Bonanza Creek Energy, Inc. (NYSE:BCEI) (the "Company") today
announces its fourth quarter and full year 2016 financial and
operating results.
Fourth Quarter 2016 Results
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Three Months Ended |
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Twelve Months Ended |
Avg. Daily
Sales Volumes: |
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12/31/2016 |
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9/30/2016 |
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% Change |
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12/31/2016 |
|
12/31/2015 |
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% Change |
Crude oil
(Bbls/d) |
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9,058 |
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10,997 |
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(18)% |
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11,776 |
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16,636 |
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(29)% |
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Natural
gas (Mcf/d) |
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29,664 |
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32,677 |
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(9)% |
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33,419 |
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39,866 |
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(16)% |
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Natural
gas liquids (Bbls/d) |
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4,237 |
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4,523 |
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(6)% |
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4,336 |
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4,992 |
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(13)% |
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Crude oil
equivalent (Boe/d) |
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18,239 |
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20,966 |
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(13)% |
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21,682 |
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28,272 |
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(23)% |
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Product
Mix |
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Crude oil |
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50% |
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52% |
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54% |
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59% |
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Natural gas |
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27% |
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26% |
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26% |
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23% |
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Natural gas
liquids |
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23% |
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22% |
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20% |
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18% |
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Average Sales
Prices (before derivatives): |
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Crude oil (per
Bbl) |
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$ |
41.96 |
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$ |
37.45 |
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12% |
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|
35.42 |
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|
40.98 |
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(14)% |
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Natural gas (per
Mcf) |
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$ |
2.45 |
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$ |
2.31 |
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6% |
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|
|
1.88 |
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|
|
1.82 |
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3% |
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Natural gas liquids
(per Bbl) |
|
$ |
14.40 |
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$ |
10.80 |
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33% |
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12.39 |
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9.49 |
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31% |
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Crude oil equivalent
(per Boe) |
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$ |
28.17 |
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$ |
25.57 |
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10% |
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24.61 |
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28.36 |
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(13)% |
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Product Revenue (in
thousands) |
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$ |
47,266 |
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$ |
49,325 |
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(4)% |
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$ |
195,295 |
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$ |
292,679 |
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(33)% |
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For the fourth quarter of 2016, the Company reported reduced
production volumes on a sequential and annual basis due to
inactivity. At the end of the first quarter of 2016, the Company
released its last drilling rig and suspended drilling and
completion operations. Since the beginning of the second quarter,
the Company has focused efforts on maximizing production from PDP
wells, meeting or beating the midpoint of its production guidance
range in each quarter of 2016. Realized pricing before the effects
of derivative activity was stronger in the fourth quarter of 2016
compared to the previous quarter resulting in a moderated decrease
to top line revenue on a sequential basis. For the full year of
2016, the Company reported reduced revenues due to both decreased
production volumes as well as weaker realized pricing when compared
to the 2015 fiscal year.
Given the lack of drilling and completion activity during the
year, a key focus of the Company was to materially reduce operating
expenses while retaining its commitment to safety and the
environment. The table below provides operating expenses
comparatively on a sequential quarterly basis and annual
year-over-year basis.
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Three Months Ended |
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Twelve Months Ended |
Operating
Expenses |
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12/31/2016 |
|
9/30/2016 |
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% Change |
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12/31/2016 |
|
12/31/2015 |
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% Change |
Lease
operating expense |
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9,743 |
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9,893 |
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(2)% |
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43,671 |
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65,038 |
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(33)% |
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Gas plant
and midstream operating expense |
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2,628 |
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2,874 |
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(9)% |
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12,826 |
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11,368 |
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13% |
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Severance
and ad valorem taxes |
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3,773 |
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4,100 |
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(8)% |
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15,304 |
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18,629 |
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(18)% |
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Exploration |
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3 |
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— |
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NM |
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|
946 |
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15,827 |
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(94)% |
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Depreciation, depletion and amortization |
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26,613 |
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27,296 |
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(3)% |
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111,215 |
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244,921 |
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(55)% |
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Impairment of oil and gas properties |
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— |
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— |
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—% |
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10,000 |
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740,478 |
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(99)% |
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Abandonment and impairment of unproved properties |
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229 |
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7,682 |
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(97)% |
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24,692 |
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33,543 |
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(26)% |
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Unused
commitments |
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4,226 |
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1,688 |
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NM |
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7,686 |
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— |
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NM |
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Contract
settlement expense |
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21,000 |
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— |
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NM |
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21,000 |
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— |
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NM |
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Recurring
Cash G&A (1) |
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11,374 |
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|
10,890 |
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4% |
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45,636 |
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54,612 |
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(16)% |
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Stock
Compensation |
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1,643 |
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1,863 |
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(12)% |
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8,892 |
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14,552 |
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(39)% |
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Cash
severance costs |
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— |
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— |
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—% |
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2,162 |
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1,155 |
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87% |
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Advisor
fees related to financial alternatives |
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14,457 |
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5,918 |
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144% |
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20,375 |
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— |
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NM |
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Total
General and Administrative |
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27,474 |
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|
18,671 |
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47% |
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|
77,065 |
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|
70,319 |
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10% |
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Total Operating
Expenses |
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95,689 |
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|
72,204 |
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33% |
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324,405 |
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1,200,123 |
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(73)% |
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Adjusted cash operating
expense (2) |
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27,518 |
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27,757 |
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(1)% |
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117,437 |
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149,647 |
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(22)% |
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(1)
Recurring cash G&A is a non-GAAP measure that is exclusive of
the Company's stock based compensation, one-time severance charges
and advisor fees. See schedule 10 for reconciliation to GAAP
G&A. |
(2)
Adjusted cash operating expense is a non-GAAP measure and includes
recurring cash costs associated with producing hydrocarbons and
includes lease operating expense, midstream operating expense,
severance and ad valorem taxes, and recurring cash G&A.
