Berry Corporation (bry) (NASDAQ: BRY) (“Berry”, “bry” or the
“Company”) announced that it will increase its quarterly common
stock dividend to $0.06 per share beginning with the dividend
declared by the Board of Directors for the third quarter of 2021.
“Berry’s solid second quarter results were
consistent with our expectations and annual guidance. Since going
public in 2018, Berry has remained committed to its disciplined
financial principles and delivering long-term value for
stockholders. In recognition of our strong financial position and
continued confidence in Berry’s future, the Board has voted to
increase the quarterly dividend by 50%. In our three years as a
public company, Berry has returned capital amounting to 115% of the
IPO proceeds, or $127 million, including $77 million in the form of
dividends, highlighting Berry’s commitment to return capital to its
shareholders,” said Trem Smith, Berry board Chairman and CEO.
The Company also reported a net loss of $13
million or $0.16 per diluted share and Adjusted Net Loss(1) of $6
million or $0.08 per diluted share for the second quarter of
2021.
Quarterly Highlights
- Generated Adjusted EBITDA(1) of $41
million
- Increased sequential total
production 1% to 27,300 boe/d
- Drilled 58 wells, of which 21 will
come on production in Q3
- Increased quarterly dividend 50% to
$0.06 per share
- Reaffirming annual guidance
_______
(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.
“Our business model is simple, durable and
resilient and able to withstand pandemics, market collapses and
political headwinds. We have proven it generates positive cash flow
in all but the most extreme market environments. We live within
Levered Free Cash Flow (1), which we define to include our
expenses, the capital needed to keep production flat, interest and
dividends. Our confidence in our ability to generate excess Levered
Free Cash Flow is once again evident by the dividend increase
announced today. We believe the best current use of capital is to
keep production flat, enabling us to return capital and increase
shareholder returns," continued Smith. “We continue to execute
successfully on our two-year plan that was established in early
2020 following the Covid-19 outbreak and oil market disruption. As
promised, we increased production in the second quarter and remain
in a good position to meet our 2021 production goals to keep
production flat year on year. We maintained our non-energy cost
levels, despite increasing commodity prices, while maintaining our
high safety and environmental standards. As has been the case for
the last several years, no California governmental or regulatory
constraints have had a meaningful impact on our operations and we
are continuing to receive permits and continuing to drill. The
demand for oil and gas is strong in California and is expected to
remain strong for the foreseeable future. I look forward to what’s
ahead for Berry.”
Second Quarter 2021 Results
Adjusted EBITDA(1), on a hedged basis, was $41
million in the second quarter 2021. This compared to $52 million in
the first quarter 2021, which had included notably higher sales
from acutely higher gas and electricity prices as a result of the
natural gas shortage related to Winter Storm Uri. In the second
quarter 2021, the impact of higher oil prices and increased
production resulted in favorable impacts on revenue. Energy-related
operating expenses were higher, as well as taxes, other than income
taxes mainly due to higher Greenhouse Gas (GHG) prices. Adjusted
general and administrative expense was slightly lower than the
first quarter.
The Company grew average daily production 1% to
27,300 boe/d for the second quarter of 2021 compared to the first
quarter of 2021, as a result of its continuing 2021 development
program, consisting of 58 new wells in the quarter, including eight
wells in Utah. The Company held oil production for the second
quarter 2021 essentially flat at 24,000 bbl/d. Production in Utah
increased 10%, while the Company's California production of 21,700
boe/d for the second quarter of 2021 decreased 1% from the first
quarter 2021. California production has been negatively impacted by
a loss of our production from one of Berry's locations where lower
water withdrawals by an offset operator along with a reduction in
our steam injection volumes triggered a drop in production. The
issue has reduced production by approximately 600 bbl/d and this
will impact all of 2021. However, the steam is expected to recharge
and be back to historical production levels by early next year.
The Company-wide hedged realized oil price for
the second quarter 2021 was $46.39 per bbl, a 4% increase from the
first quarter. The California average oil price before hedges for
the second quarter was $65.37 per bbl, 95% of Brent, which was 14%
higher than the $57.34 per bbl in the first quarter 2021, which was
94% of Brent.
