DENVER, Aug. 6, 2015 /PRNewswire/ -- Bill Barrett
Corporation (the "Company") (NYSE: BBG) reports second quarter of
2015 results, including these highlights:
- Sales volumes grew to 1.6 MMBoe, exceeding guidance by 9% due
to solid execution of the DJ Basin drilling program
- Increased DJ Basin production by 76% year-over-year and 8%
sequentially
- Increasing full-year 2015 production guidance to 6.1-6.5 MMBoe,
represents 23% growth over 2014 utilizing the mid-point of the
guidance range
- Generated $1.06 per share
discretionary cash flow
- Maintain strong liquidity of $450
million with zero drawn on credit facility and cash and
short-term investments of $101
million
Chief Executive Officer and President Scot Woodall commented, "I am pleased with the
results of the second quarter as we executed on all phases of our
strategic plan and delivered very solid results. Our entire
organization is focused on achieving our operational objectives and
this can be seen in second quarter production volumes that exceeded
our forecast by 9%. Importantly, DJ Basin and Uinta Oil Program
("UOP") production for the first half of 2015 surpassed our initial
forecasted guidance by over 10% and was 35% higher compared 2014.
Our excellent performance through the first half of the year allows
us to increase full year 2015 production guidance for the third
time, which at the mid-point represents 23% growth over 2014,
excluding asset sales, and is 11% greater than the mid-point of our
initial forecasted guidance. Our drilling results continue to
reflect the quality of our DJ Basin assets and positions us to
achieve our goals for the remainder of the year while providing a
strong foundation heading into 2016.
"We are encouraged by the early production data we are seeing
from our extended reach lateral ("XRL") program and our preferred
completion technique1 is proving to be the most
effective and efficient method to develop our asset as evidenced by
the improving production data we are reporting. We continue
implementing technological refinements and enhancements to our
drilling and completion process in an effort to optimize well
results and further enhance operational efficiencies to improve
economic returns. Specifically, we are making significant strides
in increasing drilling efficiency as we have reduced recent XRL
well drilling days by approximately 40% compared to earlier XRL
program wells. Our core Northeast ("NE") Wattenberg acreage
provides a competitive advantage as more than 80% of our acreage is
expected to be developed with XRL wells that we project provide
acceptable rates of return at the current commodity price
strip.
"We maintain a strong financial position in the challenging
macro-economic environment that we are presently navigating. We
enter the second half of the year with an undrawn revolving credit
facility and $101 million in cash and
short-term investments that provide ample liquidity. In addition,
approximately 80% of our expected second half of 2015 production
volumes and approximately 40% of 2016 production volumes are hedged
at very favorable commodity prices. We remain capital
disciplined, financially responsible and operationally flexible as
we preserve the strength of our balance sheet."
SECOND QUARTER 2015 OPERATING AND FINANCIAL
RESULTS
(Prior year period results are pro forma for assets
sold.)
The Company realized substantial growth in production from its
core DJ Basin asset, driven by strong NE Wattenberg XRL well
results that offset a production decline from the UOP. Oil, natural
gas and natural gas liquids ("NGL") production from the DJ Basin
and UOP totaled 1.6 million barrels of oil equivalent ("MMBoe") in
the second quarter of 2015 compared with 1.3 MMBoe in the second
quarter of 2014. DJ Basin production grew 76% while UOP production
was down 21%. The decline in UOP production was primarily due to a
decrease in drilling and workover activity, as the Company is
focusing the majority of its 2015 capital program on its
higher-return DJ Basin assets. NGL production was greater compared
to the first quarter of 2015 and second quarter of 2014 due to
greater processing yields. Second quarter of 2015 production was
69% oil, 18% natural gas and 13% NGLs.
