DENVER, Nov. 5, 2015 /PRNewswire/ -- Bill Barrett
Corporation (the "Company") (NYSE: BBG) reports third quarter of
2015 results, including these highlights:
- Production sales volumes of 1.7 MMBoe, exceeding guidance by
13% due to the performance of the DJ Basin extended reach lateral
("XRL") drilling program
- Increased Denver-Julesburg ("DJ") Basin production by 72%
year-over-year and 14% sequentially
- Reported adjusted net income of $(0.09) per share excluding non-recurring charges
and impairment expense; generated $1.11 per share of discretionary cash flow
- Maintaining cost discipline as XRL well costs of $5.6 million are approximately 32% lower compared
to wells drilled in the fourth quarter of 2014
- Lease operating expense of $5.67
per Boe, a 19% sequential reduction
- Lease operating expense guidance lowered by 8% at the mid-point
to $45-$47 million
- Executed agreements to sell non-core asset for aggregate
proceeds of $79 million
year-to-date
- Borrowing base reaffirmed at $375
million in September 2015
Chief Executive Officer and President Scot Woodall commented, "We posted another
quarter of solid results that was highlighted by production
exceeding expectations for a third consecutive quarter and our
ability to decrease drilling days for XRL wells and meaningfully
lower well costs and cash expenses. We remain on track to meet
full-year production guidance despite shutting in approximately
1,000 Boe/d of production in the Uinta Basin during the second
quarter of 2015 and including a reduction in volumes associated
with expected asset sales. This is clearly a reflection of the
performance of our Northeast ("NE") Wattenberg assets. XRL drilling
days have improved by 40% to approximately 10 days per well and we
have been consistently drilling recent wells in 8 days or less.
Furthermore, associated cost reductions have lowered completed XRL
well costs to $5.6 million, or by
32%, and we are committed to continuous cost reduction measures as
we endeavor to further improve our capital efficiency. Efficiency
gains are also translating into tangible reductions in operating
costs across our assets, as evidenced by third quarter LOE of
$5.67 per Boe, which was 19% lower
than the second quarter, and we will seek additional means to drive
down costs.
"We maintain a strong financial position. Year-to-date, we have
executed agreements to sell assets that were not expected to
compete for drilling capital in the near or mid-term for aggregate
proceeds of $79 million, including
transactions in the DJ, Uinta and Powder River Basins. This further
augments our balance sheet and enhances our liquidity as we look to
2016. Our undrawn revolving credit facility was recently reaffirmed
at $375 million and, when combined
with our cash position, provides ample liquidity to navigate the
current environment."
THIRD QUARTER 2015 OPERATING AND FINANCIAL
RESULTS
(Prior year period results are pro forma for
assets sold.)
The Company realized growth in production volumes from its core
DJ Basin asset, driven by the results of the NE Wattenberg XRL well
program that offset a production decline from the Uinta Oil Program
("UOP"). Oil, natural gas and natural gas liquids ("NGL")
production from the DJ Basin and UOP totaled 1.7 million
barrels of oil equivalent ("MMBoe") in the third quarter of 2015
compared with 1.4 MMBoe in the third quarter of 2014. DJ Basin
production grew 72%, while UOP production was down 38% as compared
to the third quarter of 2014. The decline in UOP production was
primarily due to a decrease in drilling and workover activity and
the decision to shut-in certain wells during the second quarter of
2015 due to higher operating costs. Third quarter of 2015
production was 63% oil, 22% natural gas and 15% NGLs. The increase
in the proportion of natural gas and NGL volumes relative to oil
volumes was primarily due to a greater amount of natural gas
liquids yields that benefited from the expansion of regional
processing capacity and the delay in timing of oil sales from
inventory.
