2013-03-15 00:19:49 -
DENVER, March 14, 2012 - Bonanza Creek Energy, Inc. (NYSE: BCEI) today reported
its fourth quarter and full year 2012 operating and financial results.
Key highlights for fourth quarter 2012 include:
* 107% increase in production to 11,994 Boe/d; 74% crude oil and liquids
* 100% increase in revenue to $74.0 million; net income of $13.0 million
* 77% increase in adjusted net income per share (non-GAAP) to $0.39
* 138% increase in EBITDAX (non-GAAP) to $54.1 million
Reconciliations of all non-GAAP financial measures stated in this release are
made to the most directly comparable GAAP financial measures are included at the
end of this release.
Operational highlights include:
* The Company's first horizontal Niobrara "C" Bench well achieved a 30-day
average production rate of 444 Boe/d at 79% crude oil
* The Company's first extended reach lateral targeting the Niobrara "B" Bench
achieved a 30-day average production rate in early 2013 of 795 Boe/d at 76%
crude oil
* The Company's first horizontal Codell well achieved a 30-day average
production rate of 370 Boe/d at 81% crude oil, and a 60-day average
production rate of 367 Boe/d at 75% crude oil
* During 2012, the Company's proved reserves increased 21% to 53 MMBoe
Michael Starzer, Bonanza Creek's President and Chief Executive Officer,
commented, "I am pleased with our Company's performance during 2012 executing on
the development plan and identifying significant oil-weighted upside,
particularly in the Wattenberg Field. With our expanding development runway and
excellent well performance, the foundation for realizing Bonanza Creek's top
tier growth potential has been assembled. The Company expanded Niobrara "B"
Bench horizontal drilling across our acreage in Wattenberg, achieving strong
results, and initiated testing of significant upside catalysts. The Mid-
Continent Region also performed very well in 2012 executing its development
plan, including the installation of our third gas processing facility, ahead of
schedule and under budget. I am proud of our team and that Bonanza Creek's
culture of continuous improvement has produced solid results for our
stockholders."
Fourth Quarter 2012 Financial Results
Bonanza Creek began the divestiture process of its California properties in the
second quarter 2012. Under generally accepted accounting principles, the results
of operations for the California properties are presented as "discontinued
operations" for 2012 and for the prior-year in our accompanying condensed
financial statement. Consequently, production, revenue and expenses associated
with the California properties have been removed from continuing operations and
reported separately as discontinued operations in our accompanying condensed
financial statements. In this release, the Condensed Statement of Operations in
Schedule 1 and the Condensed Balance Sheet in Schedule 3 state the changes to
the current period and the prior-year period for the disclosure of the
discontinued operations. The following supplemental non-GAAP information
presents the reported GAAP amounts as compared to the amounts that would have
been reported if the California operations were included in continuing
operations. Except as otherwise noted, all comparisons discussed in the text of
this release include the California operations as continuing operations in the
current year and the prior year periods as previously reported.
Average realized prices for fourth quarter 2012, before the effect of commodity
derivatives, were $84.26 per Bbl of oil, $4.36 per Mcf of natural gas and $54.60
per Bbl of NGLs, compared to $91.43 per Bbl of oil, $4.37 per Mcf of natural gas
and $64.11 per Bbl of NGLs for fourth quarter 2011.
Net revenue for fourth quarter 2012 was $74.0 million, compared to $36.9 million
for fourth quarter 2011, a 100% increase. Crude oil and liquids revenue
accounted for approximately 89% of total revenue for fourth quarter 2012.
Lease operating expense ("LOE") for fourth quarter 2012 was $8.6 million, or
$7.81 per Boe, compared to $7.0 million, or $13.20 per Boe, for fourth quarter
2011. The decrease in per unit LOE is primarily attributable to increased sales
volumes and lower per unit operating costs for horizontal wells.
General and administrative expense ("G&A") for fourth quarter 2012 was $9.0
million, or $8.15 per Boe, compared to $8.5 million, or $15.96 per Boe, for
fourth quarter 2011. The decrease in per unit G&A is attributed primarily to
increased sales volumes. G&A for fourth quarter 2012 also includes $1.6 million
of non-cash stock compensation expense and approximately $0.4 million of legal
fees.
