Bill Barrett Corporation Reports Third Quarter 2013 Results, Including Strong Well Results from the DJ Basin

Bill Barrett Corporation Reports Third Quarter 2013 Results, Including Strong
                        Well Results from the DJ Basin

PR Newswire

DENVER, Oct. 31, 2013

DENVER, Oct. 31, 2013 /PRNewswire/ -- Bill Barrett Corporation (NYSE: BBG)
today reported third quarter 2013 results and announced operational updates
highlighted by:

  oOil, natural gas and natural gas liquids ("NGL") production of 21.4
    billion cubic feet equivalent ("Bcfe")
  oOil production averaging 9,880 barrels per day, or 25% of production
  oAverage realized price of $6.81 per Mcfe, reflecting the benefit of
    growing oil volumes. Oil sales accounted for 56% of pre-hedge sales
    revenues
  oDiscretionary cash flow of $74.9 million, or $1.58 per diluted common
    share
  oTwo new delineation wells in the southern portion of the Company's
    Northeast Wattenberg, Denver-Julesburg ("DJ") Basin acreage position.
    Initial production ("IP") rates from the two wells averaged more than
    1,000 barrels of oil equivalent per day ("Boe/d") per well over a peak 24
    hours and averaged approximately 500 Boe/d per well over 30 days
  oSix new pad wells, adjacent to earlier pad drilling in the Northeast
    Wattenberg area, averaged more than 1,000 Boe/d per well over a peak 24
    hours and averaged approximately 600 Boe/d per well over 30 days
  oSigned agreement for $371 million sale of West Tavaputs natural gas
    assets, expected to close by year-end

Chief Executive Officer and President Scot Woodall commented: "Execution of
our 2013 plan is right on track. Our commitment to complete an asset sale and
maintain our debt level at or below year-end 2012 is being accomplished. Our
objective to delineate all of our Northeast Wattenberg acreage position, test
the development potential of the B and C benches of the Niobrara formation and
the Codell formation as well as test down-spacing to 80-acres is all well
underway. Year-to-date in the Wattenberg, we have drilled 43 wells in our
65-well program and have completed 26. Wells spud include 6 in the C bench, 4
in the Codell, and 8 in the southern acreage area. We are providing results
from 8 wells today that demonstrate strong flow rates and continued success in
the southern area. Further, we have completed the 2013 drilling plan in the
Uinta Oil Program with 57 wells drilled and 56 completed, including 20 wells
in the East Bluebell acreage position. We are diligently working to complete
our 2013 drilling program, positioning our Company for solid oil reserve
growth at year-end and cash flow growth in 2014."

OPERATING AND FINANCIAL RESULTS

Oil, natural gas and NGL production totaled 21.4 Bcfe in the third quarter of
2013. As of January 1, 2013, the Company adopted three-stream reporting for
its natural gas, oil and NGL production volumes. As of the third quarter of
2013, to allow for consistent reporting of production volumes between periods
whether we recover ethane as a separate sales product or elect ethane
rejection, the Company modified its methodology for reporting ethane volumes.
Prior to the third quarter of 2013, ethane recovery rejected at the processing
plant was included with natural gas production volumes; these ethanevolumes
are now included in the NGL volumes.(On a comparable two-stream basis,
production was 19.6 Bcfe in the third quarter of 2013.) Production is down
from 31.3 Bcfe reported in the third quarter of 2012 (reported on a two-stream
basis), primarily due to asset sales closed in the fourth quarter of 2012.
Oil production of 9,880 barrels per day ("Bbls/d") in the third quarter of
2013 was up 27% compared with the third quarter of 2012, including a 37%
increase at the Uinta Oil Program and a 100% increase in the DJ Basin,
partially offset by a reduction in oil production due to properties that were
sold in the fourth quarter of 2012. Production for the first nine months of
2013 was 66.9 Bcfe compared with 89.4 Bcfe in the first nine months of 2012.
Production for the first nine months of 2013 reflects the revised reported
production volumes for the first and second quarters, as presented in the
table below.

