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Form 8-K MURPHY OIL CORP /DE For: Feb 24

February 24, 2016 8:47 AM EST

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

FORM 8-K

 

 

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

 

 

Date of report (Date of earliest event reported): February 24, 2016

 

 

 

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

 

 

 

 

 

 

 

 

 

 

Delaware

 

1-8590

 

71-0361522

(State or other jurisdiction of incorporation)

 

(Commission File Number)

 

(I.R.S. Employer Identification No.)

 

 

 

 

 

 

 

 

 

 

 

 

 

300 Peach Street

 

P.O. Box 7000, El Dorado, Arkansas

71730-7000

(Address of principal executive offices)

(Zip Code)

 

 

 

Registrant’s telephone number, including area code 870-862-6411

 

 

 

Not applicable

(Former Name  or Former Address, if Changed Since Last Report)

 

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

 

 

[   ]

Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

 

[   ]

Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

 

[   ]

Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

 

[   ]

Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

 

 


 

Item 7.01 Regulation FD Disclosure.

As previously announced, , Roger Jenkins, President and CEO of Murphy Oil Corporation, will present at the Credit Suisse 21st Annual Energy Summit. Materials accompanying Mr. Jenkins’s presentation are attached as Exhibit 99.1 hereto.

 

Forward-Looking Statements: This report contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Words such as “targets”, “expectations”, “plans”, “forecasts”, “projections” and other comparable terminology often identify forward-looking statements. These statements, which express management's current views concerning future events or results are subject to inherent risks and uncertainties. Factors that could cause one or more of these forecasted events not to occur include, but are not limited to, a failure to obtain necessary regulatory approvals, a deterioration in the business or prospects of Murphy, adverse developments in Murphy business' markets, adverse developments in the U.S. or global capital markets, credit markets or economies in general. Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of our exploration programs, our ability to maintain production rates and replace reserves, customer demand for our products, adverse foreign exchange movements, political and regulatory instability, and uncontrollable natural hazards.  For further discussion of risk factors, see Murphy's most recent Annual Report on Form 10-K, on file with the U.S. Securities and Exchange Commission. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

 

The information in this Item 7.01, including Exhibit 99.1 attached hereto, is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that Section and shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, as amended, or the Exchange Act, except as otherwise expressly stated in such filing. 

 

Item 9.01.  Financial Statements and Exhibits

 

 

 

(d)

Exhibits

 

 

99.1

Materials accompanying presentation delivered at February 24, 2016 Credit Suisse 21st Annual Energy Summit.

 

 

 

 

 

 


 

Signature

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

 

 

 

 

 

MURPHY OIL CORPORATION

 

 

 

 

By:

/s/  Keith Caldwell

 

 

Keith Caldwell

 

 

Senior Vice President and Controller

 

 

Date:  February 24, 2016

 

 

 

 


 

Exhibit Index

 

 

 

99.1

Materials accompanying presentation delivered at February 24, 2016 Credit Suisse 21st Annual Energy Summit.

 

 

 


Picture 11       CREDIT SUISSECREDIT SUISSE 2121STSTANNUAL ENERGY SUMMITANNUAL ENERGY SUMMIT FEBRUARY 24, 2016FEBRUARY 24, 2016    ROGER JENKINS PRESIDENT & CHIEF EXECUTIVE OFFICER

 


 

Picture 22   MURPHY OIL CORPORATION    www.murphyoilcorp.com    NYSE: MUR    Cautionary Statement    Cautionary Note to U.S. Investors –The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves.  We may use certain terms in this presentation, such as “resource”, “gross resource”, “recoverable resource”, “net risked PMEANresource”, “recoverable oil”, “resource base”, “EUR or estimated ultimate recovery” and similar terms that the SEC’s rules strictly prohibit us from including in filings with the SEC. Investors are urged to consider closely the oil and gas disclosures in Murphy’s 2014 Annual Report on Form 10-K on file with the SEC. Forward-Looking Statements –This presentation contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.  Words such as “targets”, “expectations”, “plans”, “forecasts”, “projections”, and other comparable terminology often identify forward-looking statements. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties.  Factors that could causeone or more of the events forecasted in this presentation not to occur include, but are not limited to, a deterioration in the business or prospects of Murphy, adverse developments in Murphy’s markets, or adverse developments in the U.S. or global capital markets, credit markets or economies generally.  Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of our exploration programs, our ability to maintain production rates and replace reserves, political and regulatory instability, and uncontrollable natural hazards.  For further discussionofrisk factors, see Murphy’s 2014 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission.  Murphy undertakes no duty to publicly update or revise any forward-looking statements.


