Bonanza Creek Energy, Inc. (NYSE:BCEI) (the "Company") today
announces its second quarter 2017 financial results and operating
outlook and has posted an updated investor presentation to its
corporate website.
Jack Vaughn, Chairman of the Board of Directors commented, "On
behalf of the Board of Directors, we are very pleased with our
team's swift progress in commencing the Company's 2017 drilling and
completion program. Three key objectives of this program are to
maximize well performance through completion design enhancements,
reduce the cost structure at the field and corporate level,
commence operations in the French Lake area, and allocate capital
at a pace that preserves the Company's balance sheet. As the team
executes the 2017 capital program, the Board of Directors has
engaged an executive search firm to identify and review CEO
candidates and is simultaneously assessing strategic opportunities.
With strong leadership, we believe that Bonanza Creek can become a
premier DJ Basin producer."
Second Quarter 2017 Results
For the second quarter of 2017, the Company reported average
daily production of 15.9 MBoe per day, in line with the Company's
guidance of 15.8 – 16.2 Mboe per day, and a 32% decrease from the
second quarter of 2016. The reduction in production volumes from
the prior year is a result of having no drilling and completion
activity during the previous five quarters. Product mix for the
second quarter of 2017 was 51% oil, 22% NGLs, and 27% natural
gas.
Net revenue for the second quarter of 2017 was $44.1 million,
compared to $54.5 million for the second quarter of 2016. Crude oil
accounted for approximately 74% of total revenue. Differentials for
the Company's Rocky Mountain oil production during the quarter
averaged approximately $4.45 per Bbl, a 50% decrease from the
second quarter of 2016. The significant reduction in the Company's
oil differentials is a result of its recently restructured oil
purchasing contracts in the Wattenberg. Corporate average realized
prices for the second quarter of 2017 are presented below.
Average
Realized Prices |
|
|
|
Three Months Ended June 30, 2017 |
|
Oil (per Bbl) |
44.89 |
|
Gas (per Mcf) |
2.52 |
|
NGL (per Bbl) |
16.71 |
|
Boe (Per Boe) |
30.51 |
|
Lease operating expense ("LOE") for the second quarter of 2017
was $9.4 million, or $6.47 per Boe, a 13% reduction in total LOE
compared to $10.7 million or $5.08 per Boe in the second quarter of
2016. Per unit metrics have increased from year to year as a result
of declining volumes. These metrics are expected to improve as
activity is restarted and production volumes stabilize and
increase.
Below is a breakout of the Company's regional LOE and gas plant
and midstream operating expense for the second quarter of 2017.
|
|
Three Months Ended June 30, 2017 |
|
Rocky Mountain |
|
Mid-Continent |
|
Total Company |
|
($M) |
|
($/Boe) |
|
($M) |
|
($/Boe) |
|
($M) |
|
($/Boe) |
Lease operating
expense |
$ |
6,808 |
|
|
$ |
5.94 |
|
|
$ |
2,548 |
|
|
$ |
8.46 |
|
|
$ |
9,356 |
|
|
$ |
6.47 |
|
Gas plant and midstream
operating expense |
$ |
1,535 |
|
|
$ |
1.34 |
|
|
$ |
1,063 |
|
|
$ |
3.53 |
|
|
2,598 |
|
|
$ |
1.80 |
|
Total |
$ |
8,343 |
|
|
$ |
7.28 |
|
|
$ |
3,611 |
|
|
$ |
11.99 |
|
|
$ |
11,954 |
|
|
$ |
8.27 |
|
The Company's general and administrative ("G&A") expense was
$19.1 million for the second quarter of 2017, a 45% increase from
the second quarter of 2016. The increase is primarily due to
approximately $7.1 million in non-cash stock compensation, which
was accelerated in connection with the departure of the Company's
former CEO on June 11, 2017, and $1.1 million of post-petition
restructuring fees. The Company's recurring cash G&A expense
for the second quarter of 2017 was $9.2 million and is exclusive of
the aforementioned post-petition restructuring fees. This compares
to prior year recurring cash G&A expense of $10.9 million. The
benefits of the Company's ongoing G&A cost reduction program
are discussed below. Recurring cash G&A is a non-GAAP measure.
Please refer to the reconciliation to GAAP general and
administrative expense in the financial exhibits to this press
release.
Operational Highlights
Testing and Assessing Enhanced CompletionsDuring the second
quarter of 2017, the Company completed its first pad of 4 drilled
uncompleted ("DUC") wells. These 4,100-foot standard reach lateral
("SRL") wells were completed using approximately 2,000 pounds of
sand per lateral foot and utilized approximately 100-foot stage
spacing. This enhanced completion design compares to the Company's
previous standard design of approximately 1,000 pounds per lateral
foot of sand and stage spacing of approximately 160 feet. Flow-back
of these wells has utilized the Company's enhanced recovery
flow-back protocol, which provides choke management to increase oil
cuts and overall recoveries by maintaining down-hole pressures
higher for longer and decreasing medium-term decline rates. The
DUCs started flowing back on July 2, 2017 and while early, the
initial results are encouraging.
The Company commenced its 2017 drilling program at the end of
July by spudding a three-well pad, consisting of one, 9,600 foot
extended reach lateral ("XRL") well and two SRL wells. The Company
expects the first pad to be turned into sales during the fourth
quarter.
All of the Company's 2017 drilling and completion activity will
utilize various forms of enhanced completion design to maximize
well productivity, recovery, and project economics.
In addition to its operated program, the Company plans to
participate in approximately 18 gross non-operated wells. These 18
wells will also test enhanced completions and provide informative
and useful well data over a broader areal extent of the Company's
acreage with lower capital commitments. The operated and
non-operated programs will together provide a significant data set
of 43 well results. These results will provide key information
regarding the potential uplift from various leading-edge completion
designs, which will inform the Company's development plans.
