Bill Barrett Corporation Reports First Quarter 2014 Results, Announces Results from Seven New Northeast Wattenberg Wells and Re

Bill Barrett Corporation Reports First Quarter 2014 Results, Announces Results
    from Seven New Northeast Wattenberg Wells and Reaffirms 2014 Guidance

PR Newswire

DENVER, May 1, 2014

DENVER, May 1, 2014 /PRNewswire/ -- Bill Barrett Corporation ("the Company")
(NYSE: BBG) today reported first quarter 2014 results and announced
operational updates highlighted by:

  oTotal production of 2.43 MMBoe reflecting strong year-over-year production
    growth in the Denver-Julesburg ("DJ") Basin of 137%, East Bluebell of 34%
    and the Powder Deep of 108%
  oDJ Basin production of 6,430 Boe/d, up 25% sequentially from the fourth
    quarter of 2013
  oCommodity balanced production with 38% oil, 44% natural gas and 18% NGLs
  oDiscretionary cash flow of $55.3 million, or $1.15 per diluted common
    share. This is up 36% per Boe from the first quarter of 2013 as the
    Company drives improved profitability from its core oil development
    programs
  oFive new delineation wells in the southern portion of the Company's
    Northeast Wattenberg, DJ Basin acreage position. Initial production rates
    averaged approximately 875 Boe/d per well over a peak 24 hours and
    averaged approximately 420 Boe/d per well over 30 days
  oTwo new wells in the western portion of the Northeast Wattenberg position.
    Initial production rates averaged more than 830 Boe/d per well over a peak
    24 hours and averaged approximately 436 Boe/d per well over 30 days
  oFour wells year-to-date in the East Bluebell area. Initial production
    rates averaged 217 Bbls/d of oil over 30 days, exceeding the expected type
    curve

Chief Executive Officer and President Scot Woodall commented: "We had a solid
first quarter despite severe winter weather, downtime and lower yields at our
primary NGL processor in the Piceance Basin, and unexpected delays associated
with remediation of offset wellbores in the DJ Basin as required by
regulation. First quarter oil production was aligned with our internal
operations plan while NGL production fell somewhat short. While we plan for
certain delays and unexpected events, circumstances in the first quarter were
more challenging than usual and I commend our team for doing an excellent job
in meeting those challenges. The Company remains on track for our 2014
operating plan and guidance.

"Today we are providing strong well results from the Northeast Wattenberg area
of our DJ Basin program. Results from seven wells located in the southern and
western portions of the position demonstrate the quality and consistency of
our Northeast Wattenberg acreage. During the first quarter, we also drilled
four wells in the Chalk Bluffs area and look forward to those results later
this year. In the second quarter of 2014, we are drilling our first extended
reach laterals, which we believe have the potential to drive superior returns
in the DJ Basin program. In the Uinta Oil Program, we are very pleased with
the East Bluebell wells to date, which are exceeding expectations both in
terms of production and drilling and completion costs.

"In March, we announced our plans to sell our Powder Deep Oil Program and the
formal process is now underway. Given interest in the property to date, we
expect to conclude a sale in the coming months that will serve to better focus
our portfolio on our core Uinta and DJ Basin programs and continue to improve
our balance sheet."

OPERATING AND FINANCIAL RESULTS

Oil, natural gas and natural gas liquids ("NGLs") production totaled 2.43
million barrels of oil equivalent ("MMBoe") (or 14.6 billion cubic feet
equivalent of natural gas, "Bcfe") in the first quarter of 2014. Oil
production increased to 38% of total production in the first quarter of 2014
compared with 21% in the first quarter of 2013 as the Company has focused its
capital expenditures on development of its core oil programs. The Company
enjoyed high year-over-year production growth in the DJ Basin at 137%, East
Bluebell at 34% and the Powder Deep Oil Program at 108%. Total production is
down from 3.8 MMBoe in the first quarter of 2013, primarily due to an asset
sale that closed in the fourth quarter of 2013 and natural declines in the
Gibson Gulch natural gas program.