|
|
Three Months
Ended
June 30,
|
|
Three Months Ended
March 31,
|
|
|
2015
|
2014
|
Change
|
|
2015
|
Change
|
Production
Data:
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
1,120
|
858
|
31%
|
|
1,125
|
0%
|
|
Natural gas
(MMcf)
|
1,800
|
1,650
|
9%
|
|
1,764
|
2%
|
|
NGLs
(MBbls)
|
208
|
132
|
58%
|
|
162
|
28%
|
|
Combined volumes
(MBoe)
|
1,628
|
1,265
|
29%
|
|
1,581
|
3%
|
|
Daily combined
volumes (Boe/d)
|
17,890
|
13,901
|
29%
|
|
17,567
|
2%
|
|
Pre-hedge commodity prices were down significantly compared with
2014. For the second quarter of 2015, approximately 92% of oil
production and 96% of natural gas production benefited from
commodity derivative swaps that averaged $90.39 per barrel of oil (WTI) and $4.13 per MMBtu of natural gas (regionally priced
at NWPL). The Company had no NGL hedges in place.
|
|
Three Months
Ended
June 30,
|
|
Three Months Ended
March 31,
|
|
|
2015
Pre-
hedge
|
2015
Including
hedge
|
2014
Pre-
hedge
|
|
2015
Pre-
hedge
|
2015
Including
hedge
|
Average Sales
Prices:
|
|
|
|
|
|
|
|
Oil (per
Bbl)
|
$ 48.68
|
$ 78.44
|
$ 85.76
|
|
$ 37.12
|
$ 76.28
|
|
Natural gas (per
Mcf)
|
2.33
|
4.10
|
4.86
|
|
2.60
|
3.92
|
|
NGLs (per
Bbl)
|
12.76
|
12.76
|
23.91
|
|
13.31
|
13.31
|
|
Combined (per
Boe)
|
37.70
|
60.13
|
67.05
|
|
30.68
|
60.01
|
|
Cash operating costs (lease operating expense, gathering,
transportation and processing costs and production tax expense)
were $9.92 per Boe in the second
quarter of 2015, down 9% compared to the first quarter of
2015. This was primarily a result of increased efficiencies,
lease operating cost reductions across both basins, and the
Company's decision to proactively reduce workover activity in the
UOP and to shut-in certain UOP wells in the current commodity price
environment due to higher operating costs. The DJ Basin has lower
per unit lease operating costs than the UOP and averaged
$5.84 per Boe in the second quarter
of 2015. Production tax expense for the second quarter of 2015
averaged 6.2% of pre-hedge revenue. Normalized production taxes are
expected to approximate 8% of pre-hedge revenue for the remainder
of the year.
|
|
Three Months
Ended
June 30,
|
|
Three Months Ended
March 31,
|
|
|
2015
|
2014
|
Change
|
|
2015
|
Change
|
Average Costs (per
Boe):
|
|
|
|
|
|
|
|
Leasing operating
expenses
|
$ 7.01
|
$ 8.13
|
-14%
|
|
$ 8.72
|
-20%
|
|
Gathering,
transportation and processing
expense
|
0.57
|
1.18
|
-52%
|
|
0.60
|
-5%
|
|
Production tax
expenses
|
2.34
|
5.23
|
-55%
|
|
1.60
|
46%
|
|
Depreciation,
depletion and amortization
|
32.36
|
33.40
|
-3%
|
|
33.05
|
-2%
|
|
Corporate Discretionary Cash Flow and Adjusted Net
Loss
(Prior period totals are total company results and are
not pro forma for assets sold.)
Discretionary cash flow and adjusted net loss are non-GAAP
measures. These measures are reconciled to net income (loss) in the
schedule attached to this press release. Discretionary cash flow
and adjusted net income as previously reported for the 2014 period
includes cash flow and income generated from assets sold over the
past two years.
Discretionary cash flow in the second quarter of 2015 was
$51.4 million, or $1.06 per share, down from $67.3 million, or $1.40 per share, in the second quarter of 2014.
Discretionary cash flow in the second quarter of 2015 compared to
2014 was impacted by lower revenues due to a 38% decline in
production volumes as a result of asset sales.
