Berry Corporation (bry) (NASDAQ: BRY) (“Berry” or the “Company”)
today reported fourth quarter and full-year 2022 results. For the
fourth quarter Berry’s net income was $72 million, or $0.90 per
diluted share, and Adjusted Net Income(1) was $76 million, or $0.95
per diluted share. For the full year Berry's net income was $250
million, or $3.03 per diluted share, Adjusted Net Income(1) was
$226 million, or $2.74 per diluted share, and cash flows from
operating activities were $361 million.
2022 Highlights
- Delivered record $189 million of
shareholder returns, consisting of:
- $1.78 per share fixed and variable
dividends (inclusive of dividends to be paid in March 2023)
and
- Five million shares repurchased, or
7% of current shares outstanding
- Produced net income of $250 million
and Adjusted EBITDA(1) of $380 million
- Generated cash flows from operating
activities of $361 million and Adjusted Free Cash Flow(1) of $200
million
- Increased proved reserves to 110
million boe, achieved reserve replacement of 236%, primarily
through field extensions
- Announced doubling the fixed
dividend to $0.48 per share annually beginning with the first
quarter 2023
- Increased authorization of share
repurchases to $200 million
__________
|
(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. |
“2022 was a good year for Berry both financially
and operationally. Once again, we showed the incredible quality of
our assets and our ability to navigate the California regulatory
environment by holding production flat in the state, net of prior
year divestitures. We believe the quality of our assets gives us a
competitive advantage over other energy companies. We have decline
curves in the low teens, and we achieved 94% of our total annual
production from our existing wells, or our base production, in
2022. We are proud to have returned $189 million to shareholders in
the form of dividends and share repurchases, which is roughly 27%
of our current market capitalization returned in just one year. Our
unique assets and operating model generated strong free cash flow
which, when allocated in accordance with our shareholder return
model, delivered industry leading returns to our shareholders,”
said Fernando Araujo, Berry CEO.
“Reflecting the confidence we have in our
business plan and strategy, we are doubling our quarterly fixed
dividend in 2023. Our goal is to continue to demonstrate our
ability to consistently generate substantial free cash flow and
return it to shareholders, further proving the quality of our
assets and our ability to efficiently manage the business,”
continued Araujo.
Fourth Quarter 2022 Results
Net income was $72 million and Adjusted EBITDA
was $78 million in the fourth quarter 2022 compared to $192 million
and $97 million, respectively, in the third quarter. This decrease
is primarily due to lower commodity prices resulting in lower
revenue, higher purchased fuel costs and higher greenhouse gas
(“GHG”) costs.
The Company's average daily production in the
fourth quarter 2022 of 25,800 boe/d was flat compared to third
quarter volumes. Company-wide oil production in the fourth quarter
2022 increased 2% sequentially and California production, which
consists solely of oil and comprises 82% of total company
production, increased 1% to 21,100 mboe/d in the fourth
quarter.
Company-wide realized oil price, including
hedging effects, were $73.39 per bbl for the fourth quarter 2022
compared to $76.41 per bbl in the third quarter. Excluding hedging
effects, California's average realized oil prices were $81.66 per
bbl in the fourth quarter, 92% of Brent, and $91.67 per bbl in the
third quarter, 94% of Brent.
Lease operating expenses, which includes fuel
gas costs for our California steam operations, increased 11% in the
fourth quarter 2022 from the third quarter due to higher natural
gas purchase prices. Natural gas average purchase price increased
18% from the third quarter.
Taxes, other than income taxes increased 95% in
the fourth quarter 2022 from the third quarter due to higher GHG
mark-to-market prices and higher property taxes.
General and administrative expenses increased
15% in the fourth quarter 2022 compared to the third quarter,
almost entirely due to executive transition costs. Adjusted General
and Administrative Expenses(1), which excludes non-cash stock
compensation costs and non-recurring costs, remained flat quarter
over quarter.
The net income for the well servicing and
abandonment business, C&J Well Services, improved 27% to $6.6
million in the fourth quarter 2022 compared to $5.2 million in the
third quarter, due to improved margins.
For the fourth quarter 2022, capital
expenditures were approximately $45 million, excluding
acquisitions, asset retirement obligation spending and well
servicing and abandonment capital of $5 million. This was an
increase compared to $41 million for the third quarter
reflecting California development activity late into the year.
Additionally, Berry spent approximately $4 million for plugging and
abandonment activities in the fourth quarter.
Full-Year 2022 Results
Net income was $250 million in 2022 compared to
a net loss of $16 million in 2021. Adjusted EBITDA was
$380 million in 2022 compared to $212 million in 2021. The
increase was primarily driven by higher oil and gas realized prices
and lower GHG costs, partially offset by higher purchased fuel
costs, other non-fuel lease operating expenses, and general and
administrative expenses.
The decrease in the Company's average daily
production for the full year 2022 compared to 2021 was driven by
the divestitures made in late 2021 (California) and early 2022
(Colorado), partially offset by the Utah Antelope Creek acquisition
in early 2022. California production, net of the 2021 divestiture,
production was flat year-over-year despite significant challenges
in receiving new drill permits which forced a mid-year capital
allocation pivot to increased sidetrack, workover and recompletion
activity. Utah production in 2022 increased 12% compared to 2021
due to new drilling activity and the Antelope Creek acquisition,
which more than offset natural decline.
Company-wide realized oil prices, including
hedging effects, were $77.59 per bbl in 2022 compared to $50.12 per
bbl in 2021. Excluding hedging effects, California average realized
oil prices were $93.40 per bbl, 94% of Brent in 2022 and $67.27 per
bbl in 2021, 95% of Brent.
Lease operating expenses, which includes fuel
costs for our California steam operations, increased 28% due to
higher prices associated with purchased fuel, well servicing and
workover costs, outside services, chemicals, power, and other
inflationary impacts. Natural gas average purchase price increased
39% from 2021. Natural gas prices also impact electricity
generation expense.
The divestitures made in late 2021 (California)
and early 2022 (Colorado) also decreased other expenses and
revenues related to our field operations, including for
electricity, marketing and transportation activities. In
particular, the majority of our marketing expenses and revenues
were related to our Colorado operations, which were sold in early
2022.
Taxes, other than income taxes, decreased 15% in
2022 compared to 2021, largely due to the California divestiture in
the fourth quarter of 2021, which lowered GHG emissions, as well as
lower GHG mark-to-market prices in 2022 on remaining
operations.
General and administrative expenses increased
32% in 2022 compared to 2021, primarily due to a full year of
expense for the well servicing and abandonment business, employee
cost inflation, including non-cash stock compensation costs and
higher professional services costs. Adjusted General and
Administrative Expenses, which excludes non-cash stock compensation
costs and non-recurring costs, increased for largely the same
reasons.
The well servicing and abandonment business
results of operations were included in the Company's consolidated
results beginning on the October 1, 2021 acquisition date. The full
year 2022 results for this business include services revenues of
$181 million, costs of services of $143 million, general and
administrative expenses of $13 million, net income before income
taxes of $15 million, and Adjusted EBITDA of $26 million.
Capital expenditures, excluding acquisitions and
asset retirement obligation spending totaled $145 million for 2022
(excluding well servicing and abandonment capital of $8 million)
compared to $132 million for 2021. The Company’s increased 2022
capital program compared to 2021 was in response to the improved
oil price environment and the improving global and national
economic environment. The Company allocated more capital to the
Utah assets in 2022, compared to 2021, in part due to the
opportunities in the newly acquired Antelope Creek properties. As a
result of the significant challenges in receiving new drill permits
in California, the Company drilled fewer new wells and increased
the sidetrack, workover and recompletion activity in California
compared to the prior year. The increase in full-year capital
expenditures is also partially due to cost inflation in excess of
our initial expectations, which we began to experience mid-year.
Additionally, Berry spent $20 million in 2022 on plugging and
abandonment activities.
At December 31, 2022, the Company had liquidity
of $252 million, consisting of $46 million cash and $206
million available for borrowings under the Company’s revolving
credit facilities.
Proved reserves were 110 mmboe on December 31,
2022, of which 76% are located in California, which is also where
85% of the PV-10(1) value is located. In 2022, Berry achieved a
reserve replacement of 236%, primarily from field extensions.
Mike Helm, Berry's Chief Financial Officer
stated, “Looking ahead to 2023, our core strategy of delivering
substantial shareholder returns has not changed. We are modifying
our shareholder return model allocation, with the goal of
increasing the value of our shares and lowering our cost of
capital. Our strategy includes doubling our fixed dividends,
currently planned at $0.48 per share annually. Additionally, we
intend to allocate 80% of our Adjusted Free Cash Flow primarily to
share repurchases and debt repurchases, while the remaining 20%
will be allocated to variable dividends. Based on current prices
and outlook, we are now targeting a high single-digit dividend
yield, combining the fixed and variable dividends. We have crafted
a capital program for 2023 that is designed to support these goals
by optimizing our production and driving cost efficiencies. Berry’s
focus is on maximizing shareholder value through our shareholder
return model and managing what we are able to control.”
