DENVER, March 1, 2016
/PRNewswire/ -- Bill Barrett Corporation (the "Company")
(NYSE: BBG) reported fourth quarter and year-end 2015 results and
provides 2016 operating guidance, including these highlights:
- 2015 production sales volumes of 6.6 million barrels of oil
equivalent ("MMBoe"), exceeded high-end of guidance and was 16%
above the mid-point of original guidance
- Denver-Julesburg ("DJ") Basin production for the
fourth quarter of 2015 increased 55% year-over-year
- 2015 lease operating expense ("LOE") of $43 million, 7% below the mid-point of guidance
and 10% below the mid-point of original guidance
- Fourth quarter LOE of $4.70 per
Boe, represents a 17% sequential decrease
- 2015 capital expenditures of $287
million, 10% below the mid-point of guidance
- Exhibited cost discipline as current extended reach lateral
("XRL") well costs of $4.75 million
are approximately 42% lower compared to wells drilled in the fourth
quarter of 2014
- Entered 2016 with $129 million of
cash and an undrawn credit facility of $375
million
- 2016 operating plan has projected capital expenditures of
$100-$150 million, approximately 55%
below 2015 levels, with total production of 5.8-6.2 MMBoe
Chief Executive Officer and President Scot Woodall commented, "This past year
presented numerous challenges for the energy sector as oil prices
fell to levels not witnessed in over a decade. We responded to
these challenges and successfully executed on our operational
objectives by focusing on the items within our control. We have
taken a number of proactive steps to reset our operating cost and
G&A structure and will realize tangible benefits during 2016,
as evidenced by our cost guidance. Our priority for this year is to
protect our balance sheet as we entered 2016 with a financial
position consisting of $129 million
of cash, an undrawn credit facility, and a strong 2016 hedge
position."
Mr. Woodall continued, "In response to current commodity prices,
we have set our 2016 capital budget at $100-$150 million. This level of spending allows
us to sustain production at levels similar to 2015, pro forma for
asset divestitures completed during 2015, while spending
approximately 55% less capital than 2015 at the mid-point. Based on
the uncertainty of an oil price recovery during 2016, we are making
the decision to curtail drilling activity to preserve capital and
will monitor industry conditions to determine the appropriate time
to resume drilling. Accordingly, we recently released the sole rig
we were operating. Although this results in the deferral of
production during the second half of the year, we believe it is the
appropriate action to take in this commodity price environment as
it allows us to retain operational and financial
flexibility."
OPERATING AND FINANCIAL RESULTS
Reserves
Total estimated proved reserves at year-end 2015 were 83.7 MMBoe
compared to 122.3 MMBoe at year-end 2014. Estimated proved reserves
were 66% oil, 20% natural gas and 14% natural gas liquids ("NGLs")
and were 48% developed compared to 34% developed at year-end 2014.
The decrease in estimated proved reserves compared to year-end 2014
is primarily the result of asset divestitures of 16.1 MMBoe and
negative commodity price-related and other revisions of 24.4 MMBoe,
offset in part by extensions and discoveries of 8.5 MMBoe. The
decrease in proved reserves is also a result of the Company
electing to take a conservative approach to adding proved
undeveloped ("PUD") reserves due to the present commodity price
environment. Only well locations that were in the process of being
drilled at year-end 2015 were included and no new undrilled
locations were added to the PUD reserve inventory. Negative
price-related revisions were a result of a 47% decrease in the
average WTI oil price and a 41% decrease in the average Henry Hub
natural gas price used to calculate the 2015 proved reserves
compared to 2014.
Changes in Proved
Reserves (MMBoe)
|
|
|
Proved reserves as of
December 31, 2014
|
122.3
|
|
Extensions and
discoveries
|
8.5
|
|
Production
|
(6.6)
|
|
Sale of
properties
|
(16.1)
|
|
Pricing revisions and
other
|
(24.4)
|
|
Proved reserves as of
December 31, 2015
|
83.7
|
|
2015 Production and Financial Results
Oil, natural gas and natural gas liquids production totaled 6.6
MMBoe in 2015, exceeding the Company's guidance range of 6.3-6.5
MMBoe. The outperformance was driven by new XRL well results and
achieved despite a reduction in volumes associated with non-core
asset sales in both the DJ Basin and Uinta Oil Program ("UOP") that
were completed in the fourth quarter of 2015 and from UOP
production declines that included approximately 1,000 Boe/d that
was shut-in for economic reasons beginning in the second quarter of
2015.
Fourth quarter of 2015 production totaled 1.7 MMBoe, a 20%
increase over the fourth quarter of 2014, and was 65% oil, 19%
natural gas and 16% NGLs. Fourth quarter of 2015 production in the
DJ Basin increased 55%, while UOP production was down 26% compared
with the fourth quarter of 2014.
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2015
|
|
2014 (1)
|
|
2015
|
|
2014 (1)
|
Production
Data:
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
1,090
|
|
|
956
|
|
|
4,401
|
|
|
4,012
|
|
Natural gas
(MMcf)
|
1,986
|
|
|
1,794
|
|
|
7,764
|
|
|
21,744
|
|
NGLs
(MBbls)
|
264
|
|
|
146
|
|
|
898
|
|
|
1,476
|
|
Combined volumes
(MBoe)
|
1,685
|
|
|
1,401
|
|
|
6,593
|
|
|
9,112
|
|
Daily combined
volumes (Boe/d)
|
18,315
|
|
|
15,233
|
|
|
18,063
|
|
|
24,964
|
|
|
|
(1)
|
2014 data represents
total company as previously reported for the period, including
assets subsequently sold.
|
Pre-hedge commodity prices for 2015 were down significantly
compared to both the fourth quarter and full-year 2014 as oil and
natural gas prices declined significantly throughout 2015. For the
fourth quarter of 2015, the Company had derivative commodity swaps
in place for 10,800 barrels of oil per day tied to WTI pricing at
$89.81 per barrel, 20,000 MMBtu of
natural gas per day tied to Northwest Pipeline ("NWPL") regional
pricing at $4.13 per MMBtu and no
hedges in place for NGLs.
