Berry Corporation (bry) (NASDAQ: BRY) (“Berry” or the “Company”)
today reported fourth quarter and full-year 2021 results. For the
fourth quarter the net income was $9 million, or $0.11 per diluted
share, and Adjusted Net Income(1) was $10 million, or $0.12 per
diluted share. For the full year Berry's net loss was $16 million,
or $0.19 per diluted share, and Adjusted Net Income(1) was $21
million, or $0.25 per diluted share. In addition, the Company's
Board of Directors approved a first quarter 2022 dividend of $0.06
per share.
2021 Highlights
- Generated Adjusted EBITDA(1) of
$212 million (hedged) and $300 million (unhedged) for the year
- Increased production each quarter;
2021 Q4 exit rate was 5% higher than prior year
- Reduced non-energy operating
expenses by $11 million or 8% compared to prior year
- Reduced our required GHG offsets
and approximately $53 million of ARO through various A&D
activities
- Boosted shareholder returns with a
50% increase in quarterly fixed dividends in Q3 2021 and created
new shareholder return model starting in Q1 2022 targeting top tier
returns
__________
(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.
“In 2022, under our new shareholder return
model, which we are implementing in Q1 2022, we currently expect to
deliver a 2022 overall cash return in the mid- to high teens at
today’s oil and stock prices. In terms of dollars, the 2022 cash
return is expected be about 160% to 190% of the $82 million we've
returned since going public three-and-a-half years ago. Like our
business model, our new shareholder return model has
predictability, simplicity, and transparency as its governing
principles. The foundation of our return model is our base
production, of which approximately 90% comes from our existing
wells. Drilling new wells and workovers of existing wells are used
to cover the gap between our base production and our goal of
holding production flat. Combining the tremendous value of our base
production with simple cost structure and current oil price strip
makes our returns to shareholders easy to calculate and highly
predictable,” said Trem Smith, Berry board chairman and CEO.
“At Berry, we are continuing to advance our
Environment, Social and Governance (ESG) initiatives while having a
positive economic impact on our operations. Our planned activities
include two solar projects, a carbon sequestration project, a clean
water project, upgrading to low emission Tier 4 engines on many of
our service rigs, and various other greenhouse gas (GHG) reduction
opportunities. Beyond our ESG capital projects, we are also
uniquely positioned to capture a portion of the recently announced
state and federal funds to plug and abandon California’s thousands
of methane leaking, orphan wells with our well services business.
This is just the beginning for Berry’s ESG program as we continue
to demonstrate our commitment to being a good corporate citizen
while providing equitable and affordable energy for all
Californians,” continued Smith.
Fourth Quarter 2021 Results
Adjusted EBITDA(1) on a hedged basis was $60
million in the fourth quarter 2021 compared to $59 million in the
third quarter 2021. This increase is largely the result of higher
oil and gas prices and increased oil volumes, as well as a positive
impact from the acquisition of C&J Well Services in the fourth
quarter, partially offset by higher energy operating expenses.
The Company realized a 2% increase in average
daily production in the fourth quarter 2021 to 27,900 boe/d,
despite the divestment of our Los Angeles County Placerita assets
in October, when compared to the third quarter volumes of 27,400
boe/d, as a result of its successful 2021 development program.
Company-wide oil production in the fourth quarter 2021 increased 3%
sequentially and California production, which is all oil and 92% of
total company production, increased 4% to 22,700 mboe/d in the
fourth quarter. On a pro forma basis, California production would
have been 6% higher with a full quarter of the divested Placerita
assets.
The Company-wide hedged realized oil price for
the fourth quarter 2021 was $54.61 per bbl, a slight increase from
the third quarter. California’s unhedged realized oil price in the
fourth quarter increased 9% to $75.90 per bbl, which was 95% of
Brent.
Operating expenses, or OpEx, consists of lease
operating expenses (“LOE”), third-party expenses and revenues from
electricity generation, transportation, and marketing activities,
as well as the effect of derivative settlements (received or paid)
for gas purchases.
On a hedged basis, OpEx increased to $22.46 per
boe for the fourth quarter 2021, compared to $17.18 per boe in the
third quarter. This 31% increase in OpEx was entirely due to higher
hedged natural gas fuel prices and lower electricity revenues due
to the seasonal impact and the sale of our largest cogeneration
facility with the Placerita divestiture. The higher hedged natural
gas prices were due to the previous hedges expiring and the new
hedges that were in place at less favorable pricing. Non-energy
OpEx decreased approximately 1% on a per boe basis due to decreased
well maintenance, recompletion, and workover activity in the fourth
quarter.
Taxes, other than income taxes were $4.65 per
boe in the fourth quarter compared to $5.33 in the third quarter.
The decrease was largely due to lower property taxes for the
quarter, including the impact of the Placerita divestiture.
General and administrative expenses increased
27% in the fourth quarter 2021 compared to the third quarter 2021,
primarily due to C&J Well Services which was acquired on
October 1, 2021. Adjusted General and Administrative Expenses(1),
which excludes non-cash stock compensation costs and nonrecurring
costs, increased 26% for the same reason.
The results of operations from C&J Well
Services were included in Berry's consolidated results beginning
the fourth quarter 2021. The C&J Well Services fourth quarter
results included services revenues of $36 million, costs of
services of $28 million, net income before income taxes of less
than $1 million and Adjusted EBITDA of $4 million. The C&J Well
Services general and administrative expenses were $4.5 million and
adjusted general and administrative expenses were $3.2 million,
which excludes non-recurring costs related to the acquisition and
transition activity.
For the fourth quarter 2021, capital
expenditures were approximately $27 million on an accrual
basis and excluding acquisitions and asset retirement obligation
spending, as well as C&J Well Services capital of $1 million.
This was a decrease compared to $38 million for the third
quarter reflecting the planned reduction in activity in the fourth
quarter. Nearly all of the fourth quarter capital was focused on
development activities in California. Additionally, Berry spent
approximately $7 million for plugging and abandonment activities in
the fourth quarter.
At December 31, 2021, the Company had liquidity
of $215 million, consisting of $22 million cash on hand and
$193 million available for borrowings under our 2021 RBL
Facility.
Full-Year 2021 Results
Adjusted EBITDA(1) on a hedged basis was
$212 million in 2021 compared to $244 million in 2020. The
decrease was primarily driven by lower realized hedged prices in
2021. Additionally, taxes other than income taxes were higher in
2021. On a year-over-year basis, non-energy OpEx, energy OpEx and
adjusted general and administrative expenses all experienced
decreases. On an unhedged basis, Adjusted EBITDA increased to $300
million in 2021 compared to $102 million in 2020.
Average daily production for 2021 was 27,400
boe/d and increased each quarter throughout 2021, and the fourth
quarter of 2021 was 5% higher than the same quarter of 2020. This
is indicative of the positive response from our assets with
strategic capital deployment. The year-over-year production results
were impacted by the significant capital reduction in 2020 in
response to the significant decline in oil price and the measured
ramp up in activity in early 2021. Oil production decreased 4% in
2021 compared to 2020, however the fourth quarter 2021 exit rate
was 6% higher than the fourth quarter of the prior year. As a
result of the 2021 development campaign in Utah, the year-over-year
production in Utah was essentially flat compared to the decline of
14% in 2020.
