Berry Corporation (NASDAQ: BRY) (“Berry” or the “Company”) today
reported net income of $53 million or $0.65 per diluted share and
adjusted net income of $33 million or $0.40 per diluted share for
the third quarter of 2019. In addition, the Board approved a fourth
quarter dividend of $0.12 per share, as it has done each quarter
since becoming a public company in 2018.
Highlights for the Quarter
- Adjusted EBITDA of $84 million and Unhedged Adjusted EBITDA of
$69 million
- Third quarter production of 29,600 BOE/D up 7.7% compared to
second quarter
- Third quarter production mix 87% oil with September improving
to 88% oil
- Capital Expenditures of $63 million with fourth quarter
expected to be $35-$40 million
- Added to 2019 and 2020 oil hedges; more than 60% oil production
covered for Q4 2019 and more than 50% for 2020
- Full-year production and spending are on track for mid-point of
guidance
“It is clear from Berry’s strong third quarter production that
our California oil assets respond to investment and the capital
deployed during the first half of the year is now driving value. We
expect Berry’s production for the year will be at the mid-point of
our guidance, while spending will come in just under the mid-point
of guidance,” stated Trem Smith, Berry Board Chair, Chief Executive
Officer and President. “Since becoming a public company in 2018, we
have grown production and consistently paid a substantial dividend
within levered free cash flow. Our focus continues to be on
responsible production while creating value for our shareholders
through a combination of growth and return of capital. This year we
expect to see double-digit production growth at about 12%
company-wide, provide an attractive dividend yield, and buy back 4%
of our stock. We are well positioned to continue this strategy in
2020 as we are well hedged for the remainder of 2019 and throughout
2020. In short, Berry is in a strong position to continue to
create and deliver top-tier value in the market.”
Third Quarter Results
Adjusted EBITDA, on a hedged basis, increased to $84 million in
the third quarter from $63 million in the second quarter. Results
include the impact of higher production, lower oil prices, higher
oil hedge settlements received and lower gas hedge settlement
payments. Adjusted EBITDA, on an unhedged basis, was $69 million in
the third quarter compared to $66 million in the second
quarter.
Average daily production was 8% higher in the third quarter
compared to the second quarter driven by our development capital
spending in 2019. Our California production of 23.0 MBoe/d for the
third quarter of 2019 was up 10% compared to the second quarter of
2019.
California oil prices before hedges for the third quarter
averaged 95% of Brent, or $59.00/Bbl which were 8% lower than the
$63.91/Bbl in the second quarter. The Company realized oil prices
before hedges of $57.92/Bbl which was 6% lower than the second
quarter average of $61.69/Bbl.
For the third quarter on an unhedged basis, Operating Expenses
("OpEx") decreased to $18.13 per Boe for the third quarter 2019
compared to $18.94 for the second quarter 2019. The decrease
includes a net $0.47 per Boe benefit from higher seasonal
electricity sales and a $0.44 per Boe reduction in lease operating
expense.
Additionally, operating expenses, including hedge effects,
decreased to $18.90 per Boe in the third quarter 2019 from $20.38
in the second quarter due to these same factors and a $0.67 per Boe
decrease in gas hedge settlement payments.
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.
General and administrative expenses were $6.04 per Boe for the
third quarter compared to $6.47 per Boe for the second quarter.
Adjusted general and administrative expenses were $5.13 per Boe for
the third quarter compared to $4.92 per Boe for the second quarter
primarily due to insurance renewals and continued development and
growth of our Corporate Affairs department and its activities.
“We have been building our capabilities and expertise in our
Corporate Affairs department to support our participation in the
regulatory, political and legislative processes primarily in
California. Initial achievements are an outcome of the
team’s ongoing efforts to partner with the state to responsibly
deliver affordable energy to its citizens and become less reliant
on foreign energy sources. As a result of this initiative, as well
as our continuing efforts to improve our internal systems and
comply with public company requirements, our full year adjusted
G&A will be on the high side of guidance. A major focus in 2020
will be on reducing overall general and administrative expenses on
a per Boe basis,” said Cary Baetz, Chief Financial Officer,
Executive Vice President and Board Director.
Taxes, other than income taxes were $3.40 per Boe for the third
quarter compared to $4.54 per Boe in the second quarter, due to
lower market rates for greenhouse gas allowance requirements.
