SOURCE: Bill Barrett Corporation

Bill Barrett Corporation

February 23, 2010 08:00 ET

Bill Barrett Corporation Reports 2009 Results: Another Record Year

DENVER, CO--(Marketwire - February 23, 2010) - Bill Barrett Corporation (NYSE: BBG) today reported full-year 2009 operating results highlighted by:

--  Production growth, up 16% to 89.7 Bcfe
--  Proved reserve growth, up 18% to 965 Bcfe
--  Proved, probable and possible reserves up 97% to 5.7 Tcfe
--  Discretionary cash flow of $459.6 million, or $10.21 per diluted common
    share and $5.12 per Mcfe
--  Net income of $50.2 million, or $1.12 per diluted share, and adjusted
    net income of $82.7 million, or $1.84 per diluted share
--  Finding and development costs that average $1.74 per Mcfe, weighted
    over three years
--  Current available borrowing capacity of $593 million

Chairman and Chief Executive Officer Fred Barrett commented: "Our Company continues to deliver solid growth, maintaining its outstanding multi-year track record. In 2009, we realized record discretionary cash flow (a non-GAAP measure, see 'Discretionary Cash Flow Reconciliation' below) of $460 million, substantial production growth of 16%, positive reserve replacement of 264%, and we reduced finding and development costs (See 'Costs Incurred and Reserve Information' below) to $1.68 per thousand cubic feet ('Mcfe') for the year. 2009 results underscore our Company's position as a low cost operator and confirm the quality and long-term visibility of our asset base.

"We are off to a great start in 2010. Projected production growth of 8% to 12%, combined with hedge positions already in place on approximately 60% of production, is expected to deliver another year of solid cash flow. In addition, we have a very strong balance sheet with current available borrowing capacity of $593 million that positions the Company to take advantage of growth opportunities. Our 2010 capital program is focused on development properties yet will be flexible to additional activity if we choose to pursue accelerated growth either through acquisition, exploration success, or if regulatory approvals are received at West Tavaputs."

Natural gas and oil production totaled 89.7 billion cubic feet equivalent ("Bcfe") in 2009 compared with 77.6 Bcfe in 2008. Including the effects of the Company's hedging activities, the average realized sales price was $7.10 per Mcfe in 2009 compared with $7.81 per Mcfe in 2008. The Company's 2009 hedging program increased its natural gas and oil revenues by $271.8 million, or $3.03 per Mcfe of production. For the fourth quarter 2009, production totaled 22.8 Bcfe, up 11% compared with 20.6 Bcfe in the fourth quarter of 2008, and the average realized price was $7.02 per Mcfe, up from $6.96 per Mcfe in the fourth quarter of 2008.

Proved reserves at year-end 2009 were 964.8 Bcfe, up 18% from 818.3 Bcfe at year-end 2008. Capital expenditures for 2009 totaled $406.4 million, down significantly from $601.1 million in 2008 as the Company aligned 2009 capital expenditures with discretionary cash flow.

Discretionary cash flow (a non-GAAP measure, see "Discretionary Cash Flow Reconciliation" below) was $459.6 million in 2009, or $10.21 per diluted common share, up $30.5 million compared with $429.1 million, or $9.53 per diluted common share, in 2008. The increase in 2009 is due to: a 16% increase in production; lower general and administrative expenses; lower cash operating costs, which included lower lease operating expense and lower production taxes; partially offset by a lower average realized price. For the fourth quarter of 2009, discretionary cash flow was $114.4 million, or $2.53 per diluted common share, up from $101.8 million, or $2.28 per diluted common share, in the fourth quarter of 2008. Fourth quarter 2009 results benefited from higher production, higher oil prices and certain lower per unit costs.