Company-wide hedged realized oil prices were
$50.12 per bbl in 2021 compared to $56.07 per bbl in 2020. The
California average unhedged oil price was $67.27 per bbl, 95% of
Brent in 2021 and $40.01 per bbl in 2020, 93% of Brent.
OpEx on a hedged basis decreased $0.62 per boe
from 2020 to $17.89 in 2021. Most of the cost savings was realized
in non energy OpEx which decreased $0.51 per boe as a result of
cost saving and efficiency measures implemented beginning in 2020
and continuing in 2021. Energy OpEx decreased $0.11 per boe due to
higher electricity revenue partially offset by higher hedged fuel
costs.
Taxes, other than income taxes, increased $1.24
to $4.65 per boe in 2021 compared to $3.41 in 2020. The increase
was largely due to higher greenhouse gas (“GHG”) prices during
2021. GHG prices began 2021 at $18 per metric ton and increased to
$32 at year-end. During 2021, Berry experienced an increase in
property taxes, as well as higher severance taxes due to increased
revenue driven by higher product prices.
General and administrative expenses decreased 6%
in 2021 compared to 2020, primarily due to lower non-cash stock
compensation costs and non-recurring cost, partially offset by
increased expenses from the C&J Well Services acquisition.
Excluding the impact of the C&J Well Services acquisition in
the fourth quarter, general and administrative expenses decreased
by approximately 12% for 2021 compared to 2020. Adjusted general
and administrative expenses, which excludes non-cash stock
compensation costs and nonrecurring costs, and excluding C&J
Well Services were $54 million for the year ended December 31, 2021
compared to $57 million for the year ended December 31, 2020. The
decrease was largely due to lower employee expenses.
The C&J Well Services results of operations
beginning on the October 1, 2021, acquisition date were included in
Berry's 2021 consolidated results. Such C&J Well Services
results included services revenues of $36 million, costs of
services of $28 million, net income before income taxes of less
than $1 million and Adjusted EBITDA of $4 million. The C&J Well
Services general and administrative expenses were $4.5 million and
adjusted general and administrative expenses were $3.2 million,
which excludes non-recurring costs related to the acquisition and
transition activity.
Capital expenditures on an accrual basis and
excluding acquisitions and asset retirement obligation spending
totaled $132 million for 2021 (excluding C&J Well Services
capital of $1 million) compared to $77 million for 2020. The
increase was due primarily to the increase in drilling with 191
wells in 2021 compared to 45 in 2020. Approximately 79% of 2021
capital was directed to California oil operations and 12% to Utah
operations. Additionally, Berry spent $19 million in 2021 on
plugging and abandonment activities.
Proved reserves were 97 mmboe on December 31,
2021, of which 81% are located in California and where 91% of the
PV-10(1) value is located. In 2021, Berry replaced 120% of our
production with additional proved reserves driven by price
increases and reserves extensions.
“For 2022, we plan to deploy $125 to $135
million of capital, excluding approximately $8 million for C&J
Well Services, which should keep our production flat. We expect a
substantial improvement in our cash flows due to improved market
pricing and oil hedge position compared to 2021,” stated Cary
Baetz, executive vice president and chief financial officer. “We
have also improved our oil intensity over the last few months and
further increased the concentration of production areas. We
recently sold our Colorado gas operations and purchased a Utah
operation that is 88% oil. We also sold our Placerita operations in
the LA Basin, which makes us exclusively a Kern County oil producer
in California. The portfolio rationalization makes us now 92% oil,
up from 89%.”
__________
(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 2022 at a rate of $0.06
per share on the Company’s outstanding common stock, payable on
April 15, 2022 to shareholders of record at the close of business
on March 15, 2022.
Subject to approval by the Board and depending
on a variety of factors, including the Company’s financial
condition and results of operations, the Company intends to pay a
similar fixed dividend in future quarters, as well as additional
dividends in accordance with its newly adopted shareholder returns
model commencing for the first quarter of 2022.
Full-Year 2022 Guidance
Berry remains committed to a maintenance capital
program in 2022 with a fundamental focus on maximizing
discretionary cash flow to return to shareholders.
Full-Year 2022 Guidance |
Low |
|
High |
Average Daily Production (boe/d)(1) |
25,500 |
|
27,500 |
Non-Energy Operating Expenses ($/boe) |
$13.75 |
|
$14.25 |
Operating Expenses ($/boe) |
$20.00 |
|
$22.00 |
Taxes, Other than Income Taxes ($/boe) |
$4.50 |
|
$5.50 |
Adjusted General & Administrative (G&A) expenses
($/boe) |
|
|
|
Development and Production Segment & Corp |
$5.75 |
|
$6.25 |
Well Servicing and Abandonment Segment |
|
~$1.45 |
|
Capital Expenditures ($ millions) |
|
|
|
Development and Production Segment & Corp |
$125 |
|
$135 |
Well Servicing and Abandonment Segment |
|
~$8 |
|
Well Servicing & Abandonment Segment Adjusted EBITDA ($mm) |
|
~$27 |
|
__________
(1) Oil production is expected to be
approximately 92% of total.
The guidance stated above assumes CalGEM
continues to issue new drilling permits and certain other
regulatory permits and approvals, as they have indicated they
will.
Earnings Conference Call
Berry will host a conference call February 23, 2022 to discuss
these results:
Live Call Date: |
Wednesday, February 23,
2022 |
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: |
CORRECTION - 6097724 |
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 9,
2022 |
Replay Dial-in: |
855-859-2056 from the
U.S. |
|
404-537-3406 from
international locations |
Replay Passcode: |
CORRECTION - 6097724 |
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
onshore, low geologic risk, long-lived conventional oil reserves in
the San Joaquin basin of California, with newly acquired well
servicing and abandonment capabilities in 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 our 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; our new shareholder return model and the payment
of any 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 the implementation of additional requirements for
the regulatory approval and permitting process; 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; the impact and duration of the ongoing COVID-19 pandemic
on demand and pricing levels; and the ability to effectively deploy
our ESG strategy and risks associated with initiating new projects
or business in connection therewith; 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, 2021.
