Berry Corporation (bry) (NASDAQ: BRY) (“Berry” or the “Company”)
announced fourth quarter and full-year 2023 results. For the fourth
quarter 2023, Berry’s net income was $63 million, or $0.81 per
diluted share, Adjusted Net Income(1) was $10 million, or $0.13 per
diluted share, and cash flows from operating activities were $79
million. For the full year 2023, Berry's net income was $37
million, or $0.48 per diluted share, Adjusted Net Income(1) was $39
million, or $0.51 per diluted share, and cash flows from operating
activities were $199 million.
Fourth Quarter 2023
Highlights
- Delivered Adjusted EBITDA(1) of $70
million and Adjusted Free Cash Flow(1) of $55 million
- Declared total fixed and variable
dividends of $0.26 per share, a 24% increase over third quarter
2023
- Acquired highly synergistic working
interest in Kern County, CA at year-end
- Produced 25,900
boe/d supported by development program and accretive
acquisitions
2023 Highlights
- Delivered $65 million of
shareholder returns, or 33% of cash flow from operating activities,
consisting of:
- $0.73 per share fixed and variable
dividends (inclusive of dividends to be paid in March 2024)
and
- 1.4 million shares
repurchased, or 2% of current shares outstanding
- Generated Adjusted EBITDA(1) of
$268 million
- Generated cash flows from operating
activities of $199 million and Adjusted Free Cash Flow(1) of $97
million
- Produced 25,400 boe/d, at the top
of updated guidance, on lower capital expenditures
- Completed 2023 with zero lost time
incidents
- Lower G&A compared to 2022, including 4% reduction in
Adjusted G&A(1)
- 2023 year-end reserves of 103
million boe with California reserve replacement ratio of 176%(1)
from field extensions and acquisitions, offsetting the impact of
production and lower pricing
__________(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.
“2023 was a solid year for Berry in light of a
lower energy price environment. We delivered top-tier dividends to
our shareholders, maintained production levels essentially flat
with lower capital expenditures than planned, and expanded our
production base and future cash flow with two financially accretive
bolt-on acquisitions,” said Fernando Araujo, Berry’s Chief
Executive Officer. “Our full-year average production of 25,400
boe/day was primarily driven by our innovative reservoir management
practices with additional contribution from our successful drilling
program, which was focused on sidetracks in 2023, our robust
workover campaign and the impact from the Macpherson acquisition at
the end of the third quarter.”
He continued, “For 2024, our strategy is
unchanged with a focus to deliver sustainable free cash flow. We
will seek to enhance value in our current asset base through cost
reductions and maintaining flat production with the mid-point of
our 2024 annual guidance. Note that our 2024 development program
and guidance does not depend on obtaining new drill permits, which
are currently constrained by ongoing litigation challenging Kern
County’s Environmental Impact Review (EIR) for CEQA compliance
purposes. We will continue to seek scale and growth through
bolt-ons or other opportunities in and outside of California, all
while being mindful of optimizing our capital structure.”
Fourth Quarter 2023 Results
Net income in the fourth quarter 2023 was $63
million compared with a loss of $45 million in the third quarter
largely driven by the positive impact of improved derivative
valuations and related income tax effects, partially offset by
lease operating expenses, which includes fuel gas costs for our
California steam operations, which increased 13% in the fourth
quarter mostly because of higher natural gas (fuel) costs and
higher utility costs. Adjusted net income was $10 million and $12
million in the fourth and third quarters of 2023, respectively.
Adjusted EBITDA was $70 million in both of the fourth and third
quarters of 2023. GHG prices increased consistently throughout
2023 beyond expectations. This had an unexpected effect on Adjusted
EBITDA and earnings per share.
The Company's average daily production in the
fourth quarter 2023 increased 2% to 25,900 boe/d, compared to third
quarter volumes. Company-wide oil production in the fourth quarter
2023 increased 3% sequentially and California production, which
consists solely of oil and comprises 83% of total company
production, increased 5% to 21,500 mboe/d in the fourth quarter.
These increases were largely driven by the impact from the
acquisition of Macpherson Energy Corporation (the “Macpherson
Acquisition”) at the end of the third quarter.
Company-wide realized oil price, including
hedging effects, was $72.65 per bbl for the fourth quarter 2023
compared to $73.13 per bbl in the third quarter 2023. Excluding
hedging effects, California's average realized oil prices were
$77.74 per bbl in the fourth quarter 2023, 94% of Brent, and $79.98
per bbl in the third quarter 2023, 93% of Brent.
Lease operating expenses, which includes fuel
gas costs for our California steam operations, increased 13% in the
fourth quarter 2023 from the third quarter 2023, mostly as a result
of higher natural gas (fuel) costs and higher utility costs.
Taxes, other than income taxes decreased 12% in
the fourth quarter 2023 compared to the third quarter 2023 mainly
due to lower severance expense and GHG allowance requirements,
partially offset by increased GHG prices quarter over quarter which
rose consistently throughout 2023 beyond expectations.
General and administrative expenses (“G&A”)
remained flat in the fourth quarter 2023 compared to the third
quarter 2023. Adjusted General and Administrative Expenses(1),
which excludes non-cash stock compensation costs and non-recurring
costs, increased 7% in the fourth quarter 2023 compared to the
third quarter 2023 due to higher costs related to year-end payroll
tax and benefit true-ups, and insurance cost increases.
The net income for the well servicing and
abandonment business, C&J Well Services, remained flat at $3
million in the fourth quarter 2023 compared to the third quarter
2023.
For the fourth quarter 2023, capital
expenditures were approximately $16 million, excluding
acquisitions, asset retirement obligation spending and $1 million
of well servicing and abandonment segment capital. This represented
a 36% increase in capital expenditures compared to the third
quarter 2023, mainly due to an increase in drilling, facilities,
and workover costs in the fourth quarter. Additionally, Berry spent
approximately $3 million for plugging and abandonment activities in
the fourth quarter 2023.
Full-Year 2023 Results
Net income was $37 million in 2023 compared
to $250 million in 2022. Adjusted EBITDA was $268 million
in 2023 compared to $380 million in 2022. The decreases were
primarily driven by lower oil prices and volumes, higher GHG costs
included in taxes, other than income taxes and higher lease
operating expenses excluding fuel, partially offset by lower fuel
costs driven by lower fuel consumption. Net income changes also
included the positive overall impact of improved derivative
valuation and income taxes of $18 million compared to a benefit of
$42 million in the prior year due to the utilization of net
operating losses and tax credits. Adjusted free cash flow declined
by $102 million on lower earnings.
The Company's average daily production for the
full year 2023 was 25,400 boe/d compared to 26,100 boe/d in 2022.
Company-wide oil production in 2023 was 23,500 bbl/d, accounting
for 93% of total Company production, with California production
contributing 20,700 boe/d or 81% of total production. Overall
production decreased 3% principally due to reduced drilling and
workover activity, along with natural base decline, partially
offset by production from the Macpherson Acquisition in September
2023.
Company-wide realized oil prices, including
hedging effects, were $71.67 per bbl in 2023 compared to $77.59 per
bbl in 2022. Excluding hedging effects, California average realized
oil prices were $76.89 per bbl in 2023 and $93.40 per bbl, in 2022,
each 94% of Brent.
Lease operating expenses, which includes fuel
costs for our California steam operations, increased 5% due to
higher outside services and lease maintenance costs, partially
offset by lower fuel costs. Fuel consumption decreased 12% compared
to 2022, which resulted in decreased fuel costs of 8%, net of a 4%
increase in average natural gas prices. Lease operating expenses
excluding fuel increased 12%, due to higher outside services and
lease maintenance costs, mostly weather related in the first
quarter 2023, as well as increased power costs driven by higher
rates.
Electricity generation expenses and sales
decreased 68% and 50%, respectively, in 2023 compared to 2022, due
to lower volumes sold resulting from operating one of our
cogeneration facilities for a portion of the year compared to
running it all of 2022 to maximize the margin efficiency of these
facilities. Fuel costs included in lease operating expenses and
electricity generation expenses exclude the effects of natural gas
derivative settlements.
Taxes, other than income taxes, increased 47% in
2023 compared to 2022, largely from increases in GHG expense due to
higher GHG emission prices in a volatile California carbon
allowance market, partially offset by lower GHG emissions. GHG
prices increased consistently throughout 2023 beyond expectations.
