| | Published : November 04th, 2011 | Reports Third Quarter 2011 Results and Announces Further Encouraging Uinta Oil Results |
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Bill Barrett Corporation Reports
Third Quarter 2011 Results and Announces Further Encouraging Uinta Oil Results
DENVER, Nov. 3, 2011 /PRNewswire/ -- Bill Barrett Corporation (NYSE: BBG)
today reported third quarter 2011 operating results highlighted by:
- Natural gas and oil production growth, up 10% to 28.0
Bcfe compared with the third quarter of 2010
- Third and fourth Uteland Butte horizontal oil wells
showing strong initial flow rates
- Discretionary cash flow of $125.9 million or $2.65 per
diluted common share
- Net income of $20.6 million or $0.43 per diluted common
share and adjusted net income of $16.8 million or $0.35 per diluted common
share
- Issuing $400 million of 7.625% senior notes, providing
substantial liquidity
- Closing key Denver-Julesburg (�DJ�) oil acquisition,
adding 7 MMBoe proved reserves with 28,500 net acres
Chairman, Chief Executive Officer and President Fred Barrett commented:
�Solid execution on strategies to increase the oil mix in our portfolio
continued in the third quarter. Our build in oil is demonstrated on a few
fronts with September oil production representing a 42% increase since the
start of the year. Our acquisitions team closed on our DJ Basin acquisition,
adding a fourth key development area and another liquids-focused program. Our
operations team has completed two more horizontal Uteland Butte wells, both
with encouraging results from our Uinta Oil Program. Currently, oil and natural
gas liquids represent approximately 20% of our production based on energy
content and approximately 44% of pre-hedge revenue, driving our continued
emphasis on balancing the portfolio with liquids growth.
�We are very pleased to report continued positive results from the Uinta Oil
Program where the peak 24-hour initial production (�IP�) rates for the first
four horizontal Uteland Butte wells have averaged in excess of 1,000 barrels of
oil equivalent per day (�Boe/d�). To date, the first two horizontal wells are
producing as, or better than, expected. The third Uteland Butte horizontal well
flowed and pumped an average 707 Boe/d over the first 30 days of production and
had a peak 24-hour IP rate of 1,330 Boe/d, and the fourth Uteland Butte
horizontal well, which has been on production for only 21 days, has averaged
596 Boe/d and had a peak IP rate of 863 Boe/d during that period. It is too
early to estimate EURs from results to date, yet success in the Uteland Butte
would open the potential for inventory expansion in our sizable Uinta Oil
Program acreage position.
�As 2011 is nearing a close, we have added a third rig in the Uinta Oil
Program where we will soon commence drilling in the East Bluebell oil expansion
area. We have also recently added a rig in the DJ Basin, where we will continue
development in the Wattenberg Field and will soon drill our first horizontal
Niobrara test at our Chalk Bluffs exploration area. We are diligently working
to complete facility upgrades at West Tavaputs in order to keep pace with
production there. We have updated 2011 guidance to lower cost estimates for both
operating and transportation expenses while keeping production and capital
expenditure expectations unchanged (see �Guidance� below.) 2011 remains on
track to deliver solid growth while positioning the Company for an even
stronger year in 2012.�
Third quarter 2011 natural gas and oil production totaled 28.0 billion cubic
feet equivalent (�Bcfe�), up 10% from 25.5 Bcfe in the third quarter of 2010
and up 6% sequentially from the second quarter of 2011. For the first nine
months of 2011, production totaled 77.7 Bcfe, up 8% from the 2010 period. The
Company is on track for its full year guidance range of 106 to 110 Bcfe. Third
quarter production growth was predominantly from the West Tavaputs natural gas
program as well as the Uinta Oil Program and acquisition properties. Including
the effects of the Company�s hedging activities and natural gas liquids
recovery, the average realized sales price in the third quarter of 2011 was
$7..06 per thousand cubic feet equivalent (�Mcfe�) compared with $7.03 per Mcfe
in the third quarter of 2010. The Company�s commodity hedging program increased
third quarter 2011 natural gas and oil revenues by net $16.8 million, or $0.60
per Mcfe of production. The incremental revenue benefit from processing a
portion of its natural gas for natural gas liquids increased to $1.41 per Mcfe
in the third quarter of 2011, reflecting strong natural gas liquids pricing in
the period and inclusion of incremental NGL benefits from West Tavaputs and the
DJ Basin.
Discretionary cash flow (a non-GAAP measure, see �Discretionary Cash Flow
Reconciliation� below) in the third quarter of 2011 was $125.9 million, or
$2.65 per diluted common share, compared with $136.5 million, or $2.98 per
diluted common share, in the third quarter of 2010. Discretionary cash flow was
down from the comparable 2010 period primarily due to a one-time adjustment
from current to deferred tax expense in the 2010 period totaling $13.1 million.
