- Quarterly GAAP cash flow from operating activities of $16.2
million; adjusted EBITDAX(1) of $21.6 million; GAAP net loss of
$0.28 per diluted share; adjusted net income(1) of $0.40 per
diluted share
- 2017 all-in finding and development costs of $7.46 per Boe
- Slick-water completion test is outperforming offset wells and
expectations
(1) Non-GAAP measure, see attached Reconciliation Schedules.
Bonanza Creek Energy, Inc. (NYSE:BCEI) (the "Company") today
announces its fourth quarter and full year 2017 financial and
operating results.
Fourth Quarter 2017 ResultsFor the fourth
quarter of 2017, the Company reported quarterly and annual
production volumes of 14.8 MBoe per day and 16.0 MBoe per day,
respectively. As previously announced, these production
figures exceeded the high end of the Company's guidance range. As
the Company brought online new wells in the back half of the year,
the product mix became increasingly oil-weighted as new wells with
enhanced completions and choke management increased oil cuts. The
oil-weighted growth from these wells along with increased commodity
prices resulted in a 6% increase in quarterly revenues, despite the
19% decrease in production volumes from the prior year. The table
below provides production data for the quarter and year ended
December 31, 2017.
|
|
|
|
|
|
|
Three Months Ended |
|
Twelve Months Ended |
Avg. Daily
Sales Volumes: |
|
12/31/2017 |
|
12/31/2016 |
|
% Change |
|
12/31/2017 |
|
12/31/2016 |
|
% Change |
Crude oil
(Bbls/d) |
|
8,350 |
|
|
9,058 |
|
|
(8)% |
|
|
8,442 |
|
|
11,776 |
|
|
(28)% |
|
Natural
gas (Mcf/d) |
|
22,176 |
|
|
29,664 |
|
|
(25)% |
|
|
25,408 |
|
|
33,419 |
|
|
(24)% |
|
Natural
gas liquids (Bbls/d) |
|
2,705 |
|
|
4,237 |
|
|
(36)% |
|
|
3,319 |
|
|
4,336 |
|
|
(23)% |
|
Crude oil
equivalent (Boe/d) |
|
14,750 |
|
|
18,239 |
|
|
(19)% |
|
|
15,995 |
|
|
21,682 |
|
|
(26)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product
Mix |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
|
57 |
% |
|
50 |
% |
|
|
|
53 |
% |
|
54 |
% |
|
|
Natural gas |
|
25 |
% |
|
27 |
% |
|
|
|
26 |
% |
|
26 |
% |
|
|
Natural gas
liquids |
|
18 |
% |
|
23 |
% |
|
|
|
21 |
% |
|
20 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales
Prices (before derivatives): |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (per
Bbl) |
|
$ |
52.00 |
|
|
$ |
41.86 |
|
|
24% |
|
|
$ |
47.56 |
|
|
$ |
35.31 |
|
|
35% |
|
Natural gas (per
Mcf) |
|
$ |
2.23 |
|
|
$ |
2.32 |
|
|
(4)% |
|
|
$ |
2.39 |
|
|
$ |
1.76 |
|
|
36% |
|
Natural gas liquids
(per Bbl) |
|
$ |
21.56 |
|
|
$ |
14.40 |
|
|
50% |
|
|
$ |
18.06 |
|
|
$ |
12.39 |
|
|
46% |
|
Crude oil equivalent
(per Boe) |
|
$ |
36.73 |
|
|
$ |
27.90 |
|
|
32% |
|
|
$ |
32.65 |
|
|
$ |
24.36 |
|
|
34% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product Revenue (in
thousands) |
|
$ |
49,850 |
|
|
$ |
46,823 |
|
|
6% |
|
|
$ |
190,617 |
|
|
$ |
193,335 |
|
|
(1)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Upon emerging from bankruptcy, the Company focused on reducing
operating expenses to right-size its cost structure with the
current environment. The table below provides selected cash
operating expenses comparatively on a quarterly and annual
year-over-year basis.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Twelve Months Ended |
Operating
Expenses |
|
12/31/2017 |
|
12/31/2016 |
|
% Change |
|
12/31/2017 |
|
12/31/2016 |
|
% Change |
Lease
operating expense |
|
$ |
10,066 |
|
|
$ |
9,743 |
|
|
3% |
|
|
$ |
38,990 |
|
|
$ |
43,671 |
|
|
(11)% |
|
Gas plant
and midstream operating expense |
|
$ |
3,314 |
|
|
$ |
2,628 |
|
|
26% |
|
|
$ |
11,882 |
|
|
$ |
12,826 |
|
|
(7)% |
|
Severance
and ad valorem taxes |
|
$ |
4,748 |
|
|
$ |
3,773 |
|
|
26% |
|
|
$ |
15,261 |
|
|
$ |
15,304 |
|
|
—% |
|
General
and Administrative |
|
$ |
11,356 |
|
|
$ |
27,474 |
|
|
(59)% |
|
|
$ |
57,768 |
|
|
$ |
77,065 |
|
|
(25)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On an annual basis, the Company reduced its cash operating costs
substantially as a result of various cost-saving measures that were
implemented during 2017. While annual costs were reduced year over
year, fourth quarter expenses increased compared to 2016. These
increased costs resulted from increased well servicing expenses in
the Mid-Continent region and implementation costs of compressor
swaps that occurred in the Company's Rocky Mountain region. During
the fourth quarter, the Company began a program to swap out
existing compressors in the Wattenberg field to reduce its future
rental fees. Compressor exchanges will continue into 2018 and the
associated costs are reflected in the Company's lease
operating expense guidance, provided on January 29, 2018. The
Company expects its operating expenses to be reduced on a per-unit
basis in 2018 as production volumes grow and field-level
infrastructure capacity is optimally utilized.