OpEx consists of lease operating expenses
(“LOE”), third-party revenues and expenses from electricity
generation, transportation and marketing activities, as well as the
effect of derivative settlements (received or paid) for gas
purchases, and excludes taxes other than income taxes.
On a hedged basis, operating expenses increased
by 20% or $2.91 per boe to $17.31 for the second quarter 2021,
compared to $14.40 for the first quarter 2021, entirely due to the
impact of energy related expenses on a hedged basis in the second
quarter 2021 and the acutely higher electricity sales prices in the
first quarter. During the second quarter the Company maintained its
cost savings efforts with non-energy operating expenses down
slightly on a per boe basis, compared to the first quarter of 2021,
despite higher commodity prices.
General and administrative expenses decreased by
$1 million, or 6%, to approximately $16 million for the second
quarter 2021, compared to the first quarter 2021, largely due to
lower non-cash stock compensation expenses. Adjusted General and
Administrative Expenses(1), which exclude non-cash stock
compensation costs and nonrecurring costs, decreased 1% to $13
million and 3% to $5.35 per boe for the second quarter 2021.
Taxes, other than income taxes were $4.67 per
boe for the second quarter compared to $3.93 per boe in the first
quarter 2021. GHG costs were higher in the second quarter of 2021
due to higher mark-to-market valuations.
For the second quarter 2021, capital
expenditures were approximately $43 million on an accrual basis
excluding acquisitions and asset retirement obligation spending.
Berry drilled 58 wells in the second quarter, of which 21 will come
on production in the third quarter 2021. Capital for the second
quarter was higher as more wells were drilled, including eight
wells drilled in Utah, which require more capital than typical
California wells, as well as increased California workover,
equipping and facilities work. Approximately 72% of this capital
was directed to California oil operations, and 21% to Utah
operations. Additionally, Berry also spent approximately
$3 million for plugging and abandonment activities in the
second quarter 2021.
At June 30, 2021, the Company had liquidity of
$268 million consisting of $75 million cash in the bank
and $193 million available for borrowings under its RBL
Facility which had no borrowings and $7 million of letters of
credit outstanding. The RBL Facility has a $200 million borrowing
base with an elected commitment of $200 million.
“We continued to deliver on our plan and we are
seeing better-than-expected results from our capital
spending. However, this capital efficiency is being
masked by the temporary production loss in one of our fields
resulting from a reduction in steam intensity late last year,”
stated Cary Baetz, chief financial officer, EVP and director. “We
will continue to see a healthy spend in the third quarter that
decreases in the fourth quarter, which aligns with our annual
guidance. Our oil hedge position will improve in the second half of
this year and into next year. While our need for natural gas
hedging is being reduced, we are now starting to gain some access
to the Kern County pipeline which will allow us to use some of our
Rockies gas production in our steam operations. Lastly, we continue
to focus on the return of capital and are happy to announce an
increase in our quarterly dividend to $0.06 per
share.”
Quarterly Dividend
The Company’s Board of Directors declared a
regular dividend for the third quarter of 2021 at a rate of $0.06
per share on the Company’s outstanding common stock, payable on
October 15, 2021 to shareholders of record at the close of business
on September 15, 2021.
Subject to approval by the Board and depending
on a variety of factors, including the Company’s financial
condition and results of operations, the Company intends to pay a
similar dividend in future quarters._______
(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
August 4, 2021, to discuss these results:
Live Call
Date: |
Wednesday,
August 4, 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: |
5973754 |
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, August 18, 2021 |
Replay Dial-in: |
855-859-2056 from the U.S. |
|
404-537-3406 from international locations |
Replay Passcode: |
5973754 |
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. More information can be found at the Company’s
website at bry.com.
