Berry Corporation (bry) (NASDAQ: BRY) (“Berry” or the “Company”)
today reported fourth quarter and full-year 2020 results. For the
full year Berry's net loss was $263 million, or $3.29 per diluted
share, and Adjusted Net Income(1) was $45 million, or $0.56 per
diluted share. For the fourth quarter the net loss was $64 million,
or $0.80 per diluted share, and Adjusted Net Income(1) was $9
million, or $0.11 per diluted share. In addition, the Company's
Board of Directors approved a first quarter dividend of $0.04 per
share.
Highlights for the Quarter
- Generated $33 million in Levered
Free Cash Flow(1)
- Restarted development program with
two rigs part time, drilling 22 wells, all California oil
- Adjusted EBITDA(1) of $54
million
- 88% oil production mix
- Capital
expenditures of $12 million with approximately 96% directed to
California development
Highlights for the Full Year
- Generated $131 million in Levered
Free Cash Flow(1)
- Ended year with cash balance of $80
million
- Adjusted EBITDA(1) of $244
million
- Reduced 2020 OpEx by $1.81/Boe
- Increased California oil production
more than 1% from 2019 volumes
- Oil production of 25,000 Boe/d
comprising 88% of total production
- Capital expenditures of
$69 million, approximately 96% directed to California
assets
__________
(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.
“One of Berry’s core financial tenets has always been to live
out of Levered Free Cash Flow while protecting our base production.
Even in the midst of an unprecedented year, we successfully
delivered our plan. We adeptly improved our hedge position
before prices plummeted, lowered our costs, and maximized our cash
position to weather the volatile environment that was 2020. We
committed to all stakeholders that we would enter 2021 in a strong
position poised for growth and we are,” said Trem Smith, Berry
board chair and chief executive officer. “We started 2021 in a
strong liquidity position by continuing our cash build and
currently have more than $100 million. For 2021, we will utilize
our proven financial formula of operating within our Levered Free
Cash Flow and returning capital to our shareholders. We are pleased
to announce the return of a quarterly dividend justified by
the improving price environment, our growing confidence in the
business fundamentals for oil and our strong liquidity position.
Our cash position and improving oil prices, allow us to put capital
to work protecting and growing our California production. We plan
to hold year-over-year company-wide production flat in 2021 and
anticipate a strong fourth quarter exit rate. In addition, we are
laser focused on increasing our scale. Our growth strategy
continues to be directed toward conventional, low corporate decline
assets with strong visibility to cash flow.”
Fourth Quarter 2020 Results
Adjusted EBITDA(1) on a hedged basis, was $54
million in the fourth quarter 2020, compared to $62 million in the
third quarter 2020, reflecting lower volumes, as well as lower
electricity sales due to seasonal effects and higher workover
activity driving higher Operating Expenses (OpEx).
Average daily production in the fourth quarter
2020 of 26,600 Boe/d was 4% lower than the third quarter volumes of
27,600 Boe/d due mainly to natural decline resulting from pausing
drilling activity for the majority of the year, with drilling
restarting during the fourth quarter. Company-wide oil production
declined 3% sequentially and California oil production, which is
80% of total production, was 21,200 MBoe/d for the fourth
quarter.
The Company-wide hedged realized oil price for
the fourth quarter 2020 was $56.41/Bbl, essentially flat from the
third quarter. The financial hedges for oil sales for the fourth
quarter 2020 added $15.03/Bbl to the realized price, highlighting
the effectiveness of the Company’s oil hedge positions in 2020.
Company-wide realized oil prices before hedges of $41.38/Bbl was 4%
higher in the fourth quarter 2020 compared to the third
quarter.
California’s unhedged realized oil price in the
fourth quarter increased 4% or $1.72 per Bbl to $41.74, which was
92% of Brent and unchanged from the previous quarter. Rockies’
unhedged realized oil price declined 2% to $37.56 per Bbl but the
Company-wide average price increased 15% as the natural gas price
increased 43% to $2.78 per Mcf. The total Company average oil and
gas price increased 5% to $38.28 per Boe in the fourth quarter 2020
from $36.35 in the third quarter.
Levered Free Cash Flow(1) for the fourth quarter
2020 was $33 million, after $12 million of capital expenditures and
$8 million of interest.
OpEx increased to $19.06/Boe for the fourth
quarter 2020, compared to $16.97/Boe in the third quarter. This
$4 million increase in OpEx was primarily due to the seasonal
effect of lower electricity capacity revenues, as well as the
workover and recompletion campaign which began during the fourth
quarter, higher natural gas fuel prices, as well as general
facility and well maintenance.
General and administrative expenses increased by
$1 million, or 6%, to approximately $20 million for the
fourth quarter 2020, compared to the third quarter of 2020.
Adjusted General and Administrative Expenses(1), which excludes
non-cash stock compensation costs and nonrecurring costs, were $15
million and $14 million for the fourth and third quarter of 2020,
respectively. The higher fourth quarter 2020 expenses reflect
increased employee compensation accruals.
Taxes, other than income taxes were $4.43 per
Boe in the fourth quarter compared to $3.91 in the third quarter.
The increase was largely due to annual property tax assessments in
the quarter.
Capital expenditures, which were focused on
development activities in California, increased to $12 million
for the fourth quarter compared to $4 million for the third
quarter. This was due to resuming California drilling activity
after more than six months of not drilling because of low prices
and an oversupply in the market. These amounts exclude capitalized
overhead and interest costs of $2 million for the fourth quarter
and expenditures for asset retirement obligation of $4 million.
Full-Year 2020 Results
Adjusted EBITDA(1) (hedged) was $244 million for
2020, a decrease of $58 million compared to 2019 primarily due to
lower commodity prices and, to a much lesser degree, lower volumes
due to the pause of drilling from April to October related to
pricing. Offsetting a portion of the price impact was a $22 million
reduction in OpEx.
Year-over-year California production increased
over 1% to 22,900 Bbl/d, while overall Company production decreased
2% to 28,500 Boe/d in 2020 due to the natural decline of our
Rockies properties in the absence of development activity.
California’s unhedged realized oil price was
$40.01 per Bbl in 2020 and $60.51 in 2019. Rockies’ unhedged
realized oil price declined to $34.69 per Bbl from $45.78 in 2019.
Total Company average oil and gas price decreased $17.10 per Boe
from 2019 to $36.29 in 2020. Oil hedge settlements increased to
$16.51 per Bbl ($152 million) in 2020 from $4.68 per Bbl in the
previous year.
OpEx on a hedged basis decreased $1.81 per Boe,
or $22 million from 2019 to $18.51 in 2020. As a result of cost
saving and efficiency measures implemented in 2020, Non-Energy OpEx
decreased $15 million, or $1.17 per Boe, when compared to the prior
year. Energy OpEx decreased $7 million or $0.63 per Boe.
General and administrative expenses increased by
$15 million, or 24%, to approximately $78 million for the year
ended December 31, 2020, compared to the prior year. Adjusted
General and Administrative Expenses(1), which excludes non-cash
stock compensation costs and nonrecurring costs, were $57 million
and $51 million in 2020 and 2019, respectively. The year-over-year
increase is due to higher employee compensation and increased
activities necessary for our participation in the regulatory and
legislative process primarily in California.
