- Third quarter production volumes averaged 21.0 MBoe per day,
exceeding the midpoint of guidance by 5%
- Improving operational efficiency resulted in the fifth
consecutive quarter of reductions in Rockies LOE and midstream
expense; Rockies upstream LOE of $4.09/Boe
- GAAP cash provided by operating activities of $17.5 million;
adjusted EBITDAX(1) of $25.1 million; GAAP net loss of $0.71 per
diluted share; adjusted net loss(1) of $0.35 per diluted share
- Updated 2016 guidance reflects increased production and reduced
LOE and midstream expense
(1) Non-GAAP measure, see attached Reconciliation Schedules.
Bonanza Creek Energy, Inc. (NYSE:BCEI) (the "Company") today
announces its third quarter 2016 financial and operating results.
Third Quarter 2016 Results
For the third quarter of 2016, the Company reported average
daily production of 21.0 MBoe per day, a 10% sequential decrease
from the second quarter of 2016, and a 28% decrease from the third
quarter of 2015. The reduction in production volumes is a result of
suspended drilling and completion operations at the end of the
first quarter of 2016. Product mix for the third quarter of 2016
was 52% oil, 22% NGLs, and 26% natural gas.
Net revenue for the third quarter of 2016 was $49.3 million, a
10% sequential decrease from the second quarter of 2016 and a 32%
decrease from the third quarter of 2015. Crude oil accounted for
approximately 77% of total revenue. Differentials for the Company's
Rocky Mountain oil production during the quarter averaged
approximately $9.64 per Bbl. Average realized prices for the third
quarter of 2016 are presented below.
Average Realized Prices |
|
Three Months Ended September 30, 2016 |
|
Before Derivatives |
|
After Derivatives |
Oil (per Bbl) (1) |
37.45 |
|
|
41.74 |
|
Gas (per Mcf) (2) |
2.31 |
|
|
2.31 |
|
NGL (per Bbl) |
10.80 |
|
|
10.80 |
|
Boe (Per Boe) |
25.57 |
|
|
27.83 |
|
(1) Crude
oil sales includes $104,000 and $46,000 of oil transportation
revenues from third parties, which do not have associated sales
volumes, for the three months ended September 30, 2016 and 2015,
respectively. |
(2) Natural
gas sales includes $381,000 and $291,000 of gas gathering revenues
from third parties, which do not have associated sales volumes, for
the three months ended September 30, 2016 and 2015,
respectively. |
The Company's Rocky Mountain region has lowered its cost
structure significantly on a sequential basis by reducing its LOE
and midstream operating expense by $2.3 million and $0.3 million,
respectively, from the second quarter of 2016. Rockies LOE and
midstream expense for the third quarter of 2016 was $6.4 million
and $1.2 million, respectively. Total Company LOE for the third
quarter of 2016 was $9.9 million, or $5.13 per Boe, compared to
$10.7 million, or $5.08 per Boe in the second quarter of 2016, and
$17.2 million, or $6.44 per Boe in the third quarter of 2015. The
Company continues to execute on cost saving initiatives resulting
in a 20% year over year reduction in per unit LOE in a period of
declining production. Below is a breakout of the Company's
regional LOE and gas plant and midstream operating expense for the
third quarter of 2016.
Lease Operating Expense |
|
Three Months Ended September 30,
2016 |
|
Rocky Mountain |
|
Mid-Continent |
|
Total Company |
|
($M) |
|
($/Boe) |
|
($M) |
|
($/Boe) |
|
($M) |
|
($/Boe) |
LOE |
$ |
6,403 |
|
|
$ |
4.09 |
|
|
$ |
3,490 |
|
|
$ |
9.61 |
|
|
$ |
9,893 |
|
|
$ |
5.13 |
|
Gas plant and midstream
operating expense |
1,237 |
|
|
0.79 |
|
|
1,637 |
|
|
4.51 |
|
|
2,874 |
|
|
1.49 |
|
Total |
$ |
7,640 |
|
|
$ |
4.88 |
|
|
$ |
5,127 |
|
|
$ |
14.12 |
|
|
$ |
12,767 |
|
|
$ |
6.62 |
|
Recurring cash general and administrative ("G&A") expense,
which excludes stock compensation and advisor fees, for the third
quarter of 2016 was $10.9 million, or $5.65 per Boe. This compares
to recurring cash G&A expense of $10.9 million, or $5.13 per
Boe in the second quarter of 2016, and $13.5 million, or $5.07 per
Boe in the third quarter of 2015. Total G&A expense for the
third quarter of 2016 was $18.7 million, or $9.68 per Boe. This
compares to G&A expense of $17.8 million, or $6.69 per Boe in
the third quarter of 2015 and $13.2 million, or $6.26 per Boe in
the second quarter of 2016. Total G&A expense has increased
sequentially by 41% from the second quarter of 2016, and has
increased by 5% from the third quarter of 2015. The increase to
G&A during the third quarter of 2016 was a result of advisor
fees incurred in connection with the Company's evaluation of
certain financing alternatives of $5.9 million.
Depreciation, depletion and amortization ("DD&A") for third
quarter of 2016 was $27.3 million, or $14.15 per Boe, a 3%
sequential decrease on a per unit basis from the second quarter of
2016 and a 36% decrease on a per unit basis from the third quarter
2015.