Net income for fourth quarter 2012 was $13.0 million, or $0.32 per diluted
share, compared to a net loss of $176 thousand, or $(0.01) per diluted share,
for fourth quarter 2011. Adjusted net income (a non-GAAP financial measure) for
fourth quarter 2012 was $15.7 million, or $0.39 per diluted share, compared to
adjusted net income of $6.7 million, or $0.22 per diluted share, for fourth
quarter 2011.
Full Year 2012 Financial Results
All amounts discussed below reflect total operations, including our discontinued
California operations.
Key highlights for full year 2012 include:
* 115% increase in production to 9,403 Boe/d; 73% crude oil and liquids
* 267% increase in net income to $46.5 million
* 118% increase in adjusted net income per share (non-GAAP) to $1.31
* 136% increase in EBITDAX (non-GAAP) to $162.1 million
Average realized prices for 2012, before the effect of commodity derivatives,
were $89.37 per Bbl of oil, $3.62 per Mcf of natural gas and $55.53 per Bbl of
NGLs, compared to $90.57 per Bbl of oil, $4.84 per Mcf of natural gas and $67.23
per Bbl of NGLs for 2011.
Net revenue for 2012 was $236.6 million, compared to $112.5 million for 2011, a
110% increase. Crude oil and liquids revenue accounted for approximately 91% of
total revenue for 2012.
LOE for 2012 was $33.0 million, or $9.58 per Boe, compared to $21.5 million, or
$13.43 per Boe, for 2011. The decrease in per unit LOE is primarily attributable
to increased sales volumes and lower per unit operating costs for horizontal
wells.
G&A for 2012 was $31.4 million, or $9.13 per Boe, compared to $17.6 million, or
$11.01 per Boe, for 2011. The decrease in per unit G&A is attributed primarily
to increased sales volumes. G&A for 2012 also includes $4.5 million of non-cash
stock compensation expense and approximately $3.0 million of legal fees.
Net income for 2012 was $46.5 million, or $1.17 per diluted share, compared to
$12.7 million, or $0.43 per diluted share, for 2011. Adjusted net income for
2012 was $52.2 million, or $1.31 per diluted share, compared to adjusted net
income of $17.8 million, or $0.60 per diluted share, for 2011.
As of December 31, 2012, Bonanza Creek has one remaining California property,
located in the Midway-Sunset Field, which is in the process of being sold.
Operations Update
During 2012, the Company achieved an average production rate of 9,403 Boe/d,
comprised of 65% crude oil, 8% NGLs, and 27% natural gas, increasing crude oil
as a percentage of production by 5% and increasing total production by 115% over
2011. For fourth quarter 2012, the Company's average daily production was
11,994 Boe/d, a 107% increase over fourth quarter 2011.
Rocky Mountain Region - Wattenberg Horizontal Development
The Rocky Mountain region contributed approximately 4,568 Boe/d, or 49% of total
company net sales volumes for 2012, comprised of 75% crude oil and 25% liquid-
rich natural gas. Approximately 2,223 Boe/d came from horizontal wells. During
fourth quarter 2012, the Rocky Mountain region contributed approximately 6,549
Boe/d, or 55% of total company net sales volumes for the quarter with
approximately 3,683 Boe/d coming from horizontal wells.
During 2012, the Company drilled 32 horizontal Niobrara "B" Bench wells for an
average total well cost of approximately $4.5 million to an average 4,000 feet
lateral length. The average well cost was negatively affected by drilling
difficulties associated with four wells. Since Bonanza Creek began its
horizontal Niobrara "B" Bench development program in July 2011, the Company has
30-day average production rates on 36 wells and 60-day average production rates
on 28 wells. These wells have averaged the following rates:
30-day production rates: 503 Boe/d (76% oil; 24% liquid-rich gas)
60-day production rates: 405 Boe/d (75% oil; 25% liquid-rich gas)
In addition, the Company drilled three horizontal wells testing additional
resource potential, including:
1. Niobrara "C" Bench: 30-day average production rate of 444 Boe/d, at 79%
crude oil, for a total well cost of $4.4 million
2. Extended reach lateral in the Niobrara "B" Bench: 30-day average production
rate of 795 Boe/d, at 76% crude oil, for a total well cost of $7.4 million
3. Codell: 30-day average production rate of 370 Boe/d, at 81% crude oil, and a
60-day average production rate of 367 Boe/d, at 75% crude oil, for a total
well cost of $4.5 million
Mid-Continent Cotton Valley Program
The Mid-Continent region contributed 4,689 Boe/d, or 50% of total company net
sales volumes for 2012, comprised of 54% crude oil, 17% natural gas liquids and
29% natural gas. Production volumes increased by approximately 90% over 2011.
