DENVER, Aug. 3 /PRNewswire-FirstCall/ -- Bill
Barrett Corporation (NYSE: BBG
- News) reported
that production for the second quarter that ended June 30, 2005
was 8.6 billion cubic feet equivalent (Bcfe), which compares to
8.1 Bcfe in the second quarter 2004. Net of the effects of hedging,
the realized price for the Company's production in the second
quarter 2005 was $6.31 per thousand cubic feet equivalent (Mcfe)
compared to a realized price of $5.01 per Mcfe in the second quarter
2004. Discretionary cash flow (1), a non-GAAP measure defined
below, was $34.7 million for the second quarter of 2005, an increase
of 41% over the second quarter 2004. As further described below,
the Company recorded a non-cash impairment of $36.3 million related
to certain of its Cooper Reservoir and Talon properties in the
Wind River Basin. After recording this impairment in the second
quarter 2005, the Company reported a net loss of $15.9 million,
which compares to net income of $3.0 million in the second quarter
2004.
For the first six months of 2005, the Company
reported production of 17.0 Bcfe, compared to 15.4 Bcfe in the
first half of 2004. The realized price, net of hedging, was
$6.15 per Mcfe in the first half of 2005 compared to $4.95 per
Mcfe in the similar period of 2004. Discretionary cash flow
(1) was $66.3 million in the first half of 2005, an increase
of 39% over the first half of 2004. The Company reported a net
loss of $12.8 million in the first six months of 2005, which
compared to net income of $7.8 million in the first half of
2004.
The Company also announced encouraging preliminary
results in the Cave Gulch area for its exploratory Bullfrog
#14-18 well and the stimulation of the Cave Gulch 1-29.
Fredrick J. Barrett, Chief Operating Officer
and President, commented, "Our active drilling program continues
to keep us on track to achieve significant reserve and production
growth. In the Wind River Basin, we are excited about the potential
exploration success with our Bullfrog well along with the successful
hydraulic fracturing of the Cave Gulch 1-29 well, both of which
have the potential to be multi-Bcfe wells. Additionally, our
Piceance completions continue to improve, preliminary indications
in West Tavaputs are encouraging, and our Williston horizontal
drilling is yielding increasing oil production. Although we
are disappointed with the results to date at Cooper Reservoir
and Talon, the success of our diversified drilling programs
confirms our expectations that we will achieve our 2005 production
targets and continue to generate strong cash flow."
Operating and Drilling Update
The Company spent $88.1 million on capital
expenditures in the second quarter of 2005, which was comprised
of $10.0 million for the acquisition of undeveloped properties,
$76.5 million for drilling, development, exploration and exploitation
of natural gas and oil properties, $0.7 million for geologic
and geophysical costs, and $0.9 million for equipment and other
expenditures. The following table lists the Company's capital
expenditures by basin and wells spud for the second quarter
of 2005.
For the Quarter Ended June 30, 2005
Area Capital Expenditures Wells
(in millions) spud
Piceance Basin $31.4 24
Wind River Basin 17.2 3
Uinta Basin 16.4 7
Powder River Basin 9.5 39
Williston Basin 6.6 2
Other 7.0 1
Total $88.1 76
The Company provides the following guidance
for production and expenses based on information available at
the time of this release. The guidance amounts do not include
production or operating costs that may result from acquisitions
or future successful exploration projects. Please see the forward-looking
statements disclosure at the end of this release for more discussion
of the inherent limitations of these forward-looking statements.
Third Quarter Year
Guidance: Ending Ending
September 30, December 31,
2005 2005
Production:
Oil (MBbl) 110 - 130 486 - 526
Natural Gas (Bcf) 8.3 - 8.9 34.5 - 36.8
Total Natural Gas Equivalent (Bcfe) 9.0 - 9.7 37.4 - 40.0
Operating Costs (in millions):
Lease operating expense $5.2 - $5.4 $21.5 - $23.3
Gathering and transportation expense $3.1 - $3.3 $11.4 - $12.2
General and administrative
expense (excluding non-cash
stock-based compensation) $6.3 - $6.9 $23.0 - $24.5
The Company currently intends to participate
in the drilling of 352 wells in 2005, including 19 exploration
wells. The Company's capital budget currently is set at $305
million, but industry-wide cost increases and accelerating certain
of the Company's drilling programs may cause the Company to
increase the budget.
