SOURCE: Bill Barrett Corporation

Bill Barrett Corporation

August 04, 2009 07:00 ET

Bill Barrett Corporation Reports Second Quarter 2009 Results

DENVER, CO--(Marketwire - August 4, 2009) - Bill Barrett Corporation (NYSE: BBG) today reported second quarter 2009 operating results highlighted by:

--  Production of 22.1 Bcfe, up 15% from the prior year period and flat
    sequentially
--  Discretionary cash flow of $102.8 million, or $2.28 per diluted common
    share and $4.65 per Mcfe
--  Net income of $10.6 million and adjusted net income of $15.4 million,
    or $0.34 per diluted share
--  Acquisition of 90% working interest in 40,300 undeveloped acres in the
    Cottonwood Gulch area of the Piceance Basin in western Colorado
--  July completion of $250.0 million Senior Notes offering, increasing
    current liquidity to $473.5 million
    

Chairman and Chief Executive Officer Fred Barrett commented: "We continue to realize strong results despite difficult market conditions. Through a combination of increasingly efficient operations, substantial and attractively priced hedge positions, shortened drilling times and reduced service costs, our team is executing on all fronts. Further, the acquisition of the Cottonwood Gulch acreage in the prolific Piceance Basin is an exciting opportunity and natural fit for the Company, and we look forward to initiating responsible development of this substantial resource.

"We are well-positioned financially. In early July, we completed the offering of $250 million in senior notes, increasing our liquidity to $474 million. In addition, we have hedges in place to regional sales points covering 70% to 73% of second half 2009 estimated production at an average floor price of $7.64 per Mcfe. We are on track to complete our development and assess our exploration programs as planned, and we are financially capable should additional opportunities emerge. As a result of strong year-to-date performance, we have revised our full year guidance to include: increased production; lowered LOE costs; reduced G&A expenses; and, maintained capital expenditures before acquisitions at $350 million." (See page 5 for details.)

Second quarter 2009 natural gas and oil production totaled 22.1 billion cubic feet equivalent (Bcfe), up 15% from 19.2 Bcfe in the second quarter of 2008 and flat sequentially with 22.1 Bcfe in the first quarter of 2009. For the first half of 2009, production totaled 44.2 Bcfe, an increase of 18% compared with the first half of 2008. Despite a significant decline in natural gas and oil market prices in the second quarter of 2009 compared with the second 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 second quarter 2009 natural gas and oil revenues by $75.3 million, more than doubling the average per unit price received. Including the effects of hedging activities, the average sales price realized in the second quarter of 2009 was $6.64 per Mcfe, down from $8.31 per Mcfe in the second quarter of 2008 and down from $7.70 per Mcfe in the first quarter of 2009.

Discretionary cash flow (a non-GAAP measure, see page 12) in the second quarter of 2009 was $102.8 million, or $2.28 per diluted common share, down 9.3% from $113.4 million, or $2.50 per diluted common share, in the second quarter of 2008. While the Company benefitted in the second quarter of 2009 from higher production and lower per unit cash operating costs, this was more than offset by a $1.67 per Mcfe decline in realized prices and a $4.3 million increase in cash income taxes. Of note, cash operating costs in the second quarter of 2009 were reduced by lower per unit lease operating costs at West Tavaputs and lower production tax expense as a result of significantly lower wellhead prices. (See per unit metrics on page 8.) Discretionary cash flow for the first half of 2009 was $237.5 million, or $5.30 per diluted common share, up 7% compared with $221.7 million, or $4.90 per diluted common share, in the first half of 2008.

Net income in the second quarter of 2009 was $10.6 million, or $0.24 per diluted common share, compared with $33.3 million, or $0.73 per diluted common share, in the prior year period. Net income included a $7.9 million unrealized commodity derivative loss (principally related to basis only hedges), a $0.4 million addition to the production tax benefit discussed last quarter and a nominal loss on property sales. Adjusting for these items, tax effected, adjusted net income (a non-GAAP measure, see page 12) was $15.4 million or $0.34 per diluted common share. For the first half of 2009, net income was $37.0 million, down from $63.8 million in the first half of 2008, and adjusted net income was $57.7 million, down from $66.6 million in the first half of 2008. Net income for the second quarter of 2009 and first half of 2009 also included $9.4 million in dry hole costs for five wells (four described below plus the Rocktober well in the Big Horn Basin), or approximately $5.6 million after tax.

