Berry Corporation (bry) (NASDAQ: BRY) (“Berry” or the “Company”)
today reported an 18% increase in fourth quarter 2019 production
from its California assets over the prior year fourth quarter and
it replaced nearly 300% of its California proved reserves. For the
full year of 2019, Berry's net income was $44 million, or $0.53 per
diluted share, and Adjusted Net Income(1) was $110 million, or
$1.35 per diluted share. For the fourth quarter of 2019, the net
loss was $7 million, or $0.09 per diluted share, and Adjusted Net
Income was $33 million, or $0.41 per diluted share. In addition,
the Board approved a first quarter 2020 dividend of $0.12 per
share, as it has done each quarter since becoming a public company
in 2018. The Board also approved the opportunistic repurchase of an
additional $50 million shares pursuant to the previously announced
$100 million share repurchase program.
Highlights for the Quarter
- California production increased 18% over prior year fourth
quarter and 11% sequentially
- Fourth quarter production mix was 89% oil
- Adjusted EBITDA(1) of $87 million and Unhedged Adjusted
EBITDA(1) of $72 million
- Capital expenditures of $42 million with approximately 84%
directed to development in California
- Repurchased 1.4 million shares in fourth quarter and nearly 5.1
million shares to date for $50 million
“We had a great fourth quarter and 2019. Our
business model works and when we invest capital in development
drilling, our assets respond, creating additional value. Our top
tier returns and strong production and reserve profile, achieved
while generating excess levered free cash flow, demonstrate the
strength of our financial principles. In 2019, we grew California
oil production more than 15% year over year; increased our
California reserves, entirely oil, 23% before production on a
year-over-year basis; and we paid $85 million to return capital to
our shareholders by repurchasing 6% of our outstanding shares while
continuing to pay one of the highest dividend yields in the
industry. In 2020, you can expect more of the same from
Berry. We are committed to generating strong oil growth on a lower
capital spend; continuing our substantial return of capital and, at
today’s pricing, generating solid excess levered free cash flow,”
stated Trem Smith, Berry board chair, chief executive officer and
president.
Highlights for the Full Year
- Oil production up 15% compared to prior year and comprised 87%
of total production
- Adjusted EBITDA of $302 million and Unhedged Adjusted EBITDA of
$260 million
- Capital expenditures of $211 million with approximately 91%
directed to California assets
- Repurchased 4.6 million shares for $46 million and paid over
$39 million in dividends
- Replaced nearly 300%(2) of California reserves and 159%(2) of
total company PUD inventory
- Increased inventory to over 10,800 locations
- Total company PV-10(1) of over $1.8 billion, including $1.7
billion for California
__________
(1) Please see "Non-GAAP Financial
Measures and Reconciliations" later in this press release for a
reconciliation and more information on these Non-GAAP measures.
(2) Please see " Non-GAAP Financial
Measures and Reconciliations" later in this press release for more
information on how we calculate reserve replacement ratios and
total company PUD inventory replacement ratios.
Smith continued, “In California, we remain
steadfast in our commitment to the state and its ambitious
environmental initiatives. We have sharpened our focus on
Environmental, Social, and Governance (ESG) reporting, and we are
formalizing how we monitor and manage our ESG performance and
engage with our stakeholders on these important issues. We believe
that the oil and gas industry will remain an important part of the
energy landscape for the long term. In California, specifically,
that means locally producing and supplying affordable and reliable
energy to ensure a safe, healthy and prosperous future for its
communities and citizens, and reducing California’s reliance upon
imported foreign oil that comes from countries that do not share
our environmental and social justice standards and
expectations.”
Fourth Quarter 2019 Results
Adjusted EBITDA for the fourth quarter 2019
increased to $87 million, compared to $84 million in the third
quarter 2019, primarily due to increased production. Adjusted
EBITDA, on an unhedged basis, was $72 million in the fourth quarter
2019 compared to $69 million in the third quarter 2019.
Levered Free Cash Flow(1) for the fourth quarter
2019 was $28 million, after $42 million of capital expenditures, $8
million of interest and $10 million of dividends declared.
Additionally, the Company repurchased 1.4 million shares in the
fourth quarter for approximately $11 million.
Average daily production in the fourth quarter
2019 of 31,300 Boe/d was 12% higher than the prior year fourth
quarter and increased 6% compared to the third quarter 2019 driven
by our development capital spending in 2019. California production
of 25,500 MBoe/d for the fourth quarter 2019 was up 18% over the
prior year and 11% sequentially to the third quarter 2019.
California oil prices before hedges for the
fourth quarter 2019 averaged $60.20/Bbl which was 2% higher than
the $59.00/Bbl realized in the third quarter 2019. Company-wide
realized oil prices before hedges of $59.28/Bbl was also 2% higher
in the fourth quarter 2019 compared to the third quarter 2019.
For the fourth quarter 2019, Operating Expenses
("OpEx") increased to $20.37/Boe compared to $18.90/Boe in the
third quarter. This increase in OpEx was primarily due to higher
hedged fuel gas price and management’s continuing efforts to
aggressively manage repair and maintenance activities, in
particular, some inherited long-term delayed maintenance on some
equipment.
Total general and administrative ("G&A")
expenses for the fourth quarter decreased almost $0.60/Boe to
$5.46/Boe compared to the third quarter due to increased production
and year-end incentive compensation true-ups. Adjusted G&A(1)
also decreased for the same reasons in the fourth quarter to
$4.66/Boe compared to $5.13/Boe for the third quarter.
Taxes, other than income taxes were $4.16/Boe
for the fourth quarter, compared to $3.40/Boe in the third quarter,
largely due to increased market rates for our greenhouse gas
allowance requirements.
Capital expenditures, which were largely focused
on drilling in California, decreased to $42 million for the fourth
quarter compared to $63 million for the third quarter, in both
periods largely focused on drilling in California. Consistent with
our 2019 plan, we reduced our fourth quarter drilling activity
compared to the rest of the year, while we spent additional capital
preparing for our 2020 capital program. In Utah, the Company
drilled two wells, and completed a third well that was drilled in
the prior quarter.
In addition to the proved reserve increases in
California, total company proved undeveloped drilling locations
increased 159% for the year. This increase was offset by the
reduction in proved undeveloped reserves in its Piceance natural
gas properties in Colorado, triggered by the decline in gas prices
and management’s intention to continue investing capital in
California and Utah while this low gas price in the Colorado market
persists. As a result, the Company recorded a non-cash,
pre-tax asset impairment charge of $51 million in
the fourth quarter. Also in the fourth quarter, the Company
recorded a $37 million tax benefit related to tax credits taken in
recently filed federal returns.
Full Year 2019 Results
Adjusted EBITDA increased 17% to $302 million for the full year
2019 from $258 million in 2018 primarily due to the 15% increase in
oil production. This increase was partially offset by increased
OpEx, G&A, taxes other than income taxes and decreased oil
prices. Adjusted EBITDA, on an unhedged basis, was $260 million in
2019 compared to $296 million in 2018.
For the year, increased Adjusted EBITDA
supported positive Levered Free Cash Flow of nearly $20 million,
which included $211 million of capital expenditures, $34 million of
interest and $39 million of dividends declared. Additionally,
the Company spent approximately $46 million in the year to
repurchase 4.6 million shares, or approximately 6% of outstanding
shares and approximately $50 million cumulatively for the program,
begun in late 2018.
Year-over-year California production increased
15%, while overall production increased 7% due to production
response from the development capital spending throughout 2019 and
2018, which more than offset the natural decline of our properties
and the sale of our East Texas properties in November 2018.
For 2019, California oil prices before hedges
averaged $60.51/Bbl which was 8% lower than the $65.64/Bbl realized
in 2018. Realized oil prices before hedges for the Company were
$58.93/Bbl, a 9% decrease over 2018.
For 2019, OpEx increased to $20.32/Boe compared
to $18.33/Boe in 2018. The key drivers included higher repair and
maintenance expenses, decreased electricity margins from higher
downtime, higher hedged fuel cost and the increased oil mix of our
properties which generally have higher costs, partially offset by
lower transportation expense.