Net income was $50.2 million in 2009, or $1.12 per diluted common share, compared with $105.3 million, or $2.34 per diluted common share, in 2008. The decline in net income is driven by higher non-cash charges, primarily $43.7 million of unrealized losses on commodity derivatives. Net income for 2009 also includes: an impairment expense of $19.7 million related to sub-economic performing wells at the Company's Yellow Jacket prospect in the Paradox Basin and to properties in the North Hill Creek field in the Uinta Basin; one-time benefits to production tax expenses of $5.0 million as a result of amended severance tax returns for 2004 through 2008; and, a gain on the sale of properties of $1.4 million. Adjusting for these items, tax effected, adjusted net income (a non-GAAP measure, see "Adjusted Net Income Reconciliation" below) was $82.7 million. Total dry hole expense for 2009 was $30.7 million, or $17.5 million after tax, and included interests in 14 wells in five exploration areas. Net income for the fourth quarter of 2009 was $12.5 million compared with $6.1 million in the fourth quarter of 2008. Adjusted net income was $20.3 million in the fourth quarter of 2009, nearly flat with $19.9 million in the fourth quarter of 2008.

DEBT AND LIQUIDITY

As of December 31, 2009, the Company had $5.0 million in outstanding borrowings on its revolving credit facility, which were entirely repaid in February 2010. The revolving credit facility has a borrowing base of $630.0 million and bank commitments totaling $592.8 million. Also at December 31, 2009, the Company 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. 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 twelve months ended December 31, 2009:


                Three Months ended               Twelve Months ended
                December 31, 2009                 December 31, 2009
          ------------------------------- -------------------------------
          Average Net  Wells    Capital   Average Net  Wells    Capital
          Production   Spud  Expenditures Production   Spud  Expenditures
Basin     (Mmcfe/d)   (gross)  (millions) (Mmcfe/d)   (gross)  (millions)
          ---------- --------- ---------- ---------- --------- ---------


Piceance         106        38 $     51.6        100       119 $   254.8(1)
Uinta             81         4       13.7         88        20      93.7
Powder
 River (CBM)      37        16        2.5         33        40      13.9
Wind River        21         0        3.4         23         0       5.1
Paradox            2         0        2.7          1         5      25.2
Other              1         1        4.0          1         2      13.7
          ---------- --------- ---------- ---------- --------- ---------

Total            248        59 $     77.9        246       186 $   406.4
          ========== ========= ========== ========== ========= =========

(1) Includes $60 million for the acquisition of Cottonwood Gulch

Fourth quarter 2009 capital expenditures totaled $77.9 million and full year 2009 expenditures totaled $406.4 million, well within 2009 discretionary cash flow of $459.6 million. Expenditures for 2009 included: $329.3 million for drilling, exploration and development of natural gas and oil properties, $71.8 million for acquisitions of proved and unevaluated properties and other real estate, $3.2 million for geologic and geophysical costs and exploratory dry holes and abandonment, and $2.1 million for furniture, fixtures, equipment and other assets. The Company did not have any material divestitures in 2009.

Operating and Drilling Update

The Company currently has five rigs drilling, with three in the Piceance Basin, one at West Tavaputs and one at Blacktail Ridge. The 2010 drilling program will concentrate on growth at our key development areas.

Piceance Basin, Colorado

Gibson Gulch - Current net production is approximately 106 million cubic feet equivalent per day (MMcfe/d). During 2009, Piceance operations continued to realize improved operating efficiencies, driven primarily by the Company's water management system, and improved drilling efficiencies, reflected by an average six days drilling time per well, down from nine days in 2008. In addition, the Company elected to process natural gas, which added on average $0.32 per Mcfe to the realized price company-wide for 2009. Piceance operations exemplify our Rocky Mountain expertise and offer strong margins due to low cost operations and the benefit to revenue related to liquids. In 2010, the Company plans to drill 120 to 130 wells in its Gibson Gulch program and realize year-over-year production growth of approximately 30% for the project. The Gibson Gulch program continues to be a key, lower risk development area for the Company and offers flexibility to adjust the number of active rigs dependent upon the Company's capital strategy.

At December 31, 2009, the Company had an approximate 96% working interest in production from 532 gross wells in its Gibson Gulch program.

Cottonwood Gulch - In June 2009, the Company acquired a 90% working interest in 40,300 undeveloped acres in Cottonwood Gulch. The Company continues to participate in the mediation process for a lawsuit by environmental groups challenging the leases. The property has a signed Record of Decision for an Environmental Impact Statement and Resource Management Plan in effect with the Bureau of Land Management. The Company agreed to delay oil and gas activities during the mediation process.