This had an unexpected effect on Adjusted EBITDA and earnings per
share.
General and administrative expenses decreased by
approximately $1 million to $96 million in 2023 compared to
2022 due to a decrease in professional services. Adjusted General
and Administrative Expenses, which excludes non-cash stock
compensation costs and non-recurring costs, decreased by 4%,
primarily due to cost saving initiatives implemented in early
2023.
The net income for the well servicing and
abandonment business, C&J Well Services, was $13 million for
2023, compared to $15 million for 2022, primarily due to a decline
in California drilling activity.
For 2023, capital expenditures were
approximately $67 million, excluding acquisitions, asset retirement
obligation spending and $6 million of well servicing and
abandonment capital, a 54% decrease compared to the prior year. The
reduction in development activity was generally made in connection
with the Macpherson Acquisition in September 2023. The capital
budget was adjusted to reflect the reduced need for drilling
activities on the legacy Berry assets due to the addition of
producing assets, allowing Berry to meet production targets while
reducing drilling, workover and other activities on the legacy
Berry assets. In connection with the closing of the Macpherson
Acquisition in September 2023, a total of $35 million was
reallocated from the 2023 capital expenditures budget to fund a
portion of the purchase price. Additionally, the Company spent
approximately $18 million for plugging and abandonment
activities in 2023.
At December 31, 2023, the Company had liquidity
of $171 million, consisting of $5 million cash and
$166 million available for borrowings under the Company’s
revolving credit facilities.
Proved reserves were 103 mmboe at December 31,
2023, of which 87% are located in California, which is also where
approximately 97% of the PV-10(1) value is located. In 2023, Berry
replaced 176% of its California production and 19% of its total
Company production, with additional proved reserves, from field
extensions and acquisitions, offsetting the impact of production
and lower pricing.
“We delivered solid financial and operational
results in a period of declining energy prices and generated 2023
operating cash flows of $199 million, as well as $97 million of
Adjusted Free Cash Flow, more than half of which, $55 million, was
attributable to the fourth quarter,” said Mike Helm, Berry’s Chief
Financial Officer. “For 2023, we returned $65 million to
shareholders, including $55 million in the form of fixed and
variable dividends. These cash returns resulted in a top-tier
sector total dividend yield of approximately 10% for our
shareholders. We also completed $10 million in stock repurchases,
or about 2% of outstanding shares. Highlighting our prudent cash
management, before the end of the fourth quarter, we paid down the
RBL balance that was drawn in the third quarter in connection with
the closing of the Macpherson Acquisition. We then utilized about
$30 million of our RBL at year end to fund our second bolt-on
acquisition.”
__________(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 2024, the Company’s Board of
Directors approved a fixed cash dividend of $0.12 per share, as
well as a variable cash dividend of $0.14 per share, based on the
results of the fourth quarter 2023. Both dividends are payable on
March 25, 2024, to shareholders of record at the close of business
on March 15, 2024. Cash dividends based on 2023 results totaled
$0.73 per share, as noted in the table below.
2023 Dividends
| |
First Quarter |
|
Second Quarter |
|
Third Quarter |
|
Fourth Quarter |
|
Year-to-Date |
|
Fixed Dividends |
$ |
0.12 |
|
|
$ |
0.12 |
|
|
$ |
0.12 |
|
|
$ |
0.12 |
|
|
$ |
0.48 |
|
| Variable Dividends(1) |
|
— |
|
|
|
0.02 |
|
|
|
0.09 |
|
|
|
0.14 |
|
|
|
0.25 |
|
| Total |
$ |
0.12 |
|
|
$ |
0.14 |
|
|
$ |
0.21 |
|
|
$ |
0.26 |
|
|
$ |
0.73 |
|
_______(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. In
February 2024, the Board of Directors approved a $0.14 per share
variable dividend based on the results for the three months ended
December 31, 2023.
Full-Year 2024 Guidance
Berry’s 2024 capital program reflects
management’s prior experience with the constraints imposed by the
current permitting litigation impacting Kern County, with an
underlying commitment to maximize Adjusted Free Cash Flow and
shareholder value. Our current plan is based on 2024 production
that is essentially flat to 2023. Berry’s current capital program
for 2024 focuses on sidetracks, workovers and other activities
related to existing wellbores. The Company expects to benefit from
a full year of production from the assets acquired in the
Macpherson Acquisition and another bolt-on acquisition completed at
the end of 2023, which should help keep our production essentially
flat in 2024. As a result of the ongoing regulatory uncertainty in
California impacting the permitting process in Kern County where
all of our California assets are located, the capital program has
been prepared based on the assumption that we will not receive
additional new drill permits in California in 2024, but that we
will continue to timely receive the other permits and approvals
needed for planned activities, in addition to the permits we
already have in hand. However, should there be favorable changes to
the permitting process we are well prepared to take advantage of
the opportunities.
In 2024, the Company expects to continue to
focus on debt and leverage, including looking at opportunistically
refinancing the senior notes due February 2026, if market
conditions allow. The Company also expects to reduce general and
administrative expenses, as well as operating costs, primarily
energy costs which is reflected in the 2024 guidance.
The Company has oil hedges for more than 80% of
its expected 2024 oil production, while approximately 70% of the
expected production is hedged with swaps with an average strike
price of $77.97 per barrel Brent. The Company has gas purchase
hedges for approximately three quarters of its expected 2024 gas
demand, approximately 96% of this position is swaps with an average
strike of $3.99 per mmbtu.
|
Full-Year 2024 Guidance |
Low |
|
High |
|
Average Daily Production (boe/d)(1) |
24,600 |
|
25,800 |
|
Expenses from field operations ($/boe)(2) |
$26.50 |
|
$29.50 |
|
E&P non-production revenues ($/boe)(3) |
$1.80 |
|
$2.00 |
|
Natural gas purchase hedge settlements ($/boe)(4)(5) |
$0.60 |
|
$0.90 |
|
Taxes, Other than Income Taxes ($/boe) |
$6.50 |
|
$7.50 |
|
Adjusted General & Administrative (G&A) expenses
($/boe)(6)(7) |
|
|
|
|
E&P Segment & Corp |
$5.85 |
|
$6.25 |
|
Well Servicing and Abandonment Segment |
$1.30 |
|
$1.50 |
|
Capital Expenditures ($ millions)(8) |
$95 |
|
$110 |
|
Well Servicing & Abandonment Segment Adjusted EBITDA ($
millions) |
$16 |
|
$24 |
__________(1) Oil production is expected
to be approximately 93% 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 December 31, 2023,
and the Henry Hub gas price of $3.00 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”.(8) Total
company capital expenditures, including E&P segment, well
servicing & abandonment segment and corporate.
Earnings Conference Call
The Company will host a conference call to
discuss these results:
Call Date: Wednesday, March 6, 2024Call
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/7kymzcmg or at
https://bry.com/category/events. Accompanying slides will also be
available at the time of the call at www.bry.com.
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/BI4cf49100fcd44636a09625e75442bc53
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
athttps://ir.bry.com/reports-resources or visit
https://edge.media-server.com/mmc/p/7kymzcmg
orhttps://bry.com/category/events
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 oil and gas reserves. We
operate in two business segments: (i) exploration and production
(“E&P”) and (ii) well servicing and abandonment. Our E&P
assets are located in California and Utah, are characterized by
high oil content and are predominantly located in rural areas with
low population. Our California assets are in the San Joaquin basin
(100% oil), while our Utah assets are in the Uinta basin (60% oil
and 40% gas). We operate our well servicing and abandonment segment
in California. More information can be found at the Company’s
website at www.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); financial and operating, results; capital program and
development and production plans; operations and business strategy;
potential acquisition and other strategic opportunities; reserves;
hedging activities; capital expenditures; return of capital; our
shareholder return model and the payment of future dividends;
future repurchases of stock or debt; future reduction or
refinancing of existing debt; capital investments, recovery
factors; projected accretion to financial and production results;
projected synergies related to the Macpherson Acquisition;
anticipated increases to free cash flow and shareholder returns;
our capital expenditures and leverage profile; 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 financial position, financial and operating
results, liquidity, cash flows (including, but not limited to,
Adjusted Free Cash Flow) and business prospects.