 

Picture 33   MURPHY OIL CORPORATION    www.murphyoilcorp.com    NYSE: MUR   Agenda    Business Update Progressing the Portfolio Takeaways


 

Picture 44    Murphy Overview    35%    34%    3%    6%    22%    2015 Proved Reserves    EFS    Canada Onshore    Canada Offshore    GOM    Malaysia   28%    31%    41%    Canada    Malaysia    United States   61%    25%    9%    5%    Oil    Natural Gas    Oil-Indexed Gas    NGL   Balanced Reserve Portfolio •Onshore North American Shale and Offshore Reserves    •Outstanding Reserve Replacement History with F&D Cost Improvements    Diversified Brent Weighted Production Base •Malaysia, United States & Canada    •Oil, Natural Gas & Liquids   Partner Relationship with PETRONAS  •Global LNG Leader   Health, Safety & Environment •Proven Track Record   Long Corporate History   •IPO 1956     774 MMboe    208 MMboe    208 MMboe    FY 2015 Production


 

Picture 55    Business Update    Financial  •Spent $2.19 BN Capital Expenditures, ~5% Under 2015 Budget    •Reduced LOE $/boeby 17% Y-O-Y    •Reduced G&A by 16% Y-O-Y    Reserve Replacement •Total Organic Replacement 154%    •Total Replacement 123%   Portfolio •Monetization of Canadian Midstream Assets    •Signed Agreement to Acquire an Interest in Duvernay & Liquids Rich Montney   Revised FY 16 Capex  •Reduction from January 2016 Guidance of $825 MM   •$580 MM Capex –FY 16    •Maintain 180 –185 MboepdProduction –FY 16    Well-Positioned CAPITALDISCIPLINE      Adding Resource RESERVE REPLACEMENT CONTINUES      Progressing the Portfolio MIDSTREAM MONETIZATION DUVERNAY & LIQUIDS RICH MONTNEY      Financial Flexibility ADDITIONALCAPEX REDUCTION


 

Picture 66   35%    7%    5%    11%    15%    3%    4%    20%    EFS    Montney    Seal/Syncrude    GOM/E Canada    Sarawak    Block K    Block H    Other   2016 Total Capex, $580 Million   Revised 2016 Guidance    NA Onshore 47%    Offshore 53%    2016 Revised Capex to $580 MM •30% Reduction from Jan 2016 Guidance    •73% Reduction from 2015    •76% Allocated to Development    2016 Production •Maintain FY 16 Guidance 180 -185 Mboepd    •Maintain 1Q 16 Guidance 190 –194 Mboepd    KaybobDuvernay& MontneyLiquids Rich Guidance •Not Included in Current Capex & Production    •FY 16 Additional Capex $39 MM    •FY 16 Additional Production 3.3 Mboepd


 

Picture 77    Continued Cost Focus    10.14    8.25    14.61    11.04    9.21    5    7    9    11    13    15    4Q 14    4Q 15    2013    2014    2015    Lease Operating Expense*   $/boe    37% Reduction    19% Reduction    Focusing on Cost Reductions  •Reduced LOE by 19% Q-O-Q    •Reduced LOE by over 17% Y-O-Y    •EFS 4Q 15 LOE of $8.46/boe     * Excludes both Syncrudeand Severance & Ad Valorem Taxes


 

Picture 88    35%    19%    15%    10%    21%    EFS    Resource (Other)    Syncrude/Heavy    Conventional    Deepwater   Proved Reserves YE 2015 774 MMboe    2015 –An Outstanding Year in Corporate Reserves    •Total Replacement 123%    •R/P Increased to 10.2 years    •10thConsecutive Year >100%    •5 Year Reserve Life Increase of ~25%    •5 Year AvgReplacement >180%    •9% CAGR Reserve Growth 2010-15    MUR    63%  PD    757 37% PUD    69%    31%   Onshore    Offshore    $27.15 5 Yr    $20.61 3 Yr    $18.70 1 Yr    $10    $15    $20    $25    $30    MUR 2015 –Average F&D Costs, $/boe   62% PD 38% PUD    MUR    68% Liquids & Oil-Indexed Gas    4    6    8    10    12    0    200    400    600    800    2011    2012    2013    2014    2015    Years    MMboe    MUR Proved Reserves & Reserves Life*    Proved    R/P   *2014 and 2015 includesimpact of Malaysia Sell-Down     GLOBAL OFFSHORE


