DENVER, CO -- 11/03/09 --
Bill Barrett Corporation (NYSE: BBG) today
reported third quarter 2009 operating results highlighted by:
-- Production of 22.8 Bcfe, up 16% from the prior year period and up 3%
sequentially
-- Discretionary cash flow of $107.7 million, or $2.39 per diluted common
share and $4.73 per Mcfe
-- Net income of $0.7 million, or $0.02 per diluted share, and adjusted
net income of $7.9 million, or $0.18 per diluted share
-- Increased borrowing base on credit facility to $630 million following
October bank redetermination
-- Encouraging results to date at Yellow Jacket prospect from larger
fracture stimulations
Chairman and Chief Executive Officer Fred Barrett commented: "Our team has
met the challenges of a difficult market head-on throughout 2009. Third
quarter and year-to-date results reflect increased production as well as
growth in discretionary cash flows. Exploration and development
expenditures will be well within discretionary cash flows for the year and
will deliver production growth of 13% to 15%. As a result, we have further
increased production guidance for 2009 to 88.0 to 89.0 billion cubic feet
equivalent (Bcfe; see page 5 for details.) Year-to-date, we have been
busy evaluating multiple projects on the exploration front and, not
surprisingly, we have had both encouraging and disappointing results. At
Yellow Jacket, we are encouraged with the performance to date from our two
latest horizontal well completions. Our exploration strategy is to target
large scale, repeatable resource plays like Yellow Jacket. However, in the
Circus and Pine Ridge prospects, results to date do not appear to meet
these criteria, and we have expensed our exploration wells in these areas.
Into the fourth quarter, we continue to benefit from operating and drilling
efficiencies in core areas, favorable hedge positions and a very strong
balance sheet.
"As 2009 nears a close, we are positioning ourselves for 2010. In October
2009, our borrowing base was increased and our lender commitments returned
to the levels prior to our July debt offering, providing a solid $573
million in liquidity. To date, we have 55.9 Bcfe hedged for 2010 at an
average floor price of $7.43 per thousand cubic feet equivalent (Mcfe) and
will opportunistically add to these positions. While we are currently
preparing our 2010 plan, we expect to align our capital program with cash
flows while delivering continued production growth. Our exceptional
financial strength will allow us to be flexible over the coming months as
we continue to monitor market conditions. In addition, we are working hard
to deliver key growth catalysts such as the EIS process at West Tavaputs
and resolution with stakeholders in our Cottonwood Gulch area."
Third quarter 2009 natural gas and oil production totaled 22.8 Bcfe, up 16%
from 19.6 Bcfe in the third quarter of 2008 and up 3% from 22.1 Bcfe in the
second quarter of 2009. For the first nine months of 2009, production
totaled 67.0 Bcfe, an increase of 17% compared with the first nine months
of 2008. Despite a significant decline in natural gas and oil market prices
in the third quarter of 2009 compared with the third quarter of 2008, the
Company was able to realize strong production revenue through its effective
hedging program. The Company's commodity hedging program increased its
third quarter 2009 natural gas and oil revenues by $69.8 million, or more
than $3.00 per Mcfe. Including the effects of hedging activities, the
average sales price realized in the third quarter of 2009 was $7.03 per
Mcfe, down from $7.86 per Mcfe in the third quarter of 2008 yet up from
$6.64 per Mcfe in the second quarter of 2009.
Discretionary cash flow (a non-GAAP measure, see page 12) in the third
quarter of 2009 was $107.7 million, or $2.39 per diluted common share, up
2% from $105.6 million, or $2.34 per diluted common share, in the third
quarter of 2008. Higher production, a $0.07 per Mcfe decline in lease
operating expense and a $0.40 per Mcfe decline in production taxes drove
the increased discretionary cash flow. These benefits more than offset an
$0.83 per Mcfe decline in the average realized price from $7.86 to $7.03
and a $0.19 per Mcfe increase in gathering and transportation expenses.
(See per unit metrics on page 8.) The decline in lease operating expense is
primarily due to lower water handling costs at West Tavaputs, and the lower
production tax expense is primarily a result of significantly lower
wellhead prices. Higher gathering and transportation expenses relate to
natural gas processing charges and increased firm transportation charges
with expansion of the Rockies Express Pipeline system. During the third
quarter of 2009, the Company elected to process and sell natural gas
liquids from the Piceance Basin, and the higher processing fees were more
than offset by proceeds from the sale of resulting natural gas liquids.
