or June 30, 2018 in index, including reinvestment of dividends.
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, 2016 and as of and for the two months ended February 28, 2017 is derived from the audited historical financial
statements of our predecessor company. The selected historical financial information as of and for the ten months ended
December 31, 2017 and as of and for the year ended December 31, 2018 is derived from audited consolidated financial
statements of the successor company.
Upon Berry LLC’s emergence from bankruptcy on February 28, 2017, or the Effective Date, in connection with
the Plan, 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. Upon
adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date.
These fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities
as reflected in our predecessor company’s historical balance sheet. The effects of the Plan and the application of fresh-
start accounting are reflected in Berry Corp.’s consolidated financial statements as of the Effective Date and the related
adjustments thereto are recorded in our consolidated statements of operations as reorganization items for the periods
prior to the Effective Date. 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. You
should read the following table in conjunction with “Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations,” the historical financial statements of our predecessor and accompanying notes
included elsewhere in this report.
53
Berry Corp. (Successor)
Berry LLC (Predecessor)
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
Net income (loss)
Net income (loss) attributable to common stockholders
Net income (loss) per share of common stock
Basic
Diluted
Dividends per common share
Weighted-average common stock outstanding
Basic
Diluted(1)
Cash Flow Data:
Operating activities(2)
Capital expenditures
Balance Sheet Data (at period end):
Total assets
Long-term debt, net
Other Financial Data:
Adjusted EBITDA(3)
Adjusted Net Income (Loss)(4)
$
$
$
$
$
$
$
$
$
$
$
$
92,718
$
410,991
(502,964) $ (1,283,196)
$
$
$
$
$
$
586,557
147,102
49,160
0.85
0.85
0.21
57,743
57,932
319,669
(21,068)
(39,316)
$
$
(1.02)
(1.02)
n/a
n/a
n/a
— $
— $
38,644
38,644
n/a
n/a
n/a
n/a
n/a
—
n/a
n/a
103,100
$
107,399
(127,281) $
(65,479)
$
$
22,431
$
13,197
(3,158) $
(34,796)
1,546,402
$ 1,561,038
$
$
2,652,050
—
400,000
1,692,263
391,786
257,924
100,001
$
$
$
$
379,000
149,613
35,880
$
$
$
28,845
$
89,646
(7,779) $
(149,961)
__________
(1) The Series A Preferred Stock was not a participating security; therefore, we calculated diluted earnings per share using the “if-converted”
method, under which the preferred dividends are added back to the numerator and the Series A 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 earnings per share calculation for
the year ended December 31, 2018 and the ten months ended December 31, 2017 as their effect was antidilutive under the “if-converted”
method. In July 2018, all outstanding shares of our Series A Preferred Stock were converted to common shares in connection with the IPO.
Please see Note 8 for further detail.
(2) 2018 includes a one-time payment of $127 million in the second quarter to early terminate unsettled derivative contracts. The elective cancellation
was effected to realign our hedging pricing with current market rates and move from NYMEX WTI to ICE Brent underlying.
(3) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation to our most directly comparable
financial measure calculated and presented in accordance with GAAP, please see “Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations—Non-GAAP Financial Measures.”
(4) Adjusted Net Income is a non-GAAP financial measure. For a definition of Adjusted Net Income and a reconciliation to our most directly
comparable financial measure calculated and presented in accordance with GAAP, please see “Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations—Non-GAAP Financial Measures.”
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.”
Executive Overview
We are a western United States independent upstream energy company with a focus on the conventional, long-
lived oil reserves in the San Joaquin basin of California. Our long-lived, high-margin asset base is uniquely positioned
to support our objectives of generating top-tier corporate-level returns and positive levered free cash flow through
commodity price cycles. We target onshore, low-cost, low-risk, oil-rich reservoirs in the San Joaquin basin of California
and, to a lesser extent, our Rockies assets including 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 long-term,
capital efficient production growth as well as the ability to continue returning capital to our stockholders.
How We Plan and Evaluate Operations
We use Levered Free Cash Flow to plan our capital allocation for maintenance and internal growth opportunities
as well as hedging needs. We define Levered Free Cash Flow as Adjusted EBITDA less interest expense, dividends,
and capital expenditures.
We use the following metrics to manage and assess the performance of our operations: (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
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.
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. Overall, operating expense is used
by management as a measure of the efficiency with which operations are performing.
55
Environmental, health & safety
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. Meeting corporate EH&S metrics is a part of our incentive programs for all employees.
General and administrative expenses
We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead activities.
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.
Emergence from Chapter 11 Bankruptcy
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. Through the Chapter
11 Proceedings, the Company significantly improved its financial position from that of Berry LLC while it was owned
by the Linn Entities. A final decree closing the Chapter 11 Proceedings were 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. 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.
Factors Affecting the Comparability of Our Financial Condition and Results of Operations
Basis of Presentation and Fresh-Start Accounting
Upon Berry LLC’s emergence from bankruptcy, we adopted fresh-start accounting, which, with the recapitalization
upon emergence from bankruptcy, resulted in Berry Corp. becoming the financial reporting entity in our corporate
group.
Unless otherwise noted or suggested by context, all financial information and data and accompanying financial
statements and corresponding notes, as contained in this report, on or prior to the Effective Date, reflect the actual
historical results of operations and financial condition of our predecessor company for the periods before and after the
Effective Date and do not give effect to the Plan or any of the transactions contemplated thereby or the adoption of
fresh-start accounting. Following the Effective Date, they reflect the actual historical results of operations and financial
condition of Berry Corp. on a consolidated basis and give effect to the Plan and any of the transactions contemplated
thereby and the adoption of fresh-start accounting. Thus, the financial information presented herein on or prior to the
Effective Date is not comparable to Berry Corp.’s performance or financial condition after the Effective Date. As a
result, “black-line” financial statements are presented to distinguish between Berry LLC as the predecessor and Berry
Corp. as the successor.
Berry Corp.’s financial statements reflect the application of fresh-start accounting under GAAP. GAAP requires
that the financial statements, for periods subsequent to the Chapter 11 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 Berry Corp.’s as well as Berry LLC’s statements of operations. In addition, Berry Corp.’s
56
balance sheet classifies the cash distributions from a $35 million cash distribution pool (the “Cash Distribution Pool”)
as “liabilities subject to compromise.” Pre-petition unsecured and under-secured obligations that were affected by the
bankruptcy reorganization process have been classified as “liabilities subject to compromise” on our balance sheet and
our predecessor company’s balance sheet.
Reorganization and Financing Activities
The main actions we took affecting comparability between periods before and after the Effective Date include the
reorganization of Berry LLC through bankruptcy and resulting substantial elimination of debt, entry into the RBL
Facility, issuance of the 2026 Notes, dividends on and conversion of Series A Preferred Stock and completion of the
IPO. These actions are described below in “—Liquidity and Capital Resources.”
Capital Expenditures and Capital Budget
Immediately following Berry LLC’s emergence from bankruptcy and separation from the Linn Entities in 2017,
we increased our pace of development and have continued to do so throughout 2018. For the years ended December 31,
2018 and 2017, our capital expenditures were approximately $148 million and $73 million, respectively, on an accrual
basis excluding acquisitions. Our 2019 anticipated capital expenditure budget is approximately $195 to $225 million,
which represents an increase of approximately 42% over 2018 capital expenditures. Capital expenditures increased
103% from 2017 to 2018. Based on current commodity prices and a drilling success rate comparable to our historical
performance, we believe we will be able to fund our 2019 capital development programs while producing positive
Levered Free Cash Flow. Our 2019 capital program is focused on growing our oil production in California. We anticipate
oil production will be approximately 86% of total production in 2019, compared to 82% in 2018. This change in product
mix also factors in the divestiture of our non-core East Texas gas properties in late 2018. During 2019, we expect to:
•
•
employ four drilling rigs in California throughout the year; and
drill approximately 370 to 420 gross development wells, all of which we expect will be in California for oil
production.
The table below sets forth the expected allocation of our 2019 capital expenditure budget by area as compared
to the allocation of our 2018 and 2017 capital expenditures.
California
Rockies
Corporate
Total
2019 Budget
2018 Actual
2017 Actual
(in millions)
185-212
$
126
$
4-6
6-7
17
5
195-225
$
148
$
$
$
71
2
—
73
The amount and timing of these capital expenditures is within our control and subject to our management’s
discretion. We retain the flexibility to defer a portion of these 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 availability of necessary equipment, infrastructure and capital, the receipt and timing of required
regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by
other interest owners. 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.
57
Acquisitions and Divestitures
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.
Chevron North Midway-Sunset Acquisition
In April 2018, we acquired two leases on an aggregate of 214 acres and a lease option on 490 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 $34.5 million to drill 115 wells on or before April 1, 2020, which we extended
to April 1, 2022. 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. We had not drilled any of these wells as of December 31, 2018. We
would assume an additional 40 well drilling commitment if we exercise our option on the 490 acres. We paid no other
consideration for the acquisition. Our 2019 anticipated capital expenditure budget currently includes approximately
$16 million to drill 33 out of these 115 wells. 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.
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.
Commodity 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 fixed charges, including maintenance capital expenditures, for up to two years out. We have hedged a portion of
our exposure to differentials between Brent and WTI as well. 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.
As of February 28, 2019, our hedge position consisted of oil swaps and puts and natural gas swaps. 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.
For our purchased puts, we would receive settlement payments for prices below the indicated weighted-average
price per barrel of Brent. For some of our put positions, we paid the premium at the time the positions were created,
and for others, we will pay the premium at the time of settlement. In order to mitigate the exposure to these deferred
premiums, we have entered into several offsetting put positions. Swap contracts are designed to provide a fixed price.
For fixed-price swaps, we make settlement payments for prices above the indicated weighted-average price per barrel
of Brent and receive settlement payments for prices below the indicated weighted average price per barrel of Brent.
For oil basis swaps, we make settlement payments if the difference between Brent and WTI is greater than the indicated
58
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 fixed-price natural 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.
In January and February 2019, we closed a portion of our deferred premium put positions by selling offsetting put
positions and terminating contracts. We also added to our natural gas swap positions we had previously hedged. As of
February 28, 2019, we had hedged approximately 15.3 MBbl/d of our 2019 crude oil production at $68 per barrel, as
outlined in the following table along with our natural gas derivative contracts:
Net Purchased/Sold Oil Put Options (ICE Brent):
Hedged volume (MBbls)
Weighted-average price ($/Bbl)
Fixed Price Oil Swaps (ICE Brent):
Hedged volume (MBbls)
Weighted-average price ($/Bbl)
Oil basis differential positions (ICE Brent-NYMEX WTI basis
swaps):
Hedged volume (MBbls)
Weighted-average price ($/Bbl)
Fixed Price Gas Purchase Swaps (Kern, Delivered):
Hedged volume (MMBtu)
Weighted-average price ($/MMBtu)
Q1 2019
Q2 2019
Q3 2019
Q4 2019
484
1,365
368
61.16
$
61.00
$
50.00
$
1,080
637
644
75.76
$
76.27
$
76.27
$
368
50.00
644
76.27
45
46
46
46
(1.29) $
(1.29) $
(1.29) $
(1.29)
1,815,000
2,730,000
1,380,000
465,000
2.68
$
2.70
$
2.65
$
2.65
$
$
$
$
The following table summarizes the historical results of our hedging activities.
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31, 2018
Ten Months Ended
December 31, 2017
Two Months Ended
February 28, 2017
Year Ended
December 31, 2016
Crude Oil (per Bbl):
Realized price, before the effects of derivative
settlements
Effects of derivative settlements
$
$
64.76
$
(5.09) $
48.05
0.48
$
$
46.94
0.46
$
$
35.83
1.05
We expect our operations to generate substantial cash flows at current commodity prices. We have protected a
portion of our anticipated cash flows through 2020 as part of our crude oil hedging program. Our low-decline production
base, coupled with our stable operating cost environment, affords an ability to hedge a material amount of our future
expected production.
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 and Brent oil purchased put options for January 2019 through March 2020. The Brent
oil swaps hedged 1.8 MMBbls in 2018 and 0.9 MMBbls in 2019 at a weighted-average price of $75.66. The Brent oil
purchased put options provided a weighted-average price floor of $65.00 for 2.8 MMBbls in 2019 and 0.5 MMBbls in
2020. We effected these transactions to move from a WTI-based position to a Brent-based position as well as bring our
hedge pricing more in line with current market pricing.
59
Taxes, other than income taxes
Taxes, other than income taxes includes severance taxes, ad valorem and property taxes, GHG allowances, and
other taxes not based on income. We include these taxes when analyzing the economics of development projects and
the efficiency of our hydrocarbon recovery; however, we do not include these taxes in our operating expenses.
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
Securities and Exchange Commission (“SEC”) permitted the recognition of provisional amounts based on a reasonable
estimate, subject to adjustments in a one-year measurement period. For the year 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 (15)% in the ten months ended December 31, 2017 to
23% for the year ended December 31, 2018 was the reduction in our valuation allowance. Our earnings for 2018 allowed
for the release of our valuation allowance, described below, resulting in an effective tax rate less than the statutory
federal and state tax rates.
Business Environment and Market Conditions
The oil and gas industry is heavily influenced by commodity prices. While oil prices improved in 2018 compared
to 2017 and 2016, they did fluctuate during the year. Brent crude oil contract prices ranged during 2018 from $62.59
per Bbl at the beginning, to a high of $86.29 per Bbl and back to $50.47 per Bbl at the end of the year. The Henry Hub
spot price for natural gas also fluctuated during 2018 between $2.55 per MMBtu and $3.23 per MMBtu. Our revenue,
costs, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production
and the prices we pay for our natural gas purchases which will continue to be affected by a variety of factors. Please
see “Item 1A. Risk Factors—Risks Related to Our Business and Industry—Oil, natural gas and NGL prices are volatile
and directly affect our results.”
The following table presents the average ICE Brent, NYMEX WTI oil and NYMEX Henry Hub natural gas prices
for the year ended December 31, 2018, the ten months ended December 31, 2017, the two months ended February 28,
2017, and the year ended December 31, 2016:
ICE (Brent) oil ($/Bbl)
NYMEX (WTI) oil ($/Bbl)
NYMEX (Henry Hub) natural
gas ($/MMBtu)
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31, 2018
Ten Months Ended
December 31, 2017
Two Months Ended
February 28, 2017
Year Ended
December 31, 2016
$
$
$
71.53
64.76
3.09
$
$
$
54.65
50.53
3.00
$
$
$
55.72
53.04
3.66
$
$
$
45.00
43.32
2.46
60
California oil prices are Brent-influenced as California refiners import more than 50% of the state’s demand from
foreign 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, as well as availability of
transportation capacity from producing areas. We use substantially more natural gas for our steamfloods and power
generation, than we produce and sell. Consequently, higher gas prices have a negative impact on our operating costs.
However, we mitigate a substantial portion of this exposure by selling excess electricity from our cogeneration operations
to third parties. 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. 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. The most significant input
and cost of the cogeneration facilities is natural gas. The price we receive from selling electricity to third–parties is
closely tied to the price of natural gas and thus these operations effectively serve as a partial hedge against gas price
increases.
61
Certain Operating and Financial Information
The following tables set forth information regarding total production, average daily production, average prices and
average costs for the year ended December 31, 2018 compared to the year ended December 31, 2017, including the
successor and predecessor periods, and the year ended December 31, 2016. The information for the year ended December
31, 2017 is reflected in the tables and narrative discussion that follows in two distinct periods, the ten months ended
December 31, 2017 and the two months ended February 28, 2017, as a result of our emergence from bankruptcy on
February 28, 2017. References in these results of operations to the year ended December 31, 2017 are used to provide
comparable periods. While this combined presentation is a non-GAAP presentation for which there is no comparable
GAAP measure, management believes that providing this financial information is the most relevant and useful method
for comparing the periods before and after the Effective Date.
62
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31, 2018
Ten Months Ended
December 31, 2017
Two Months Ended
February 28, 2017
Year Ended
December 31, 2016
Average daily production(1):
Oil (MBbl/d)
Natural Gas (MMcf/d)
NGLs (MBbl/d)
Total (MBoe/d)(2)
Total Production:
Oil (MBbl)
Natural gas (MMcf)
NGLs (MBbl)
Total (MBoe)(2)
Weighted-average realized prices:
Oil with hedges (Bbl)
Oil without hedges (Bbl)
Natural gas (Mcf)
NGLs (Bbl)
Average Benchmark prices:
Oil (Bbl) – Brent
Oil (Bbl) – WTI
Natural gas (MMBtu) – Henry Hub
Average costs per Boe(3):
Lease operating expenses
Electricity generation expenses
Electricity sales(3)
Transportation expenses
Transportation sales(3)
Marketing expenses
Marketing revenues(3)
Derivative settlements (received) paid
for gas purchases(3)
Total operating expenses
General and administrative expenses(4)
Depreciation, depletion and
amortization
Taxes, other than income taxes
$
$
$
$
$
$
$
$
$
$
$
$
22.0
26.3
0.6
27.0
8,045
9,589
211
9,855
59.67
64.76
2.74
26.74
71.53
64.76
3.09
19.16
2.09
(3.57)
1.00
(0.08)
0.22
(0.24)
(0.24)
18.33
5.48
8.75
3.36
$
$
$
$
$
$
$
$
$
$
$
$
20.6
49.4
2.0
30.9
6,318
15,119
605
9,443
48.53
48.05
2.70
22.23
54.65
50.53
3.00
15.84
1.58
(2.33)
2.04
—
0.25
(0.29)
—
17.09
5.93
7.25
3.62
$
$
$
$
$
$
$
$
$
$
$
$
19.5
71.7
5.2
36.7
1,153
4,232
304
2,162
47.40
46.94
3.42
18.20
55.72
53.04
3.66
13.06
1.48
(1.69)
2.86
—
0.30
(0.29)
—
15.72
3.68
13.02
2.41
$
$
$
$
$
$
$
$
$
$
$
$
23.1
78.1
3.6
39.7
8,463
28,577
1,307
14,533
36.88
35.83
2.31
17.67
45.00
43.32
2.46
12.73
1.18
(1.60)
2.86
—
0.21
(0.25)
—
15.13
5.45
12.26
1.73
__________
(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.