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 EndedDecember 31,
2021 |
|
Quarter EndedSeptember 30,
2021 |
|
Quarter EndedDecember 31,
2020 |
|
Year EndedDecember 31, 2021 |
|
Year EndedDecember 31, 2020 |
|
(unaudited)($ and shares in thousands, except per share
amounts) |
Consolidated Statement
of Operations Data: |
|
|
|
|
|
|
|
|
|
Revenues and
other: |
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
181,377 |
|
|
$ |
161,058 |
|
|
$ |
93,811 |
|
|
$ |
625,475 |
|
|
$ |
378,663 |
|
Service revenue |
|
35,840 |
|
|
|
— |
|
|
|
— |
|
|
|
35,840 |
|
|
|
— |
|
Electricity sales |
|
6,308 |
|
|
|
12,371 |
|
|
|
6,724 |
|
|
|
35,636 |
|
|
|
25,813 |
|
(Losses) gains on oil and gas sales derivatives |
|
(16,378 |
) |
|
|
(30,864 |
) |
|
|
(39,617 |
) |
|
|
(156,399 |
) |
|
|
117,781 |
|
Marketing revenues |
|
834 |
|
|
|
732 |
|
|
|
351 |
|
|
|
3,921 |
|
|
|
1,426 |
|
Other revenues |
|
105 |
|
|
|
117 |
|
|
|
97 |
|
|
|
477 |
|
|
|
150 |
|
Total revenues and other |
|
208,086 |
|
|
|
143,414 |
|
|
|
61,366 |
|
|
|
544,950 |
|
|
|
523,833 |
|
Expenses and
other: |
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
67,292 |
|
|
|
60,930 |
|
|
|
49,621 |
|
|
|
236,048 |
|
|
|
186,348 |
|
Cost of services |
|
28,339 |
|
|
|
— |
|
|
|
— |
|
|
|
28,339 |
|
|
|
— |
|
Electricity generation expenses |
|
3,660 |
|
|
|
7,128 |
|
|
|
5,422 |
|
|
|
23,148 |
|
|
|
16,608 |
|
Transportation expenses |
|
1,758 |
|
|
|
1,806 |
|
|
|
1,559 |
|
|
|
6,897 |
|
|
|
6,938 |
|
Marketing expenses |
|
825 |
|
|
|
715 |
|
|
|
344 |
|
|
|
3,811 |
|
|
|
1,380 |
|
General and administrative expenses |
|
22,357 |
|
|
|
17,614 |
|
|
|
20,409 |
|
|
|
73,106 |
|
|
|
77,696 |
|
Depreciation, depletion and amortization |
|
38,903 |
|
|
|
35,902 |
|
|
|
30,434 |
|
|
|
144,495 |
|
|
|
139,180 |
|
Impairment of oil and gas properties |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
289,085 |
|
Taxes, other than income taxes |
|
11,920 |
|
|
|
13,420 |
|
|
|
10,858 |
|
|
|
46,500 |
|
|
|
35,572 |
|
Losses (gains) on natural gas purchase derivatives |
|
15,772 |
|
|
|
(14,980 |
) |
|
|
3,859 |
|
|
|
(38,577 |
) |
|
|
1,035 |
|
Other operating (income) expenses |
|
(1,726 |
) |
|
|
3,986 |
|
|
|
3,123 |
|
|
|
3,101 |
|
|
|
5,781 |
|
Total expenses and other |
|
189,100 |
|
|
|
126,521 |
|
|
|
125,629 |
|
|
|
526,868 |
|
|
|
759,623 |
|
Other (expenses)
income: |
|
|
|
|
|
|
|
|
|
Interest expense |
|
(7,451 |
) |
|
|
(7,810 |
) |
|
|
(8,308 |
) |
|
|
(31,964 |
) |
|
|
(34,295 |
) |
Other, net |
|
(91 |
) |
|
|
(5 |
) |
|
|
(13 |
) |
|
|
(247 |
) |
|
|
(28 |
) |
Total other (expenses) income |
|
(7,542 |
) |
|
|
(7,815 |
) |
|
|
(8,321 |
) |
|
|
(32,211 |
) |
|
|
(34,323 |
) |
Income (loss) before
income taxes |
|
11,444 |
|
|
|
9,078 |
|
|
|
(72,584 |
) |
|
|
(14,129 |
) |
|
|
(270,113 |
) |
Income tax expense
(benefit) |
|
2,619 |
|
|
|
(758 |
) |
|
|
(8,754 |
) |
|
|
1,413 |
|
|
|
(7,218 |
) |
Net income
(loss) |
$ |
8,825 |
|
|
$ |
9,836 |
|
|
$ |
(63,830 |
) |
|
$ |
(15,542 |
) |
|
$ |
(262,895 |
) |
|
|
|
|
|
|
|
|
|
|
Net earnings (loss)
per share: |
|
|
|
|
|
|
|
|
|
Basic |
$ |
0.11 |
|
|
$ |
0.12 |
|
|
$ |
(0.80 |
) |
|
$ |
(0.19 |
) |
|
$ |
(3.29 |
) |
Diluted |
$ |
0.11 |
|
|
$ |
0.12 |
|
|
$ |
(0.80 |
) |
|
$ |
(0.19 |
) |
|
$ |
(3.29 |
) |
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares
outstanding - basic |
|
80,007 |
|
|
|
80,242 |
|
|
|
79,922 |
|
|
|
80,209 |
|
|
|
79,802 |
|
Weighted-average common shares
outstanding - diluted |
|
84,011 |
|
|
|
82,898 |
|
|
|
79,922 |
|
|
|
80,209 |
|
|
|
79,802 |
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net Income(1) |
$ |
10,204 |
|
|
$ |
11,536 |
|
|
$ |
8,580 |
|
|
$ |
21,072 |
|
|
$ |
44,816 |
|
Weighted-average common shares
outstanding - diluted |
|
84,011 |
|
|
|
82,898 |
|
|
|
80,033 |
|
|
|
83,496 |
|
|
|
79,902 |
|
Diluted earnings per share on
Adjusted Net Income |
$ |
0.12 |
|
|
$ |
0.14 |
|
|
$ |
0.11 |
|
|
$ |
0.25 |
|
|
$ |
0.56 |
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(1) |
$ |
60,395 |
|
|
$ |
59,324 |
|
|
$ |
53,682 |
|
|
$ |
212,146 |
|
|
$ |
244,430 |
|
Adjusted EBITDA
unhedged(1) |
$ |
93,816 |
|
|
$ |
76,946 |
|
|
$ |
18,365 |
|
|
$ |
299,771 |
|
|
$ |
102,138 |
|
Levered Free Cash Flow(1) |
$ |
20,473 |
|
|
$ |
8,692 |
|
|
$ |
31,215 |
|
|
$ |
31,166 |
|
|
$ |
124,091 |
|
Levered Free Cash Flow
Unhedged(1) |
$ |
53,894 |
|
|
$ |
26,314 |
|
|
$ |
(4,102 |
) |
|
$ |
118,791 |
|
|
$ |
(18,201 |
) |
Adjusted General and
Administrative Expenses(1) |
$ |
16,870 |
|
|
$ |
13,442 |
|
|
$ |
14,881 |
|
|
$ |
57,015 |
|
|
$ |
57,406 |
|
Effective Tax Rate, including
discrete items |
|
23 |
% |
|
|
(8) |
% |
|
|
12 |
% |
|
|
(10) |
% |
|
|
3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow
Data: |
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities |
$ |
40,230 |
|
|
$ |
22,399 |
|
|
$ |
52,110 |
|
|
$ |
122,488 |
|
|
$ |
196,529 |
|
Net cash used in investing
activities |
$ |
(58,251 |
) |
|
$ |
(50,024 |
) |
|
$ |
(19,098 |
) |
|
$ |
(168,787 |
) |
|
$ |
(93,620 |
) |
Net cash used in financing
activities |
$ |
(4,857 |
) |
|
$ |
(9,132 |
) |
|
$ |
(75 |
) |
|
$ |
(18,975 |
) |
|
$ |
(22,352 |
) |
__________
(1) See further discussion and reconciliation in
“Non-GAAP Financial Measures and Reconciliations”.
|
December 31, 2021 |
|
December 31, 2020 |
|
(unaudited)($ and shares in thousands) |
Balance Sheet
Data: |
|
|
|
Total current assets |
$ |
147,498 |
|
$ |
154,491 |
Total property, plant and
equipment, net |
$ |
1,301,349 |
|
$ |
1,258,084 |
Total current liabilities |
$ |
187,149 |
|
$ |
175,306 |
Long-term debt |
$ |
394,566 |
|
$ |
393,480 |
Total stockholders'
equity |
$ |
692,648 |
|
$ |
714,036 |
Outstanding common stock
shares as of |
|
80,007 |
|
|
79,929 |
The following table represents selected
financial information for the periods presented regarding the
Company's business segments on a stand-alone basis and the
consolidation and elimination entries necessary to arrive at the
financial information for the Company on a consolidated basis.