During fourth quarter 2012, the Mid-Continent region contributed approximately
5,402 Boe/d, a 67% increase over fourth quarter 2011.
During 2012, Bonanza Creek drilled 42 Cotton Valley wells in the Mid-Continent
region, including 11 wells in the fourth quarter 2012. Also during the year, the
Company performed 80 recompletions that added upper Cotton Valley oil sands to
production. At the McKamie-Patton Field, the Company successfully tested the
Cotton Valley oil sands in four wells with an average 30-day production rate of
137 Bbl/d, at 100% crude oil.
The Company invested $16.2 million constructing a third gas processing facility
in the region, expanding its total processing capacity to approximately 40
MMcf/d. This facility, located in the Dorcheat-Macedonia field, began processing
natural gas and natural gas liquids in February 2013.
Capital Expenditures
The Company's capital expenditures in 2012 equaled $340.9 million, versus a
budget of $298.0 million. The over-expenditure was due to a number of events,
notably:
1. Participation in eight non-operated horizontal Niobrara wells successfully
drilled by an offset operator in the Wattenberg Field late in the year for
which production will be largely matched against such expenditures in first
quarter 2013
2. Augmented 2012 projects such as micro-seismic acquisition, gas gathering
system improvements and acreage leasing
3. Additional rig costs in the late stages of transitioning out of the legacy
2012 vertical drilling program
4. Drilling difficulties in four horizontal wells
5. The addition of two incremental frac stages on 24 horizontal wells resulting
in increased well productivity
The Company believes that most of these costs were the result of the rapid
transition in the Wattenberg Field from a vertical well program to a horizontal
well program. Revised costs have been incorporated into the 2013 capital budget.
2012 Proved Reserves
The Company reported its year-end 2012 proved reserves as prepared by its
independent third party reserve engineer, Cawley Gillespie & Associates. Proved
reserves increased 21% over year-end 2011 to approximately 53.0 MMBoe and the
before tax PV-10 (non-GAAP) was approximately $835 million. During 2012,
successful execution of the development program resulted in a 47% increase in
PDP reserves and a 51% increase in PDP PV-10 (non-GAAP), notwithstanding lower
oil and gas prices. Total Company reserve replacement for 2012 was 371%. The
Rocky Mountain region added 12.8 MMBoe net proved reserves at a cost of $18.68
per Boe as a result of its horizontal drilling program during 2012. In addition,
proved reserves for the Niobrara "B" Bench increased from 6.5 MMBoe to 22 MMBoe,
or 41% of total company proved reserves.
The following table summarizes the Company's 2012 proved reserves and PV-10:
2012
% of Oil Gas NGL 2012 2011 % PV-10
Reserve Reserves (MBbls) (MMcf) (MBbls) MBOE MBOE Change (millions)
Category
------------------------------------------------------------------------------------
Proved 31% 10,193.9 33,604.3 784.3 16,578.9 11,244.3 47% $445.5
Developed
Producing
Proved 14% 4,135.9 15,337.4 561.0 7,253.1 5,816.2 25% $151.8
Developed
Non-
Producing
Proved 55% 15,829.1 69,606.5 1,762.0 29,192.2 26,652.1 10% $237.4
Undeveloped
Total 100% 30,158.9 118,548.2 3,107.3 53,024.2 43,712.6 21% $834.7
Proved
A reconciliation of PV-10 to Standardized Measure is included in Schedule 7.
Financial Update
Credit Agreement and Liquidity
As of December 31, 2012, Bonanza Creek had a $600 million revolving credit
facility with a $325 million borrowing base and $158.0 million outstanding, and
cash of $4.3 million. The Company's total liquidity was $123.3 million after
reducing the borrowing base by $48.0 million to account for a letter of credit
required to facilitate the Company's acquisition of leasehold acreage in the
Wattenberg Field. Schedule 8 provides a calculation of total liquidity.
