Berry Corporation (bry) (NASDAQ: BRY) (“Berry”, “bry” or the
“Company”) announced improved third quarter results, including net
income of $10 million or $0.12 per diluted share, Adjusted Net
Income(1) of $12 million or $0.14 per diluted share, and Adjusted
EBITDA(1) of $59.3 million, a 46% increase sequentially. The Board
of Directors approved a quarterly common stock dividend of $0.06
per share for the fourth quarter of 2021, and a new total
shareholder return model expected to be implemented in 2022.
Quarterly Highlights
- Increased sequential quarterly
Adjusted EBITDA(1) by 46% to $59.3 million totaling $152 million
YTD
- Completed accretive acquisition of
CA well services business, now operating as C&J Well Services,
further aligning bry with the State of California's goal to reduce
fugitive emissions
- Completed sale of Placerita Field
operations in Los Angeles County, consolidating all California
assets into rural Kern County
- Completed new $500 million RBL
credit facility; maintaining $200 million borrowing base and
elected commitment
- Updated guidance to reflect
drilling and A&D activity
- Board approved fourth quarter 2021
dividend of $0.06/share
- Announced plan to implement new
shareholder return model starting in 2022
_______(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.
“The most recent upturn in oil prices, the
continued global under-investment in oil and gas, and the on-going
growth in global demand presents an exceptional opportunity for
bry. We believe this cycle is different than prior cycles. Our
current view is that it will likely be longer in duration, possibly
the next couple of decades, and therefore represents a potentially
fundamental change for the industry.” said Trem Smith, bry board
chairman and CEO.
“The Board has approved the following model that
will continue to position Berry as a top tier returner of capital
back to our shareholders. It will consist of a mix of returns
through variable cash dividends, in addition to our current
dividend, share repurchases and debt retirement, while keeping a
portion available for organic growth and bolt-on acquisitions. At
our stock price and the current oil strip, we believe the
shareholder returns could be more than 20% per share annually.
Berry has all the critical elements in place with a proven, simple
business model which includes a low corporate decline rate, a
predictable cost structure, an abundance of inventory, Brent
pricing and a simple, clean balance sheet. Based on current
industry fundamentals, we should generate considerable levered free
cash flow for many years to come. We look forward to unveiling the
full details of the model later this quarter and implementing it
beginning in 2022,” continued Smith.
Third Quarter 2021 Results
Adjusted EBITDA(1), on a hedged basis, was $59.3
million in the third quarter 2021. This represented a 46% increase
compared to $40.6 million in the second quarter 2021. The increase
was largely the result of higher oil and natural gas prices, as
well as improved hedge positions and increased oil and gas
production.
The Company realized a slight increase in
average daily production by 100 boe/d to 27,400 boe/d for the third
quarter of 2021 compared to the second quarter of 2021, as a result
of its continuing 2021 development program, consisting of 56 new
wells in the quarter. The Company's oil production for the third
quarter 2021 was 24,100 bbl/d, while California production was
21,800 boe/d, each of which was a slight increase from the second
quarter 2021. Production for the third quarter was impacted as we
managed the onboarding of a new drilling operator and an
industry-wide shortage of truck drivers. Most of these issues were
mitigated by the end of the third quarter.
The Company-wide hedged realized oil price for
the third quarter 2021 was $54.35 per bbl, a 17% increase from the
second quarter. The California average oil price before hedges for
the third quarter was $69.92 per bbl, 95% of Brent, which was 7%
higher than the $65.37 per bbl in the second quarter 2021, also 95%
of Brent.
Operating expenses, or OpEx, consists of lease
operating expenses (“LOE”), third-party expenses and revenues from
electricity generation, transportation and marketing activities, as
well as the effect of derivative settlements (received or paid) for
gas purchases.
On a hedged basis, operating expenses decreased
by 1% or $0.13 per boe to $17.18 for the third quarter 2021,
compared to $17.31 for the second quarter 2021. During the third
quarter the Company's non-energy operating expenses increased
slightly on a per boe basis, compared to the second quarter of
2021, due primarily to higher well maintenance activity, higher
power prices, and higher outside services and facility costs
partially offset by lower steam facility expense. Energy operating
expenses improved as increased electricity revenue and gas purchase
hedging more than offset higher natural gas prices.
General and administrative expenses increased by
almost $2 million, or 10%, to approximately $18 million for the
third quarter 2021, compared to the second quarter 2021, largely
due to legal and professional service expenses related to
acquisition and divestment activity. Adjusted General and
Administrative Expenses(1), which exclude non-cash stock
compensation costs and nonrecurring costs, were essentially flat at
$13 million and $5.34 per boe for the third quarter 2021.
Taxes, other than income taxes were $5.33 per
boe for the third quarter compared to $4.67 per boe in the second
quarter 2021 largely due to higher greenhouse gas costs as
mark-to-market valuations increased.
For the third quarter 2021, capital expenditures
were approximately $38 million on an accrual basis and excluding
acquisitions and asset retirement obligation spending.
Approximately 78% of this capital was directed to California oil
operations, and 15% to Utah operations. Additionally, bry spent
approximately $5 million and $12 million for plugging and
abandonment activities in the third quarter 2021 and year-to-date,
respectively.
At September 30, 2021, the Company had liquidity
of $243 million consisting of $43 million cash on hand
and $200 million available for borrowings under its RBL
Facility.