|
Three Months
Ended
September 30,
|
|
Three Months
Ended
June 30,
|
|
2015
|
|
2014
|
|
Change
|
|
2015
|
|
Change
|
Production Sales
Data:
|
|
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
1,066
|
|
|
934
|
|
|
14
|
%
|
|
1,120
|
|
|
(5)
|
%
|
Natural
gas(MMcf)
|
2,214
|
|
|
1,842
|
|
|
20
|
%
|
|
1,800
|
|
|
23
|
%
|
NGLs
(MBbls)
|
264
|
|
|
148
|
|
|
78
|
%
|
|
208
|
|
|
27
|
%
|
Combined volumes
(MBoe)
|
1,699
|
|
|
1,389
|
|
|
22
|
%
|
|
1,628
|
|
|
4
|
%
|
Daily combined
volumes (Boe/d)
|
18,467
|
|
|
15,098
|
|
|
22
|
%
|
|
17,890
|
|
|
3
|
%
|
Pre-hedge commodity prices were down significantly compared with
2014. For the third quarter of 2015, 93% of oil production and 83%
of natural gas production benefited from commodity derivative swaps
that averaged $89.81 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
September 30,
|
|
Three Months
Ended
June 30,
|
|
2015
Pre-
hedge
|
|
2015
Including
hedge
|
|
2014
Pre-
hedge
|
|
2015
Pre-
hedge
|
|
2015
Including
hedge
|
Average Sales
Price:
|
|
|
|
|
|
|
|
|
|
Oil (per
Bbl)
|
$
|
38.71
|
|
|
$
|
79.15
|
|
|
$
|
82.25
|
|
|
$
|
48.68
|
|
|
$
|
78.44
|
|
Natural gas (per
Mcf)
|
2.08
|
|
|
3.36
|
|
|
4.32
|
|
|
2.33
|
|
|
4.10
|
|
NGLs (per
Bbl)
|
11.17
|
|
|
11.17
|
|
|
24.27
|
|
|
12.76
|
|
|
12.76
|
|
Combined (per
Boe)
|
28.73
|
|
|
55.77
|
|
|
63.64
|
|
|
37.70
|
|
|
60.13
|
|
Cash operating costs (lease operating expense ("LOE"),
gathering, transportation and processing costs and production tax
expense) were $8.23 per Boe in the
third quarter of 2015, down 17% compared to the second quarter of
2015. LOE was $5.67 per Boe, down 19%
compared to the second quarter of 2015. This was primarily a result
of increased operational efficiencies, lease operating cost
reductions and the Company's decision during the second quarter of
2015 to reduce workover activity in the UOP and to shut-in certain
UOP wells in the current commodity price environment. LOE for the
DJ Basin improved to an average of $3.96 per Boe in the third quarter of 2015.
Production tax expense for the third quarter of 2015 averaged 7.5%
of pre-hedge revenue. Normalized production taxes are expected to
approximate 8% of pre-hedge revenue for the fourth quarter of
2015.
|
Three Months
Ended
September 30,
|
|
Three Months
Ended
June 30,
|
|
2015
|
|
2014
|
|
Change
|
|
2015
|
|
Change
|
Average Costs (per
Boe):
|
|
|
|
|
|
|
|
|
|
Lease operating
expenses
|
$
|
5.67
|
|
|
$
|
7.53
|
|
|
(25)
|
%
|
|
$
|
7.01
|
|
|
(19)
|
%
|
Gathering,
transportation and processing expense
|
0.40
|
|
|
0.63
|
|
|
(37)
|
%
|
|
0.57
|
|
|
(30)
|
%
|
Production tax
expenses
|
2.16
|
|
|
5.48
|
|
|
(61)
|
%
|
|
2.34
|
|
|
(8)
|
%
|
Depreciation,
depletion and amortization
|
32.22
|
|
|
34.31
|
|
|
(6)
|
%
|
|
32.36
|
|
|
—
|
%
|
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 third quarter of 2015 was
$53.5 million, or $1.11 per share, compared to $70.1 million, or $1.46 per share, in the third quarter of 2014.
Discretionary cash flow in the third quarter of 2015 compared to
2014 was impacted by lower revenues due to a 36% decline in
production volumes as a result of asset sales.
Net loss for the third quarter of 2015 was $(410.3) million, or $(8.49) per share, compared with the third
quarter of 2014 at $(34.6) million,
or $(0.72) per share. Adjusted net
loss was $(4.4) million, or
$(0.09) per share, in the third
quarter of 2015 compared with $(3.1)
million, or $(0.06) per share,
in the third quarter of 2014. Adjusted net income (loss) removes
the effect of unrealized derivative gains and losses and
non-recurring charges such as impairment expenses, property sales
and certain one-time items.
|
Three Months
Ended
September 30,
|
|
2015
|
|
2014
|
Discretionary Cash
Flow ($ millions)
|
$
|
53.5
|
|
|
$
|
70.1
|
|
Discretionary Cash
Flow per share
|
1.11
|
|
|
1.46
|
|
Adjusted Net Loss ($
millions)
|
(4.4)
|
|
|
(3.1)
|
|
Adjusted Net Loss per
share
|
(0.09)
|
|
|
(0.06)
|
|
Non-Cash Impairment
The Company recognized a non-cash impairment charge of
$571.9 million in the third quarter
of 2015 related to the UOP proved and unproved oil and gas
assets. The impairment was the result of reduced future net
revenues compared against the current carrying value from the
second quarter of 2015 to the third quarter of 2015.