__________
|
(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
In February 2023, the Company’s Board of
Directors declared dividends totaling $0.50 per share on the
Company’s outstanding common stock, comprising a fixed dividend of
$0.06 per share and a variable dividend of $0.44 per share, based
on fourth quarter 2022 Adjusted Free Cash Flow in accordance with
the Company’s shareholder return model. Both dividends are payable
on March 23, 2023 to shareholders of record at the close of
business on March 15, 2023. Cash dividends attributable to 2022
totaled $1.78 per share, as noted in the table below.
2022 Dividends
| |
First Quarter |
|
Second Quarter |
|
Third Quarter |
|
Fourth Quarter |
|
Year-to-Date |
|
Fixed Dividends |
$ |
0.06 |
|
$ |
0.06 |
|
$ |
0.06 |
|
$ |
0.06 |
|
$ |
0.24 |
|
Variable Dividends(1) |
|
0.13 |
|
|
0.56 |
|
|
0.41 |
|
|
0.44 |
|
|
1.54 |
|
Total |
$ |
0.19 |
|
$ |
0.62 |
|
$ |
0.47 |
|
$ |
0.50 |
|
$ |
1.78 |
_______
|
(1) |
Variable Dividends are declared the quarter following the period of
results (the period used to determine the variable divided based on
the shareholder return model). The table notes total dividends
earned in each quarter. |
Going forward, subject to declaration by the
Board, the Company intends to double the fixed dividend to $0.12
per share quarterly or $0.48 per share annually; variable dividends
will be paid in accordance with its shareholder return model.
Updated Shareholder Return Model
(SRM)
Beginning with first quarter 2023 results, in
accordance with the updated shareholder return model, Berry plans
to allocate Adjusted Free Cash Flow as follows:
- 80% primarily to share repurchases
and debt repurchases, and
- 20% to variable dividends.
Adjusted Free Cash Flow does not represent the
total increase or decrease in our cash balance, and it should not
be inferred that the entire amount of Adjusted Free Cash Flow is
available for variable dividends, debt or share repurchases or
other discretionary expenditures, since we have other
non-discretionary expenditures that are not deducted from this
measure and would be paid out of the 80% bucket, as
necessary.
The Board also increased the authorization for
share repurchases to $200 million. The Board had previously
authorized $75 million of debt repurchases all of which remains
available.
Full-Year 2023 Guidance
Berry’s 2023 capital program reflects
management’s prior experience with the constraints imposed by the
current permitting environment impacting Kern County, with an
underlying commitment to maximize Adjusted Free Cash Flow to return
to shareholders. Accordingly, our current plan contemplates a
slight decline in annual production year-over-year, primarily due
to anticipated delays in the receipt of new drill permits. In sum,
Berry’s current capital program for 2023 focuses on workovers and
other activities related to existing wellbores, as well as a
limited number of new wells for which we already have permits in
hand. The Company still, however, expects to be able to generate
significant Adjusted Free Cash Flow in 2023, based on current strip
pricing. For the avoidance of doubt, the expected sequential year
over year decline in Adjusted Free Cash Flow is almost exclusively
due to lower commodity price assumptions.
The Company has oil hedges for approximately
three-quarters of its expected 2023 oil production at about $77 per
barrel Brent and gas hedges for approximately three-quarters of its
expected 2023 gas purchases at about $5.40 per mmbtu.
|
Full-Year 2023 Guidance |
Low |
|
High |
|
Average Daily Production (boe/d)(1) |
|
24,000 |
|
|
|
25,200 |
|
|
Expenses from field operations ($/boe)(2) |
|
$35.00 |
|
|
|
$37.00 |
|
|
E&P non-production revenues ($/boe)(3) |
|
$3.30 |
|
|
|
$3.50 |
|
|
Natural gas purchase hedge settlements ($/boe)(4)(5) |
|
(3.60) |
|
|
|
(3.85) |
|
|
Taxes, Other than Income Taxes ($/boe) |
|
$4.75 |
|
|
|
$5.25 |
|
|
Adjusted General & Administrative (G&A) expenses
($/boe)(6)(7) |
|
|
|
|
E&P Segment & Corp |
|
$6.55 |
|
|
|
$6.95 |
|
|
Well Servicing and Abandonment Segment |
|
~$1.55 |
|
|
Capital Expenditures ($ millions) |
|
|
|
|
E&P Segment & Corp |
|
$95 |
|
|
|
$105 |
|
|
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. |
| (2) |
Expenses from field operations
include lease operating expenses, electricity generation expenses,
transportation expense, and marketing expenses. |
| (3) |
E&P non-production revenues
include sales from electricity, transportation, and marketing
activities. |
| (4) |
Natural gas purchase hedge
settlements is the cash (received) or paid from these derivatives
on a per boe basis. |
| (5) |
Based on natural gas hedge
positions and basis differentials as of February 1, 2023, and the
Henry Hub gas price of $3.75 per mmbtu. |
| (6) |
Adjusted General &
Administrative expenses and Well Servicing and Abandonment Segment
Adjusted EBITDA are non-GAAP financial measures. The Company does
not provide a reconciliation of these measures because the Company
believes such reconciliation would imply a degree of precision and
certainty that could be confusing to investors and is unable to
reasonably predict certain items included in or excluded from the
GAAP financial measures without unreasonable efforts. This is due
to the inherent difficulty of forecasting the timing or amount of
various items that have not yet occurred and are out of the
Company’s control or cannot be reasonably predicted. Non-GAAP
forward-looking measures provided without the most directly
comparable GAAP financial measures may vary materially from the
corresponding GAAP financial measures. |
| (7) |
See further discussion and
reconciliation in “Non-GAAP Financial Measures and
Reconciliations”. |
E&P FIELD OPERATIONS
We have changed the presentation of what we
formerly referred to as Opex or operating expenses. Overall,
management assesses the efficiency of our E&P field operations
by considering core E&P operating expenses together with our
cogeneration, marketing and transportation activities. In
particular, a core component of our E&P operations in
California is steam, which we use to lift heavy oil to the surface.
We operate several cogeneration facilities to produce some of the
steam needed in our operations. In comparing the cost effectiveness
of our cogeneration plants against other sources of steam in our
operations, management considers the cost of operating the
cogeneration plants, including the cost of the natural gas
purchased to operate the facilities, against the value of the steam
and electricity used in our E&P field operations and the
revenues we receive from sales of excess electricity to the grid.
We strive to minimize the variability of our fuel gas costs for our
California steam operations with natural gas purchase hedges.
Consequently, the efficiency of our E&P field operations are
impacted by the cash settlements we receive or pay from these
derivatives. We also have contracts for the transportation of fuel
gas from the Rockies which has historically been cheaper than the
California markets. With respect to transportation and marketing,
management also considers opportunistic sales of incremental
capacity in assessing the overall efficiencies of E&P
operations.
Lease operating expenses include fuel, labor,
field office, vehicle, supervision, maintenance, tools and
supplies, and workover expenses. Electricity generation expenses
include the portion of fuel, labor, maintenance, and tools and
supplies from two of our cogeneration facilities allocated to
electricity generation expense; the remaining cogeneration expenses
are included in lease operating expense. Transportation expenses
relate to our costs to transport the oil and gas that we produce
within our properties or move it to the market. Marketing expenses
mainly relate to natural gas purchased from third parties that
moves through our gathering and processing systems and then is sold
to third parties. Electricity revenue is from the sale of excess
electricity from two of our cogeneration facilities to a California
utility company under long-term contracts at market prices. These
cogeneration facilities are sized to satisfy the steam needs in
their respective fields, but the corresponding electricity produced
is more than the electricity that is currently required for the
operations in those fields. Transportation sales relate to water
and other liquids that we transport on our systems on behalf of
third parties and marketing revenues represent sales of natural gas
purchased from and sold to third parties.
Earnings Conference Call
Call Date: Wednesday, February 22, 2023
Call Time: 11:00 a.m. Eastern Time / 10:00 a.m.
Central Time / 8:00 a.m. Pacific Time
Join the live listen-only audio webcast at
https://edge.media-server.com/mmc/p/wjwwahmj or at
https://bry.com/category/events
If you would like to ask a question on the live
call, please preregister at any time using the following
link:https://register.vevent.com/register/BIc62dbff31cac400faf92dc1624074392
Once registered, you will receive the dial-in
numbers and a unique PIN number. You may then dial-in or have a
call back. When you dial in, you will input your PIN and be placed
into the call. If you register and forget your PIN or lose your
registration confirmation email, you may simply re-register and
receive a new PIN.