Berry acquired C&J Well Services on October 1, 2021 and the
results of their operations were included in Berry's consolidated
results beginning the fourth quarter 2021.
|
Year Ended December 31, 2021 |
|
Development & Production |
|
Well Servicing and Abandonment |
|
Corporate/Eliminations |
|
Consolidated Company |
|
(unaudited)(in thousands) |
Revenues - excluding hedges |
$ |
665,509 |
|
$ |
35,840 |
|
$ |
— |
|
|
$ |
701,349 |
|
Net income (loss) before
income taxes |
$ |
82,826 |
|
$ |
1 |
|
$ |
(96,956 |
) |
|
$ |
(14,129 |
) |
Adjusted EBITDA |
$ |
251,146 |
|
$ |
4,310 |
|
$ |
(43,310 |
) |
|
$ |
212,146 |
|
Capital expenditures |
$ |
129,479 |
|
$ |
1,029 |
|
$ |
2,211 |
|
|
$ |
132,719 |
|
Total assets |
$ |
1,450,157 |
|
$ |
81,093 |
|
$ |
(74,771 |
) |
|
$ |
1,456,479 |
|
SUMMARY BY AREA
The following table shows a summary by area of
our selected historical financial and operating information for our
development and production operations.
|
California(San Joaquin and Ventura
basins)(3) |
|
Utah(Uinta basin) |
|
Colorado(Piceance
basin)(4) |
|
Year EndedDecember 31, 2021 |
Year EndedDecember 31, 2020 |
|
Year EndedDecember 31, 2021 |
Year EndedDecember 31, 2020 |
|
Year EndedDecember 31, 2021 |
Year EndedDecember 31, 2020 |
|
|
|
|
(unaudited)($ in thousands, unless noted otherwise) |
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
540,782 |
|
$ |
335,642 |
|
|
$ |
69,968 |
|
$ |
37,481 |
|
|
$ |
14,705 |
|
$ |
5,537 |
|
Operating income (loss)
(1) |
$ |
74,247 |
|
$ |
(7,915 |
) |
|
$ |
30,128 |
|
$ |
(126,289 |
) |
|
$ |
11,570 |
|
$ |
(357 |
) |
Depreciation, depletion, and
amortization (DD&A) |
$ |
138,969 |
|
$ |
130,388 |
|
|
$ |
1,795 |
|
$ |
7,058 |
|
|
$ |
152 |
|
$ |
324 |
|
Impairment of oil and gas properties |
$ |
— |
|
$ |
163,879 |
|
|
$ |
— |
|
$ |
125,206 |
|
|
$ |
— |
|
$ |
— |
|
Average daily production
(mboe/d) |
|
22.0 |
|
|
22.9 |
|
|
|
4.2 |
|
|
4.3 |
|
|
|
1.2 |
|
|
1.3 |
|
Production (oil % of
total) |
|
100 |
% |
|
100 |
% |
|
|
51 |
% |
|
50 |
% |
|
|
2 |
% |
|
2 |
% |
Realized sales prices: |
|
|
|
|
|
|
|
|
Oil (per bbl) |
$ |
67.27 |
|
$ |
40.01 |
|
|
$ |
59.49 |
|
$ |
34.81 |
|
|
$ |
53.22 |
|
$ |
24.01 |
|
NGLs (per bbl) |
$ |
— |
|
$ |
— |
|
|
$ |
36.64 |
|
$ |
12.57 |
|
|
$ |
— |
|
$ |
— |
|
Gas (per mcf) |
$ |
— |
|
$ |
— |
|
|
$ |
4.94 |
|
$ |
2.22 |
|
|
$ |
5.76 |
|
$ |
1.87 |
|
Capital expenditures(2) |
$ |
104,485 |
|
$ |
65,456 |
|
|
$ |
16,289 |
|
$ |
1,247 |
|
|
$ |
1 |
|
$ |
206 |
|
Total proved reserves
(mmboe) |
|
79 |
|
|
87 |
|
|
|
14 |
|
|
7 |
|
|
|
4 |
|
|
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.(3)
Includes production for Placerita properties, in the Ventura basin,
though the end of October 2021 when they were divested. These
properties had average daily production in 2021 of over 800 boe/d
prior to the sale.(4) Our properties in Colorado were in the
Piceance basin, all of which were all divested in January 2022.
COMMODITY PRICING
|
Quarter EndedDecember 31,
2021 |
|
Quarter EndedSeptember 30,
2021 |
|
Quarter EndedDecember 31,
2020 |
|
Year EndedDecember 31, 2021 |
|
Year EndedDecember 31, 2020 |
Weighted Average
Realized Prices |
|
|
|
|
|
|
|
|
|
Oil without hedge ($/bbl) |
$ |
75.11 |
|
|
$ |
69.01 |
|
|
$ |
41.38 |
|
$ |
66.57 |
|
|
$ |
39.56 |
Effects of scheduled
derivative settlements ($/bbl) |
$ |
(20.50 |
) |
|
$ |
(14.66 |
) |
|
$ |
15.03 |
|
$ |
(16.45 |
) |
|
$ |
16.51 |
Oil with hedge ($/bbl) |
$ |
54.61 |
|
|
$ |
54.35 |
|
|
$ |
56.41 |
|
$ |
50.12 |
|
|
$ |
56.07 |
Natural gas ($/mcf) |
$ |
5.60 |
|
|
$ |
4.29 |
|
|
$ |
2.78 |
|
$ |
5.27 |
|
|
$ |
2.08 |
NGLs ($/bbl) |
$ |
47.45 |
|
|
$ |
40.88 |
|
|
$ |
16.78 |
|
$ |
36.64 |
|
|
$ |
12.57 |
|
|
|
|
|
|
|
|
|
|
Index
Prices |
|
|
|
|
|
|
|
|
|
Brent oil ($/bbl) |
$ |
79.66 |
|
|
$ |
73.23 |
|
|
$ |
45.26 |
|
$ |
70.95 |
|
|
$ |
43.21 |
WTI oil ($/bbl) |
$ |
76.89 |
|
|
$ |
70.63 |
|
|
$ |
42.66 |
|
$ |
67.90 |
|
|
$ |
39.59 |
Kern, Delivered natural gas
($/mmbtu)(1) |
$ |
5.65 |
|
|
$ |
5.75 |
|
|
$ |
3.38 |
|
$ |
5.65 |
|
|
$ |
2.46 |
Henry Hub natural gas
($/mmbtu)(2) |
$ |
4.75 |
|
|
$ |
4.35 |
|
|
$ |
2.52 |
|
$ |
3.89 |
|
|
$ |
2.03 |
__________
(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 February 11, 2022, we had the following crude oil
production and gas purchases hedges.