Primarily as a result of this quarter's impairment charge, the
Company recorded a valuation allowance against its net deferred tax
asset of $66.4 million.
Debt and Liquidity
The Company's semi-annual borrowing base review was completed in
September 2015 with the bank group
reaffirming the Company's $375
million borrowing base related to its revolving credit
facility maturing in April 2020. At
September 30, 2015, the 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 $802.9 million and cash and
short-term investments were $112.8
million, resulting in net debt (principal balance of debt
outstanding less the cash and investment balance) of $690.1 million. Liquidity was $461.8 million.
In addition, as of November 5, 2015, the Company has not
issued any shares under its previously announced "at-the-market"
equity offering program and does not anticipate currently utilizing
it due to market conditions.
Divestitures
During the third quarter, the Company announced the signing of
an agreement to sell certain properties located in the Uinta Basin
for after-tax cash proceeds of approximately $27 million. The transaction is expected to close
on or before November 30, 2015,
subject to customary closing conditions. The properties produced
approximately 484 Boe/d during September
2015, had estimated proved reserves of 11 million barrels of
oil equivalent ("MMBoe") (9% proved developed) as of December 31, 2014 and included 17,632 net
acres.
Subsequent to the end of the quarter, the Company executed
agreements to sell certain assets in the DJ Basin that are located
outside of the core NE Wattenberg area for after-tax cash proceeds
of approximately $31 million. The
transaction is expected to close on or before November 30, 2015, and is subject to customary
closing conditions.
Including this transaction, the Company has completed or
announced three separate DJ Basin transactions for aggregate
after-tax proceeds of $43 million
during 2015. None of the assets sold are located within the
Company's NE Wattenberg focus area, and they were not expected to
compete for drilling capital in the near or mid-term. The assets
primarily included legacy vertical wells that had estimated
production of approximately 1,265 Boe/d (29% natural gas),
estimated proved reserves of 4 MMBoe (76% proved developed) as of
December 31, 2014 and included 23,735
net acres. Based on the Company's internal estimates, the sale
price amounts to approximately 8x estimated 2016 operating cash
flow (excluding general and administrative expense) based on
current strip pricing.
In aggregate, the Company expects to receive proceeds of
approximately $58 million, prior to
customary purchase price adjustments, for the Uinta Basin and
recent DJ Basin divestitures in the fourth quarter of 2015. The
sale of these properties will not result in a reduction of the
Company's borrowing base related to its revolving credit
facility.
Capital Expenditures
Capital expenditures ("Capex") for the third quarter of 2015
were $63.2 million and totaled
$242.6 million for the nine months
ended September 30, 2015. Capex
included 18 gross/ 16.9 net spud wells in the DJ Basin, all of
which were XRL wells operated by the Company, and 3 gross/ 1 net
operated wells in the UOP. In the third quarter, 8 gross/ 7.8 net
XRL wells began flowback operations and were placed on initial
sales. Capital expenditures included $59.3
million for drilling, $0.8
million for leaseholds, and $3.1
million for infrastructure and corporate assets.
Basin Summary
|
Three Months
Ended
September 30, 2015
|
|
Nine Months Ended
September 30, 2015
|
|
Average
Net Daily
Production
(Boe/d)
|
|
Wells
Spud
Net
(1)
|
|
Capital
Expenditures
($
millions)
|
|
Average
Net Daily
Production
(Boe/d)
|
|
Wells
Spud
Net
(1)
|
|
Capital
Expenditures
($
millions)
|
Basin:
|
|
|
|
|
|
|
|
|
|
|
|
Denver-Julesburg
|
14,250
|
|
|
18
|
|
|
$
|
55.8
|
|
|
12,828
|
|
|
38
|
|
|
$
|
214.3
|
|
Uinta
|
4,185
|
|
|
2
|
|
|
7.2
|
|
|
5,059
|
|
|
8
|
|
|
26.3
|
|
Other
(2)
|
32
|
|
|
—
|
|
|
0.2
|
|
|
91
|
|
|
—
|
|
|
2.0
|
|
Total
|
18,467
|
|
|
20
|
|
|
$
|
63.2
|
|
|
17,978
|
|
|
46
|
|
|
$
|
242.6
|
|
|
|
(1)
|
Includes operated and
non-operated wells
|
(2)
|
Primarily
non-operated production in Wyoming and New Mexico
|
OPERATIONAL HIGHLIGHTS
DJ Basin
Third quarter DJ Basin highlights include:
- Produced an average of 14,250 Boe/d, an increase of 72% from
the third quarter of 2014 and an increase of 14% sequentially.