Net loss for the second quarter of 2015 was ($44.6) million, or ($0.92) per share, compared with the second
quarter of 2014 at ($26.6) million,
or ($0.55) per share. Adjusted net
loss was ($4.0) million, or
($0.08) per share, in the second
quarter of 2015 compared with ($8.6)
million, or ($0.18) per share,
in the second quarter of 2014. Adjusted net income (loss) removes
the effect of unrealized derivative gains and losses and
non-recurring charges such as impairment expenses, property sales
and certain one-time items.
|
Three Months
Ended
June 30,
|
|
2015
|
2014
|
Discretionary Cash
Flow ($ millions)
|
$ 51.4
|
$ 67.3
|
Discretionary Cash
Flow per share
|
1.06
|
1.40
|
|
|
|
Adjusted Net Loss ($
millions)
|
(4.0)
|
(8.6)
|
Adjusted Net Loss per
share
|
(0.08)
|
(0.18)
|
|
Debt & Liquidity
At June 30, 2015, the Company's
revolving credit facility had a $375.0
million borrowing base with 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
$803.0 million and cash and
short-term investments were $100.8
million, resulting in net debt (principal balance of debt
outstanding less the cash and investment balance) of $702.2 million. Liquidity was $449.8 million.
In addition, as of August 6, 2015,
the Company has not issued any shares under its previously
announced "at-the-market" equity offering program.
Capital Expenditures
Capital expenditures ("Capex") for the second quarter of 2015
were $65.1 million, which was 19%
below guidance of $80 million
primarily due to the timing of drilling and completion activities
in the DJ Basin. Capex included 13 gross/9 net wells in the DJ
Basin, of which, 7 gross/7 net were XRL wells operated by the
Company. In the second quarter, 10 gross/9 net XRL wells began
initial flowback operations and were placed on sales. These
wells are expected to reach peak initial production in the fourth
quarter of 2015. Capital expenditures included $59.6 million for drilling, $1.8 million for leaseholds, and $3.7 million for infrastructure and corporate
assets.
Basin Summary
|
|
Three Months
Ended
June 30,
2015
|
|
Six Months
Ended
June 30,
2015
|
|
|
Average Net Daily
Production (Boe/d)
|
Wells Spud
Net(1)
|
Capital
Expenditures
($ millions)
|
|
Average Net Daily
Production (Boe/d)
|
Wells Spud
Net(1)
|
Capital
Expenditures
($ millions)
|
Basin:
|
|
|
|
|
|
|
|
|
Denver-Julesburg
|
12,527
|
9
|
$ 58.9
|
|
12,105
|
22
|
$ 158.6
|
|
Uinta
|
5,330
|
2
|
6.2
|
|
5,503
|
4
|
19.1
|
|
Other(2)
|
33
|
0
|
0
|
|
121
|
0
|
1.8
|
|
|
|
|
|
|
|
|
|
|
|
17,890
|
11
|
$ 65.1
|
|
17,729
|
26
|
$ 179.5
|
|
|
(1)
|
Includes operated and
non-operated wells
|
(2)
|
Primarily
non-operated production in Wyoming and New Mexico
|
OPERATIONAL HIGHLIGHTS
DJ Basin
Second quarter DJ Basin highlights include:
- Produced an average of 12,527 Boe/d, up 76% from the second
quarter of 2014 and up 8% sequentially.
- Drilled 7 gross/7 net operated XRL wells.
- Increased operational efficiency by reducing the number of
drilling days for the most recent seven XRL wells by 40%. The most
recent pad averaged 10 days per well, including a best-in-class
well drilled in 8 days.
- Maintained cost discipline as contracted NE Wattenberg XRL
drilling and completion costs of $6.25
million are approximately 25% lower compared to wells
drilled in the fourth quarter of 2014.
- Placed 10 gross/9 net XRL wells on initial sales with 30-day
peak initial production ("IP") rates (see Disclosure section below)
expected to be reached in the fourth quarter of 2015. Subsequent to
the end of the quarter, an additional 4 gross/4 net XRL wells were
placed on initial sales in July
2015.
- Continued implementing and improving preferred completion
technology and mechanics for XRL wells that includes a combination
of plug-and-perf stimulation, approximately 1,000 pounds of
proppant per foot, 55-stage completions and controlled flowback,
yielding improved early well performance and a shallower initial
production decline compared to prior completion practices.
- The four initial XRL wells utilizing the preferred completion
technology had an average 30-day peak IP rate of 649 Boe/d, a
60-day average IP rate of 615 Boe/d and a 90-day average IP rate of
580 Boe/d.
The NE Wattenberg XRL program remains the focus of the 2015
operating plan as it offers the best returns in the Company's
portfolio. Approximately 90% of the 2015 capital expenditures
are planned for the NE Wattenberg area.