G&A was $5.91/Boe for 2019 compared to
$5.48/Boe for 2018. Adjusted G&A was $4.84/Boe for 2019
compared to $4.13/Boe in the prior year. G&A and Adjusted
G&A Expenses increases were primarily associated with
supporting the company's growth and public company status. We also
invested in the continuing development of our corporate affairs
department and activities whose purpose is to support our efforts
and participation in the regulatory, political and legislative
process primarily in California.
Taxes, other than income taxes were $3.84/Boe
for 2019, compared to $3.36/Boe in 2018, due to higher greenhouse
gas unit costs partially offset by lower severance taxes.
Capital expenditures totaled $211 million for
2019 compared to $148 million for 2018. Capital was largely focused
on increased drilling in California, which accounted for 91% of
2019 development capital.
As of December 31, 2019, the elected
commitment under Berry's reserves-based lending credit facility
(“RBL Facility”) was $400 million with $2 million of outstanding
borrowings. The Company had $391 million available for borrowing
under the RBL Facility which included $7 million of outstanding
letters of credit. In February, Berry's Board of Directors approved
programs to opportunistically repurchase up to $75 million of the
$400 million of outstanding 7.0% 2026 Notes and another $50 million
of shares.
“In 2020, we are currently targeting capital
expenditures in the range of $125 million to $145 million, which we
expect will result in continued annual organic production growth in
the low double digits from our California assets,” stated Cary
Baetz, executive vice president and chief financial officer. “At
current energy price levels, in combination with our hedging
program, we expect to generate strong EBITDA and solid excess
levered free cash flow, allowing us to continue to create
shareholder value and continuing to return capital to our
shareholders. Reflecting confidence in this program and the results
it will generate, the Board recently approved the first quarter
2020 dividend of $0.12 per share following the approval of our
budget, marking our seventh consecutive regular quarterly dividend
since our 2018 initial public offering.”
Full-Year 2020 Guidance
The Company expects to employ up to three
drilling rigs in California during the last three quarters of 2020,
and up to one rig throughout most, if not all, of the first quarter
of 2020. Additionally, the Company anticipates drilling
approximately 195 to 225 gross development wells during 2020,
almost all of which will be in California for oil production.
Full-Year 2020 Guidance |
Low |
|
High |
Average Daily Production (MBoe/d) |
|
29.5 |
|
|
32.5 |
Oil as % of Production |
|
~90% |
|
Operating Expenses ($/Boe) |
$ |
19.00 |
|
$ |
21.00 |
Taxes, Other than Income Taxes ($/Boe) |
$ |
4.00 |
|
$ |
4.50 |
Adjusted General & Administrative (G&A) expenses
($/Boe) |
$ |
4.75 |
|
$ |
5.25 |
Capital Expenditures ($ millions) |
$ |
125 |
|
$ |
145 |
New Drill Wells |
|
195 |
|
|
225 |
Dividend Announcement
In February 2020, the Company's Board of
Directors declared a regular dividend for the first quarter of 2020
at a rate of $0.12 per share on the Company’s outstanding
common stock. This is the Company's seventh regular quarterly
dividend, and the Company intends to pay a similar dividend in
future quarters, subject to Board approval.
The first quarter dividend is payable on or
about April 15, 2020 to shareholders of record at the close of
business on March 13, 2020.
Name Change and New Logo
In mid-February 2020, Berry introduced a new
logo and shortened name to reflect the company’s progressive
approach to evolving and growing the business in today’s dynamic
oil and gas industry. This identity will be rolled out completely
in the coming month. The new logo shows an intricate network of
integrated components all working together to form one shape. The
color gradations represent the range of competencies as well as the
changing nature of the business and echo the company’s commitment
to health, safety and the environment. Trem Smith, Berry board
chair, CEO and president said “We are proactively engaging the many
forces driving our industry to maximize our assets, create value
for shareholders, and support environmental goals that align with a
more positive future. One of the more visible elements of our
business is our publicly traded stock, and our new logo echoes the
public value of the company by using our ticker symbol as an
identifiable element of our brand.”
Earnings Conference Call
Berry will host a conference call February 27, 2020 to discuss
these results:
Live Call Date: |
Thursday, February 27,
2020 |
Live Call Time: |
9:00 a.m. Eastern Time (6 a.m.
Pacific Time) |
Live Call Dial-in: |
877-491-5169 from the
U.S. |
|
720-405-2254 from
international locations |
Live Call Passcode: |
2697719 |
A live audio webcast will be available on the “Investors”
section of Berry’s website at bry.com/investors.
An audio replay will be available shortly after the
broadcast:
Replay Dates: |
Through Wednesday, March 11,
2020 |
Replay Dial-in: |
855-859-2056 from the
U.S. |
|
404-537-3406 from
international locations |
Replay Passcode: |
2697719 |
A replay of the audio webcast will also be
archived on the “Investors” section of Berry’s website
at bry.com/investors. In addition, an investor presentation
will be available on the Company’s website.
About Berry Corporation
(bry)
Berry is a publicly traded (NASDAQ: BRY) western
United States independent upstream energy company with a focus on
the conventional, long-lived oil reserves in the San Joaquin basin
of California. More information can be found at the Company’s
website at bry.com.
Forward Looking Statements
The information in this press release includes
forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange
Act of 1934. All statements, other than statements of
historical facts, included in this press release that address
activities, events or developments that the Company expects,
believes or anticipates will or may occur in the future are
forward-looking statements. Such statements involve risks and
uncertainties that could materially affect our expected results of
operations, liquidity, cash flows and business prospects. Without
limiting the generality of the forgoing, such statements
specifically include our expectations as to our future:
- financial position,
- liquidity,
- cash flows,
- anticipated financial and operating results,
- our capital program and development and production plans,
- business strategy,
- potential acquisition opportunities,
- other plans and objectives for operations,
- maintenance capital requirements,
- expected production and costs,
- reserves,
- hedging activities,
- return of capital,
- payment of future dividends,
- future repurchases of stock or debt,
- capital investments and other guidance.
Actual results may differ from expectations,
sometimes materially, and reported results should not be considered
an indication of future performance. Known factors (but not all the
factors) that could cause results to differ include:
- volatility of oil, natural gas and natural gas liquids (NGL)
prices;
- price and availability of natural gas and electricity;
- availability and the timing of required permits and approvals
and our inability to meet existing or new conditions imposed on
those permits and approvals;our ability to meet our planned
drilling schedule, including our inability to obtain permits on a
timely basis or at all, and our ability to successfully drill wells
that produce oil and natural gas in commercially viable
quantities;
- the impact of current laws and regulations, and of pending or
future legislative or regulatory changes, including those related
to drilling, completion, well stimulation, operation, maintenance
or abandonment of wells or facilities, managing energy, water,
land, greenhouse gases or other emissions, protection of health,
safety and the environment, or transportation, marketing and sale
of our products;
- our ability to use derivative instruments to manage commodity
price risk;
- inability to generate sufficient cash flow from operations or
to obtain adequate financing to fund capital expenditures and to
meet working capital requirements;
- the impact of environmental, health and safety, and other
governmental regulations, and of current or pending or future
legislation;
- uncertainties associated with estimating proved reserves and
related future cash flows;
- our ability to replace our reserves through exploration and
development activities;
- lower-than-expected production or reserves from development
projects or higher-than-expected decline rates;
- untimely or unavailable drilling and completion equipment or
crew unavailability or lack of access to necessary resources for
drilling, completing and operating wells;
- our ability to make acquisitions and successfully integrate any
acquired businesses;
- catastrophic events;
- market fluctuations in electricity prices and the cost of
steam; and
- other material risks that appear in the Risk Factors section of
our Annual Report on Form 10-K and other periodic reports filed
with the Securities and Exchange Commission.
You can typically identify forward-looking
statements by words such as aim, anticipate, achievable, believe,
continue, could, 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.
Any forward-looking statement speaks only as of
the date on which such statement is made, and we undertake no
obligation to correct or update any forward-looking statement,
whether as a result of new information, future events or otherwise,
except as required by applicable law.
TABLES FOLLOWING
The financial information and certain other
information presented in this Exhibit 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 addition, certain
percentages presented here 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.