(3) 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 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 includes the effect of derivative
settlements (received or paid) for gas purchases.
63
(4)
Includes non-recurring restructuring and other costs and non-cash stock compensation expense, in aggregate, of approximately $1.36 per Boe
and $3.40 per Boe for the year ended December 31, 2018 and the ten months ended December 31, 2017, respectively, and none for each of the
two months ended February 28, 2017 and the year ended December 31, 2016.
The following table sets forth average daily production by operating area for the periods indicated:
Average daily production (MBoe/d)(1):
California(2)
Rockies(4)
Hugoton basin(3)
Total average daily production
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31, 2018
Ten Months Ended
December 31, 2017
Two Months Ended
February 28, 2017
Year Ended
December 31, 2016
19.7
7.3
—
27.0
18.0
8.4
4.5
30.9
17.0
8.8
10.8
36.7
20.2
10.0
9.5
39.7
__________
(1) Production represents volumes sold during the period.
(2) On July 31, 2017, we purchased the remaining approximately 84% working interest of our South Belridge Hill property, located in Kern County,
California.
(3) On July 31, 2017, we sold our 78% working interest in the Hugoton natural gas field located in southwest Kansas and the Oklahoma Panhandle.
Our Hugoton assets represented approximately 24% of our average net daily production for the year ended December 31, 2016.
(4) On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
We allocated predominantly all of our 2018 capital to develop California’s oil properties which experienced an
11% or 1.9 MBoe/d increase in 2018 production compared to 2017. This included a 1.5 MBoe/d year-over-year increase
due to the Hill Acquisition. The 2018 development activities accelerated our California production growth throughout
the year, resulting in an 11% increase from 19.5 MBoe/d in the three months ended December 31, 2017 to 21.7 MBoe/
d in the three months ended December 31, 2018.
The year-over-year Rockies production decline, predominantly gas, was largely due to our decision to allocate
most of the 2018 capital to California development. The challenging market conditions in the Uinta basin due to limited
local oil demand and takeaway capacity further contributed to this reduction. We also sold our East Texas gas properties
in November 2018. Finally, our 2018 production was approximately 5.6 MBoe/d lower than 2017 due to the Hugoton
Disposition in July 2017.
The impact of our California oil-focused capital program, as well as the Hill Acquisition (100% oil) and Hugoton
Disposition (100% natural gas) in 2017, was an increase in oil production to 82% of total production in the year ended
December 31, 2018 from 64% of total production in the year ended December 31, 2017.
Average daily production volumes decreased in 2017, including the successor ten months ended December 31,
2017 and the predecessor two months ended February 28, 2017, by 7.9 MBoe/d or 20% when compared to the year
ended December 31, 2016, primarily due to reduced development capital spending in 2016 and early 2017 and the
Hugoton Disposition in July 2017, partially offset by the additional oil volumes from the Hill Acquisition in July 2017.
64
Summary by Area
The following table shows a summary by area of our selected historical financial information and operating data
for the periods indicated. Full year data for 2017 are presented as a single amount for simplicity, but represent two
distinct periods, the two months ended February 28, 2017 (our predecessor) and the ten months ended December 31,
2017 (our successor).
($ in thousands, except prices)
Total revenues
Operating income(1)
Depreciation, depletion, and amortization
Average daily production (MBoe/d)
Production (oil% of total)
Realized prices:
Oil (per Bbl)
NGLs (per Bbl)
Gas (per Mcf)
Capital expenditures
Total proved reserves (MMBoe)
PV-10(2)
California
(San Joaquin and Ventura basins)
Year Ended
December 31,
2018
Year Ended
December 31,
2017
Rockies
(Uinta and Piceance basins)
Year Ended
December 31,
2018
Year Ended
December 31,
2017
$
$
$
$
$
$
$
$
471,983
226,854
72,260
$
$
$
19.7
100%
311,247
74,629
71,092
$
$
$
17.8
100%
65.64
$
47.79
$
— $
— $
125,565
106
2,026,880
$
$
— $
— $
63,313
93
998,391
$
$
76,855
19,089
11,066
6.7
36%
57.34
26.95
2.71
17,351
37
124,652
$
$
$
$
$
$
$
$
76,365
9,961
17,792
7.4
36%
48.47
21.36
2.78
1,451
46
108,375
__________
(1) Operating income includes oil, natural gas and NGL sales, offset by operating expenses, general and administrative expenses, DD&A, and
taxes, other than income taxes.
(2) PV-10 is a financial measure that is not calculated in accordance with GAAP. For a definition of PV-10 and a reconciliation to the standardized
measure of discounted future net cash flows, please see “Items 1 and 2. Business and Properties—Our Reserves and Production Information”.
.
Results of Operations
Results of Operations - Year ended December 31, 2018, Ten Months Ended December 31, 2017, and Two Months
Ended February 28, 2017
Our results of operations for the year ended December 31, 2017 are reflected in the tables and narrative discussion
that follows in two distinct periods, the two months ended February 28, 2017 and the ten months ended December 31,
2017, as a result of our emergence from bankruptcy on February 28, 2017. References in these results of operations to
“the change” and “the percentage change” compare the year ended December 31, 2018 results to the combined results
for the comparison period in 2017 in order to provide comparability of such information. While this combined
presentation is a non-GAAP presentation for which there is no comparable GAAP measure, management believes that
providing this financial information is the most relevant and useful method for comparing the periods before and after
the Effective Date.
65
Berry Corp.
(Successor)
(c) Year
Ended
December 31,
2018
(a) Ten Months
Ended
December 31,
2017
Berry LLC
(Predecessor)
(b) Two Months
Ended
February 28,
2017
(in thousands)
(c)-((a)+(b))
Change
%
Change
Revenues and other:
Oil, natural gas and NGL sales
$
552,874
$
357,928
$
74,120
$ 120,826
Electricity sales
Gains (losses) on oil derivatives
Marketing revenues
Other revenues
35,208
(4,621)
2,322
774
21,972
(66,900)
2,694
3,975
3,655
12,886
633
1,424
9,581
49,393
(1,005)
(4,625)
Total revenues and other
586,557
319,669
92,718
174,170
Expenses:
Lease operating expenses
Electricity generation expenses
Transportation expenses
Marketing expenses
General and administrative expenses
Depreciation, depletion and amortization
Taxes, other than income taxes
(Gains) losses on natural gas derivatives
(Gains) losses on sale of assets and other,
net
188,776
20,619
9,860
2,140
54,026
86,271
33,117
(6,357)
(2,747)
149,599
14,894
19,238
2,320
56,009
68,478
34,211
—
28,238
3,197
6,194
653
7,964
28,149
5,212
—
10,939
2,528
(15,572)
(833)
(9,947)
(10,356)
(6,306)
(6,357)
(22,930)
(183)
20,366
Total expenses and other
385,705
321,819
79,424
(15,538)
Other income (expenses):
Interest expense
Other, net
Reorganization items, net
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
(35,648)
243
24,690
190,137
43,035
147,102
(18,454)
4,071
(1,732)
(18,265)
2,803
(8,245)
(63)
(507,720)
(502,734)
230
(8,949)
(3,765)
534,142
711,136
40,002
(21,068)
$
(502,964) $ 671,134
Series A Preferred Stock dividends and
conversion to common stock
Net income (loss) attributable to common
stockholders
(97,942)
(18,248)
$
49,160
$
(39,316)
n/a
n/a
n/a
n/a
28 %
37 %
(91)%
(30)%
(86)%
42 %
6 %
14 %
(61)%
(28)%
(16)%
(11)%
(16)%
(100)%
(88)%
(4)%
34 %
(94)%
(105)%
(136)%
1,319 %
(128)%
n/a
n/a
Revenues and Other
Oil, natural gas and NGL sales increased in 2018 by $121 million or 28% when compared to the year ended
December 31, 2017, including the successor and predecessor periods. The increase was primarily due to increased oil
production in California and higher realized oil prices, partially offset by lower gas and NGL production. Oil production
in the Rockies was adversely impacted as we managed storage to address the extended shutdown of a major refinery
in the area which limited sales and negatively impacted production. The net effect of the Hill Acquisition and Hugoton
Disposition in 2017 resulted in lower total production on an oil equivalent basis but helped to increase oil volumes and
the relative mix of oil production, resulting in a $39 million increase in revenues. Our organic oil production growth
from our 2018 capital program also contributed to increased revenues.
Electricity sales represents sales to utilities which increased in 2018 by $10 million or 37% when compared to the
year ended December 31, 2017, including the successor and predecessor periods, primarily due to higher prices,
66
attributed to higher natural gas costs, and higher volumes sold externally because of increased utilization at our
cogeneration facilities.
Losses on oil derivatives were $4.6 million, a decrease of $49 million or 91% when compared to the year ended
December 31, 2017, including the successor and predecessor periods. 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 revenues, which primarily represent sales of natural gas purchased from third-parties, decreased in 2018
compared to the year ended December 31, 2017, including the successor and predecessor periods, due to lower sales
volume.
Other revenues decreased in 2018 by $5 million or 86% when compared to the year ended December 31, 2017,
including the successor and predecessor periods. Other revenues in 2017 primarily consisted of helium sales, all of
which were derived from our Hugoton assets prior to their disposition in July 2017.
Expenses
Operating expenses includes 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. Operating expenses for
2018 increased to $18.33 per Boe from $16.84 for the year ended December 31, 2017, including the successor and
predecessor periods. The increase was primarily driven by an increase in lease operating expenses per Boe, partially
offset by an increase in the gross margin for our electricity sales, as discussed below.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies,
and workover expenses. Lease operating expenses per Boe increased by 25% to $19.16 per Boe for the year ended
December 31, 2018 from $15.32 per Boe in 2017, including the successor and predecessor periods. The increase was
primarily due to the change in the mix of our products from 64% oil in 2017 to 82% in 2018. Our oil production is
more costly than gas production, but also generates more margin per barrel. The change in product mix was driven by
the Hugoton Disposition (natural gas production) and Hill Acquisition (oil production) in July 2017, as well as the oil
production growth from capital expenditures during 2018. Lease operating expenses in absolute dollars increased in
2018 by $11 million or 6% when compared to the year ended December 31, 2017, including the successor and predecessor
periods. The increase reflected higher fuel gas costs (mostly due to more volumes purchased), and increased facility
maintenance and well servicing activity in 2018 compared to the prior year.
Electricity generation expenses per Boe increased by 34% to $2.09 per Boe for the year ended December 31, 2018
from $1.56 per Boe in 2017, including the successor and predecessor periods. Electricity generation expenses in 2018
increased in absolute dollars by $3 million or 14% compared to the year ended December 31, 2017, including the
successor and predecessor periods, due to higher fuel costs, mostly due to more volumes purchased for increased steam
and electricity cogeneration. The increase on per Boe basis was largely due to the impact of lower volumes in 2018
noted above from the change in production mix resulting from the Hugoton and Hill transactions.
In 2018 we began hedging a portion of our internal consumption of natural gas used primarily to fuel our
cogeneration units. Gains on natural gas derivatives in 2018 reflected relatively high gas prices in California, compared
to the strike price of our derivatives.
Transportation expenses per Boe decreased by 54% to $1.00 per Boe for the year ended December 31, 2018 from
$2.19 per Boe in 2017, including the successor and predecessor periods, primarily due to the Hugoton Disposition,
which required significant transportation expenses. Transportation expenses in absolute dollars decreased in 2018 by
$16 million or 61% when compared to the year ended December 31, 2017, including the successor and predecessor
periods.
67
Marketing expenses, which primarily represent the cost of natural gas purchased from third parties, decreased in
2018 when compared to the year ended December 31, 2017, including the successor and predecessor periods, primarily
due to lower sales volumes.
General and administrative expenses decreased in 2018 by $10 million or 16% when compared to the year ended
December 31, 2017, including the successor and predecessor periods, in absolute dollars. This activity was consistent
with our post-emergence efforts to build out our corporate structure in 2017 while reducing restructuring costs going
forward. General and administrative expenses mainly consisted of management, support staff, legal and professional
services, non-cash stock-based compensation and annual cash incentives, which are largely based upon, and fluctuate
with, our financial performance. On a per Boe basis, general and administrative expenses decreased from $5.51 in 2017
to $5.48 in year ended December 31, 2018. In 2018 and 2017, general and administrative expenses included non-
recurring restructuring and other costs of approximately $7 million and $30 million, respectively, and non-cash stock
compensation costs of approximately $7 million and $2 million, respectively. Adjusted general and administrative
expenses were $4.13 per Boe for 2018 compared to $2.74 per Boe for 2017. The increase in adjusted general and
administrative expenses per Boe reflected increased costs associated with supporting the company's growth and public
company status, as well as the impact of lower volumes noted above from the change in production mix resulting from
the Hugoton and Hill transactions. Adjusted general and administrative expenses is a non-GAAP financial measure
defined as general and administrative expenses adjusted for non-recurring restructuring and other costs and non-cash
stock compensation expense. Please see “—Non-GAAP Financial Measure” for a reconciliation to the GAAP financial
measure of general and administrative expenses.
Depreciation, depletion and amortization decreased in 2018 by $10 million or 11% when compared to the year
ended December 31, 2017, including the successor and predecessor periods. This decrease was largely driven by the
decreased year-over-year production, partially offset by higher depreciation and depletion rates for 2018 due to the
impact of the July 2017 Hugoton Disposition (lower rates) and Hill Acquisition (higher rates).
Taxes, Other Than Income Taxes
Berry Corp.
(Successor)
Berry LLC
(Predecessor)
(c) Year
Ended
December 31,
2018
(a) Ten Months
Ended
December 31,
2017
(b) Two Months
Ended
February 28,
2017
(in thousands)
(c)-((a)+(b))
change
% change
Severance taxes
Ad valorem taxes
Greenhouse gas allowances
Total taxes other than income taxes
$
$
9,373
$
8,992
$
1,540
$
(1,159)
13,556
10,188
33,117
$
11,599
13,620
34,211
2,108
1,564
(151)
(4,996)
$
5,212
$
(6,306)
(11)%
(1)%
(33)%
(16)%
Taxes, other than income taxes per BOE decreased by 1% to $3.36 per BOE for the year ended December 31, 2018
from $3.40 per BOE in 2017, including the successor and predecessor periods. These costs decreased in 2018 by $6
million or 16% compared to 2017. The $1 million or 11% lower severance taxes in 2018 compared to 2017, including
successor and predecessor periods, was largely a result of lower production, the basis for severance taxes. Ad valorem
taxes, which are based on the value of reserves and production equipment and vary by location, were comparable year-
over-year. Greenhouse gas allowances decreased in 2018 by $5 million or 33% when compared to the year ended
December 31, 2017, including the successor and predecessor periods. This was a result of additional free allowances
in 2018, which reduced the average unit cost of the incurred emissions compared to 2017.
Gains on Sale of Assets and Other, Net
Gains on sales of assets and other, net decreased in 2018 by $20 million or 88% compared to the year ended
December 31, 2017, including the successor and predecessor periods. The gains in 2018 included a $4 million gain
68
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. The 2017 gains included a $23 million gain on the sale of our Hugoton
assets.
Other Income (Expenses)
Berry Corp.
(Successor)
Berry LLC
(Predecessor)
(c) Year
Ended
December 31,
2018
(a) Ten Months
Ended
December 31,
2017
(b) Two Months
Ended
February 28,
2017
(in thousands)
(c)-((a)+(b))
change
% change
Interest expense
Other, net
Total other income (expenses)
$
$
(35,648) $
(18,454)
243
4,071
(35,405) $
(14,383)
$
$
(8,245) $
(8,949)
(63)
(3,765)
(8,308) $ (12,714)
34 %
(94)%
56 %
Interest expense increased in 2018 by $9 million or 34% compared to the year ended December 31, 2017, including
the successor and predecessor periods, due to the interest expense on the 7% 2026 Notes issued in February 2018,
partially offset by lower interest expense on the RBL Facility which had reduced borrowings in 2018 compared to 2017.
Other income, net, for the year ended December 31, 2017 primarily consisted of a refund of a federal income tax
overpayment from a prior year.
Reorganization Items, Net
Reorganization items, net, reflected a gain of approximately $25 million for the year ended December 31, 2018
compared to an expense of $509 million for the year ended December 31, 2017, including the successor and predecessor
periods. The gains for 2018 were primarily due to a return of $23 million from the funds reserved for the claims of the
general unsecured creditors, coupled with a third-party bankruptcy claim receipt and the resolution of pre-emergence
liabilities, partially offset by remaining bankruptcy-related legal and professional fees. Reorganization items represent
costs and income directly associated with the Chapter 11 Proceedings since May 11, 2016, and also include adjustments
to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as
such adjustments are determined.