This measure excludes non-cash items and items which are considered
one-time in nature. The Company provides this metric as it believes
it provides comparable cash operating costs between periods. |
Throughout 2016, the Company implemented cost-saving measures
that resulted in a material reduction in adjusted cash operating
expense. The reduction was led by decreases in LOE and recurring
cash G&A. The decrease in DD&A in 2016 is due to the lower
depreciable asset base resulting from the large property impairment
in 2015. Notable increases in expenses in 2016 were severance and
advisory expense, unused commitments, contract settlement, and
midstream operating expense. The severance and advisory expenses
incurred in 2016 relate to reduction-in-force payments made to
employees in the first quarter of 2016, and the advisory fees
relate to efforts to explore financial alternatives and
restructuring options. Unused commitments relate to pipeline volume
deficiencies the Company incurred during the year. Increases to
midstream operating expense year over year are due to the build-out
of the RMI asset during 2015, which made up 43% of the total
midstream operating expense in the fourth quarter of 2016. A
breakout of the LOE and midstream operating expense by region is
included in the table below.
Regional Breakout |
|
Three Months Ended December 31,
2016 |
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Rocky Mountain |
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Mid-Continent |
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Total Company |
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($M) |
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($/Boe) |
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($M) |
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($/Boe) |
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($M) |
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($/Boe) |
LOE |
$ |
6,696 |
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$ |
4.99 |
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$ |
3,047 |
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$ |
9.04 |
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$ |
9,743 |
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$ |
5.81 |
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Gas plant and midstream
operating expense |
1,127 |
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|
0.84 |
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|
1,501 |
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|
4.45 |
|
|
2,628 |
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|
1.57 |
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Total |
$ |
7,823 |
|
|
$ |
5.83 |
|
|
$ |
4,548 |
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|
$ |
13.49 |
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$ |
12,371 |
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$ |
7.38 |
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Reported net loss for the fourth quarter of 2016 was $67.3
million, or $1.37 per diluted share, compared to a net loss of
$573.7 million, or $12.08 per diluted share, for the fourth quarter
of 2015. The quarterly GAAP net loss for 2015 was driven largely by
total property impairments of $585.6 million. Adjusted net
loss for the fourth quarter of 2016 was $27.9 million, or $0.57 per
diluted share, compared to adjusted net loss of $8.4 million, or
$0.17 per diluted share for the fourth quarter of 2015.
Adjusted EBITDAX for the fourth quarter of 2016 was $14.5
million, a 78% decrease compared to $67.1 million for the fourth
quarter of 2015.
Adjusted net loss and adjusted EBITDAX are non-GAAP financial
measures. Please refer to the respective reconciliations in the
schedules at the end of this release for additional information
about these measures.
The table below summarizes the Company's quarterly and annual
results as compared to previously provided guidance.
Guidance vs
Actual Summary |
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Three Months Ended December 31,
2016 |
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Guidance |
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Actual |
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Production (MBoe/d) |
17.7 –
18.3 |
|
18.2 |
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Twelve Months Ended December 31,
2016 |
|
Guidance |
|
Actual |
Production (MBoe/d) |
21.5 –
21.7 |
|
21.7 |
|
LOE
($MM) |
$43 –
$46 |
|
$ |
43.7 |
|
Midstream
($MM) |
$12 –
$14 |
|
$ |
12.8 |
|
Recurring
cash G&A ($MM)* |
$44 –
$46 |
|
$ |
45.6 |
|
Production taxes (% of pre-derivative realization) |
6% –
7% |
|
7.8% |
|
CAPEX
($MM) |
$25 –
$27 |
|
$ |
21.7 |
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* 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 $20.4 million. The Company does not guide to GAAP
G&A expense because of the uncertain nature of the amount of
stock based compensation expense in a given period and the
non-recurring portions of GAAP G&A. See schedule 10 for
reconciliation to GAAP G&A. |
2016 Proved Reserves
As of year-end 2016, Bonanza Creek reported proved reserves of
90.7 MMBoe, which represents a decrease of 10% from 2015. The
Company's year-end 2016 proved reserves were comprised of 50.1
MMBbls of oil, 17.5 MMBbls of NGLs, and 138.0 Bcf of natural gas
and were 56% proved developed. The Company recorded a 40% decline
in its year-end 2016 Mid-Continent proved reserves from 2015 as a
result of writing off all remaining proved undeveloped reserves in
the region. These proved undeveloped reserves were removed as the
Company's drilling plans did not contemplate the development of
these proved undeveloped locations within the required five-year
period. The PV-10 value for estimated proved reserves as of
December 31, 2016 was $276.9 million. PV-10 is a non-GAAP measure
and is derived from the Standardized Measure, which is the most
directly comparable GAAP financial measure. A reconciliation of
PV-10 to its most comparable GAAP financial measure is provided in
Schedule 9 of this release. The 12-month average benchmark pricing
used to estimate SEC proved reserves for crude oil and natural gas
was $42.75 per Bbl of WTI crude oil and $2.48 per MMBtu of natural
gas at Henry Hub before differential adjustments. Year-end 2016
benchmark prices for oil, and natural gas were 15%, and 4% lower,
respectively, from year-end 2015 SEC pricing. After differential
adjustments, the Company's SEC pricing realizations for year-end
2016 were $38.42 per Bbl of oil, $12.12 per Bbl of NGLs, and $2.07
per Mcf of natural gas. As of year-end 2016, the Company estimates
that its exit-to-exit corporate PDP decline rate will be 25% in
2017, 20% in 2018, and 16% in 2019. The table below summarizes
estimated proved reserves for 2016.
