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  • 1

    May 2017Investor Presentation

    PREMIER OPERATOR OF TOP TIER ASSETS

  • Please Read This presentation makes reference to:

    Forward-looking statements

    This presentation contains forward-looking statements within the meaning of securities laws. The words anticipate, assume, believe,

    budget, estimate, expect, forecast, guidance, intend, plan, project, will and similar expressions are intended to identify forward-

    looking statements. These statements involve known and unknown risks, which may cause SM Energy's actual results to differ materially from

    results expressed or implied by the forward-looking statements. Forward-looking statements in this presentation include, among other things,

    2017 guidance, expectations regarding growth strategy, consummation of pending transactions, anticipated drilling plans and capital

    expenditures, anticipated growth in cash flows, the expected benefits, financing sources and timing of acquisitions, and the expected benefits

    and likelihood of completing divestitures. General risk factors include the uncertain nature of acquisition, divestiture, joint venture, farm down or

    similar efforts and the ability to complete any such transactions; the uncertain nature of expected benefits from the actual or expected

    acquisition, divestiture, joint venture, farm down or similar efforts; the uncertainty of negotiations to result in an agreement or a completed

    transaction; the availability of and access to capital markets; the availability, proximity and capacity of gathering, processing and transportation

    facilities; the volatility and level of oil, natural gas, and natural gas liquids prices, including any impact on the Companys asset carrying values

    or reserves arising from price declines; uncertainties inherent in projecting future rates of production or other results from drilling and completion

    activities; the imprecise nature of estimating oil and gas reserves; uncertainties inherent in projecting future drilling and completion activities,

    costs or results, including from pilot tests; the availability of additional economically attractive exploration, development, and acquisition

    opportunities for future growth and any necessary financings; unexpected drilling conditions and results; unsuccessful exploration and

    development drilling results; the availability of drilling, completion, and operating equipment and services; the risks associated with the

    Company's commodity price risk management strategy; uncertainty regarding the ultimate impact of potentially dilutive securities; and other

    such matters discussed in the Risk Factors section of SM Energy's 2016 Annual Report on Form 10-K, as such risk factors may be updated

    from time to time in the Company's other periodic reports filed with the Securities and Exchange Commission. In addition, production forecasts

    and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells

    and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost

    increases. The forward-looking statements contained herein speak as of the date of this announcement. Although SM Energy may from time to

    time voluntarily update its prior forward-looking statements, it disclaims any commitment to do so except as required by securities laws.

    2

    Non-GAAP financial measures: See appendix for reconciliations

    Note: slide deck changes (slides 5,6, and 8) include impact of increased

    production and cash flow to 3-year plan.

  • 3

    Midland BasinSweetie Peck/RockStar

    ~88,000 net acres

    Maverick BasinEagle Ford

    ~167,000 net acres

    SM Energy 3-Year Plan Focused on Two Core Assets

    3

    Top tier oil in Midland + top tier NGLs and gas in Eagle Ford

    Successful transformation to core up portfolio

  • 4

    SM Energy A Premier Operator of Top Tier Assets

    3 Year Plan Expected

    Outcomes:

    Big growth in

    high-margin

    production

    Big growth in

    cash flow

    Debt:EBITDAX

    ~2x in 2019

    Top Tier

    portfolio

  • 5

    Big Expected Production Growth

    0%

    10%

    20%

    30%

    40%

    50%

    -

    10,000

    20,000

    30,000

    40,000

    50,000

    60,000

    70,000

    2016 2017 2018 2019

    Oil %

    Pro

    du

    cti

    on

    (MB

    oe

    )

    Midland Basin Operated Eagle Ford Rockies Revised Guidance Sold Oil %

    (e) (e) (e)

    ~100% CAGR Midland Basin

    Adjusted 3-year plan(1)

    (1) Adjusted for increased production guidance provided on 5/3/17 and retention of Divide County assets.

    (2) Sold production relates to the Non-operated Eagleford, Williston, and Southeast New Mexico divestitures. Note that the initial version of this slide posted on 5/16/17 only

    included the Non-operated Eagle Ford divestiture in the sold category.

    (2)

  • 6

    Big Cash Flow Growth Driven by Expected Margin Expansion

    Operating margin expected to increase 80% 4Q16 2019

    Production growth expected within cash flow in 2019

    Adjusted plan results in increased cash flow, decreased outspend

    Note: Based on strip pricing as of 2/3/17.

    (1) Adjusted for increased production guidance provided on 5/3/17 and retention of Divide County assets.

    (2) Realized price before the effect of hedges less LOE, transportation, production taxes, and G&A.