69
The following table summarizes the components of reorganization items included on the statement of operations:
Berry Corp.
(Successor)
Berry LLC
(Predecessor)
(c) Year
Ended
December 31,
2018
(a) Ten Months
Ended
December 31,
2017
(b) Two Months
Ended
February 28,
2017
(c)-((a)+(b))
change
% change
Return of undistributed funds from cash
distribution pool
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
(in thousands)
$
22,855
$
— $
3,713
(3,083)
—
—
1,205
—
—
—
(705)
(1,027)
(19,481)
17,425
22,855
100 %
—
—
3,713
421,774
(421,774)
(100)%
(920,699)
920,699
10,686
(8,776)
100 %
(85)%
(100)%
(88)%
(105)%
Total reorganization items, net
$
24,690
$
(1,732)
$
(507,720) $ 534,142
Income Tax Expense (Benefit)
Income tax expense increased in 2018 compared to 2017, including the successor and predecessor periods, by
approximately $40 million due to the significant increase in pretax income in 2018 compared to the pre-tax loss in
2017 and the change in the effective tax rates. The key contributor to the change in our effective rate from (15)% in
the ten months ended December 31, 2017 to 23% for the year ended December 31, 2018 was the reduction in the
valuation allowance. Our earnings for 2018 allowed for the release of our valuation allowance, resulting in an effective
tax rate less than the statutory federal and state tax rates.
Series A Preferred Stock dividends and conversion to common stock
The increase in Series A Preferred Stock dividends and conversion to common stock in 2018 compared to the ten
months ended December 31, 2017 was due to a $60 million payment 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.
Results of Operations - Ten Months Ended December 31, 2017, Two Months Ended February 28, 2017 and
Year ended December 31, 2016
Our results of operations for the year ended December 31, 2017 are reflected in the tables and narrative discussion
that follows in two distinct periods, the two months ended February 28, 2017 and the ten months ended December 31,
2017, as a result of our emergence from bankruptcy on February 28, 2017. References in these results of operations to
“the change” and “the percentage change” compare the year ended December 31, 2016 results to the combined results
for the comparison period in 2017 in order to provide comparability of such information. While this combined
presentation is a non-GAAP presentation for which there is no comparable GAAP measure, management believes that
providing this financial information is the most relevant and useful method for comparing the periods before and after
the Effective Date.
70
Revenues and other:
Oil, natural gas and NGL sales
$
357,928
$
74,120
$
392,345
$
Berry Corp.
(Successor)
Berry LLC
(Predecessor)
(a) Ten Months
Ended
December 31,
2017
(b) Two Months
Ended
February 28,
2017
(c) Year
Ended
December 31,
2016
(in thousands)
((a)+(b))-(c)
Change
%
Change
21,972
(66,900)
2,694
3,975
319,669
3,655
12,886
633
1,424
92,718
23,204
(15,781)
3,653
7,570
410,991
149,599
28,238
185,056
3,197
6,194
653
7,964
17,133
41,619
3,100
79,236
28,149
178,223
39,703
2,423
10 %
10 %
(38,233)
(242)%
(326)
(2,171)
1,396
(7,219)
958
(16,187)
(127)
(15,263)
(81,596)
(9)%
(29)%
—%
(4)%
6 %
(39)%
(4)%
(19)%
(46)%
—
5,212
(183)
1,030,588
(1,030,588)
25,113
14,310
(100)%
57 %
(109)
(23,004)
(21,105)%
79,424
1,559,959
(1,158,716)
(74)%
(8,245)
(63)
(61,268)
(182)
34,569
4,190
(507,720)
(72,662)
(436,790)
(502,734)
(1,283,080)
762,081
56 %
2,302 %
(601)%
59 %
230
116
2,917
2,514 %
14,894
19,238
2,320
56,009
68,478
—
34,211
(22,930)
321,819
(18,454)
4,071
(1,732)
(18,265)
2,803
Electricity sales
Gains (losses) on oil derivatives
Marketing revenues
Other revenues
Total revenues and other
Expenses:
Lease operating expenses
Electricity generation expenses
Transportation expenses
Marketing expenses
General and administrative expenses
Depreciation, depletion and
amortization
Impairment of long-lived assets
Taxes, other than income taxes
(Gains) losses on sale of assets and
other, net
Total expenses and other
Other income (expenses)
Interest expense
Other, net
Reorganization items, net
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
(21,068)
$
(502,964) $ (1,283,196) $
759,164
59 %
Series A Preferred Stock dividends and
conversion to common stock
Net income (loss) attributable to
common stockholders
Revenues and Other
(18,248)
$
(39,316)
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
Oil, natural gas and NGL sales increased in 2017, including the successor and predecessor periods, by $40 million
or 10% when compared to the year ended December 31, 2016 due to an increase in realized oil and NGL prices and
an increased mix of oil production compared to gas production as a result of the Hill Acquisition and Hugoton
Disposition, partially offset by decreased natural gas and NGL production.
Electricity sales increased in 2017, including the successor and predecessor periods, by $2 million or 10% when
compared to the year ended December 31, 2016 primarily due to higher volumes sold externally because of lower
internal utilization as well as higher prices.
71
Losses on oil and natural gas derivatives increased in 2017, including the successor and predecessor periods, by
$38 million or 242% when compared to the year ended December 31, 2016 primarily due to increased hedging activity,
a portion of which was required by the RBL Facility, and improved commodity prices relative to the fixed prices of
our derivative contracts.
Marketing revenues in 2017, including the successor and predecessor periods, were comparable to the year ended
December 31, 2016.
Other revenues decreased in 2017, including the successor and predecessor periods, by $2 million or 29% when
compared to the year ended December 31, 2016 due to a decrease in helium gas sales as a result of the Hugoton
Disposition.
Expenses
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies,
and workover expenses. Lease operating expenses in absolute dollars decreased in 2017, including the successor and
predecessor periods, by $7 million or 4% when compared to the year ended December 31, 2016 primarily due to our
production decline as a result of decreased development activity and a reduction of steamflooding. Lease operating
expenses per Boe increased to $15.32 per Boe in 2017, including the successor and predecessor periods, from $12.73
per Boe for the year ended December 31, 2016. The increase in lease operating expenses per Boe was primarily due
to the effect of the Hugoton Disposition (natural gas production) and the Hill Acquisition (oil production), both of
which occurred in July 2017, reflecting higher operating expenses associated with oil production compared to natural
gas production. While production volumes decreased as a result of the Hugoton Disposition and Hill Acquisition, which
decrease adversely impacted costs per Boe, our oil, natural gas and NGL revenues remained constant due to a product
mix more heavily weighted towards oil.
Electricity generation expenses increased in 2017, including the successor and predecessor periods, by $1 million
or 6% when compared to the year ended December 31, 2016, primarily due to the increase in the price of natural gas
used in steam generation, for which electricity generation is a by-product.
Transportation expenses decreased in 2017, including the successor and predecessor periods, by $16 million or
39% when compared to the year ended December 31, 2016, primarily due to the cancellation of uneconomic contracts
in the Chapter 11 Proceedings and the Hugoton Disposition, which required significant transportation expenses.
Marketing expenses in 2017, including the successor and predecessor periods, were comparable to the year ended
December 31, 2016.
General and administrative expenses decreased in 2017, including the successor and predecessor periods, by $15
million or 19% when compared to the year ended December 31, 2016 primarily due to the management change in
conjunction with our emergence from bankruptcy. The reduction in absolute dollars offset by lower production resulted
in higher general and administrative expenses per Boe for the year ended December 31, 2017 when compared to the
same period in 2016. General and administrative expenses include non-recurring restructuring and other costs of
approximately $30 million and non-cash stock compensation costs of approximately $2 million for the ten months
ended December 31, 2017. General and administrative expenses in 2016 mainly consisted of allocations from our parent
company at the time.
Depreciation, depletion and amortization decreased in 2017, including the successor and predecessor periods, by
$82 million or 46% when compared to the year ended December 31, 2016, primarily due to the fair market revaluation
of our assets in fresh-start accounting resulting in a lower depreciable asset base and lower depreciation and depletion
rates. Lower production in 2017 also contributed to the reduction in absolute dollars of depreciation, depletion and
amortization for the year ended December 31, 2017, including successor and predecessor periods, when compared to
2016.
72
Impairment of Long-Lived Assets
We recorded the following non-cash impairment charges associated with proved oil and natural gas properties:
California operating area
Uinta basin operating area
East Texas operating area(1)
Proved oil and natural gas properties
Unproved oil and natural gas properties
Impairment of long-lived assets
Berry Corp.
(Successor)
Ten Months
Ended
December 31,
2017
Berry LLC
(Predecessor)
Two Months
Ended
February 28,
2017
(in thousands)
Year
Ended
December 31,
2016
$
$
— $
— $
984,288
—
—
—
—
—
—
—
—
26,677
6,387
1,017,352
13,236
— $
— $
1,030,588
__________
(1) On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
The impairment charge of $1.0 billion for the year ended December 31, 2016 was primarily due to a decline in
commodity prices and changes in expected capital development resulting in a decline of our proved reserves.
Taxes, Other Than Income Taxes
Berry Corp.
(Successor)
(a) Ten Months
Ended
December 31,
2017
Berry LLC
(Predecessor)
(b) Two Months
Ended
February 28,
2017
(c) Year
Ended
December 31,
2016
(in thousands)
((a)+(b))-(c)
change
% change
Severance taxes
Ad valorem taxes
Greenhouse gas allowances
Other
Total taxes other than income taxes
$
$
8,992
$
1,540
$
7,968
$
11,599
13,620
—
2,108
1,564
—
10,951
6,063
131
2,564
2,756
9,121
(131)
34,211
$
5,212
$
25,113
$
14,310
32 %
25 %
150 %
(100)%
57 %
Taxes, other than income taxes, increased in 2017, including the successor and predecessor periods, by $14 million
or 57% compared to the year ended December 31, 2016. Severance taxes, which are a function of production in certain
jurisdictions, increased in 2017, including successor and predecessor periods, by $2.5 million or 32% primarily because
of increased production in those areas. Ad valorem taxes, which are based on the value of reserves and production
equipment, and vary by location, increased in 2017, including the successor and predecessor periods, by $3 million or
25% compared to the year ended December 31, 2016, as a result of higher estimated valuations by various tax authorities
based on increased commodity prices. Greenhouse gas allowances increased in 2017, including the successor and
predecessor periods, by $9 million or 150% when compared to the year ended December 31, 2016, primarily due to
increased development activity in the second half of 2017 and an increase in the price of allowances.
Gains on Sale of Assets and Other, Net
Gains on sales of assets and other, net increased in 2017, including the successor and predecessor periods, by $23
million, compared to the year ended December 31, 2016, primarily due to the Hugoton Disposition.
73
Other Income (Expenses)
Berry Corp.
(Successor)
(a) Ten Months
Ended
December 31,
2017
Berry LLC
(Predecessor)
(b) Two Months
Ended
February 28,
2017
(c) Year
Ended
December 31,
2016
(in thousands)
((a)+(b))-(c)
change
% change
Interest expense
Other, net
Total other income (expenses)
$
$
(18,454)
4,071
(14,383)
$
$
(8,245) $
(61,268) $
34,569
56%
(63)
(182)
4,190
2,302%
(8,308) $
(61,450) $
38,759
63%
Interest expense decreased in 2017, including the successor and predecessor periods, by $35 million or 56%
compared to the year ended December 31, 2016, due to reduced debt resulting from the bankruptcy. Other income, net,
for the year ended December 31, 2017, primarily consists of a refund of a federal income tax overpayment from a prior
year.
Reorganization Items, Net
Reorganization items, net, contributed a larger loss in 2017, including the successor and predecessor periods by
$437 million or 600% compared to the year ended December 31, 2016, primarily due to the impact from the application
of fresh-start accounting in conjunction with our emergence from bankruptcy during the two months ended February
28, 2017, partially offset by the gains on settlement of liabilities subject to compromise. Reorganization items represent
costs and income directly associated with the Chapter 11 Proceedings since May 11, 2016, and also include adjustments
to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as
such adjustments are determined.
The following table summarizes the components of reorganization items included on the statement of operations:
Berry Corp.
(Successor)
(a) Ten Months
Ended
December 31,
2017
Berry LLC
(Predecessor)
(b) Two Months
Ended
February 28,
2017
(c) Year
Ended
December 31,
2016
(in thousands)
((a)+(b))-(c)
change
% change
Gains on settlement of liabilities subject to
compromise
$
— $
421,774
$
— $
421,774
—
Legal and other professional advisory fees
(1,732)
(19,481)
Unamortized premiums
Terminated contracts
Fresh-start valuation adjustments
Other
—
—
—
—
—
—
(920,699)
10,686
(30,130)
10,923
(55,148)
—
1,693
Total reorganization items, net
$
(1,732)
$
(507,720) $
(72,662) $
(436,790)
8,917
(10,923)
55,148
30 %
(100)%
100 %
(920,699)
—
8,993
531 %
(601)%
Income Tax Expense (Benefit)
On the Effective Date, upon consummation of the Plan, we became subject to federal and state income taxes as a
C corporation. Prior to the consummation of the Plan, we were treated as a disregarded entity for federal and state
income tax purposes as a limited liability company, 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, we did not directly pay federal and
74
state income taxes and recognition was not given to federal and state income taxes for our operations prior to the
Effective Date.
Income tax expense increased in 2017, including the successor and predecessor periods, by $3 million when
compared to the year ended December 31, 2016 as a result of federal and state alternative minimum tax current taxes
and a valuation allowance in excess of net deferred tax assets of $1.9 million due to the impact of applying the Tax Act
legislation at the end of 2017.
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 maintenance operations, organic growth and,
opportunistic repurchases of our common stock or debt. We believe our liquidity and capital resources will be sufficient
to conduct our business and operations for the next 12 months.
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.
On August 21, 2018, our board of directors approved a $0.12 per share quarterly cash dividend on our common
stock on a pro-rated basis from the date of our IPO through September 30, 2018, which resulted in a payment of $0.09
per share in October 2018. On November 7, 2018, our board of directors approved a $0.12 per share quarterly cash
75
dividend on our common stock for the fourth quarter of 2018, which was paid in January 2019. On February 28, 2019,
our board of directors approved a $0.12 per share quarterly cash dividend on our common stock for the first quarter of
2019.
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 March 2018, the board approved a $0.158 per share, or approximately
$5.6 million, cash dividend on the Series A Preferred Stock for the quarter ended March 31, 2018. In both cases, the
payments were to stockholders of record as of March 15, 2018. In May 2018, the board of directors approved a $0.15
per share, or approximately $5.6 million, cash dividend on the Series A Preferred Stock for the quarter ended June 30,
2018. The payment was made to stockholders of record as of June 7, 2018.
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 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 on or about each
May 1 and November 1, 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 November 2018, we completed a borrowing
76
base redetermination under our RBL Facility that increased our borrowing base from $400 million to $850 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, 2018, we had approximately $7
million in letters of credit outstanding and borrowing availability of $393 million 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, 2018, our Leverage Ratio and Current Ratio were 1.63:1.00 and 3.73:1.00, respectively.
As of December 31, 2018, we had $393 million available for borrowing under the RBL Facility and were in compliance
with the financial covenants under the RBL Facility.
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.
Hedging
We have protected a significant portion of our anticipated cash flows through our commodity hedging program,
including through fixed-price derivative contracts. For information regarding risks related to our hedging program, see
“Item 1A. Risk Factors—Risks Related to Our Business and Industry”. In January and February 2019, we closed a
portion of our deferred premium put positions by selling offsetting put positions and terminating contracts. We also
added to our natural gas swap positions we had previously hedged. As of February 28, 2019, we had hedged
approximately 15.3 MBbl/d of our 2019 crude oil production at $68 per barrel.
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.
See “—Factors Affecting the Comparability of Our Financial Condition and Results of Operations—Capital
Expenditures and Capital Budget” for a description of our 2018 capital expenditure budget and expected 2019 capital
expenditure budget.
77
Statements of Cash Flows
The following is a comparative cash flow summary:
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31,
2018
Ten Months
Ended
December 31,
2017
Two Months
Ended
February 28,
2017
Year Ended
December 31,
2016
(in thousands)
Net cash:
Provided by (used in) operating activities(1)
$
103,100
$
107,399
$
22,431
$
13,197
Used in investing activities
Provided by (used in) financing activities
(119,069)
15,911
(80,525)
(43,170)
(3,133)
(162,668)
(34,602)
(1,701)
Net decrease in cash, cash equivalents and restricted cash
$
(58) $
(16,296)
$
(143,370) $
(23,106)
__________
(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 was approximately $103 million for the year ended December 31, 2018
compared to cash provided by operating activities of approximately $130 million for the year ended December 31,
2017, including the successor and predecessor periods. The amounts provided by operating activities in 2018 were
negatively impacted by a one-time $127 million payment made in May 2018 for early termination on derivatives in
order to better align our hedge pricing with the then-prevailing market pricing. Excluding the impact of these early
hedge termination payments, the increase in cash provided by operating activities in 2018 compared to 2017 reflected
higher oil prices and lower operating costs slightly offset by negative working capital effects, lower oil and gas volumes
and scheduled derivative cash settlements.
