Bill Barrett Corporation Reports 2012 Financial and Operating Results and Announces Strong Initial Oil Rates on All Four-Well

  Bill Barrett Corporation Reports 2012 Financial and Operating Results and
     Announces Strong Initial Oil Rates on All Four-Well Pads in DJ Basin

PR Newswire

DENVER, Feb. 21, 2013

DENVER, Feb. 21, 2013 /PRNewswire/ -- Bill Barrett Corporation (NYSE: BBG)
today reported 2012 results and announced operational updates including:

  oTotal oil and natural gas production growth up 10% to 118 billion cubic
    feet equivalent ("Bcfe")
  oOil production up 80% to 2.7 million barrels
  oOil reserves up 66% to 51 million barrels
  oProved reserves plus risked resources of 2.9 trillion cubic feet
    equivalent ("Tcfe"), including nearly 200 million barrels of oil
  oDiscretionary cash flow of $403 million or $8.51 per diluted common share;
    Adjusted net income of $6.9 million, or $0.15 per diluted common share
    (non-GAAP measures, see below)
  oSuccess with Denver-Julesburg ("DJ") Basin pad drilling, with 30-day rates
    averaging 412 barrels of oil equivalent per well per day ("Boe/d") at the
    first three four-well pads
  oCompletion of $335 million sale of natural gas assets

Chief Executive Officer Scot Woodall commented: "We closed 2012 with estimated
proved reserves that included 51 million barrels of oil, an increase of 66%
over 2011, and exit rate production that included 8,950 barrels of oil per
day, accounting for24% of total production. We have established a drilling
inventory at our key oil programs of nearly 3,000 locations, or more than 15
years of drilling based on current activity.

"We have commenced 2013 with a focused strategy: execute development of our
two core oil programs to optimize operating efficiencies and returns. We will
increase activity at the Uinta Oil Program with a four-rig vertical drilling
program. In the DJ Basin, we are very encouraged by results to date. We will
run a two-rig program that will be predominantly pad drilling, as well as
delineate our acreage position in the Northeast Wattenberg –an area where
industry activity has established proven results, identified significant
upside and demonstrated repeatability. We have no active rigs in our natural
gas plays.

"We have an $825 million line of credit and have approximately 70% of 2013
production hedged. As previously reported, we plan to fully fund our 2013
capital program with cash flows and asset sales. We are well positioned with
the right assets, excellent liquidity and a solid, focused plan to deliver
value to our shareholders in 2013."

OPERATING AND FINANCIAL RESULTS

Total estimated proved reserves at year-end 2012 were 1.04 trillion cubic feet
equivalent ("Tcfe"). Estimated proved reserves were 29% oil and 71% natural
gas and were 59% developed and 41% undeveloped.

Oil and natural gas production totaled 117.6 Bcfe in 2012, up 10% from 106.8
Bcfe in 2011. Production growth was primarily from the Uinta and DJ oil
programs followed by growth in natural gas production stemming from early year
drilling at West Tavaputs and Gibson Gulch. Year-over-year growth in oil
production of 80% met the Company's target for the year. Fourth quarter
production was 28.2 Bcfe, down slightly from 29.1 Bcfe in the fourth quarter
of 2011, and was negatively affected by 1.2 Bcf due to a fire at a West
Tavaputs compressor station.

Realized pricing, including the effects of the Company's hedging activities
and natural gas liquids ("NGL") recovery, was $6.32 per thousand cubic feet
equivalent ("Mcfe"), including an $0.82 per Mcfe benefit from NGL-related
pricing and a $1.05 per Mcfe benefit from realized hedges. The average
realized price is down from $7.05 per Mcfe in 2011, primarily due to
significantly lower natural gas and NGL prices. The average realized natural
gas price was $5.07 per Mcf in 2012 compared with $6.46 per Mcf in 2011. The
average realized oil price was $84.96 per barrel ("Bbl") in 2012 compared with
$80.63 per Bbl in 2011. The fourth quarter 2012 average realized price was
$6.78 per Mcfe compared with $6.96 per Mcfe in 2011. (See "Selected Operating
Highlights" below for more detail.)

Discretionary cash flow (a non-GAAP measure, see "Discretionary Cash Flow
Reconciliation" below) for 2012 was $402.9 million, or $8.51 per diluted
common share, down from $478.2 million, or $10.12 per diluted common share, in
2011. The decline in discretionary cash flow is primarily due to lower
realized natural gas prices and increased interest expenses, partially offset
by higher production volumes. Discretionary cash flow was $103.5 million for
the fourth quarter of 2012 compared with $124.8 million for the fourth quarter
of 2011.