Discretionary cash flow for the first nine months of 2011 was $353.4 million,
down 1% from $357.1 million in the first nine months of 2010.
Net income in the third quarter of 2011 was $20.6 million, or $0.43 per
diluted common share, compared with $24.6 million, or $0.54 per diluted common
share, in the third quarter of 2010. The decline in net income was primarily
due to higher impairment, dry hole and abandonment expense in the 2011 period.
Dry hole expense in the third quarter of 2011 was $11.0 million ($6.9 million
net of tax) and included the McRae Gap exploration well in the Wind River Basin
and interests in two exploratory wells in the north end of the DJ Basin. Net
income for the first nine months of 2011 was $68.5 million, down 22% from the
first nine months of 2010, primarily due to higher derivative losses and higher
impairment, dry hole and abandonment expenses. Adjusted net income for the
third quarter of 2011 (a non-GAAP measure, see �Adjusted Net Income
Reconciliation� below) was $16.8 million, or $0.35 per diluted common share,
compared with $24.0 million, or $0.52 per diluted common share, in the third
quarter of 2010. The decline in adjusted net income was primarily due to the
higher dry hole cost in the 2011 period, which is not added back in the
adjusted net income calculation. Adjusted net income removes the effect of non-recurring
charges such as unrealized derivative gains and losses, impairment expenses,
property sales and one-time items.
DEBT AND LIQUIDITY
At September 30, 2011, the Company�s revolving credit facility was undrawn.
Subsequent to quarter-end, the Company increased its borrowing base to $1.1
billion and bank commitments to $900.0 million, while extending the maturity of
the credit facility to October 2016. After deducting an outstanding letter of
credit for $26.0 million, borrowing capacity is currently $874.0 million.
During the quarter, the Company completed the offering of $400 million of
7.625% senior notes due 2019, issued at par. Proceeds from the offering were
used to pay down the Company�s revolving credit facility. The Company also had
$172.5 million in 5% convertible senior notes and $250.0 million in 9.875%
senior notes outstanding at September 30, 2011.
OPERATIONS
Production, Wells Spud and Capital Expenditures
The following table lists production, wells spud and total capital
expenditures by basin for the three months and nine months ended September 30,
2011:
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Three
Months ended September 30, 2011
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Nine
Months ended September 30, 2011
|
|
|
Average
Net
|
|
Wells
|
|
Capital
|
|
Average
Net
|
|
Wells
|
|
Capital
|
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Production
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|
Spud
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|
Expenditures
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|
Production
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|
Spud
|
|
Expenditures
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|
Basin
|
(MMcfe/d)
|
|
(gross)
|
|
(millions)
|
|
(MMcfe/d)
|
|
(gross)
|
|
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Piceance
|
134
|
|
32
|
|
$
55.2
|
|
133
|
|
83
|
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$
149.5
|
|
Uinta
|
116
|
|
45
|
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104.0
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|
99
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|
102
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383.0
|
|
Powder River (CBM)
|
36
|
|
1
|
|
0.3
|
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36
|
|
6
|
|
3.8
|
|
Wind River
|
15
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0
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2.4
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15
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0
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3.9
|
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Other
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4
|
|
4
|
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162..9
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2
|
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16
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192..6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total
|
305
|
|
82
|
|
$
324.8
|
|
285
|
|
207
|
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$
732.8
|
|
|
|
|
|
|
|
|
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Capital expenditures totaled $324.8 million for the third quarter of 2011,
including the acquisition of properties in the DJ Basin for $149.1 million.
Operating and Drilling Update
The Company anticipates participating in the drilling of approximately 300
gross wells in 2011, including approximately 6 coal bed methane (�CBM�) wells.
The Company currently has eight active operated drilling rigs with two at West
Tavaputs, two at Gibson Gulch, three at the Uinta Oil Program and one at the DJ
Basin acquisition area. The Company�s development program is focused on growth
in production and reserves as well as driving operating efficiencies at West
Tavaputs.
Uinta Basin, Utah
West Tavaputs � Current net production is approximately 100 million
cubic feet equivalent per day (�MMcfe/d�). The Company continues to
successfully execute its development program in the area and is on track for
its approximate 100-well program for 2011. Due to increased drilling
efficiencies and better than expected well performance at certain wells,
production increased faster than anticipated, and the Company is currently
installing a loop line and additional compression capacity. New capacity will
be in place in the first quarter of 2012 that will support future production.
West Tavaputs is one of the Company�s largest development assets based on its
current reserve base of 345 Bcfe proved and 1.3 Tcfe proved, probable and
possible reserves (see �Reserve Disclosure� below), providing a multi-year,
high growth program for the Company.
At September 30, 2011, the Company had an approximate 97% working interest
in production from 235 gross wells in its West Tavaputs shallow and deep
programs. The West Tavaputs development program primarily targets the shallow
Mesaverde and Wasatch zones. Upside potential is also recognized in the shallow
Green River oil zones and deeper formations including the Mancos.