The table below provides a regional breakout of the Company's
lease operating expense and gas plant and midstream operating
expenses.
|
Regional Breakout |
|
Three Months Ended December 31,
2017 |
|
Rocky Mountain |
|
Mid-Continent |
|
Total Company |
|
($M) |
|
($/Boe) |
|
($M) |
|
($/Boe) |
|
($M) |
|
($/Boe) |
Lease operating
expense |
$ |
6,728 |
|
|
$ |
6.11 |
|
|
$ |
3,338 |
|
|
$ |
13.04 |
|
|
$ |
10,066 |
|
|
$ |
7.42 |
|
Gas plant and midstream
operating expense |
1,802 |
|
|
1.64 |
|
|
1,512 |
|
|
5.90 |
|
|
3,314 |
|
|
2.44 |
|
Total |
$ |
8,530 |
|
|
$ |
7.75 |
|
|
$ |
4,850 |
|
|
$ |
18.94 |
|
|
$ |
13,380 |
|
|
$ |
9.86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reported net loss for the fourth quarter of 2017 was $5.8
million, or $0.28 per diluted share, compared to a net loss of
$67.3 million, or $1.37 per diluted share, for the fourth quarter
of 2016. Adjusted net income for the fourth quarter of 2017
was $8.3 million, or $0.40 per diluted share, compared to adjusted
net loss of $27.9 million, or $0.57 per diluted share, for the
fourth quarter of 2016. The increase in GAAP and adjusted net
income over the prior year was driven by improved cost structure,
greater oil-weighted production and an increase in commodity prices
over the prior period.
Adjusted EBITDAX for the fourth quarter of 2017 was $21.6
million, a 49% increase compared to $14.5 million for the fourth
quarter of 2016.
Adjusted net income (loss) and adjusted EBITDAX are non-GAAP
financial measures. Please refer to the respective reconciliations
in the schedules at the end of this release for additional
information about these measures.
The table below summarizes the Company's annual results as
compared to previously provided guidance.
|
|
|
|
Guidance vs
Actual Summary |
|
|
|
|
Twelve Months Ended December 31,
2017 |
|
Guidance |
|
Actual |
Production (MBoe/d) |
15.7 –
15.9 |
|
16.0 |
|
Lease
operating expense ($/Boe) |
$6.50
– $7.00 |
|
$ |
6.68 |
|
Midstream
($/Boe) |
$1.90
– $2.10 |
|
$ |
2.04 |
|
Cash
G&A ($MM)* |
$41 –
$43 |
|
$ |
44 |
|
Production taxes (% of pre-derivative realization) |
7% –
8% |
|
8.0 |
% |
CAPEX
($MM) |
$108 –
$115 |
|
$ |
110 |
|
|
|
|
|
* Cash G&A guidance is a non-GAAP measure that is exclusive
of the Company's stock based compensation. The Company does not
guide to GAAP G&A expense as it has excessive uncertainty due
to the stock based compensation portion of GAAP G&A. Please
refer to the non-GAAP disclosure at the end of this release for
information regarding cash G&A. |
|
The Company reported annual production above the high-end of
guidance. With the exception of cash G&A, costs and capital
were reported within the guided range. The Company's cash G&A
expense for the year was above the high end of the Company's 2017
guidance range as a result of higher than expected advisory fees in
the fourth quarter related to the previously proposed merger with
SandRidge Energy, Inc.
2017 Proved Reserves, Costs Incurred, and Finding and
Development Costs
As previously reported, Bonanza Creek's year-end 2017 proved
reserves were 102.0 MMBoe, which represented a 13% increase from
2016. The Company's year-end 2017 proved reserves were comprised of
52.9 MMBbls of oil, 22.8 MMBbls of NGLs, and 157.7 Bcf of natural
gas and were 53% proved developed. At year end the Company's
proved reserves PV-10 utilizing SEC pricing was $598 million. If
SEC pricing for oil and gas increased by 10% to $56.47 per barrel
WTI and $3.28 per Mcf Henry Hub, the Company's proved reserves
PV-10 would increase by 27% to $760 million. If, rather than flat
pricing, 2017 year-end strip pricing is used, the Company's PV-10
value for its proved reserves would be $656 million. Please see
Schedule 9 at the end of this release for information on SEC
pricing and a reconciliation from PV-10 to the GAAP figure
"Standardized Measure of Oil and Gas." All-in finding and
development costs for 2017 were $7.46 per Boe, based on the
Company's 2017 costs incurred of $127.5 million and all-in
additions of 17,090 MBoe. A breakout of the Company's costs
incurred are provided in the table below.
Costs Incurred
(in
thousands) |
For the Year EndedDecember 31,
2017 |
|
|
|
Acquisition(1) |
|
$ |
5,828 |
|
Development(2) |
|
|
117,229 |
|
Exploration |
|
|
4,440 |
|
Total(3) |
|
$ |
127,497 |
|
(1) Acquisition costs for unproved properties were $5.8 million.
There were no acquisition costs for proved properties in 2017.(2)
Development costs include workover costs of $6.1 million.(3)
Includes amounts relating to asset retirement obligations of $8.3
million.
Proved Reserve Roll-Forward
|
MBoe |
Balance as of December
31, 2016 |
90,651 |
|
Extensions, discoveries
and infills |
15,547 |
|
Revisions to previous
estimates |
1,543 |
|
Production |
(5,719 |
) |
Balance as of December
31, 2017 |
102,022 |
|
|
|
|
2018 Production, Capital, and Expense
GuidanceThe table below reiterates the Company's
previously provided 2018 guidance:
|
|
|
|
|
Guidance Summary |
|
|
|
|
|
Three Months EndedMarch 31, 2018 |
|
|
Twelve Months EndedDecember 31, 2018 |
|
|
|
|
|
Production
(MBoe/d) |
16.0 -
16.6 |
|
|
17.7 -
18.7 |
LOE ($/Boe) |
|
|
|
$5.00
- $6.00 |
Midstream expense
($/Boe) |
|
|
|
$1.40
- $1.80 |
Recurring cash G&A
($MM)(1) |
|
|
|
$1.40
- $1.80 |
Production taxes (% of
pre-derivative realization) |
|
|
|
7% -
8% |
Total CAPEX ($MM) |
|
|
|
$280 -
$320 |
Rockies Oil
Differential (2) |
|
|
|
$5.85
off WTI |
|
|
|
|
|
(1)
Recurring cash G&A guidance is a non-GAAP measure that is
defined as GAAP G&A expense less stock based compensation and
anticipated costs for permanent CEO compensation. The Company does
not guide to GAAP G&A expense as it has excessive uncertainty
due to the stock based compensation portion of GAAP G&A. Please
refer to the Non-GAAP disclosure at the end of this release for
information regarding Recurring cash G&A. |
(2) Assumes strip pricing as of January 23, 2018. |
|
Operational Update
During the fourth quarter, the Company turned online two
adjacent pads in its central legacy acreage, the J21 and T21, which
now have approximately 120 days of production data. These two pads
consisted of a total of five wells, two SRL and three XRL, and
tested an average of approximately 1,700 pounds of proppant per
lateral foot. One of the SRL wells on the T21 pad utilized a
slick-water completion design, which increased the fluid intensity
by over 100%. While the wells on both of the pads are generally 5
performing in line with expectations, the one slick-water well on
the T21 pad stands out with significant outperformance when
compared to the other wells on these adjacent pads. The slick-water
SRL that was tested in the central acreage is tracking the
performance of the 500 MBoe per well average of the North Platte
44-13 pad on the Company's west acreage. The Company is very
encouraged by the slick-water results and plans to test additional
slick-water designs in the first half of the year in various
portions of the Company's Wattenberg acreage.