Net income for 2012 was $0.6 million, or $0.01 per diluted common share, down
from income of $30.7 million, or $0.65 per diluted common share, in 2011. Net
income in 2012 was affected by the same factors as discretionary cash flow,
which were partially offset by a commodity derivative gain in 2012 of $72.8
million versus a loss in 2011 of $14.3 million and a lower impairment expense
in 2012 of $37.3 million versus $100.3 million in 2011. Dry hole expenses in
2012 were $21.0 million, or $13.0 million after-tax (applying a standard 38%
rate.) Net income for the fourth quarter was $14.0 million compared with a
loss of $37.8 million in the fourth quarter of 2011. Dry hole expenses in the
fourth quarter were $5.1 million (pre-tax), which related primarily to one
exploratory dry hole in the Southern Alberta Basin.

Adjusted net income (a non-GAAP measure, see "Adjusted Net Income
Reconciliation" below) for 2012 was $6.9 million, or $0.15 per diluted common
share, compared with $84.0 million, or $1.78 per diluted common share, in
2011. Adjusted net income for the fourth quarter of 2012 was $9.6 million
compared with $20.6 million in 2011. Adjusted net income removes the effect of
non-recurring charges such as unrealized derivative gains and losses,
impairment expenses, property sales and one-time items.

On December 31, 2012, the Company closed on the sale of natural gas assets for
a transaction value of $335 million. The assets included all Wind River
natural gas producing properties, Powder River Basin coal bed methane and a
working interest in the Gibson Gulch-Piceance Basin development property. The
transaction value was adjusted to the October 1, 2012 effective date and for
other customary closing adjustments, providing net proceeds to the Company of
$325.3 million, which included a $33.5 million deposit received in November
2012. Net proceeds from the transaction were applied to pay off the $250
million balance on the Company's revolving credit facility and to working
capital, with the remaining proceeds of approximately $30 million to be
applied to the Company's 2013 development capital.

DEBT AND LIQUIDITY

At December 31, 2012, the Company had borrowing capacity of $799.0 million and
total debt outstanding of $1.17 billion. The Company had zero drawn on its
revolving credit facility. The facility has a borrowing base of $825.0 million
less an outstanding letter of credit for $26.0 million. Debt outstanding
includes $1,075.3 million principal in senior notes and $97.6 million for a
lease financing obligation. The Company has no significant debt maturity
before 2016.

OPERATIONS

Production and Capital Expenditures

The following table lists average daily production and capital expenditures by
basin for the three and twelve months ended December 31, 2012:

                      Average Net Production      Capital Expenditures
                      (MMcfe/d)                   ($millions)
                      Three Months  Twelve        Three        Twelve
                      Ended         Months Ended  Months       Months
                                                  Ended        Ended
                      December 31,  December 31,  December     December
                      2012          2012          31, 2012     31, 2012
Basin
Uinta:
   Uinta Oil Program  42            31            72           315
   West Tavaputs      77            95            14           107
Piceance              134           141           15           208
Denver-Julesburg      15            10            50           226
Powder River (CBM)    26            30            -            -
Other                 13            14            33           108
Total                 307           321           184          963

(MMcfe/d: million cubic feet equivalent per day)

Operating and Drilling Update

The Company's 2013 capital budget is focused on development drilling at the
Company's two core oil programs in the Uinta and DJ Basins. The capital budget
anticipates drilling or participating in approximately 180 gross/100 net
development wells, including approximately 30 non-operated wells, and includes
on average four active rigs in the Uinta and two active rigs in the DJ. The
budget also anticipates drilling at least five development wells in the Powder
River Deep Oil Program.

Uinta Basin, Utah

Uinta Oil Program (Blacktail Ridge, Lake Canyon, East Bluebell and South
Altamont) –

The Company is currently running a four-rig program in the area and expects to
drill approximately 80-85 gross/45-50 net operated wells in 2013, plus
participate in approximately 8 wells operated by its partner in Lake Canyon.
Substantially all wells are vertical development wells. The 2013 drilling
program includes activity in each of the Company's positions across the basin,
including Blacktail Ridge, Lake Canyon, South Altamont and East Bluebell, and
includes testing 80-acre spacing in the Blacktail Ridge area.