Uinta Basin, Utah

West Tavaputs - Current net production is approximately 66 MMcfe/d. The Company recommenced drilling in December 2009 with three wells and plans to drill and complete eight additional wells in the first half of 2010, as well as to complete eight wells from the 2009 program. During 2009, the Company continued to improve operating costs at West Tavaputs, primarily through the addition of a salt water disposal well that serves to better manage produced water. Results from 20-acre density wells on the Prickly Pear mesa continued to be positive and the Company expects to continue drilling this acreage with the increased density locations. During 2009, the Company worked closely with groups representing archeological, wildlife and wilderness interests in regards to the development of West Tavaputs. The Company believes it is close to resolution in addressing their interests and concerns and looks forward to working together with the Bureau of Land Management in obtaining the final Environmental Impact Statement and Record of Decision for full-field development of the West Tavaputs project, which is expected in the first half of 2010. The West Tavaputs program offers growth in the shallow Mesaverde and Wasatch zones as well as upside opportunity through the Mancos shale.

At December 31, 2009, the Company had an approximate 97% working interest in production from 166 gross wells in its West Tavaputs shallow and deep programs.

Blacktail Ridge/Lake Canyon - Current net production is approximately 629 barrels of oil equivalent per day ("Boepd") from 9 wells. The Company drilled one well in 2009 and currently has a rig in the area and plans to participate in up to a 16-well program in 2010. The working interests in this area range from 19% to 100%.

Powder River Basin, Wyoming

Coal Bed Methane (CBM) - Current CBM net production is approximately 36 MMcf/d. The Company plans to participate in a 60 to 70 well program for 2010 beginning in the second half of the year when wildlife stipulations end. The Company drilled 40 wells in 2009 and production increased approximately 45% during the year, benefitting from continued dewatering of wells drilled earlier in addition to an extensive workover program. Development of this area requires dewatering of wells, which takes an average of six to 12 months.

At December 31, 2009, the Company had an approximate 73% working interest in production from 676 gross CBM wells.

Wind River Basin, Wyoming

Cave Gulch/Bullfrog/Other - Current net production from the area is approximately 21 MMcfe/d, including the Bullfrog 33-19 well that was recompleted in December 2009.

Paradox Basin, Colorado

Yellow Jacket - At the Yellow Jacket shale gas prospect (55% working interest), the Koskie 13H-27 well is currently producing 1.1 MMcfe/d from the Gothic shale at 400 psi tubing pressure. This well was completed with a substantially larger fracture stimulation than used on earlier well completions, which has produced better results. The Company will continue to monitor data from this well for the next few months and plans to commence its 2010 confirmation program in the second quarter of 2010 with a minimum of one well. This prospect includes approximately 308,600 gross, and 139,750 net, undeveloped acres plus approximately 178,600 gross, and 127,600 net, undeveloped acres in a similar shale gas prospect in the adjacent Green Jacket area.

ADDITIONAL FINANCIAL INFORMATION

Guidance

As previously announced, the Company's 2010 guidance (please reference "Forward-looking Statements" below) includes:

--  Capital expenditures of $400 to $425 million before acquisitions
--  Oil and natural gas production of 97 to 100 Bcfe
--  Lease operating costs per Mcfe of $0.57 to $0.61
--  Gathering and transportation costs per Mcfe of $0.75 to $0.80
--  General and administrative expenses before non-cash stock-based
    compensation between $40 and $43 million

Commodity Hedges Update

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. Hedging is intended to reduce the risks associated with unpredictable future commodity prices and to provide predictability for a portion of cash flows to support the Company's capital expenditure program.

For 2010 and 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 2010, approximately 60.2 Bcfe at a weighted average blended floor
    price of $7.67 per Mcfe. These hedges are weighted more heavily through
    the third quarter of 2010 when seasonal natural gas prices tend to be
    lower.
--  For 2011, approximately 34.8 Bcfe at a weighted average blended floor
    price of $6.72 per Mcfe.