First quarter 2014 pre-hedge pricing was up 52% compared with the first
quarter of 2013, driven by both an increase in commodity prices and a higher
proportion of sales coming from oil production. After settling $9.0 million in
cash commodity hedge losses, realized commodity prices were up 33% on average.
(See "Selected Operating Highlights" for more detail.)

Discretionary cash flow (a non-GAAP measure, see "Discretionary Cash Flow
Reconciliation" below) in the first quarter of 2014 was $55.3 million, or
$1.15 per diluted common share, down from $63.6 million in the first quarter
of 2013. The decline in discretionary cash flow in the first quarter of 2014
compared with the first quarter of 2013 was primarily due to lower production
(described above) largely offset by a 33% increase in the average realized
price per unit. Cash operating costs (lease operating expense, gathering
transportation and processing expense and production tax expense) per unit
were higher in the first quarter of 2014 at $14.58 per Boe compared with the
first quarter of 2013 at $10.55 per Boe, due to the higher proportion of oil
production, as oil is more costly to produce per unit than natural gas, as
well as an increased number of well workovers in the first quarter of 2014.
Other expenses in the quarter included a 29% reduction in interest expense and
a 22% reduction in general and administrative expenses compared with the prior
year period. Discretionary cash flow per Boe was up 36% in the first quarter
of 2014 compared with the first quarter of 2013.

Net loss in the first quarter of 2014 was $12.7 million, or ($0.27) per
diluted common share, compared with a net loss of $33.2 million in the first
quarter of 2013. The net loss reflected higher per unit depreciation,
depletion and amortization expenses as well as a $25.2 million commodity
derivative loss.

Adjusted net loss for the first quarter of 2014 (a non-GAAP measure, see
"Adjusted Net Income (Loss) Reconciliation" below) was $2.2 million, or
($0.05) per diluted common share, compared with a loss of $11.8 million, or
($0.25) per diluted common share, in the first quarter of 2013. Adjusted net
income (loss) removes the effect of unrealized derivative gains and losses,
and non-recurring charges such as impairment expenses, property sales and
certain one-time items.

DEBT AND LIQUIDITY

At March 31, 2014, the Company had total debt outstanding (principal balance)
of $1,047.5 million. Debt outstanding included $180.0 million drawn on its
revolving credit facility, $25.3 million in convertible senior notes, $400.0
million in 7.625% senior notes, $400.0 million in 7.000% senior notes and
$42.2 million for a lease financing obligation. Subsequent to quarter-end,
through the semi-annual redetermination process, the borrowing base on the
credit facility was reaffirmed at $625.0 million.

OPERATIONS

Production, Wells Spud and Capital Expenditures

The following table lists production, wells spud and total capital
expenditures by basin for the three months ended March 31, 2014:

                              Three Months Ended March 31, 2014
                              Average Net
                                                     Capital
                              Daily       Wells Spud
                                                     Expenditures
                              Production  Gross/Net*
                                                     ($ millions)
                              (Boe)
Basin
Denver-Julesburg              6,430       32/19      95.0
Uinta                         5,763       13/7       29.7
Piceance                      13,507      --         0.1
Powder River Deep Oil & Other 1,344       7/1        9.7
Total                         27,044      52/27      $134.5
           *Includes operated and non-operated wells

Operating and Drilling Update

In 2014, the Company anticipates participating in approximately 190 gross/100
net development wells of which approximately 130 gross are to be operated by
the Company. The Company's drilling program remains flexible to changes
throughout the year, particularly if positive well results and technical
changes expand opportunities.

Denver-Julesburg Basin, Colorado and Wyoming

Northeast Wattenberg/DJ Basin – First quarter of 2014 net production averaged
6,430 barrels of oil equivalent per day ("Boe/d"), a 137% increase from the
first quarter of 2013 and up 25% sequentially from the fourth quarter of 2013.
Production was 62% oil, 22% natural gas and 16% NGLs. The Company realized
strong sequential production growth despite approximately two weeks of delays
in well completions affecting approximately 14 wells due to sub-zero
temperatures in the region. In addition, the Company experienced an additional
20 days in delays in drilling a pad in the southern portion of the Northeast
Wattenberg area as a result of unexpected remediation efforts on offset
wellbores prior to drilling, as required by recent regulation. The Company's
internal operating plan adjusts for certain delays and unplanned events, and
the Company remains on track for its 2014 production guidance.

