- Second quarter production volumes averaged 23.2 MBoe per day,
compared to guidance of 23.0 MBoe per day at the midpoint
- GAAP cash used in operating activities of $11.8 million;
adjusted EBITDAX(1) of $27.7 million; GAAP net loss of $1.00 per
diluted share; adjusted net loss(1) of $0.40 per diluted share
- Improving operational efficiency resulted in reductions in LOE
and midstream expense; the Company is updating its 2016 guidance,
reducing the full-year midpoint for LOE, midstream, and CAPEX
- Suspending asset sale processes and focusing on other liquidity
enhancing and debt reducing measures
(1) Non-GAAP measure, see attached Reconciliation
Schedules.
Bonanza Creek Energy, Inc. (NYSE:BCEI) (the "Company") today
announces its second quarter 2016 financial and operating results.
Richard Carty, President and Chief Executive Officer, commented,
"Our operations team continues to exceed expectations and is
focused on increasing efficiencies and reducing costs. The second
quarter marked the fourth consecutive quarter of asset
outperformance in the Rockies since the full field implementation
of RMI in the third quarter of 2015, demonstrating a repeated
pattern of higher production volumes and lower LOE. Our
efficiency mandates have yielded a 41% decrease in second quarter
LOE from a year ago, and a 39% decrease in second quarter G&A
from the prior year. The second quarter also marked an
important milestone of two million work-hours completed without a
lost time injury, a commendable record for our health, safety, and
environmental initiatives. While the operating assets
continue to perform, our balance sheet and access to capital remain
a major headwind. In an effort to enhance the liquidity position of
the Company, in the first and second quarter of 2016 we targeted
divestitures of both our RMI and MidCon assets. Although we
received strong economic bids for both of these asset packages,
conditions included in the bid proposals require that the Company
improve its liquidity and its balance sheet. As a result, we have
suspended the divestiture efforts to focus on other liquidity
enhancing and debt restructuring options. To assist in evaluating
all alternatives, we have retained (as previously announced)
Perella Weinberg Partners as restructuring advisors and Davis Polk
& Wardwell as legal advisors."
Mr. Carty further commented, “Lastly, I want to express our
gratitude to Tony Buchanon, Executive Vice President and Chief
Operating Officer, for his contributions in building a strong and
capable operations team since 2013. Tony recently decided to step
down from his position in order to pursue another opportunity in
the industry. We wish him the very best. Our Board of Directors is
confident that our experienced engineering and operations managers
reporting to Dean Tinsley, Vice President, Rocky Mountain Asset
Management, Kerry McCowen, Vice President, Rocky Mountain
Operations, John Larson, Vice President, Mid-Continent Operations,
and David Stewart, Vice President, Environmental, Health, Safety
and Regulatory Compliance, and other talented Bonanza leaders will
ensure that our company doesn’t miss a beat. In addition, Jeff
Wojahn, a member of our Board and the former President of Encana
Oil & Gas (USA) Inc., has graciously volunteered to serve as
Senior Operations Advisor, to be done in his continued capacity as
a director of the Company. Although our drilling and completion
program is currently suspended while we address our balance sheet,
Jeff’s significant experience in the Wattenberg Field will be
extremely valuable as the Company prepares to resume more typical
operational activity levels."
Second Quarter 2016 Results
For the second quarter of 2016, the Company reported average
daily production of 23.2 MBoe per day, a 4% sequential decrease
from the first quarter of 2016, and a 17% decrease from the second
quarter of 2015. The reduction in production volumes is a result of
suspended drilling and completion operations at the end of the
first quarter. Product mix for the second quarter of 2016 was 56%
oil, 19% NGLs, and 25% natural gas.
Net revenue for the second quarter of 2016 was $54.5 million, a
23% sequential increase from the first quarter of 2016 and a 40%
decrease from the second quarter of 2015. Crude oil accounted for
approximately 83% of total revenue. Differentials for the Company's
Rocky Mountain oil production during the quarter averaged
approximately $8.99 per Bbl. Average realized prices for the second
quarter of 2016 are presented below.
Average Realized Prices |
|
Three Months Ended June 30, 2016 |
|
Before Derivatives |
|
After Derivatives |
Oil (per Bbl) |
38.21 |
|
|
41.51 |
|
Gas (per Mcf) |
1.48 |
|
|
1.48 |
|
NGL (per Bbl) |
11.53 |
|
|
11.53 |
|
Boe (Per Boe) |
25.78 |
|
|
27.62 |
|
|
|
|
|
|
|
LOE for the second quarter of 2016 was $10.7 million, or $5.08
per Boe, compared to $13.3 million, or $6.01 per Boe in the first
quarter of 2016, and $18.2 million, or $7.12 per Boe in the second
quarter of 2015. The Company continues to execute on cost saving
metrics resulting in a 19% sequential decrease and a 41% year over
year decrease in total LOE. Below is a breakout of the Company's
regional LOE and gas plant and midstream operating expense for the
second quarter of 2016.