Uinta Oil Program (Blacktail Ridge, Lake Canyon and East Bluebell) �
Current net production is approximately 4,400 Boe/d. The Company added a third
rig to the area in early October 2011. This area offers upside potential
through horizontal drilling, increased density and field extension.
During the third quarter of 2011, the Company continued horizontal drilling
into the Uteland Butte formation (working interest 55.8% for first four wells).
The third well was completed in the Uteland Butte at approximately 5,850� with
a 3,400� lateral and 15 fracture stimulation stages and flowed and pumped an
average 707 Boe/d over the first 30 days of production with a peak 24-hour IP
rate of 1,330 Boe/d. The fourth well was completed to approximately 5,900� with
a 3,200� lateral and 15 fracture stimulation stages and had a peak IP rate of
863 Boe/d during the 21 days it has been on production. The Company intends to
drill a total of seven horizontal wells targeting the Uteland Butte formation
by year-end. The Company expects to sizably increase its well inventory at the
Uinta Oil Program with continued success in both its vertical and horizontal
drilling plans.
The Company also completed a vertical test well into the Mahogany formation
to 5,500� with 245� of core. Core tests in the Mahogany formation were positive
and the well is recovering oil. The Company is currently permitting for two
additional vertical test wells it expects to drill in mid-2012.
At September 30, 2011, the Company had an approximate 68% working interest
in production from 105 gross wells in the combined area. The working interests
in this area range from 19% to 100%.
Piceance Basin, Colorado
Gibson Gulch � Current net production is approximately 138 MMcfe/d.
The Company continues to operate two rigs in the area and expects to complete a
100-plus well program in 2011. The Company continues to benefit from its
election to process the majority of its Gibson Gulch natural gas production,
which exposes the Company to natural gas liquids pricing. Gibson Gulch
operations offer strong margins due to low operating costs and the currently
higher revenues related to liquids. The program continues to be a key, lower
risk development area for the Company.
At September 30, 2011, the Company had an approximate 98% working interest
in production from 792 gross wells in its Gibson Gulch program.
Denver-Julesburg Basin, Colorado and Wyoming
Wattenberg/Chalk Bluffs/Sagebrush � The Company has approximately
67,500 net acres in the DJ Basin, a fourth key development area for the
Company. The Company closed on its DJ Basin acquisition in August, took over
operations as of September and initiated drilling in mid-October. Drilling
commenced in the Wattenberg area, where current production is from the Codell,
Niobrara and J Sand formations. Following four-to-five vertical wells in the
Wattenberg Field, the Company plans to initiate exploration drilling in the
area, targeting the Niobrara shale formation through horizontal wells.
During the third quarter of 2011, the Company completed its first DJ Basin
exploration well and had a small participation interest in a second well, both
located in the northern DJ Basin, north of the Company�s recent acquisition,
which did not produce commercial quantities of oil and were expensed as dry
holes.
Wind River Basin, Wyoming
McRae Gap - The Company has identified approximately 100,000 net
undeveloped acres within its acreage position in the area that it considers
prospective for Niobrara shale oil. In the third quarter of 2011, the Company
completed its first horizontal exploration well into the lower bench of the
Niobrara shale at approximately 8,000� in depth with an approximate 3,200�
lateral and 13 fracture stimulation stages. While the first exploration well in
the area produced only minor amounts of oil, the Company is reviewing data to
refine its drilling focus in the prospect. In the third quarter, this $5.7
million McRae Gap well was expensed as a dry hole.
ADDITIONAL FINANCIAL INFORMATION
Guidance
The Company�s 2011 guidance (please reference �Forward-Looking Statements�
below) is updated as follows:
- Capital expenditures for exploration and development of
$685 to $705 million, unchanged. This amount is before acquisition
purchase costs totaling approximately $268 million through the first nine
months.
- Oil and natural gas production of 106 to 110 Bcfe,
unchanged.
- Lease operating costs per Mcfe of $0.53 to $0.55,
reduced and narrowed from $0.54 to $0.58 as a result of effective cost
discipline across operations.
- Gathering, transportation and processing costs per Mcfe
of $0.87 to $0.89, lowered from $0.89 to $0.93.
- General and administrative expenses before non-cash
stock-based compensation between $47.5 and $48.5 million, increased from
$46.0 and $47.5 million, mostly due to higher employee costs and
headcount.
Commodity Hedges Update
It is the Company�s strategy to hedge a portion of its production to reduce
the risks associated with unpredictable future commodity prices and to provide
predictability for a portion of cash flows in order to support the Company�s
capital expenditure program.
For the fourth quarter of 2011 and for 2012, the Company has hedges in place
as outlined in the table below. Swap and collar hedge positions are tied to
regional sales points and include:
- For the fourth quarter of 2011, approximately 18.7 Bcfe
at a weighted average blended floor price of $7.30 per Mcfe.