SUMMARY OF RESULTS
|
Berry
Corporation (bry) |
|
Quarter Ended December 31, 2019 |
|
Quarter Ended September 30, 2019 |
|
Quarter Ended December 31, 2018 |
|
Year Ended December 31, 2019 |
|
Year Ended December 31, 2018 |
|
($ and shares in thousands, except per share amounts) |
Consolidated Statement
of Operations Data: |
|
|
|
|
|
|
|
|
|
Revenues and
other: |
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
156,336 |
|
|
$ |
141,250 |
|
|
$ |
142,861 |
|
|
$ |
565,596 |
|
|
$ |
552,874 |
|
Electricity sales |
6,844 |
|
|
7,460 |
|
|
9,517 |
|
|
29,397 |
|
|
35,208 |
|
Gains (losses) on oil derivatives |
(45,544 |
) |
|
45,509 |
|
|
127,160 |
|
|
(37,998 |
) |
|
(4,621 |
) |
Marketing revenues |
437 |
|
|
413 |
|
|
534 |
|
|
2,094 |
|
|
2,322 |
|
Other revenues |
55 |
|
|
40 |
|
|
274 |
|
|
316 |
|
|
774 |
|
Total revenues and other |
118,128 |
|
|
194,672 |
|
|
280,346 |
|
|
559,405 |
|
|
586,557 |
|
Expenses and
other: |
|
|
|
|
|
|
|
|
|
Lease operating expenses |
59,529 |
|
|
50,957 |
|
|
51,308 |
|
|
216,294 |
|
|
188,776 |
|
Electricity generation expenses |
4,785 |
|
|
3,781 |
|
|
6,764 |
|
|
19,490 |
|
|
20,619 |
|
Transportation expenses |
2,124 |
|
|
2,067 |
|
|
2,220 |
|
|
8,059 |
|
|
9,860 |
|
Marketing expenses |
403 |
|
|
398 |
|
|
716 |
|
|
2,073 |
|
|
2,140 |
|
General and administrative expenses |
15,710 |
|
|
16,434 |
|
|
16,130 |
|
|
62,643 |
|
|
54,026 |
|
Depreciation, depletion, amortization and accretion |
30,102 |
|
|
27,664 |
|
|
24,253 |
|
|
106,006 |
|
|
86,271 |
|
Impairment of oil and gas properties |
51,081 |
|
|
— |
|
|
— |
|
|
51,081 |
|
|
— |
|
Taxes, other than income taxes |
11,962 |
|
|
9,249 |
|
|
7,829 |
|
|
40,645 |
|
|
33,117 |
|
(Gains) losses on natural gas derivatives |
(3,385 |
) |
|
3,008 |
|
|
(4,477 |
) |
|
6,957 |
|
|
(6,357 |
) |
Other operating expenses (income) |
774 |
|
|
(550 |
) |
|
(3,269 |
) |
|
4,588 |
|
|
(2,747 |
) |
Total expenses and other |
173,085 |
|
|
113,008 |
|
|
101,474 |
|
|
517,836 |
|
|
385,705 |
|
Other income
(expenses): |
|
|
|
|
|
|
|
|
|
Interest expense |
(7,871 |
) |
|
(8,597 |
) |
|
(8,820 |
) |
|
(34,234 |
) |
|
(35,648 |
) |
Other, net |
— |
|
|
(77 |
) |
|
108 |
|
|
80 |
|
|
243 |
|
Total other income (expenses) |
(7,871 |
) |
|
(8,674 |
) |
|
(8,712 |
) |
|
(34,154 |
) |
|
(35,405 |
) |
Reorganization items, net |
— |
|
|
(170 |
) |
|
1,498 |
|
|
(426 |
) |
|
24,690 |
|
Income (loss) before
income taxes |
(62,828 |
) |
|
72,820 |
|
|
171,658 |
|
|
6,989 |
|
|
190,137 |
|
Income tax expense
(benefit) |
(55,844 |
) |
|
20,171 |
|
|
39,890 |
|
|
(36,550 |
) |
|
43,035 |
|
Net income
(loss) |
(6,984 |
) |
|
52,649 |
|
|
131,768 |
|
|
43,539 |
|
|
147,102 |
|
Series A preferred stock dividends and conversion to common
stock |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(97,942 |
) |
Net income (loss)
attributable to common stockholders |
$ |
(6,984 |
) |
|
$ |
52,649 |
|
|
$ |
131,768 |
|
|
$ |
43,539 |
|
|
$ |
49,160 |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per
share attributable to common stockholders |
|
|
|
|
|
|
|
|
|
Basic(a) |
$ |
(0.09 |
) |
|
$ |
0.65 |
|
|
$ |
1.56 |
|
|
$ |
0.54 |
|
|
$ |
0.85 |
|
Diluted(a) |
$ |
(0.09 |
) |
|
$ |
0.65 |
|
|
$ |
1.56 |
|
|
$ |
0.53 |
|
|
$ |
0.85 |
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares
outstanding - basic(a) |
80,435 |
|
|
80,982 |
|
|
84,367 |
|
|
81,379 |
|
|
57,743 |
|
Weighted-average common shares
outstanding - diluted(a) |
80,435 |
|
|
81,051 |
|
|
84,592 |
|
|
81,951 |
|
|
57,932 |
|
|
|
|
|
|
|
|
|
|
|
Adjusted net income
(loss)(b) |
$ |
33,189 |
|
|
$ |
32,760 |
|
|
$ |
34,809 |
|
|
$ |
110,228 |
|
|
$ |
100,001 |
|
Weighted-average common shares
outstanding - diluted |
80,788 |
|
|
81,051 |
|
|
84,592 |
|
|
81,951 |
|
|
79,633 |
|
Diluted earnings per share on
adjusted net income |
$ |
0.41 |
|
|
$ |
0.40 |
|
|
$ |
0.41 |
|
|
$ |
1.35 |
|
|
$ |
1.26 |
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(b) |
$ |
86,995 |
|
|
$ |
83,931 |
|
|
$ |
81,669 |
|
|
$ |
302,184 |
|
|
$ |
257,924 |
|
Adjusted EBITDA
unhedged(b) |
$ |
71,529 |
|
|
$ |
68,778 |
|
|
$ |
72,990 |
|
|
$ |
259,987 |
|
|
$ |
296,406 |
|
Levered free cash flow(b) |
$ |
27,695 |
|
|
$ |
2,126 |
|
|
$ |
9,531 |
|
|
$ |
17,802 |
|
|
$ |
45,787 |
|
Levered free cash flow
unhedged(b) |
$ |
12,229 |
|
|
$ |
(13,027 |
) |
|
$ |
852 |
|
|
$ |
(24,395 |
) |
|
$ |
84,269 |
|
Adjusted general and
administrative expenses(b) |
$ |
13,421 |
|
|
13,940 |
|
|
$ |
11,533 |
|
|
$ |
51,226 |
|
|
$ |
40,668 |
|
Effective Tax Rate |
89 |
% |
|
28 |
% |
|
23 |
% |
|
(523 |
)% |
|
23 |
% |
Cash Flow
Data: |
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
operating activities(c) |
$ |
86,036 |
|
|
$ |
65,320 |
|
|
$ |
94,511 |
|
|
$ |
241,829 |
|
|
$ |
105,471 |
|
Net cash provided by (used in)
investing activities |
$ |
(57,361 |
) |
|
$ |
(60,285 |
) |
|
$ |
(35,438 |
) |
|
$ |
(225,025 |
) |
|
$ |
(121,440 |
) |
Net cash provided by (used in)
financing activities |
$ |
(28,675 |
) |
|
$ |
(5,262 |
) |
|
$ |
(14,306 |
) |
|
$ |
(85,484 |
) |
|
$ |
15,911 |
|
__________
(a) Our weighted-average common shares
outstanding increased beginning in the third quarter of 2018 for
additional shares from our initial public offering and preferred
stock conversion. We retrospectively adjusted for 2,770,000 shares
issued instead of the 7,080,000 shares that were reserved for
holders of allowed Unsecured Notes and General Unsecured Claims in
our earnings per share calculations for 2018.