As of February 18, 2010:

SWAPS & COLLARS

Period            Natural Gas/NGLs         Oil              Equivalent
                ------------------- ------------------- -------------------
                 Volume     Price    Volume     Price    Volume     Price
                MMBtu/d   $/MMBtu     Bbl/d     $/Bbl     Mmcfe    $/Mcfe
                --------- --------- --------- --------- --------- ---------

 1Q10             185,315 $    6.85       966 $   79.65    15,684 $    7.73
 2Q10             187,502 $    6.79     1,000 $   79.88    16,058 $    7.67
 3Q10             187,464 $    6.79     1,000 $   79.88    16,231 $    7.66
 4Q10             140,056 $    6.67     1,000 $   79.88    12,266 $    7.60
 1Q11             122,500 $    6.31         -         -    10,023 $    6.94
 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

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

-- 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.

FOURTH QUARTER AND YEAR-END 2009 WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held later this morning to discuss fourth quarter and year-end 2009 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 866-713-8566 (617-597-5325 international callers) with passcode 11510914. The webcast will remain available on the Company's website for approximately 30 days, and a replay of the call will be available through February 26, 2010 at call-in number 888-286-8010 (617-801-6888 international) with passcode 79944965. The Company has also tentatively scheduled its 2010 earnings conference calls for 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. None of the following conference presentations is webcast, but please check the website at 5:00 p.m. Mountain time the business day prior to the investor event for the most recent presentation.

Chief Financial Officer Bob Howard plans to present at the 2010 J.P Morgan Global High Yield and Leveraged Finance Conference on March 1, 2010 at 10:15 a.m. Eastern time.

President and Chief Operating Officer Joe Jaggers will participate in an E&P panel discussion at the Simmons & Company International Tenth Annual Energy Conference on March 3, 2010 at 11:00 a.m. Pacific time.

Chairman and Chief Executive Officer Fred Barrett plans to present at the Howard Weil 38th Annual Energy Conference on March 22, 2010 at 4:20 p.m. Central time.

DISCLOSURE STATEMENTS

Reserve Disclosure

The Securities and Exchange Commission ("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 press release. The estimates are consistent with the guidelines outlined in the SPE/WPC/AAPG/SPEE Petroleum Resources Management System. The estimates are not prepared or reviewed by third party engineers and do not conform to SEC guidelines for estimating proved and possible reserves. Our probable and possible reserve estimate methodology differs from the new SEC guidelines including our use of commodity pricing. Rather than the SEC simple 12-month average of the 2009 first day of the month oil and gas prices, we use strip pricing, which we use internally for planning and budgeting purposes. Because these estimates were not prepared in accordance with SEC Guidelines, they may not be included in SEC filings. 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. The Company's methods for estimating probable and possible reserves may differ from methods used by other companies to disclose non-proved reserves and our estimate may not be comparable to similarly titled measures provided by other companies. U.S. investors are urged to consider closely the disclosure in our Annual Report on Form 10-K, as filed for the year ended December 31, 2009, 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.

Forward-Looking Statements

This press release contains forward-looking statements, including statements regarding projected results and future events. In particular, the Company is providing "2010 Guidance," which contain projections for certain 2010 operational and financial results. 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, 2009 filed with the SEC, and other filings including our 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, exploration drilling and testing results, the ability to receive drilling and other permits and regulatory approvals, the outcome of negotiation with the wilderness and other groups and government approval for development projects, governmental regulations, availability and costs of financing to fund the Company's operations, availability of third party gathering, transportation and processing, market conditions, 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, unexpected future capital expenditures, competition, risks associated with operating in one major geographic area, the success of the Company's risk management activities, the speculative actual recovery of estimated potential volumes, 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  Twelve Months
                                                    Ended         Ended
                                                 December 31,  December 31,
                                                ------------- -------------
                                                 2009   2008   2009   2008
                                                ------ ------ ------ ------
Production Data:
                                                ------ ------ ------ ------
    Natural gas (MMcf)                          21,626 19,449 85,485 73,623
    Oil (MBbls)                                    193    188    710    661
    Combined volumes (MMcfe)                    22,784 20,577 89,745 77,589
    Daily combined volumes (MMcfed)                248    224    246    212
                                                ------ ------ ------ ------
Average Prices (before the effects of realized
 hedges):
                                                ------ ------ ------ ------
    Natural gas (per Mcf)                       $ 4.98 $ 4.09 $ 3.86 $ 7.05
    Oil (per Bbl)                                65.53  42.54  49.56  83.27
    Combined (per Mcfe)                           5.28   4.25   4.07   7.40
                                                ------ ------ ------ ------
Average Prices (includes the effects of
 realized hedges):
                                                ------ ------ ------ ------
    Natural gas (per Mcf)                       $ 6.79 $ 6.86 $ 6.96 $ 7.61
    Oil (per Bbl)                                67.76  51.88  59.03  69.55
    Combined (per Mcfe)                           7.02   6.96   7.10   7.81
                                                ------ ------ ------ ------
Average Costs (per Mcfe):
                                                ------ ------ ------ ------
    Lease operating expense                     $ 0.51 $ 0.58 $ 0.52 $ 0.57
    Gathering, transportation and processing
     expense                                      0.73   0.47   0.63   0.51
    Production tax expense (1)                    0.06   0.34   0.15   0.57
    Depreciation, depletion and amortization      2.82   2.75   2.83   2.66
    General and administrative expense,
     excluding stock-based compensation (2)       0.38   0.50   0.42   0.52