A web based audio replay will be available
shortly after the broadcast and will be archived at
https://ir.bry.com/reports-resources or visit
https://edge.media-server.com/mmc/p/wjwwahmj
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 and the Uinta basin of Utah,
with 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 (including, but not limited to, Adjusted Free
Cash Flow); 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
shareholder return model and the payment of any future dividends;
future repurchases of stock or debt; our ESG strategy and
initiation of new projects or business in connection therewith;
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, production and other operating risks;
effects of competition; uncertainties inherent in estimating
natural gas and oil reserves and in projecting future rates of
production; our ability to replace our reserves through exploration
and development activities; cash flow and access to capital; the
timing and funding of development expenditures; environmental,
health and safety risks; effects of hedging arrangements; potential
shut-ins of production due to lack of downstream demand or storage
capacity; disruptions to, capacity constraints in. or other
limitations on the third-party transportation and market takeaway
infrastructure (including pipeline systems) that deliver our oil
and natural gas and other processing and transportation
considerations; the impact and duration of the ongoing COVID-19
pandemic on demand and pricing levels; the ability to effectively
deploy our ESG strategy and risks associated with initiating new
projects or business in connection therewith; overall domestic and
global political and economic conditions; inflation levels,
particularly the recent rise to historically high levels, and
government efforts to reduce inflation, including increased
interest rates; changes in tax laws; 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 and the
Company’s Quarterly Report on Form 10-Q for the quarter ended
September 30, 2022.
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
responsibility 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
31,2022 |
|
Quarter EndedSeptember
30,2022 |
|
Quarter EndedDecember
31,2021 |
|
Year EndedDecember 31,2022 |
|
Year EndedDecember 31,2021 |
| |
(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 |
$ |
188,442 |
|
|
$ |
203,585 |
|
|
$ |
181,377 |
|
|
$ |
842,449 |
|
|
$ |
625,475 |
|
|
Service revenue |
|
46,792 |
|
|
|
48,594 |
|
|
|
35,840 |
|
|
|
181,400 |
|
|
|
35,840 |
|
|
Electricity sales |
|
8,284 |
|
|
|
9,711 |
|
|
|
6,308 |
|
|
|
30,833 |
|
|
|
35,636 |
|
|
(Losses) gains on oil and gas sales derivatives |
|
(48,872 |
) |
|
|
114,279 |
|
|
|
(16,378 |
) |
|
|
(137,109 |
) |
|
|
(156,399 |
) |
|
Marketing revenues |
|
— |
|
|
|
— |
|
|
|
834 |
|
|
|
289 |
|
|
|
3,921 |
|
|
Other revenues |
|
37 |
|
|
|
277 |
|
|
|
105 |
|
|
|
479 |
|
|
|
477 |
|
|
Total revenues and other |
|
194,683 |
|
|
|
376,446 |
|
|
|
208,086 |
|
|
|
918,341 |
|
|
|
544,950 |
|
|
Expenses and other: |
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
87,601 |
|
|
|
79,141 |
|
|
|
67,292 |
|
|
|
302,321 |
|
|
|
236,048 |
|
|
Cost of services |
|
35,010 |
|
|
|
37,628 |
|
|
|
28,339 |
|
|
|
142,819 |
|
|
|
28,339 |
|
|
Electricity generation expenses |
|
5,199 |
|
|
|
6,055 |
|
|
|
3,660 |
|
|
|
21,839 |
|
|
|
23,148 |
|
|
Transportation expenses |
|
1,021 |
|
|
|
1,277 |
|
|
|
1,758 |
|
|
|
4,564 |
|
|
|
6,897 |
|
|
Marketing expenses |
|
— |
|
|
|
— |
|
|
|
825 |
|
|
|
299 |
|
|
|
3,811 |
|
|
General and administrative expenses |
|
26,926 |
|
|
|
23,388 |
|
|
|
22,357 |
|
|
|
96,439 |
|
|
|
73,106 |
|
|
Depreciation, depletion and amortization |
|
39,509 |
|
|
|
39,506 |
|
|
|
38,903 |
|
|
|
156,847 |
|
|
|
144,495 |
|
|
Taxes, other than income taxes |
|
14,341 |
|
|
|
7,335 |
|
|
|
11,920 |
|
|
|
39,495 |
|
|
|
46,500 |
|
|
(Gains) losses on natural gas purchase derivatives |
|
(41,460 |
) |
|
|
(28,942 |
) |
|
|
15,772 |
|
|
|
(88,795 |
) |
|
|
(38,577 |
) |
|
Other operating (income) expenses |
|
(1,023 |
) |
|
|
623 |
|
|
|
(1,726 |
) |
|
|
3,722 |
|
|
|
3,101 |
|
|
Total expenses and other |
|
167,124 |
|
|
|
166,011 |
|
|
|
189,100 |
|
|
|
679,550 |
|
|
|
526,868 |
|
|
Other (expenses) income: |
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
(7,646 |
) |
|
|
(7,867 |
) |
|
|
(7,451 |
) |
|
|
(30,917 |
) |
|
|
(31,964 |
) |
|
Other, net |
|
(63 |
) |
|
|
(24 |
) |
|
|
(91 |
) |
|
|
(142 |
) |
|
|
(247 |
) |
|
Total other (expenses) income |
|
(7,709 |
) |
|
|
(7,891 |
) |
|
|
(7,542 |
) |
|
|
(31,059 |
) |
|
|
(32,211 |
) |
|
Income (loss) before income taxes |
|
19,850 |
|
|
|
202,544 |
|
|
|
11,444 |
|
|
|
207,732 |
|
|
|
(14,129 |
) |
|
Income tax (benefit) expense |
|
(52,114 |
) |
|
|
10,884 |
|
|
|
2,619 |
|
|
|
(42,436 |
) |
|
|
1,413 |
|
|
Net income (loss) |
$ |
71,964 |
|
|
$ |
191,660 |
|
|
$ |
8,825 |
|
|
$ |
250,168 |
|
|
$ |
(15,542 |
) |
| |
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) per share: |
|
|
|
|
|
|
|
|
|
|
Basic |
$ |
0.94 |
|
|
$ |
2.46 |
|
|
$ |
0.11 |
|
|
$ |
3.19 |
|
|
$ |
(0.19 |
) |
|
Diluted |
$ |
0.90 |
|
|
$ |
2.34 |
|
|
$ |
0.11 |
|
|
$ |
3.03 |
|
|
$ |
(0.19 |
) |
| |
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares outstanding - basic |
|
76,181 |
|
|
|
78,044 |
|
|
|
80,007 |
|
|
|
78,517 |
|
|
|
80,209 |
|
|
Weighted-average common shares outstanding - diluted |
|
80,312 |
|
|
|
82,045 |
|
|
|
84,011 |
|
|
|
82,586 |
|
|
|
80,209 |
|
| |
|
|
|
|
|
|
|
|
|
|
Adjusted Net Income(1) |
$ |
76,449 |
|
|
$ |
76,977 |
|
|
$ |
8,120 |
|
|
$ |
226,463 |
|
|
$ |
10,722 |
|
|
Weighted-average common shares outstanding - diluted |
|
80,312 |
|
|
|
82,045 |
|
|
|
84,011 |
|
|
|
82,586 |
|
|
|
83,496 |
|
|
Diluted earnings per share on Adjusted Net Income(1) |
$ |
0.95 |
|
|
$ |
0.94 |
|
|
$ |
0.10 |
|
|
$ |
2.74 |
|
|
$ |
0.13 |
|
| |
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(1) |
$ |
77,508 |
|
|
$ |
96,981 |
|
|
$ |
60,395 |
|
|
$ |
379,948 |
|