Taxes, other than income taxes, decreased to
$3.41/Boe in 2020 from $3.84/Boe in 2019. The decrease was largely
due to lower greenhouse gas prices during 2020 including some
allowance purchases made at low prices due to a temporary market
dislocation in the first quarter of 2020, as well as lower CO2
emissions. Partially offsetting the greenhouse gas prices were
higher property tax rates, as well as higher severance tax rates
due to the expiration of certain deductions.
Capital expenditures totaled $69 million for
2020 compared to $209 million for 2019. The decrease was due
primarily to the reduction in drilling with 45 wells in 2020
compared to 338 in 2019. These amounts exclude capitalized overhead
and interest costs. Additionally, we spent $18 million in 2020 on
plugging and abandonment activities. Capital was largely focused on
development drilling in California, which accounted for 96% of 2020
development capital.
Proved reserves were 95 MMBoe at December 31,
2020, of which 91% are located in California and where 97% of the
PV-10(1) value is located. The formulaic SEC oil price used to
calculate proved reserves decreased 34% year-over-year, which drove
a 26% reduction in our proved reserves, before the effect of
current year production. Additionally, the significant drop in
commodity prices during the year resulted in a significant decline
in the Company’s capital program, limiting opportunities to
prove-up additional reserves. The Company drilled 87% fewer wells
in 2020 than in the prior year. Based on current Brent strip
pricing the Company anticipates a material improvement in 2021
proved reserves, should prices remain at those levels.
As of December 31, 2020, the elected commitment
under Berry's reserves-based lending credit facility (“RBL
Facility”) was $200 million with no outstanding borrowings. The
Company had $193 million available for borrowing under the RBL
Facility which included $7 million of outstanding letters of
credit.
“We delivered on the promises we made last
spring to bridge to the end of 2021 as the pandemic took its hold
on the global economy. At the time, we planned for a two-year
down-cycle in our industry. We immediately began to cut costs and
leverage our strong hedge position in an effort to preserve cash
for 2021. At year-end, we had more than $80 million of cash in the
bank and currently we have more than $100 million. For 2021, we
plan to deploy $120 to $130 million of capital, which should keep
our production relatively flat on an annual basis, with an
accelerated rate exiting 2021. Like 2020, we plan to see oil growth
in our attractive California basin,” stated Cary Baetz, executive
vice president and chief financial officer. “Notably, our reserve
calculations were negatively impacted by the severe price
correction caused by the Saudi/Russia market dispute earlier in the
year and demand erosion due to Covid-19. However, for 2021, we
expect a substantial improvement in our calculated reserves as the
current strip prices are more than 40% higher than the SEC prices
used for the 2020 reserve calculation.”
__________
(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.
Quarterly Dividend
The Company's Board of Directors declared a
regular dividend for the first quarter of 2021 at a rate of $0.04
per share on the Company’s outstanding common stock, payable on
April 15, 2021 to shareholders of record at the close of business
on March 15, 2021. This is the Company’s first regular quarterly
dividend since its suspension during the price decline in early
2020 related to the pandemic and commodities markets.
Subject to approval by the Board and depending
on a variety of factors, including the Company’s financial
condition and results of operations, the Company intends to pay a
similar dividend in future quarters.
Full-Year 2021 Guidance
The Company expects to employ up to three
drilling rigs in California during 2021. Additionally, the Company
anticipates drilling approximately 170 to 200 gross development
wells during 2021, almost all of which will be in California for
oil production.
Full-Year 2021 Guidance |
Low |
|
High |
Average Daily Production (MBoe/d) |
27.0 |
|
29.0 |
Oil as % of Production |
|
~89% |
|
Operating Expenses ($/Boe) |
$17.25 |
|
$18.55 |
Taxes, Other than Income Taxes ($/Boe) |
$3.75 |
|
$4.25 |
Adjusted General & Administrative (G&A) expenses
($/Boe) |
$5.50 |
|
$6.25 |
Capital Expenditures ($ millions) |
$120 |
|
$130 |
New Drill Wells |
170 |
|
200 |
Earnings Conference Call
Berry will host a conference call February 24, 2021
to discuss these results:
Live Call Date: |
Wednesday, February 24, 2021 |
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: |
1256432 |
A live audio webcast will be available on the
“Events” section of Berry’s website
at bry.com/category/events.
An audio replay will be available shortly after the
broadcast:
Replay Dates: |
Through Wednesday, March 10, 2021 |
Replay Dial-in: |
855-859-2056 from the U.S. |
|
404-537-3406 from international locations |
Replay Passcode: |
1256432 |
A replay of the audio webcast will also be
archived on the “Reports & Resources” section of Berry’s
website at ir.bry.com/reports-resources.
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 plans,
activities, events, objectives, goals, strategies, or developments
that the Company expects, believes or anticipates will or may occur
in the future, such as those regarding financial position;
liquidity; cash flows; anticipated financial and operating,
results; capital program and development and production plans;
operations and business strategy; potential acquisition
opportunities; reserves; hedging activities; capital expenditures,
return of capital; payment, improvement of future dividends; future
repurchases of stock or debt; capital investments, recovery factors
and other guidance are forward-looking statements. The
forward-looking statements in this press release are based upon
various assumptions, many of which are based, in turn, upon further
assumptions. Although we believe that these assumptions were
reasonable when made, these assumptions are inherently subject to
significant uncertainties and contingencies which are difficult or
impossible to predict and are beyond our control. Therefore, such
forward-looking statements involve significant risks and
uncertainties that could materially affect our expected results of
operations, liquidity, cash flows and business prospects.
Berry cautions you that these forward-looking
statements are subject to all of the risks and uncertainties,
incident to the exploration for and development, production,
gathering and sale of natural gas, NGLs and oil most of which are
difficult to predict and many of which are beyond Berry’s control.
These risks include, but are not limited to, commodity price
volatility; legislative and regulatory actions that may prevent,
delay or otherwise restrict our ability to drill and develop our
assets, including regulatory approval and permitting requirements;
the impact and duration of the ongoing COVID-19 pandemic on demand
and pricing levels; legislative and regulatory initiatives in
California or our other areas of operation addressing climate
change or other environmental concerns; investment in and
development of competing or alternative energy sources;
drilling and other operating risks; uncertainties inherent in
estimating natural gas and oil reserves and in projecting future
rates of production; cash flow and access to capital; the timing
and funding of development expenditures; environmental risks;
effects of hedging arrangements; potential shut-ins of production
due to lack of downstream demand or storage capacity; and the other
risks described under the heading “Item 1A. Risk Factors” in the
Company’s Annual Report on Form 10-K for the year ended December
31, 2020.
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.
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. Investors are urged to
consider carefully the disclosure in our filings with the
Securities and Exchange Commission, available from us at via our
website or via the Investor Relations contact below, or from the
SEC’s website at www.sec.gov.