As of June 30, 2005, the Company had eight
conventional and eight coalbed methane rigs in operation, and
is providing the following update of certain of its drilling
activities.
Wind River Basin, Wyoming
Cave Gulch/Bullfrog -- In the Bullfrog area,
the Company recently completed and is testing the Bullfrog #14-18
(93% working interest), a 19,400 foot deep exploratory test
targeting the Lakota, Muddy and Frontier formations. Early results
are encouraging. As of July 26, 2005, this well was flowing
approximately 17.8 MMcfd (gross) into the sales line at 10,940
pounds per square inch (psi) flowing tubing pressure with 30
barrels of water per day (bwpd) from a completion in the Muddy
formation. Other Muddy wells in the area tend to have relatively
short reserve lives and highly variable reservoir size. Below
the Muddy, the Lakota formation tested dry gas in excess of
one MMcfd (gross), but is currently isolated under a bridge
plug. Above the Muddy, the Frontier formation intervals remain
untested and behind pipe. The Company has identified several
additional potential drilling locations in the area targeting
these formations.
In Cave Gulch, the Company has identified
Muddy/Frontier stimulation and re-stimulation candidates in
its development program. The first of these stimulations was
performed in mid-June with promising results. The Muddy formation
was stimulated in the Cave Gulch 1-29 (70% working interest)
and, as of July 26, 2005, the well was flowing approximately
11.8 MMcfd (gross) into the sales line at 1,650 psi flowing
tubing pressure along with 60 bwpd, a significant increase from
the approximately 0.7 MMcfd (gross) at 1,070 psi flowing tubing
pressure and 0-22 bwpd prior to stimulation. The Company plans
to re-stimulate the Muddy formation in the Cave Gulch 5-30 well,
an offset to the Cave Gulch 1-29, later this year. Both the
Cave Gulch 1-29 and Cave Gulch 5-30 have behind pipe potential
in the Frontier formation.
In the Cooper Reservoir area, the Company
drilled six wells targeting the Lance and Fort Union formations
in the first half of 2005. Five wells are producing into the
sales line and the other development well was a dry hole. As
a result of drilling these wells and ongoing evaluation of the
area, the Company determined that infill wells are encountering
depleted sands and are not recovering sufficient incremental
reserves to continue the program in the Lance and Fort Union
formations. The Company recorded an impairment expense of $29.5
million in the second quarter to reduce the carrying value of
properties in the Cooper Reservoir to fair value. The Company
has identified deeper Muddy and Frontier potential on 3-D seismic
that it believes is on trend with the Muddy production in the
Bullfrog area. The Company will continue to assess Cooper Reservoir
as a deep exploration play.
East Madden -- The Company continues to test
the Lance formation in the Hitchcock Draw exploratory well (37.5%
working interest). As of July 31, 2005, the well was flowing
approximately 365 Mcfd (gross) into the sales line from four
completion intervals in the Lower Lance formation. Additional
intervals of potential pay remain untested at present in the
Upper Lance and Fort Union formations. The Company and its industry
partner are assessing the potential of drilling an offset to
this well.
Talon -- In the first half of 2005, the Company
drilled and completed three wells and participated in another
three nonoperated wells. Of the three nonoperated wells, one
is waiting on pipeline, one is waiting on completion, and one
was deemed to be a dry hole. The Company currently has nine
productive wells in Talon; however, performance of these wells
has been weaker than expected. While the Company continues to
believe that Talon is a large, unconventional basin centered
area with significant oil and gas in place in both the Lance
and Fort Union formations, additional development of drilling
and completion techniques will be required to determine whether
this gas may be recovered economically. As a result of performance
to date, the Company recorded an impairment expense totaling
$6.8 million in the second quarter to reduce the carrying value
of these exploration wells to the fair value of the reserves
developed. The Company plans to drill another two exploratory
wells before year end and is assessing the feasibility of horizontal
drilling in the Fort Union formation.