Discretionary cash flow for the first nine months of 2009 was $345.2
million, or $7.69 per diluted common share, up 5% compared with $327.3
million, or $7.24 per diluted common share, in the first nine months of
2008.
Net income in the third quarter of 2009 was $0.7 million, or $0.02 per
diluted common share, compared with $35.3 million, or $0.78 per diluted
common share, in the prior year period. Net income included a $12.3 million
unrealized commodity derivative loss and a nominal gain on property sales.
Adjusting for these items, tax effected, adjusted net income (a non-GAAP
measure, see page 12) was $7.9 million, or $0.18 per diluted common share,
compared with $29.3 million, or $0.65 per diluted share, in the prior year
period. For the first nine months of 2009, net income was $37.7 million,
down from $99.1 million in the first nine months of 2008, and adjusted net
income was $63.0 million, down from $95.5 million in the first nine months
of 2008. Net income includes dry hole costs of $17.7 million for the third
quarter of 2009 (related to three exploratory areas, details provided
below) and $27.1 million for the first nine months of 2009, or $10.4
million and $16.5 million after tax, respectively.
DEBT AND LIQUIDITY
The Company ended the third quarter of 2009 with $33.0 million drawn on its
revolving credit facility and had outstanding 5% Convertible Senior Notes
in the principal amount of $172.5 million and 9.875% Senior Notes due 2016
in the principal amount of $250.0 million. In October 2009, the Company's
borrowing base under its bank credit facility increased to $630.0 million
from $537.5 million with commitments of $592.8 million. Currently, $20
million is drawn on the credit facility, providing $572.8 million in
available borrowing capacity. The Company has significant liquidity
available from cash flows from operations and the credit facility to fund
its planned capital programs.
OPERATIONS
Production, Wells Spud and Capital Expenditures
The following table lists production, wells spud and total capital
expenditures by basin for the three and nine months ended September 30,
2009:
Three Months ended Nine Months ended
September 30, 2009 September 30, 2009
----------------------------- -------------------------
Average Capital Average Capital
Net Wells Expendi- Net Wells Expendi-
Production Spud tures Production Spud tures
Basin (Mmcfe/d) (gross) (millions) (Mmcfe/d)(gross)(millions)
--------- --------- --------- --------- ------- -------
Piceance 99 41 $ 57.5 98 81 $ 203.2
Uinta 91 0 16.9 91 16 80.1
Powder River (CBM) 36 11 2.5 32 23 11.4
Wind River 21 0 0.3 24 0 1.7
Other 1 1 8.7 1 6 32.1
--------- --------- --------- --------- ------- -------
Total 248 53 $ 85.9 245 126 $ 328.5
========= ========= ========= ========= ======= =======
Third quarter 2009 capital expenditures totaled $85.9 million, bringing the
total spent to $328.5 through the third quarter of 2009, including the $60
million Cottonwood Gulch acquisition. Exploration and development capital
expenditures are expected to be less than discretionary cash flow and
allocated approximately 80% to 85% to development projects at the Company's
key assets in the Piceance, Uinta and Powder River basins and approximately
15% to 20% to delineation of prior discoveries and on-going exploration
activities. The Company has three rigs currently drilling, all of which are
operating in the Piceance Basin, as well as a smaller rig operating in the
Powder River Basin. As a result of improved drilling efficiencies, mainly
in the Piceance Basin, the Company anticipates participating in the
drilling of 170 to 180 total wells for the full year 2009, up from the
previous estimate of 165 to 175 wells. This includes approximately 40 to 45
coal bed methane (CBM) wells.
Operating and Drilling Update
Piceance Basin, Colorado
Gibson Gulch - Current net production is approximately 102 million cubic
feet equivalent per day (MMcfe/d) and the Company anticipates a 2009 exit
rate of approximately 107 MMcfe/d. Piceance operations continue to improve.