Forward-Looking Statements
The information in this press release includes
forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange
Act of 1934. All statements, other than statements of historical
facts, included in this press release that address plans,
activities, events, objectives, goals, strategies, or developments
that the Company expects, believes or anticipates will or may occur
in the future, such as those regarding financial position;
liquidity; cash flows; anticipated financial and operating,
results; capital program and development and production plans;
operations and business strategy; potential acquisition
opportunities; reserves; hedging activities; capital expenditures,
return of capital; payment, payment of or improvement of future
dividends; future repurchases of stock or debt; capital
investments, recovery factors and other guidance are
forward-looking statements. The forward-looking statements in this
press release are based upon various assumptions, many of which are
based, in turn, upon further assumptions. Although we believe that
these assumptions were reasonable when made, these assumptions are
inherently subject to significant uncertainties and contingencies
which are difficult or impossible to predict and are beyond our
control. Therefore, such forward-looking statements involve
significant risks and uncertainties that could materially affect
our expected results of operations, liquidity, cash flows and
business prospects.
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.
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 |
|
June 30, 2021 |
|
March 31, 2021 |
|
June 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 |
$ |
147,775 |
|
|
|
$ |
135,265 |
|
|
|
$ |
70,515 |
|
|
Electricity sales |
6,888 |
|
|
|
10,069 |
|
|
|
4,884 |
|
|
Losses on oil and gas sales derivatives |
(55,653 |
) |
|
|
(53,504 |
) |
|
|
(42,267 |
) |
|
Marketing revenues |
121 |
|
|
|
2,234 |
|
|
|
292 |
|
|
Other revenues |
118 |
|
|
|
137 |
|
|
|
29 |
|
|
Total revenues and other |
99,249 |
|
|
|
94,201 |
|
|
|
33,453 |
|
|
|
|
|
|
|
|
Expenses and other: |
|
|
|
|
|
Lease operating expenses |
45,543 |
|
|
|
62,284 |
|
|
|
40,733 |
|
|
Electricity generation expenses |
4,712 |
|
|
|
7,648 |
|
|
|
3,022 |
|
|
Transportation expenses |
1,757 |
|
|
|
1,576 |
|
|
|
1,789 |
|
|
Marketing expenses |
44 |
|
|
|
2,227 |
|
|
|
280 |
|
|
General and administrative expenses |
16,065 |
|
|
|
17,070 |
|
|
|
18,777 |
|
|
Depreciation, depletion and amortization |
35,850 |
|
|
|
33,840 |
|
|
|
37,512 |
|
|
Taxes, other than income taxes |
11,603 |
|
|
|
9,557 |
|
|
|
10,449 |
|
|
(Gains) losses on natural gas purchase derivatives |
(11,639 |
) |
|
|
(27,730 |
) |
|
|
925 |
|
|
Other operating expenses (income) |
42 |
|
|
|
799 |
|
|
|
(1,192 |
) |
|
Total expenses and other |
103,977 |
|
|
|
107,271 |
|
|
|
112,295 |
|
|
|
|
|
|
|
|
Other (expenses) income: |
|
|
|
|
|
Interest expense |
(8,217 |
) |
|
|
(8,485 |
) |
|
|
(8,676 |
) |
|
Other, net |
(8 |
) |
|
|
(143 |
) |
|
|
(6 |
) |
|
Total other (expenses) income |
(8,225 |
) |
|
|
(8,628 |
) |
|
|
(8,682 |
) |
|
