BAML Energy Conference Miami | November 2014 2 materially from - - PowerPoint PPT Presentation

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BAML Energy Conference Miami | November 2014

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Forward‐looking Statements

This presentation contains projections and

• ther forward‐looking statements within the

meaning of Section 27A of the U.S. Securities Act of 1933 and Section 21E of the U.S. Securities Exchange Act of 1934. These projections and statements reflect the Company’s current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in the Company’s periodic reports filed with the U.S. Securities and Exchange Commission.

Contact: Karen Acierno Director – Investor Relations kacierno@cimarex.com 303‐285‐4957 Mark Burford VP – Capital Markets & Planning Cimarex Energy Co. 1700 Lincoln Street, Suite 3700 Denver, CO 80203 303‐295‐3995

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• Focused on idea generation and execution
• Diverse portfolio of assets provides flexibility

— Balanced commodity mix: Proved reserves are 52% natural gas — Regional optionality: Permian Basin and Mid‐Continent

• Strong balance sheet

— No bank debt — Sale of non‐core assets provides cash at year end — Net debt/total capitalization: 18%

• Long‐term time horizon

Cimarex Value Proposition

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• Expect full‐year 2014

production growth of 25%

— Mid‐Continent operations driving gas (+23%) and NGL (+45%) growth — Permian Basin projects driving 16% oil growth

• Horizontal volume growth

driving earnings and cash flow

— YTD Net Income up 20% — Cash Flow up 35%

Strong Growth Momentum

Daily Production (MMcfe) 350

303 357 324 348

627 705

300 600 900 2012 2013 2014E

Oil & NGL Natural Gas

+25% 864‐870

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Product and Regional Diversity

Revenue Mix Area 3Q 2014 Production: 942 MMcfe/d

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2014 E&D Investment Plan

Total Capital: $1.95 billion By Region:

Drilling 80% Land, Seismic & Cap. Overhead 14% Facilities & Other 6%

• Robust Permian opportunity set commands 74% of capex
• Mid‐Continent investment set to increase in 2015
• Cana‐Woodford infill accelerating
• Mid‐year acquisition consolidates position

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• Delaware Basin focus

— 90+ industry rigs working — 18 Cimarex‐operated rigs

• Multiple projects targeting

multiple zones

— Avalon Shale (oil window)

— Bone Spring sands (oil) — Wolfcamp shale (oil & gas)

Permian Basin Region

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2014 Permian Drilling Capital

• Delineation, development and downspacing tests
• Wolfcamp program includes multiple extended laterals

in the second half

Total Permian $1.2 billion Wolfcamp $650 million

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• Invest $360mm in 2014 to drill

86 gross (50 net) wells

• 60 gross (32 net) wells YTD
• Three areas

■ New Mexico 2nd & 3rd Bone Spring (Eddy & Lea Counties)

• 23 operated wells YTD
• 30‐day average peak IP*: 962

BOE/d; 749 bo/d

■ Texas 3rd Bone Spring (Ward County)

• 7 operated wells YTD
• 30‐day average peak IP*: 989

BOE/d (763 bo/d)

■ Culberson County 2nd Bone Spring

• 12 operated wells YTD
• 30‐day average peak IP*: 1,026

BOE/d (606 bo/d)

*Two stream.

Delaware Basin ‐ Bone Spring Activity

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Delaware Basin Avalon Shale

• Seven wells completed to date

— 30‐day average peak IP of 909 BOE/d (69% oil)

• Upsized frac design unlocks oil

window in the Avalon

• 13,700 net acres identified as

prospective in Lea County

• 200+ locations identified
• 13 net wells planned in 2014
• $160mm of capex

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• ~235,000 net acres in the

fairway

• Multiple Wolfcamp Targets

— Culberson/White City Area

• 100,000+ net acres
• Wolfcamp A, C & D
• JDA with Chevron

— Reeves County

• 80,000 net acres
• Wolfcamp A & B/C

— Ward County

• 42,000 net acres
• Wolfcamp A & B/C

Delaware Basin Wolfcamp Fairway

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Thick, Multi‐pay Wolfcamp Section

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Culberson Area

100,000 net acres

Reeves County

80,000 net acres

Ward County

42,000 net acres

IIndicates producing zone.