|
Q1 2022 |
|
Q2 2022 |
|
Q3 2022 |
|
Q4 2022 |
|
FY 2023 |
|
FY 2024 |
Brent |
|
|
|
|
|
|
|
|
|
|
|
Swaps |
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (bbls) |
|
976,500 |
|
|
1,117,500 |
|
|
1,104,000 |
|
|
1,104,000 |
|
|
3,055,750 |
|
|
732,000 |
Weighted-average price ($/bbl) |
$ |
69.79 |
|
$ |
71.87 |
|
$ |
71.84 |
|
$ |
71.84 |
|
$ |
71.55 |
|
$ |
61.78 |
Put Spreads |
|
|
|
|
|
|
|
|
|
|
|
Long $50/$40 Put Spread hedged volume (bbls) |
|
405,000 |
|
|
409,500 |
|
|
414,000 |
|
|
414,000 |
|
|
2,555,000 |
|
|
1,647,000 |
Short $50/$40 Put Spread hedged volume (bbls) |
|
45,000 |
|
|
45,500 |
|
|
46,000 |
|
|
46,000 |
|
|
365,000 |
|
|
366,000 |
Collar |
|
|
|
|
|
|
|
|
|
|
|
Purchased Puts hedged volume (bbls) |
|
270,000 |
|
|
— |
|
|
— |
|
|
— |
|
|
1,095,000 |
|
|
— |
Weighted-average price ($/bbl) |
$ |
40.00 |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
40.00 |
|
$ |
— |
Sold hedged volume (bbls) |
|
270,000 |
|
|
— |
|
|
— |
|
|
— |
|
|
1,095,000 |
|
|
— |
Weighted-average price ($/bbl) |
$ |
80.00 |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
106.33 |
|
$ |
— |
Henry
Hub |
|
|
|
|
|
|
|
|
|
|
|
Purchased Puts |
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (mmbtu) |
|
1,800,000 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
Weighted-average price ($/mmbtu) |
$ |
2.75 |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
— |
Purchased Calls |
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (mmbtu) |
|
2,700,000 |
|
|
2,730,000 |
|
|
2,760,000 |
|
|
2,760,000 |
|
|
10,950,000 |
|
|
9,150,000 |
Weighted-average price ($/mmbtu) |
$ |
4.00 |
|
$ |
4.00 |
|
$ |
4.00 |
|
$ |
4.00 |
|
$ |
4.00 |
|
$ |
4.00 |
Sold Puts |
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (mmbtu) |
|
2,700,000 |
|
|
2,730,000 |
|
|
2,760,000 |
|
|
2,760,000 |
|
|
10,950,000 |
|
|
9,150,000 |
Weighted-average price ($/mmbtu) |
$ |
2.75 |
|
$ |
2.75 |
|
$ |
2.75 |
|
$ |
2.75 |
|
$ |
2.75 |
|
$ |
2.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES
|
Quarter EndedDecember 31,
2021 |
|
Quarter EndedSeptember 30,
2021 |
|
Quarter EndedDecember 31,
2020 |
|
Year EndedDecember 31, 2021 |
|
Year EndedDecember 31, 2020 |
|
(unaudited)($ in thousands except per boe amounts) |
Expenses: |
|
|
|
|
|
|
|
|
|
Lease operating expenses |
$ |
67,292 |
|
|
$ |
60,930 |
|
|
$ |
49,621 |
|
|
$ |
236,048 |
|
|
$ |
186,348 |
|
Electricity generation
expenses |
|
3,660 |
|
|
|
7,128 |
|
|
|
5,422 |
|
|
|
23,148 |
|
|
|
16,608 |
|
Electricity sales |
|
(6,308 |
) |
|
|
(12,371 |
) |
|
|
(6,724 |
) |
|
|
(35,636 |
) |
|
|
(25,813 |
) |
Transportation expenses |
|
1,758 |
|
|
|
1,806 |
|
|
|
1,559 |
|
|
|
6,897 |
|
|
|
6,938 |
|
Transportation sales |
|
(105 |
) |
|
|
(117 |
) |
|
|
(97 |
) |
|
|
(477 |
) |
|
|
(150 |
) |
Marketing expenses |
|
825 |
|
|
|
715 |
|
|
|
344 |
|
|
|
3,811 |
|
|
|
1,380 |
|
Marketing revenues |
|
(834 |
) |
|
|
(732 |
) |
|
|
(351 |
) |
|
|
(3,921 |
) |
|
|
(1,426 |
) |
Derivative settlements
(received) paid for gas purchases(1) |
|
(8,650 |
) |
|
|
(14,095 |
) |
|
|
(3,090 |
) |
|
|
(50,897 |
) |
|
|
9,298 |
|
Total operating expenses(2) |
$ |
57,638 |
|
|
$ |
43,264 |
|
|
$ |
46,684 |
|
|
$ |
178,973 |
|
|
$ |
193,183 |
|
|
|
|
|
|
|
|
|
|
|
Expenses per
boe:(2) |
|
|
|
|
|
|
|
|
|
Lease operating expenses |
$ |
26.23 |
|
|
$ |
24.20 |
|
|
$ |
20.25 |
|
|
$ |
23.60 |
|
|
$ |
17.86 |
|
Electricity generation
expenses |
|
1.43 |
|
|
|
2.83 |
|
|
|
2.21 |
|
|
|
2.31 |
|
|
|
1.59 |
|
Electricity sales |
|
(2.46 |
) |
|
|
(4.91 |
) |
|
|
(2.74 |
) |
|
|
(3.56 |
) |
|
|
(2.47 |
) |
Transportation expenses |
|
0.69 |
|
|
|
0.72 |
|
|
|
0.64 |
|
|
|
0.69 |
|
|
|
0.66 |
|
Transportation sales |
|
(0.05 |
) |
|
|
(0.05 |
) |
|
|
(0.04 |
) |
|
|
(0.05 |
) |
|
|
(0.01 |
) |
Marketing expenses |
|
0.32 |
|
|
|
0.28 |
|
|
|
0.14 |
|
|
|
0.38 |
|
|
|
0.13 |
|
Marketing revenues |
|
(0.33 |
) |
|
|
(0.29 |
) |
|
|
(0.14 |
) |
|
|
(0.39 |
) |
|
|
(0.14 |
) |
Derivative settlements
(received) paid for gas purchases |
|
(3.37 |
) |
|
|
(5.60 |
) |
|
|
(1.26 |
) |
|
|
(5.09 |
) |
|
|
0.89 |
|
Total operating expenses(2) |
$ |
22.46 |
|
|
$ |
17.18 |
|
|
$ |
19.06 |
|
|
$ |
17.89 |
|
|
$ |
18.51 |
|
Total unhedged operating expenses(1) |
$ |
25.83 |
|
|
$ |
22.78 |
|
|
$ |
20.32 |
|
|
$ |
22.98 |
|
|
$ |
17.62 |
|
|
|
|
|
|
|
|
|
|
|
Total non-energy operating expenses(3) |
$ |
13.41 |
|
|
$ |
13.59 |
|
|
$ |
14.35 |
|
|
$ |
13.12 |
|
|
$ |
13.63 |
|
Total energy operating expenses(4) |
$ |
9.05 |
|
|
$ |
3.59 |
|
|
$ |
4.70 |
|
|
$ |
4.77 |
|
|
$ |
4.88 |
|
|
|
|
|
|
|
|
|
|
|
Total mboe |
|
2,566 |
|
|
|
2,519 |
|
|
|
2,450 |
|
|
|
10,004 |
|
|
|
10,435 |
|
__________
(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 EndedDecember 31,
2021 |
|
Quarter EndedSeptember 30,
2021 |
|
Quarter EndedDecember 31,
2020 |
|
Year EndedDecember 31, 2021 |
|
Year EndedDecember 31, 2020 |
Net Oil, Natural Gas
and NGLs Production Per
Day(1): |
|
|
|
|
|
|
|
|
|
Oil
(mbbl/d) |
|
|
|
|
|
|
|
|
|
California(2) |
22.7 |
|
21.8 |
|
21.2 |
|
22.0 |
|
22.9 |
Utah |
2.1 |
|
2.3 |
|
2.1 |
|
2.2 |
|
2.1 |
Colorado(3) |
— |
|
— |
|
— |
|
— |
|
— |
Total oil |
24.8 |
|
24.1 |
|
23.3 |
|
24.2 |
|
25.0 |
Natural gas
(mmcf/d) |
|
|
|
|
|
|
|
|
|
California |
— |
|
— |
|
— |
|
— |
|
— |
Utah |
10.0 |
|
10.7 |
|
9.8 |
|
10.2 |
|
10.7 |
Colorado(3) |
6.4 |
|
6.9 |
|
7.8 |
|
6.9 |
|
7.8 |
Total natural gas |
16.4 |
|
17.6 |
|
17.6 |