“We continued to deliver on our 2021 plan, while
enhancing our portfolio since the second quarter with the accretive
acquisition of our new C&J Well Services business, which was a
strategic and value-adding transaction purchased at a competitive
price. Last week, we sold our Placerita Field operations in Los
Angeles County consolidating all our California operations into
Kern County. Also, due primarily to the divestiture of our
Placerita asset we have refined our total production range for 2021
to be in the 27,200 to 27,700 range,” stated Cary Baetz, chief
financial officer, EVP and director. “Additionally, we completed
our new $500 million RBL facility which matures in 2025,
maintaining our $200 million borrowing base and elected
commitment.”
Quarterly Dividend
The Company’s Board of Directors declared a
regular dividend for the fourth quarter of 2021 at a rate of $0.06
per share on the Company’s outstanding common stock, payable on
January 17, 2022 to shareholders of record at the close of business
on December 15, 2021.
Subject to approval by the Board on a quarterly
basis and depending on a variety of factors, including the
Company’s financial condition and results of operations, the
Company intends to pay a similar fixed dividend in future
quarters.
_______(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.
Earnings Conference Call
The Company will host a conference call November 3, 2021,
to discuss these results:
Live Call Date: |
|
Wednesday, November 3, 2021 |
Live Call Time: |
|
9:00 a.m. Eastern Time (6 a.m. Pacific Time) |
Live Call Dial-in: |
|
877-491-5169 from the U.S.720-405-2254 from international
locations |
Live Call Passcode: |
|
3586911 |
A live audio webcast will be available at
bry.com/category/events.
An audio replay will be available shortly after the
broadcast:
Replay Dates: |
|
Through Wednesday, November 17, 2021 |
Replay Dial-in: |
|
855-859-2056 from the U.S.404-537-3406 from international
locations |
Replay Passcode: |
|
3586911 |
A replay of the audio webcast will also be archived at
ir.bry.com/reports-resources.
About Berry Corporation
(bry)
Bry is a publicly traded (NASDAQ: BRY) western
United States independent upstream energy company with a focus on
the conventional, long-lived oil reserves in the San Joaquin basin
of California, with well servicing and abandonment capabilities.
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 its financial position;
liquidity; cash flows; anticipated financial and operating results;
capital program and development and production plans; operations
and business strategy; potential acquisition opportunities;
reserves; hedging activities; capital expenditures, shareholder
returns or return of capital; payment, payment of or improvement of
future dividends; future repurchases of stock or debt; capital
investments, and 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.
Bry 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 bry’s control.
These risks include, but are not limited to, commodity price
volatility; legislative and regulatory processes and actions that
may prevent, delay or otherwise restrict our ability to drill and
develop our assets, including regulatory approval and permitting
requirements; legislative and regulatory initiatives in California
or our other areas of operation addressing climate change or other
environmental concerns; drilling, production and other operating
risks; investment in and development of competing or alternative
energy sources; uncertainties inherent in estimating natural gas
and oil reserves and in projecting future rates of production; cash
flow and access to capital; the timing and funding of development
expenditures; environmental, health and safety risks; effects of
hedging arrangements; potential shut-ins of production due to lack
of downstream demand or storage capacity; the impact and duration
of the ongoing COVID-19 pandemic on demand and pricing levels; and
the other risks described under the heading “Item 1A. Risk Factors”
in the Company’s Annual Report on Form 10-K for the year ended
December 31, 2020 and subsequent filings with the SEC, including
the Company's Form 10-Q for the quarter ended September 30,
2021.
You can typically identify forward-looking
statements by words such as aim, anticipate, achievable, believe,
budget, continue, could, effort, estimate, expect, forecast, goal,
guidance, intend, likely, may, might, objective, outlook, plan,
potential, predict, project, seek, should, target, will or would
and other similar words that reflect the prospective nature of
events or outcomes.
Any forward-looking statement speaks only as of
the date on which such statement is made, and we undertake no
obligation to correct or update any forward-looking statement,
whether as a result of new information, future events or otherwise
except as required by applicable law. Investors are urged to
consider carefully the disclosure in our filings with the
Securities and Exchange Commission, available from us at via our
website or via the Investor Relations contact below, or from the
SEC’s website at www.sec.gov.
Tables Following
The financial information and certain other
information presented have been rounded to the nearest whole number
or the nearest decimal. Therefore, the sum of the numbers in a
column may not conform exactly to the total figure given for that
column in certain tables. In addition, certain percentages
presented here reflect calculations based upon the underlying
information prior to rounding and, accordingly, may not conform
exactly to the percentages that would be derived if the relevant
calculations were based upon the rounded numbers, or may not sum
due to rounding.