Year-to-date drilling times have averaged seven days spud-to-spud compared
with 11 days one year ago. As a result, the Company expects improved costs
on a per well basis and now plans to drill a 115 to 120 well program in the
area for 2009. The Company currently has 140 MMcf/d gross operating
compression capacity in the area and anticipates adding an additional 22
MMcf/d of capacity during 2010. The Gibson Gulch program continues to be a
key, low-risk, high growth development area for the Company and offers
flexibility to adjust the number of active rigs dependent upon the
Company's capital strategy.
At September 30, 2009, the Company had an approximate 96% working interest
in production from 506 gross wells in its Gibson Gulch program.
Cottonwood Gulch - The Company has a 90% working interest in 40,300
undeveloped acres in Cottonwood Gulch. The Company continues to work with
stakeholders to arrive at a mutually satisfactory resolution of matters
related to responsible development of this area.
Uinta Basin, Utah
West Tavaputs - Current net production is approximately 83 MMcfe/d, and the
Company anticipates a 2009 exit rate of approximately 74 MMcfe/d. The
Company has completed its 2009 drilling and completions program and
continues to work with the BLM and other stakeholders toward approval of
the Record of Decision on the Environmental Impact Statement for full-field
development at West Tavaputs, which is targeted for the first half of 2010.
In the shallow development drilling program (Wasatch/Mesaverde), 40-acre
density drilling continues successfully at Peter's Point, and the Company
remains encouraged by 20-acre density results at Prickly Pear. The West
Tavaputs program offers low-risk growth in the shallow Mesaverde and
Wasatch zones as well as upside opportunity through the Mancos shale.
At September 30, 2009, the Company had an approximate 97% working interest
in production from 167 gross wells in its West Tavaputs shallow and deep
programs.
Blacktail Ridge/Lake Canyon - Currently in the combined area, there are 19
operated wells with gross production capacity of approximately 3,600
barrels of oil equivalent per day (Boepd), most of which were returned to
production during the quarter following completion of additional natural
gas gathering capacity. In the first quarter of 2010, additional gathering
and compression capacity is scheduled to be completed by a third party,
which should provide sufficient capacity for the Company's anticipated 2010
program. The Company anticipates initiating new drilling activity near
year-end and maintaining a one-rig program in the area through 2010. The
working interests in this area range from 19% to 100%.
Hook - In the deep Hook prospect (50% working interest) targeting the
Manning Canyon shale, the Company drilled and completed its first
horizontal well, the State 16H. The well flowed natural gas at a
sub-commercial rate and was expensed as a dry hole in the third quarter of
2009. Although the well was not commercial, the Company will conduct
further analysis of a longer horizontal section and improved completion
techniques, building on the knowledge gained from this initial well, and
will consider a second horizontal well in the area. Also during the third
quarter of 2009, the Company expensed the costs associated with the second
shallow well into the Juana Lopez horizon as well as the Woodside well
previously drilled.
Powder River Basin, Wyoming
Coal Bed Methane (CBM) - Current CBM net production is approximately 35
MMcf/d, and the Company anticipates a 2009 exit rate of approximately 38
MMcf/d. Drilling activity recommenced in August 2009 with the end of
seasonal wildlife stipulations, and the Company expects its 2009 drilling
program for the area to include participation in a total of 40 to 45 CBM
wells. Development of this area requires dewatering of wells, which takes
an average of six to 12 months.
At September 30, 2009, the Company had an approximate 73% working interest
in production from 644 gross CBM wells.
Wind River Basin, Wyoming
Cave Gulch/Bullfrog/Cave Gulch Deep - Current net production from the area
is approximately 18 MMcfe/d, including the Bullfrog 14-18 recompletion well
(94% working interest) that continues to be a strong producer. The Company
anticipates a 2009 exit rate of approximately 13 MMcf/d.
Paradox Basin, Colorado
Yellow Jacket - At the Yellow Jacket shale gas discovery (55% working
interest), targeting the Gothic shale, the Company continued to adjust
completion techniques in order to improve well performance. All wells are
now completed. The most recent completion technique was applied to one full
lateral and one-half lateral and included substantially larger fracture
stimulations than used on earlier well completions. To date, flow rates are
encouraging. The larger completion of the full Koskie 13H-27 wellbore has
been on production for 38 days at an average rate of 2.1 MMcf/d, and the
well is currently flowing 2.4 MMcf/d. The one-half lateral completion of
the Neely 13H-18 well has produced for 12 days at an average rate of 2.3
Mmcf/d and is currently producing 2.1 MMcf/d. The Company will continue to
monitor data from these wells before designing its 2010 capital program for
the area. The Company currently has seven wells on production producing 5.7
MMcf/d (gross) and approximately 312,000 gross and 141,000 net undeveloped
acres in the prospect.