During 2012, the Company increased production from the area significantly,
increasing 86% in the fourth quarter of 2012 compared with the fourth quarter
of 2011. In addition, year-end reserves in the area increased 63% to 47 MMBoe.

At December 31, 2012, the Company had an approximate 76% working interest in
production from 226 gross wells. The working interests for wells in the 2013
program are expected to average 54% (or higher depending upon partner
elections). As of year-end 2012, the Company had approximately 155,000 net
acres (including acreage to be earned) in the program.

West Tavaputs – Drilling in the area remains suspended due to low natural gas
prices. Fourth quarter 2012 production was negatively affected by a fire at
one of the Company's compressor stations in the area, with the majority of
production back on-line by the start of the first quarter. 

At December 31, 2012, the Company had an approximate 96% working interest in
production from 298 gross wells.

The Company's acreage in the area, including acreage at the nearby Hornfrog
prospect and other acreage that can be earned, is 71,000 gross and 53,000 net.
The Company plans no drilling activity in the area in 2013, which will have a
nominal effect on its lease position and is not expected to impact future
drilling plans.

Denver-Julesburg Basin, Colorado and Wyoming

Wattenberg – In the rapidly growing DJ Basin program, the Company is currently
running one rig with plans to add a second rig in the second quarter. The
Company expects to drill approximately 65 gross/45 net operated wells in 2013,
plus participate in approximately 20 wells operated by partners. The 2013
drilling planis primarily focused onhorizontal development drilling,
targeting the B bench of the Niobrara formation.

The Company initiated pad drilling in the second half of 2012 with three
four-well pads. The wells were drilled on average to a vertical depth of
approximately 6,400 feet plus a 4,000 foot lateral with an average of 18
fracture stimulation stages. One pad placed all four horizontal wells into the
Niobrara B bench and the two additional pads drilled two wells into the
Niobrara B and two wells into the Niobrara C benches. Results are encouraging
to date, with 24-hour peak rates that averaged 742 Boe/d per well and 30-day
average rates of 412 Boe/d per well.

During 2012, the Company significantly increased production from the area, up
2.6 times in the fourth quarter of 2012 compared with the fourth quarter of
2011. The Company increased year-end reserves in the area by 82% to 12 MMBoe
and estimated risked resources (see "Reserve and Resource Disclosure" below)
in the area at 89 MMBoe with more than 1,000 associated drilling locations.

At December 31, 2012, the Company had an approximate 74% working interest in
production from 298 gross wells and held approximately 76,000 net acres in the
program including approximately 39,700 in the Northeast Wattenberg where the
Company plans to concentrate its 2013 drilling program. 

Piceance Basin, Colorado

Gibson Gulch – Drilling in the area remains suspended as a result of low
natural gas and NGL prices. In the fourth quarter of 2012, the Company closed
on the sale of an 18% interest (which progresses to 26% in 2016) in Gibson
Gulch.

A portion of Gibson Gulch natural gas production is processed, at the election
of the Company, exposing the Company to the benefits of NGL pricing. The
incremental benefit to the Company-wide realized price from natural gas
liquids was $0.82 per Mcfe in 2012 and $0.62 per Mcfe in the fourth quarter of
2012. Due to low current and anticipated pricing of ethane, the Company has
elected to reject ethane in the processing of NGLs for the first quarter of
2013 and expects it may elect to reject ethane in future quarters of 2013.

At December 31, 2012, the Company had an approximate 80% working interest in
production from 955 gross wells in its Gibson Gulch program. The Company plans
no drilling activity in the area in 2013, which will have no effect on its
lease position, as 99% of the Company's net acreage is held by production.

ADDITIONAL FINANCIAL INFORMATION

Guidance

The Company's 2013 guidance (please reference "Forward-Looking Statements"
below) is as follows. As previously reported, the Company is committed to not
increasing debt year-over-year and intends to fund its capital expenditure
program with cash flow and property dispositions.

The Company may update the following guidance as business conditions warrant:

  oCapital expenditures of $475 to $525 million.
  oOil and natural gas production of 83 to 87 Bcfe on a two-stream basis or
    oil, natural gas and NGL production of 86 to 90 Bcfe on a three-stream
    basis. The Company is targeting 50% to 55% growth in oil production in
    2013 over 2012 and expects approximately 6% to 8% of production will be
    NGLs (assuming ethane rejection.)
  oLease operating costs of $62 to $67 million.
  oGathering, transportation and processing costs of $72 to $75 million.
  oGeneral and administrative expenses, before non-cash stock-based
    compensation costs, of $50 to $54 million. This range includes
    approximately $4 million for one-time charges associated with employee
    transition costs.

