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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