Berry Petroleum Corporation (NASDAQ: BRY) (“Berry” or the
“Company”) today reported net income attributable to common
stockholders of $132 million, or $1.56 per diluted share, and
adjusted net income of $35 million, or $0.41 per diluted share, for
the fourth quarter of 2018. For the full year of 2018, Berry's net
income attributable to common stockholders was $49 million, or
$0.85 per diluted share, and adjusted net income was $100 million,
or $1.26 per diluted share.
Highlights for the Quarter
- Adjusted EBITDA of $82 million and Unhedged Adjusted EBITDA of
$73 million
- Capital Expenditures of $53 million with approximately 79%
directed to development capital in California
- California production increased 11% over third quarter
2018
- Initiated share repurchase program with approximately 450,000
shares acquired in Q4 and nearly 2.4 million to date
- Completed divestiture of East Texas natural gas assets
(approximately 0.7 MBoe/d) for $7 million
- Settlement of General Unsecured Stock Claims for 2.8 million
shares of the 7.1 million initially reserved
Highlights for the Full Year
- Adjusted EBITDA of $258 million and Unhedged Adjusted EBITDA of
$296 million
- Total company PV-10 increased by over $1.0 billion to $2.2
billion, including $2.0 billion for California
- Replaced 114% of total company reserves and 275% in
California
- Capital Expenditures of $148 million with approximately 88%
directed to development capital in California
- Drilled 224 wells in California to help grow production for
California by 11% year over year
- Cash flows from operations of $230 million, which excludes $127
million for hedge early termination payment
Trem Smith, Berry President, Chief Executive
Officer and Chairman of the Board stated, “Results for our fourth
quarter and first full year of operations reinforce the new Berry
story, namely how Berry’s business model is simple and unique to
the industry and why we are substantially different from the Berry
of yesteryear. The idea of managing by growing value and returning
capital to shareholders while living within free cash flow is not
new to us - we do it now. It has been our strategy since Day One
and we plan to continue to do it consistently through the complete
commodity price cycle. The Berry of today is focused. We now only
operate in three states, down from five at the time of emergence,
and California is our area of greatest value creation as seen in
our production and reserves growth as well as significant increase
in value in 2018.”
“As fiduciaries of the Company’s capital
program, we focused our capital on our best long-term value,
California. We grew daily production in California by 11%
year-over-year and confidently expect to grow in the mid-teens for
2019. Replacing our reserves in California by almost 275% just
gives us more confidence in value remaining in our fields. We saw
our total company reserves grow to 143 million Boe while the PV-10
improved by over $1 billion to $2.2 billion. We did this while
living within free cash flow, paying a top tier dividend, and
generating additional free cash.”
“Our focus is on value through the
cycle. Berry is capital efficient and doesn’t have long-term
drilling contracts that drive inefficiency. We can drill and move
capital to where it provides the best long-term value and do it
quickly. We are very flexible and responsive to changing market
conditions. As a result, we have decreased our 2019 capital
spending by $35 million or 14% with only a little more than 3%
reduction in company-wide projected production. The technical
knowledge gained over the last year and a half on our assets gives
us a high level of confidence in the cash generating capability of
these assets for many years to come. At Berry, we are excited about
the value creation opportunities in 2019 and beyond.”
Fourth Quarter 2018 Results
For the fourth quarter, Berry reported Adjusted
EBITDA of $82 million, the same as the third quarter. Adjusted
EBITDA, on an unhedged basis, was $73 million in the fourth quarter
compared to $83 million in the third quarter, primarily due to
lower oil prices, partially offset by increased production.
For the fourth quarter California oil prices
before hedges averaged $62.65/Bbl which was 9% lower than the
$69.13/Bbl realized in the third quarter. Realized oil prices for
the Company before hedges of $61.48/Bbl were 9% lower than the
third quarter.
Oil production averaged 23,700 barrels per day
in the fourth quarter, while natural gas averaged 22,100 Mcf per
day and NGLs averaged 600 barrels per day. California provided
21,700 Boe/d in the fourth quarter, an 11% increase over the third
quarter, while the Rockies provided 5,800 Boe/d, down 19% from the
third quarter due to continued marketing issues in Utah that
impacted both sales and production. East Texas, the sale of which
closed November 30, provided 700 Boe/d prior to the sale.
For the fourth quarter, Operating Expenses
("OpEx") totaled $48 million or $18.77/Boe compared to $46 million
or $18.10/Boe in the third quarter. OpEx consists of lease
operating expenses ("LOE"), as well as expenses and third-party
revenues from electricity generation, transportation and marketing
activities and the effect of derivative settlements (received or
paid) for gas purchases while excluding taxes other than income
taxes. The fourth quarter OpEx per Boe increase compared to the
third quarter was primarily driven by higher fuel gas prices,
reductions in electricity capacity payment revenues and changes in
inventory costs in Utah, as well as the impact of selling our
East Texas natural gas assets in November which had lower costs on
a Boe basis compared to our other operations. We also mitigate a
portion of our LOE with natural gas purchase hedges which offset a
portion of the fourth quarter fuel costs.
General and administrative expenses were $16.1
million for the fourth quarter compared to $13.4 million for the
third quarter largely due to an increase in stock compensation
associated with performance shares meeting target thresholds.
Adjusted general and administrative expenses were $11.5 million or
$4.49/Boe for the fourth quarter compared to $10.7 million or
$4.25/Boe for the third quarter. The quarter-over-quarter increases
were primarily due to costs associated with supporting the
Company's growth, public company status and the continued system
improvements.
Taxes, other than income taxes were $7.8
million, or $3.05/Boe for the fourth quarter, compared to $8.3
million or $3.30/Boe in the third quarter, due to lower severance
taxes associated with the lower production and rates where those
taxes apply.
Capital expenditures totaled $53 million for the
fourth quarter compared to $40 million for the third quarter, in
both periods largely focused on drilling in California.
Adjusted net income was $35 million for the
fourth quarter compared to $41 million for the third quarter of
2018. The decrease in adjusted net income was primarily
associated with an increase in our corporate tax rate from 17% in
the third quarter to 23% in the fourth quarter.
Full Year 2018 Results
Full year comparisons to 2017 present 2017
results as a single amount for simplicity, but represent two
distinct periods, the two months ended February 28, 2017
(associated with our predecessor) and the ten months ended December
31, 2017 (our results as successor).
For 2018, Berry reported Adjusted EBITDA of $258
million compared to $178 million for 2017. Adjusted EBITDA, on an
unhedged basis, was $296 million in 2018 compared to $175 million
in 2017, primarily due to higher oil prices and increased oil
production, as well as the increased percentage oil represents of
our production in 2018 due to the acquisition of oil assets and
disposal of gas assets in 2017.
For 2018, California oil prices before hedges
averaged $65.64/Bbl which was 37% higher than the $47.79/Bbl
realized in 2017. Realized oil prices for the Company before hedges
of $64.76/Bbl were 35% higher than 2017.
Oil production averaged 22,000 barrels per day
in 2018, natural gas averaged 26,300 Mcf per day and NGLs averaged
600 barrels per day. California provided 19,700 Boe/d in 2018, an
11% increase over 2017, while the Rockies provided 6,600 Boe/d,
down 11% from 2017 due to continued marketing issues in Utah that
impacted both sales and production. East Texas, the sale of which
closed November 30, 2018 provided 700 Boe/d prior to the sale.
Included in these year-over-year changes was the impact of the 2017
asset transactions which increased daily oil production in
California by approximately 1,500 barrels and reduced gas
production in the Rockies by 5,600 Boe.