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2015
|
|
2014 (1)
|
|
2015
|
|
2014 (1)
|
Average Sales Prices
(before the effects of realized hedges):
|
Oil (per
Bbl)
|
$
|
35.57
|
|
|
$
|
58.36
|
|
|
$
|
40.06
|
|
|
$
|
77.92
|
|
Natural gas (per
Mcf)
|
1.98
|
|
|
4.16
|
|
|
2.23
|
|
|
4.78
|
|
NGLs (per
Bbl)
|
11.98
|
|
|
20.16
|
|
|
12.16
|
|
|
31.55
|
|
Combined (per
Boe)
|
27.21
|
|
|
47.26
|
|
|
31.02
|
|
|
50.82
|
|
|
|
|
|
|
|
|
|
Average Realized
Sales Prices (after the effects of realized hedges):
|
Oil (per
Bbl)
|
$
|
78.98
|
|
|
$
|
79.47
|
|
|
$
|
78.19
|
|
|
$
|
79.51
|
|
Natural gas (per
Mcf)
|
3.72
|
|
|
3.88
|
|
|
3.75
|
|
|
4.45
|
|
NGLs (per
Bbl)
|
11.98
|
|
|
21.44
|
|
|
12.16
|
|
|
31.51
|
|
Combined (per
Boe)
|
57.36
|
|
|
61.44
|
|
|
58.27
|
|
|
50.73
|
|
|
|
(1)
|
2014 data represents
total company as previously reported for the period, including
assets subsequently sold.
|
Cash operating costs (LOE, gathering, transportation and
processing costs, and production tax expense) totaled $6.54 per Boe in the fourth quarter of 2015, 21%
lower on a sequential basis and 45% lower compared to the fourth
quarter of 2014. LOE was $4.70 per
Boe, 17% lower compared to the third quarter of 2015 and 45% lower
on a year over year basis. This was primarily a result of improved
operational efficiencies and lease operating cost reductions in
both the DJ Basin and the UOP. LOE for the DJ Basin improved to an
average of $3.25 per Boe in the
fourth quarter of 2015 compared to $3.96 per Boe in the third quarter of 2015 and
$5.56 per Boe in the fourth quarter
of 2014. Production tax expense averaged 6.0% of pre-hedge revenue
for the year ended December 31, 2015,
compared with 6.8% of pre-hedge revenue for the year ended
December 31, 2014.
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2015
|
|
2014 (1)
|
|
2015
|
|
2014 (1)
|
Average Costs (per
Boe):
|
|
|
|
|
|
|
|
Lease operating
expenses
|
$
|
4.70
|
|
|
$
|
8.52
|
|
|
$
|
6.48
|
|
|
$
|
6.62
|
|
Gathering,
transportation and processing expense
|
0.55
|
|
|
0.86
|
|
|
0.53
|
|
|
3.89
|
|
Production tax
expenses
|
1.29
|
|
|
2.54
|
|
|
1.85
|
|
|
3.44
|
|
Depreciation,
depletion and amortization
|
27.06
|
|
|
33.10
|
|
|
31.14
|
|
|
25.88
|
|
General and
administrative expense, excluding long-term incentive compensation
expense (2)
|
7.03
|
|
|
7.55
|
|
|
6.53
|
|
|
4.61
|
|
|
|
(1)
|
2014 data represents
total company as previously reported for the period, including
assets subsequently sold.
|
(2)
|
This separate
presentation is a non-GAAP (Generally Accepted Accounting
Principles) measure. Management believes the presentation of
general and administrative expense excluding the long-term
incentive compensation component of general and administrative
expense is useful because it provides a better understanding of
current period general and administrative expenses. Management also
believes that this disclosure may allow for a more accurate
comparison to the Company's peers, which may have higher or lower
stock-based/long-term incentive compensation expense.
|
Discretionary cash flow and adjusted net income (loss) are
non-GAAP measures and are reconciled to net income (loss) in the
schedule attached to this press release.
Discretionary cash flow for 2015 was $206.3 million, or $4.27 per share, compared to $231.6 million, or $4.78 per share, for 2014. Discretionary cash
flow in the fourth quarter of 2015 was $53.3
million, or $1.10 per share,
compared to $38.9 million, or
$0.80 per share, in the fourth
quarter of 2014.
Net income for 2015 was a loss of $487.8
million, or $(10.10) per
diluted common share, compared with net income of $15.1 million, or $0.31 per diluted common share in 2014. Net
income for 2015 and 2014 includes impairment charges of
$572.4 million (pre-tax) and
$40.2 million (pre-tax),
respectively, as well as a derivative gain of $104.1 million (pre-tax) in 2015 and a derivative
gain of $197.4 million (pre-tax) in
2014. Impairment charges in 2015 were primarily the result of a
reduction of future net revenues compared to the carrying value of
the UOP assets.
Net loss for the fourth quarter of 2015 was $21.1 million, or $(0.45) per share, compared with net income for
the fourth quarter of 2014 of $89.1
million, or $1.84 per share.
Adjusted net income (loss) (a non-GAAP measure, see the relevant
reconciliation table below) was $3.4
million, or $0.07 per share,
in the fourth quarter of 2015 compared with a loss of $11.3 million, or $(0.23) per share, in the fourth quarter of 2014.
Adjusted net income (loss) removes the effect of unrealized
derivative gains and losses and non-recurring charges such as
impairment expenses, property sales and certain one-time items.