 

Picture 9GLOBAL OFFSHORE


 

Picture 1010   Malaysia   Sarawak •SK Gas –Reached Record Gross Production Volumes of 272 MMcfdin 2015    •South AcisDevelopment Drilling –Positive Results     Kakap-Gumusut  •Production Exceeding Forecast      Block H FLNG •De-Risked with Drilling of 2 Wells     Brunei •CA-2 KeratauSuccess    •Working Field Development Plan


 

Picture 1111    South Acis Field –Drilling Results    •Completed 3rdPhase of Program    •Deeper Oil-water Contacts and More Net Pay    •Potential Near-field Exploration Well to Test Far Eastern Faults Blocks    25    41    46    51    0    15    30    45    60    Sanction (2012)    Post 1st Drilling(2013)    Post 2nd Drilling(2015)    Post 3rd Drilling(2016)    EUR Gross (MMSTB)    South Acis Field –Gross EUR Changes    EUR Gross (MMSTB)       Oil Producer Well       Non Associated Gas Well   Water Injector Well    SASA-04    SASA-21    SASA-21 ST1    SASA-05    SASA-20 ST1    SASA-04    SASA-14 ST1    SASA-13    SASA-06    SASA-20    SASA-15   Updated Oil/Water Contact   Previous Oil/Water Contact    Gas / Oil Contact   Oil / Water Contact      SASA-14 (Appraisal)    Depth Structure Map of Top K010


 

Picture 1212    Offshore Vietnam     CA-1    CA-2    K    SK 314A    H    144    145    11-2/11    13/03    Vietnam    Cambodia    Thailand    Laos    Sarawak    Sabah    Brunei    Indonesia    Malaysia    Philippines    Indonesia   SK 2C    0    250    Miles       Ruby / Topaz Blk. 130 MMBOE      Rang Dong Blk. 260 MMBOE   Bach Ho / RongBlk. 1,900 MMBOE   TeGiacTrang Blk. 320 MMBOE     Lac Da Vang Blk. 15-1/05    Su TuDen Blk. 400 MMBOE   CuuLong Basin •New Focus Area    •Signed Farm-in Agreement for Block 15-1/05    •Highly Successful Oil Prone Basin    •Successful Appraisal & Flow test


 

Picture 1313    Gulf of Mexico   •Dalmatian South #2 –70% W.I. (Operator)    •Expanding Dalmatian Infrastructure    •Spud 3Q 15; 1stOil Dec 2015    •Producing 4,000 bopd      •Kodiak –29% W.I. (Non-Op.)    •Tieback to Devil’s Tower    •First Well Drilled & Completed to Plan    •First Oil Expected in Coming Days


 

Picture 14NORTH AMERICA ONSHORE


 

Picture 1515    Onshore Canada -Montney    image001     100 t    150 t    50 t   •22 New Wells Online in 2015    •Future Growth of 1000+ Potential Locations    •AECO Hedges     •2016: 59 MMcfd@ $C 3.19/mcf(AECO)   •Midstream Monetization –1Q 16 Expected Close    •New Completions Adding Upside    •EURs 10 -15 BCF    •Moved to 180T/frac(late 2015 and 2016)   •Continue to Drive Costs Down    •2015: $5.7 MM D&C (5,200’ lateral)    •2016: $5.3 MM D&C (9,500’ lateral)   •Targeting 15 BCF Wells in 2016    •Longer Laterals:  Shift from 5,200’ up to 9,500’    •Higher Sand Concentration >1,000lbs/ft    •Higher Efficiency Drilling Rig       Tupper West New Well Completions    Mscfd


 

Picture 1616      -     20,000     40,000     60,000     80,000     100,000     120,000     140,000     160,000      -     10     20     30     40     50     60     70     80     90     100     110     120     130    Cumulative Gross BOE Produced    Days on Production    Austin Chalk: JOG A1H Performance -Cum Gross BOE    Lower EFS Type Curve    Austin Chalk Type Curve    JOG A1H   Onshore -Eagle Ford Shale    Running Room •648 Operated Online Wells to Date    •Remaining Resource Potential 800+ MMboe    •Austin Chalk    •JOG Unit A 1H -140 MboeCumulative Production in 5 Months    •Preliminary Net Risked Resource & Locations    •~55 Mmboe (200-450 Mboe per Well)    •~265 Locations    •Price Advantaged Near GOM    •45°API Gravity; Oil-Weighted 77% Oil   •US WTI Hedges    •2016:  20,000 bopd@ $