French Lake OpportunityDuring 2017 and into the beginning of
2018, the Company plans to drill and complete eight XRL wells in
its French Lake area. The Company acquired this acreage in the fall
of 2014 and, with its financial restructuring and recapitalization
complete, the Company is eager to confirm the geology and reservoir
performance of the area. Bonanza Creek is pursuing its plans under
an agreement with an offset operator, and upon completion of these
eight wells, will essentially eliminate all of the Company's
near-term lease expiry risk in its Wattenberg acreage. The Company
plans to pursue a comprehensive agreement to develop this acreage
with the offset operator.
Production, Capital, and Expense Outlook
The Company is reiterating its production and capital guidance
for the remainder of the year and providing initial cost guidance
for 2017. As a part of its ongoing cost structure review, the
Company executed a reduction in force subsequent to the second
quarter, which resulted in a reduction of 25% of its employee base.
Based on these changes, the Company now expects its annualized
recurring cash G&A expense to be within the range of $30 – $32
million, which compares to $45.6 million of recurring cash G&A
in 2016. Recurring G&A expense excludes non-recurring items
associated with advisor fees and severance charges. These announced
G&A savings, along with continued efforts to reduce LOE and
further reduce non-payroll G&A, will help drive Bonanza Creek
towards its goal of increasing full-cycle returns.
Below is a table summarizing the Company's production,
capital, and expense guidance for the remainder of 2017.
Guidance Summary |
|
|
|
|
Three Months Ended September 30, 2017 |
|
Twelve Months Ended December 31, 2017 |
|
|
|
|
Production
(MBoe/d) |
15.8 –
16.2 |
|
16.3 –
16.7 |
LOE ($/Boe) |
|
|
$6.50
– $7.00 |
Midstream expense
($/Boe) |
|
|
$1.90
– $2.10 |
Cash G&A*
($MM) |
|
|
$38 –
$40 |
Production taxes (% of
pre-derivative realization) |
|
|
7% –
8% |
Total CAPEX ($MM) |
|
|
$120 –
$130 |
* Cash
G&A guidance assumes expected severance costs of $2.0 million
in the third quarter of 2017 and nonrecurring expenses of $3.2
million. Cash G&A is a non-GAAP measure that excludes the
Company's stock based compensation. The Company does not guide to
GAAP G&A expense as it has less certainty to the stock based
compensation portion of GAAP G&A. |
Financial Highlights
As of the end of the second quarter, the Company had liquidity
of $246 million, which included cash on hand of $54 million and
$192 million of borrowing capacity under its credit facility.
The Company has no outstanding term debt and its credit facility is
undrawn. Based on the terms of the credit facility, the Company's
next borrowing base redetermination will occur in April of
2018. The Company's balance sheet strength allows it to be
flexible, patient and selective in its investment decisions, and
the opportunity to participate in acquisition opportunities and the
flexibility to objectively evaluate divestiture candidates.
Commodity Derivative PositionSubsequent to the second quarter,
the Company began to implement hedges for oil and gas for the
remainder of 2017 through the first half of 2019. As the new wells
are turned into sales, the Company plans to add incremental hedges
to lock in cash flows and project returns. The Company's current
hedge position is summarized in the table below.
|
|
Crude Oil(NYMEX WTI) |
|
Natural Gas(NYMEX Henry Hub) |
|
|
Bbls/day |
|
Weighted Avg. Price per Bbl |
|
MMBtu/day |
|
Weighted Avg. Price per MMBTU |
4Q17 |
|
|
|
|
|
|
|
|
Cashless
Collar |
|
2,000 |
|
|
$41.50/$51.00 |
|
2,600 |
|
|
$3.00/$3.30 |
1Q18 |
|
|
|
|
|
|
|
|
Swap |
|
— |
|
|
|
|
3,000 |
|
|
3.35 |
Cashless
Collar |
|
2,000 |
|
|
$42.00/$52.50 |
|
2,600 |
|
|
$2.75/$3.35 |
2Q18 |
|
|
|
|
|
|
|
|
Cashless
Collar |
|
2,000 |
|
|
$42.00/$52.50 |
|
2,600 |
|
|
$2.75/$3.35 |
3Q18 |
|
|
|
|
|
|
|
|
Cashless
Collar |
|
1,000 |
|
|
$41.00/$52.00 |
|
2,600 |
|
|
$2.75/$3.35 |
4Q18 |
|
|
|
|
|
|
|
|
Cashless
Collar |
|
1,000 |
|
|
$41.00/$52.00 |
|
2,600 |
|
|
$2.75/$3.35 |
1Q19 |
|
|
|
|
|
|
|
|
Cashless
Collar |
|
1,000 |
|
|
$41.00/$54.00 |
|
— |
|
|
|
April 2019 |
|
|
|
|
|
|
|
|
Cashless
Collar |
|
1,000 |
|
|
$41.00/$54.00 |
|
— |
|
|
|
Fresh Start Accounting
The Company adopted fresh-start accounting as of April 28, 2017,
the effective date of its emergence from Chapter 11 bankruptcy
proceedings, resulting in a new corporate entity for financial
reporting purposes. Upon the adoption of fresh-start accounting,
the Company’s assets and liabilities were recorded at their fair
values as of the fresh-start reporting date. As a result, the
Company’s unaudited condensed consolidated financial statements
subsequent to April 28, 2017 are not comparable to its financial
statements prior to April 28, 2017. References to "Predecessor"
refer to the Company prior to the adoption of fresh-start
accounting while references to "Successor" refer to the Company
subsequent to the adoptions of fresh-start accounting. Please
review the Company’s second quarter 2017 Form 10-Q for further
details regarding fresh-start accounting and the financial
information presented at the end of this release.
