Bill Barrett Corporation Announces 66% Increase in Oil Reserves and 80% Increase in 2012 Oil Production and Provides 2013

   Bill Barrett Corporation Announces 66% Increase in Oil Reserves and 80%
          Increase in 2012 Oil Production and Provides 2013 Guidance

PR Newswire

DENVER, Jan. 31, 2013

DENVER, Jan. 31, 2013 /PRNewswire/ --Bill Barrett Corporation (the "Company")
(NYSE: BBG) announced today certain unaudited operating results and estimated
reservesfor year-end 2012 and certain operating guidance for 2013.
Highlights from 2012 include (unaudited):

  oProduction growth of 10% to 118 Bcfe, including 80% growth in oil
  oProved reserves of 1.04 Tcfe, including 66% growth in oil reserves
  oProved reserves plus risked resources of 2.9 Tcfe
  oContinued DJ Basin success with 82% growth in proved reserves and nearly
    four-fold increase in resource drilling locations
  oStrong balance sheet with $825 million line of credit undrawn

Interim Chief Executive Officer and Chief Operating Officer Scot Woodall
commented: "During the past two years we have focused on building a better
oil-to-natural gas balance in our asset portfolio, and we exit 2012
recognizing substantial success with this challenging transition. Over the
past two years, our production mix increased to 24% oil exiting 2012 (pro
forma for the fourth quarter asset sale) compared with 7% oil exiting 2010.
Our proved reserves were 29% oil at year-end 2012 compared with 7% at year-end
2010 and drilling locations targeting oil increased to nearly 2,900 from
approximately 400, year-end 2012 compared with year-end 2010. Total production
was up 10% in 2012 compared with 2011 with oil production up 80%, meeting our
targeted growth.

"Our investment in oil programs has delivered two solid, scalable development
programs in the Uinta and Denver-Julesburg ("DJ") basins. In 2013, we are
focused on developing the inventories we have built while optimizing the
margins and returns at these programs. These basins each offer strong returns
and notable upside through downspacing and operating efficiencies that
correspond with increasing scale. Our $475 to $525 million capital program in
2013 assumes six active rigs in these two basins and includes a total of
approximately 180 gross/100 net wells (including non-operated wells.)
Approximately 97% of our capital budget is directed towards our oil programs,
and we are targeting 50% to 55% growth in oil production in 2013. Execution is
our theme for 2013, and we have realigned our senior technical personnel to
focus on our development programs and to deliver top tier operational

Chief Financial Officer Bob Howard adds: "We enter 2013 in a strong financial
position with zero drawn on the $825 million borrowing base available from the
Company's credit facility. The borrowing base was redetermined at year-end,
and it is expected to remain virtually unchanged with the spring scheduled
redetermination. We are committed to ending 2013 with no increase in our total
debt and will be actively managing our portfolio to generate proceeds from the
sale of assets to meet our funding requirements. In addition, we have hedges
in place to support our expected cash flows for 2013 including 7,000 barrels
per day of oil ("Bopd") at $98.00, about 60-65% of expected oil production,
and 133 million cubic feet per day ("MMcf/d") of natural gas at $3.70, or
about 75% of expected natural gas production."


(The following information is unaudited and preliminary. Audited and final
results will be provided in our Annual Report on Form 10-K for the year ended
December 31, 2012 currently planned to be filed with the Securities and
Exchange Commission ("SEC") by the end of February 2013.)

2012 Year-End Reserves

2012 year-end estimated proved reserves of 1.04 trillion cubic feet equivalent
("Tcfe") reflect 74% growth in proved reserves at the Company's three active
oil programs in the Uinta Basin, DJ Basin and Powder River Basin plus natural
gas drilling additions at West Tavaputs and Gibson Gulch. This growth was more
than offset by: the fourth quarter asset sale that included 219 billion cubic
feet equivalent ("Bcfe") of proved reserves as of year-end 2012; and, negative
revisions of 221 Bcfe in West Tavaputs and Gibson Gulch related to the
significantly lower natural gas price used to determine reserves, the
Company's expectation to not drill in these areas during 2013, and negative
engineering revisions at West Tavaputs associated with performance of 20-acre
spacing on a portion of the Company's acreage position.

Table: Reserve Reconciliation 2011 to 2012
Reserves                                                     Bcfe
2011 year-end estimated proved reserves                      1,365
2012 estimated production                                    (118)
2012 reserve dispositions                                    (219)
2012 revisions at natural gas programs (described above)     (221)
2012 reserve additions, acquisitions and all other revisions 237
2012 year-end estimated proved reserves                      1,044

Year-end estimated proved reserves were 29% oil and 71% natural gas and were
59% developed and 41% undeveloped. The present value of proved reserves, or
PV10, was estimated at $1.4 billion, which is down $700 million from year-end
2011, primarily due to the fourth quarter 2012 asset sale and impact from a
35% decline in the natural gas commodity price used for the calculation. The
present value calculation is before income taxes and is based on a Colorado
Interstate Gas ("CIG") natural gas price of $2.56 per MMBtu, a West Texas
Intermediate ("WTI") oil price of $91.21 per barrel and a 10% per annum
discount rate. PV10 information is provided because it is a commonly used
metric in the exploration and production industry. PV10 sensitivity to the
natural gas price at +$1.00 and + $2.00 is provided below:

Table: PV10 Sensitivity
Commodity Price                  Natural Gas Oil      Equivalent PV10
                                 (Bcf)       (MMBbls) (Bcfe)     (Millions)
2012: $2.56 gas, $91.21 oil      739         51       1,044      $1,401
+$1.00/$0: $3.56 gas, $91.21 oil 817         51       1,123      $1,720
+$2.00/$0: $4.56 gas, $91.21 oil 839         51       1,146      $2,091

2012 Year-End Risked Resources

In addition to estimated proved reserves, the Company estimates it has risked
resources of 1.9 Tcfe at December 31, 2012, for total proved reserves plus
risked resources of approximately 2.9 Tcfe. See "Reserve and Resource
Disclosure" note below.

Table: Proved Reserves, Risked Resources and Drilling Locations
                                             Proved Plus
                       Proved       Percent  Risked       Percent  Gross
                       Reserves              Resources             Drilling
                       Bcfe         Oil      Bcfe         Oil      Locations
Gibson Gulch,          401          6%       511          6%       528
Uinta Oil Program,     282          80%      967          79%      1,696
West Tavaputs, Uinta   265          1%       885          1%       588
Denver-Julesburg       75           50%      532          61%      1,082
Powder River Basin     21           84%      40           85%      107
Other                  -            -        1            -        -
Total                  1,044        29%      2,936        40%      4,001

2012 Production

Estimated production for 2012 was 117.6 Bcfe. Total production was up 10% from
2011 and oil production was up 80% to 2.69 million barrels from 1.49 million
barrels in 2011. Fourth quarter 2012 production of 28.2 Bcfe was negatively
affected by approximately 1.2 Bcf due to the previously announced fire at a
West Tavaputs compressor station (with 90% of pre-fire production back

Table: 2012 Production and Sales Volumes by Quarter
                             1Q12      2Q12      3Q12      4Q12      2012
Reported Production Volumes
Oil (Bbls/d)                 5,286     6,972     7,766     9,315     7,341
Natural gas, including NGLs  278       287       294       251       277
Reported Realized Prices:
Oil (per Bbl)                $ 88.42  $ 84.86  $ 84.08  $ 83.84  $ 84.96
Natural gas, including NGLs  $  5.46 $  4.77 $  4.90 $  5.18 $  5.07
(per Mcf)
Sales* Volumes:
Oil (Bbls/d)                 5,286     6,972     7,766     9,315     7,341
Natural gas sold as dry gas  257       262       265       223       252
NGLs (Bbls/d)                11,985    11,439    10,341    8,687     10,615
*See Disclosure Statements below.

Entering 2013, production will be affected by the sale of natural gas assets
that closed December 31, 2012 and ethane rejection reducing the natural gas
liquids ("NGL") volumes. Calculated as three-streams and adjusted for those
factors, January production is estimated at approximately 220 million cubic
feet equivalent per day ("MMcfe/d) with 22% oil, 70% natural gas and 8% NGLs.

2012 Capital Expenditures

Preliminary, unaudited capital expenditures for 2012 were $963 million and
included drilling 288 gross/185 net wells, including participation in
non-operated wells. Capital included $677 million for drilling at development
programs, $124 million for acquisitions and leaseholds to expand development
programs, $62 million for infrastructure and corporate, and $100 million for
exploration drilling and leaseholds. During 2012, drilling activity was
stopped in West Tavaputs and Piceance in the second and third quarters,
respectively, as a result of low natural gas and NGL prices. The following is
a summary of unaudited capital expenditures by area and wells spud for 2012:

Table: Capital Expenditures and Wells Spud by Area
                                          Wells Spud Capital Expenditures
Basin                                     (gross)    (millions)
Uinta Oil Program                         105        $  284
West Tavaputs                             16         107
Piceance                                  91         200
Denver-Julesburg                          53         141
Other including exploration and corporate 23         107
Acquisitions at development programs                 124
Total                                     288        $  963
(Includes non-operated wells)


Under successful efforts accounting, the Company expects to record impairment,
dry hole and abandonment expenses in the fourth quarter of 2012 of
approximately $7.7 million (pre-tax), of which approximately $5.1 million
relates primarily to one exploratory dry hole in the Southern Alberta Basin,
approximately $2.4 million relates to abandonment and $0.2 million relates to
impairment. For the full year 2012, impairment, dry hole and abandonment
expenses are estimated at $67.9 million of which $21.0 million relates to dry
holes, $37.3 million to impairment and $9.6 million to abandonment. These
amounts are unaudited and subject to further review by management and
independent auditors.


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
included $25.3 million of convertible senior notes, $250.0 million in 9.875%
senior notes, $400.0 million in 7.625% senior notes, $400.0 million in 7.000%
senior notes and $97.6 million for a lease financing obligation.