Capital expenditures totaled $63 million for the third quarter
compared to $57 million for the second quarter and was largely
focused on California drilling, as well as equipping and hydraulic
stimulation of previously drilled wells.
Net income for the third quarter 2019 was $53 million compared
to $32 million in the second quarter. This difference was largely
driven by increased production and derivative gains that offset
lower oil prices. Adjusted net income was $33 million for the third
quarter, representing a 63% increase over the second quarter of
2019. The increase was generally attributable to the same factors
impacting Adjusted EBITDA.
At September 30, 2019, funds available under our $400 million
reserve-based revolver were $381 million with $9 million of
outstanding letters of credit and borrowings of $10 million on our
revolver in order to fund monthly working capital fluctuations and
asset retirement payments during the third quarter. The Company
expects to have little to no revolver borrowings by year-end.
“We are very pleased that our projected
production for 2019 will be at the mid-point of our guidance,
especially when taking into account that capital spending is
expected to come in below the mid-point of the range. While our
operating costs continue to improve, we expect operating expenses
to be at the higher side of guidance for the year due to the
unseasonably high gas prices experienced in the first quarter,”
stated Baetz.
Dividend Announcement
On November 6, 2019 the Board declared a regular dividend for
the fourth quarter at a rate of $0.12 per share on the Company’s
outstanding common stock. This is the Company's sixth regular
quarterly dividend, and the Company intends to pay a similar
dividend in future quarters, subject to Board approval.
The fourth quarter dividend is payable on January 15, 2019 to
shareholders of record at the close of business on December 13,
2019.
Earnings Conference Call
The Company will host a conference call November 7, 2019 to
discuss these results:
Live Call Date: |
Thursday, November 7, 2019 |
Live Call Time: |
5:00 p.m. Eastern Time (2 p.m.
Pacific Time) |
Live Call Dial-in: |
877-491-5169 from the
U.S. |
|
720-405-2254 from
international locations |
Live Call Passcode: |
2845519 |
|
|
A live audio webcast will be available on the “Investors”
section of Berry’s website at berrypetroleum.com/investors.An
audio replay will be available shortly after the broadcast:
Replay Dates: |
Through Thursday, November 21, 2019 |
Replay Dial-in: |
855-859-2056 from the
U.S. |
|
404-537-3406 from
international locations |
Replay Passcode: |
2845519 |
|
|
A replay of the audio webcast will also be archived on the
“Investors” section of Berry’s website at bry.com/investors.
In addition, an investor presentation will be available on the
Company’s website.
About Berry Petroleum
Berry Corporation 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 www.bry.com.
Forward Looking Statements
The information in this press release includes
forward-looking statements that involve risks and uncertainties
that could materially affect our expected results of operations,
liquidity, cash flows and business prospects. Such statements
specifically include our expectations as to our future:
- financial position,
- liquidity,
- cash flows,
- results of operations and business strategy,
- potential acquisition opportunities,
- other plans and objectives for operations,
- maintenance capital requirements,
- expected production and costs,
- reserves,
- hedging activities,
- return of capital,
- capital investments and other guidance.
Actual results may differ from expectations,
sometimes materially, and reported results should not be considered
an indication of future performance. Factors (but not all the
factors) that could cause results to differ include:
- volatility of oil, natural gas and natural gas liquids (NGL)
prices;
- our ability to obtain permits and otherwise to meet our
proposed drilling schedule and to successfully drill wells that
produce oil and natural gas in commercially viable quantities;
- price and availability of natural gas and electricity;
- changes in laws or regulations;
- our ability to use derivative instruments to manage commodity
price risk;
- the impact of environmental, health and safety, and other
governmental regulations, and of current or pending or future
legislation;
- uncertainties associated with estimating proved reserves and
related future cash flows;
- our ability to replace our reserves through exploration and
development activities;
- timely and available drilling and completion equipment and crew
availability and access to necessary resources for drilling,
completing and operating well;
- our ability to make acquisitions and successfully integrate any
acquired businesses;
- catastrophic events; and
- other material risks that appear in the Risk Factors section of
the prospectus filed with the SEC in connection with our initial
public offering.
You can typically identify forward-looking
statements by words such as aim, anticipate, achievable, believe,
continue, could, 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. We undertake no responsibility to publicly release the
result of any revision of our forward-looking statements after the
date they are made.