TABLES FOLLOWING
The financial information and certain other
information presented 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
|
Quarter Ended December 31,
2020 |
|
Quarter Ended September 30,
2020 |
|
Quarter Ended December 31,
2019 |
|
Year Ended December 31,
2020 |
|
Year Ended December 31,
2019 |
|
|
|
|
|
|
|
|
|
|
|
($ and shares in thousands, except per share amounts) |
Consolidated Statement of Operations Data: |
|
|
|
|
|
|
|
|
|
Revenues and other: |
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
93,811 |
|
|
|
$ |
92,239 |
|
|
|
$ |
156,336 |
|
|
|
$ |
378,663 |
|
|
|
$ |
565,596 |
|
|
Electricity sales |
6,724 |
|
|
|
8,744 |
|
|
|
6,844 |
|
|
|
25,813 |
|
|
|
29,397 |
|
|
(Losses) gains on oil and gas sales derivatives |
(39,617 |
) |
|
|
(11,564 |
) |
|
|
(45,544 |
) |
|
|
117,781 |
|
|
|
(37,998 |
) |
|
Marketing revenues |
351 |
|
|
|
330 |
|
|
|
437 |
|
|
|
1,426 |
|
|
|
2,094 |
|
|
Other revenues |
97 |
|
|
|
— |
|
|
|
55 |
|
|
|
150 |
|
|
|
316 |
|
|
Total revenues and other |
61,366 |
|
|
|
89,749 |
|
|
|
118,128 |
|
|
|
523,833 |
|
|
|
559,405 |
|
|
Expenses and other: |
|
|
|
|
|
|
|
|
|
Lease operating expenses |
49,621 |
|
|
|
45,243 |
|
|
|
59,529 |
|
|
|
186,348 |
|
|
|
216,294 |
|
|
Electricity generation expenses |
5,422 |
|
|
|
4,217 |
|
|
|
4,785 |
|
|
|
16,608 |
|
|
|
19,490 |
|
|
Transportation expenses |
1,559 |
|
|
|
1,768 |
|
|
|
2,124 |
|
|
|
6,938 |
|
|
|
8,059 |
|
|
Marketing expenses |
344 |
|
|
|
326 |
|
|
|
403 |
|
|
|
1,380 |
|
|
|
2,073 |
|
|
General and administrative expenses |
20,409 |
|
|
|
19,173 |
|
|
|
15,710 |
|
|
|
77,696 |
|
|
|
62,643 |
|
|
Depreciation, depletion and amortization |
30,434 |
|
|
|
35,905 |
|
|
|
30,102 |
|
|
|
139,180 |
|
|
|
106,006 |
|
|
Impairment of oil and gas properties |
— |
|
|
|
— |
|
|
|
51,081 |
|
|
|
289,085 |
|
|
|
51,081 |
|
|
Taxes, other than income taxes |
10,858 |
|
|
|
9,913 |
|
|
|
11,962 |
|
|
|
35,572 |
|
|
|
40,645 |
|
|
Losses (gains) on natural gas purchase derivatives |
3,859 |
|
|
|
(15,784 |
) |
|
|
(3,385 |
) |
|
|
1,035 |
|
|
|
6,957 |
|
|
Other operating expenses (income) |
3,123 |
|
|
|
1,648 |
|
|
|
774 |
|
|
|
5,781 |
|
|
|
4,588 |
|
|
Total expenses and other |
125,629 |
|
|
|
102,409 |
|
|
|
173,085 |
|
|
|
759,623 |
|
|
|
517,836 |
|
|
Other (expenses) income: |
|
|
|
|
|
|
|
|
|
Interest expense |
(8,308 |
) |
|
|
(8,391 |
) |
|
|
(7,871 |
) |
|
|
(34,295 |
) |
|
|
(34,234 |
) |
|
Other, net |
(13 |
) |
|
|
(3 |
) |
|
|
— |
|
|
|
(28 |
) |
|
|
80 |
|
|
Total other (expenses) income |
(8,321 |
) |
|
|
(8,394 |
) |
|
|
(7,871 |
) |
|
|
(34,323 |
) |
|
|
(34,154 |
) |
|
Reorganization items, net |
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(426 |
) |
|
(Loss) income before income taxes |
(72,584 |
) |
|
|
(21,054 |
) |
|
|
(62,828 |
) |
|
|
(270,113 |
) |
|
|
6,989 |
|
|
Income tax (benefit) expense |
(8,754 |
) |
|
|
(2,190 |
) |
|
|
(55,844 |
) |
|
|
(7,218 |
) |
|
|
(36,550 |
) |
|
Net (loss) income |
$ |
(63,830 |
) |
|
|
$ |
(18,864 |
) |
|
|
$ |
(6,984 |
) |
|
|
$ |
(262,895 |
) |
|
|
$ |
43,539 |
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings per share: |
|
|
|
|
|
|
|
|
|
Basic |
$ |
(0.80 |
) |
|
|
$ |
(0.24 |
) |
|
|
$ |
(0.09 |
) |
|
|
$ |
(3.29 |
) |
|
|
$ |
0.54 |
|
|
Diluted |
$ |
(0.80 |
) |
|
|
$ |
(0.24 |
) |
|
|
$ |
(0.09 |
) |
|
|
$ |
(3.29 |
) |
|
|
$ |
0.53 |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares outstanding - basic |
79,922 |
|
|
|
79,879 |
|
|
|
80,435 |
|
|
|
79,802 |
|
|
|
81,379 |
|
|
Weighted-average common shares outstanding - diluted |
79,922 |
|
|
|
79,879 |
|
|
|
80,435 |
|
|
|
79,802 |
|
|
|
81,951 |
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net Income(1) |
$ |
8,580 |
|
|
|
$ |
13,452 |
|
|
|
$ |
33,189 |
|
|
|
$ |
44,816 |
|
|
|
$ |
110,228 |
|
|
Weighted-average common shares outstanding - diluted |
80,033 |
|
|
|
80,062 |
|
|
|
80,788 |
|
|
|
79,902 |
|
|
|
81,951 |
|
|
Diluted earnings per share on Adjusted Net Income |
$ |
0.11 |
|
|
|
$ |
0.17 |
|
|
|
$ |
0.41 |
|
|
|
$ |
0.56 |
|
|
|
$ |
1.35 |
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(1) |
$ |
53,682 |
|
|
|
$ |
61,515 |
|
|
|
$ |
86,995 |
|
|
|
$ |
244,430 |
|
|
|
$ |
302,184 |
|
|
Adjusted EBITDA unhedged(1) |
$ |
18,365 |
|
|
|
$ |
26,039 |
|
|
|
$ |
71,529 |
|
|
|
$ |
102,138 |
|
|
|
$ |
259,987 |
|
|
Levered Free Cash Flow(1) |
$ |
33,011 |
|
|
|
$ |
49,129 |
|
|
|
$ |
28,298 |
|
|
|
$ |
131,451 |
|
|
|
$ |
20,127 |
|
|
Levered Free Cash Flow Unhedged(1) |
$ |
(2,306 |
) |
|
|
$ |
13,653 |
|
|
|
$ |
12,832 |
|
|
|
$ |
(10,841 |
) |
|
|
$ |
(22,070 |
) |
|
Adjusted General and Administrative Expenses(1) |
$ |
14,881 |
|
|
|
$ |
13,888 |
|
|
|
$ |
13,421 |
|
|
|
$ |
57,406 |
|
|
|
$ |
51,226 |
|
|
Effective Tax Rate, including discrete items |
12 |
|
% |
|
10 |
|
% |
|
89 |
|
% |
|
3 |
|
% |
|
(523 |
) |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Data: |
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
$ |
52,110 |
|
|
|
$ |
57,997 |
|
|
|
$ |
77,562 |
|
|
|
$ |
196,529 |
|
|
|
$ |
241,829 |
|
|
Net cash used in investing activities |
$ |
(19,098 |
) |
|
|
$ |
(9,004 |
) |
|
|
$ |
(63,739 |
) |
|
|
$ |
(93,620 |
) |
|
|
$ |
(225,025 |
) |
|
Net cash used in financing activities |
$ |
(75 |
) |
|
|
$ |
(1,373 |
) |
|
|
$ |
(28,675 |
) |
|
|
$ |
(22,352 |
) |
|
|
$ |
(85,484 |
) |
|
__________
(1) See further discussion and
reconciliation in “Non-GAAP Financial Measures and
Reconciliations”.