- DJ Basin oil volumes averaged 8,283 Bbls/d, an increase of 72%
from the third quarter of 2014 and an increase of 3%
sequentially.
- Spud 18 gross/ 16.9 net operated XRL wells during the third
quarter of 2015.
- Placed 8 gross/ 7.8 net XRL wells on initial sales during the
third quarter of 2015.
- Placed 9 gross/ 8.1 net XRL wells on initial sales in
November 2015.
- Operational efficiency increased by reducing the number of
drilling days for XRL wells by 40% to an average of approximately
10 days per well. Recent wells have consistently been drilled in
approximately 8 days per well, including a best-in-class well
drilled in 6.9 days. These improved efficiencies allow the
remainder of 2015 drilling program to be accomplished with one-rig
drilling program.
- Maintaining a sharp focus on cost discipline as recently
contracted XRL drilling and completion costs of $5.6 million are approximately 32% lower compared
to wells drilled in the fourth quarter of 2014.
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 for the remainder of
the year includes 4 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 operational
efficiencies, and associated cost 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 wells in the current commodity price
environment.
2015 OPERATING GUIDANCE
The Company is providing the following update to guidance for
its 2015 activities. See "Forward-Looking Statements" below.
- Capital expenditures of $315-$325
million, unchanged.
- Includes the reduction in the operated rig count from two rigs
to one rig in NE Wattenberg as previously announced.
- Production of 6.3-6.5 MMBoe, unchanged.
- It is estimated that the aggregate production reduction from
the pending DJ and Uinta Basin asset sales, which are scheduled to
close on or before November 30, 2015,
will be approximately 42 MBoe in December
2015.
- Lease operating expense of $45-$47
million, decreased from $48-$52
million to correspond with lease operating cost reductions
in both the DJ Basin and UOP.
COMMODITY HEDGES UPDATE
Generally, it is the Company's strategy to hedge 50%-70% of
production on a forward 12-month to 18-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 following table summarizes hedge positions as of
November 5, 2015:
|
|
Oil (WTI)
|
|
Natural Gas
(NWPL)
|
Period
|
|
Volume
Bbls/d
|
|
Price
$/Bbl
|
|
Volume
MMBtu/d
|
|
Price
$/MMBtu
|
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
Third Quarter Conference Call and Webcast
The Company plans to host a conference call on Friday,
November 6, 2015, to discuss the 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 63826020. The
webcast will remain on the Company's website for approximately 30
days and a replay of the call will be available through
November 13, 2015 at 855-859-2056 (404-537-3406 international)
with passcode 63826020.
DISCLOSURE STATEMENTS
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 "2015 Operating Guidance," which contains projections
for certain 2015 operational and financial metrics as well as
certain projections for the fourth quarter of 2015. Additional
forward-looking statements in this release relate to, among other