During the third quarter, the Company incurred upstream CAPEX of
approximately $1.0 million, which related to lease extensions and
pumping units in the Wattenberg field. This compares to upstream
CAPEX of $77.8 million in the third quarter of 2015. Year to date,
2016 total CAPEX was $18.5 million, of which $2.1 million was
attributable to the Company's midstream subsidiary, Rocky Mountain
Infrastructure, LLC ("RMI").
Reported GAAP net loss for the third quarter of 2016 was $34.9
million, or $0.71 per diluted share, compared to a net loss of
$112.3 million, or $2.25 per diluted share, for the third quarter
of 2015. Adjusted net loss for the third quarter of 2016 was $17.4
million, or $0.35 per diluted share, compared to an adjusted net
loss of $3.6 million, or $0.07 per diluted share for the third
quarter of 2015, and an adjusted net loss of $19.7 million, or
$0.40 per diluted share for the second quarter of 2016. Adjusted
EBITDAX for the third quarter of 2016 was $25.1 million, a 66%
decrease compared to $73.3 million for the third quarter of 2015
and a 9% sequential decrease from the second quarter of 2016.
Recurring cash G&A, adjusted net income and adjusted EBITDAX
are non-GAAP financial measures. Recurring cash G&A is defined
as GAAP G&A expense excluding stock compensation and
non-recurring items such as severance costs and advisory fees. See
Schedule 1 for general and administrative break-out of stock-based
compensation and schedule 6 for the break out of severance costs
and advisor fees. For adjusted net income and adjusted EBITDAX,
please refer to the respective reconciliations in the schedules at
the end of this release for additional information about these
measures.
The table below summarizes the Company's quarterly and year to
date results as compared to guidance provided in the second quarter
earnings release. Updated twelve month guidance is included in the
Fourth Quarter Guidance and Update section of this release.
Third Quarter
Guidance vs Actual Summary |
|
|
|
|
Three Months Ended September 30,
2016 |
|
Guidance |
|
Actual |
|
|
|
|
Production
(MBoe/d) |
19.6 –
20.2 |
|
21.0 |
|
|
|
|
|
|
Twelve Months Ended December 31, 2016 |
|
Nine Months Ended September 30,
2016 |
|
Guidance |
|
Actual |
LOE ($MM) |
$44 –
$48 |
|
$ |
33.9 |
|
Midstream ($MM) |
$14 –
$16 |
|
$ |
10.2 |
|
Recurring cash G&A
($MM)* |
$40 –
$44 |
|
$ |
34.3 |
|
Production taxes (% of
pre-derivative realization) |
6% –
7% |
|
7.8 |
% |
CAPEX ($MM) |
$25 –
$35 |
|
$ |
18.5 |
|
|
|
|
|
* Recurring
cash G&A guidance is a non-GAAP measure that is exclusive of
the Company's stock based compensation, one-time severance charges
of $2.2 million in the first quarter of 2016, and advisor fees of
$5.9 million in the third quarter of 2016. The Company does not
guide to GAAP G&A expense as it has less certainty to the stock
based compensation and non-recurring portions of GAAP G&A. |
Operations Update
Rocky Mountain Region – Wattenberg
Production from the Rocky Mountain region during the third
quarter of 2016, averaged 17.0 MBoe/d, or 81% of total Company
volumes. The production was comprised of 52% crude oil, 23% NGLs,
and 25% natural gas. Rocky Mountain average daily sales volumes
decreased sequentially by 11% from the second quarter of 2016 and
decreased 28% compared to the third quarter of 2015 due to
suspended drilling and completion activity.
The Company did not drill or complete any horizontal wells
during the third quarter as it idled its development program at the
end of the first quarter. At the end of the third quarter, the
Company had six drilled uncompleted wells, consisting of four
standard reach and two extended reach laterals. The Company does
not currently have any plans to restart drilling or completion
activity in the fourth quarter of 2016.
Mid-Continent Region – Cotton Valley
The Mid-Continent region contributed 3.9 MBoe/d, or 19% of total
Company net sales volumes for the third quarter of 2016, and was
comprised of 55% crude oil, 15% NGLs, and 30% natural gas. Sales
volumes decreased sequentially by 6% from the second quarter of
2016 and decreased 26% compared to the third quarter of 2015 as a
result of suspended drilling and completions activity.
Financial and Risk Management Update
Debt and Liquidity
The Company has a $1.0 billion revolving credit facility, which
was redetermined on October 31, the "Redetermination Date" to an
approved borrowing base and commitment amount of $150 million. As
of September 30, 2016, the Company had borrowings under its
credit facility of $229.3 million and cash totaling $133.4
million. As the outstanding borrowings on the credit facility
exceed the newly redetermined borrowing base, the Company, under
the terms of the agreement, has 20 days from the Redetermination
Date to notify the bank group of its intended method to cure the
deficiency. To cure the deficiency, the Company may elect to, a)
repay advances such that the deficiency is cured within a 30-day
period, b) pledge additional oil and gas properties acceptable to
the lenders to eliminate the deficiency, c) elect to repay the
deficiency amount in 6 equal monthly installments, or d) a
combination of options b and c. As of the end of the third quarter,
the Company had two remaining deficiency payments payable to the
bank group related to its borrowing base deficiency resulting from
the May 20, 2016 redetermination, the first of which was paid on
October 13, 2016, with the last payment due in November.