    Cash Flow Expected to Double 2017 - 2019

    $10

    $13

    $16

    $19

    $22

    $25

    $0

    $650

    $1,300

    4Q16 2017 2018 2019

    Op

    era

    tin

    g M

    arg

    in$

    /Bo

    e

    Ca

    sh

    Flo

    w$

    /MM

    Cash Flow Operating Margin

    (e)

    Adjusted 3-year plan(1)

    (e) (e)

    (2)

  • Financial Discipline Strengthening the Balance Sheet

    7

    On track with 2017 financial strategy

    Other

    86% 8%

    Drilling and

    Completion

    86%

    Facilities

    6%

    Other

    8%

    (1)

    Liquidity of $1.6 billion (as of March 31, 2017) $747 million net cash proceeds from non-operated Eagle Ford sale March 2017 Net debt reduced to $2.3 billion; reduced 22% 1Q17/4Q16 No bond maturities until 2021; 2021 notes currently callable; 2023 notes callable July 2017 Coverage metrics provide flexibility; March 31, 2017:

    Senior Secured Debt:TTM Adjusted EBITDAX at ~0.0 times; max ratio allowed 2.75 times TTM Adjusted EBITDAX:Interest at ~4.5 times; minimum ratio required 2.0 times

    $500$500$500$395

    $562

    $345

    $172.5

    $0

    $250

    $500

    $750

    $1,000

    2026202520242023202220212020201920182017

    Debt Maturities as of March 31, 2017(in millions)

    ~$0 drawn

    Commitments and Borrowing

    base $925 million (as of 3/31/17)

    Corporate ratings: S&P BB-, Moodys B1

    Coupon 1.500%6.500%

    6.125% 6.500% 5.000% 5.625% 6.750%

  • 3-Year Plan Prefunded by Cash Flow and Divestiture

    8

    Proceeds from non-operated Eagle Ford sale > 2017-2018 expected outspend

    Other

    86% 8%86%

    Facilities

    6%

    Other

    8%Midland

    Basin

    80%

    (2)(1)

    2017

    Outspend

    2018

    Outspend

    Non-operated

    Eagle Ford

    sale

    2017 2018

    Projected

    Outspend

    Additional cash flows from retention of Divide County assets reduce 2017-2018 expected outspend

    3-year plan objective of Net Debt : EBITDAX ~2.0x

    Note: Based on strip pricing as of 2/3/17.

  • Financial Discipline Hedging Provides Cash Flow Stability

    9

    ~75% of expected 2017 production volumes hedged (at the midpoint of guidance) ~ 70% of oil, 80% of natural gas and 80% of NGLs

    Approximately 1/2 of expected 2018 volumes hedged

    0

    1

    2

    3

    4

    5

    6

    7

    8

    9

    10

    2Q17 3Q17 4Q17

    (MM

    BO

    E)

    Hedged Volumes as of April 26, 2017

    Oil Gas NGLs

    Credit Agreement modified to allow hedging of up

    to 85% of 2017-2019 projected production

    Note: The hedged volumes on this slide do not include any volumes related to basis swaps.

  • SM Energy A Premier Operator of Top Tier Assets

    2017 Priorities:

    Complete

    portfolio

    transition

    Focus capital

    on drivers of

    value creation

    Midland Basin

    development

    acceleration

    Strong

    balance sheet

    and liquidity

    10

  • Midland Basin Setting Up for Expanded 2018 Program

    11

    Excellent vendor relationships and continued improvements in operating efficiencies

    set the stage for expansion in 2018

    Significant experience

    in the basin - strong

    vendor relationships

    Sufficient takeaway

    capacity

    Sufficient water

    availability to run program

    Continued performance

    improvement

  • Midland Basin 1Q17

    12

    Midland Basin~88,000 net acres

    Sweetie Peck

    RockStar

    Halff East

    Ramping up quickly setting up for 2018

    6 horizontal rigs and 1 data gathering rig; 3 completions crews

    active

    Production up 55% sequentially; RockStar wells significantly

    outperforming acquisition

    assumptions

    Drilled 20(1) 10,000 laterals to date and added 1,300 net acres of

    adjacent land positions

    Program actively testing WolfcampA, Wolfcamp B, and Lower

    Spraberry

    (1) Includes four wells drilled by previous operator and completed by SM.