Commodity Derivatives Positions
The following table summarizes the Company's crude oil and natural gas commodity
derivative positions as of February 28, 2013:
Average Average
Derivative Total Notional Amount Floor Ceiling
Settlement Period Instrument (Bo/MMBtu) Price Price
------------------- ------------ ------------------------ ---------- ----------
Oil
2013 Collar 1,163,116 $ 88.38 $ 102.29
Swap 1,035,417 88.54
2014 Collar 1,310,000 86.72 95.56
Swap 228,000 90.80
Gas
2013 Swap 154,806 6.40
Conference Call Information
Bonanza Creek will host a conference call on Friday, March 15, 2013 at 9:00 a.m.
Mountain Time (11:00 a.m. Eastern Time). To access the live interactive call,
please dial (866) 700-6293 or (617) 213-8835 and use the passcode 38172270. This
call is being webcast and can be accessed at Bonanza Creek's website
www.bonanzacrk.com for one year after the event.
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 oil shale, and in southern Arkansas,
focused on the 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. Without limiting the generality of the
foregoing, forward-looking statements contained in this press release
specifically include statements regarding the nonrecurring nature of the
additional capital expenditures in 2012 and estimated reserves. 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. 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. 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, 2012, expected to be
filed on or about March 15, 2013, and other filings submitted by us to the
Securities Exchange Commission. The Company's SEC filings are available on the
Company's website at www.bonanzacrk.com and on the SEC's website at www.sec.gov.
All of the forward-looking statements made in this press release are qualified
by these cautionary statements. Any forward-looking statement speaks only as of
the date on which such statement is made, including guidance, and the Company
undertakes no obligation to correct or update any forward-looking statement,
whether as a result of new information, future events or otherwise, except as
required by applicable law.
For further information, please contact:
Mr. Ryan Zorn
Vice President - Finance
720-440-6172
Mr. James Masters
Investor Relations Manager
720-440-6121
Schedule 1: Condensed Statement of Operations
(in thousands, expect for per share data, unaudited)
Three Months Ended Twelve Months Ended
December 31, December 31,
------------------------------ ----------------------------
2012 2011 2012 2011
--------------- -------------- -------------- -------------
NET REVENUES
Oil and gas sales $ 73,592 $ 35,115 $ 231,205 $ 105,724
--------------- -------------- -------------- -------------
OPERATING EXPENSES:
Lease operating 8,189 6,212 30,695 18,253
Severance and ad
valorem taxes 4,287 2,140 13,674 5,919
Exploration 1,151 311 10,715 877
Depreciation,
depletion and
amortization 24,451 9,541 66,202 28,014
Impairment of
proved properties 343 - 611 623
General and
administrative 8,995 8,497 31,405 17,613
--------------- -------------- -------------- -------------
Total operating
expenses 47,416 26,701 153,302 71,299
--------------- -------------- -------------- -------------
INCOME FROM
OPERATIONS 26,176 8,414 77,903 34,425
--------------- -------------- -------------- -------------
OTHER INCOME
(EXPENSE):
Other (loss) (49) (9) (133) (110)
Interest expense (1,791) (1,330) (4,133) (4,017)
Unrealized gain
(loss) in fair
value of
commodity
derivatives (1,336) (6,871) 1,650 225
Realized gain
(loss) in fair
value of
commodity
derivatives 448 (671) (725) (3,024)
--------------- -------------- -------------- -------------
Total other (loss)
(2,728) (8,881) (3,341) (6,926)
--------------- -------------- -------------- -------------
INCOME FROM
CONTINUING
OPERATIONS
BEFORE TAXES $ 23,448 $ (467) $ 74,562 $ 27,499
--------------- -------------- -------------- -------------
Income tax benefit
(expense) (10,194) 286 (29,991) (12,890)