Pre-hedge pricing in the third quarter of 2013 was $6.88 per thousand cubic
feet equivalent ("Mcfe"), up 35% from the third quarter of 2012, reflecting
the higher contribution from oil production in the commodity mix. The average
realized price in the third quarter of 2013 was $6.81 per Mcfe, negatively
affected by $0.07 per Mcfe as realized benefits on natural gas hedges were
more than offset by realized losses on oil hedges. The average realized prices
by commodity for the third quarter of 2013 were $83.51 per barrel ("Bbl") of
oil, $4.30 per Mcfe of natural gas and $28.74 per Bbl of NGLs. (See "Selected
Operating Highlights" below for more detail.)

The table below presents production volumes, sales volumes (see "Disclosure
Statements" below) and realized prices historically by quarter. 2013
production reflects the effects of the 2012 asset sale, the change to
three-stream reporting, and the change in methodology to report rejected
ethane in the NGL stream:

                                       3Q12    4Q12    1Q13    2Q13    3Q13
Reported Production Volumes 3-Stream:
 Oil (Bbls/d)                          N/A     N/A     8,827   9,060   9,880
 Natural gas (MMcf/d)                  N/A     N/A     163     157     141
 NGLs (Bbls/d)                         N/A     N/A     6,469   5,979   5,438
Reported Production Volumes 2-Stream:
 Oil (Bbls/d)                          7,766   9,315   N/A     N/A     N/A
 Natural gas, including NGLs (MMcf/d)  294     251     N/A     N/A     N/A
Sales Volumes:^1
 Oil (Bbls/d)                          7,766   9,315   8,827   9,060   9,880
 Natural gas sold as dry gas (MMcf/d)  265     223     163     157     141
 NGLs (Bbls/d)                         10,341  8,687   6,469   5,979   5,438
Reported Realized Prices:^2
 Oil (per Bbl)                         $ 84.08 $ 83.84 $ 81.74 $ 82.11 $ 83.51
 Natural gas sold as dry gas (per      N/A     N/A     $ 4.10  $ 3.92  $ 4.30
 Mcf)
 Natural gas including benefit of NGL  $ 4.90  $ 5.18  N/A     N/A     N/A
 realizations (per Mcf)
 NGLs (per Bbl)                        N/A     N/A     $ 25.01 $ 29.90 $ 28.74

(1) (see "Disclosure Statements" below)
(2) (see footnote 3 under "Selected Operating Highlights" below)

Discretionary cash flow (a non-GAAP measure, see "Discretionary Cash Flow
Reconciliation" below) in the third quarter of 2013 was $74.9 million, or
$1.58 per diluted common share, down from $105.8 million in the third quarter
of 2012. The decline in discretionary cash flow in the third quarter of 2013
compared with the third quarter of 2012 was primarily due to lower production
(described above). Cash operating costs (lease operating expense, gathering
transportation and processing expense and production tax expense) per unit
were higher in the third quarter of 2013 at $1.99 compared with the third
quarter of 2012 at $1.65, as oil is more costly to produce per unit than
natural gas. In addition, higher per unit lease operating expenses in the
third quarter of 2013 were a result of workover activity as well as
non-recurring charges associated with the sale of the West Tavaputs assets,
changes in the artificial lift systems in the DJ Basin and weather-related
road work in both the Uinta and DJ Basins. Higher costs per Mcfe were more
than offset by higher realized prices per Mcfe. For the first nine months of
2013, discretionary cash flow was $204.2 million compared with $299.4 million
for the first nine months of 2012.

Net loss in the third quarter of 2013 was $166.7 million, or ($3.51) per
diluted common share, compared with a net loss of $52.6 million in the third
quarter of 2012. The net loss in the quarter was predominantly due to
impairment charges of $216.6 million, associated with the expected 2013 sale
of the West Tavaputs assets and exploration properties located in the Southern
Alberta Basin in Montana. The third quarter loss was also affected by the same
items that affected discretionary cash flow (described above) and higher per
unit depreciation and depletion expense. For the first nine months of 2013,
net loss was $185.5 million compared with a net loss of $13.4 million in the
first nine months of 2012. Adjusted net income (loss) for the third quarter
of 2013 (a non-GAAP measure, see "Adjusted Net Income (Loss) Reconciliation"
below) was a loss of $4.4 million, or ($0.09) per diluted common share,
compared with a loss of $9.7 million, or ($0.20) per diluted common share, in
the third quarter of 2012. Adjusted net income (loss) removes the effect of
non-recurring charges such as unrealized derivative gains and losses,
impairment expenses, property sales and certain one-time items. For the first
nine months of 2013, adjusted net income was a loss of $25.7 million compared
with a loss of $2.7 million for the first nine months of 2012.