Commodity Hedges Update

It is the Company's strategy to hedge a portion of its production to reduce
the risks associated with unpredictable future commodity prices and to provide
predictability for a portion of cash flows in order to support the Company's
capital expenditure program.

For 2013 and 2014, the Company has hedges in place as outlined in the table
below. Swap positions for natural gas and NGLs are tied to regional sales
points and oil hedge positions are tied to WTI and include:

  oFor 2013, approximately 62.4 Bcfe, or approximately 70% of production, at
    a weighted average blended price of $7.57 per Mcfe.
  oFor 2014, approximately 32.8 Bcfe at a weighted average blended price of
    $7.05 per Mcfe.

The following table summarizes hedge positions as of February 8, 2013:

            Natural Gas               NGLs*                   Oil
            Volume       Price        Volume         Price    Volume    Price
                                      Gallons
Period      MMBtu/d      $/MMBtu                     $/Gal    Bopd      $/Bbl
                                      Qtr Total
1Q13        150.0        3.69         3,375,000      1.78     7,172     98.00
2Q13        127.5        3.74         3,375,000      1.78     7,500     98.01
3Q13        140.0        3.70         3,375,000      1.78     7,500     98.01
4Q13        123.4        3.72         3,375,000      1.78     7,500     98.01
1Q14        75.0         3.83         -              -        3,600     95.99
2Q14        75.0         3.83         -              -        3,600     95.99
3Q14        75.0         3.83         -              -        3,600     95.99
4Q14        75.0         3.83         -              -        3,600     95.99
*NGL volumes include propane, butanes and natural gasoline. No ethane volumes
are hedged.

2012 RESULTS WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held tomorrow,
February 22, 2013, to discuss 2012 results. Please join Bill Barrett
Corporation executive management at 11:00 a.m. Eastern time/9:00 a.m. Mountain
time for the live webcast, accessed at www.billbarrettcorp.com, or join by
telephone by calling 800-215-2410 (617-597-5410 inter-national callers) with
passcode 86881460. The webcast will remain available on the Company's website
for approximately 30 days, and a replay of the call will be available through
March 1, 2013 at call-in number 888-286-8010 (617-801-6888 international) with
passcode 48429249.

UPCOMING EVENTS

Updated investor presentations will be posted to the homepage of the Company's
website at www.billbarrettcorp.com for each event below. Webcast events will
also be accessible on the homepage of the Company's website:

Investor Conferences

Chief Financial Officer Bob Howard will participate in investor meetings at
the Simmons Thirteenth Annual Energy Conference on March 1, 2013. The
presentation for this event will be posted at 5:00 p.m. Mountain time on
Thursday, February 28, 2013.

Chief Executive Officer Scot Woodall will present at the 41^st Annual Howard
Weil Energy Conference on March 18, 2013 at 2:55 p.m. Central time. The event
will not be webcast. The presentation for this event will be posted at 5:00
p.m. Mountain time on Friday, March 15, 2013.

DISCLOSURE STATEMENTS

Natural Gas Liquids

Effective January 1, 2013, the Company intends to report its production
volumes on a three-stream basis, which separately reports NGLs extracted from
the natural gas stream and sold as a separate product. The NGL volumes
identified by our gas purchasers are converted to an oil equivalent, based on
42 gallons per barrel and compared to overall gas equivalent production based
on a 1 barrel to 6 Mcf ratio.

Reserve and Resource Disclosure

The SEC permits oil and gas companies to disclose proved, 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.

We may use certain terms in this release, such as "risked resources," that the
SEC's guidelines strictly prohibit us from including in filings with the SEC.
The calculation of risked resources, and any other estimates of reserves and
resources that are not proved, probable or possible reserves are not
necessarily calculated in accordance with SEC guidelines. Our estimate of
risked resources is not prepared or reviewed by third party engineers, is
determined using strip pricing, which we use internally for planning and
budgeting purposes, and may differ from an un-risked estimate of proved,
probable and possible reserves. The Company's estimate of risked resources 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; however, the Company's estimate of
risked resources may not be comparable to similar metrics provided by other
companies. Investors are urged to consider closely the disclosure in our
Annual Report on Form 10-K for the year ended December 31, 2012, 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 "2013 guidance," which contains projections for certain 2013
operational and financial metrics. These forward-looking statements are based
on management's judgment as of the date of this press release and include
certain risks and uncertainties. Please refer to the Company's Annual Report
on Form 10-K for the year ended December 31, 2012 filed with the SEC, and
other filings including our Current Reports on Form 8-K and Quarterly Reports
on Form 10-Q, for a list of certain risk factors that may affect these
forward-looking statements. The Company provided unaudited estimates of
certain year-end financial results, which are subject to revision in our
audited financial statements to be included in our Annual Report on Form 10-K
for the year ended December 31, 2012.