Pine Ridge/Salt Flank - During the third quarter of 2009, the Company
completed testing the first well in its Pine Ridge exploration prospect, a
structural salt flank play. The well was drilled in 2008 to approximately
10,000 feet targeting the Cutler and Honaker Trail formations. The well did
not produce commercial quantities of gas and was expensed as a dry hole
during the third quarter of 2009. The Company has several prospects in the
salt flank play.
Montana Overthrust, Montana
Circus - During the third quarter, the Company completed testing three
vertical wells drilled during 2008 targeting the Cody shale. Well results
varied but were non-commercial and included gas flows up to 1.1 MMcf/d, oil
flows up to 117 bopd and significant quantities of water. As a result, four
vertical wells in the area were expensed during the third quarter of 2009.
The Company focused on this horizon to identify a large, repeatable natural
gas resource play, but test results instead indicate more complex geology
than anticipated that is not aligned with the Company's strategy and
timeline for development.
ADDITIONAL FINANCIAL INFORMATION
Guidance
The Company's 2009 guidance is updated to include:
-- Capital expenditures of approximately $350 million before
acquisitions, unchanged from the previous estimate, or $410 million
including the Cottonwood Gulch acquisition
-- Oil and natural gas production of 88 to 89 Bcfe, up from 86 to 88
Bcfe, which represents growth of 13% to 15% over 2008
-- Lease operating costs per Mcfe of $0.53 to $0.54, narrowed from $0.53
to $0.55
-- Gathering and transportation costs per Mcfe of $0.63 to $0.65,
increased from $0.56 to $0.59 due to increased processing charges
associated with natural gas liquids sales
-- General and administrative expenses before non-cash stock-based
compensation between $39.0 and $40.0 million, narrowed and slightly reduced
from $39.5 to $41.0 million
Commodity Hedges Update
During the third quarter of 2009, the Company had hedges in place for 72%
of its natural gas production volumes and 56% of its oil production
volumes, which resulted in a net increase in natural gas revenues of $68.6
million and an increase in oil revenues of $1.2 million. The net effect
increased the average price received per Mcfe to $7.03 from $3.97.
It is the Company's strategy to typically hedge 50% to 70% of production
through basis to regional sales points for the next 12 months on a rolling
basis. Natural gas and oil hedging is intended to reduce the risks
associated with unpredictable future natural gas and oil prices and to
provide predictability for a portion of cash flows to support the Company's
capital expenditure program.
For the fourth quarter of 2009 through 2011, 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 2009, approximately 15.3 Bcfe, or
approximately 69% to 73% of projected production, at a weighted average
blended floor price of $7.46 per Mcfe.
-- For 2010, approximately 55.9 Bcfe at a weighted average blended floor
price of $7.43 per Mcfe. These hedges are weighted more heavily through the
third quarter of 2010 when summer natural gas prices tend to be lower.
-- For 2011, approximately 32.4 Bcfe at a weighted average blended floor
price of $6.71 per Mcfe.
Swaps and Collars
-----------------
Natural Gas Oil Equivalent
------------------- ------------------- -------------------
Volume Price Volume Price Volume Price
Period (MMBtu/d) ($/MMBtu) (bopd) ($/bbl) (MMcfe) ($/Mcfe)
------ --------- --------- --------- --------- --------- ---------
4Q09 175,712 6.55 1,125 80.27 15,317 7.46
1Q10 174,000 6.48 800 78.44 14,668 7.30
2Q10 184,000 6.65 800 78.44 15,659 7.48
3Q10 184,000 6.65 800 78.44 15,831 7.48
4Q10 111,728 6.55 800 78.44 9,786 7.47
1Q11 92,500 6.35 - - 7,568 6.99
2Q11 112,500 5.98 - - 9,307 6.58
3Q11 112,500 5.98 - - 9,409 6.58
4Q11 72,717 6.18 - - 6,082 6.80
The Company also has natural gas basis only hedges in place, none of which
are currently in the money, including:
-- For the fourth quarter of 2009: 1,530,000 MMBtu at an average
differential of ($1.85) per MMBtu
-- For 2010: 12,940,000 MMBtu at an average differential of ($2.42) per
MMBtu.
