Bill Barrett Corporation Reports 2012 Financial and Operating Results and Announces Strong Initial Oil Rates on All Four-Well Pads in DJ Basin PR Newswire DENVER, Feb. 21, 2013 DENVER, Feb. 21, 2013 /PRNewswire/ -- Bill Barrett Corporation (NYSE: BBG) today reported 2012 results and announced operational updates including: oTotal oil and natural gas production growth up 10% to 118 billion cubic feet equivalent ("Bcfe") oOil production up 80% to 2.7 million barrels oOil reserves up 66% to 51 million barrels oProved reserves plus risked resources of 2.9 trillion cubic feet equivalent ("Tcfe"), including nearly 200 million barrels of oil oDiscretionary cash flow of $403 million or $8.51 per diluted common share; Adjusted net income of $6.9 million, or $0.15 per diluted common share (non-GAAP measures, see below) oSuccess with Denver-Julesburg ("DJ") Basin pad drilling, with 30-day rates averaging 412 barrels of oil equivalent per well per day ("Boe/d") at the first three four-well pads oCompletion of $335 million sale of natural gas assets Chief Executive Officer Scot Woodall commented: "We closed 2012 with estimated proved reserves that included 51 million barrels of oil, an increase of 66% over 2011, and exit rate production that included 8,950 barrels of oil per day, accounting for24% of total production. We have established a drilling inventory at our key oil programs of nearly 3,000 locations, or more than 15 years of drilling based on current activity. "We have commenced 2013 with a focused strategy: execute development of our two core oil programs to optimize operating efficiencies and returns. We will increase activity at the Uinta Oil Program with a four-rig vertical drilling program. In the DJ Basin, we are very encouraged by results to date. We will run a two-rig program that will be predominantly pad drilling, as well as delineate our acreage position in the Northeast Wattenberg –an area where industry activity has established proven results, identified significant upside and demonstrated repeatability. We have no active rigs in our natural gas plays. "We have an $825 million line of credit and have approximately 70% of 2013 production hedged. As previously reported, we plan to fully fund our 2013 capital program with cash flows and asset sales. We are well positioned with the right assets, excellent liquidity and a solid, focused plan to deliver value to our shareholders in 2013." OPERATING AND FINANCIAL RESULTS Total estimated proved reserves at year-end 2012 were 1.04 trillion cubic feet equivalent ("Tcfe"). Estimated proved reserves were 29% oil and 71% natural gas and were 59% developed and 41% undeveloped. Oil and natural gas production totaled 117.6 Bcfe in 2012, up 10% from 106.8 Bcfe in 2011. Production growth was primarily from the Uinta and DJ oil programs followed by growth in natural gas production stemming from early year drilling at West Tavaputs and Gibson Gulch. Year-over-year growth in oil production of 80% met the Company's target for the year. Fourth quarter production was 28.2 Bcfe, down slightly from 29.1 Bcfe in the fourth quarter of 2011, and was negatively affected by 1.2 Bcf due to a fire at a West Tavaputs compressor station. Realized pricing, including the effects of the Company's hedging activities and natural gas liquids ("NGL") recovery, was $6.32 per thousand cubic feet equivalent ("Mcfe"), including an $0.82 per Mcfe benefit from NGL-related pricing and a $1.05 per Mcfe benefit from realized hedges. The average realized price is down from $7.05 per Mcfe in 2011, primarily due to significantly lower natural gas and NGL prices. The average realized natural gas price was $5.07 per Mcf in 2012 compared with $6.46 per Mcf in 2011. The average realized oil price was $84.96 per barrel ("Bbl") in 2012 compared with $80.63 per Bbl in 2011. The fourth quarter 2012 average realized price was $6.78 per Mcfe compared with $6.96 per Mcfe in 2011. (See "Selected Operating Highlights" below for more detail.) Discretionary cash flow (a non-GAAP measure, see "Discretionary Cash Flow Reconciliation" below) for 2012 was $402.9 million, or $8.51 per diluted common share, down from $478.2 million, or $10.12 per diluted common share, in 2011. The decline in discretionary cash flow is primarily due to lower realized natural gas