|
$ |
212,146 |
|
|
Adjusted Free Cash Flow(1)(2) |
$ |
55,803 |
|
|
$ |
52,724 |
|
|
|
n/a |
|
|
$ |
199,766 |
|
|
|
n/a |
|
|
Adjusted General and Administrative Expenses(1) |
$ |
19,410 |
|
|
$ |
19,107 |
|
|
$ |
16,870 |
|
|
$ |
76,475 |
|
|
$ |
57,015 |
|
|
Effective Tax Rate |
|
(263) |
% |
|
|
5 |
% |
|
|
23 |
% |
|
|
(20) |
% |
|
|
(10) |
% |
| |
|
|
|
|
|
|
|
|
|
| |
Quarter EndedDecember
31,2022 |
|
Quarter EndedSeptember
30,2022 |
|
Quarter EndedDecember
31,2021 |
|
Year EndedDecember 31,2022 |
|
Year EndedDecember 31,2021 |
| |
(unaudited)($ and shares in thousands, except per share
amounts) |
|
Cash Flow Data: |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
$ |
105,407 |
|
|
$ |
95,762 |
|
|
$ |
40,230 |
|
|
$ |
360,941 |
|
|
$ |
122,488 |
|
|
Net cash used in investing activities |
$ |
(54,888 |
) |
|
$ |
(34,241 |
) |
|
$ |
(58,251 |
) |
|
$ |
(164,552 |
) |
|
$ |
(168,787 |
) |
|
Net cash used in financing activities |
$ |
(45,742 |
) |
|
$ |
(72,543 |
) |
|
$ |
(4,857 |
) |
|
$ |
(165,422 |
) |
|
$ |
(18,975 |
) |
__________
|
(1) |
See further discussion and reconciliation in “Non-GAAP Financial
Measures and Reconciliations”. See further discussion and
reconciliation in “Non-GAAP Financial Measures and
Reconciliations”. |
| (2) |
Adjusted Free Cash Flow was not a
metric utilized by the Company prior to 2022. |
| |
December 31, 2022 |
|
December 31, 2021 |
| |
(unaudited)($ and shares in thousands) |
|
Balance Sheet Data: |
|
|
|
|
Total current assets |
$ |
218,055 |
|
$ |
147,498 |
|
Total property, plant and equipment, net |
$ |
1,359,813 |
|
$ |
1,301,349 |
|
Total current liabilities |
$ |
234,207 |
|
$ |
187,149 |
|
Long-term debt |
$ |
395,735 |
|
$ |
394,566 |
|
Total stockholders' equity |
$ |
800,485 |
|
$ |
692,648 |
|
Outstanding common stock shares as of |
|
75,768 |
|
|
80,007 |
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, 2022 |
| |
E&P |
|
Well Servicing and Abandonment |
|
Corporate/Eliminations |
|
Consolidated Company |
|
|
(unaudited)(in thousands) |
|
Revenues(1) |
$ |
874,190 |
|
$ |
184,448 |
|
$ |
(3,188 |
) |
|
$ |
1,055,450 |
|
Net income (loss) before income taxes |
$ |
298,125 |
|
$ |
14,747 |
|
$ |
(105,140 |
) |
|
$ |
207,732 |
|
Adjusted EBITDA(2) |
$ |
411,811 |
|
$ |
26,113 |
|
$ |
(57,976 |
) |
|
$ |
379,948 |
|
Capital expenditures |
$ |
141,930 |
|
$ |
8,455 |
|
$ |
2,536 |
|
|
$ |
152,921 |
|
Total assets |
$ |
1,563,251 |
|
$ |
83,461 |
|
$ |
(15,682 |
) |
|
$ |
1,631,030 |
| |
Year Ended December 31, 2021 |
| |
E&P |
|
Well Servicing and Abandonment |
|
Corporate/Eliminations |
|
Consolidated Company |
|
|
(unaudited)(in thousands) |
|
Revenues(1) |
$ |
665,509 |
|
$ |
35,840 |
|
$ |
— |
|
|
$ |
701,349 |
|
|
Net income (loss) before income taxes |
$ |
82,826 |
|
$ |
1 |
|
$ |
(96,956 |
) |
|
$ |
(14,129 |
) |
|
Adjusted EBITDA(2) |
$ |
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 |
|
__________
|
(1) |
These revenues do not include hedge settlements. |
| (2) |
See further discussion and
reconciliation in “Non-GAAP Financial Measures and
Reconciliations”. |
COMMODITY PRICING
| |
Quarter EndedDecember
31,2022 |
|
Quarter EndedSeptember
30,2022 |
|
Quarter EndedDecember
31,2021 |
|
Year EndedDecember 31,2022 |
|
Year EndedDecember 31,2021 |
|
Weighted Average Realized Prices |
|
|
|
|
|
|
|
|
|
|
Oil without hedge ($/bbl) |
$ |
80.61 |
|
|
$ |
89.54 |
|
|
$ |
75.11 |
|
|
$ |
91.98 |
|
|
$ |
66.57 |
|
|
Effects of scheduled derivative settlements ($/bbl) |
$ |
(7.22 |
) |
|
$ |
(13.13 |
) |
|
$ |
(20.50 |
) |
|
$ |
(14.39 |
) |
|
$ |
(16.45 |
) |
|
Oil with hedge ($/bbl) |
$ |
73.39 |
|
|
$ |
76.41 |
|
|
$ |
54.61 |
|
|
$ |
77.59 |
|
|
$ |
50.12 |
|
|
Natural gas ($/mcf) |
$ |
12.02 |
|
|
$ |
7.95 |
|
|
$ |
5.60 |
|
|
$ |
7.96 |
|
|
$ |
5.27 |
|
|
NGLs ($/bbl) |
$ |
29.67 |
|
|
$ |
40.72 |
|
|
$ |
47.45 |
|
|
$ |
43.85 |
|
|
$ |
36.64 |
|
| |
|
|
|
|
|
|
|
|
|
|
Index Prices |
|
|
|
|
|
|
|
|
|
|
Brent oil ($/bbl) |
$ |
88.63 |
|
|
$ |
97.70 |
|
|
$ |
79.66 |
|
|
$ |
99.04 |
|
|
$ |
70.95 |
|
|
WTI oil ($/bbl) |
$ |
82.51 |
|
|
$ |
91.96 |
|
|
$ |
76.89 |
|
|
$ |
94.39 |
|
|
$ |
67.90 |
|
|
Kern, Delivered natural gas ($/mmbtu)(1) |
$ |
14.94 |
|
|
$ |
8.74 |
|
|
$ |
5.65 |
|
|
$ |
8.99 |
|
|
$ |
5.65 |
|
|
Natural gas (mmbtu) - Northwest, Rocky Mountains(2) |
$ |
7.54 |
|
|
$ |
7.79 |
|
|
$ |
5.91 |
|
|
$ |
6.95 |
|
|
$ |
3.90 |
|
|
Henry Hub natural gas ($/mmbtu)(2) |
$ |
5.55 |
|
|
$ |
8.03 |
|
|
$ |
4.75 |
|
|
$ |
6.45 |
|
|
$ |
3.89 |
|
__________
|
(1) |
Kern, Delivered Index is the relevant index used for gas purchases
in California. |
| (2) |
Northwest, Rocky Mountains and
Henry Hub are the relevant indices used for gas sales and purchases
in the Rockies. |
Natural gas prices and differentials are
strongly affected by local market fundamentals, availability of
transportation capacity from producing areas and seasonal impacts.
Our key exposure to gas prices is in our costs. We purchase
substantially more natural gas for our California steamfloods and
cogeneration facilities than we produce and sell in the Rockies. In
May 2022, we began purchasing most of our gas in the Rockies and
transporting it to our California operations using our Kern River
pipeline capacity. In 2022, we purchased approximately 60,000
mmbtu/d, of which 12,000 mmbtu/d was purchased in California
beginning when we entered into the Kern River pipeline capacity
agreement for 48,000 mmbtu/d. The natural gas we purchase in the
Rockies is shipped to our operations in California to help limit
our exposure to California fuel gas purchase price fluctuations. We
strive to further minimize the variability of our fuel gas costs
for our steam operations by hedging a significant portion of gas
purchases. Additionally, the negative impact of higher gas prices
on our California operating expenses is partially offset by higher
gas sales for the gas we produce and sell in the Rockies.
CURRENT HEDGING SUMMARY
As of January 31, 2023, we had the following crude
oil production and gas purchases hedges.