Cash provided by operating activities increased for the year ended December 31, 2017, including successor and
predecessor periods, by approximately $117 million when compared to the same period in 2016, primarily due to the
increases in the price of oil and natural gas, and decreases in operating expenses, interest expense and costs incurred
in conjunction with our emergence from bankruptcy.
Investing Activities
The following provides a comparative summary of cash flow from investing activities:
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31,
2018
Ten Months
Ended
December 31,
2017
Two Months
Ended
February 28,
2017
Year Ended
December 31,
2016
(in thousands)
Capital expenditures (1)
Development of oil and natural gas properties
$
(112,225) $
(52,712)
$
(859) $
(21,988)
Purchase of other property and equipment
Proceeds from sale of properties and equipment and other
Acquisition of properties
Cash used in investing activities:
__________
(1) Based on actual cash payments rather than accrual.
(15,056)
8,212
—
(12,767)
234,292
(249,338)
(2,299)
(12,808)
25
—
194
—
$
(119,069) $
(80,525)
$
(3,133) $
(34,602)
78
Cash used in investing activities was approximately $119 million for the year ended December 31, 2018. The
increase in cash used for investing activities for the year ended December 31, 2018 when compared to the year ended
December 31, 2017 including the successor and predecessor periods, was due to the expansion of our drilling program
in accordance with the 2018 capital budget. Investing activities in 2017 included the Hill Acquisition and the Hugoton
Disposition.
Cash used in investing activities increased in 2017, including the successor and predecessor periods, by $49 million
compared to the year ended December 31, 2016, due to the Hill Acquisition, partially offset by the Hugoton Disposition
and the increase in capital expenditures. Capital expenditures increased in 2017, including the successor and predecessor
periods, by $34 million or 97% compared to the year ended December 31, 2016, primarily due to development of oil
and gas properties as a result of increased liquidity. Our liquidity improved significantly in 2017 due to our emergence
from bankruptcy, improved commodity prices, decreased costs and entry into the RBL Facility.
Financing Activities
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, offset by $379 million in payments on our RBL Facility, a $60 million payment to preferred stockholders in
connection with the Series A Preferred 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. Cash used in financing activities was approximately $43 million for the ten months
ended December 31, 2017 and was primarily related to repayments of the Emergence Credit Facility (as defined below)
of $400 million and payments of debt issuance costs for the RBL Facility of $22 million, partially offset by borrowings
under the new RBL Facility of $379 million. Cash used in financing activities was approximately $163 million for the
two months ended February 28, 2017 and was primarily related to the repayments on the Pre-Emergence Credit Facility
(as defined below) of $498 million, partially offset by the receipt of proceeds from the issuance of our Series A Preferred
Stock of $335 million. Cash used in financing activities was approximately $2 million for the year ended December
31, 2016 and was primarily related to repayments on the Pre-Emergence Credit Facility.
Pre-Emergence Credit Facility and Emergence Credit Facility
All outstanding obligations under the 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”) were canceled and the agreements governing these obligations were
terminated on the Effective Date. Also on the Effective Date, Berry LLC entered into a new 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 (the
“Emergence Credit Facility”). Initial borrowings under the RBL Facility were primarily incurred to repay borrowings
made under the Emergence Credit Facility. All outstanding obligations under the Emergence Credit Facility were
canceled, and the agreements governing these obligations were terminated on July 31, 2017.
Lawsuits, Claims, 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
79
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
December 31, 2018 and December 31, 2017. 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, 2018, 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, 2018:
Debt obligations:
2026 Notes
Interest(1)
Other:
Total
2019
2020-2021
2022-2023
Thereafter
Payments Due
(in thousands)
400,000
199,529
—
—
—
28,000
56,000
56,000
400,000
59,529
Commodity derivatives
Off-Balance Sheet arrangements:
Processing and transportation contracts(2)
Operating lease obligations
Other(3)
1,385
1,385
—
—
12,769
2,482
6,000
3,195
1,290
6,000
5,923
637
—
3,651
555
—
—
—
—
—
Total contractual obligations
$
622,165
$
39,870
$
62,560
$
60,206
$
459,529
__________
(1) Represents interest on the 2026 Notes computed at 7.0% through contractual maturity in 2026.
(2) Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of
(3)
business to secure transportation of our natural gas production to market as well as pipeline and processing capacity.
Included are obligations of approximately $6 million, which could be higher if we elect to construct, or begin construction of, the road in
which case we are obligated to cover 100% of the first $9 million of construction costs plus 50% of the all construction costs above $9
million. Alternatively, we can provide long-term access to an existing road.
80
Balance Sheet Analysis
The changes in our balance sheet from December 31, 2017 to December 31, 2018 are discussed below.
Cash and cash equivalents
Accounts receivable, net
Derivative instruments - current and long-term
Restricted cash
Other current assets
Property, plant & equipment, net
Other non-current assets
Accounts payable and accrued liabilities
Derivative instruments - current and long-term
Liabilities subject to compromise
Long-term debt
Asset retirement obligation
Other non-current liabilities
Equity
Berry Corp. (Successor)
December 31, 2018
December 31, 2017
(in thousands)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
68,680
57,379
91,885
$
$
$
— $
14,367
1,442,708
17,244
144,118
$
$
$
$
— $
— $
391,786
89,176
14,902
1,006,446
$
$
$
$
33,905
54,720
—
34,833
14,066
1,387,191
21,687
97,877
75,281
34,833
379,000
94,509
3,704
859,310
See “—Liquidity and Capital Resources” for discussions about the changes in cash and cash equivalents and long-
term debt.
The $3 million increase in accounts receivable was primarily driven by an increase in receivables for derivative
settlements.
The increase in the derivative asset reflected the early termination and replacement of certain hedge contracts
during 2018 to align our hedging program with higher commodity prices and the impact of mark-to-market values on
our derivatives at the end of 2018 compared to the end of 2017.
Restricted cash at December 31, 2017 represented funds set aside to settle the general unsecured creditors' claims
resulting from our bankruptcy process. The decrease in restricted cash, and the corresponding decrease in liabilities
subject to compromise, represented the settlement of these claims, the return of undistributed funds of approximately
$23 million and professional fees related to the settlement of these claims.
The $56 million increase in property, plant and equipment was largely the result of increased capital expenditures
in oil and gas properties, partially offset by increased accumulated depreciation associated with such properties.
The $4 million decrease in other non-current assets was primarily driven by amortization of debt issuance costs.
The increase in accounts payable and accrued liabilities included a $19 million increase in the accruals for the
increased capital spending in 2018, an $11 million increase from the new interest payment obligations on our 2026
Notes, issued in February of 2018, a $10 million increase in dividends payable, a $3 million increase in the current
portion of the asset retirement obligation, and other items, partially offset by a $10 million decrease in the current
portion of our greenhouse gas liability and other items.
81
The decrease in the derivative liability reflected the early termination and replacement of certain hedge contracts
during 2018 to align our hedging program with higher commodity prices and the impact of mark-to-market values on
our derivatives at the end of 2018 compared to the end of 2017.
The increase in long-term debt resulted from the issuance of our 2026 Notes in February 2018 in the principal
amount of $400 million, net of deferred financing costs, which was used to pay down the $379 million balance on our
RBL Facility.
The decrease in the long-term portion of the asset retirement obligation reflected a reduction in the estimated
obligation for 2018 of $5 million, a reduction due to property sales of $4 million, liabilities settled during the period
of $4 million and an increase to the current portion of the asset retirement obligation of $3 million. These decreases
were offset by accretion expenses of $6 million and new liabilities incurred of $5 million.
The increase in other non-current liabilities primarily represented an additional greenhouse gas liability of $12
million for production during the 2018, which is due for payment more than one year from December 31, 2018.
The increase in equity reflected the receipt of IPO net proceeds of $110 million, net income of $147 million, and
stock-based incentive awards of $7 million; offset by approximately $60 million of distributions to the former preferred
stockholders in connection with the Series A Preferred Stock Conversion, $20 million repurchase from certain general
unsecured creditors of the right to receive shares of our common stock in settlement of their claims, $17 million in
common stock dividends, and $11 million in preferred stock dividends, treasury stock purchases of $4 million and
shares withheld for payment of taxes on equity awards of $4 million.
Non-GAAP Financial Measures
Adjusted EBITDA, Levered Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and
Administrative Expenses
Adjusted EBITDA and Adjusted Net Income (Loss) are not measures of net income (loss) and Levered Free Cash
Flow is not a measure of cash flow, 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 for maintenance and 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.
82
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. We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted
for non-recurring restructuring and other costs and non-cash stock compensation expense. Management believes
Adjusted General and Administrative Expenses is useful because it allows us to more effectively compare our
performance from period to period.
We exclude the items listed above from general and administrative expenses in arriving at Adjusted General and
Administrative Expenses because these amounts can vary widely and unpredictably in nature, timing, amount and
frequency and stock compensation expense is non-cash in nature. Adjusted General and Administrative Expenses should
not be considered as an alternative to, or more meaningful than, general and administrative expenses as determined in
accordance with GAAP. Our computations of Adjusted General and Administrative Expenses may not be comparable
to other similarly titled measures of other companies.
The following tables present reconciliations of the non-GAAP financial measures Adjusted EBITDA, Adjusted
Net Income (Loss) and Levered Free Cash Flow to the GAAP financial measures of net income (loss) and net cash
provided or used by operating activities, as applicable, for each of the periods indicated.
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)
Add (Subtract):
Interest expense
Income tax (benefit) expense
Depreciation, depletion, and amortization
Derivative (gains) losses
Net cash received (paid) for scheduled derivative
settlements(1)
Impairment of long-lived assets
Stock compensation expense
Non-recurring restructuring and other costs
Reorganization items, net
Adjusted EBITDA
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31,
2018
Ten Months
Ended
December 31,
2017
Two Months
Ended
February 28,
2017
Year Ended
December 31,
2016
(in thousands)
$
147,102
$
(21,068)
$
(502,964) $ (1,283,196)
35,648
43,035
86,271
(1,735)
(38,482)
18,454
2,803
68,478
66,900
3,068
—
6,750
6,773
(24,690)
—
1,851
30,325
1,732
8,245
230
28,149
(12,886)
534
(183)
—
—
—
507,720
61,268
116
178,223
20,386
9,708
(109)
1,030,588
—
—
72,662
89,646
$
257,924
$
149,613
$
28,845
$
__________
(1) Net cash received (paid) for scheduled derivative settlements does not include the $127 million in cash paid for early terminated derivatives.
83
(Gains) losses on sale of assets and other
(2,747)
(22,930)
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31,
2018
Ten Months
Ended
December 31,
2017
Two Months
Ended
February 28,
2017
Year Ended
December 31,
2016
(in thousands)
Adjusted EBITDA and Levered Free Cash Flow
reconciliation to net cash provided (used) by operating
activities:
Net cash provided by (used in) operating activities
$
103,100
$
107,399
$
22,431
$
13,197
Add (Subtract):
Cash interest payments
Cash income tax payments
Cash reorganization item (receipts) payments
Non-recurring restructuring and other costs
Derivative early termination payment
Other changes in operating assets and liabilities
Other, net
Adjusted EBITDA
Subtract:
Capital expenditures - accrual basis
Interest expense
Cash dividends declared(1)
Levered Free Cash Flow(2)
19,761
(1,901)
832
6,773
126,949
2,410
—
14,276
1,994
1,732
30,325
—
(6,113)
—
257,924
149,613
(147,831)
(35,648)
(28,658)
(67,963)
(18,454)
(18,248)
8,057
—
11,838
—
—
(13,323)
(158)
28,845
(5,406)
(8,245)
—
57,759
347
19,116
—
—
(876)
103
89,646
(34,796)
(61,268)
—
$
45,787
$
44,948
$
15,194
$
(6,418)
__________
(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.
(2) Levered Free Cash Flow includes cash paid for scheduled derivative settlements of $38 million for the year ended December 31, 2018 and
cash received for scheduled derivative settlements of $3 million for the ten months ended December 31, 2017, $1 million for the two months
ended February 28, 2017, and $10 million for the year ended December 31, 2016.
84
The following table presents a reconciliation of the non-GAAP financial measure Adjusted Net Income (Loss)
to the GAAP financial measure of Net income (loss).
Adjusted Net Income (Loss) reconciliation to Net income
(loss)
Net income (loss)
Add (Subtract):
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31,
2018
Ten Months
Ended
December 31,
2017
Two Months
Ended
February 28,
2017
Year Ended
December 31,
2016
(in thousands)
$
147,102
$
(21,068)
$
(502,964) $ (1,283,196)
(Gains) losses on oil and natural gas derivatives
(1,735)
66,900
(12,886)
20,386
Net cash received (paid) for scheduled derivative
settlements
(38,482)
3,068
(Gains) losses on sale of assets and other, net
(2,747)
(22,930)
Impairments
Non-recurring restructuring and other costs
Reorganization items, net
Total additions (subtractions), net
—
6,773
(24,690)
(60,881)
—
30,325
1,732
79,095
534
(183)
—
—
507,720
495,185
9,708
(109)
1,030,588
—
72,662
1,133,235
Income tax benefit (expense) of adjustments at effective tax
rate(1)
13,780
(22,147)
—
—
Adjusted Net Income (Loss)
$
100,001
$
35,880
$
(7,779) $
(149,961)
__________
(1) For the ten months ended December 31, 2017, our effective tax rate was (15%) due to a net loss and valuation allowances. For purposes of
this calculation, we used the statutory rate for this period, which was 28%.
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.
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31,
2018
Ten Months
Ended
December 31,
2017
Two Months
Ended
February 28,
2017
Year Ended
December 31,
2016
(in thousands)
Adjusted General and Administrative Expense
reconciliation to general and administrative expenses:
General and administrative expenses
$
54,026
$
56,009
$
7,964
$
79,236
Subtract:
Non-recurring restructuring and other costs
Non-cash stock compensation expense
(6,773)
(6,585)
(30,325)
(1,819)
—
—
—
—
Adjusted General and Administrative Expenses
$
40,668
$
23,865
$
7,964
$
79,236
Off-Balance Sheet Arrangements
See “—Liquidity and Capital Resources—Lawsuits, Claims, Commitments, and Contingencies” and “—
Contractual Obligations” for information regarding our off-balance sheet arrangements.
85
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.
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.
86
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
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 ICE (Brent) and NYMEX (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.
87
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 and development costs of proved properties are capitalized and amortized on a unit-of-production basis
over the remaining life of the proved reserves and proved developed reserves, respectively. 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 and exploratory well costs in 2018, 2017 and 2016 was not significant. 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
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.
Impairment of Proved Properties
Based on the analysis described above, for the year ended December 31, 2016, we recorded non-cash impairment
charges of approximately $1.0 billion associated with proved oil and natural gas properties. The 2016 impairment
charges were due to a decline in commodity prices, changes in expected capital development and a decline in our
estimates of proved reserves. The carrying values of the impaired proved properties were reduced to fair value, estimated
using inputs characteristic of a Level 3 fair value measurement (see Note 1 for definition). The impairment charges
were included in “impairment of long-lived assets” on our statements of operations.
Unproved Properties
A portion of the carrying value of our oil and gas properties was attributable to unproved properties. At December 31,
2018 and 2017, the net capitalized costs attributable to unproved properties were approximately $388 million and $517
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, 2018.
88
Based on the analysis described above, for the year ended December 31, 2016, we recorded non-cash impairment
charges of approximately $13 million associated with unproved oil and natural gas properties. The impairment charges
in 2016 were primarily due to a decline in commodity prices and changes in expected capital development. The carrying
values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level
3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on our statements
of operations.
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
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 validate data provided by third parties by understanding the
valuation inputs used, obtaining market values from other pricing sources, analyzing pricing data in certain situations
and confirming that those instruments trade in active markets. We classify these measurements as Level 2.
Stock-based Compensation
Subsequent to February 28, 2017, we 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, 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
89
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.
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.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
The information in this document 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, maintenance capital
requirements, 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”.
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 and meet working capital requirements;
•
price and availability of natural gas;
90
•
•
•
•
•
•
•
•
our ability to use derivative instruments to manage commodity price risk;
impact of environmental, health and safety, and other governmental regulations, and of current, pending, or
future legislation;
uncertainties associated with estimating proved reserves and related future cash flows;
our inability to replace our reserves through exploration and development activities;
our ability to obtain permits and otherwise to meet our proposed drilling schedule and to successfully drill
wells that produce oil and natural gas in commercially viable quantities;
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;
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;
concerns about climate change and other air quality issues;
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.
91
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 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 it is
appropriate to hedge based on a variety of factors, including, among other things, current and future expected commodity
prices, 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. Currently, our hedging
program mainly consists of swaps and puts.
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 validate data provided by third parties by understanding the valuation
inputs used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and
confirming that those instruments trade in active markets. At December 31, 2018, the fair value of our hedge positions
was a net asset of approximately $92 million. A 10% increase in the oil and natural gas index prices above the
December 31, 2018 prices would result in a net liability of approximately $82 million, which represents a decrease in
the fair value of our derivative position of approximately $10 million; conversely, a 10% decrease in the oil and natural
gas index prices below the December 31, 2018 prices would result in a net asset of approximately $102 million, which
represents an increase in the fair value of approximately $10 million. For additional information about derivative
activity, see Note 6 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 nine commodity derivative counterparties at December 31, 2018 and five at December 31, 2017. 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
92
to credit losses related to our business at December 31, 2018 was not material and losses associated with credit risk
have been insignificant for all periods presented.