Lease Operating Expense |
|
Three Months Ended June 30, 2016 |
|
Rocky Mountain |
|
Mid-Continent |
|
Total Company |
|
($M) |
|
($/Boe) |
|
($M) |
|
($/Boe) |
|
($M) |
|
($/Boe) |
LOE |
$ |
8,657 |
|
|
$ |
4.99 |
|
|
$ |
2,080 |
|
|
$ |
5.46 |
|
|
$ |
10,737 |
|
|
$ |
5.08 |
|
Gas plant and midstream
operating expense |
1,526 |
|
|
0.88 |
|
|
2,009 |
|
|
5.27 |
|
|
3,535 |
|
|
1.67 |
|
Total |
$ |
10,183 |
|
|
$ |
5.87 |
|
|
$ |
4,089 |
|
|
$ |
10.73 |
|
|
$ |
14,272 |
|
|
$ |
6.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative ("G&A") expense for the second
quarter of 2016 was $13.2 million, or $6.26 per Boe. This compares
to G&A expense of $21.6 million, or $8.47 per Boe in the second
quarter of 2015 and $17.7 million, or $7.99 per Boe in the first
quarter of 2016. On a sequential basis, total G&A expense has
decreased by 25% and has decreased by 39% from the second quarter
of 2015. Cash G&A expense, which excludes stock compensation,
for the second quarter of 2016 was $10.9 million, or $5.13 per Boe.
This compares to cash G&A expense, excluding severance charges,
of $12.5 million, or $5.66 per Boe in the first quarter of 2016.
The decrease in cash G&A is a result of the previously
announced reduction in force which occurred at the end of the first
quarter.
Depreciation, depletion and amortization ("DD&A") for second
quarter of 2016 was $30.9 million, or $14.62 per Boe, a 23%
sequential increase on a per unit basis from the first quarter of
2016 and a 47% decrease on a per unit basis from the second quarter
2015. The increase in total DD&A expense in the second quarter
is primarily due to the resumption of DD&A expense for the
Rocky Mountain Infrastructure ("RMI") assets, which were previously
classified as held for sale and not depreciated pursuant to GAAP.
Upon moving these assets back into Proved Properties on the balance
sheet, DD&A expense was calculated and recorded for the three
quarters during which the RMI assets were classified as held for
sale. The Company's Arkansas ("MidCon") assets were also moved out
of the held for sale classification. As the MidCon assets were
impaired to market value while they were classified as held for
sale, however, a DD&A catch-up is unnecessary for these
assets.
As of the end of the second quarter, year to date 2016 total
CAPEX was $17.5 million, of which $2.3 million was attributable to
RMI. A downward adjustment of $3.1 million in CAPEX was recorded in
the second quarter as a result of estimated costs which exceeded
actual costs.
Reported GAAP net loss for the second quarter of 2016 was $49.5
million, or $1.00 per diluted share, compared to a net loss of
$41.2 million, or $0.83 per diluted share, for the second quarter
of 2015. Adjusted net loss for the second quarter of 2016 was $19.7
million, or $0.40 per diluted share, compared to an adjusted net
loss of $6.9 million, or $0.14 per diluted share for the second
quarter of 2015, and an adjusted net loss of $22.4 million, or
$0.46 per diluted share for the first quarter of 2016. Adjusted
EBITDAX for the second quarter of 2016 was $27.7 million, a 63%
decrease compared to $74.0 million for the second quarter of 2015
and a 50% sequential increase from the first quarter of 2016.
Cash G&A, adjusted net income and adjusted EBITDAX are
non-GAAP financial measures. Please refer to the respective
reconciliations in the schedules at the end of this release for
additional information about these measures. Cash G&A is
defined as GAAP G&A expense excluding the stock compensation
portion of the expense. See Schedule 1 for general and
administrative break-out of stock-based compensation.
The table below summarizes the Company's quarterly and year to
date results as compared to guidance provided in the first quarter
earnings release. Updated twelve month guidance is included in the
Third Quarter Guidance and Update section of this release.
Guidance vs Actual Summary |
|
Three Months Ended June 30, 2016 |
|
Guidance |
|
Actual |
|
|
|
|
Production
(MBoe/d) |
22.7 –
23.3 |
|
23.2 |
|
|
|
|
|
|
Twelve Months EndedDecember 31, 2016 |
|
Six Months EndedJune 30,
2016 |
|
Guidance |
|
Actual |
LOE ($MM) |
$52 –
$56 |
|
$ |
24.0 |
|
Midstream ($MM) |
$15 –
$17 |
|
$ |
7.3 |
|
Cash G&A
($MM)* |
$40 –
$44 |
|
$ |
23.4 |
|
Production taxes (% of
pre-derivative realization) |
6% –
7% |
|
7.5 |
% |
CAPEX ($MM) |
$35 –
$45 |
|
$ |
17.5 |
|
|
|
|
|
* Cash
G&A guidance is a non-GAAP measure that is exclusive of the
Company's stock based compensation and one-time severance charges
of $2.2 million in the first quarter of 2016. 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. |
Operations Update
Rocky Mountain Region – Wattenberg
Production from the Rocky Mountain region during the second
quarter of 2016, averaged 19.1 MBoe/d, or 82% of total Company
volumes. The production was comprised of 56% crude oil, 20% NGLs,
and 24% natural gas. Rocky Mountain average daily sales volumes
decreased sequentially by 4% from the first quarter of 2016 and
decreased 16% compared to the second quarter of 2015 due to
suspended drilling and completion activity.