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, 2019 |
|
June 30, 2019 |
|
September 30, 2018 |
|
($ and shares in thousands, except per share amounts) |
Statement of
Operations Data: |
|
|
|
|
|
Revenues and
other: |
|
|
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
141,250 |
|
|
$ |
136,908 |
|
|
$ |
147,004 |
|
Electricity sales |
7,460 |
|
|
5,364 |
|
|
14,268 |
|
Gains (losses) on oil derivatives |
45,509 |
|
|
27,276 |
|
|
(18,994 |
) |
Marketing revenues |
413 |
|
|
414 |
|
|
486 |
|
Other revenues |
40 |
|
|
104 |
|
|
183 |
|
Total revenues and other |
194,672 |
|
|
170,066 |
|
|
142,947 |
|
|
|
|
|
|
|
Expenses and
other: |
|
|
|
|
|
Lease operating expenses |
50,957 |
|
|
47,879 |
|
|
51,649 |
|
Electricity generation expenses |
3,781 |
|
|
3,164 |
|
|
6,130 |
|
Transportation expenses |
2,067 |
|
|
1,694 |
|
|
2,318 |
|
Marketing expenses |
398 |
|
|
421 |
|
|
437 |
|
General and administrative expenses |
16,434 |
|
|
16,158 |
|
|
13,429 |
|
Depreciation, depletion and amortization |
27,664 |
|
|
23,654 |
|
|
21,729 |
|
Taxes, other than income taxes |
9,249 |
|
|
11,348 |
|
|
8,317 |
|
Losses (gains) on natural gas derivatives |
3,008 |
|
|
9,449 |
|
|
(1,879 |
) |
Other operating (income) expenses |
(550 |
) |
|
3,119 |
|
|
400 |
|
Total expenses and other |
113,008 |
|
|
116,886 |
|
|
102,530 |
|
|
|
|
|
|
|
Other income
(expenses): |
|
|
|
|
|
Interest expense |
(8,597 |
) |
|
(8,961 |
) |
|
(9,877 |
) |
Other, net |
(77 |
) |
|
— |
|
|
347 |
|
Total other expenses |
(8,674 |
) |
|
(8,961 |
) |
|
(9,530 |
) |
Reorganization items, net |
(170 |
) |
|
(26 |
) |
|
13,781 |
|
Income before income
taxes |
72,820 |
|
|
44,193 |
|
|
44,668 |
|
Income tax expense |
20,171 |
|
|
12,221 |
|
|
7,683 |
|
Net
income |
52,649 |
|
|
31,972 |
|
|
36,985 |
|
Series A preferred stock
dividends |
— |
|
|
— |
|
|
(86,642 |
) |
Net income (loss)
attributable to common stockholders |
$ |
52,649 |
|
|
$ |
31,972 |
|
|
$ |
(49,657 |
) |
|
|
|
|
|
|
Net income (loss) per
share attributable to common stockholders |
|
|
|
|
|
Basic |
$ |
0.65 |
|
|
$ |
0.39 |
|
|
$ |
(0.70 |
) |
Diluted |
$ |
0.65 |
|
|
$ |
0.39 |
|
|
$ |
(0.70 |
) |
|
|
|
|
|
|
Weighted-average common shares
outstanding - basic |
80,982 |
|
|
81,519 |
|
|
70,940 |
|
Weighted-average common shares
outstanding - diluted |
81,051 |
|
|
81,683 |
|
|
70,940 |
|
|
|
|
|
|
|
Adjusted net income |
$ |
32,760 |
|
|
$ |
20,046 |
|
|
$ |
40,529 |
|
Adjusted EBITDA |
$ |
83,931 |
|
|
$ |
62,756 |
|
|
$ |
81,736 |
|
Adjusted EBITDA unhedged |
$ |
68,778 |
|
|
$ |
66,082 |
|
|
$ |
82,788 |
|
Levered free cash flow |
$ |
2,126 |
|
|
$ |
(12,560 |
) |
|
$ |
24,185 |
|
Levered free cash flow
unhedged |
$ |
(13,027 |
) |
|
$ |
(9,234 |
) |
|
$ |
25,237 |