Berry cautions you that these forward-looking
statements are subject to all of the risks and uncertainties
incident to acquisition transactions and 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 with respect to existing
and/or new requirements in 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 or strategic transactions;
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; epidemics
or pandemics, including the effects of related public health
concerns and the impact of actions that may be taken by
governmental authorities and other third parties in response to a
pandemic; the ability to effectively deploy our ESG strategy and
risks associated with initiating new projects or business in
connection therewith; our ability to successfully integrate the
Macpherson assets into our operations; we fail to identify risks or
liabilities related to Macpherson, its operations or assets; our
inability to achieve anticipated synergies; our ability to
successfully execute other strategic bolt-on acquisitions; overall
domestic and global political and economic conditions; the
imposition of tariffs or trade or other economic sanctions,
political instability or armed conflict in oil and gas producing
regions, including the ongoing conflict in Ukraine, the
Israel-Hamas conflict, or a prolonged recession; inflation levels
and government efforts to reduce inflation, including increased
interest rates and volatility in financial markets and banking;
changes in tax laws; information technology failures or
cyberattacks 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, 2023 and subsequent filings with the
SEC.
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
31,2023 |
|
Quarter EndedSeptember
30,2023 |
|
Quarter EndedDecember
31,2022 |
|
Year EndedDecember 31,2023 |
|
Year EndedDecember 31,2022 |
| |
(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 |
$ |
172,439 |
|
|
$ |
172,611 |
|
|
$ |
188,442 |
|
|
$ |
669,110 |
|
|
$ |
842,449 |
|
|
Service revenue |
|
40,746 |
|
|
|
45,511 |
|
|
|
46,792 |
|
|
|
178,554 |
|
|
|
181,400 |
|
|
Electricity sales |
|
2,905 |
|
|
|
3,849 |
|
|
|
8,284 |
|
|
|
15,277 |
|
|
|
30,833 |
|
|
Gains (losses) on oil and gas sales derivatives |
|
83,918 |
|
|
|
(103,282 |
) |
|
|
(48,872 |
) |
|
|
40,006 |
|
|
|
(137,109 |
) |
|
Marketing revenues |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
289 |
|
|
Other revenues |
|
319 |
|
|
|
113 |
|
|
|
37 |
|
|
|
513 |
|
|
|
479 |
|
|
Total revenues and other |
|
300,327 |
|
|
|
118,802 |
|
|
|
194,683 |
|
|
|
903,460 |
|
|
|
918,341 |
|
| |
|
|
|
|
|
|
|
|
|
| Expenses and
other: |
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
67,342 |
|
|
|
59,842 |
|
|
|
87,601 |
|
|
|
316,726 |
|
|
|
302,321 |
|
|
Cost of services |
|
32,783 |
|
|
|
35,806 |
|
|
|
35,010 |
|
|
|
141,771 |
|
|
|
142,819 |
|
|
Electricity generation expenses |
|
1,827 |
|
|
|
1,479 |
|
|
|
5,199 |
|
|
|
7,079 |
|
|
|
21,839 |
|
|
Transportation expenses |
|
1,260 |
|
|
|
1,089 |
|
|
|
1,021 |
|
|
|
4,486 |
|
|
|
4,564 |
|
|
Marketing expenses |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
299 |
|
|
Acquisition costs |
|
284 |
|
|
|
2,082 |
|
|
|
— |
|
|
|
3,338 |
|
|
|
— |
|
|
General and administrative expenses |
|
20,729 |
|
|
|
20,987 |
|
|
|
26,926 |
|
|
|
95,873 |
|
|
|
96,439 |
|
|
Depreciation, depletion and amortization |
|
40,937 |
|
|
|
39,729 |
|
|
|
39,509 |
|
|
|
160,542 |
|
|
|
156,847 |
|
|
Taxes, other than income taxes |
|
15,826 |
|
|
|
17,980 |
|
|
|
14,341 |
|
|
|
57,973 |
|
|
|
39,495 |
|
|
Losses (gains) on natural gas purchase derivatives |
|
21,397 |
|
|
|
(8,425 |
) |
|
|
(41,460 |
) |
|
|
26,386 |
|
|
|
(88,795 |
) |
|
Other operating expenses (income) |
|
36 |
|
|
|
(505 |
) |
|
|
(1,023 |
) |
|
|
(1,788 |
) |
|
|
3,722 |
|
|
Total expenses and other |
|
202,421 |
|
|
|
170,064 |
|
|
|
167,124 |
|
|
|
812,386 |
|
|
|
679,550 |
|
| |
|
|
|
|
|
|
|
|
|
| Other (expenses)
income: |
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
(9,680 |
) |
|
|
(9,101 |
) |
|
|
(7,646 |
) |
|
|
(35,412 |
) |
|
|
(30,917 |
) |
|
Other, net |
|
(10 |
) |
|
|
(42 |
) |
|
|
(63 |
) |
|
|
(237 |
) |
|
|
(142 |
) |
|
Total other expenses |
|
(9,690 |
) |
|
|
(9,143 |
) |
|
|
(7,709 |
) |
|
|
(35,649 |
) |
|
|
(31,059 |
) |
| |
|
|
|
|
|
|
|
|
|
| Income (loss) before
income taxes |
|
88,216 |
|
|
|
(60,405 |
) |
|
|
19,850 |
|
|
|
55,425 |
|
|
|
207,732 |
|
| Income tax expense
(benefit) |
|
25,665 |
|
|
|
(15,343 |
) |
|
|
(52,114 |
) |
|
|
18,025 |
|
|
|
(42,436 |
) |
| Net income
(loss) |
$ |
62,551 |
|
|
$ |
(45,062 |
) |
|
$ |
71,964 |
|
|
$ |
37,400 |
|
|
$ |
250,168 |
|
| |
|
|
|
|
|
|
|
|
|
| Net income (loss) per
share: |
|
|
|
|
|
|
|
|
|
| Basic |
$ |
0.83 |
|
|
$ |
(0.60 |
) |
|
$ |
0.94 |
|
|
$ |
0.49 |
|
|
$ |
3.19 |
|
| Diluted |
$ |
0.81 |
|
|
$ |
(0.60 |
) |
|
$ |
0.90 |
|
|
$ |
0.48 |
|
|
$ |
3.03 |
|
| |
|
|
|
|
|
|
|
|
|
| Weighted-average common shares
outstanding - basic |
|
75,667 |
|
|
|
75,662 |
|
|
|
76,181 |
|
|
|
76,038 |
|
|
|
78,517 |
|
| Weighted-average common shares
outstanding - diluted |
|
77,349 |
|
|
|
75,662 |
|
|
|
80,312 |
|
|
|
77,583 |
|
|
|
82,586 |
|
| |
|
|
|
|
|
|
|
|
|
| Adjusted Net Income(1) |
$ |
10,426 |
|
|
$ |
11,831 |
|
|
$ |
76,449 |
|
|
$ |
39,230 |
|
|
$ |
226,463 |
|
| Weighted-average common shares
outstanding - diluted |
|
77,349 |
|
|
|
77,606 |
|
|
|
80,312 |
|
|
|
77,583 |
|
|
|
82,586 |
|
| Diluted earnings per share on
Adjusted Net Income(1) |
$ |
0.13 |
|
|
$ |
0.15 |
|
|
$ |
0.95 |
|
|
$ |
0.51 |
|
|
$ |
2.74 |
|
| |
|
|
|
|
|
|
|
|
|
| Adjusted EBITDA(1) |
$ |
70,036 |
|
|
$ |
69,829 |
|
|
$ |
77,508 |
|
|
$ |
268,257 |
|
|
$ |
379,948 |
|
| Adjusted Free Cash
Flow(1) |
$ |
54,824 |
|
|
$ |
35,407 |
|
|
$ |
55,803 |
|
|
$ |
97,324 |
|
|
$ |
199,766 |
|
| Adjusted General and
Administrative Expenses(1) |
$ |
17,886 |
|
|
$ |
16,763 |
|
|
$ |
19,410 |
|
|
$ |
73,495 |
|
|
$ |
76,475 |
|
| Effective Tax Rate |
|
29 |
% |
|
|
25 |
% |
|
(263 |
)% |
|
|
33 |
% |
|
(20 |
)% |
| |
|
|
|
|
|
|
|
|
|
| Cash Flow
Data: |
|
|
|
|
|
|
|
|
|
| Net cash provided by operating
activities |
$ |
79,018 |
|
|
$ |
55,320 |
|
|
$ |
105,407 |
|
|
$ |
198,657 |
|
|
$ |
360,941 |
|
| Net cash used in investing
activities |
$ |
(48,822 |
) |
|
$ |
(68,029 |
) |
|
$ |
(54,888 |
) |
|
$ |
(175,272 |
) |
|
$ |
(164,552 |
) |
| Net cash (used in) provided by
financing activities |
$ |
(42,561 |
) |
|
$ |
21,343 |
|
|
$ |
(45,742 |
) |
|
$ |
(64,800 |
) |
|
$ |
(165,422 |
) |
__________(1) See further discussion and reconciliation in
“Non-GAAP Financial Measures and Reconciliations”.