|
December 31, 2020 |
|
December 31, 2019 |
|
|
|
|
|
($ and shares in thousands) |
Balance Sheet Data: |
|
|
|
Total current assets |
$ |
154,491 |
|
$ |
100,432 |
Total property, plant and equipment, net |
$ |
1,258,084 |
|
$ |
1,576,267 |
Total current liabilities |
$ |
175,306 |
|
$ |
156,628 |
Long-term debt |
$ |
393,480 |
|
$ |
394,319 |
Total stockholders' equity |
$ |
714,036 |
|
$ |
972,448 |
Outstanding common stock shares as of |
79,929 |
|
79,543 |
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,
2020 |
Year Ended December 31,
2019 |
|
Year Ended December 31,
2020 |
Year Ended December 31,
2019 |
|
Year Ended December 31,
2020 |
Year Ended December 31,
2019 |
($ in thousands, unless noted otherwise) |
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
335,642 |
|
|
$ |
498,325 |
|
|
$ |
37,481 |
|
|
$ |
59,383 |
|
|
$ |
5,537 |
|
|
$ |
7,740 |
|
|
Operating (loss)
income(1) |
$ |
(7,915 |
) |
|
$ |
230,500 |
|
|
$ |
(126,289 |
) |
|
$ |
7,624 |
|
|
$ |
(357 |
) |
|
$ |
(48,955 |
) |
|
Depreciation, depletion, and amortization (DD&A) |
$ |
130,388 |
|
|
$ |
93,025 |
|
|
$ |
7,058 |
|
|
$ |
11,754 |
|
|
$ |
324 |
|
|
$ |
1,055 |
|
|
Impairment of oil and gas
properties |
$ |
163,879 |
|
|
$ |
— |
|
|
$ |
125,206 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
51,081 |
|
|
Average daily production (MBoe/d) |
22.9 |
|
|
22.6 |
|
|
4.3 |
|
|
5.0 |
|
|
1.3 |
|
|
1.4 |
|
|
Production (oil % of
total) |
100 |
|
% |
100 |
% |
|
50 |
|
% |
54 |
% |
|
2 |
|
% |
2 |
|
% |
Realized sales prices: |
|
|
|
|
|
|
|
|
Oil (per Bbl) |
$ |
40.01 |
|
|
$ |
60.51 |
|
|
$ |
34.81 |
|
|
$ |
45.72 |
|
|
$ |
24.01 |
|
|
$ |
52.36 |
|
|
NGLs (per Bbl) |
$ |
— |
|
|
$ |
— |
|
|
$ |
12.57 |
|
|
$ |
17.08 |
|
|
$ |
— |
|
|
$ |
— |
|
|
Gas (per Mcf) |
$ |
— |
|
|
$ |
— |
|
|
$ |
2.22 |
|
|
$ |
2.94 |
|
|
$ |
1.87 |
|
|
$ |
2.26 |
|
|
Capital expenditures(2) |
$ |
66,398 |
|
|
$ |
189,648 |
|
|
$ |
1,247 |
|
|
$ |
10,229 |
|
|
$ |
206 |
|
|
$ |
603 |
|
|
Total proved reserves (MMBoe) |
87 |
|
|
122 |
|
|
7 |
|
|
15 |
|
|
1 |
|
|
1 |
|
|
__________
(1) Operating income (loss) includes
oil, natural gas and NGL sales, marketing revenues, other revenues,
and scheduled oil derivative settlements, offset by operating
expenses (as defined elsewhere), general and administrative
expenses, DD&A, impairment of oil and gas properties, and
taxes, other than income taxes.
(2) Excludes corporate capital
expenditures.
COMMODITY PRICING
|
Quarter Ended December 31,
2020 |
|
Quarter Ended September 30,
2020 |
|
Quarter Ended December 31,
2019 |
|
Year Ended December 31,
2020 |
|
Year Ended December 31,
2019 |
Realized Prices |
|
|
|
|
|
|
|
|
|
Oil without hedge ($/Bbl) |
$ |
41.38 |
|
|
$ |
39.88 |
|
|
$ |
59.28 |
|
|
$ |
39.56 |
|
|
$ |
58.93 |
|
Effects of derivative settlements ($/Bbl) |
$ |
15.03 |
|
|
$ |
16.28 |
|
|
$ |
5.70 |
|
|
$ |
16.51 |
|
|
$ |
4.68 |
|
Oil with hedge ($/Bbl) |
$ |
56.41 |
|
|
$ |
56.16 |
|
|
$ |
64.98 |
|
|
$ |
56.07 |
|
|
$ |
63.61 |
|
Natural gas ($/Mcf) |
$ |
2.78 |
|
|
$ |
1.95 |
|
|
$ |
2.60 |
|
|
$ |
2.08 |
|
|
$ |
2.66 |
|
NGLs ($/Bbl) |
$ |
16.78 |
|
|
$ |
13.25 |
|
|
$ |
14.60 |
|
|
$ |
12.57 |
|
|
$ |
17.02 |
|
|
|
|
|
|
|
|
|
|
|
Index Prices |
|
|
|
|
|
|
|
|
|
Brent oil ($/Bbl) |
$ |
45.26 |
|
|
$ |
43.34 |
|
|
$ |
62.42 |
|
|
$ |
43.21 |
|
|
$ |
64.16 |
|
WTI oil ($/Bbl) |
$ |
42.66 |
|
|
$ |
40.87 |
|
|
$ |
57.02 |
|
|
$ |
39.59 |
|
|
$ |
57.03 |
|
Kern, Delivered natural gas ($/MMBtu)(1) |
$ |
3.38 |
|
|
$ |
2.84 |
|
|
$ |
2.99 |
|
|
$ |
2.46 |
|
|
$ |
3.14 |
|
Henry Hub natural gas ($/MMBtu)(2) |
$ |
2.52 |
|
|
$ |
2.00 |
|
|
$ |
2.40 |
|
|
$ |
2.03 |
|
|
$ |
2.56 |
|
__________
(1) Kern, Delivered Index is the
relevant index used for gas purchases in California.