|
17.1 |
|
18.5 |
NGLs
(mbbl/d) |
|
|
|
|
|
|
|
|
|
California |
— |
|
— |
|
— |
|
— |
|
— |
Utah |
0.4 |
|
0.4 |
|
0.4 |
|
0.4 |
|
0.4 |
Colorado(3) |
— |
|
— |
|
— |
|
— |
|
— |
Total NGLs |
0.4 |
|
0.4 |
|
0.4 |
|
0.4 |
|
0.4 |
Total Production
(mboe/d)(2) |
27.9 |
|
27.4 |
|
26.6 |
|
27.4 |
|
28.5 |
__________
(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) Includes production for
Placerita properties though the end of October 2021 when they were
divested. These properties had average daily production in 2021 of
over 800 boe/d prior to the sale.(3) Our properties in Colorado
were in the Piceance basin, all of which were all divested in
January 2022.
CAPITAL EXPENDITURES (ACCRUAL BASIS)
|
Quarter EndedDecember 31,
2021 |
|
Quarter EndedSeptember 30,
2021 |
|
Quarter EndedDecember 31,
2020 |
|
Year EndedDecember 31, 2021 |
|
Year EndedDecember 31, 2020 |
|
(unaudited)(in thousands) |
Capital expenditures (accrual basis)(1,2) |
$ |
27,673 |
|
$ |
38,016 |
|
$ |
14,159 |
|
$ |
132,719 |
|
$ |
76,480 |
__________
(1) Capital expenditures on an accrual basis
include capitalized overhead and interest and excludes acquisitions
and asset retirement spending.(2) Capital expenditures in the
quarter and year ended December 31, 2021 included $1 million for
C&J Well Services which was acquired on October 1, 2021.
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, unusual 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 unusual and infrequent items. We
define Levered Free Cash Flow as Adjusted EBITDA less capital
expenditures, interest expense and fixed dividends. We define
Adjusted General and Administrative Expenses as general and
administrative expenses adjusted for non-cash stock compensation
expense and unusual and infrequent costs.
Adjusted Net Income (Loss) excludes the impact
of unusual and infrequent items affecting earnings that vary widely
and unpredictably, including non-cash items such as derivative
gains and losses. This measure is used by management when comparing
results period over period. 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, pay fixed dividends and accelerate
our asset retirement activity. 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, which is
widely used by the industry to understand the present value of oil
and gas companies. It represents the present value of estimated
future cash inflows from proved oil and gas reserves, less future
development and production costs, discounted at 10% per annum to
reflect the timing of future cash flows and does not give effect to
derivative transactions or estimated future income taxes.
Management believes that PV-10 provides useful information to
investors because it is widely used by analysts and investors in
evaluating oil and natural gas companies. Because there are many
unique factors that can impact an individual company when
estimating the amount of future income taxes to be paid, management
believes the use of a pre-tax measure is valuable for evaluating
the Company. PV-10 should not be considered as an alternative to
the standardized measure of discounted future net cash flows as
computed under GAAP.
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 EndedDecember 31,
2021 |
|
Quarter EndedSeptember 30,
2021 |
|
Quarter EndedDecember 31,
2020 |
|
Year EndedDecember 31, 2021 |
|
Year EndedDecember 31, 2020 |
|
(unaudited)($ thousands, except per share amounts) |
Net income (loss) |
$ |
8,825 |
|
|
$ |
9,836 |
|
|
$ |
(63,830 |
) |
|
$ |
(15,542 |
) |
|
$ |
(262,895 |
) |
Add: discrete income tax
items |
|
581 |
|
|
|
— |
|
|
|
16,724 |
|
|
|
581 |
|
|
|
61,030 |
|
|
|
|
|
|
|
|
|
|
|
Add (Subtract): |
|
|
|
|
|
|
|
|
|
Losses (gains) on derivatives |
|
32,150 |
|
|
|
15,885 |
|
|
|
43,476 |
|
|
|
117,822 |
|
|
|
(116,746 |
) |
Net cash (paid) received for scheduled derivative settlements |
|
(33,421 |
) |
|
|
(17,622 |
) |
|
|
35,317 |
|
|
|
(87,625 |
) |
|
|
142,292 |
|
Other operating (income) expenses |
|
(1,726 |
) |
|
|
3,986 |
|
|
|
3,123 |
|
|
|
3,101 |
|
|
|
5,781 |
|
Impairment of oil and gas properties |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
289,085 |
|
Non-recurring costs |
|
2,030 |
|
|
|
705 |
|
|
|
2,375 |
|
|
|
2,735 |
|
|
|
6,026 |
|
Total (subtractions) additions, net |
|
(967 |
) |
|
|
2,954 |
|
|
|
84,291 |
|
|
|
36,033 |
|
|
|
326,438 |
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit (expense)
of adjustments at effective tax rate(1) |
|
1,765 |
|
|
|
(1,254 |
) |
|
|
(28,605 |
) |
|
|
— |
|
|
|
(79,757 |
) |
Adjusted Net Income |
$ |
10,204 |
|
|
$ |
11,536 |
|
|
$ |
8,580 |
|
|
$ |
21,072 |
|
|
$ |
44,816 |
|
|
|
|
|
|
|
|
|
|
|
Basic EPS on Adjusted Net
Income |
$ |
0.13 |
|
|
$ |
0.14 |
|
|
$ |
0.11 |
|
|
$ |
0.26 |
|
|
$ |
0.56 |
|
Diluted EPS on Adjusted Net
Income |
$ |
0.12 |
|
|
$ |
0.14 |
|
|
$ |
0.11 |
|
|
$ |
0.25 |
|
|
$ |
0.56 |
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding - basic |
|
80,007 |
|
|
|
80,242 |
|
|
|
79,922 |
|
|
|
80,209 |
|
|
|
79,802 |
|
Weighted average shares
outstanding - diluted |
|
84,011 |
|
|
|
82,898 |
|
|
|
80,033 |
|
|
|
83,496 |
|
|
|
79,902 |
|
__________
(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 EndedDecember 31,
2021 |
|
Quarter EndedSeptember 30,
2021 |
|
Quarter EndedDecember 31,
2020 |
|
Year EndedDecember 31, 2021 |
|
Year EndedDecember 31, 2020 |
|
(unaudited)($ thousands) |
Net income (loss) |
$ |
8,825 |
|
|
$ |
9,836 |