 

Picture 17PROGRESSING THE PORTFOLIO


 

Picture 1818    Montney Midstream Monetization    •C$538 MM Divestiture of Montney Midstream Assets in British Columbia, Canada    •100% Cash Proceeds    •20 year Customary Fee Structure    •Assets Include Natural Gas Processing Plants and Sales Pipelines for Tupper and Tupper West    •Expected to Close First Quarter   •Enbridge Will Own and Operate    •Well-established Operator    •Current Gross Capacity 320 MMcfpd    •Opportunity for Plant Expansion   •Cash Proceeds Allocated to:    •Balance Sheet Cash –C$288 MM    •Duvernay and Liquids Rich Montney Joint Venture –C$250 MM


 

Picture 1919    •C$475 MM Joint Venture Agreement in KaybobDuvernay and Liquids Rich Montney Area    •C$250 MM Cash; C$225 MM Flexible Carry     •Risked Recoverable Resource of 200 -350 MMboeNet    1.KaybobDuvernay    •70% WI, Operatorship    •230,000 Gross Acres (200,000 Currently Prospective)     •6,900 boepdGross, 58% Liquids    •Area Includes 247,000 Gross Acres of Overlying Conventional Montney Rights   2.Liquids Rich Montney    •30% WI, Non-Operated    •60,000 Gross Acres (21,000 Currently Prospective)    •900 boepdGross, 44% Liquids      Athabasca Oil Joint Venture Transaction    Area of Mutual Interest “AMI”                Montney 70% WI (Operated)    Montney 30% WI (Non-Operated)    Duvernay 70% WI (Operated)   Pipeline Infrastructure 35% WI    Processing Infrastructure 35% WI


 

Picture 2020    •Strategically Complements NA Onshore Unconventional Portfolio Utilizing In-House Expertise    •Capital Flexibility in Volatile Price Environment    •Up to Five Year Ability to Pay Carry Based on Pricing    •Allocated Canadian Funds from Midstream Monetization to Joint Venture    •Maintains Balance Sheet as Self-funded by Canadian Subsidiary   •Duvernay Recognized as Premier Play    •Proven Gas Condensate Window    •Emerging Light Oil With Upside in Black Oil    •Operated by Murphy   •Liquids Rich Montneyis Proven Area    •Minimal Activity Required to Hold Acreage    •+75% of Land Expires in 2019 or Later    •Provides Ability to Control Pace Maintaining Capital Flexibility   •Long Term Regional Demand for Condensate from Heavy Oil Projects    Joint Venture Highlights   T64    T57    R21W5    6 miles   DuvernayProducer      Gas Condensate    Light Oil    Lean  Gas         Athabasca Encana Repsol Trilogy Shell Chevron    Black Oil


 

Picture 2121   KaybobDuvernay Overview    •Emerging as Premier Play    •Gas Condensate Delivering High Liquid Yields    •Early Stages of Light Oil Development    •Analogous Results to EFS Light Oil   •Results Continue to Improve    •Increasing Well EURs    •Optimizing Completion Techniques    •Decreasing D&C Costs   •Long Term Growth    •500 Gross Locations    •Condensate –160 Acre Spacing    •Oil –160 to 230 Acre Spacing   •500+ Potential Down-spacing Upside    •Untapped Northern Area     *Estimated Using Fixed Condensate Gas Ratio for Gas Condensate Wells    Recent Industry DuvernayTests & Performance      Peer –2,100 BOEPD –200-250 BBL/MMCF  (Recent Down-spacing Pilot)    Peer –1,500 BOEPD –425 BBL/MMCF    Peer –935 BOEPD –500-700 BBL/MMCF (Average of Multiple Wells)    Peer –3,100 BOEPD –350 BBL/MMCF   Max Month Liquids bbl/day*    300-600    600-1000    1000-1300    1-300    1300-1600        Peer –825 BOEPD –950 BBL/MMCF   Peer –645 BOEPD –1,415 BBL/MMCF   67K acres    110K acres    33K acres    22K acres      Peer –800 BOEPD –200 BBL/MMCF    Peer –2,100 BOEPD –240 BBL/MMCF      ATH –1,380 BOEPD –270 BBL/MMCF    ATH –780 BOEPD –450 BBL/MMCF


 

Picture 2222    image001      Permian    Duvernay    Montney    Eagle Ford   Comparative Rock Properties in Premier NA Shales