Conference Call Information
The Company will host a conference call to discuss these
financial and operating results on August 9, 2017 at 8:00 a.m.
Mountain Time (10:00 a.m. Eastern Time). A webcast of the live
event, as well as a replay, will be available on the Investor
Relations section of the Company’s website at www.bonanzacrk.com.
Dial-in information for the conference call is included below.
Type |
Phone Number |
Passcode |
Live Participant |
877-793-4362 |
63290457 |
Replay |
855-859-2056 |
63290457 |
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 Mountain region 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; decreasing operating and capital costs; impact of the
Company's reorganization; and updated 2017 guidance. 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, 2016, filed on March 16, 2017, 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.
Schedule 1: Statement of Operations(in thousands, expect for per
share amounts, unaudited)
|
Successor |
|
|
Predecessor |
Predecessor |
|
April 29, 2017 through June 30,
2017 |
|
|
April 1, 2017 through April 28,
2017 |
Three Months Ended June 30, 2016 |
Operating net
revenues: |
|
|
|
|
|
Oil and
gas sales |
$ |
28,114 |
|
|
|
$ |
16,030 |
|
$ |
54,530 |
|
Operating
expenses: |
|
|
|
|
|
Lease
operating expense |
6,153 |
|
|
|
3,203 |
|
10,737 |
|
Gas plant
and midstream operating expense |
1,762 |
|
|
|
836 |
|
3,535 |
|
Severance
and ad valorem taxes |
2,408 |
|
|
|
1,352 |
|
4,277 |
|
Exploration |
359 |
|
|
|
292 |
|
677 |
|
Depreciation, depletion and amortization |
4,836 |
|
|
|
6,853 |
|
30,927 |
|
Abandonment and impairment of unproved properties |
— |
|
|
|
— |
|
9,875 |
|
General
and administrative (including $7,949, $391 and $2,380,
respectively, of stock-based compensation) |
16,139 |
|
|
|
2,998 |
|
13,235 |
|
Total
operating expenses |
31,657 |
|
|
|
15,534 |
|
73,263 |
|
Income (loss) from
operations |
(3,543 |
) |
|
|
496 |
|
(18,733 |
) |
Other income
(expense): |
|
|
|
|
|
Derivative loss |
— |
|
|
|
— |
|
(12,923 |
) |
Interest
expense |
(195 |
) |
|
|
(1,088 |
) |
(16,527 |
) |
Reorganization items, net |
— |
|
|
|
97,811 |
|
— |
|
Other
income (loss) |
158 |
|
|
|
(283 |
) |
(1,294 |
) |
Total
other income (expense) |
(37 |
) |
|
|
96,440 |
|
(30,744 |
) |
Income (loss) from
operations before taxes |
(3,580 |
) |
|
|
96,936 |
|
(49,477 |
) |
Income tax benefit
(expense) |
— |
|
|
|
— |
|
— |
|
Net income (loss) |
$ |
(3,580 |
) |
|
|
$ |
96,936 |
|
$ |
(49,477 |
) |
Comprehensive income
(loss) |
$ |
(3,580 |
) |
|
|
$ |
96,936 |
|
$ |
(49,477 |
) |
|
|
|
|
|
|
Basic net income (loss)
per common share |
$ |
(0.18 |
) |
|
|
$ |
1.88 |
|
$ |
(1.00 |
) |
|
|
|
|
|
|
|
|
Diluted net income
(loss) per common share |
$ |
(0.18 |
) |
|
|
$ |
1.85 |
|
$ |
(1.00 |
) |
|
|
|
|
|
|
Basic weighted-average
common shares outstanding |
20,369 |
|
|
|
49,902 |
|
49,277 |
|
|
|
|
|
|
|
Diluted
weighted-average common shares outstanding |
20,369 |
|
|
|
50,486 |
|
49,277 |
|
|
|
|
|
|
|
|
|
|
- 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 income (loss) per share. Please
refer to Note 12 – Earnings per Share in the Form 10-Q, for a
detailed calculation.
