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BAML Energy ConferenceMiami | November 2014
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Forward‐looking StatementsThis presentation contains projections and
other 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 AciernoDirector – Investor [email protected]‐285‐4957
Mark BurfordVP – Capital Markets & Planning
Cimarex Energy Co.1700 Lincoln Street, Suite 3700Denver, CO 80203303‐295‐3995
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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
3
4
• 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)
350303
357
324
348627
705
0
300
600
900
2012 2013 2014E
Oil & NGL Natural Gas
+25%864‐870
5
Product and Regional Diversity
RevenueMix Area
3Q 2014 Production: 942 MMcfe/d
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2014 E&D Investment PlanTotal Capital: $1.95 billion By Region:
Drilling80%
Land, Seismic & Cap.
Overhead14%
Facilities & Other6%
• 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
8
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
9
• 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
12
Culberson Area100,000 net acres
Reeves County80,000 net acres
Ward County42,000 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 ($27mm YTD)
Culberson Focus Area Wolfcamp
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Upsized Returns from Long Lateral with Upsized Frac
14
BOE/day
Culberson County Wolfcamp D Wells
0
500
1000
1500
2000
2500
3000
0 6 12 18 24 30 36 42 48
MonthsOld Completion ‐ 5,000 ft. lateral; 12 stages (12‐well average)
New Completion ‐ 5,000 ft. lateral; 20 stages (4‐well average)
Long lateral ‐ 10,000 ft.; 43 stages (single well ‐ Gallant Fox)
Old New LongWell Cost ($MM) $8.0 $9.0 $13.5BT IRR 30% 90% 161%NPV10 ($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
3,00030‐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 Grand5,000 ft. lateral
Wolfcamp D Wolfcamp A
Tim Tam5,000 ft. lateral
Gallant Fox10,000 ft. lateral
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Upsized Returns – Oil Price Sensitivity
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Culberson County Wolfcamp D WellsBefore Tax IRR
Realized Oil PriceAssumes $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‐
over‐year— Complimentary $238mm
acquisition in May— 128,000 net acres prospective
for Woodford Shale (86%HBP)
• Drilling already underway on 2015 infill development program
Mid‐Continent Highlights
Operated WellNon‐operated Well
Cana‐Woodford Activity Map
Golden Section
Hartz Section
2015 Infill
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Upsized Production from Upsized FracCana‐Woodford Shale Completion ComparisonAverage 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
10.29.6
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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23
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:
24
24
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
25
25
Permian Production Growth
29 30
34 36
40 41
46 49
46
53
59
55 58
6668
‐
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
26
2014 Guidance
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Fourth Quarter Full‐YearProduction*Total Equivalent (Mmcfe/d) 930‐955 864‐870
% Liquids 51% 51%
Expenses ($/Mcfe):Production $1.08 ‐ $1.12Transportation, 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
27
Permian Basin Oil Takeaway Capacity1
27
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 CapacityCactus 2Q15 200Permian Express Phase II 3Q15 230 Total Long‐Haul Expansion 430
Gathering ExpansionsMonahans to Crane (PAA) 4Q14 100Sunrise (PAA) 1Q15 200Upton 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
29
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
OilWeighted Average Price
Period Index (1) Type Bbl/d Floor Ceiling
Oct. - Dec. '14 WTI Collar 12,000 $85.00 $103.47
GasWeighted 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 $4.50
(1) WTI refers to West Texas Intermediate oil price as quoted on the New York Mercantile Exchange. PEPL refers to Panhandle Eastern Pipe Line Tex/OK Mid-Continent index and PermEp is El Paso Permian Basin index both as quoted in Platt’s Inside FERC.
31
Non‐GAAP Reconciliation
31
($ 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
32
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)