Noble Energy Announces Fourth Quarter and Full Year 2011 Results, Including Record Sales Volumes and Proved Reserves (NYSE: NBL) reported today a fourth quarter 2011 net loss of $296 million, or $1.67 per share diluted, on revenues of $985 million. Results for the quarter included an asset impairment charge and an unrealized commodity derivatives loss. Excluding these items, fourth quarter adjusted net income (1) was $211 million, or $1.18 per share diluted. The Company reported net income of $52 million during the final quarter of 2010, or $0.29 per share diluted, on revenues of $783 million. Adjusted net income (1) for the fourth quarter of 2010 was $185 million, or $1.04 per share diluted. Discretionary cash flow (1) for the fourth quarter 2011 was $677 million compared to $538 million for the similar quarter in 2010. Net cash provided by operating activities was $385 million, compared to $494 million, and capital expenditures (2) were $1.0 billion. Key highlights for the fourth quarter of 2011 include: Record sales volume of 233 thousand barrels of oil equivalent per day (MBoe/d) and 222 MBoe/d for the year Increased DJ Basin volumes to 66 MBoe/d with horizontal production exiting the quarter at 17 MBoe/d, a 48 percent increase over the prior quarter exit rate Produced 74 million cubic feet per day (MMcf/d) net in the Marcellus Joint Venture (JV) Started up the Aseng oil project offshore Equatorial Guinea, and exited the year producing 19 thousand barrels of oil per day (MBbl/d) net Announced a world-class discovery offshore Cyprus with a gross mean resource estimate of seven trillion cubic feet (Tcf) Successfully appraised the Leviathan discovery offshore Israel resulting in an increase in the gross mean resource estimate to 17 Tcf or 6 Tcf net Recorded year-end proved reserves of 1.2 billion barrels of oil equivalent (BBoe), up 11 percent from 2010 Further strengthened the balance sheet through an upsized $3 billion credit facility and issuance of $1 billion 10-year bonds resulting in year-end liquidity of approximately $4.5 billion Noble Energy reported full year 2011 net income of $453 million, or $2.54 per share diluted, compared to net income of $725 million, or $4.10 per share diluted, in 2010. Adjusted net income (1) for 2011 was $947 million, or $5.31 per share diluted, up from $746 million, or $4.22 per share diluted, in 2010. Discretionary cash flow (1) was $2.5 billion for the year, up 26 percent from 2010, and net cash provided by operating activities for the year was $2.2 billion, up 12 percent from 2010. Total year capital expenditures (2) were $3.0 billion. Charles D. Davidson, Noble Energy's Chairman and CEO, commented, "Noble Energy closed out 2011 with record production for the fourth quarter while significantly progressing our inventory of major projects. First production was reached at Aseng offshore Equatorial Guinea seven months ahead of schedule and 13 percent below budget. We are positioned to deliver production from Galapagos and South Raton in the Gulf of Mexico in the first half of 2012. We continue to mature our Eastern Mediterranean portfolio, where the development at Tamar is progressing on schedule and on budget and the recent appraisal drilling at Leviathan has increased the estimated resources of the field. The discovery at Cyprus, along with the Tanin discovery announced this week, increased gross estimated mean resources discovered in the Levant Basin to approximately 35 Tcf. Balancing our growing international portfolio are two lower-risk onshore U.S. developments. Production out of the DJ Basin continues to grow led by the horizontal program which completed 25 wells in the fourth quarter. The Marcellus JV is growing production, and we began to operate our first rig in early 2012 in the wet gas portion of the acreage. Financially, we have increased our liquidity position to support our major project developments. We are exceptionally well positioned for continued growth and delivery of value to our shareholders. Fourth quarter 2011 sales volumes averaged 233 MBoe/d, up eight percent from the fourth quarter 2010 excluding volumes from Ecuador, which we exited in 2011. The sales volume split for the fourth quarter 2011 was 40 percent liquids, 29 percent international natural gas, and 31 percent U.S. natural gas. Noble Energy's U.S. volumes totaled 127 MBoe/d for the fourth quarter 2011, up seven percent from the same quarter last year. The increase was attributed to the addition of the Marcellus JV and continued growth in the horizontal Niobrara play in the DJ Basin. Natural production declines were experienced in the deepwater Gulf of Mexico and various onshore natural gas properties. Sales volume from the Company's international assets was 106 MBoe/d for the final quarter of 2011, an increase of eight percent from the fourth quarter of 2010 excluding volumes from Ecuador. The increase was due to the early startup of the Aseng oil project offshore Equatorial Guinea and higher sales from the Mari-B field which continued to produce at high levels to satisfy Israeli natural gas demand. Crude oil and condensate prices were up significantly from the fourth quarter of 2010. Noble Energy's global crude oil price averaged $101.12 per barrel, up 22 percent versus the fourth quarter 2010. Natural gas realizations in the U.S. averaged $3.42 per thousand cubic feet (Mcf) and in Israel averaged $5.10 per Mcf. Natural gas liquid pricing in the U.S. averaged $46.11 per barrel for the quarter, representing 48 percent of the Company's average U.S. crude oil realization. Total production costs