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor |
|
|
Predecessor |
Predecessor |
|
April 29, 2017 through June 30,
2017 |
|
|
January 1, 2017 through April 28,
2017 |
Six Months Ended June 30, 2016 |
Operating net
revenues: |
|
|
|
|
|
Oil and
gas sales |
$ |
28,114 |
|
|
|
$ |
68,589 |
|
$ |
98,704 |
|
Operating
expenses: |
|
|
|
|
|
Lease
operating expense |
6,153 |
|
|
|
13,128 |
|
24,035 |
|
Gas plant
and midstream operating expense |
1,762 |
|
|
|
3,541 |
|
7,324 |
|
Severance
and ad valorem taxes |
2,408 |
|
|
|
5,671 |
|
7,431 |
|
Exploration |
359 |
|
|
|
3,699 |
|
943 |
|
Depreciation, depletion and amortization |
4,836 |
|
|
|
28,065 |
|
57,306 |
|
Impairment of oil and gas properties |
— |
|
|
|
— |
|
10,000 |
|
Abandonment and impairment of unproved properties |
— |
|
|
|
— |
|
16,781 |
|
Unused
commitments |
— |
|
|
|
993 |
|
— |
|
General
and administrative (including $7,949, $2,116, $5,384, respectively,
of stock-based compensation) |
16,139 |
|
|
|
15,092 |
|
30,920 |
|
Total
operating expenses |
31,657 |
|
|
|
70,189 |
|
154,740 |
|
Loss from
operations |
(3,543 |
) |
|
|
(1,600 |
) |
(56,036 |
) |
Other income
(expense): |
|
|
|
|
|
Derivative loss |
— |
|
|
|
— |
|
(13,930 |
) |
Interest
expense |
(195 |
) |
|
|
(5,656 |
) |
(31,074 |
) |
Reorganization items, net |
— |
|
|
|
8,808 |
|
— |
|
Gain on
termination fee |
— |
|
|
|
— |
|
6,000 |
|
Other
income (loss) |
158 |
|
|
|
1,108 |
|
(1,674 |
) |
Total
other income (expense) |
(37 |
) |
|
|
4,260 |
|
(40,678 |
) |
Income (loss) from
operations before taxes |
(3,580 |
) |
|
|
2,660 |
|
(96,714 |
) |
Income tax benefit
(expense) |
— |
|
|
|
— |
|
— |
|
Net income (loss) |
$ |
(3,580 |
) |
|
|
$ |
2,660 |
|
$ |
(96,714 |
) |
Comprehensive income
(loss) |
$ |
(3,580 |
) |
|
|
$ |
2,660 |
|
$ |
(96,714 |
) |
|
|
|
|
|
|
Basic net income (loss)
per common share |
$ |
(0.18 |
) |
|
|
$ |
0.05 |
|
$ |
(1.97 |
) |
|
|
|
|
|
|
Diluted net income
(loss) per common share |
$ |
(0.18 |
) |
|
|
$ |
0.05 |
|
$ |
(1.97 |
) |
|
|
|
|
|
|
Basic weighted-average
common shares outstanding |
20,369 |
|
|
|
49,559 |
|
49,204 |
|
|
|
|
|
|
|
Diluted
weighted-average common shares outstanding |
20,369 |
|
|
|
50,971 |
|
49,204 |
|
|
|
|
|
|
|
|
|
|
- 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 income (loss) per share. Please
refer to Note 12 – Earnings per Share in the Form 10-Q, for a
detailed calculation.
Schedule 2: Statement of Cash Flows(in thousands, unaudited)
|
Successor |
|
|
Predecessor |
Predecessor |
|
April 29, 2017 through June 30,
2017 |
|
|
April 1, 2017 through April 28,
2017 |
Three Months Ended June 30, 2016 |
|
|
|
|
|
|
Cash flows from
operating activities: |
|
|
|
|
|
Net
income (loss) |
$ |
(3,580 |
) |
|
|
$ |
96,936 |
|
$ |
(49,477 |
) |
Adjustments to reconcile net income (loss) to net cash provided by
operating activities: |
|
|
|
|
|
Depreciation, depletion and amortization |
4,836 |
|
|
|
6,853 |
|
30,927 |
|
Non-cash
reorganization items |
— |
|
|
|
(101,501 |
) |
— |
|
Abandonment and impairment of unproved properties |
— |
|
|
|
— |
|
9,875 |
|
Well
abandonment costs and dry hole expense |
64 |
|
|
|
230 |
|
734 |
|
Stock-based compensation |
7,949 |
|
|
|
391 |
|
2,380 |
|
Amortization of deferred financing costs and debt premium |
— |
|
|
|
374 |
|
1,671 |
|
Derivative loss |
— |
|
|
|
— |
|
12,923 |
|
Derivative cash settlements |
— |
|
|
|
— |
|
3,893 |
|
Other |
5 |
|
|
|
(365 |
) |
4 |
|
Changes
in current assets and liabilities: |
|
|
|
|
|
Accounts
receivable |
6,420 |
|
|
|
(2,826 |
) |
371 |
|
Prepaid
expenses and other assets |
270 |
|
|
|
1,499 |
|
274 |
|
Accounts
payable and accrued liabilities |
(19,338 |
) |
|
|
(36,972 |
) |
(25,316 |
) |
Settlement of asset retirement obligations |
(459 |
) |
|
|
(155 |
) |
(34 |
) |
Net cash
used in operating activities |
(3,833 |
) |
|
|
(35,536 |
) |
(11,775 |
) |
Cash flows from
investing activities: |
|
|
|
|
|
Acquisition of oil and gas properties |
(4,982 |
) |
|
|
(6 |
) |
(284 |
) |
Exploration and development of oil and gas properties |
(4,913 |
) |
|
|
(1,698 |
) |