Loss before income taxes |
(12,953 |
) |
|
|
(21,698 |
) |
|
|
(87,524 |
) |
|
Income tax benefit |
(72 |
) |
|
|
(376 |
) |
|
|
(22,623 |
) |
|
Net loss |
$ |
(12,881 |
) |
|
|
$ |
(21,322 |
) |
|
|
$ |
(64,901 |
) |
|
|
|
|
|
|
|
Net loss per share: |
|
|
|
|
|
Basic |
$ |
(0.16 |
) |
|
|
$ |
(0.27 |
) |
|
|
$ |
(0.81 |
) |
|
Diluted |
$ |
(0.16 |
) |
|
|
$ |
(0.27 |
) |
|
|
$ |
(0.81 |
) |
|
|
|
|
|
|
|
Weighted-average shares of common stock outstanding - basic |
80,471 |
|
|
|
80,115 |
|
|
|
79,795 |
|
|
Weighted-average shares of common stock outstanding - diluted |
80,471 |
|
|
|
80,115 |
|
|
|
79,795 |
|
|
|
|
|
|
|
|
Adjusted Net (Loss) Income(1) |
$ |
(6,293 |
) |
|
|
$ |
5,627 |
|
|
|
$ |
4,609 |
|
|
Weighted-average shares of common stock outstanding - diluted |
80,471 |
|
|
|
82,276 |
|
|
|
80,640 |
|
|
Diluted earnings per share on Adjusted Net (Loss) Income |
$ |
(0.08 |
) |
|
|
$ |
0.07 |
|
|
|
$ |
0.06 |
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
|
($ and shares in thousands, except per share amounts) |
Adjusted EBITDA(1) |
$ |
40,599 |
|
|
|
$ |
51,829 |
|
|
|
$ |
57,433 |
|
|
Adjusted EBITDA Unhedged(1) |
$ |
78,030 |
|
|
|
$ |
50,979 |
|
|
|
$ |
5,559 |
|
|
Levered Free Cash Flow(1) |
$ |
(14,298 |
) |
|
|
$ |
16,301 |
|
|
|
$ |
32,057 |
|
|
Levered Free Cash Flow Unhedged(1) |
$ |
23,133 |
|
|
|
$ |
15,451 |
|
|
|
$ |
(19,817 |
) |
|
Adjusted General and Administrative Expenses(1) |
$ |
13,302 |
|
|
|
$ |
13,401 |
|
|
|
$ |
14,081 |
|
|
Effective Tax Rate, including discrete items |
1 |
|
% |
|
2 |
|
% |
|
26 |
|
% |
|
|
|
|
|
|
Cash Flow Data: |
|
|
|
|
|
Net cash provided by operating activities |
$ |
21,429 |
|
|
|
$ |
38,430 |
|
|
|
$ |
41,939 |
|
|
Net cash used in investing activities |
$ |
(40,575 |
) |
|
|
$ |
(19,937 |
) |
|
|
$ |
(22,480 |
) |
|
Net cash used in financing activities |
$ |
(3,298 |
) |
|
|
$ |
(1,688 |
) |
|
|
$ |
(19,460 |
) |
|
__________
(1) See further discussion and
reconciliation in “Non-GAAP Financial Measures and
Reconciliations”.
|
June 30, 2021 |
|
December 31, 2020 |
|
($ and shares in thousands) |
Balance Sheet Data: |
|
|
|
Total current assets |
$ |
177,063 |
|
|
$ |
154,491 |
|
Total property, plant and equipment, net |
$ |
1,262,417 |
|
|
$ |
1,258,084 |
|
Total current liabilities |
$ |
222,062 |
|
|
$ |
175,306 |
|
Long-term debt |
$ |
394,009 |
|
|
$ |
393,480 |
|
Total stockholders' equity |
$ |
678,658 |
|
|
$ |
714,036 |
|
Outstanding common stock shares as of |
80,471 |
|
|
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 |
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
($ in thousands, except prices) |
|
|
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
129,128 |
|
|
$ |
113,177 |
|
|
$ |
62,943 |
|
Operating income(1) |
$ |
11,413 |
|
|
$ |
18,965 |
|
|
$ |
32,469 |
|
Depreciation, depletion, and
amortization (DD&A) |
$ |
35,174 |
|
|
$ |
32,896 |
|
|
$ |
36,518 |
|
Average daily production (mboe/d) |
21.7 |
|
|
21.9 |
|
|
23.4 |
|
Production (oil % of
total) |
100 |
% |
|
100 |
% |
|
100 |
% |
Realized sales prices: |
|
|
|
|
|
Oil (per bbl) |
$ |
65.37 |
|
|
$ |
57.34 |
|
|
$ |