Piceance Basin, Colorado
The Company currently is operating four drilling
rigs in its Gibson Gulch project area (97% average working interest).
For the first seven months of 2005, the Company drilled 42 wells
in Gibson Gulch. Twenty wells drilled in 2005 have been completed
and hooked up to a sales line at initial maximum daily rates
ranging from 375 Mcfd to 2,400 Mcfd (gross). The other 22 wells
are either being completed or waiting on completion. The Company
continues to refine the completion procedures it applies to
the field, demonstrated by the nine most recent completions.
Those wells had initial test rates that ranged between 700 to
2,400 Mcfd (gross), with seven of the nine exceeding an initial
test rate of 1,200 Mcfd (gross). The Company has budgeted $127
million for capital expenditures for the Piceance Basin in 2005,
including drilling 80 wells and acquiring 25 square miles of
3-D seismic. However, depending on drilling results, the Company
may drill additional wells in the Piceance in 2005.
Uinta Basin, Utah
West Tavaputs -- The Company currently is
operating four drilling rigs in its West Tavaputs project area
(100% working interest). For the first seven months of 2005,
the Company drilled seven wells to the Mesaverde and Wasatch
formations in the West Tavaputs development area. Three wells
have been completed and four are waiting on completion. Initial
production in these recently completed wells ranged between
1.1 MMcfd to 3.1 MMcfd (gross). The Company also has spud its
first deep test well in West Tavaputs, the #6-7 Peters Point
well, which is being directionally drilled. The Company expects
to reach total depth of 15,700 feet in late August to test the
potential of the Dakota, Entrada, Navajo and Wingate formations
identified on the Company's Stone Cabin 3-D seismic survey.
The Company has budgeted $55 million to drill a total of 14
wells in 2005, complete four wells that were drilled in 2004,
and recomplete four wells before the onset of winter restrictions
in mid-November.
Lake Canyon -- The Company is proceeding with
field activities to acquire a 57-square-mile 3-D seismic survey
over the next several months. The Company will use the results
to drill a 14,700 foot Mesaverde test (75% working interest)
that is expected to spud before year end. The Company also plans
to participate in two 6,500 foot Green River formation test
wells (working interest range 18.75% to 25%) that are expected
to spud before year end.
Garmesa -- At the Cedar Camp prospect, the
Company is waiting on pipeline connection to evaluate the Dakota,
Entrada and Wingate formations after completing two wells (working
interest 80%) drilled during the first half of 2005. The Company
drilled one exploratory dry hole in this area in 2005.
Powder River Basin, Wyoming
The Company currently has eight CBM rigs drilling
in the Powder River Basin targeting two pilot areas and one
development area in the Big George formation. In the first seven
months of 2005, the Company drilled two Wyodak wells and 71
Big George wells. Those wells drilled in our pilot areas, Cat
Creek and Dead Horse, are in the initial stages of de-watering.
For 2005, the Company expects to drill a total of 219 CBM wells.
Williston Basin, Montana and North Dakota
Red Bank/Target -- In the first half of 2005,
the Company drilled two horizontal wells, of which one is producing
and one is in the process of completion. These wells targeted
the Mississippian Ratcliff formation offsetting a successful
exploratory well drilled by the Company last year. The completed
well averaged over 230 barrels of oil per day (Bopd) (gross)
in it first month of production. The Company has working interests
in these wells ranging from 92% to 95%. The Company has identified
another six locations in the Target Field area with working
interests that range from 50% to 100%.