things, the closing of, and proceeds from the planned asset sales
and 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; 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 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
September 30,
|
|
Nine Months Ended
September 30,
|
|
2015
|
|
2014 (1)
|
|
2015
|
|
2014 (1)
|
Production
Data:
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
1,066
|
|
|
1,107
|
|
|
3,311
|
|
|
3,056
|
|
Natural gas
(MMcf)
|
2,214
|
|
|
6,834
|
|
|
5,772
|
|
|
19,950
|
|
NGLs
(MBbls)
|
264
|
|
|
408
|
|
|
635
|
|
|
1,330
|
|
Combined volumes
(MBoe)
|
1,699
|
|
|
2,654
|
|
|
4,908
|
|
|
7,711
|
|
Daily combined
volumes (Boe/d)
|
18,467
|
|
|
28,848
|
|
|
17,978
|
|
|
28,245
|
|
|
|
|
|
|
|
|
|
Average Sales Prices
(before the effects of realized hedges):
|
Oil (per
Bbl)
|
$
|
38.71
|
|
|
$
|
82.83
|
|
|
$
|
41.54
|
|
|
$
|
84.04
|
|
Natural gas (per
Mcf)
|
2.08
|
|
|
4.24
|
|
|
2.31
|
|
|
4.83
|
|
NGLs (per
Bbl)
|
11.17
|
|
|
32.65
|
|
|
12.24
|
|
|
32.80
|
|
Combined (per
Boe)
|
28.73
|
|
|
50.48
|
|
|
32.33
|
|
|
51.47
|
|
|
|
|
|
|
|
|
|
Average Realized
Sales Prices (after the effects of realized hedges):
|
Oil (per
Bbl)
|
$
|
79.15
|
|
|
$
|
79.98
|
|
|
$
|
77.93
|
|
|
$
|
79.52
|
|
Natural gas (per
Mcf)
|
3.36
|
|
|
4.27
|
|
|
3.76
|
|
|
4.50
|
|
NGLs (per
Bbl)
|
11.17
|
|
|
33.19
|
|
|
12.24
|
|
|
32.61
|
|
Combined (per
Boe)
|
55.77
|
|
|
49.46
|
|
|
58.58
|
|
|
48.78
|
|
|
|
|
|
|
|
|
|
Average Costs (per
Boe):
|
|
|
|
|
|
|
|
Lease operating
expenses
|
$
|
5.67
|
|
|
$
|
6.14
|
|
|
$
|
7.10
|
|
|
$
|
6.27
|
|
Gathering,
transportation and processing expense
|
0.40
|
|
|
4.06
|
|
|
0.52
|
|
|
4.44
|
|
Production tax
expenses
|
2.16
|
|
|
3.95
|
|
|
2.04
|
|
|
3.60
|
|
Depreciation,
depletion and amortization
|
32.22
|
|
|
26.01
|
|
|
32.53
|
|
|
24.57
|
|
General and
administrative expense, excluding long-term incentive compensation
expense (2)
|
5.31
|
|
|
2.86
|
|
|
6.36
|
|
|
4.07
|
|
|
|
(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
September 30,
|
|
As of
December
31,
|
|
2015
|
|
2014
|
|
(in
thousands)
|
Assets:
|
|
|
|
Cash and cash
equivalents
|
$
|
92,836
|
|
|
$
|
165,904
|
|
Short-term
investments
|
19,992
|
|
|
—
|
|
Other current assets
(1)
|
157,312
|
|
|
260,201
|
|
Property and
equipment, net
|
1,238,947
|
|
|
1,753,121
|
|
Other noncurrent
assets (1)
|
87,173
|
|
|
65,258
|
|
Total
assets
|
$
|
1,596,260
|
|
|
$
|
2,244,484
|
|
|
|
|
|
Liabilities and
Stockholders' Equity:
|
|
|
|
Current liabilities,
other
|
$
|
199,635
|
|
|
$
|
239,343
|
|
Current liabilities,
convertible senior notes
|
579
|
|
|
25,344
|
|
Capitalized lease
obligation
|
2,894
|
|
|
3,222
|
|
Senior
notes
|
800,000
|
|
|
800,000
|
|
Other long-term
liabilities
|
25,386
|
|
|
147,087
|
|
Stockholders'
equity
|
567,766
|
|
|
1,029,488
|
|
Total liabilities and
stockholders' equity
|
$
|
1,596,260
|
|
|
$
|
2,244,484
|
|
|
|
(1)
|
At September 30,
2015, the estimated fair value of all of the Company's commodity
derivative instruments was a net asset of $142.1 million, comprised
of $109.9 million of current assets and $32.2 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