As of September 30, 2016, the Company was not in compliance
with its interest coverage ratio covenant under its credit
facility. The interest coverage ratio as set forth in the credit
facility is to remain above 2.5x. At the end of the third quarter,
the Company's interest coverage ratio was 2.3x. The Company is
currently in discussions with its credit facility lending syndicate
to negotiate a waiver, amendment or forbearance agreement. If the
Company is unable to obtain one of the aforementioned remedies, the
lenders could give notice of acceleration as a result of this
non-compliance. The Company was in compliance with its remaining
two financial covenants under its credit facility, with a senior
secured debt to TTM EBITDAX ratio of 1.7x, and a current ratio of
2.4x. The Company's credit facility covenants require a secured
debt to TTM EBITDAX ratio of less than 2.5x and a current ratio of
greater than 1.0x.
On November 8, 2016, the Company made the bond interest payment
on its $500 million issue of 6.75% senior unsecured notes to the
indenture trustee, which was due on October 15, 2016. By making the
$17.0 million interest payment within the 30-day grace period, the
Company remains in compliance with its senior unsecured notes.
The Company continues to work with its advisors, and is
currently in discussions with various stakeholders,
regarding a potential (i) debt for equity
exchange or (ii) private secured financing
transaction.
Please review the Company's quarterly report on Form 10-Q filed
with the Securities Exchange Commission on November 9, 2016 for
further information regarding the Company's debt and liquidity.
Commodity Derivatives Positions
The following table summarizes the Company’s crude oil and
natural gas commodity derivative positions as of September 30,
2016 and settling quarterly:
Settlement Period |
|
Volume (Bbls/d) |
|
Contract Type |
|
Swap Price |
4Q
2016 |
|
2,303 |
|
Fixed
Price Swap |
|
$ |
52.83 |
|
|
|
|
|
|
|
|
Settlement Period |
|
Volume (Bbls/d) |
|
Contract Type |
|
Floor Price |
4Q
2016 |
|
4,031 |
|
Floor
(Long Put) |
|
$ |
51.01 |
|
Fourth Quarter Guidance and Update
The Company is providing updated cost and CAPEX guidance for the
fourth quarter of 2016 that reflects a continued improvement in
cost structure and lower than expected PDP declines. As a result,
the Company has increased its production guidance for the full year
2016, reduced the midpoint of its full year guidance for LOE,
midstream expense, and CAPEX. The table below provides updated
guidance for the fourth quarter and full year of 2016.
Fourth Quarter
Guidance Summary |
|
|
|
|
Three Months Ended December 31, 2016 |
|
Twelve Months Ended December 31, 2016 |
|
|
|
|
Production
(MBoe/d) |
17.7 –
18.3 |
|
21.5 –
21.7 |
LOE ($MM) |
|
|
$43 –
$46 |
Midstream expense
($MM) |
|
|
$12 –
$14 |
Recurring cash G&A
($/Boe)* |
|
|
$44 –
$46 |
Production taxes (% of
pre-derivative realization) |
|
|
6% –
7% |
Total CAPEX |
|
|
$25 –
$27 |
* Recurring
cash G&A guidance is a non-GAAP measure that is exclusive of
the Company's stock based compensation, one-time severance charges
of $2.2 million in the first quarter of 2016, and advisor fees of
$5.9 million in the third quarter of 2016. The Company does not
guide to GAAP G&A expense as it has less certainty to the stock
based compensation and non-recurring portions of GAAP G&A. |
Conference Call InformationThe Company will not
be hosting a conference call to discuss its third quarter
results.