DEBT AND LIQUIDITY

The Company ended the second quarter of 2009 with $299.0 million drawn on its revolving credit facility and had outstanding 5% convertible senior notes in the principal amount of $172.5 million. Subsequently, the Company closed on its previously announced offering of $250.0 million 9.875% Senior Notes due 2016, issued at 95.172% of par with a yield to maturity of 10.875%. All of the net proceeds from the offering of $232.3 million were used to reduce the amount outstanding under the revolving credit facility. Also as a result of the senior notes offering, the borrowing base on the credit facility was reduced by 25% of the principal amount of the senior notes to $537.5 million. Currently, there is $64.0 million drawn on the revolving credit facility, providing $473.5 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 program.

OPERATIONS

Production, Wells Spud and Capital Expenditures

The following table lists production, wells spud and total capital expenditures by basin for the second quarter and first six months of 2009:

                    Second Quarter 2009             First Half 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        24  $   98.4        97        40  $  145.7
Uinta                 87         8      19.4        90        16      63.2
Powder River (CBM)    32         0       3.1        30        12       8.9
Wind River            23         0       0.0        25         0       1.4
Other                  2         1      10.7         2         5      23.4
                --------  --------  --------  --------  --------  --------

Total                243        33  $  131.6       244        73  $  242.6
                ========  ========  ========  ========  ========  ========

Second quarter 2009 capital expenditures including the recent Cottonwood Gulch acquisition totaled $131.6 million. The Company plans to spend up to $410.0 million for capital expenditures in 2009, including $60.0 million paid for Cottonwood Gulch. Excluding the acquisition, capital expenditures are expected to be aligned with cash flows and allocated approximately 80% to 85% to development projects at its 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 a result of improved drilling efficiencies, the Company anticipates participating in the drilling of 165 to 175 wells for the full year 2009, up from the previous estimate of 145 to 155 wells. This includes approximately 35 to 40 coal bed methane (CBM) wells.

Operating and Drilling Update

Piceance Basin, Colorado

Gibson Gulch -- Current net production is approximately 95 million cubic feet equivalent per day (MMcfe/d). The Company plans to operate three rigs in the area through the remainder of 2009 and, as a result of improved drilling times, expects to drill a 105 to 110 well program for the full year. All permits for the program are in place. In addition, improvements in water handling reduced lease operating expenses in the area for the second quarter compared with the first quarter. 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 the end of the second quarter 2009, the Company had an approximate 96% working interest in production from 472 gross wells in its Gibson Gulch program.

Cottonwood Gulch -- In June 2009, the Company paid $60 million to acquire a 90% working interest in 40,300 undeveloped acres in Cottonwood Gulch, formerly known as Naval Oil Shale Reserve #1. The acreage is adjacent to the prolific Rulison and Parachute fields in the Piceance Basin, and the Company expects the acquisition to add more than 2 trillion cubic feet equivalent of probable and possible resources to its portfolio. The Roan Plateau Resource Management Plan is in effect and an environmental impact statement has been signed for development of the area. In order to initiate development in 2010, the Company is working with stakeholders to resolve remaining issues, including a lawsuit by environmental groups against the Bureau of Land Management (BLM) that challenges various matters related to the leasing and development of this area.

Uinta Basin, Utah

West Tavaputs -- Current net production is approximately 88 MMcfe/d. The Company completed drilling its 14-well program for 2009 with completions operations on six of these wells finished to date. The BLM is working towards completion of tasks necessary to issue a Record of Decision on the Environmental Impact Statement for full-field development at West Tavaputs and currently targets approval for the first half of 2010.

In the shallow development drilling program (Wasatch/Mesaverde), 40-acre density continues successfully at Peter's Point, and the Company continues to be encouraged by 20-acre density results at Prickly Pear. During the second quarter of 2009, the Company continued to drive operating cost savings in West Tavaputs with reduced water handling charges and plans a second salt water disposal well to further improve costs. The Company also identified a new and environmentally friendly method of dust suppression, which it expects will drive further cost savings on road maintenance.

The West Tavaputs program continues to offer low-risk growth in the shallow Mesaverde and Wasatch zones as well as upside opportunity through the Mancos shale.

At the end of the second quarter 2009, the Company had an approximate 97% working interest in production from 146 gross wells in its West Tavaputs shallow and deep programs.