For 2018 OpEx totaled $181 million or $18.33/Boe
compared to $195 million or $16.84/Boe in 2017. The OpEx per Boe
increase was primarily driven by a 25% increase in LOE per Boe from
$15.32 per Boe in 2017 to $19.16 in 2018 largely due to the change
in the mix of our products from 64% oil to 82% driven by the July
2017 asset transactions, as well as the oil production growth from
capital expenditures during 2018. LOE increased due to higher fuel
gas costs (mainly higher volumes purchased), and increased facility
maintenance, and well servicing activity. The OpEx per Boe increase
was partially offset by a decrease in transportation expense in
2018 primarily due to the disposition of gas assets in 2017, which
required significant transportation.
General and administrative expenses were $54
million for 2018 compared to $64 million for 2017. The decrease in
general and administrative expenses was due to reduced
restructuring and transaction costs, partially offset by higher
costs associated with building out a public company infrastructure
including higher labor costs and the related increased stock
compensation. Adjusted general and administrative expenses were $41
million or $4.13/Boe for 2018 compared to $32 million or $2.74/Boe
for 2017. The increase in adjusted general and administrative
expenses per Boe was due to increased costs associated with
supporting the company's growth and public company status, as well
as the impact of lower volumes noted above from the change in
production mix resulting from the 2017 asset transactions.
Taxes, other than income taxes were $33 million,
or $3.36/Boe for 2018, compared to $39 million or $3.40/Boe in
2017, due to reduced green house gas unit costs and lower severance
taxes associated with the lower production and rates where those
taxes apply.
Capital expenditures totaled $148 million for
2018 compared to $73 million for 2017. The increased capital was
largely focused on increased drilling in California, which
accounted for 88% of our development capital spent in 2018.
Adjusted net income was $100 million for 2018
compared to $28 million for 2017. The improved results in
2018 compared to 2017 reflected improved operating results,
partially offset by an increased corporate tax rate.
As of December 31, 2018 our elected
commitment under our reserves-based lending credit facility (“RBL
Facility”) was $400 million with no outstanding borrowings. We had
$393 million available for borrowing under the RBL Facility due to
outstanding letters of credit. The Company has current liquidity of
$401 million including a cash balance of $10 million. For 2018 we
generated levered free cash flow, as defined in “Non-GAAP Financial
Measures and Reconciliations”, of $46 million, or $84 million on an
unhedged basis. During the fourth quarter we repurchased
approximately 450,000 shares of Berry’s common equity and almost
2.4 million shares to date.
“Our significant adjusted EBITDA in 2018 gave us
the confidence to return meaningful capital to shareholders in the
form of dividends, which we began in our first quarter as a public
company, as well as through our share repurchase program, which we
initiated in the fourth quarter. We have repurchased almost 2.4
million shares to date for approximately $25 million. We also
issued the remaining common shares reserved for claims in
connection with the bankruptcy. We issued only 2.8 million shares
of the 7.1 million shares initially reserved,” stated Cary Baetz,
Chief Financial Officer. “In light of the continued challenging
market in Utah and our constant focus on value, we have realigned
our 2019 plans to focus almost all capital in
California. Within California, we have reallocated the capital
to areas which are less likely to be impacted by regulatory
permitting delays. We have reduced planned capital spending by
$35 million while reducing production projections by only a little
more than 3%. We still see our California production growth in the
mid-high teens in California, and we are still living out of our
levered free cash flow at today’s strip prices. Accordingly, we
have updated our 2019 guidance. Beginning with this period, we will
present our operating and financial results split between
California and Rockies to provide better visibility to our
operations and their value.”
Full-Year 2019 Guidance
- Production between 28,000 to 31,000 Boe/d, approximately 86%
oil
- OPEX ranging from $18.00 to $19.50 per Boe
- Taxes, other than income taxes, ranging from $4.25 to $4.75 per
Boe
- Adjusted G&A ranging from $4.25 to $4.75 per Boe
- CapEx ranging from $195 million to $225 million
- CROIC(a) ranging from 18% to 24%
__________(a) Cash Returned on Invested Capital
(“CROIC”) consists of net cash provided by operating activities
before working capital, interest and non-recurring items, divided
by the sum of average stockholders' equity and average debt.
Board of Directors Changes
As the Company previously announced, Donald Paul
has been added to the board as an independent director. In
addition, the board appointed Trem Smith, Berry Petroleum President
and CEO, as Chairman of the Board. Smith replaces previous Chairman
Brent Buckley in that position, effective February 28, 2019, with
Buckley continuing to serve as a director.
Brent Buckley of Benefit Street Partners served
as board chairman from June 2017 and helped lead the company out of
bankruptcy to a successful IPO in July 2018. Smith stated “The
company is profoundly grateful for the primary role Brent took in
leading Berry out of bankruptcy two years ago and helping, as Board
Chairman, prepare us to be a public company. I am honored to work
with him and greatly appreciate his intensity and commitment to
making Berry what it is today. We are pleased that Brent will
remain a director and member of the Audit and Compensation
Committees continuing to provide valuable guidance to the Board.”
Buckley noted, “I have always seen the potential of Berry’s assets
and capital structure offer. Now that we’ve successfully taken
Berry public and have added a number of capable directors, it is
time to transition some of my responsibilities on the Board. I look
forward to continuing to work with the team and welcome the new
directors.”
Berry Petroleum added new board members Ms. Anne
Marriuci and Mr. Kent Potter in September 2018. The addition of
Donald Paul brings the total board membership to seven.
Additionally, the company today announced Ms. Mariucci will assume
the role of Lead Director for the Board further reflecting
corporate best practices designed to ensure independent oversight
of the company and its activities.
Earnings Conference Call
The Company will host a conference call March 7, 2019 to discuss
these results:
Live Call Date: |
Thursday, March 7,
2019 |
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: |
7682805 |
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, March
21, 2019 |
Replay Dial-in: |
855-859-2056 from the
U.S. |
|
404-537-3406 from
international locations |
Replay Passcode: |
7682805 |
A replay of the audio webcast will also be
archived on the “Investors” section of Berry’s website
at berrypetroleum.com/investors. In addition, an investor
presentation will be available on the Company’s website.
About Berry Petroleum
Berry Petroleum 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 berrypetroleum.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,
- capital expenditures
- return of capital
- improvement of recovery factors and other guidance.