Uinta Oil Program
Drilling and completion activity in the UOP has been
significantly reduced to only include several commitment wells as
the Company has elected to focus the majority of its 2015 capital
program on its higher-return DJ Basin assets. Operations are
focused on cost efficiencies, and reductions have been realized as
a result of lower lease operating costs following the Company's
decision to proactively reduce workover activity in the UOP and to
shut-in certain UOP wells in the current commodity price
environment.
2015 OPERATING GUIDANCE
The Company's 2015 plan is expected to result in approximately
23% pro forma production growth from core assets at the mid-point
of guidance, with approximately 25% growth in oil volumes. The
Company anticipates drilling 35-40 gross (28-32 net) wells in the
NE Wattenberg area during 2015, most of which are XRL wells, and to
participate in approximately 5 net non-operated DJ Basin wells.
The Company is providing the following updated guidance for its
2015 activities. See "Forward-Looking Statements" below.
- Capital expenditures of $320-$350
million, unchanged.
- Includes the addition of a second drilling rig in NE Wattenberg
that began operating in June
2015.
- The level of capital expenditures between the third and the
fourth quarter of 2015 will depend on the timing of completion
activities that are scheduled to begin in the third quarter of
2015.
- Production of 6.1-6.5 MMBoe, increased from 6.0-6.4
MMBoe.
- The mid-point of guidance represents 23% annual production
growth over 2014, pro forma for asset sales, and is 11% greater
than initial forecasted guidance.
- The increase is primarily due to continued strong well
performance from the DJ Basin drilling program.
- Production is expected to be approximately 70% oil, 20% natural
gas and 10% NGLs.
- Third quarter 2015 production is expected to be approximately
1.5 MMBoe.
COMMODITY HEDGES UPDATE
Generally, it is the Company's strategy to hedge 50%-70% of
production on a forward 12-month basis to reduce the risks
associated with unpredictable future commodity prices to provide
certainty for a portion of its cash flow and to support its capital
expenditure program. The Company has hedges in place for
approximately 80% of its remaining forecasted 2015
production.
The following table summarizes hedge positions as of
August 6, 2015:
|
Oil
(WTI)
|
|
Natural Gas
(NWPL)
|
|
|
|
|
|
|
Period
|
Volume
Bbls/d
|
Price
$/Bbl
|
|
Volume
MMBtu/d
|
Price
$/MMBtu
|
|
|
|
|
|
|
3Q15
|
10,800
|
89.81
|
|
20,000
|
4.13
|
4Q15
|
10,800
|
89.81
|
|
20,000
|
4.13
|
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
Second Quarter Conference Call and Webcast
The Company plans to host a conference call on Friday, August 7, 2015, to discuss results and
management's outlook for the future (not part of this earnings
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
80924651. The webcast will remain on the Company's website for
approximately 30 days and a replay of the call will be available
through August 14, 2015 at
855-859-2056 (404-537-3406 international) with passcode
80924651.
DISCLOSURE STATEMENTS
Well Performance
The calculation of 30-day IP rates averages the daily production
for the 30 days following the date upon which the Company
determines the well has achieved peak production. This date
may occur several days or weeks after oil production commences. In
calculating the IP rate of a well over a specified period of time,
the calculation will exclude days on which production is impaired
for mechanical, third party mid-stream or other non-geologic
reasons. IP rates and other initial indications of well performance
do not necessarily reflect expected ultimate recoveries or other
long-term measures of a well's performance. Peer data may not be
comparable to results reported by the Company.
Forward-Looking Statements
All statements in this press release, other than historical
financial information, 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 "2015 Operating Guidance," which contains projections
for certain 2015 operational and financial metrics as well as
certain projections for the third quarter of 2015.
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; 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; 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 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
www.billbarrettcorp.com.