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
updated 2016 guidance; drilling and completion expectations for the
remainder of 2016; and the impact of redeterminations of the
Company's borrowing base and covenant breaches under the Company's
revolving credit facility and the Company's ability to cure such
deficiencies. 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, 2015, filed on February 29, 2016, 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)
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Operating net
revenues: |
|
|
|
|
|
|
|
Oil and gas sales |
$ |
49,325 |
|
|
$ |
72,149 |
|
|
$ |
148,029 |
|
|
$ |
235,647 |
|
Operating
expenses: |
|
|
|
|
|
|
|
Lease operating expense |
9,893 |
|
|
17,155 |
|
|
33,928 |
|
|
51,710 |
|
Gas plant and midstream operating
expense |
2,874 |
|
|
3,081 |
|
|
10,198 |
|
|
8,685 |
|
Severance and ad valorem taxes |
4,100 |
|
|
2,411 |
|
|
11,531 |
|
|
13,055 |
|
Exploration |
— |
|
|
6,979 |
|
|
943 |
|
|
13,225 |
|
Depreciation, depletion and
amortization |
27,296 |
|
|
58,635 |
|
|
84,602 |
|
|
187,564 |
|
Impairment of oil and gas
properties |
— |
|
|
166,780 |
|
|
10,000 |
|
|
166,780 |
|
Abandonment and impairment of
unproved properties |
7,682 |
|
|
1,630 |
|
|
24,463 |
|
|
21,627 |
|
Unused commitments |
1,688 |
|
|
— |
|
|
3,460 |
|
|
— |
|
General and administrative
(including $1,863, $3,164, $7,249 and $10,951, respectively, of
stock-based compensation) |
18,671 |
|
|
17,818 |
|
|
49,591 |
|
|
56,292 |
|
Total operating expenses |
72,204 |
|
|
274,489 |
|
|
228,716 |
|
|
518,938 |
|
Loss from
operations |
(22,879 |
) |
|
(202,340 |
) |
|
(80,687 |
) |
|
(283,291 |
) |
Other income
(expense): |
|
|
|
|
|
|
|
Derivative gain (loss) |
2,206 |
|
|
37,894 |
|
|
(11,724 |
) |
|
51,272 |
|
Interest expense |
(15,142 |
) |
|
(14,073 |
) |
|
(46,216 |
) |
|
(42,779 |
) |
Gain on termination fee |
— |
|
|
— |
|
|
6,000 |
|
|
— |
|
Other gain (loss) |
913 |
|
|
(2,077 |
) |
|
1,011 |
|
|
(1,929 |
) |
Total other income (expense) |
(12,023 |
) |
|
21,744 |
|
|
(50,929 |
) |
|
6,564 |
|
Loss from operations
before taxes |
(34,902 |
) |
|
(180,596 |
) |
|
(131,616 |
) |
|
(276,727 |
) |
Income tax benefit |
— |
|
|
68,297 |
|
|
— |
|
|
104,843 |
|
Net loss |
$ |
(34,902 |
) |
|
$ |
(112,299 |
) |
|
(131,616 |
) |
|
$ |
(171,884 |
) |
|
|
|
|
|
|
|
|
Basic and diluted net
loss per common share |
$ |
(0.71 |
) |
|
$ |
(2.25 |
) |
|
$ |
(2.67 |
) |
|
$ |
(3.56 |
) |
|
|
|
|
|
|
|
|
Basic and diluted
weighted-average common shares outstanding |
49,324 |
|
|
48,962 |
|
|
49,244 |
|
|
47,485 |
|
- The Company follows the two-class method when computing the
basic and diluted loss per share, which allocates earnings between
common shareholders and participating securities. Please refer to
Note 10 – Earnings per Share in the Form 10-Q, for a detailed
calculation.
Schedule 2: Statement of Cash Flows(in thousands, unaudited)
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Cash flows from
operating activities: |
|
|
|
|
|
|
|
Net loss |
$ |
(34,902 |
) |
|
$ |
(112,299 |
) |
|
$ |
(131,616 |
) |
|
$ |
(171,884 |
) |
Adjustments to reconcile net loss
to net cash provided by operating activities: |
|
|
|
|
|
|
|
Depreciation, depletion and
amortization |
27,296 |
|
|
58,635 |
|
|
84,602 |
|
|
187,564 |
|
Deferred income tax benefit |
— |
|
|
(69,051 |
) |
|
— |
|
|
(105,595 |
) |
Impairment of oil and gas
properties |
— |
|
|
166,780 |
|
|
10,000 |
|
|
166,780 |
|
Abandonment and impairment of
unproved properties |
7,682 |
|
|
1,630 |
|
|
24,463 |
|
|
21,627 |
|
Dry hole expense |
(61 |
) |
|
1,948 |