| |
December 31, 2023 |
|
December 31, 2022 |
| |
(unaudited)($ and shares in thousands) |
| Balance Sheet
Data: |
|
|
|
|
Total current assets |
$ |
140,800 |
|
|
$ |
218,055 |
|
| Total property, plant and
equipment, net |
$ |
1,406,612 |
|
|
$ |
1,359,813 |
|
| Total current liabilities |
$ |
223,182 |
|
|
$ |
234,207 |
|
| Long-term debt |
$ |
427,993 |
|
|
$ |
395,735 |
|
| Total stockholders’
equity |
$ |
757,976 |
|
|
$ |
800,485 |
|
| Outstanding common stock
shares as of |
|
75,667 |
|
|
|
75,768 |
|
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.
| |
Year Ended December 31, 2023 |
| |
E&P |
|
Well Servicing andAbandonment |
|
Corporate/Eliminations |
|
ConsolidatedCompany |
| |
(unaudited)(in thousands) |
|
Revenues(1) |
$ |
684,900 |
|
|
$ |
185,767 |
|
|
$ |
(7,213 |
) |
|
$ |
863,454 |
|
| Net income (loss) before
income taxes |
$ |
163,819 |
|
|
$ |
13,462 |
|
|
$ |
(121,856 |
) |
|
$ |
55,425 |
|
| Capital expenditures |
$ |
64,844 |
|
|
$ |
5,805 |
|
|
$ |
2,478 |
|
|
$ |
73,127 |
|
| Total assets |
$ |
1,652,979 |
|
|
$ |
68,670 |
|
|
$ |
(127,491 |
) |
|
$ |
1,594,158 |
|
| |
Year Ended December 31, 2022 |
| |
E&P |
|
Well Servicing andAbandonment |
|
Corporate/Eliminations |
|
ConsolidatedCompany |
| |
(unaudited)(in thousands) |
|
Revenues(1) |
$ |
874,190 |
|
|
$ |
184,448 |
|
|
$ |
(3,188 |
) |
|
$ |
1,055,450 |
|
| Net income (loss) before
income taxes |
$ |
303,178 |
|
|
$ |
14,747 |
|
|
$ |
(110,193 |
) |
|
$ |
207,732 |
|
| Capital expenditures |
$ |
141,930 |
|
|
$ |
8,455 |
|
|
$ |
2,536 |
|
|
$ |
152,921 |
|
| Total assets |
$ |
1,563,251 |
|
|
$ |
83,461 |
|
|
$ |
(15,682 |
) |
|
$ |
1,631,030 |
|
__________(1) These revenues do not
include hedge settlements.
COMMODITY PRICING
| |
Quarter EndedDecember
31,2023 |
|
Quarter EndedSeptember
30,2023 |
|
Quarter EndedDecember
31,2022 |
|
Year EndedDecember 31,2023 |
|
Year EndedDecember 31,2022 |
| Weighted Average
Realized Sales Prices |
|
|
|
|
|
|
|
|
|
|
Oil without hedges ($/bbl) |
$ |
76.00 |
|
|
$ |
78.89 |
|
|
$ |
80.61 |
|
|
$ |
75.05 |
|
|
$ |
91.98 |
|
| Effects of scheduled
derivative settlements ($/bbl) |
$ |
(3.35 |
) |
|
$ |
(5.76 |
) |
|
$ |
(7.22 |
) |
|
$ |
(3.38 |
) |
|
$ |
(14.39 |
) |
| Oil with hedges ($/bbl) |
$ |
72.65 |
|
|
$ |
73.13 |
|
|
$ |
73.39 |
|
|
$ |
71.67 |
|
|
$ |
77.59 |
|
| Natural gas ($/mcf) |
$ |
4.48 |
|
|
$ |
3.57 |
|
|
$ |
12.02 |
|
|
$ |
6.94 |
|
|
$ |
7.96 |
|
| NGLs ($/bbl) |
$ |
24.01 |
|
|
$ |
22.54 |
|
|
$ |
29.67 |
|
|
$ |
24.47 |
|
|
$ |
43.85 |
|
| |
|
|
|
|
|
|
|
|
|
| Purchased Natural
Gas |
|
|
|
|
|
|
|
|
|
| Purchase price, before the
effects of derivative settlements ($/mmbtu) |
$ |
5.29 |
|
|
$ |
4.18 |
|
|
$ |
9.62 |
|
|
$ |
8.21 |
|
|
$ |
7.86 |
|
| Effects of derivative
settlements ($/mmbtu) |
$ |
0.44 |
|
|
$ |
1.43 |
|
|
$ |
(2.28 |
) |
|
$ |
(1.79 |
) |
|
$ |
(1.74 |
) |
| Purchase price, after the
effects of derivative settlements($/mmbtu) |
$ |
5.73 |
|
|
$ |
5.61 |
|
|
$ |
7.34 |
|
|
$ |
6.42 |
|
|
$ |
6.12 |
|
| |
|
|
|
|
|
|
|
|
|
| Index
Prices |
|
|
|
|
|
|
|
|
|
| Oil – Brent (bbl) |
$ |
82.85 |
|
|
$ |
85.92 |
|
|
$ |
88.63 |
|
|
$ |
82.18 |
|
|
$ |
99.04 |
|
| Oil – WTI (bbl) |
$ |
78.49 |
|
|
$ |
81.99 |
|
|
$ |
82.51 |
|
|
$ |
77.61 |
|
|
$ |
94.39 |
|
| Natural gas (mmbtu) – SoCal
Gas city-gate (1) |
$ |
6.25 |
|
|
$ |
7.10 |
|
|
$ |
9.71 |
|
|
$ |
10.96 |
|
|
$ |
8.38 |
|
| Natural gas (mmbtu) –
Northwest, Rocky Mountains(2) |
$ |
4.53 |
|
|
$ |
3.40 |
|
|
$ |
7.54 |
|
|
$ |
8.28 |
|
|
$ |
6.95 |
|
| Natural gas (mmbtu) – Henry
Hub(2) |
$ |
2.74 |
|
|
$ |
2.59 |
|
|
$ |
5.55 |
|
|
$ |
2.53 |
|
|
$ |
6.45 |
|
__________(1) The natural gas we purchase to generate
steam and electricity is primarily based on Rockies price indexes,
including transportation charges, as we currently purchase a
substantial majority of our gas needs from the Rockies, with the
balance purchased in California. SoCal Gas city-gate Index is the
relevant index used only for the portion of gas purchases in
California. Beginning in the first quarter of 2023, we are
purchasing a majority of our fuel gas in the Rockies, most of the
purchases made in California utilize the SoCal Gas city-gate index,
whereas prior to this shift the predominant index for California
purchases were Kern, Delivered.(2) Most of our gas
purchases and gas sales in the Rockies are predicated on the
Northwest, Rocky Mountains index, and to a lesser extent based on
Henry Hub.
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. We buy approximately 48,000 mmbtu/d in the
Rockies, and the remainder comes from California markets. The
volume purchased in California fluctuates and averaged 5,000
mbbtu/d in 2023, and 12,000 mmbtu/d in 2022.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 our 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. The Kern capacity allows us to purchase and sell natural
gas at the same pricing indices.