Today, the Company is providing results on seven new wells in the Northeast
Wattenberg area:

  oFive new delineation wells in the southern portion of the Northeast
    Wattenberg. Initial production ("IP") rates averaged approximately 875
    Boe/d per well over a peak 24 hours and averaged approximately 420 Boe/d
    per well over 30 days. All wells were drilled into the B bench of the
    Niobrara.
  oTwo new wells in the western portion of the Northeast Wattenberg. IP rates
    averaged more than 830 Boe/d per well over a peak 24 hours and averaged
    approximately 436 Boe/d per well over 30 days. Both wells targeted the
    Codell formation.

The newly reported wells were standard length horizontals drilled to between
6,100 and 6,600 feet vertical depth with approximate 4,000 foot laterals and
were completed with 18-25 fracture stimulation stages. The wells employed a
variety of artificial lift technologies and were typically placed on lift
after flowing for two or more weeks. The Company also drilled four Codell
wells in the Chalk Bluffs area, two of which have positive preliminary
production results and two of which are yet to be completed.

The Company is currently operating three rigs in the Northeast Wattenberg
area. While the drilling program will remain somewhat flexible throughout the
year, the Company expects to drill approximately 85 gross operated wells (65
net), and participate in an additional 35 gross wells (7-8 net) in the DJ
Basin program during 2014. The drilling program for the second quarter
includes drilling three extended reach laterals targeting the B and C benches
of the Niobrara, two in the southern area with planned 7,400 and 9,000 foot
laterals, and one in the northern area with a planned 9,000 foot lateral.

At March 31, 2014, the Company had an approximate 77% working interest in
production from 344 gross/217 net wells, including approximately 200 legacy
vertical wellsfrom priorDJ Basin property acquisitions. As of the end of the
first quarter of 2014, the Company had approximately 75,500 net acres in the
DJ Basin developmentprogram.

Uinta Basin, Utah

Uinta Oil Program (East Bluebell, Blacktail Ridge-Lake Canyon and South
Altamont) - First quarter of 2014 net production averaged 5,763 Boe/d, down
17% from the first quarter of 2013 and down 21% sequentially from the fourth
quarter of 2013. Lower production was a result of natural production declines
following the 2013 drilling program, which concluded late summer with peak
production in the fall of 2013. Production was 78% oil, 16% natural gas and 6%
NGLs.

Execution of the 2014 drilling plan is ahead of schedule in East Bluebell, and
preliminary results from the four wells placed on production year-to-date are
on track to exceed the expected type curve at lower costs. Thirty-day IP rates
per well from the first four wells averaged 217 barrels per day ("Bbls/d") of
oil. Seven wells drilled in the same area during 2013 had average IP rates per
well of 209 Bbls/d over 30 days, 195 Bbls/d over 60 days and 189 Bbls/d over
90 days. Production declines in the area tend to be very flat. In the more
southern portion of the Company's East Bluebell position, wells drilled in
2013 had average IP rates per well of 136 Bbls/d over 30 days, 147 Bbls/d over
60 days and 150 Bbls/d over 90 days. Drilling time has averaged 9 days per
well, down from 13, and drilling and completion costs have improved
approximately 20% compared with 2013. As a result of better drill times and
well performance, the Company has modified its 2014 drilling program in East
Bluebell to include 34 gross wells (21 net), up from 25 gross wells.

The Company is operating two active rigs in the area and during 2014 expects
to drill 44 gross wells (26 net) in the Uinta Oil Program.

At March 31, 2014, the Company had an approximate 77% working interest in
production from 304 gross/175 net wells. As of the end of the first quarter of
2014, the Company had approximately 152,000 net acres (including approximately
51,000 acres to be earned) in the Uinta Oil program, including 21,500 acres in
the East Bluebell area.

Piceance Basin, Colorado

Gibson Gulch – First quarter of 2014 net production averaged 81 million cubic
feet equivalent per day ("MMcfe/d"). Drilling in the area remains suspended
as the Company focuses its operations plan on oil development.