prices and increased interest expenses, partially offset by higher production volumes. Discretionary cash flow was $103.5 million for the fourth quarter of 2012 compared with $124.8 million for the fourth quarter of 2011. Net income for 2012 was $0.6 million, or $0.01 per diluted common share, down from income of $30.7 million, or $0.65 per diluted common share, in 2011. Net income in 2012 was affected by the same factors as discretionary cash flow, which were partially offset by a commodity derivative gain in 2012 of $72.8 million versus a loss in 2011 of $14.3 million and a lower impairment expense in 2012 of $37.3 million versus $100.3 million in 2011. Dry hole expenses in 2012 were $21.0 million, or $13.0 million after-tax (applying a standard 38% rate.) Net income for the fourth quarter was $14.0 million compared with a loss of $37.8 million in the fourth quarter of 2011. Dry hole expenses in the fourth quarter were $5.1 million (pre-tax), which related primarily to one exploratory dry hole in the Southern Alberta Basin. Adjusted net income (a non-GAAP measure, see "Adjusted Net Income Reconciliation" below) for 2012 was $6.9 million, or $0.15 per diluted common share, compared with $84.0 million, or $1.78 per diluted common share, in 2011. Adjusted net income for the fourth quarter of 2012 was $9.6 million compared with $20.6 million in 2011. Adjusted net income removes the effect of non-recurring charges such as unrealized derivative gains and losses, impairment expenses, property sales and one-time items. On December 31, 2012, the Company closed on the sale of natural gas assets for a transaction value of $335 million. The assets included all Wind River natural gas producing properties, Powder River Basin coal bed methane and a working interest in the Gibson Gulch-Piceance Basin development property. The transaction value was adjusted to the October 1, 2012 effective date and for other customary closing adjustments, providing net proceeds to the Company of $325.3 million, which included a $33.5 million deposit received in November 2012. Net proceeds from the transaction were applied to pay off the $250 million balance on the Company's revolving credit facility and to working capital, with the remaining proceeds of approximately $30 million to be applied to the Company's 2013 development capital. DEBT AND LIQUIDITY At December 31, 2012, the Company had borrowing capacity of $799.0 million and total debt outstanding of $1.17 billion. The Company had zero drawn on its revolving credit facility. The facility has a borrowing base of $825.0 million less an outstanding letter of credit for $26.0 million. Debt outstanding includes $1,075.3 million principal in senior notes and $97.6 million for a lease financing obligation. The Company has no significant debt maturity before 2016. OPERATIONS Production and Capital Expenditures The following table lists average daily production and capital expenditures by basin for the three and twelve months ended December 31, 2012: Average Net Production Capital Expenditures (MMcfe/d) ($millions) Three Months Twelve Three Twelve Ended Months Ended Months Months Ended Ended December 31, December 31, December December 2012 2012 31, 2012 31, 2012 Basin Uinta: Uinta Oil Program 42 31 72 315 West Tavaputs 77 95 14 107 Piceance 134 141 15 208 Denver-Julesburg 15 10 50 226 Powder River (CBM) 26 30 - - Other 13 14 33 108 Total 307 321 184 963 (MMcfe/d: million cubic feet equivalent per day) Operating and Drilling Update The Company's 2013 capital budget is focused on development drilling at the Company's two core oil programs in the Uinta and DJ Basins. The capital budget anticipates drilling or participating in approximately 180 gross/100 net development wells, including approximately 30 non-operated wells, and includes on average four active rigs in the Uinta and two active rigs in the DJ. The budget also anticipates drilling at least five development wells in the Powder River Deep Oil Program. Uinta Basin, Utah Uinta Oil Program (Blacktail Ridge, Lake Canyon, East Bluebell and South Altamont) – The Company is currently running a four-rig program in the area and expects to drill approximately 80-85 gross/45-50 net operated wells in 2013, plus participate in approximately 8 wells operated by its partner in Lake Canyon. Substantially