 

Picture 2323   Duvernay Condensate –Improving Performance By Completion Type    Cumulative, Mboe    Time, months    1    2    ATH   ATH   Proppant  (#/ft)   500      750    1000    1250    1500   1750   250   2250    Type Curve: 760 MBOE    Type Curve: 1000 MBOE    2   1   ATH   ATH   •33,000 Gross Acres (Gas Condensate)         DuvernayRights     ATH    ATH


 

Picture 2424   Duvernay Light Oil –Improving Performance By Completion Type   Cumulative, Mboe    Time, months    Type Curve: 400 MBOE    Type Curve: 670 MBOE    1    2    ATH*   ATH   Proppant  (#/ft)   500      750    1000    1250    1750   3250    ATH   ATH    DuvernayRights       •67,000 Gross Acres (Light Oil)    •110,000 Gross Acres (Black Oil)      2   1   ATH    ATH    *Well drilled N-S, instead of perpendicular to principal stress


 

Picture 2525    Liquids Rich Montney Overview    •Montney Most Actively Drilled Canadian Play in 2015   •Significant Liquids Component (30%)    •Results Continue to Improve Providing Upside to Economics    •Increasing Well EURs Across the Play    •Optimizing Completion Techniques    •Decreasing D&C Costs   •Long Term Growth    •100 -200 Gross Locations    •Potential Down-spacing Upside     Industry Well Rates 600 MAX BOEPD –38 BBL/MMCF (Peer -2013) 1272 MAX BOEPD –49 BBL/MMCF (Peer -2014) 1053 MAX BOEPD –139 BBL/MMCF (Peer -2014) 1750 MAX BOEPD –97 BBL/MMCF (Peer –2014) 800 MAX BOEPD –1200 BBL/MMCF (Peer -2013)      6 miles   Exxon    Cequence    Conoco    Athabasca    Delphi    EnCana    CIOC    Velvet    Chevron    Omers    Apache    Trilogy    Dry Gas Limit    Condensate Limit    Montney Producer    7 Gens    CNRL          Athabasca Well Rates 900 MAX BOEPD –300 BBL/MMCF >830 MAX BOEPD


 

Picture 2626   MURPHY OIL CORPORATION    www.murphyoilcorp.com    NYSE: MUR    Drilling & Completions Recent Performance    •Early Stage of Learning Curve    •Will Benefit from Experience in EFS and Montney   •Industry Driving Well Costs Down as Play is Developed    •Reduced Drilling Days    •Efficiencies With Multi-Well Pads    •Assume $6.8 MM Well to $4.9 MM Well Over Time    •Recent Athabasca Duvernay Costs    •Athabasca –Average = 14.5 Days for $2.4 MM/Well    •Athabasca –$6.4 MM/Well D&C   •Recent Montney Costs    •Company A –$5.1 MM/Well D&C (Est)    •Company B –$4.7 -5.3 MM/Well D&C        B     Gas Condensate    Light Oil    Lean  Gas    Black Oil    A    A    A


 

Picture 2727   MURPHY OIL CORPORATION    www.murphyoilcorp.com    NYSE: MUR    •Proven Track Record of Lowering Costs While Optimizing Drilling & Completion Techniques    •Utilize Internal Expertise and Partner Success    •Similar Well Design to Montney& EFS   •DuvernayStill in Early Stages of Development    •Light Oil Drilling Well Design Similar to EFS and Tupper (2 casing strings)    0    2    4    6    8    10    12    2013    2014    2015    2016E    Goal    Cost per well ($MM)    Duvernay D&C    Drilling    Completion   0    2,000    4,000    6,000    8,000    0    2000    4000    6000    8000    10000    2011    2012    2013    2014    2015    2016E    Lateral Length (ft)    Cost per well ($MM)    Tupper/Tupper West D&C    Drilling    Completion    Lateral Length   Learning Curve Will Bring Costs Down    0    2,000    4,000    6,000    8,000    0    2    4    6    8    10    12    2011    2012    2013    2014    2015    2016E    Lateral Length (ft)    Cost per well ($MM)    EFS D&C    Drilling    Completion    Lateral Length   Est Costs Decrease 29%    45% Reduction


 

