Whiting Petroleum Corporation. Third Quarter 2006 Financial and Operating Results October 31, 2006

Transcription

1 Whiting Petroleum Corporation Third Quarter 2006 Financial and Operating Results October 31,

2 Forward-Looking Statement Disclosure and Non-GAAP Measures This presentation includes forward-looking statements that the Company believes to be forwardlooking statements within the meaning of the Private Securities Litigation Reform Act of All statements other than statements of historical fact included in this presentation are forward-looking statements. These forward-looking statements are subject to risks, uncertainties, assumptions and other factors, many of which are beyond the control of the Company. Important factors that could cause actual results to differ materially from those expressed or implied by the forward-looking statements include the Company s business strategy, reserves, technology, financial strategy, realized oil and natural gas prices, production, the Company s ability to successfully integrate acquired properties, unforeseen underperformance of or liabilities associated with acquired properties, drilling of wells, uncertainty regarding the Company s future operating results and plans, objectives, expectations and intentions and other factors described in the Company s Form 10-K for the year ended December 31, 2005 and the Company s Form 10-Q for the three and nine months ended September 30, In this presentation, we refer to EBITDAX and Discretionary Cash Flow, both of which are non-gaap measures that we believe are helpful in evaluating the performance of our business. A reconciliation of EBITDAX and Discretionary Cash Flow to relevant GAAP measures can be found at the end of the presentation. Contact: John Kelso Director of Investor Relations Whiting Petroleum Corporation 1700 Broadway, Suite 2300 Denver, Colorado (303)

3 Company Overview Market Capitalization 1 $1.65 B Long-term Debt 2 Fully Diluted Shares $945.2 MM MM Debt/Total Cap % Proved reserves MMBOE % Oil 76% RP ratio 4 Sept Production 17 years 42.5 MBOE/d Big Horn Basin, Wyoming - Continental Government Buffalo #3 1 Assumes a $44.59 share price (closing price as of October 25, 2006) on 36,948,618 shares. 2 Debt outstanding as of September 30, Refer to Total Capitalization slide for details. 3 Whiting reserves as of December 31, 2005 based on independent engineering reports. 4 Based on September 2006 production. 2

4 Growth In Production Average Daily Production Per Quarter 33% Increase in 2005 (in MBOE/d) st Qtr 2nd Qtr 3rd Qtr 4th Qtr

5 Growth In Production Production Per Share Per Quarter (in BOE) (3) (1) % Increase in 2005 (1) (3) (4) (1) (2) st Qtr 2nd Qtr 3rd Qtr 4th Qtr (1) (2) (3) (4) Based on weighted average shares of 29.6 million Based on weighted average shares of 36.5 million Based on weighted average shares of 36.7 million Based on weighted average shares of 36.8 million

6 Growth In Reserves Total Reserves and Reserves Per Share Reserves (MMBOE) IPO % Increase 47% Increase Reserves (BOE/share) 11/19/ (1) (2) (3) (1) Based on year-end outstanding shares of 18.8 million Based on year-end outstanding shares of 29.6 million Based on year-end outstanding shares of 36.8 million (2 (3) 0.0 5

7 Reserve & Production Profiles Proved Reserves As of Dec. 31, MMBOE Proved Reserves By Core Area 21% 6% 23% Daily Production By Core Area Sept MBOE/d 8% 13% 31% 41% 11% 59% 39% 17% Developed Undeveloped Rocky Mountains Gulf Coast Michigan 31% Permian Basin Mid-Continent Based on September 2006 Production, Whiting Has a 17 Year R/P Ratio 6

8 Earnings Growth Net Income Per Quarter $50.0 $45.9 $49.5 $40.0 $33.0 $33.3 $38.3 in Millions $30.0 $20.0 $26.1 $24.2 $10.0 $0.0 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr

9 Growing Levels of Cash Flow Discretionary Cash Flow Per Quarter (1) $150.0 $125.0 $119.4 $126.7 $109.9 in Millions $100.0 $75.0 $50.0 $96.3 $64.6 $65.3 $79.5 $25.0 $0.0 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr (1) Please refer to Slide #18 and #19 Reconciliation of Net Cash Provided by Operating Activities. 8

10 Growing Levels of Cash Flow EBITDAX (1) $ in Millions $ in Millions $400.0 $300.0 $200.0 $100.0 $0.0 $400.0 $300.0 $200.0 $100.0 $352.4 $384.1 $184.2 $ Mos 06 Cash Flow From Operations $351.9 $330.4 $135.5 $96.4 $ Mos 06 (1) Please refer to Slide #17 EBITDAX Reconciliation 9