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
Discretionary Cash
Flow ($ millions)
|
$
|
53.3
|
|
|
$
|
38.9
|
|
|
$
|
206.3
|
|
|
$
|
231.6
|
|
Discretionary Cash
Flow (per share)
|
$
|
1.10
|
|
|
$
|
0.80
|
|
|
$
|
4.27
|
|
|
$
|
4.78
|
|
Adjusted Net Income
(Loss) ($ millions)
|
$
|
3.4
|
|
|
$
|
(11.3)
|
|
|
$
|
(9.4)
|
|
|
$
|
(25.2)
|
|
Adjusted Net Income
(Loss) (per share)
|
$
|
0.07
|
|
|
$
|
(0.23)
|
|
|
$
|
(0.20)
|
|
|
$
|
(0.52)
|
|
At December 31, 2015, the
Company's revolving credit facility had zero drawn and $349.0 million in available capacity, after
taking into account a $26.0 million
letter of credit. The principal balance of long-term debt was
$803.8 million and cash and cash
equivalents were $128.8 million,
resulting in net debt (principal balance of debt outstanding less
the cash and cash equivalents balance) of $675.0 million.
Capital Expenditures
Capital expenditures for 2015 of $287.4
million was 49% lower than 2014 and included drilling 43
gross/39.8 net wells in the DJ Basin, which were primarily XRL
wells operated by the Company, and 15 gross/9.6 net operated wells
drilled in the UOP. Capital expenditures included $264.3 million for drilling and completion
operations, $7.7 million for
leaseholds to expand development programs, and $15.4 million for infrastructure and corporate
purposes.
Capital expenditures for the fourth quarter of 2015 of
$44.8 million included 9 gross/8.0
net wells in the DJ Basin, which were primarily XRL wells operated
by the Company, and 4 gross/2.1 net operated wells drilled in the
UOP. Capital expenditures included $37.3
million for drilling and completion operations, $3.4 million for leaseholds, and $4.1 million for infrastructure and corporate
assets.
|
Three Months Ended
December 31, 2015
|
|
Twelve Months
Ended December 31, 2015
|
|
Average Net
Daily
Production
(Boe/d)
|
|
Wells Spud
Net (1)
|
|
Capital
Expenditures
($ millions)
|
|
Average Net
Daily
Production
(Boe/d)
|
|
Wells Spud
Net (1)
|
|
Capital
Expenditures
($ millions)
|
Basin:
|
|
|
|
|
|
|
|
|
|
|
|
Denver-Julesburg
|
13,837
|
|
|
8
|
|
$
|
36.0
|
|
|
13,082
|
|
|
44
|
|
$
|
250.3
|
|
Uinta
|
4,445
|
|
|
2
|
|
8.3
|
|
|
4,904
|
|
|
12
|
|
34.6
|
|
Other
|
33
|
|
|
—
|
|
0.5
|
|
|
77
|
|
|
—
|
|
2.5
|
|
Total
|
18,315
|
|
|
10
|
|
$
|
44.8
|
|
|
18,063
|
|
|
56
|
|
$
|
287.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Includes operated and
non-operated wells and UOP wells that were drilled, but not
completed
|
OPERATIONAL HIGHLIGHTS
DJ Basin
Fourth quarter DJ Basin highlights include:
- Produced an average of 13,837 Boe/d, an increase of 55% from
the fourth quarter of 2014
- DJ Basin oil volumes averaged 8,263 Bbls/d, an increase of 51%
from the fourth quarter of 2014
- Spud 9.0 gross/8.0 net operated XRL wells during the fourth
quarter of 2015.
- Placed 9.0 gross/8.1 net XRL wells on initial sales during the
fourth quarter of 2015.
- 17 XRL wells are currently in various stages of flowback and
ramping up to a peak oil rate, including two four-well XRL pads and
a ten-well pad that includes 9 XRL wells.
- 16 wells, including 15 XRL wells, are in various stages of
completion and are expected to be placed on initial flowback in
April 2016.
- 8 XRL wells have recently finished drilling and will begin
completion operations beginning in March
2016.
- XRL well drilling days to rig release have been reduced to an
average of approximately 8 days per well, including a best-in-class
well that was drilled in approximately 6.5 days. This represents a
49% improvement from the average of 2014.
- XRL drilling and completion costs of $4.75 million per well are approximately 42%
lower compared to XRL wells drilled in the fourth quarter of
2014.
Uinta Oil Program
Drilling and completion activity in the UOP during the fourth
quarter of 2015 included drilling 4 gross commitment wells.
Operations continue to be focused on improving operational
efficiencies, and associated cost reductions have been realized as
a result of lower lease operating costs.
2016 OPERATING GUIDANCE
The 2016 capital program is designed to align capital
expenditures with expected cash flow as certain drilling activity
may be deferred to protect the Company's liquidity position. This
will result in 2016 production levels being similar to or slightly
higher than 2015 production, pro forma for asset sales, with
planned spending approximately 55% lower than 2015 capital
expenditures. The capital program will be focused on XRL well
development in the DJ Basin with minimal planned expenditures in
the UOP. The Company is well positioned for 2016 having ample
liquidity, a strong hedge position with approximately 65% of its
2016 oil production hedged at $80.47
per barrel of oil, nominal drilling commitments and no long-term
drilling, completion or oil marketing contracts. The Company
intends to fund its capital expenditure program with cash flow from
operations and from its available cash balance.
The Company is providing the following guidance for its 2016
activities. See "Forward-Looking Statements" below.
- Capital expenditures of $100-$150
million
- This is approximately 55% below 2015 spending at the mid-point
and represents a one-rig program for a portion of the year to drill
up to 20 XRL wells in the NE Wattenberg field of the DJ Basin.