SUMMARY OF
RESULTS |
Three Months Ended |
|
September 30, 2021 |
|
June 30, 2021 |
|
September 30, 2020 |
|
($ and shares in thousands, except per share amounts) |
Statement of
Operations Data: |
|
|
|
|
|
Revenues and
other: |
|
|
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
161,058 |
|
|
$ |
147,775 |
|
|
$ |
92,239 |
|
Electricity sales |
12,371 |
|
|
6,888 |
|
|
8,744 |
|
Losses on oil and gas sales derivatives |
(30,864 |
) |
|
(55,653 |
) |
|
(11,564 |
) |
Marketing revenues |
732 |
|
|
121 |
|
|
330 |
|
Other revenues |
117 |
|
|
118 |
|
|
— |
|
Total revenues and other |
143,414 |
|
|
99,249 |
|
|
89,749 |
|
|
|
|
|
|
|
Expenses and
other: |
|
|
|
|
|
Lease operating expenses |
60,930 |
|
|
45,543 |
|
|
45,243 |
|
Electricity generation expenses |
7,128 |
|
|
4,712 |
|
|
4,217 |
|
Transportation expenses |
1,806 |
|
|
1,757 |
|
|
1,768 |
|
Marketing expenses |
715 |
|
|
44 |
|
|
326 |
|
General and administrative expenses |
17,614 |
|
|
16,065 |
|
|
19,173 |
|
Depreciation, depletion and amortization |
35,902 |
|
|
35,850 |
|
|
35,905 |
|
Taxes, other than income taxes |
13,420 |
|
|
11,603 |
|
|
9,913 |
|
Gains on natural gas purchase derivatives |
(14,980 |
) |
|
(11,639 |
) |
|
(15,784 |
) |
Other operating expenses |
3,986 |
|
|
42 |
|
|
1,648 |
|
Total expenses and other |
126,521 |
|
|
103,977 |
|
|
102,409 |
|
|
|
|
|
|
|
Other (expenses)
income: |
|
|
|
|
|
Interest expense |
(7,810 |
) |
|
(8,217 |
) |
|
(8,391 |
) |
Other, net |
(5 |
) |
|
(8 |
) |
|
(3 |
) |
Total other (expenses) income |
(7,815 |
) |
|
(8,225 |
) |
|
(8,394 |
) |
Income (loss) before
income taxes |
9,078 |
|
|
(12,953 |
) |
|
(21,054 |
) |
Income tax benefit |
(758 |
) |
|
(72 |
) |
|
(2,190 |
) |
Net income
(loss) |
$ |
9,836 |
|
|
$ |
(12,881 |
) |
|
$ |
(18,864 |
) |
|
|
|
|
|
|
Net income (loss) per
share: |
|
|
|
|
|
Basic |
$ |
0.12 |
|
|
$ |
(0.16 |
) |
|
$ |
(0.24 |
) |
Diluted |
$ |
0.12 |
|
|
$ |
(0.16 |
) |
|
$ |
(0.24 |
) |
|
|
|
|
|
|
Weighted-average shares of
common stock outstanding - basic |
80,242 |
|
|
80,471 |
|
|
79,879 |
|
Weighted-average shares of
common stock outstanding - diluted |
82,898 |
|
|
80,471 |
|
|
79,879 |
|
|
|
|
|
|
|
Adjusted Net Income
(Loss)(1) |
$ |
11,536 |
|
|
$ |
(6,293 |
) |
|
$ |
13,452 |
|
Weighted-average shares of
common stock outstanding - diluted |
82,898 |
|
|
80,471 |
|
|
80,062 |
|
Diluted earnings per share on
Adjusted Net Income (Loss) |
$ |
0.14 |
|
|
$ |
(0.08 |
) |
|
$ |
0.17 |
|
|
|
|
|
|
|
|
Three Months Ended |
|
September 30, 2021 |
|
June 30, 2021 |
|
September 30, 2020 |
|
($ and shares in thousands, except per share amounts) |
Adjusted EBITDA(1) |
$ |
59,324 |
|
|
$ |
40,599 |
|
|
$ |
61,515 |
|
Adjusted EBITDA
Unhedged(1) |
$ |
76,946 |
|
|
$ |
78,030 |
|
|
$ |
26,039 |
|
Levered Free Cash Flow(1) |
$ |
8,692 |
|
|
$ |
(14,298 |
) |
|
$ |
47,206 |
|
Levered Free Cash Flow
Unhedged(1) |
$ |
26,314 |
|
|
$ |
23,133 |
|
|
$ |
11,730 |
|
Adjusted General and
Administrative Expenses(1) |
$ |
13,442 |
|
|
$ |
13,302 |
|
|
$ |
13,888 |
|
Effective Tax Rate, including
discrete items |
(8 |
)% |
|
1 |
% |
|
10 |
% |
|
|
|
|
|
|
Cash Flow
Data: |
|
|
|
|
|
Net cash provided by operating
activities |
$ |
22,399 |
|
|
$ |
21,429 |
|
|
$ |
57,997 |
|
Net cash used in investing
activities |
$ |
(50,024 |
) |
|
$ |
(40,575 |
) |
|
$ |
(9,004 |
) |
Net cash used in financing
activities |
$ |
(9,132 |
) |
|
$ |
(3,298 |
) |
|
$ |
(1,373 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
__________(1) See further discussion and reconciliation in
“Non-GAAP Financial Measures and Reconciliations”.(2) The effective
tax rate for the nine months ended September 30, 2021 is 5%.
|
September 30, 2021 |
|
December 31, 2020 |
|
($ and shares in thousands) |
Balance Sheet
Data: |
|
|
|
Total current assets |
$ |
178,919 |
|
|
$ |
154,491 |
|
Total property, plant and
equipment, net |
$ |
1,233,223 |
|
|
$ |
1,258,084 |
|
Total current liabilities |
$ |
194,058 |
|
|
$ |
175,306 |
|
Long-term debt |
$ |
394,285 |
|
|
$ |
393,480 |
|
Total stockholders'
equity |
$ |
684,896 |
|
|
$ |
714,036 |
|
Outstanding common stock
shares as of |
80,007 |
|
|
79,929 |
|
|
|
|
|
|
|
SUMMARY BY AREA
The following table shows a summary by area of
our selected historical financial information and operating data
for the periods indicated.