11 Total Capitalization ($ in thousands) As of September 30, 2006 Cash and Cash Equivalent $ 3,750 Long-Term Debt 945,169 Stockholders Equity 1,155,612 Total Capitalization $ 2,104,531 Total Debt/Capitalization 44.9% 10

12 Conservative Approach to Leverage Total Debt/Book Capitalization Total Debt/EBITDAX (1) % 35% 47% 45% 5.0x 4.0x 3.0x 2.0x 1.9x 1.8x 2.5x 1.8x x /30/ x /30/2006 EBITDAX & Total Interest Expense Coverage $300.0 $200.0 $100.0 $ x 11.6x 8.4x 7.1x $352.4 $384.1 $184.2 $100.3 $9.2 $15.9 $42.0 $ st 9Mos 06 EBITDAX (1) Annualized based on first nine months 2006 total. Total Interest Expense 11

13 Consistently Strong Margins Consistently Delivering Strong EBITDA Margins (1) $45.00 $44.70 $52.07 Whiting Realized Prices (1) $/BOE $35.00 $25.00 $15.00 $5.00 $27.50 $16.22/59% 2% 7% 6% 25% $35.23 $22.91/65% 2% 7% 20% 6% $28.73/64% 3% 6% 7% 21% $33.25/64% Mos 06 Lease Operating Expense Production Taxes G&A Exploration Expense EBITDA 3% 5% 6% 23% (1) Includes hedging adjustments. 12

14 Disciplined Hedging Strategy Utilize hedges to manage exposure against potential commodity price declines while maintaining pricing upside Employ mix of contracts weighted toward the short-term Existing Hedge Positions (1) Period Hedged Volumes (MMBtu)/(Bbl) per Month % of Gas/Oil Volume During Sept Weighted Average Hedge Price Range ($/MMBtu)/($/Bbl) Q ,600,000 / 450,000 62% / 55% / Q ,600,000 / 450,000 62% / 55% / Q / 410,000 0% / 50% 0-0 / Q / 410,000 0% / 50% 0-0 / Q / 410,000 0% / 50% 0-0 / Q / 110,000 0% / 13% 0-0 / Q / 110,000 0% / 13% 0-0 / Q / 110,000 0% / 13% 0-0 / Q / 110,000 0% / 13% 0-0 / (1) As of October 16, Note: Table does not include two fixed price contracts: 51,000 MMBtu per month through 12/2011 at $4.57 per MMBtu with 4% annual escalator. 60,000 MMBtu per month through 12/2012 at $4.05 per MMBtu with 4% annual escalator. 13

15 2006 Capital Expenditures by Region 2006 Estimated Capex by Region $420 MM - $440 MM Total 2006 Gross Wells by Region 430 Total Estimated 20% 28% 5% 17% % % 42% 62% Rocky Mountains Gulf Coast Permian Basin Mid-Continent/Michigan 14

16 Postle and North Ward Estes Fields Build in Core Areas Acquired Total Whiting Properties Whiting % Postle/NWE (1) 12/31/05 Proved Reserves Oil - MMBbl % Gas - Bcf % Total - MMBOE % MID- CONTINENT % Crude Oil 59% 93% 76% Sept Production Total - MBOE/d % Existing Whiting Properties PERMIAN ROCKY MOUNTAINS Headquarters PERMIAN MID- MICHIGAN CONTINENT GULF COAST Field Office Whiting Properties North Ward Estes & Ancillary Fields Postle Field Postle and North Ward Estes Fields Complement Whiting s Core Areas (1) Based on independent engineering reports. 15

17 Exploration Projects Central Rockies PICEANCE BASIN Sulphur Creek Area Continuous phase gas in Williams Fork 2.0 to 2.5 Bcf per well Drilling costs: $2.9 MM per well (with stimulation) 170 gross (85 net) locations on 20-acre spacing (primarily fee acreage) 3 wells planned for 2006 and 13 in

18 Exploration Projects Central Rockies PICEANCE BASIN Sulphur Creek Area Continuous phase gas in Williams Fork 2.0 to 2.5 Bcf per well Drilling costs: $2.9 MM per well (with stimulation) 170 gross (85 net) locations on 20-acre spacing (primarily fee acreage) 3 wells planned for 2006 and 13 in

19 Exploration Projects - Utah Hingeline Prospect Whiting acquired a 15% working interest in 170,000 leased acres in an active exploration play along the Central Utah Hingeline. The acreage position covers several prospects along trend with the ~70 MMBOE Covenant field discovered in Whiting believes geologic conditions in this area are conducive to field sizes of 50 to 100 MMBOE. The initial prospect, located south of Covenant field, is scheduled to be drilled in Q4-06. Whiting will have a 7.5% working interest in the initial well. 18