- For 2012, approximately 51.7 Bcfe at a weighted average
blended floor price of $7.27 per Mcfe.
As of October 31, 2011:
SWAPS
& COLLARS
|
|
|
|
|
|
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|
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Period
|
|
Natural
Gas / NGLs
|
|
Oil
|
|
Equivalent
|
|
|
|
Volume
|
Price
|
|
Volume
|
Price
|
|
Volume
|
Price
|
|
|
|
MMBtu/d
|
$/MMBtu
|
|
Bbl/d
|
$/Bbl
|
|
MMcfe
|
$/Mcfe
|
|
|
|
|
|
|
|
|
|
|
|
|
4Q11
|
|
202,221
|
$
5.82
|
|
3,300
|
$
93.66
|
|
18,735
|
$
7.30
|
|
1Q12
|
|
169,223
|
$
5.10
|
|
3,400
|
$
100.88
|
|
15,856
|
$
6.92
|
|
2Q12
|
|
133,131
|
$
5.11
|
|
3,400
|
$
100.88
|
|
12,870
|
$
7.24
|
|
3Q12
|
|
133,069
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$
5.11
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|
3,400
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$
100.88
|
|
13,006
|
$
7.23
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|
4Q12
|
|
96,602
|
$
5.31
|
|
3,400
|
$
100.88
|
|
9,956
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$
7.91
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In addition, the Company has natural gas basis only hedges in place for the
fourth quarter of 2011 for 20,000 MMBtu/d at a basis differential price between
CIG Rocky Mountains and Henry Hub of ($1.72) per MMBtu and for 2012 of 20,000
MMBtu/d at a basis differential price of ($1.22) per MMBtu. These hedges are
not in the money.
THIRD QUARTER 2011 WEBCAST AND CONFERENCE CALL
As previously announced, a webcast and conference call will be held later
this morning to discuss third quarter 2011 results. Please join Bill Barrett
Corporation executive management at 12:00 p.m. Eastern time (�ET�)/10:00 a.m.
Mountain time (�MT�) for the live webcast, accessed at www.billbarrettcorp.com,
or join by telephone by calling 866-761-0748 (617-614-2706 international
callers) with passcode 68573156. The webcast will remain available on the
Company�s website for approximately 30 days, and a replay of the call will be
available through November 10, 2011 at call-in number 888-286-8010
(617-801-6888 international) with passcode 69611288. The Company also has
tentatively scheduled its fourth quarter 2011 earnings conference call for
February 23, 2012 at noon ET/10:00 a.m. MT.
UPCOMING EVENTS
Updated investor presentations will be posted to the homepage of the
Company�s website at www.billbarrettcorp.com
for each event below. Please check the website at 5:00 p.m. MT on the business
day prior to the investor event for the most recent presentation, unless
otherwise noted:
Investor Conferences
Chief Financial Officer Bob Howard will participate at the Barclays Capital
Second Annual Energy, Engineering and Construction Forum in Dallas on November
10, 2011. An updated investor presentation will be posted at 5:00 p.m. MT on
Tuesday, November 8, 2011.
Chief Operating Officer Scot Woodall will present at the Bank of America
Merrill Lynch Global Energy Conference in Miami on November 15, 2011 at 1:20
p.m. ET. The event will be webcast.
Chief Financial Officer Bob Howard will present at the Bank of America
Merrill Lynch Leveraged Finance Conference in Orlando on December 2, 2011 at
10:50 a.m. ET. The event will be webcast. The presentation for this event will
be posted at 5:00 p.m. MT on Wednesday, November 30, 2011.
DISCLOSURE STATEMENTS
Forward-Looking Statements
This press release contains forward-looking statements, including statements
regarding projected results and future events, including guidance and the
upside potential and other prospects of acquisitions and other planned
activities. These forward-looking statements are based on management�s judgment
as of this date and include certain risks and uncertainties. Please refer to
the Company�s Annual Report on Form 10-K for the year-ended December 31, 2010
filed with the SEC, and other filings including our Quarterly Report on Form
10-Q for the quarter ended September 30, 2011 and Current Reports on Form 8-K,
for a list of certain risk factors.
Actual results may differ materially from Company projections and can be
affected by a variety of factors outside the control of the Company including,
among other things, market conditions, oil and gas price volatility,
exploration and development drilling and testing results, performance of
acquired properties, the ability to receive drilling and other permits and
rights-of-way, regulatory approvals, governmental laws and regulations and
changes in enforcement of those laws and regulations, new laws and regulations,
risks related to and costs of hedging activities including counterparty
viability, surface access and costs, availability of third party gathering,
transportation and processing, the availability and cost of services and
materials, 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, availability and costs of financing to fund the
Company�s operations, uncertainties inherent in oil and gas production
operations and estimating reserves, the speculative actual recovery of
estimated potential volumes, unexpected future capital expenditures,
competition, risks associated with operating in one major geographic area, the
success of the Company�s risk management activities, title to properties,
litigation, environmental liabilities, and other factors discussed in the
Company�s reports filed with the SEC. Bill Barrett Corporation encourages
readers to consider the risks and uncertainties associated with projections and
other forward-looking statements. In addition, the Company assumes no
obligation to publicly revise or update any forward-looking statements based on
future events or circumstances.