Red Water -- The Company is negotiating to
sell a 50% working interest in this exploratory project to an
industry partner. The Company would retain a 50% working interest
and 10,287 net undeveloped acres and expects to drill its first
horizontal well by year end to test the Bakken formation. Red
Water is an exploratory project that extends northwest from
the Bakken trend.
Grand River -- Subsequent to the joint exploration
agreement that was executed with an industry partner in the
second quarter, the Company expects to spud its first horizontal
Red River B test well (60% working interest) by the fourth quarter
of 2005 in the Grand River area.
Nameless and Indian Hills -- The Company participated
in a successful, nonoperated dual lateral horizontal Ratcliffe/Rival
well in the Nameless area, the Snider 1-11H (working interest
41%) well, which currently is producing 130 Bopd (gross). This
quarter, the Company expects to drill an offset (87% working
interest) to this well. In the Indian Hills area, the Company
completed one horizontal Rival formation well, and plans to
drill another Ratcliffe formation well before year end.
Mondak -- In the first half of 2005, the Company
participated in the completion of a horizontal Bakken discovery
well, which had an initial production rate of 194 Bopd (gross)
(6% working interest) after stimulation. In the third quarter,
the Company plans to participate in another Bakken horizontal
well two miles southwest of the discovery and has identified
an additional four drilling locations.
Denver-Julesburg Basin, Colorado/Kansas/Nebraska
In the first half of 2005, the Company drilled
two Niobrara wells, one vertical and one horizontal, in the
Tri-State Prairie Star area (50% working interest). The Company
and its partner are testing both wells and assessing the feasibility
of connecting them to pipeline. The Company is near completion
of its 530 linear mile 2-D seismic survey and plans to acquire
up to 100 square miles of 3-D seismic before year end.
Big Horn Basin, Wyoming
As of June 30, 2005, the Company had acquired
a total of 112,295 net undeveloped acres (70% working interest)
in this exploration project, along with a 100% working interest
in a wellbore that had previously produced 3.5 Bcfe from the
Muddy formation. The Company plans to re-enter the well and
test several other formations.
Hedging Update
The Company recently entered into the following
previously unannounced cashless collars for natural gas and
oil:
Daily Quantity Floor-Ceiling
Volume Type Price Index Price Contract Period
5,000 MMBtu $5.25-$10.60 Colorado Interstate Aug-Dec 2005
Gas (CIG)
4,000 MMBtu $5.25-$12.05 CIG Jan-Dec 2006
29,000 MMBtu $5.25-$10.22 CIG Jan-Dec 2007
50 Bbls $50.00-$81.10 WTI Jan-Dec 2006
600 Bbls $50.00-$78.15 WTI Jan-Dec 2007
Conference call to discuss second quarter results
As previously announced, a conference call
to discuss second quarter results for the Company is scheduled
for 2:00 p.m. EDT (1:00 p.m. CDT, 12:00 p.m. MDT) on Thursday,
August 4, 2005. The call participation number is 1-800-344-0624
in the U.S. and Canada (1-706-643-1890 outside the U.S. and
Canada) and the passcode is 7922211. Access to a live Internet
broadcast will be available at www.billbarrettcorp.com
by clicking on the link entitled "Webcasts." A webcast archive
will be made available approximately one hour after the conference
call at www.billbarrettcorp.com.
A telephonic replay will also be available approximately two
hours after the call on Thursday, August 4, 2005 and will continue
to be available through Saturday, August 6, 2005. The replay
telephone number is 1-800-642-1687 in the U.S. and Canada (1-706-645-9291
outside the U.S. and Canada) and the passcode is 7922211.
Forward-Looking Statements and Cautionary
Statements
This press release and certain statements
in the presentation are forward-looking within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of
the Securities Exchange Act of 1934. These forward looking statements
reflect Bill Barrett Corporation's current views with respect
to future events, based on what we believe are reasonable assumptions.
No assurance can be given, however, that these events will occur.