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: oil, NGL and natural gas price volatility; costs and
availability of third party facilities for gathering, processing, refining and
transportation; the ability to receive drilling and other permits and
rights-of-way; regulatory approvals, including regulatory restrictions on
federal lands; legislative or regulatory changes, including initiatives
related to hydraulic fracturing; exploration risks such as drilling
unsuccessful wells; higher than expected costs and expenses, including the
availability and cost of services and materials; unexpected future capital
expenditures; economic and competitive conditions; debt and equity market
conditions, including the availability and costs of financing to fund the
Company's operations; 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; declines in the values of our oil
and gas properties resulting in impairments; changes in estimates of proved
reserves; development drilling and testing results; the potential for
production decline rates to be greater than we expect; performance of acquired
properties; compliance with environmental and other regulations; derivative
and hedging activities; risks associated with operating in one major
geographic area; the success of the Company's risk management activities;
title to properties; litigation; environmental liabilities; and, other factors
discussed in the Company's reports filed with the SEC. Bill Barrett
Corporation encourages readers to consider the risks and uncertainties
associated with projections and other forward-looking statements. In addition,
the Company assumes no obligation to publicly revise or update any
forward-looking statements based on future events or circumstances.

ABOUT BILL BARRETT CORPORATION

Bill Barrett Corporation (NYSE: BBG), headquartered in Denver, Colorado,
explores for and develops natural gas and oil in the Rocky Mountain region of
the United States. Additional information about the Company may be found on
its website www.billbarrettcorp.com.

BILL BARRETT CORPORATION
Selected Operating Highlights
(Unaudited)
                                    Three Months Ended   Twelve Months Ended
                                    December 31,         December 31,
                                    2012      2011       2012        2011
Production Data:
 Natural gas (MMcf)                 23,070    26,260     101,486     97,856
 Oil (MBbls)                        857       466        2,687       1,490
 Combined volumes (MMcfe)           28,212    29,056     117,608     106,796
 Daily combined volumes             307       316        321         293
 (Mmcfe/d)
Average Prices (before the
effects of realized hedges):
 Natural gas (per Mcf)          (1) $     $      $      $    
                                     4.56     5.44     4.00         5.71
 Oil (per Bbl)                      75.03     81.57      79.39       81.97
 Combined (per Mcfe)                6.01      6.23       5.27        6.37
Average Realized Prices (after
the effects of realized
hedges):
 Natural gas (per Mcf)          (1) $     $      $      $    
                                     5.18     6.26     5.07         6.46
 Oil (per Bbl)                      83.84     81.48      84.96       80.63
 Combined (per Mcfe)                6.78      6.96       6.32        7.05
Average Costs (per Mcfe):
 Lease operating expense            $     $      $      $    
                                     0.64     0.54     0.62         0.53
 Gathering, transportation and      0.94      0.94       0.91        0.87
 processing expense
 Production tax expense             0.15      0.28       0.22        0.35
 Depreciation, depletion and    (3) 3.32      2.68       2.91        2.70
 amortization
 General and administrative
 expense,excluding non-cash    (2) 0.47      0.39       0.44        0.45
 stock-based compensation

(1) Natural gas average prices include the effect of NGL revenues.
    Management believes the separate presentation of the non-cash component of
    general and administrative expense is useful because the cash portion
(2) 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.
    The calculation of the per unit DD&A rate for the fourth quarter of 2012
(3) is adjusted to reflect the fourth quarter asset sale. The assets were
    excluded from the overall corporate depletion pool, and the per unit
    calculation adjusts the production accordingly.