|
Adjusted general and
administrative expenses |
$ |
13,940 |
|
|
$ |
12,277 |
|
|
$ |
10,706 |
|
Effective Tax Rate |
28 |
% |
|
28 |
% |
|
17 |
% |
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
September 30, 2019 |
|
June 30, 2019 |
|
September 30, 2018 |
|
($ in thousands) |
Cash Flow
Data: |
|
|
|
|
|
Net cash provided by operating
activities |
$ |
65,320 |
|
|
$ |
71,362 |
|
|
$ |
56,880 |
|
Net cash used in investing
activities |
$ |
(60,285 |
) |
|
$ |
(56,574 |
) |
|
$ |
(40,028 |
) |
Net cash used in financing
activities |
$ |
(5,262 |
) |
|
$ |
(16,223 |
) |
|
$ |
(16,250 |
) |
|
September 30, 2019 |
|
December 31, 2018 |
|
($ and shares in thousands) |
Balance Sheet
Data: |
|
|
|
Total current assets |
$ |
130,037 |
|
|
$ |
229,022 |
|
Total property, plant and
equipment, net |
$ |
1,607,810 |
|
|
$ |
1,442,708 |
|
Total current liabilities |
$ |
148,894 |
|
|
$ |
144,118 |
|
Long-term debt |
$ |
402,290 |
|
|
$ |
391,786 |
|
Total equity |
$ |
997,344 |
|
|
$ |
1,006,446 |
|
Outstanding common stock
shares as of |
80,997 |
|
|
81,202 |
|
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) |
|
Rockies (Uinta and Piceance basins) |
|
Three Months Ended |
|
Three Months Ended |
|
September 30, 2019 |
|
June 30, 2019 |
|
September 30, 2018 |
|
September 30, 2019 |
|
June 30, 2019 |
|
September 30, 2018 |
($ in thousands, except prices) |
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids sales |
$ |
124,540 |
|
|
$ |
120,917 |
|
|
$ |
124,007 |
|
|
$ |
16,711 |
|
|
$ |
15,991 |
|
|
$ |
22,998 |
|
Operating income(a) |
$ |
49,185 |
|
|
$ |
47,809 |
|
|
$ |
62,791 |
|
|
$ |
1,241 |
|
|
$ |
954 |
|
|
$ |
7,176 |
|
Depreciation, depletion, and
amortization (DD&A) |
$ |
24,360 |
|
|
$ |
20,460 |
|
|
$ |
17,908 |
|
|
$ |
3,303 |
|
|
$ |
3,194 |
|
|
$ |
3,268 |
|
Average daily production
(MBoe/d) |
23.0 |
|
|
20.8 |
|
|
19.5 |
|
|
6.6 |
|
|
6.6 |
|
|
7.9 |
|
Production (oil % of
total) |
100 |
% |
|
100 |
% |
|
100 |
% |
|
41 |
% |
|
41 |
% |
|
35 |
% |
Realized sales prices: |
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
$ |
59.00 |
|
|
$ |
63.91 |
|
|
$ |
69.13 |
|
|
$ |
48.82 |
|
|
$ |
44.92 |
|
|
$ |
57.45 |
|
NGLs (per Bbl) |
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
12.10 |
|
|
$ |
16.86 |
|
|
$ |
37.75 |
|
Gas (per Mcf) |
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
2.12 |
|
|
$ |
2.16 |
|
|
$ |
2.55 |
|
Capital expenditures(b) |
$ |
59,076 |
|
|
$ |
52,374 |
|
|
$ |
35,124 |
|
|
$ |
2,064 |
|
|
$ |
1,443 |
|
|
$ |
2,624 |
|
__________
(a) Operating income comprises oil, natural gas
and NGL sales, offset by operating expenses, general and
administrative expenses, DD&A, and taxes, other than income
taxes.(b) Excludes corporate capital expenditures.