per barrel of oil equivalent (Boe), including lease operating expense (LOE), production and ad valorem taxes, and transportation were $7.88 per Boe, up 13 percent from the last quarter of 2010. LOE and depreciation, depletion, and amortization (DD&A) per Boe were $5.08 and $13.20, respectively. The unit rates were impacted by the Company's mix of sales volumes, particularly with the startup of Aseng offshore Equatorial Guinea and the increased production from the DJ Basin. Production and ad valorem taxes reflected stronger liquid commodity prices and higher volumes. Exploration expense for the fourth quarter 2011 was $85 million, which included costs associated with the Bwabe dry hole offshore Cameroon. The Company's adjusted effective tax rate for the fourth quarter 2011 was 33 percent, with 43 percent deferred. The Company recorded a $620 million asset impairment related to onshore U.S. dry natural gas properties, primarily in the Piceance Basin, as a result of declining natural gas prices. Other operating expenses of $41 million were mostly due to costs associated with disposition of surplus inventory and expected legal settlements. Non-operating expenses included a $22 million deferred compensation charge associated with the quarterly value change of Noble Energy stock held in a benefit program. Estimated reserves at the end of 2011 were approximately 1.2 BBoe, up 11 percent from 2010. Reserves in the U.S. accounted for 47 percent of the total, with International the remaining 53 percent. Reserves are split 31 percent global liquids, 42 percent international natural gas, and 27 percent U.S. natural gas. Noble Energy added total proved reserves of 198 million barrels of oil equivalent (MMBoe) in 2011, including revisions. These additions replaced 244 percent of 2011 production. U.S. net additions of 120 MMBoe resulted in 279 percent replacement of U.S. production and were driven by the acquisition of the Company's Marcellus JV and the horizontal drilling program in the DJ Basin. These net additions included negative revisions of 45 MMBoe primarily associated with the reduction of undeveloped vertical locations in the DJ Basin as the Company continues to transition rigs to horizontal drilling and reduced activity levels in dry gas fields due to lower natural gas prices. The international portfolio added net 78 MMBoe of reserves, or 205 percent replacement of international production, with 80 MMBoe of additions from the successful appraisal drilling results at Tamar offset slightly by revisions in non-core areas. A Non-GAAP measure, see attached Reconciliation Schedules Capital expenditures for the fourth quarter and full year 2011 exclude a non-cash accrual related to construction progress to date on the Aseng FPSO and the Marcellus acquisition. Conference call numbers for participation are 888-299-7208 and 719-325-2149. This news release contains certain non-GAAP measures of financial performance that management believes are good tools for internal use and the investment community in evaluating the company's overall financial performance. These non-GAAP measures help facilitate comparison of company operating performance across periods and with peer companies. Forward-looking statements are not statements of historical fact and reflect Noble Energy's current views about future events. We use certain terms in this news release, such as "estimated resources," "gross estimated resource," and "gross mean resource estimate." Schedule 1 Noble Energy, Inc. Reconciliation of Net Income (Loss) to Adjusted Earnings in millions, except per share amounts, unaudited Per Diluted Share [6] Per Diluted Share Unrealized (gains) losses on commodity derivative instruments Asset impairments [1] (Gain) loss on divestitures [2] Drilling rig expense [3] Other adjustments Total Adjustments before tax Income Tax Effect of Adjustments [4] Adjusted Earnings [5] Weighted average number of shares outstanding Diluted [6] [1] Impairments for 2011 related to our Piceance, Tri-State, East Texas, and Iron Horse developments, all onshore US assets, due to a significant decline in the natural gas prices, specifically during fourth quarter of 2011. Impairments for 2010 related to our Iron Horse development, an onshore US area, our non-core New Albany Shale assets, our investment in the Noa/Noa South development, offshore Israel and certain other Gulf of Mexico assets. [2] Gain on divestitures in 2011 relates to the transfer of assets and exit from Ecuador and in 2010 relates to the sale of non-core US onshore assets. [3] Amount for 2011 represents stand-by rig expense incurred prior to receiving permit to resume drilling activities in the deepwater Gulf of Mexico. Amount for 2010 represents costs to terminate a deepwater Gulf of Mexico drilling rig contract due to the Federal Deepwater Moratorium. [4] The net tax effects are determined by calculating the tax provision for GAAP Net Income, which includes the adjusting items, and comparing the results to the tax provision for Adjusted Earnings, which excludes the adjusting items. The difference in the tax provision calculations represents the tax impact of the adjusting items listed here. The calculation is performed at the end of each quarter and, as a result, the tax rates for each discrete period may be different. [5] Adjusted earnings should not be considered a substitute for net income (loss) as reported in accordance with GAAP. Adjusted earnings is provided for comparison to earnings forecasts prepared by analysts and other third parties. Our management believes, and certain investors may