The Company did not drill or complete any wells during the
second quarter as it idled its development program at the end of
the first quarter. At the end of the second quarter, the Company
had six drilled uncompleted wells, consisting of four standard
reach and two extended reach laterals. The Company does not have
any current plans to restart drilling or completion activity in the
second half of 2016.
Mid-Continent Region – Cotton Valley
The Mid-Continent region contributed 4.2 MBoe/d, or 18% of total
Company net sales volumes for the second quarter of 2016, and was
comprised of 54% crude oil, 16% NGLs, and 30% natural gas. Sales
volumes decreased sequentially by 6% from the first quarter of 2016
and decreased 21% compared to the second 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 in May of 2016 to an approved borrowing base and
commitment amount of $200 million. As of June 30, 2016, the
Company had borrowings under its credit facility of $273.3 million
and cash totaling $170.2 million. Upon redetermination of the
Company's credit facility, its borrowings exceeded its borrowing
base by $88 million. The Company has elected to pay this deficiency
in six monthly installments as allowed under the terms of the
credit facility agreement. During the quarter the Company paid off
its remaining $12.0 million letter of credit and made its first
credit facility deficiency payment of $14.7 million. The Company
has subsequently paid its second deficiency payment of $14.7
million in July and has four remaining payments to be made on a
monthly basis to remedy its credit facility deficiency. The
Company's next redetermination is expected to happen in the fourth
quarter of 2016. As of June 30, 2016, the Company was in
compliance with all financial covenants under its credit facility,
with a senior secured debt to TTM EBITDAX ratio of 1.5x, an
interest coverage ratio of 3.2x, and a current ratio of 2.7x.
In addition to the credit facility, Bonanza Creek has two
outstanding issues of unsecured high-yield bonds which consist of
$500 million of 6.75% senior notes due in 2021 and $300 million of
5.75% senior notes due in 2023. The Company is subject to certain
covenants under the respective indentures governing the senior
notes that, among other things, limit its ability to incur
additional indebtedness. Specifically, the incurrence by the
Company (or any of the guarantors under the indentures) of
additional indebtedness and letters of credit under the revolving
credit facility in an aggregate principal amount at any one time
outstanding is not to exceed the greater of (a) $300.0 million or
(b) 35% of the Company's Adjusted Consolidated Net Tangible Assets
(“ACNTA”) determined as of the date of the incurrence of such
indebtedness. ACNTA is defined as the Company's PV-10 value plus
capitalized costs for unproved properties plus consolidated net
working capital and other tangible assets. At June 30, 2016,
35% of the Company’s ACNTA was equal to approximately $380
million.
While the Company currently has sufficient cash on hand to make
its upcoming bond interest payment, it has made the election to not
pay the interest payment for its $300 million 5.75% senior
unsecured notes, which was due on August 1, 2016. By not paying the
interest due, the Company has entered into a 30-day grace period
during which it retains the right to pay the interest due to the
holders of its 5.75% notes and thereby remain within compliance of
the bond indenture. The 30-day grace period also applies to any
potential cross-default under the Company's credit facility with
respect to the bond interest payment.
Asset Sale Processes - RMI and Mid-Continent
During the second quarter of 2016, the Company re-launched a
marketing effort to divest its RMI assets. The Company engaged a
third party advisor to assist in locating a purchaser for these
assets by performing a widely marketed process. While the Company
received economically strong bids for the assets, they all
contained significant conditions that required the Company to
remedy its debt burden and its limited access to capital. With
regard to the MidCon assets, the Company also performed a widely
marketed process to divest the assets with the assistance of a
third party advisor. Bids received for these assets also contained
significant going concern representations resulting from the
Company's liquidity constraints. Upon reviewing these bids, given
the significant conditions and, in the absence of improvement to
the Company's balance sheet, the unlikely sale for either package,
the Company's management and board have decided to suspend these
asset sale processes and focus efforts on alternative methods to
reduce debt and increase liquidity.
Please review the Company's quarterly report on Form 10-Q filed
with the Securities Exchange Commission on August 1, 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 June 30, 2016
and settling quarterly:
Settlement Period |
|
Volume (Bbls/d) |
|
Contract Type |
|
Swap Price |
3Q
2016 |
|
2,704 |
|
Fixed
Price Swap |
|
$ |
51.78 |
|
4Q
2016 |
|
2,303 |
|
Fixed
Price Swap |
|
$ |
52.83 |
|
|
|
|
|
|
|
|
Settlement Period |
|
Volume (Bbls/d) |
|
Contract Type |
|
Floor Price |
3Q
2016 |
|
4,733 |
|
Floor
(Long Put) |
|
$ |
51.01 |
|
4Q
2016 |
|
4,031 |
|
Floor
(Long Put) |
|
$ |
51.01 |
|
Third Quarter Guidance and Update
The Company is providing updated cost and CAPEX guidance for the
remainder of 2016 that reflects a lower cost structure that the
Company implemented during the first half of the year. As a result
of efficiency gains in its operations and service cost reductions,
the Company has reduced the midpoint of its full year guidance for
LOE and Midstream expense by 15% and 6%, respectively. The Company
attributes approximately 80% of the cost savings to efficiency
gains that it expects to be repeatable irrespective of service
costs. The Company has also reduced its full year CAPEX guidance
midpoint by 25% due to reductions in previous well costs estimates.