-- For 2011: 7,300,000 MMBtu at an average differential of ($1.72) per
MMBtu.
THIRD QUARTER 2009 WEBCAST AND CONFERENCE CALL
As previously announced, a webcast and conference call will be held later
this morning to discuss third quarter results. Please join Bill Barrett
Corporation executive management at noon Eastern time/10:00 a.m. Mountain
time for the live webcast, accessed at www.billbarrettcorp.com, or join by
telephone by calling 800-261-3417 (617-614-3673 international callers) with
passcode 83530527. 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 6, 2009 at call-in number 888-286-8010
(617-801-6888 international) with passcode 30551192. The Company has also
tentatively scheduled its 2010 earnings conference calls for February 23,
May 4, August 3 and November 2, each at noon Eastern time/10:00 a.m.
Mountain time.
UPCOMING EVENTS
Investor Conferences
Updated investor presentations are posted on the homepage of the Company's
website at www.billbarrettcorp.com. Please check the website prior to
investor events for the most recent presentation.
Chief Financial Officer and Treasurer Bob Howard plans to present at the
Bank of America Merrill Lynch 2009 Credit Conference on December 3, 2009 at
3:00 p.m. Eastern time. The event will be webcast and may be accessed live
and for replay on the Company's website.
Chairman and CEO Fred Barrett plans to present at the Wells Fargo
Exploration and Production, Energy Services and Utility Symposium on
December 9, 2009 at 2:30 p.m. Eastern time. The event will be webcast and
may be accessed live and for replay on the Company's website.
DISCLOSURE STATEMENTS
Forward-looking statements:
This press release contains forward-looking statements, including
statements regarding projected results and future events. In particular,
the Company is providing updated "2009 Guidance," and certain general
guidelines for 2010 capital expenditures. 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, 2008 filed with the Securities
and Exchange Commission ("SEC"), and subsequent filings including our
Current Reports on Form 8-K and Form 10-Q, 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, exploration drilling and test results, the
ability to receive drilling and other permits and regulatory approvals,
governmental regulations, transportation, processing, availability and
costs of financing to fund the Company's operations, availability of third
party gathering, market conditions, supply and demand changes and resulting
oil and gas price volatility, risks related to hedging activities including
counterparty viability, 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, surface access and costs, uncertainties
inherent in oil and gas production operations and estimating reserves, the
impact of commodity price changes on reserve estimates, unexpected future
capital expenditures, competition, risks associated with operating in one
major geographic area, the success of the Company's risk management
activities, 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. 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,
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 Nine Months
Ended Ended
September 30, September 30,
--------------- ---------------
2009 2008 2009 2008
------- ------- ------- -------
Production Data:
------- ------- ------- -------
Natural gas (MMcf) 21,711 18,568 63,859 54,173
Oil (MBbls) 180 172 517 473
Combined volumes (MMcfe) 22,791 19,600 66,961 57,011
Daily combined volumes (MMcfed) 248 213 245 208
------- ------- ------- -------
Average Prices (before the effects of
realized hedges):
------- ------- ------- -------
Natural gas (per Mcf) $ 3.70 $ 7.10 $ 3.48 $ 8.11
Oil (per Bbl) 56.53 102.98 43.59 99.47
Combined (per Mcfe) 3.97 7.63 3.66 8.53
------- ------- ------- -------
Average Prices (includes the effects of
realized hedges):
------- ------- ------- -------
Natural gas (per Mcf) $ 6.86 $ 7.57 $ 7.02 $ 7.87
Oil (per Bbl) 63.30 79.07 55.76 76.57
Combined (per Mcfe) 7.03 7.86 7.12 8.12
------- ------- ------- -------
Average Costs (per Mcfe):
------- ------- ------- -------
Lease operating expense $ 0.57 $ 0.64 $ 0.52 $ 0.57
Gathering and transportation expense 0.71 0.52 0.60 0.52
Production tax expense (1) 0.29 0.69 0.18 0.66
Depreciation, depletion and
amortization 2.93 2.53 2.83 2.63
General and administrative expense,
excluding stock-based compensation (2) 0.45 0.50 0.44 0.53
------- ------- ------- -------
(1) Production tax expense for the nine months ended September 30, 2009
includes a one-time benefit to reduce and re-estimate prior periods as
a result of an agreement with the State of Colorado regarding certain
calculations of severance taxes. Exclusive of the one-time benefit,
the production tax expense per unit would have been $0.25 for the nine-
month period.