Reserve Disclosure
The SEC, under its recently revised guidelines, permits oil and gas
companies to disclose probable and possible reserves in their filings with the
SEC. The Company does not plan to include probable and possible reserve
estimates in its filings with the SEC.
The Company has provided internally generated estimates for probable and
possible reserves in this release. The estimates conform to SEC guidelines.
They are not prepared or reviewed by third party engineers. Our probable and
possible reserve estimates are determined using strip pricing, which we use
internally for planning and budgeting purposes. The Company's estimate of
probable and possible reserves is provided in this release because management
believes it is useful, additional information that is widely used by the
investment community in the valuation, comparison and analysis of companies.
U.S. investors are urged to consider closely the disclosure in our Annual
Report on Form 10-K for the year ended December 31, 2010, available on the
Company's website at www.billbarrettcorp.com
or from the corporate offices at 1099 18th Street, Suite 2300, Denver, CO
80202. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or
at www.sec.gov.
ABOUT BILL BARRETT CORPORATION
Bill Barrett Corporation (NYSE: BBG), headquartered in Denver, Colorado,
explores for and develops natural gas and oil 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
|
|
Nine
Months Ended
|
|
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
|
|
2011
|
2010
|
|
2011
|
2010
|
|
Production Data:
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
25,655
|
23,540
|
|
71,596
|
67,505
|
|
|
Oil (MBbls)
|
|
|
396
|
322
|
|
1,024
|
795
|
|
|
Combined volumes
(MMcfe)
|
|
|
28,031
|
25,472
|
|
77,740
|
72,275
|
|
|
Daily combined
volumes (Mmcfe/d)
|
|
|
305
|
277
|
|
285
|
265
|
|
Average Prices
(before the effects of realized hedges):
|
|
|
|
|
|
|
|
|
|
Natural gas (per
Mcf)
|
|
|
$
5.87
|
$
4.77
|
|
$
5.81
|
$
5.32
|
|
|
Oil (per Bbl)
|
|
|
76.81
|
64.65
|
|
82.15
|
66.43
|
|
|
Combined (per Mcfe)
|
|
|
6.46
|
5.23
|
|
6.43
|
5.70
|
|
Average Realized
Prices (after the effects of realized hedges):
|
|
|
|
|
|
|
|
|
|
Natural gas (per
Mcf)
|
|
|
$
6.48
|
$
6.67
|
|
$
6.54
|
$
6.83
|
|
|
Oil (per Bbl)
|
|
|
79.79
|
68.57
|
|
80.24
|
69.49
|
|
|
Combined (per Mcfe)
|
|
|
7.06
|
7.03
|
|
7.08
|
7.14
|
|
Average Costs (per
Mcfe):
|
|
|
|
|
|
|
|
|
|
Lease operating
expense
|
|
|
$
0.49
|
$
0.51
|
|
$
0.53
|
$
0.54
|
|
|
Gathering,
transportation and processing expense
|
|
|
0.91
|
0.68
|
|
0.85
|
0.72
|
|
|
Production tax
expense
|
(1)
|
|
0.39
|
0.32
|
|
0.38
|
0.35
|
|
|
Depreciation,
depletion and amortization
|
|
|
2.72
|
2.72
|
|
2.71
|
2.65
|
|
|
General and
administrative expense,
|
|
|
|
|
|
|
|
|
|
excluding non-cash stock-based compensation
|
(2)
|
|
0.45
|
0.41
|
|
0.47
|
0.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Production tax
expense for the first nine months of 2010 includes a one-time benefit to
reduce and re-estimate prior periods as a result of amended returns filed
with the State of Utah regarding the calculation of severance taxes.
Exclusive of the one-time benefits, the production tax expense per Mcfe
for the first nine months of 2010 would have been $0..38.
|
|
|
|
|
|
|
|
|
|
|
|
(2)
|
Management believes
the separate presentation of the non-cash component of general and
administrative expense is useful because the cash portion provides a better
understanding of cash required for general and administrative expenses.