DEBT AND LIQUIDITY

At September 30, 2013, the Company had total debt outstanding (principal
balance) of $1,306.2 million, including $390.0 million drawn on its $825.0
million revolving credit facility due 2016. The Company anticipates paying
down the revolving credit facility with proceeds from the sale of West
Tavaputs. In addition, the purchaser of West Tavaputs will assume $46.0
million of the Company's lease financing obligation. The Company has no term
debt due before 2019.

OPERATIONS

Production, Wells Spud and Capital Expenditures

The following table lists production, wells spud and total capital
expenditures by basin for the three and nine months ended September 30, 2013:

                 Three Months Ended September    Nine Months Ended September
                 30, 2013                        30, 2013
                 Average                         Average           Capital
                 Net        Wells  Capital       Net        Wells  Expenditures
                 Daily      Spud   Expenditures Daily      Spud   (in
                 Production Gross* (in millions) Production Gross* millions)
                 (MMcfe)                         (MMcfe)
Basin
Uinta:
  Uinta Oil      48         8      $61           43         56     $193
  Program
  West Tavaputs  58         0      (2)           66         0      0
Piceance         100        0      0             110        0      5
Denver-Julesburg 20         22     64            18         34     120
Powder River     7          0      3             8          5      45
Deep Oil & Other
Total            233        30     $126          245        95     $363
* Operated wells

Operating and Drilling Update

The Company anticipates drilling or participating in approximately 177
gross/95 net development wells in 2013, including participation in
approximately 50 gross non-operated wells.

Denver-Julesburg Basin, Colorado and Wyoming

Northeast Wattenberg/DJ Basin - Third quarter net production averaged 3,300
Boe/d, a 111% increase from the third quarter of 2012 and up 12% sequentially.
Today, the Company is providing results on two new delineation wells in the
southern portion of the Northeast Wattenberg. One of these wells had a 24-hour
peak IP rate of 1,270 Boe/d and a 30-day rate of 560 Boe/d, and the second a
24-hour peak IP rate of 850 Boe/d and a 30-day rate of 430 Boe/d. The Company
is also providing results on six wells drilled on a pad on the western portion
of the Northeast Wattenberg position where 24-hour peak IP rates averaged more
than 1,000 Boe/d per well and 30-day rates averaged approximately 600 Boe/d
per well. The wells were drilled to approximately 6,100 feet vertical depth
with approximate 4,000 foot laterals and were completed with 17 fracture
stimulation stages for an average cost of $4.2 million.

The Company is operating four active rigs in the area and is on track to drill
approximately 65 gross/45 net operated wells by year-end, of which
approximately 50 gross operated wells should be completed by year-end. The
2013 drilling program is focused on delineating the Company's approximate
40,000 net acre Northeast Wattenberg acreage position, testing 80-acre
down-spacing, and testing the development potential of the Niobrara B and C
benches along with the deeper Codell formation. The 2013 drilling schedule was
modified slightly to include drilling a 10-well pad in its core Wattenberg
position, deferring spud dates of wells in the western area, as the Company
intends to exploit its entire 75,000-plus acre position in the DJ Basin over
the coming years. Year-to-date through October 2013, in the DJ Basin the
Company has spud 43 wells of which 26 are completed. The Company also
anticipates participating in approximately 20 non-operated wells for the full
year.

At September 30, 2013, the Company had an approximate 80% working interest in
production from 293 gross wells, including approximately 200 vertical wells
mostly acquired in DJ Basin property acquisitions. As of the end of the third
quarter of 2013, the Company had approximately 75,300 net acres in the DJ
Basin program.

Uinta Basin, Utah

Uinta Oil Program (Blacktail Ridge, Lake Canyon, East Bluebell and South
Altamont) - Third quarter net production averaged 7,950 Boe/d, up 43% from the
third quarter of 2012 and up 18% sequentially. The Company has completed
drilling a 57-well program for 2013.

Performance from the East Bluebell/South Altamont areas continues to be
particularly strong with returns exceeding program averages, benefiting from
consistent geology and lower costs. In East Bluebell, the Company is moving
forward with 80-acre spacing, and the area offers the potential for further
downspacing. Drilling in these areas are vertical wells targeting the Wasatch
and Green River formations.