Proved
Reserves |
|
As of December 31, 2015 |
|
As of December 31, 2016 |
Reserve Category |
|
Equiv. (MMBoe) |
% of Total |
|
Oil (MMBbls) |
NGLs (MMBbls) |
Gas (Bcf) |
Equiv. (MMBoe) |
% of Total |
YoY Change |
Proved Developed
Producing |
|
49.7 |
|
49% |
|
|
25.3 |
|
9.8 |
|
83.6 |
|
49.0 |
|
54% |
|
(1)% |
|
Proved Developed
Non-Producing |
|
2.4 |
|
2% |
|
|
1.0 |
|
0.2 |
|
2.3 |
|
1.6 |
|
2% |
|
(33)% |
|
Proved Undeveloped |
|
49.2 |
|
49% |
|
|
23.8 |
|
7.6 |
|
52.1 |
|
40.1 |
|
44% |
|
(18)% |
|
Total Proved Reserves |
|
101.3 |
|
100% |
|
|
50.1 |
|
17.5 |
|
138.0 |
|
90.7 |
|
100% |
|
(10)% |
|
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Regional
Summary |
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|
|
|
|
|
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|
Rocky Mountain |
|
80.1 |
|
79% |
|
|
42.5 |
|
16.4 |
|
114.2 |
|
78.0 |
|
86% |
|
(3)% |
|
Mid-Continent |
|
21.2 |
|
21% |
|
|
7.6 |
|
1.2 |
|
23.9 |
|
12.7 |
|
14% |
|
(40)% |
|
Total Proved Reserves |
|
101.3 |
|
100% |
|
|
50.1 |
|
17.5 |
|
138.0 |
|
90.7 |
|
100% |
|
(10)% |
|
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Note: Totals may not foot due to rounding
Restructuring Update and 2017 Outlook
The Company continues to pursue a restructuring under the terms
set forth in the Restructuring Support and Lock-Up Agreement
("RSA"), filed with the SEC on December 23, 2016. Since filing
voluntary petitions under chapter 11 of the United Sates Code in
the United States Bankruptcy Court for the District of Delaware, on
January 4, 2017, the Company has been granted all of its first day
motions which include, among others things the ability to conduct
its normal business activities, pay its trade vendors, royalty
interest owners, and partners. The Company is scheduled to have a
confirmation hearing on the proposed Plan of Reorganization and the
associated Disclosure Statement on April 3, 2017 and expects to
emerge from Chapter 11 during the first half of 2017.
Certain holders of the Company’s common shares have formed an ad
hoc committee of equity security holders (the “Ad Hoc Equity
Committee”) and have filed motions and other pleadings in the
Chapter 11 cases adverse to the restructuring contemplated by the
RSA. In particular, on February 3, 2017, the Ad Hoc Equity
Committee filed a motion (the “Trustee Motion”) for an order
appointing a trustee pursuant to section 1104(a) of the Bankruptcy
Code or, in the alternative, appointing an examiner pursuant to
section 1104(c) of the Bankruptcy Code. If the Trustee Motion
were granted with respect to the Ad Hoc Equity Committee’s request
for the appointment of a trustee, then the Company and its
subsidiaries would cease to be debtors in possession and the
affairs and management of the business would be controlled by a
court-appointed trustee.
Upon emergence from bankruptcy, the Company expects to resume
drilling and completion activity. The activity program that was
presented to the signatories of the RSA contemplates a one-rig
program, with an intermittent second rig to satisfy leasehold
obligations. The capital requirements expected for the proposed
program would range from $160 – $180 million for the time period
from May to December 2017. This program assumes drilling 61 and
completing 53 net standard reach lateral equivalent ("SRLe") wells
in its Wattenberg program, investing a modest amount on
infrastructure, participating in economic non-operated wells, and
investing $3 – $5 million in Mid-Continent recompletions. The
Company expects approximately 65% of its 53 SRLe completions to be
XRLs. The proposed capital budget is dependent on emergence from
bankruptcy and approval from a newly appointed board.
About Bonanza Creek Energy, Inc.
Bonanza Creek Energy, Inc. is an independent oil and natural gas
company engaged in the acquisition, exploration, development and
production of onshore oil and associated liquids-rich natural gas
in the United States. The Company’s assets and operations are
concentrated primarily in the Rocky Mountains in the Wattenberg
Field, focused on the Niobrara and Codell formations, and in
southern Arkansas, focused on oily Cotton Valley sands. The
Company’s common shares are listed for trading on the NYSE under
the symbol: “BCEI.” For more information about the Company, please
visit www.bonanzacrk.com. Please note that the Company routinely
posts important information about the Company under the Investor
Relations section of its website.
Forward-Looking Statements
This press release contains forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. All statements,
other than statements of historical facts, included in this press
release that address activities, events or developments that the
Company expects, believes or anticipates will or may occur in the
future are forward-looking statements. These statements are based
on certain assumptions made by the Company based on management’s
experience, perception of historical trends and technical analyses,
current conditions, anticipated future developments and other
factors believed to be appropriate and reasonable by management.