CURRENT HEDGING
SUMMARY
As of February 29, 2024, we had the following crude oil
production and gas purchases hedges:
| |
Q1 2024 |
|
Q2 2024 |
|
Q3 2024 |
|
Q4 2024 |
|
FY 2025 |
|
FY 2026 |
| Brent - Crude Oil
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (bbls) |
|
1,536,118 |
|
|
|
1,611,294 |
|
|
|
1,481,749 |
|
|
|
1,438,656 |
|
|
|
2,669,125 |
|
|
|
1,881,768 |
|
|
Weighted-average price ($/bbl) |
$ |
78.95 |
|
|
$ |
78.97 |
|
|
$ |
76.87 |
|
|
$ |
76.94 |
|
|
$ |
75.22 |
|
|
$ |
70.84 |
|
|
Sold Calls(1) |
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (bbls) |
|
122,000 |
|
|
|
91,000 |
|
|
|
92,000 |
|
|
|
92,000 |
|
|
|
2,486,127 |
|
|
|
1,251,500 |
|
|
Weighted-average price ($/bbl) |
$ |
105.00 |
|
|
$ |
105.00 |
|
|
$ |
105.00 |
|
|
$ |
105.00 |
|
|
$ |
91.11 |
|
|
$ |
85.53 |
|
|
Purchased Puts (net)(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (bbls) |
|
318,500 |
|
|
|
318,500 |
|
|
|
322,000 |
|
|
|
322,000 |
|
|
|
2,486,127 |
|
|
|
1,251,500 |
|
|
Weighted-average price ($/bbl) |
$ |
50.00 |
|
|
$ |
50.00 |
|
|
$ |
50.00 |
|
|
$ |
50.00 |
|
|
$ |
58.53 |
|
|
$ |
60.00 |
|
|
Sold Puts (net)(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (bbls) |
|
45,500 |
|
|
|
45,500 |
|
|
|
46,000 |
|
|
|
46,000 |
|
|
|
— |
|
|
|
— |
|
|
Weighted-average price ($/bbl) |
$ |
40.00 |
|
|
$ |
40.00 |
|
|
$ |
40.00 |
|
|
$ |
40.00 |
|
|
$ |
— |
|
|
$ |
— |
|
| NWPL - Natural Gas
Purchases(3) |
|
|
|
|
|
|
|
|
|
|
|
|
Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (mmbtu) |
|
3,040,000 |
|
|
|
3,640,000 |
|
|
|
3,680,000 |
|
|
|
3,680,000 |
|
|
|
6,080,000 |
|
|
|
— |
|
|
Weighted-average price ($/mmbtu) |
$ |
4.11 |
|
|
$ |
3.96 |
|
|
$ |
3.96 |
|
|
$ |
3.96 |
|
|
$ |
4.27 |
|
|
$ |
— |
|
| HH - Natural Gas
Purchases(3) |
|
|
|
|
|
|
|
|
|
|
|
|
Purchased Calls |
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (mmbtu) |
|
600,000 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Weighted-average price ($/mmbtu) |
$ |
3.38 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
| Gas Basis
Differentials |
|
|
|
|
|
|
|
|
|
|
|
|
NWPL/HH - Natural Gas
Purchases(3) |
|
|
|
|
|
|
|
|
|
|
|
|
Hedged volume (mmbtu) |
|
600,000 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Weighted-average price ($/mmbtu) |
$ |
4.10 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
__________(1) Purchased calls and sold
calls with the same strike price have been presented on a net
basis.(2) Purchased puts and sold puts have been presented on
a net basis.(3) The term “NWPL” is defined as Northwest
Rocky Mountain Pipeline. The term “HH” is defined as Henry Hub.
GAINS (LOSSES) ON
DERIVATIVES
A summary of gains and losses on the derivatives
included on the statements of operations is presented below:
| |
Quarter EndedDecember
31,2023 |
|
Quarter EndedSeptember
30,2023 |
|
Quarter EndedDecember
31,2022 |
|
Year EndedDecember 31,2023 |
|
Year EndedDecember 31,2022 |
| |
(unaudited)(in thousands) |
| Realized gains
(losses) on commodity derivatives: |
|
|
|
|
|
|
|
|
|
|
Realized (losses) on oil and gas sales derivatives |
$ |
(7,405 |
) |
|
$ |
(12,304 |
) |
|
$ |
(16,031 |
) |
|
$ |
(28,917 |
) |
|
$ |
(126,176 |
) |
|
Realized (losses) gains on natural gas purchase derivatives |
|
(2,211 |
) |
|
|
(7,128 |
) |
|
|
12,527 |
|
|
|
34,812 |
|
|
|
38,153 |
|
|
Total realized (losses) gains on derivatives |
$ |
(9,616 |
) |
|
$ |
(19,432 |
) |
|
$ |
(3,504 |
) |
|
$ |
5,895 |
|
|
$ |
(88,023 |
) |
| |
|
|
|
|
|
|
|
|
|
| Unrealized gains
(losses) on commodity derivatives: |
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses) on oil and gas sales derivatives |
$ |
91,323 |
|
|
$ |
(90,978 |
) |
|
$ |
(32,841 |
) |
|
$ |
68,923 |
|
|
$ |
(10,933 |
) |
|
Unrealized (losses) gains on natural gas purchase derivatives |
|
(19,186 |
) |
|
|
15,553 |
|
|
|
28,933 |
|
|
|
(61,198 |
) |
|
|
50,642 |
|
|
Total unrealized gains (losses) on derivatives |
$ |
72,137 |
|
|
$ |
(75,425 |
) |
|
$ |
(3,908 |
) |
|
$ |
7,725 |
|
|
$ |
39,709 |
|
|
Total gains (losses) on derivatives |
$ |
62,521 |
|
|
$ |
(94,857 |
) |
|
$ |
(7,412 |
) |
|
$ |
13,620 |
|
|
$ |
(48,314 |
) |
E&P FIELD OPERATIONS
| |
Quarter EndedDecember
31,2023 |
|
Quarter EndedSeptember
30,2023 |
|
Quarter EndedDecember
31,2022 |
|
Year EndedDecember 31,2023 |
|
Year EndedDecember 31,2022 |
| |
(unaudited)($ in per boe amounts) |
| Expenses from field
operations |
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
$ |
28.25 |
|
|
$ |
25.73 |
|
|
$ |
36.95 |
|
|
$ |
34.21 |
|
|
$ |
31.72 |
|
|
Electricity generation expenses |
|
0.77 |
|
|
|
0.64 |
|
|
|
2.19 |
|
|
|
0.76 |
|
|
|
2.29 |
|
|
Transportation expenses |
|
0.53 |
|
|
|
0.47 |
|
|
|
0.43 |
|
|
|
0.48 |
|
|
|
0.48 |
|
|
Marketing expenses |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
0.03 |
|
|
Total |
$ |
29.55 |
|
|
$ |
26.84 |
|
|
$ |
39.57 |
|
|
$ |
35.45 |
|
|
$ |
34.52 |
|
| |
|
|
|
|
|
|
|
|
|
| Cash settlements
received for gas purchase hedges |
$ |
0.93 |
|
|
$ |
3.06 |
|
|
$ |
(5.28 |
) |
|
$ |
(3.76 |
) |
|
$ |
(4.00 |
) |
| |
|
|
|
|
|
|
|
|
|
| E&P non-production
revenues |
|
|
|
|
|
|
|
|
|
|
Electricity sales |
$ |
1.22 |
|
|
$ |
1.65 |
|
|
$ |
3.49 |
|
|
$ |
1.65 |
|
|
$ |
3.24 |
|
|
Transportation sales |
|
0.13 |
|
|
|
0.05 |
|
|
|
0.02 |
|
|
|
0.06 |
|
|
|
0.05 |
|
|
Marketing revenue |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
0.03 |
|
|
Total |
$ |
1.35 |
|
|
$ |
1.70 |
|
|
$ |
3.51 |
|
|
$ |
1.71 |
|
|
$ |
3.32 |
|
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 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
31,2023 |
|
Quarter EndedSeptember
30,2023 |
|
Quarter EndedDecember
31,2022 |
|
Year EndedDecember
31,2023 |
|
Year EndedDecember
31,2022 |
|
Net Oil, Natural Gas and NGLs Production Per
Day(1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Oil
(mbbl/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California |
21.5 |
|
|
20.5 |
|
|
21.1 |
|
|
20.7 |
|
|
21.3 |
|
|
Utah |
2.5 |
|
|
2.7 |
|
|
3.0 |
|
|
2.8 |
|
|
2.7 |
|
|
Total oil |
24.0 |
|
|
23.2 |
|
|
24.1 |
|
|
23.5 |
|
|
24.0 |
|
| Natural gas
(mmcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
Utah |
7.8 |
|
|
9.5 |
|
|
7.8 |
|
|
8.8 |
|
|
9.6 |
|
|
Colorado(2) |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
0.6 |
|
|
Total natural gas |
7.8 |
|
|
9.5 |
|
|
7.8 |
|
|
8.8 |
|
|
10.2 |
|
| NGLs
(mbbl/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
Utah |
0.6 |
|
|
0.5 |
|
|
0.4 |
|
|
0.4 |
|
|
0.4 |
|
|
Total NGLs |
0.6 |
|
|
0.5 |
|
|
0.4 |
|
|
0.4 |
|
|
0.4 |
|
| Total Production
(mboe/d)(3) |
25.9 |
|
|
25.3 |
|
|
25.8 |
|
|
25.4 |
|
|
26.1 |
|
__________(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) In January 2022, we
divested all of our natural gas properties in Colorado.(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, 2023, the average prices of Brent oil
and Henry Hub natural gas were $82.18 per bbl and $2.53 per mmbtu
respectively.