COMMODITY PRICING
|
Three Months Ended |
|
September 30, 2019 |
|
June 30, 2019 |
|
September 30, 2018 |
Realized Sales Prices
(weighted-average) |
|
|
|
|
|
Oil without hedge ($/Bbl) |
$ |
57.92 |
|
|
$ |
61.69 |
|
|
$ |
67.67 |
|
Effects of scheduled
derivative settlements ($/Bbl) |
$ |
7.31 |
|
|
$ |
0.13 |
|
|
$ |
(0.44 |
) |
Oil with hedge ($/Bbl) |
$ |
65.23 |
|
|
$ |
61.82 |
|
|
$ |
67.23 |
|
Natural gas ($/Mcf) |
$ |
2.12 |
|
|
$ |
2.16 |
|
|
$ |
2.55 |
|
NGLs ($/Bbl) |
$ |
12.10 |
|
|
$ |
16.86 |
|
|
$ |
37.75 |
|
|
|
|
|
|
|
Index
Prices |
|
|
|
|
|
Brent oil ($/Bbl) |
$ |
62.03 |
|
|
$ |
68.47 |
|
|
$ |
75.84 |
|
WTI oil ($/Bbl) |
$ |
56.33 |
|
|
$ |
59.86 |
|
|
$ |
69.60 |
|
Kern, Delivered natural gas
($/MMBtu)(a) |
$ |
2.50 |
|
|
$ |
2.07 |
|
|
$ |
4.12 |
|
__________
(a) Kern, Delivered Index is
the relevant index used for gas purchases in California.
CURRENT HEDGING SUMMARY
As of September 30, 2019, we had the
following crude oil production and gas purchases hedges, with no
changes through October 31, 2019.
|
Q4 2019 |
|
FY 2020 |
|
FY 2021 |
Fixed Price Oil Swaps
(Brent): |
|
|
|
|
|
Hedged volume (MBbls) |
1,656 |
|
|
5,856 |
|
|
730 |
|
Weighted average price ($/Bbl) |
$ |
70.20 |
|
|
$ |
64.25 |
|
|
$ |
58.50 |
|
Fixed Price Oil Swaps
(WTI): |
|
|
|
|
|
Hedged volume (MBbls) |
92 |
|
|
121 |
|
|
— |
|
Weighted average price ($/Bbl) |
$ |
61.75 |
|
|
$ |
61.75 |
|
|
$ |
— |
|
Oil basis differential
swaps (Brent-WTI basis swaps): |
|
|
|
|
|
Hedged volume (MBbls) |
46 |
|
|
— |
|
|
— |
|
Weighted average price ($/Bbl) |
$ |
(1.29 |
) |
|
$ |
— |
|
|
$ |
— |
|
Sold Oil Call Options
(Brent): |
|
|
|
|
|
Hedged volume (MBbls) |
92 |
|
|
— |
|
|
— |
|
Weighted average price ($/Bbl) |
$ |
81.00 |
|
|
$ |
— |
|
|
$ |
— |
|
Fixed Price Gas
Purchase Swaps (Kern, Delivered): |
|
|
|
|
|
Hedged volume (MMBtu) |
4,905,000 |
|
|
17,385,000 |
|
|
900,000 |
|
Weighted average price ($/MMBtu) |
$ |
2.90 |
|
|
$ |
2.88 |
|
|
$ |
2.50 |
|
Fixed Price Gas
Purchase Swaps (SoCal Citygate): |
|
|
|
|
|
Hedged volume (MMBtu) |
460,000 |
|
|
1,525,000 |
|
|
— |
|
Weighted average price ($/MMBtu) |
$ |
3.80 |
|
|
$ |
3.80 |
|
|
$ |
— |
|
OPERATING EXPENSES
|
Three Months Ended |
|
September 30, 2019 |
|
June 30, 2019 |
|
September 30, 2018 |
|
($ in thousands except per Boe amounts) |
Lease operating expenses |
$ |
50,957 |
|
|
$ |
47,879 |
|
|
$ |
51,649 |
|
Electricity generation
expenses |
3,781 |
|
|
3,164 |
|
|
6,130 |
|
Electricity sales(a) |
(7,460 |
) |
|
(5,364 |
) |
|
(14,268 |
) |
Transportation expenses |
2,067 |
|
|
1,694 |
|
|
2,318 |
|
Transportation sales(a) |
(40 |
) |
|
(104 |
) |
|
(183 |
) |
Marketing expenses |
398 |
|
|
421 |
|
|
437 |
|
Marketing revenues(a) |
(413 |
) |
|
(414 |
) |
|
(486 |
) |
Derivative settlements paid
for gas purchases(a) |
2,088 |
|
|
3,593 |
|
|
— |
|
Total operating expenses(a) |
$ |
51,378 |
|
|
$ |
50,869 |
|
|
$ |
45,597 |
|
|
|
|
|
|
|
Lease operating expenses
($/Boe) |
$ |
18.74 |
|
|
$ |
19.18 |
|
|
$ |
20.50 |
|
Electricity generation
expenses ($/Boe) |
1.39 |
|
|
1.27 |
|
|
2.43 |
|
Electricity sales ($/Boe) |