(7,881 |
) |
Payments
of contractual obligation |
— |
|
|
|
— |
|
(12,000 |
) |
Increase
in restricted cash |
(2 |
) |
|
|
— |
|
(2 |
) |
Additions
to property and equipment - non oil and gas |
(161 |
) |
|
|
(253 |
) |
(8 |
) |
Net cash
used in investing activities |
(10,058 |
) |
|
|
(1,957 |
) |
(20,175 |
) |
Cash flows from
financing activities: |
|
|
|
|
|
Payments
to credit facility |
— |
|
|
|
(191,667 |
) |
(14,667 |
) |
Proceeds
from sale of common stock |
— |
|
|
|
207,500 |
|
— |
|
Deferred
restructuring charges |
— |
|
|
|
— |
|
(1,684 |
) |
Payment
of employee tax withholdings in exchange for the return of common
stock |
(2,080 |
) |
|
|
(92 |
) |
(44 |
) |
Deferred
financing costs |
— |
|
|
|
— |
|
(83 |
) |
Net cash
(used in) provided by financing activities |
(2,080 |
) |
|
|
15,741 |
|
(16,478 |
) |
Net change in cash and
cash equivalents |
(15,971 |
) |
|
|
(21,752 |
) |
(48,428 |
) |
Cash and cash
equivalents: |
|
|
|
|
|
Beginning
of period |
70,183 |
|
|
|
91,935 |
|
218,599 |
|
End of
period |
$ |
54,212 |
|
|
|
$ |
70,183 |
|
$ |
170,171 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor |
|
|
Predecessor |
Predecessor |
|
April 29, 2017 through June 30,
2017 |
|
|
January 1, 2017 through April 28,
2017 |
Six Months Ended June 30, 2016 |
|
|
|
|
|
|
Cash flows from
operating activities: |
|
|
|
|
|
Net
income (loss) |
$ |
(3,580 |
) |
|
|
$ |
2,660 |
|
$ |
(96,714 |
) |
Adjustments to reconcile net income (loss) to net cash provided by
operating activities: |
|
|
|
|
|
Depreciation, depletion and amortization |
4,836 |
|
|
|
28,065 |
|
57,306 |
|
Non-cash
reorganization items |
— |
|
|
|
(44,160 |
) |
— |
|
Impairment of oil and gas properties |
— |
|
|
|
— |
|
10,000 |
|
Abandonment and impairment of unproved properties |
— |
|
|
|
— |
|
16,781 |
|
Well
abandonment costs and dry hole expense |
64 |
|
|
|
2,931 |
|
966 |
|
Stock-based compensation |
7,949 |
|
|
|
2,116 |
|
5,384 |
|
Amortization of deferred financing costs and debt premium |
— |
|
|
|
374 |
|
2,279 |
|
Derivative loss |
— |
|
|
|
— |
|
13,930 |
|
Derivative cash settlements |
— |
|
|
|
— |
|
11,401 |
|
Other |
5 |
|
|
|
18 |
|
(112 |
) |
Changes
in current assets and liabilities: |
|
|
|
|
|
Accounts
receivable |
6,420 |
|
|
|
(6,640 |
) |
23,415 |
|
Prepaid
expenses and other assets |
270 |
|
|
|
963 |
|
(1,348 |
) |
Accounts
payable and accrued liabilities |
(19,338 |
) |
|
|
(5,880 |
) |
(28,457 |
) |
Settlement of asset retirement obligations |
(459 |
) |
|
|
(331 |
) |
(75 |
) |
Net
cash (used in) provided by operating activities |
(3,833 |
) |
|
|
(19,884 |
) |
14,756 |
|
Cash flows from
investing activities: |
|
|
|
|
|
Acquisition of oil and gas properties |
(4,982 |
) |
|
|
(445 |
) |
(816 |
) |
Exploration and development of oil and gas properties |
(4,913 |
) |
|
|
(5,123 |
) |
(42,753 |
) |
Payments
of contractual obligation |
— |
|
|
|
— |
|
(12,000 |
) |
(Increase) decrease in restricted cash |
(2 |
) |
|
|
118 |
|
(2,535 |
) |
(Additions) deletions to property and equipment - non oil and
gas |
(161 |
) |
|
|
(454 |
) |
39 |
|
Net cash
used in investing activities |
(10,058 |
) |
|
|
(5,904 |
) |
(58,065 |
) |
Cash flows from
financing activities: |
|
|
|
|
|
Proceeds
from credit facility |
— |
|
|
|
— |
|
209,000 |
|
Payments
to credit facility |
— |
|
|
|
(191,667 |
) |
(14,667 |
) |
Proceeds
from sale of common stock |
— |
|
|
|
207,500 |
|
— |
|
Deferred
restructuring charges |
— |
|
|
|
— |
|
(1,684 |
) |
Payment
of employee tax withholdings in exchange for the return of common
stock |
(2,080 |
) |
|
|
(427 |
) |
(273 |
) |
Deferred
financing costs |
— |
|
|
|
— |
|
(237 |
) |
Net cash
(used in) provided by financing activities |
(2,080 |
) |
|
|
15,406 |
|
192,139 |
|
Net change in cash and
cash equivalents |
(15,971 |
) |
|
|
(10,382 |
) |
148,830 |
|
Cash and cash
equivalents: |
|
|
|
|
|
Beginning
of period |
70,183 |
|
|
|
80,565 |
|
21,341 |
|
End of
period |
$ |
54,212 |
|
|
|
$ |
70,183 |
|
$ |
170,171 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Schedule 3: Condensed Consolidated Balance Sheets(in thousands,