When used in this press release, the words “will,” “potential,”
“believe,” “estimate,” “intend,” “expect,” “may,” “should,”
“anticipate,” “could,” “plan,” “predict,” “project,” “profile,”
“model” or their negatives, other similar expressions or the
statements that include those words, are intended to identify
forward-looking statements, although not all forward-looking
statements contain such identifying words. These statements include
statements regarding future reserves; EUR estimates and PDP decline
rates; development and completion expectations and strategy;
anticipated operating and capital costs; and the timing of
emergence from Chapter 11. 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: further declines in natural
gas, oil and NGL prices, including any impact on the Company's
asset carrying values or reserves arising from price declines;
general economic conditions, including the performance of financial
markets and interest rates; the Company's liquidity; drilling
programs and results; shortages of oilfield equipment, services and
personnel; operating risks such as unexpected drilling conditions
and uncertainties inherent in projecting future drilling and
completion activities and costs; uncertainties of negotiations to
result in an agreement or a completed transaction; 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 15, 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)
|
Three Months Ended December 31, |
|
Twelve Months Ended December 31, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Operating net
revenues: |
|
|
|
|
|
|
|
Oil and
gas sales |
$ |
47,266 |
|
|
$ |
57,032 |
|
|
$ |
195,295 |
|
|
$ |
292,679 |
|
Operating
expenses: |
|
|
|
|
|
|
|
Lease
operating expense |
9,743 |
|
|
13,214 |
|
|
43,671 |
|
|
65,038 |
|
Midstream
operating expense |
2,628 |
|
|
2,797 |
|
|
12,826 |
|
|
11,368 |
|
Severance
and ad valorem taxes |
3,773 |
|
|
5,574 |
|
|
15,304 |
|
|
18,629 |
|
Exploration |
3 |
|
|
2,602 |
|
|
946 |
|
|
15,827 |
|
Depreciation, depletion and amortization |
26,613 |
|
|
57,357 |
|
|
111,215 |
|
|
244,921 |
|
Impairment of oil and gas properties |
— |
|
|
573,698 |
|
|
10,000 |
|
|
740,478 |
|
Abandonment and impairment of unproved properties |
229 |
|
|
11,916 |
|
|
24,692 |
|
|
33,543 |
|
Unused
commitments |
4,226 |
|
|
— |
|
|
7,686 |
|
|
— |
|
Contract
settlement expense |
21,000 |
|
|
— |
|
|
21,000 |
|
|
— |
|
General
and administrative (including $1,643, $3,601, $8,892, and $14,552
respectively, of stock compensation) |
27,474 |
|
|
14,027 |
|
|
77,065 |
|
|
70,319 |
|
Total
operating expenses |
95,689 |
|
|
681,185 |
|
|
324,405 |
|
|
1,200,123 |
|
Income (loss) from
operations |
(48,423 |
) |
|
(624,153 |
) |
|
(129,110 |
) |
|
(907,444 |
) |
Other income
(expense): |
|
|
|
|
|
|
|
Derivative gain (loss) |
490 |
|
|
5,286 |
|
|
(11,234 |
) |
|
56,558 |
|
Interest
expense |
(15,842 |
) |
|
(14,273 |
) |
|
(62,058 |
) |
|
(57,052 |
) |
Gain on
termination fee |
— |
|
|
— |
|
|
6,000 |
|
|
— |
|
Other
income (loss) |
(3,559 |
) |
|
(574 |
) |
|
(2,548 |
) |
|
(2,503 |
) |
Total
other income (expense) |
(18,911 |
) |
|
(9,561 |
) |
|
(69,840 |
) |
|
(2,997 |
) |
Income (loss) from
continuing operations before taxes |
(67,334 |
) |
|
(633,714 |
) |
|
(198,950 |
) |
|
(910,441 |
) |
Income
tax benefit (expense) |
— |
|
|
60,051 |
|
|
— |
|
|
164,894 |
|
Net income (loss) |
$ |
(67,334 |
) |
|
$ |
(573,663 |
) |
|
$ |
(198,950 |
) |
|
$ |
(745,547 |
) |
|
|
|
|
|
|
|
|
Net
income (loss) per basic common share |
$ |
(1.37 |
) |
|
$ |
(12.08 |
) |
|
$ |
(4.04 |
) |
|
$ |
(15.57 |
) |
|
|
|
|
|
|
|
|
Net
income (loss) per diluted common share |
$ |
(1.37 |
) |
|
$ |
(12.08 |
) |
|
$ |
(4.04 |
) |
|
$ |
(15.57 |
) |
|
|
|
|
|
|
|
|
Basic weighted-average
common shares outstanding |
49,338 |
|
|
49,030 |
|
|
49,268 |
|
|
47,874 |
|
Diluted
weighted-average common shares outstanding |
49,338 |
|
|
49,030 |
|
|
49,268 |
|
|
47,874 |
|
|
|
|
|
|
|
|
|
|
|
|
|
● The
Company follows the two-class method when computing the basic and
diluted income (loss) per share, which allocates earnings between
common shareholders and participating securities. Please refer to
Note 14 – Earnings per Share in the Form 10-K, for a detailed
calculation. |
Schedule 2: Statement of Cash Flows(in thousands, unaudited)
|
Three Months Ended December 31, |
|
Twelve Months Ended December 31, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Cash flows from
operating activities: |
|
|
|
|
|
|
|
Net
income (loss) |
$ |
(67,334 |
) |
|
$ |
(573,663 |
) |
|
$ |
(198,950 |
) |
|
$ |
(745,547 |
) |
Adjustments to reconcile net income (loss) to net cash provided by
operating activities: |