--------------- -------------- -------------- -------------
INCOME FROM
CONTINUING
OPERATIONS 13,254 (181) 44,571 14,609
DISCONTINUED
OPERATIONS
Income (loss) from
operations
associated with oil
and gas
properties held for
sale (135) 25 (927) (3,610)
Gain (loss) on sale
of oil and gas
properties (88) 4,192 -
Income tax
(expense) benefit 18 (20) (1,313) 1,692
--------------- -------------- -------------- -------------
Income (loss)
associated with oil
and gas
properties held for
sale (205) 5 1,952 (1,918)
--------------- -------------- -------------- -------------
NET INCOME (LOSS) $ 13,049 (176) $ 46,523 $ 12,691
--------------- -------------- -------------- -------------
BASIC AND DILUTED
INCOME (LOSS) PER
SHARE
Income (loss) from
continuing $ $
operations $ 0.32 $ (0.01) 1.12 0.49
--------------- -------------- -------------- -------------
Income (loss) from
discontinued $ $ $
operations - $ 0.00 0.05 (0.06)
--------------- -------------- -------------- -------------
Net income (loss)
per common $ $
share $ 0.32 $ (0.01) 1.17 0.43
WEIGHTED AVERAGE
NUMBER OF SHARES
OF COMMON STOCK-
BASIC AND DILUTED 40,065 30,923 39,788 29,576
Schedule 2: Condensed Statement of Cash Flows
(in thousands, unaudited)
Twelve Months Ended
December 31,
------------------------------------
2012 2011
------------------ -----------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 46,523 $ 12,691
Adjustments to reconcile net income to net
cash
provided by operating activities:
Depreciation, depletion and amortization 68,445 31,508
Impairment of proved properties 2,259 4,067
Deferred income taxes 30,773 11,198
Stock-based compensation 4,483 4,437
Exploration 8,379 -
Amortization of deferred financing costs 700 1,004
Valuation (increase) decrease in
commodity derivatives (1,650) (225)
Gain on sale of oil and gas properties (4,192) -
Accretion of contractual obligation for
land acquisition 317 -
Other charges 168
(40)
(Increase) decrease in operating assets:
Accounts receivable (20,738) (11,712)
Prepaid expenses and other
assets (1,164) (1,165)
(Decrease) increase in operating
liabilities:
Accounts payable and accrued liabilities 22,769 5,996
Settlement of asset retirement
obligations (162) (156)
------------------ -----------------
Net cash provided by operating
activities 156,910 57,603
------------------ -----------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of oil and gas
properties 9,337 -
Acquisition of oil and gas
properties (13,920) (1,809)
Exploration and development of oil and
gas properties (281,326) (134,184)
Natural gas plant capital expenditures (15,788) (22,687)
Proceeds from note receivable - 987
Decrease in restricted cash 253 -
Additions to property and equipment-non
oil and gas (3,107) (1,209)
------------------ -----------------
Net cash used in investing activities (304,551) (158,902)
------------------ -----------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in bank revolving
credit 151,400 108,100
Payment on bank revolving
credit - (156,900)
Proceeds from sale of common stock - 155,878
Deferred financing
costs (1,111) (2,284)
Offering costs related to sale of common
stock (3) -
Common stock returned for tax
withholdings (467) (1,405)
------------------ -----------------
Net cash provided by financing
activities 149,819 103,389
------------------ -----------------
Net increase (decrease) in cash and cash
equivalents 2,178 2,090
Cash and cash equivalents, beginning of
period $ 2,090 -
Cash and cash equivalents, end of period $ 4,268 $ 2,090
Schedule 3: Condensed Balance Sheet
(in thousands, unaudited)
December 31, December 31,
2012 2011
------------------------ ---------------------
Assets
Current assets $ 55,304 $ 32,127
Oil and gas properties and gas
plant, net 938,975 618,229
Other assets 7,629
4,097
Oil and gas properties held for
sale, less accumulated
depreciation, depletion, and
amortization 582
9,896
Total Assets $ 1,002,490 $ 664,349