- The Company has spud 4 XRL wells since the beginning of the
year and recently released the drilling rig that it was operating
due to low oil prices.
- The low-end of the guidance range assumes that all wells that
have been drilled are completed and placed on production and no new
wells are drilled in 2016, while the high-end of the guidance range
assumes that drilling activity resumes during the second half of
2016.
- Assumes an XRL well cost of approximately $4.75 million.
- First quarter of 2016 capital expenditures are expected to be
approximately $55-$60 million and
includes capital for completions of wells drilled during 2015.
- Production of 5.8-6.2 MMBoe
- Represents a production level that is similar to or slightly
higher than pro forma 2015 sales volumes of 5.9 MMBoe at the
mid-point, which excludes asset divestitures completed during
2015.
- Production is estimated to be approximately 65% oil, 20%
natural gas and 15% NGLs.
- Production is expected to be weighted higher in the second half
of 2016 as current completion and flowback operations on a 16-well
drilling and spacing unit ("DSU"), including 15 XRL wells, and a
8-well DSU, all of which are XRL wells, will contribute to second
half production rates. The Company anticipates that the fourth
quarter of 2016 exit rate will be similar to the fourth quarter of
2015. This also represents an approximate 20-25% increase from the
first quarter of 2016 to the fourth quarter of 2016.
- First quarter of 2016 production is expected to approximate
1.3-1.4 MMBoe, which represents lower sequential production from
the fourth quarter of 2015, in part, due to the sale of non-core
assets that were completed during the quarter.
- Lease operating expense of $33-$36
million, approximately 20% lower than 2015
- Gathering, transportation and processing costs of $3-$5 million
- Unused commitment for firm natural gas transportation charges
of $18-$19 million
- General and administrative expenses of $31-$34 million, which excludes non-cash,
performance-based compensation and other one-time costs,
approximately 25% lower than 2015
COMMODITY HEDGES UPDATE
For 2016, 6,772 barrels per day of oil is hedged at an average
WTI price of $80.47 per barrel and
5,000 MMBtu/d of natural gas is hedged at an average NWPL price of
$4.10 per MMBtu. The current value of
the hedge position is approximately $136
million, as of February 26,
2016.
The following table summarizes hedge positions as of
February 26, 2016:
|
|
Oil
(WTI)
|
|
Natural Gas
(NWPL)
|
Period
|
|
Volume
Bbls/d
|
|
Price
$/Bbl
|
|
Volume
MMBtu/d
|
|
Price
$/MMBtu
|
1Q16
|
|
7,300
|
|
|
$
|
81.65
|
|
|
5,000
|
|
|
$
|
4.10
|
|
2Q16
|
|
7,300
|
|
|
81.65
|
|
|
5,000
|
|
|
4.10
|
|
3Q16
|
|
6,250
|
|
|
79.11
|
|
|
5,000
|
|
|
4.10
|
|
4Q16
|
|
6,250
|
|
|
79.11
|
|
|
5,000
|
|
|
4.10
|
|
1Q17
|
|
2,250
|
|
|
73.88
|
|
|
—
|
|
|
—
|
|
2Q17
|
|
2,250
|
|
|
73.88
|
|
|
—
|
|
|
—
|
|
3Q17
|
|
1,500
|
|
|
78.16
|
|
|
—
|
|
|
—
|
|
4Q17
|
|
1,500
|
|
|
78.16
|
|
|
—
|
|
|
—
|
|
Realized sales prices will reflect basis differentials from the
index prices to the sales location.
UPCOMING EVENTS
Teleconference Call and Webcast
The Company plans to host a conference call on Wednesday,
March 2, 2016, to discuss the results and other items
presented in this press release. The call is scheduled at
10:00 a.m. Eastern time (8:00 a.m. Mountain time). Please join the webcast
conference call live or for replay via the Internet at
www.billbarrettcorp.com, accessible from the home page. To
join by telephone, call 855-760-8152 (631-485-4979 international
callers) with passcode 38878862. The webcast will remain on the
Company's website for approximately 30 days and a replay of the
call will be available through March 9, 2016 at 855-859-2056
(404-537-3406 international) with passcode 38878862.
DISCLOSURE STATEMENTS
Reserve Disclosure
The Company may from time to time provide internally generated
estimates of its probable and possible reserves. These
estimates conform to SPEE methodology but are not prepared or
reviewed by third party engineers. Unless otherwise indicated,
probable and possible reserve estimates are determined using
year-end pricing, as used in the calculation of proved reserves.
Probable and possible reserves are subject to significantly greater
risk of recovery than proved reserves.
Forward-Looking Statements
All statements in this press release, other than statements of
historical fact, may be deemed to be 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.
Words such as expects, forecast, guidance, anticipates, intends,
plans, believes, seeks, estimates and similar expressions or
variations of such words are intended to identify forward-looking
statements herein; however, these are not the exclusive means of
identifying forward-looking statements. In particular, the Company
is providing "2016 Operating Guidance," which contains projections
for certain 2016 operational and financial metrics. Additional
forward-looking statements in this release relate to, among other
things, future capital expenditures, projects and
opportunities.