September 30,
|
|
Nine Months Ended
September 30,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
(in thousands, except
per share amounts)
|
Operating and Other
Revenues:
|
|
|
|
|
|
|
|
Oil, gas and NGLs
(1)
|
$
|
48,799
|
|
|
$
|
134,342
|
|
|
$
|
158,667
|
|
|
$
|
397,731
|
|
Other
|
880
|
|
|
921
|
|
|
2,664
|
|
|
7,658
|
|
Total operating and
other revenues
|
49,679
|
|
|
135,263
|
|
|
161,331
|
|
|
405,389
|
|
Operating
Expenses:
|
|
|
|
|
|
|
|
Lease
operating
|
9,638
|
|
|
16,284
|
|
|
34,834
|
|
|
48,367
|
|
Gathering,
transportation and processing
|
684
|
|
|
10,784
|
|
|
2,559
|
|
|
34,238
|
|
Production
tax
|
3,670
|
|
|
10,495
|
|
|
10,020
|
|
|
27,770
|
|
Exploration
|
20
|
|
|
23
|
|
|
145
|
|
|
442
|
|
Impairment, dry hole
costs and abandonment
|
572,651
|
|
|
29,109
|
|
|
574,996
|
|
|
32,613
|
|
(Gain) Loss on
divestitures
|
(77)
|
|
|
99,466
|
|
|
(759)
|
|
|
96,896
|
|
Depreciation,
depletion and amortization
|
54,738
|
|
|
69,024
|
|
|
159,666
|
|
|
189,426
|
|
Unused
commitments
|
4,388
|
|
|
—
|
|
|
13,163
|
|
|
—
|
|
General and
administrative (2)
|
9,018
|
|
|
7,591
|
|
|
31,200
|
|
|
31,408
|
|
Long-term incentive
compensation (2)
|
2,007
|
|
|
3,520
|
|
|
7,826
|
|
|
9,631
|
|
Total operating
expenses
|
656,737
|
|
|
246,296
|
|
|
833,650
|
|
|
470,791
|
|
Operating Income
(Loss)
|
(607,058)
|
|
|
(111,033)
|
|
|
(672,319)
|
|
|
(65,402)
|
|
Other Income and
Expense:
|
|
|
|
|
|
|
|
Interest and other
income
|
100
|
|
|
264
|
|
|
519
|
|
|
991
|
|
Interest
expense
|
(15,754)
|
|
|
(18,033)
|
|
|
(49,574)
|
|
|
(53,285)
|
|
Commodity derivative
gain (loss) (1)
|
69,133
|
|
|
72,299
|
|
|
75,914
|
|
|
369
|
|
Gain (loss) on
extinguishment of debt
|
—
|
|
|
—
|
|
|
1,749
|
|
|
—
|
|
Total other income
and expense
|
53,479
|
|
|
54,530
|
|
|
28,608
|
|
|
(51,925)
|
|
Income (Loss) before
Income Taxes
|
(553,579)
|
|
|
(56,503)
|
|
|
(643,711)
|
|
|
(117,327)
|
|
(Provision for)
Benefit from Income Taxes
|
143,265
|
|
|
21,854
|
|
|
177,085
|
|
|
43,343
|
|
Net Income
(Loss)
|
$
|
(410,314)
|
|
|
$
|
(34,649)
|
|
|
$
|
(466,626)
|
|
|
$
|
(73,984)
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) per
Common Share
|
|
|
|
|
|
|
|
Basic
|
$
|
(8.49)
|
|
|
$
|
(0.72)
|
|
|
$
|
(9.67)
|
|
|
$
|
(1.54)
|
|
Diluted
|
$
|
(8.49)
|
|
|
$
|
(0.72)
|
|
|
$
|
(9.67)
|
|
|
$
|
(1.54)
|
|
Weighted Average
Common Shares Outstanding
|
|
|
|
|
|
|
|
Basic
|
48,340
|
|
|
48,060
|
|
|
48,280
|
|
|
47,983
|
|
Diluted
|
48,340
|
|
|
48,060
|
|
|
48,280
|
|
|
47,983
|
|
|
|
|
|
(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
September 30,
|
|
Nine Months Ended
September 30,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
(in
thousands)
|
Included in oil, gas
and NGL production revenue:
|
|
|
|
|
|
|
|
Certain realized
gains on hedges
|
$
|
—
|
|
|
$
|
351
|
|
|
$
|
—
|
|
|
$
|
889
|
|
Included in commodity
derivative gain (loss):
|
|
|
|
|
|
|
|
Realized gain (loss)
on derivatives not designated as cash flow hedges
|
$
|
45,936
|
|
|
$
|
(3,054)
|
|
|
$
|
128,834
|
|
|
$
|
(21,580)
|
|
Unrealized gain