CAPITAL EXPENDITURES
| |
Quarter EndedDecember
31,2023 |
|
Quarter EndedSeptember
30,2023 |
|
Quarter EndedDecember
31,2022 |
|
Year EndedDecember 31,2023 |
|
Year EndedDecember 31,2022 |
| |
(unaudited)(in thousands) |
|
Capital expenditures(1)(2) |
$ |
17,003 |
|
|
$ |
13,596 |
|
|
$ |
50,398 |
|
|
$ |
73,127 |
|
|
$ |
152,921 |
|
__________(1) Capital expenditures include capitalized
overhead and interest and excludes acquisitions and asset
retirement spending.(2) Capital expenditures in the quarters
ended December 31, 2023, September 30, 2023 and December 31, 2022
included $1 million, $2 million and $5 million, respectively, for
the well servicing and abandonment business. Capital expenditures
in the years ended December 31, 2023 and December 31, 2022 included
approximately $6 million and $8 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 expenditure 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
substantially the same volume of annual oil and gas production and
is defined as capital expenditures, excluding, when applicable, (i)
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, (ii) capital expenditures in our well servicing and
abandonment segment, (iii) corporate expenditures that are related
to ancillary sustainability initiatives and/or (iv) 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 plan for future growth.
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,
strategic acquisitions or other growth opportunities, 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 reconciliations of
the GAAP financial measures of net income (loss) and net cash
provided (used) by operating activities to the non-GAAP financial
measure of Adjusted EBITDA, as applicable, for each of the periods
indicated.
| |
Quarter EndedDecember
31,2023 |
|
Quarter EndedSeptember
30,2023 |
|
Quarter EndedDecember
31,2022 |
|
Year EndedDecember 31,2023 |
|
Year EndedDecember 31,2022 |
| |
(unaudited)(in thousands) |
| Adjusted
EBITDA reconciliation: |
|
|
|
|
|
Net income (loss) |
$ |
62,551 |
|
|
$ |
(45,062 |
) |
|
$ |
71,964 |
|
|
$ |
37,400 |
|
|
$ |
250,168 |
|
| Add (Subtract): |
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
9,680 |
|
|
|
9,101 |
|
|
|
7,646 |
|
|
|
35,412 |
|
|
|
30,917 |
|
|
Income tax expense (benefit) |
|
25,665 |
|
|
|
(15,343 |
) |
|
|
(52,114 |
) |
|
|
18,025 |
|
|
|
(42,436 |
) |
|
Depreciation, depletion, and amortization |
|
40,937 |
|
|
|
39,729 |
|
|
|
39,509 |
|
|
|
160,542 |
|
|
|
156,847 |
|
|
Stock compensation expense |
|
3,020 |
|
|
|
3,018 |
|
|
|
4,350 |
|
|
|
14,356 |
|
|
|
16,973 |
|
|
(Gains) losses on derivatives |
|
(62,521 |
) |
|
|
94,857 |
|
|
|
7,412 |
|
|
|
(13,620 |
) |
|
|
48,314 |
|
|
Net cash (paid) received for scheduled derivative settlements |
|
(9,616 |
) |
|
|
(19,432 |
) |
|
|
(3,504 |
) |
|
|
5,895 |
|
|
|
(88,023 |
) |
|
Acquisition costs(1) |
|
284 |
|
|
|
2,082 |
|
|
|
— |
|
|
|
3,338 |
|
|
|
— |
|
|
Non-recurring costs(2) |
|
— |
|
|
|
1,384 |
|
|
|
3,268 |
|
|
|
8,697 |
|
|
|
3,466 |
|
|
Other operating expenses (income) |
|
36 |
|
|
|
(505 |
) |
|
|
(1,023 |
) |
|
|
(1,788 |
) |
|
|
3,722 |
|
| Adjusted
EBITDA |
$ |
70,036 |
|
|
$ |
69,829 |
|
|
$ |
77,508 |
|
|
$ |
268,257 |
|
|
$ |
379,948 |
|
| |
|
|
|
|
|
|
|
|
|
| Net cash provided by operating
activities |
$ |
79,018 |
|
|
$ |
55,320 |
|
|
$ |
105,407 |
|
|
$ |
198,657 |
|
|
$ |
360,941 |
|
| Add (Subtract): |
|
|
|
|
|
|
|
|
|
|
Cash interest payments |
|
1,794 |
|
|
|
15,065 |
|
|
|
311 |
|
|
|
32,251 |
|
|
|
29,792 |
|
|
Cash income tax payments |
|
525 |
|
|
|
2,087 |
|
|
|
828 |
|
|
|
3,282 |
|
|
|
3,633 |
|
|
Acquisition costs(1) |
|
284 |
|
|
|
2,082 |
|
|
|
— |
|
|
|
3,338 |
|
|
|
— |
|
|
Non-recurring costs(2) |
|
— |
|
|
|
1,384 |
|
|
|
3,268 |
|
|
|
8,697 |
|
|
|
3,466 |
|
|
Changes in operating assets and liabilities - working
capital(3) |
|
(11,070 |
) |
|
|
(5,114 |
) |
|
|
(31,003 |
) |
|
|
25,654 |
|
|
|
(21,446 |
) |
|
Other operating (income) expenses - cash portion(4) |
|
(515 |
) |
|
|
(995 |
) |
|
|
(1,303 |
) |
|
|
(3,622 |
) |
|
|
3,562 |
|
| Adjusted
EBITDA |
$ |
70,036 |
|
|
$ |
69,829 |
|
|
$ |
77,508 |
|
|
$ |
268,257 |
|
|
$ |
379,948 |
|
__________(1) Consists of costs related to
the Macpherson Acquisition.(2) In 2023, non-recurring costs
included executive transition costs and workforce reduction costs
in the first quarter, and costs related to the settlement of
shareholder litigation in the third quarter. In 2022, non-recurring
costs included legal and professional service expenses related to
acquisition and divestiture activity in the first quarter and
executive transition costs in the fourth quarter.(3) Changes
in other assets and liabilities consists of working capital and
various immaterial items.(4) Represents the cash portion of
other operating (income) expenses from the income statement, net of
the non-cash portion in the cash flow statement.