(2) Henry Hub is the relevant index
used for gas sales in the Rockies.
CURRENT HEDGING SUMMARY
As of December 31, 2020, our positions were as
follows:
|
Q1 2021 |
|
Q2 2021 |
|
Q3 2021 |
|
Q4 2021 |
Fixed Price Oil Swaps (Brent): |
|
|
|
|
|
|
|
Hedged volume (MBbls) |
1,710 |
|
|
1,728 |
|
|
1,042 |
|
|
1,042 |
|
Weighted-average price ($/Bbl) |
$ |
45.82 |
|
|
$ |
45.82 |
|
|
$ |
46.17 |
|
|
$ |
46.17 |
|
Fixed Price Gas Purchase Swaps (Kern,
Delivered): |
|
|
|
|
|
|
|
Hedged volume (MMBtu) |
4,950,000 |
|
|
4,777,500 |
|
|
4,830,000 |
|
|
2,085,000 |
|
Weighted-average price ($/MMBtu) |
$ |
2.69 |
|
|
$ |
2.83 |
|
|
$ |
2.83 |
|
|
$ |
2.95 |
|
As of December 31, 2020 we also had open swap
positions that are excluded from the table above where we are both
buyer and seller of equal notional volumes of 12,500 MMBtu/d of
fixed price gas sales swaps each indexed to Northwest Pipeline
Rocky Mountains and CIG, for the period January 1, 2021 through
December 31, 2021. These swap positions effectively cancel each
other while resulting in a mark-to-market gain of
$2.6 million. This gain will be cash settled in 2021 as the
positions expire
In February 2021, we added 3,000 Bbls/d of fixed
price oil swaps (Brent) at approximately $58 for the period July
2021 through December 31, 2021.
OPERATING EXPENSES
|
Quarter Ended December 31,
2020 |
|
Quarter Ended September 30,
2020 |
|
Quarter Ended December 31,
2019 |
|
Year Ended December 31,
2020 |
|
Year Ended December 31,
2019 |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands except per Boe amounts) |
Expenses: |
|
|
|
|
|
|
|
|
|
Lease operating expenses |
$ |
49,621 |
|
|
|
$ |
45,243 |
|
|
|
$ |
59,529 |
|
|
|
$ |
186,348 |
|
|
|
$ |
216,294 |
|
|
Electricity generation expenses |
5,422 |
|
|
|
4,217 |
|
|
|
4,785 |
|
|
|
16,608 |
|
|
|
19,490 |
|
|
Electricity sales |
(6,724 |
) |
|
|
(8,744 |
) |
|
|
(6,844 |
) |
|
|
(25,813 |
) |
|
|
(29,397 |
) |
|
Transportation expenses |
1,559 |
|
|
|
1,768 |
|
|
|
2,124 |
|
|
|
6,938 |
|
|
|
8,059 |
|
|
Transportation sales |
(97 |
) |
|
|
— |
|
|
|
(55 |
) |
|
|
(150 |
) |
|
|
(316 |
) |
|
Marketing expenses |
344 |
|
|
|
326 |
|
|
|
403 |
|
|
|
1,380 |
|
|
|
2,073 |
|
|
Marketing revenues |
(351 |
) |
|
|
(330 |
) |
|
|
(437 |
) |
|
|
(1,426 |
) |
|
|
(2,094 |
) |
|
Derivative settlements (received) paid for gas purchases(1) |
(3,090 |
) |
|
|
614 |
|
|
|
(906 |
) |
|
|
9,298 |
|
|
|
1,059 |
|
|
Total operating expenses(2) |
$ |
46,684 |
|
|
|
$ |
43,094 |
|
|
|
$ |
58,599 |
|
|
|
$ |
193,183 |
|
|
|
$ |
215,168 |
|
|
|
|
|
|
|
|
|
|
|
|
Expenses per
Boe:(2) |
|
|
|
|
|
|
|
|
|
Lease operating expenses |
$ |
20.25 |
|
|
|
$ |
17.83 |
|
|
|
$ |
20.69 |
|
|
|
$ |
17.86 |
|
|
|
$ |
20.42 |
|
|
Electricity generation expenses |
2.21 |
|
|
|
1.66 |
|
|
|
1.66 |
|
|
|
1.59 |
|
|
|
1.84 |
|
|
Electricity sales |
(2.74 |
) |
|
|
(3.45 |
) |
|
|
(2.38 |
) |
|
|
(2.47 |
) |
|
|
(2.77 |
) |
|
Transportation expenses |
0.64 |
|
|
|
0.69 |
|
|
|
0.74 |
|
|
|
0.66 |
|
|
|
0.76 |
|
|
Transportation sales |
(0.04 |
) |
|
|
— |
|
|
|
(0.02 |
) |
|
|
(0.01 |
) |
|
|
(0.03 |
) |
|
Marketing expenses |
0.14 |
|
|
|
0.13 |
|
|
|
0.14 |
|
|
|
0.13 |
|
|
|
0.20 |
|
|
Marketing revenues |
(0.14 |
) |
|
|
(0.13 |
) |
|
|
(0.15 |
) |
|
|
(0.14 |
) |
|
|
(0.20 |
) |
|
Derivative settlements (received) paid for gas purchases |
(1.26 |
) |
|
|
0.24 |
|
|
|
(0.31 |
) |
|
|
0.89 |
|
|
|
0.10 |
|
|
Total operating expenses(2) |
$ |
19.06 |
|
|
|
$ |
16.97 |
|
|
|
$ |
20.37 |
|
|
|
$ |
18.51 |
|
|
|
$ |
20.32 |
|
|
Total unhedged operating expenses(1) |
$ |
20.32 |
|
|
|
$ |
16.73 |
|
|
|
$ |
20.68 |
|
|
|
$ |
17.62 |
|
|
|
$ |
20.22 |
|
|
|
|
|
|
|
|
|
|
|
|
Total non-energy operating expenses(3) |
$ |
14.35 |
|
|
|
$ |
13.34 |
|
|
|
$ |
14.96 |
|
|
|
$ |
13.63 |
|
|
|
$ |
14.80 |
|
|
Total energy operating expenses(4) |
$ |
4.70 |
|
|
|
$ |
3.65 |
|
|
|
$ |
5.41 |
|
|
|
$ |
4.88 |
|
|
|
$ |
5.51 |
|
|
|
|
|
|
|
|
|
|
|
|
Total MBoe |
2,450 |
|
|
|
2,537 |
|
|
|
2,877 |
|
|
|
10,435 |
|
|
|
10,594 |
|
|
__________
(1) Total unhedged operating
expenses equals total operating expenses, excluding the derivative
settlements paid (received) for gas purchases.(2) We
report electricity, transportation and marketing sales separately
in our financial statements as revenues in accordance with GAAP.