These statements are subject to risks and uncertainties that
could cause actual results to differ materially including, among
other things, exploration results, market conditions, oil and
gas price volatility, uncertainties inherent in oil and gas
production operations and estimating reserves, unexpected future
capital expenditures, competition, the success of Bill Barrett
Corporation risk management activities, governmental regulations
and other factors discussed in the Company's Annual Report on
Form 10-K for the year ended December 31, 2004 filed with the
Securities and Exchange Commission (www.sec.gov).
About Bill Barrett Corporation
Bill Barrett Corporation, headquartered in
Denver, explores for and develops oil and natural gas in nine
basins and the overthrust belt in the Rocky Mountain region
of the United States. Additional information about the Company
may be found on its web site www.billbarrettcorp.com
.
The following is a summary of our operational
and financial highlights. The financial statements that follow
are unaudited and subject to adjustment.
Bill Barrett Corporation
Selected Operating Highlights
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2005 2004 2005 2004
Production Data:
Natural gas (MMcf) 7,813 7,360 15,526 14,060
Oil (MBbls) 124 119 250 228
Combined volumes (MMcfe) 8,557 8,074 17,026 15,428
Daily combined volumes
(Mmcfe/d) 94 89 94 85
Average Prices (includes
effects of hedges):
Natural gas (per Mcf) $6.20 $4.91 $6.04 $4.88
Oil (per Bbl) 44.73 36.01 43.70 34.53
Combined (per Mcfe) 6.31 5.01 6.15 4.95
Average Costs (per Mcfe):
Lease operating expense $0.52 $0.52 $0.52 $0.47
Gathering and
transportation expense 0.34 0.17 0.33 0.16
Production tax expense 0.75 0.64 0.77 0.62
Depreciation, depletion
and amortization 2.24 2.30 2.29 2.01
General and administrative
(excluding stock based
compensation) 0.69 0.57 0.68 0.56
Bill Barrett Corporation
Consolidated Statements of Operations
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2005 2004 2005 2004
(in thousands, except per share amounts)
Revenues:
Oil and gas production $53,962 $40,450 $104,647 $76,442
Other 487 1,949 1,708 2,398
Total revenues $54,449 $42,399 $106,355 $78,840
Operating Expenses:
Lease operating expense 4,413 4,174 8,894 7,187
Gathering and
transportation expense 2,881 1,339 5,604 2,491
Production tax expense 6,419 5,189 13,029 9,565
Exploration expense 684 1,334 2,665 2,813
Impairment expense 36,343 -- 36,343 --
Dry hole costs 2,647 278 7,332 281
Depreciation, depletion
and amortization 19,177 18,580 38,954 31,002
General and administrative 5,878 4,562 11,555 8,571
Stock based compensation 778 970 1,478 2,237
Total operating expenses 79,220 36,426 125,854 64,147
Operating income (loss) (24,771) 5,973 (19,499) 14,693
Other Income and Expense:
Interest income 502 67 1,041 128
Interest expense (496) (789) (1,002) (1,383)
Total other income
and expense 6 (722) 39 (1,255)
Income (Loss) before
Income Taxes (24,765) 5,251 (19,460) 13,438
Provision for (Benefit
from) Income Taxes (8,894) 2,216 (6,643) 5,666
Net Income (Loss) (15,871) 3,035 (12,817) 7,772
Less cumulative dividends
on preferred stock n/a (4,805) n/a (9,338)
Net loss attributable
to common stock $(15,871) $(1,770) $(12,817) $(1,566)
Net Loss Per Common Share,
Basic and Diluted $(0.37) $(1.27) $(0.30) $(1.18)
Weighted Average Common
Shares Outstanding,
Basic and Diluted 43,186,922 1,397,796 43,136,115 1,325,686
Bill Barrett Corporation
Consolidated Condensed Balance Sheets
(Unaudited)
As of As of
June 30, December 31,
2005 2004
(in thousands)
Cash and cash
equivalents $35,699 $99,926
Other current assets 37,528 37,964
Property and equipment, net 617,232 552,165
Other non current assets 14,457 6,103
Total assets $704,916 $696,158
Current liabilities $86,761 $62,106
Note payable to bank -- --
Other non current liabilities 21,274 14,320