  • Midland Basin Premier Operator

    13

    0

    20,000

    40,000

    60,000

    80,000

    100,000

    120,000

    140,000

    0 20 40 60 80 100 120 140 160 180 200 220 240

    Cum

    ula

    tive P

    roduction (

    BO

    E)

    Days

    VENKMAN 26-35 A #15WA VENKMAN 26-35 B #1 WA

    Applying technology to optimize development

    Acquiring core and log data

    Steering to best zones

    Identifying new pay intervals

    Enhancing completion designs

    Swapping and acquiring adjacent land positions: more long laterals

    Gaining efficiencies through intensive pad drilling

    Using Digital Oilfield to improve well uptime statistics

    Example: Venkman wells in RockStar Area

    Improved

    Completion

    Design

    Optimized completion design in two Wolfcamp A wells in same spacing unit

    Result: More than 60% improvement in 120 day cumulative oil production

    (completed by previous operator)

    7,700 lateral7,430 lateral

  • 14

    Howard County Significant Increase in Activity

    Industry confidence drives increased drilling activity across the county

    January 2017: 18 Rigs April 2017: 28 Rigs

  • 15

    Howard County Positive Peer Well Results

    Peer wells extend confirmed geologic assessment to east and south

    Tubb A 1HA

    Thumper 14-23

    Thumper 14-23 7,500 lateral

    24-hour rate: 1,357 Boe

    (91% oil)

    Tubb A 1HA 9,366 lateral

    produced 141,000 Boe

    over 132 days

    Source: Tubb A 1HA well data courtesy of Earthstone Energy Inc.

  • 0

    20,000

    40,000

    60,000

    80,000

    100,000

    120,000

    140,000

    160,000

    180,000

    200,000

    220,000

    240,000

    0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320

    Gro

    ss

    Cu

    mu

    lati

    ve

    Pro

    du

    cti

    on

    (B

    OE

    )

    Production Days

    1 MMBOE Peer Type Curve 20% IRR Type Curve

    RockStar Top Tier Well Performance Continues

    16

    Initial production rates on SM completed wells soundly beating acquisition assumptions

    Note: Well economics at $50 oil and $3.00 gas; monthly data normalized to days on production.

    * Peer Type Curve adjusted to meet 20% IRR

    SM Operated Well

    RockStar wells average ~90% oil at ~40 API gravity

  • Howard County Recent Well Results

    Recent wells targeting three intervals: Wolfcamp A, Wolfcamp B, and Lower Spraberry

    17

    Well Name Interval

    Lateral

    Length

    IP Rate

    (BOE/d)

    IP

    Days

    Tackleberry 43-42 A 1LS LS 7,873 1,286 30

    Tackleberry 43-42 A 1WA WCA 7,861 2,262 30

    Tackleberry 43-42 A 2WB WCB 7,885 1,412 30

    Rambo 3846WA(4) WCA 7,546 1,130 30

    Rambo 3848WA(5) WCA 7,590 1,118 30

    Venkman 26-35 B 1WA WCA 7,700 1,274 30

    Top Gun 1632LS(6) LS 7,711 1,236 30

    Top Gun 1652WA(7) WCA 7,595 1,655 30

    (1) Name changed from Corrine Elizabeth 26-27 A 1H (4) Name changed from Rambo 38-47 7WA (7) Name changed from Top Gun 1H

    (2) Name changed from Corrine Elizabeth 26-27 A 2H (5) Name changed from Rambo 38-47 9WA

    (3) Name changed from Corrine Elizabeth 26-27 A 3H (6) Name changed from Top Gun 2H

    Well Name Interval

    Lateral

    Length

    IP Rate

    (BOE/d)

    IP

    Days

    Guitar North 2722LS(1) LS 9,692 1,093+ 20

    Guitar North 2742WA(2) WCA 9,698 1,981 20

    Guitar North 2762WB(3) WCB 9,693 1,693 20

    1Q17 Wells

    4Q16 Wells

    Note: Guitar North 2722LS 20-day IP Rate still climbing

  • 0

    10

    20

    30

    40

    50

    0 30 60 90 120 150 180 210 240 270

    Gro

    ss C

    um

    ula

    tive P

    roduction (

    BO

    E/F

    T)

    Production Days

    Eagle Ford Increasing Value With More Wells Per Section

    18

    900 East Type Curve

    (LEF) BOE/FT

    All three areas support UEF/LEF co-development

    6 Wells (A)

    11 UEF/LEF

    Co-Development

    wells

    4Q16

    Completions

    Operated Eagle Ford Recent Well Results

    2015/2016 East Area co-development

    4Q 2016 East Area co-development (A)

    1Q 2017 North Area co-development

    South

    Area

    North

    AreaEast

    Area

    East 4Q16 Completions

    Continued Outperformance

    at 312 plan view spacing

    1Q17

    Completions

    Note: 2-stream data; does not reflect ~70

    Bbls/MMcf NGL yield for type curve shown.