|
California (San Joaquin and Ventura
basins) |
|
Three Months Ended |
|
September 30, 2021 |
|
June 30, 2021 |
|
September 30, 2020 |
($ in thousands, except prices) |
|
|
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
140,160 |
|
|
$ |
129,128 |
|
|
$ |
81,592 |
|
Operating income(1) |
$ |
26,652 |
|
|
$ |
11,413 |
|
|
$ |
36,296 |
|
Depreciation, depletion, and
amortization (DD&A) |
$ |
35,252 |
|
|
$ |
35,174 |
|
|
$ |
34,779 |
|
Average daily production
(mboe/d) |
21.8 |
|
|
21.7 |
|
|
22.2 |
|
Production (oil % of
total) |
100 |
% |
|
100 |
% |
|
100 |
% |
Realized sales prices: |
|
|
|
|
|
Oil (per bbl) |
$ |
69.92 |
|
|
$ |
65.37 |
|
|
$ |
40.02 |
|
NGLs (per bbl) |
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Gas (per mcf) |
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Capital expenditures(2) |
$ |
29,806 |
|
|
$ |
31,303 |
|
|
$ |
4,467 |
|
|
Utah(Uinta basin) |
|
Colorado(Piceance basin) |
|
Three Months Ended |
|
Three Months Ended |
|
September 30,2021 |
|
June 30,2021 |
|
September 30,2020 |
|
September 30,2021 |
|
June 30,2021 |
|
September 30,2020 |
($ in thousands, except prices) |
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
18,118 |
|
|
$ |
16,199 |
|
|
$ |
9,311 |
|
|
$ |
2,779 |
|
|
$ |
2,438 |
|
|
$ |
1,336 |
|
Operating income
(loss)(1) |
$ |
7,246 |
|
|
$ |
6,736 |
|
|
$ |
1,093 |
|
|
$ |
2,360 |
|
|
$ |
1,121 |
|
|
$ |
(235 |
) |
Depreciation, depletion, and
amortization (DD&A) |
$ |
611 |
|
|
$ |
630 |
|
|
$ |
915 |
|
|
$ |
38 |
|
|
$ |
38 |
|
|
$ |
165 |
|
Average daily production
(mboe/d) |
4.4 |
|
|
4.4 |
|
|
4.1 |
|
|
1.2 |
|
|
1.2 |
|
|
1.3 |
|
Production (oil % of
total) |
50 |
% |
|
52 |
% |
|
47 |
% |
|
1 |
% |
|
2 |
% |
|
2 |
% |
Realized sales prices: |
|
|
|
|
|
|
|
|
|
|
|
Oil (per bbl) |
$ |
60.09 |
|
|
$ |
58.55 |
|
|
$ |
38.40 |
|
|
$ |
66.97 |
|
|
$ |
56.05 |
|
|
$ |
33.60 |
|
NGLs (per bbl) |
$ |
40.88 |
|
|
$ |
29.61 |
|
|
$ |
13.25 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Gas (per mcf) |
$ |
4.31 |
|
|
$ |
3.30 |
|
|
$ |
2.05 |
|
|
$ |
4.24 |
|
|
$ |
3.53 |
|
|
$ |
1.80 |
|
Capital expenditures(2) |
$ |
5,728 |
|
|
$ |
9,162 |
|
|
$ |
103 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
46 |
|
__________(1) Operating income (loss) includes oil, natural gas
and NGL sales, and scheduled oil derivative settlements, offset by
operating expenses (as defined elsewhere), general and
administrative expenses, DD&A, impairment of oil and gas
properties, and taxes, other than income taxes.(2) Excludes
corporate capital expenditures.
COMMODITY PRICING
|
Three Months Ended |
|
September 30, 2021 |
|
June 30, 2021 |
|
September 30, 2020 |
Weighted-average
realized sales prices: |
|
|
|
|
|
Oil without hedges ($/bbl) |
$ |
69.01 |
|
|
$ |
64.72 |
|
|
$ |
39.88 |
|
Effects of scheduled
derivative settlements ($/bbl) |
$ |
(14.66 |
) |
|
$ |
(18.33 |
) |
|
$ |
16.28 |
|
Oil with hedges ($/bbl) |
$ |
54.35 |
|
|
$ |
46.39 |
|
|
$ |
56.16 |
|
Natural gas ($/mcf) |
$ |
4.29 |
|
|
$ |
3.39 |
|
|
$ |
1.95 |
|
NGLs ($/bbl) |
$ |
40.88 |
|
|
$ |
29.61 |
|
|
$ |
13.25 |
|
|
|
|
|
|
|
Average Benchmark
prices: |
|
|
|
|
|
Oil (bbl) – Brent |
$ |
73.23 |
|
|
$ |
69.08 |
|
|
$ |
43.34 |
|
Oil (bbl) – WTI |
$ |
70.63 |
|
|
$ |
66.03 |
|
|
$ |
40.87 |
|
Natural gas (mmbtu) – Kern,
Delivered(1) |
$ |
5.75 |
|
|
$ |
3.23 |
|
|
$ |
2.84 |
|
Natural gas (mmbtu) – Henry
Hub(2) |
$ |
4.35 |
|
|
$ |
2.95 |
|
|
$ |
2.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
__________(1) Kern, Delivered Index is the relevant index used
for gas purchases in California.(2) Henry Hub is the relevant index
used for gas sales in the Rockies.