ADJUSTED FREE CASH FLOW
The following table presents a reconciliation of
the GAAP financial measure of operating cash flow to the non-GAAP
financial measure of Adjusted Free Cash Flow for each of the
periods indicated.
| |
Quarter EndedDecember 31,2023 |
|
Quarter EndedSeptember 30,2023 |
|
Quarter EndedDecember 31,2022 |
|
Year EndedDecember 31,2023 |
|
Year EndedDecember 31,2022 |
| |
(unaudited)(in thousands) |
| Adjusted
Free Cash Flow reconciliation: |
|
Net cash provided by operating activities(1) |
$ |
79,018 |
|
|
$ |
55,320 |
|
|
$ |
105,407 |
|
|
$ |
198,657 |
|
|
$ |
360,941 |
|
|
Subtract: |
|
|
|
|
|
|
|
|
|
|
Maintenance capital(2) |
|
(15,114 |
) |
|
|
(10,833 |
) |
|
|
(45,047 |
) |
|
|
(64,844 |
) |
|
|
(141,930 |
) |
|
Fixed dividends(3) |
|
(9,080 |
) |
|
|
(9,080 |
) |
|
|
(4,557 |
) |
|
|
(36,489 |
) |
|
|
(19,245 |
) |
| Adjusted Free Cash
Flow |
$ |
54,824 |
|
|
$ |
35,407 |
|
|
$ |
55,803 |
|
|
$ |
97,324 |
|
|
$ |
199,766 |
|
__________(1) On a consolidated
basis.(2) Maintenance capital is the capital required to keep
annual production substantially flat, and is calculated as
follows:
| |
Quarter EndedDecember 31,2023 |
|
Quarter EndedSeptember 30,2023 |
|
Quarter EndedDecember 31,2022 |
|
Year EndedDecember 31,2023 |
|
Year EndedDecember 31,2022 |
| |
(unaudited)(in thousands) |
|
Consolidated capital expenditures(a) |
$ |
(17,003 |
) |
|
$ |
(13,596 |
) |
|
$ |
(50,398 |
) |
|
$ |
(73,127 |
) |
|
$ |
(152,921 |
) |
|
Excluded items(b) |
|
1,889 |
|
|
|
2,763 |
|
|
|
5,351 |
|
|
|
8,283 |
|
|
|
10,991 |
|
|
Maintenance capital(c) |
$ |
(15,114 |
) |
|
$ |
(10,833 |
) |
|
$ |
(45,047 |
) |
|
$ |
(64,844 |
) |
|
$ |
(141,930 |
) |
__________(a)
Capital expenditures include capitalized overhead and interest and
excludes acquisitions and asset retirement spending.(b)
Comprised of the capital expenditures in the Company’s E&P
segment that are related to strategic business expansion, such as
acquisitions 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 the
Company’s well servicing and abandonment segment and corporate
expenditures that are related to ancillary sustainability
initiatives or other expenditures that are discretionary and
unrelated to maintaining flat production in the Company’s E&P
business. For the three months ended December 31, 2023, September
30, 2023, December 31, 2022, and the years ended December 31, 2023
and 2022, we excluded approximately $1 million, $2 million, $5
million, $6 million and $8 million of capital expenditures in the
Company’s well servicing and abandonment segment, respectively,
which was substantially all used for sustainability initiatives or
other expenditures that are discretionary and unrelated to
maintenance of the Company’s core business. For the three months
ended December 31, 2023, September 30, 2023, December 31, 2022, and
the years ended December 31, 2023 and 2022, we excluded
approximately $0.5 million, $0.7 million, $0.5 million, $2 million
and $3 million of corporate capital expenditures, respectively,
which the Company determined was not related to the maintenance of
baseline production.(c) In 2024, we updated the definition of
Adjusted Free Cash Flow to cash flow from operations less regular
fixed dividends and capital expenditures. Adjusted Free Cash Flow
for prior periods has not been retroactively adjusted for the
updated definition.
(3) Represents fixed dividends
declared for the periods presented.
ADJUSTED NET INCOME (LOSS)
The following table presents a reconciliation of
the GAAP financial measures of net income (loss) and net income
(loss) per share — diluted to the non-GAAP financial measures of
Adjusted Net Income (Loss) and Adjusted Net Income (Loss) per share
— diluted for each of the periods indicated.
| |
Quarter Ended |
| |
December 31, 2023 |
|
September 30, 2023 |
|
December 31, 2022 |
| |
(in thousands) |
|
per share -diluted |
|
(in thousands) |
|
per share -diluted |
|
(in thousands) |
|
per share -diluted |
| |
(unaudited) |
| Adjusted
Net Income (Loss) reconciliation: |
|
Net income (loss) |
$ |
62,551 |
|
|
$ |
0.81 |
|
|
$ |
(45,062 |
) |
|
$ |
(0.58 |
) |
|
$ |
71,964 |
|
|
$ |
0.90 |
|
| Add
(Subtract): |
|
|
|
|
|
|
|
|
|
|
|
|
(Gains) losses on derivatives |
|
(62,521 |
) |
|
|
(0.81 |
) |
|
|
94,857 |
|
|
|
1.22 |
|
|
|
7,412 |
|
|
|
0.09 |
|
|
Net cash (paid) for scheduled derivative settlements |
|
(9,616 |
) |
|
|
(0.12 |
) |
|
|
(19,432 |
) |
|
|
(0.25 |
) |
|
|
(3,504 |
) |
|
|
(0.04 |
) |
|
Other operating expenses (income) |
|
36 |
|
|
|
— |
|
|
|
(505 |
) |
|
|
(0.01 |
) |
|
|
(1,023 |
) |
|
|
(0.02 |
) |
|
Acquisition costs(1) |
|
284 |
|
|
|
— |
|
|
|
2,082 |
|
|
|
0.03 |
|
|
|
— |
|
|
|
— |
|
|
Non-recurring costs(2) |
|
— |
|
|
|
— |
|
|
|
1,384 |
|
|
|
0.02 |
|
|
|
3,268 |
|
|
|
0.04 |
|
|
Total (subtractions) additions, net |
|
(71,817 |
) |
|
|
(0.93 |
) |
|
|
78,386 |
|
|
|
1.01 |
|
|
|
6,153 |
|
|
|
0.07 |
|
|
Income tax benefit (expense) of adjustments(3) |
|
19,692 |
|
|
|
0.25 |
|
|
|
(21,493 |
) |
|
|
(0.28 |
) |
|
|
(1,668 |
) |
|
|
(0.02 |
) |
| Adjusted Net
Income |
$ |
10,426 |
|
|
$ |
0.13 |
|
|
$ |
11,831 |
|
|
$ |
0.15 |
|
|
$ |
76,449 |
|
|
$ |
0.95 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
| Basic EPS on Adjusted Net
Income |
$ |
0.14 |
|
|
|
|
$ |
0.16 |
|
|
|
|
$ |
1.00 |
|
|
|
| Diluted EPS on Adjusted Net
Income |
$ |
0.13 |
|
|
|
|
$ |
0.15 |
|
|
|
|
$ |
0.95 |
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
| Weighted average shares of
common stock outstanding - basic |
|
75,667 |
|
|
|
|
|
75,662 |
|
|
|
|
|
76,181 |
|
|
|
| Weighted average shares of
common stock outstanding - diluted |
|
77,349 |
|
|
|
|
|
77,606 |
|
|
|
|
|
80,312 |
|
|
|
__________(1) Consists of costs related to
the Macpherson Acquisition.(2) Consists of costs related to
the settlement of shareholder litigation in the third quarter of
2023, and executive transition costs in the fourth quarter of
2022.(3) The federal and state statutory rates were
utilized in both 2023 and 2022.