(loss) on derivatives not designated as cash flow hedges
|
23,197
|
|
|
75,353
|
|
|
(52,920)
|
|
|
21,949
|
|
Total commodity
derivative gain (loss)
|
$
|
69,133
|
|
|
$
|
72,299
|
|
|
$
|
75,914
|
|
|
$
|
369
|
|
|
|
(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
September 30,
|
|
Nine Months Ended
September 30,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
(in
thousands)
|
Operating
Activities:
|
|
|
|
|
|
|
|
Net income
(loss)
|
$
|
(410,314)
|
|
|
$
|
(34,649)
|
|
|
$
|
(466,626)
|
|
|
$
|
(73,984)
|
|
Adjustments to
reconcile to net cash provided by operations:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
54,738
|
|
|
69,024
|
|
|
159,666
|
|
|
189,426
|
|
Impairment, dry hole
costs and abandonment expense
|
572,651
|
|
|
29,109
|
|
|
574,996
|
|
|
32,613
|
|
Unrealized derivative
(gain) loss, non-cash flow hedges
|
(23,197)
|
|
|
(75,353)
|
|
|
52,920
|
|
|
(21,949)
|
|
Deferred income tax
benefit
|
(142,977)
|
|
|
(22,073)
|
|
|
(176,797)
|
|
|
(43,604)
|
|
Incentive
compensation and other non-cash charges
|
2,068
|
|
|
3,496
|
|
|
7,281
|
|
|
9,651
|
|
Amortization of debt
discounts and deferred financing costs
|
633
|
|
|
1,068
|
|
|
3,983
|
|
|
3,200
|
|
(Gain) loss on sale
of properties
|
(77)
|
|
|
99,466
|
|
|
(759)
|
|
|
96,896
|
|
(Gain) loss on
extinguishment of debt
|
—
|
|
|
—
|
|
|
(1,749)
|
|
|
—
|
|
Change in operating
assets and liabilities:
|
|
|
|
|
|
|
|
Accounts
receivable
|
3,285
|
|
|
3,326
|
|
|
20,394
|
|
|
9,025
|
|
Prepayments and other
assets
|
878
|
|
|
(154)
|
|
|
(261)
|
|
|
914
|
|
Accounts payable,
accrued and other liabilities
|
18,025
|
|
|
23,518
|
|
|
4,347
|
|
|
20,723
|
|
Amounts payable to
oil and gas property owners
|
(4,161)
|
|
|
—
|
|
|
(850)
|
|
|
1,936
|
|
Production taxes
payable
|
3,208
|
|
|
7,106
|
|
|
(10,644)
|
|
|
6,455
|
|
Net cash provided by
(used in) operating activities
|
$
|
74,760
|
|
|
$
|
103,884
|
|
|
$
|
165,901
|
|
|
$
|
231,302
|
|
Investing
Activities:
|
|
|
|
|
|
|
|
Additions to oil and
gas properties, including acquisitions
|
(61,936)
|
|
|
(161,633)
|
|
|
(256,059)
|
|
|
(425,978)
|
|
Additions of
furniture, equipment and other
|
(158)
|
|
|
(1,254)
|
|
|
(1,036)
|
|
|
(2,110)
|
|
Proceeds from sale of
properties and other investing activities
|
99
|
|
|
549,572
|
|
|
66,617
|
|
|
557,747
|
|
Proceeds from the
sale of short-term investments
|
45,000
|
|
|
—
|
|
|
95,000
|
|
|
—
|
|
Cash paid for
short-term investments
|
—
|
|
|
—
|
|
|
(114,883)
|
|
|
—
|
|
Net cash provided by
(used in) investing activities
|
$
|
(16,995)
|
|
|
$
|
386,685
|
|
|
$
|
(210,361)
|
|
|
$
|
129,659
|
|
Financing
Activities:
|
|
|
|
|
|
|
|
Proceeds from
debt
|
—
|
|
|
30,000
|
|
|
—
|
|
|
165,000
|
|
Principal payments on
debt
|
(107)
|
|
|
(281,157)
|
|
|
(25,083)
|
|
|
(283,442)
|
|
Deferred financing
costs and other
|
(704)
|
|
|
(413)
|
|
|
(3,525)
|
|
|
(2,462)
|
|
Proceeds from stock
option exercises
|
—
|
|
|
—
|
|
|
—
|
|
|
126
|
|
Net cash provided by
(used in) financing activities
|
$
|
(811)
|
|
|
$
|
(251,570)
|
|
|
$
|
(28,608)
|
|
|
$
|
(120,778)
|
|
Increase (Decrease)
in Cash and Cash Equivalents