CURRENT HEDGING SUMMARY
As of September 30, 2021, we had the following crude oil
production and gas purchases hedges.
|
Q4 2021 |
|
FY 2022 |
|
FY 2023 |
|
FY 2024 |
Fixed Price Oil Swaps
(Brent): |
|
|
|
|
|
|
|
Hedged volume (mbbls) |
1,318 |
|
|
3,387 |
|
|
1,596 |
|
|
732 |
|
Weighted-average price ($/bbl) |
$ |
48.61 |
|
|
$ |
66.63 |
|
|
$ |
65.26 |
|
|
$ |
61.78 |
|
Purchased Oil Put
Options (Brent): |
|
|
|
|
|
|
|
Hedged volume (mbbls) |
307 |
|
|
1,643 |
|
|
2,555 |
|
|
1,647 |
|
Weighted-average price ($/bbl) |
$ |
60.00 |
|
|
$ |
50.00 |
|
|
$ |
50.00 |
|
|
$ |
50.00 |
|
Sold Oil Put Options
(Brent): |
|
|
|
|
|
|
|
Hedged volume (mbbls) |
— |
|
|
1,643 |
|
|
2,555 |
|
|
1,647 |
|
Weighted-average price ($/bbl) |
$ |
— |
|
|
$ |
40.00 |
|
|
$ |
40.00 |
|
|
$ |
40.00 |
|
Sold Oil Calls Options
(Brent): |
|
|
|
|
|
|
|
Hedged volume (mbbls) |
307 |
|
|
— |
|
|
— |
|
|
— |
|
Weighted-average price ($/bbl) |
$ |
75.00 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Purchased Gas Call
Options (Henry Hub): |
|
|
|
|
|
|
|
Hedged volume (mmbtu) |
|
1,830,000 |
|
|
|
10,950,000 |
|
|
|
10,950,000 |
|
|
|
9,150,000 |
|
Weighted-average price ($/mmbtu) |
$ |
4.00 |
|
|
$ |
4.00 |
|
|
$ |
4.00 |
|
|
$ |
4.00 |
|
Sold Gas Put Options
(Henry Hub): |
|
|
|
|
|
|
|
Hedged volume (mmbtu) |
1,830,000 |
|
|
10,950,000 |
|
|
10,950,000 |
|
|
9,150,000 |
|
Weighted-average price ($/mmbtu) |
$ |
2.75 |
|
|
$ |
2.75 |
|
|
$ |
2.75 |
|
|
$ |
2.75 |
|
Fixed Price Gas
Purchase Swaps (Kern, Delivered): |
|
|
|
|
|
|
|
Hedged volume (mmbtu) |
2,085,000 |
|
|
— |
|
|
— |
|
|
— |
|
Weighted-average price ($/mmbtu) |
$ |
2.95 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In October we added purchased gas put options
(Henry Hub) of 20,000 mmbtu/d at $2.75 beginning November 2021
through March 2022, which offset the fourth quarter 2021 and first
quarter 2022 sold gas put options included in the above table. We
added sold oil put options (Brent) of 500 bbl/d at $60.00 beginning
November 2021 through December 2021, which offset the fourth
quarter 2021 purchased oil put options included in the above table.
We also added purchased fixed price oil swaps (Brent) of 1,000
bbl/d at $66.95 beginning January 2022 through December 2022, which
partially offset the 2022 fixed price oil swaps included in the
table above.
During the second and third quarters of 2021 we
entered into pipeline capacity agreements for the shipment of
natural gas from the Rockies to our assets in California, that will
reduce our exposure to fuel gas purchase price fluctuations. During
the third quarter of 2021 we entered into a capacity agreement for
approximately 32,700 mmbtu/d beginning May 2022 through April 2032
for a total commitment of $62 million. In the second quarter
of 2021 we entered into pipeline capacity agreements for
approximately 10,000 mmbtu/d beginning October 2021 through October
2036 and approximately 5,500 mmbtu/d beginning November 2021
through December 2024 for a total commitment of $32 million.
The average price for all three agreements is approximately $0.52
mmbtu/d.
OPERATING EXPENSES
|
Three Months Ended |
|
September 30, 2021 |
|
June 30, 2021 |
|
September 30, 2020 |
|
($ in thousands except per boe amounts) |
Lease operating expenses |
$ |
60,930 |
|
|
$ |
45,543 |
|
|
$ |
45,243 |
|
Electricity generation
expenses |
7,128 |
|
|
4,712 |
|
|
4,217 |
|
Electricity sales(1) |
(12,371 |
) |
|
(6,888 |
) |
|
(8,744 |
) |
Transportation expenses |
1,806 |
|
|
1,757 |
|
|
1,768 |
|
Transportation sales(1) |
(117 |
) |
|
(118 |
) |
|
— |
|
Marketing expenses |
715 |
|
|
44 |
|
|
326 |
|
Marketing revenues(1) |
(732 |
) |
|
(121 |
) |
|
(330 |
) |
Derivative settlements
(received) paid for gas purchases(1) |
(14,095 |
) |
|
(1,913 |
) |
|
614 |
|
Total operating expenses(1) |
$ |
43,264 |
|
|
$ |
43,016 |
|
|
$ |
43,094 |
|
|
|
|
|
|
|
Lease operating expenses
($/boe) |
$ |
24.20 |
|
|
$ |
18.33 |
|
|
$ |
17.83 |
|
Electricity generation
expenses ($/boe) |
2.83 |
|
|
1.90 |
|
|
1.66 |
|
Electricity sales ($/boe) |
(4.91 |
) |
|
(2.77 |
) |
|
(3.45 |
) |
Transportation expenses
($/boe) |
0.72 |
|
|
0.70 |
|
|
0.69 |
|
Transportation sales
($/boe) |
(0.05 |
) |
|
(0.05 |
) |
|
— |
|
Marketing expenses
($/boe) |
0.28 |
|
|
0.02 |
|
|
0.13 |
|
Marketing revenues
($/boe) |
(0.29 |
) |
|
(0.05 |
) |
|
(0.13 |
) |
Derivative settlements
(received) paid for gas purchases ($/boe) |
(5.60 |
) |
|
(0.77 |
) |
|
0.24 |
|
Total operating expenses ($/boe) |
$ |
17.18 |
|
|
$ |
17.31 |
|
|
$ |
16.97 |
|
Total unhedged operating expenses ($/boe)(2) |
$ |
22.78 |
|