Blacktail Ridge/Lake Canyon -- Currently in the combined area, there are 16 operated wells with gross production capacity of approximately 3,200 barrels of oil per day (Bopd) and three wells waiting on gas gathering improvements before completion. The Company continues to shut-in most of its wells due to gas gathering constraints, which it expects will be resolved around year-end 2009. Current production averages approximately 950 barrels of oil equivalent per day (Boepd) gross, or approximately 500 Boepd net. As a result of infrastructure constraints, the Company has reached agreement with the Ute Tribe to suspend certain drilling commitments. The working interests in this area range from 19% to 100%.

Hook -- In the deep Hook prospect (50% working interest), the Company is targeting the Manning Canyon shale at a depth of approximately 8,000 feet. The Company drilled its first Manning Canyon horizontal well and expects to complete the well by September 2009. The Company also drilled two vertical test wells in the shallower Juana Lopez shale (100% working interest), at approximately 4,000 feet. Testing of the first Juana Lopez well drilled in 2008 was completed and was recorded as a dry hole expense in the second quarter of 2009. Completion of the second Juana Lopez well is planned for 2010.

Powder River Basin, Wyoming

Coal Bed Methane (CBM) -- Current CBM net production is approximately 36 MMcf/d and drilling activity will be re-started in August 2009 with the end of seasonal wildlife stipulations. The Company has reduced its 2009 drilling program for the area to participation in a total of 35 to 40 CBM wells. Development of this area requires dewatering of wells, which takes an average of six to 12 months. During 2009, the Company will continue to dewater wells with production expected to increase to approximately 38 MMcf/d in the fourth quarter.

At the end of the second quarter 2009, the Company had an approximate 75% working interest in production from 634 gross CBM wells.

Wind River Basin, Wyoming

Cave Gulch/Bullfrog/Cave Gulch deep -- Current net production from the area is approximately 21 MMcfe/d, including the Bullfrog 14-18 recompletion well (94% working interest) that continues to be a strong producer, currently averaging approximately 12 MMcf/d gross. Additional activity in this region remains postponed due to low natural gas prices.

Paradox Basin, Colorado

Yellow Jacket -- At the Yellow Jacket shale gas discovery (55% working interest), targeting the Gothic shale, the Company has drilled eight wells and continues to adjust completion and production techniques in an effort to avoid salt precipitation in the wellbore, maximize exposure to the shale formation and improve well performance. The Company has five wells on production. One well, the Oliver 13H, was expensed in the second quarter as a dry hole due to the impact on completion of a cross-cutting fault that encountered nominal H2S, a circumstance unique to this well. The Company has approximately 307,000 gross and 140,000 net undeveloped acres in the prospect.

Green Jacket -- At the Green Jacket prospect (100% working interest), targeting the Hovenweep shale, the Company completed its first horizontal well during the second quarter of 2009. The well did not encounter the salt issues that are present in the Yellow Jacket wells and is currently shut-in due to its distance from the pipeline and as the Company focuses its efforts on the Yellow Jacket well completions. The Company has approximately 150,000 gross and 110,000 net undeveloped acres in the prospect.

Montana Overthrust, Montana

Circus -- The Company began completion work and testing on three vertical wells that were drilled during 2008 targeting the Cody shale and is permitting a Cody shale horizontal well. Testing was completed on the Draco and Leviathan wells, which were drilled in 2007 and originally targeted structural features below 7,000 feet, and the remaining well costs were expensed as dry holes. Targeted zones in these wells were not related to the Cody shale currently being tested. The Company has a 50% working interest in this prospect.

ADDITIONAL FINANCIAL INFORMATION

Guidance

The Company's 2009 guidance is updated to include:

--  Capital expenditures of up to $350 million before acquisitions,
    unchanged from the previous estimate, or $410 million including the
    Cottonwood Gulch acquisition
--  Oil and natural gas production of 86 to 88 Bcfe, up from 84 to 87
    Bcfe, which represents growth of 11% to 13% over 2008
--  Lease operating costs per Mcfe of $0.53 to $0.55, improved from $0.60
    to $0.66
--  Gathering and transportation costs per Mcfe of $0.56 to $0.59, the
    range narrowed from $0.55 to $0.60
--  General and administrative expenses before non-cash stock-based
    compensation reduced to between $39.5 and $41.0 million from between $41.0
    and $43.0 million
    

Commodity Hedges Update

During the second quarter of 2009, the Company had hedges in place for 78% of its natural gas production volumes and 50% of its oil production volumes, which resulted in an increase in natural gas revenues of $73.4 million and an increase in oil revenues of $1.9 million. The net effect increased the average price received per Mcfe to $6.64 from $3.23.