(b) See further discussion and reconciliation in
“Non-GAAP Financial Measures and Reconciliations”.
(c) Year ended December 31, 2018 includes
approximately $127 million paid 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. Had we not elected to cancel
these derivative contracts our net cash provided by operating
activities would have been approximately $230 million.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Berry Corporation (bry) |
|
|
|
December 31, 2019 |
|
|
|
December 31, 2018 |
|
|
|
($ and shares in thousands) |
|
Balance Sheet
Data: |
|
|
|
|
|
|
|
Total current assets |
$ |
100,432 |
|
|
$ |
229,022 |
|
Total property, plant and
equipment, net |
$ |
1,576,267 |
|
|
$ |
1,442,708 |
|
Total current liabilities |
$ |
156,628 |
|
|
$ |
144,118 |
|
Long-term debt |
$ |
394,319 |
|
|
$ |
391,786 |
|
Total equity |
$ |
972,448 |
|
|
$ |
1,006,446 |
|
Outstanding common stock
shares as of(d) |
79,543 |
|
|
81,202 |
|
__________
(d) At December 31, 2018, excludes 2,770,000
common stock shares negotiated with general unsecured creditors
electing to settle claims in exchange for common shares subsequent
to December 31, 2018.
SUMMARY BY AREA
The following table shows a summary by area of
our selected historical financial information and operating data
for the periods indicated.
|
California (San Joaquin and Ventura
basins) |
|
Utah (Uinta basin) |
|
Colorado (Piceance basin) |
|
Year Ended December 31, 2019 |
Year Ended December 31, 2018 |
|
|
Year Ended December 31,
2019 |
Year Ended December 31,
2018 |
|
|
Year Ended December 31,
2019 |
|
|
Year Ended December 31,
2018 |
|
($ in thousands, unless noted otherwise) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural
gas liquids sales |
$ |
498,325 |
|
$ |
471,802 |
|
|
$ |
59,383 |
|
$ |
65,605 |
|
|
$ |
7,740 |
|
$ |
10,657 |
|
Operating income(a) |
$ |
230,500 |
|
$ |
185,965 |
|
|
$ |
7,624 |
|
$ |
15,066 |
|
|
$ |
(48,955 |
) |
$ |
6,346 |
|
Depreciation, depletion, and
amortization (DD&A) |
$ |
93,025 |
|
$ |
72,260 |
|
|
$ |
11,754 |
|
$ |
10,420 |
|
|
$ |
1,055 |
|
$ |
646 |
|
Impairment of oil and gas
properties |
$ |
— |
|
$ |
— |
|
|
$ |
— |
|
$ |
— |
|
|
$ |
51,081 |
|
$ |
— |
|
Average daily production
(MBoe/d) |
22.6 |
|
19.7 |
|
|
5.0 |
|
5.0 |
|
|
1.4 |
|
1.7 |
|
Production (oil % of
total) |
100 |
% |
100 |
% |
|
54 |
% |
48 |
% |
|
2 |
% |
1 |
% |
Realized sales prices: |
|
|
|
|
|
|
|
|
Oil (per Bbl) |
$ |
60.51 |
|
$ |
65.64 |
|
|
$ |
45.72 |
|
$ |
57.30 |
|
|
$ |
52.36 |
|
$ |
61.50 |
|
NGLs (per Bbl) |
$ |
— |
|
$ |
— |
|
|
$ |
17.08 |
|
$ |
26.95 |
|
|
$ |
— |
|
$ |
— |
|
Gas (per Mcf) |
$ |
— |
|
$ |
— |
|
|
$ |
2.94 |
|
$ |
2.68 |
|
|
$ |
2.26 |
|
$ |
2.75 |
|
Capital expenditures(b) |
$ |
191,955 |
|
$ |
125,565 |
|
|
$ |
10,229 |
|
$ |
16,738 |
|
|
$ |
603 |
|
$ |
613 |
|
Total proved reserves (MMBoe) |
122 |
|
106 |
|
|
15 |
|
19 |
|
|
1 |
|
18 |
|
__________
(a) Operating income includes oil, natural gas
and NGL sales, marketing revenues, other revenues, and scheduled
oil derivative settlements, offset by operating expenses, general
and administrative expenses, DD&A, impairment of oil and gas
properties, and taxes, other than income taxes.(b) Excludes
corporate capital expenditures.
COMMODITY PRICING
|
Berry Corporation (bry) |
|
Quarter Ended December 31,
2019 |
|
Quarter Ended September 30,
2019 |
|
Quarter Ended December 31,
2018 |
|
Year Ended December 31,
2019 |
|
Year Ended December 31,
2018 |
Realized
Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil without hedge ($/Bbl) |
$ |
59.28 |
|
|
$ |
57.92 |
|
|
$ |
61.48 |
|
|
$ |
58.93 |
|
|
$ |
64.76 |
|
Effects of scheduled
derivative settlements ($/Bbl) |
$ |
5.70 |
|
|
$ |
7.31 |
|
|
$ |
2.88 |
|
|
$ |
4.68 |
|
|
$ |
(5.09 |
) |
Oil with hedge ($/Bbl) |
$ |
64.98 |
|
|
$ |
65.23 |
|
|
$ |
64.36 |
|
|
$ |
63.61 |
|
|
$ |
59.67 |
|
Natural gas ($/Mcf) |
$ |
2.60 |
|
|
$ |
2.12 |
|
|
$ |
3.86 |
|
|
$ |
2.66 |
|
|
$ |
2.74 |
|
NGLs ($/Bbl) |
$ |
14.60 |
|
|
$ |
12.10 |
|
|
$ |
20.39 |
|
|
$ |
17.02 |
|
|
$ |
26.74 |
|
|
|
|
|
|
|
|
|
|
|
Index
Prices |
|
|
|
|
|
|
|
|
|
Brent oil ($/Bbl) |
$ |
62.42 |
|
|
$ |
62.03 |
|
|
$ |
68.08 |
|
|
$ |
64.16 |
|
|
$ |
71.69 |
|
WTI oil ($/Bbl) |
$ |
57.02 |
|
|
$ |
56.33 |
|
|
$ |
58.81 |
|
|
$ |
57.03 |
|
|
$ |
64.81 |
|
Kern, Delivered natural gas
($/MMBtu)(a) |
$ |
2.99 |
|
|
$ |
2.50 |
|
|
$ |
4.40 |
|
|
$ |
3.14 |
|
|
$ |
3.36 |
|
Henry Hub natural gas
(S/MMBtu) |
$ |
2.40 |
|
|
$ |
2.38 |
|
|
$ |
3.64 |
|
|
$ |
2.56 |
|
|
$ |
3.15 |
|
__________
(a) Kern, Delivered Index is the relevant index
used for gas purchases in California.
CURRENT HEDGING SUMMARY
As of December 31, 2019, our positions were as follows:
|
Q1 2020 |
|
|
Q2 2020 |
|
|
Q3 2020 |
|
|
Q4 2020 |
|
|
FY 2021 |
|
Fixed Price Oil Swaps
(Brent): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (MBbls) |
1,729 |
|
|
1,456 |
|
|
1,472 |
|
|
1,472 |
|
|
730 |
|
Weighted-average price ($/Bbl) |
$ |
63.92 |
|
|
$ |
64.30 |
|
|
$ |
64.21 |
|
|
$ |
64.21 |
|
|
$ |
58.50 |
|
Fixed Price Oil Swaps
(WTI): |
|
|
|
|
|
|
|
|
|
Hedged volume (MBbls) |
91 |
|
|
30 |
|
|
— |
|
|
— |
|
|
— |
|
Weighted-average price ($/Bbl) |
$ |
61.75 |
|
|
$ |
61.75 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Fixed Price Gas
Purchase Swaps (Kern, Delivered): |
|
|
|
|
|
|
|
|
|
Hedged volume (MMBtu) |
5,005,000 |
|
|
5,005,000 |
|
|
5,060,000 |
|
|
2,315,000 |
|
|
900,000 |
|
Weighted-average price ($/MMBtu) |
$ |
2.89 |
|
|
$ |
2.89 |
|
|
$ |
2.89 |
|
|
$ |
2.79 |
|
|
$ |
2.50 |
|
Fixed Price Gas
Purchase Swaps (SoCal Citygate): |
|
|
|
|
|
|
|
|
|
Hedged volume (MMBtu) |
455,000 |
|
|
455,000 |
|
|
460,000 |
|
|
155,000 |
|
|
— |
|
Weighted-average price ($/MMBtu) |
$ |
3.80 |
|
|
$ |
3.80 |
|
|
$ |
3.80 |
|
|
$ |
3.80 |
|
|
$ |
— |
|
After December 31, 2019 we added fixed price gas
purchase swaps (Kern, Delivered) of 5,000 MMBtu/d at $2.55
beginning November 2020 through October 2021.