Management also believes that this disclosure may allow for a more accurate
comparison to the Company's peers that may have higher or lower costs
associated with equity grants.
|
|
|
|
|
|
|
|
|
|
|
|
BILL
BARRETT CORPORATION
|
|
Consolidated
Statements of Operations
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
(in thousands,
except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and Other
Revenues:
|
|
|
|
|
|
|
|
|
|
|
Oil and gas
production
|
(1)
|
$
206,611
|
|
$
185,007
|
|
$
573,136
|
|
$
534,956
|
|
|
Commodity derivative
gain (loss)
|
(1)
|
1,285
|
|
(4,934)
|
|
(12,734)
|
|
(2,922)
|
|
|
Other
|
|
769
|
|
558
|
|
4,028
|
|
3,032
|
|
|
Total operating and other revenues
|
|
208,665
|
|
180,631
|
|
564,430
|
|
535,066
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
13,683
|
|
13,001
|
|
41,057
|
|
39,023
|
|
|
Gathering,
transportation and processing
|
|
25,431
|
|
17,301
|
|
66,105
|
|
51,758
|
|
|
Production tax
|
(2)
|
10,946
|
|
8,193
|
|
29,293
|
|
25,524
|
|
|
Exploration
|
|
554
|
|
3,841
|
|
2,602
|
|
4,796
|
|
|
Impairment, dry hole
costs and abandonment
|
|
17,187
|
|
4,653
|
|
18,563
|
|
8,520
|
|
|
Depreciation,
depletion and amortization
|
|
76,165
|
|
69,192
|
|
210,406
|
|
191,626
|
|
|
General and
administrative
|
(3)
|
12,743
|
|
10,557
|
|
36,549
|
|
30,560
|
|
|
Non-cash stock-based
compensation
|
(3)
|
5,052
|
|
3,428
|
|
13,699
|
|
11,169
|
|
|
Total operating expenses
|
|
161,761
|
|
130,166
|
|
418,274
|
|
362,976
|
|
Operating Income
|
|
46,904
|
|
50,465
|
|
146,156
|
|
172,090
|
|
Other Income and
Expense:
|
|
|
|
|
|
|
|
|
|
|
Interest income and
other income (expense)
|
|
(2)
|
|
231
|
|
163
|
|
356
|
|
|
Interest expense
|
|
(14,015)
|
|
(11,170)
|
|
(38,378)
|
|
(32,492)
|
|
|
Total other income and expense
|
|
(14,017)
|
|
(10,939)
|
|
(38,215)
|
|
(32,136)
|
|
Income before Income
Taxes
|
|
32,887
|
|
39,526
|
|
107,941
|
|
139,954
|
|
Provision for Income
Taxes
|
|
12,251
|
|
14,964
|
|
39,454
|
|
52,217
|
|
Net Income
|
|
|
$
20,636
|
|
$
24,562
|
|
$
68,487
|
|
$
87,737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Per
Common Share
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
0.44
|
|
$
0.54
|
|
$
1.48
|
|
$
1.95
|
|
|
Diluted
|
|
$
0.43
|
|
$
0.54
|
|
$
1.45
|
|
$
1.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
Common Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
46,735
|
|
45,206
|
|
46,417
|
|
45,067
|
|
|
Diluted
|
|
47,527
|
|
45,791
|
|
47,125
|
|
45,595
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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,
|
|
|
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
|
Included in oil and
gas production revenue:
|
|
|
|
|
|
|
|
|
|
|
Realized gain on
cash flow hedges
|
|
$
25,525
|
|
$
51,841
|
|
$
73,223
|
|
$
122,739
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in
commodity derivative gain (loss):
|
|
|
|
|
|
|
|
|
|
|
Realized loss on
derivatives not designated as
|
|
|
|
|
|
|
|
|
|
|
cash flow
hedges
|
|
$
(8,711)
|
|
$
(5,941)
|
|
$
(22,705)
|
|
$
(18,927)
|
|
|
Unrealized
ineffectiveness gain (loss) recognized
|
|
|
|
|
|
|
|
|
|
|
on
derivatives designated as cash flow hedges
|
|
(18)
|
|
(781)
|
|
1,032
|
|
(1,047)
|
|
|
Unrealized gain on
derivatives
|
|
|
|
|
|
|
|
|
|
|
not
designated as cash flow hedges
|
|
10,014
|
|
1,788
|
|
8,939
|
|
17,052
|
|
|
Total
commodity derivative gain (loss)
|
|
$
1,285
|
|
$
(4,934)
|
|
$
(12,734)
|
|
$
(2,922)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2)
|
Production tax
expense for the first nine months of 2010 period includes a one-time
benefit to reduce and re-estimate prior periods as a result of amended
returns filed with the State of Utah regarding the calculation of severance
taxes.
|
|
|
|
|
|
|
|
|
|
|
|
|
(3)
|
Management believes
the separate presentation of the non-cash component of general and
administrative expense is useful because the cash portion provides a better
understanding of cash required for general and administrative expenses.