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
26,613 |
|
|
57,357 |
|
|
111,215 |
|
|
244,921 |
|
Deferred
income taxes |
— |
|
|
(60,072 |
) |
|
— |
|
|
(165,667 |
) |
Impairment of oil and gas properties |
— |
|
|
573,698 |
|
|
10,000 |
|
|
740,478 |
|
Abandonment and impairment of unproved properties |
229 |
|
|
11,916 |
|
|
24,692 |
|
|
33,543 |
|
Dry hole
expense |
(33 |
) |
|
(1,998 |
) |
|
872 |
|
|
5,630 |
|
Stock-based compensation |
1,643 |
|
|
3,601 |
|
|
8,892 |
|
|
14,552 |
|
Amortization of deferred financing costs and debt premium |
475 |
|
|
588 |
|
|
3,180 |
|
|
2,280 |
|
Accretion
of contractual obligation for land acquisition |
— |
|
|
— |
|
|
— |
|
|
814 |
|
Derivative (gain) loss |
(490 |
) |
|
(5,286 |
) |
|
11,234 |
|
|
(56,558 |
) |
Derivative cash settlements |
2,584 |
|
|
42,624 |
|
|
18,333 |
|
|
130,996 |
|
Inventory
adjustment |
4,390 |
|
|
— |
|
|
4,390 |
|
|
— |
|
Other |
(450 |
) |
|
1,146 |
|
|
(323 |
) |
|
1,429 |
|
Changes
in current assets and liabilities: |
|
|
|
|
|
|
|
Accounts
receivable |
5,840 |
|
|
6,977 |
|
|
35,282 |
|
|
35,230 |
|
Prepaid
expenses and other assets |
(791 |
) |
|
7,450 |
|
|
(1,838 |
) |
|
8,444 |
|
Accounts
payable and accrued liabilities |
11,636 |
|
|
(11,750 |
) |
|
(11,616 |
) |
|
(23,655 |
) |
Settlement of asset retirement obligations |
(327 |
) |
|
(89 |
) |
|
(800 |
) |
|
(867 |
) |
Net cash
provided by operating activities |
(16,015 |
) |
|
52,499 |
|
|
14,563 |
|
|
226,023 |
|
Cash flows from
investing activities: |
|
|
|
|
|
|
|
Acquisition of oil and gas properties |
821 |
|
|
(2,668 |
) |
|
(98 |
) |
|
(16,270 |
) |
Deposits
for acquisitions |
— |
|
|
1,549 |
|
|
— |
|
|
1,549 |
|
Proceeds
from sale of oil and gas properties |
— |
|
|
— |
|
|
— |
|
|
— |
|
Payments
of contractual obligation |
— |
|
|
— |
|
|
(12,000 |
) |
|
(12,000 |
) |
Exploration and development of oil and gas properties |
(4,853 |
) |
|
(64,900 |
) |
|
(52,344 |
) |
|
(425,918 |
) |
Natural
gas plant capital expenditures |
— |
|
|
1 |
|
|
— |
|
|
(112 |
) |
(Increase) decrease in restricted cash |
5,094 |
|
|
61 |
|
|
(2,613 |
) |
|
2,987 |
|
Additions
to property and equipment - non oil and gas |
(240 |
) |
|
(419 |
) |
|
(346 |
) |
|
(2,809 |
) |
Net cash
used in investing activities |
822 |
|
|
(66,376 |
) |
|
(67,401 |
) |
|
(452,573 |
) |
Cash flows from
financing activities: |
|
|
|
|
|
|
|
Proceeds
from credit facility |
— |
|
|
22,000 |
|
|
209,000 |
|
|
137,000 |
|
Payments
to credit facility |
(37,666 |
) |
|
(12,000 |
) |
|
(96,333 |
) |
|
(91,000 |
) |
Proceeds
from sale of common stock |
— |
|
|
8 |
|
|
— |
|
|
209,308 |
|
Offering
costs related to sale of common stock |
— |
|
|
— |
|
|
— |
|
|
(6,620 |
) |
Proceeds
from sale of Senior Notes |
— |
|
|
— |
|
|
— |
|
|
— |
|
Offering
costs related to sale of Senior Notes |
— |
|
|
— |
|
|
— |
|
|
(99 |
) |
Payment
of employee tax withholdings in exchange for the return of common
stock |
(6 |
) |
|
(90 |
) |
|
(289 |
) |
|
(2,683 |
) |
Deferred
financing costs |
— |
|
|
(26 |
) |
|
(316 |
) |
|
(599 |
) |
Net cash
provided by (used in) financing activities |
(37,672 |
) |
|
9,892 |
|
|
112,062 |
|
|
245,307 |
|
Net change in cash and
cash equivalents |
(52,865 |
) |
|
(3,985 |
) |
|
59,224 |
|
|
18,757 |
|
Cash and cash
equivalents: |
|
|
|
|
|
|
|
Beginning
of period |
133,430 |
|
|
25,326 |
|
|
21,341 |
|
|
2,584 |
|
End of
period |
$ |
80,565 |
|
|
$ |
21,341 |
|
|
$ |
80,565 |
|
|
$ |
21,341 |
|
Schedule 3: Condensed Balance Sheets(in thousands,
unaudited)
|
December 31, |
|
December 31, |
|
2016 |
|
2015 |
ASSETS |
|
|
|
Current assets |
$ |
112,428 |
|
|
$ |
120,074 |
|
Oil and gas properties
held for sale, net of accumulated depreciation, depletion and
amortization of $636,917 in 2015 |
— |
|
|
214,922 |
|
Total property and
equipment, net |
1,018,968 |
|
|
922,344 |
|
Other assets |
3,082 |
|
|
2,301 |
|
Total
Assets |
$ |
1,134,478 |
|
|
$ |
1,259,641 |
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS’ EQUITY |
|
|
|
Current
liabilities |
$ |
1,070,466 |
|
|
$ |
135,973 |
|
Long-term debt |
— |
|
|
871,666 |
|
Other long-term
liabilities |
44,951 |
|
|
42,595 |
|
Total
Liabilities |
1,115,417 |
|
|
1,050,234 |
|
|
|
|
|
Stockholders’
Equity |
19,061 |
|
|
209,407 |
|
Total
Liabilities and Stockholders’ Equity |
$ |
1,134,478 |
|
|
$ |
1,259,641 |
|
Schedule 4: Volumes and Realized Prices (Before and After the
Effect of Commodity Hedges)(unaudited)
|
Three Months Ended |
|
December 31, |
|
2016 |
|
2015 |
Wellhead
Volumes and Prices |
|
|
|
|
|
|
|
Crude Oil and
Condensate Sales Volumes (Bbl/d) |
|
|
|
Rocky Mountains |
7,042 |
|
|
13,655 |
|
Mid-Continent |
2,016 |
|
|
2,627 |
|
Total |
9,058 |
|
|