The Company continues to test two vertical 80-acre spacing pilot programs in
the Blacktail Ridge area. Resultsare encouraging, and the Company will
continue to assess each area. The Company continues to optimize drilling and
operating costs in this sizable program.

At September 30, 2013, the Company had an approximate 76% working interest in
production from 295 gross wells. As of the end of the third quarter of 2013,
the Company had approximately 151,400 net acres (including acreage to be
earned) in the Uinta Oil program.

West Tavaputs - Third quarter net production averaged 58 million cubic feet
equivalent per day ("MMcfe/d"). As previously announced, the Company has
entered into an agreement to sell this property and the transaction is
expected to close by year-end.

At September 30, 2013, the Company had an approximate 97% working interest in
production from 301 gross wells in West Tavaputs.

Piceance Basin, Colorado

Gibson Gulch - Third quarter net production averaged 100 MMcfe/d. As
previously described, the production reporting of ethane rejected at the
processing plant has been moved from the natural gas stream to the NGL stream
for the three quarters of 2013. Considering this revised method, Piceance
production in the first and second quarters of 2013 was 119 MMcfe/d and 112
MMcfe/d, respectively. Drilling in the area remains suspended as the Company
focuses its operations plan on oil development.

At September 30, 2013, the Company had an approximate 81% working interest in
production from 956 gross wells and held 12,600 net acres in its Gibson Gulch
program.

Powder River Basin, Wyoming

Powder Deep Oil Program - Third quarter net production averaged approximately
1,140 Boe/d. The Company completed its drilling program in the first half of
2013 with five wells to the Shannon formation, and all of these wells continue
to have positive results. During 2013, the Company is actively participating
in approximately 15 non-operated wells throughout the area targeting the
Shannon, Frontier, Parkman and Turner formations, five of which have extended
reach laterals. The Company believes the Powder Deep Oil Program offers a new,
growing oil position in a relatively low risk basin.

At September 30, 2013, the Company had an approximate 52% working interest in
production from 99 gross wells and held 68,300 net acres in its Powder Deep
Oil Program.

ADDITIONAL FINANCIAL INFORMATION

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 the remainder of 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 the fourth quarter of 2013, 15.7 Bcfe is hedged, or approximately 70%
    of production, at a weighted average price of $8.13 per Mcfe.
  oFor 2014, approximately 46.0 Bcfe is hedged at a weighted average blended
    price of $8.80 per Mcfe.
  oFor 2015, approximately 6.9 Bcfe is hedged at a weighted average blended
    price of $10.06 per Mcfe.

The following table summarizes hedge positions as of October 21, 2013:

        Natural Gas       NGLs*          Oil
Period  Volume   Price    Volume  Price  Volume  Price
        MMBtu/d  $/MMBtu  Bbls/d  $/Bbl  Bbls/d  $/Bbl
4Q13    123,424  3.72     1,068   69.47  8,764   98.01
1Q14    85,000   3.87     99      42.00  9,000   94.27
2Q14    85,000   3.87     98      42.00  9,000   94.27
3Q14    85,000   3.87     97      42.00  7,600   94.62
4Q14    78,370   3.85     97      42.00  7,600   94.62

*NGL volumes include propane, butanes and natural gasoline. No ethane volumes
are hedged.

2013 Guidance

The Company's updated 2013 guidance (please reference "Forward-Looking
Statements" below) is as follows. Guidance ranges are before the effect of
the sale of West Tavaputs, which is expected to close by year-end. The Company
may update guidance as business conditions warrant.

  oCapital expenditures of $465 million to $485 million, unchanged.
  oOil, natural gas and NGL production of 85 to 87 Bcfe, narrowed and
    adjusted to reflect the effect of reclassifying rejected ethane volumes as
    NGL volumes. Oil production is expected to increase approximately 30% to
    35% in 2013 over 2012, unchanged.
  oLease operating costs of $69 million to $71 million, increased from $64
    million to $67 million, due to increased workover activity as well as
    non-recurring charges associated with the sale of West Tavaputs, changes
    in the artificial lift systems in the DJ Basin and weather-related road
    work in both the Uinta and DJ Basins. It also includes one-time charges of
    $1.4 million associated with the West Tavaputs compressor fire.
  oGathering, transportation and processing costs of $65 million to $68
    million, unchanged.
  oGeneral and administrative expenses, before non-cash stock-based
    compensation cost, of $50 million to $52 million, narrowed from $50
    million to $54 million.