OPERATING EXPENSES
|
Berry Corporation (bry) |
|
Quarter Ended December 31, 2019 |
|
Quarter Ended September 30, 2019 |
|
Quarter Ended December 31, 2018 |
|
Year Ended December 31, 2019 |
|
Year Ended December 31, 2018 |
|
|
|
($ in thousands except per Boe amounts) |
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
Lease operating expenses |
$ |
59,529 |
|
|
$ |
50,957 |
|
|
$ |
51,308 |
|
|
$ |
216,294 |
|
|
$ |
188,776 |
|
Electricity generation
expenses |
4,785 |
|
|
3,781 |
|
|
6,764 |
|
|
19,490 |
|
|
20,619 |
|
Electricity sales(1) |
(6,844 |
) |
|
(7,460 |
) |
|
(9,517 |
) |
|
(29,397 |
) |
|
(35,208 |
) |
Transportation expenses |
2,124 |
|
|
2,067 |
|
|
2,220 |
|
|
8,059 |
|
|
9,860 |
|
Transportation sales(1) |
(55 |
) |
|
(40 |
) |
|
(274 |
) |
|
(316 |
) |
|
(774 |
) |
Marketing expenses |
403 |
|
|
398 |
|
|
716 |
|
|
2,073 |
|
|
2,140 |
|
Marketing revenues(1) |
(437 |
) |
|
(413 |
) |
|
(534 |
) |
|
(2.094 |
) |
|
(2,322 |
) |
Derivative settlements
(received) paid for gas purchases(a) |
(906 |
) |
|
2,088 |
|
|
(2,407 |
) |
|
1,050 |
|
|
(2,407 |
) |
Total operating expenses(a) |
$ |
58,599 |
|
|
$ |
51,378 |
|
|
$ |
48,276 |
|
|
$ |
217,251 |
|
|
$ |
180,684 |
|
|
|
|
|
|
|
|
|
|
|
Expenses per
Boe:(a) |
|
|
|
|
|
|
|
|
|
Lease operating expenses |
$ |
20.69 |
|
|
$ |
18.74 |
|
|
$ |
19.96 |
|
|
$ |
20.42 |
|
|
$ |
19.16 |
|
Electricity generation
expenses |
1.66 |
|
|
1.39 |
|
|
2.63 |
|
|
1.84 |
|
|
2.09 |
|
Electricity sales |
(2.38 |
) |
|
(2.74 |
) |
|
(3.70 |
) |
|
(2.77 |
) |
|
(3.57 |
) |
Transportation expenses |
0.74 |
|
|
0.76 |
|
|
0.86 |
|
|
0.76 |
|
|
1.00 |
|
Transportation sales |
(0.02 |
) |
|
(0.01 |
) |
|
(0.11 |
) |
|
(0.03 |
) |
|
(0.08 |
) |
Marketing expenses |
0.14 |
|
|
0.15 |
|
|
0.28 |
|
|
0.20 |
|
|
0.22 |
|
Marketing revenues |
(0.15 |
) |
|
(0.15 |
) |
|
(0.21 |
) |
|
(0.20 |
) |
|
(0.24 |
) |
Derivative settlements
(received) paid for gas purchases |
(0.31 |
) |
|
0.77 |
|
|
(0.94 |
) |
|
0.10 |
|
|
(0.24 |
) |
Total operating expenses (per Boe)(b) |
$ |
20.37 |
|
|
$ |
18.90 |
|
|
$ |
18.77 |
|
|
$ |
20.32 |
|
|
$ |
18.33 |
|
Total unhedged operating expenses(b) |
$ |
20.68 |
|
|
$ |
18.13 |
|
|
$ |
19.71 |
|
|
$ |
20.22 |
|
|
$ |
18.57 |
|
|
|
|
|
|
|
|
|
|
|
Total MBoe |
2,877 |
|
|
2,719 |
|
|
2,571 |
|
|
10,594 |
|
|
9,855 |
|
__________
(a) 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.
(b) Total unhedged operating expenses equals
total operating expenses less the derivatives settlements paid for
gas purchases
PRODUCTION STATISTICS
|
Berry
Corporation (bry) |
|
Quarter Ended December 31, 2019 |
|
Quarter Ended September 30, 2019 |
|
Quarter Ended December 31, 2018 |
|
Year Ended December 31, 2019 |
|
Year Ended December 31, 2018 |
Net Oil, Natural Gas
and NGLs Production Per
Day(a): |
|
|
|
|
|
|
|
|
|
Oil
(MBbl/d) |
|
|
|
|
|
|
|
|
|
California |
25.5 |
|
|
23.0 |
|
|
21.7 |
|
|
22.6 |
|
|
19.7 |
|
Utah |
2.2 |
|
|
2.7 |
|
|
2.0 |
|
|
2.7 |
|
|
2.3 |
|
Colorado |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Total oil |
27.7 |
|
|
25.7 |
|
|
23.7 |
|
|
25.3 |
|
|
22.0 |
|
Natural gas
(MMcf/d) |
|
|
|
|
|
|
|
|
|
California |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Utah |
10.7 |
|
|
12.1 |
|
|
9.8 |
|
|
11.2 |
|
|
12.0 |
|
Colorado |
8.2 |
|
|
8.8 |
|
|
9.6 |
|
|
8.8 |
|
|
10.1 |
|
East Texas(b) |
— |
|
|
— |
|
|
2.8 |
|
|
— |
|
|
4.2 |
|
Total natural gas |
18.9 |
|
|
20.9 |
|
|
22.1 |
|
|
20.0 |
|
|
26.3 |
|
NGLs
(MBbl/d) |
|
|
|
|
|
|
|
|
|
California |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Utah |
0.4 |
|
|
0.4 |
|
|
0.6 |
|
|
0.4 |
|
|
0.6 |
|
Colorado |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Total NGLs |
0.4 |
|
|
0.4 |
|
|
0.6 |
|
|
0.4 |
|
|
0.6 |
|
Total Production
(MBoe/d)(c) |
31.3 |
|
|
29.6 |
|
|
28.0 |
|
|
29.0 |
|
|
27.0 |
|
__________
(a) Production represents volumes sold during
the period.
(b) On November 30, 2018, we sold our non-core
gas-producing properties and related assets located in the East
Texas basin.
(c) Natural gas volumes have been converted to
Boe based on energy content of six Mcf of gas to one Bbl of oil.
Barrels of oil equivalence does not necessarily result in price
equivalence. The price of natural gas on a barrel of oil equivalent
basis is currently substantially lower than the corresponding price
for oil and has been similarly lower for a number of years. For
example, in the year ended December 31, 2019, the average
prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl
and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio
of over 4 to 1 on an energy equivalent basis.
CAPITAL EXPENDITURES (ACCRUAL BASIS)
|
|
|
|
|
|
|
Berry Corporation (bry) |
|
|
|
|
|
|
Quarter Ended December 31, 2019 |
|
Quarter Ended September 30, 2019 |
|
Quarter Ended December 31, 2018 |
|
Year Ended December 31, 2019 |
|
Year Ended December 31, 2018 |
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
Capital
expenditures (accrual basis) |
$ |
41,877 |
|
|
$ |
63,488 |
|
|
$ |
53,326 |
|
|
$ |
211,095 |
|
|
$ |
147,831 |
|
NON-GAAP FINANCIAL MEASURES AND
RECONCILIATIONS
Adjusted Net Income (Loss) is not a measure of
net income (loss), Levered Free Cash Flow is not a measure of cash
flow, and Adjusted EBITDA is not a measure of either, in all cases,
as determined by GAAP. Adjusted Net Income (Loss), Adjusted
EBITDA, Levered Free Cash Flow and Adjusted General and
Administrative Expenses are supplemental non-GAAP financial
measures used by management and external users of our financial
statements, such as industry analysts, investors, lenders and
rating agencies. We define Adjusted 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. 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. We define Adjusted General and
Administrative Expenses as general and administrative expenses
adjusted for restructuring and other non-recurring costs and
non-cash stock compensation expense.