20 In Summary Geographically diversified, longlived reserve base Growth in reserves and production per share Significant discretionary cash flow visibility Disciplined acquiror with strong record of accretive acquisitions, Celero most recently Multi-year inventory of development and exploitation projects to drive organic production growth going forward Exploration potential in the Permian Basin, Rockies and Gulf Coast Commitment to financial strength Proven management and technical team 5 Core Regions; 17 year R/P Grown from 71.7 MMBOE at IPO to MMBOE 36% reserve/share CAGR and 8% production/share CAGR from 2003 IPO thru 12/31/05 $342.4 MM of Disc. Cash Flow first 9Mos acquisitions in ; $6.94 per BOE average acquisition cost 5+ year drilling inventory resulting from Celero acquisition Permian: Penn, Devonian, Montoya, Ellenburger Williston: Bakken, Red River Piceance: Williams Fork, Wasatch, Mancos Targeted 40% debt to cap Average 25+ years of experience 19

21 EBITDAX Reconciliation We define EBITDAX as earnings before interest, taxes, depreciation, depletion, and exploration expense. EBITDAX is not a measure or performance calculated in accordance with generally accepted accounting principles in the United States, or GAAP. Although not prescribed under GAAP, we believe the presentation of EBITDAX is relevant and useful, because it helps our investors to understand our operating performance and makes it easier to compare our results with those of other companies that have different financing and capital structures or tax rates. EBITDAX should not be considered in isolation of, or as a substitute for, net income as an indicator of operating performance. EBITDAX, as we calculate it, may not be comparable to EBITDAX measures reported by other companies. In addition, EBITDAX does not represent funds available for discretionary use. In evaluating EBITDAX, you should be aware that our EBITDAX for the year ended December 31, 2003 included one-time charges to net income of (i) $10.9 million for payments to our employees under our phantom equity plan in connection with our initial public offering in November 2003 and (ii) $3.9 million (non-cash) related to our adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. The following table presents a reconciliation of our consolidated net income to consolidated EBITDAX. Year Ended December 31, 9Mos (in millions) Net Income $128.4 $121.9 $ 70.0 $ 18.3 Income Tax Expense, net Interest Expense, net Depreciation, Depletion and Amortization Exploration Expense & Impairment Cumulative Effect of FASB Phantom Equity Plan Gains on Sales - - (5.8) - EBITDAX $384.1 $352.4 $184.2 $

22 Discretionary Cash Flow (1) Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow (In Thousands) Three Months Ended 3/31/05 6/30/05 9/30/05 12/31/05 Net cash provided by operating activities... $ 70,189 $ 67,587 $ 73,406 $ 119,252 Exploration. 1,298 4,130 4,384 4,853 Changes in working capital... (6,874) (6,372) 1,706 (14,204) Discretionary cash flow (1) $ 64,613 $ 65,345 $ 79,496 $ 109,901 (1) Discretionary cash flow is computed as net income plus exploration costs, depreciation, depletion and amortization, deferred income taxes, non-cash interest costs, non-cash compensation plan charges, and impairment of oil and gas properties less the gain on sale of properties and marketable securities. The non-gaap measure of discretionary cash flow is presented because management believes it provides useful information to investors for analysis of the Company s ability to internally fund acquisitions, exploration and development. Discretionary cash flow 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, cash flow or liquidity measures under GAAP and may not be comparable to other similarly titled measures of other companies. 21

23 Discretionary Cash Flow (1) Reconciliation of Net Cash Provided by Operating Activities to Discretionary Cash Flow (In Thousands) Three Months Ended Sept. 30, Net cash provided by operating activities... $ 132,635 $ 73,406 Exploration. 5,618 4,384 Changes in working capital... (11,533) 1,706 Discretionary cash flow.. $ 126,720 $ 79,496 Nine Months Ended Sept. 30, Net cash provided by operating activities... $ 351,880 $211,182 Exploration... 21,161 9,812 Changes in working capital... (30,662) (11,540) Discretionary cash flow.. $ 342,379 $209,454 (1) Discretionary cash flow is computed as net income plus exploration costs, depreciation, depletion and amortization, deferred income taxes, non-cash interest costs, non-cash compensation plan charges and change in Production Participation Plan liability and other non-cash amounts, less the gain on sale of properties and marketable securities. The non-gaap measure of discretionary cash flow is presented because management believes it provides useful information to investors for analysis of the Company s ability to internally fund acquisitions, exploration and development. Discretionary cash flow 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, cash flow or liquidity measures under GAAP and may not be comparable to other similarly titled measures of other companies. 22