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• 100,000+ net acres
• 2013 main objectives

— Drilling to hold acreage — Wolfcamp C & D

• Two rigs; ~20 wells
• 41 wells to date; 30‐day

average IP of 6.5 MMcfe/d

• Product mix of 45% gas;

26% oil; 29% NGL

— Upsize frac stages

• First 20‐stage test has 30‐day

average IP of 8.4 MMcfe/d

— Testing Wolfcamp A — Experiment with long laterals — Stacked lateral test — Design downspacing pilot

• 100,000 net acres
• Joint Development Area with CVX
• Long laterals in Wolfcamp D show

significant uplift

— 30‐day average peak IP of 2,660 BOE/d vs. 1,500 BOE/d on 5k’ — 40% gas, 27% oil, 33% NGL

• Additional long laterals planned

in 4Q (Wolfcamp D & A)

• Wolfcamp A wells average 1,192

BOE/d (54% oil)

• Downspacing pilots producing

— Stacked C/D lateral test — 4‐well, 80‐acre downspacing pilot has average 30‐day peak IP of1,103 BOE/d

• $35mm midstream investment in

2014 ($27mm YTD)

Culberson Focus Area Wolfcamp

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Upsized Returns from Long Lateral with Upsized Frac

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BOE/day Culberson County Wolfcamp D Wells

500 1000 1500 2000 2500 3000 6 12 18 24 30 36 42 48

Months

Old Completion ‐ 5,000 ft. lateral; 12 stages (12‐well average) New Completion ‐ 5,000 ft. lateral; 20 stages (4‐well average) Long lateral ‐ 10,000 ft.; 43 stages (single well ‐ Gallant Fox)

Old New Long Well Cost ($MM) $8.0 $9.0 $13.5 BT IRR 30% 90% 161% NPV10 ($MM) $4.0 $12.2 $31.6

Assumptions: Oil ‐ $90/bbl; Gas ‐ $4/Mcf; NGL ‐ $30/bbl (full recovery)

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Shallow Decline of Upsized Fracs (BOE/d)

Performance of Key Culberson County Wolfcamp Wells

1,365 2,450 ‐ 500 1,000 1,500 2,000 2,500 3,000

30‐day IP Days 30‐60 Days 60‐90 90 day average

1,095 ‐ 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000

Twenty Grand 5,000 ft. lateral Wolfcamp D Wolfcamp A Tim Tam 5,000 ft. lateral Gallant Fox 10,000 ft. lateral

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Upsized Returns – Oil Price Sensitivity

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Culberson County Wolfcamp D Wells Before Tax IRR Realized Oil Price

Assumes $3.50/Mcf gas; $25/bbl NGL

37% 45% 60% 65% 74% 89% 113% 122%

$50 $60 $75 $80 5,000 ft. lateral 10,000 ft. lateral

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Reeves County

• Four‐well, 80‐acre spacing test

producing — Wells average 1,029 BOE/d (49% oil); 30‐day peak IP

• Nearby acreage available for

long laterals

• Offset long lateral completing

— Top‐tier returns implied

• $35mm midstream investment

in 2014 ($28mm YTD)

Ward County

• 12 wells producing with average 30‐

day peak IP of 648 BOE/d; 477 bo/d (74%)

• Optimizing completion & landing

zone

Reeves & Ward Counties

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4Q Long lateral

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• E&D capex of $480mm
• Woodford shale capex of

~$360mm

— Upsized frac boosts results — Production grew 44% year‐

• ver‐year

— Complimentary $238mm acquisition in May — 128,000 net acres prospective for Woodford Shale (86%HBP)

• Drilling already underway
• n 2015 infill development

program

Mid‐Continent Highlights

Operated Well Non‐operated Well

Cana‐Woodford Activity Map Golden Section Hartz Section 2015 Infill

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Upsized Production from Upsized Frac

Cana‐Woodford Shale Completion Comparison Average 30‐day Peak IP

(MMcfe/d)

Hartz Section Golden Section

5% 8% 12%

0.0 2.0 4.0 6.0 8.0 10.0 12.0 Old Completion Golden Section Hartz Section Gas NGLs Oil

10.2 9.6 6.7

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• Redefinition of

Woodford underway

— Glenda well has 30‐day peak IP of 12.4 MMcfe/d

• 69% gas

— Leota well has 30‐day peak IP of 11.4 MMcfe/d

• Includes 662 bo/d

— First 10,000 foot lateral drilled in Woodford

• 30‐day peak IP of 12.9

MMcfe/d (20% oil)

• 7 Meramec tests in 2014

— First well has 30‐day peak IP of 9.4 MMcfe/d (306 bo/d) — 70k net acres (86% HBP)

Mid‐Continent

Woodford test (Leota)

Regional Activity Map

Meramec test & Woodford long lateral (Bomhoff)

Woodford test (Glenda)

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• Diverse portfolio with strong returns

— Multiple Delaware Basin opportunities — Cana‐Woodford upside & re‐delineation — Continuous generation of ideas

• Production growth driving cash flow
• Strong balance sheet

— Sale of non‐core assets provides cash at year end

• Long track record of profitable growth

Well Positioned for 2015 and beyond

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Appendix

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Upsized Wolfcamp Frac

Old Frac Design:

