Fourth Quarter 2018 Operating and Financial Update. February 2019 NYSE: WLL

Transcription

1 Fourth Quarter 2018 Operating and Financial Update February

2 Forward Looking Statement and Non-GAAP Measures This presentation contains statements that Whiting Petroleum Corporation ( Whiting ) believes to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of All statements other than historical facts, including, without limitation, statements regarding the expected future reserves, production, future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and debt levels of Whiting, and plans and objectives of management for future operations, are forward-looking statements. Such forwardlooking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. These risks and uncertainties include, but are not limited to: declines in, or extended periods of low, oil, NGL or natural gas prices; our level of success in exploration, development and production activities; risks related to our level of indebtedness, ability to comply with debt covenants and periodic redeterminations of the borrowing base under our credit agreement; the geographic concentration of our operations; impacts to financial statements as a result of impairment write-downs; federal and state initiatives relating to the regulation of hydraulic fracturing and air emissions; revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures; inaccuracies of our reserve estimates or our assumptions underlying them; risks relating to any unforeseen liabilities of ours; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations; our ability to successfully complete asset dispositions and the risks related thereto; unforeseen underperformance of or liabilities associated with acquired properties; the impacts of hedging on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; availability of, and risks associated with, transport of oil and gas; our ability to drill producing wells on undeveloped acreage prior to its lease expiration; shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services; uninsured or underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and gas operations; the potential impact of changes in laws, that could have a negative effect on the oil and gas industry; our ability to replace our oil and natural gas reserves; negative impacts from litigation and legal proceedings; any loss of our senior management or technical personnel; competition in the oil and gas industry; cyber security attacks or failures of our telecommunication systems; and other risks described under the caption Risk Factors in Item 1A of our Annual Report on Form 10-K for the period ended December 31, We assume no obligation, and disclaim any duty, to update the forward-looking statements in this news release. In this presentation, we refer to Operating Cash Flow in Excess of Capital Expenditures, free cash flow and Discretionary Cash Flow, which are non-gaap measures that Whiting believes are helpful in evaluating the performance of its business. A reconciliation of such non-gaap measures to the relevant GAAP measures can be found at the end of the presentation. 2

3 Strategic Vision MAXIMIZE ECONOMIC RETURNS AT THE DRILLING SPACING UNIT LEVEL 1 Strategic Initiatives Industry-leading capital efficiency as measured by cost to add oil-weighted reserves and production REDUCE DEBT AND ADD HIGH ROR BAKKEN INVENTORY 4 Achieve Industry- Leading Results in Capital Efficient Development of Resource Plays 3 2 MAXIMIZE VALUE FROM THE SAND FACE TO THE SALE POINT Industry-leading free cash flow yield Debt-to-EBITDAX <2x at $55 NYMEX oil Strong economic results at the development level through optimized completions DELIVER LEADING CORPORATE LEVEL CAPITAL EFFICIENCY AND FREE CASH FLOW 3

4 Four Pillars of Executive Responsibility Brad Holly Mike Stevens Chip Rimer Tim Sulser A corporate leadership division A financial division that drives An operations division that drives A strategy and planning division that ensures Whiting has the excellence into our organization excellence in the field and that generates strong near and capital, communications and by managing a solid balance moves our teams to an even long-term plans that enable culture to achieve its goals. sheet and enhancing our higher level of performance. Whiting to continue to deliver CHIEF EXECUTIVE OFFICER CHIEF FINANCIAL OFFICER profitability. CHIEF OPERATING OFFICER CHIEF STRATEGY OFFICER tangible value to shareholders. 4

5 Added High Quality Talent in Key Positions Shane Fross SENIOR VICE PRESIDENT OF OPERATIONS 2018 was about getting the right people in the right seats. Recruited top performers from across industry. Empowered Whiting to deliver even better performance. Upgraded areas where performance was not optimal. Jason Finch VICE PRESIDENT PLANNING Brad Marvin VICE PRESIDENT BUSINESS DEVELOPMENT Kevin Kelly VICE PRESIDENT MARKETING Chris Edwards VICE PRESIDENT EXPLORATION 5

6 2018 Scorecard Grow Production Generate Free Cash Flow Lower Cost Structure Grow Oil Volumes Add Top-Tier Inventory Full Year 2018 Daily Production Averaged 127,980 BOE/d, an 8% increase Year-Over- Year 2018 Net Cash Provided by Operating Activities Totaled $1,092 Million and 2018 Free Cash Flow Totaled $280 Million 2018 Full Year LOE and G&T, G&A and DD&A Expense per BOE Decreased 10%, 8% and 24% from 2017 Levels Q Daily Oil Production Averaged 88,645 Bbl/d, a 3% increase over Third Quarter 2018 Added Top-tier Inventory through Accretive Acquisition and Successful Optimized Completions in the Bakken Halo 6