(2.74 |
) |
|
(2.15 |
) |
|
(5.66 |
) |
Transportation expenses
($/Boe) |
0.76 |
|
|
0.68 |
|
|
0.92 |
|
Transportation sales
($/Boe) |
(0.01 |
) |
|
(0.04 |
) |
|
(0.07 |
) |
Marketing expenses
($/Boe) |
0.15 |
|
|
0.17 |
|
|
0.17 |
|
Marketing revenues
($/Boe) |
(0.15 |
) |
|
(0.17 |
) |
|
(0.19 |
) |
Derivative settlements paid
for gas purchases ($/Boe) |
0.77 |
|
|
1.44 |
|
|
— |
|
Total operating expenses ($/Boe) |
$ |
18.90 |
|
|
$ |
20.38 |
|
|
$ |
18.10 |
|
Total unhedged operating expenses ($/Boe)(b) |
$ |
18.13 |
|
|
$ |
18.94 |
|
|
$ |
18.10 |
|
|
|
|
|
|
|
Total MBoe |
2,719 |
|
|
2,497 |
|
|
2,520 |
|
__________
(a) 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
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, reported in "Other
Revenues", relates to water and other liquids that we transport on
our systems on behalf of third parties.
(b) Total unhedged operating
expenses equals total operating expenses less the derivatives
settlements paid for gas purchases.
PRODUCTION STATISTICS
|
Three Months Ended |
|
September 30, 2019 |
|
June 30, 2019 |
|
September 30, 2018 |
Net Oil, Natural Gas
and NGLs Production Per
Day(a): |
|
|
|
|
|
Oil
(MBbl/d) |
|
|
|
|
|
California |
23.0 |
|
20.8 |
|
19.5 |
Rockies |
2.7 |
|
2.7 |
|
2.8 |
East Texas(c) |
— |
|
— |
|
— |
Total oil |
25.7 |
|
23.5 |
|
22.3 |
Natural gas
(MMcf/d) |
|
|
|
|
|
California |
— |
|
— |
|
— |
Rockies |
20.9 |
|
20.8 |
|
23.1 |
East Texas(c) |
— |
|
— |
|
4.1 |
Total natural gas |
20.9 |
|
20.8 |
|
27.4 |
NGLs
(MBbl/d) |
|
|
|
|
|
California |
— |
|
— |
|
— |
Rockies |
0.4 |
|
0.4 |
|
0.5 |
East Texas(c) |
— |
|
— |
|
— |
Total NGLs |
0.4 |
|
0.4 |
|
0.5 |
Total Production
(MBoe/d)(b) |
29.6 |
|
27.4 |
|
27.4 |
__________
(a) Production represents
volumes sold during the period.(b) 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, 2019, the average prices of Brent oil and Henry
Hub natural gas were $62.03 per Bbl and $2.38 per MMBtu,
respectively, resulting in an oil-to-gas ratio of approximately 4
to 1 on an energy equivalent basis.(c) On
November 30, 2018, we sold our non-core gas-producing properties
and related assets located in the East Texas basin.
CAPITAL EXPENDITURES (ACCRUAL BASIS)
|
Three Months Ended |
|
September 30, 2019 |
|
June 30, 2019 |
|
September 30, 2018 |
|
(in thousands) |
Capital expenditures (accrual basis) |
$ |
63,488 |
|
|
$ |
56,645 |
|
|
$ |
40,243 |
|
NON-GAAP FINANCIAL MEASURES AND
RECONCILIATIONS
Adjusted EBITDA and Adjusted Net Income (Loss)
are not measures of net income (loss) and Levered Free Cash Flow is
not a measure of cash flow, in all cases, as determined by GAAP.
Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash
Flow 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 other unusual, out-of-period and
infrequent items, including restructuring costs and reorganization
items. We define Levered Free Cash Flow as Adjusted EBITDA less
capital expenditures, interest expense and dividends.
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 for maintenance and
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.