unaudited)
|
Successor |
|
|
Predecessor |
|
June 30, 2017 |
|
|
December 31, 2016 |
ASSETS |
|
|
|
|
Current assets: |
|
|
|
|
Cash and
cash equivalents |
$ |
54,212 |
|
|
|
$ |
80,565 |
|
Accounts
receivable: |
|
|
|
|
Oil and
gas sales |
18,410 |
|
|
|
14,479 |
|
Joint
interest and other |
3,073 |
|
|
|
6,784 |
|
Prepaid
expenses and other |
4,682 |
|
|
|
5,915 |
|
Inventory
of oilfield equipment |
3,942 |
|
|
|
4,685 |
|
Total
current assets |
84,319 |
|
|
|
112,428 |
|
Property and equipment
(successful efforts method): |
|
|
|
|
Proved
properties |
498,229 |
|
|
|
2,525,587 |
|
Less:
accumulated depreciation, depletion and amortization |
(4,266 |
) |
|
|
(1,694,483 |
) |
Total
proved properties, net |
493,963 |
|
|
|
831,104 |
|
Unproved
properties |
183,443 |
|
|
|
163,369 |
|
Wells in
progress |
16,100 |
|
|
|
18,250 |
|
Other
property and equipment, net of accumulated depreciation of $238 in
2017 and $11,206 in 2016 |
5,980 |
|
|
|
6,245 |
|
Total
property and equipment, net |
699,486 |
|
|
|
1,018,968 |
|
Other noncurrent
assets |
2,739 |
|
|
|
3,082 |
|
Total assets |
$ |
786,544 |
|
|
|
$ |
1,134,478 |
|
LIABILITIES AND STOCKHOLDERS’ EQUITY |
|
|
|
|
Current
liabilities: |
|
|
|
|
Accounts
payable and accrued expenses |
$ |
28,586 |
|
|
|
$ |
61,328 |
|
Oil and
gas revenue distribution payable |
22,321 |
|
|
|
23,773 |
|
Revolving
credit facility - current portion |
— |
|
|
|
191,667 |
|
Senior
Notes - current portion |
— |
|
|
|
793,698 |
|
Total
current liabilities |
50,907 |
|
|
|
1,070,466 |
|
|
|
|
|
|
Long-term
liabilities: |
|
|
|
|
Ad
valorem taxes |
20,288 |
|
|
|
14,118 |
|
Asset
retirement obligations for oil and gas properties |
28,938 |
|
|
|
30,833 |
|
Total liabilities |
100,133 |
|
|
|
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 June 30, 2017 |
— |
|
|
|
— |
|
Successor
common stock, $.01 par value, 225,000,000 shares authorized,
20,429,691 issued and outstanding as of June 30, 2017 |
4,286 |
|
|
|
— |
|
Additional paid-in capital |
685,705 |
|
|
|
814,990 |
|
Accumulated deficit |
(3,580 |
) |
|
|
(795,978 |
) |
Total
stockholders’ equity |
686,411 |
|
|
|
19,061 |
|
Total liabilities and
stockholders’ equity |
$ |
786,544 |
|
|
|
$ |
1,134,478 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Schedule 4: Volumes and Realized Prices (Before and After the
Effect of Commodity Hedges)(unaudited)
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
Wellhead
Volumes and Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and
Condensate Sales Volumes (Bbl/d) |
|
|
|
|
|
|
|
Rocky Mountains |
6,189 |
|
|
10,715 |
|
|
6,690 |
|
|
11,190 |
|
Mid-Continent |
1,845 |
|
|
2,270 |
|
|
1,889 |
|
|
2,353 |
|
Total |
8,034 |
|
|
12,985 |
|
|
8,579 |
|
|
13,543 |
|
|
|
|
|
|
|
|
|
Crude Oil and
Condensate Realized Prices ($/Bbl) |
|
|
|
|
|
|
|
Rocky Mountains |
$ |
44.06 |
|
|
$ |
36.74 |
|
|
$ |
46.32 |
|
|
$ |
30.70 |
|
Mid-Continent |
$ |
47.69 |
|
|
$ |
45.18 |
|
|
$ |
49.94 |
|
|
$ |
40.41 |
|
Composite |
$ |
44.89 |
|
|
$ |
38.21 |
|
|
$ |
47.11 |
|
|
$ |
32.39 |
|
Composite (after
derivatives) |
$ |
44.89 |
|
|
$ |
41.51 |
|
|
$ |
47.11 |
|
|
$ |
37.01 |
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids Sales Volumes (Bbl/d) |
|
|
|
|
|
|
|
Rocky Mountains |
3,046 |
|
|
3,772 |
|
|
3,167 |
|
|
3,594 |
|
Mid-Continent |
452 |
|
|
675 |
|
|
471 |
|
|
697 |
|
Total |
3,498 |
|
|
4,447 |
|
|
3,638 |
|
|
4,291 |
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids Realized Prices ($/Bbl) |
|
|
|
|
|
|
|
Rocky Mountains |
$ |
16.10 |
|
|
$ |
10.59 |
|
|
$ |
15.99 |
|
|
$ |
11.80 |
|
Mid-Continent |
$ |
20.84 |
|
|
$ |
16.75 |
|
|
$ |
23.45 |
|
|
$ |
14.48 |
|
Composite |
$ |
16.71 |
|
|
$ |
11.53 |
|
|
$ |
16.96 |
|
|
$ |
12.23 |
|
Composite (after
derivatives) |
$ |
16.71 |
|
|
$ |
11.53 |
|
|
$ |
16.96 |
|
|
$ |
12.23 |
|
|
|
|
|
|
|
|
|
Natural Gas
Sales Volumes (Mcf/d) |
|
|
|
|
|
|
|
Rocky Mountains |
20,144 |
|
|
27,450 |
|
|
20,786 |
|
|
28,044 |
|
Mid-Continent |
6,067 |
|
|
7,444 |
|
|
6,249 |
|
|
7,648 |
|
Total |
26,211 |
|
|
34,894 |
|
|
27,035 |
|
|
35,692 |
|
|
|
|
|
|