Effective as of January 1, 2013, the Company plans to report its reserves and
production in three streams, separating NGLs from the natural gas stream. In
an effort to put year-end 2012 results and 2013 guidance into better context,
certain results and data are presented below in both formats.

The Company plans to spend between $475 and $525 million for capital
expenditures in 2013. The Company expects to participate in approximately 180
gross/100 net development wells, including approximately 30 non-operated
wells, and which will include approximately 90 gross wells at the Uinta Oil
Program and approximately 85 gross wells in the DJ Basin plus at least five
wells in the Powder River Oil Program.

The Company is providing the following guidance for its 2013 activities. See
"Forward-Looking Statements" below.

Table: Guidance for 2013 Capital Expenditures, Production and Costs
Capital expenditures ($millions)                                  $475 – $525
Production (2-stream basis; Bcfe)                                 83 – 87
Production (3-stream basis; Bcfe)                                 86 – 90
Operating costs: Lease operating ($millions)                      $62 – $67
Operating costs: Gathering, processing and transportation         $72 – $75
General and administrative, before non-cash, stock based
compensation and including approximately $4 million of estimated  $50 – $54
one-time employee transition costs ($millions)

Production guidance for 2013 projects 50%-55% growth in oil production
compared with 2012 and estimates approximately 6%-8% of production will be
NGLs under three-stream reporting. NGL production declines from 2012 are due
to the partial sale of Gibson Gulch and assumes the Company rejects ethane for
the full year. Lower projected production in 2013 compared to 2012 is due to
the sale of natural gas assets and ceasing drilling at the Company's natural
gas programs.


The Company has hedges in place for approximately 70% of forecast 2013
production. Natural gas hedges are all tied to Rocky Mountain regional
pricing. Generally, it is the Company's strategy to hedge 50% to 70% of
production through basis at regional sales points on a forward 12-month basis
in order to reduce the risks associated with unpredictable future commodity
prices and to provide certainty for a portion of its cash flow to support its
capital expenditure program.

The following table summarizes hedge positions as of January 25, 2013:

             Natural Gas               NGLs*                  Oil

             Volume        Price       Volume        Price    Volume    Price
Period       MMBtu/d       $/MMBtu                   $/Gal    Bopd      $/Bbl
                                       Qtr Total
1Q13         150.0         3.69        3,375,000     1.78     7,000     98.00
2Q13         140.0         3.70        3,375,000     1.78     7,000     98.00
3Q13         140.0         3.70        3,375,000     1.78     7,000     98.00
4Q13         123.4         3.72        3,375,000     1.78     7,000     98.00
1Q14         75.0          3.83        -             -        3,200     96.17
2Q14         75.0          3.83        -             -        3,200     96.17
3Q14         75.0          3.83        -             -        3,200     96.17
4Q14         75.0          3.83        -             -        3,200     96.17
*NGL volumes include propane, butanes and natural gasoline. No ethane volumes
are hedged.


Total estimated proved reserves year-end 2012 by commodity, presented in both
two-stream and three-stream formats were as follows:

Table: Year-end 2012 Total Proved Reserves Two & Three Stream Formats
                                    2 Streams        3 Streams
Oil (MMBbls)                        50.8             50.8
Natural gas liquids (MMBbls)        -                30.5
Natural gas (Bcf)                   739.1            682.1
Total Bcfe                          1,043.7          1,169.9

Estimated proved reserves reported in three streams were 26% oil, 58% natural
gas and 16% NGLs.


Credit Suisse Conference

Interim Chief Executive Officer and Chief Operating Officer Scot Woodall will
participate in investor meetings on February 6-7, 2013 at the Credit Suisse
Energy Summit 2013. The Company will post an updated investor presentation to
be used for this event on Tuesday, February 5, 2013 at 5:00 p.m. Mountain

Simmons Conference

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


Year-end 2012 Financial Results Presented are Unaudited

Results for year-end 2012 presented in this press release are preliminary and
unaudited. These unaudited amounts are subject to further review by management
and independent auditors.

Calculation of Natural Gas Liquids as a Percent of Sales Volumes

The Company's 2012 natural gas production included in this press release is
based on wellhead volumes and its 2012 natural gas revenue includes the
incremental revenue benefit of receiving NGL sales prices for NGL volumes
processed by the purchasers of our natural gas deliveries. Many oil and gas
producing companies report NGL volumes and revenues separate from natural gas
volumes and revenues. In order to provide a metric that is comparable to
other oil and gas production companies, the Company is providing the
percentage of total company sales volumes that receive NGL pricing based on
the barrel of oil equivalent NGL volumes for revenues received from our gas
purchasers. 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.

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.

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 possiblereserves 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, 2011, available on
the Company's website at 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

Forward-Looking Statements

This press release contains forward-looking statements, including preliminary
and unaudited results for 2012 and projections for future events. In
particular, the Company is providing "2013 Operating 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, 2011 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 to be filed in February 2013.

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.


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

SOURCE Bill Barrett Corporation

Contact: Jennifer Martin, Vice President of Investor Relations,
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