The table below provides updated guidance for the third quarter and
full year of 2016.
Guidance
Summary |
|
|
|
|
Three Months Ended September 30, 2016 |
|
Twelve Months Ended December 31, 2016 |
|
|
|
|
Production
(MBoe/d) |
19.6 –
20.2 |
|
19.7 –
21.7 |
LOE ($MM) |
|
|
$44 –
$48 |
Midstream expense
($MM) |
|
|
$14 –
$16 |
Cash G&A
($/Boe)* |
|
|
$40 –
$44 |
Production taxes (% of
pre-derivative realization) |
|
|
6% –
7% |
Total CAPEX |
|
|
$25 –
$35 |
* Cash
G&A guidance is a non-GAAP measure that is exclusive of the
Company's stock based compensation and one-time severance charges
of $2.2 million in the first quarter of 2016. 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. |
Conference Call InformationThe Company will not
be hosting a conference call to discuss its second 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 expectations; timing of future
redeterminations of the Company's borrowing base under its
revolving credit facility and anticipated efficiency gains. 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 June 30, |
|
Six Months Ended June 30, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Operating net
revenues: |
|
|
|
|
|
|
|
Oil and
gas sales |
$ |
54,530 |
|
|
$ |
90,422 |
|
|
$ |
98,704 |
|
|
$ |
163,498 |
|
Operating
expenses: |
|
|
|
|
|
|
|
Lease
operating expense |
10,737 |
|
|
18,169 |
|
|
24,035 |
|
|
35,142 |
|
Gas plant
and midstream operating expense |
3,535 |
|
|
2,726 |
|
|
7,324 |
|
|
5,017 |
|
Severance
and ad valorem taxes |
4,277 |
|
|
4,148 |
|
|
7,431 |
|
|
10,644 |
|
Exploration |
677 |
|
|
5,748 |
|
|
943 |
|
|
6,246 |
|
Depreciation, depletion and amortization |
30,927 |
|
|
69,925 |
|
|
57,306 |
|
|
128,929 |
|
Impairment of oil and gas properties |
— |
|
|
— |
|
|
10,000 |
|
|
— |
|
Abandonment and impairment of unproved properties |
9,875 |
|
|
14,527 |
|
|
16,781 |
|
|
19,996 |
|
General
and administrative (including $2,380, $4,359, $5,384 and $7,787,
respectively, of stock-based compensation) |
13,235 |
|
|
21,602 |
|
|
30,920 |
|
|
38,474 |
|
Total
operating expenses |
73,263 |
|
|
136,845 |
|
|
154,740 |
|
|
244,448 |
|
Loss from
operations |
(18,733 |
) |
|
(46,423 |
) |
|
(56,036 |
) |
|
(80,950 |
) |
Other income
(expense): |
|
|
|
|
|
|
|
Derivative gain (loss) |
(12,923 |
) |
|
(5,478 |
) |
|
(13,930 |
) |
|
13,378 |
|
Interest
expense |
(16,527 |
) |
|
(14,468 |
) |
|
(31,074 |
) |
|
(28,706 |
) |
Gain on
termination fee |
— |
|
|
— |
|
|
6,000 |
|
|
— |
|
Other
gain (loss) |
(1,294 |
) |
|
198 |
|
|
(1,674 |
) |
|
148 |
|
Total
other income (expense) |
(30,744 |
) |
|
(19,748 |
) |
|
(40,678 |
) |
|
(15,180 |
) |
Loss from operations
before taxes |
(49,477 |
) |
|
(66,171 |
) |
|
(96,714 |
) |
|
(96,130 |
) |
Income
tax benefit |
— |
|
|
25,007 |
|
|
— |
|
|
36,544 |
|
Net loss |
$ |
(49,477 |
) |
|
$ |
(41,164 |
) |
|
(96,714 |
) |
|
$ |
(59,586 |
) |
|
|
|
|
|
|
|
|
Basic net loss per
common share |
$ |
(1.00 |
) |
|
$ |
(0.83 |
) |
|
$ |
(1.97 |
) |
|
$ |
(1.25 |
) |
|
|
|
|
|
|
|
|
Diluted net loss per
common share |
$ |
(1.00 |
) |
|
$ |
(0.83 |
) |
|
$ |
(1.97 |
) |
|
$ |
(1.25 |
) |
|
|
|
|
|
|
|
|
Basic weighted-average
common shares outstanding |
49,277 |
|
|
48,923 |
|
|
49,204 |
|
|
46,734 |
|
|
|
|
|
|
|
|
|
Diluted
weighted-average common shares outstanding |