| |
Q1 2023 |
|
Q2 2023 |
|
Q3 2023 |
|
Q4 2023 |
|
FY 2024 |
|
FY 2025 |
|
FY 2026 |
|
Brent |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (bbls) |
|
1,385,278 |
|
|
1,387,750 |
|
|
1,211,717 |
|
|
1,196,000 |
|
|
3,392,048 |
|
|
— |
|
|
— |
|
Weighted-average price ($/bbl) |
$ |
77.15 |
|
$ |
77.01 |
|
$ |
76.26 |
|
$ |
76.18 |
|
$ |
76.12 |
|
$ |
— |
|
$ |
— |
|
Put Spreads |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (bbls) |
|
540,000 |
|
|
546,000 |
|
|
552,000 |
|
|
552,000 |
|
|
1,281,000 |
|
|
— |
|
|
— |
|
Weighted-average price ($/bbl) |
$50.00/$40.00 |
|
$50.00/$40.00 |
|
$50.00/$40.00 |
|
$50.00/$40.00 |
|
$50.00/$40.00 |
|
$ |
— |
|
$ |
— |
|
Producer Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (bbls) |
|
360,000 |
|
|
364,000 |
|
|
368,000 |
|
|
368,000 |
|
|
1,098,000 |
|
|
2,486,127 |
|
|
472,500 |
|
Weighted-average price ($/bbl) |
$40.00/$106.00 |
|
$40.00/$106.00 |
|
$40.00/$106.00 |
|
$40.00/$106.00 |
|
$40.00/$105.00 |
|
$58.53/$91.11 |
|
$60.00/$82.21 |
|
Henry Hub - Natural Gas purchases |
|
|
|
|
|
|
|
|
|
|
|
|
|
Consumer Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (mmbtu) |
|
2,110,000 |
|
|
1,820,000 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Weighted-average price ($/mmbtu) |
$4.00/$2.75 |
|
$4.00/$2.75 |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
NWPL - Natural Gas purchases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (mmbtu) |
|
1,800,000 |
|
|
3,640,000 |
|
|
3,680,000 |
|
|
3,680,000 |
|
|
7,320,000 |
|
|
6,080,000 |
|
|
— |
|
Weighted-average price ($/mmbtu) |
$ |
6.40 |
|
$ |
5.34 |
|
$ |
5.34 |
|
$ |
5.34 |
|
$ |
4.27 |
|
$ |
4.27 |
|
$ |
— |
|
Gas Basis Differentials |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NWPL/HH - Natural Gas Purchases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (mmbtu) |
|
1,180,000 |
|
|
— |
|
|
— |
|
|
610,000 |
|
|
— |
|
|
— |
|
|
— |
|
Weighted-average price ($/mmbtu) |
$ |
1.12 |
|
$ |
— |
|
$ |
— |
|
$ |
1.12 |
|
$ |
— |
|
$ |
— |
|
$ |
— |
E&P FIELD OPERATIONS
| |
Quarter EndedDecember
31,2022 |
|
Quarter EndedSeptember
30,2022 |
|
Quarter EndedDecember
31,2021 |
|
Year EndedDecember 31,2022 |
|
Year EndedDecember 31,2021 |
| |
(unaudited)($ in per boe amounts) |
|
Expenses from field operations |
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
$ |
36.95 |
|
|
$ |
33.40 |
|
|
$ |
26.23 |
|
|
$ |
31.72 |
|
|
$ |
23.60 |
|
|
Electricity generation expenses |
|
2.19 |
|
|
|
2.56 |
|
|
|
1.43 |
|
|
|
2.29 |
|
|
|
2.31 |
|
|
Transportation expenses |
|
0.43 |
|
|
|
0.54 |
|
|
|
0.69 |
|
|
|
0.48 |
|
|
|
0.69 |
|
|
Marketing expenses |
|
— |
|
|
|
— |
|
|
|
0.32 |
|
|
|
0.03 |
|
|
|
0.38 |
|
|
Total |
$ |
39.57 |
|
|
$ |
36.50 |
|
|
$ |
28.67 |
|
|
$ |
34.52 |
|
|
$ |
26.98 |
|
| |
|
|
|
|
|
|
|
|
|
|
Cash settlements received for gas purchase
hedges |
$ |
(5.28 |
) |
|
$ |
(5.82 |
) |
|
$ |
(3.37 |
) |
|
$ |
(4.00 |
) |
|
$ |
(5.09 |
) |
| |
|
|
|
|
|
|
|
|
|
|
E&P non-production revenues |
|
|
|
|
|
|
|
|
|
|
Electricity sales |
$ |
3.49 |
|
|
$ |
4.10 |
|
|
$ |
2.46 |
|
|
$ |
3.24 |
|
|
$ |
3.56 |
|
|
Transportation sales |
|
0.02 |
|
|
|
0.12 |
|
|
|
0.05 |
|
|
|
0.05 |
|
|
|
0.05 |
|
|
Marketing revenue |
|
— |
|
|
|
— |
|
|
|
0.33 |
|
|
|
0.03 |
|
|
|
0.39 |
|
|
Total |
$ |
3.51 |
|
|
$ |
4.22 |
|
|
$ |
2.84 |
|
|
$ |
3.32 |
|
|
$ |
4.00 |
|
| |
|
|
|
|
|
|
|
|
|
|
Total mboe |
|
2,371 |
|
|
|
2,369 |
|
|
|
2,566 |
|
|
|
9,532 |
|
|
|
10,004 |
|
We have changed the presentation of what we
formerly referred to as Opex or operating expenses. Overall,
management assesses the efficiency of our E&P field operations
by considering core E&P operating expenses together with our
cogeneration, marketing and transportation activities. In
particular, a core component of our E&P operations in
California is steam, which we use to lift heavy oil to the surface.
We operate several cogeneration facilities to produce some of the
steam needed in our operations. In comparing the cost effectiveness
of our cogeneration plants against other sources of steam in our
operations, management considers the cost of operating the
cogeneration plants, including the cost of the natural gas
purchased to operate the facilities, against the value of the steam
and electricity used in our E&P field operations and the
revenues we receive from sales of excess electricity to the grid.
We strive to minimize the variability of our fuel gas costs for our
California steam operations with natural gas purchase hedges.
Consequently, the efficiency of our E&P field operations are
impacted by the cash settlements we receive or pay from these
derivatives. We also have contracts for the transportation of fuel
gas from the Rockies which has historically been cheaper than the
California markets. With respect to transportation and marketing,
management also considers opportunistic sales of incremental
capacity in assessing the overall efficiencies of E&P
operations.
Lease operating expenses include fuel, labor,
field office, vehicle, supervision, maintenance, tools and
supplies, and workover expenses. Electricity generation expenses
include the portion of fuel, labor, maintenance, and tools and
supplies from two of our cogeneration facilities allocated to
electricity generation expense; the remaining cogeneration expenses
are included in lease operating expense. Transportation expenses
relate to our costs to transport the oil and gas that we produce
within our properties or move it to the market. Marketing expenses
mainly relate to natural gas purchased from third parties that
moves through our gathering and processing systems and then is sold
to third parties. Electricity revenue is from the sale of excess
electricity from two of our cogeneration facilities to a California
utility company under long-term contracts at market prices. These
cogeneration facilities are sized to satisfy the steam needs in
their respective fields, but the corresponding electricity produced
is more than the electricity that is currently required for the
operations in those fields. Transportation sales relate to water
and other liquids that we transport on our systems on behalf of
third parties and marketing revenues represent sales of natural gas
purchased from and sold to third parties.
PRODUCTION STATISTICS
|
|
Quarter EndedDecember
31,2022 |
|
Quarter EndedSeptember
30,2022 |
|
Quarter EndedDecember
31,2021 |
|
Year EndedDecember 31,2022 |
|
Year EndedDecember 31,2021 |
|
Net Oil, Natural Gas and NGLs Production Per
Day(1): |
|
|
|
|
|
|
|
|
|
|
Oil (mbbl/d) |
|
|
|
|
|
|
|
|
|
|
California(2) |
21.1 |
|
20.8 |
|
22.7 |
|
21.3 |
|
22.0 |
|
Utah(3) |
3.0 |
|
2.9 |
|
2.1 |
|
2.7 |
|
2.2 |
|
Colorado(4) |
— |
|
— |
|
— |
|
— |
|
— |
|
Total oil |
24.1 |
|
23.7 |
|
24.8 |
|
24.0 |
|
24.2 |
|
Natural gas (mmcf/d) |
|
|
|
|
|
|
|
|
|
|
California |
— |
|
— |
|
— |
|
— |
|
— |
|
Utah(3) |
7.8 |
|
10.4 |
|
10.0 |
|
9.6 |
|
10.2 |
|
Colorado(4) |
— |
|
— |
|
6.4 |
|
0.6 |
|
6.9 |
|
Total natural gas |
7.8 |
|
10.4 |
|
16.4 |
|
10.2 |
|
17.1 |
|
NGLs (mbbl/d) |
|
|
|
|
|
|
|
|
|
|
California |
— |
|
— |
|
— |
|
— |
|
— |
|
Utah(3) |
0.4 |
|
0.4 |
|
0.4 |
|
0.4 |
|
0.4 |
|
Colorado(4) |
— |
|
— |
|
— |
|
— |
|
— |
|
Total NGLs |
0.4 |
|
0.4 |
|
0.4 |
|
0.4 |
|
0.4 |
|
Total Production
(mboe/d)(5) |
25.8 |
|
25.8 |
|
27.9 |
|
26.1 |
|
27.4 |
__________
|
(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
approximately 700 boe/d. |
| (3) |
Includes production for Antelope
Creek area from February 2022, when it was acquired, through the
end of 2022. |
| (4) |
In January 2022, we divested all
of our natural gas properties in Colorado. |
| (5) |
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, 2022,
the average prices of Brent oil and Henry Hub natural gas were
$99.04 per bbl and $6.45 per mmbtu respectively. |
CAPITAL EXPENDITURES
| |
Quarter EndedDecember 31,
2022 |
|
Quarter EndedSeptember 30,
2022 |
|
Quarter EndedDecember 31,
2021 |
|
Year EndedDecember 31, 2022 |
|
Year EndedDecember 31, 2021 |
| |
(unaudited)(in thousands) |
|
Capital expenditures(1)(2) |
$ |
50,398 |
|
$ |
40,817 |
|
$ |
27,673 |
|
$ |
152,921 |
|
$ |
132,719 |
__________
|
(1) |
Capital expenditures include capitalized overhead and interest and
excludes acquisitions and asset retirement spending. |
| (2) |
Capital expenditures in the
quarters ended December 31, 2022, September 30, 2022 and December
31, 2021 included $5 million, $2 million and $1 million,
respectively, for the well servicing and abandonment business,
which was acquired on October 1, 2021. Capital expenditures in the
years ended December 31, 2022 and December 31, 2021 included $8
million and $1 million, respectively, for the well servicing and
abandonment business. |
NON-GAAP
FINANCIAL MEASURES AND RECONCILIATIONS
Adjusted Net Income (Loss) is not a measure of
net income (loss), Adjusted Free Cash Flow is not a measure of cash
flow, and Adjusted EBITDA is not a measure of either net income
(loss) or cash flow, in all cases, as determined by GAAP. Adjusted
EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) 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 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. 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. We also use Adjusted EBITDA in planning our
capital allocation to sustain production levels and to determine
our strategic hedging needs aside from the hedging requirements of
the 2021 RBL Facility.