These and other forward-looking statements in this press release
are based on management's judgment as of the date of this release
and are subject to numerous risks and uncertainties. Actual results
may vary significantly from those indicated in the forward-looking
statements due to, among other things: oil, NGL and natural gas
price volatility, including regional price differentials; changes
in operational and capital plans; changes in capital costs,
operating costs, availability and timing of build-out of third
party facilities for gathering, processing, refining and
transportation; delays or other impediments to drilling and
completing wells arising from political or judicial developments at
the local, state or federal level, including voter initiatives
related to hydraulic fracturing; development drilling and testing
results; the potential for production decline rates to be greater
than expected; regulatory delays, including seasonal or other
wildlife restrictions on federal lands; exploration risks such as
drilling unsuccessful wells; higher than expected costs and
expenses, including the availability and cost of services and
materials, and our potential inability to achieve expected cost
savings; unexpected future capital expenditures; economic and
competitive conditions; debt and equity market conditions,
including the availability and costs of financing to fund the
Company's operations; the ability to obtain industry partners to
jointly explore certain prospects, and the willingness and ability
of those partners to meet capital obligations when requested;
declines in the values of our oil and gas properties resulting in
impairments; changes in estimates of proved reserves; compliance
with environmental and other regulations, including new emission
control requirements; derivative and hedging activities; risks
associated with operating in one major geographic area; the success
of the Company's risk management activities; unexpected obstacles
to closing anticipated transactions or unfavorable purchase price
adjustments; title to properties; litigation; and environmental
liabilities. Please refer to the Company's Annual Report on Form
10-K for the year ended December 31, 2014 filed with the SEC
and for the year 2015 upon filing, and other filings, including our
Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, all
of which are incorporated by reference herein, for further
discussion of risk factors that may affect the forward-looking
statements. The Company encourages you to consider the risks and
uncertainties associated with projections and other forward-looking
statements and to not place undue reliance on any such statements.
In addition, the Company assumes no obligation to publicly revise
or update any forward-looking statements based on future events or
circumstances.
ABOUT BILL BARRETT CORPORATION
Bill Barrett Corporation (NYSE: BBG), headquartered in
Denver, Colorado, develops oil and
natural gas in the Rocky Mountain region of the United States. Additional information
about the Company may be found on its website at
www.billbarrettcorp.com.
BILL BARRETT
CORPORATION
Selected Operating
Highlights
(Unaudited)
|
|
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
Production
Data:
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
1,090
|
|
|
956
|
|
|
4,401
|
|
|
4,012
|
|
Natural gas
(MMcf)
|
1,986
|
|
|
1,794
|
|
|
7,764
|
|
|
21,744
|
|
NGLs
(MBbls)
|
264
|
|
|
146
|
|
|
898
|
|
|
1,476
|
|
Combined volumes
(MBoe)
|
1,685
|
|
|
1,401
|
|
|
6,593
|
|
|
9,112
|
|
Daily combined
volumes (Boe/d)
|
18,315
|
|
|
15,233
|
|
|
18,063
|
|
|
24,964
|
|
|
|
|
|
|
|
|
|
Average Sales Prices
(before the effects of realized hedges):
|
Oil (per
Bbl)
|
$
|
35.57
|
|
|
$
|
58.36
|
|
|
$
|
40.06
|
|
|
$
|
77.92
|
|
Natural gas (per
Mcf)
|
1.98
|
|
|
4.16
|
|
|
2.23
|
|
|
4.78
|
|
NGLs (per
Bbl)
|
11.98
|
|
|
20.16
|
|
|
12.16
|
|
|
31.55
|
|
Combined (per
Boe)
|
27.21
|
|
|
47.26
|
|
|
31.02
|
|
|
50.82
|
|
|
|
|
|
|
|
|
|
Average Realized
Sales Prices (after the effects of realized hedges):
|
Oil (per
Bbl)
|
$
|
78.98
|
|
|
$
|
79.47
|
|
|
$
|
78.19
|
|
|
$
|
79.51
|
|
Natural gas (per
Mcf)
|
3.72
|
|
|
3.88
|
|
|
3.75
|
|
|
4.45
|
|
NGLs (per
Bbl)
|
11.98
|
|
|
21.44
|
|
|
12.16
|
|
|
31.51
|
|
Combined (per
Boe)
|
57.36
|
|
|
61.44
|
|
|
58.27
|
|
|
50.73
|
|
|
|
|
|
|
|
|
|
Average Costs (per
Boe):
|
|
|
|
|
|
|
|
Lease operating
expenses
|
$
|
4.70
|
|
|
$
|
8.52
|
|
|
$
|
6.48
|
|
|
$
|
6.62
|
|
Gathering,
transportation and processing expense
|
0.55
|
|
|
0.86
|
|
|
0.53
|
|
|
3.89
|
|
Production tax
expenses
|
1.29
|
|
|
2.54
|
|
|
1.85
|
|
|
3.44
|
|
Depreciation,
depletion and amortization
|
27.06
|
|
|
33.10
|
|
|
31.14
|
|
|
25.88
|
|
General and
administrative expense, excluding long-term incentive compensation
expense (1)
|
7.03
|
|
|
7.55
|
|
|
6.53
|
|
|
4.61
|
|
|
|
(1)
|
This separate
presentation is a non-GAAP (Generally Accepted Accounting
Principles) measure. Management believes the separate presentation
of the long-term incentive compensation component of general and
administrative expense is useful because it provides a better
understanding of current period general and administrative
expenses. Management also believes that this disclosure may allow
for a more accurate comparison to the Company's peers, which may
have higher or lower stock-based/long-term incentive compensation
expense.