49,277 |
|
|
48,923 |
|
|
49,204 |
|
|
46,734 |
|
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 June 30, |
|
Six Months Ended June 30, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Cash flows from
operating activities: |
|
|
|
|
|
|
|
Net
loss |
$ |
(49,477 |
) |
|
$ |
(41,164 |
) |
|
$ |
(96,714 |
) |
|
$ |
(59,586 |
) |
Adjustments to reconcile net loss to net cash provided by operating
activities: |
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
30,927 |
|
|
69,925 |
|
|
57,306 |
|
|
128,929 |
|
Deferred
income tax benefit |
— |
|
|
(25,007 |
) |
|
— |
|
|
(36,544 |
) |
Impairment of oil and gas properties |
— |
|
|
— |
|
|
10,000 |
|
|
— |
|
Abandonment and impairment of unproved properties |
9,875 |
|
|
14,527 |
|
|
16,781 |
|
|
19,996 |
|
Dry hole
expense |
734 |
|
|
5,680 |
|
|
966 |
|
|
5,680 |
|
Stock-based compensation |
2,380 |
|
|
4,359 |
|
|
5,384 |
|
|
7,787 |
|
Amortization of deferred financing costs and debt premium |
1,671 |
|
|
703 |
|
|
2,279 |
|
|
1,226 |
|
Accretion
of contractual obligation for land acquisition |
— |
|
|
349 |
|
|
— |
|
|
698 |
|
Derivative (gain) loss |
12,923 |
|
|
5,478 |
|
|
13,930 |
|
|
(13,378 |
) |
Derivative cash settlements |
3,893 |
|
|
15,189 |
|
|
11,401 |
|
|
50,655 |
|
Other |
4 |
|
|
(16 |
) |
|
(112 |
) |
|
(43 |
) |
Changes
in current assets and liabilities: |
|
|
|
|
|
|
|
Accounts
receivable |
371 |
|
|
2,021 |
|
|
23,415 |
|
|
18,319 |
|
Prepaid
expenses and other assets |
274 |
|
|
525 |
|
|
(1,348 |
) |
|
(1,348 |
) |
Accounts
payable and accrued liabilities |
(25,316 |
) |
|
(21,073 |
) |
|
(28,457 |
) |
|
(23,054 |
) |
Settlement of asset retirement obligations |
(34 |
) |
|
(234 |
) |
|
(75 |
) |
|
(519 |
) |
Net cash
provided by (used in) operating activities |
(11,775 |
) |
|
31,262 |
|
|
14,756 |
|
|
98,818 |
|
Cash flows from
investing activities: |
|
|
|
|
|
|
|
Acquisition of oil and gas properties |
(284 |
) |
|
(532 |
) |
|
(816 |
) |
|
(11,914 |
) |
Payments
of contractual obligation |
(12,000 |
) |
|
— |
|
|
(12,000 |
) |
|
— |
|
Exploration and development of oil and gas properties |
(7,881 |
) |
|
(128,694 |
) |
|
(42,753 |
) |
|
(283,106 |
) |
Increase
in restricted cash |
(2 |
) |
|
— |
|
|
(2,535 |
) |
|
— |
|
Additions
to property and equipment - non oil and gas |
(8 |
) |
|
841 |
|
|
39 |
|
|
(649 |
) |
Net cash
used in investing activities |
(20,175 |
) |
|
(128,385 |
) |
|
(58,065 |
) |
|
(295,669 |
) |
Cash flows from
financing activities: |
|
|
|
|
|
|
|
Proceeds
from credit facility |
— |
|
|
43,000 |
|
|
209,000 |
|
|
87,000 |
|
Payments
to credit facility |
(14,667 |
) |
|
— |
|
|
(14,667 |
) |
|
(77,000 |
) |
Proceeds
from sale of common stock |
— |
|
|
— |
|
|
— |
|
|
209,300 |
|
Offering
costs related to sale of common stock |
— |
|
|
(115 |
) |
|
— |
|
|
(6,607 |
) |
Offering
costs related to sale of Senior Notes |
— |
|
|
(74 |
) |
|
— |
|
|
(93 |
) |
Payment
of employee tax withholdings in exchange for the return of common
stock |
(44 |
) |
|
(321 |
) |
|
(273 |
) |
|
(2,448 |
) |
Deferred
restructuring charges |
(1,684 |
) |
|
— |
|
|
(1,684 |
) |
|
— |
|
Deferred
financing costs |
(83 |
) |
|
(541 |
) |
|
(237 |
) |
|
(545 |
) |
Net cash
provided by (used in) financing activities |
(16,478 |
) |
|
41,949 |
|
|
192,139 |