At March 31, 2014, the Company had an approximate 77% working interest in
production from 956 gross/717 net wells and held 12,150 net acres in its
Gibson Gulch program.

Powder River Basin, Wyoming

Powder Deep Oil Program – First quarter of 2014 net production averaged
approximately 1,330 Boe/d from 20 net wells and was 82% oil. The Company's
68,000 net acre position includes resource rich targets into multiple
horizons. The 2014 programexpects participation in approximately 18 gross
partner-operated wells (2 net), down from approximately 35 gross wells in the
original 2014 plan. This asset is currently being marketed for sale and the
Company has engaged the Energy Advisory Services of BMO Capital Markets.

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 next four quarters, 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.

  oHedges in place for the remainder of 2014 include an average 10,071 Bbls/d
    of oil at an average price of $94.03 per barrel and approximately 67,218
    MMBtu/d of natural gas at an average price of $3.97 per MMBtu.

The following table summarizes hedge positions as of April 25, 2014:

         Oil               Natural Gas         NGLs
 Volume   Price    Volume     Price    Volume   Price

Period   Bbls/d  $/Bbl   MMBtu/d   $/MMBtu  Bbls/d   $Bbl
2Q14     9,000    94.27    65,000     4.02     988      58.61
3Q14     10,600   93.98    65,000     4.02     1,029    60.18
4Q14     10,600   93.98    71,630     3.89     1,029    60.18
1Q15     10,800   90.07    20,000     4.13     __       __

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

2014 Operating Guidance

As previously reported, the Company's 2014 operating guidance (please
reference "Forward-Looking Statements" below) is as follows. The Company may
update the following guidance as business conditions warrant:

  oCapital expenditures of $500 million - $550 million.
  oProduction of 11.0 million -12.2 million Boe, before the effect of the
    expected sale of Powder Deep assets.
  oLease operating costs of $62 million - $67 million.
  oGathering, transportation and processing costs of $43 million - $48
    million.
  oGeneral and administrative expenses, before non-cash stock-based
    compensation costs, of $48 million - $52 million.

FIRST QUARTER 2014 RESULTS WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held tomorrow
morning to discuss first quarter 2014 results. Please join Bill Barrett
Corporation executive management at 11:00 a.m. Eastern time/9:00 a.m. Mountain
time on May 2, 2014 for the live webcast, accessed at www.billbarrettcorp.com,
or join by telephone by calling 877-703-6104 (857-244-7303 international
callers) with passcode 86571587. The webcast will remain available on the
Company's website for approximately 30 days, and a replay of the call will be
available May 2 through May 9, 2014 at call-in number 888-286-8010
(617-801-6888 international) with passcode 57629535.

QUARTERLY REPORT ON FORM 10-Q

The Company plans to file later today its Quarterly Report on Form 10-Q for
the quarter ended March 31, 2014. The Form 10-Q will be posted to the
Company's website at www.billbarrettcorp.comand found under "SEC Filings".

UPCOMING EVENTS

Updated investor presentations are posted to the homepage of the Company's
website at www.billbarrettcorp.comprior to investor events. The next investor
presentation will be posted at 5:00 p.m. Mountain time today.