|
BILL BARRETT
CORPORATION
Consolidated
Condensed Balance Sheets
(Unaudited)
|
|
|
As of
December 31,
|
|
As
of
December
31,
|
|
2015
|
|
2014
|
|
(in
thousands)
|
Assets:
|
|
|
|
Cash and cash
equivalents
|
$
|
128,836
|
|
|
$
|
165,904
|
|
Other current assets
(1)
|
145,481
|
|
|
260,201
|
|
Property and
equipment, net
|
1,170,684
|
|
|
1,753,121
|
|
Other noncurrent
assets (1)
|
70,228
|
|
|
65,258
|
|
Total
assets
|
$
|
1,515,229
|
|
|
$
|
2,244,484
|
|
|
|
|
|
Liabilities and
Stockholders' Equity:
|
|
|
|
Current liabilities,
other
|
$
|
144,791
|
|
|
$
|
238,917
|
|
Current liabilities,
convertible senior notes
|
—
|
|
|
25,344
|
|
Capitalized lease
obligation
|
3,222
|
|
|
3,648
|
|
Senior
notes
|
800,579
|
|
|
800,000
|
|
Other long-term
liabilities
|
17,221
|
|
|
147,087
|
|
Stockholders'
equity
|
549,416
|
|
|
1,029,488
|
|
Total liabilities and
stockholders' equity
|
$
|
1,515,229
|
|
|
$
|
2,244,484
|
|
|
|
(1)
|
At December 31,
2015, the estimated fair value of all of the Company's commodity
derivative instruments was a net asset of $119.5 million, comprised
of $99.8 million of current assets and $19.7 million of non-current
assets. This amount will fluctuate based on estimated future
commodity prices and the current hedge position.
|
BILL BARRETT
CORPORATION
Consolidated
Statements of Operations
(Unaudited)
|
|
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
(in thousands,
except per share amounts)
|
Operating and Other
Revenues:
|
|
|
|
|
|
|
|
Oil, gas and NGLs
(1)
|
$
|
45,870
|
|
|
$
|
66,406
|
|
|
$
|
204,537
|
|
|
$
|
464,137
|
|
Other
|
691
|
|
|
496
|
|
|
3,355
|
|
|
8,154
|
|
Total operating and
other revenues
|
46,561
|
|
|
66,902
|
|
|
207,892
|
|
|
472,291
|
|
Operating
Expenses:
|
|
|
|
|
|
|
|
Lease
operating
|
7,919
|
|
|
11,941
|
|
|
42,753
|
|
|
60,308
|
|
Gathering,
transportation and processing
|
923
|
|
|
1,199
|
|
|
3,482
|
|
|
35,437
|
|
Production
tax
|
2,177
|
|
|
3,563
|
|
|
12,197
|
|
|
31,333
|
|
Exploration
|
8
|
|
|
11
|
|
|
153
|
|
|
453
|
|
Impairment, dry hole
costs and abandonment
|
314
|
|
|
14,268
|
|
|
575,310
|
|
|
46,881
|
|
(Gain) Loss on
divestitures
|
2,504
|
|
|
3,511
|
|
|
1,745
|
|
|
100,407
|
|
Depreciation,
depletion and amortization
|
45,609
|
|
|
46,379
|
|
|
205,275
|
|
|
235,805
|
|
Unused
commitments
|
5,936
|
|
|
4,434
|
|
|
19,099
|
|
|
4,434
|
|
General and
administrative (2)
|
11,850
|
|
|
10,573
|
|
|
43,050
|
|
|
41,981
|
|
Long-term incentive
compensation (2)
|
3,014
|
|
|
1,749
|
|
|
10,840
|
|
|
11,380
|
|
Total operating
expenses
|
80,254
|
|
|
97,628
|
|
|
913,904
|
|
|
568,419
|
|
Operating Income
(Loss)
|
(33,693)
|
|
|
(30,726)
|
|
|
(706,012)
|
|
|
(96,128)
|
|
Other Income and
Expense:
|
|
|
|
|
|
|
|
Interest and other
income
|
46
|
|
|
303
|
|
|
565
|
|
|
1,294
|
|
Interest
expense
|
(15,731)
|
|
|
(16,338)
|
|
|
(65,305)
|
|
|
(69,623)
|
|
Commodity derivative
gain (loss) (1)
|
28,233
|
|
|
197,078
|
|
|
104,147
|
|
|
197,447
|
|
Gain (loss) on
extinguishment of debt
|
—
|
|
|
—
|
|
|
1,749
|
|
|
—
|
|
Total other income
and expense
|
12,548
|
|
|
181,043
|
|
|
41,156
|
|
|
129,118
|
|
Income (Loss) before
Income Taxes
|
(21,145)
|
|
|
150,317
|
|
|
(664,856)
|
|
|
32,990
|
|
(Provision for)
Benefit from Income Taxes
|
—
|
|
|
(61,252)
|
|
|
177,085
|
|
|
(17,909)
|
|
Net Income
(Loss)
|
$
|
(21,145)
|
|
|
$
|
89,065
|
|
|
$
|
(487,771)
|
|
|
$
|
15,081
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) per
Common Share
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.45)
|
|
|
$
|
1.85
|
|
|
$
|
(10.10)
|
|
|
$
|
0.31
|
|
Diluted
|
$
|
(0.45)
|
|
|
$
|
1.84
|
|
|
$
|
(10.10)
|
|
|
$
|
0.31
|
|
Weighted Average
Common Shares Outstanding
|
|
|
|
|
|
|
|
Basic
|
48,373
|
|
|
48,093
|
|
|
48,303
|
|
|
48,011
|
|
Diluted
|
48,373
|
|
|
48,329
|
|
|
48,303
|
|
|
48,436
|
|
|
(1) The table below
summarizes the realized and unrealized gains and losses the Company
recognized related to its oil and natural gas derivative
instruments for the periods indicated:
|
|
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
(in
thousands)
|
Included in oil, gas
and NGL production revenue:
|
|
|
|
|
|
|
|
Certain realized
gains on hedges
|
$
|
—
|
|
|
$
|
181
|
|
|
$
|
—
|
|
|
$
|
1,070
|
|
Included in commodity
derivative gain (loss):
|
|
|
|
|
|
|
|
Realized gain (loss)
on derivatives not designated as cash flow hedges
|
$
|
50,818
|
|
|
$
|
19,692
|
|
|
$
|
179,652
|
|
|
$
|
(1,888)
|
|
Prior period
unrealized (gain) loss transferred to realized (gain)
loss
|
(46,681)
|
|
|
(2,905)
|
|
|
(145,226)
|
|
|
6,706
|
|
Unrealized gain
(loss) on derivatives not designated as cash flow hedges
|
24,096
|
|
|
180,291
|
|
|
69,721
|
|
|
192,629
|
|
Total commodity
derivative gain (loss)
|
$
|
28,233
|
|
|
$
|
197,078
|
|
|
$
|
104,147
|
|
|
$
|
197,447
|
|
|
|
(2)
|
This separate
presentation is a non-GAAP (Generally Accepted Accounting
Principles) measure. Management believes the separate presentation
of the long-term incentive compensation component of general and
administrative expense is useful because it provides a better
understanding of current period general and administrative
expenses. Management also believes that this disclosure may allow
for a more accurate comparison to the Company's peers, which may
have higher or lower stock-based/long-term incentive compensation
expense.