16,282 |
|
|
|
|
|
|
|
Crude Oil and
Condensate Realized Prices ($/Bbl) |
|
|
|
Rocky Mountains |
$ |
40.10 |
|
|
$ |
33.90 |
|
Mid-Continent |
48.44 |
|
|
41.69 |
|
Composite (before
derivatives) |
41.96 |
|
|
35.15 |
|
Composite (after
derivatives) |
45.06 |
|
|
63.15 |
|
|
|
|
|
Natural Gas
Liquids Sales Volumes (Bbl/d) |
|
|
|
Rocky Mountains |
3,695 |
|
|
|
4,745 |
|
Mid-Continent |
542 |
|
|
|
765 |
|
Total |
4,237 |
|
|
|
5,510 |
|
|
|
|
|
Natural Gas
Liquids Realized Prices ($/Bbl) |
|
|
|
Rocky Mountains
(1) |
$ |
13.19 |
|
|
$ |
12.82 |
|
Mid-Continent (1) |
22.65 |
|
|
(65.98 |
) |
Composite (before
derivatives)(1) |
14.40 |
|
|
1.88 |
|
Composite (after
derivatives) |
14.40 |
|
|
1.88 |
|
|
|
|
|
Natural Gas
Sales Volumes (Mcf/d) |
|
|
|
Rocky Mountains |
23,061 |
|
|
|
31,236 |
|
Mid-Continent |
6,603 |
|
|
|
9,441 |
|
Total |
29,664 |
|
|
|
40,677 |
|
|
|
|
|
Natural Gas
Realized Prices ($/Mcf) |
|
|
|
Rocky Mountains
(2) |
$ |
2.29 |
|
|
$ |
0.49 |
|
Mid-Continent |
3.01 |
|
|
2.32 |
|
Composite (before
derivatives)(2) |
2.45 |
|
|
0.91 |
|
Composite (after
derivatives) |
2.45 |
|
|
1.10 |
|
|
|
|
|
Crude Oil
Equivalent Sales Volumes (Boe/d) |
|
|
|
Rocky Mountains |
14,581 |
|
|
23,606 |
|
Mid-Continent |
3,658 |
|
|
4,966 |
|
Total |
18,239 |
|
|
28,572 |
|
|
|
|
|
Crude Oil
Equivalent Sales Prices ($/Boe) |
|
|
|
Rocky Mountains |
$ |
26.34 |
|
|
$ |
22.83 |
|
Mid-Continent |
35.47 |
|
|
16.29 |
|
Composite (before
derivatives) |
28.17 |
|
|
21.70 |
|
Composite (after
derivatives) |
29.71 |
|
|
37.91 |
|
|
|
|
|
Total Sales
Volumes (MBoe) |
1,678.0 |
|
|
2,628.6 |
|
|
|
|
|
(1) Fourth
quarter 2015 includes pricing adjustments of approximately $5.2
million. Without the effect of these adjustments, realized pricing
would have been approximately $11.60/Bbl in the Rocky Mountain
region, $14.90/Bbl in the Mid-Continent region, and $12.06/Bbl
(before derivatives) on a corporate basis. |
(2) Fourth
quarter 2015 includes a State of Colorado royalty adjustment of
approximately $2.5 million. Without the effect of this adjustment,
realized pricing would have been approximately $1.35/Mcf in the
Rocky Mountain region and $1.57/Mcf (before derivatives) on a
corporate basis. |
Schedule 5: Per unit operating margins(unaudited)
|
For the Three Months Ended December
31, |
|
For the Twelve Months Ended December
31, |
|
2016 |
|
2015 |
|
Percent Change |
|
2016 |
|
2015 |
|
Percent Change |
Per Unit Costs
($/Boe) |
|
|
|
|
|
|
|
|
|
|
|
Realized
price (before derivatives) |
$ |
28.17 |
|
|
$ |
21.70 |
|
|
30% |
|
|
$ |
24.61 |
|
|
$ |
28.36 |
|
|
(13)% |
|
LOE |
$ |
5.81 |
|
|
$ |
5.03 |
|
|
16% |
|
|
$ |
5.50 |
|
|
$ |
6.30 |
|
|
(13)% |
|
Midstream
expense |
$ |
1.57 |
|
|
$ |
1.06 |
|
|
48% |
|
|
$ |
1.62 |
|
|
$ |
1.10 |
|
|
47% |
|
Severance
and Ad Valorem |
$ |
2.25 |
|
|
$ |
2.12 |
|
|
6% |
|
|
$ |
1.93 |
|
|
$ |
1.81 |
|
|
7% |
|
Cash
General and Administrative (1) |
$ |
15.39 |
|
|
$ |
3.97 |
|
|
288% |
|
|
$ |
8.59 |
|
|
$ |
5.40 |
|
|
59% |
|
Total
cash operating costs |
$ |
25.02 |
|
|
$ |
12.18 |
|
|
105% |
|
|
$ |
17.64 |
|
|
$ |
14.61 |
|
|
21% |
|
Cash
operating margin (before derivatives) |
$ |
3.15 |
|
|
$ |
9.52 |
|
|
(67)% |
|
|
$ |
6.97 |
|
|
$ |
13.75 |
|
|
(49)% |
|
Derivative Cash Settlements |
$ |
1.54 |
|
|
$ |
16.21 |
|
|
(90)% |
|
|
$ |
2.31 |
|
|
$ |
12.70 |
|
|
(82)% |
|
Cash
operating margin (after derivatives) |
$ |
4.69 |
|
|
$ |
25.73 |
|
|
(82)% |
|
|
$ |
9.28 |
|
|
$ |
26.45 |
|
|
(65)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash
items |
|
|
|
|
|
|
|
|
|
|
|
Depreciation Depletion and Amortization |
$ |
15.86 |
|
|
$ |
21.82 |
|
|
(27)% |
|
|
$ |
14.01 |
|
|
$ |
23.73 |
|
|
(41)% |
|
Non-cash
General and Administrative |
$ |
0.98 |
|
|
$ |
1.37 |
|
(28)% |
|
|
$ |
1.12 |
|
|
$ |
1.41 |
|
|
(21)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Cash general and administrative expense excludes stock
based compensation of $1.6 million and $3.6 million for the
three-month periods ended December 31, 2016 and 2015, respectively,
and $8.9 million and $14.5 million for the twelve-month periods
ended December 31, 2016 and 2015, respectively. |
Schedule 6: Adjusted Net Loss(in thousands, except per
share amounts, unaudited)
Adjusted net 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, including unrealized gains and
losses on unsettled derivative instruments, impairment of oil and
gas properties, other similar non-cash charges (2) one-time
transactions and then (3) the non-cash and one time items’ impact
on taxes based on an applicable rate that approximates the
Company's effective tax rate in each period. Adjusted net loss is
not a measure of net loss as determined by GAAP.