all wells are vertical development wells. The 2013 drilling program includes activity in each of the Company's positions across the basin, including Blacktail Ridge, Lake Canyon, South Altamont and East Bluebell, and includes testing 80-acre spacing in the Blacktail Ridge area. During 2012, the Company increased production from the area significantly, increasing 86% in the fourth quarter of 2012 compared with the fourth quarter of 2011. In addition, year-end reserves in the area increased 63% to 47 MMBoe. At December 31, 2012, the Company had an approximate 76% working interest in production from 226 gross wells. The working interests for wells in the 2013 program are expected to average 54% (or higher depending upon partner elections). As of year-end 2012, the Company had approximately 155,000 net acres (including acreage to be earned) in the program. West Tavaputs – Drilling in the area remains suspended due to low natural gas prices. Fourth quarter 2012 production was negatively affected by a fire at one of the Company's compressor stations in the area, with the majority of production back on-line by the start of the first quarter. At December 31, 2012, the Company had an approximate 96% working interest in production from 298 gross wells. The Company's acreage in the area, including acreage at the nearby Hornfrog prospect and other acreage that can be earned, is 71,000 gross and 53,000 net. The Company plans no drilling activity in the area in 2013, which will have a nominal effect on its lease position and is not expected to impact future drilling plans. Denver-Julesburg Basin, Colorado and Wyoming Wattenberg – In the rapidly growing DJ Basin program, the Company is currently running one rig with plans to add a second rig in the second quarter. The Company expects to drill approximately 65 gross/45 net operated wells in 2013, plus participate in approximately 20 wells operated by partners. The 2013 drilling planis primarily focused onhorizontal development drilling, targeting the B bench of the Niobrara formation. The Company initiated pad drilling in the second half of 2012 with three four-well pads. The wells were drilled on average to a vertical depth of approximately 6,400 feet plus a 4,000 foot lateral with an average of 18 fracture stimulation stages. One pad placed all four horizontal wells into the Niobrara B bench and the two additional pads drilled two wells into the Niobrara B and two wells into the Niobrara C benches. Results are encouraging to date, with 24-hour peak rates that averaged 742 Boe/d per well and 30-day average rates of 412 Boe/d per well. During 2012, the Company significantly increased production from the area, up 2.6 times in the fourth quarter of 2012 compared with the fourth quarter of 2011. The Company increased year-end reserves in the area by 82% to 12 MMBoe and estimated risked resources (see "Reserve and Resource Disclosure" below) in the area at 89 MMBoe with more than 1,000 associated drilling locations. At December 31, 2012, the Company had an approximate 74% working interest in production from 298 gross wells and held approximately 76,000 net acres in the program including approximately 39,700 in the Northeast Wattenberg where the Company plans to concentrate its 2013 drilling program. Piceance Basin, Colorado Gibson Gulch – Drilling in the area remains suspended as a result of low natural gas and NGL prices. In the fourth quarter of 2012, the Company closed on the sale of an 18% interest (which progresses to 26% in 2016) in Gibson Gulch. A portion of Gibson Gulch natural gas production is processed, at the election of the Company, exposing the Company to the benefits of NGL pricing. The incremental benefit to the Company-wide realized price from natural gas liquids was $0.82 per Mcfe in 2012 and $0.62 per Mcfe in the fourth quarter of 2012. Due to low current and anticipated pricing of ethane, the Company has elected to reject ethane in the processing of NGLs for the first quarter of 2013 and expects it may elect to reject ethane in future quarters of 2013. At December 31, 2012, the Company had an approximate 80% working interest in production from 955 gross wells in its Gibson Gulch program. The Company plans no drilling activity in the area in 2013, which will have no effect on its lease