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. Our management believes
Adjusted EBITDA provides useful information in assessing our
financial condition, results of operations and cash flows and is
widely used by the industry and the investment community. The
measure also allows our management to more effectively evaluate our
operating performance and compare the results between periods
without regard to our financing methods or capital structure.
Levered Free Cash Flow is used by management as a primary metric to
plan capital allocation to sustain production levels and for
internal growth opportunities, as well as hedging needs. It also
serves as a measure for assessing our financial performance and our
ability to generate excess cash from operations to service debt and
pay dividends. Management believes Adjusted General and
Administrative Expenses is useful because it allows us to more
effectively compare our performance from period to period. We
exclude the items listed above from general and administrative
expenses in arriving at Adjusted General and Administrative
Expenses because these amounts can vary widely and unpredictably in
nature, timing, amount and frequency and stock compensation expense
is non-cash in nature.
While Adjusted Net Income (Loss), Adjusted
EBITDA, Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered
Free Cash Flow Unhedged and Adjusted General and Administrative
Expenses are non-GAAP measures, the amounts included in the
calculations of Adjusted Net Income (Loss), Adjusted EBITDA,
Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash
Flow Unhedged and Adjusted General and Administrative Expenses were
computed in accordance with GAAP. These measures are provided in
addition to, and not as an alternative for, income and liquidity
measures calculated in accordance with GAAP and should not be
considered as an alternative to, or more meaningful than, income
and liquidity measures calculated in accordance with GAAP. Our
computations of Adjusted Net Income (Loss), Adjusted EBITDA,
Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash
Flow Unhedged and Adjusted General and Administrative Expenses may
not be comparable to other similarly titled measures used by other
companies. Adjusted Net Income (Loss), Adjusted EBITDA, Adjusted
EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash Flow
Unhedged and Adjusted General and Administrative Expenses should be
read in conjunction with the information contained in our financial
statements prepared in accordance with GAAP.
PV-10 is a non-GAAP financial measure and
represents the present value of estimated future cash inflows from
proved oil and gas reserves, less future development and production
costs, discounted at 10% per annum to reflect the timing of future
cash flows and does not give effect to derivative transactions or
estimated future income taxes. Management believes that PV-10
provides useful information to investors because it is widely used
by analysts and investors in evaluating oil and natural gas
companies. Because there are many unique factors that can impact an
individual company when estimating the amount of future income
taxes to be paid, management believes the use of a pre-tax measure
is valuable for evaluating the Company. PV-10 should not be
considered as an alternative to the standardized measure of
discounted future net cash flows as computed under GAAP.
Finding and Development Cost ("F&D Cost")
and reserves replacement ratio are non-GAAP measures that we
believe are widely used in our industry, as well as by analysts and
investors, to measure and evaluate the cost of replacing annual
production and adding proved reserves. F&D Cost – All-In is
calculated by dividing total costs incurred for the year as defined
by GAAP by the sum of proved reserve extensions and discoveries,
revisions of previous estimates, improved recovery and purchases of
minerals in place for the year. F&D Cost – Program is
calculated by dividing total costs incurred for the year as defined
by GAAP by extensions and discoveries and improved recovery for the
year. 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 performing as many factors fully or partially outside of
management's control, including commodity prices, availability of
capital and the underlying geology, affect reserves additions.
Management uses this measure to gauge results of its capital
allocation. The measure is limited in that reserves may be added
and produced based on costs incurred in separate periods and other
oil and gas producers may use different measures affecting
comparability.
ADJUSTED NET INCOME (LOSS)
The following table presents a reconciliation of
the GAAP financial measure of net income (loss) to the non-GAAP
financial measure of Adjusted Net Income (Loss).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Berry Corporation (bry) |
|
|
|
|
|
|
Quarter Ended December 31, 2019 |
|
Quarter Ended September 30, 2019 |
|
Quarter Ended December 31, 2018 |
|
Year Ended December 31, 2019 |
|
Year Ended December 31, 2018 |
|
|
|
|
|
|
($ thousands, except per share amounts) |
|
|
|
|
|
Net income (loss) |
$ |
(6,984 |
) |
|
$ |
52,649 |
|
|
$ |
131,768 |
|
|
$ |
43,539 |
|
|
$ |
147,102 |
|
Subtract: prior period income
tax credits |
|
(38,653 |
) |
|
|
— |
|
|
|
— |
|
|
|
(38,653 |
) |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add (Subtract): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gains) losses on oil and natural gas derivatives |
|
42,159 |
|
|
|
(42,501 |
) |
|
|
(131,637 |
) |
|
|
44,955 |
|
|
|
(1,735 |
) |
Net cash received (paid) for scheduled derivative settlements |
|
15,466 |
|
|
|
15,153 |
|
|
|
8,679 |
|
|
|
42,197 |
|
|
|
(38,482 |
) |
Other operating expenses (income) |
|
774 |
|
|
|
(550 |
) |
|
|
(3,269 |
) |
|
|
4,588 |
|
|
|
(2,747 |
) |
Impairment of oil & gas properties |
|
51,081 |
|
|
|
— |
|
|
|
— |
|
|
|
51,081 |
|
|
|
— |
|
Restructuring and other non-recurring costs |
|
— |
|
|
|
219 |
|
|
|
1,414 |
|
|
|
3,061 |
|
|
|
6,773 |
|
Reorganization items, net |
|
— |
|
|
|
170 |
|
|
|
(1,498 |
) |
|
|
426 |
|
|
|
(24,690 |
) |
Total additions (subtractions), net |
|
109,480 |
|
|
|
(27,509 |
) |
|
|
(126,311 |
) |
|
|
146,308 |
|
|
|
(60,881 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (expense) benefit
of adjustments at effective tax rate(1) |
|
(30,654 |
) |
|
|
7,620 |
|
|
|
29,352 |
|
|
|
(40,966 |
) |
|
|
13,780 |
|
Adjusted net income
(loss) |
|
$ |
33,189 |
|
|
|
$ |
32,760 |
|
|
|
$ |
34,809 |
|
|
|
$ |
110,228 |
|
|
|
$ |
100,001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS on adjusted net
income |
|
$ |
0.41 |
|
|
|
$ |
0.40 |
|
|
|
$ |
0.41 |
|
|
|
$ |
1.35 |
|
|
|
$ |
1.73 |
|
Diluted EPS on adjusted net
income |
|
$ |
0.41 |
|
|
|
$ |
0.40 |
|
|
|
$ |
0.41 |
|
|
|
$ |
1.35 |
|
|
|
$ |
1.26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding - basic |
|
80,435 |
|
|
|
80,982 |
|
|
|
84,367 |
|
|
|
81,379 |
|
|
|
57,743 |
|
Weighted average shares
outstanding - diluted |
|
80,788 |
|
|
|
81,309 |
|
|
|
84,592 |
|
|
|
81,379 |
|
|
|
79,633 |
|
__________
(1) Excludes prior year income tax credits from
the total additions (subtractions), net line item and the tax
effect the prior tax credits have on the current year effective tax
rate.