The Company intends to provide guidance for its 2014 capital and operating
plan in late January 2014.

THIRD QUARTER 2013 RESULTS WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held tomorrow
morning to discuss third quarter 2013 results. Please join Bill Barrett
Corporation executive management at 11:00 a.m. Eastern time/9:00 a.m. Mountain
time on November 1, 2013 for the live webcast, accessed at
www.billbarrettcorp.com,or join by telephone by calling 866-270-6057
(617-213-8891 international callers) with passcode 81445497. The webcast will
remain available on the Company's website for approximately 30 days, and a
replay of the call will be available November 1 through November 8, 2013 at
call-in number 888-286-8010 (617-801-6888 international) with passcode
18134202.

QUARTERLY REPORT ON FORM 10-Q

The Company plans to file later today its Quarterly Report on Form 10-Q for
the quarter ended September 30, 2013. The Form 10-Q will be posted to the
Company's website at www.billbarrettcorp.com and found under "SEC Filings".

UPCOMING EVENTS

Updated investor presentations are posted to the homepage of the Company's
website at www.billbarrettcorp.com prior to investor events. An updated
presentation will be posted at 5:00 p.m. Mountain time on Monday, November 4,
2013 and Tuesday, December 10, 2013.

Investor Conferences

Chief Executive Officer and President Scot Woodall will present at the Wells
Fargo 12^th Annual Pipeline, MLP and Energy Symposium on Wednesday, December
11, 2013 (time not yet confirmed.) The event will be webcast, and the live and
archived webcast will be accessible on the Company's homepage at
www.billbarrettcorp.com. 

Mr. Woodall will also participate in the Capital One Southcoast, Inc. 2013
Energy Conference the same week.

DISCLOSURE STATEMENTS

Natural Gas Liquids

Effective January 1, 2013, the Company began reporting its production volumes
on a three-stream basis, which separately reports NGLs from the natural gas
stream. The NGL volumes identified by our gas purchasers or processors 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.

Calculation of Natural Gas Liquids as a Percent of Sales Volumes

Prior to January 1, 2013, the Company reported natural gas production based on
wellhead volumes and its natural gas revenue included the incremental revenue
benefit from third party purchasers and processors when the Company elected to
receive NGL values from certain volumes of natural gas. In order to provide a
metric that is comparable to three-stream reporting, the Company is providing
the percentage of total Company sales volumes by product including oil,
natural gas and NGL revenues received from our gas purchasers or processors
for certain historical time periods. The NGL volumes identified by our gas
purchasers or processors 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.

Forward-Looking Statements

This press release contains forward-looking statements, including statements
regarding projected results and future events. In particular, the Company is
providing revised "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.

Actual results may differ materially from Company projections and other
forward-looking statements 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; the ability to complete property sales or other
transactions; the ability to receive drilling and other permits and
rights-of-way in a timely manner; development drilling and testing results;
the potential for production decline rates to be greater than expected;
performance of acquired properties and newly drilled wells; costs and
availability of third party facilities for gathering, processing, refining and
transportation; regulatory approvals, including regulatory restrictions on
federal lands; legislative or regulatory changes, including initiatives
related to hydraulic fracturing; higher than expected costs and expenses,
including the availability and cost of services and materials; unexpected
future capital expenditures; economic and competitive conditions; 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; 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 oil and natural gas 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  Nine Months Ended
                                    September 30,       September 30,
                                    2013       2012     2013       2012
Production Data:
 Natural gas (MMcf)                 12,988     27,010   41,959     78,417
 Oil (MBbls)                        909        714      2,528      1,830
 NGLs (MBbls)                       500        N/A      1,627      N/A
 Combined volumes (MMcfe)           21,442     31,294   66,889     89,397
 Daily combined volumes             233        340      245        326
 (MMcfe/d)
Average Prices (before the
effects of realized hedges):
 Natural gas (per Mcf)          (1) $  3.98    $  3.85  $  3.92    $ 3.84
 Oil (per Bbl)                  (2) 90.41      77.99    83.01      81.42
 NGLs (per Bbl)                     27.14      N/A      26.34      N/A
 Combined (per Mcfe)                6.88       5.10     6.23       5.03
Average Realized Prices (after
the effects of realized         (3)
hedges):
 Natural gas (per Mcf)          (1) $  4.30    $  4.90  $  4.10    $ 5.04
 Oil (per Bbl)                  (2) 83.51      84.08    82.50      85.49
 NGLs (per Bbl)                     28.74      N/A      27.79      N/A
 Combined (per Mcfe)                6.81       6.15     6.37       6.17
Average Costs (per Mcfe):
 Lease operating expense            $  0.85    $  0.54  $  0.79    $ 0.61
 Gathering, transportation and  (2) 0.76       0.85     0.76       0.89
 processing expense
 Production tax expense             0.38       0.26     0.33       0.24
 Depreciation, depletion and        3.36       2.92     3.21       2.81
 amortization
 General and administrative
 expense, excluding non-cash    (4) 0.52       0.44     0.54       0.44
 stock-based compensation
 expense