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 statutory tax rate. 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. We
believe Adjusted Net Income (Loss) is useful to investors because
it reflects how management evaluates the Company’s ongoing
financial and operating performance from period-to-period after
removing certain transactions and activities that affect
comparability of the metrics and are not reflective of the
Company’s core operations. We believe this also makes it easier for
investors to compare our period-to-period results with our
peers.
We define Adjusted Free Cash Flow, which is a
non-GAAP financial measure, as cash flow from operations less
regular fixed dividends and maintenance capital. Maintenance
capital represents the capital expenditures needed to maintain the
same volume of annual oil and gas production and is defined as
capital expenditures, excluding, when applicable, E&P capital
expenditures that are related to strategic business expansion, such
as acquisitions and divestitures of oil and gas properties and any
exploration and development activities to increase production
beyond the prior year’s annual production volumes and capital
expenditures in our Well Servicing and Abandonment and Corporate
segments that are related to ancillary sustainability initiatives
or other expenditures that are discretionary and unrelated to
maintenance of our core business. Management believes Adjusted Free
Cash Flow may be useful in an investor analysis of our ability to
generate cash from operating activities from our existing oil and
gas asset base after maintaining the existing production volumes of
that asset base to return capital to stockholders, fund further
business expansion through acquisitions or investments in our
existing asset base to increase production volumes and pay other
non-discretionary expenses. Management also uses Adjusted Free Cash
Flow as the primary metric to determine the quarterly variable
dividend. Under our shareholder return model, in 2022, we expected
to allocate 60% of Adjusted Free Cash Flow to direct shareholder
returns, predominantly in the form of cash variable dividends, as
well as opportunistic debt repurchases. We expected to use the
remaining 40% for opportunistic growth, including from our
extensive inventory of drilling opportunities, advancing our short-
and long-term sustainability initiatives, share repurchases,
capital retention and funding mandatory debt service requirements
or other non-discretionary expenditures. In early 2023, we updated
our shareholder return model including to double our quarterly
fixed dividend to $0.12 per share. Any dividends actually paid will
be determined by our Board of Directors in light of existing
conditions, including our earnings, financial condition,
restrictions in financing agreements, business conditions and other
factors. We also modified the allocations of Adjusted Free Cash
Flow. Our goal is to continue maximizing shareholder value through
overall returns. The allocation beginning in 2023 will be (a) 80%
in the form of debt or share repurchases, or other items including
growth and sustainability initiatives, as well as funding mandatory
debt service requirements or other non-discretionary expenditures;
(b) 20% in the form of variable cash dividends.
Adjusted Free Cash Flow does not represent the
total increase or decrease in our cash balance, and it should not
be inferred that the entire amount of Adjusted Free Cash Flow is
available for variable dividends, debt or share repurchase or other
discretionary expenditures, since we have mandatory debt service
requirements and other non-discretionary expenditures that are not
deducted from this measure.
We define Adjusted General and Administrative
Expenses as general and administrative expenses adjusted for
non-cash stock compensation expense and unusual and infrequent
costs. Management believes Adjusted General and Administrative
Expenses is useful because it allows us to more effectively compare
our performance from period to period. We believe Adjusted General
and Administrative Expenses is useful to investors because it
reflects how management evaluates the Company’s ongoing general and
administrative expenses from period-to-period after removing
non-cash stock compensation, as well as unusual or infrequent costs
that affect comparability of the metrics and are not reflective of
the Company’s administrative costs. We believe this also makes it
easier for investors to compare our period-to-period results with
our peers.
While Adjusted EBITDA, Adjusted Free Cash Flow,
Adjusted Net Income (Loss) and Adjusted General and Administrative
Expenses are non-GAAP measures, the amounts included in the
calculation of Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted
Net Income (Loss) 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. Certain
items excluded from Adjusted EBITDA are significant components in
understanding and assessing our financial performance, such as our
cost of capital and tax structure, as well as the historic cost of
depreciable and depletable assets. Our computations of Adjusted
EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and
Adjusted General and Administrative Expenses may not be comparable
to other similarly titled measures used by other companies.
Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income
(Loss) 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 EBITDA
The following tables present a reconciliation of
the non-GAAP measure Adjusted EBITDA to the GAAP financial measures
of net income (loss) and net cash provided (used) by operating
activities, as applicable, for each of the periods indicated.
| |
Quarter EndedDecember
31,2022 |
|
Quarter EndedSeptember
30,2022 |
|
Quarter EndedDecember
31,2021 |
|
Year EndedDecember 31,2022 |
|
Year EndedDecember 31,2021 |
| |
(unaudited)(in thousands) |
|
Adjusted EBITDA reconciliation to net income (loss) and net
cash provided by operating activities: |
|
|
|
|
|
Net income (loss) |
$ |
71,964 |
|
|
$ |
191,660 |
|
|
$ |
8,825 |
|
|
$ |
250,168 |
|
|
$ |
(15,542 |
) |
|
Add (Subtract): |
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
7,646 |
|
|
|
7,867 |
|
|
|
7,451 |
|
|
|
30,917 |
|
|
|
31,964 |
|
|
Income tax (benefit) expense |
|
(52,114 |
) |
|
|
10,884 |
|
|
|
2,619 |
|
|
|
(42,436 |
) |
|
|
1,413 |
|
|
Depreciation, depletion, and amortization |
|
39,509 |
|
|
|
39,506 |
|
|
|
38,903 |
|
|
|
156,847 |
|
|
|
144,495 |
|
|
Losses (gains) on derivatives |
|
7,412 |
|
|
|
(143,221 |
) |
|
|
32,150 |
|
|
|
48,314 |
|
|
|
117,822 |
|
|
Net cash paid for scheduled derivative settlements |
|
(3,504 |
) |
|
|
(14,739 |
) |
|
|
(33,421 |
) |
|
|
(88,023 |
) |
|
|
(87,625 |
) |
|
Other operating (income) expenses |
|
(1,023 |
) |
|
|
623 |
|
|
|
(1,726 |
) |
|
|
3,722 |
|
|
|
3,101 |
|
|
Stock compensation expense |
|
4,350 |
|
|
|
4,401 |
|
|
|
3,564 |
|
|
|
16,973 |
|
|
|
13,783 |
|
|
Non-recurring costs(1) |
|
3,268 |
|
|
|
— |
|
|
|
2,030 |
|
|
|
3,466 |
|
|
|
2,735 |
|
|
Adjusted EBITDA |
$ |
77,508 |
|
|
$ |
96,981 |
|
|
$ |
60,395 |
|
|
$ |
379,948 |
|
|
$ |
212,146 |
|
| |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
$ |
105,407 |
|
|
$ |
95,762 |
|
|
$ |
40,230 |
|
|
$ |
360,941 |
|
|
$ |
122,488 |
|
|
Add (Subtract): |
|
|
|
|
|
|
|
|
|
|
Cash interest payments |
|
311 |
|
|
|
14,493 |
|
|
|
97 |
|
|
|
29,792 |
|
|
|
29,211 |
|
|
Cash income tax payments |
|
828 |
|
|
|
321 |
|
|
|
405 |
|
|
|
3,633 |
|
|
|
699 |
|
|
Non-recurring costs(1) |
|
3,268 |
|
|
|
— |
|
|
|
2,030 |
|
|
|
3,466 |
|
|
|
2,735 |
|
|
Changes in operating assets and liabilities - working
capital(2) |
|
(31,003 |
) |
|
|
(14,151 |
) |
|
|
14,884 |
|
|
|
(21,446 |
) |
|
|
53,425 |
|
|
Other operating (income) expenses, net (noncash portion) |
|
(1,303 |
) |
|
|
556 |
|
|
|
2,749 |
|
|
|
3,562 |
|
|
|
3,588 |
|
|
Adjusted EBITDA |
$ |
77,508 |
|
|
$ |
96,981 |
|
|
$ |
60,395 |
|
|
$ |
379,948 |
|
|
$ |
212,146 |
|
__________
|
(1) |
Non-recurring costs include legal and professional service expenses
related to acquisition and divestiture activity for the fourth
quarter of 2021 and the first quarter of 2022 and the executive
transition costs in the fourth quarter of 2022. |
| (2) |
Changes in other assets and
liabilities consists of working capital and various immaterial
items. |
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, 2022 |
| |
E&P |
|
Well Servicing and Abandonment |
|
Corporate/Eliminations |
|
Consolidated Company |
| |
(unaudited)(in thousands) |
|
Adjusted EBITDA reconciliation to net income
(loss): |
|
|
|
|
|
|
|
|
Net income (loss) |
$ |
298,125 |
|
|
$ |
14,747 |
|
|
$ |
(62,704 |
) |
|
$ |
250,168 |
|
|
Add (Subtract): |
|
|
|
|
|
|
|
|
Interest expense |
|
5,053 |
|
|
|
23 |
|
|
|
25,841 |
|
|
|
30,917 |
|
|
Income tax benefit |
|
— |
|
|
|
— |
|
|
|
(42,436 |
) |
|
|
(42,436 |
) |
|
Depreciation, depletion, and amortization |
|
139,886 |
|
|
|
12,548 |
|
|
|
4,413 |
|
|
|
156,847 |
|
|
Losses on derivatives |
|
48,314 |
|
|
|
— |
|
|
|
— |
|
|
|
48,314 |
|
|
Net cash paid for scheduled derivative settlements |
|
(88,023 |
) |
|
|
— |
|
|
|
— |
|
|
|
(88,023 |
) |
|
Other operating expenses (income) |
|
3,827 |
|
|
|
(1,690 |
) |
|
|
1,585 |
|
|
|
3,722 |
|
|
Stock compensation expense |
|
1,361 |
|
|
|
287 |
|
|
|
15,325 |
|
|
|
16,973 |
|
|
Non-recurring costs(1) |
|
3,268 |
|
|
|
198 |
|
|
|
— |
|
|
|
3,466 |
|
|
Adjusted EBITDA |
$ |
411,811 |
|
|
$ |
26,113 |
|
|
$ |
(57,976 |
) |
|
$ |
379,948 |
|
| |
Year Ended December 31, 2021 |
| |
E&P |
|
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) |
|
— |
|
|
|
1,335 |
|
|
1,400 |
|
|
|
2,735 |
|
|
Adjusted EBITDA |
$ |
251,146 |
|
|
$ |
4,310 |
|
$ |
(43,310 |
) |
|
$ |
212,146 |
|
__________
|
(1) |
Non-recurring costs include legal and professional service expenses
related to acquisition and divestiture activity for the fourth
quarter of 2021 and the first quarter of 2022 and the executive
transition costs in the fourth quarter of 2022. |
ADJUSTED FREE CASH
FLOW
The following table presents a reconciliation of
the non-GAAP financial measure Adjusted Free Cash Flow to the GAAP
financial measure of operating cash flow in the period indicated.