|
$ |
18.08 |
|
|
$ |
16.73 |
|
|
|
|
|
|
|
Total non-energy operating expenses(3) |
$ |
13.59 |
|
|
$ |
12.71 |
|
|
$ |
13.34 |
|
Total energy operating expenses(4) |
$ |
3.59 |
|
|
$ |
4.60 |
|
|
$ |
3.65 |
|
|
|
|
|
|
|
Total mboe |
2,519 |
|
|
2,485 |
|
|
2,537 |
|
|
|
|
|
|
|
|
|
|
__________(1) We report electricity,
transportation and marketing sales separately in our financial
statements as revenues in accordance with GAAP. However, these
revenues are viewed and used internally in calculating operating
expenses which is used to track and analyze the economics of
development projects and the efficiency of our hydrocarbon
recovery. We purchase third-party gas to generate electricity
through our cogeneration facilities to be used in our field
operations activities and view the added benefit of any excess
electricity sold externally as a cost reduction/benefit to
generating steam for our thermal recovery operations. Marketing
revenues and expenses mainly relate to natural gas purchased from
third parties that moves through our gathering and processing
systems and then is sold to third parties. Transportation sales
relate to water and other liquids that we transport on our systems
on behalf of third parties and have not been significant to date.
Operating expenses also include the effect of derivative
settlements (received or paid) for gas purchases.(2) Total unhedged
operating expenses equals total operating expenses, excluding the
derivative settlements paid (received) for gas purchases.(3) Total
non-energy operating expenses equals total operating expenses,
excluding fuel, electricity sales and gas purchase derivative
settlement (gains) losses.(4) Total energy operating expenses
equals fuel and gas purchase derivative settlement (gains) losses
less electricity sales.
PRODUCTION STATISTICS
|
Three Months Ended |
|
September 30, 2021 |
|
June 30, 2021 |
|
September 30, 2020 |
Net Oil, Natural Gas
and NGLs Production Per
Day(1): |
|
|
|
|
|
Oil
(mbbl/d) |
|
|
|
|
|
California |
21.8 |
|
21.7 |
|
22.2 |
Utah |
2.3 |
|
2.3 |
|
1.9 |
Colorado |
— |
|
— |
|
— |
Total oil |
24.1 |
|
24.0 |
|
24.1 |
Natural gas
(mmcf/d) |
|
|
|
|
|
California |
— |
|
— |
|
— |
Utah |
10.7 |
|
10.3 |
|
11.0 |
Colorado |
6.9 |
|
7.2 |
|
7.7 |
Total natural gas |
17.6 |
|
17.5 |
|
18.7 |
NGLs
(mbbl/d) |
|
|
|
|
|
California |
— |
|
— |
|
— |
Utah |
0.4 |
|
0.4 |
|
0.4 |
Colorado |
— |
|
— |
|
— |
Total NGLs |
0.4 |
|
0.4 |
|
0.4 |
Total Production
(mboe/d)(2) |
27.4 |
|
27.3 |
|
27.6 |
|
|
|
|
|
|
__________(1) Production represents volumes sold
during the period.(2) Natural gas volumes have been converted to
boe based on energy content of six mcf of gas to one bbl of oil.
Barrels of oil equivalence does not necessarily result in price
equivalence. The price of natural gas on a barrel of oil equivalent
basis is currently substantially lower than the corresponding price
for oil and has been similarly lower for a number of years. For
example, in the three months ended September 30, 2021, the average
prices of Brent oil and Henry Hub natural gas were $73.23 per bbl
and $4.35 per mmbtu respectively.
CAPITAL EXPENDITURES (ACCRUAL BASIS)
|
Three Months Ended |
|
September 30, 2021 |
|
June 30, 2021 |
|
September 30, 2020 |
|
(in thousands) |
Capital expenditures (accrual basis)(1) |
$ |
38,016 |
|
|
$ |
43,461 |
|
|
$ |
5,918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
__________(1) Excludes acquisitions and asset
retirement spending.
NON-GAAP FINANCIAL MEASURES AND
RECONCILIATIONS
Adjusted Net Income (Loss) is not a measure of
net income (loss), Levered Free Cash Flow is not a measure of cash
flow, and Adjusted EBITDA is not a measure of either, in all cases,
as determined by GAAP. Adjusted Net Income (Loss), Adjusted
EBITDA, Levered Free Cash Flow and Adjusted General and
Administrative Expenses are supplemental non-GAAP financial
measures used by management and external users of our financial
statements, such as industry analysts, investors, lenders and
rating agencies. We define Adjusted Net Income (Loss) as net income
(loss) adjusted for derivative gains or losses net of cash received
or paid for scheduled derivative settlements, other unusual and
infrequent items, and the income tax expense or benefit of these
adjustments using our effective tax rate. We define Adjusted EBITDA
as earnings before interest expense; income taxes; depreciation,
depletion, and amortization; derivative gains or losses net of cash
received or paid for scheduled derivative settlements; impairments;
stock compensation expense; and other unusual and infrequent items.