At the beginning of 2018, the Company turned online its 8-SRL
F26 pad, which utilized an average of approximately 2,000 pounds of
proppant per lateral foot and has also recently turned online its
first French Lake well. The Company is currently drilling its four
XRL B-28 pad on its eastern acreage and is completing its remaining
seven French Lake wells. These remaining French Lake wells are
expected to be turned online by the end of the second quarter.
The Company has provided an updated investor presentation to its
website, under the "For Investors" section of its corporate website
at www.bonanzacrk.com. Included in this presentation are updated
production results and corresponding type curves.
Fourth Quarter Earnings Release and Conference
Call
The Company announces that in conjunction with this release of
it fourth quarter 2017 operating and financial results, it will
host a conference call to discuss these results on March 15, 2018
at 9:00 a.m. Mountain Time. A live webcast and replay of this event
will be available on the Investor Relations section of the
Company’s website at www.bonanzacrk.com. A dial-in replay of the
event will be available through March 29, 2018. Dial-in information
for the conference call is included below.
Type |
Phone Number |
Passcode |
Live participant |
877-793-4362 |
1899728 |
Replay |
855-859-2056 |
1899728 |
About Bonanza Creek Energy, Inc.
Bonanza Creek Energy, Inc. is an independent oil and natural gas
company engaged in the acquisition, exploration, development and
production of onshore oil and associated liquids-rich natural gas
in the United States. The Company’s assets and operations are
concentrated primarily in the Rocky Mountains in the Wattenberg
Field, focused on the Niobrara and Codell formations, and in
southern Arkansas, focused on oily Cotton Valley sands. The
Company’s common shares are listed for trading on the NYSE under
the symbol: “BCEI.” For more information about the Company, please
visit www.bonanzacrk.com. Please note that the Company routinely
posts important information about the Company under the Investor
Relations section of its website.
Forward-Looking Statements
This press release contains 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 activities, events or developments that the
Company expects, believes or anticipates will or may occur in the
future are forward-looking statements. These statements are based
on certain assumptions made by the Company based on management’s
experience, perception of historical trends and technical analyses,
current conditions, anticipated future developments and other
factors believed to be appropriate and reasonable by management.
When used in this press release, the words “will,” “potential,”
“believe,” “estimate,” “intend,” “expect,” “may,” “should,”
“anticipate,” “could,” “plan,” “predict,” “project,” “profile,”
“model” or their negatives, other similar expressions or the
statements that include those words, are intended to identify
forward-looking statements, although not all forward-looking
statements contain such identifying words. These statements include
statements regarding development and completion expectations and
strategy; and decreasing operating and capital costs. Such
statements are subject to a number of assumptions, risks and
uncertainties, many of which are beyond the control of the Company,
that may cause actual results to differ materially from those
implied or expressed by the forward-looking statements, including
the following: changes in natural gas, oil and NGL prices; general
economic conditions, including the performance of financial markets
and interest rates; drilling results; shortages of oilfield
equipment, services and personnel; operating risks such as
unexpected drilling conditions; ability to acquire adequate
supplies of water; risks related to derivative instruments; access
to adequate gathering systems and pipeline take-away capacity; and
pipeline and refining capacity constraints. Further information on
such assumptions, risks and uncertainties is available in the
Company’s SEC filings. We refer you to the discussion of risk
factors in our Annual Report on Form 10-K for the year ended
December 31, 2017, filed on March 14, 2018, and other filings
submitted by us to the Securities Exchange Commission. The
Company’s SEC filings are available on the Company’s website at
www.bonanzacrk.com and on the SEC’s website at www.sec.gov.
All of the forward-looking statements made in this press release
are qualified by these cautionary statements. Any forward-looking
statement speaks only as of the date on which such statement is
made, including guidance, and the Company undertakes 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.
For further information, please contact:James
R. EdwardsDirector - Investor
Relations720-440-6136jedwards@bonanzacrk.com
Schedule 1: Statement of Operations(in thousands, expect for per
share amounts, unaudited)
|
Successor |
|
|
Predecessor |
|
Three MonthsEnded December31,
2017 |
|
|
Three MonthsEnded December31,
2016 |
Operating net
revenues: |
|
|
|
|
Oil and
gas sales |
$ |
50,189 |
|
|
|
$ |
47,266 |
|
Operating
expenses: |
|
|
|
|
Lease
operating expense |
10,066 |
|
|
|
9,743 |
|
Gas plant
and midstream operating expense |
3,314 |
|
|
|
2,628 |
|
Severance
and ad valorem taxes |
4,748 |
|
|
|
3,773 |
|
Exploration |
3,386 |
|
|
|
3 |
|
Depreciation, depletion and amortization |
9,126 |
|
|
|
26,613 |
|
Abandonment and impairment of unproved properties |
— |
|
|
|
229 |
|
Unused
commitments |
— |
|
|
|
4,226 |
|
Contract
settlement expense |
— |
|
|
|
21,000 |
|
General
and administrative (including $1,035 and $1,643, respectively, of
stock compensation) |
11,356 |
|
|
|
27,474 |
|
Total
operating expenses |
41,996 |
|
|
|
95,689 |
|
Income (loss) from
operations |
8,193 |
|
|
|
(48,423 |
) |
Other income
(expense): |
|
|
|
|
Derivative gain (loss) |
(12,603 |
) |
|
|
490 |
|
Interest
expense |
(313 |
) |
|
|
(15,842 |
) |
Other
income (loss) |
(1,421 |
) |
|
|
(3,559 |
) |
Total
other income (expense) |
(14,337 |
) |
|
|
(18,911 |
) |
Loss from operations
before taxes |
(6,144 |
) |
|
|
(67,334 |
) |
Income
tax benefit (expense) |
376 |
|
|
|
— |
|
Net loss |
$ |
(5,768 |
) |
|
|
$ |
(67,334 |
) |
|
|
|
|
|
Net loss
per basic common share |
$ |
(0.28 |
) |
|
|
$ |
(1.37 |
) |
|
|
|
|
|
Net loss
per diluted common share |
$ |
(0.28 |
) |
|
|
$ |
(1.37 |
) |
|
|
|
|
|
Basic weighted-average
common shares outstanding |
20,454 |
|
|
|
49,388 |
|
Diluted
weighted-average common shares outstanding |
20,454 |
|
|
|
49,388 |
|
- The Predecessor Company followed the two-class method when
computing the basic and diluted loss per share, which allocates
earnings between common shareholders and unvested participating
securities. The Successor Company follows the treasury stock method
to compute basic and diluted net loss per share. Please refer to
Note 14 – Earnings per Share in the Company's Annual Report on Form
10-K for the year ended December 31, 2017, for a detailed
calculation.