We use Adjusted Free Cash Flow for our shareholder return model,
which began in 2022.
| |
Quarter Ended |
|
Year Ended |
| |
December 31, 2022 |
|
September 30, 2022 |
|
December 31,
2022(4) |
| |
|
|
(unaudited)(in thousands) |
|
|
|
Adjusted Free Cash Flow: |
|
Net cash provided by operating activities(1) |
$ |
105,407 |
|
|
$ |
95,762 |
|
|
$ |
360,941 |
|
|
Subtract: |
|
|
|
|
|
|
Maintenance capital(2) |
|
(45,047 |
) |
|
|
(38,312 |
) |
|
|
(141,930 |
) |
|
Fixed dividends(3) |
|
(4,557 |
) |
|
|
(4,726 |
) |
|
|
(19,245 |
) |
|
Adjusted Free Cash Flow |
$ |
55,803 |
|
|
$ |
52,724 |
|
|
$ |
199,766 |
|
__________
| (1) |
On a
consolidated basis. |
| (2) |
Maintenance capital is the capital required to keep annual
production flat, and is calculated as follows: |
| |
Quarter Ended |
|
Year Ended |
| |
December 31, 2022 |
|
September 30, 2022 |
|
December 31, 2022 |
| |
(unaudited)(in thousands) |
|
Consolidated capital expenditures(a) |
$ |
(50,398 |
) |
|
$ |
(40,817 |
) |
|
$ |
(152,921 |
) |
|
Excluded items(b) |
|
5,351 |
|
|
|
2,505 |
|
|
|
10,991 |
|
|
Maintenance capital |
$ |
(45,047 |
) |
|
$ |
(38,312 |
) |
|
$ |
(141,930 |
) |
__________
|
|
(a) |
Capital expenditures include capitalized overhead and interest and
excludes acquisitions and asset retirement spending. |
| |
(b) |
Comprised of the capital
expenditures in our E&P segment that are related to strategic
business expansion, such as acquisitions and divestitures of oil
and gas properties and any exploration and development activities
to increase production beyond the prior year’s annual production
volumes and capital expenditures in our well servicing and
abandonment segment and corporate expenditures that are related to
ancillary sustainability initiatives or other expenditures that are
discretionary and unrelated to maintenance of our core business.
For the quarter ended December 31, 2022, the quarter ended
September 30, 2022, and the year ended December 31, 2022 we
excluded approximately $5 million, $2 million, and $8 million of
capital expenditures related to our well servicing and abandonment
segment, which was substantially all used for sustainability
initiatives. For the quarter ended December 31, 2022, the quarter
ended September 30, 2022, and the year ended December 31, 2022 we
excluded approximately $0.5 million, $0.8 million, and $3 million
of corporate capital expenditures, which we determined was not
related to the maintenance of our baseline production. |
| (3) |
Represents fixed
dividends declared which are included in the “Dividends declared on
common stock” line in the consolidated statement of stockholders’
equity. |
| (4) |
Adjusted Free Cash
Flow was not a metric utilized by the Company prior to 2022. |
ADJUSTED NET INCOME (LOSS)
The following table presents a reconciliation of
the non-GAAP financial measure Adjusted Net Income (Loss) to the
GAAP financial measure of net income (loss) and Adjusted Net Income
(Loss) per share — diluted to net income per share — diluted.
| |
Quarter Ended |
| |
December 31, 2022 |
|
September 30, 2022 |
|
December 31, 2021 |
| |
(in thousands) |
|
per share - diluted |
|
(in thousands) |
|
per share - diluted |
|
(in thousands) |
|
per share - diluted |
| |
(unaudited) |
|
Adjusted Net Income (Loss) reconciliation to net income
(loss): |
|
Net income |
$ |
71,964 |
|
|
$ |
0.90 |
|
|
$ |
191,660 |
|
|
$ |
2.34 |
|
|
$ |
8,825 |
|
|
$ |
0.11 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Add (Subtract): |
|
|
|
|
|
|
|
|
|
|
|
|
Losses (gains) on derivatives |
|
7,412 |
|
|
|
0.09 |
|
|
|
(143,221 |
) |
|
|
(1.75 |
) |
|
|
32,150 |
|
|
|
0.38 |
|
|
Net cash paid for scheduled derivative settlements |
|
(3,504 |
) |
|
|
(0.04 |
) |
|
|
(14,739 |
) |
|
|
(0.18 |
) |
|
|
(33,421 |
) |
|
|
(0.40 |
) |
|
Other operating (income) expenses |
|
(1,023 |
) |
|
|
(0.02 |
) |
|
|
623 |
|
|
|
0.01 |
|
|
|
(1,726 |
) |
|
|
(0.01 |
) |
|
Non-recurring costs(1) |
|
3,268 |
|
|
|
0.04 |
|
|
|
— |
|
|
|
— |
|
|
|
2,030 |
|
|
|
0.02 |
|
|
Total additions (subtractions), net |
|
6,153 |
|
|
|
0.07 |
|
|
|
(157,337 |
) |
|
|
(1.92 |
) |
|
|
(967 |
) |
|
|
(0.01 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (expense) benefit of adjustments(2) |
|
(1,668 |
) |
|
|
(0.02 |
) |
|
|
42,654 |
|
|
|
0.52 |
|
|
|
262 |
|
|
|
— |
|
|
Adjusted Net Income |
$ |
76,449 |
|
|
$ |
0.95 |
|
|
$ |
76,977 |
|
|
$ |
0.94 |
|
|
$ |
8,120 |
|
|
$ |
0.10 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS on Adjusted Net Income |
$ |
1.00 |
|
|
|
|
$ |
0.99 |
|
|
|
|
$ |
0.10 |
|
|
|
|
Diluted EPS on Adjusted Net Income |
$ |
0.95 |
|
|
|
|
$ |
0.94 |
|
|
|
|
$ |
0.10 |
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding - basic |
|
76,181 |
|
|
|
|
|
78,044 |
|
|
|
|
|
80,007 |
|
|
|
|
Weighted average shares outstanding - diluted |
|
80,312 |
|
|
|
|
|
82,045 |
|
|
|
|
|
84,011 |
|
|
|
__________
|
(1) |
Non-recurring costs include legal and professional service expenses
related to acquisition and divestiture activity for the fourth
quarter of 2021 and the first quarter of 2022 and the executive
transition costs in the fourth quarter of 2022. |
| (2) |
The federal and state statutory
rate was utilized in both 2022 and 2021. We updated the disclosure
for 2021 to reflect the statutory rate, instead of the effective
tax rate previously utilized. |
| |
Year Ended |
| |
December 31, 2022 |
|
December 31, 2021 |
| |
(in thousands) |
|
per share-diluted |
|
(in thousands) |
|
per share-diluted |
| |
(unaudited) |
| Adjusted Net Income
(Loss) reconciliation to net (loss) income: |
|
|
Net income (loss) |
$ |
250,168 |
|
|
$ |
3.03 |
|
|
$ |
(15,542 |
) |
|
$ |
(0.19 |
) |
| |
|
|
|
|
|
|
|
|
Add (Subtract): |
|
|
|
|
|
|
|
|
Losses on derivatives |
|
48,314 |
|
|
|
0.59 |
|
|
|
117,822 |
|
|
|
1.41 |
|
|
Net cash paid for scheduled derivative settlements |