position, as 99% of the Company's net acreage is held by production. ADDITIONAL FINANCIAL INFORMATION Guidance The Company's 2013 guidance (please reference "Forward-Looking Statements" below) is as follows. As previously reported, the Company is committed to not increasing debt year-over-year and intends to fund its capital expenditure program with cash flow and property dispositions. The Company may update the following guidance as business conditions warrant: oCapital expenditures of $475 to $525 million. oOil and natural gas production of 83 to 87 Bcfe on a two-stream basis or oil, natural gas and NGL production of 86 to 90 Bcfe on a three-stream basis. The Company is targeting 50% to 55% growth in oil production in 2013 over 2012 and expects approximately 6% to 8% of production will be NGLs (assuming ethane rejection.) oLease operating costs of $62 to $67 million. oGathering, transportation and processing costs of $72 to $75 million. oGeneral and administrative expenses, before non-cash stock-based compensation costs, of $50 to $54 million. This range includes approximately $4 million for one-time charges associated with employee transition costs. Commodity Hedges Update It is the Company's strategy to hedge a portion of its production to reduce the risks associated with unpredictable future commodity prices and to provide predictability for a portion of cash flows in order to support the Company's capital expenditure program. For 2013 and 2014, the Company has hedges in place as outlined in the table below. Swap positions for natural gas and NGLs are tied to regional sales points and oil hedge positions are tied to WTI and include: oFor 2013, approximately 62.4 Bcfe, or approximately 70% of production, at a weighted average blended price of $7.57 per Mcfe. oFor 2014, approximately 32.8 Bcfe at a weighted average blended price of $7.05 per Mcfe. The following table summarizes hedge positions as of February 8, 2013: Natural Gas NGLs* Oil Volume Price Volume Price Volume Price Gallons Period MMBtu/d $/MMBtu $/Gal Bopd $/Bbl Qtr Total 1Q13 150.0 3.69 3,375,000 1.78 7,172 98.00 2Q13 127.5 3.74 3,375,000 1.78 7,500 98.01 3Q13 140.0 3.70 3,375,000 1.78 7,500 98.01 4Q13 123.4 3.72 3,375,000 1.78 7,500 98.01 1Q14 75.0 3.83 - - 3,600 95.99 2Q14 75.0 3.83 - - 3,600 95.99 3Q14 75.0 3.83 - - 3,600 95.99 4Q14 75.0 3.83 - - 3,600 95.99 *NGL volumes include propane, butanes and natural gasoline. No ethane volumes are hedged. 2012 RESULTS WEBCAST AND CONFERENCE CALL As previously announced, a webcast and conference call will be held tomorrow, February 22, 2013, to discuss 2012 results. Please join Bill Barrett Corporation executive management at 11:00 a.m. Eastern time/9:00 a.m. Mountain time for the live webcast, accessed at www.billbarrettcorp.com, or join by telephone by calling 800-215-2410 (617-597-5410 inter-national callers) with passcode 86881460. The webcast will remain available on the Company's website for approximately 30 days, and a replay of the call will be available through March 1, 2013 at call-in number 888-286-8010 (617-801-6888 international) with passcode 48429249. UPCOMING EVENTS Updated investor presentations will be posted to the homepage of the Company's website at www.billbarrettcorp.com for each event below. Webcast events will also be accessible on the homepage of the Company's website: Investor Conferences Chief Financial Officer Bob Howard will participate in investor meetings at the Simmons Thirteenth Annual Energy Conference on March 1, 2013. The presentation for this event will be posted at 5:00 p.m. Mountain time on Thursday, February 28, 2013. Chief Executive Officer Scot Woodall will present at the 41^st Annual Howard Weil Energy Conference on March 18, 2013 at 2:55 p.m. Central time. The event will not be webcast. The presentation for this event will be posted at 5:00 p.m. Mountain time on Friday, March 15, 2013. DISCLOSURE STATEMENTS Natural Gas Liquids Effective January 1, 2013, the Company intends to report its production volumes on a three-stream basis, which separately reports NGLs extracted from the natural gas stream and sold as a separate product. The NGL volumes identified by our gas purchasers are converted to an oil equivalent, based on 42 gallons per barrel and compared to overall gas equivalent production based on a 