| |
Year Ended |
| |
December 31, 2023 |
|
December 31, 2022 |
| |
(in thousands) |
|
per share -diluted |
|
(in thousands) |
|
per share -diluted |
| |
(unaudited) |
| Adjusted Net Income
(Loss) reconciliation: |
|
|
Net income |
$ |
37,400 |
|
|
$ |
0.48 |
|
|
$ |
250,168 |
|
|
$ |
3.03 |
|
| Add
(Subtract): |
|
|
|
|
|
|
|
|
(Gains) losses on derivatives |
|
(13,620 |
) |
|
|
(0.18 |
) |
|
|
48,314 |
|
|
|
0.59 |
|
|
Net cash received (paid) for scheduled derivative settlements |
|
5,895 |
|
|
|
0.08 |
|
|
|
(88,023 |
) |
|
|
(1.07 |
) |
|
Other operating (income) expenses |
|
(1,788 |
) |
|
|
(0.01 |
) |
|
|
3,722 |
|
|
|
0.04 |
|
|
Acquisition costs(1) |
|
3,338 |
|
|
|
0.04 |
|
|
|
— |
|
|
|
— |
|
|
Non-recurring costs(2) |
|
8,697 |
|
|
|
0.11 |
|
|
|
3,466 |
|
|
|
0.04 |
|
|
Total additions (subtractions), net |
|
2,522 |
|
|
|
0.04 |
|
|
|
(32,521 |
) |
|
|
(0.40 |
) |
|
Income tax (expense) benefit of adjustments(3) |
|
(692 |
) |
|
|
(0.01 |
) |
|
|
8,816 |
|
|
|
0.11 |
|
| Adjusted Net
Income |
$ |
39,230 |
|
|
$ |
0.51 |
|
|
$ |
226,463 |
|
|
$ |
2.74 |
|
| |
|
|
|
|
|
|
|
| Basic EPS on Adjusted Net
Income |
$ |
0.52 |
|
|
|
|
$ |
2.88 |
|
|
|
| Diluted EPS on Adjusted Net
Income |
$ |
0.51 |
|
|
|
|
$ |
2.74 |
|
|
|
| |
|
|
|
|
|
|
|
| Weighted average shares of
common stock outstanding - basic |
|
76,038 |
|
|
|
|
|
78,517 |
|
|
|
| Weighted average shares of
common stock outstanding - diluted |
|
77,583 |
|
|
|
|
|
82,586 |
|
|
|
__________(1) Consists of costs related to
the Macpherson Acquisition.(2) In 2023, non-recurring costs
included executive transition costs and workforce reduction costs
in the first quarter, and costs related to the settlement of
shareholder litigation in the third quarter. In 2022, non-recurring
costs included legal and professional service expenses related to
acquisition and divestiture activity in the first quarter and
executive transition costs in the fourth quarter.(3) The
federal and state statutory rates were utilized in both 2023 and
2022.
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 measure of Adjusted General and
Administrative Expenses for each of the periods indicated.
| |
Quarter EndedDecember
31,2023 |
|
Quarter EndedSeptember
30,2023 |
|
Quarter EndedDecember
31,2022 |
|
Year EndedDecember 31,2023 |
|
Year EndedDecember 31,2022 |
| |
(unaudited)($ in thousands) |
| Adjusted
General and Administrative Expense reconciliation: |
|
|
|
|
|
General and administrative expenses |
$ |
20,729 |
|
|
$ |
20,987 |
|
|
$ |
26,926 |
|
|
$ |
95,873 |
|
|
$ |
96,439 |
|
|
Subtract: |
|
|
|
|
|
|
|
|
|
|
Non-cash stock compensation expense (G&A portion) |
|
(2,843 |
) |
|
|
(2,840 |
) |
|
|
(4,248 |
) |
|
|
(13,681 |
) |
|
|
(16,498 |
) |
|
Non-recurring costs(1) |
|
— |
|
|
|
(1,384 |
) |
|
|
(3,268 |
) |
|
|
(8,697 |
) |
|
|
(3,466 |
) |
| Adjusted General and
Administrative Expenses |
$ |
17,886 |
|
|
$ |
16,763 |
|
|
$ |
19,410 |
|
|
$ |
73,495 |
|
|
$ |
76,475 |
|
| |
|
|
|
|
|
|
|
|
|
| Well servicing and
abandonment segment |
$ |
2,177 |
|
|
$ |
2,910 |
|
|
$ |
3,296 |
|
|
$ |
11,171 |
|
|
$ |
12,975 |
|
| |
|
|
|
|
|
|
|
|
|
| E&P segment, and
corporate |
$ |
15,709 |
|
|
$ |
13,853 |
|
|
$ |
16,114 |
|
|
$ |
62,324 |
|
|
$ |
63,500 |
|
| E&P segment, and
corporate ($/boe) |
$ |
6.59 |
|
|
$ |
5.96 |
|
|
$ |
6.80 |
|
|
$ |
6.73 |
|
|
$ |
6.66 |
|
| |
|
|
|
|
|
|
|
|
|
| Total
mboe |
|
2,384 |
|
|
|
2,326 |
|
|
|
2,371 |
|
|
|
9,258 |
|
|
|
9,532 |
|
__________(1) In 2023, non-recurring costs included
executive transition costs and workforce reduction costs in the
first quarter, and costs related to the settlement of shareholder
litigation in the third quarter. In 2022, non-recurring costs
included legal and professional service expenses related to
acquisition and divestiture activity in the first quarter and
executive transition costs in the fourth quarter.
RESERVES AND PV-10
The following table summarizes our estimated
proved reserves and related PV-10 as of December 31, 2023:
| |
Proved Reserves as of December 31,
2023(1) |
| |
California (San
Joaquinbasin) |
|
Utah(Uinta basin) |
|
Total |
| |
(unaudited) |
| Proved developed
reserves: |
|
|
|
|
|
|
Oil (mmbbl) |
|
46 |
|
|
|
6 |
|
|
|
52 |
|
|
Natural gas (bcf) |
|
— |
|
|
|
21 |
|
|
|
21 |
|
|
NGLs (mmbbl) |
|
— |
|
|
|
1 |
|
|
|
1 |
|
|
Total (mmboe)(2)(3) |
|
46 |
|
|
|
11 |
|
|
|
57 |
|
| Proved undeveloped
reserves: |
|
|
|
|
|
|
Oil (mmbbl) |
|
44 |
|
|
|
2 |
|
|
|
46 |
|
|
Natural gas (bcf) |
|
— |
|
|
|
5 |
|
|
|
5 |
|
|
NGLs (mmbbl) |
|
— |
|
|
|
— |
|
|
|
— |
|
|
Total (mmboe)(3) |
|
44 |
|
|
|
2 |
|
|
|
46 |
|
| Total proved
reserves: |
|
|
|
|
|
|
Oil (mmbbl) |
|
90 |
|
|
|
8 |
|
|
|
98 |
|
|
Natural gas (bcf) |
|
— |
|
|
|
26 |
|
|
|
26 |
|
|
NGLs (mmbbl) |
|
— |
|
|
|
1 |
|
|
|
1 |
|
|
Total (mmboe)(3) |
|
90 |
|
|
|
13 |
|
|
|
103 |
|
| |
|
|
|
|
|
| PV-10 (in
millions)(4) |
$ |
1,977 |
|
|
$ |
72 |
|
|
$ |
2,049 |
|
__________(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 $82.84
per bbl Brent for oil and NGLs and $2.63 per mmbtu Henry Hub for
natural gas at December 31, 2023. The volume-weighted average
realized prices over the lives of the properties were $77.30 per
bbl of oil and condensate, $26.90 per bbl of NGLs and $3.73 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 12%
of total and 12% of oil are non-producing.(3) Natural gas
volumes have been converted to boe based on energy content of six
mcf of gas to one bbl of oil. Barrels of oil equivalence does not
necessarily result in price equivalence. The price of natural gas
on a barrel of oil equivalent basis is currently substantially
lower than the corresponding price for oil and has been similarly
lower for a number of years. For example, in the year ended
December 31, 2023, the average prices of Brent oil and Henry Hub
natural gas were $82.18 per bbl and $2.53 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, 2023:
| |
At December 31, 2023 |
| |
(unaudited)(in millions) |
|
California PV-10 |
$ |
1,977 |
|
| Utah PV-10 |
|
72 |
|
| Total Company PV-10 |
|
2,049 |
|
| Less: present value of future
income taxes discounted at 10% |
|
(366 |
) |
| Standardized measure of
discounted future net cash flows |
$ |
1,683 |
|
The following table presents reserves changes
and production for 2023:
| |
Total Company |
|
California |
| |
(unaudited)(in mmboe) |
|
Extensions and discoveries |
5 |
|
|
5 |
|
| Revisions of previous
estimates |
(12 |
) |
|
(1 |
) |
| Purchases of minerals(1) |
9 |
|
|
9 |
|
|
Total reserves changes |
2 |
|
|
13 |
|
| |
|
|
|
| Production |
(9 |
) |
|
(7 |
) |
| Reserve replacement ratio |
19 |
% |
|
176 |
% |
__________(1) Purchases of minerals
are related to the Macpherson Acquisition and a small acquisition
in Kern County in December 2023.
Contact
Contact: Berry Corporation (bry)
Todd Crabtree - Director, Investor Relations
(661) 616-3811
ir@bry.com
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