|
BILL BARRETT
CORPORATION
Consolidated
Statements of Cash Flows
(Unaudited)
|
|
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
(in
thousands)
|
Operating
Activities:
|
|
|
|
|
|
|
|
Net income
(loss)
|
$
|
(21,145)
|
|
|
$
|
89,065
|
|
|
$
|
(487,771)
|
|
|
$
|
15,081
|
|
Adjustments to
reconcile to net cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
45,609
|
|
|
46,379
|
|
|
205,275
|
|
|
235,805
|
|
Impairment, dry hole
costs and abandonment expense
|
314
|
|
|
14,268
|
|
|
575,310
|
|
|
46,881
|
|
Unrealized derivative
(gain) loss, non-cash flow hedges
|
22,585
|
|
|
(177,386)
|
|
|
75,505
|
|
|
(199,335)
|
|
Deferred income tax
benefit
|
—
|
|
|
60,248
|
|
|
(176,797)
|
|
|
16,644
|
|
Incentive
compensation and other non-cash charges
|
2,759
|
|
|
1,701
|
|
|
10,040
|
|
|
11,352
|
|
Amortization of debt
discounts and deferred financing costs
|
641
|
|
|
1,064
|
|
|
4,624
|
|
|
4,264
|
|
(Gain) loss on sale
of properties
|
2,504
|
|
|
3,511
|
|
|
1,745
|
|
|
100,407
|
|
(Gain) loss on
extinguishment of debt
|
—
|
|
|
—
|
|
|
(1,749)
|
|
|
—
|
|
Change in operating
assets and liabilities:
|
|
|
|
|
|
|
|
Accounts
receivable
|
601
|
|
|
23,138
|
|
|
20,995
|
|
|
32,163
|
|
Prepayments and other
assets
|
572
|
|
|
729
|
|
|
311
|
|
|
1,643
|
|
Accounts payable,
accrued and other liabilities
|
(23,145)
|
|
|
(15,604)
|
|
|
(18,798)
|
|
|
5,119
|
|
Amounts payable to
oil and gas property owners
|
(2,680)
|
|
|
(9,068)
|
|
|
(3,530)
|
|
|
(7,132)
|
|
Production taxes
payable
|
(838)
|
|
|
(7,630)
|
|
|
(11,482)
|
|
|
(1,175)
|
|
Net cash provided by
(used in) operating activities
|
$
|
27,777
|
|
|
$
|
30,415
|
|
|
$
|
193,678
|
|
|
$
|
261,717
|
|
Investing
Activities:
|
|
|
|
|
|
|
|
Additions to oil and
gas properties, including acquisitions
|
(68,475)
|
|
|
(154,965)
|
|
|
(324,534)
|
|
|
(580,943)
|
|
Additions of
furniture, equipment and other
|
(187)
|
|
|
(1,548)
|
|
|
(1,223)
|
|
|
(3,658)
|
|
Proceeds from sale of
properties and other investing activities
|
56,505
|
|
|
(2,451)
|
|
|
123,122
|
|
|
555,296
|
|
Proceeds from the
sale of short-term investments
|
20,000
|
|
|
—
|
|
|
115,000
|
|
|
—
|
|
Cash paid for
short-term investments
|
—
|
|
|
—
|
|
|
(114,883)
|
|
|
—
|
|
Net cash provided by
(used in) investing activities
|
$
|
7,843
|
|
|
$
|
(158,964)
|
|
|
$
|
(202,518)
|
|
|
$
|
(29,305)
|
|
Financing
Activities:
|
|
|
|
|
|
|
|
Proceeds from
debt
|
—
|
|
|
—
|
|
|
—
|
|
|
165,000
|
|
Principal payments on
debt
|
(108)
|
|
|
(104)
|
|
|
(25,191)
|
|
|
(283,546)
|
|
Deferred financing
costs and other
|
488
|
|
|
(221)
|
|
|
(3,037)
|
|
|
(2,683)
|
|
Proceeds from stock
option exercises
|
—
|
|
|
—
|
|
|
—
|
|
|
126
|
|
Net cash provided by
(used in) financing activities
|
$
|
380
|
|
|
$
|
(325)
|
|
|
$
|
(28,228)
|
|
|
$
|
(121,103)
|
|
Increase (Decrease)
in Cash and Cash Equivalents
|
36,000
|
|
|
(128,874)
|
|
|
(37,068)
|
|
|
111,309
|
|
Beginning Cash and
Cash Equivalents
|
92,836
|
|
|
294,778
|
|
|
165,904
|
|
|
54,595
|
|
Ending Cash and Cash
Equivalents
|
$
|
128,836
|
|
|
$
|
165,904
|
|
|
$
|
128,836
|
|
|
$
|
165,904
|
|
BILL BARRETT
CORPORATION
Reconciliation of
Discretionary Cash Flow, Adjusted Net Income (Loss) and Pre-tax
PV10
(Unaudited)
|
|
Discretionary Cash
Flow Reconciliation
|
|
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
(in thousands,
except per share amounts)
|
Net Income
(Loss)
|
$
|
(21,145)
|
|
|
$
|
89,065
|
|
|
$
|
(487,771)
|
|
|
$
|
15,081
|
|
Adjustments to
reconcile to discretionary cash flow:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
45,609
|
|
|
46,379
|
|
|
205,275
|
|
|
235,805
|
|
Impairment, dry hole
and abandonment expense
|
314
|
|
|
14,268
|
|
|
575,310
|
|
|
46,881
|
|
Exploration
expense
|
8
|
|
|
11
|
|
|
153
|
|
|
453
|
|
Unrealized derivative
(gain) loss, non-cash flow hedges