BILL BARRETT
CORPORATION
|
Selected Operating
Highlights
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Six Months
Ended
|
|
|
|
|
June
30,
|
|
June
30,
|
|
|
|
|
2015
|
2014 (1)
|
|
2015
|
2014 (1)
|
Production
Data:
|
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
|
|
1,120
|
1,026
|
|
2,245
|
1,948
|
|
Natural gas
(MMcf)
|
|
|
1,800
|
6,696
|
|
3,558
|
13,116
|
|
NGLs
(MBbls)
|
|
|
208
|
480
|
|
371
|
922
|
|
Combined volumes
(MBoe)
|
|
|
1,628
|
2,622
|
|
3,209
|
5,056
|
|
Daily combined
volumes (Boe/d)
|
|
|
17,890
|
28,813
|
|
17,729
|
27,934
|
Average Sales Prices
(before the effects of realized hedges):
|
|
|
|
|
|
|
|
|
Oil (per
Bbl)
|
|
|
$ 48.68
|
$ 86.64
|
|
$ 42.89
|
$ 84.73
|
|
Natural gas (per
Mcf)
|
|
|
2.33
|
4.74
|
|
2.46
|
5.14
|
|
NGLs (per
Bbl)
|
|
|
12.76
|
31.64
|
|
13.00
|
32.87
|
|
Combined (per
Boe)
|
|
|
37.70
|
51.80
|
|
34.24
|
51.98
|
Average Realized
Sales Prices (after the effects of realized hedges):
|
|
|
|
|
|
|
|
|
Oil (per
Bbl)
|
|
|
$ 78.44
|
$ 79.69
|
|
$ 77.35
|
$ 79.26
|
|
Natural gas (per
Mcf)
|
|
|
4.10
|
4.46
|
|
4.01
|
4.62
|
|
NGLs (per
Bbl)
|
|
|
12.76
|
31.75
|
|
13.00
|
32.35
|
|
Combined (per
Boe)
|
|
|
60.13
|
48.39
|
|
60.07
|
48.43
|
Average Costs (per
Boe):
|
|
|
|
|
|
|
|
|
Lease operating
expense
|
|
|
$ 7.01
|
$ 6.07
|
|
$ 7.85
|
$ 6.35
|
|
Gathering,
transportation and processing expense
|
|
|
0.57
|
4.48
|
|
0.58
|
4.64
|
|
Production tax
expense
|
|
|
2.34
|
3.68
|
|
1.98
|
3.42
|
|
Depreciation,
depletion and amortization
|
|
|
32.36
|
24.75
|
|
32.70
|
23.81
|
|
General and administrative
expense, excluding long-term incentive compensation
expense
|
|
(2)
|
7.31
|
4.58
|
|
6.91
|
4.71
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 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
|
|
As
of
|
|
|
|
|
|
|
June 30,
2015
|
|
December 31,
2014
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
|
$
35,882
|
|
$
165,904
|
|
Short-term
investments
|
|
|
64,963
|
|
-
|
|
Other current
assets
|
|
|
(1)
|
142,602
|
|
260,201
|
|
Property and
equipment, net
|
|
|
1,802,869
|
|
1,753,121
|
|
Other noncurrent
assets
|
|
(1)
|
41,385
|
|
65,258
|
|
|
Total
assets
|
|
|
$
2,087,701
|
|
$
2,244,484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and
Stockholders' Equity:
|
|
|
|
|
|
|
Current liabilities,
other
|
|
|
$
174,836
|
|
$
239,343
|
|
Current liabilities,
convertible senior notes
|
|
579
|
|
25,344
|
|
Capitalized lease
obligation
|
|
|
3,004
|
|
3,222
|
|
Senior
notes
|
|
|
|
800,000
|
|
800,000
|
|
Other long-term
liabilities
|
|
|
133,287
|
|
147,087
|
|
Stockholders'
equity
|
|
|
|
975,995
|
|
1,029,488
|
|
|
Total liabilities and
stockholders' equity
|
$
2,087,701
|
|
$
2,244,484
|
|
|
|
|
|
|
|
|
|
(1)
|
At June 30, 2015, the
estimated fair value of all of the Company's commodity derivative
instruments was a net asset of $118.9 million, comprised of $90.9
million of current assets and $28.0 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
|
|
Six Months
Ended
|
|
|
|
|
|
|
June
30,
|
|
June
30,
|
|
|
|
|
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
(in thousands,
except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and Other
Revenues:
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and
NGLs
|
|
(1)
|
$ 61,382
|
|
$ 136,220
|
|
$ 109,868
|
|
$ 263,389
|
|
|
Other
|
|
|
|
1,236
|
|
8,788
|
|
1,784
|
|
9,307
|
|
|
Total operating and
other revenues
|
|
62,618
|
|
145,008
|
|
111,652
|
|
272,696
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
|
|
11,405
|
|
15,919
|
|
25,196
|
|
32,083
|
|
|
Gathering,
transportation and processing
|
|
933
|
|
11,750
|
|
1,875
|
|
23,454
|
|
|
Production
tax
|
|
|
|
3,816
|
|
9,651
|
|
6,350
|
|
17,275
|
|
|
Exploration
|
|
|
|
92
|
|
116
|
|
125
|
|
419
|
|
|
Impairment, dry hole
costs and abandonment
|
|
1,090
|
|
1,743
|
|
2,345
|
|
3,504
|
|
|
(Gain) Loss on
divestitures
|
|
(644)
|
|
-
|
|
(682)
|
|
-
|
|
|
Depreciation,
depletion and amortization
|
|
52,674
|
|
64,894
|
|
104,928
|
|
120,402
|
|
|
Unused
commitments
|
|
4,387
|
|
-
|
|
8,775
|
|
-
|
|
|
General and
administrative
|
(2)
|
11,903
|
|
11,998
|
|
22,182
|
|
23,817
|
|
|
Long-term incentive
compensation
|
(2)
|
2,769
|
|
2,523
|
|
5,819
|
|
6,111
|
|
|
Total operating
expenses
|
|
88,425
|
|
118,594
|
|
176,913
|
|
227,065
|
|
Operating Income
(Loss)
|
|
|
|
(25,807)
|
|
26,414
|
|
(65,261)
|
|
45,631
|
|
Other Income and
Expense:
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other
income
|
|
144
|
|
352
|
|
419
|
|
727
|
|
|
Interest
expense
|
|
|
|
(17,390)
|
|
(17,821)
|
|
(33,820)
|
|
(35,252)
|
|
|
Commodity derivative
gain (loss)
|
(1)
|
(27,657)
|
|
(46,775)
|
|
6,781
|
|
(71,930)
|
|
|
Gain (loss) on
extinguishment of debt
|
|
(818)
|
|
-
|
|
1,749
|
|
-
|
|
|
Total other income
and expense
|
|
(45,721)
|
|
(64,244)
|
|
(24,871)
|
|
(106,455)
|
|
Income (Loss) before
Income Taxes
|
|
(71,528)
|
|
(37,830)
|
|
(90,132)
|
|
(60,824)
|
|
Benefit from Income
Taxes
|
|
|
|
26,947
|
|
11,244
|
|
33,820
|
|
21,489
|
|
Net Income
(Loss)
|
|
|
|
$ (44,581)
|
|
$ (26,586)
|
|
$ (56,312)
|
|
$ (39,335)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Per
Common Share
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
$ (0.92)
|
|
$ (0.55)
|
|
$ (1.17)
|
|
$ (0.82)
|
|
|
Diluted
|
|
|
|
$ (0.92)
|
|
$ (0.55)
|
|
$ (1.17)
|
|
$ (0.82)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
Common Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
48,299
|
|
47,997
|
|
48,249
|
|
47,944
|
|
|
Diluted
|
|
|
|
48,299
|
|
47,997
|
|
48,249
|
|
47,944
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 June 30,
|
|
Six Months
Ended June 30,
|
|
|
|
|
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
|
Included in oil, gas
and NGL production revenue:
|
|
|
|
|
|
|
|
|
|
|
Certain realized
gains on hedges
|
|
$
-
|
|
$
382
|
|
$
-
|
|
$
538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in commodity
derivative gain (loss):
|
|
|
|
|
|
|
|
|
|
|
Realized gain (loss) on derivatives not designated
as cash flow hedges
|
|
|
$ 36,523
|
|
$ (9,326)
|
|
$ 82,898
|
|
$ (18,526)
|
|
|
Unrealized loss on
derivatives not designated as cash flow hedges
|
|
|
(64,180)
|
|
(37,449)
|
|
(76,117)
|
|
(53,404)
|
|
|
Total
commodity derivative gain (loss)
|
|
$ (27,657)
|
|
$ (46,775)
|
|
$ 6,781
|
|
$ (71,930)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
|
|
Six Months
Ended
|
|
|
|
|
|