Management also believes that this disclosure may allow for a more accurate
comparison to the Company's peers that may have higher or lower costs
associated with equity grants.
|
|
|
|
|
|
|
|
|
|
|
|
|
BILL
BARRETT CORPORATION
|
|
Consolidated
Condensed Balance Sheets
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
of
|
|
As
of
|
|
|
|
|
|
September
30, 2011
|
|
December
31, 2010
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
105,219
|
|
$
58,690
|
|
|
Other current assets
|
(1)
|
162,042
|
|
148,958
|
|
|
Property and
equipment, net
|
|
2,327,555
|
|
1,811,819
|
|
|
Other noncurrent
assets
|
|
42,816
|
|
19,033
|
|
|
|
Total assets
|
|
$
2,637,632
|
|
$
2,038,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and
Stockholders' Equity:
|
|
|
|
|
|
|
Current liabilities
|
(1)
|
$
194,740
|
|
$
165,957
|
|
|
Notes payable to
bank
|
|
-
|
|
-
|
|
|
Senior notes
|
|
640,829
|
|
239,766
|
|
|
Convertible senior
notes
|
|
169,354
|
|
164,633
|
|
|
Other long-term
liabilities
|
(1)
|
382,801
|
|
327,182
|
|
|
Stockholders' equity
|
|
1,249,908
|
|
1,140,962
|
|
|
|
Total liabilities
and stockholders' equity
|
|
$
2,637,632
|
|
$
2,038,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
At September 30,
2011, the estimated fair value of all of our commodity derivative instruments
was a net asset of $82.7 million, comprised of: $64.0 million current assets;
$0.8 million current liabilities; $20.1 million non-current assets; and $0.6
million non-current liabilities. This amount will fluctuate quarterly
based on estimated future commodity prices and the current hedge position.
|
|
|
|
|
BILL
BARRETT CORPORATION
|
|
Consolidated
Statements of Cash Flows
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
|
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Activities:
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
20,636
|
|
$
24,562
|
|
$
68,487
|
|
$
87,737
|
|
|
Adjustments to
reconcile to net cash
|
|
|
|
|
|
|
|
|
|
|
provided by
operations:
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
76,165
|
|
69,192
|
|
210,406
|
|
191,626
|
|
|
|
Impairment, dry hole
costs and abandonment expense
|
|
17,187
|
|
4,653
|
|
18,563
|
|
8,520
|
|
|
|
Unrealized
derivative gain
|
|
(9,996)
|
|
(1,007)
|
|
(9,971)
|
|
(16,005)
|
|
|
|
Deferred income
taxes
|
|
12,267
|
|
28,068
|
|
39,470
|
|
60,350
|
|
|
|
Stock compensation
and other non-cash charges
|
|
5,613
|
|
3,926
|
|
15,958
|
|
12,253
|
|
|
|
Amortization of debt
discounts and deferred financing costs
|
|
3,429
|
|
3,170
|
|
9,849
|
|
8,831
|
|
|
|
Loss (gain) on sale
of properties
|
|
-
|
|
50
|
|
(2,009)
|
|
(999)
|
|
|
|
Change in assets and
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
7,335
|
|
(15)
|
|
(14,779)
|
|
(80)
|
|
|
|
|
Prepayments and
other assets
|
|
548
|
|
(7,332)
|
|
2,617
|
|
(10,303)
|
|
|
|
|
Accounts payable,
accrued and other liabilities
|
|
(8,838)
|
|
(6,392)
|
|
(12,152)
|
|
(9,943)
|
|
|
|
|
Amounts payable to
oil & gas property owners
|
|
300
|
|
3,777
|
|
7,761
|
|
5,446
|
|
|
|
|
Production taxes
payable
|
|
8,088
|
|
5,936
|
|
9,773
|
|
3,122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by
operating activities
|
|
$
132,734
|
|
$
128,588
|
|
$
343,973
|
|
$
340,555
|
|
Investing
Activities:
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and
gas properties, including acquisitions
|
|
(317,595)
|
|
(114,299)
|
|
(701,397)
|
|
(313,481)
|
|
|
Additions of
furniture, equipment and other
|
|
(2,986)
|
|
(453)
|
|
(5,758)
|
|
(2,091)
|
|
|
Proceeds from sale
of properties and other investing activities
|
|
(56)
|
|
(135)
|
|
1,804
|
|
2,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in
investing activities
|
|
$
(320,637)
|
|
$
(114,887)
|
|
$
(705,351)
|
|
$
(313,439)
|
|
Financing
Activities:
|
|
|
|
|
|
|
|
|
|
|
Proceeds from debt
|
|
585,000
|
|
-
|
|
730,000
|
|
20,000
|
|
|
Principal payments
on debt
|
|
(330,000)
|
|
-
|
|
(330,000)
|
|
(25,000)
|
|
|
Deferred financing
costs and other
|
|
(7,647)
|
|
(291)
|
|
(11,084)
|
|
(15,257)
|
|
|
Proceeds from stock
option exercises
|
|
5,913
|
|
8,121
|
|
18,991
|
|
10,508
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by
(used in) financing activities
|
|
$
253,266
|
|
$
7,830
|
|
$
407,907
|
|
$
(9,749)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in Cash and