------------------------ ---------------------
Liabilities and Stockholders'
Equity
Current liabilities 102,603 38,531
Bank revolving credit 158,000
6,600
Deferred taxes 110,377 79,604
Other long-term liabilities 52,992
11,633
Total Liabilities $ 423,972 $ 136,368
------------------------ ---------------------
Stockholders' Equity 578,518
527,981
Total Liabilities and
Stockholders' Equity $ 1,002,490 $ 664,349
------------------------ ---------------------
Schedule 4: Volumes and Realized Prices
(unaudited)
Three Months Ended Twelve Months Ended
December 31, December 31,
------------------------------ ------------------------------
2012 2011 2012 2011
--------------- -------------- --------------- --------------
Wellhead Volumes
and Prices
Crude Oil and
Condensate Sales
Volumes (Bbl/d)
Rocky Mountains 4,952 1,734 3,433 1,227
Mid-Continent 2,965 1,556 2,553 1,204
California 43 172 146
180
--------------- -------------- --------------- --------------
Total 7,960 3,462 6,132 2,611
--------------- -------------- --------------- --------------
Crude Oil and
Condensate
Realized Prices
($/Bbl)
Rocky Mountains $ 80.07 $ 86.30 $ 84.60 $ 86.11
Mid-Continent 90.99 94.64 95.12 93.29
California 102.05 114.06 101.19 102.72
--------------- -------------- --------------- --------------
Composite $ 84.26 $ 91.43 $ 89.37 $ 90.57
Natural Gas
Liquids Sales
Volumes (Bbl/d)
Mid-Continent 895 598 778
504
--------------- -------------- --------------- --------------
Total 895 598 778
504
--------------- -------------- --------------- --------------
Natural Gas
Liquids Realized
Prices ($/Bbl)
Mid-Continent $ 54.60 $ 64.11 $ 55.54 $ 67.23
--------------- -------------- --------------- --------------
Composite $ 54.60 $ 64.11 $ 55.54 $ 67.23
Natural Gas Sales
Volumes (Mcf/d)
Rocky Mountains 9,583 3,814 6,808 2,970
Mid-Continent 9,249 6,530 8,146 4,628
California - 21 4
9
--------------- -------------- --------------- --------------
Total 18,832 10,365 14,958 7,607
--------------- -------------- --------------- --------------
Natural Gas
Realized Prices
($/Mcf)
Rocky Mountains $ 5.17 $ 5.81 $ 4.46 $ 5.96
Mid-Continent 3.53 3.53 2.91
4.14
-
California 1.59 1.11
2.06
--------------- -------------- --------------- --------------
Composite $ 4.36 $ 4.37 $ 3.62 $ 4.84
Crude Oil
Equivalent Sales
Volumes (Boe/d)
Rocky Mountains 6,549 2,370 4,567 1,722
Mid-Continent 5,402 3,242 4,689 2,479
California 43 176 147
181
--------------- -------------- --------------- --------------
Total 11,994 5,788 9,403 4,382
--------------- -------------- --------------- --------------
Total Sales
Volumes (MMBoe) 1.1 0.5 3.4
1.6
--------------- -------------- --------------- --------------
Schedule 5: Adjusted Net Income
(in thousands, except per share amounts, unaudited)
This release contains the non-GAAP financial measures adjusted net income and
adjusted net income per diluted share, which exclude (1) unrealized gain or loss
in fair value of commodity derivatives, (2) stock-based compensation expense,
(3) impairment of proved properties, (4) exploratory dry hole cost and (5) gain
or loss on sale of oil and gas properties. The amounts included in the
calculation of adjusted net income and adjusted net income per diluted share,
below, were computed in accordance with GAAP. We believe adjusted net income and
adjusted net income per diluted share are useful to investors because they
provide readers with a more meaningful measure of our profitability before
recording certain items the timing or amount of which cannot be reasonably
determined. However, these measures are provided in addition to, not as an
alternative for and should be read in conjunction with, the information
contained in our financial statements prepared in accordance with GAAP
(including the notes in our SEC filings and posted on our website. The following
tables provide a reconciliation of adjusted net income for the three and twelve
months ended December 31, 2012 and 2011, respectively.