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 second half 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 remaining two quarters of 2009, approximately 30.6 Bcfe, or
    approximately 70% to 73% of projected production, at a weighted average
    blended floor price of $7.64 per Mcfe.
--  For 2010, approximately 53.8 Bcfe at a weighted average blended floor
    price of $7.39 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 29.8 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)
                --------- --------- --------- --------- --------- ---------

3Q09              184,000      6.83     1,075     80.47    15,982      7.73
4Q09              167,424      6.63     1,075     80.47    14,596      7.54

1Q10              171,500      6.51       550     77.95    14,329      7.28
2Q10              184,000      6.64       550     77.95    15,522      7.41
3Q10              184,000      6.64       550     77.95    15,693      7.41
4Q10               95,152      6.59       550     77.95     8,262      7.46

1Q11               72,500      6.34         -         -     5,932      6.97
2Q11              107,500      5.99         -         -     8,893      6.59
3Q11              107,500      5.99         -         -     8,991      6.59
4Q11               71,033      6.18         -         -     5,941      6.80

The Company also has natural gas basis only hedges in place, none of which are currently in the money including:

--  For the second half of 2009: 2,450,000 MMBtu at an average
    differential of ($2.00) 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.
    

SECOND QUARTER 2009 WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held later this morning to discuss second 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 866-700-6067 (617-213-8834 international callers) with passcode 24448795. The webcast will remain available on the Company's website for approximately 30 days, and a replay of the call will be available through August 7, 2009 at call-in number 888-286-8010 (617-801-6888 international) with passcode 59502354. The Company has also tentatively scheduled its third quarter 2009 conference call for November 3 at noon Eastern time/10:00 a.m. Mountain time.

UPCOMING EVENTS

Investor Conferences

Updated investor presentations are posted to the homepage of the Company's website at www.billbarrettcorp.com. Please check the website prior to investor events for the most recent presentation.

Chairman and CEO Fred Barrett plans to present at the Enercom 2009 Oil and Gas Conference on August 10, 2009 at 4:50 p.m. Mountain time. The event will be webcast and may be accessed live and for replay on the Company's website at www.billbarrettcorp.com.

Chairman and CEO Fred Barrett plans to present at the Barclays Capital CEO Energy/Power Conference on September 9, 2009 at 12:25 p.m. Eastern time. The event will be webcast and may be accessed live and for replay on the Company's website at www.billbarrettcorp.com.

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," which contain projections for certain 2009 operational and financial results and projected 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)


                                      Quarter Ended      Six Months Ended
                                         June 30,            June 30,
                                    ------------------- -------------------
                                      2009      2008      2009      2008
                                    --------- --------- --------- ---------
Production Data:
                                    --------- --------- --------- ---------
    Natural gas (MMcf)                 21,075    18,274    42,141    35,606
    Oil (MBbls)                           168       157       338       301
    Combined volumes (MMcfe)           22,083    19,216    44,169    37,412
    Daily combined volumes (MMcfed)       243       211       244       206
                                    ========= ========= ========= =========
Average Prices (before the effects
 of realized hedges):
                                    --------- --------- --------- ---------
    Natural gas (per Mcf)           $    2.99 $    9.24 $    3.37 $    8.64
    Oil (per Bbl)                       48.51    109.70     36.71     97.46
    Combined (per Mcfe)                  3.23      9.68      3.49      9.00
                                    ========= ========= ========= =========
Average Prices (includes the
 effects of realized hedges):
                                    --------- --------- --------- ---------
    Natural gas (per Mcf)           $    6.48 $    8.05 $    7.10 $    8.03
    Oil (per Bbl)                       59.61     80.03     51.75     75.14
    Combined (per Mcfe)                  6.64      8.31      7.17      8.25
                                    ========= ========= ========= =========
Average Costs (per Mcfe):
                                    --------- --------- --------- ---------
    Lease operating expense         $    0.46 $    0.55 $    0.50 $    0.53
    Gathering and transportation
     expense                             0.58      0.53      0.54      0.53
    Production tax expense       (1)     0.20      0.71      0.12      0.64
    Depreciation, depletion and
     amortization                        2.90      2.56      2.78      2.68
    General and administrative
     expense, excluding stock-based
     compensation                        0.42      0.51      0.43      0.55
                                    ========= ========= ========= =========

(1) Production tax expense for the six months ended June 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 $0.22 in the
    quarter ended June 30, 2009 and $0.23 in the six months ended June 30,
    2009.