Cash Equivalents
|
|
65,363
|
|
21,531
|
|
46,529
|
|
17,367
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning Cash and
Cash Equivalents
|
|
39,856
|
|
50,241
|
|
58,690
|
|
54,405
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending Cash and Cash
Equivalents
|
|
$
105,219
|
|
$
71,772
|
|
$
105,219
|
|
$
71,772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BILL
BARRETT CORPORATION
|
|
Reconciliation
of Discretionary Cash Flow & Adjusted Net Income
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash
Flow Reconciliation
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
(in thousands,
except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
$
20,636
|
|
$
24,562
|
|
$
68,487
|
|
$
87,737
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to
reconcile to discretionary cash flow:
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
76,165
|
|
69,192
|
|
210,406
|
|
191,626
|
|
|
Impairment, dry hole
and abandonment expense
|
17,187
|
|
4,653
|
|
18,563
|
|
8,520
|
|
|
Exploration expense
|
554
|
|
3,841
|
|
2,602
|
|
4,796
|
|
|
Unrealized
derivative gain
|
(9,996)
|
|
(1,007)
|
|
(9,971)
|
|
(16,005)
|
|
|
Deferred income
taxes
|
12,267
|
|
28,068
|
|
39,470
|
|
60,350
|
|
|
Stock compensation
and other non-cash charges
|
5,613
|
|
3,926
|
|
15,958
|
|
12,253
|
|
|
Amortization of debt
discounts and deferred financing costs
|
3,429
|
|
3,170
|
|
9,849
|
|
8,831
|
|
|
Loss (gain) on sale
of properties
|
-
|
|
50
|
|
(2,009)
|
|
(999)
|
|
Discretionary Cash
Flow
|
$
125,855
|
|
$
136,455
|
|
$
353,355
|
|
$
357,109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per share, diluted
|
$
2.65
|
|
$
2.98
|
|
$
7.50
|
|
$
7.83
|
|
|
Per Mcfe
|
$
4.49
|
|
$
5.36
|
|
$
4.55
|
|
$
4.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net Income
Reconciliation
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
|
September
30,
|
|
September
30,
|
|
|
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
(in thousands except
per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
$
20,636
|
|
$
24,562
|
|
$
68,487
|
|
$
87,737
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to net
income:
|
|
|
|
|
|
|
|
|
|
Unrealized
derivative gain
|
(9,996)
|
|
(1,007)
|
|
(9,971)
|
|
(16,005)
|
|
|
Impairment expense
|
3,879
|
|
|
|
3,879
|
|
|
|
|
Loss (gain) on sale of properties
|
-
|
|
50
|
|
(2,009)
|
|
(999)
|
|
|
One time items:
|
|
|
|
|
|
|
|
|
|
|
Production tax
expense
|
-
|
|
-
|
|
-
|
|
(2,184)
|
|
|
Subtotal Adjustments
|
(6,117)
|
|
(957)
|
|
(8,101)
|
|
(19,188)
|
|
|
Effective tax rate
|
37%
|
|
38%
|
|
37%
|
|
37%
|
|
|
Tax effected
adjustments
|
(3,854)
|
|
(593)
|
|
(5,104)
|
|
(12,088)
|
|
Adjusted Net Income
|
$
16,782
|
|
$
23,969
|
|
$
63,383
|
|
$
75,649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per share, diluted
|
$
0.35
|
|
$
0.52
|
|
$
1.35
|
|
$
1.66
|
|
|
Per Mcfe
|
$
0.60
|
|
$
0.94
|
|
$
0.82
|
|
$
1.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The non-GAAP
(Generally Accepted Accounting Principles in the United States of America)
measures of discretionary cash flow and adjusted net income 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 for unusual items to allow for a more consistent comparison from
period to period. In addition, 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 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 exclude
some, but not all, items that affect net income and net cash provided by
operating activities and may vary among companies, the amounts presented may
not be comparable to similarly titled measures of other companies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bill Barrett Corporation
|
|
|
CODE : BBG |
ISIN : US06846N1046 |
|
| |
ProfileMarket IndicatorsVALUE : Projects & res.Press releasesAnnual reportRISK : Asset profileContact Cpy |
Bill Barrett corp is a exploration company based in United states of america. Bill Barrett corp is listed in Germany and in United States of America. Its market capitalisation is US$ 534.1 millions as of today (€ 432.6 millions). Its stock quote reached its highest recent level on June 05, 2015 at US$ 9.67, and its lowest recent point on March 19, 2018 at US$ 4.84. Bill Barrett corp has 110 349 217 shares outstanding. |
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