BILL BARRETT CORPORATION
Consolidated Statements of Operations
(Unaudited)
                                 Three Months Ended      Twelve Months Ended
                                 December 31,            December 31,
                                 2012        2011        2012        2011
(in thousands, except per
share amounts)
Operating and Other
Revenues:
    Oil and gas             (1)  $       $       $       $    
    production                    184,083    207,615    700,639    780,751
    Other                        (4,282)     845         (444)       4,873
    Total operating and          179,801     208,460     700,195     785,624
    other revenues
Operating Expenses:
    Lease operating              18,063      15,546      72,734      56,603
    Gathering,
    transportation and           26,609      27,318      106,548     93,423
    processing
    Production tax              4,320       8,205       25,513      37,498
    Exploration                  751         1,043       8,814       3,645
    Impairment, dry hole
    costs and                    7,690       99,036      67,869      117,599
    abandonment
    Depreciation,
    depletion and                75,425      78,015      326,842     288,421
    amortization
    General and             (2)  13,196      11,195      52,222      47,744
    administrative
    Non-cash stock-based    (2)  4,029       5,337       16,444      19,036
    compensation
    Total operating              150,083     245,695     676,986     663,969
    expenses
Operating Income/ (Loss)         29,718      (37,235)    23,209      121,655
Other Income and
Expense:
    Interest income and
    other income                 27          (560)       1,756       (397)
    (expense)
    Interest expense             (25,477)    (20,238)    (95,506)    (58,616)
    Commodity derivative    (1)  19,328      (1,529)     72,759      (14,263)
    gain (loss)
    Total other income           (6,122)     (22,327)    (20,991)    (73,276)
    and expense
Income (Loss) before             23,596      (59,562)    2,218       48,379
Income Taxes
Provision for (Benefit           9,579       (21,782)    1,636       17,672
from) Income Taxes
                                 $       $       $       $    
Net Income (Loss)                                             
                                 14,017      (37,780)    582         30,707
Net Income (Loss) Per
Common Share
                                 $       $       $       $    
    Basic                                                    
                                 0.30       (0.81)     0.01       0.66
                                 $       $       $       $    
    Diluted                                                  
                                 0.30       (0.81)     0.01       0.65
Weighted Average Common Shares Outstanding
    Basic                        47,260      46,888      47,195      46,536
    Diluted                      47,358      46,888      47,354      47,237
    The table below summarizes the realized and unrealized gains and losses
(1) the Company recognized related to its oil and natural gas derivative
    instruments for the periods indicated:
                                 Three Months Ended     Twelve Months Ended
                                 December 31,           December 31,
                                 2012        2011        2012        2011
    Included in oil and
    gas production
    revenue:
    Certain realized             $       $       $       $    
    gains on hedges                                           
                                 14,514      26,699      81,166      99,922
    Included in
    commodity derivative
    gain (loss):
    Realized gain (loss)         $       $       $       $    
    on derivatives not                                      
    designated as cash           7,291       (5,349)     42,305      (28,054)
    flow hedges
    Unrealized
    ineffectiveness gain
    (loss) recognized on         -           (6)         -           1,026
    derivatives
    designated as cash
    flow hedges
    Unrealized gain on
    derivatives not              12,037      3,826       30,454      12,765
    designated as cash
    flow hedges
     Total commodity                                               $
    derivative gain              $ 19,328    $ (1,529)   $ 72,759    (14,263)
    (loss)
    Management believes the separate presentation of the non-cash component of
    general and administrative expense is useful because the cash portion
(2) 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, 2012  December 31, 2011
(in thousands)
Assets:
  Cash and cash equivalents        $          $           
                                     79,445           57,331
  Other current assets         (1) 148,894            189,012
  Property and equipment, net      2,611,337          2,406,764
  Other noncurrent assets      (1) 29,773             34,823
     Total assets                  $           $          
                                   2,869,449         2,687,930
Liabilities and Stockholders'
Equity:
  Current liabilities   (1) $          $           
                                    213,133           233,198
  Notes payable to bank            -                  70,000
  Capital lease                    88,519             -
  Senior notes                     1,042,791          641,198
  Convertible senior notes         25,344             171,042
  Other long-term              (1) 316,887            353,654
  liabilities
  Stockholders' equity             1,182,775          1,218,838
     Total liabilities and         $           $          
     stockholders' equity          2,869,449         2,687,930

    At December 31, 2012, the estimated fair value of all of our commodity
    derivative instruments was a net asset of $32.6 million, comprised of:
(1) $30.0 million current assets; $3.0 million non-current assets; and $0.4
    million non-current liabilities. This amount will fluctuate quarterly
    based on estimated future commodity prices and the current hedge position.