|
|
|
Successor |
|
|
Predecessor |
|
|
April 29, 2017throughDecember
31,2017 |
|
|
January 1,2017 throughApril 28,
2017 |
|
TwelveMonths EndedDecember
31,2016 |
Operating net
revenues: |
|
|
|
|
|
|
|
Oil and
gas sales |
|
$ |
123,535 |
|
|
|
$ |
68,589 |
|
|
$ |
195,295 |
|
Operating
expenses: |
|
|
|
|
|
|
|
Lease
operating expense |
|
25,862 |
|
|
|
13,128 |
|
|
43,671 |
|
Gas plant
and midstream operating expense |
|
8,341 |
|
|
|
3,541 |
|
|
12,826 |
|
Severance
and ad valorem taxes |
|
9,590 |
|
|
|
5,671 |
|
|
15,304 |
|
Exploration |
|
3,745 |
|
|
|
3,699 |
|
|
946 |
|
Depreciation, depletion and amortization |
|
21,312 |
|
|
|
28,065 |
|
|
111,215 |
|
Impairment of oil and gas properties |
|
— |
|
|
|
— |
|
|
10,000 |
|
Abandonment and impairment of unproved properties |
|
— |
|
|
|
— |
|
|
24,692 |
|
Unused
commitments |
|
— |
|
|
|
993 |
|
|
7,686 |
|
Contract
settlement expense |
|
— |
|
|
|
— |
|
|
21,000 |
|
General
and administrative (including $11,630, $2,116, and $8,892,
respectively, of stock compensation) |
|
42,676 |
|
|
|
15,092 |
|
|
77,065 |
|
Total
operating expenses |
|
111,526 |
|
|
|
70,189 |
|
|
324,405 |
|
Income (loss) from
operations |
|
12,009 |
|
|
|
(1,600 |
) |
|
(129,110 |
) |
Other income
(expense): |
|
|
|
|
|
|
|
Derivative gain (loss) |
|
(15,365 |
) |
|
|
— |
|
|
(11,234 |
) |
Interest
expense |
|
(773 |
) |
|
|
(5,656 |
) |
|
(62,058 |
) |
Reorganization items, net |
|
— |
|
|
|
8,808 |
|
|
— |
|
Gain on
termination fee |
|
— |
|
|
|
— |
|
|
6,000 |
|
Other
income (loss) |
|
(1,267 |
) |
|
|
1,108 |
|
|
(2,548 |
) |
Total
other income (expense) |
|
(17,405 |
) |
|
|
4,260 |
|
|
(69,840 |
) |
Income (loss) from
operations before taxes |
|
(5,396 |
) |
|
|
2,660 |
|
|
(198,950 |
) |
Income
tax benefit (expense) |
|
376 |
|
|
|
— |
|
|
— |
|
Net income (loss) |
|
$ |
(5,020 |
) |
|
|
$ |
2,660 |
|
|
$ |
(198,950 |
) |
|
|
|
|
|
|
|
|
Net
income (loss) per basic common share |
|
$ |
(0.25 |
) |
|
|
$ |
0.05 |
|
|
$ |
(4.04 |
) |
|
|
|
|
|
|
|
|
Net
income (loss) per diluted common share |
|
$ |
(0.25 |
) |
|
|
$ |
0.05 |
|
|
$ |
(4.04 |
) |
|
|
|
|
|
|
|
|
Basic weighted-average
common shares outstanding |
|
20,427 |
|
|
|
49,559 |
|
|
49,268 |
|
Diluted
weighted-average common shares outstanding |
|
20,427 |
|
|
|
50,971 |
|
|
49,268 |
|
- The Predecessor Company followed the two-class method when
computing the basic and diluted loss per share, which allocates
earnings between common shareholders and unvested participating
securities. The Successor Company follows the treasury stock method
to compute basic and diluted net loss per share. Please refer to
Note 14 – Earnings per Share in the Company's Annual Report on Form
10-K for the year ended December 31, 2017, for a detailed
calculation.