(1) Production tax expense for the three and twelve months ended December
    31, 2009 includes a one-time benefit to reduce prior periods as a
    result of an agreement with the State of Colorado regarding the
    calculation of severance taxes.  Exclusive of the one-time items,
    the production tax expense per unit would have been  $0.07 and $0.20
    for the three- and twelve-month periods.

(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   Twelve Months Ended
                                    December 31,          December 31,
                                --------------------  --------------------
                                  2009       2008       2009       2008
                                ---------  ---------  ---------  ---------
(in thousands, except per share
 amounts)
                                ---------  ---------  ---------  ---------
Operating and Other Revenues:
                                ---------  ---------  ---------  ---------
        Oil and gas
         production (1)         $ 168,384  $ 142,122  $ 647,839  $ 605,881
        Commodity derivative
         gain (loss) (1)           (5,955)     4,273    (54,567)     7,920
        Other                       3,344        380      4,891      4,110
                                ---------  ---------  ---------  ---------
          Total operating and
           other revenues         165,773    146,775    598,163    617,911
                                ---------  ---------  ---------  ---------

                                ---------  ---------  ---------  ---------
Operating Expenses:
                                ---------  ---------  ---------  ---------
        Lease operating            11,571     11,927     46,492     44,318
        Gathering,
         transportation and
         processing                16,596      9,596     56,608     39,342
        Production tax (2)          1,347      7,005     13,197     44,410
        Exploration                 1,055      5,204      3,227      8,139
        Impairment, dry hole
         costs and abandonment     22,451     26,447     52,285     32,065
        Depreciation, depletion
         and amortization          64,114     56,518    253,573    206,316
        General and
         administrative (3)         8,747     10,330     37,940     40,454
        Non-cash stock-based
         compensation (3)           4,377      4,656     16,458     16,752
                                ---------  ---------  ---------  ---------
          Total operating
           expenses               130,258    131,683    479,780    431,796
                                ---------  ---------  ---------  ---------
Operating Income                   35,515     15,092    118,383    186,115
                                ---------  ---------  ---------  ---------
Other Income and Expense:
                                ---------  ---------  ---------  ---------
        Interest and other
         income                       144        364        438      2,036
        Interest expense          (10,549)    (5,678)   (30,647)   (19,717)
                                ---------  ---------  ---------  ---------
          Total other income and
           expense                (10,405)    (5,314)   (30,209)   (17,681)
                                ---------  ---------  ---------  ---------
Income before Income Taxes         25,110      9,778     88,174    168,434
Provision for Income Taxes         12,631      3,657     37,956     63,175
                                ---------  ---------  ---------  ---------
Net Income                      $  12,479  $   6,121  $  50,218  $ 105,259
                                =========  =========  =========  =========

                                ---------  ---------  ---------  ---------
Net Income Per Common Share
        Basic                   $    0.28  $    0.14  $    1.12  $    2.37
        Diluted                 $    0.28  $    0.14  $    1.12  $    2.34
                                ---------  ---------  ---------  ---------