|
|
905 |
|
|
7,628 |
|
Stock-based compensation |
1,865 |
|
|
3,164 |
|
|
7,249 |
|
|
10,951 |
|
Amortization of deferred financing
costs and debt premium |
426 |
|
|
466 |
|
|
2,705 |
|
|
1,692 |
|
Accretion of contractual obligation
for land acquisition |
— |
|
|
116 |
|
|
— |
|
|
814 |
|
Derivative (gain) loss |
(2,206 |
) |
|
(37,894 |
) |
|
11,724 |
|
|
(51,272 |
) |
Derivative cash settlements |
4,348 |
|
|
37,717 |
|
|
15,749 |
|
|
88,372 |
|
Other |
1,923 |
|
|
328 |
|
|
127 |
|
|
283 |
|
Changes in current assets and
liabilities: |
|
|
|
|
|
|
|
Accounts receivable |
6,027 |
|
|
9,934 |
|
|
29,442 |
|
|
28,253 |
|
Prepaid expenses and other
assets |
301 |
|
|
2,342 |
|
|
(1,047 |
) |
|
994 |
|
Accounts payable and accrued
liabilities |
5,205 |
|
|
11,149 |
|
|
(23,252 |
) |
|
(11,905 |
) |
Settlement of asset retirement
obligations |
(398 |
) |
|
(259 |
) |
|
(473 |
) |
|
(778 |
) |
Net cash provided by operating
activities |
17,506 |
|
|
74,706 |
|
|
30,578 |
|
|
173,524 |
|
Cash flows from
investing activities: |
|
|
|
|
|
|
|
Acquisition of oil and gas
properties |
(103 |
) |
|
(1,688 |
) |
|
(919 |
) |
|
(13,602 |
) |
Payments of contractual
obligation |
— |
|
|
(12,000 |
) |
|
(12,000 |
) |
|
(12,000 |
) |
Exploration and development of oil
and gas properties |
(4,738 |
) |
|
(78,025 |
) |
|
(47,491 |
) |
|
(361,131 |
) |
Increase in restricted cash |
(5,172 |
) |
|
2,926 |
|
|
(7,707 |
) |
|
2,926 |
|
Additions to property and equipment
- non oil and gas |
(145 |
) |
|
(1,741 |
) |
|
(106 |
) |
|
(2,390 |
) |
Net cash used in investing
activities |
(10,158 |
) |
|
(90,528 |
) |
|
(68,223 |
) |
|
(386,197 |
) |
Cash flows from
financing activities: |
|
|
|
|
|
|
|
Proceeds from credit facility |
— |
|
|
28,000 |
|
|
209,000 |
|
|
115,000 |
|
Payments to credit facility |
(44,000 |
) |
|
(2,000 |
) |
|
(58,667 |
) |
|
(79,000 |
) |
Proceeds from sale of common
stock |
— |
|
|
— |
|
|
— |
|
|
209,300 |
|
Offering costs related to sale of
common stock |
— |
|
|
(13 |
) |
|
— |
|
|
(6,620 |
) |
Offering costs related to sale of
Senior Notes |
— |
|
|
(6 |
) |
|
— |
|
|
(99 |
) |
Payment of employee tax
withholdings in exchange for the return of common stock |
(10 |
) |
|
(145 |
) |
|
(283 |
) |
|
(2,593 |
) |
Deferred restructuring charges |
— |
|
|
— |
|
|
— |
|
|
— |
|
Deferred financing costs |
(79 |
) |
|
(28 |
) |
|
(316 |
) |
|
(573 |
) |
Net cash provided by (used in)
financing activities |
(44,089 |
) |
|
25,808 |
|
|
149,734 |
|
|
235,415 |
|
Net change in cash and
cash equivalents |
(36,741 |
) |
|
9,986 |
|
|
112,089 |
|
|
22,742 |
|
Cash and cash
equivalents: |
|
|
|
|
|
|
|
Beginning of period |
170,171 |
|
|
15,340 |
|
|
21,341 |
|
|
2,584 |
|
End of period |
$ |
133,430 |
|
|
$ |
25,326 |
|
|
$ |
133,430 |
|
|
$ |
25,326 |
|
Schedule 3: Condensed Balance Sheet(in thousands, unaudited)
|
September 30, |
|
December
31, |
|
2016 |
|
2015 |
ASSETS |
|
|
|
Current assets |
$ |
176,746 |
|
|
$ |
120,074 |
|
Oil and gas properties
and natural gas plant held for sale, net of accumulated
depreciation, depletion and amortization of $636,917 in 2015 |
— |
|
|
214,922 |
|
Total property and
equipment, net |
1,039,289 |
|
|
922,344 |
|
Other noncurrent
assets |
8,362 |
|
|
2,301 |
|
Total
Assets |
$ |
1,224,397 |
|
|
$ |
1,259,641 |
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS’ EQUITY |
|
|
|
Current
liabilities |
$ |
1,101,870 |
|
|
$ |
135,973 |
|
Long-term debt |
— |
|
|
871,666 |
|
Other long-term
liabilities |
37,771 |
|
|
42,595 |
|
Total
Liabilities |
1,139,641 |
|
|
1,050,234 |
|
|
|
|
|
Stockholders’
Equity |