The following table provides a reconciliation of net loss (GAAP)
to adjusted net loss (non-GAAP):
|
Three Months Ended |
|
Twelve Months Ended |
|
December 31, |
|
December 31, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Net income
(loss) |
$ |
(67,334 |
) |
|
$ |
(573,663 |
) |
|
$ |
(198,950 |
) |
|
$ |
(745,547 |
) |
|
|
|
|
|
|
|
|
Adjustments to net
income (loss): |
|
|
|
|
|
|
|
Derivative (gain) loss |
(490 |
) |
|
(5,286 |
) |
|
11,234 |
|
|
(56,558 |
) |
Derivative cash settlements |
2,584 |
|
|
42,624 |
|
|
18,333 |
|
|
130,996 |
|
Impairment of proved properties |
— |
|
|
573,698 |
|
|
10,000 |
|
|
740,478 |
|
Abandonment and impairment of unproved properties |
229 |
|
|
11,916 |
|
|
24,692 |
|
|
33,543 |
|
Exploratory dry hole expense |
(33 |
) |
|
(1,998 |
) |
|
872 |
|
|
5,630 |
|
Stock-based compensation (1) |
1,643 |
|
|
3,601 |
|
|
8,892 |
|
|
14,552 |
|
Advisor
fees related to financial alternatives (1) |
14,457 |
|
|
— |
|
|
20,375 |
|
|
— |
|
Cash
severance costs (1) |
— |
|
|
— |
|
|
2,162 |
|
|
1,155 |
|
Gain on
termination fee |
— |
|
|
— |
|
|
6,000 |
|
|
— |
|
Contract
settlement expense |
21,000 |
|
|
— |
|
|
21,000 |
|
|
— |
|
Derivative conversion payment (2) |
— |
|
|
— |
|
|
— |
|
|
10,472 |
|
Litigation settlement (3) |
— |
|
|
— |
|
|
— |
|
|
1,638 |
|
Total adjustments
before taxes |
39,390 |
|
|
624,555 |
|
|
123,560 |
|
|
881,906 |
|
Income tax effect |
— |
|
|
(59,333 |
) |
|
— |
|
|
(160,988 |
) |
Total adjustments after
taxes |
$ |
39,390 |
|
|
$ |
565,222 |
|
|
$ |
123,560 |
|
|
$ |
720,918 |
|
|
|
|
|
|
|
|
|
Adjusted net
income (loss) |
$ |
(27,944 |
) |
|
$ |
(8,441 |
) |
|
$ |
(75,390 |
) |
|
$ |
(24,629 |
) |
Adjusted net
income (loss) per diluted share |
$ |
(0.57 |
) |
|
$ |
(0.17 |
) |
|
$ |
(1.53 |
) |
|
$ |
(0.51 |
) |
|
|
|
|
|
|
|
|
Diluted
weighted-average common shares outstanding |
49,338 |
|
|
49,030 |
|
|
49,268 |
|
|
47,874 |
|
|
|
|
|
|
|
|
|
(1)
Included as a portion of general and administrative expense on the
consolidated statement of operations. |
(2)
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. |
(3)
Included as a portion of other income (loss) on the consolidated
statement of operations. |
Schedule 7: Adjusted EBITDAX(in thousands, except per share
amounts, unaudited)
Adjusted EBITDAX is a supplemental non-GAAP financial measure
that is used by management and external users of the Company’s
consolidated financial statements, such as industry analysts,
investors, lenders and rating agencies. The Company defines
adjusted EBITDAX as earnings before interest expense, income taxes,
depreciation, depletion, amortization, impairment, exploration
expenses and other similar non-cash and non-recurring charges.
Adjusted EBITDAX is not a measure of net income or cash flows as
determined by GAAP.