(1) Natural gas average prices include the effect of NGL revenues for the 2012
    period.
    Average oil prices for the three and nine months ended September30, 2013
    include an approximate $5.31 per Bbl transportation deduct related to
(2) certain production within the Uinta Oil Program. These costs were
    previously included in 2012 within gathering, transportation and
    processing expense. The effect on the average per unit oil price is
    approximately $1.95 per Bbl.
    Average realized prices shown in the table are net of the effects of all
    settled commodity hedging transactions related to current period
    production. This presentation is a non-GAAP measure as it only represents
    the cash settled portion of our total commodity derivative gain loss in
(3) the Unaudited Consolidated Statements of Operations. Management believes
    the presentation of average prices including the effects of settled
    commodity derivative gains and losses is useful because the cash
    settlement portion provides a better understanding of the Company's
    average prices received for production volumes. We also believe that this
    disclosure allows for a more accurate comparison to our peers.
    This separate presentation is a non-GAAP (Generally Accepted Accounting
    Principles) measure. Management believes the separate presentation of the
    non-cash component of general and administrative expense is useful because
(4) 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, which may have higher or lower costs associated with stock-based
    grants.



BILL BARRETT CORPORATION

Consolidated Statements of Operations

(Unaudited)
                          Three Months Ended       Nine Months Ended

                          September 30,            September 30,
                          2013         2012        2013         2012
(in thousands, except
per share amounts)
Operating and Other
Revenues:
 Oil, gas and NGLs    (1) $ 149,345    $ 180,024   $ 424,130    $ 516,556
 Other                    (790)        842         5,001        3,838
 Total operating and      148,555      180,866     429,131      520,394
 other revenues
Operating Expenses:
 Lease operating          18,280       17,003      53,138       54,671
 Gathering,
 transportation and       16,374       26,725      50,734       79,939
 processing
 Production tax           8,183        8,094       21,915       21,193
 Exploration              (24)         3,562       212          8,063
 Impairment, dry hole
 costs and                219,363      38,540      227,646      60,179
 abandonment
 Depreciation,
 depletion and            72,047       91,392      214,792      251,417
 amortization
 General and          (2) 11,083       13,912      36,278       39,026
 administrative
 Non-cash stock-based (2) 3,319        4,053       $ 11,979     $ 12,415
 compensation
 Total operating          348,625      203,281     616,694      526,903
 expenses
Operating Loss            (200,070)    (22,415)    (187,563)    (6,509)
Other Income and
Expense:
 Interest income and      52           53          123          128
 other income
 Interest expense         (20,078)     (24,527)    (69,346)     (70,029)
 Commodity derivative (1) (25,595)     (38,340)    (18,607)     53,431
 gain (loss)
 Gain (loss) on
 extinguishment of        (21,460)     —           (21,460)     1,601
 debt
 Total other income       (67,081)     (62,814)    (109,290)    (14,869)
 and expense
Loss before Income        (267,151)    (85,229)    (296,853)    (21,378)
Taxes
Benefit from Income       (100,495)    (32,603)    (111,319)    (7,943)
Taxes
Net Loss                  $ (166,656)  $ (52,626)  $ (185,534)  $ (13,435)
Net Loss Per Common
Share
 Basic                    $ (3.51)     $ (1.11)    $ (3.91)     $ (0.28)
 Diluted                  $ (3.51)     $ (1.11)    $ (3.91)     $ (0.28)
Weighted Average
Common Shares
Outstanding
 Basic                    47,535       47,230      47,453       47,173
 Diluted                  47,535       47,230      47,453       47,173