29.53 |
|
NGLs (per bbl) |
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Gas (per mcf) |
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Capital expenditures(2) |
$ |
31,303 |
|
|
$ |
22,760 |
|
|
$ |
16,446 |
|
|
Utah(Uinta basin) |
|
Colorado(Piceance basin) |
|
Three Months Ended |
|
Three Months Ended |
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
($ in thousands, except prices) |
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
16,199 |
|
|
$ |
15,889 |
|
|
$ |
6,439 |
|
|
|
$ |
2,438 |
|
|
$ |
6,194 |
|
|
$ |
1,132 |
|
Operating income (loss)(1) |
$ |
6,736 |
|
|
$ |
7,433 |
|
|
$ |
(584 |
) |
|
|
$ |
1,121 |
|
|
$ |
5,039 |
|
|
$ |
6 |
|
Depreciation, depletion, and amortization (DD&A) |
$ |
630 |
|
|
$ |
554 |
|
|
$ |
905 |
|
|
|
$ |
38 |
|
|
$ |
38 |
|
|
$ |
43 |
|
Average daily production (mboe/d) |
4.4 |
|
|
4.0 |
|
|
4.4 |
|
|
|
1.2 |
|
|
1.2 |
|
|
1.3 |
|
Production (oil % of total) |
52 |
% |
|
49 |
% |
|
49 |
|
% |
|
2 |
% |
|
2 |
% |
|
2 |
% |
Realized sales prices: |
|
|
|
|
|
|
|
|
|
|
|
Oil (per bbl) |
$ |
58.55 |
|
|
$ |
52.08 |
|
|
$ |
23.11 |
|
|
|
$ |
56.05 |
|
|
$ |
25.80 |
|
|
$ |
20.67 |
|
NGLs (per bbl) |
$ |
29.61 |
|
|
$ |
26.81 |
|
|
$ |
5.82 |
|
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Gas (per mcf) |
$ |
3.30 |
|
|
$ |
6.65 |
|
|
$ |
1.68 |
|
|
|
$ |
3.53 |
|
|
$ |
9.83 |
|
|
$ |
1.53 |
|
Capital expenditures(2) |
$ |
9,162 |
|
|
$ |
392 |
|
|
$ |
81 |
|
|
|
$ |
— |
|
|
$ |
1 |
|
|
$ |
145 |
|
__________
(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 |
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
Weighted-average realized sales prices: |
|
|
|
|
|
Oil without hedges ($/bbl) |
$ |
64.72 |
|
|
$ |
56.89 |
|
|
$ |
28.98 |
|
Effects of scheduled derivative settlements ($/bbl) |
$ |
(18.33 |
) |
|
$ |
(12.08 |
) |
|
$ |
25.42 |
|
Oil with hedges ($/bbl) |
$ |
46.39 |
|
|
$ |
44.81 |
|
|
$ |
54.40 |
|
Natural gas ($/mcf) |
$ |
3.39 |
|
|
$ |
7.96 |
|
|
$ |
1.62 |
|
NGLs ($/bbl) |
$ |
29.61 |
|
|
$ |
26.81 |
|
|
$ |
5.82 |
|
|
|
|
|
|
|
Average Benchmark prices: |
|
|
|
|
|
Oil (bbl) – Brent |
$ |
69.08 |
|
|
$ |
61.32 |
|
|
$ |
33.39 |
|
Oil (bbl) – WTI |
$ |
66.03 |
|
|
$ |
57.82 |
|
|
$ |
28.42 |
|
Natural gas (mmbtu) – Kern, Delivered(1) |
$ |
3.23 |
|
|
$ |
7.99 |
|
|
$ |
1.45 |
|
Natural gas (mmbtu) – Henry Hub(2) |
$ |
2.95 |
|
|
$ |
3.50 |
|
|
$ |
1.70 |
|
__________
(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 June 30, 2021, we had the following crude oil
production and gas purchases hedges.
|
Q3 2021 |
|
Q4 2021 |
|
FY 2022 |
Fixed Price Oil Swaps (Brent): |
|
|
|
|
|
Hedged volume (mbbls) |
1,318 |
|
|
1,318 |
|
|
1,095 |
|
Weighted-average price ($/bbl) |
$ |
48.66 |
|
|
$ |
48.66 |
|
|
$ |
60.00 |
|
Fixed Price Gas Purchase Swaps (Kern,
Delivered): |
|
|
|
|
|
Hedged volume (mmbtu) |
4,830,000 |
|
|
2,085,000 |
|
|
— |
|
Weighted-average price ($/mmbtu) |
$ |
2.83 |
|
|
$ |
2.95 |
|
|
$ |
— |
|
We recently entered into new 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. These capacity agreements are 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
$32 million.