                                ---------  ---------  ---------  ---------
Weighted Average Common Shares
 Outstanding
        Basic                      44,782     44,531     44,723     44,432
        Diluted                    45,276     44,637     45,036     45,037
                                ---------  ---------  ---------  ---------

(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   Twelve Months Ended
                                    December 31,          December 31,
                                --------------------  --------------------
                                  2009       2008       2009       2008
                                ---------  ---------  ---------  ---------
        Included in oil and gas
         production revenue:
        Realized gains on cash
         flow hedges            $  49,070  $  54,560  $ 282,734  $  31,900
                                =========  =========  =========  =========

        Included in commodity
         derivative loss:
        Realized gains (losses)
         on derivatives not
         designated cash flow
         hedges                 $  (8,456) $   1,025  $ (10,902) $      62
        Unrealized
         ineffectiveness gains
         (losses) recognized on
         derivatives designated
         cash flow hedges             149      3,682     (5,572)     6,803
        Unrealized gains
         (losses) on
         derivatives not
         designated cash flow
         hedges                     2,352       (434)   (38,093)     1,055
                                ---------  ---------  ---------  ---------
           Total commodity
            derivative gain
            (loss)              $  (5,955) $   4,273  $ (54,567) $   7,920
                                =========  =========  =========  =========

(2) Production tax expense for 2009 includes a one-time benefit to reduce
    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.




                         BILL BARRETT CORPORATION
                  Consolidated Condensed Balance Sheets
                                (Unaudited)

                                                      As of       As of
                                                  December 31, December 31,
                                                       2009       2008
                                                   ----------- -----------
(in thousands)
                                                   ----------- -----------
Assets:
                                                   ----------- -----------
        Cash and cash equivalents                  $    54,405 $    43,063
        Other current assets (1)                       125,634     270,311
        Property and equipment, net                  1,659,260   1,561,819
        Other noncurrent assets (1)                     26,824     119,300
                                                   ----------- -----------
          Total assets                             $ 1,866,123 $ 1,994,493
                                                   =========== ===========


                                                   ----------- -----------
Liabilities and Stockholders' Equity:
                                                   ----------- -----------
        Current liabilities (1)                    $   153,292 $   225,794
        Notes payable under bank credit facility         5,000     254,000
        Senior notes (2)                               238,478           -
        Convertible senior notes                       158,772     153,411
        Other long-term liabilities (1)                282,026     262,055
        Stockholders' equity                         1,028,555   1,099,233
                                                   ----------- -----------
          Total liabilities and stockholders'
           equity                                  $ 1,866,123 $ 1,994,493
                                                   =========== ===========

(1) At December 31, 2009, the estimated fair value of all of our commodity
    derivative instruments was a net asset of $51.5 million, comprised of:
    $58.5 million current assets; $17.2 million non-current assets; $9.4
    million current liabilities; and $14.8 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.





                         BILL BARRETT CORPORATION
                  Consolidated Statements of Cash Flows
                                (Unaudited)


                                 Three Months Ended   Twelve Months Ended
                                     December 31,         December 31,
                                 -------------------  --------------------
                                   2009      2008       2009       2008
                                 --------  ---------  ---------  ---------
(in thousands)
                                 --------  ---------  ---------  ---------
Operating Activities:
                                 --------  ---------  ---------  ---------
  Net income                     $ 12,479  $   6,121  $  50,218  $ 105,259
  Adjustments to reconcile to
   net cash provided by
   operations:
     Depreciation, depletion and
      amortization                 64,114     56,518    253,573    206,316
     Impairment, dry hole costs
      and abandonment costs        22,451     26,447     52,285     32,065
     Unrealized derivative loss
      (gain)                       (2,501)    (3,248)    43,665     (7,858)
     Deferred income taxes         10,996      3,974     31,867     62,565
     Excess tax benefit from
      option exercises                (52)         -        (52)         -
     Stock compensation and
      other non-cash charges        4,675      4,957     17,750     18,117
     Amortization of deferred
      financing costs               2,457      1,801      8,410      5,619
     Loss (gain) on sale of
      properties                   (1,352)         2     (1,386)    (1,132)
                                 --------  ---------  ---------  ---------
     Change in assets and
      liabilities:
         Accounts receivable      (15,991)   (15,568)     3,854    (16,047)
         Prepayments and other
          assets                      920      4,309       (922)      (324)
         Accounts payable,
          accrued and other
          liabilities               7,133    (11,280)    20,046     (7,908)
         Amounts payable to oil
          & gas property owners     8,523     (3,718)     3,088     (5,142)
         Production taxes
          payable                  (5,925)    (7,556)    (1,652)    11,417
                                 --------  ---------  ---------  ---------