Interest Rate Risk
Our RBL Facility has a variable interest rate on outstanding balances. We used a portion of the proceeds from the
issuance of the 2026 Notes to repay borrowings under the RBL Facility in February 2018. As of December 31, 2018,
there were no borrowings under our RBL Facility and thus we were not exposed to interest rate risk on this facility.
The 2026 Notes have a fixed interest rate and thus we are not exposed to interest rate risk on these instruments. See
Note 5 to our consolidated financial statements for additional information regarding interest rates on outstanding debt.
93
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, 2018 and December 31, 2017 ....................................
Consolidated Statements of Operations for the Year Ended December 31, 2018, the Ten Months Ended
December 31, 2017, the Two Months Ended February 28, 2017, and the Year Ended December 31,
2016 .......................................................................................................................................................
Consolidated Statements of Equity for the Year Ended December 31, 2018, the Ten Months Ended
December 31, 2017, the Two Months Ended February 28, 2017, and the Year Ended December 31,
2016 .......................................................................................................................................................
Consolidated Statements of Cash Flows for the Year Ended December 31, 2018, the Ten Months Ended
December 31, 2017, the Two Months Ended February 28, 2017, and the Year Ended December 31,
2016 .......................................................................................................................................................
Notes to the Consolidated Financial Statements.......................................................................................
Supplemental Quarterly Financial Data (Unaudited)................................................................................
Supplemental Oil & Natural Gas Data (Unaudited) .................................................................................
Page
95
96
97
98
99
100
135
137
94
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Stockholders and Board of Directors
Berry Petroleum Corporation:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Berry Petroleum Corporation and its subsidiary (the
“Company”) as of December 31, 2018 (Successor) and December 31, 2017 (Successor), the related consolidated
statements of operations, equity, and cash flows for the year ended December 31, 2018 (Successor), the ten months
ended December 31, 2017 (Successor), the two months ended February 28, 2017 (Predecessor), and the year ended
December 31, 2016 (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, 2018 (Successor) and December 31, 2017 (Successor) and the results of its operations
and its cash flows for the year ended December 31, 2018 (Successor), the ten months ended December 31, 2017
(Successor), the two months ended February 28, 2017 (Predecessor), and the year ended December 31, 2016
(Predecessor), in conformity with U.S. generally accepted accounting principles.
Basis of Presentation
As discussed in Note 2 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 2.
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 auditing 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. Our audits included performing procedures to assess the risks
of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing
procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the
amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of the
consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company’s auditor since 2013.
Los Angeles, California
March 7, 2019
95
BERRY PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
Current assets:
Cash and cash equivalents
ASSETS
Accounts receivable, net of allowance for doubtful accounts of $950 at December
31, 2018 and $970 at December 31, 2017
Derivative instruments
Restricted cash
Other current assets
Total current assets
Non-current assets:
Oil and natural gas properties
Accumulated depletion and amortization
Total oil and natural gas properties, net
Other property and equipment
Accumulated depreciation
Total other property and equipment, net
Derivative instruments
Other non-current assets
Total assets
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses
Derivative instruments
Liabilities subject to compromise
Total current liabilities
Non-current liabilities:
Long term debt
Derivative instruments
Deferred income taxes
Asset retirement obligation
Other non-current liabilities
Commitments and Contingencies - Note 7
Equity:
Series A Preferred Stock ($.001 par value; 250,000,000 shares authorized; none
outstanding at December 31, 2018 and 35,845,001 shares outstanding at December
31, 2017)
Common stock ($.001 par value; 750,000,000 shares authorized; 81,651,098 and
32,920,000 shares issued; and 81,202,437 and 32,920,000 shares outstanding, at
December 31, 2018 and December 31, 2017, respectively)
Additional paid-in capital
Treasury stock, at cost (448,661 shares at December 31, 2018 and none at December
31, 2017)
Retained earnings (accumulated deficit)
Total equity
Total liabilities and equity
Berry Corp. (Successor)
December 31, 2018 December 31, 2017
(in thousands, except share amounts)
$
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
33,905
54,720
—
34,833
14,066
137,524
1,342,453
(54,785)
1,287,668
104,879
(5,356)
99,523
—
21,687
$
$
1,692,263
$
1,546,402
144,118
$
—
—
144,118
391,786
—
45,835
89,176
14,902
—
82
914,540
(24,218)
116,042
1,006,446
97,877
49,949
34,833
182,659
379,000
25,332
1,888
94,509
3,704
335,000
33
545,345
—
(21,068)
859,310
$
1,692,263
$
1,546,402
The accompanying notes are an integral part of these financial statements.
96
BERRY PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
Berry Corp. (Successor)
Berry LLC (Predecessor)
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)
Revenues and other:
Oil, natural gas and natural gas liquid sales
$
552,874
$
357,928
$
74,120
$
392,345
Electricity sales
Gains (losses) 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 long-lived assets
Taxes, other than income taxes
(Gains) losses on natural gas derivatives
(Gains) losses on sale of assets and other, net
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 income (loss)
35,208
(4,621)
2,322
774
21,972
(66,900)
2,694
3,975
586,557
319,669
3,655
12,886
633
1,424
92,718
23,204
(15,781)
3,653
7,570
410,991
149,599
28,238
185,056
188,776
20,619
9,860
2,140
54,026
86,271
—
33,117
(6,357)
(2,747)
385,705
243
(35,405)
24,690
190,137
43,035
147,102
14,894
19,238
2,320
56,009
68,478
—
34,211
—
(22,930)
321,819
4,071
(14,383)
(1,732)
(18,265)
2,803
3,197
6,194
653
7,964
17,133
41,619
3,100
79,236
28,149
178,223
—
1,030,588
5,212
—
(183)
25,113
—
(109)
79,424
1,559,959
(8,245)
(63)
(8,308)
(507,720)
(61,268)
(182)
(61,450)
(72,662)
(502,734)
(1,283,080)
230
116
(35,648)
(18,454)
(21,068)
$
(502,964) $ (1,283,196)
Series A Preferred Stock dividends and conversion to common
stock
Net income (loss) attributable to common stockholders
Income (loss) per share attributable to common
stockholders:
Basic
Diluted
(97,942)
(18,248)
49,160
$
(39,316)
0.85
0.85
$
$
(1.02)
(1.02)
$
$
$
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
The accompanying notes are an integral part of these financial statements.
97
BERRY PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
December 31, 2015
Net loss
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
$
(1,012,554) $
1,786,159
—
2,798,713
—
1
2,798,714
(2,798,714)
(1,283,196)
(2,295,750)
(502,964)
—
(2,798,714)
2,798,714
$
— $
— $
(1,283,196)
502,963
(502,964)
1
—
—
—
Berry Corp. (Successor)
Series A
Preferred
Stock
Common
Stock
Additional
Paid-in
Capital
Treasury
Stock
Retained
Earnings
(Accumulated
Deficit)
Total
Equity
(in thousands)
$ 335,000
$
— $
— $
— $
— $ 335,000
Issuance of Series A convertible preferred
stock
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
—
335,000
—
—
335,000
—
Conversion of Series A Preferred Stock
into common stock
(335,000)
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
—
—
—
—
—
—
—
—
—
— $
$
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
1
—
—
—
—
—
82
—
—
—
—
—
—
—
—
—
—
—
—
—
—
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)
—
—
(20,265)
(3,953)
(7,365)
—
$ 914,540
—
—
$ (24,218) $
(9,992)
(17,357)
147,102
116,042
147,102
$1,006,446
The accompanying notes are an integral part of these financial statements.
98
BERRY PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flow from operating activities:
Net income (loss)
Adjustments to reconcile net loss to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization
Amortization of debt issuance costs
Impairment of long-lived asset
Stock-based compensation expense
Deferred income taxes
(Decrease) increase in allowance for doubtful accounts
(Gains) losses on sale of assets and other, net
Reorganization expenses, net - non-cash
Derivatives activities:
Total (gains) losses
Cash settlements on normal 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 (used in) operating activities
Cash flow from investing activities:
Capital expenditures:
Development of oil and natural gas properties
Purchases of other property and equipment
Acquisition of properties
Proceeds from sale of properties and equipment and other
Net cash provided by (used in) investing activities
Cash flow from financing activities:
Repayments on new credit facility
Borrowings under new credit facility
IPO proceeds net of issuance costs
Repurchase of common stock
Payment to preferred stockholders in conversion
Issuance of 2026 Senior Unsecured Notes
Dividends paid on Series A Preferred Stock
Dividends paid on common stock
Purchase of treasury stock
Shares withheld for payment of taxes on equity awards
Debt issuance costs
Borrowings on emergence credit facility
Repayments on emergence credit facility
Proceeds from sale of Series A Preferred Stock
Repayments on pre-emergence credit facility
Net cash provided by (used in) financing activities
Net (decrease) increase in cash and cash equivalents
Cash, cash equivalents and restricted cash:
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31,
2018
Ten Months
Ended
December 31,
2017
Two Months
Ended
February 28,
2017
(in thousands)
Year Ended
December 31,
2016
$
147,102
$
(21,068)
$
(502,964) $ (1,283,196)
86,271
5,430
—
6,750
43,946
(20)
(2,747)
(25,523)
(1,735)
(38,482)
(126,949)
(1,683)
(3,190)
19,526
(5,596)
103,100
(112,225)
(15,056)
—
8,212
(119,069)
(582,510)
203,510
133,805
(23,712)
(60,273)
400,000
(11,301)
(7,365)
(23,351)
(3,699)
(9,193)
—
—
—
—
15,911
(58)
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
(52,712)
(12,767)
(249,338)
234,292
(80,525)
(23,285)
402,285
—
—
—
—
—
—
—
—
(22,170)
51,000
(451,000)
—
—
(43,170)
(16,296)
28,149
416
—
—
9
—
(25)
501,872
(12,886)
534
—
(9,152)
(2,842)
18,330
990
22,431
(859)
(2,299)
—
25
(3,133)
—
—
—
—
—
—
—
—
—
—
—
—
—
335,000
(497,668)
(162,668)
(143,370)
178,223
1,849
1,030,588
—
(11)
—
(212)
43,289
20,386
8,007
1,701
(6,556)
1,962
22,101
(4,934)
13,197
(21,988)
(12,808)
—
194
(34,602)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1,701)
(1,701)
(23,106)
Beginning
Ending
68,738
68,680
$
85,034
68,738
228,404
85,034
$
251,510
228,404
$
$
The accompanying notes are an integral part of these financial statements.
99
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1—Basis of Presentation and Significant Accounting Policies
“Berry Corp.” refers to Berry Petroleum Corporation, 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, 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 2, 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”) and include the accounts of the Successor and its wholly owned subsidiary after February 28,
2017 and the accounts of the Predecessor prior to February 28, 2017. All significant intercompany transactions and
balances have been eliminated 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.
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.
100
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 2 for definition), the financial statements on or after February 28, 2017 are
not comparable to the financial statements prior to that date. See Note 3 for additional information.
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.
As fair value is a market-based measurement, it was determined based on the assumptions that we believe market
participants would use. We based these assumptions on management's best estimates and judgment. Management
evaluates its assumptions on an ongoing basis using historical experience and other factors, including the current
economic environment, that management believes to be reasonable under the circumstances. Such assumptions are
adjusted when management determines that facts and circumstances dictate. As future events and their effects cannot
be determined with precision, actual results could differ from these estimates.
Cash Equivalents
We consider all highly liquid short-term investments with original maturities of three months or less to be cash
equivalents.
Restricted Cash
As of December 31, 2018 and December 31, 2017, “restricted cash” was approximately zero and $35 million,
respectively. Restricted cash was classified as a current asset on the consolidated balance sheets and represents cash
that was used to settle certain claims and pay certain professional fees in accordance with the Plan (as defined below).
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 and development costs of proved properties are capitalized and amortized on a unit-of-production basis
over the remaining life of the proved reserves and proved developed reserves, respectively. 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
101
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 and exploratory well costs in 2018, 2017 and 2016 was not significant. 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 are reduced to fair value
when the expected undiscounted future cash flows are less than net book value. We measure the fair values of proved
properties are measured 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 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.
Impairment of Proved Properties
Based on the analysis described above, for the year ended December 31, 2016, we recorded non-cash impairment
charges of approximately $1.0 billion associated with proved oil and natural gas properties. The 2016 impairment
charges were due to a decline in commodity prices, changes in expected capital development and a decline in our
estimates of proved reserves. The carrying values of the impaired proved properties were reduced to fair value, estimated
using inputs characteristic of a Level 3 fair value measurement. The impairment charges were included in “impairment
of long-lived assets” on our statements of operations.
The 2016 non-cash impairment charges associated with proved oil and natural gas properties arose in the following
operating areas of our Predecessor:
California operating area
Uinta basin operating area
East Texas operating area
Total non-cash impairment charges
Unproved Properties
Berry LLC (Predecessor)
Year Ended December 31, 2016
(in thousands)
$
$
984,288
26,677
6,387
1,017,352
A portion of the carrying value of our oil and gas properties was attributable to unproved properties. At December 31,
2018 and 2017, the net capitalized costs attributable to unproved properties were approximately $388 million and $517
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
102
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2018.
Based on the analysis described above, for the year ended December 31, 2016, we recorded non-cash impairment
charges of approximately $13 million associated with unproved oil and natural gas properties. The impairment charges
in 2016 were primarily due to a decline in commodity prices and changes in expected capital development. The carrying
values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level
3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on our statements
of operations.
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 and are depreciated using the straight-line method based on expected useful lives ranging from 5 to
39 years for buildings and leasehold improvements and two to 30 years for plant and pipeline, drilling and other
equipment.
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 $89 million, $95 million
and $109 million were included in long term liabilities as of December 31, 2018, December 31, 2017, and February
28, 2017, respectively, with the remaining current portion included in accrued liabilities:
Berry Corp.
(Successor)
Berry LLC
(Predecessor)
Year Ended
December 31, 2018
Ten Months Ended
December 31, 2017
Two Months Ended
February 28, 2017
$
97,422
$
113,275
$
141,798
(in thousands)
4,901
(3,555)
6,258
(4,145)
(5,333)
—
—
(2,333)
5,562
(19,082)
—
—
$
95,548
$
97,422
$
152
(861)
1,112
—
—
(28,926)
113,275
Beginning balance
Liabilities incurred
Settlements and payments
Accretion expense
Reduction due to property sales
Revisions
Fresh-Start adjustment
Ending balance
Revenue Recognition
We recognize revenue from oil, natural gas and natural gas liquids (“NGLs”) when title has passed from us to the
purchaser, and in the case of electricity when it is delivered to a custody transfer point, collection of revenue from the
103
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
sale is reasonably assured and the sales price is fixed or determinable. We recognize our share of oil, natural gas and
NGL revenues net of any royalties and other third-party share. The electricity and natural gas we produce and use in
our operations are not included in revenues. The excess electricity produced by our cogeneration facilities is marketed
to third parties under multi-year contracts approved by the California Public Utilities Commission (the “CPUC”) for
which the electricity is offered daily into the California electric market to be dispatched based on pricing and grid
requirements. In addition, we engage in the purchase, gathering and transportation of third-party natural gas and
subsequently market such natural gas to independent purchasers under separate arrangements. As a result, we separately
report third-party marketing revenues and marketing expenses.
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 validate data provided by third parties by understanding the
valuation inputs used, obtaining market values from other pricing sources, analyzing pricing data in certain situations
and confirming that those instruments trade in active markets. 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.
Stock-based Compensation
Subsequent to February 28, 2017, we 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, 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.
104
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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
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
105
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2018, our three largest customers represented approximately 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. For the year ended December 31, 2016, our two largest customers represented
approximately 34% and 28% of our sales.
At December 31, 2018, trade accounts receivable from three customers represented approximately 26%, 22%, and
10% of our receivables. At December 31, 2017, trade accounts receivable from two customers represented
approximately 35% and 26% of our receivables.
Recently Adopted Accounting Standards
In November 2016, the Financial Accounting Standards Board (the “FASB”) issued rules intended to address the
diversity in practice in classification and presentation of changes in restricted cash on the statement of cash flows. We
adopted these rules retrospectively on January 1, 2018, as a result of which we included restricted cash amounts in our
beginning and ending cash balances on the statement of cash flows and included a disclosure reconciling cash and cash
equivalents presented on the balance sheets to cash, cash equivalents and restricted cash on the statement of cash flows.
In March 2016, the FASB issued rules to improve the accounting for share-based payment transactions. We early-
adopted these rules retrospectively on April 1, 2018 and as a result are reporting cash paid to tax authorities when we
withhold shares from an employee's award as a cash outflow for financing activities on the statement of cash flows.
There was no change to the other financial statements as a result of adopting these rules.
New Accounting Standards Issued, But Not Yet Adopted
In August 2017, the FASB released targeted improvements to hedge accounting standards that will expand hedge
accounting for non-financial and financial risk components and amend measurement methodologies to more closely
align hedge accounting with a company’s risk management activities. These rules are also intended to decrease the cost
and complexity of hedge accounting. The new rules are effective for fiscal years beginning after December 15, 2018.
We do not anticipate the adoption of this new rule to have a material impact on our consolidated financial statements.