OPERATING EXPENSES
|
Three Months Ended |
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
|
($ in thousands except per boe amounts) |
Lease operating expenses |
$ |
45,543 |
|
|
|
$ |
62,284 |
|
|
|
$ |
40,733 |
|
|
Electricity generation expenses |
4,712 |
|
|
|
7,648 |
|
|
|
3,022 |
|
|
Electricity sales(1) |
(6,888 |
) |
|
|
(10,069 |
) |
|
|
(4,884 |
) |
|
Transportation expenses |
1,757 |
|
|
|
1,576 |
|
|
|
1,789 |
|
|
Transportation sales(1) |
(118 |
) |
|
|
(137 |
) |
|
|
(29 |
) |
|
Marketing expenses |
44 |
|
|
|
2,227 |
|
|
|
280 |
|
|
Marketing revenues(1) |
(121 |
) |
|
|
(2,234 |
) |
|
|
(292 |
) |
|
Derivative settlements (received) paid for gas purchases(1) |
(1,913 |
) |
|
|
(26,239 |
) |
|
|
7,362 |
|
|
Total operating expenses(1) |
$ |
43,016 |
|
|
|
$ |
35,056 |
|
|
|
$ |
47,981 |
|
|
|
|
|
|
|
|
Lease operating expenses ($/boe) |
$ |
18.33 |
|
|
|
$ |
25.58 |
|
|
|
$ |
15.37 |
|
|
Electricity generation expenses ($/boe) |
1.90 |
|
|
|
3.14 |
|
|
|
1.14 |
|
|
Electricity sales ($/boe) |
(2.77 |
) |
|
|
(4.13 |
) |
|
|
(1.84 |
) |
|
Transportation expenses ($/boe) |
0.70 |
|
|
|
0.65 |
|
|
|
0.67 |
|
|
Transportation sales ($/boe) |
(0.05 |
) |
|
|
(0.06 |
) |
|
|
(0.01 |
) |
|
Marketing expenses ($/boe) |
0.02 |
|
|
|
0.92 |
|
|
|
0.11 |
|
|
Marketing revenues ($/boe) |
(0.05 |
) |
|
|
(0.92 |
) |
|
|
(0.11 |
) |
|
Derivative settlements (received) paid for gas purchases
($/boe) |
(0.77 |
) |
|
|
(10.78 |
) |
|
|
2.78 |
|
|
Total operating expenses ($/boe) |
$ |
17.31 |
|
|
|
$ |
14.40 |
|
|
|
$ |
18.11 |
|
|
Total unhedged operating expenses ($/boe)(2) |
$ |
18.08 |
|
|
|
$ |
25.18 |
|
|
|
$ |
15.33 |
|
|
|
|
|
|
|
|
Total non-energy operating expenses(3) |
$ |
12.71 |
|
|
|
$ |
12.74 |
|
|
|
$ |
12.81 |
|
|
Total energy operating expenses(4) |
$ |
4.60 |
|
|
|
$ |
1.66 |
|
|
|
$ |
5.30 |
|
|
|
|
|
|
|
|
Total mboe |
2,485 |
|
|
|
2,435 |
|
|
|
2,650 |
|
|
__________
(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 |
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
Net Oil, Natural Gas and NGLs Production Per
Day(1): |
|
|
|
|
|
Oil (mbbl/d) |
|
|
|
|
|
California |
21.7 |
|
21.9 |
|
23.4 |
Utah |
2.3 |
|
2.0 |
|
2.2 |
Colorado |
— |
|
— |
|
— |
Total oil |
24.0 |
|
23.9 |
|
25.6 |
Natural gas (mmcf/d) |
|
|
|
|
|
California |
— |
|
— |
|
— |
Utah |
10.3 |
|
10.0 |
|
11.5 |
Colorado |
7.2 |
|
6.9 |
|
7.7 |
Total natural gas |
17.5 |
|
16.9 |
|
19.2 |
NGLs (mbbl/d) |
|
|
|
|
|
California |
— |
|
— |
|
— |
Utah |
0.4 |
|
0.3 |
|
0.3 |
Colorado |
— |
|
— |
|
— |
Total NGLs |
0.4 |
|
0.3 |
|
0.3 |
Total Production (mboe/d)(2) |
27.3 |
|
27.1 |
|
29.1 |
__________
(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 June 30,
2021, the average prices of Brent oil and Henry Hub natural gas
were $69.08 per bbl and $2.95 per mmbtu respectively.