However, these revenues are viewed and used internally in
calculating operating expenses which is used to track and analyze
the economics of development projects and the efficiency of our
hydrocarbon recovery. We purchase third-party gas to generate
electricity through our cogeneration facilities to be used in our
field operations activities and view the added benefit of any
excess electricity sold externally as a cost reduction/benefit to
generating steam for our thermal recovery operations. Marketing
revenues and expenses mainly relate to natural gas purchased from
third parties that moves through our gathering and processing
systems and then is sold to third parties. Transportation sales
relate to water and other liquids that we transport on our systems
on behalf of third parties and have not been significant to date.
Operating expenses also include the effect of derivative
settlements (received or paid) for gas purchases.(3)
Total non-energy operating expenses equals total operating
expenses, excluding fuel, electricity sales and gas purchase
derivative settlements (gains) losses.(4) Total energy
operating expenses equals fuel and gas purchase derivative
settlements (gains) losses less electricity sales.
PRODUCTION STATISTICS
|
Quarter Ended December 31,
2020 |
|
Quarter Ended September 30,
2020 |
|
Quarter Ended December 31,
2019 |
|
Year Ended December 31,
2020 |
|
Year Ended December 31,
2019 |
Net Oil, Natural Gas and NGLs Production Per
Day(1): |
|
|
|
|
|
|
|
|
|
Oil (MBbl/d) |
|
|
|
|
|
|
|
|
|
California |
21.2 |
|
|
22.2 |
|
|
25.5 |
|
|
22.9 |
|
|
22.6 |
|
Utah |
2.1 |
|
|
1.9 |
|
|
2.2 |
|
|
2.1 |
|
|
2.7 |
|
Colorado |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Total oil |
23.3 |
|
|
24.1 |
|
|
27.7 |
|
|
25.0 |
|
|
25.3 |
|
Natural gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
California |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Utah |
9.8 |
|
|
11.0 |
|
|
10.7 |
|
|
10.7 |
|
|
11.2 |
|
Colorado |
7.8 |
|
|
7.7 |
|
|
8.2 |
|
|
7.8 |
|
|
8.8 |
|
Total natural gas |
17.6 |
|
|
18.7 |
|
|
18.9 |
|
|
18.5 |
|
|
20.0 |
|
NGLs (MBbl/d) |
|
|
|
|
|
|
|
|
|
California |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Utah |
0.4 |
|
|
0.4 |
|
|
0.4 |
|
|
0.4 |
|
|
0.4 |
|
Colorado |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Total NGLs |
0.4 |
|
|
0.4 |
|
|
0.4 |
|
|
0.4 |
|
|
0.4 |
|
Total Production
(MBoe/d)(2) |
26.6 |
|
|
27.6 |
|
|
31.3 |
|
|
28.5 |
|
|
29.0 |
|
__________
(1) Production represents volumes
sold during the period. We also consume a portion of the natural
gas we produce on lease to extract oil and gas.
(2) Natural gas volumes have been
converted to Boe based on energy content of six Mcf of gas to one
Bbl of oil. Barrels of oil equivalence does not necessarily result
in price equivalence. The price of natural gas on a barrel of oil
equivalent basis is currently substantially lower than the
corresponding price for oil and has been similarly lower for a
number of years. For example, in the year ended December 31, 2020,
the average prices of Brent oil and Henry Hub natural gas were
$43.21 per Bbl and $2.03 per MMBtu, respectively.
CAPITAL EXPENDITURES (ACCRUAL
BASIS)
|
Quarter Ended December 31,
2020 |
|
Quarter Ended September 30,
2020 |
|
Quarter Ended December 31,
2019 |
|
Year Ended December 31,
2020 |
|
Year Ended December 31,
2019 |
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
Capital expenditures (accrual basis) |
$ |
12,363 |
|
|
$ |
3,995 |
|
|
$ |
41,274 |
|
|
$ |
69,120 |
|
|
$ |
208,770 |
|
__________
(1) Capital expenditures on an
accrual basis excludes capitalized overhead and interest,
acquisitions and asset retirement spending.
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, 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. 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 non-cash stock compensation expense and unusual, out
of period and infrequent costs.
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.
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).
|
Quarter Ended December 31,
2020 |
|
Quarter Ended September 30,
2020 |
|
Quarter Ended December 31,
2019 |
|
Year Ended December 31,
2020 |
|
Year Ended December 31,
2019 |
|
|
|
|
|
|
|
|
|
|
|
($ thousands, except per share amounts) |
Net (loss) income |
$ |
(63,830 |
) |
|
|
$ |
(18,864 |
) |
|
|
$ |
(6,984 |
) |
|
|
$ |
(262,895 |
) |
|
|
$ |
43,539 |
|
|
Add (Subtract): discrete income tax items |
16,724 |
|
|
|
(2,394 |
) |
|
|
(38,653 |
) |
|
|
61,030 |
|
|
|
(38,653 |
) |
|
|
|
|
|
|
|
|
|
|
|
Add (Subtract): |
|
|
|
|
|
|
|
|
|
Losses (gains) on derivatives |
43,476 |
|
|
|
(4,220 |
) |
|
|
42,159 |
|
|
|
(116,746 |
) |
|
|
44,955 |
|
|
Net cash received for scheduled derivative settlements |
35,317 |
|
|
|
35,476 |
|
|
|
15,466 |
|
|
|
142,292 |
|
|
|
42,197 |
|
|
Other operating expenses |
3,123 |
|
|
|
1,648 |
|
|
|
774 |
|
|
|
5,781 |
|
|
|
4,588 |
|
|
Impairment of oil and gas properties |
— |
|
|
|
— |
|
|
|
51,081 |
|
|
|
289,085 |
|
|
|
51,081 |
|
|
Non-recurring costs |
2,375 |
|
|
|
1,473 |
|
|
|
— |
|
|
|
6,026 |
|
|
|
3,061 |
|
|
Reorganization items, net |
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
426 |
|
|
Total additions (subtractions), net |
84,291 |
|
|
|
34,377 |
|
|
|
109,480 |
|
|
|
326,438 |
|
|
|
146,308 |
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (expense) benefit of adjustments at effective tax
rate(1) |
(28,605 |
) |
|
|
333 |
|
|
|
(30,654 |
) |
|
|
(79,757 |
) |
|
|
(40,966 |
) |
|
Adjusted Net Income (Loss) |
$ |
8,580 |
|
|
|
$ |
13,452 |
|
|
|
$ |
33,189 |
|
|
|
$ |
44,816 |
|
|
|
$ |
110,228 |
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS on Adjusted Net Income |
$ |
0.11 |
|
|
|
$ |
0.17 |
|
|
|
$ |
0.41 |
|
|
|
$ |
0.56 |
|
|
|
$ |
1.35 |
|
|
Diluted EPS on Adjusted Net Income |
$ |
0.11 |
|
|
|
$ |
0.17 |
|
|
|
$ |
0.41 |
|
|
|
$ |
0.56 |
|
|
|
$ |
1.35 |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding - basic |
79,922 |
|
|
|
79,879 |
|
|
|
80,435 |
|
|
|
79,802 |
|
|
|
81,379 |
|
|
Weighted average shares outstanding - diluted |
80,033 |
|
|
|
80,062 |
|
|
|
80,788 |
|
|
|
79,902 |
|
|
|
81,951 |
|
|
__________
(1) Excludes discrete income tax
items from the total additions (subtractions), net line item and
the tax effect the discrete income tax items have on the current
rate.