     Net cash provided by
      operating activities       $107,927  $  62,759  $ 480,744  $ 402,947
                                 ========  =========  =========  =========
Investing Activities:
                                 --------  ---------  ---------  ---------
  Additions to oil and gas
   properties, including
   acquisitions                   (77,591)  (183,670)  (450,411)  (568,445)
  Additions of furniture,
   equipment and other               (684)    (2,795)    (3,971)    (4,752)
  Proceeds from sale of
   properties                       1,034         51      3,748      2,405
                                 --------  ---------  ---------  ---------

     Net cash used in investing
      activities                 $(77,241) $(186,414) $(450,634) $(570,792)
                                 ========  =========  =========  =========
Financing Activities:
                                 --------  ---------  ---------  ---------
  Proceeds from credit facility         -     80,000    100,000    147,300
  Principal payments on credit
   facility                       (28,000)         -   (349,000)  (167,300)
  Proceeds from issuance of
   senior convertible notes             -          -          -    172,500
  Proceeds from issuance of
   9.875% senior notes                  -          -    237,930          -
  Deferred financing costs            (62)        (3)    (6,502)    (5,167)
  Proceeds from sale of common
   stock                              252         11        880      4,082
  Other                            (2,022)      (694)    (2,076)      (792)
                                 --------  ---------  ---------  ---------

     Net cash provided by (used
      in) financing activities   $(29,832) $  79,314  $ (18,768) $ 150,623
                                 ========  =========  =========  =========

                                 ========  =========  =========  =========
Increase (Decrease) in Cash and
 Cash Equivalents                     854    (44,341)    11,342    (17,222)

Beginning Cash and Cash
 Equivalents                       53,551     87,404     43,063     60,285
                                 --------  ---------  ---------  ---------

Ending Cash and Cash Equivalents $ 54,405  $  43,063  $  54,405  $  43,063
                                 --------  ---------  ---------  ---------



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

Discretionary Cash Flow Reconciliation

                                  Three Months Ended  Twelve Months Ended
                                     December 31,         December 31,
                                  ------------------  --------------------
                                    2009      2008      2009       2008
                                 --------  ---------  ---------  ---------
(in thousands, except per share
 amounts)
                                  --------  --------  ---------  ---------
Net Income                        $ 12,479  $  6,121  $  50,218  $ 105,259

Adjustments to reconcile to
 discretionary cash flow:
   Depreciation, depletion and
    amortization                    64,114    56,518    253,573    206,316
   Impairment, dry hole costs and
    abandonment costs               22,451    26,447     52,285     32,065
   Exploration expense               1,055     5,204      3,227      8,139
   Unrealized derivative loss
    (gain)                          (2,501)   (3,248)    43,665     (7,858)
   Deferred income taxes            10,996     3,974     31,867     62,565
   Stock compensation and other
    non-cash charges                 4,675     4,957     17,750     18,117
   Amortization of deferred
    financing and discount on
    convertible notes                2,457     1,801      8,410      5,619
   Loss (gain) on sale of
    properties                      (1,352)        2     (1,386)    (1,132)
                                  --------  --------  ---------  ---------
Discretionary Cash Flow           $114,374  $101,776  $ 459,609  $ 429,090
                                  ========  ========  =========  =========

   Per share, diluted             $   2.53  $   2.28  $   10.21  $    9.53
   Per Mcfe                       $   5.02  $   4.95  $    5.12  $    5.53