                         BILL BARRETT CORPORATION
                  Consolidated Statements of Operations
                                (Unaudited)



                                   Quarter Ended        Six Months Ended
                                      June 30,              June 30,
                                --------------------  --------------------
                                  2009       2008       2009       2008
                                ---------  ---------  ---------  ---------
(in thousands, except per share              (As                   (As
 amounts)                                  Adjusted)             Adjusted)
                                ---------  ---------  ---------  ---------
Operating and Other Revenues:
                                ---------  ---------  ---------  ---------
   Oil and gas production (1)   $ 147,560  $ 159,664  $ 317,736  $ 308,709
   Commodity derivative
    loss                  (1)      (8,963)    (3,313)   (34,919)    (4,843)
   Other                              293      1,168        813      2,855
                                ---------  ---------  ---------  ---------
      Total operating and
       other revenues             138,890    157,519    283,630    306,721
                                =========  =========  =========  =========

                                =========  =========  =========  =========
Operating Expenses:
                                ---------  ---------  ---------  ---------
   Lease operating                 10,236     10,542     21,916     19,843
   Gathering and
    transportation                 12,728     10,244     23,752     19,643
   Production tax         (2)       4,377     13,627      5,303     23,886
   Exploration                        782      1,284      1,542      1,925
   Impairment, dry hole
    costs and abandonment          10,546      3,603     10,731      5,155
   Depreciation, depletion
    and amortization               63,960     49,160    122,717    100,117
   General and
    administrative        (3)       9,316      9,788     18,902     20,420
   Non-cash stock-based
    compensation          (3)       3,944      4,563      7,738      8,146
                                ---------  ---------  ---------  ---------
      Total operating
       expenses                   115,889    102,811    212,601    199,135
                                =========  =========  =========  =========
Operating Income                   23,001     54,708     71,029    107,586
                                =========  =========  =========  =========
Other Income and Expense:
                                ---------  ---------  ---------  ---------
   Interest and other
    income                             52        395        250        867
   Interest expense       (4)      (5,223)    (5,093)   (10,352)    (8,972)
                                ---------  ---------  ---------  ---------
      Total other income
       and expense                 (5,171)    (4,698)   (10,102)    (8,105)
                                =========  =========  =========  =========
Income before Income Taxes         17,830     50,010     60,927     99,481
Provision for Income
 Taxes                    (4)       7,222     16,741     23,906     35,658
                                ---------  ---------  ---------  ---------
Net Income                (4)   $  10,608  $  33,269  $  37,021  $  63,823
                                =========  =========  =========  =========


                                =========  =========  =========  =========
Net Income Per Common Share
   Basic                        $    0.24  $    0.75  $    0.83  $    1.44
   Diluted                      $    0.24  $    0.73  $    0.83  $    1.41
                                =========  =========  =========  =========


                                =========  =========  =========  =========
Weighted Average Common Shares
 Outstanding
   Basic                           44,731     44,425     44,675     44,352
   Diluted                         45,005     45,447     44,811     45,242
                                =========  =========  =========  =========

(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:

                                   Quarter Ended        Six Months Ended
                                      June 30,              June 30,
                                --------------------  --------------------
                                  2009       2008       2009       2008
                                ---------  ---------  ---------  ---------
   Included in oil and gas
    production revenue:
   Realized gains on cash
    flow hedges                 $  76,335  $ (26,424) $ 163,454  $ (28,156)
                                =========  =========  =========  =========

   Included in commodity
    derivative loss:
   Realized losses on
    derivatives not
    designated
    cash flow hedges            $  (1,023) $       -  $  (1,023) $       -
   Unrealized
    ineffectiveness
    recognized on
    derivatives
    designated cash
    flow hedges                      (599)    (1,036)    (6,462)    (2,566)
   Unrealized losses on
    derivatives not designated
    cash flow hedges (basis
    only swaps)                    (7,341)    (2,277)   (27,434)    (2,277)
                                ---------  ---------  ---------  ---------
      Total commodity
       derivative loss          $  (8,963) $  (3,313) $ (34,919) $  (4,843)
                                =========  =========  =========  =========