Schedule 2: Statement of Cash Flows(in thousands, unaudited)
|
Successor |
|
|
Predecessor |
|
Three MonthsEnded December31,
2017 |
|
|
Three MonthsEnded December31,
2016 |
Cash flows from
operating activities: |
|
|
|
|
Net
loss |
$ |
(5,768 |
) |
|
|
$ |
(67,334 |
) |
Adjustments to reconcile net loss to net cash provided by (used in)
operating activities: |
|
|
|
|
Depreciation, depletion and amortization |
9,126 |
|
|
|
26,613 |
|
Abandonment and impairment of unproved properties |
— |
|
|
|
229 |
|
Well
abandonment costs and dry hole expense |
— |
|
|
|
(33 |
) |
Stock-based compensation |
1,035 |
|
|
|
1,643 |
|
Amortization of deferred financing costs and debt premium |
— |
|
|
|
475 |
|
Derivative (gain) loss |
12,603 |
|
|
|
(490 |
) |
Derivative cash settlements |
(1,464 |
) |
|
|
2,584 |
|
Inventory
write-off |
1,758 |
|
|
|
4,390 |
|
Other |
4 |
|
|
|
(450 |
) |
Changes
in current assets and liabilities: |
|
|
|
|
Accounts
receivable |
(2,450 |
) |
|
|
5,840 |
|
Prepaid
expenses and other assets |
(1,899 |
) |
|
|
(791 |
) |
Accounts
payable and accrued liabilities |
3,441 |
|
|
|
11,636 |
|
Settlement of asset retirement obligations |
(231 |
) |
|
|
(327 |
) |
Net cash provided by (used in) operating activities |
16,155 |
|
|
|
(16,015 |
) |
Cash flows from
investing activities: |
|
|
|
|
Acquisition of oil and gas properties |
(309 |
) |
|
|
821 |
|
Exploration and development of oil and gas properties |
(34,020 |
) |
|
|
(4,853 |
) |
(Increase) decrease in restricted cash |
(4 |
) |
|
|
5,094 |
|
Additions
to property and equipment - non oil and gas |
(207 |
) |
|
|
(240 |
) |
Net cash provided by (used in) investing activities |
(34,540 |
) |
|
|
822 |
|
Cash flows from
financing activities: |
|
|
|
|
Payments
to predecessor credit facility |
— |
|
|
|
(37,666 |
) |
Payment
of employee tax withholdings in exchange for the return of common
stock |
— |
|
|
|
(6 |
) |
Net cash provided by (used in) financing activities |
— |
|
|
|
(37,672 |
) |
Net change in cash and
cash equivalents |
(18,385 |
) |
|
|
(52,865 |
) |
Cash and cash
equivalents: |
|
|
|
|
Beginning
of period |
31,096 |
|
|
|
133,430 |
|
End of
period |
$ |
12,711 |
|
|
|
$ |
80,565 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor |
|
|
Predecessor |
|
|
April 29,2017throughDecember31,
2017 |
|
|
January 1,2017throughApril
28,2017 |
|
TwelveMonthsEndedDecember31, 2016 |
Cash flows from
operating activities: |
|
|
|
|
|
|
|
Net
income (loss) |
|
$ |
(5,020 |
) |
|
|
$ |
2,660 |
|
|
$ |
(198,950 |
) |
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities: |
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
21,312 |
|
|
|
28,065 |
|
|
111,215 |
|
Non-cash
reorganization items |
|
— |
|
|
|
(44,160 |
) |
|
— |
|
Impairment of oil and gas properties |
|
— |
|
|
|
— |
|
|
10,000 |
|
Abandonment and impairment of unproved properties |
|
— |
|
|
|
— |
|
|
24,692 |
|
Well
abandonment costs dry hole expense |
|
75 |
|
|
|
2,931 |
|
|
872 |
|
Stock-based compensation |
|
11,630 |
|
|
|
2,116 |
|
|
8,892 |
|
Amortization of deferred financing costs and debt premium |
|
— |
|
|
|
374 |
|
|
3,180 |
|
Derivative (gain) loss |
|
15,365 |
|
|
|
— |
|
|
11,234 |
|
Derivative cash settlements |
|
(1,464 |
) |
|
|
— |
|
|
18,333 |
|
Inventory
write-off |
|
1,758 |
|
|
|
— |
|
|
4,390 |
|
Other |
|
11 |
|
|
|
18 |
|
|
(323 |
) |
Changes
in current assets and liabilities: |
|
|
|
|
|
|
|
Accounts
receivable |
|
(4,477 |
) |
|
|
(6,640 |
) |
|
35,282 |
|
Prepaid
expenses and other assets |
|
(1,979 |
) |
|
|
963 |
|
|
(1,838 |
) |
Accounts
payable and accrued liabilities |
|
(8,470 |
) |
|
|
(5,880 |
) |
|
(11,616 |
) |
Settlement of asset retirement obligations |
|
(1,167 |
) |
|
|
(331 |
) |
|
(800 |
) |
Net cash provided by (used in) operating activities |
|
27,574 |
|
|
|
(19,884 |
) |
|
14,563 |
|
Cash flows from
investing activities: |
|
|
|
|
|
|
|
Acquisition of oil and gas properties |
|
(5,383 |
) |
|
|
(445 |
) |
|
(98 |
) |
Payments
of contractual obligation |
|
— |
|
|
|
— |
|
|
(12,000 |
) |
Exploration and development of oil and gas properties |
|
(76,375 |
) |
|
|
(5,123 |
) |
|
(52,344 |
) |
(Increase) decrease in restricted cash |
|
(16 |
) |
|
|
118 |
|
|
(2,613 |
) |
Additions
to property and equipment - non oil and gas |
|
(874 |
) |
|
|
(454 |
) |
|
(346 |
) |
Net cash used in investing activities |
|
(82,648 |
) |
|
|
(5,904 |
) |
|
(67,401 |
) |
Cash flows from
financing activities: |
|
|
|
|
|
|
|
Proceeds
from predecessor credit facility |
|
— |
|
|
|
— |
|
|
209,000 |
|
Payments
to predecessor credit facility |
|
— |
|
|
|
(191,667 |
) |
|
(96,333 |
) |
Proceeds
from sale of common stock |
|
— |
|
|
|
207,500 |
|
|
— |
|
Payment
of employee tax withholdings in exchange for the return of common
stock |
|
(2,398 |
) |
|
|
(427 |
) |
|
(289 |
) |
Deferred
financing costs |
|
— |
|
|
|
— |
|
|
(316 |
) |
Net cash provided by (used in) financing activities |
|
(2,398 |
) |
|
|
15,406 |
|
|
112,062 |
|
Net change in cash and
cash equivalents |
|
(57,472 |
) |
|
|
(10,382 |
) |
|
59,224 |
|
Cash and cash
equivalents: |
|
|
|
|
|
|
|
Beginning
of period |
|
70,183 |
|
|
|
80,565 |
|
|
21,341 |
|
End of
period |
|
$ |
12,711 |
|