Adjusted Net Income Reconciliation

                                  Three Months Ended  Twelve Months Ended
                                     December 31,         December 31,
                                  ------------------  --------------------
                                    2009      2008      2009       2008
                                 --------  ---------  ---------  ---------
(in thousands except per share
 amounts)
                                  --------  --------  ---------  ---------
Net Income                        $ 12,479  $  6,121  $  50,218  $ 105,259

Adjustments to net inome:
   Unrealized derivative loss
    (gain)                          (2,501)   (3,248)    43,665     (7,858)
   Impairment expense               19,654    25,322     19,654     25,322
   Loss (gain) on sale of
    properties                      (1,352)        2     (1,386)    (1,132)
   One time items:
      Production tax expense          (187)        -     (4,983)         -
                                  --------  --------  ---------  ---------
   Subtotal Adjustments             15,614    22,076     56,950     16,332
   Effective tax rate                   50%       37%        43%        38%
                                  --------  --------  ---------  ---------
   Tax effected adjustments          7,807    13,820     32,461     10,206
                                  --------  --------  ---------  ---------
Adjusted Net Income               $ 20,286  $ 19,941  $  82,679  $ 115,465
                                  ========  ========  =========  =========

   Per share, diluted             $   0.45  $   0.45  $    1.84  $    2.56
   Per Mcfe                       $   0.89  $   0.97  $    0.92  $    1.49


The non-GAAP (Generally Accepted Accounting Principles) 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.



                         BILL BARRETT CORPORATION
                  Costs Incurred and Reserve Information
                                (Unaudited)

                                                     2009    2008    2007
                                                    ------  ------  ------
($ in millions)
                                                    ------  ------  ------
TOTAL CAPITAL EXPENDITURES                          $406.4  $601.1  $443.7
      Furniture, fixtures and equipment and real
       estate                                         (3.7)   (4.8)   (4.9)
      Asset retirement obligation                     (1.2)    8.2     1.0
                                                    ------  ------  ------
TOTAL COSTS INCURRED                                $401.6  $604.5  $439.8
                                                    ======  ======  ======


TOTAL COSTS INCURRED DISCLOSURE
      Exploration costs                             $185.4  $342.9  $250.7
      Development costs                              147.2   214.0   162.5
      Acquisition costs:
         Unproved properties                          70.1    33.1    23.6
         Proved properties                               -     6.3     2.0
      Asset retirement obligation                     (1.2)    8.2     1.0
                                                    ------  ------  ------
TOTAL COSTS INCURRED                                 401.5   604.5   439.8
             less: Asset retirement obligation         1.2    (8.2)   (1.0)
             less: Proceeds received from JV
              partners (1)                               -       -   (12.1)
             less: Deferred tax component of CH4
              acquisition                                -       -     1.6
             less: Capitalized interest               (4.6)   (2.0)   (1.6)
                                                    ------  ------  ------
         Adjusted costs incurred (2)                $398.1  $594.3  $426.7
                                                    ======  ======  ======

RESERVE ADDITIONS (Bcfe)
      Extensions, discoveries and other additions    177.3   196.2   175.7
      Revisions of previous estimates                101.5   146.4    34.8
      Revisions of previous estimates based on
       price                                         (42.8)   (7.3)   19.4
      Purchases of reserves in place                   0.5     3.1     2.7
                                                    ------  ------  ------
      RESERVE ADDITIONS                              236.5   338.4   232.6
                                                    ======  ======  ======


                                                    ======  ======  ======
SALES INFORMATION
                                                    ------  ------  ------
      Property sales (1)                            $  3.7  $  2.4  $ 84.4
      Sales of reserves (Bcfe)                         0.2     0.1    42.2
                                                    ======  ======  ======

(1) The sum of proceeds from joint venture partners and property sales
    equals "Proceeds from sales of properties" from the Consolidated
    Statement of Cash Flows.

(2) Finding and developments cost is a non-GAAP metric commonly used in
    the exploration and production industry. The calculation presented
    by the Company on page 1 is the quotient of "Adjusted costs incurred"
    divided by "Reserve additions." The calculation may not be comparable
    to similarly titled measures provided by other companies. The quotient
    of $1.68 per Mcfe is slightly revised from the estimate of $1.69 per
    Mcfe provided on January 21, 2010.

Contact Information

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