|
|
$ |
(63,830 |
) |
|
$ |
(15,542 |
) |
|
$ |
(262,895 |
) |
Add (Subtract): |
|
|
|
|
|
|
|
|
|
Interest expense |
|
7,451 |
|
|
|
7,810 |
|
|
|
8,308 |
|
|
|
31,964 |
|
|
|
34,295 |
|
Income tax expense (benefit) |
|
2,619 |
|
|
|
(758 |
) |
|
|
(8,754 |
) |
|
|
1,413 |
|
|
|
(7,218 |
) |
Depreciation, depletion, and amortization |
|
38,903 |
|
|
|
35,902 |
|
|
|
30,434 |
|
|
|
144,495 |
|
|
|
139,180 |
|
Impairment of oil and gas properties |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
289,085 |
|
Losses (gains) on derivatives |
|
32,150 |
|
|
|
15,885 |
|
|
|
43,476 |
|
|
|
117,822 |
|
|
|
(116,746 |
) |
Net cash (paid) received for scheduled derivative settlements |
|
(33,421 |
) |
|
|
(17,622 |
) |
|
|
35,317 |
|
|
|
(87,625 |
) |
|
|
142,292 |
|
Other operating (income) expenses |
|
(1,726 |
) |
|
|
3,986 |
|
|
|
3,123 |
|
|
|
3,101 |
|
|
|
5,781 |
|
Stock compensation expense |
|
3,564 |
|
|
|
3,580 |
|
|
|
3,233 |
|
|
|
13,783 |
|
|
|
14,630 |
|
Non-recurring costs |
|
2,030 |
|
|
|
705 |
|
|
|
2,375 |
|
|
|
2,735 |
|
|
|
6,026 |
|
Adjusted EBITDA |
$ |
60,395 |
|
|
$ |
59,324 |
|
|
$ |
53,682 |
|
|
$ |
212,146 |
|
|
$ |
244,430 |
|
Net cash paid (received) for
scheduled derivative settlements |
|
33,421 |
|
|
|
17,622 |
|
|
|
(35,317 |
) |
|
|
87,625 |
|
|
|
(142,292 |
) |
Adjusted EBITDA unhedged |
$ |
93,816 |
|
|
$ |
76,946 |
|
|
$ |
18,365 |
|
|
$ |
299,771 |
|
|
$ |
102,138 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities |
$ |
40,230 |
|
|
$ |
22,399 |
|
|
$ |
52,110 |
|
|
$ |
122,488 |
|
|
$ |
196,529 |
|
Add (Subtract): |
|
|
|
|
|
|
|
|
|
Cash interest payments |
|
97 |
|
|
|
14,189 |
|
|
|
— |
|
|
|
29,211 |
|
|
|
29,962 |
|
Cash income tax payments |
|
405 |
|
|
|
294 |
|
|
|
— |
|
|
|
699 |
|
|
|
222 |
|
Non-recurring costs |
|
2,030 |
|
|
|
705 |
|
|
|
2,375 |
|
|
|
2,735 |
|
|
|
6,026 |
|
Other changes in operating assets and liabilities |
|
17,633 |
|
|
|
21,737 |
|
|
|
(803 |
) |
|
|
57,013 |
|
|
|
11,691 |
|
Adjusted EBITDA |
$ |
60,395 |
|
|
$ |
59,324 |
|
|
$ |
53,682 |
|
|
$ |
212,146 |
|
|
$ |
244,430 |
|
Net cash paid (received) for
scheduled derivative settlements |
|
33,421 |
|
|
|
17,622 |
|
|
|
(35,317 |
) |
|
|
87,625 |
|
|
|
(142,292 |
) |
Adjusted EBITDA unhedged |
$ |
93,816 |
|
|
$ |
76,946 |
|
|
$ |
18,365 |
|
|
$ |
299,771 |
|
|
$ |
102,138 |
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA is the measure reported to the
chief operating decision maker (CODM) for purposes of making
decisions about allocating resources to and assessing performance
of each segment. EBITDA represents earnings before interest
expense; income taxes; depreciation, depletion, and amortization;
derivative gains or losses net of cash received or paid for
scheduled derivative settlements; impairments; stock compensation
expense; and unusual and infrequent items.
|
Year Ended December 31, 2021 |
|
Development & Production |
|
Well Servicing and Abandonment |
|
Corporate/Eliminations |
|
Consolidated Company |
|
(unaudited)(in thousands) |
Adjusted EBITDA
reconciliation to net income (loss): |
|
|
|
|
|
|
|
Net income (loss) |
$ |
82,825 |
|
|
$ |
1 |
|
$ |
(98,368 |
) |
|
$ |
(15,542 |
) |
Add
(Subtract): |
|
|
|
|
|
|
|
Interest expense |
|
— |
|
|
|
— |
|
|
31,964 |
|
|
|
31,964 |
|
Income tax expense |
|
— |
|
|
|
— |
|
|
1,413 |
|
|
|
1,413 |
|
Depreciation, depletion, and amortization |
|
136,915 |
|
|
|
2,974 |
|
|
4,606 |
|
|
|
144,495 |
|
Losses on derivatives |
|
117,822 |
|
|
|
— |
|
|
— |
|
|
|
117,822 |
|
Net cash paid for scheduled derivative settlements |
|
(87,625 |
) |
|
|
— |
|
|
— |
|
|
|
(87,625 |
) |
Other operating expenses |
|
109 |
|
|
|
— |
|
|
2,992 |
|
|
|
3,101 |
|
Stock compensation expense |
|
1,100 |
|
|
|
— |
|
|
12,683 |
|
|
|
13,783 |
|
Non-recurring costs |
|
— |
|
|
|
1,335 |
|
|
1,400 |
|
|
|
2,735 |
|
Adjusted
EBITDA |
$ |
251,146 |
|
|
$ |
4,310 |
|
$ |
(43,310 |
) |
|
$ |
212,146 |
|
|
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 EndedDecember 31,
2021 |
|
Quarter EndedSeptember 30,
2021 |
|
Quarter EndedDecember 31,
2020 |
|
Year EndedDecember 31, 2021 |
|
Year EndedDecember 31, 2020 |
|
(unaudited)($ thousands) |
Adjusted EBITDA |
$ |
60,395 |
|
|
$ |
59,324 |
|
|
$ |
53,682 |
|
|
$ |
212,146 |
|
|
$ |
244,430 |
|
Subtract: |
|
|
|
|
|
|
|
|
|
Capital expenditures - accrual basis(1) |
|
(27,673 |
) |
|
|
(38,016 |
) |
|
|
(14,159 |
) |
|
|
(132,719 |
) |
|
|
(76,480 |
) |
Interest expense |
|
(7,451 |
) |
|
|
(7,810 |
) |
|
|
(8,308 |
) |
|
|
(31,964 |
) |
|
|
(34,295 |
) |
Fixed cash dividends declared |
|
(4,798 |
) |
|
|
(4,806 |
) |
|
|
— |
|
|
|
(16,297 |
) |
|
|
(9,564 |
) |
Levered Free Cash Flow(2) |
$ |
20,473 |
|
|
$ |
8,692 |
|
|
$ |
31,215 |
|
|
$ |
31,166 |
|
|
$ |
124,091 |
|
Net cash paid (received) for
scheduled derivative settlements |
|
33,421 |
|
|
|
17,622 |
|
|
|
(35,317 |
) |
|
|
87,625 |
|
|
|
(142,292 |
) |
Levered Free Cash Flow
Unhedged |
$ |
53,894 |
|
|
$ |
26,314 |
|
|
$ |
(4,102 |
) |
|
$ |
118,791 |
|
|
$ |
(18,201 |
) |
__________
(1) Capital expenditures on an accrual basis
includes capitalized overhead and interest and excludes
acquisitions. Also excluded is asset retirement spending of $7
million, $5 million, $4 million for the quarters ended December 31,
2021, September 30, 2021 and December 31, 2020, respectively, and
$19 million and $18 million for the years ended December 31, 2021
and 2020, respectively.