|
|
$ |
70,183 |
|
|
$ |
80,565 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Schedule 3: Balance Sheets(in thousands,
unaudited)
|
Successor |
|
|
Predecessor |
|
As ofDecember 31, 2017 |
|
|
As ofDecember 31, 2016 |
ASSETS |
|
|
|
|
Current assets: |
|
|
|
|
Cash and
cash equivalents |
$ |
12,711 |
|
|
|
$ |
80,565 |
|
Accounts
receivable: |
|
|
|
|
Oil and
gas sales |
28,549 |
|
|
|
14,479 |
|
Joint
interest and other |
3,831 |
|
|
|
6,784 |
|
Prepaid
expenses and other |
6,555 |
|
|
|
5,915 |
|
Inventory
of oilfield equipment |
1,019 |
|
|
|
4,685 |
|
Derivative asset |
488 |
|
|
|
— |
|
Total current assets |
53,153 |
|
|
|
112,428 |
|
Property and equipment
(successful efforts method): |
|
|
|
|
Proved
properties |
555,341 |
|
|
|
2,525,587 |
|
Less:
accumulated depreciation, depletion and amortization |
(17,032 |
) |
|
|
(1,694,483 |
) |
Total
proved properties, net |
538,309 |
|
|
|
831,104 |
|
Unproved
properties |
183,843 |
|
|
|
163,369 |
|
Wells in
progress |
47,224 |
|
|
|
18,250 |
|
Other
property and equipment, net of accumulated depreciation of $2,224
in 2017 and $11,206 in 2016 |
4,706 |
|
|
|
6,245 |
|
Total
property and equipment, net |
774,082 |
|
|
|
1,018,968 |
|
Long-term derivative
asset |
6 |
|
|
|
— |
|
Other noncurrent
assets |
3,130 |
|
|
|
3,082 |
|
Total assets |
$ |
830,371 |
|
|
|
$ |
1,134,478 |
|
LIABILITIES AND STOCKHOLDERS’ EQUITY |
|
|
|
|
Current
liabilities: |
|
|
|
|
Accounts
payable and accrued expenses |
$ |
62,129 |
|
|
|
$ |
61,328 |
|
Oil and
gas revenue distribution payable |
15,667 |
|
|
|
23,773 |
|
Derivative liability |
11,423 |
|
|
|
— |
|
Predecessor credit facility - current portion |
— |
|
|
|
191,667 |
|
Senior
Notes - current portion |
— |
|
|
|
793,698 |
|
Total
current liabilities |
89,219 |
|
|
|
1,070,466 |
|
Long-term
liabilities: |
|
|
|
|
Ad
valorem taxes |
11,584 |
|
|
|
14,118 |
|
Long-term
derivative liability |
2,972 |
|
|
|
— |
|
Asset
retirement obligations for oil and gas properties |
38,262 |
|
|
|
30,833 |
|
Total liabilities |
142,037 |
|
|
|
1,115,417 |
|
Commitments and
contingencies |
|
|
|
|
Stockholders’
equity: |
|
|
|
|
Predecessor preferred stock, $.001 par value, 25,000,000 shares
authorized, none outstanding as of December 31, 2016 |
— |
|
|
|
— |
|
Predecessor common stock, $.001 par value, 225,000,000 shares
authorized, 49,660,683 issued and outstanding as of
December 31, 2016 |
— |
|
|
|
49 |
|
Successor
preferred stock, $.01 par value, 25,000,000 shares authorized, none
outstanding as of December 31, 2017 |
— |
|
|
|
— |
|
Successor
common stock, $.01 par value, 225,000,000 shares authorized,
20,453,549 issued and outstanding as of December 31, 2017 |
4,286 |
|
|
|
— |
|
Additional paid-in capital |
689,068 |
|
|
|
814,990 |
|
Retained
deficit |
(5,020 |
) |
|
|
(795,978 |
) |
Total
stockholders’ equity |
688,334 |
|
|
|
19,061 |
|
Total liabilities and
stockholders’ equity |
$ |
830,371 |
|
|
|
$ |
1,134,478 |
|
|
|
|
|
|
|
|
|
|
Schedule 4: Volumes and Realized Prices (Before and After the
Effect of Commodity Hedges)(unaudited)
|
Three Months Ended |
|
December 31, |
|
2017 |
|
2016 |
Wellhead
Volumes and Prices |
|
|
|
|
|
|
|
Crude Oil and
Condensate Sales Volumes (Bbl/d) |
|
|
|
Rocky Mountains |
6,762 |
|
7,042 |
Mid-Continent |
1,588 |
|
2,016 |
Total |
8,350 |
|
9,058 |
|
|
|
|
Crude Oil and
Condensate Realized Prices ($/Bbl) |
|
|
|
Rocky Mountains |
$ |
51.30 |
|
$ |
39.98 |
Mid-Continent |
54.95 |
|
48.44 |
Composite (before
derivatives) |
52.00 |
|
41.86 |
Composite (after
derivatives) |
50.06 |
|
44.96 |
|
|
|
|
Natural Gas
Liquids Sales Volumes (Bbl/d) |
|
|
|
Rocky Mountains |
2,311 |
|
3,695 |
Mid-Continent |
394 |
|
542 |
Total |
2,705 |
|
4,237 |
|
|
|
|
Natural Gas
Liquids Realized Prices ($/Bbl) |
|
|
|
Rocky Mountains |
$ |
19.66 |
|
$ |
13.19 |
Mid-Continent |
32.72 |
|
22.65 |
Composite (before
derivatives) |
21.56 |
|
14.40 |
Composite (after
derivatives) |
21.56 |
|
14.40 |
|
|
|
|
Natural Gas
Sales Volumes (Mcf/d) |
|
|
|
Rocky Mountains |
17,397 |
|
23,061 |
Mid-Continent |
4,779 |
|
6,603 |
Total |
22,176 |
|
29,664 |
|
|
|
|
Natural Gas
Realized Prices ($/Mcf) |
|
|
|
Rocky Mountains |
$ |
2.08 |
|
$ |
2.12 |
Mid-Continent |
2.77 |
|
3.01 |
Composite (before
derivatives) |
2.23 |
|
2.32 |
Composite (after
derivatives) |
2.24 |
|
2.32 |
|
|
|
|
Crude Oil
Equivalent Sales Volumes (Boe/d) |
|
|
|
Rocky Mountains |
11,972 |
|
14,581 |
Mid-Continent |
2,778 |
|
3,658 |
Total |
14,750 |
|
18,239 |
|
|
|
|
Crude Oil
Equivalent Sales Prices ($/Boe) |
|
|
|
Rocky Mountains |
$ |
35.79 |
|
$ |
26.01 |
Mid-Continent |
40.81 |
|
35.47 |
Composite (before
derivatives) |
36.73 |
|
27.90 |
Composite (after
derivatives) |
35.66 |
|
29.44 |
|
|
|
|
Total Sales
Volumes (MBoe) |
1,357.0 |
|
1,678.0 |
|
|
|
|
Schedule 5: Per unit operating margins(unaudited)
|
For the Three MonthsEnded December
31, |
|
For the Twelve MonthsEnded December
31, |
|
2017 |
|
2016 |
|
PercentChange |
|
2017 |
|
2016 |
|
PercentChange |
Per Unit Costs
($/Boe) |
|
|
|
|
|
|
|
|
|
|
|
Realized
price (before derivatives) |
$ |
36.73 |
|
|
$ |
27.90 |
|
|
32% |
|
|
$ |
32.65 |
|
|
$ |
24.36 |
|
|
34% |
|
Lease
operating expense |
$ |
7.42 |
|