Actual results may differ from anticipated
results, sometimes materially, and reported results should not be
considered an indication of future performance. Factors (but not
necessarily all the factors) that could cause results to differ
include:
- volatility of oil, natural gas and natural gas liquids
prices;
- inability to generate sufficient cash flow from operations or
to obtain adequate financing to fund capital expenditures and meet
working capital requirements;
- price and availability of natural gas;
- our ability to use derivative instruments to manage commodity
price risk;
- impact of environmental, health and safety, and other
governmental regulations, and of current, pending or future
legislation;
- uncertainties associated with estimating proved reserves and
related future cash flows;
- our inability to replace our reserves through exploration and
development activities;
- our ability to obtain permits and otherwise meet our proposed
drilling schedule and to successfully drill wells that produce oil
and natural gas in commercially viable quantities;
- changes in tax laws;
- effects of competition;
- our ability to make acquisitions and successfully integrate any
acquired businesses;
- market fluctuations in electricity prices and the cost of
steam; 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 in this Exhibit 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
|
Berry Corp. (Successor) |
|
|
Berry LLC (Predecessor) |
|
Quarter Ended December 31, 2018 |
|
Quarter Ended September 30, 2018 |
|
Quarter Ended December 31, 2017 |
|
Year Ended December 31, 2018 |
|
Ten Months Ended December 31,
2017 |
|
|
Two Months Ended February 28,
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ and shares in thousands, except per share
amounts) |
Consolidated
Statement of Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and
other: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and
natural gas liquids sales |
$ |
142,861 |
|
|
$ |
147,004 |
|
|
$ |
120,603 |
|
|
$ |
552,874 |
|
|
$ |
357,928 |
|
|
|
$ |
74,120 |
|
Electricity sales |
9,517 |
|
|
14,268 |
|
|
6,455 |
|
|
35,208 |
|
|
21,972 |
|
|
|
3,655 |
|
Gains
(losses) on oil derivatives |
127,160 |
|
|
(18,994 |
) |
|
(72,542 |
) |
|
(4,621 |
) |
|
(66,900 |
) |
|
|
12,886 |
|
Marketing
revenues |
534 |
|
|
486 |
|
|
793 |
|
|
2,322 |
|
|
2,694 |
|
|
|
633 |
|
Other
revenues |
274 |
|
|
183 |
|
|
73 |
|
|
774 |
|
|
3,975 |
|
|
|
1,424 |
|
Total
revenues and other |
280,346 |
|
|
142,947 |
|
|
55,382 |
|
|
586,557 |
|
|
319,669 |
|
|
|
92,718 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and
other: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expenses |
51,308 |
|
|
51,649 |
|
|
44,586 |
|
|
188,776 |
|
|
149,599 |
|
|
|
28,238 |
|
Electricity generation expenses |
6,764 |
|
|
6,130 |
|
|
4,701 |
|
|
20,619 |
|
|
14,894 |
|
|
|
3,197 |
|
Transportation expenses |
2,220 |
|
|
2,318 |
|
|
593 |
|
|
9,860 |
|
|
19,238 |
|
|
|
6,194 |
|
Marketing
expenses |
716 |
|
|
437 |
|
|
645 |
|
|
2,140 |
|
|
2,320 |
|
|
|
653 |
|
General
and administrative expenses |
16,130 |
|
|
13,429 |
|
|
12,480 |
|
|
54,026 |
|
|
56,009 |
|
|
|
7,964 |
|
Depreciation, depletion, amortization and accretion |
24,253 |
|
|
21,729 |
|
|
20,086 |
|
|
86,271 |
|
|
68,478 |
|
|
|
28,149 |
|
Taxes,
other than income taxes |
7,829 |
|
|
8,317 |
|
|
9,098 |
|
|
33,117 |
|
|
34,211 |
|
|
|
5,212 |
|
(Gains)
losses on natural gas derivatives |
(4,477 |
) |
|
(1,879 |
) |
|
— |
|
|
(6,357 |
) |
|
— |
|
|
|
— |
|
(Gains)
losses on sale of assets and other, net |
(3,269 |
) |
|
400 |
|
|
(2,243 |
) |
|
(2,747 |
) |
|
(22,930 |
) |
|
|
(183 |
) |
Total
expenses and other |
101,474 |
|
|
102,530 |
|
|
89,946 |
|
|
385,705 |
|
|
321,819 |
|
|
|
79,424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income
(expenses): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense |
(8,820 |
) |
|
(9,877 |
) |
|
(5,972 |
) |
|
(35,648 |
) |
|
(18,454 |
) |
|
|
(8,245 |
) |
Other,
net |
108 |
|
|
347 |
|
|
— |
|
|
243 |
|
|
4,071 |
|
|
|
(63 |
) |
Total
other income (expenses) |
(8,712 |
) |
|
(9,530 |
) |
|
(5,972 |
) |
|
(35,405 |
) |
|
(14,383 |
) |
|
|
(8,308 |
) |
Reorganization items,
net |
1,498 |
|
|
13,781 |
|
|
(730 |
) |
|
24,690 |
|
|
(1,732 |
) |
|
|
(507,720 |
) |
Income (loss)
before income taxes |
171,658 |
|
|
44,668 |
|
|
(41,266 |
) |
|
190,137 |
|
|
(18,265 |
) |
|
|
(502,734 |
) |
Income tax expense
(benefit) |
39,890 |
|
|
7,683 |
|
|
(6,386 |
) |
|
43,035 |
|
|
2,803 |
|
|
|
230 |
|
Net income
(loss) |
131,768 |
|
|
36,985 |
|
|
(34,880 |
) |
|
147,102 |
|
|
(21,068 |
) |
|
|
$ |
(502,964 |
) |
Series A preferred
stock dividends and conversion to common stock |
— |
|
|
(86,642 |
) |
|
(5,567 |
) |
|
(97,942 |
) |
|
(18,248 |
) |
|
|
n/a |
|
Net income
(loss) attributable to common stockholders |
$ |
131,768 |
|
|
$ |
(49,657 |
) |
|
$ |
(40,447 |
) |
|
$ |
49,160 |
|
|
$ |
(39,316 |
) |
|
|
n/a |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss) per share attributable to common stockholders |
|
|
|
|
|
|
|
|
|
|
|
|
Basic(a) |
$ |
1.56 |
|
|
$ |
(0.70 |
) |
|
$ |
(1.05 |
) |
|
$ |
0.85 |
|
|
$ |
(1.02 |
) |
|
|
n/a |
|
Diluted(a) |
$ |
1.56 |
|
|
$ |
(0.70 |
) |
|
$ |
(1.05 |
) |
|
$ |
0.85 |
|
|
$ |
(1.02 |
) |
|
|
n/a |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common
shares outstanding - basic(a) |
84,367 |
|
|
70,940 |
|
|
38,644 |
|
|
57,743 |
|
|
38,644 |
|
|
|
n/a |
|
Weighted-average common
shares outstanding - diluted(a) |
84,592 |
|
|
70,940 |
|
|
38,644 |
|
|
57,932 |
|
|
38,644 |
|
|
|
n/a |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted net income
(loss)(b) |
$ |
34,809 |
|
|
$ |
40,529 |
|
|
$ |
21,835 |
|
|
$ |
100,001 |
|
|
$ |
35,880 |
|
|
|
$ |
(7,779 |
) |
Adjusted EBITDA(b) |
$ |
81,669 |
|
|
$ |
81,736 |
|
|
$ |
52,840 |
|
|
$ |
257,924 |
|
|
$ |
149,613 |
|
|
|
$ |
28,845 |
|
Adjusted EBITDA
unhedged(b) |
$ |
72,990 |
|
|
$ |
82,788 |
|
|
$ |
59,674 |
|
|
$ |
296,406 |
|
|
$ |
146,545 |
|
|
|
$ |
28,311 |
|
Levered free cash
flow(b) |
$ |
9,531 |
|
|
$ |
24,251 |
|
|
$ |
35,425 |
|
|
$ |
45,787 |
|
|
$ |
44,948 |
|
|
|
$ |
15,194 |
|
Levered free cash flow
unhedged(b) |
$ |
852 |
|
|
$ |
25,303 |
|
|
$ |
42,259 |
|
|
$ |
84,269 |
|
|
$ |
41,880 |
|
|
|
$ |
14,660 |
|
Adjusted general and
administrative expenses(b) . |
$ |
11,533 |
|
|
$ |
10,706 |
|
|
$ |
8,659 |
|
|
$ |
40,668 |
|
|
$ |
23,865 |
|
|
|
$ |
7,964 |
|
Effective Tax Rate |
23 |
% |
|
17 |
% |
|
15 |
% |
|
23 |
% |
|
(15 |
)% |
|
|
0 |
% |
Cash Flow
Data: |
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by
(used in) operating activities(c) |
$ |
95,767 |
|
|
$ |
56,880 |
|
|
$ |
39,086 |
|
|
$ |
103,100 |
|
|
$ |
107,399 |
|
|
|
$ |
22,431 |
|
Net cash provided by
(used in) investing activities |
$ |
(36,694 |
) |
|
$ |
(40,028 |
) |
|
$ |
(8,045 |
) |
|
$ |
(119,069 |
) |
|
$ |
(80,525 |
) |
|
|
$ |
(3,133 |
) |
Net cash provided by
(used in) financing activities |
$ |
(14,306 |
) |
|
$ |
(16,250 |
) |
|
$ |
(62 |
) |
|
$ |
15,911 |
|
|
$ |
(43,170 |
) |
|
|
$ |
(162,668 |
) |
__________(a) Our weighted-average common
shares outstanding increased beginning in the third quarter of 2018
for additional shares from our initial public offering and
preferred stock conversion. We retrospectively adjusted for
2,770,000 shares issued instead of the 7,080,000 shares that were
reserved for holders of allowed Unsecured Notes and General
Unsecured Claims in our earnings per share calculations for the
2018 and 2017 Successor periods.(b) See further
discussion and reconciliation in “Non-GAAP Financial Measures and
Reconciliations”.(c) Year ended December 31, 2018 includes
approximately $127 million paid to early terminate unsettled
derivative contracts. The elective cancellation was effected to
realign our hedging pricing with current market rates and move from
NYMEX WTI to ICE Brent underlying. Had we not elected to cancel
these derivative contracts our net cash provided by operating
activities would have been approximately $230 million.