DISCLOSURE STATEMENTS

Forward-Looking Statements

This press release contains forward-looking statements. Forward-looking
statements are dependent upon events, risks and uncertainties that may be
outside the Company's control. Our actual results could differ materially from
those discussed in these forward-looking statements. In particular, the
Company is confirming "2014 Operating Guidance," which contains projections
for certain 2014 operational and financial metrics. These and other
forward-looking statements in this press release, including well performance
and sale of the Powder Deep Oil Program, are based on management's judgment as
of the date of this press release and include certain risks and uncertainties.
Among a number of factors, operations plans are subject to change during the
year and such changes can materially affect projected results provided in the
Company's guidance. Please refer to the Company's Annual Report on Form 10-K
for the year ended December 31, 2013 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 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, including
regional price differentials; costs, availability and timing of build-out of
third party facilities for gathering, processing, refining and transportation;
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; legislative or
regulatory changes, including initiatives related to hydraulic fracturing;
regulatory approvals, including regulatory restrictions on federal lands;
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; 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 and to not place undue reliance on any such 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,
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
                                             March 31,
                                             2014             2013
Production Data:
  Oil (MBbls)                                922              794
  Natural gas (MMcf)                         6,420            14,664
  NGLs (MBbls)                               442              582
  Combined volumes (MBoe)                    2,434            3,820
  Daily combined volumes (Boe/d)             27,044           42,444
Average Prices (before the effects of
realized hedges):
  Oil (per Bbl)                              $    82.60   $    78.73
  Natural gas (per Mcf)                      5.57             3.71
  NGLs (per Bbl)                             34.19            24.28
  Combined (per Boe)                         52.19            34.32
Average Realized Prices (after the
effects of realized hedges):
  Oil (per Bbl)                              $    78.78   $    81.74
  Natural gas (per Mcf)                      4.79             4.10
  NGLs (per Bbl)                             33.00            25.01
  Combined (per Boe)                         48.47            36.55
Average Costs (per Boe):
  Lease operating expense                    $      6.64 $      4.91
  Gathering, transportation and              4.81             4.08
  processing expense
  Production tax expense                     3.13             1.56
  Depreciation, depletion and                22.81            17.92
  amortization
  General and administrative expense,
   excluding non-cash stock-based     (1) 4.86             3.97
  compensation expense

    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
(1) 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
                                                  March 31,
                                                  2014           2013
(in thousands, except per share amounts)
Operating and Other Revenues:
         Oil, gas and NGLs                   (1)  $ 127,169      $ 134,405
         Other                                    519            3,872
          Total operating and other            127,688        138,277
         revenues
Operating Expenses:
         Lease operating                          16,164         18,746
         Gathering, transportation and            11,704         15,588
         processing
         Production tax                          7,624          5,951
         Exploration                              303            95
         Impairment, dry hole costs and           1,761          7,101
         abandonment
         Depreciation, depletion and              55,508         68,438
         amortization
         General and administrative          (2)  11,819         15,148
         Non-cash stock-based compensation   (2)  3,588          5,434
          Total operating expenses             108,471        136,501
Operating Income                                  19,217         1,776
Other Income and Expense:
         Interest and other income                375            39
         Interest expense                         (17,431)       (24,542)
         Commodity derivative loss           (1)  (25,155)       (29,851)
          Total other income and expense       (42,211)       (54,354)
Loss before Income Taxes                          (22,994)       (52,578)
Benefit from Income Taxes                         (10,245)       (19,427)
Net Loss                                          $ (12,749)    $ (33,151)
Net Loss Per Common Share
         Basic                                    $   (0.27)  $   (0.70)
         Diluted                                  $   (0.27)  $   (0.70)
Weighted Average Common Shares Outstanding
         Basic                                    47,890         47,353
         Diluted                                  47,890         47,353

    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 March 31,
                                                2014             2013
 Included in oil, gas and NGL production
 revenue:
 Certain realized gains on hedges               $     156   $    2,067
 Included in commodity derivative loss:
 Realized gain (loss) on derivatives not
 designated as
  cash flow hedges                            $   (9,200)   $    6,453
 Unrealized loss on derivatives
  not designated as cash flow hedges          (15,955)         (36,304)
  Total commodity derivative loss             $  (25,155)    $  (29,851)

    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
                                          March 31, 2014   December 31, 2013
(in thousands)
Assets:
 Cash and cash equivalents                $         $         
                                          62,232             54,595
 Other current assets                 (1) 96,135           102,652
 Property and equipment, net              2,282,107        2,202,496
 Other noncurrent assets              (1) 19,501           21,770
    Total assets                          $            $        
                                          2,459,975        2,381,513
Liabilities and Stockholders' Equity:
 Current liabilities           (1) $           $         
                                          228,764          192,719
 Notes payable to bank                    180,000          115,000
 Capitalized lease obligation             37,545           38,738
 Senior notes                             800,000          800,000
 Convertible senior notes                 25,344           25,344
 Other long-term liabilities    (1) 193,397          203,994
 Stockholders' equity                     994,925          1,005,718
    Total liabilities and                 $            $        
    stockholders' equity                  2,459,975        2,381,513