CAPITAL EXPENDITURES (ACCRUAL
BASIS)
|
Three Months Ended |
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
|
(in thousands) |
Capital expenditures (accrual basis)(1) |
$ |
43,461 |
|
|
$ |
23,569 |
|
|
$ |
16,700 |
|
__________
(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 |
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
|
($ thousands, except per share amounts) |
Net loss |
$ |
(12,881 |
) |
|
|
$ |
(21,322 |
) |
|
|
$ |
(64,901 |
) |
|
|
|
|
|
|
|
Add (Subtract): |
|
|
|
|
|
Losses on derivatives |
44,014 |
|
|
|
25,774 |
|
|
|
43,192 |
|
|
Net cash (paid) received for scheduled derivative settlements |
(37,431 |
) |
|
|
850 |
|
|
|
51,874 |
|
|
Other operating expenses (income) |
42 |
|
|
|
799 |
|
|
|
(1,192 |
) |
|
Non-recurring costs |
— |
|
|
|
— |
|
|
|
316 |
|
|
Total additions, net |
6,625 |
|
|
|
27,423 |
|
|
|
94,190 |
|
|
|
|
|
|
|
|
Income tax expense of adjustments at effective tax rate |
(37 |
) |
|
|
(474 |
) |
|
|
(24,680 |
) |
|
Adjusted Net (Loss) Income |
$ |
(6,293 |
) |
|
|
$ |
5,627 |
|
|
|
$ |
4,609 |
|
|
|
|
|
|
|
|
Basic EPS on Adjusted Net (Loss) Income |
$ |
(0.08 |
) |
|
|
$ |
0.07 |
|
|
|
$ |
0.06 |
|
|
Diluted EPS on Adjusted Net (Loss) Income |
$ |
(0.08 |
) |
|
|
$ |
0.07 |
|
|
|
$ |
0.06 |
|
|
|
|
|
|
|
|
Weighted average shares of common stock outstanding - basic |
80,471 |
|
|
|
80,115 |
|
|
|
79,795 |
|
|
Weighted average shares of common stock outstanding - diluted |
80,471 |
|
|
|
82,276 |
|
|
|
80,640 |
|
|
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 |
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
|
($ thousands) |
Net loss |
$ |
(12,881 |
) |
|
|
$ |
(21,322 |
) |
|
|
$ |
(64,901 |
) |
|
Add (Subtract): |
|
|
|
|
|
Interest expense |
8,217 |
|
|
|
8,485 |
|
|
|
8,676 |
|
|
Income tax benefit |
(72 |
) |
|
|
(376 |
) |
|
|
(22,623 |
) |
|
Depreciation, depletion and amortization |
35,850 |
|
|
|
33,840 |
|
|
|
37,512 |
|
|
Losses on derivatives |
44,014 |
|
|
|
25,774 |
|
|
|
43,192 |
|
|
Net cash (paid) received for scheduled derivative settlements |
(37,431 |
) |
|
|
850 |
|
|
|
51,874 |
|
|
Other operating expense (income) |
42 |
|
|
|
799 |
|
|
|
(1,192 |
) |
|
Stock compensation expense |
2,860 |
|
|
|
3,779 |
|
|
|
4,579 |
|
|
Non-recurring costs |
— |
|
|
|
— |
|
|
|
316 |
|
|
Adjusted EBITDA |
$ |
40,599 |
|
|
|
$ |
51,829 |
|
|
|
$ |
57,433 |
|
|
Net cash paid (received) for scheduled derivative settlements |
37,431 |
|
|
|
(850 |
) |
|
|
(51,874 |
) |
|
Adjusted EBITDA Unhedged |
$ |
78,030 |
|
|
|
$ |
50,979 |
|
|
|
$ |
5,559 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
$ |
21,429 |
|
|
|
$ |
38,430 |
|
|
|
$ |
41,939 |
|
|
Add (Subtract): |
|
|
|
|
|
Cash interest payments |
288 |
|
|