June
30,
|
|
June
30,
|
|
|
|
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Activities:
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
$ (44,581)
|
|
$ (26,586)
|
|
$ (56,312)
|
|
$ (39,335)
|
|
Adjustments to
reconcile to net cash
|
|
|
|
|
|
|
|
|
|
provided by
operations:
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
52,674
|
|
64,894
|
|
104,928
|
|
120,402
|
|
|
Impairment, dry hole
costs and abandonment expense
|
|
1,090
|
|
1,743
|
|
2,345
|
|
3,504
|
|
|
Unrealized derivative
(gain) loss, non-cash flow hedges
|
64,180
|
|
37,449
|
|
76,117
|
|
53,404
|
|
|
Deferred income tax
benefit
|
|
(26,947)
|
|
(11,286)
|
|
(33,820)
|
|
(21,531)
|
|
|
Incentive
compensation and other non-cash charges
|
|
2,470
|
|
2,463
|
|
5,213
|
|
6,155
|
|
|
Amortization of debt
discounts and deferred financing costs
|
2,283
|
|
1,065
|
|
3,350
|
|
2,132
|
|
|
(Gain) loss on sale
of properties
|
|
(644)
|
|
(2,570)
|
|
(682)
|
|
(2,570)
|
|
|
(Gain) loss on
extinguishment of debt
|
|
818
|
|
-
|
|
(1,749)
|
|
-
|
|
|
Change in assets and
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
8,045
|
|
169
|
|
17,109
|
|
5,699
|
|
|
|
Prepayments and other
assets
|
|
225
|
|
660
|
|
(1,139)
|
|
1,068
|
|
|
|
Accounts payable,
accrued and other liabilities
|
|
(12,017)
|
|
(8,929)
|
|
(13,678)
|
|
(2,795)
|
|
|
|
Amounts payable to
oil & gas property owners
|
|
(3,527)
|
|
(7,465)
|
|
3,311
|
|
1,936
|
|
|
|
Production taxes
payable
|
|
(6,753)
|
|
617
|
|
(13,852)
|
|
(651)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by
operating activities
|
|
$ 37,316
|
|
$ 52,224
|
|
$ 91,141
|
|
$ 127,418
|
Investing
Activities:
|
|
|
|
|
|
|
|
|
|
Additions to oil and
gas properties, including acquisitions
|
|
(83,114)
|
|
(135,407)
|
|
(194,123)
|
|
(264,345)
|
|
Additions of
furniture, equipment and other
|
|
(269)
|
|
(582)
|
|
(878)
|
|
(856)
|
|
Proceeds from sale of
properties and other investing activities
|
103
|
|
8,563
|
|
66,518
|
|
8,175
|
|
Proceeds from the
sale of short-term investments
|
|
50,000
|
|
-
|
|
50,000
|
|
-
|
|
Cash paid for short
term investments
|
|
-
|
|
-
|
|
(114,883)
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in
investing activities
|
|
$ (33,280)
|
|
$ (127,426)
|
|
$ (193,366)
|
|
$ (257,026)
|
Financing
Activities:
|
|
|
|
|
|
|
|
|
|
Proceeds from
debt
|
|
-
|
|
70,000
|
|
-
|
|
135,000
|
|
Principal payments on
debt
|
|
(105)
|
|
(1,148)
|
|
(24,976)
|
|
(2,285)
|
|
Deferred financing
costs and other
|
|
(1,821)
|
|
(103)
|
|
(2,821)
|
|
(2,049)
|
|
Proceeds from stock
option exercises
|
|
-
|
|
-
|
|
-
|
|
126
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by
(used in) financing activities
|
|
$ (1,926)
|
|
$ 68,749
|
|
$ (27,797)
|
|
$ 130,792
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
in Cash and Cash Equivalents
|
|
2,110
|
|
(6,453)
|
|
(130,022)
|
|
1,184
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning Cash and
Cash Equivalents
|
|
33,772
|
|
62,232
|
|
165,904
|
|
54,595
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending Cash and Cash
Equivalents
|
|
$ 35,882
|
|
$ 55,779
|
|
$ 35,882
|
|
$ 55,779
|
BILL BARRETT
CORPORATION
|
Reconciliation of