Stockholders' equity: 596,881 619,732
Total liabilities and
stockholders' equity $704,916 $696,158
Bill Barrett Corporation
Consolidated Statement of Cash Flows
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2005 2004 2005 2004
Operating Activities:
Net Income (Loss) ($15,871) $3,035 ($12,817) $7,772
Adjustments to reconcile to net cash
provided by operations:
Depreciation, depletion and
amortization 19,177 18,580 38,954 31,002
Deferred income taxes (8,894) 2,216 (6,643) 5,666
Dry hole costs, abandonments,
and impairment expense 38,990 278 43,675 281
Stock compensation and other non-
cash charges 733 990 1,405 2,319
Amortization of deferred financing
costs 281 121 563 207
Gain on sale of properties (371) (1,917) (1,465) (2,335)
Change in current assets and
liabilities:
Accounts receivable (869) (1,760) 5,401 (6,476)
Prepayments and other current assets (872) (989) (370) (1,398)
Accounts payable, accrued and other
liabilities (2,933) 1,409 (3,112) (1,817)
Amounts payable to oil and gas
property owners (609) 271 1,476 1,404
Production taxes payable 4,202 3,436 7,606 6,221
Net cash provided by operating
activities 32,964 25,670 74,673 42,846
Investing Activities:
Additions to oil and gas properties (86,376) (36,069) (144,315) (80,553)
Additions of furniture, equipment
and other (865) (486) (1,405) (914)
Proceeds from sale of properties 1,052 2,237 6,580 7,206
Net cash used in investing
activities (86,189) (34,318) (139,140) (74,261)
Financing Activities:
Proceeds from debt -- 19,000 -- 45,000
Principal payments on debt -- (17,000) -- (37,000)
Proceeds from sale of common and
preferred stock 141 13,654 290 33,760
Deferred financing costs and other 39 (536) (50) (1,554)
Net cash provided by financing
activities 180 15,118 240 40,206
Increase (Decrease) in Cash and Cash
Equivalents (53,045) 6,470 (64,227) 8,791
Beginning Cash and Cash Equivalents 88,744 18,355 99,926 16,034
Ending Cash and Cash Equivalents $35,699 $24,825 $35,699 $24,825
Bill Barrett Corporation
Reconciliation of Discretionary Cash Flow (1) from Net Income (Loss)
Three Months Ended Six Months Ended
June 30, June 30,
2005 2004 2005 2004
(in thousands)
Net Income (Loss) ($15,871) $3,035 ($12,817) $7,772
Adjustments to reconcile to
discretionary cash flow (1):
Depreciation, depletion and
amortization 19,177 18,580 38,954 31,002
Dry hole costs, abandonments
and impairment expense 38,990 278 43,675 281
Exploration expense 684 1,334 2,665 2,813
Deferred income taxes (8,894) 2,216 (6,643) 5,666
Stock compensation and other non
cash items 733 990 1,405 2,319
Amortization of deferred financing
costs 281 121 563 207
Gain on sale of properties (371) (1,917) (1,465) (2,335)
Discretionary cash flow (1) $34,729 $24,637 $66,337 $47,725
(1) Discretionary cash flow is computed as net income plus depreciation,
depletion, amortization, impairment expenses, deferred income taxes,
exploration expenses, non-cash stock based compensation, gains on
sale of properties, and certain other non-cash charges. The non-GAAP
measure of discretionary cash flow is presented because management
believes that it provides useful additional information to investors
for analysis of the Company's ability to internally generate funds
for exploration, development and acquisitions. In addition,
discretionary cash flow is 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 many investors use the published research of
industry research analysts in making investment decisions.
Discretionary cash flow 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 under GAAP. Because discretionary cash
flow excludes some, but not all, items that affect net income and net
cash provided by operating activities and may vary among companies,
the discretionary cash flow amounts presented may not be comparable
to similarly titled measures of other companies.