|
$ |
5.81 |
|
|
28% |
|
|
$ |
6.68 |
|
|
$ |
5.50 |
|
|
21% |
|
Midstream
expense |
$ |
2.44 |
|
|
$ |
1.57 |
|
|
55% |
|
|
$ |
2.04 |
|
|
$ |
1.62 |
|
|
26% |
|
Severance
and Ad Valorem |
$ |
3.50 |
|
|
$ |
2.25 |
|
|
56% |
|
|
$ |
2.61 |
|
|
$ |
1.93 |
|
|
35% |
|
Cash
General and Administrative (1) |
$ |
7.61 |
|
|
$ |
15.39 |
|
|
(51)% |
|
|
$ |
7.54 |
|
|
$ |
8.59 |
|
|
(12)% |
|
Total
cash operating costs |
$ |
20.97 |
|
|
$ |
25.02 |
|
|
(16)% |
|
|
$ |
18.87 |
|
|
$ |
17.64 |
|
|
7% |
|
Cash
operating margin (before derivatives) |
$ |
15.76 |
|
|
$ |
2.88 |
|
|
447% |
|
|
$ |
13.78 |
|
|
$ |
6.72 |
|
|
105% |
|
Derivative Cash Settlements |
$ |
(1.07) |
|
|
$ |
1.54 |
|
|
(169)% |
|
|
$ |
(0.25) |
|
|
$ |
2.31 |
|
|
(111)% |
|
Cash
operating margin (after derivatives) |
$ |
14.69 |
|
|
$ |
4.42 |
|
|
232% |
|
|
$ |
13.53 |
|
|
$ |
9.03 |
|
|
50% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash
items |
|
|
|
|
|
|
|
|
|
|
|
Depreciation Depletion and Amortization |
$ |
6.72 |
|
|
$ |
15.86 |
|
|
(58)% |
|
|
$ |
8.46 |
|
|
$ |
14.01 |
|
|
(40)% |
|
Non-cash
General and Administrative |
$ |
0.76 |
|
|
$ |
0.98 |
|
|
(22)% |
|
|
$ |
2.35 |
|
|
$ |
1.12 |
|
|
110% |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Cash general and administrative expense excludes stock
based compensation of $1.0 million and $1.6 million for the
three-month periods ended December 31, 2017 and 2016, respectively,
and $13.7 million and $8.9 million for the twelve-month periods
ended December 31, 2017 and 2016, respectively. |
|
Schedule 6: Adjusted Net Income (Loss)(in thousands, except per
share amounts, unaudited)
Adjusted net income (loss) is a supplemental non-GAAP financial
measure that is used by management and external users of the
Company’s consolidated financial statements, such as industry
analysts, investors, lenders and rating agencies. The Company
defines adjusted net income (loss) as net income (loss) after
adjusting first for (1) the impact of certain non-cash items,
including unrealized gains and losses on unsettled derivative
instruments, impairment of oil and gas properties, other similar
non-cash charges (2) one-time transactions and then (3) the
non-cash and one time items’ impact on taxes based on an applicable
rate that approximates the Company's effective tax rate in each
period. Adjusted net income (loss) is not a measure of net income
(loss) as determined by GAAP.
The following table provides a reconciliation of net loss (GAAP)
to adjusted net income (loss) (non-GAAP):
|
Three Months Ended |
|
Twelve Months Ended |
|
December 31, |
|
December 31, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
Net
loss |
$ |
(5,768 |
) |
|
$ |
(67,334 |
) |
|
$ |
(2,360 |
) |
|
$ |
(198,950 |
) |
|
|
|
|
|
|
|
|
Adjustments to net
loss: |
|
|
|
|
|
|
|
Derivative (gain) loss |
12,603 |
|
|
(490 |
) |
|
15,365 |
|
|
11,234 |
|
Derivative cash settlements |
(1,464 |
) |
|
2,584 |
|
|
(1,464 |
) |
|
18,333 |
|
Impairment of proved properties |
— |
|
|
— |
|
|
— |
|
|
10,000 |
|
Abandonment and impairment of unproved properties |
— |
|
|
229 |
|
|
— |
|
|
24,692 |
|
Exploratory dry hole expense |
— |
|
|
(33 |
) |
|
3,006 |
|
|
872 |
|
Stock-based compensation (1) |
1,035 |
|
|
1,643 |
|
|
13,746 |
|
|
8,892 |
|
Advisor
fees related to CEO transition and strategic alternatives (1) |
2,774 |
|
|
14,457 |
|
|
2,774 |
|
|
20,375 |
|
Cash
severance costs (1) |
— |
|
|
— |
|
|
1,605 |
|
|
2,162 |
|
Pre-petition advisory fees(1) |
— |
|
|
— |
|
|
683 |
|
|
— |
|
Post-petition restructuring fees(1) |
— |
|
|
— |
|
|
3,740 |
|
|
— |
|
Reorganization items |
— |
|
|
— |
|
|
(8,808 |
) |
|
— |
|
Gain on
termination fee |
— |
|
|
— |
|
|
— |
|
|
6,000 |
|
Contract
settlement expense |
— |
|
|
21,000 |
|
|
— |
|
|
21,000 |
|
Total adjustments
before taxes |
14,948 |
|
|
39,390 |
|
|
30,647 |
|
|
123,560 |
|
Income tax effect |
(912 |
) |
|
— |
|
|
(4,199 |
) |
|
— |
|
Total adjustments after
taxes |
$ |
14,036 |
|
|
$ |
39,390 |
|
|
$ |
26,448 |
|
|
$ |
123,560 |
|
|
|
|
|
|
|
|
|
Adjusted net
income (loss) |
$ |
8,268 |
|
|
$ |
(27,944 |
) |
|
$ |
24,088 |
|
|
$ |
(75,390 |
) |
Adjusted net
income (loss) per diluted share (2) |
$ |
0.40 |
|
|
$ |
(0.57 |
) |
|
$ |
1.18 |
|
|
$ |
(1.53 |
) |
|
|
|
|
|
|
|
|
Diluted
weighted-average common shares outstanding (2) |
20,454 |
|
|
49,388 |
|
|
20,427 |
|
|
49,268 |
|
|
|
|
|
|
|
|
|
(1)
Included as a portion of general and administrative expense on the
consolidated statement of operations. |
(2) For
the twelve-month period ended December 31, 2017, the Company used
the Successor's diluted weighted average share count to calculate
adjusted net income per diluted share. |
|
Schedule 7: Adjusted EBITDAX(in thousands, except per share
amounts, unaudited)
Adjusted EBITDAX is a supplemental non-GAAP financial measure
that is used by management and external users of the Company’s
consolidated financial statements, such as industry analysts,
investors, lenders and rating agencies. The Company defines
adjusted EBITDAX as earnings before interest expense, income taxes,
depreciation, depletion, amortization, impairment, exploration
expenses and other similar non-cash and non-recurring charges.