84,756 |
|
|
209,407 |
|
Total
Liabilities and Stockholders’ Equity |
$ |
1,224,397 |
|
|
$ |
1,259,641 |
|
Schedule 4: Volumes and Realized Prices (Before and After the
Effect of Commodity Hedges)(unaudited)
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Wellhead
Volumes and Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and
Condensate Sales Volumes (Bbl/d) |
|
|
|
|
|
|
|
Rocky Mountains |
8,845 |
|
|
14,083 |
|
|
10,403 |
|
|
13,947 |
|
Mid-Continent |
2,152 |
|
|
2,774 |
|
|
2,286 |
|
|
2,809 |
|
Total |
10,997 |
|
|
16,857 |
|
|
12,689 |
|
|
16,756 |
|
|
|
|
|
|
|
|
|
Crude Oil and
Condensate Realized Prices ($/Bbl) |
|
|
|
|
|
|
|
Rocky Mountains |
$ |
35.77 |
|
|
$ |
37.49 |
|
|
$ |
32.15 |
|
|
$ |
41.52 |
|
Mid-Continent |
$ |
44.33 |
|
|
$ |
45.89 |
|
|
$ |
41.64 |
|
|
$ |
49.70 |
|
Composite (before
derivatives) (1) |
$ |
37.45 |
|
|
$ |
38.87 |
|
|
$ |
33.86 |
|
|
$ |
42.89 |
|
Composite (after
derivatives) (1) |
$ |
41.74 |
|
|
$ |
62.75 |
|
|
$ |
38.39 |
|
|
$ |
61.76 |
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids Sales Volumes (Bbl/d) |
|
|
|
|
|
|
|
Rocky Mountains |
3,916 |
|
|
4,409 |
|
|
3,702 |
|
|
3,859 |
|
Mid-Continent |
607 |
|
|
862 |
|
|
667 |
|
|
958 |
|
Total |
4,523 |
|
|
5,271 |
|
|
4,369 |
|
|
4,817 |
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids Realized Prices ($/Bbl) |
|
|
|
|
|
|
|
Rocky Mountains |
$ |
9.77 |
|
|
$ |
8.01 |
|
|
$ |
11.08 |
|
|
$ |
12.15 |
|
Mid-Continent |
$ |
17.44 |
|
|
$ |
7.37 |
|
|
$ |
15.38 |
|
|
$ |
13.50 |
|
Composite (before
derivatives) |
$ |
10.80 |
|
|
$ |
7.90 |
|
|
$ |
11.73 |
|
|
$ |
12.42 |
|
Composite (after
derivatives) |
$ |
10.80 |
|
|
$ |
7.91 |
|
|
$ |
11.73 |
|
|
$ |
12.42 |
|
|
|
|
|
|
|
|
|
Natural Gas
Sales Volumes (Mcf/d) |
|
|
|
|
|
|
|
Rocky Mountains |
25,536 |
|
|
30,914 |
|
|
27,202 |
|
|
29,843 |
|
Mid-Continent |
7,141 |
|
|
10,022 |
|
|
7,478 |
|
|
9,750 |
|
Total |
32,677 |
|
|
40,936 |
|
|
34,680 |
|
|
39,593 |
|
|
|
|
|
|
|
|
|
Natural Gas
Realized Prices ($/Mcf) |
|
|
|
|
|
|
|
Rocky Mountains |
$ |
2.14 |
|
|
$ |
1.89 |
|
|
$ |
1.54 |
|
|
$ |
1.85 |
|
Mid-Continent |
$ |
2.93 |
|
|
$ |
2.88 |
|
|
$ |
2.33 |
|
|
$ |
3.03 |
|
Composite (before
derivatives) (2) |
$ |
2.31 |
|
|
$ |
2.13 |
|
|
$ |
1.71 |
|
|
$ |
2.14 |
|
Composite (after
derivatives) (2) |
$ |
2.31 |
|
|
$ |
2.32 |
|
|
$ |
1.71 |
|
|
$ |
2.33 |
|
|
|
|
|
|
|
|
|
Crude Oil
Equivalent Sales Volumes (Boe/d) |
|
|
|
|
|
|
|
Rocky Mountains |
17,017 |
|
|
23,645 |
|
|
18,639 |
|
|
22,780 |
|
Mid-Continent |
3,949 |
|
|
5,306 |
|
|
4,199 |
|
|
5,392 |
|
Total |
20,966 |
|
|
28,951 |
|
|
22,838 |
|
|
28,172 |
|
|
|
|
|
|
|
|
|
Crude Oil
Equivalent Sales Prices ($/Boe) |
|
|
|
|
|
|
|
Rocky Mountains |
$ |
24.05 |
|
|
$ |
26.14 |
|
|
$ |
22.39 |
|
|
$ |
29.90 |
|
Mid-Continent |
$ |
32.13 |
|
|
$ |
30.64 |
|
|
$ |
29.26 |
|
|
$ |
33.77 |
|
Composite (before
derivatives) |
$ |
25.57 |
|
|
$ |
27.09 |
|
|
$ |
23.66 |
|
|
$ |
30.64 |
|
Composite (after
derivatives) |
$ |
27.83 |
|
|
$ |
41.25 |
|
|
$ |
26.17 |
|
|
$ |
42.13 |
|
Total Sales
Volumes (MBoe) |
1,928.9 |
|
|
2,663.5 |
|
|
6,257.5 |
|
|
7,690.8 |
|
|
|
|
|
|
|
|
|
(1) Crude
oil sales includes $104,000 and $46,000 of oil transportation
revenues from third parties, which do not have associated sales
volumes, for the three months ended September 30, 2016 and 2015,
respectively; and includes $387,000 and $46,000 for the nine months
ended September 30, 2016 and 2015, respectively. |
(2)
Natural gas sales includes $381,000 and $291,000 of gas gathering
revenues from third parties, which do not have associated sales