|
22,585
|
|
|
(177,386)
|
|
|
75,505
|
|
|
(199,335)
|
|
Deferred income
taxes
|
—
|
|
|
60,248
|
|
|
(176,797)
|
|
|
16,644
|
|
Stock compensation
and other non-cash charges
|
2,759
|
|
|
1,701
|
|
|
10,040
|
|
|
11,352
|
|
Amortization of debt
discounts and deferred financing costs
|
641
|
|
|
1,064
|
|
|
4,624
|
|
|
4,264
|
|
(Gain) loss on sale
of properties
|
2,504
|
|
|
3,511
|
|
|
1,745
|
|
|
100,407
|
|
(Gain) loss on
extinguishment of debt
|
—
|
|
|
—
|
|
|
(1,749)
|
|
|
—
|
|
Discretionary Cash
Flow
|
$
|
53,275
|
|
|
$
|
38,861
|
|
|
$
|
206,335
|
|
|
$
|
231,552
|
|
Per share,
diluted
|
$
|
1.10
|
|
|
$
|
0.80
|
|
|
$
|
4.27
|
|
|
$
|
4.78
|
|
Per Boe
|
$
|
31.60
|
|
|
$
|
27.74
|
|
|
$
|
31.30
|
|
|
$
|
25.41
|
|
|
Adjusted Net
Income (Loss) Reconciliation
|
|
|
Three Months
Ended
December 31,
|
|
Twelve Months
Ended
December 31,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
(in thousands,
except per share amounts)
|
Net Income
(Loss)
|
$
|
(21,145)
|
|
|
$
|
89,065
|
|
|
$
|
(487,771)
|
|
|
$
|
15,081
|
|
(Provision
for) Benefit from income taxes
|
—
|
|
|
(61,252)
|
|
|
177,085
|
|
|
(17,909)
|
|
Income (Loss) before
income taxes
|
(21,145)
|
|
|
150,317
|
|
|
(664,856)
|
|
|
32,990
|
|
Adjustments to net
income (loss):
|
|
|
|
|
|
|
|
Unrealized derivative
(gain) loss, non-cash flow hedges
|
22,585
|
|
|
(177,386)
|
|
|
75,505
|
|
|
(199,335)
|
|
Impairment
expense
|
72
|
|
|
12,062
|
|
|
572,438
|
|
|
40,183
|
|
(Gain) loss on sale
of properties
|
2,504
|
|
|
3,511
|
|
|
1,745
|
|
|
100,407
|
|
(Gain) loss on
extinguishment of debt
|
—
|
|
|
—
|
|
|
(1,749)
|
|
|
—
|
|
One-time
items:
|
|
|
|
|
|
|
|
CO2 unused
commitment
|
1,429
|
|
|
—
|
|
|
1,429
|
|
|
—
|
|
West Tavaputs NGL
processing true-up
|
(268)
|
|
|
—
|
|
|
(1,273)
|
|
|
(5,677)
|
|
Expenses (credit)
relating to compressor station fire
|
—
|
|
|
—
|
|
|
—
|
|
|
(570)
|
|
Expenses relating to
amending credit facility
|
—
|
|
|
—
|
|
|
1,617
|
|
|
—
|
|
Adjusted Income
(Loss) before income taxes
|
5,177
|
|
|
(11,496)
|
|
|
(15,144)
|
|
|
(32,002)
|
|
(Provision for) Benefit from income
taxes
|
(1,804)
|
|
|
237
|
|
|
5,714
|
|
|
6,787
|
|
Adjusted Net Income
(Loss)
|
$
|
3,373
|
|
|
$
|
(11,259)
|
|
|
$
|
(9,430)
|
|
|
$
|
(25,215)
|
|
Per share,
diluted
|
$
|
0.07
|
|
|
$
|
(0.23)
|
|
|
$
|
(0.20)
|
|
|
$
|
(0.52)
|
|
Per Boe
|
$
|
2.00
|
|
|
$
|
(8.04)
|
|
|
$
|
(1.43)
|
|
|
$
|
(2.77)
|
|
Discretionary cash flow and adjusted net income (loss) are
non-GAAP measures. These measures are presented because management
believes that they provide useful additional information to
investors for analysis of the Company's ability to internally
generate funds for exploration, development and acquisitions as
well as adjusting net income (loss) for one-time or unusual items
to allow for a more consistent comparison from period to period. In
addition, the Company believes that these measures are widely used
by professional research analysts and others in the valuation,
comparison and investment recommendations of companies in the oil
and gas exploration and production industry, and that many
investors use the published research of industry research analysts
in making investment decisions.
These measures should not be considered in isolation or as a
substitute for net income, income from operations, net cash
provided by operating activities or other income, profitability,
cash flow or liquidity measures prepared in accordance with GAAP.
Because discretionary cash flow and adjusted net income (loss)
exclude some, but not necessarily all, items that affect net income
(loss) and may vary among companies, the amounts presented may not
be comparable to similarly titled measures of other companies.
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SOURCE Bill Barrett Corporation