We define Levered Free Cash Flow as Adjusted EBITDA less capital
expenditures, interest expense and dividends. We define Adjusted
General and Administrative Expenses as general and administrative
expenses adjusted for non-cash stock compensation expense and
unusual and infrequent costs.
Adjusted Net Income (Loss) excludes the impact
of unusual and infrequent items affecting earnings that vary widely
and unpredictably, including non-cash items such as derivative
gains and losses. This measure is used by management when comparing
results period over period. Our management believes Adjusted EBITDA
provides useful information in assessing our financial condition,
results of operations and cash flows and is widely used by the
industry and the investment community. The measure also allows our
management to more effectively evaluate our operating performance
and compare the results between periods without regard to our
financing methods or capital structure. Levered Free Cash Flow is
used by management as a primary metric to plan capital allocation
to sustain production levels and for internal growth opportunities,
as well as hedging needs. It also serves as a measure for assessing
our financial performance and our ability to generate excess cash
from operations to service debt and pay dividends. Management
believes Adjusted General and Administrative Expenses is useful
because it allows us to more effectively compare our performance
from period to period. We exclude the items listed above from
general and administrative expenses in arriving at Adjusted General
and Administrative Expenses because these amounts can vary widely
and unpredictably in nature, timing, amount and frequency and stock
compensation expense is non-cash in nature.
While Adjusted Net Income (Loss), Adjusted
EBITDA, Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered
Free Cash Flow Unhedged and Adjusted General and Administrative
Expenses are non-GAAP measures, the amounts included in the
calculations of Adjusted Net Income (Loss), Adjusted EBITDA,
Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash
Flow Unhedged and Adjusted General and Administrative Expenses were
computed in accordance with GAAP. These measures are provided in
addition to, and not as an alternative for, income and liquidity
measures calculated in accordance with GAAP and should not be
considered as an alternative to, or more meaningful than, income
and liquidity measures calculated in accordance with GAAP. Our
computations of Adjusted Net Income (Loss), Adjusted EBITDA,
Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash
Flow Unhedged and Adjusted General and Administrative Expenses may
not be comparable to other similarly titled measures used by other
companies. Adjusted Net Income (Loss), Adjusted EBITDA, Adjusted
EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash Flow
Unhedged and Adjusted General and Administrative Expenses should be
read in conjunction with the information contained in our financial
statements prepared in accordance with GAAP.
ADJUSTED NET INCOME (LOSS)
The following table presents a reconciliation of
the GAAP financial measure of net income (loss) to the non-GAAP
financial measure of Adjusted Net Income (Loss).
|
Three Months Ended |
|
September 30, 2021 |
|
June 30, 2021 |
|
September 30, 2020 |
|
($ thousands, except per share amounts) |
Net income (loss) |
$ |
9,836 |
|
|
$ |
(12,881 |
) |
|
$ |
(18,864 |
) |
Subtract: discrete income tax items |
— |
|
|
— |
|
|
(2,394 |
) |
Add (Subtract): |
|
|
|
|
|
Losses on derivatives |
15,885 |
|
|
44,014 |
|
|
(4,220 |
) |
Net cash (paid) received for scheduled derivative settlements |
(17,622 |
) |
|
(37,431 |
) |
|
35,476 |
|
Other operating expenses |
3,986 |
|
|
42 |
|
|
1,648 |
|
Non-recurring costs |
705 |
|
|
— |
|
|
1,473 |
|
Total additions, net |
2,954 |
|
|
6,625 |
|
|
34,377 |
|
|
|
|
|
|
|
Income tax (expense) benefit
of adjustments at effective tax rate |
(1,254 |
) |
|
(37 |
) |
|
333 |
|
Adjusted Net Income
(Loss) |
$ |
11,536 |
|
|
$ |
(6,293 |
) |
|
$ |
13,452 |
|
|
|
|
|
|
|
Basic EPS on Adjusted Net
Income (Loss) |
$ |
0.14 |
|
|
$ |
(0.08 |
) |
|
$ |
0.17 |
|
Diluted EPS on Adjusted Net
Income (Loss) |
$ |
0.14 |
|
|
$ |
(0.08 |
) |
|
$ |
0.17 |
|
|
|
|
|
|
|
Weighted average shares of
common stock outstanding - basic |
80,242 |
|
|
80,471 |
|
|
79,879 |
|
Weighted average shares of
common stock outstanding - diluted |
82,898 |
|
|
80,471 |
|
|
80,062 |
|
|
|
|
|
|
|
|
|
|
ADJUSTED EBITDA AND ADJUSTED EBITDA
UNHEDGED
The following tables present a reconciliation of
the GAAP financial measures of net income (loss) and net cash
provided by operating activities to the non-GAAP financial measures
of Adjusted EBITDA and Adjusted EBITDA Unhedged.