BILL BARRETT CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
                            Three Months Ended        Twelve Months Ended
                            December 31,              December 31,
                            2012         2011         2012         2011
(in thousands)
Operating Activities:
 Net income (loss)          $       $       $       $     
                             14,017     (37,780)         582   30,707
 Adjustments to reconcile
 to net cashprovided by
 operations:
   Depreciation, depletion  75,425       78,015       326,842      288,421
   and amortization
   Impairment, dry hole
   costs and abandonment    7,690        99,036       67,869       117,599
   expense
   Unrealized derivative    (12,037)     (3,820)      (30,454)     (13,791)
   (gain)\loss
   Deferred income taxes    7,484        (21,782)     (217)        17,688
   Stock compensation and   4,047        5,995        16,727       21,953
   other non-cash charges
   Amortization of debt
   discounts and deferred   1,715        4,037        8,425        13,886
   financing costs
   Loss (gain) on sale of   4,387        54           4,279        (1,955)
   properties
   Change in assets and
   liabilities:
      Accounts receivable   (14,986)     (12,901)     (10,511)     (27,680)
      Prepayments and       (222)        (808)        1,293        1,809
      other assets
      Accounts payable,
      accrued and other     7,402        36,683       2,589        24,531
      liabilities
      Amounts payable to
      oil & gas property    3,421        (11,771)     3,988        (4,010)
      owners
      Production taxes      (510)        417          (2,976)      10,190
      payable
   Net cash provided by     $       $       $       $     
   operating activities      97,833     135,375      388,436      479,348
Investing Activities:
 Additions to oil and gas
 properties, including      (207,109)    (245,809)    (958,654)    (947,206)
 acquisitions
 Additions of furniture,    (1,712)      (5,384)      (7,231)      (11,142)
 equipment and other
 Proceeds from sale of
 properties and other       328,797      (102)        328,888      1,702
 investing activities
   Net cash provided by     $       $        $        $    
   (used in) investing      119,976      (251,295)    (636,997)    (956,646)
   activities
Financing Activities:
 Proceeds from debt         90,000       70,000       875,826      800,000
 Principal payments on      (252,223)    -            (595,386)    (330,000)
 debt
 Deferred financing costs   (74)         (5,224)      (10,438)     (16,308)
 and other
 Proceeds from stock        -            3,256        673          22,247
 option exercises
   Net cash provided by     $        $       $       $     
   (used in) financing      (162,297)     68,032     270,675      475,939
   activities
Increase (Decrease) in      55,512       (47,888)     22,114       (1,359)
Cash and Cash Equivalents
Beginning Cash and Cash     23,933       105,219      57,331       58,690
Equivalents
Ending Cash and Cash        $       $       $       $     
Equivalents                  79,445      57,331      79,445      57,331



BILL BARRETT CORPORATION
Reconciliation of Discretionary Cash Flow & Adjusted Net Income
(Unaudited)
Discretionary Cash Flow
Reconciliation
                            Three Months Ended        Twelve Months Ended
                            December 31,              December 31,
                            2012         2011         2012          2011
(in thousands, except per
share amounts)
                            $       $       $         $    
Net Income (Loss)            14,017     (37,780)                30,707
                                                      582
Adjustments to reconcile
to discretionary cash
flow:
 Depreciation, depletion    75,425       78,015       326,842       288,421
 and amortization
 Impairment, dry hole and   7,690        99,036       67,869        117,599
 abandonment expense
 Exploration expense        751          1,043        8,814         3,645
 Unrealized derivative      (12,037)     (3,820)      (30,454)      (13,791)
 (gain)/loss
 Deferred income taxes      7,484        (21,782)     (217)         17,688
 Stock compensation and     4,047        5,995        18,328        21,953
 other non-cash charges
 Amortization of debt
 discounts and deferred     1,715        4,037        8,425         13,886
 financing costs
 Gain on extinguishment of  -            -            (1,601)       -
 debt
 Loss (gain) on sale of     4,387        54           4,279         (1,955)
 properties
Discretionary Cash Flow     $       $       $         $    
                            103,479      124,798       402,867      478,153
                            $       $       $         $    
 Per share, diluted            2.19      2.66               
                                                      8.51          10.12
                            $       $       $         $    
 Per Mcfe                      3.67      4.30                
                                                      3.43          4.48
Adjusted Net Income (Loss)
Reconciliation
                            Three Months Ended        Twelve Months Ended
                            December 31,              December 31,
                            2012         2011         2012          2011
(in thousands except per
share amounts)
                            $       $       $         $    
Net Income (Loss)            14,017     (37,780)                30,707
                                                      582
Adjustments to net income
(loss):
 Unrealized derivative      (12,037)     (3,820)      (30,454)      (13,791)
 (gain)/loss
 Impairment expense         239          96,399       37,348        100,278
 Loss (gain) on sale of     4,387        54           4,279         (1,955)
 properties
 One time items:
     Gain on
     extinguishment of      -            -            (1,601)       -
     debt
 Subtotal Adjustments       (7,411)      92,633       9,572         84,532
 Effective tax rate         41%          37%          34%       (1) 37%
 Tax effected adjustments   (4,372)      58,359       6,327         53,255
                            $       $       $         $    
Adjusted Net Income           9,645     20,579                  83,962
                                                      6,909
                            $       $       $         $    
 Per share, diluted            0.20     0.44               
                                                      0.15         1.78
                            $       $       $         $    
 Per Mcfe                      0.34     0.71               
                                                      0.06         0.79