7 Balanced 2019 Capital Plan 2019 Capital Plan Williston Basin Non-Op Land Other (1) Total Capex of $800 - $840 Million $702 Million Development Plan to Drill 132 gross wells Plan to Complete 154 gross wells Plan to Put on Production 146 gross wells Forecast to generate solid free cash flow at a $55+ NYMEX oil price. $40 $30 $ Production 129,000 BOE/d Forecast to grow total operated Williston Basin production 11% and oil production 15% year-over-year Estimated Well Counts Q Q Q Q Current Drilling Rigs Current Completion Crews $662 Drill Complete Put on Production (1) Includes facilities, exploration and capital workovers, 7

8 Consistently Generating Free Cash Flow 2018 Free Cash Flow, $ Millions (1) $280 $104 $66 $91 $19 Q Q Q Q Total (1) For reconciliation of free cash flow to the applicable GAAP measure, see the reconciliation later in this presentation. 8

9 Leading in Operating Cash Flow in Excess of Capex (1) Q1 - Q Cash Flow From Operations Less Capital Expenditures $300.0 $200.0 $100.0 $0.0 ($100.0) ($200.0) ($300.0) ($400.0) ($500.0) ($600.0) ($700.0) $209.4 $198.6 WLL Peer A $46.6 Peer B ($7.9) Peer C ($37.0) Peer D ($67.0) ($81.9) ($111.5) ($159.6) ($179.0) ($197.2) ($232.7) ($293.0) Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L ($434.0) ($454.4) Peer M Peer N ($624.1) Peer O (1) For reconciliation of operating cash flow in excess of capex to the applicable GAAP measure, see the reconciliation later in this presentation. Source: Bloomberg and Company filings. Peers consist of CDEV, CRZO, DNR, EGN, EPE, LPI, NFX, OAS, PDCE, PE, RRC, SM, SWN, WPX, XEC. 9

10 WLL Lower Decline Provides Competitive Advantage Lower Decline Increases Free Cash Flow Potential Source: Macquarie Research February,

11 A Leader in Optimized Completions Generation 1.0 ( ) 240 lbs/ft proppant 380 stage spacing 4 bbl/ft fluid 380 cluster spacing Packer, Ball-and-Sleeve Generation 2.0 ( ) 390 lbs/ft proppant 300 stage spacing 9 bbl/ft fluid 150 cluster spacing Mix of Packer, Ball-and-Sleeve & Cemented liner PnP Generation 3.0 ( ) 930 lbs/ft proppant 240 stage spacing 25 bbl/ft fluid 42 cluster spacing All cemented liner PnP Diversion technology in use Generation 4.0 (2018) 600 1,200 lbs/ft proppant stage spacing bbl/ft fluid cluster spacing All cemented liner PnP Diversion technology in use, evolving Optimize the completion to the situation Large geometry completions for infill wells in DSUs with high remaining recoverable oil in place Near-wellbore completions for DSUs with high parent well count 11

12 A Generation Ahead of the Competition Generation 5.0 (2019) lbs/ft proppant stage spacing bbl/ft fluid Reduced cluster spacing All cemented liner PnP Diversion technology in use with evolving techniques and variable products Optimize the completions to the well spacing and geology Increased fracture intensity High Intensity Near-Wellbore Completion: Concentrating more of the stimulation near the new infill well, lower sand loading, more entry points, more diversion techniques applied Large Frac Geometry Completion: Create a mix of far-reaching fractures and near-wellbore concentration, higher sand loading, adequate entry points, diversion to ensure all entry points connected 12

13 The Optimum Frac Design for Each Specific Area Differences in reservoir and mechanical properties exist across the Williston Basin. Every area requires a customized completion design. Example of Multivariate Analysis for a Specific Region Strategy for optimum design: Build calibrated completion models for every prospect area. Use multivariate analysis to understand which completion factors most heavily affect the results in each area. Pilot and adopt the latest completion technologies available through preferred service companies. Example frac geometry from GOHFER frac model Entry Points Frac Stages Total Fluid Proppant Entry Points Frac Stages Total Fluid Proppant Diverter Lateral Length Importance 13