volumes, for the three months ended September 30, 2016 and 2015,
respectively; and includes $1.1 million and $0.4 million for
the nine months ended September 30, 2016 and 2015,
respectively. |
Schedule 5: Per unit operating margins(unaudited)
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
|
2016 |
|
|
|
2015 |
|
|
Percent Change |
|
|
2016 |
|
|
2015 |
|
Percent Change |
Production |
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl) |
1,011.7 |
|
|
1,550.8 |
|
|
(35 |
)% |
|
3,476.6 |
|
|
4,574.3 |
|
|
(24 |
)% |
Gas (MMcf) |
3,006.2 |
|
|
3,766.0 |
|
|
(20 |
)% |
|
9,502.2 |
|
|
10,808.8 |
|
|
(12 |
)% |
NGL (MBbl) |
416.2 |
|
|
485.0 |
|
|
(14 |
)% |
|
1,197.2 |
|
|
1,315.0 |
|
|
(9 |
)% |
Equivalent (MBoe) |
1,928.9 |
|
|
2,663.5 |
|
|
(28 |
)% |
|
6,257.5 |
|
|
7,690.8 |
|
|
(19 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
Realized pricing (before derivatives) |
|
|
|
|
|
|
|
|
|
|
Oil ($/Bbl) |
$ |
37.45 |
|
|
$ |
38.87 |
|
|
(4 |
)% |
|
$ |
33.86 |
|
|
$ |
42.89 |
|
|
(21 |
)% |
Gas ($/Mcf) |
$ |
2.31 |
|
|
$ |
2.13 |
|
|
8 |
% |
|
1.71 |
|
|
2.14 |
|
|
(20 |
)% |
NGL ($/Bbl) |
$ |
10.80 |
|
|
$ |
7.91 |
|
|
37 |
% |
|
11.73 |
|
|
12.42 |
|
|
(6 |
)% |
Equivalent ($/Boe) |
$ |
25.57 |
|
|
$ |
27.09 |
|
|
(6 |
)% |
|
$ |
23.66 |
|
|
$ |
30.64 |
|
|
(23 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
Per Unit Costs
($/Boe) |
|
|
|
|
|
|
|
|
|
|
|
Realized price (before
derivatives) |
$ |
25.57 |
|
|
$ |
27.09 |
|
|
(6 |
)% |
|
$ |
23.66 |
|
|
30.64 |
|
|
(23 |
)% |
LOE |
5.13 |
|
|
6.44 |
|
|
(20 |
)% |
|
$ |
5.42 |
|
|
$ |
6.72 |
|
|
(19 |
)% |
Gas plant and midstream operating
expense |
1.49 |
|
|
1.16 |
|
|
28 |
% |
|
$ |
1.63 |
|
|
$ |
1.13 |
|
|
44 |
% |
Severance and Ad Valorem |
2.13 |
|
|
0.91 |
|
|
134 |
% |
|
$ |
1.84 |
|
|
$ |
1.70 |
|
|
8 |
% |
Cash General and
Administrative |
|
8.71 |
|
|
|
5.50 |
|
|
58 |
% |
|
$ |
6.77 |
|
|
$ |
5.90 |
|
|
15 |
% |
Total cash operating costs |
$ |
17.46 |
|
|
$ |
14.01 |
|
|
25 |
% |
|
$ |
15.66 |
|
|
$ |
15.45 |
|
|
1 |
% |
Cash operating margin (before
derivatives) |
$ |
8.11 |
|
|
$ |
13.08 |
|
|
(38 |
)% |
|
$ |
8.00 |
|
|
$ |
15.19 |
|
|
(47 |
)% |
Derivative Cash Settlements |
2.26 |
|
|
14.16 |
|
|
(84 |
)% |
|
$ |
2.51 |
|
|
11.49 |
|
|
(78 |
)% |
Cash operating margin (after
derivatives) |
$ |
10.37 |
|
|
$ |
27.24 |
|
|
(62 |
)% |
|
$ |
10.51 |
|
|
26.68 |
|
|
(61 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash
items |
|
|
|
|
|
|
|
|
|
|
|
Depreciation Depletion and
Amortization |
14.15 |
|
|
22.01 |
|
|
(36 |
)% |
|
$ |
13.52 |
|
|
$ |
24.39 |
|
|
(45 |
)% |
Non-cash General and
Administrative |
$ |
0.97 |
|
|
$ |
1.19 |
|
|
(18 |
)% |
|
$ |
1.16 |
|
|
$ |
1.42 |
|
|
(18 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
Schedule 6: Adjusted Net Income (Loss)(in thousands, except per
share amounts, unaudited)
Adjusted net income is a supplemental non-GAAP financial measure
that is used by management to present recurring
profitability by excluding items which are non-recurring in nature
or items which are not easily estimable. Management believes
adjusted net income provides external users of the Company's
consolidated financial statements such as industry analysts,
investors, creditors, and rating agencies with additional
information to assist in their analysis of the Company. The Company
defines adjusted net income as net income 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 and one-time
transactions and then (2) 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 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 income (loss).