Picture 2828   MURPHY OIL CORPORATION    www.murphyoilcorp.com    NYSE: MUR    Growing Heavy Oil and Diluent Demand    •2014 to 2018: >800 MbblpdGrowth Alberta Oil Sands Production    •From Projects Currently Under Construction   •2014 to 2018: Diluent Requirement Expected to Grow 200 Mbblpd    •Imports Near Current Max of Pipeline Import Capacity   •Expect Western Canada Premium for Condensate vs Gulf Coast Prices    •Cost to Transport from Gulf Coast by Rail = US$10 -15/bbl    •WTI + $1.25 = $33.12 as of 2/23/16     0    500    1000    1500    2000    2500    3000    3500    2003    2004    2005    2006    2007    2008    2009    2010    2011    2012    2013    2014    2015E    2016E    2017E    2018E    2019E    2020E    mbbl/d    Alberta Oil Sands Region Production Outlook, Base Case    Upgraded SCO    Non-Upgraded Bitumen   0    100    200    300    400    500    600    700    2005    2006    2007    2008    2009    2010    2011    2012    2013    2014    2015E    2016E    2017E    2018E    2019E    2020E    mbbl/d    DilbitDiluent Requirement (Base Case) vs. Supply Estimate    Diluent Imports    Domestic Supply Diluent    Refined Product    Estimated Diluent Required    Piped Import Capacity    Ref: First Energy Capital / CAPP / BMO


 

Picture 2929    Existing Strategic Infrastructure    Alberta    60mmcf/d 12,500bbls/d (50% WI)    150-180mmcf/d (50% WI)    TCPL    Alliance    Pembina    •Flexible Takeaway OptionsWith Future Growth Potential    Gas Pipelines (Gross)      Up to 180 Mmcf/d         Battery Capacity (Gross)      Oil     36,000 bb/d      Gas     84 Mmcf/d, expandableto >130Mmcf/d         Alliance    Pembina    TCPL    Alberta Oil Sands  Pipeline (Pembina)    Source:  Athabasca Oil


 

Picture 3030    US Unconventional Single Well Economics    Based on January 19, 2016 forward pricing; escalated 2%/yronce 5 years forward curve ends. Fixed and Variable Well Cost Only –No Facility Costs No Planned Drilling in 2016 @ E, N & W. Tilden    Current    Athabasca Joint Venture    Area     Type Curve ROR      Catarina KBS     24%      Catarina Kone     16%      Karnes Lower EFS     20%      TupperMain     48%      Tupper West     52%         Area     Type Curve ROR      DuvernayCondensate     22%      DuvernayLight Oil     30%      Liquids Rich Montney     24%


 

Picture 3131    FINANCIAL OUTLOOK


 

Picture 3232    $0    $250    $500    $750    $1,000    $1,250    $1,500    2016    2017    2018    2019    2020    2021    2022    2023    2024    2025    2026    2027    2028    2029    2030    2031    2032    2033    2034    2035    2036    2037    2038    2039    2040    2041    2042    2043    2044    2045    2046    >2046    Debt Balance  $MM   10 YEAR   20YEAR   30 YEAR   Murphy –Current Profile    Source:  MUFG; Bloomberg   3 YEAR   5YEAR    Current Maturity Profile*      Total Bonds Outstanding $MM     $2,250.0      Weighted AvgFixed Coupon     4.07%      Weighted AvgMaturity Date     May2025      Weighted AvgYears to Maturity     9.28         *As of 12/31/15    Current Sources of Liquidity •$0.6 BN Drawn on $2.0 BN Revolver    •$0.4 BN Cash & Liquid Invested Securities    •Midstream Monetization Partial Proceeds -Cash on Balance Sheet


 

Picture 3333    Managing the Balance Sheet    •Reduced Capital to $580 MM, 73% from 2015 Including a 75%Reduction in the EFS    •Securing Longer Tenor on Revolver    •Dividend Review if Commodity Prices Remain at Current Levels    •Non Core Asset Sales –Continue to Review Portfolio


 

Picture 3434    Preserving the Balance Sheet    Outstanding Year in Reserves Replacement    Takeaways       1   2   3   4    Reducing Capital While Maintaining Production    Focusing on NA Unconventional Resources   5   Balanced Production Between Onshore/Offshore


 

Picture 3535    APPENDIX


 

Picture 3636    Appendix    •Non-GAAPReconciliation    •Abbreviations    •Guidance    •HedgingPositions


 

Picture 3737    Non-GAAP Financial Measure Definitions & Reconciliations    ThefollowinglistofNon-GAAPfinancialmeasuredefinitionsandrelatedreconciliationsisintendedtosatisfytherequirementsofRegulationGoftheSecuritiesExchangeActof1934,asamended.Thisinformationishistoricalinnature.MurphyundertakesnoobligationtopubliclyupdateorreviseanyNon-GAAPfinancialmeasuredefinitionsandrelatedreconciliations.