ADJUSTED EBITDA AND ADJUSTED EBITDA
UNHEDGED
The following tables present a reconciliation of
Adjusted EBITDA and Adjusted EBITDA Unhedged to the most directly
comparable GAAP financial measures of net income (loss) and net
cash provided (used) by operating activities, respectively.
|
|
|
|
|
Berry Corporation (bry) |
|
|
|
|
|
Quarter Ended December 31, 2019 |
|
|
Quarter Ended September 30, 2019 |
|
|
Quarter Ended December 31, 2018 |
|
|
Year Ended December 31, 2019 |
|
|
Year Ended December 31, 2018 |
Net income (loss) |
|
|
|
|
($ thousands) |
|
|
|
|
|
|
Add (Subtract): |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,984) |
|
|
$ |
|
|
|
52,649 |
|
|
$ |
|
|
|
131,768 |
|
|
$ |
|
|
|
43,539 |
|
|
$ |
|
|
|
147,102 |
|
Interest expense |
|
7,871 |
|
|
|
8,597 |
|
|
|
8,820 |
|
|
|
34,234 |
|
|
|
35,648 |
|
Income tax expense (benefit) |
|
(55,845 |
) |
|
|
20,171 |
|
|
|
39,890 |
|
|
|
(36,550 |
) |
|
|
43,035 |
|
Depreciation, depletion, and amortization |
|
30,102 |
|
|
|
27,664 |
|
|
|
24,253 |
|
|
|
106,006 |
|
|
|
86,271 |
|
Impairment of oil and gas properties |
|
51,081 |
|
|
|
— |
|
|
|
— |
|
|
|
51,081 |
|
|
|
— |
|
Derivative (gains) losses |
|
42,160 |
|
|
|
(42,501 |
) |
|
|
(131,637 |
) |
|
|
44,955 |
|
|
|
(1,735 |
) |
Net cash received (paid) for scheduled derivative settlements |
|
15,466 |
|
|
|
15,153 |
|
|
|
8,679 |
|
|
|
42,197 |
|
|
|
(38,482 |
) |
Other operating expenses (income) |
|
774 |
|
|
|
(550 |
) |
|
|
(3,269 |
) |
|
|
4,588 |
|
|
|
(2,747 |
) |
Stock compensation expense |
|
2,370 |
|
|
|
2,360 |
|
|
|
3,249 |
|
|
|
8,647 |
|
|
|
6,750 |
|
Restructuring and other non-recurring costs |
|
— |
|
|
|
219 |
|
|
|
1,414 |
|
|
|
3,061 |
|
|
|
6,773 |
|
Reorganization items, net |
|
— |
|
|
|
170 |
|
|
|
(1,498 |
) |
|
|
426 |
|
|
|
(24,690 |
) |
Adjusted EBITDA |
|
$ |
86,995 |
|
|
|
$ |
83,931 |
|
|
|
$ |
81,669 |
|
|
|
$ |
302,184 |
|
|
|
$ |
257,924 |
|
Net cash (received) paid for
scheduled derivative settlements |
|
(15,466 |
) |
|
|
(15,153 |
) |
|
|
(8,679 |
) |
|
|
(42,197 |
) |
|
|
38,482 |
|
Adjusted EBITDA unhedged |
|
$ |
71,529 |
|
|
|
$ |
68,778 |
|
|
|
$ |
72,990 |
|
|
|
$ |
259,987 |
|
|
|
$ |
296,406 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities |
|
$ |
86,036 |
|
|
|
$ |
65,320 |
|
|
|
$ |
94,511 |
|
|
|
$ |
241,829 |
|
|
|
$ |
105,471 |
|
Add (Subtract): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash interest payments |
|
584 |
|
|
|
14,864 |
|
|
|
562 |
|
|
|
30,720 |
|
|
|
19,761 |
|
Cash income tax (refunds) |
|
(3 |
) |
|
|
— |
|
|
|
(1,901 |
) |
|
|
(2 |
) |
|
|
(1,901 |
) |
Cash reorganization item (receipts) payments |
|
— |
|
|
|
— |
|
|
|
(174 |
) |
|
|
— |
|
|
|
832 |
|
Restructuring and other non-recurring costs |
|
— |
|
|
|
219 |
|
|
|
1,414 |
|
|
|
3,061 |
|
|
|
6,773 |
|
Derivative early termination payment |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
126,949 |
|
Other changes in operating assets and liabilities |
|
378 |
|
|
|
3,528 |
|
|
|
(12,743 |
) |
|
|
26,576 |
|
|
|
39 |
|
Adjusted EBITDA |
|
$ |
86,995 |
|
|
|
$ |
83,931 |
|
|
|
$ |
81,669 |
|
|
|
$ |
302,184 |
|
|
|
$ |
257,924 |
|
Net cash (received) paid for
scheduled derivative settlements |
|
(15,466 |
) |
|
|
(15,153 |
) |
|
|
(8,679 |
) |
|
|
(42,197 |
) |
|
|
38,482 |
|
Adjusted EBITDA unhedged |
|
$ |
71,529 |
|
|
|
$ |
68,778 |
|
|
|
$ |
72,990 |
|
|
|
$ |
259,987 |
|
|
|
$ |
296,406 |
|
LEVERED FREE CASH FLOW AND LEVERED FREE CASH FLOW
UNHEDGED
The following table presents a reconciliation of
Adjusted EBITDA to the non–GAAP measures of Levered Free Cash Flow.
The reconciliation of Adjusted EBITDA is presented above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Berry Corporation (bry) |
|
|
|
|
|
Quarter Ended December 31, 2019 |
|
|
Quarter Ended September 30, 2019 |
|
|
Quarter Ended December 31, 2018 |
|
|
Year Ended December 31, 2019 |
|
|
Year Ended December 31, 2018 |
|
|
|
|
|
|
|
|
($ thousands) |
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86,995 |
|
|
|
$ |
|
|
83,931 |
|
|
|
$ |
|
|
81,669 |
|
|
|
$ |
|
|
302,184 |
|
|
|
$ |
|
|
257,924 |
|
Subtract: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures - accrual basis |
|
(41,877 |
) |
|
|
(63,488 |
) |
|
|
(53,326 |
) |
|
|
(211,095 |
) |
|
|
(147,831 |
) |
Interest expense |
|
(7,871 |
) |
|
|
(8,597 |
) |
|
|
(8,820 |
) |
|
|
(34,234 |
) |
|
|
(35,648 |
) |
Cash dividends declared |
|
(9,552 |
) |
|
|
(9,720 |
) |
|
|
(9,992 |
) |
|
|
(39,053 |
) |
|
|
(28,658 |
) |
Levered Free Cash Flow |
|
$ |
27,695 |
|
|
|
$ |
2,126 |
|
|
|
$ |
9,531 |
|
|
|
$ |
17,802 |
|
|
|
$ |
45,787 |
|
Net cash (received) paid for
scheduled derivative settlements |
|
(15,466 |
) |
|
|
(15,153 |
) |
|
|
(8,679 |
) |
|
|
(42,197 |
) |
|
|
38,482 |
|
Levered Free Cash Flow
Unhedged |
|
$ |
12,229 |
|
|
|
$ |
(13,027 |
) |
|
|
$ |
852 |
|
|
|
$ |
(24,395 |
) |
|
|
$ |
84,269 |
|
ADJUSTED GENERAL AND ADMINISTRATIVE
EXPENSES
The following table presents a reconciliation of the GAAP
financial measure of general and administrative expenses to the
non-GAAP financial measures of Adjusted general and administrative
expenses.