14 Superior Completion Efficiency Beating the Benchmark in Completion Execution In 2018 Whiting had 29% better pumping efficiency than the North Dakota industry average based on total hours of actual pumping in a given month goal is to improve this metric by 5%. In 2018, Whiting had 31% better cycle time efficiency than the North Dakota industry average in cycle time between stages goal is to improve this metric by 10%. Source: Industry service provider data Monthly Pumping Hours 269 ND Average Cycle Time Between Stages 1.89 ND Average 29% -31% WLL Performance WLL Performance 5% -10% WLL Target WLL Target 14

15 North Williston Team Overview 2019 Capital Plan Capex of $216 Million Plan to Drill 19 gross wells WILDROSE Plan to Complete 57 gross wells Plan to Put on Production 57 gross wells 2019 Drilling Catalysts CASSANDRA Cassandra well results Wildrose well results Generation 5.0 well results POLAR PERIOT WELLS Current Drilling Rigs Current Completion Crews 15

16 Cassandra Generation 4.0 Wells Outperform Offsets Periot wells are outperforming the nearby offset wells completed by other operators in the area. Cassandra Periot wells completed with Generation 4.0 design. Generation 4.0 design involves perforating more clusters per stage, using advanced diverter technology, pumping low viscosity fluids and pumping small mesh proppant. Completion design decisions are a result of: 1. Multi-disciplinary collaboration 2. Frac modeling Cumulative Oil (Bbls) 200, , , , , ,000 80, MMLB Periot Bakken Well Periot Three Forks Well Offset Bakken Wells Offset Three Forks Wells 4.9 MMLB 5.9 MMLB 6.0 MMLB 7.5 MMLB 8.3 MMLB 3. An understanding of the stimulation vs. performance drivers in each of our unique prospect areas. THE RESULT: Create more stimulated surface area within the target intervals than our competitors. 60,000 40,000 20, MMLB Days on Production 16

17 East Williston Team Overview 2019 Capital Plan Capex of $180 Million Plan to Drill 60 gross wells Plan to Complete 40 gross wells POD 8 PROJECT POD 9 PROJECT SANISH / PARSHALL Plan to Put on Production 37 gross wells 2019 Drilling Catalysts MCNAMARA PROJECT BARTELSON WELLS Pod 9 well results in Sanish Section line wells 1- ½ mile laterals 3-mile laterals Three Forks infills Generation 5.0 well results PRONGHORN Current Drilling Rigs Current Completion Crews 17

18 Pod 8 Infill Wells Outperform Parent Wells Cumulative Oil per 1,000 Lateral Feet 12,000 10,000 8,000 6,000 4,000 2,000 0 Pod 8 Infill Wells Parent Wells Days on Production Project Goals Drill Four Bakken infill wells and complete utilizing Whiting optimized completions. Maximize recovery factor in a high OOIP area. Protect parent well production. Well Stats Four New Bakken Wells One 640-acre spaced well Three 1,280-acre spaced wells Four Parent Bakken Wells Two 640-acre spaced wells Two 1,280-acre spaced wells 18

19 McNamara Results A Catalyst for Future Development 1.7 MMBBLs produced in 500 days. Recovery factor of unit is projected to double. Pump-ins successful in protecting Bakken parent wells from negative impacts. Risk reduced on 192 future Bakken infill wells. Project PAID OUT 10/03/ year payout 100% NYMEX oil price NPV10: $52 million 19

20 Western Sanish Generation 4.0 Bakken Wells Outperform by 83% Cumulative Oil per 1,000 Lateral Feet 12,000 10,000 8,000 6,000 4,000 2,000 Bartelson Bakken Wells Parent Wells Bartelson Bakken wells demonstrate strong results on the western side of Whiting s Sanish acreage. Generation 4.0 completions performing 83% better than legacy well. BARTELSON PROJECT SANISH Days on Production 20

21 South Williston Team 2019 Capital Plan Capex of $266 Million Plan to Drill 53 gross wells EAST MISSOURI BREAKS Plan to Complete 57 gross wells Plan to Put on Production 52 gross wells 2019 Drilling Catalysts Stenehjem well results in Hidden Bench Foreman Butte area results Generation 5.0 well results WEST MISSOURI BREAKS FOREMAN BUTTE HIDDEN BENCH Current Drilling Rigs Current Completion Crews 21

22 Gen 5.0 Completions Drive Stenehjem Performance Cumulative Oil (Bbls) 30,000 25,000 20,000 15,000 10,000 5,000 LOKEN 41-17H LOKEN H MALLOW 34-8H STENEHJEM 44-7H STENEHJEM H STENEHJEM FEDERAL 24-7H STENEHJEM FEDERAL H Stenehjem Generation 5.0 Stenehjem Gen 5 Completion tests outperform Mallow and Loken offsets. Proppant loading optimized for best results and maximum IRR. Stenehjem H and Stenehjem H cumulative production exceeds 25,000 Bbls black oil. LOKEN WELLS MALLOW WELLS STENEHJEM WELLS Days on Production 22