Discretionary Cash Flow & Adjusted Net Income
(Loss)
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash
Flow Reconciliation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Six Months
Ended
|
|
|
|
|
|
June
30,
|
|
June
30,
|
|
|
|
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
(in thousands,
except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
(Loss)
|
|
|
|
$ (44,581)
|
|
$ (26,586)
|
|
$ (56,312)
|
|
$ (39,335)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to
reconcile to discretionary cash flow:
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
52,674
|
|
64,894
|
|
104,928
|
|
120,402
|
|
Impairment, dry hole
and abandonment expense
|
|
1,090
|
|
1,743
|
|
2,345
|
|
3,504
|
|
Exploration
expense
|
|
92
|
|
116
|
|
125
|
|
419
|
|
Unrealized derivative
loss, non-cash flow hedges
|
|
64,180
|
|
37,449
|
|
76,117
|
|
53,404
|
|
Deferred income
taxes
|
|
(26,947)
|
|
(11,286)
|
|
(33,820)
|
|
(21,531)
|
|
Stock compensation
and other non-cash charges
|
|
2,470
|
|
2,463
|
|
5,213
|
|
6,155
|
|
Amortization of debt
discounts and deferred financing costs
|
|
2,283
|
|
1,065
|
|
3,350
|
|
2,132
|
|
(Gain) loss on sale
of properties
|
|
(644)
|
|
(2,570)
|
|
(682)
|
|
(2,570)
|
|
(Gain) loss on
extinguishment of debt
|
|
818
|
|
-
|
|
(1,749)
|
|
-
|
Discretionary Cash
Flow
|
|
|
$ 51,435
|
|
$ 67,288
|
|
$ 99,515
|
|
$ 122,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per share,
diluted
|
|
$ 1.06
|
|
$ 1.40
|
|
$ 2.06
|
|
$ 2.56
|
|
Per Boe
|
|
|
$ 31.59
|
|
$ 25.66
|
|
$ 31.01
|
|
$ 24.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Loss) Reconciliation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Six Months
Ended
|
|
|
|
|
|
June
30,
|
|
June
30,
|
|
|
|
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
(in thousands
except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss
|
|
|
|
$ (44,581)
|
|
$ (26,586)
|
|
$ (56,312)
|
|
$ (39,335)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to net
loss:
|
|
|
|
|
|
|
|
|
|
Unrealized derivative
loss, non-cash flow hedges
|
|
64,180
|
|
37,449
|
|
76,117
|
|
53,404
|
|
Impairment
expense
|
|
445
|
|
340
|
|
503
|
|
1,378
|
|
(Gain) loss on sale
of properties
|
|
(644)
|
|
(2,570)
|
|
(682)
|
|
(2,570)
|
|
(Gain) loss on
extinguishment of debt
|
|
818
|
|
-
|
|
(1,749)
|
|
-
|
|
One-time
items:
|
|
|
|
|
|
|
|
|
|
|
West Tavaputs NGL
processing true-up
|
|
(1,005)
|
|
(5,677)
|
|
(1,005)
|
|
(5,677)
|
|
|
Expenses (credit)
relating to compressor station fire
|
|
-
|
|
(570)
|
|
-
|
|
(570)
|
|
|
Expenses related to
amending credit facility
|
|
1,617
|
|
-
|
|
1,617
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal
adjustments
|
|
65,411
|
|
28,972
|
|
74,801
|
|
45,965
|
|
Statutory tax
rate
|
|
38%
|
|
38%
|
|
38%
|
|
38%
|
|
Tax effected
adjustments
|
|
|
|
40,555
|
|
17,963
|
|
46,377
|
|
28,498
|
Adjusted Net
Loss
|
|
|
|
$ (4,026)
|
|
$ (8,623)
|
|
$ (9,935)
|
|
$ (10,837)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per share,
diluted
|
|
$ (0.08)
|
|
$ (0.18)
|
|
$ (0.21)
|
|
$ (0.23)
|
|
Per Boe
|
|
|
$ (2.47)
|
|
$ (3.29)
|
|
$ (3.10)
|
|
$ (2.14)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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