|
|
209,607 |
|
Net change in cash and
cash equivalents |
(48,428 |
) |
|
(55,174 |
) |
|
148,830 |
|
|
12,756 |
|
Cash and cash
equivalents: |
|
|
|
|
|
|
|
Beginning
of period |
218,599 |
|
|
70,514 |
|
|
21,341 |
|
|
2,584 |
|
End of
period |
$ |
170,171 |
|
|
$ |
15,340 |
|
|
$ |
170,171 |
|
|
$ |
15,340 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Schedule 3: Condensed Balance
Sheet |
(in thousands, unaudited) |
|
|
|
|
|
June 30, |
|
December
31, |
|
2016 |
|
2015 |
ASSETS |
|
|
|
Current assets |
$ |
221,685 |
|
|
$ |
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 |
1,071,501 |
|
|
922,344 |
|
Other noncurrent
assets |
4,980 |
|
|
2,301 |
|
Total
Assets |
$ |
1,298,166 |
|
|
$ |
1,259,641 |
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS’ EQUITY |
|
|
|
Current
liabilities |
$ |
1,147,269 |
|
|
$ |
135,973 |
|
Long-term debt |
— |
|
|
871,666 |
|
Other long-term
liabilities |
33,093 |
|
|
42,595 |
|
Total
Liabilities |
1,180,362 |
|
|
1,050,234 |
|
|
|
|
|
Stockholders’
Equity |
117,804 |
|
|
209,407 |
|
Total
Liabilities and Stockholders’ Equity |
$ |
1,298,166 |
|
|
$ |
1,259,641 |
|
|
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, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Wellhead
Volumes and Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and
Condensate Sales Volumes (Bbl/d) |
|
|
|
|
|
|
|
Rocky Mountains |
10,715 |
|
|
14,079 |
|
|
11,190 |
|
|
13,877 |
|
Mid-Continent |
2,270 |
|
|
2,768 |
|
|
2,353 |
|
|
2,827 |
|
Total |
12,985 |
|
|
16,847 |
|
|
13,543 |
|
|
16,704 |
|
|
|
|
|
|
|
|
|
Crude Oil and
Condensate Realized Prices ($/Bbl) |
|
|
|
|
|
|
|
Rocky Mountains |
$ |
36.74 |
|
|
$ |
48.72 |
|
|
$ |
30.70 |
|
|
$ |
43.60 |
|
Mid-Continent |
$ |
45.18 |
|
|
$ |
55.93 |
|
|
$ |
40.41 |
|
|
$ |
51.60 |
|
Composite (before
derivatives) |
$ |
38.21 |
|
|
$ |
49.90 |
|
|
$ |
32.39 |
|
|
$ |
44.96 |
|
Composite (after
derivatives) |
$ |
41.51 |
|
|
$ |
59.37 |
|
|
$ |
37.01 |
|
|
$ |
61.26 |
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids Sales Volumes (Bbl/d) |
|
|
|
|
|
|
|
Rocky Mountains |
3,772 |
|
|
3,696 |
|
|
3,594 |
|
|
3,579 |
|
Mid-Continent |
675 |
|
|
1,020 |
|
|
697 |
|
|
1,007 |
|
Total |
4,447 |
|
|
4,716 |
|
|
4,291 |
|
|
4,586 |
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids Realized Prices ($/Bbl) |
|
|
|
|
|
|
|
Rocky Mountains |
$ |
10.59 |
|
|
$ |
16.21 |
|
|
$ |
11.80 |
|
|
$ |
14.99 |
|
Mid-Continent |
$ |
16.75 |
|
|
$ |
16.56 |
|
|
$ |
14.48 |
|
|
$ |
16.16 |
|
Composite (before
derivatives) |
$ |
11.53 |
|
|
$ |
16.28 |
|
|
$ |
12.23 |
|
|
$ |
15.25 |
|
Composite (after
derivatives) |
$ |
11.53 |
|
|
$ |
16.28 |
|
|
$ |
12.23 |
|
|
$ |
15.25 |
|
|
|
|
|
|
|
|
|
Natural Gas
Sales Volumes (Mcf/d) |
|
|
|
|
|
|
|
Rocky Mountains |
27,450 |
|
|
29,782 |
|
|
28,044 |
|
|
29,299 |
|
Mid-Continent |
7,444 |
|
|
9,075 |
|
|
7,648 |
|
|
9,612 |
|
Total |
34,894 |
|
|
38,857 |
|
|
35,692 |
|
|
38,911 |
|
|
|
|
|
|
|
|
|
Natural Gas
Realized Prices ($/Mcf) |
|
|
|
|
|
|
|
Rocky Mountains |
$ |
1.34 |
|
|
$ |
1.65 |
|
|
$ |
1.27 |
|
|
$ |
1.80 |
|
Mid-Continent |
$ |
2.01 |
|
|
$ |
2.99 |
|
|
$ |
2.05 |
|
|
$ |
3.10 |
|
Composite (before
derivatives) |
$ |
1.48 |
|
|
$ |
1.96 |
|
|
$ |
1.44 |
|
|
$ |
2.12 |
|
Composite (after
derivatives) |
$ |
1.48 |