Three Months Ended Twelve Months Ended
December 31, December 31,
----------------------------- ----------------------------
2012 2011 2012 2011
----------------------------- ----------------------------
Net Income $ 13,049 $ (176) $ 46,523 $ 12,691
Unrealized (gain)
loss in fair value
of derivatives 1,336 6,871 (1,650) (225)
Stock-based
compensation 1,570 4,244 4,483
4,437
Impairment 343 - 2,259
4,067
Exploratory dry
hole cost 1,000 - 8,379
-
Gain (loss) on
sale of oil and
gas properties 88 - (4,192) -
--------------- ------------- -------------- -------------
Total adjustments
before tax 4,337 11,115 9,279
8,279
Adjusted for income
tax effects 2,667 6,835 5,707
5,091
Adjusted net
income $ 15,716 $ 6,659 $ 52,230 $ 17,783
Adjusted net
income per diluted
share $ 0.39 $ 0.22 $ 1.31 $
0.60
Schedule 6: EBITDAX
(in thousands, except per share amounts, unaudited)
We define EBITDAX as net income, plus (1) exploration expense, (2) depletion,
depreciation and amortization expense, (3) impairment of proved properties, (4)
stock-based compensation expense, (5) gain or loss on sale of oil and gas
properties, (6) interest expense, (7) unrealized gain or loss in fair value of
commodity derivatives, and (8) income taxes or benefit. EBITDAX is not a measure
of net income or cash flow as determined by GAAP. EBITDAX is presented herein
and reconciled to the GAAP measure of net income because of its wide acceptance
by the investment community as a financial indicator of a Company's ability to
internally fund development and exploration activities. This measure is provided
in addition to, not as an alternative for and should be read in conjunction
with, the information contained in our financial statements prepared in
accordance with GAAP (including the notes) in our SEC filings and posted on our
website. The following table provides a reconciliation of EBITDAX to net income
for the three and twelve months ended December 31, 2012 and 2011, respectively.
Three Months Ended Twelve Months Ended
December 31, December 31,
----------------------------- ----------------------------
2012 2011 2012 2011
----------------------------- ----------------------------
Net Income $ 13,049 $ (176) $ 46,523 $ 12,691
Exploration
1,174 311 10,754 884
Depletion,
depreciation, and
amortization 24,544 10,425 68,445 31,508
Impairment of
proved properties 343 - 2,259 4,067
Stock-based
compensation 1,570 4,244 4,483 4,437
Gain (loss) on
sale of oil and
gas properties 88 - (4,192) -
Interest expense
1,791 1,331 4,133 4,017
Unrealized loss
(gain) in fair
value of commodity
derivatives 1,336 6,870 (1,650) (225)
Income taxes
(benefit) 10,176 (265) 31,305 11,198
EBITDAX $ 54,071 $ 22,740 $ 162,060 $ 68,577
-------------- -------------- --------------- ------------
EBITDAX per $ $ $ $
diluted share 1.35 0.74 4.07 2.32
-------------- -------------- --------------- ------------
Schedule 7: Reconciliation of PV-10 to Standardized Measure
PV-10 is derived from the Standardized Measure of discounted future net cash
flows, 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 oil and natural gas reserves.
The following table provides a reconciliation of PV-10 to the Standardized
Measure at December 31, 2012, 2011 and 2010:
December 31,
--------------------------------------
2012 2011 2010
------------ ------------ ------------
(In millions)
PV-10 $ 834.7 $ 794.0 $ 461.6
Present value of future income taxes
discounted at 10% (151.3) (127.8) (86.9)
------------ ------------ ------------
Standardized Measure $ 683.4 $ 666.2 $ 374.7
------------ ------------ ------------
Schedule 8: Liquidity
(in thousands, unaudited)
Liquidity is calculated by adding the net funds available under our revolving
credit facility and cash and cash equivalents. We use liquidity as an indicator
of the Company's ability to fund development and exploration activities.
However, this measurement has limitations. This measurement can vary from year-
to-year for the Company and can vary among companies based on what is or is not
included in the measurement on a Company's financial statements. This
measurement is provided in addition to, not as an alternative for and should be
read in conjunction with, the information contained in our financial statements
prepared in accordance with GAAP (including the notes) in our SEC filings and
posted on our website. The table below summarizes our liquidity as of December
31, 2012.
December 31, 2012
------------------------------------
Borrowing base $ 325,000
Cash and cash equivalents
4,268
Letter of credit securing contractual
obligation for land acquisition (48,000)
Long-term debt (158,000)
------------------------------------
Liquidity $ 123,268
------------------------------------
This announcement is distributed by Thomson Reuters on behalf of
Thomson Reuters clients. The owner of this announcement warrants that:
(i) the releases contained herein are protected by copyright and
other applicable laws; and
(ii) they are solely responsible for the content, accuracy and
originality of the information contained therein.
Source: Bonanza Creek Energy, Inc. via Thomson Reuters ONE
[HUG#1685494]