|
Three Months Ended |
|
September 30, 2021 |
|
June 30, 2021 |
|
September 30, 2020 |
|
($ thousands) |
Net income (loss) |
$ |
9,836 |
|
|
$ |
(12,881 |
) |
|
$ |
(18,864 |
) |
Add (Subtract): |
|
|
|
|
|
Interest expense |
7,810 |
|
|
8,217 |
|
|
8,391 |
|
Income tax benefit |
(758 |
) |
|
(72 |
) |
|
(2,190 |
) |
Depreciation, depletion and amortization |
35,902 |
|
|
35,850 |
|
|
35,905 |
|
Losses (gains) on derivatives |
15,885 |
|
|
44,014 |
|
|
(4,220 |
) |
Net cash (paid) received for scheduled derivative settlements |
(17,622 |
) |
|
(37,431 |
) |
|
35,476 |
|
Other operating expense(1) |
3,986 |
|
|
42 |
|
|
1,648 |
|
Stock compensation expense |
3,580 |
|
|
2,860 |
|
|
3,896 |
|
Non-recurring costs(2) |
705 |
|
|
— |
|
|
1,473 |
|
Adjusted EBITDA |
$ |
59,324 |
|
|
$ |
40,599 |
|
|
$ |
61,515 |
|
Net cash paid (received) for
scheduled derivative settlements |
17,622 |
|
|
37,431 |
|
|
(35,476 |
) |
Adjusted EBITDA Unhedged |
$ |
76,946 |
|
|
$ |
78,030 |
|
|
$ |
26,039 |
|
|
|
|
|
|
|
Net cash provided by operating
activities |
$ |
22,399 |
|
|
$ |
21,429 |
|
|
$ |
57,997 |
|
Add (Subtract): |
|
|
|
|
|
Cash interest payments |
14,189 |
|
|
288 |
|
|
14,435 |
|
Cash income tax payments |
294 |
|
|
— |
|
|
221 |
|
Non-recurring costs |
705 |
|
|
— |
|
|
1,473 |
|
Other changes in operating assets and liabilities |
21,737 |
|
|
18,882 |
|
|
(12,611 |
) |
Adjusted EBITDA |
$ |
59,324 |
|
|
$ |
40,599 |
|
|
$ |
61,515 |
|
Net cash paid (received) for
scheduled derivative settlements |
17,622 |
|
|
37,431 |
|
|
(35,476 |
) |
Adjusted EBITDA Unhedged |
$ |
76,946 |
|
|
$ |
78,030 |
|
|
$ |
26,039 |
|
|
|
|
|
|
|
|
|
|
|
|
|
__________(1) Other operating expenses mainly
consist of unamortized debt issuance costs related to the
termination of the 2017 RBL Facility, supplemental property tax
assessments and royalty audit charges, excess abandonment costs and
oil tank storage fees, as well as income from employee retention
credits.(2) Non-recurring costs include legal and professional
service expenses related to acquisition and divestiture
activity.
LEVERED FREE CASH FLOW
The following table presents a reconciliation of
Adjusted EBITDA to the non–GAAP measures of Levered Free Cash Flow.
The reconciliation of Adjusted EBITDA is presented above.
|
Three Months Ended |
|
September 30, 2021 |
|
June 30, 2021 |
|
September 30, 2020 |
|
($ thousands) |
Adjusted EBITDA |
$ |
59,324 |
|
|
$ |
40,599 |
|
|
$ |
61,515 |
|
Subtract: |
|
|
|
|
|
Capital expenditures - accrual basis(1) |
(38,016 |
) |
|
(43,461 |
) |
|
(5,918 |
) |
Interest expense |
(7,810 |
) |
|
(8,217 |
) |
|
(8,391 |
) |
Cash dividends declared |
(4,806 |
) |
|
(3,219 |
) |
|
— |
|
Levered Free Cash Flow |
$ |
8,692 |
|
|
$ |
(14,298 |
) |
|
$ |
47,206 |
|
Net cash paid (received) for
scheduled derivative settlements |
17,622 |
|
|
37,431 |
|
|
(35,476 |
) |
Levered Free Cash Flow
Unhedged |
$ |
26,314 |
|
|
$ |
23,133 |
|
|
$ |
11,730 |
|
|
|
|
|
|
|
|
|
|
|
|
|
__________(1) Capital expenditures excludes
acquisitions and asset retirement spending.
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.
|
Three Months Ended |
|
September 30, 2021 |
|
June 30, 2021 |
|
September 30, 2020 |
|
($ in thousands except per mboe amounts) |
General and administrative expenses |
$ |
17,614 |
|
|
$ |
16,065 |
|
|
$ |
19,173 |
|
Subtract: |
|
|
|
|
|
Non-cash stock compensation expense (G&A portion) |
(3,467 |
) |
|
(2,763 |
) |
|
(3,812 |
) |
Non-recurring costs |
(705 |
) |
|
— |
|
|
(1,473 |
) |
Adjusted General and
Administrative Expenses |
$ |
13,442 |
|
|
$ |
13,302 |
|
|
$ |
13,888 |
|
|
|
|
|
|
|
General and administrative
expenses ($/boe) |
$ |
6.99 |
|
|
$ |
6.46 |
|
|
$ |
7.56 |
|
Subtract: |
|
|
|
|
|
Non-cash stock compensation expense ($/boe) |
(1.37 |
) |
|
(1.11 |
) |
|
(1.50 |
) |
Non-recurring costs ($/boe) |
(0.28 |
) |
|
— |
|
|
(0.58 |
) |
Adjusted General and
Administrative Expenses ($/boe) |
$ |
5.34 |
|
|
$ |
5.35 |
|
|
$ |
5.47 |
|
|
|
|
|
|
|
Total mboe |
2,519 |
|
|
2,485 |
|
|
2,537 |
|
|
|
|
|
|
|
|
|
|
Contact
Contact: bry
Todd Crabtree - Manager, Investor Relations
(661) 616-3811
ir@bry.com
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