23 Unlocking Value at Foreman Butte Acquisition Acquisition $130 million purchase price funded from free cash flow. Closed July 31, ,833 net acres overlap in Hidden Bench and East Missouri Breaks acreage. LOKEN WELLS 1,290 BOE/d of production at closing. Development First well was spud on 12/5/ wells planned for development in FOREMAN BUTTE NON-OP WELL (46% WI) 90-DAY CUM. 90 MBOE STENEHJEM WELLS 23

24 Driving Cash Costs Down $20.00 $18.73 Established pipe gathering systems for produced water Renegotiated low rates for existing produced water systems. Currently 85% of produced water is piped. Implemented advanced well monitoring and intervention technologies. $/BOE $18.00 $16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $3.80 $3.68 $1.35 $9.90 $16.28 $4.83 $2.43 $1.44 $7.58 $15.47 $14.65 $13.65 $4.67 $3.70 $3.57 $2.55 $2.38 $2.37 $1.66 $2.10 $1.03 $6.59 $6.47 $6.68 $2.00 $ LOE G&T G&A Interest Total 24

25 Continuous Improvement in Operations Spud to TD - Days Well Cost $MM CONTINUALLY IMPROVING DRILLING EFFICIENCY $ MM lbs $ MM lbs INDUSTRY LEADING COMPLETION TECHNOLOGY $6.8 8 MM lbs 2018 $ MM lbs 2019 Drilling Industry leading in drilling performance with 60% reduction in SPUD to TD since Utilizing the latest generation drilling rigs, high-torque mud motors and 3D bit cutter technology to reduce time on location and well costs. Leveraging Whiting s vast experience of drilling 8,300 miles of wellbore since Completion Industry leader in advancement of completion technology, completion efficiency and cost efficiency. Leverage increased efficiency, logistics and market to increase stimulation by 3x while reducing well costs 24%. Continuing to advance leading position in 2019 by implementing technologies to increase pumping efficiency and fracture intensity near wellbore to increase well performance and reduce cost. Introducing a new initiative to reduce SPUD to completion cycle times. (1) Based on the estimated 2018 mid-point well cost. 25

26 Optimization Efforts Lead to Decreased Downtime NORTHERN ROCKIES DOWNHOLE FAILURE CONTINUES TO DECREASE Optimizing Production and Reducing LOE Failures per Well per Year Implemented advanced well monitoring and intervention techniques utilizing SCADA. Reduced downhole failure rate by 29% over three year period. Employed predictive analytic software to improve downhole design. Utilizing advanced downhole tubular and rod metallurgies Optimized pumping unit driver parameters and improved chemical programs. 26

27 Why Whiting? 1 Projecting growth and free cash flow in Top-tier people in unconventional resource development. 3 Managing the asset portfolio to maximize capital efficiency and corporate level returns. 4 A technology leader in the E&P sector. 5 Strong balance sheet liquidity. 6 A culture of communication, innovation and excellence. 27

28 Appendix 28

29 Top Acreage Position across the Core Williston Basin WILDROSE WEST MISSOURI BREAKS CASSANDRA POLAR SANISH / PARSHALL EAST MISSOURI BREAKS FOREMAN BUTTE HIDDEN BENCH Area Gross Acres (1) Net Acres (1) Net Wells Drilled (1) Cassandra 28,502 13, East Missouri Breaks 61,167 29, Foreman Butte 98,967 57, Hidden Bench 102,395 74, Polar 97,769 51, Pronghorn 113,626 80, Sanish / Parshall 171,914 82, West Missouri Breaks 66,072 52, Wildrose 28,503 19, Other 16,850 7,829 - PRONGHORN Grand Total 785, ,443 1,347 WLL Acreage WLL Rig (1) As of 12/31/

30 Capital Efficiency Through Smarter Completions 30

31 Capital Efficiency Through Smarter Completions 31

32 Hedge Position (1) 1,200,000 1,000, , , , ,000 0 Volumes Hedged by Month Weighted Average As a Percentage of Derivative Hedge Contracted Crude NYMEX Price December 2018 Instrument Period (Bbls per Month) (Per Bbl) Oil Production Swaps Fixed Price Jul - Sep ,000 $ % Oct - Dec ,000 $ % Floor/Ceiling Collars Jan - Mar ,100,000 $ $ % Apr - Jun ,100,000 $ $ % Jul - Sep ,000 $ $ % Oct - Dec ,000 $ $ % Collars Swaps (1) As of February 20, (2) As a percentage of December 2018 oil production. 32