(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,
-------------------- --------------------
2009 2008 2009 2008
--------- --------- --------- ---------
(in thousands, except per share (As (As
amounts) Adjusted) Adjusted)
--------- --------- --------- ---------
Operating and Other Revenues:
--------- --------- --------- ---------
Oil and gas
production (1) $ 161,719 $ 155,050 $ 479,455 $ 463,759
Commodity derivative
gain (loss) (1) (13,693) 8,490 (48,612) 3,647
Other 734 875 1,547 3,730
--------- --------- --------- ---------
Total operating and
other revenues 148,760 164,415 432,390 471,136
--------- --------- --------- ---------
--------- --------- --------- ---------
Operating Expenses:
--------- --------- --------- ---------
Lease operating 13,005 12,548 34,921 32,391
Gathering and
transportation 16,260 10,103 40,012 29,746
Production tax (2) 6,547 13,519 11,850 37,405
Exploration 630 1,010 2,172 2,935
Impairment, dry hole costs
and abandonment 19,103 463 29,834 5,618
Depreciation, depletion
and amortization 66,742 49,681 189,459 149,798
General and
administrative (3) 10,291 9,704 29,193 30,124
Non-cash stock-based
compensation (3) 4,343 3,950 12,081 12,096
--------- --------- --------- ---------
Total operating expenses 136,921 100,978 349,522 300,113
--------- --------- --------- ---------
Operating Income 11,839 63,437 82,868 171,023
--------- --------- --------- ---------
Other Income and Expense:
--------- --------- --------- ---------
Interest and other income 44 805 294 1,672
Interest expense (4) (9,746) (5,067) (20,098) (14,039)
--------- --------- --------- ---------
Total other income and
expense (9,702) (4,262) (19,804) (12,367)
--------- --------- --------- ---------
Income before Income Taxes 2,137 59,175 63,064 158,656
Provision for Income Taxes (4) 1,419 23,860 25,325 59,518
--------- --------- --------- ---------
Net Income (4) $ 718 $ 35,315 $ 37,739 $ 99,138
--------- --------- --------- ---------
--------- --------- --------- ---------
Net Income Per Common Share
Basic $ 0.02 $ 0.79 $ 0.84 $ 2.23
Diluted $ 0.02 $ 0.78 $ 0.84 $ 2.19
--------- --------- --------- ---------
--------- --------- --------- ---------
Weighted Average Common Shares
Outstanding
Basic 44,758 44,493 44,703 44,399
Diluted 45,109 45,056 44,899 45,184
========= ========= ========= =========
(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 period indicated:
Three Months Ended Nine Months Ended
September 30, September 30,
--------- --------- --------- ---------
2009 2008 2009 2008
--------- --------- --------- ---------
Included in oil and gas
production revenue:
Realized gains (losses) on cash
flow hedges $ 71,210 $ 5,457 $ 234,664 $ (22,699)
========= ========= ========= =========
Included in commodity
derivative loss:
Realized losses on
derivatives not
designated cash flow hedges $ (1,423) $ (963) $ (2,446) $ (963)
Unrealized ineffectiveness
gains (losses) recognized
on derivatives designated
cash flow hedges 741 5,687 (5,721) 3,121
Unrealized gains (losses) on
derivatives not designated
cash flow hedges (13,011) 3,766 (40,445) 1,489
--------- --------- --------- ---------
Total commodity
derivative gain (loss) $ (13,693) $ 8,490 $ (48,612) $ 3,647
========= ========= ========= =========
(2) Production tax expense for the 2009 nine-month period includes a
one-time benefit to reduce and re-estimate prior periods as a result
of an agreement with the State of Colorado regarding certain
calculations 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.