    The table below summarizes the realized and unrealized gains and losses
(1) the Company recognized related to its oil, natural gas and NGL derivative
    instruments for the periods indicated:

                                  Three Months Ended      Nine Months Ended

                                  September 30,           September 30,
                                  2013        2012        2013        2012
Included in oil and gas
production revenue:
Certain realized gains on hedges  $ 1,899     $ 20,391    $ 5,902     $ 66,654
Included in commodity derivative
gain (loss):
Realized gain (loss) on
derivatives not designated as     $ (3,255)   $ 12,295    $ 2,971     $ 35,014
cash flow hedges
Unrealized gain (loss) on
derivatives not designated as     (22,340)    (50,635)    (21,578)    18,417
cash flow hedges
Total commodity derivative gain   $ (25,595)  $ (38,340)  $ (18,607)  $ 53,431
(loss)

    This separate presentation is a non-GAAP measure. Management believes the
    separate presentation of the non-cash component of general and
    administrative expense is useful because the cash portion provides a
(2) 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, which may have higher or
    lower costs associated with stock-based grants.



BILL BARRETT CORPORATION

Consolidated Condensed Balance Sheets

(Unaudited)
                                        As of               As of
                                        September 30, 2013  December 31, 2012
(in thousands)


Assets:
  Cash and cash equivalents             $     60,530        $   79,445
  Other current assets           (1)    108,521             148,894
  Property and equipment, net           2,533,145           2,611,337
  Other noncurrent assets        (1)    24,065              29,773
  Total assets                          $     2,726,261     $   2,869,449
Liabilities and Stockholders' Equity:
  Current liabilities            (1)    $     206,237       213,133
  Notes payable to bank                 390,000             —
  Lease financing obligation            39,899              88,519
  Senior notes                          800,000             1,042,791
  Convertible senior notes              25,344              25,344
  Other long-term liabilities    (1)    257,783             316,887
  Stockholders' equity                  1,006,998           1,182,775
  Total liabilities and stockholders'   $     2,726,261     $   2,869,449
  equity

    At September30, 2013, the estimated fair value of all of the Company's
    commodity derivative instruments was a net asset of $5.1 million,
(1) comprised of $3.5 million current assets, $3.9 million non-current assets
    and $2.3 million 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        Nine Months Ended
                        September 30, 2013        September 30, 2013
                        2013         2012         2013         2012
(in thousands)
Operating Activities:
 Net loss               $ (166,656)  $ (52,626)   $ (185,534)  $ (13,435)
 Adjustments to
 reconcile to net cash
 provided by
 operations:
   Depreciation,
   depletion and        72,047       91,392       214,792      251,417
   amortization
   Impairment, dry hole
   costs and            219,363      38,540       227,646      60,179
   abandonment expense
   Total commodity
   derivative gain      25,595       38,340       18,607       (53,431)
   (loss)
   Settlements of
   commodity            (3,255)      12,295       2,971        35,014
   derivatives
   Deferred income      (99,212)     (32,329)     (110,036)    (7,669)
   taxes
   Stock compensation
   and other non-cash   3,392        5,008        12,681       14,249
   charges
   Amortization of debt
   discounts and        1,069        1,708        4,535        6,710
   deferred financing
   costs
   (Gain) loss on
   extinguishment of    21,460       —            21,460       (1,601)
   debt
   (Gain) loss on sale  1,091        (108)        (3,102)      (108)
   of properties
   Change in assets and
   liabilities:
      Accounts          (4,163)      (13,661)     12,343       4,475
      receivable
      Prepayments and
      other current     (110)        7,581        1,475        1,515
      assets
      Accounts payable,
      accrued and other (1,058)      4,040        (24,801)     (4,813)
      liabilities
      Amounts payable
      to oil & gas      (3,227)      5,950        6,510        567
      property owners
      Production taxes  6,937        5,229        (3,245)      (2,466)
      payable
   
                        $ 73,273     $ 111,359    $ 196,302    $ 290,603
   Net cash provided by
   operating activities
Investing Activities:
 Additions to oil and
 gas properties,        (118,945)    (291,486)    (335,597)    (751,545)
 including acquisitions
 Additions of
 furniture, equipment   (319)        (1,278)      (1,506)      (5,519)
 and other
 Proceeds from sale of
 properties and other   (3,302)      (43)         784          91
 investing activities
   