 

Picture 3838    Non-GAAP Reconciliation    ADJUSTEDEARNINGS Murphy defines Adjusted Earnings as net income adjusted to exclude discontinued operations and certain other items that affect comparability between periods.     Adjusted Earnings is used by management to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted Earnings, as reported by Murphy, may not be comparable to similarly titled measures used by other companies and it should be considered in conjunction with net income, cash flow from operations and other performance measures prepared in accordance with generally accepted accounting principles (GAAP).  Adjusted Earnings has certain limitations regarding financial assessments because it excludes certain items that affect net income.  Adjusted Earnings should not be considered in isolation or as a substitute for an analysis of Murphy's GAAP results as reported.


 

Picture 3939    Non-GAAP Reconciliation    ADJUSTEDEARNINGS    $ Millions     Twelve Months Ended –December 31, 2015     Twelve Months Ended –December 31, 2014      Net Income (loss)     (2,270.8)     905.6      Discontinued operationsloss     15.0     119.4      Deepwater rig contract exit costs     183.3      -      Deferred tax on distributed foreign earnings     188.5      -      Mark-to-marketgains  on crude oil derivate contracts     (37.7)     (0.3)      Foreign exchange gains     (86.7)     (39.9)      Impairment of assets     1,660.0     46.3      Tax benefitson investments in foreign areas     (16.9)     (154.9)      Gain on sale of interest in Malaysia (10% in 2015, 20% in 2014)     (218.8)     (321.4)      Environmentalprovisions     35.8      -      Increase in Alberta corporate tax rate     23.8      -      Decrease in Malaysia corporate tax rate on certain fields     (21.8)      -      Restructuring charges     14.1      -      OilInsurance Limited dividends     (4.5)     (3.3)      Write-offof previously suspended exploration wells      -     59.6      Adjusted Earnings (loss)     (536.7)     611.1


 

Picture 4040    Non-GAAP Reconciliation    EBITDA Murphy defines EBITDA as income from continuing operations before income taxes,  depreciation, depletion and amortization (DD&A), net interest expense, and impairment expense.   Management believes that EBITDA provides useful information for assessing Murphy's financial condition and results of operationsand it is a widely accepted financial indicator of the ability of a company to incur and service debt, fund capital expenditure programs, and pay dividends and make other distributions to stockholders. EBITDA per barrel is computed by taking EBITDA divided by total barrels of oil equivalents produced during the respective periods.   EBITDA, as reported by Murphy, may not be comparable to similarly titled measures used by other companies and it should be considered in conjunction with net income, cash flow from operations and other performance measures prepared in accordance with generally accepted accounting principles (GAAP).  EBITDA has certain limitations regarding financial assessments because it excludes certain items that affectnet income and net cash provided by operating activities.  EBITDA should not be considered in isolation or as a substitute for an analysis of Murphy's GAAP results as reported.    $ Millions     Twelve Months Ended –December 31, 2015     Twelve Months Ended –December 31, 2014      Income from continuingoperations     (2,255.8)     1,025.0      Incometax expense (benefit)     (1,026.5)     227.3      Interest expense, net of interest  capitalized     117.4     115.8      DD&Aexpense     1,619.8     1,906.2      Impairmentof assets     2,493.2     51.3      Consolidated EBITDA (Non-GAAP)     948.1*     3,325.6**         *Includes $155.1 MM pre-tax gain on sale of 10% interest in Malaysia in the twelve month period of 2015and $282.0 million pre-tax charge related to exit of deepwaterdrilling rig contracts. **Includes $144.8 million pre-tax gain on sale of 20% interest in Malaysia in the 2014 period.