|
Berry Corp. (Successor) |
|
December 31, 2018 |
|
December 31, 2017 |
|
|
|
|
|
($ and shares in thousands) |
Balance Sheet
Data: |
|
|
|
Total current
assets |
$ |
229,022 |
|
|
$ |
137,524 |
|
Total property, plant
and equipment, net |
$ |
1,442,708 |
|
|
$ |
1,387,191 |
|
Total current
liabilities |
$ |
144,118 |
|
|
$ |
182,659 |
|
Long-term
debt |
$ |
391,786 |
|
|
$ |
379,000 |
|
Total equity |
$ |
1,006,446 |
|
|
$ |
859,310 |
|
Outstanding common
stock shares as of(d) |
81,202 |
|
|
32,920 |
|
__________(d) Excludes 2,770,000 common
stock shares negotiated with general unsecured creditors electing
to settle claims in exchange for common shares subsequent to
December 31, 2018. Also excludes 1,930,000 shares repurchased in
our share repurchase program subsequent to December 31, 2018.
SUMMARY BY AREA
The following table shows a summary by area of
our selected historical financial information and operating data
for the periods indicated. Full year data for 2017 are presented as
a single amount for simplicity, but represent two distinct periods,
the two months ended February 28, 2017 (our predecessor) and the
ten months ended December 31, 2017 (our successor).
|
California (San Joaquin and Ventura
basins) |
|
Rockies (Uinta and Piceance
basins) |
|
Year Ended December 31, 2018 |
|
Year Ended December 31, 2017 |
|
Year Ended December 31, 2018 |
|
Year Ended December 31, 2017 |
($ in thousands, except prices) |
|
|
|
|
|
|
|
Total revenues |
$ |
471,983 |
|
|
$ |
311,247 |
|
|
$ |
76,855 |
|
|
$ |
76,365 |
|
Operating
income(a) |
$ |
226,854 |
|
|
$ |
74,629 |
|
|
$ |
19,089 |
|
|
$ |
9,961 |
|
Depreciation,
depletion, and amortization |
$ |
72,260 |
|
|
$ |
71,092 |
|
|
$ |
11,066 |
|
|
$ |
17,792 |
|
Average daily
production (MBoe/d) |
19.7 |
|
|
17.8 |
|
|
6.7 |
|
|
7.4 |
|
Production (oil% of
total) |
100 |
% |
|
100 |
% |
|
36 |
% |
|
36 |
% |
Realized prices: |
|
|
|
|
|
|
|
Oil (per
Bbl) |
$ |
65.64 |
|
|
$ |
47.79 |
|
|
$ |
57.34 |
|
|
$ |
48.47 |
|
NGLs (per
Bbl) |
$ |
— |
|
|
$ |
— |
|
|
$ |
26.95 |
|
|
$ |
21.36 |
|
Gas (per
Mcf) |
$ |
— |
|
|
$ |
— |
|
|
$ |
2.71 |
|
|
$ |
2.78 |
|
Capital
expenditures |
$ |
125,565 |
|
|
$ |
63,313 |
|
|
$ |
17,351 |
|
|
$ |
1,451 |
|
Total proved reserves
(MMBoe) |
106 |
|
|
93 |
|
|
37 |
|
|
46 |
|
PV-10(b) |
$ |
2,026,880 |
|
|
$ |
998,391 |
|
|
$ |
124,652 |
|
|
$ |
108,375 |
|
__________(a) Operating income includes
oil, natural gas and NGL sales, offset by operating expenses,
general and administrative expenses, DD&A, and taxes, other
than income taxes.(b) PV-10 is a financial measure that is
not calculated in accordance with GAAP. For a definition of PV-10
and a reconciliation to the standardized measure of discounted
future net cash flows, please see “Non-GAAP Financial Measures and
Reconciliations”.