1 barrel to 6 Mcf ratio. Reserve and Resource Disclosure The SEC permits oil and gas companies to disclose proved, probable and possible reserves in their filings with the SEC. The Company does not plan to include probable and possible reserve estimates in its filings with the SEC. We may use certain terms in this release, such as "risked resources," that the SEC's guidelines strictly prohibit us from including in filings with the SEC. The calculation of risked resources, and any other estimates of reserves and resources that are not proved, probable or possible reserves are not necessarily calculated in accordance with SEC guidelines. Our estimate of risked resources is not prepared or reviewed by third party engineers, is determined using strip pricing, which we use internally for planning and budgeting purposes, and may differ from an un-risked estimate of proved, probable and possible reserves. The Company's estimate of risked resources is provided in this release because management believes it is useful, additional information that is widely used by the investment community in the valuation, comparison and analysis of companies; however, the Company's estimate of risked resources may not be comparable to similar metrics provided by other companies. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2012, available on the Company's website at www.billbarrettcorp.com or from the corporate offices at 1099 18th Street, Suite 2300, Denver, CO 80202. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or at www.sec.gov. Forward-Looking Statements This press release contains forward-looking statements, including statements regarding projected results and future events. In particular, the Company is providing "2013 guidance," which contains projections for certain 2013 operational and financial metrics. These forward-looking statements are based on management's judgment as of the date of this press release and include certain risks and uncertainties. Please refer to the Company's Annual Report on Form 10-K for the year ended December 31, 2012 filed with the SEC, and other filings including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, for a list of certain risk factors that may affect these forward-looking statements. The Company provided unaudited estimates of certain year-end financial results, which are subject to revision in our audited financial statements to be included in our Annual Report on Form 10-K for the year ended December 31, 2012. Actual results may differ materially from Company projections and can be affected by a variety of factors outside the control of the Company including, among other things: oil, NGL and natural gas price volatility; costs and availability of third party facilities for gathering, processing, refining and transportation; the ability to receive drilling and other permits and rights-of-way; regulatory approvals, including regulatory restrictions on federal lands; legislative or regulatory changes, including initiatives related to hydraulic fracturing; exploration risks such as drilling unsuccessful wells; higher than expected costs and expenses, including the availability and cost of services and materials; unexpected future capital expenditures; economic and competitive conditions; debt and equity market conditions, including the availability and costs of financing to fund the Company's operations; the ability to obtain industry partners to jointly explore certain prospects, and the willingness and ability of those partners to meet capital obligations when requested; declines in the values of our oil and gas properties resulting in impairments; changes in estimates of proved reserves; development drilling and testing results; the potential for production decline rates to be greater than we expect; performance of acquired properties; compliance with environmental and other regulations; derivative and hedging activities; risks associated with operating in one major geographic area; the success of the Company's risk management activities; title to properties; litigation; environmental liabilities; and, other factors discussed in the Company's reports filed with the SEC. Bill Barrett Corporation encourages readers to consider the risks and uncertainties associated with projections and other forward-looking