|
|
|
Natural Gas
Realized Prices ($/Mcf) |
|
|
|
|
|
|
|
Rocky Mountains |
$ |
2.36 |
|
|
$ |
1.34 |
|
|
$ |
2.48 |
|
|
$ |
1.27 |
|
Mid-Continent |
$ |
3.06 |
|
|
$ |
2.01 |
|
|
$ |
3.17 |
|
|
$ |
2.05 |
|
Composite |
$ |
2.52 |
|
|
$ |
1.48 |
|
|
$ |
2.64 |
|
|
$ |
1.44 |
|
Composite (after
derivatives) |
$ |
2.52 |
|
|
$ |
1.48 |
|
|
$ |
2.64 |
|
|
$ |
1.44 |
|
|
|
|
|
|
|
|
|
Crude Oil
Equivalent Sales Volumes (Boe/d) |
|
|
|
|
|
|
|
Rocky Mountains |
12,592 |
|
|
19,062 |
|
|
13,322 |
|
|
19,458 |
|
Mid-Continent |
3,308 |
|
|
4,186 |
|
|
3,402 |
|
|
4,325 |
|
Total |
15,900 |
|
|
23,248 |
|
|
16,724 |
|
|
23,783 |
|
|
|
|
|
|
|
|
|
Crude Oil
Equivalent Sales Prices ($/Boe) |
|
|
|
|
|
|
|
Rocky Mountains |
$ |
29.31 |
|
|
$ |
24.68 |
|
|
$ |
30.93 |
|
|
$ |
21.66 |
|
Mid-Continent |
$ |
35.05 |
|
|
$ |
30.78 |
|
|
$ |
36.79 |
|
|
$ |
27.94 |
|
Composite |
$ |
30.51 |
|
|
$ |
25.78 |
|
|
$ |
32.12 |
|
|
$ |
22.80 |
|
Composite (after
derivatives) |
$ |
30.51 |
|
|
$ |
27.62 |
|
|
$ |
32.12 |
|
|
$ |
25.44 |
|
|
|
|
|
|
|
|
|
Total Sales
Volumes (MBoe) |
1,446.9 |
|
|
2,115.5 |
|
|
3,026.9 |
|
|
4,328.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Schedule 5: Per unit operating margins(unaudited)
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
2017 |
|
2016 |
|
Percent Change |
|
2017 |
|
2016 |
|
Percent Change |
Production |
|
|
|
|
|
|
|
|
|
|
|
Oil
(MBbl) |
731 |
|
|
1,182 |
|
|
(38 |
)% |
|
1,553 |
|
|
2,465 |
|
|
(37 |
)% |
Gas
(MMcf) |
2,385 |
|
|
3,175 |
|
|
(25 |
)% |
|
4,893 |
|
|
6,496 |
|
|
(25 |
)% |
NGL
(MBbl) |
318 |
|
|
405 |
|
|
(21 |
)% |
|
659 |
|
|
781 |
|
|
(16 |
)% |
Equivalent (MBoe) |
1,447 |
|
|
2,116 |
|
|
(32 |
)% |
|
3,027 |
|
|
4,329 |
|
|
(30 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized pricing (before derivatives) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
($/Bbl) |
$ |
44.89 |
|
|
$ |
38.21 |
|
|
17 |
% |
|
$ |
46.85 |
|
|
$ |
32.38 |
|
|
45 |
% |
Gas
($/Mcf) |
$ |
2.52 |
|
|
$ |
1.48 |
|
|
70 |
% |
|
$ |
2.63 |
|
|
$ |
1.44 |
|
|
83 |
% |
NGL
($/Bbl) |
$ |
16.71 |
|
|
$ |
11.53 |
|
|
45 |
% |
|
$ |
16.86 |
|
|
$ |
12.23 |
|
|
38 |
% |
Equivalent ($/Boe) |
$ |
30.51 |
|
|
$ |
25.78 |
|
|
18 |
% |
|
$ |
31.95 |
|
|
$ |
22.80 |
|
|
40 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Unit Costs
($/Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized
price (before derivatives) |
$ |
30.51 |
|
|
$ |
25.78 |
|
|
18 |
% |
|
$ |
31.95 |
|
|
$ |
22.80 |
|
|
40 |
% |
Lease
operating expense |
6.47 |
|
|
5.08 |
|
|
27 |
% |
|
|
6.37 |
|
|
|
5.55 |
|
|
15 |
% |
Gas plant
and midstream operating expense |
1.80 |
|
|
1.67 |
|
|
8 |
% |
|
|
1.75 |
|
|
|
1.69 |
|
|
4 |
% |
Severance
and ad valorem |
2.60 |
|
|
2.02 |
|
|
29 |
% |
|
|
2.67 |
|
|
|
1.72 |
|
|
55 |
% |
Cash
general and administrative |
7.46 |
|
|
5.13 |
|
|
45 |
% |
|
|
6.99 |
|
|
|
5.90 |
|
|
18 |
% |
Total
cash operating costs |
$ |
18.33 |
|
|
$ |
13.90 |
|
|
32 |
% |
|
$ |
17.78 |
|
|
$ |
14.86 |
|
|
20 |
% |
Cash
operating margin (before derivatives) |
$ |
12.18 |
|
|
$ |
11.88 |
|
|
3 |
% |
|
$ |
14.17 |
|
|
$ |
7.94 |
|
|
78 |
% |
Derivative cash settlements |
— |
|
|
1.84 |
|
|
(100 |
)% |
|
— |
|
|
2.64 |
|
|
(100 |
)% |
Cash
operating margin (after derivatives) |
$ |
12.18 |
|
|
$ |
13.72 |
|
|
(11 |
)% |
|
$ |
14.17 |
|
|
$ |
10.58 |
|
|
34 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash
items |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash
general and administrative |
$ |
5.76 |
|
|
$ |
1.13 |
|
|
410 |
% |
|
$ |
3.33 |
|
|
$ |
1.24 |
|
|
169 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 loss as net loss after adjusting first for (1)
the impact of certain non-cash items and one-time transactions and
then (2) the non-cash and one time items’ impact on taxes based on
a tax rate that approximates the Company's effective tax rate in
each period. Adjusted net loss is not a measure of net income as
determined by GAAP.
The following table presents a reconciliation of the GAAP
financial measure of net income (loss) to the non-GAAP financial
measure of adjusted net loss.