  • 19

    SM Energy A Premier Operator of Top Tier Assets

    3 Year Plan Expected Outcomes:

    Big growth in

    high-margin

    production

    Big growth in

    cash flowDebt:EBITDAX

    ~2x in 2019

    2017 Priorities:

    Complete

    portfolio

    transition

    Focus capital

    on drivers of

    value creation

    Midland Basin

    development

    acceleration

    Top Tier

    portfolio

    Strong

    balance sheet

    and liquidity

  • 20

    Appendix

  • 0%

    20%

    40%

    60%

    80%

    100%

    120%

    $40 $45 $50 $55 $60

    IRR

    NYMEX WTI

    7,600' 10,000'

    0%

    20%

    40%

    60%

    80%

    100%

    120%

    $40 $45 $50 $55 $60

    IRR

    NYMEX WTI

    7,600' 10,000'

    0%

    20%

    40%

    60%

    80%

    100%

    $0.60 $0.65 $0.70

    IRR

    Mt. Belvieu $/Gal

    Regional Well Projected Economics

    21

    2017 capital program focusing on areas with top tier returns

    RockStar Wolfcamp A

    Well Cost: $5.6MM

    Well Spacing: 660Well Cost: $6.8MM

    Well Spacing: 660Well Cost: $5.9MM

    Well Spacing: 660

    Well Cost: $7.0MM

    Well Spacing: 660

    Sweetie Peck Lower Spraberry

    Note: well costs include drill, complete, and equip; sensitivities at $3.00/MMBtu NYMEX; Eagle Ford East oil flat at $50/Bbl WTI

    Eagle Ford East

    Well Cost: $5.2MM, Lateral Length: 8,000, Well Spacing: 625, Sand Loading: 2,000 lbs/ft, Stage Spacing: 150

    Sand loading: 1,900 lbs/ft; Stage Spacing: 167 Sand loading: 1,900 lbs/ft; Stage Spacing: 167

    Eagle Ford East

    ~35% NGLs

    1Q17 Average

    Mt. Belvieu ($/Gal)

  • 1st Quarter 2017 Performance

    22

    Production 1Q17

    Total Production (MMBoe) 12.1

    Average Daily Production (MBoe/d) 134.4

    Pre-Hedge Realized Price ($/Boe) $27.55

    Post-Hedge Realized Price ($/Boe) $27.55

    Costs

    LOE ($/Boe) $3.82

    Ad Valorem ($/Boe) $0.55

    LOE including Ad Valorem ($/Boe) $4.37

    Transportation ($/Boe) $5.88

    Production Taxes (% of pre-derivative oil, gas & NGL revenue) 4.2%

    Total Cash Production Expenses $11.42

    Production Margin (pre-hedge) $16.13

    G&A Cash ($/Boe) $2.08

    G&A Non Cash ($/Boe) $0.34

    Total G&A ($/Boe) $2.42

    DD&A ($/Boe) $11.39

  • 1Q17 Regional Realizations

    23

    Pricing

    NYMEX WTI Oil ($/Bbl) $51.91

    NYMEX LLS Oil ($/Bbl) $53.39

    NYMEX Henry Hub Gas ($/MMBTU) $3.32

    Hart Composite NGL ($/Bbl) $26.74

    Production Volumes Eagle Ford Op(1) Rocky Mountain Permian

    Eagle Ford

    Non-Op(2) SM Total

    Oil (MBbls) 421 999 1,623 483 3,525

    Gas (MMcf) 26,936 1,026 2,882 3,052 33,895

    NGL (MBbls) 2,404 36 6 474 2,921

    MBOE 7,315 1,206 2,109 1,465 12,095

    Expenses (in thousands)

    LOE $13,420 $11,785 $16,328 $4,629 $46,162

    Ad Valorem 3,172 32 2,174 1,285 6,663

    Transportation 58,366 2,288 116 10,323 71,093

    Production Taxes 3,389 4,974 4,617 1,148 14,128

    Revenue (in thousands)

    Oil $17,324 $47,261 $81,499 $21,540 $167,624

    Gas 77,983 1,641 11,309 10,218 101,151

    NGL 53,152 919 147 10,205 64,423

    Total $148,459 $49,821 $92,955 $41,962 $333,198

    Note: Totals may not sum due to rounding and other classifications

    (1) Includes nominal amounts of other production and expenses from the region

    (2) The Eagle Ford Non-Op divestiture closed on March 10, 2017

    Per Unit Metrics:

    Re...