Adjusted EBITDAX is not a measure of net income or cash flows as
determined by GAAP.
The following table presents a reconciliation of GAAP financial
measures of net income (loss) to the non-GAAP financial measure of
Adjusted EBITDAX.
|
Three Months Ended |
|
Twelve Months Ended |
|
December 31, |
|
December 31, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
Net Income
(loss) |
$ |
(5,768 |
) |
|
$ |
(67,334 |
) |
|
$ |
(2,360 |
) |
|
$ |
(198,950 |
) |
Exploration |
3,386 |
|
|
3 |
|
|
7,444 |
|
|
946 |
|
Depreciation, depletion and amortization |
9,126 |
|
|
26,613 |
|
|
49,377 |
|
|
111,215 |
|
Impairment of proved properties |
— |
|
|
— |
|
|
— |
|
|
10,000 |
|
Abandonment and impairment of unproved properties |
— |
|
|
229 |
|
|
— |
|
|
24,692 |
|
Stock-based Compensation (1) |
1,035 |
|
|
1,643 |
|
|
13,746 |
|
|
8,892 |
|
Cash
severance costs (1) |
— |
|
|
— |
|
|
1,605 |
|
|
2,162 |
|
Advisor
fees related to CEO search and strategic alternatives(1) |
2,774 |
|
|
14,457 |
|
|
2,774 |
|
|
20,375 |
|
Gain on
termination fee |
— |
|
|
— |
|
|
— |
|
|
(6,000 |
) |
Contract
settlement expense |
— |
|
|
21,000 |
|
|
— |
|
|
21,000 |
|
Pre-petition advisory fees(1) |
— |
|
|
— |
|
|
683 |
|
|
— |
|
Post-petition restructuring fees(1) |
— |
|
|
— |
|
|
3,740 |
|
|
— |
|
Reorganization items |
— |
|
|
— |
|
|
(8,808 |
) |
|
— |
|
Interest
expense |
313 |
|
|
15,842 |
|
|
6,429 |
|
|
62,058 |
|
Derivative (gain) loss |
12,603 |
|
|
(490 |
) |
|
15,365 |
|
|
11,234 |
|
Derivative cash settlements |
(1,464 |
) |
|
2,584 |
|
|
(1,464 |
) |
|
18,333 |
|
Income
tax (benefit) expense |
(376 |
) |
|
— |
|
|
(376 |
) |
|
— |
|
Adjusted
EBITDAX |
$ |
21,629 |
|
|
$ |
14,547 |
|
|
$ |
88,155 |
|
|
$ |
85,957 |
|
|
|
|
|
|
|
|
|
(1)
Included as a portion of general and administrative expense on the
consolidated statement of operations. |
|
Schedule 9: PV-10 of Estimated Proved Reserves
PV-10 is derived from the Standardized Measure, which is the
most directly comparable GAAP financial measure. PV-10 is a
computation of the Standardized Measure on a pre-tax basis. PV-10
is equal to the Standardized Measure at the applicable date, before
deducting future income taxes, discounted at 10%. We believe that
the presentation of PV-10 is relevant and useful to investors
because it presents the discounted future net cash flows
attributable to our estimated net proved reserves prior to taking
into account future corporate income taxes, and it is a useful
measure for evaluating the relative monetary significance of our
oil and natural gas properties. Further, investors may utilize the
measure as a basis for comparison of the relative size and value of
our reserves to other companies. We use this measure when assessing
the potential return on investment related to our oil and natural
gas properties. PV-10, however, is not a substitute for the
Standardized Measure. Our PV-10 measure and the Standardized
Measure do not purport to present the fair value of our proved oil
and natural gas reserves.
The following table presents a reconciliation of GAAP
Standardized Measure to the non-GAAP financial measure of
PV-10.
|
|
December 31, |
(in thousands) |
|
2017 |
|
|
|
PV-10 (1) |
|
598,498 |
|
Present value of future
income taxes discounted at 10% (2) |
|
— |
|
Standardized
Measure |
|
$ |
598,498 |
|
|
|
|
(1) The
12-month average benchmark pricing used to estimate SEC proved
reserves and PV-10 value for crude oil and natural gas was $51.34
per Bbl of WTI crude oil and $2.98 per MMBtu of natural gas at
Henry Hub before differential adjustments. Year-end 2017 benchmark
prices for oil, and natural gas were both 20% higher from year-end
2016 SEC pricing. After differential adjustments, the Company's SEC
pricing realizations for year-end 2017 were $46.76 per Bbl of oil,
$19.57 per Bbl of NGLs, and $2.45 per Mcf of natural gas. Please
refer to the Non-GAAP Disclosure at the end of this release for
information regarding PV-10 |
(2) The tax
basis of the Company's oil and gas properties as of December 31,
2017 provides more tax deduction than income generation when
reserve estimates were prepared using 2017 SEC pricing. |
|
Schedule 10: Cash G&A(in thousands, unaudited)
Cash G&A is a supplemental non-GAAP financial measure that
is used by management and external users of the Company’s
consolidated financial statements, such as industry analysts,
investors, lenders and rating agencies. The Company defines cash
G&A as GAAP general and administrative expense exclusive of the
Company's stock based compensation and one-time charges, such as
severance costs and advisor fees. The Company refers to cash
G&A to provide typical cash G&A costs that are planned for
in a given period. Cash G&A is not a fully inclusive measure of
general and administrative expense as determined by GAAP.
The following table presents a reconciliation of GAAP financial
measures of G&A expense to the non-GAAP financial measure of
cash G&A.
|
|
Three Months Ended |
|
Twelve Months Ended |
|
|
12/31/2017 |
|
9/30/2017 |
|
12/31/2017 |
|
12/31/2016 |
General and
Administrative Expense |
|
$ |
11,356 |
|
|
$ |
15,181 |
|
|
$ |
57,768 |
|
|
$ |
77,065 |
|
Stock Compensation |
|
(1,035 |
) |
|
(2,646 |
) |
|
(13,746 |
) |
|
(8,892 |
) |
Cash G&A |
|
10,321 |
|
|
12,535 |
|
|
44,022 |
|
|
68,173 |
|
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