(1) The annualized rate was adjusted to a weighted rate so that the four
quarters would sum.
The non-GAAP (Generally Accepted Accounting Principles in the United States of
America) measures of discretionary cash flow and adjusted net income are
presented because management believes that they provide useful additional
information to investors for analysis of the Company's ability to internally
generate funds for exploration, development and acquisitions as well as
adjusting net income for unusual items to allow for a more consistent
comparison from period to period. In addition, these measures are widely used
by professional research analysts and others in the valuation, comparison and
investment recommendations of companies in the oil and gas exploration and
production industry, and many investors use the published research of industry
research analysts in making investment decisions.
These measures should not be considered in isolation or as a substitute for
net income, income from operations, net cash provided by operating activities
or other income, profitability, cash flow or liquidity measures prepared in
accordance with GAAP. Because discretionary cash flow and adjusted net income
exclude some, but not all, items that affect net income and net cash provided
by operating activities and may vary among companies, the amounts presented
may not be comparable to similarly titled measures of other companies.



BILL BARRETT CORPORATION
Costs Incurred and Reserve Information
(Unaudited)
                                     2012       2011         2010
($ in millions)
TOTAL CAPITAL EXPENDITURES           $      $         $   
                                     962.6     987.3        473.3
 Furniture, fixtures and equipment   (6.9)      (10.6)       (3.8)
 and real estate
 Change in asset retirement          8.3        12.1         1.3
 obligation
TOTAL COSTS INCURRED (1)             $      $         $   
                                     964.0     988.8        470.8
TOTAL COSTS INCURRED DISCLOSURE
 Exploration costs                   32.5       20.8         $    
                                                             82.8
 Development costs                   754.2      607.7        358.3
 Acquisition costs:
  Unproved properties              163.0      183.4        25.2
  Proved properties                6.0        164.8        3.2
 Change in asset retirement          8.3        12.1         1.3
 obligation
TOTAL COSTS INCURRED (1)             964.0      988.8        470.8
  less: asset retirement       (8.3)      (12.1)       (1.3)
 obligation
  less: (Proceeds)/adjusted    -          -            1.5
 proceeds received from JV partners
  less: Capitalized interest   (0.5)      (1.4)        (4.2)
  Adjusted costs incurred          $      $         $   
                                     955.2     975.3        466.8
RESERVE ADDITIONS (Bcfe)
 Extensions, discoveries and other   187.3      211.4        185.1
 additions
 Revisions of previous estimates     (44.0)     37.9         39.8
 based on performance
 Revisions of previous estimates     (129.2)    5.5          27.4
 based on price or aging
 Purchases of reserves in place      1.8        98.3         1.4
 RESERVE ADDITIONS Bcfe              15.9       353.1        253.7
 RESERVE ADDITIONS MMBoe             2.7        58.9         42.3
SALES INFORMATION
 Property sales                    $      $       $    
                                     329.0     2.0           4.4
 Sales of reserves (Bcfe)            219.3      -            3.7

 (1) Costs Incurred is a defined capital expenditure used in the discussion of
 proved reserves in the Company's Form 10-K for the years indicated.

SOURCE Bill Barrett Corporation

Website: http://www.billbarrettcorp.com
Contact: Jennifer Martin, Vice President of Investor Relations,
+1-303-312-8155
 
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