|
|
$ |
2.15 |
|
|
$ |
1.44 |
|
|
$ |
2.31 |
|
|
|
|
|
|
|
|
|
Crude Oil
Equivalent Sales Volumes (Boe/d) |
|
|
|
|
|
|
|
Rocky Mountains |
19,062 |
|
|
22,739 |
|
|
19,458 |
|
|
22,339 |
|
Mid-Continent |
4,186 |
|
|
5,300 |
|
|
4,325 |
|
|
5,436 |
|
Total |
23,248 |
|
|
28,039 |
|
|
23,783 |
|
|
27,775 |
|
|
|
|
|
|
|
|
|
Crude Oil
Equivalent Sales Prices ($/Boe) |
|
|
|
|
|
|
|
Rocky Mountains |
$ |
24.68 |
|
|
$ |
34.96 |
|
|
$ |
21.66 |
|
|
$ |
31.84 |
|
Mid-Continent |
$ |
30.78 |
|
|
$ |
37.50 |
|
|
$ |
27.94 |
|
|
$ |
35.32 |
|
Composite (before
derivatives) |
$ |
25.78 |
|
|
$ |
35.44 |
|
|
$ |
22.80 |
|
|
$ |
32.52 |
|
Composite (after
derivatives) |
$ |
27.62 |
|
|
$ |
41.39 |
|
|
$ |
25.44 |
|
|
$ |
42.60 |
|
|
|
|
|
|
|
|
|
Total Sales
Volumes (MBoe) |
2,115.5 |
|
|
2,551.5 |
|
|
4,328.7 |
|
|
5,027.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Schedule 5: Per unit operating
margins |
(unaudited) |
|
|
|
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
|
2016 |
|
|
|
2015 |
|
|
Percent Change |
|
|
2016 |
|
|
2015 |
|
Percent Change |
Production |
|
|
|
|
|
|
|
|
|
|
|
Oil
(MBbl) |
1,181.7 |
|
|
1,533.0 |
|
|
(23 |
)% |
|
2,465.0 |
|
|
3,023.5 |
|
|
(18 |
)% |
Gas
(MMcf) |
3,175.3 |
|
|
3,535.9 |
|
|
(10 |
)% |
|
6,496.0 |
|
|
7,042.8 |
|
|
(8 |
)% |
NGL
(MBbl) |
404.7 |
|
|
429.2 |
|
|
(6 |
)% |
|
781.0 |
|
|
830.0 |
|
|
(6 |
)% |
Equivalent (MBoe) |
2,115.5 |
|
|
2,551.5 |
|
|
(17 |
)% |
|
4,328.7 |
|
|
5,027.3 |
|
|
(14 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
Realized pricing (before derivatives) |
|
|
|
|
|
|
|
|
|
|
Oil
($/Bbl) |
$ |
38.21 |
|
|
$ |
49.90 |
|
|
(23 |
)% |
|
$ |
32.38 |
|
|
$ |
44.96 |
|
|
(28 |
)% |
Gas
($/Mcf) |
$ |
1.48 |
|
|
$ |
1.96 |
|
|
(24 |
)% |
|
1.44 |
|
|
2.12 |
|
|
(32 |
)% |
NGL
($/Bbl) |
$ |
11.53 |
|
|
$ |
16.28 |
|
|
(29 |
)% |
|
12.23 |
|
|
15.25 |
|
|
(20 |
)% |
Equivalent ($/Boe) |
$ |
25.78 |
|
|
$ |
35.44 |
|
|
(27 |
)% |
|
$ |
22.80 |
|
|
$ |
32.52 |
|
|
(30 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
Per Unit Costs
($/Boe) |
|
|
|
|
|
|
|
|
|
|
|
Realized
price (before derivatives) |
$ |
25.78 |
|
|
$ |
35.44 |
|
|
(27 |
)% |
|
$ |
22.80 |
|
|
32.52 |
|
|
(30 |
)% |
LOE |
5.08 |
|
|
7.12 |
|
|
(29 |
)% |
|
$ |
5.55 |
|
|
$ |
6.99 |
|
|
(21 |
)% |
Gas plant
and midstream operating expense |
1.67 |
|
|
1.07 |
|
|
56 |
% |
|
$ |
1.69 |
|
|
$ |
1.00 |
|
|
69 |
% |
Severance
and Ad Valorem |
2.02 |
|
|
1.63 |
|
|
24 |
% |
|
$ |
1.72 |
|
|
$ |
2.12 |
|
|
(19 |
)% |
Cash
General and Administrative |
|
5.13 |
|
|
|
6.76 |
|
|
(24 |
)% |
|
$ |
5.90 |
|
|
$ |
6.10 |
|
|
(3 |
)% |
Total
cash operating costs |
$ |
13.90 |
|
|
$ |
16.58 |
|
|
(16 |
)% |
|
$ |
14.86 |
|
|
$ |
16.21 |
|
|
(8 |
)% |
Cash
operating margin (before derivatives) |
$ |
11.88 |
|
|
$ |
18.86 |
|
|
(37 |
)% |
|
$ |
7.94 |
|
|
$ |
16.31 |
|
|
(51 |
)% |
Derivative Cash Settlements |
1.84 |
|
|
5.95 |
|
|
(69 |
)% |
|
$ |
2.64 |
|
|
10.08 |
|
|
(74 |
)% |
Cash
operating margin (after derivatives) |
$ |
13.72 |
|
|
$ |
24.81 |
|
|
(45 |
)% |
|
$ |
10.58 |
|
|
26.39 |
|
|
(60 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash
items |
|
|
|
|
|
|
|
|
|
|
|
Depreciation Depletion and Amortization |
14.62 |
|
|
27.41 |
|
|
(47 |
)% |
|
$ |
13.24 |
|
|
$ |
25.65 |
|
|
(48 |
)% |
Non-cash