(4) Effective January 1, 2009, the Company adopted financial reporting
rule FSP ABP 14-1, which was incorporated into Accounting Standard
Codification (ASC) Subtopic 470-20, to account for convertible debt
instruments that may be settled in cash upon conversion. The new rule
applies a fair value to the equity conversion feature of the debt and
results in reporting the convertible notes at a discount to the
principal value. The debt discount is amortized as non-cash interest
expense over the expected term of the convertible notes. The 2008
financial statements have been adjusted to reflect the changed
accounting treatment.
BILL BARRETT CORPORATION
Consolidated Condensed Balance Sheets
(Unaudited)
As of As of
September 30, December 31,
2009 2008
------------- -------------
(in thousands) (As Adjusted)
------------- -------------
Assets:
---------------------------
Cash and cash equivalents $ 53,551 $ 43,063
Other current assets (1) 131,431 270,311
Property and equipment, net 1,668,133 1,561,819
Other noncurrent assets (1) 25,825 119,300
------------- -------------
Total assets $ 1,878,940 $ 1,994,493
------------- -------------
------------- -------------
Liabilities and Stockholders' Equity:
------------- -------------
Current liabilities (1) $ 164,060 $ 225,794
Notes payable under bank credit
facility 33,000 254,000
Senior notes (2) 238,179 -
Convertible senior notes (3) 157,358 153,411
Other long-term liabilities (1) 263,779 262,055
Stockholders' equity 1,022,564 1,099,233
------------- -------------
Total liabilities and stockholders' equity $ 1,878,940 $ 1,994,493
------------- -------------
(1) At September 30, 2009, the estimated fair value of all of our commodity
derivative instruments was a net asset of $66.8 million, comprised of:
$79.0 million current assets; $15.4 million non-current assets; $8.5
million current liabilities; and $19.1 million non-current liabilities.
This amount will fluctuate quarterly based on estimated future
commodity prices.
(2) The 9.875% Senior Notes were issued at a 95.172% discount to par and
have a principal amount of $250.0 million.
(3) Effective January 1, 2009, the Company adopted financial reporting rule
FSP ABP 14-1, which was incorporated into ASC Subtopic 470-20, to
account for convertible debt instruments that may be settled in cash
upon conversion. This rule applies a fair value to the equity
conversion feature of the debt and results in reporting the convertible
notes at a discount to the principal value. The debt discount is
amortized as non-cash interest expense over the expected term of the
convertible notes. The 2008 financial statements have been adjusted to
reflect the changed accounting treatment. The principal amount of the
notes is $172.5 million.
BILL BARRETT CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2009 2008 2009 2008
---------- ---------- ---------- ----------
(As (As
(in thousands) Adjusted) Adjusted)
---------- ---------- ---------- ----------
Operating Activities:
---------- ---------- ---------- ----------
Net income $ 718 $ 35,315 $ 37,739 $ 99,138
Adjustments to reconcile
to net cash provided by
operations:
Depreciation,
depletion and
amortization 66,742 49,681 189,459 149,798
Impairment, dry hole
costs and abandonment
costs 19,103 463 29,834 5,618
Unrealized derivative
loss (gain) 12,270 (9,453) 46,166 (4,610)
Deferred income taxes 1,419 23,155 20,871 58,591
Stock compensation and
other non-cash
charges 4,529 4,273 13,075 13,160
Amortization of
deferred financing
costs 2,381 1,692 5,953 3,818
Gain on sale of
properties (100) (561) (34) (1,134)
---------- ---------- ---------- ----------
Change in assets and
liabilities:
Accounts
receivable (5,421) 30,391 19,845 (479)
Prepayments and
other assets (672) 1,535 (1,842) (4,633)
Accounts payable,
accrued and other
liabilities 3,901 175 12,913 3,372
Amounts payable to
oil & gas
property owners 1,285 (4,070) (5,435) (1,424)
Production taxes
payable 4,523 8,693 4,273 18,973
---------- ---------- ---------- ----------