find, that adjusted earnings is beneficial in evaluating our financial performance as it excludes the impact of significant non-cash items. We believe such measures can facilitate comparisons of operating performance between periods and with our peers. [6] The diluted weighted average number of shares outstanding used to calculate "Adjusted Earnings Per Diluted Share" for the three months ended December 31, 2011 was 179 million shares. Schedule 2 Summary Statement of Operations Crude oil and condensate Income from equity method investees Lease operating expense Production and Ad Valorem taxes Transportation expense Exploration expense (Gain) loss on divestitures Other operating expense, net Other (Income) Expense (Gain) loss on commodity derivative instruments Interest, net of amount capitalized Other expense (income), net Total other (income) expense Income (Loss) Before Taxes Income Tax Provision (Benefit) Earnings (Loss) Per Share, Basic Earnings (Loss) Per Share, Diluted Weighted Average Number of Shares Outstanding, Basic Weighted Average Number of Shares Outstanding, Diluted Schedule 3 Volume and Price Statistics Crude Oil and Condensate Sales Volumes (MBbl/d) Total consolidated operations Equity method investee Total sales volumes Crude Oil and Condensate Realized Prices ($/Bbl) Consolidated average realized prices Natural Gas Sales Volumes (MMcf/d) Ecuador Natural Gas Realized Prices ($/Mcf) Average realized prices Natural Gas Liquids (NGL) Sales Volumes (MBbl/d) Natural Gas Liquids Realized Prices ($/Bbl) Barrels of Oil Equivalent Volumes (MBoe/d) Total barrels of oil equivalent (Mboe/d) Barrels of oil equivalent volumes (MMBoe) Schedule 4 Condensed Balance Sheets Accounts payable - trade Total Shareholders" Equity Total Liabilities and Shareholders" Equity Schedule 5 Discretionary Cash Flow and Reconciliation to Operating Cash Flow in millions, unaudited Adjusted Earnings [1] Adjustments to reconcile adjusted earnings to discretionary cash flow: (Income) /distributions from equity method investments, net Deferred compensation (income) expense Discretionary Cash Flow [2] Reconciliation to Operating Cash Flows Net changes in working capital Cash exploration costs Current tax expense of earnings adjustments Stand-by rig expense [3] Net Cash Provided by Operating Activities Capital expenditures (accrual based) Increase in FPSO lease obligation Marcellus Shale Asset Acquisition [4] DJ Basin Asset Acquisition Total Capital Expenditures (Accrual Based) Proceeds from Divestitures [1] See Schedule 1, Reconciliation of Net Income to Adjusted Earnings. [2] The table above reconciles discretionary cash flow to net cash provided by operating activities. Adjustments for capitalized interest were retrospectively removed from our discretionary cash flow calculation as of March 31, 2011. While discretionary cash flow is not a GAAP measure of financial performance, our management believes it is a useful tool for evaluating our overall financial performance. Among our management, research analysts, portfolio managers and investors, discretionary cash flow is broadly used as an indicator of a company's ability to fund exploration and production activities and meet financial obligations. Discretionary cash flow is also commonly used as a basis to value and compare companies in the oil and gas industry. Amount for 2010 represents costs to terminate a deepwater Gulf of Mexico drilling rig contract due to the Federal Deepwater Moratorium [4] Year ended December 31, 2011, includes $69 million representing our initial investment in CONE Gathering LLC. Schedule 6 Effect of Commodity Derivative Instruments Reclassification from Accumulated Other Comprehensive Loss (AOCL) to Revenue [1] Crude Oil Natural Gas Total Revenue Decrease (Gain) Loss on Commodity Derivative Instruments Realized Unrealized Total crude oil Total natural gas Total (Gain) Loss on Commodity Derivative Instruments Summary of Cash Settlements Realized (gain) on commodity derivative instruments Amounts reclassified from AOCL Cash settlements (received) paid [1] The amounts reclassified from AOCL represented deferred unrealized hedge gains and losses. All hedge gains or losses had been reclassified to revenues by December 31, 2010. Schedule 7 Supplemental Data 2011 Costs Incurred in Oil and Gas Activities Int'l [1] Property acquisition costs Proved Unproved Total acquisition costs Exploration costs Development costs [2] Subtotal costs incurred Increase in FPSO Lease Obligation Total costs incurred Reconciliation to Capital Spending (accrual basis) Exploration overhead Lease rentals Total oil and gas spending CONE LLC Investment Other capital Total capital spending (accrual basis) Proved Reserves [4] Int'l [3] Total Barrel Oil Equivalents (MMBoe) Beginning reserves - December 31, 2010 Revisions of previous estimates Extensions, discoveries and other additions Purchase of minerals in place Sale of minerals in place Production Ending reserves - December 31, 2011 Proved Developed Reserves (MMBoe) [1] International includes Equatorial Guinea, Israel, Cameroon, Cyprus, Senegal, Guinea-Bissau, North Sea, China, France and Nicaragua. [2] Includes ARO costs of $115 million for United States and $13 million for Int'l. [3] International includes Equatorial Guinea, Israel, North Sea and China. [4] Netherland, Sewell & Associates, Inc. performed an audit of approximately 90% of Noble Energy's year-end 2011 total proved reserves and concluded the Company's estimates of proved reserves, in the aggregate, are reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. SOURCE Noble Energy