    At March 31, 2014, the estimated fair value of all of the Company's
    commodity derivative instruments was a net liability of $19.4 million,
(1) comprised of: $1.2 million non-current assets, $20.4 million current
    liabilities and $0.2 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
                                                    March 31,
                                                    2014          2013
(in thousands)
Operating Activities:
  Net loss                                          $  (12,749)  $  (33,151)
  Adjustments to reconcile to net cash
   provided by operations:
   Depreciation, depletion and amortization         55,508        68,438
   Impairment, dry hole costs and abandonment       1,761         7,101
   expense
   Derivative loss, non-cash                        15,955        36,304
   Deferred income taxes                            (10,245)      (19,427)
   Stock compensation and other non-cash charges    3,692         6,070
   Amortization of debt discounts and deferred      1,067         1,732
   financing costs
   Gain on sale of properties                       -             (3,519)
   Change in assets and liabilities:
        Accounts receivable                         5,530         19,235
        Prepayments and other current assets        408           818
        Accounts payable, accrued and other         6,134         (14,089)
        liabilities
        Amounts payable to oil & gas property       9,401         2,406
        owners
        Production taxes payable                    (1,268)       (4,992)
   Net cash provided by operating activities        $   75,194  $   66,926
Investing Activities:
  Additions to oil and gas properties, including    (128,938)     (115,324)
  acquisitions
  Additions of furniture, equipment and other       (274)         (445)
  Proceeds from sale of properties and other        (388)         6,424
  investing activities
   Net cash used in investing activities            $ (129,600)   $ (109,345)
Financing Activities:
  Proceeds from debt                                65,000        25,000
  Principal payments on debt                        (1,137)       (2,241)
  Deferred financing costs and other                (1,946)       (1,263)
  Proceeds from stock option exercises              126           -
   Net cash provided by financing activities        $   62,043  $   21,496
Increase (Decrease) in Cash and Cash Equivalents    7,637         (20,923)
Beginning Cash and Cash Equivalents                 54,595        79,445
Ending Cash and Cash Equivalents                    $   62,232  $   58,522

BILL BARRETT CORPORATION
Reconciliation of Discretionary Cash Flow & Adjusted Net Income
(Unaudited)
Discretionary Cash Flow Reconciliation
                                                    Three Months Ended
                                                    March 31,
                                                    2014          2013
(in thousands, except per share amounts)
Net Loss                                            $ (12,749)    $ (33,151)
Adjustments to reconcile to discretionary cash
flow:
 Depreciation, depletion and amortization           55,508        68,438
 Impairment, dry hole and abandonment expense       1,761         7,101
 Exploration expense                                303           95
 Unrealized derivative loss                         15,955        36,304
 Deferred income taxes                              (10,245)      (19,427)
 Stock compensation and other non-cash charges      3,692         6,070
 Amortization of debt discounts and deferred        1,067         1,732
 financing costs
 Gain on sale of properties                         -             (3,519)
Discretionary Cash Flow                             $ 55,292     $ 63,643
 Per share, diluted                                 $    1.15  $    1.34
 Per Boe                                            $   22.72   $   16.66
Adjusted Net Income (Loss) Reconciliation
                                                    Three Months Ended
                                                    March 31,
                                                    2014          2013
(in thousands except per share amounts)
Net Loss                                            $ (12,749)    $ (33,151)
Adjustments to net income (loss):
 Unrealized derivative (gain) loss                  15,955        36,304
 Impairment expense                                 1,038         -
 Gain on sale of properties                         -             (3,519)
 One time items:
         Expenses relating to compressor            -             1,175
         station fire
 Subtotal Adjustments                               16,993        33,960
 Effective tax rate                             (1) 38%           37%
 Tax effected adjustments                           10,536        21,395
Adjusted Net Loss                                   $  (2,213)   $ (11,756)
 Per share, diluted                                 $   (0.05)  $   (0.25)
 Per Boe                                            $   (0.91)  $   (3.08)

(1) First quarter of 2014 applies the standard corporate tax rate.
Discretionary cash flow and adjusted net income 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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