statements. In addition, the Company assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances. ABOUT BILL BARRETT CORPORATION Bill Barrett Corporation (NYSE: BBG), headquartered in Denver, Colorado, explores for and develops natural gas and oil in the Rocky Mountain region of the United States. Additional information about the Company may be found on its website www.billbarrettcorp.com. BILL BARRETT CORPORATION Selected Operating Highlights (Unaudited) Three Months Ended Twelve Months Ended December 31, December 31, 2012 2011 2012 2011 Production Data: Natural gas (MMcf) 23,070 26,260 101,486 97,856 Oil (MBbls) 857 466 2,687 1,490 Combined volumes (MMcfe) 28,212 29,056 117,608 106,796 Daily combined volumes 307 316 321 293 (Mmcfe/d) Average Prices (before the effects of realized hedges): Natural gas (per Mcf) (1) $ $ $ $ 4.56 5.44 4.00 5.71 Oil (per Bbl) 75.03 81.57 79.39 81.97 Combined (per Mcfe) 6.01 6.23 5.27 6.37 Average Realized Prices (after the effects of realized hedges): Natural gas (per Mcf) (1) $ $ $ $ 5.18 6.26 5.07 6.46 Oil (per Bbl) 83.84 81.48 84.96 80.63 Combined (per Mcfe) 6.78 6.96 6.32 7.05 Average Costs (per Mcfe): Lease operating expense $ $ $ $ 0.64 0.54 0.62 0.53 Gathering, transportation and 0.94 0.94 0.91 0.87 processing expense Production tax expense 0.15 0.28 0.22 0.35 Depreciation, depletion and (3) 3.32 2.68 2.91 2.70 amortization General and administrative expense,excluding non-cash (2) 0.47 0.39 0.44 0.45 stock-based compensation (1) Natural gas average prices include the effect of NGL revenues. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion (2) provides a better understanding of cash required for general and administrative expenses. Management also believes that this disclosure may allow for a more accurate comparison to the Company's peers that may have higher or lower costs associated with equity grants. The calculation of the per unit DD&A rate for the fourth quarter of 2012 (3) is adjusted to reflect the fourth quarter asset sale. The assets were excluded from the overall corporate depletion pool, and the per unit calculation adjusts the production accordingly. BILL BARRETT CORPORATION Consolidated Statements of Operations (Unaudited) Three Months Ended Twelve Months Ended December 31, December 31, 2012 2011 2012 2011 (in thousands, except per share amounts) Operating and Other Revenues: Oil and gas (1) $ $ $ $ production 184,083 207,615 700,639 780,751 Other (4,282) 845 (444) 4,873 Total operating and 179,801 208,460 700,195 785,624 other revenues Operating Expenses: Lease operating 18,063 15,546 72,734 56,603 Gathering, transportation and 26,609 27,318 106,548 93,423 processing Production tax 4,320 8,205 25,513 37,498 Exploration 751 1,043 8,814 3,645 Impairment, dry hole costs and 7,690 99,036 67,869 117,599 abandonment Depreciation, depletion and 75,425 78,015 326,842 288,421 amortization General and (2) 13,196 11,195 52,222 47,744 administrative Non-cash stock-based (2) 4,029 5,337 16,444 19,036 compensation Total operating 150,083 245,695 676,986 663,969 expenses Operating Income/ (Loss) 29,718 (37,235) 23,209 121,655 Other Income and Expense: Interest income and other income 27 (560) 1,756 (397) (expense) Interest expense (25,477) (20,238) (95,506) (58,616) Commodity derivative (1) 19,328 (1,529) 72,759 (14,263) gain (loss) Total other income (6,122) (22,327) (20,991) (73,276) and expense Income (Loss) before 23,596 (59,562) 2,218 48,379 Income Taxes Provision for (Benefit 9,579 (21,782) 1,636 17,672 from) Income Taxes $ $ $ $ Net Income (Loss) 14,017 (37,780) 582 30,707 Net Income (Loss) Per Common Share $ $ $ $ Basic 0.30 (0.81) 0.01 0.66 $ $ $ $ Diluted 0.30 (0.81) 0.01 0.65 Weighted Average Common Shares Outstanding Basic 47,260 46,888 47,195 46,536 Diluted 47,358 46,888 47,354 47,237 The table below summarizes the realized and unrealized gains and losses (1) the Company recognized related to its oil and natural gas derivative instruments for the periods indicated: Three Months Ended Twelve Months Ended December 31, December 31, 2012 2011 2012 2011 Included in oil and gas production revenue: Certain realized $ $ $ $ gains on hedges 14,514 26,699 81,166 99,922 Included in commodity derivative gain (loss): Realized gain (loss) $ $ $ $ on derivatives not designated as cash 7,291 (5,349) 42,305 (28,054) flow hedges Unrealized ineffectiveness gain (loss) recognized on - (6) - 1,026 derivatives designated as cash flow hedges Unrealized gain on derivatives not 12,037 3,826 30,454 12,765 designated as cash flow hedges Total commodity $ derivative gain $ 19,328 $ (1,529) $ 72,759 (14,263) (loss) Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion (2) provides a better understanding of cash required for general and administrative expenses. Management also believes that this disclosure may allow for a more accurate comparison to the Company's peers that may have higher or lower costs associated with equity grants. BILL BARRETT CORPORATION Consolidated Condensed Balance Sheets (Unaudited) As of As of December 31, 2012 December 31, 2011 (in thousands) Assets: Cash and cash equivalents $ $ 79,445 57,331 Other current assets (1) 148,894 189,012 Property and equipment, net 2,611,337 2,406,764 Other noncurrent assets (1) 29,773 34,823 Total assets $ $ 2,869,449 2,687,930 Liabilities and Stockholders' Equity: Current liabilities (1) $ $ 213,133 233,198 Notes payable to bank - 70,000 Capital lease 88,519 - Senior notes 1,042,791 641,198 Convertible senior notes 25,344 171,042 Other long-term (1) 316,887 353,654 liabilities Stockholders' equity 1,182,775 1,218,838 Total liabilities and $ $ stockholders' equity 2,869,449 2,687,930 At December 31, 2012, the estimated fair value of all of our commodity derivative instruments was a net asset of $32.6 million, comprised of: (1) $30.0 million current assets; $3.0 million non-current assets; and $0.4 million non-current liabilities. This amount will fluctuate quarterly based on estimated future commodity prices and the current hedge position. BILL BARRETT CORPORATION Consolidated Statements of Cash Flows (Unaudited) Three Months Ended Twelve Months Ended December 31, December 31, 2012 2011 2012 2011 (in thousands) Operating Activities: Net income (loss) $ $ $ $ 14,017 (37,780) 582 30,707 Adjustments to reconcile to net cashprovided by operations: Depreciation, depletion 75,425 78,015 326,842 288,421 and amortization Impairment, dry hole costs and abandonment 7,690 99,036 67,869 117,599 expense Unrealized derivative (12,037) (3,820) (30,454) (13,791) (gain)\loss Deferred income taxes 7,484 (21,782) (217) 17,688 Stock compensation and 4,047 5,995 16,727 21,953 other non-cash charges Amortization of debt discounts and deferred 1,715 4,037 8,425 13,886 financing costs Loss (gain) on sale of 4,387 54 4,279 (1,955) properties Change in assets and liabilities: Accounts receivable (14,986) (12,901) (10,511) (27,680) Prepayments and (222) (808) 1,293 1,809 other assets Accounts payable, accrued and other 7,402 36,683 2,589 24,531 liabilities Amounts payable to oil & gas property 3,421 (11,771) 3,988 (4,010) owners Production taxes (510) 417 (2,976) 10,190 payable Net cash provided by $ $ $ $ operating activities 97,833 135,375 388,436 479,348 Investing Activities: Additions to oil and gas properties, including (207,109) (245,809) (958,654) (947,206) acquisitions Additions of furniture, (1,712) (5,384) (7,231) (11,142) equipment and other Proceeds from sale of properties and other 328,797 (102) 328,888 1,702 investing activities Net cash provided by $ $ $ $ (used in) investing 119,976 (251,295) (636,997) (956,646) activities Financing Activities: Proceeds from debt 90,000 70,000 875,826 800,000 Principal payments on (252,223) - (595,386) (330,000) debt Deferred financing costs (74) (5,224) (10,438) (16,308) and other Proceeds from stock - 3,256 673 22,247 option exercises Net cash provided by $ $ $ $ (used in) financing (162,297) 68,032 270,675 475,939 activities Increase (Decrease) in 55,512 (47,888) 22,114 (1,359) Cash and Cash Equivalents Beginning Cash and Cash 23,933 105,219 57,331 58,690 Equivalents Ending Cash and Cash $ $ $ $ Equivalents 79,445 57,331 79,445 57,331 BILL BARRETT CORPORATION Reconciliation of Discretionary Cash Flow & Adjusted Net Income (Unaudited) Discretionary Cash Flow Reconciliation Three Months Ended Twelve Months Ended December 31, December 31, 2012 2011 2012 2011 (in thousands, except per share amounts) $ $ $ $ Net Income (Loss) 14,017 (37,780) 30,707 582 Adjustments to reconcile to discretionary cash flow: Depreciation, depletion 75,425 78,015 326,842 288,421 and amortization Impairment, dry