33 Strong Balance Sheet Liquidity and Financial Flexibility BOND MATURITY PROFILE AS OF 12/31/2018 ($ MILLIONS) $1,000 $874 $562 $ Sr. Unsecured Convertible $1.75 billion of bank credit commitments on a $2.4 billion borrowing base. No borrowings outstanding as of 12/31/2018. Bank credit agreement through 4/12/2023 (1). Bank credit agreement covenants: Total Debt-to-EBITDAX less than 4.0:1. It was 2.2:1 as of 12/31/2018. Current Ratio greater than 1:1. It was 3.9:1 as of 12/31/2018. No bond maturities until Bond Finance Covenant: Ratio of consolidated cash flows to fixed charges (interest expense) must be greater than 2.0:1. It was 6.6:1 as of 12/31/2018. Effective 8/10/2018, S&P upgraded Whiting s Credit Rating to BB. Effective 9/17/2018 Moody s upgraded to B2. (1) The credit agreement matures on April 12, 2023, provided that if at any time and for so long as any senior notes (other than the 2020 Convertible Senior Notes) have a maturity date prior to 91 days after April 12, 2023, the maturity date shall be the date that is 91 days prior to the maturity of such senior notes. 33

34 Slower Activity Build Means Less Cost Pressure Change in Rig Count from January 1, % Change in Rig Count from January 1, % 40.0% 20.0% 0.0% (20.0%) (40.0%) (60.0%) North Dakota Texas Oklahoma +59% +37% +7.5% (80.0%) Source: Bloomberg and Company filings. 34

35 Strong Williston Basin Differentials Enhance Cash Flow $0.00 ($2.00) ($4.00) $/BOE ($6.00) ($4.63) ($4.79) ($8.00) ($7.22) ($8.53) ($10.00) ($12.00) ($10.93) Williston Basin Oil Differential 35

36 Oil Takeaway Sufficient; Gas & NGL Outlook Improving Local Refinery Demand, Pipeline Capacity and Rail Capacity Provide > 2 MMBbls of Takeaway Potential Multiple New Processing Additions Expected to Alleviate Basin Constraints 3,500,000 3,000,000 2,500,000 Barrels of Oil per Day 2,000,000 1,500,000 1,000, , /1/2013 5/1/2013 9/1/2013 1/1/2014 5/1/2014 9/1/2014 1/1/2015 5/1/2015 9/1/2015 1/1/2016 5/1/2016 9/1/2016 1/1/2017 5/1/2017 9/1/2017 1/1/2018 5/1/2018 9/1/2018 1/1/2019 5/1/2019 9/1/2019 1/1/2020 5/1/2020 9/1/2020 Pipeline & Refinery Takeaway Rail Loading Capacity North Dakota Production Source: EIA, North Dakota Pipeline Authority. 36

37 Williston Basin Rail Loading Facilities 1.7 MMBbls 37

38 Reconciliation of Discretionary Cash Flow, Free Cash Flow and Operating Cash Flow in Excess of Capex Three Months Ended Mar. 31, June 30, Sept. 30, Dec. 31, Total Net cash provided by operating activities $ 232,867 $ 310,413 $ 263,756 $ 284,967 $ 1,092,003 Operating cash outflow for settlement of commodity derivative contract 61, ,036 Exploration 5,236 5,527 5,177 6,140 22,080 Changes in working capital (8,131) (46,348) 29,457 (38,138) (63,160) Discretionary cash flow (1) 291, , , ,969 1,111,959 Capital expenditures (187,144) (203,250) (207,278) (234,351) (832,023) Free cash flow (1) $ 103,864 $ 66,342 $ 91,112 $ 18,618 $ 279,936 Three Months Ended Mar. 31, June 30, Sept. 30, Total Net cash provided by operating activities $ 232,867 $ 310,413 $ 263,756 $ 807,036 Capital expenditures (187,144) (203,250) (207,278) (597,672) Operating cash flow in excess of capital expenditures (1) $ 45,723 $ 107,163 $ 56,478 $ 209,364 (1) Discretionary cash flow, free cash flow and operating cash flow in excess of capital expenditures are non-gaap measures. Such measures are presented because management believes they provide useful information to investors for analysis of the Company s ability to internally fund acquisitions, exploration and development. Such 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, cash flow or liquidity measures under U.S. GAAP and may not be comparable to other similarly titled measures of other companies. 38