COMMODITY PRICING
|
Berry Corp. (Successor) |
|
|
Berry LLC (Predecessor) |
|
Quarter Ended December 31, 2018 |
|
Quarter Ended September 30, 2018 |
|
Quarter Ended December 31, 2017 |
|
Year Ended December 31, 2018 |
|
Ten Months Ended December 31,
2017 |
|
|
Two Months Ended February 28, 2017 |
Realized
Prices |
|
|
|
|
|
|
|
|
|
|
|
|
Oil without hedge
($/Bbl) |
$ |
61.48 |
|
|
$ |
67.67 |
|
|
$ |
54.77 |
|
|
$ |
64.76 |
|
|
$ |
48.05 |
|
|
|
$ |
46.94 |
|
Effects of scheduled
derivative settlements ($/Bbl) |
$ |
2.88 |
|
|
$ |
(0.51 |
) |
|
$ |
(3.37 |
) |
|
$ |
(5.09 |
) |
|
$ |
0.48 |
|
|
|
$ |
0.46 |
|
Oil with hedge
($/Bbl) |
$ |
64.36 |
|
|
$ |
67.16 |
|
|
$ |
51.40 |
|
|
$ |
59.67 |
|
|
$ |
48.53 |
|
|
|
$ |
47.40 |
|
Natural gas
($/Mcf) |
$ |
3.86 |
|
|
$ |
2.55 |
|
|
$ |
2.75 |
|
|
$ |
2.74 |
|
|
$ |
2.70 |
|
|
|
$ |
3.42 |
|
NGLs ($/Bbl) |
$ |
20.39 |
|
|
$ |
37.75 |
|
|
$ |
28.15 |
|
|
$ |
26.74 |
|
|
$ |
22.23 |
|
|
|
$ |
18.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Index
Prices |
|
|
|
|
|
|
|
|
|
|
|
|
Brent oil ($/Bbl) |
$ |
68.08 |
|
|
$ |
75.93 |
|
|
$ |
61.52 |
|
|
$ |
71.53 |
|
|
$ |
54.65 |
|
|
|
$ |
55.72 |
|
WTI oil ($/Bbl) |
$ |
58.81 |
|
|
$ |
69.50 |
|
|
$ |
55.40 |
|
|
$ |
64.76 |
|
|
$ |
50.53 |
|
|
|
$ |
53.04 |
|
Henry Hub natural gas
($/MMBtu) |
$ |
3.64 |
|
|
$ |
2.90 |
|
|
$ |
2.93 |
|
|
$ |
3.09 |
|
|
$ |
3.00 |
|
|
|
$ |
3.66 |
|
CURRENT HEDGING SUMMARY
As of February 28, 2019, our positions were as follows:
|
Q1 2019 |
|
Q2 2019 |
|
Q3 2019 |
|
Q4 2019 |
Net
Purchased/Sold Oil Put Options (ICE Brent): |
|
|
|
|
|
|
|
Hedged
volume (MBbls) |
484 |
|
|
|
1,365 |
|
|
368 |
|
|
368 |
|
Weighted-average price ($/Bbl) |
$ |
61.16 |
|
|
$ |
61.00 |
|
$ |
50.00 |
|
|
$ |
50.00 |
|
Fixed Price Oil
Swaps (ICE Brent): |
|
|
|
|
|
|
|
Hedged
volume (MBbls) |
1,080 |
|
|
$ |
637 |
|
|
644 |
|
|
644 |
|
Weighted-average price
($/Bbl) |
$ |
75.76 |
|
|
$ |
76.27 |
|
|
$ |
76.27 |
|
|
$ |
76.27 |
|
Oil basis
differential positions (ICE Brent-NYMEX WTI basis
swaps): |
|
|
|
|
|
|
|
Hedged
volume (MBbls) |
45 |
|
|
|
46 |
|
|
46 |
|
|
46 |
|
Weighted-average price ($/Bbl) |
$ |
(1.29 |
) |
|
$ |
(1.29 |
) |
|
$ |
(1.29 |
) |
|
$ |
(1.29 |
) |
Fixed Price Gas
Purchase Swaps (Kern, Delivered): |
|
|
|
|
|
|
|
Hedged
volume (MMBtu) |
1,815,000 |
|
|
$ |
2,730,000 |
|
|
1,380,000 |
|
|
465,000 |
|
Weighted-average price ($/MMBtu) |
$ |
2.68 |
|
|
$ |
2.70 |
|
|
$ |
2.65 |
|
|
$ |
2.65 |
|
OPERATING EXPENSES
|
Berry Corp. (Successor) |
|
|
Berry LLC (Predecessor) |
|
Quarter Ended December 31, 2018 |
|
Quarter Ended September 30, 2018 |
|
Quarter Ended December 31, 2017 |
|
Year Ended December 31, 2018 |
|
Ten Months Ended December 31,
2017 |
|
|
Two Months Ended February 28, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands except per MBoe amounts) |
Lease operating
expenses |
$ |
51,308 |
|
|
$ |
51,649 |
|
|
$ |
44,586 |
|
|
$ |
188,776 |
|
|
$ |
149,599 |
|
|
|
$ |
28,238 |
|
Electricity generation
expenses |
6,764 |
|
|
6,130 |
|
|
4,701 |
|
|
20,619 |
|
|
14,894 |
|
|
|
3,197 |
|
Electricity
sales(a) |
(9,517 |
) |
|
(14,268 |
) |
|
(6,455 |
) |
|
(35,208 |
) |
|
(21,972 |
) |
|
|
(3,655 |
) |
Transportation
expenses |
2,220 |
|
|
2,318 |
|
|
593 |
|
|
9,860 |
|
|
19,238 |
|
|
|
6,194 |
|
Transportation
sales(a) |
(274 |
) |
|
(183 |
) |
|
— |
|
|
(774 |
) |
|
— |
|
|
|
— |
|
Marketing expenses |
716 |
|
|
437 |
|
|
645 |
|
|
2,140 |
|
|
2,320 |
|
|
|
653 |
|
Marketing
revenues(a) |
(534 |
) |
|
(486 |
) |
|
(793 |
) |
|
(2,322 |
) |
|
(2,694 |
) |
|
|
(633 |
) |
Derivative settlements
(received) paid for gas purchases(a) |
(2,407 |
) |
|
— |
|
|
— |
|
|
(2,407 |
) |
|
— |
|
|
|
— |
|
Total
operating expenses(a) |
$ |
48,276 |
|
|
$ |
45,597 |
|
|
$ |
43,277 |
|
|
$ |
180,684 |
|
|
$ |
161,385 |
|
|
|
$ |
33,994 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
expenses ($/Boe) |
$ |
19.96 |
|
|
$ |
20.50 |
|
|
$ |
17.40 |
|
|
$ |
19.16 |
|
|
$ |
15.84 |
|
|
|
$ |
13.06 |
|
Electricity generation
expenses ($/Boe) |
2.63 |
|
|
2.43 |
|
|
$ |
1.83 |
|
|
2.09 |
|
|
1.58 |
|
|
|
1.48 |
|
Electricity sales
($/Boe) |
(3.70 |
) |
|
(5.66 |
) |
|
$ |
(2.52 |
) |
|
(3.57 |
) |
|
(2.33 |
) |
|
|
(1.69 |
) |
Transportation expenses
($/Boe) |
0.86 |
|
|
0.92 |
|
|
$ |
0.23 |
|
|
1.00 |
|
|
2.04 |
|
|
|
2.86 |
|
Transportation sales
($/Boe) |
(0.11 |
) |
|
(0.07 |
) |
|
$ |
0.00 |
|
|
(0.08 |
) |
|
— |
|
|
|
— |
|
Marketing expenses
($/Boe) |
0.28 |
|
|
0.17 |
|
|
$ |
0.25 |
|
|
0.22 |
|
|
0.25 |
|
|
|
0.30 |
|
Marketing revenues
($/Boe) |
(0.21 |
) |
|
(0.19 |
) |
|
$ |
(0.31 |
) |
|
(0.24 |
) |
|
(0.29 |
) |
|
|
(0.29 |
) |
Derivative settlements
(received) paid for gas purchases ($/Boe) |
(0.94 |
) |
|
— |
|
|
— |
|
|
(0.24 |
) |
|
— |
|
|
|
— |
|
Total
operating expenses ($/Boe) |
$ |
18.77 |
|
|
$ |
18.10 |
|
|
$ |
16.89 |
|
|
$ |
18.33 |
|
|
$ |
17.09 |
|
|
|
$ |
15.72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total MBoe |
2,571 |
|
|
2,520 |
|
|
2,563 |
|
|
9,855 |
|
|
9,443 |
|
|
|
2,162 |
|
__________(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 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 includes the effect of derivative settlements (received or
paid) for gas purchases.