|
14,637 |
|
|
|
648 |
|
|
Non-recurring costs |
— |
|
|
|
— |
|
|
|
316 |
|
|
Other changes in operating assets and liabilities |
18,882 |
|
|
|
(1,238 |
) |
|
|
14,530 |
|
|
Adjusted EBITDA |
$ |
40,599 |
|
|
|
$ |
51,829 |
|
|
|
$ |
57,433 |
|
|
Net cash paid (received) for scheduled derivative settlements |
37,431 |
|
|
|
(850 |
) |
|
|
(51,874 |
) |
|
Adjusted EBITDA Unhedged |
$ |
78,030 |
|
|
|
$ |
50,979 |
|
|
|
$ |
5,559 |
|
|
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 |
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
|
($ thousands) |
Adjusted EBITDA |
$ |
40,599 |
|
|
|
$ |
51,829 |
|
|
|
$ |
57,433 |
|
|
Subtract: |
|
|
|
|
|
Capital expenditures - accrual basis(1) |
(43,461 |
) |
|
|
(23,569 |
) |
|
|
(16,700 |
) |
|
Interest expense |
(8,217 |
) |
|
|
(8,485 |
) |
|
|
(8,676 |
) |
|
Cash dividends declared |
(3,219 |
) |
|
|
(3,474 |
) |
|
|
— |
|
|
Levered Free Cash Flow |
$ |
(14,298 |
) |
|
|
$ |
16,301 |
|
|
|
$ |
32,057 |
|
|
Net cash paid (received) for scheduled derivative settlements |
37,431 |
|
|
|
(850 |
) |
|
|
(51,874 |
) |
|
Levered Free Cash Flow Unhedged |
$ |
23,133 |
|
|
|
$ |
15,451 |
|
|
|
$ |
(19,817 |
) |
|
__________
(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 |
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
|
($ in thousands except per mboe amounts) |
General and administrative expenses |
$ |
16,065 |
|
|
|
$ |
17,070 |
|
|
|
$ |
18,777 |
|
|
Subtract: |
|
|
|
|
|
Non-cash stock compensation expense (G&A portion) |
(2,763 |
) |
|
|
(3,669 |
) |
|
|
(4,380 |
) |
|
Non-recurring costs |
— |
|
|
|
— |
|
|
|
(316 |
) |
|
Adjusted General and Administrative Expenses |
$ |
13,302 |
|
|
|
$ |
13,401 |
|
|
|
$ |
14,081 |
|
|
|
|
|
|
|
|
General and administrative expenses ($/boe) |
$ |
6.46 |
|
|
|
$ |
7.01 |
|
|
|
$ |
7.09 |
|
|
Subtract: |
|
|
|
|
|
Non-cash stock compensation expense ($/boe) |
(1.11 |
) |
|
|
(1.51 |
) |
|
|
(1.65 |
) |
|
Non-recurring costs ($/boe) |
— |
|
|
|
— |
|
|
|
(0.12 |
) |
|
Adjusted General and Administrative Expenses ($/boe) |
$ |
5.35 |
|
|
|
$ |
5.50 |
|
|
|
$ |
5.31 |
|
|
|
|
|
|
|
|
Total mboe |
2,485 |
|
|
|
2,435 |
|
|
|
2,650 |
|
|
FULL YEAR 2021 GUIDANCE
|
Low |
|
High |
Average Daily Production (mboe/d) |
27.0 |
|
29.0 |
Oil as % of Production |
|
~89% |
|
Operating Expenses ($/boe) |
$17.25 |
|
$18.55 |
Taxes, Other than Income Taxes ($/boe) |
$3.75 |
|
$4.25 |
Adjusted General & Administrative (G&A) expenses
($/boe) |
$5.50 |
|
$6.25 |
Capital Expenditures ($ millions) |
$120 |
|
$130 |
New Wells Drilled |
170 |
|
200 |
Contact
Contact: bry
Todd Crabtree - Manager, Investor Relations
(661) 616-3811
ir@bry.com
Berry (NASDAQ:BRY)
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