(2)   Production tax expense for the 2009 periods 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 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
                                          June 30, 2009   December 31, 2008
                                        ----------------- -----------------
(in thousands)                                              (As Adjusted)
                                        ----------------- -----------------
Assets:
                                        ----------------- -----------------
        Cash and cash equivalents       $          63,523 $          43,063
        Other current assets       (1)            202,872           270,311
        Property and equipment, net             1,667,574         1,561,819
        Other noncurrent assets    (1)             44,075           119,300
                                        ----------------- -----------------
                Total assets            $       1,978,044 $       1,994,493
                                        ================= =================


                                        ================= =================
Liabilities and Stockholders' Equity:
                                        ----------------- -----------------
        Current liabilities             $         174,592 $         225,794
        Notes payable under bank credit
         facility                                 299,000           254,000
        Convertible senior notes   (2)            155,975           153,411
        Other long-term liabilities               266,349           262,055
        Stockholders' equity                    1,082,128         1,099,233
                                        ----------------- -----------------
                Total liabilities and
                 stockholders' equity   $       1,978,044 $       1,994,493
                                        ================= =================

(1) At June 30, 2009, the estimated fair value of all of our commodity
    derivative instruments was a net asset of $182.4 million, comprised of:
    $156.5 million current assets; $38.7 million non-current assets; and
    $2.5 million current liabilities and $10.3 million non-current
    liabilities.  This amount will fluctuate quarterly based on estimated
    future commodity prices.

(2) Effective January 1, 2009, the Company adopted financial reporting rule
    FSP ABP 14-1 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. The principal
    value of the notes is $172.5 million.

                         BILL BARRETT CORPORATION
                  Consolidated Statements of Cash Flows
                                (Unaudited)


                      Quarter Ended June 30,    Six Months Ended June 30,
                    --------------------------  --------------------------
                        2009          2008          2009          2008
                    ------------  ------------  ------------  ------------
                                      (As                         (As
(in thousands)                      Adjusted)                   Adjusted)
                    ------------  ------------  ------------  ------------
Operating
 Activities:
                    ------------  ------------  ------------  ------------
  Net income        $     10,608  $     33,269  $     37,021  $     63,823
  Adjustments to
   reconcile to net
   cash provided by
   operations:
     Depreciation,
      depletion and
      amortization        63,960        49,160       122,717       100,117
     Impairment,
      dry hole
      costs and
      abandonment
      costs               10,546         3,603        10,731         5,155
     Unrealized
      derivative
      loss                 7,940         3,313        33,896         4,843
     Deferred
      income taxes         2,824        16,629        19,452        35,436
     Stock
      compensation
      and other
      non-cash
      charges              4,232         4,913         8,546         8,887
     Amortization
      of deferred
      financing
      costs                1,821         1,625         3,572         2,126
     Amortization
      of discount
      on
      convertible
      notes
     (Gain) loss on
      sale of
      properties              65          (401)           66          (573)
                    ------------  ------------  ------------  ------------
     Change in
      assets and
      liabilities:
         Accounts
          receivable      12,357       (11,338)       25,266       (30,870)
         Prepayments
          and other
          assets           1,334        (3,054)       (1,170)       (6,168)
         Accounts
          payable,
          accrued
          and other
          liabilities      2,344         6,279         9,012         3,197
         Amounts
          payable
          to oil &
          gas
          property
          owners          (1,383)        3,791        (6,720)        2,646
         Production
          taxes
          payable          2,955         5,914          (250)       10,280
                    ------------  ------------  ------------  ------------

     Net cash
      provided by
      operating
      activities    $    119,603  $    113,703  $    262,139  $    198,899
                    ============  ============  ============  ============
Investing
 Activities:
                    ------------  ------------  ------------  ------------
  Additions to oil
   and gas
   properties,
   including
   acquisitions         (152,105)     (108,463)     (287,006)     (223,455)
  Additions of
   furniture,
   equipment and
   other                    (697)         (861)       (1,923)       (1,466)
  Proceeds from
   sale of
   properties              2,714           427         2,714         1,639
                    ------------  ------------  ------------  ------------