General and Administrative |
$ |
1.13 |
|
|
$ |
1.71 |
|
|
(34 |
)% |
|
$ |
1.24 |
|
|
$ |
1.55 |
|
|
(20 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
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 June 30, |
|
Six Months Ended June 30, |
|
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Net
loss |
|
$ |
(49,477 |
) |
|
$ |
(41,164 |
) |
|
$ |
(96,714 |
) |
|
$ |
(59,586 |
) |
Adjustments to net
loss: |
|
|
|
|
|
|
|
|
Derivative (gain)
loss |
|
12,923 |
|
|
5,478 |
|
|
13,930 |
|
|
(13,378 |
) |
Derivative cash
settlements |
|
3,893 |
|
|
15,189 |
|
|
11,401 |
|
|
50,655 |
|
Impairment of proved
properties |
|
— |
|
|
— |
|
|
10,000 |
|
|
— |
|
Abandonment and
impairment of unproved properties |
|
9,875 |
|
|
14,527 |
|
|
16,781 |
|
|
19,996 |
|
Exploratory dry
hole |
|
734 |
|
|
5,680 |
|
|
966 |
|
|
5,680 |
|
Stock-based
compensation |
|
2,380 |
|
|
4,359 |
|
|
5,384 |
|
|
7,787 |
|
Cash severance costs
(1) |
|
— |
|
|
— |
|
|
2,162 |
|
|
— |
|
Gain on termination fee
(2) |
|
— |
|
|
— |
|
|
(6,000 |
) |
|
— |
|
Derivative Conversion
Payment (3) |
|
— |
|
|
10,472 |
|
|
— |
|
|
10,472 |
|
Total adjustments
before taxes |
|
29,805 |
|
|
55,705 |
|
|
54,624 |
|
|
81,212 |
|
Income tax effect |
|
— |
% |
|
38.5 |
% |
|
— |
% |
|
38.5 |
% |
Total adjustments after
taxes |
|
$ |
29,805 |
|
|
$ |
34,259 |
|
|
$ |
54,624 |
|
|
$ |
49,945 |
|
|
|
|
|
|
|
|
|
|
Adjusted net
loss |
|
$ |
(19,672 |
) |
|
$ |
(6,905 |
) |
|
$ |
(42,090 |
) |
|
$ |
(9,641 |
) |
Adjusted net
loss per diluted share |
|
$ |
(0.40 |
) |
|
$ |
(0.14 |
) |
|
$ |
(0.86 |
) |
|
$ |
(0.21 |
) |
|
|
|
|
|
|
|
|
|
Diluted
weighted-average common shares outstanding |
|
49,277 |
|
|
48,923 |
|
|
49,204 |
|
|
46,734 |
|
|
|
|
|
|
|
|
|
|
(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. |
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 June 30, |
|
Six Months Ended June 30, |
|
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Net
loss |
|
$ |
(49,477 |
) |
|
$ |
(41,164 |
) |
|
$ |
(96,714 |
) |
|
$ |
(59,586 |
) |
Exploration |
|
677 |
|
|
5,748 |
|
|
943 |
|
|
6,246 |
|
Depreciation, depletion and amortization |
|
30,927 |
|
|
69,925 |
|
|
57,306 |
|
|
128,929 |
|
Impairment of proved properties |
|
— |
|
|
— |
|
|
10,000 |
|
|
— |
|
Abandonment and impairment of unproved properties |
|
9,875 |
|
|
14,527 |
|
|
16,781 |
|
|
19,996 |
|
Stock-based compensation |
|
2,380 |
|
|
4,359 |
|
|
5,384 |
|
|
7,787 |
|
Cash
severance costs (1) |
|
— |
|
|
— |
|
|
2,162 |
|
|
— |
|
Gain on
termination fee (2) |
|
— |
|
|
— |
|
|
(6,000 |
) |
|
— |
|
Derivative conversion payment (3) |
|
— |
|
|
10,472 |
|
|
— |
|
|
10,472 |
|
Interest
expense |
|
16,527 |
|
|
14,468 |
|
|
31,074 |
|
|
28,706 |
|
Derivative (gain) loss |
|
12,923 |
|
|
5,478 |
|
|
13,930 |
|
|
(13,378 |
) |
Derivative cash settlements |
|
3,893 |
|
|
15,189 |
|
|
11,401 |
|
|
50,655 |
|
Income
tax benefit |
|
— |
|
|
(25,007 |
) |
|
— |
|
|
(36,544 |
) |
Adjusted
EBITDAX |
|
$ |
27,725 |
|
|
$ |
73,995 |
|
|
$ |
46,267 |
|
|
$ |
143,283 |
|
|
|
|
|
|
|
|
|
|
(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. |
For further information, please contact:
James R. Edwards
Director - Investor Relations
720-440-6136
jedwards@bonanzacrk.com
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