The following table presents a reconciliation of GAAP financial
measures of net income (loss) to the non-GAAP financial measure of
Adjusted EBITDAX.
|
Three Months Ended |
|
Twelve Months Ended |
|
December 31, |
|
December 31, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
Net Income
(loss) |
$ |
(67,334 |
) |
|
$ |
(573,663 |
) |
|
$ |
(198,950 |
) |
|
$ |
(745,547 |
) |
Exploration |
3 |
|
|
2,602 |
|
|
946 |
|
|
15,827 |
|
Depreciation, depletion and amortization |
26,613 |
|
|
57,357 |
|
|
111,215 |
|
|
244,921 |
|
Impairment of proved properties |
— |
|
|
573,698 |
|
|
10,000 |
|
|
740,478 |
|
Abandonment and impairment of unproved properties |
229 |
|
|
11,916 |
|
|
24,692 |
|
|
33,543 |
|
Stock-based Compensation (1) |
1,643 |
|
|
3,601 |
|
|
8,892 |
|
|
14,552 |
|
Cash
severance costs (1) |
— |
|
|
— |
|
|
2,162 |
|
|
1,155 |
|
Advisor
fees related to financial alternatives (1) |
14,457 |
|
|
— |
|
|
20,375 |
|
|
— |
|
Gain on
termination fee |
— |
|
|
— |
|
|
(6,000 |
) |
|
— |
|
Contract
settlement expense |
21,000 |
|
|
— |
|
|
21,000 |
|
|
— |
|
Derivative conversion payment (2) |
— |
|
|
— |
|
|
— |
|
|
10,472 |
|
Litigation Settlement (3) |
— |
|
|
— |
|
|
— |
|
|
1,638 |
|
Interest
expense |
15,842 |
|
|
14,273 |
|
|
62,058 |
|
|
57,052 |
|
Derivative (gain) loss |
(490 |
) |
|
(5,286 |
) |
|
11,234 |
|
|
(56,558 |
) |
Derivative cash settlements |
2,584 |
|
|
42,624 |
|
|
18,333 |
|
|
130,996 |
|
Income
tax (benefit) expense |
— |
|
|
(60,051 |
) |
|
— |
|
|
(164,894 |
) |
Adjusted
EBITDAX |
$ |
14,547 |
|
|
$ |
67,071 |
|
|
$ |
85,957 |
|
|
$ |
283,635 |
|
|
|
|
|
|
|
|
|
(1)
Included as a portion of general and administrative expense on the
consolidated statement of operations. |
(2)
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. |
(3)
Included as a portion of other income (loss) on the consolidated
statement of operations. |
Schedule 8: Costs Incurred
|
|
For the Year Ended
December 31, |
|
|
2016 |
|
|
(in thousands) |
Acquisition(1) |
|
$ |
97 |
|
Development(2) |
|
|
31,209 |
|
Exploration |
|
|
74 |
|
Total(3) |
|
$ |
31,380 |
|
|
|
|
|
|
(1)
Acquisition costs for unproved properties were $97,000. Acquisition
costs for proved properties were $0. |
(2)
Development costs include workover costs of $6.0 million. |
(3)
Includes amounts relating to asset retirement obligations of $3.1
million. |
Schedule 9: PV-10 of Estimated Proved Reserves
PV-10 is derived from the Standardized Measure, which is the
most directly comparable GAAP financial measure. PV-10 is a
computation of the Standardized Measure on a pre-tax basis. PV-10
is equal to the Standardized Measure at the applicable date, before
deducting future income taxes, discounted at 10%. We believe that
the presentation of PV-10 is relevant and useful to investors
because it presents the discounted future net cash flows
attributable to our estimated net proved reserves prior to taking
into account future corporate income taxes, and it is a useful
measure for evaluating the relative monetary significance of our
oil and natural gas properties. Further, investors may utilize the
measure as a basis for comparison of the relative size and value of
our reserves to other companies. We use this measure when assessing
the potential return on investment related to our oil and natural
gas properties. PV-10, however, is not a substitute for the
Standardized Measure. Our PV-10 measure and the Standardized
Measure do not purport to present the fair value of our proved oil
and natural gas reserves.
The following table presents a reconciliation of GAAP
Standardized Measure to the non-GAAP financial measure of
PV-10.
|
|
December 31, |
(in thousands) |
|
2016 |
|
|
|
PV-10 |
|
$ |
276,955 |
|
Present value of future
income taxes discounted at 10% (1) |
|
— |
|
Standardized
Measure |
|
$ |
276,955 |
|
|
|
|
(1) The tax
basis of the Company's oil and gas properties as of December 31,
2016 provides more tax deduction than income generation when
reserve estimates were prepared using 2016 SEC pricing. |
Schedule 10: 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 general and administrative
expense exclusive of the Company's stock based compensation and
one-time charges, such as severance costs and advisor fees. The
Company refers to recurring cash G&A to provide typical cash
G&A costs that are planned for in a given period. Recurring
cash G&A is not a measure fully inclusive measure of general
and administrative expense as determined by GAAP.
The following table presents a reconciliation of GAAP financial
measures of G&A expense to the non-GAAP financial measure of
recurring cash G&A.
|
|
Three Months Ended |
|
Twelve Months Ended |
|
|
12/31/2016 |
|
9/30/2016 |
|
12/31/2016 |
|
12/31/2015 |
General and
Administrative Expense |
|
$ |
27,474 |
|
|
$ |
18,671 |
|
|
$ |
77,065 |
|
|
$ |
70,319 |
|
|
|
|
|
|
|
|
|
|
Stock
Compensation |
|
(1,643 |
) |
|
(1,863 |
) |
|
(8,892 |
) |
|
(14,552 |
) |
Cash
severance costs |
|
— |
|
|
— |
|
|
(2,162 |
) |
|
(1,155 |
) |
Advisor
fees related to financial alternatives |
|
(14,457 |
) |
|
(5,918 |
) |
|
(20,375 |
) |
|
— |
|
Recurring cash
G&A Expense |
|
$ |
11,374 |
|
|
$ |
10,890 |
|
|
$ |
45,636 |
|
|
$ |
54,612 |
|
|
|
|
|
|
|
|
|
|
For further information, please contact:
James R. Edwards
Director - Investor Relations
720-440-6136
jedwards@bonanzacrk.com
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