|
|
|
|
Berry Corporation (bry) |
|
|
|
|
Quarter Ended December 31, 2019 |
|
|
Quarter Ended September 30, 2019 |
|
|
Quarter Ended December 31, 2018 |
|
|
Year Ended December 31, 2019 |
|
|
Year Ended December 31, 2018 |
|
|
|
|
|
|
($ in thousands except per MBoe amounts) |
|
|
|
|
General and administrative
expenses |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,710 |
|
|
$ |
|
|
|
16,434 |
|
|
$ |
|
|
16,130 |
|
|
$ |
|
|
62,643 |
|
|
$ |
|
|
54,026 |
|
Subtract: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-recurring restructuring and other costs |
|
— |
|
|
(219 |
) |
|
(1,414 |
) |
|
(3,061 |
) |
|
(6,773 |
) |
Non-cash stock compensation expense |
|
(2,289 |
) |
|
(2,275 |
) |
|
(3,183 |
) |
|
(8,356 |
) |
|
(6,585 |
) |
Adjusted general and
administrative expenses |
|
$ |
13,421 |
|
|
$ |
13,940 |
|
|
$ |
11,533 |
|
|
$ |
51,226 |
|
|
$ |
40,668 |
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
expenses ($/Boe) |
|
$ |
5.46 |
|
|
$ |
6.04 |
|
|
$ |
6.27 |
|
|
$ |
5.91 |
|
|
$ |
5.48 |
|
Subtract: |
|
|
|
|
|
|
|
|
|
|
Non-recurring restructuring and other costs ($/Boe) |
|
— |
|
|
(0.08 |
) |
|
(0.55 |
) |
|
(0.29 |
) |
|
(0.69 |
) |
Non-cash stock compensation expense ($/Boe) |
|
(0.80 |
) |
|
(0.84 |
) |
|
(1.24 |
) |
|
(0.79 |
) |
|
(0.67 |
) |
Adjusted general and
administrative expenses ($/Boe) |
|
$ |
4.66 |
|
|
$ |
5.13 |
|
|
$ |
4.49 |
|
|
$ |
4.84 |
|
|
$ |
4.13 |
|
|
|
|
|
|
|
|
|
|
|
|
Total MBoe |
|
2,877 |
|
|
2,719 |
|
|
2,571 |
|
|
10,594 |
|
|
9,855 |
|
RESERVES AND PV-10
The following table summarizes our estimated
proved reserves and related PV-10 as of December 31, 2019.
|
Proved Reserves as of December 31,
2019(1) |
|
California(San Joaquin and Ventura
basins) |
|
|
Utah(Uinta basin) |
|
|
Colorado(Piceance
basin) |
|
|
Total |
|
Proved developed
reserves: |
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl) |
68 |
|
|
6 |
|
|
— |
|
|
74 |
|
Natural Gas (Bcf) |
— |
|
|
30 |
|
|
9 |
|
|
39 |
|
NGLs (MMBbl) |
— |
|
|
1 |
|
|
— |
|
|
1 |
|
Total (MMBoe)(2)(3) |
68 |
|
|
12 |
|
|
1 |
|
|
82 |
|
Proved undeveloped
reserves: |
|
|
|
|
|
|
|
Oil (MMBbl) |
54 |
|
|
2 |
|
|
— |
|
|
56 |
|
Natural Gas (Bcf) |
— |
|
|
6 |
|
|
— |
|
|
6 |
|
NGLs (MMBbl) |
— |
|
|
— |
|
|
— |
|
|
— |
|
Total (MMBoe)(3) |
54 |
|
|
3 |
|
|
— |
|
|
57 |
|
Total proved
reserves: |
|
|
|
|
|
|
|
Oil (MMBbl) |
122 |
|
|
8 |
|
|
— |
|
|
130 |
|
Natural Gas (Bcf) |
— |
|
|
36 |
|
|
9 |
|
|
45 |
|
NGLs (MMBbl) |
— |
|
|
1 |
|
|
— |
|
|
1 |
|
Total (MMBoe)(3) |
122 |
|
|
15 |
|
|
1 |
|
|
138 |
|
|
|
|
|
|
|
|
|
PV-10 (in
billions)(4) |
$ |
1.7 |
|
|
$ |
0.1 |
|
|
$ |
— |
|
|
$ |
1.8 |
|
__________
(1) Our estimated net reserves were determined
using average first-day-of-the-month prices for the prior 12 months
in accordance with SEC guidance. The unweighted arithmetic average
first-day-of-the-month prices for the prior 12 months were $63.15
per Bbl Brent for oil and NGLs and $2.62 per MMBtu Henry Hub for
natural gas at December 31, 2019. The volume-weighted average
prices over the lives of the properties were $58.88 per Bbl of oil
and condensate, $16.93 per Bbl of NGLs and $2.84 per Mcf. The
prices were held constant for the lives of the properties and we
took into account pricing differentials reflective of the market
environment. Prices were calculated using oil and natural gas price
parameters established by current guidelines of the SEC and
accounting rules including adjustments by lease for quality, fuel
deductions, geographical differentials, marketing bonuses or
deductions and other factors affecting the price received at the
wellhead.
(2) Approximately 18% of proved developed oil
reserves, 0% of proved developed NGL reserves, 0% of proved
developed natural gas reserves and 16% of total proved developed
reserves are non-producing.
(3) Natural gas volumes have been converted to
Boe based on energy content of six Mcf of gas to one Bbl of oil.
Barrels of oil equivalence does not necessarily result in price
equivalence. The price of natural gas on a barrel of oil equivalent
basis is currently substantially lower than the corresponding price
for oil and has been similarly lower for a number of years. For
example, in the year ended December 31, 2019, the average
prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl
and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio
of over 4 to 1 on an energy equivalent basis.
(4) For a definition of PV-10 and a
reconciliation to the standardized measure of discounted future net
cash flows, please see “Non-GAAP Financial Measures and
Reconciliations—PV-10.” PV-10 does not give effect to derivatives
transactions.
The following table provides a reconciliation of
PV-10 of our proved reserves to the standardized measure of
discounted future net cash flows at December 31, 2019:
|
At December 31, 2019 |
|
|
(in millions) |
|
California PV-10 |
$ |
|
|
1.7 |
|
Utah PV-10 |
0.1 |
|
Colorado PV-10 |
— |
|
Total Company PV-10 |
1.8 |
|
Less: present value of future
income taxes discounted at 10% |
(0.3 |
) |
Standardized measure of
discounted future net cash flows |
$ |
1.5 |
|
RESERVES AND PUD INVENTORY REPLACEMENT RATIOS AND
F&D COSTS
The following table presents a calculation of
our reserves and PUD inventory replacement ratio and F&D Cost
from the total changes to our proved reserves in 2019, as well as
the related costs incurred:
|
Total Company |
|
|
California |
|
|
(in MMBoe, except ratio and cost amounts) |
Extensions and discoveries
(B) |
13.3 |
|
|
13.3 |
|
Revisions of previous
estimates(b) |
(7.3 |
) |
|
11.2 |
|
Purchases of minerals |
— |
|
|
— |
|
Organic changes (C) |
6.0 |
|
|
24.5 |
|
Sales of minerals |
— |
|
|
— |
|
Total reserves changes |
6.0 |
|
|
24.5 |
|
|
|
|
|
Production |
10.6 |
|
|
8.2 |
|
Reserve replacement ratio |
57 |
% |
|
299 |
% |
|
|
|
|
Costs incurred (development
costs)(A) ($ millions) |
$ |
280.0 |
|
|
|
|
|
|
|
Finding & Development
costs per Boe |
|
|
|
All-In (A)/(C) |
$ |
46.67 |
|
|
|
Program (A)/(B) |
$ |
21.05 |
|
|
|
|
|
|
|
Adjustments to All-In
Finding & Development costs per BOE |
|
|
|
Costs incurred (development
costs)(A) ($ millions) |
$ |
280.0 |
|
|
|
Asset Retirement
Obligations ($ millions) |
(68.0 |
) |
|
|
Adjusted Costs Incurred ($ millions) (D) |
$ |
212.0 |
|
|
|
|
|
|
|
Total reserves changes |
6.0 |
|
|
|
Impairments (MMBoe) |
13.5 |
|
|
|
Adjusted organic changes (MMBoe) (E) |
19.5 |
|
|
|
|
|
|
|
Adjusted All-In Finding &
Developing costs per BOE (D)/(E) |
$ |
10.87 |
|
|
|
__________
(a) All costs incurred in 2019 were development
costs.
(b) Total Company revisions includes the removal
of 16 MMBoe of proved undeveloped reserves (negative revision) in
our Colorado Piceance natural gas properties, and the associated
impairment.
|
Total Company |
Proved Undeveloped (PUD)
drilling locations at Dec. 31, 2018 |
1,071 |
|
PUD locations drilled and
revisions of previous inventory |
(368 |
) |
PUD drilling location
additions |
586 |
|
PUD drilling locations at Dec.
31, 2019 |
1,289 |
|
PUD replacement ratio |
159 |
% |
Contact
Contact: Berry Corporation (bry)
Todd Crabtree - Manager, Investor Relations
(661) 616-3811
ir@bry.com
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