In June 2016, the FASB issued rules that change how entities will measure credit losses for certain financial assets
and other instruments that are not measured at fair value. These rules are effective for fiscal years beginning after
December 15, 2019, including interim periods within those fiscal years, with early adoption permitted. We are currently
evaluating the impact of these rules on our consolidated financial statements.
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-Securities
Exchange Commission (“SEC”) issuers which is for fiscal years beginning after December 15, 2019, including interim
periods within those fiscal years. We expect the adoption of these rules to increase other assets and other liabilities on
our balance sheet and do not expect a material impact on our consolidated results of operations.
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 have 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 will adopt these rules in the first
quarter of 2019 and apply 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 do not expect adoption to have a material impact on our consolidated financial statements,
106
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
however, certain immaterial costs currently netted in revenue will likely be recorded in expenses. In addition, we have
evaluated the expected changes to relevant business practices, accounting policies and control activities and do not
expect to have a material change as a result of the adoption of these rules.
Note 2—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.
• 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. For additional
information about the Emergence Credit Facility, see Note 5.
• 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.
107
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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. The Debtors have settled, and may continue to settle, claims through the Bankruptcy
Court. To the extent that such adjustments relate to Unsecured Claims, no additional liability to the Company is
anticipated as such claimants received only 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. The liability for the cash distribution pool was $34.8 million at December 31, 2017 and is included in liabilities
subject to compromise. 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.
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:
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31,
2018
Ten Months
Ended
December 31,
2017
Two Months
Ended
February 28,
2017
Year Ended
December 31,
2016
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
Unamortized premiums
Terminated contracts
Other
Reorganization items, net
$
$
22,855
3,713
(3,083)
—
—
—
—
1,205
24,690
$
$
(in thousands)
— $
—
(1,027)
—
—
—
—
(705)
(1,732)
$
— $
—
(19,481)
421,774
(920,699)
—
—
10,686
(507,720) $
—
—
(30,130)
—
—
10,923
(55,148)
1,693
(72,662)
__________
(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.
108
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 May
12, 2016 through December 31, 2016 and from January 1, 2017 through February 28, 2017. For those periods, unrecorded
contractual interest was approximately $35 million and $9 million, respectively.
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. See Note 5 for additional details about the Predecessor’s debt.
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.
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 3—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.
109
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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
(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, 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
110
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
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.
111
BERRY PETROLEUM CORPORATION
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
__________
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,
112
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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
(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
$
$
$
$
113
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(12) Net increase in capital accounts reflects:
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 8 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 4, 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
$
$
114
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(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:
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.
Note 4—Oil and Natural Gas Properties and Other Property and Equipment
Oil and Natural Gas Capitalized Costs
As a result of the application of fresh-start accounting, we recorded our oil and natural gas properties and other
property and equipment at fair value as of the Effective Date. The fair values of oil and natural gas properties were
measured 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 and unproved properties include
estimates of i) reserves ii) future operating and development costs iii) future commodity prices and (iv) a market-based
weighted-average cost of capital rate. These inputs required significant judgments and estimates at the time of the
valuation and are the most sensitive and subject to change of our inputs. The fair value was estimated using inputs
characteristic of a Level 3 fair value measurement.
115
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated
depletion and amortization are presented below:
Proved properties
Unproved properties
Total proved and unproved properties
Less accumulated depletion and amortization
Total proved and unproved properties, net
Other Property and Equipment
Other property and equipment consisted of the following:
Natural gas plants and pipelines
Buildings and leasehold improvements
Vehicles
Furniture and equipment
Land
Total other property and equipment
Less: accumulated depreciation
Total other property and equipment, net
Berry Corp. (Successor)
December 31,
2018
December 31,
2017
(in thousands)
$
1,073,959
$
388,034
1,461,993
(123,217)
825,416
517,037
1,342,453
(54,785)
$
1,338,776
$
1,287,668
Berry Corp. (Successor)
December 31,
2018
December 31,
2017
(in thousands)
$
86,562
$
3,359
6,753
14,964
8,073
119,710
(15,778)
$
103,932
$
79,856
2,986
3,228
10,547
8,262
104,879
(5,356)
99,523
116
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 5—Debt
The following table summarizes our outstanding debt:
December 31,
2018
December 31,
2017
(in thousands)
Interest Rate
Maturity
Security
RBL Facility
$
— $
379,000
variable rates of 4.5%
(2018) and 4.8%
(2017), respectively
June 29, 2022
Mortgage on 85% of
Present Value of proven
oil and gas reserves
2026 Notes
400,000
—
7.0%
February 15, 2026
Unsecured
Long-Term Debt -
Principal Amount
400,000
379,000
Less: Debt Issuance Costs
(8,214)
—
Long-Term Debt, net
$
391,786
$
379,000
Deferred Financing Costs
We incurred legal and bank fees related to the issuance of debt. At December 31, 2018 and December 31, 2017,
debt issuance costs for the RBL Facility (as defined below) reported in “other non-current assets” on the balance sheet
were approximately $16 million and $20 million net of amortization, respectively. The amortization of debt issuance
costs is presented in interest expense on the statements of operations. At December 31, 2018, debt issuance costs for
the 2026 Notes (as defined below) were $8 million net of amortization.
For the year ended December 31, 2018, the ten months ended December 31, 2017, the two months ended February
28, 2017, and the year ended December 31, 2016, amortization expense of approximately $4 million, $2 million, zero
and $2 million was included in “interest expense” in the consolidated statements of operations.
Fair Value
Our debt was 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
unsecured notes was approximately $368 million at December 31, 2018.
Credit Facilities
On July 31, 2017, we entered into a credit agreement (the “RBL Facility”), with Wells Fargo Bank, N.A. as
administrative agent and certain lenders 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 on or about each May 1
and November 1, 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 November 2018, we completed a borrowing
base redetermination under our RBL Facility that increased our borrowing base from $400 million to $850 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.
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
117
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
RBL Facility with prior notice at any time without a prepayment penalty, other than customary “breakage” costs with
respect to euro-dollar loans.
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.
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.
As of December 31, 2018, the financial performance covenants under our RBL Facility were (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. At December 31, 2018, our actual ratios
were 1.63 to 1.00 and 3.73 to 1.00, respectively. In addition, the RBL Facility currently provides that to the extent we
incur unsecured indebtedness, including any amounts raised in the future, the borrowing base will be reduced by an
amount equal to 25% of the amount of such unsecured debt. We were in compliance with all financial covenants as of
December 31, 2018.
As of December 31, 2018, we had approximately $393 million of available borrowing capacity under the RBL
Facility.
As of December 31, 2018 and December 31, 2017, we had letters of credit outstanding of approximately $7 million
and $21 million, respectively, under our RBL Facility. These letters of credit were issued to support ordinary course of
business marketing, insurance, regulatory and other matters.
In July and August 2018, we paid down approximately $105 million on the RBL Facility from the net proceeds
we received in the IPO of our common stock (see Note 8).
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
118
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2018.
Note 6—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 fixed charges, including maintenance capital expenditures, for up to two years out. We have hedged a portion of
our exposure to differentials between Intercontinental Exchange (“ICE”) Brent oil (“Brent”) and NYMEX West Texas
Intermediate oil (“WTI”) as well. 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.
As of February 28, 2019, our hedge position consisted of oil swaps and puts and natural gas swaps. 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. We did not designate any of our contracts as cash flow hedges; therefore,
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 of operations and gains (losses) on natural gas hedges are presented
in the expenses and other section of the statement of operations.
119
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2018, we have hedged crude oil production at the following approximate volumes and prices:
17.5 MBbl/d at $70 per barrel in 2019 and 1.2 MBbl/d at $65 per barrel in 2020, as outlined along with our natural gas
derivative contracts in the following table:
Purchased Oil Put Options (ICE Brent):
Hedged volume (MBbls)
Weighted-average price ($/Bbl)
Fixed Price Oil Swaps (ICE Brent):
Hedged volume (MBbls)
Weighted-average price ($/Bbl)
Oil basis differential positions (ICE Brent-
NYMEX WTI basis swaps):
$
$
Q1 2019
Q2 2019
Q3 2019
Q4 2019
FY 2020
360
1,001
1,012
1,012
65.00
$
65.00
$
65.00
$
65.00
$
455
65.00
1,080
637
644
644
75.76
$
76.27
$
76.27
$
76.27
$
Hedged volume (MBbls)
45
45.5
46
46
Weighted-average price ($/Bbl)
$
(1.29) $
(1.29) $
(1.29) $
(1.29) $
Fixed Price Gas Purchase Swaps (Kern,
Delivered):
Hedged volume (MMBtu)
1,350,000
1,365,000
1,380,000
465,000
Weighted-average price ($/MMBtu)
$
2.65
$
2.65
$
2.65
$
2.65
$
—
—
—
—
—
—
In January and February 2019, we closed a portion of our deferred premium put positions by selling offsetting put
positions and terminating contracts. We also added to our natural gas swap positions we had previously hedged. As of
February 28, 2019, we had hedged approximately 15.3 MBbl/d of our 2019 crude oil production at $68 per barrel.
For our purchased puts, we would receive settlement payments for prices below the indicated weighted-average
price per barrel of Brent. For some of our put positions, we paid the premium at the time the positions were created,
and for others, we will pay the premium at the time of settlement. In order to mitigate the exposure to these deferred
premiums, we have entered into several offsetting put positions. The purchased put options contain deferred premiums
of approximately $20 million and are reflected in the mark-to-market valuation of the derivatives on the balance sheet
at December 31, 2018. The premiums will be payable in conjunction with the monthly settlements of these contracts
and thus have been deferred until payments begin in 2019.
For fixed-price swaps, we make settlement payments for prices above the indicated weighted-average price per
barrel of Brent and receive settlement payments for prices below the indicated weighted average price per barrel of
Brent.
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 fixed-price natural 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.
120
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Our commodity derivatives are measured at fair value using industry-standard models with various inputs including
publicly available underlying commodity prices and forward curves, and all are classified as Level 2 in the required
fair value hierarchy for the periods presented. The following tables present the fair values (gross and net) of our
outstanding derivatives as of December 31, 2018 and December 31, 2017:
Berry Corp. (Successor)
December 31, 2018
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
Total derivatives
$
$
(in thousands)
89,981
$
3,289
(1,385)
91,885
$
Berry Corp. (Successor)
December 31, 2017
(1,385) $
—
1,385
— $
88,596
3,289
—
91,885
Balance Sheet
Classification
Gross Amounts
Recognized at Fair Value
Gross Amounts Offset
in the Balance Sheet
Net Fair Value Presented
in the Balance Sheet
Liabilities:
Commodity Contracts
Current liabilities
Commodity Contracts
Non-current liabilities
Total derivatives
$
$
(in thousands)
(49,949) $
(25,332)
(75,281) $
— $
—
— $
(49,949)
(25,332)
(75,281)
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 and Brent oil purchased put options for January 2019 through March 2020. These Brent
oil swaps hedged 1.8 MMBbls in 2018 and 0.9 MMBbls in 2019 at a weighted-average price of $75.66. These Brent
oil purchased put options provided a weighted-average price floor of $65.00 for 2.8 MMBbls in 2019 and 0.5 MMBbls
in 2020. We effected these transactions to move from a WTI-based position to a Brent-based position as well as bring
our hedge pricing more in line with market pricing at the time.
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.
121
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Gains (Losses) on Derivatives
A summary of gains and losses on the derivatives included on the statements of operations is presented below:
Gains (losses) on oil derivatives
Gains (losses) on natural gas derivatives
Lease operating expenses(1)
Total gains (losses) on oil and natural gas derivatives
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31,
2018
Ten Months
Ended
December 31,
2017
Two Months
Ended
February 28,
2017
Year Ended
December 31,
2016
(in thousands)
$
$
(4,621) $
(66,900)
$
12,886
$
(15,781)
6,357
—
—
—
—
—
—
(4,605)
(1,735) $
(66,900)
$
12,886
$
(20,386)
__________
(1) Consists of gains and (losses) on derivatives that were entered into in March 2015 to hedge exposure to differentials in consuming
areas.
For the year ended December 31, 2018, we paid net cash scheduled settlements of approximately $38 million,
excluding the payments for the early terminated derivatives. For the ten months ended December 31, 2017, the two
months ended February 28, 2017 and the year ended December 31, 2016, we received net cash settlements of
approximately $3 million, $0.5 million, and $10 million, respectively.
Note 7—Lawsuits, Claims, 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 the Plan. 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
December 31, 2018 and December 31, 2017. 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, 2018, we are not
aware of material indemnity claims pending or threatened against us.
We have certain commitments under contracts, including purchase commitments for goods and services. At
December 31, 2018, we had an obligation to provide improved road access in connection with our Piceance assets. Our
obligation is for a minimum $6 million, which could be higher if we elect to construct, or begin construction of the
road, in which case we are obligated to cover 100% of the first $9 million of construction costs plus 50% of the all
construction costs above $9 million. Alternatively, we can provide long-term access to an existing road. In addition,
122
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2018, 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:
2019
2020
2021
2022
2023
Thereafter
Total
(in thousands)
Minimum purchase obligations
Minimum lease payments
$
$
3,195 $
1,290 $
3,247 $
2,675 $
2,590 $
1,061
316 $
321 $
326 $
229 $
— $
— $
12,768
2,482
Note 8—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 Petroleum Corporation (the “Series A Certificate of
Designation”). Berry Corp. also adopted the Amended and Restated Bylaws of Berry Petroleum Corporation (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.
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 claimants to settle their claims and
subsequent to December 31, 2018 we issued approximately 2,770,000 shares instead of 7,080,000 to resolve these
claims.
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.
123
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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
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.
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 March 2018, the 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 per share and approximately
1,825,000 shares in total. Also in March 2018, the board of directors approved a $0.158 per share, or approximately
$5.6 million, cash dividend on the Series A Preferred Stock for the quarter ended March 31, 2018. In both cases, the
payments were to stockholders of record as of March 15, 2018 to be paid in April 2018.
Beneficial Conversion Feature
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.
The Registration Rights Agreement requires Berry Corp. to file a shelf registration statement with the SEC as soon
as practicable following 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.
124
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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
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, 2018, there were 81,202,438 shares of common stock issued and outstanding under the
Company's Omnibus Incentive Plan. An additional 922,952 unvested restricted stock units and performance restricted
stock units were outstanding under the Company's 2017 Omnibus Incentive Plan as of December 31, 2018. A further
7,080,000 common shares were reserved for issuance to the general unsecured creditor group (the “Unsecured Claims”)
pending resolution of disputed claims. Subsequent to December 31, 2018, we resolved such disputed claims by issuing
approximately 2,770,000 shares. See Note 2 under “Plan of Reorganization” and Note 14 for further discussion of the
common shares set aside to settle claims.
In March 2018, the 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 per share and approximately
1,825,000 shares in total. Also in March 2018, the board approved a $0.158 per share, or approximately $5.6 million,
cash dividend on the Series A Preferred Stock for the quarter ended March 31, 2018. In both cases, the payments were
to stockholders of record as of March 15, 2018. In May 2018, the board of directors approved a $0.15 per share, or
approximately $5.6 million, cash dividend on the Series A Preferred Stock for the quarter ended June 30, 2018. The
payment was to stockholders of record as of June 7, 2018. As described above, 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 following the IPO.
On August 21, 2018, our board of directors approved a $0.12 per share quarterly cash dividend on our common
stock on a pro-rated basis from the date of our IPO through September 30, 2018, which resulted in a payment of $0.09
per share in October 2018. On November 7, 2018, our board of directors approved a $0.12 per share quarterly cash
dividend on our common stock for the fourth quarter of 2018, which was paid in January 2019. On February 28, 2019,
our board of directors approved a $0.12 per share quarterly cash dividend on our common stock for the first quarter of
2019.
Purchase of rights to common stock
In 2018, we entered into several settlement agreements with general unsecured creditors from our bankruptcy
process. As a result, we paid approximately $20 million to purchase their claims to our common stock that we have
reflected as treasury stock.
125
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 Petroleum
to purchase shares during any period or at all. Any shares acquired will be available for general corporate purposes. In
December 2018, we repurchased 448,661 shares at an average price of $8.81 per share for $4 million, which is reflected
as treasury stock. The Company repurchased 1,932,096 shares from January 1, 2019 through February 28, 2019,
resulting in a total of 2,380,757 shares repurchased under the Stock Repurchase Program for $25 million as of
February 28, 2019.
Stock-Based Compensation
In July 2018, we became a public company and our stock began trading on the NASDAQ. As a result, 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 Berry Petroleum Corporation 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
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 8,381,902 as of December 31, 2018.
For the year ended December 31, 2018, ten months ended December 31, 2017 and two months ended February
28, 2017 the stock-based compensation expense was $7 million, $2 million and zero, respectively. For the year ended
December 31, 2018, stock-based compensation had an income tax benefit of approximately $1.5 million.
The table below summarizes the activity relating to restricted stock units (“RSUs”) issued under the 2017 Plan
during the year ended December 31, 2018. The RSUs vest ratably over three years. Unrecognized compensation cost
associated with the RSUs at December 31, 2018 was approximately $5 million which will be recognized over a weighted-
average period of approximately two years.