Adjusted Net Income (Loss) excludes the impact
of unusual, out-of-period 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 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, out-of-period and infrequent items,
including restructuring costs and reorganization items and the
income tax expense or benefit of these adjustments using our
effective tax rate.
While Adjusted EBITDA, Adjusted Net Income
(Loss) and Levered Free Cash Flow are non-GAAP measures, the
amounts included in the calculation of Adjusted EBITDA, Adjusted
Net Income (Loss) and Levered Free Cash Flow 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. 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
Net Income (Loss) and Levered Free Cash Flow may not be comparable
to other similarly titled measures used by other companies.
Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash
Flow should be read in conjunction with the information contained
in our financial statements prepared in accordance with GAAP.
Adjusted General and Administrative Expenses is
a supplemental non-GAAP financial measure that is used by
management. We define Adjusted General and Administrative Expenses
as general and administrative expenses adjusted for restructuring
and other non-recurring costs and non-cash stock compensation
expense. 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. Adjusted General and
Administrative Expenses should not be considered as an alternative
to, or more meaningful than, general and administrative expenses as
determined in accordance with GAAP. Our computations of Adjusted
General and Administrative Expenses may not be comparable to other
similarly titled measures of other companies.
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, 2019 |
|
June 30, 2019 |
|
September 30, 2018 |
|
($ thousands, except per share amounts) |
Net income |
$ |
52,649 |
|
|
$ |
31,972 |
|
|
$ |
36,985 |
|
|
|
|
|
|
|
Add (Subtract): |
|
|
|
|
|
(Gains) losses on oil and natural gas derivatives |
(42,501 |
) |
|
(17,827 |
) |
|
17,115 |
|
Net cash received (paid) for scheduled derivative settlements |
15,153 |
|
|
(3,326 |
) |
|
(1,052 |
) |
Other operating (income) expenses |
(550 |
) |
|
3,119 |
|
|
400 |
|
Restructuring and other non-recurring costs |
219 |
|
|
1,513 |
|
|
1,598 |
|
Reorganization items, net |
170 |
|
|
26 |
|
|
(13,781 |
) |
Total (subtractions) additions, net |
(27,509 |
) |
|
(16,495 |
) |
|
4,280 |
|
|
|
|
|
|
|
Income tax benefit (expense)
of adjustments at effective tax rate |
7,620 |
|
|
4,569 |
|
|
(736 |
) |
Adjusted net income |
$ |
32,760 |
|
|
$ |
20,046 |
|
|
$ |
40,529 |
|
|
|
|
|
|
|
Basic EPS on adjusted
income |
$ |
0.40 |
|
|
$ |
0.25 |
|
|
$ |
0.57 |
|
Diluted EPS on adjusted net
income |
$ |
0.40 |
|
|
$ |
0.25 |
|
|
$ |
0.48 |
|
|
|
|
|
|
|
Weighted average shares
outstanding - basic |
80,982 |
|
|
81,519 |
|
|
70,940 |
|
Weighted average shares
outstanding - diluted |
81,051 |
|
|
81,683 |
|
|
84,487 |
|
ADJUSTED EBITDA AND ADJUSTED EBITDA
UNHEDGED
The following tables present a reconciliation of
the GAAP financial measures of net income (loss) and net cash
(used) by operating activities to the non-GAAP financial measures
of Adjusted EBITDA and Adjusted EBITDA Unhedged.