ADJUSTED GENERAL AND ADMINISTRATIVE
EXPENSES
The following table presents a reconciliation of the GAAP
financial measure of general and administrative expenses to the
non-GAAP financial measures of Adjusted General and Administrative
Expenses.
|
Quarter EndedDecember 31,
2021 |
|
Quarter EndedSeptember 30,
2021 |
|
Quarter EndedDecember 31,
2020 |
|
Year EndedDecember 31, 2021 |
|
Year EndedDecember 31, 2020 |
|
(unaudited)($ in thousands except per mboe amounts) |
General and administrative expenses |
$ |
22,357 |
|
|
$ |
17,614 |
|
|
$ |
20,409 |
|
|
$ |
73,106 |
|
|
$ |
77,696 |
|
Subtract: |
|
|
|
|
|
|
|
|
|
Non-cash stock compensation expense (G&A portion) |
|
(3,457 |
) |
|
|
(3,467 |
) |
|
|
(3,153 |
) |
|
|
(13,356 |
) |
|
|
(14,264 |
) |
Non-recurring costs |
|
(2,030 |
) |
|
|
(705 |
) |
|
|
(2,375 |
) |
|
|
(2,735 |
) |
|
|
(6,026 |
) |
Adjusted General and
Administrative Expenses |
$ |
16,870 |
|
|
$ |
13,442 |
|
|
$ |
14,881 |
|
|
$ |
57,015 |
|
|
$ |
57,406 |
|
|
|
|
|
|
|
|
|
|
|
Well servicing and abandonment
segment |
$ |
3,193 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
3,193 |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
Development and production
segment, and corporate |
$ |
13,677 |
|
|
$ |
13,442 |
|
|
$ |
14,881 |
|
|
$ |
53,822 |
|
|
$ |
57,406 |
|
Development and production
segment, and corporate ($/boe) |
$ |
5.33 |
|
|
$ |
5.34 |
|
|
$ |
6.07 |
|
|
$ |
5.38 |
|
|
$ |
5.50 |
|
|
|
|
|
|
|
|
|
|
|
Total mboe |
|
2,566 |
|
|
|
2,519 |
|
|
|
2,450 |
|
|
|
10,004 |
|
|
|
10,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RESERVES AND PV-10
The following table summarizes our estimated
proved reserves and related PV-10 as of December 31, 2021.
|
Proved Reserves as of December 31,
2021(1) |
|
California (San Joaquin and Ventura
basins) |
|
Utah(Uinta basin) |
|
Colorado(Piceance basin) |
|
Total |
Proved developed reserves: |
|
|
|
|
|
|
|
Oil (mmbbl) |
|
47 |
|
|
6 |
|
|
— |
|
|
53 |
Natural Gas (bcf) |
|
— |
|
|
35 |
|
|
25 |
|
|
60 |
NGLs (mmbbl) |
|
— |
|
|
1 |
|
|
— |
|
|
1 |
Total (mmboe)(2)(3) |
|
47 |
|
|
13 |
|
|
4 |
|
|
64 |
Proved undeveloped reserves: |
|
|
|
|
|
|
|
Oil (mmbbl) |
|
32 |
|
|
1 |
|
|
— |
|
|
33 |
Natural Gas (bcf) |
|
— |
|
|
2 |
|
|
— |
|
|
2 |
NGLs (mmbbl) |
|
— |
|
|
— |
|
|
— |
|
|
— |
Total (mmboe)(3) |
|
32 |
|
|
1 |
|
|
— |
|
|
33 |
Total proved reserves: |
|
|
|
|
|
|
|
Oil (mmbbl) |
|
79 |
|
|
7 |
|
|
— |
|
|
86 |
Natural Gas (bcf) |
|
— |
|
|
37 |
|
|
25 |
|
|
62 |
NGLs (mmbbl) |
|
— |
|
|
1 |
|
|
— |
|
|
1 |
Total (mmboe)(3) |
|
79 |
|
|
14 |
|
|
4 |
|
|
97 |
|
|
|
|
|
|
|
|
PV-10 (in millions)(4) |
$ |
1,374 |
|
$ |
124 |
|
$ |
15 |
|
$ |
1,513 |
__________
(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 $69.47
per bbl Brent for oil and NGLs and $3.64 per mmbtu Henry Hub for
natural gas at December 31, 2021. The volume-weighted average
prices over the lives of the properties were $65.10 per Bbl of oil
and condensate, $36.08 per Bbl of NGLs and $3.98 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 10% of
total and 11% 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, 2021,
the average prices of Brent oil and Henry Hub natural gas were
$70.95 per bbl and $3.89 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, 2021:
|
At December 31, 2021 |
|
(in millions) |
California PV-10 |
$ |
1,374 |
|
Utah PV-10 |
|
124 |
|
Colorado PV-10 |
|
15 |
|
Total Company PV-10 |
|
1,513 |
|
Less: present value of future income taxes discounted at 10% |
|
(280 |
) |
Standardized measure of discounted future net cash flows |
$ |
1,233 |
|
The following table presents reserves changes
and production for 2021:
|
Total Company |
|
California |
|
(in mmboe) |
Extensions and discoveries |
3 |
|
1 |
|
Revisions of previous
estimates |
9 |
|
(1 |
) |
Purchases of minerals(1) |
— |
|
— |
|
Sales of minerals(2) |
— |
|
— |
|
Total reserves changes |
12 |
|
— |
|
|
|
|
|
Production |
10 |
|
8 |
|
__________
(1) Purchases of minerals in place were less
than 1 mmboe.(2) Sales 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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