December 31, 2017
Granted
Vested
Forfeited
December 31, 2018
Number of
shares
Weighted-average
Grant Date Fair Value
(shares in thousands)
683
218
$
$
(239) $
(21) $
641
$
10.12
11.97
10.24
10.92
10.82
The table below summarizes the activity relating to the performance-based restricted stock units (“PSUs”) issued
under the 2017 Plan during the year ended December 31, 2018. The PSUs vest if the Company's stock price reaches
126
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
certain levels over defined periods of time. Unrecognized compensation cost associated with the PSUs at December 31,
2018 is approximately $1 million which will be recognized over a weighted-average period of approximately two years.
December 31, 2017
Granted
Vested
Forfeited
December 31, 2018
Number of
shares
Weighted-average
Grant Date Fair Value
(shares in thousands)
622
132
$
$
(454) $
(18) $
282
$
7.09
7.98
7.78
7.49
6.73
In November 2018, we granted equity awards to executive officers consisting of 40% RSUs and 60% PSUs, under
and pursuant to the terms of Omnibus Plan with the number of shares covered by such awards determined as of March
1, 2019. The time-vested RSUs will vest in equal annual increments over a three-year period with the first installment
vesting March 1, 2020, subject to continued employment. The PSUs will vest, if at all, based on our total stockholder
return, or the capital gains per share plus dividends paid assuming reinvestment over the performance period of July
26, 2018 through December 31, 2020.
Use of IPO Proceeds
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.
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 also directly sold an additional 2,545,630 shares at a price of $14.00 per share for which
we did not receive any proceeds.
Note 9—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 $1.4 million, $0.8 million, $0 and $0 for the year ended December 31, 2018, the ten
months ended December 31, 2017, the two months ended February 28, 2017 and the year ended December 31, 2016,
respectively, under the provisions of the 401(k) plan.
127
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 10—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 year 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 (15)% in the ten months ended December 31, 2017 to
23% for the year ended December 31, 2018 was the reduction in the valuation allowance. Our earnings for 2018 allowed
for the release of our valuation allowance, described below, resulting in an effective tax rate less than the statutory
federal and state tax rates.
Income tax expense (benefit) consisted of the following:
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31, 2018
Ten Months Ended
December 31, 2017
Two Months Ended
February 28, 2017
Year Ended
December 31, 2016
Current taxes:
Federal
State
Total current taxes
Deferred taxes:
Federal
State
Total deferred taxes
$
(465) $
(446)
(911)
33,227
10,719
43,946
Total current and deferred taxes
$
43,035
$
(in thousands)
465
450
915
1,888
—
1,888
2,803
$
$
— $
221
221
—
9
9
230
$
—
127
127
—
(11)
(11)
116
128
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31, 2018
Ten Months Ended
December 31, 2017
Two Months Ended
February 28, 2017
Year Ended
December 31, 2016
Federal statutory rate
State, net of federal tax benefit
Effect of permanent differences
Tax reform—rate change(1)
Income excluded from nontaxable entities
Change in valuation allowance
Effective tax rate
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)%
— %
— %
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.
Significant components of the deferred tax assets and liabilities are as follows:
Deferred tax assets:
Net operating loss carryforwards
Accruals
Asset retirement obligations
Derivative instruments
Tax credits
Interest limitation carryforward
Other
Subtotal
Valuation allowance
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,
2018
December 31,
2017
(in thousands)
$
14,310
$
2,993
26,383
—
—
7,486
2,033
53,205
—
53,205
(95,348)
(3,692)
(99,040)
$
(45,835) $
1,556
2,144
27,064
18,982
528
—
867
51,141
(7,748)
43,393
(45,281)
—
(45,281)
(1,888)
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, 2018, 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. Therefore, we have fully released the valuation allowance in 2018, resulting in an income tax benefit of
$7.7 million.
As of December 31, 2018, the Company had approximately $55 million of federal net operating loss (“NOL”)
carryforwards and $45 million of state net operating loss carryforwards. $25 million of federal net operating loss
carryovers have no expiration date and the remaining expire in 2037. State net operating loss carry forwards will expire
in varying amounts beginning in 2037.
129
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Act signed into law in 2017 imposed new limitations to Code Section 163(j), restricting the ability to deduct
interest paid or accrued on indebtedness. As of December 2018, we recorded a deferred tax asset for the benefit of the
interest deduction carryforward in the amount of $7.5 million. The interest carryforward has an indefinite life.
We had no material uncertain tax positions at December 31, 2018. We do not believe that it is reasonably possible
that the total unrecognized benefits will significantly increase within the next 12 months.
We are subject to taxation in the United States and various state jurisdictions. We are not currently under audit by
any federal or state taxing authority. The 2018 and 2017 federal and state tax returns remain open to examination under
the respective statute of limitations.
Note 11—Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows
Other current assets reported on the balance sheets included the following:
Prepaid expenses
Oil inventories, materials and supplies
Other
Other current assets
Berry Corp. (Successor)
December 31, 2018 December 31, 2017
$
$
(in thousands)
4,656
$
9,473
238
14,367
$
6,901
5,938
1,227
14,066
The major classes of inventory were not material and therefore not stated separately. Other non-current assets at
December 31, 2018 and December 31, 2017 included approximately $16 million and $20 million of deferred financing
costs, net of amortization, respectively.
Accounts payable and accrued expenses on the balance sheets included the following:
Berry Corp. (Successor)
December 31, 2018 December 31, 2017
Accounts payable-trade
Accrued expenses
Royalties payable
Greenhouse gas liability
Taxes other than income tax liability
Accrued interest
Dividends payable
Other
(in thousands)
$
13,564
$
66,417
26,189
—
10,766
10,500
9,992
6,689
Total accounts payable and accrued expenses
$
144,118
$
11,916
37,912
25,793
10,446
8,437
—
—
3,373
97,877
Other non-current liabilities at December 31, 2018 included approximately $15 million of greenhouse gas liability.
130
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Supplemental Cash Flow Information
Supplemental disclosures to the statements of cash flows are presented below:
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31,
2018
Ten Months
Ended
December 31,
2017
Two Months
Ended
February 28,
2017
Year Ended
December 31,
2016
(in thousands)
Supplemental Disclosures of Significant Non-Cash Investing
Activities:
Increase (decrease) in accrued liabilities related to purchases
of property and equipment
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized
Income taxes
Reorganization items, net
$
$
$
$
19,257
$
2,483
19,761
$
14,276
(1,901) $
832
$
1,994
1,732
$
$
$
$
2,249
$
2,266
8,057
$
57,759
— $
347
11,838
$
19,116
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)
Berry LLC (Predecessor)
December 31,
2018
December 31,
2017
February 28,
2017
December 31,
2016
(in thousands)
$
$
$
$
33,905
$
34,833
—
32,049
52,860
125
$
30,483
$
1,023
197,793
250,359
128
128
68,738
$
85,034
$
228,404
$
251,510
68,680
$
—
—
33,905
34,833
—
$
32,049
$
30,483
52,860
125
197,793
128
68,680
$
68,738
$
85,034
$
228,404
Restricted cash is associated with cash reserved to settle claims with general unsecured creditors resulting from
implementation of the Plan. 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.
131
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 12—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. See
Note 8 - Equity for further details.
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. Additionally, Berry LLC paid to Linn Energy a management fee equal to $6 million per
month, prorated for partial months, during the period from the Effective Date through the last day of the second full
calendar month after the Effective Date (the “Transition Period”) and $2.7 million per month, prorated for partial
months, from the first day following the Transition Period through the last day of the second full calendar month
thereafter (the “Accounting Period”). During the Accounting Period, the scope of the transition services was reduced
to specified accounting and administrative services. The Transition Period under the TSSA ended April 30, 2017, and
the Accounting Period ended June 30, 2017. For the seven months ended September 30, 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 13—Acquisitions and Divestitures
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.
Chevron North Midway-Sunset Acquisition
In April 2018, we acquired 2 leases on an aggregate of 214 acres and a lease option on 490 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 had not drilled any of these wells as of December 31, 2018. We would assume an additional 40
well drilling commitment if we exercise our option on the 490 acres. 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 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.
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.
132
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 14—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.
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 each period. Common shares issuable upon the
satisfaction of certain conditions pursuant to a contractual agreement, such as those shares contemplated by the Plan,
are considered common shares outstanding and are included in the computation of net income (loss) per share. The
Plan required that we reserve 7,080,000 shares of our common stock to settle claims of unsecured creditors. These
shares were previously included in the 40 million shares of common stock contemplated by the Plan, without regard
to actual issuance dates. Prior to the finalization and issuance of these shares, the computation of net income (loss) per
share included the 7,080,000 reserved shares. In March 2019, we finalized settlement of these claims, 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.
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, 2018 as their effect was anti-dilutive
under the “if-converted” method. The RSUs are not a participating security as the dividends are forfeitable. The
incremental RSU shares of 189,000 were included in the diluted EPS calculation for the year ended December 31, 2018
as their effect was dilutive under the “if-converted” method. No incremental shares of Series A Preferred Stock or 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 any of the periods presented
due to their contingent nature.
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 8). 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.
133
BERRY PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Berry Corp. (Successor)
Berry LLC (Predecessor)
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)
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
Basic Earnings (loss) per share(2)
Diluted EPS calculation
Net income (loss)
less: Series A Preferred Stock dividends and conversion to
common stock
Net loss attributable to common stockholders
Weighted-average shares of common stock outstanding
Dilutive effect of potentially dilutive securities(1)
Weighted-average common shares outstanding-diluted
Diluted Earnings (loss) per share(2)
$
147,102
$
(21,068)
(97,942)
(18,248)
49,160
57,743
0.85
147,102
$
$
$
(39,316)
38,644
(1.02)
(21,068)
(97,942)
(18,248)
49,160
$
(39,316)
57,743
189
57,932
38,644
—
38,644
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
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) 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.
(2) Per share amounts are stated net of tax.
134
BERRY PETROLEUM CORPORATION
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(Unaudited)
Berry Corp. (Successor)
Quarters Ended
March 31
June 30
September 30
December 31
(in thousands, except per share amounts)
97,284
91,121
$
$
— $
8,955
6,410
760
0.02
0.02
$
$
$
$
$
65,982
90,458
123
456
$
$
$
$
(28,061) $
142,947
102,130
400
13,781
36,985
$
$
$
$
$
280,346
104,743
(3,269)
1,498
131,768
(33,711) $
(49,657) $
131,768
(0.94) $
(0.94) $
(0.70) $
(0.70) $
1.56
1.56
Berry Corp.
(Successor)
One Month
Ended
March 31
(in thousands, except per share amounts)
June 30
Quarters Ended
September 30
December 31
59,655
37,783
$
$
134,721
113,380
— $
5
$
$
$
69,910
101,397
$
$
55,382
92,189
(20,692) $
(2,243)
1,306
11,377
9,585
0.25
0.15
$
$
$
$
$
(713) $
408
$
730
12,119
6,715
0.17
0.16
$
$
$
$
(9,684) $
(34,880)
(15,169) $
(40,447)
(0.39) $
(0.39) $
(1.05)
(1.05)
2018:
Total revenues and other(1)
Total expenses(2)
(Gains) losses on sale of assets and other, net
Reorganization items, net, expense (income)
Net income (loss)
Net income (loss) attributable to common stockholders
Earnings (loss) per share attributable to common
stockholders:
Basic(4)
Diluted(4)
Berry LLC
(Predecessor)
Two Months
Ended
February 28
$
$
$
$
$
$
92,718
79,607
(183)
507,720
(502,964)
(502,964)
n/a
n/a
2017:
Total revenues and other(1)
Total expenses(2)
(Gains) losses on sale of assets and other,
net
Reorganization items, net, expense
(income)
Net income (loss)
Net income (loss) attributable to common
stockholders
Earnings (loss) per share attributable to
common stockholders:
Basic(3)(4)
Diluted(3)(4)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
135
BERRY PETROLEUM CORPORATION
SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Continued)
(Unaudited)
Berry LLC (Predecessor)(3)
Quarters Ended
March 31
June 30
September 30
December 31
(in thousands)
2016:
Total revenues and other(1)
Total expenses(2)
(Gains) losses on sale of assets and other, net
Reorganization items, net expense (income)
$
91,266
$ 1,196,393
$
$
108,639
133,868
(192) $
425
$
$
$
113,225
111,600
$
$
97,861
118,207
(370) $
28
— $
(49,086) $
87,915
$
33,833
$
$
Net income (loss)
$ (1,124,819) $
6,840
$
(98,438) $
(66,779)
__________
(1)
(2)
Includes net derivative gains (losses) for oil sales derivatives.
Includes the following expenses: lease operating, electricity generation, transportation, marketing, general and administrative, depreciation,
depletion and amortization, impairment of long-lived assets, taxes, other than income taxes, and gains or losses on natural gas derivatives.
(3) Our predecessor company was organized as a limited liability company and, as such, did not issue any stock. Accordingly, we have not presented
(4)
earnings per share calculations for the predecessor company periods.
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 14 of our consolidated financial statements for further information.
136
BERRY PETROLEUM CORPORATION
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)
Berry LLC (Predecessor)
Year Ended
December 31,
2018
Ten Months
Ended
December 31,
2017
Two Months
Ended
February 28,
2017
Year Ended
December 31,
2016
(in thousands)
$
— $
249,338
$
— $
1,545
—
—
—
—
143,002
60,381
—
—
4,544
$
143,002
$
309,719
$
4,544
$
—
—
13,091
14,636
__________
(1)
Included in development costs for the year ended December 31, 2018 are non-cash additions related to the estimated future asset retirement
obligations of the Company's oil and gas properties of $3.4 million.
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, 2018
December 31, 2017
(in thousands)
1,168,245
$
388,034
1,556,279
(132,587)
911,478
517,037
1,428,515
(58,525)
1,423,692
$
1,369,990
$
$
137
BERRY PETROLEUM CORPORATION
SUPPLEMENTAL OIL & NATURAL GAS DATA (Continued)
(Unaudited)
Results of Oil and Natural Gas Producing Activities
The results of operations for oil, natural gas and NGL producing activities (excluding items such as corporate
overhead, interest costs and reorganization items, net) are presented below:
Net revenues from production:
Oil, natural gas and NGL sales
Electricity sales
Other production-related revenue
Total net revenues from production
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
Berry Corp. (Successor)
Berry LLC (Predecessor)
Year Ended
December 31,
2018
Ten Months
Ended
December 31,
2017
Two Months
Ended
February 28,
2017
Year Ended
December 31,
2016
(in thousands)
$
552,874
$
357,928
$
74,120
$
392,345
35,208
2,908
21,972
6,569
590,990
386,469
3,655
2,003
79,778
23,204
10,899
426,448
188,776
20,619
9,860
1,876
33,117
2,140
149,599
28,238
185,056
14,894
19,238
5,786
34,211
2,320
3,197
6,194
—
5,212
653
17,133
41,619
—
24,982
3,100
Total operating costs for production
256,388
226,048
43,494
271,890
Other costs:
Depreciation, depletion and amortization
Impairment of long-lived assets
(Gains) losses on sale of assets and other, net
Total other costs
Pretax income (loss)
Income tax expense
Results of operations
81,927
—
(2,747)
79,180
255,422
69,807
67,051
—
(22,930)
44,121
116,300
45,887
26,743
169,605
—
—
1,030,588
(7)
26,743
1,200,186
9,541
(1,045,628)
230
116
$
185,615
$
70,412
$
9,311
$ (1,045,743)
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 10 for additional information about income taxes.
138
BERRY PETROLEUM CORPORATION
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, 2018, December 31, 2017 and December 31,
2016 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, 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
139
BERRY PETROLEUM CORPORATION
SUPPLEMENTAL OIL & NATURAL GAS DATA (Continued)
(Unaudited)
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
Total proved reserves:
Beginning of year (Predecessor)
Revisions of previous estimates
Extensions and discoveries
Production
End of year (Predecessor)
Proved developed reserves:
Beginning of year (Predecessor)
End of year (Predecessor)
Proved undeveloped reserves:
Beginning of year (Predecessor)
End of year (Predecessor)
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
Year Ended December 31, 2016
Oil
MBbls
NGLs
MBbls
Natural Gas
MMcf
Total
MBoe
93,892
(31,350)
1,797
(8,463)
55,876
93,892
55,422
—
454
16,953
(568)
—
(1,307)
15,078
16,953
15,078
—
—
387,848
13,311
178
(28,577)
372,760
387,848
372,760
—
—
175,487
(29,701)
1,827
(14,533)
133,080
175,487
132,626
—
454
The tables above include changes in estimated quantities of natural gas reserves shown in Boe using the ratio of
six Mcf to one barrel.
140
BERRY PETROLEUM CORPORATION
SUPPLEMENTAL OIL & NATURAL GAS DATA (Continued)
(Unaudited)
Proved reserves increased by approximately 1,335 MBoe to approximately 142,720 MBoe for the year ended
December 31, 2018, from 141,385 MBoe for the year ended December 31, 2017. The year ended December 31, 2018,
includes 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). In addition, extensions and discoveries, principally in our California properties, most of which was
thermal Diatomite, as well as in Utah, contributed approximately 22,362 MBoe to the increase in proved reserves.
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).
Proved reserves decreased by approximately 42,407 MBOE to approximately 133,080 MBOE for the year ended
December 31, 2016, from 175,487 MBOE for the year ended December 31, 2015. The year ended December 31, 2016,
includes approximately 29,701 MBOE of negative revisions of previous estimates (22,729 MBOE due to asset
performance and 6,972 MBOE due to lower commodity prices). In addition, extensions and discoveries, primarily from
23 productive wells drilled during the year, contributed approximately 1,827 MBOE to the increase in proved reserves.