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Net
loss |
|
$ |
(34,902 |
) |
|
$ |
(112,299 |
) |
|
$ |
(131,616 |
) |
|
$ |
(171,884 |
) |
Adjustments to net
loss: |
|
|
|
|
|
|
|
|
Derivative (gain)
loss |
|
(2,206 |
) |
|
(37,894 |
) |
|
11,724 |
|
|
(51,272 |
) |
Derivative cash
settlements |
|
4,348 |
|
|
37,717 |
|
|
15,749 |
|
|
88,372 |
|
Impairment of proved
properties |
|
— |
|
|
166,780 |
|
|
10,000 |
|
|
166,780 |
|
Abandonment and
impairment of unproved properties |
|
7,682 |
|
|
1,630 |
|
|
24,463 |
|
|
21,627 |
|
Exploratory dry
hole |
|
(61 |
) |
|
1,948 |
|
|
905 |
|
|
7,628 |
|
Stock-based
compensation |
|
1,865 |
|
|
3,164 |
|
|
7,249 |
|
|
10,951 |
|
Advisor fees related to
financial alternatives (1) |
|
5,918 |
|
|
— |
|
|
5,918 |
|
|
— |
|
Cash severance costs
(1) |
|
— |
|
|
1,155 |
|
|
2,162 |
|
|
1,155 |
|
Gain on termination fee
(2) |
|
— |
|
|
— |
|
|
(6,000 |
) |
|
— |
|
Derivative conversion
payment (3) |
|
— |
|
|
— |
|
|
— |
|
|
10,472 |
|
Litigation settlement
(4) |
|
— |
|
|
1,638 |
|
|
— |
|
|
1,638 |
|
Total adjustments
before taxes |
|
17,546 |
|
|
176,138 |
|
|
72,170 |
|
|
257,351 |
|
Income tax effect |
|
— |
% |
|
38.5 |
% |
|
— |
% |
|
38.5 |
% |
Total adjustments after
taxes |
|
$ |
17,546 |
|
|
$ |
108,677 |
|
|
$ |
72,170 |
|
|
$ |
158,271 |
|
|
|
|
|
|
|
|
|
|
Adjusted net
loss |
|
$ |
(17,356 |
) |
|
$ |
(3,622 |
) |
|
$ |
(59,446 |
) |
|
$ |
(13,613 |
) |
Adjusted net
loss per diluted share |
|
$ |
(0.35 |
) |
|
$ |
(0.07 |
) |
|
$ |
(1.21 |
) |
|
$ |
(0.29 |
) |
|
|
|
|
|
|
|
|
|
Diluted
weighted-average common shares outstanding |
|
49,324 |
|
|
48,962 |
|
|
49,244 |
|
|
47,485 |
|
|
|
|
|
|
|
|
|
|
(1)
Included as a portion of general and administrative expense
on the consolidated statement of operations. |
(2)
Gain resulting from termination fee on unsuccessful RMI
transaction during the first quarter of 2016. |
(3)
Conversion payment is included as a portion of derivative cash
settlements on the statement of cash flows and results from hedge
restructuring in the second quarter of 2015 from 3-way collars to
2-way collars. |
(4)
Included as a portion of other income (loss) on the consolidated
statement of operations. |
|
Schedule 7: Adjusted EBITDAX(in thousands, unaudited)
Adjusted EBITDAX is a supplemental non-GAAP financial measure
that is used by management to provide a metric of the Company's
ability to internally generate funds for exploration and
development of oil and gas properties and service debt. The metric
excludes items which are non-recurring in nature and/or items which
are not reasonably estimable. Management believes adjusted EBITDAX
provides and external users of the Company’s consolidated financial
statements, such as industry analysts, investors, creditors, and
rating agencies with additional information to assist in their
analysis of the Company. 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 September 30, |
|
Nine Months Ended September 30, |
|
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Net
loss |
|
$ |
(34,902 |
) |
|
$ |
(112,299 |
) |
|
$ |
(131,616 |
) |
|
$ |
(171,884 |
) |
Exploration |
|
— |
|
|
6,979 |
|
|
943 |
|
|
13,225 |
|
Depreciation, depletion and
amortization |
|
27,296 |
|
|
58,635 |
|
|
84,602 |
|
|
187,564 |
|
Impairment of proved
properties |
|
— |
|
|
166,780 |
|
|
10,000 |
|
|
166,780 |
|
Abandonment and impairment of
unproved properties |
|
7,682 |
|
|
1,630 |
|
|
24,463 |
|
|
21,627 |
|
Stock-based compensation |
|
1,865 |
|
|
3,164 |
|
|
7,249 |
|
|
10,951 |
|
Cash severance costs (1) |
|
— |
|
|
1,155 |
|
|
2,162 |
|
|
1,155 |
|
Advisor fees related to financial
alternatives (1) |
|
5,918 |
|
|
— |
|
|
5,918 |
|
|
— |
|
Gain on termination fee (2) |
|
— |
|
|
— |
|
|
(6,000 |
) |
|
— |
|
Derivative conversion payment
(3) |
|
— |
|
|
— |
|
|
— |
|
|
10,472 |
|
Litigation Settlement (4) |
|
— |
|
|
1,638 |
|
|
— |
|
|
1,638 |
|
Interest expense |
|
15,142 |
|
|
14,073 |
|
|
46,216 |
|
|
42,779 |
|
Derivative (gain) loss |
|
(2,206 |
) |
|
(37,894 |
) |
|
11,724 |
|
|
(51,272 |
) |
Derivative cash settlements |
|
4,348 |
|
|
37,717 |
|
|
15,749 |
|
|
88,372 |
|
Income tax benefit |
|
— |
|
|
(68,297 |
) |
|
— |
|
|
(104,843 |
) |
Adjusted
EBITDAX |
|
$ |
25,143 |
|
|
$ |
73,281 |
|
|
$ |
71,410 |
|
|
$ |
216,564 |
|
|
|
|
|
|
|
|
|
|
(1)
Included as a portion of general and administrative expense on the
consolidated statement of operations. |
(2)
Gain resulting from termination fee on unsuccessful RMI
transaction during the first quarter of 2016. |
(3)
Conversion payment is included as a portion of derivative cash
settlements on the statement of cash flows and results from hedge
restructuring in the second quarter of 2015 from 3-way collars to
2-way collars. |
(4)
Included as a portion of other income (loss) on the consolidated
statement of operations. |
For further information, please contact:
James R. Edwards
Director - Investor Relations
720-440-6136
jedwards@bonanzacrk.com
Bonanza Creek Energy (NYSE:BCEI)
Historical Stock Chart
From Mar 2024 to Apr 2024
Bonanza Creek Energy (NYSE:BCEI)
Historical Stock Chart
From Apr 2023 to Apr 2024