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
|
2017 |
|
2016 |
|
2017 |
|
2016 |
Net Income
(Loss) |
|
$ |
93,356 |
|
|
$ |
(49,477 |
) |
|
$ |
(920 |
) |
|
$ |
(96,714 |
) |
Adjustments to Net
Income (Loss): |
|
|
|
|
|
|
|
|
Derivative loss |
|
— |
|
|
12,923 |
|
|
— |
|
|
13,930 |
|
Derivative cash
settlements |
|
— |
|
|
3,893 |
|
|
— |
|
|
11,401 |
|
Gain on termination
fee |
|
— |
|
|
— |
|
|
— |
|
|
(6,000 |
) |
Impairment of proved
properties |
|
— |
|
|
— |
|
|
— |
|
|
10,000 |
|
Abandonment and
impairment of unproved properties |
|
— |
|
|
9,875 |
|
|
— |
|
|
16,781 |
|
Exploratory dry hole
expense |
|
294 |
|
|
734 |
|
|
2,995 |
|
|
966 |
|
Stock-based
compensation (1) |
|
8,340 |
|
|
2,380 |
|
|
10,065 |
|
|
5,384 |
|
Severance costs
(1) |
|
— |
|
|
— |
|
|
— |
|
|
2,162 |
|
Reorganization
items |
|
(97,811 |
) |
|
— |
|
|
(8,808 |
) |
|
— |
|
Pre-petition advisory
fees (1) |
|
— |
|
|
— |
|
|
683 |
|
|
— |
|
Post-petition
restructuring fees (1) |
|
1,422 |
|
|
— |
|
|
1,422 |
|
|
— |
|
Total adjustments
before taxes |
|
(87,755 |
) |
|
29,805 |
|
|
6,357 |
|
|
54,624 |
|
Income tax effect |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Total
adjustments after taxes |
|
$ |
(87,755 |
) |
|
$ |
29,805 |
|
|
$ |
6,357 |
|
|
$ |
54,624 |
|
|
|
|
|
|
|
|
|
|
Adjusted net
income (loss) |
|
$ |
5,601 |
|
|
$ |
(19,672 |
) |
|
$ |
5,437 |
|
|
$ |
(42,090 |
) |
Adjusted net
loss per diluted share (2) |
|
$ |
0.27 |
|
|
$ |
(0.40 |
) |
|
$ |
0.27 |
|
|
$ |
(0.86 |
) |
|
|
|
|
|
|
|
|
|
Diluted
weighted-average common shares outstanding (2) |
|
20,369 |
|
|
49,277 |
|
|
20,369 |
|
|
49,204 |
|
|
|
|
|
|
|
|
|
|
(1)
Included as a portion of general and administrative expense on the
consolidated statement of operations. |
(2) For
the three and six-month periods ended June 30, 2017, the Company
used the Successor's diluted weighted average share count to
calculated adjusted net income per diluted share. |
|
|
Schedule 7: Adjusted EBITDAX(in thousands, 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 the GAAP
financial measure of net income (loss) to the non-GAAP financial
measure of Adjusted EBITDAX.
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
|
2017 |
|
2016 |
|
2017 |
|
2016 |
Net Income
(loss) |
|
$ |
93,356 |
|
|
$ |
(49,477 |
) |
|
$ |
(920 |
) |
|
$ |
(96,714 |
) |
Exploration |
|
651 |
|
|
677 |
|
|
4,058 |
|
|
943 |
|
Depreciation, depletion and amortization |
|
11,689 |
|
|
30,927 |
|
|
32,901 |
|
|
57,306 |
|
Impairment of proved properties |
|
— |
|
|
— |
|
|
— |
|
|
10,000 |
|
Abandonment and impairment of unproved properties |
|
— |
|
|
9,875 |
|
|
— |
|
|
16,781 |
|
Stock-based compensation |
|
8,340 |
|
|
2,380 |
|
|
10,065 |
|
|
5,384 |
|
Severance
costs (1) |
|
— |
|
|
— |
|
|
— |
|
|
2,162 |
|
Gain on
termination fee |
|
— |
|
|
— |
|
|
— |
|
|
(6,000 |
) |
Interest
expense |
|
1,283 |
|
|
16,527 |
|
|
5,851 |
|
|
31,074 |
|
Derivative loss |
|
— |
|
|
12,923 |
|
|
— |
|
|
13,930 |
|
Derivative cash settlements |
|
— |
|
|
3,893 |
|
|
— |
|
|
11,401 |
|
Pre-petition advisory fees (1) |
|
— |
|
|
— |
|
|
683 |
|
|
— |
|
Post-petition restructuring fees (1) |
|
1,422 |
|
|
— |
|
|
1,422 |
|
|
— |
|
Reorganization items |
|
(97,811 |
) |
|
— |
|
|
(8,808 |
) |
|
|
— |
|
Income
tax benefit |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Adjusted
EBITDAX |
|
$ |
18,930 |
|
|
$ |
27,725 |
|
|
$ |
45,252 |
|
|
$ |
46,267 |
|
|
|
|
|
|
|
|
|
|
(1)
Included as a portion of general and administrative expense on the
consolidated statement of operations. |
Schedule 8: Recurring Cash G&A(in thousands, unaudited)
Recurring 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 recurring cash G&A as GAAP G&A after adjusting for
the impact of non-cash stock compensation expense and non-recurring
items.
The following table presents a reconciliation of the GAAP
financial measure of general and administrative expense to the
non-GAAP financial measure of recurring cash G&A.
|
|
Three Months Ended June 30, |
|
|
2017 |
|
2016 |
General and
Administrative |
|
$ |
19,137 |
|
|
$ |
13,235 |
|
Stock-based
compensation |
|
(8,340 |
) |
|
(2,380 |
) |
Cash G&A |
|
$ |
10,797 |
|
|
$ |
10,855 |
|
Post-petition
restructuring fees |
|
(1,422 |
) |
|
— |
|
Other non-recurring
expense |
|
(184 |
) |
|
— |
|
Recurring Cash
G&A |
|
$ |
9,191 |
|
|
$ |
10,855 |
|
For further information, please contact:
James R. Edwards
Director - Investor Relations
720-440-6136
jedwards@bonanzacrk.com
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