|
Three Months Ended |
|
September 30, 2019 |
|
June 30, 2019 |
|
September 30, 2018 |
|
($ thousands) |
Net income |
$ |
52,649 |
|
|
$ |
31,972 |
|
|
$ |
36,985 |
|
Add (Subtract): |
|
|
|
|
|
Interest expense |
8,597 |
|
|
8,961 |
|
|
9,877 |
|
Income tax expense |
20,171 |
|
|
12,221 |
|
|
7,683 |
|
Depreciation, depletion and amortization |
27,664 |
|
|
23,654 |
|
|
21,729 |
|
Derivative (gain) loss |
(42,501 |
) |
|
(17,827 |
) |
|
17,115 |
|
Net cash received (paid) for scheduled derivative settlements |
15,153 |
|
|
(3,326 |
) |
|
(1,052 |
) |
Other operating (income) expense |
(550 |
) |
|
3,119 |
|
|
400 |
|
Stock compensation expense |
2,360 |
|
|
2,443 |
|
|
1,182 |
|
Restructuring and other non-recurring costs |
219 |
|
|
1,513 |
|
|
1,598 |
|
Reorganization items, net |
170 |
|
|
26 |
|
|
(13,781 |
) |
Adjusted EBITDA |
$ |
83,931 |
|
|
$ |
62,756 |
|
|
$ |
81,736 |
|
Net cash (received) paid for
scheduled derivative settlements |
(15,153 |
) |
|
3,326 |
|
|
1,052 |
|
Adjusted EBITDA unhedged |
$ |
68,778 |
|
|
$ |
66,082 |
|
|
$ |
82,788 |
|
|
|
|
|
|
|
Net cash provided by operating
activities |
$ |
65,320 |
|
|
$ |
71,362 |
|
|
$ |
56,880 |
|
Add (Subtract): |
|
|
|
|
|
Cash interest payments |
14,864 |
|
|
1,272 |
|
|
15,902 |
|
Cash reorganization item receipts |
— |
|
|
— |
|
|
(345 |
) |
Restructuring and other non-recurring costs |
219 |
|
|
1,513 |
|
|
1,598 |
|
Other changes in operating assets and liabilities |
3,528 |
|
|
(11,391 |
) |
|
7,701 |
|
Adjusted EBITDA |
$ |
83,931 |
|
|
$ |
62,756 |
|
|
$ |
81,736 |
|
Net cash (received) paid for
scheduled derivative settlements |
(15,153 |
) |
|
3,326 |
|
|
1,052 |
|
Adjusted EBITDA unhedged |
$ |
68,778 |
|
|
$ |
66,082 |
|
|
$ |
82,788 |
|
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, 2019 |
|
June 30, 2019 |
|
September 30, 2018 |
|
($ thousands) |
Adjusted EBITDA |
$ |
83,931 |
|
|
$ |
62,756 |
|
|
$ |
81,736 |
|
Subtract: |
|
|
|
|
|
Capital expenditures - accrual basis |
(63,488 |
) |
|
(56,645 |
) |
|
(40,243 |
) |
Interest expense |
(8,597 |
) |
|
(8,961 |
) |
|
(9,877 |
) |
Cash dividends declared |
(9,720 |
) |
|
(9,710 |
) |
|
(7,431 |
) |
Levered free cash flow |
$ |
2,126 |
|
|
$ |
(12,560 |
) |
|
$ |
24,185 |
|
Net cash (received) paid for
scheduled derivative settlements |
(15,153 |
) |
|
3,326 |
|
|
1,052 |
|
Levered free cash flow
unhedged |
$ |
(13,027 |
) |
|
$ |
(9,234 |
) |
|
$ |
25,237 |
|
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, 2019 |
|
June 30, 2019 |
|
September 30, 2018 |
|
($ in thousands except per MBoe amounts) |
General and administrative expenses |
$ |
16,434 |
|
|
$ |
16,158 |
|
|
$ |
13,429 |
|
Subtract: |
|
|
|
|
|
Restructuring and other non-recurring costs |
(219 |
) |
|
(1,513 |
) |
|
(1,598 |
) |
Non-cash stock compensation expense (G&A portion) |
(2,275 |
) |
|
(2,368 |
) |
|
(1,125 |
) |
Adjusted general and
administrative expenses |
$ |
13,940 |
|
|
$ |
12,277 |
|
|
$ |
10,706 |
|
|
|
|
|
|
|
General and administrative
expenses ($/MBoe) |
$ |
6.04 |
|
|
$ |
6.47 |
|
|
$ |
5.33 |
|
Subtract: |
|
|
|
|
|
Restructuring and other non-recurring costs ($/MBoe) |
(0.08 |
) |
|
(0.61 |
) |
|
(0.63 |
) |
Non-cash stock compensation expense ($/MBoe) |
(0.84 |
) |
|
(0.95 |
) |
|
(0.45 |
) |
Adjusted general and
administrative expenses ($/MBoe) |
$ |
5.13 |
|
|
$ |
4.92 |
|
|
$ |
4.25 |
|
|
|
|
|
|
|
Total MBoe |
2,719 |
|
|
2,497 |
|
|
2,520 |
|
Contact
Contact: Berry Corporation
Todd Crabtree - Manager, Investor Relations
(661) 616-3811
ir@bry.com
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