|
56,954
|
|
|
238,999
|
|
|
(73,068)
|
|
|
240,183
|
|
Beginning Cash and
Cash Equivalents
|
35,882
|
|
|
55,779
|
|
|
165,904
|
|
|
54,595
|
|
Ending Cash and Cash
Equivalents
|
$
|
92,836
|
|
|
$
|
294,778
|
|
|
$
|
92,836
|
|
|
$
|
294,778
|
|
BILL BARRETT
CORPORATION
Reconciliation of
Discretionary Cash Flow and Adjusted Net Income
(Loss)
(Unaudited)
|
|
Discretionary Cash
Flow Reconciliation
|
|
|
Three Months
Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
(in thousands, except
per share amounts)
|
Net Income
(Loss)
|
$
|
(410,314)
|
|
|
$
|
(34,649)
|
|
|
$
|
(466,626)
|
|
|
$
|
(73,984)
|
|
Adjustments to
reconcile to discretionary cash flow:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
54,738
|
|
|
69,024
|
|
|
159,666
|
|
|
189,426
|
|
Impairment, dry hole
and abandonment expense
|
572,651
|
|
|
29,109
|
|
|
574,996
|
|
|
32,613
|
|
Exploration
expense
|
20
|
|
|
23
|
|
|
145
|
|
|
442
|
|
Unrealized derivative
(gain) loss, non-cash flow hedges
|
(23,197)
|
|
|
(75,353)
|
|
|
52,920
|
|
|
(21,949)
|
|
Deferred income
taxes
|
(142,977)
|
|
|
(22,073)
|
|
|
(176,797)
|
|
|
(43,604)
|
|
Stock compensation
and other non-cash charges
|
2,068
|
|
|
3,496
|
|
|
7,281
|
|
|
9,651
|
|
Amortization of debt
discounts and deferred financing costs
|
633
|
|
|
1,068
|
|
|
3,983
|
|
|
3,200
|
|
(Gain) loss on sale
of properties
|
(77)
|
|
|
99,466
|
|
|
(759)
|
|
|
96,896
|
|
(Gain) loss on
extinguishment of debt
|
—
|
|
|
—
|
|
|
(1,749)
|
|
|
—
|
|
Discretionary Cash
Flow
|
$
|
53,545
|
|
|
$
|
70,111
|
|
|
$
|
153,060
|
|
|
$
|
192,691
|
|
Per share,
diluted
|
$
|
1.11
|
|
|
$
|
1.46
|
|
|
$
|
3.17
|
|
|
$
|
4.02
|
|
Per Boe
|
$
|
31.52
|
|
|
$
|
26.42
|
|
|
$
|
31.19
|
|
|
$
|
24.99
|
|
|
|
|
|
Adjusted Net
Income (Loss) Reconciliation
|
|
|
|
|
|
Three Months
Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
|
(in thousands, except
per share amounts)
|
Net Income
(Loss)
|
$
|
(410,314)
|
|
|
$
|
(34,649)
|
|
|
$
|
(466,626)
|
|
|
$
|
(73,984)
|
|
Adjustments to net
income (loss):
|
|
|
|
|
|
|
|
Unrealized derivative
(gain) loss, non-cash flow hedges
|
(23,197)
|
|
|
(75,353)
|
|
|
52,920
|
|
|
(21,949)
|
|
Impairment
expense
|
571,863
|
|
|
26,743
|
|
|
572,366
|
|
|
28,121
|
|
(Gain) loss on sale
of properties
|
(77)
|
|
|
99,466
|
|
|
(759)
|
|
|
96,896
|
|
(Gain) loss on
extinguishment of debt
|
—
|
|
|
—
|
|
|
(1,749)
|
|
|
—
|
|
One-time
items:
|
|
|
|
|
|
|
|
West Tavaputs NGL
processing true-up
|
—
|
|
|
—
|
|
|
(1,005)
|
|
|
(5,677)
|
|
Expenses (credit)
relating to compressor station fire
|
—
|
|
|
—
|
|
|
—
|
|
|
(570)
|
|
Expenses relating to
amending credit facility
|
—
|
|
|
—
|
|
|
1,617
|
|
|
—
|
|
Subtotal
adjustments
|
548,589
|
|
|
50,856
|
|
|
623,390
|
|
|
96,821
|
|
Effective tax
rate
|
26
|
%
|
|
38
|
%
|
|
28
|
%
|
|
38
|
%
|
Tax effected
adjustments
|
405,956
|
|
|
31,531
|
|
|
448,841
|
|
|
60,029
|
|
Adjusted Net Income
(Loss)
|
$
|
(4,358)
|
|
|
$
|
(3,118)
|
|
|
$
|
(17,785)
|
|
|
$
|
(13,955)
|
|
Per share,
diluted
|
$
|
(0.09)
|
|
|
$
|
(0.06)
|
|
|
$
|
(0.37)
|
|
|
$
|
(0.29)
|
|
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