5,000‐foot lateral; 12 stages; 4mm lbs of sand 5,000‐foot lateral; 20 stages; 6mm lbs of sand

New Frac Design:

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MMcfe/day

Cana‐Woodford Production

161 156 184 215 229 216 217 226 255 310 406 ‐ 50 100 150 200 250 300 350 400 450 Q1 12 Q2 12 Q3 12 Q4 12 Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Gas NGL Oil

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Permian Production Growth

29 30 34 36 40 41 46 49 46 53 59 55 58 66 68 ‐ 10 20 30 40 50 60 70 Q1 11 Q2 11 Q3 11 Q4 11 Q1 12 Q2 12 Q3 12 Q4 12 Q1 13 Q2 13 Q3 13 Q4 13 Q1 14 Q2 14 Q3 14 Oil NGL Gas

MBOE/day

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2014 Guidance

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Fourth Quarter Full‐Year Production* Total Equivalent (Mmcfe/d) 930‐955 864‐870 % Liquids 51% 51% Expenses ($/Mcfe): Production $1.08 ‐ $1.12 Transportation, processing & other 0.61 ‐ 0.65 DD&A and ARO accretion 2.55 ‐ 2.65 General and administrative 0.23 ‐ 0.27 Taxes other than income (% of oil and gas revenue) 5.3 ‐ 5.7% Capital Expenditures $1.95 billion

2014 Production, Unit Expense and Capital Guidance

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Permian Basin Oil Takeaway Capacity1

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Existing Takeaway Capacity (Mbo/d) Local Refineries 400 Oil Pipelines 1,575 Total Existing capacity 1,975 Upcoming Capacity Additions (Mbo/d) Long‐Haul Expansions In‐Service Capacity Cactus 2Q15 200 Permian Express Phase II 3Q15 230 Total Long‐Haul Expansion 430 Gathering Expansions Monahans to Crane (PAA) 4Q14 100 Sunrise (PAA) 1Q15 200 Upton to McCamey (PAA) Early 2015 200 Total Gathering Expansions 500

• New gathering lines expected to increase utilization on longhaul pipelines

1 Source: Company data

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Culberson County Wolfcamp Pilots

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Stacked Lateral Test

• Wolfcamp C & D
• Two wells
• Producing/Evaluating

80‐acre Spacing Pilot

• Wolfcamp D
• Four wells
• Producing/Evaluating

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Reeves County Wolfcamp Pilots

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80‐acre Spacing Pilot

• Wolfcamp A
• Four wells
• Producing/Evaluating

Stacked/Staggered Spacing Pilot

• Wolfcamp A
• Six wells
• Flowing Back

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Hedges Oil

Weighted Average Price Period Index (1) Type Bbl/d Floor Ceiling

• Oct. - Dec. '14

WTI Collar 12,000 $85.00 $103.47

Gas

Weighted Average Price Period Index (1) Type MMBTU/d Floor Ceiling

• Oct. - Dec. '14

PEPL Collar 80,000 $3.51 $4.57

• Oct. - Dec. '14

PermEP Collar 60,000 $3.62 $4.50

(1) WTI refers to West Texas Intermediate oil price as quoted on the New York Mercantile Exchange. PEPL refers to Panhandle Eastern Pipe Line Tex/OK Mid-Continent index and PermEp is El Paso Permian Basin index both as quoted in Platt’s Inside FERC.

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Non‐GAAP Reconciliation

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($ in Millions) 2011 2012 2013 Net income (loss) 530 $ 354 $ 565 $ Income tax expense (benefit) 312 207 329 Interest expense, net of capitalized 7 14 23 DD&A and ARO accretion 402 527 624 EBITDA 1,250 1,102 1,541

Reconciliation of Net Income to EBITDA and Adjusted EBITDA

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Non‐GAAP Reconciliation

32 2014 2013 Net cash provided by operating activities $ 1,272 $ 941 Change in operating assets and liabilities 20 92 Adjusted cash flow from operations $ 1,292 $ 1,033 (in millions) Nine months Ended September 30,

Debt/Cap Calculation

2013 Proved Reserves adds (Bcfe)

Revisions of previous estimates (216.1) Extensions & discoveries [C] 727.3 Purchase of reserves 0.5

Total adds [A]

511.7

Total capital $MM [B]

1,603 $

All-sources F&D ($/Mcfe) [B]/[A]

3.13 $

Drilling (excl. revisions) F&D ($/Mcfe) [B]/[C]

2.20 $

Reconciliation of cash flow from operations Finding & development (F&D) cost

2014 Long-term debt $ 1,500 Stockholders' Equity 4,430 Total capitalization $ 5,930 Long-term debt/total capitalization

25%

September 30, (in millions)