PRODUCTION STATISTICS
|
Berry Corp. (Successor) |
|
|
Berry LLC (Predecessor) |
|
Quarter Ended December 31, 2018 |
|
Quarter Ended September 30, 2018 |
|
Quarter Ended December 31, 2017 |
|
Year Ended December 31, 2018 |
|
Ten Months Ended December 31,
2017 |
|
|
Two Months Ended February 28, 2017 |
Net Oil,
Natural Gas and NGLs Production Per Day(a): |
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(MBbl/d) |
|
|
|
|
|
|
|
|
|
|
|
|
California |
21.7 |
|
|
19.5 |
|
|
19.5 |
|
|
19.7 |
|
|
18.0 |
|
|
|
17.0 |
|
Rockies |
2.0 |
|
|
2.8 |
|
|
2.6 |
|
|
2.3 |
|
|
2.6 |
|
|
|
2.5 |
|
East
Texas |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
— |
|
Hugoton
basin |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
— |
|
Total
oil |
23.7 |
|
|
22.3 |
|
|
22.1 |
|
|
22.0 |
|
|
20.6 |
|
|
|
19.5 |
|
Natural gas
(MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
California |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
— |
|
Rockies |
19.3 |
|
|
23.2 |
|
|
26.1 |
|
|
22.1 |
|
|
25.0 |
|
|
|
27.1 |
|
East
Texas(c) |
2.8 |
|
|
4.3 |
|
|
5.1 |
|
|
4.2 |
|
|
5.7 |
|
|
|
6.4 |
|
Hugoton
basin |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
18.7 |
|
|
|
38.2 |
|
Total
natural gas |
22.1 |
|
|
27.4 |
|
|
31.3 |
|
|
26.3 |
|
|
49.4 |
|
|
|
71.7 |
|
NGLs
(MBbl/d) |
|
|
|
|
|
|
|
|
|
|
|
|
California |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
— |
|
Rockies |
0.6 |
|
|
0.5 |
|
|
0.6 |
|
|
0.6 |
|
|
0.5 |
|
|
|
0.6 |
|
East
Texas |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
— |
|
Hugoton
basin |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
1.4 |
|
|
|
4.5 |
|
Total
NGLs |
0.6 |
|
|
0.5 |
|
|
0.6 |
|
|
0.6 |
|
|
2.0 |
|
|
|
5.2 |
|
Total
Production (MBoe/d)(b) |
28.0 |
|
|
27.4 |
|
|
27.9 |
|
|
27.0 |
|
|
30.9 |
|
|
|
36.7 |
|
__________(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 year ended December 31,
2018, the average prices of ICE (Brent) oil and NYMEX (HH) natural
gas were $71.53 per Bbl and $3.09 per Mcf, respectively, resulting
in an oil-to-gas ratio of over 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)
|
Berry Corp. (Successor) |
|
|
Berry LLC (Predecessor) |
|
Quarter Ended December 31, 2018 |
|
Quarter Ended September 30, 2018 |
|
Quarter Ended December 31, 2017 |
|
Year Ended December 31, 2018 |
|
Ten Months Ended December 31,
2017 |
|
|
Two Months Ended February 28, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
Capital expenditures
(accrual basis) |
53,326 |
|
|
40,243 |
|
|
17,010 |
|
|
147,831 |
|
|
67,963 |
|
|
|
5,406 |
|
NON-GAAP FINANCIAL MEASURES AND
RECONCILIATIONS
Adjusted Net Income (Loss) and Adjusted EBITDA
are not measures of net income (loss), Levered Free Cash Flow is
not a measure of cash flow, and Adjusted General and Administrative
Expenses is not a measure of general and administrative expenses,
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, 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. 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. We define Adjusted
General and Administrative Expenses as general and administrative
expenses adjusted for non-recurring restructuring and other costs
and non-cash stock compensation expense.
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. Adjusted EBITDA is the
primary financial measurement that our management uses to analyze
and monitor the operating performance of our business. 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. 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 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 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.
PV-10 is a non-GAAP financial measure and
represents the present value of estimated future cash inflows from
proved oil and gas reserves, less future development and production
costs, discounted at 10% per annum to reflect the timing of future
cash flows. Calculation of PV-10 does not give effect to
derivatives transactions. Management believes that PV-10 provides
useful information to investors because it is widely used by
analysts and investors in evaluating oil and natural gas companies.
Because there are many unique factors that can impact an individual
company when estimating the amount of future income taxes to be
paid, management believes the use of a pre-tax measure is valuable
for evaluating the Company. PV-10 should not be considered as an
alternative to the standardized measure of discounted future net
cash flows as computed under GAAP.
Finding and Development cost ("F&D") and
reserves replacement ratio are non-GAAP measures that we believe
are widely used in our industry, as well as by analysts and
investors, to measure and evaluate the cost of replacing annual
production and adding proved reserves. F&D Cost – All-In is
calculated by dividing total costs incurred for the year as defined
by GAAP by the sum of proved reserve extensions and discoveries,
revisions of previous estimates, improved recovery and purchases of
minerals in place for the year. F&D Cost – Program is
calculated by dividing total costs incurred for the year as defined
by GAAP by extensions and discoveries and improved recovery for the
year. Reserves replacement ratio is calculated by dividing the sum
of proved reserve extensions and discoveries, revisions of previous
estimates, improved recovery and purchases and sales of minerals in
place for the year by current year production. There is no
guarantee that historical sources of reserves additions will
continue performing as many factors fully or partially outside of
management's control, including commodity prices, availability of
capital and the underlying geology, affect reserves additions.
Management uses this measure to gauge results of its capital
allocation. The measure is limited in that reserves may be added
and produced based on costs incurred in separate periods and other
oil and gas producers may use different measures affecting
comparability.
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).
|
Berry Corp. (Successor) |
|
|
Berry LLC (Predecessor) |
|
Quarter Ended December 31, 2018 |
|
Quarter Ended September 30, 2018 |
|
Quarter Ended December 31, 2017 |
|
Year Ended December 31, 2018 |
|
Ten Months Ended December 31,
2017 |
|
|
Two Months Ended February 28, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ thousands, except per share amounts) |
Net income (loss) |
$ |
131,768 |
|
|
$ |
36,985 |
|
|
$ |
(34,880 |
) |
|
$ |
147,102 |
|
|
$ |
(21,068 |
) |
|
|
$ |
(502,964 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Add
(Subtract): |
|
|
|
|
|
|
|
|
|
|
|
|
(Gains)
losses on oil and natural gas derivatives |
(131,637 |
) |
|
17,115 |
|
|
72,542 |
|
|
(1,735 |
) |
|
66,900 |
|
|
|
(12,886 |
) |
Net cash
received (paid) for scheduled derivative settlements |
8,679 |
|
|
(1,052 |
) |
|
(6,834 |
) |
|
(38,482 |
) |
|
3,068 |
|
|
|
534 |
|
(Gains)
losses on sale of assets and other, net |
(3,269 |
) |
|
400 |
|
|
(2,243 |
) |
|
(2,747 |
) |
|
(22,930 |
) |
|
|
(183 |
) |
Non-recurring restructuring and other costs |
1,414 |
|
|
1,598 |
|
|
2,904 |
|
|
6,773 |
|
|
30,325 |
|
|
|
— |
|
Reorganization items, net |
(1,498 |
) |
|
(13,781 |
) |
|
730 |
|
|
(24,690 |
) |
|
1,732 |
|
|
|
507,720 |
|
Total
additions, net |
(126,311 |
) |
|
4,280 |
|
|
67,099 |
|
|
(60,881 |
) |
|
79,095 |
|
|
|
495,185 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (expense)
benefit of adjustments at effective tax rate(a) |
29,352 |
|
|
(736 |
) |
|
(10,384 |
) |
|
13,780 |
|
|
(22,147 |
) |
|
|
— |
|
Adjusted net income
(loss) |
$ |
34,809 |
|
|
$ |
40,529 |
|
|
$ |
21,835 |
|
|
$ |
100,001 |
|
|
$ |
35,880 |
|
|
|
$ |
(7,779 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS on adjusted
income |
$ |
0.41 |
|
|
$ |
0.57 |
|
|
$ |
0.57 |
|
|
$ |
1.73 |
|
|
$ |
0.93 |
|
|
|
n/a |
Diluted EPS on adjusted
net income |
$ |
0.41 |
|
|
$ |
0.48 |
|
|
$ |
0.29 |
|
|
$ |
1.26 |
|
|
$ |
0.48 |
|
|
|
n/a |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding - basic |
84,367 |
|
|
70,940 |
|
|
38,644 |
|
|
57,743 |
|
|
38,644 |
|
|
|
n/a |
Weighted average shares
outstanding - diluted . |
84,592 |
|
|
84,487 |
|
|
74,703 |
|
|
79,633 |
|
|
74,569 |
|
|
|
n/a |
__________(a) For the ten
months ended December 31, 2017, our effective tax rate was (15%)
due to a net loss and valuation allowances. For purposes of this
calculation, we used the statutory rate for this period, which was
28%.