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.
|
Quarter Ended December 31,
2020 |
|
Quarter Ended September 30,
2020 |
|
Quarter Ended December 31,
2019 |
|
Year Ended December 31,
2020 |
|
Year Ended December 31,
2019 |
|
|
|
|
|
|
|
|
|
|
|
($ thousands) |
Net income (loss) |
$ |
(63,830 |
) |
|
|
$ |
(18,864 |
) |
|
|
$ |
(6,984 |
) |
|
|
$ |
(262,895 |
) |
|
|
$ |
43,539 |
|
|
Add (Subtract): |
|
|
|
|
|
|
|
|
|
Interest expense |
8,308 |
|
|
|
8,391 |
|
|
|
7,871 |
|
|
|
34,295 |
|
|
|
34,234 |
|
|
Income tax expense (benefit) |
(8,754 |
) |
|
|
(2,190 |
) |
|
|
(55,845 |
) |
|
|
(7,218 |
) |
|
|
(36,550 |
) |
|
Depreciation, depletion, and amortization |
30,434 |
|
|
|
35,905 |
|
|
|
30,102 |
|
|
|
139,180 |
|
|
|
106,006 |
|
|
Impairment of oil and gas properties |
— |
|
|
|
— |
|
|
|
51,081 |
|
|
|
289,085 |
|
|
|
51,081 |
|
|
(Gains) losses on derivatives |
43,476 |
|
|
|
(4,220 |
) |
|
|
42,160 |
|
|
|
(116,746 |
) |
|
|
44,955 |
|
|
Net cash received for scheduled derivative settlements |
35,317 |
|
|
|
35,476 |
|
|
|
15,466 |
|
|
|
142,292 |
|
|
|
42,197 |
|
|
Other operating expenses |
3,123 |
|
|
|
1,648 |
|
|
|
774 |
|
|
|
5,781 |
|
|
|
4,588 |
|
|
Stock compensation expense |
3,233 |
|
|
|
3,896 |
|
|
|
2,370 |
|
|
|
14,630 |
|
|
|
8,647 |
|
|
Non-recurring costs |
2,375 |
|
|
|
1,473 |
|
|
|
— |
|
|
|
6,026 |
|
|
|
3,061 |
|
|
Reorganization items, net |
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
426 |
|
|
Adjusted EBITDA |
$ |
53,682 |
|
|
|
$ |
61,515 |
|
|
|
$ |
86,995 |
|
|
|
$ |
244,430 |
|
|
|
$ |
302,184 |
|
|
Net cash (received) paid for scheduled derivative settlements |
(35,317 |
) |
|
|
(35,476 |
) |
|
|
(15,466 |
) |
|
|
(142,292 |
) |
|
|
(42,197 |
) |
|
Adjusted EBITDA unhedged |
$ |
18,365 |
|
|
|
$ |
26,039 |
|
|
|
$ |
71,529 |
|
|
|
$ |
102,138 |
|
|
|
$ |
259,987 |
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
$ |
52,110 |
|
|
|
$ |
57,997 |
|
|
|
$ |
77,562 |
|
|
|
$ |
196,529 |
|
|
|
$ |
241,829 |
|
|
Add (Subtract): |
|
|
|
|
|
|
|
|
|
Cash interest payments |
— |
|
|
|
14,435 |
|
|
|
584 |
|
|
|
29,962 |
|
|
|
30,720 |
|
|
Cash income tax payments (refunds) |
— |
|
|
|
221 |
|
|
|
(3 |
) |
|
|
222 |
|
|
|
(2 |
) |
|
Non-recurring costs |
2,375 |
|
|
|
1,473 |
|
|
|
— |
|
|
|
6,026 |
|
|
|
3,061 |
|
|
Other changes in operating assets and liabilities |
(803 |
) |
|
|
(12,611 |
) |
|
|
8,852 |
|
|
|
11,691 |
|
|
|
26,576 |
|
|
Adjusted EBITDA |
$ |
53,682 |
|
|
|
$ |
61,515 |
|
|
|
$ |
86,995 |
|
|
|
$ |
244,430 |
|
|
|
$ |
302,184 |
|
|
Net cash (received) paid for scheduled derivative settlements |
(35,317 |
) |
|
|
(35,476 |
) |
|
|
(15,466 |
) |
|
|
(142,292 |
) |
|
|
(42,197 |
) |
|
Adjusted EBITDA unhedged |
$ |
18,365 |
|
|
|
$ |
26,039 |
|
|
|
$ |
71,529 |
|
|
|
$ |
102,138 |
|
|
|
$ |
259,987 |
|
|
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.
|
Quarter Ended December 31,
2020 |
|
Quarter Ended September 30,
2020 |
|
Quarter Ended December 31,
2019 |
|
Year Ended December 31,
2020 |
|
Year Ended December 31,
2019 |
|
|
|
|
|
|
|
|
|
|
|
($ thousands) |
Adjusted EBITDA |
$ |
53,682 |
|
|
|
$ |
61,515 |
|
|
|
$ |
86,995 |
|
|
|
$ |
244,430 |
|
|
|
$ |
302,184 |
|
|
Subtract: |
|
|
|
|
|
|
|
|
|
Capital expenditures - accrual basis(1) |
(12,363 |
) |
|
|
(3,995 |
) |
|
|
(41,274 |
) |
|
|
(69,120 |
) |
|
|
(208,770 |
) |
|
Interest expense |
(8,308 |
) |
|
|
(8,391 |
) |
|
|
(7,871 |
) |
|
|
(34,295 |
) |
|
|
(34,234 |
) |
|
Cash dividends declared |
— |
|
|
|
— |
|
|
|
(9,552 |
) |
|
|
(9,564 |
) |
|
|
(39,053 |
) |
|
Levered Free Cash Flow |
$ |
33,011 |
|
|
|
$ |
49,129 |
|
|
|
$ |
28,298 |
|
|
|
$ |
131,451 |
|
|
|
$ |
20,127 |
|
|
Net cash (received) paid for scheduled derivative settlements |
(35,317 |
) |
|
|
(35,476 |
) |
|
|
(15,466 |
) |
|
|
(142,292 |
) |
|
|
(42,197 |
) |
|
Levered Free Cash Flow Unhedged |
$ |
(2,306 |
) |
|
|
$ |
13,653 |
|
|
|
$ |
12,832 |
|
|
|
$ |
(10,841 |
) |
|
|
$ |
(22,070 |
) |
|
__________
(1) Capital expenditures on an
accrual basis excludes capitalized overhead and interest and
acquisitions. Also excluded is asset retirement spending of $4.0
million, $3.7 million, and $7.2 million for the quarters ended
December 31, 2020, September 30, 2020 and December 31, 2019,
respectively, and $18.1 million and $26.9 million for the years
ended December 31, 2020 and 2019, respectively.