|
(88,023 |
) |
|
|
(1.07 |
) |
|
|
(87,625 |
) |
|
|
(1.05 |
) |
|
Other operating expenses |
|
3,722 |
|
|
|
0.04 |
|
|
|
3,101 |
|
|
|
0.05 |
|
|
Non-recurring costs(1) |
|
3,466 |
|
|
|
0.04 |
|
|
|
2,735 |
|
|
|
0.03 |
|
|
Total (subtractions) additions, net |
|
(32,521 |
) |
|
|
(0.40 |
) |
|
|
36,033 |
|
|
|
0.44 |
|
| |
|
|
|
|
|
|
|
|
Income tax benefit (expense) of adjustments(2) |
|
8,816 |
|
|
|
0.11 |
|
|
|
(9,769 |
) |
|
|
(0.12 |
) |
|
Adjusted Net Income |
$ |
226,463 |
|
|
$ |
2.74 |
|
|
$ |
10,722 |
|
|
$ |
0.13 |
|
| |
|
|
|
|
|
|
|
|
Basic EPS on Adjusted Net Income |
$ |
2.88 |
|
|
|
|
$ |
0.13 |
|
|
|
|
Diluted EPS on Adjusted Net Income |
$ |
2.74 |
|
|
|
|
$ |
0.13 |
|
|
|
| |
|
|
|
|
|
|
|
|
Weighted average shares outstanding - basic |
|
78,517 |
|
|
|
|
|
80,209 |
|
|
|
|
Weighted average shares outstanding - diluted |
|
82,586 |
|
|
|
|
|
83,496 |
|
|
|
__________
|
(1) |
Non-recurring costs include legal and professional service expenses
related to acquisition and divestiture activity for the fourth
quarter of 2021 and the first quarter of 2022 and the executive
transition costs in the fourth quarter of 2022. |
| (2) |
The federal and state statutory
rate was utilized in both 2022 and 2021. We updated the disclosure
for 2021 to reflect the statutory rate, instead of the effective
tax rate previously utilized. |
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
31,2022 |
|
Quarter EndedSeptember
30,2022 |
|
Quarter EndedDecember
31,2021 |
|
Year EndedDecember 31,2022 |
|
Year EndedDecember 31,2021 |
| |
(unaudited)($ in thousands except per mboe amounts) |
|
Adjusted General and Administrative Expense reconciliation
to general and administrative expenses: |
|
|
|
|
|
General and administrative expenses |
$ |
26,926 |
|
|
$ |
23,388 |
|
|
$ |
22,357 |
|
|
$ |
96,439 |
|
|
$ |
73,106 |
|
|
Subtract: |
|
|
|
|
|
|
|
|
|
|
Non-cash stock compensation expense (G&A portion) |
|
(4,248 |
) |
|
|
(4,281 |
) |
|
|
(3,457 |
) |
|
|
(16,498 |
) |
|
|
(13,356 |
) |
|
Non-recurring costs(1) |
|
(3,268 |
) |
|
|
— |
|
|
|
(2,030 |
) |
|
|
(3,466 |
) |
|
|
(2,735 |
) |
|
Adjusted General and Administrative Expenses |
$ |
19,410 |
|
|
$ |
19,107 |
|
|
$ |
16,870 |
|
|
$ |
76,475 |
|
|
$ |
57,015 |
|
| |
|
|
|
|
|
|
|
|
|
|
Well servicing and abandonment segment |
$ |
3,296 |
|
|
$ |
3,324 |
|
|
$ |
3,193 |
|
|
$ |
12,975 |
|
|
$ |
3,193 |
|
| |
|
|
|
|
|
|
|
|
|
|
E&P segment, and corporate |
$ |
16,114 |
|
|
$ |
15,783 |
|
|
$ |
13,677 |
|
|
$ |
63,500 |
|
|
$ |
53,822 |
|
|
E&P segment, and corporate ($/boe) |
$ |
6.80 |
|
|
$ |
6.66 |
|
|
$ |
5.33 |
|
|
$ |
6.66 |
|
|
$ |
5.38 |
|
| |
|
|
|
|
|
|
|
|
|
|
Total mboe |
|
2,371 |
|
|
|
2,369 |
|
|
|
2,566 |
|
|
|
9,532 |
|
|
|
10,004 |
|
__________
|
(1) |
Non-recurring costs include legal and professional service expenses
related to acquisition and divestiture activity for the fourth
quarter of 2021 and the first quarter of 2022 and the executive
transition costs in the fourth quarter of 2022. |
RESERVES AND PV-10
The following table summarizes our estimated
proved reserves and related PV-10 as of December 31, 2022.
| |
Proved Reserves as of December 31,
2022(1) |
| |
California (San Joaquin
basin) |
|
Utah(Uinta basin) |
|
Total |
| |
(unaudited) |
|
Proved developed reserves: |
|
|
|
|
|
|
Oil (mmbbl) |
|
43 |
|
|
11 |
|
|
54 |
|
Natural Gas (bcf) |
|
— |
|
|
44 |
|
|
44 |
|
NGLs (mmbbl) |
|
— |
|
|
1 |
|
|
1 |
|
Total (mmboe)(2)(3) |
|
43 |
|
|
19 |
|
|
62 |
|
Proved undeveloped reserves: |
|
|
|
|
|
|
Oil (mmbbl) |
|
41 |
|
|
4 |
|
|
45 |
|
Natural Gas (bcf) |
|
— |
|
|
15 |
|
|
15 |
|
NGLs (mmbbl) |
|
— |
|
|
1 |
|
|
1 |
|
Total (mmboe)(3) |
|
41 |
|
|
7 |
|
|
48 |
|
Total proved reserves: |
|
|
|
|
|
|
Oil (mmbbl) |
|
84 |
|
|
15 |
|
|
99 |
|
Natural Gas (bcf) |
|
— |
|
|
59 |
|
|
59 |
|
NGLs (mmbbl) |
|
— |
|
|
2 |
|
|
2 |
|
Total (mmboe)(3) |
|
84 |
|
|
26 |
|
|
110 |
| |
|
|
|
|
|
|
PV-10 (in millions)(4) |
$ |
2,240 |
|
$ |
384 |
|
$ |
2,624 |
__________
|
(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 $100.25
per bbl Brent for oil and NGLs and $6.40 per mmbtu Henry Hub for
natural gas at December 31, 2022. The volume-weighted average
realized prices over the lives of the properties were $91.33 per
bbl of oil and condensate, $48.76 per bbl of NGLs and $6.76 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 14% of total and 14% 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, 2022,
the average prices of Brent oil and Henry Hub natural gas were
$99.04 per bbl and $6.45 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, 2022:
| |
At December 31, 2022 |
| |
(unaudited)(in millions) |
|
California PV-10 |
$ |
2,240 |
|
|
Utah PV-10 |
|
384 |
|
|
Total Company PV-10 |
|
2,624 |
|
|
Less: present value of future income taxes discounted at 10% |
|
(550 |
) |
|
Standardized measure of discounted future net cash flows |
$ |
2,074 |
|
The following table presents reserves changes
and production for 2022:
| |
Total Company |
|
California |
| |
(unaudited)(in mmboe) |
|
Extensions and discoveries |
25.5 |
|
|
19.6 |
|
|
Revisions of previous estimates |
(5.9 |
) |
|
(6.8 |
) |
|
Purchases of minerals(1) |
7.1 |
|
|
— |
|
|
Sales of minerals(2) |
(4.2 |
) |
|
— |
|
|
Total reserves changes |
22.5 |
|
|
12.8 |
|
| |
|
|
|
|
Production |
9.5 |
|
|
7.8 |
|
|
Reserve replacement ratio |
236 |
% |
|
164 |
% |
__________
| (1) |
Purchases of
minerals are primarily the Antelope Creek properties we acquired in
February 2022. |
| (2) |
Sales of minerals are related to all of our natural gas
properties in Colorado, which were divested in January 2022. |
Contact
Contact: Berry Corporation (bry)
Todd Crabtree - Manager, Investor Relations
(661) 616-3811
ir@bry.com
Berry (NASDAQ:BRY)
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Berry (NASDAQ:BRY)
過去 株価チャート
から 1 2024 まで 1 2025