 

Picture 4141    Non-GAAP Reconciliation    EBITDAX MurphydefinesEBITDAXasincomefromcontinuingoperationsbeforeincometaxes,explorationexpenses,depreciation,depletionandamortization(DD&A),netinterestexpense,andimpairmentexpense. ManagementbelievesthatEBITDAXprovidesusefulinformationforassessingMurphy'sfinancialconditionandresultsofoperationsanditisawidelyacceptedfinancialindicatoroftheabilityofacompanytoincurandservicedebt,fundcapitalexpenditureprograms,andpaydividendsandmakeotherdistributionstostockholders.EBITDAXperbarreliscomputedbytakingEBITDAXdividedbytotalbarrelsofoilequivalentsproducedduringtherespectiveperiods. EBITDAX,asreportedbyMurphy,maynotbecomparabletosimilarlytitledmeasuresusedbyothercompaniesanditshouldbeconsideredinconjunctionwithnetincome,cashflowfromoperationsandotherperformancemeasurespreparedinaccordancewithgenerallyacceptedaccountingprinciples(GAAP).EBITDAXhascertainlimitationsregardingfinancialassessmentsbecauseitexcludescertainitemsthataffectnetincomeandnetcashprovidedbyoperatingactivities.EBITDAXshouldnotbeconsideredinisolationorasasubstituteforananalysisofMurphy'sGAAPresultsasreported.    $ Millions     Twelve Months Ended –December 31, 2015     Twelve Months Ended –December31, 2014      Income from continuingoperations     (2,255.8)     1,025.0      Incometax expense (benefit)     (1,026.5)     227.3      Interest expense, net of interest capitalized     117.4     115.8      DD&A expense     1,619.8     1,906.2      Impairmentof assets     2,493.2     51.3      Explorationexpense     470.9     513.6      Consolidated EBITDAX (Non-GAAP)     1,419.0*     3,839.2**         *Includes $155.1 MM pre-tax gain on sale of 10% interest in Malaysia in the twelve month period of 2015and $282.0 million pre-tax charge related to exit of deepwaterdrilling rig contracts. **Includes $144.8 million pre-tax gain on sale of 20% interest in Malaysia in the 2014 period.


 

Picture 4242    Abbreviations    BBL:  barrels (equal to 42 US gallons) BCF:  billions of cubic feet BN:  billions BOE: barrels of oil equivalent (1 barrel of oil or                   6000 cubic feet of natural gas) BOEPD:  barrels of oil equivalent per day BOPD:  barrels of oil per day CAGR:  compound annual growth rate DD&A:depreciation, depletion & amortization EBITDA: income from continuing operations before taxes, depreciation, depletion and amortization, and net interest expense    MBOEPD:  thousands of barrels of oil equivalent per day MCF:  thousands of cubic feet MM:  millions MMBOE:  millions of barrels of oil equivalent MMCF:  millions of cubic feet MMCFD:  millions of cubic feet per day NA:  North America NGL:  natural gas liquid R/P:  ration of reserves to annual production WI:  working interest WTI:  West Texas Intermediate (a grade of crude oil)    EBITDAX: income from continuing operations before taxes, depreciation, depletion and amortization, net interest expense, and exploration  expenses EFS:  Eagle Ford Shale EUR:  estimated ultimate recovery FLNG:  floating liquefied natural gas G&A:  general and administrative expenses GOM:  Gulf of Mexico IPO:  initial public offering LOE:  lease operating expense LLS:  Light Louisiana Sweet (a grade of crude oil)


 

Picture 4343    Guidance -1Q 2016    Guidance 1Q 2016     1Q 2016 Liquids (bopd)     1Q 2016 Gas (mcfd)      1Q Production:     126,000     396,000      US -EagleFord Shale     49,000     34,000      Gulfof Mexico     16,000     26,000      Canada -Heavy     3,000     2,000      Montney      -     203,500      Offshore     8,000      -      Syncrude     13,000      -      Malaysia –Sarawak     13,000     112,500      BlockK     24,000     18,000      1Q Production Volume (boepd)     190,000 –194,000      1Q Sales Volume (boepd)     190,000*      1Q Exploration Expense ($MM)     $22      FullYear 2016 Production(boepd)     180,000 –185,000      Full Year 2016 Capex ($MM)     $580**      1Q Expected Realized Prices ($/bbl)     Malaysia –Block K     32.23      Sarawak Oil     32.65      ($/mcf)     Sarawak Gas     3.25        DSC01462.JPG _MG_5738.jpg *Under lift primarily in Malaysia **Athabasca not included


 

Picture 4444    2016 Hedging Positions    Area     Commodity     Type     Volumes (bbl/d)     Price (USD/bbl)     Start Date     End Date      United States     WTI     Fixed price derivative swap     20,000     $52.01     01/01/2016     12/31/2016         Area     Commodity     Type     Volumes(MMcf/d)     Price (CAD/mcf)     StartDate     End Date      WesternCanada     Natural Gas     Fixedprice forward sales     59     C$3.19     01/01/2016     12/31/2016

 




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