ADJUSTED GENERAL AND ADMINISTRATIVE
EXPENSES
The following table presents a reconciliation of
the GAAP financial measure of general and administrative expenses
to the non-GAAP financial measures of Adjusted General and
Administrative Expenses.
|
Quarter Ended December 31,
2020 |
|
Quarter Ended September 30,
2020 |
|
Quarter Ended December 31,
2019 |
|
Year Ended December 31,
2020 |
|
Year Ended December 31,
2019 |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands except per MBoe amounts) |
General and administrative expenses |
$ |
20,409 |
|
|
|
$ |
19,173 |
|
|
|
$ |
15,710 |
|
|
|
$ |
77,696 |
|
|
|
$ |
62,643 |
|
|
Subtract: |
|
|
|
|
|
|
|
|
|
Non-cash stock compensation expense (G&A portion) |
(3,153 |
) |
|
|
(3,812 |
) |
|
|
(2,289 |
) |
|
|
(14,264 |
) |
|
|
(8,356 |
) |
|
Non-recurring costs |
(2,375 |
) |
|
|
(1,473 |
) |
|
|
— |
|
|
|
(6,026 |
) |
|
|
(3,061 |
) |
|
Adjusted General and Administrative Expenses |
$ |
14,881 |
|
|
|
$ |
13,888 |
|
|
|
$ |
13,421 |
|
|
|
$ |
57,406 |
|
|
|
$ |
51,226 |
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses ($/Boe) |
$ |
8.33 |
|
|
|
$ |
7.56 |
|
|
|
$ |
5.46 |
|
|
|
$ |
7.45 |
|
|
|
$ |
5.91 |
|
|
Subtract: |
|
|
|
|
|
|
|
|
|
Non-cash stock compensation expense ($/Boe) |
(1.29 |
) |
|
|
(1.50 |
) |
|
|
(0.80 |
) |
|
|
(1.37 |
) |
|
|
(0.79 |
) |
|
Non-recurring costs ($/Boe) |
(0.97 |
) |
|
|
(0.58 |
) |
|
|
— |
|
|
|
(0.58 |
) |
|
|
(0.29 |
) |
|
Adjusted General and Administrative Expenses ($/Boe) |
$ |
6.07 |
|
|
|
$ |
5.47 |
|
|
|
$ |
4.66 |
|
|
|
$ |
5.50 |
|
|
|
$ |
4.84 |
|
|
|
|
|
|
|
|
|
|
|
|
Total MBoe |
2,450 |
|
|
|
2,537 |
|
|
|
2,877 |
|
|
|
10,435 |
|
|
|
10,594 |
|
|
RESERVES AND PV-10
The following table summarizes our estimated
proved reserves and related PV-10 as of December 31, 2020.
|
Proved Reserves as of December 31,
2020(1) |
|
California (San Joaquin and Ventura
basins) |
|
Utah (Uinta basin) |
|
Colorado (Piceance
basin) |
|
Total |
Proved developed reserves: |
|
|
|
|
|
|
|
Oil (MMBbl) |
48 |
|
|
3 |
|
|
— |
|
|
51 |
|
Natural Gas (Bcf) |
— |
|
|
22 |
|
|
4 |
|
|
26 |
|
NGLs (MMBbl) |
— |
|
|
1 |
|
|
— |
|
|
1 |
|
Total (MMBoe)(2)(3) |
48 |
|
|
7 |
|
|
1 |
|
|
56 |
|
Proved undeveloped reserves: |
|
|
|
|
|
|
|
Oil (MMBbl) |
39 |
|
|
— |
|
|
— |
|
|
39 |
|
Natural Gas (Bcf) |
— |
|
|
— |
|
|
— |
|
|
— |
|
NGLs (MMBbl) |
— |
|
|
— |
|
|
— |
|
|
— |
|
Total (MMBoe)(3) |
39 |
|
|
— |
|
|
— |
|
|
39 |
|
Total proved reserves: |
|
|
|
|
|
|
|
Oil (MMBbl) |
87 |
|
|
3 |
|
|
— |
|
|
90 |
|
Natural Gas (Bcf) |
— |
|
|
22 |
|
|
4 |
|
|
26 |
|
NGLs (MMBbl) |
— |
|
|
1 |
|
|
— |
|
|
1 |
|
Total (MMBoe)(3) |
87 |
|
|
7 |
|
|
1 |
|
|
95 |
|
|
|
|
|
|
|
|
|
PV-10 (in millions)(4) |
$ |
504 |
|
|
$ |
16 |
|
|
— |
|
|
$ |
520 |
|
__________
(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 $41.77 per Bbl Brent for oil and NGLs and $2.03 per
MMBtu Henry Hub for natural gas at December 31, 2020. The
volume-weighted average prices over the lives of the properties
were $39.97 per Bbl of oil and condensate, $9.40 per Bbl of NGLs
and $2.19 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) For proved developed reserves
approximately 11% of total and 12% of oil are non-producing.
(3) Natural gas volumes have been
converted to Boe based on energy content of six Mcf of gas to one
Bbl of oil. Barrels of oil equivalence does not necessarily result
in price equivalence. The price of natural gas on a barrel of oil
equivalent basis is currently substantially lower than the
corresponding price for oil and has been similarly lower for a
number of years. For example, in the year ended December 31, 2020,
the average prices of Brent oil and Henry Hub natural gas were
$43.21 per Bbl and $2.03 per MMBtu, respectively.
(4) For a definition of PV-10 and a
reconciliation to the standardized measure of discounted future net
cash flows, please see the table below. 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, 2020:
|
At December 31, 2020 |
|
(in millions) |
California PV-10 |
$ |
504 |
|
|
Utah PV-10 |
16 |
|
|
Colorado PV-10 |
— |
|
|
Total Company PV-10 |
520 |
|
|
Less: present value of future income taxes discounted at 10% |
(4 |
) |
|
Standardized measure of discounted future net cash flows |
$ |
516 |
|
|
The following table presents reserves changes
and production for 2020:
|
Total Company |
|
California |
|
|
|
|
|
(in MMBoe) |
Extensions and discoveries |
1 |
|
|
|
1 |
|
|
Revisions of previous estimates |
(34 |
) |
|
|
(28 |
) |
|
Purchases of minerals(1) |
— |
|
|
|
— |
|
|
Total reserves changes |
(33 |
) |
|
|
(27 |
) |
|
|
|
|
|
Production |
10 |
|
|
|
8 |
|
|
__________
(1) Purchases of minerals in place
were less than 1 MMBoe.
Contact
Contact: Berry Corporation (bry)
Todd Crabtree - Manager, Investor Relations
(661) 616-3811
ir@bry.com
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