hole and 7,690 99,036 67,869 117,599 abandonment expense Exploration expense 751 1,043 8,814 3,645 Unrealized derivative (12,037) (3,820) (30,454) (13,791) (gain)/loss Deferred income taxes 7,484 (21,782) (217) 17,688 Stock compensation and 4,047 5,995 18,328 21,953 other non-cash charges Amortization of debt discounts and deferred 1,715 4,037 8,425 13,886 financing costs Gain on extinguishment of - - (1,601) - debt Loss (gain) on sale of 4,387 54 4,279 (1,955) properties Discretionary Cash Flow $ $ $ $ 103,479 124,798 402,867 478,153 $ $ $ $ Per share, diluted 2.19 2.66 8.51 10.12 $ $ $ $ Per Mcfe 3.67 4.30 3.43 4.48 Adjusted Net Income (Loss) Reconciliation Three Months Ended Twelve Months Ended December 31, December 31, 2012 2011 2012 2011 (in thousands except per share amounts) $ $ $ $ Net Income (Loss) 14,017 (37,780) 30,707 582 Adjustments to net income (loss): Unrealized derivative (12,037) (3,820) (30,454) (13,791) (gain)/loss Impairment expense 239 96,399 37,348 100,278 Loss (gain) on sale of 4,387 54 4,279 (1,955) properties One time items: Gain on extinguishment of - - (1,601) - debt Subtotal Adjustments (7,411) 92,633 9,572 84,532 Effective tax rate 41% 37% 34% (1) 37% Tax effected adjustments (4,372) 58,359 6,327 53,255 $ $ $ $ Adjusted Net Income 9,645 20,579 83,962 6,909 $ $ $ $ Per share, diluted 0.20 0.44 0.15 1.78 $ $ $ $ Per Mcfe 0.34 0.71 0.06 0.79 (1) The annualized rate was adjusted to a weighted rate so that the four quarters would sum. The non-GAAP (Generally Accepted Accounting Principles in the United States of America) measures of discretionary cash flow and adjusted net income are presented because management believes that they provide useful additional information to investors for analysis of the Company's ability to internally generate funds for exploration, development and acquisitions as well as adjusting net income for unusual items to allow for a more consistent comparison from period to period. In addition, these measures are widely used by professional research analysts and others in the valuation, comparison and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. These measures should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, profitability, cash flow or liquidity measures prepared in accordance with GAAP. Because discretionary cash flow and adjusted net income exclude some, but not all, items that affect net income and net cash provided by operating activities and may vary among companies, the amounts presented may not be comparable to similarly titled measures of other companies. BILL BARRETT CORPORATION Costs Incurred and Reserve Information (Unaudited) 2012 2011 2010 ($ in millions) TOTAL CAPITAL EXPENDITURES $ $ $ 962.6 987.3 473.3 Furniture, fixtures and equipment (6.9) (10.6) (3.8) and real estate Change in asset retirement 8.3 12.1 1.3 obligation TOTAL COSTS INCURRED (1) $ $ $ 964.0 988.8 470.8 TOTAL COSTS INCURRED DISCLOSURE Exploration costs 32.5 20.8 $ 82.8 Development costs 754.2 607.7 358.3 Acquisition costs: Unproved properties 163.0 183.4 25.2 Proved properties 6.0 164.8 3.2 Change in asset retirement 8.3 12.1 1.3 obligation TOTAL COSTS INCURRED (1) 964.0 988.8 470.8 less: asset retirement (8.3) (12.1) (1.3) obligation less: (Proceeds)/adjusted - - 1.5 proceeds received from JV partners less: Capitalized interest (0.5) (1.4) (4.2) Adjusted costs incurred $ $ $ 955.2 975.3 466.8 RESERVE ADDITIONS (Bcfe) Extensions, discoveries and other 187.3 211.4 185.1 additions Revisions of previous estimates (44.0) 37.9 39.8 based on performance Revisions of previous estimates (129.2) 5.5 27.4 based on price or aging Purchases of reserves in place 1.8 98.3 1.4 RESERVE ADDITIONS Bcfe 15.9 353.1 253.7 RESERVE ADDITIONS MMBoe 2.7 58.9 42.3 SALES INFORMATION Property sales $ $ $ 329.0 2.0 4.4 Sales of reserves (Bcfe) 219.3 - 3.7 (1) Costs Incurred is a defined capital expenditure used in the discussion of proved reserves in the Company's Form 10-K for the years indicated. SOURCE Bill Barrett Corporation Website: http://www.billbarrettcorp.com Contact: Jennifer Martin, Vice President of Investor Relations, +1-303-312-8155
Bill Barrett Corporation Reports 2012 Financial and Operating Results and Announces Strong Initial Oil Rates on All Four-Well
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