                        $ (122,566)  $ (292,807)  $ (336,319)  $ (756,973)
   Net cash used in
   investing activities
Financing Activities:
 Proceeds from debt     310,000      260,826      390,000      785,826
 Principal and
 redemption premium     (264,624)    (76,007)     (269,125)    (343,163)
 payments on debt
 Deferred financing     (78)         (277)        (1,426)      (10,363)
 costs and other
 Proceeds from stock    1,650        5            1,653        672
 option exercises
   
                        $ 46,948     $ 184,547    $ 121,102    $ 432,972
   Net cash provided by
   financing activities
Increase (Decrease) in
Cash and Cash           (2,345)      3,099        (18,915)     (33,398)
Equivalents

                        62,875       20,834       79,445       57,331
Beginning Cash and Cash
Equivalents

                        $ 60,530     $ 23,933     $ 60,530     $ 23,933
Ending Cash and Cash
Equivalents



BILL BARRETT CORPORATION

Reconciliation of Discretionary Cash Flow & Adjusted Net Income (Loss)

(Unaudited)
Discretionary Cash Flow Reconciliation
                           Three Months Ended         Nine Months Ended
                           September 30,              September 30,
                           2013          2012         2013          2012
(in thousands, except per
share amounts)
Net Loss                   $ (166,656)   $ (52,626)   $ (185,534)   $ (13,435)
Adjustments to reconcile
to discretionary cash
flow:
 Depreciation, depletion   72,047        91,392       214,792       251,417
 and amortization
 Impairment, dry hole and  219,363       38,540       227,646       60,179
 abandonment expense
 Exploration expense       (24)          3,562        212           8,063
 Total commodity           25,595        38,340       18,607        (53,431)
 derivative gain (loss)
 Settlements of commodity  (3,255)       12,295       2,971         35,014
 derivatives
 Deferred income taxes     (99,212)      (32,329)     (110,036)     (7,669)
 Stock compensation and    3,392         5,008        12,681        14,249
 other non-cash charges
 Amortization of debt
 discounts and deferred    1,069         1,708        4,535         6,710
 financing costs
 Loss (gain) on            21,460        —            21,460        (1,601)
 extinguishment of debt
 Loss (gain) on sale of    1,091         (108)        (3,102)       (108)
 properties
Discretionary Cash Flow    $ 74,870      $ 105,782    $ 204,232     $ 299,388
 Per share, diluted        $ 1.58        $ 2.24       $ 4.30        $ 6.35
 Per Mcfe                  $ 3.49        $ 3.38       $ 3.05        $ 3.35
Adjusted Net Income (Loss) Reconciliation
                           Three Months Ended         Nine Months Ended
                           September 30,              September 30,
                           2013          2012         2013          2012
(in thousands except per
share amounts)
Net Loss                   $ (166,656)   $ (52,626)   $ (185,534)   $ (13,435)
Adjustments to net loss:
 Total commodity           25,595        38,340       18,607        (53,431)
 derivative gain (loss)
 Settlements of commodity  (3,255)       12,295       2,971         35,014
 derivatives
 Impairment expense        216,564       18,772       216,564       37,109
 Loss (gain) on sale of    1,091         (108)        (3,102)       (108)
 properties
 One-time items:
    Expenses relating to
    compressor station     192           —            1,367         —
    fire
    Loss (gain) on         21,460        —            21,460        (1,601)
    extinguishment of debt
 Subtotal Adjustments      261,647       69,299       257,867       16,983
 Effective tax rate        38%           38%          38%           37%
 Tax effected adjustments  162,221       42,965       159,878       10,699
Adjusted Net Loss          $ (4,435)     $ (9,661)    $ (25,656)    $ (2,736)
 Per share, diluted        $ (0.09)      $ (0.20)     $ (0.54)      $ (0.06)
 Per Mcfe                  $ (0.21)      $ (0.31)     $ (0.38)      $ (0.03)

Discretionary cash flow and adjusted net income (loss) are non-GAAP measures.
These measures 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 (loss) for unusual items to allow
for a more consistent comparison from period to period. In addition, the
Company believes that 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 that 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 necessarily all, items that affect net income (loss) and
may vary among companies, the amounts presented may not be comparable to
similarly titled measures of other companies.

SOURCE Bill Barrett Corporation

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