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 (used) by operating activities to the non-GAAP financial
measures of Adjusted EBITDA and Adjusted EBITDA Unhedged.
|
Berry Corp. (Successor) |
|
|
Berry LLC (Predecessor) |
|
Quarter Ended December 31, 2018 |
|
Quarter Ended September 30, 2018 |
|
Quarter Ended December 31, 2017 |
|
Year Ended December 31, 2018 |
|
Ten Months Ended December 31,
2017 |
|
|
Two Months Ended February 28, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ thousands) |
Net income (loss) |
$ |
131,768 |
|
|
$ |
36,985 |
|
|
$ |
(34,880 |
) |
|
$ |
147,102 |
|
|
$ |
(21,068 |
) |
|
|
$ |
(502,964 |
) |
Add (Subtract): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense |
8,820 |
|
|
9,877 |
|
|
5,972 |
|
|
35,648 |
|
|
18,454 |
|
|
|
8,245 |
|
Income
tax expense (benefit) |
39,890 |
|
|
7,683 |
|
|
(6,386 |
) |
|
43,035 |
|
|
2,803 |
|
|
|
230 |
|
Depreciation, depletion, amortization and accretion |
24,253 |
|
|
21,729 |
|
|
20,086 |
|
|
86,271 |
|
|
68,478 |
|
|
|
28,149 |
|
Derivative (gains) losses |
(131,637 |
) |
|
17,115 |
|
|
72,542 |
|
|
(1,735 |
) |
|
66,900 |
|
|
|
(12,886 |
) |
Net cash
received (paid) for scheduled derivative settlements |
8,679 |
|
|
(1,052 |
) |
|
(6,834 |
) |
|
(38,482 |
) |
|
3,068 |
|
|
|
534 |
|
(Gains)
losses on sale of assets and other |
(3,269 |
) |
|
400 |
|
|
(2,243 |
) |
|
(2,747 |
) |
|
(22,930 |
) |
|
|
(183 |
) |
Stock
compensation expense |
3,249 |
|
|
1,182 |
|
|
949 |
|
|
6,750 |
|
|
1,851 |
|
|
|
— |
|
Non-recurring restructuring and other costs |
1,414 |
|
|
1,598 |
|
|
2,904 |
|
|
6,773 |
|
|
30,325 |
|
|
|
— |
|
Reorganization items, net |
(1,498 |
) |
|
(13,781 |
) |
|
730 |
|
|
(24,690 |
) |
|
1,732 |
|
|
|
507,720 |
|
Adjusted EBITDA |
$ |
81,669 |
|
|
$ |
81,736 |
|
|
$ |
52,840 |
|
|
$ |
257,924 |
|
|
$ |
149,613 |
|
|
|
$ |
28,845 |
|
Net cash (received)
paid for scheduled derivative settlements |
(8,679 |
) |
|
1,052 |
|
|
6,834 |
|
|
38,482 |
|
|
(3,068 |
) |
|
|
(534 |
) |
Adjusted EBITDA
unhedged |
$ |
72,990 |
|
|
$ |
82,788 |
|
|
$ |
59,674 |
|
|
$ |
296,406 |
|
|
$ |
146,545 |
|
|
|
$ |
28,311 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided
(used) by operating activities |
$ |
95,767 |
|
|
$ |
56,880 |
|
|
$ |
39,086 |
|
|
$ |
103,100 |
|
|
$ |
107,399 |
|
|
|
$ |
22,431 |
|
Add (Subtract): |
|
|
|
|
|
|
|
|
|
|
|
|
Cash
interest payments |
562 |
|
|
15,902 |
|
|
4,690 |
|
|
19,761 |
|
|
14,276 |
|
|
|
8,057 |
|
Cash
income tax (receipts) payments |
(1,901 |
) |
|
— |
|
|
— |
|
|
(1,901 |
) |
|
1,994 |
|
|
|
— |
|
Cash
reorganization item (receipts) payments |
(174 |
) |
|
(345 |
) |
|
794 |
|
|
832 |
|
|
1,732 |
|
|
|
11,838 |
|
Non-recurring restructuring and other costs |
1,414 |
|
|
1,598 |
|
|
2,904 |
|
|
6,773 |
|
|
30,325 |
|
|
|
— |
|
Derivative early termination payment |
— |
|
|
— |
|
|
— |
|
|
126,949 |
|
|
— |
|
|
|
— |
|
Other
changes in operating assets and liabilities |
(13,998 |
) |
|
7,701 |
|
|
5,365 |
|
|
2,410 |
|
|
(6,113 |
) |
|
|
(13,323 |
) |
Other,
net |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
(158 |
) |
Adjusted EBITDA |
$ |
81,669 |
|
|
$ |
81,736 |
|
|
$ |
52,840 |
|
|
$ |
257,924 |
|
|
$ |
149,613 |
|
|
|
$ |
28,845 |
|
Net cash (received)
paid for scheduled derivative settlements |
(8,679 |
) |
|
1,052 |
|
|
6,834 |
|
|
38,482 |
|
|
(3,068 |
) |
|
|
(534 |
) |
Adjusted EBITDA
unhedged |
$ |
72,990 |
|
|
$ |
82,788 |
|
|
$ |
59,674 |
|
|
$ |
296,406 |
|
|
$ |
146,545 |
|
|
|
$ |
28,311 |
|
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.
|
Berry Corp. (Successor) |
|
|
Berry LLC (Predecessor) |
|
Quarter Ended December 31, 2018 |
|
Quarter Ended September 30, 2018 |
|
Quarter Ended December 31, 2017 |
|
Year Ended December 31, 2018 |
|
Ten Months Ended December 31,
2017 |
|
|
Two Months Ended February 28, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ thousands) |
Adjusted EBITDA |
$ |
81,669 |
|
|
$ |
81,736 |
|
|
$ |
52,840 |
|
|
$ |
257,924 |
|
|
$ |
149,613 |
|
|
|
$ |
28,845 |
|
Subtract: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures - accrual basis |
(53,326 |
) |
|
(40,243 |
) |
|
(17,010 |
) |
|
(147,831 |
) |
|
(67,963 |
) |
|
|
(5,406 |
) |
Interest
expense |
(8,820 |
) |
|
(9,877 |
) |
|
(5,972 |
) |
|
(35,648 |
) |
|
(18,454 |
) |
|
|
(8,245 |
) |
Dividends |
(9,992 |
) |
|
(7,365 |
) |
|
5,567 |
|
|
(28,658 |
) |
|
(18,248 |
) |
|
|
— |
|
Levered free cash
flow |
$ |
9,531 |
|
|
$ |
24,251 |
|
|
$ |
35,425 |
|
|
$ |
45,787 |
|
|
$ |
44,948 |
|
|
|
$ |
15,194 |
|
Net cash (received)
paid for scheduled derivative settlements |
(8,679 |
) |
|
1,052 |
|
|
6,834 |
|
|
38,482 |
|
|
(3,068 |
) |
|
|
(534 |
) |
Levered free cash flow
unhedged |
$ |
852 |
|
|
$ |
25,303 |
|
|
$ |
42,259 |
|
|
$ |
84,269 |
|
|
$ |
41,880 |
|
|
|
$ |
14,660 |
|
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.