     Net cash used
      in investing
      activities    $   (150,088) $   (108,897) $   (286,215) $   (223,282)
                    ============  ============  ============  ============
Financing
 Activities:
                    ------------  ------------  ------------  ------------
  Proceeds from
   debt                   58,000        20,000       100,000       219,800
  Principal
   payments on debt      (35,000)          (21)      (55,000)     (167,035)
  Proceeds from
   sale of common
   stock                     482         1,815           482         3,444
  Deferred
   financing costs
   and other                (944)         (515)         (946)       (5,103)
                    ------------  ------------  ------------  ------------

     Net cash
      provided by
      financing
      activities    $     22,538  $     21,279  $     44,536  $     51,106
                    ============  ============  ============  ============

                    ============  ============  ============  ============
Increase (Decrease)
 in Cash and Cash
 Equivalents              (7,947)       26,085        20,460        26,723

Beginning Cash and
 Cash Equivalents         71,470        60,923        43,063        60,285
                    ------------  ------------  ------------  ------------

Ending Cash and
 Cash Equivalents   $     63,523  $     87,008  $     63,523  $     87,008
                    ============  ============  ============  ============



                         BILL BARRETT CORPORATION
 Reconciliation of Discretionary Cash Flow & Adjusted Net Income from Net
                                  Income
                                (Unaudited)



Discretionary Cash Flow Reconciliation
                      Quarter Ended June 30,    Six Months Ended June 30,
                    --------------------------  --------------------------
                        2009          2008          2009          2008
                    ------------  ------------  ------------  ------------
(in thousands,
 except per share                 (As Adjusted)               (As Adjusted)
 amounts)
                    ============  ============  ============  ============
Net Income          $     10,608  $     33,269  $     37,021  $     63,823

Adjustments to
 reconcile to
 discretionary cash
 flow:
   Depreciation,
    depletion and
    amortization          63,960        49,160       122,717       100,117
   Impairment, dry
    hole costs and
    abandonment
    costs                 10,546         3,603        10,731         5,155
   Exploration
    expense                  782         1,284         1,542         1,925
   Unrealized
    derivative loss        7,940         3,313        33,896         4,843
   Deferred income
    taxes                  2,824        16,629        19,452        35,436
   Stock
    compensation
    and other
    non-cash
    charges                4,232         4,913         8,546         8,887
   Amortization of
    deferred
    financing and
    discount on
    convertible
    notes                  1,821         1,625         3,572         2,126
   (Gain) loss on
    sale of
    properties                65          (401)           66          (573)
                    ------------  ------------  ------------  ------------
Discretionary Cash
 Flow               $    102,778  $    113,395  $    237,543  $    221,739
                    ============  ============  ============  ============

   Per share,
    diluted         $       2.28  $       2.50  $       5.30  $       4.90
   Per Mcfe         $       4.65  $       5.90  $       5.38  $       5.93


Adjusted Net Income Reconciliation
                      Quarter Ended June 30,    Six Months Ended June 30,
                    --------------------------  --------------------------
                        2009          2008          2009          2008
                    ------------  ------------  ------------  ------------
(in thousands except
per share amounts)                (As Adjusted)               (As Adjusted)

                    ============  ============  ============  ============
Net Income          $     10,608  $     33,269  $     37,021  $     63,823

Adjustments to net
 inome:
   Unrealized
    derivative loss        7,940         3,313        33,896         4,843
   (Gain) loss on
    sale of
    properties                65          (401)           66          (573)
   One time items:
      Production
       tax expense             0             -             5             -
                    ------------  ------------  ------------  ------------
   Subtotal
    Adjustments            8,005         2,912        33,967         4,270
   Effective tax
    rate                      41%           33%           39%           36%
                    ------------  ------------  ------------  ------------
   Tax effected
    adjustments            4,763         1,937        20,639         2,739
                    ------------  ------------  ------------  ------------
Adjusted Net Income $     15,371  $     35,206  $     57,660  $     66,562
                    ============  ============  ============  ============

   Per share,
    diluted         $       0.34  $       0.77  $       1.29  $       1.47
   Per Mcfe         $       0.70  $       1.83  $       1.31  $       1.78

The non-GAAP 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 accounting principles generally accepted in the
United States of America ("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.

Contact Information

  • Company contact:
    Jennifer Martin
    Director of Investor Relations
    303-312-8155