Net cash provided by
operating activities $ 110,678 $ 141,289 $ 372,817 $ 340,188
---------- ---------- ---------- ----------
Investing Activities:
---------- ---------- ---------- ----------
Additions to oil and gas
properties, including
acquisitions (85,814) (161,320) (372,820) (384,775)
Additions of furniture,
equipment and other (1,364) (491) (3,287) (1,957)
Proceeds from sale of
properties - 715 2,714 2,354
---------- ---------- ---------- ----------
Net cash used in
investing activities $ (87,178) $ (161,096) $ (373,393) $ (384,378)
---------- ---------- ---------- ----------
Financing Activities:
---------- ---------- ---------- ----------
Proceeds from credit
facility - 20,000 100,000 67,300
Principal payments on
credit facility (266,000) (265) (321,000) (167,300)
Proceeds from issuance of
senior convertible notes - - - 172,500
Proceeds from issuance of
9.875% senior notes 237,930 - 237,930 -
Offering costs (5,543) (150) (6,440) (5,164)
Proceeds from sale of
common stock 146 627 628 4,071
Deferred financing costs
and other (5) (9) (54) (98)
---------- ---------- ---------- ----------
Net cash provided by
(used in) financing
activities $ (33,472) $ 20,203 $ 11,064 $ 71,309
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
Increase (Decrease) in Cash
and Cash Equivalents (9,972) 396 10,488 27,119
Beginning Cash and Cash
Equivalents 63,523 87,008 43,063 60,285
---------- ---------- ---------- ----------
Ending Cash and Cash
Equivalents $ 53,551 $ 87,404 $ 53,551 $ 87,404
---------- ---------- ---------- ----------
BILL BARRETT CORPORATION
Reconciliation of Discretionary Cash Flow & Adjusted Net Income
from Net Income
(Unaudited)
Discretionary Cash Flow Reconciliation
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- --------------------
2009 2008 2009 2008
--------- --------- --------- ---------
(in thousands, except per share (As (As
amounts) Adjusted) Adjusted)
--------- --------- --------- ---------
Net Income $ 718 $ 35,315 $ 37,739 $ 99,138
Adjustments to reconcile to
discretionary cash flow:
Depreciation, depletion and
amortization 66,742 49,681 189,459 149,798
Impairment, dry hole costs
and abandonment costs 19,103 463 29,834 5,618
Exploration expense 630 1,010 2,172 2,935
Unrealized derivative loss
(gain) 12,270 (9,453) 46,166 (4,610)
Deferred income taxes 1,419 23,155 20,871 58,591
Stock compensation and other
non-cash charges 4,529 4,273 13,075 13,160
Amortization of deferred
financing and discount on
convertible notes 2,381 1,692 5,953 3,818
Gain on sale of properties (100) (561) (34) (1,134)
--------- --------- --------- ---------
Discretionary Cash Flow $ 107,692 $ 105,575 $ 345,235 $ 327,314
--------- --------- --------- ---------
Per share, diluted $ 2.39 $ 2.34 $ 7.69 $ 7.24
Per Mcfe $ 4.73 $ 5.39 $ 5.16 $ 5.74
Adjusted Net Income
Reconciliation
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- --------------------
2009 2008 2009 2008
--------- --------- --------- ---------
(in thousands, except per share (As (As
amounts) Adjusted) Adjusted)
--------- --------- --------- ---------
Net Income $ 718 $ 35,315 $ 37,739 $ 99,138
Adjustments to net inome:
Unrealized derivative loss
(gain) 12,270 (9,453) 46,166 (4,610)
Gain on sale of properties (100) (561) (34) (1,134)
One time items:
Production tax expense - - (4,796) -
--------- --------- --------- ---------
Subtotal Adjustments 12,170 (10,014) 41,336 (5,744)
Effective tax rate 41% 40% 39% 38%
--------- --------- --------- ---------
Tax effected adjustments 7,180 (5,976) 25,215 (3,589)
--------- --------- --------- ---------
Adjusted Net Income $ 7,898 $ 29,339 $ 62,954 $ 95,549
--------- --------- --------- ---------
Per share, diluted $ 0.18 $ 0.65 $ 1.40 $ 2.11
Per Mcfe $ 0.35 $ 1.50 $ 0.94 $ 1.68
The non-GAAP (Generally Accepted Accounting Principals) 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 easier 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.
Company contact:
Jennifer Martin
Director of Investor Relations
303-312-8155