|
Berry Corp. (Successor) |
|
|
Berry LLC (Predecessor) |
|
Quarter Ended December 31, 2018 |
|
Quarter Ended September 30, 2018 |
|
Quarter Ended December 31, 2017 |
|
Year Ended December 31, 2018 |
|
Ten Months Ended December 31,
2017 |
|
|
Two Months Ended February 28, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands except per MBoe amounts) |
|
|
|
General and
administrative expenses |
$ |
16,130 |
|
|
$ |
13,429 |
|
|
$ |
12,480 |
|
|
$ |
54,026 |
|
|
$ |
56,009 |
|
|
|
$ |
7,964 |
|
Subtract: |
|
|
|
|
|
|
|
|
|
|
|
|
Non-recurring restructuring and other costs |
(1,414 |
) |
|
(1,598 |
) |
|
(2,904 |
) |
|
(6,773 |
) |
|
(30,325 |
) |
|
|
— |
|
Non-cash
stock compensation expense |
(3,183 |
) |
|
(1,125 |
) |
|
(917 |
) |
|
(6,585 |
) |
|
(1,819 |
) |
|
|
— |
|
Adjusted general and
administrative expenses |
$ |
11,533 |
|
|
$ |
10,706 |
|
|
$ |
8,659 |
|
|
$ |
40,668 |
|
|
$ |
23,865 |
|
|
|
$ |
7,964 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and
administrative expenses ($/Boe) |
$ |
6.27 |
|
|
$ |
5.33 |
|
|
$ |
4.87 |
|
|
$ |
5.48 |
|
|
$ |
5.93 |
|
|
|
$ |
3.68 |
|
Subtract: |
|
|
|
|
|
|
|
|
|
|
|
|
Non-recurring restructuring and other costs ($/Boe) |
(0.55 |
) |
|
(0.63 |
) |
|
(1.13 |
) |
|
(0.69 |
) |
|
(3.21 |
) |
|
|
— |
|
Non-cash
stock compensation expense ($/Boe) |
(1.24 |
) |
|
(0.45 |
) |
|
(0.36 |
) |
|
(0.67 |
) |
|
(0.19 |
) |
|
|
— |
|
Adjusted general and
administrative expenses ($/Boe) |
$ |
4.49 |
|
|
$ |
4.25 |
|
|
$ |
3.38 |
|
|
$ |
4.13 |
|
|
$ |
2.53 |
|
|
|
$ |
3.68 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total MBoe |
2,571 |
|
|
2,520 |
|
|
2,563 |
|
|
9,855 |
|
|
9,443 |
|
|
|
2,162 |
|
RESERVES AND PV-10
The following table summarizes our estimated
proved reserves and related PV-10 as of December 31, 2018.
|
December 31, 2018 |
|
California (San Joaquin and Ventura
basins) |
|
Rockies (Uinta and Piceance
basins) |
|
Total |
Proved
developed reserves: |
|
|
|
|
|
Oil
(MMBbl) |
66 |
|
7 |
|
73 |
Natural
Gas (Bcf) |
— |
|
76 |
|
76 |
NGLs
(MMBbl) |
— |
|
1 |
|
1 |
Total
(MMBoe)(a) |
66 |
|
21 |
|
87 |
Proved
undeveloped reserves: |
|
|
|
|
|
Oil
(MMBbl) |
40 |
|
2 |
|
42 |
Natural
Gas (Bcf) |
— |
|
85 |
|
85 |
NGLs
(MMBbl) |
— |
|
— |
|
— |
|
Total
(MMBoe)(a) |
40 |
|
16 |
|
56 |
Total proved
reserves: |
|
|
|
|
|
Oil
(MMBbl) |
106 |
|
9 |
|
115 |
Natural
Gas (Bcf) |
— |
|
161 |
|
161 |
NGLs
(MMBbl) |
— |
|
1 |
|
1 |
Total
(MMBoe)(a) |
106 |
|
37 |
|
143 |
|
|
|
|
|
|
PV-10
($MM)(b) |
$ |
2,027 |
|
$ |
125 |
|
$ |
2,152 |
__________(a) Natural gas volumes have
been converted to Boe based on energy content of six Mcf of gas to
one Bbl of oil. Barrels of oil equivalence does not necessarily
result in price equivalence. The price of natural gas on a barrel
of oil equivalent basis is currently substantially lower than the
corresponding price for oil and has been similarly lower for a
number of years. For example, in the year ended December 31,
2018, the average prices of ICE (Brent) oil and NYMEX (Henry Hub)
natural gas were $71.53 per Bbl and $3.09 per Mcf, respectively,
resulting in an oil-to-gas ratio of over 4 to 1 on an energy
equivalent basis.(b) For a definition of PV-10 and a
reconciliation to the standardized measure of discounted future net
cash flows, please see “Non-GAAP Financial Measures and
Reconciliations—PV-10.” PV-10 does not give effect to derivatives
transactions.
The following table provides a reconciliation of
PV-10 of our proved reserves to the standardized measure of
discounted future net cash flows at December 31, 2018:
|
At December 31, 2018 |
|
(in millions) |
California PV-10 |
$ |
2,027 |
|
Rockies PV-10 |
125 |
|
Total Company
PV-10 |
2,152 |
|
Less: present value of
future income taxes discounted at 10% |
(390 |
) |
Standardized measure of
discounted future net cash flows |
$ |
1,762 |
|
RESERVES REPLACEMENT AND COSTS
The total changes to our proved reserves in 2018, as well as the
related costs incurred, were as follows:
|
Total Company |
|
California |
|
(in MMBoe, except ratio and cost amounts) |
Extensions and
discoveries (B) |
22.4 |
|
|
19.3 |
|
Revisions of previous
estimates |
(10.1 |
) |
|
(0.4 |
) |
Purchases of
minerals |
0.9 |
|
|
0.9 |
|
Organic changes
(C) |
13.2 |
|
|
19.8 |
|
Sales of minerals |
(2.0 |
) |
|
— |
|
Total
reserves changes |
11.2 |
|
|
19.8 |
|
|
|
|
|
Production |
9.9 |
|
|
7.2 |
|
Reserve replacement
ratio |
114 |
% |
|
275 |
% |
|
|
|
|
Costs incurred
(development costs)(A) ($ millions) |
$ |
143.0 |
|
|
|
|
|
|
|
Finding &
Development costs per Boe |
|
|
|
All-In
(A)/(C) |
$ |
10.83 |
|
|
|
Program
(A)/(B) |
$ |
6.38 |
|
|
|
__________(a) All costs incurred in 2018 were development
costs.
Contact
Contact: Berry Petroleum Corporation
Todd Crabtree - Manager, Investor Relations
(661) 616-3811
ir@bry.com
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