141
BERRY PETROLEUM CORPORATION
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. There are no future
income tax expenses for the Predecessor because the Predecessor was not subject to federal income taxes. Limited
liability companies are subject to Texas margin tax; however, these amounts were not material. See Note 10 for additional
information about income taxes.
Future cash inflows
Future production costs
Future development costs
Future income taxes(1)
Future net cash flows
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future net cash flows
Representative prices:(2)
ICE Brent Oil (Bbl)
NYMEX Henry Hub Natural gas (MMBtu)
NYMEX WTI Oil (Bbl)
Berry Corp. (Successor)
December 31,
2018
December 31,
2017
Berry LLC
(Predecessor)
December 31,
2016
(in thousands, except for prices)
$
8,119,309
$ 5,580,448
$
3,131,758
(3,357,149)
(2,725,548)
(1,893,608)
(884,055)
(757,470)
(678,312)
(365,330)
3,120,635
1,811,258
(1,359,089)
(833,910)
(220,374)
—
1,017,776
(421,554)
$
1,761,546
$
977,348
$
596,222
$
$
71.54
3.10
$
$
54.42
2.98
$
$
2.48
42.64
__________
(1) Future income taxes are based on current statutory rates, adjusted for the tax basis of oil and gas properties and applicable tax credits, deductions
(2)
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.
142
BERRY PETROLEUM CORPORATION
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,
2018
December 31,
2017
(in thousands)
Berry LLC
(Predecessor)
December 31,
2016
Standardized measure—beginning of year
$
977,348
$
596,222
$
995,372
Sales and transfers of oil, natural gas and NGLs produced during the
period
Changes in estimated future development costs
Net change in sales and transfer prices and production costs related to
future production
Extensions, discoveries and improved recovery
Purchase of minerals in place
Sales of minerals in place
Previously estimated development costs incurred during the period
Net change due to revisions in quantity estimates
Accretion of discount
Net change in income taxes
Changes in production rates and other
Net increase (decrease)
Standardized measure—end of year
(321,148)
(189,355)
35,313
6,399
(140,688)
66,386
818,705
224,064
(242,982)
363,450
5,240
(5,593)
78,803
(175,947)
111,416
157,717
317,616
(141,998)
6,913
124,609
59,622
(253,176)
(136,810)
127,135
784,198
(47,651)
381,126
21,610
—
—
—
(158,474)
99,537
—
(44,539)
(399,150)
$
1,761,546
$
977,348
$
596,222
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.
143
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, we have evaluated, under the supervision and with
the participation of our management, including our principal executive officer and principal financial officer, the
effectiveness of the design and operation 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, 2018. 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, 2018 at the reasonable assurance level.
Management’s Annual Report on Internal Control Over Financial Reporting
This annual report does not include a report of management’s assessment regarding internal control over
financial reporting or an attestation report of our registered public accounting firm due to a transition period
established by the rules of the SEC for newly public companies.
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. The Company’s internal
controls were designed to provide reasonable assurance as to the reliability of its financial reporting and the
preparation and presentation of the financial statements for external purposes in accordance with accounting
principles generally accepted in the U.S.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent
misstatements. 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.
There were no changes in the Company’s internal control over financial reporting during the fourth quarter of
2018 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over
financial reporting.
Item 9B. Other Information
None
144
Item 10. Directors, Executive Officers and Corporate Governance
Part III
The information required by this Item 10 is incorporated herein by reference from our definitive Proxy Statement,
for the 2019 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2018 where it will appear in the (i) Directors and Executive Officers section, (ii) The Board and Its
Committees – Audit Committees, (iii) Other Information section – Section 16(a) Beneficial Ownership Reporting
Compliance and (iv) Corporate Governance – Code of Ethics.
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 from our definitive Proxy Statement,
for the 2019 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2018 where it will appear in the Executive Compensation and Other Information section.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required by this Item 12 is incorporated herein by reference from our definitive Proxy Statement,
for the 2019 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2018 where it will appear in the Certain Relationships and Related Party Transactions section.
Item 13. Certain Relationships and Related Transactions and Director Independence
The information required by this Item 13 is incorporated herein by reference from our definitive Proxy Statement,
for the 2019 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2018 where it will appear in the (i) Certain Relationships and Related Party Transactions section and
(ii) The Board and Its Committees - Director Independence sections.
Item 14. Principal Accounting Fees and Services
The information required by this Item 14 is incorporated herein by reference from our definitive Proxy Statement,
for the 2019 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days
of December 31, 2018 where it will appear in the Proposal No. 2 - Ratification of Independent Registered Public
Accounting Firm.
145
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 Amended and Restated Certificate of Incorporation of Berry Petroleum Corporation (incorporated by
reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 (File No. 333-226011))
3.2 Certificate of Amendment of Certificate of Incorporation (incorporated by reference to Exhibit 3.2 of
Form 8-K filed July 30, 2018)
3.3 Second Amended and Restated Bylaws of Berry Petroleum Corporation (incorporated by reference to
Exhibit 3.3 of Form 8-K filed July 30, 2018)
3.4 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))
3.5 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))
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
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)
146
Exhibit
Number
Description
10.11† Amended and Restated Berry Petroleum Corporation 2017 Omnibus Incentive Plan, dated March 7,
2018 (incorporated by reference to Exhibit 10.8 to the Company’s Registration Statement on Form S-1
(File No. 333-226011))
10.12† Berry Petroleum Corporation Form of Restricted Stock Unit Award Agreement for Employees other
than Executive Vice Presidents (incorporated by reference to Exhibit 10.9 to the Company’s Registration
Statement on Form S-1 (File No. 333-226011))
10.13† Berry Petroleum Corporation Form of Restricted Stock Unit Award Agreement for Executive Vice
Presidents (incorporated by reference to Exhibit 10.10 to the Company’s Registration Statement on Form
S-1 (File No. 333-226011))
10.14† Berry Petroleum Corporation Form of Director Restricted Stock Unit Award Agreement (incorporated
by reference to Exhibit 10.11 to the Company’s Registration Statement on Form S-1 (File No.
333-226011))
10.15† Berry Petroleum Corporation Form of Performance-Based Restricted Stock Unit Award Agreement for
Employees other than Executive Vice Presidents (incorporated by reference to Exhibit 10.12 to the
Company’s Registration Statement on Form S-1 (File No. 333-226011)
10.16† Berry Petroleum Corporation Form of Performance-Based Restricted Stock Unit Award Agreement for
Executive Vice Presidents (incorporated by reference to Exhibit 10.13 to the Company’s Registration
Statement on Form S-1 (File No. 333-226011)
10.17† Second Amended and Restated Berry Petroleum Corporation 2017 Omnibus Incentive Plan, dated June
27, 2018 (incorporated by reference to Exhibit 4.3 of S-8 Registration Statement (File No. 333-226582))
10.18† Berry Petroleum Corporation 2017 Omnibus Incentive Plan dated June 15, 2017 (incorporated by
reference to Exhibit 10.15 to the Company’s Registration Statement on Form S-1 (File No. 333-226011))
10.19†* Berry Petroleum Corporation Form of Restricted Stock Unit Award Agreement for Employees other
than Executive Officers
10.20†* Berry Petroleum Corporation Form of Restricted Stock Unit Award Agreement for Executive Officers
10.21†* Berry Petroleum Corporation Form of Restricted Stock Unit Award Agreement for Directors
10.22†* Berry Petroleum Corporation Form of Performance-Based Restricted Stock Unit Award Agreement for
Employees other than Executive Officers
10.23†* Berry Petroleum Corporation Form of Performance-Based Restricted Stock Unit Award Agreement for
Executive Officers
10.24 Form of Indemnification Agreement (incorporated by reference to Exhibit 10.16 to the Company’s
Registration Statement on Form S-1 (File No. 333-226011))
10.25 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))
10.26 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))
10.27 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))
10.28 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)
10.29 Stock Purchase Agreement by and between Berry Petroleum Corporation, Oaktree Value Opportunities
Fund Holdings, L.P. and Oaktree Opportunities X Fund Holdings (Delaware), L.P. dated July 17, 2018
(incorporated by reference to Exhibit 10.2 of Form 8-K filed July 30, 2018)
147
Exhibit
Number
Description
10.30 Stock Purchase Agreement by and between Berry Petroleum Corporation and certain funds affiliated
with Benefit Street Partners named in Schedule I thereto, dated July 17, 2018 (incorporated by reference
to Exhibit 10.3 of Form 8-K filed July 30, 2018)
21.1* List of Subsidiaries of Berry Petroleum Corporation
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, 2018 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.
148
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:
“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 non-recurring restructuring and other 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” is an abbreviation 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.
“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.
149
“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.
“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.
“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.
“Enhanced oil recovery” or “EOR” means a technique for increasing the amount of oil that can be extracted from
a field.
“EPA” is an abbreviation for the United States Environmental Protection Agency.
“ESA” is an abbreviation for the federal Endangered Species Act.
“Estimated ultimate recovery” or “EUR” means the sum of reserves remaining as of a given date and cumulative
production as of that date. As used in this report, EUR includes only proved reserves attributable to each location in
our reserve report as of December 31, 2017 and is based on our reserve estimates. EUR is shown on a combined basis
for oil and natural gas.
“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.
“Formation” means a layer of rock which has distinct characteristics that differ from those of nearby rock.
150
“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 stimulation” means a procedure to stimulate production by forcing a mixture of fluid and proppant
(usually sand) into the formation under high pressure to increase 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.
“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.
“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.
151
“MMcf” means one million cubic feet, which is a unit of measurement of volume for natural gas.
“MMcf/d” means MMcf per day.
“MW” means megawatt.
“NAAQS” is an abbreviation for the National Ambient Air Quality Standard.
“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.
“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.
“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.
“Porosity” means the total pore volume per unit volume of rock.
“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).
152
“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 stimulation fluid to hold rock open after a hydraulic stimulation
treatment.
“Prospect” means a specific geographic area which, based on supporting geological, geophysical or other data and
also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the
discovery of commercial hydrocarbons.
“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods.
“Proved developed producing reserves” means reserves that are being recovered through existing wells with existing
equipment and operating methods.
“Proved reserves” means the estimated quantities of oil, gas and gas liquids, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward,
from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior
to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably
certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract
the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project
within a reasonable time.
“Proved undeveloped drilling location” means a site on which a development well can be drilled consistent with
spacing rules for purposes of recovering proved undeveloped reserves.
“Proved undeveloped reserves” or “PUDs” means proved reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably
certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty
of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped
reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years,
unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves 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.
“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. 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.
“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).
153
“Recompletion” means the completion for production from an existing wellbore in a formation other than that in
which the well has previously been completed.
“Reserves” means estimated remaining quantities of oil and natural gas and related substances anticipated to be
economically producible, as of a given date, by application of development projects to known accumulations. In addition,
there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue
interest in the production, installed means of delivering oil and natural gas or related substances to market and all
permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated
by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.
Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive
reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain
prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible
natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other
reservoirs.
“Resources” means quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A
portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable.
Resources include both discovered and undiscovered accumulations.
“Royalty” means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil
and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the
affected well.
“Royalty interest” means an interest in an oil and natural gas property entitling the owner to shares of oil and natural
gas production, free of costs of exploration, development and production operations.
“SDWA” is an abbreviation for the Safe Drinking Water Act, which governs the underground injection and disposal
of wastewater;.
“SEC” is an abbreviation for the Securities and Exchange Commission.
“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.
154
“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.
“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.
“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:
March 7, 2019
BERRY PETROLEUM CORPORATION
/s/ A. T. Smith
A. T. “Trem” Smith
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date
Signature
Title
March 7, 2019
/s/ A. T. Smith
President and Chief Executive Officer, and Director
A. T. “Trem” Smith
(Principal Executive Officer)
March 7, 2019
March 7, 2019
March 7, 2019
March 7, 2019
March 7, 2019
March 7, 2019
March 7, 2019
/s/ Cary Baetz
Cary Baetz
/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
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
2018 Adjusted
EBITDA* of
$258M
2018 Cash Flows
from Operations of
$230M
(excluding $127 million for
hedge early termination)
California PV-10* of
$2 billion out of
$2.2 billion total
Replaced
275%
reserves* in
California
and 114%
of total
company
reserves
Letter to shareholders
Value Focused
completed in 2018, increasing our
2018 was monumental for Berry. By
acreage position in the Midway
executing our simple and clear business
Sunset Field by about 20%.
model, Berry was and continues to be
wholly focused on value creation for
its shareholders. Our goal is always to
generate growth while operating within
our levered free cash flow. We manage
to value and not just to volume growth
and we did this in 2018 with excellence,
realizing operational efficiencies,
production growth and incident
prevention improvements.
Most notably on July 26, just a short
16 months after emerging from
bankruptcy, we began trading on the
Nasdaq, reinforcing our strong position
in the industry and value in the market.
California Focus
Last year was all about California,
where we produced 100% oil, spent
most of our capital, and realized
all of our production growth as
well as the preponderance of our
operating income. As a result, we
added more than $1 billion to our
PV-10* valuation and accomplished a
275% reserve* replacement ratio. Our
operations are focused in California,
too. Approximately 70% of our total
company production came from
the world-class super basin, the San
Joaquin Basin, and approximately
94% of the production is in Kern
County alone. Just three fields on
County alo
the west side of the Basin (Belridge,
the west s
McKittrick and Midway Sunset) made
McKittrick
up 80% of our production in California
up 80% o
and 59% of our total production. We
and 59%
remain focused on thermal recovery
remain fo
of heavy oil in shallow, conventional
of heavy
reservoirs—perfect for the refineries in
reservoir
California. Finally, we drilled 224 wells
California
in California in 2018, resulting in a 15%
in Califor
production increase.
producti
Further, our bolt-on strategy, the
Further,
addition of low-risk acreage near
addition
Future Focus
Looking ahead, our focus isn’t changing
in 2019. We currently have, and expect
to continue to have, four rigs running,
all in California.
We will direct even more capital
to California than we did in 2018
where we expect a mid- to high-
teen production exit growth rate and
continued significant reserve growth.
In 2019, we forecast approximately
94% of our capital including 98%
of our development capital to be
spent in California and plan to drill
approximately 400 wells.
We are in a great position for continued
improvement to maximize the value of
our existing fields while continuously
looking for growth through bolt-ons
and strategic acquisitions. We have
several bolt-on opportunities under
negotiations, which, if fully executed,
could grow our acreage position in
Midway Sunset by more than 50%.
Berry’s future looks bright. Our
technical assessment of our current
resource and original oil in place
indicates that a simple 1% increase
in recovery factor could result in
the addition of more than 20 million
barrels of oil in California.
Berry First Focus
We are dedicated to our Berry First
approach—to be the leader in this
industry. With the commitment of
all 325+ employees, we will continue
to execute our plan with excellence,
growing our company and, as always,
creating value for our shareholders.
our existing production and
infrastructure, was effective.
We now have access to 879
new acres through bolt-ons
A.T. (TREM) SMITH
Board Chair, Chief Executive Officer
& President
Berry Petroleum Corporation
* For definitions and GAAP reconciliations, see Form 10-K “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations—Non-GAAP Financial Measures” and “Items 1 and 2. Business
and Properties—Our Reserves and Production Information”. Reserves replacement ratio is calculated by
dividing the sum of proved reserve extensions and discoveries, revisions of previous estimates, improved
recovery and purchases and sales of minerals in place for the year by current year production. There is no
guarantee that historical sources of reserves additions will continue.
DIRECTORS
A.T. (TREM) SMITH
Board Chair, Chief Executive Officer
& President
Berry Petroleum Corporation
CARY BAETZ
Executive Vice President
& Chief Financial Officer
Berry Petroleum Corporation
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
EXECUTIVE OFFICERS
A.T. (TREM) SMITH
Board Chair, Chief Executive Officer
& President
CARY BAETZ
Executive Vice President
& Chief Financial Officer
GARY GROVE
Executive Vice President
& Chief Operating Officer
KURT NEHER
Executive Vice President,
Business Development
KENDRICK ROYER
Executive Vice President,
General Counsel & Corporate Secretary
GENERAL SHAREHOLDER INFORMATION
Shareholders and members of the investment
community should direct inquiries to:
INVESTOR RELATIONS
Todd Crabtree
Berry Petroleum Corporation
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
United States
Shareholder Services
(718) 921-8200
www.astfinancial.com
SECURITIES
Berry Common Stock is traded on
Nasdaq under the symbol BRY.
FORM 10-K
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.
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/us/en/home
(C) Committee Chair
(1) Audit Committee (2) Compensation Committee
(3) Nominating & Corporate Governance Committee
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 acquisition
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 and meet working capital
requirements; price and availability of natural gas; ability to hedge
price risk; impact of governmental regulations, and of current, pending
or future legislation; proved reserves estimation uncertainties; ability
to replace our reserves; availability of permits; drilling risk; 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”.
Founded on Value.
Focused on Growth.
2018 ANNUAL REPORT
Front and back photography courtesy of Nasdaq, Inc.
INVESTOR RELATIONS
Berry Petroleum Corporation
16000 N. Dallas Pkwy, Ste. 500
Dallas, TX 75248
(661) 616-3811
ir@bry.com
berrypetroleum.com