ecr corporate presentation - amazon s3utica.pdf · 1. as of june 5, 2015 2. as of march 31, 2015....

NYSE|ECRNYSE|ECR

Investor PresentationJune 2015

3

June 2015 Corporate Presentation

3

Company Overview Key Statistics

Market Capitalization(1) $1.4 Billion

Pro Forma Liquidity(2) $407 Million

Total Debt Outstanding, Pro Forma $550 Million

Borrowing Base Available $97 Million

Cash-On-Hand, Pro Forma for Offering $310 MillionAvg. Daily Production (MMcfe/d / % Liquids)

4Q-14 124 (27%)

2014 73 (26%)

1Q-15 160 (31%)

2Q-15 Guidance ~170-180 (~37%)

2015 Guidance ~180-190 (~32%)

Proved Reserves(3) 355.8 Bcfe

PV-10(3) $509 Million

% Liquids(3) 28%

Total Resource Potential(4) 6.5 Tcfe

Total Estimated Resource Potential Value(4) $4.0 Billion

Est. 2015 Capital Expenditures $352 Million

Net Core Acreage(5) 128,000

Utica Liquids Rich (% of Total) 51,700 (40%)

Utica Dry 49,300 (39%)

Marcellus Liquids Rich(5) 27,000 (21%)

Identified Remaining Net Drilling Locations 800

1. As of June 5, 20152. As of March 31, 2015. Cash and cash equivalents of $310MM and an effective borrowing base of $97MM ($125MM borrowing base less $28MM for letters of credit outstanding)3. As of December 31, 2014; proved reserves based on estimates provided by Eclipse's independent engineering firm. PV-10 is based on SEC pricing4. Resource potential is based on internal estimates and includes, but does not represent, total proved reserves. Remaining resource potential PV-10 is based on Wall Street

consensus estimates as of May 22, 2015; see Appendix for details5. As of April 30, 2015; acreage in Marcellus also included in Utica Dry6. Calculated by dividing net remaining identified drilling locations by net wells expected to be spud in the 2015 drilling plan. Drilling locations are specifically identified based on

the current configuration of Eclipse’s leasehold, developed and planned units and proposed non-operated wells. The Company generally assumes 1,000’ interlateral spacing for acreage within the Dry Gas areas and 750‘ interlateral spacing elsewhere

Eclipse Asset Area

Eclipse Resources is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin

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Developing Value & Improving Efficiencies

Proved Reserves (1) (Bcfe)

Eclipse continues to convert unproved assets into proved reserves, while its drilling plan creates opportunities for significant growth

1. As of December 31, 2014; proved reserves based on estimates provided by Eclipse's independent engineering firm2. A non-GAAP financial measure; see Appendix for GAAP reconciliation3. Type Curve Well AFE assuming a 6,000’ lateral

Average Gross Lateral Feet per WellNet Production (MMcfe/d)

Adjusted EBITDAX(2) ($MM) Well Costs(3) ($MM)Adjusted Revenue(2) ($MM)

38.5

159.6

-

30

60

90

120

150

180

1Q14 1Q15

316%

23.3

49.8

-

10

20

30

40

50

60

1Q14 1Q15

113%

11.9

20.7

-

10

20

30

1Q14 1Q15

73%

9.5

7.4

10.5

8.2

0

3

6

9

12

15

2014 2015

Wet

Gas

Wet

Gas

Dry G

as

Dry G

as

~23%

5,996

7,173

5,000

5,500

6,000

6,500

7,000

7,500

8,000

1Q14 1Q15

20%

78.5

355.8

-

75

150

225

300

375

YE 2013 YE 2014

353%

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5

Premier Southern Utica & Rich Marcellus Position(1)

Eclipse’s core acreage position is well delineated in the heart of a world-class play

1. Producing 30-day average sales rate; assumes ethane rejection with contractual 30% recovery

ECR 10 WellsIP Rate 4.6 MMcfe/d

60% LiquidsAvg. 6,044’ Lateral

*

*

**

*

***

ECR 1 WellIP Rate 13.8 MMcfe/d




ECR 1 WellIP Rate 18.6 MMcfe/d










**

*ECR 6 Wells

IP Rate 7.1 MMcfe/d61% Liquids

Avg. 6,637’ Lateral





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6

69.363.5

47.443.0

33.6

21.8

-

20

40

60

80

ECR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

Peer average: 41.9

Peer Leading Growth with Utica LeverageEclipse expects to achieve peer leading production growth and generate significant associated future proved reserve growth

2014 – 2017E Production Growth CAGR(1)(2)

Non-Op D&C29%

Op D&C:Liquids

12%

Op D&C:Dry Gas

46%

Land &Other12%

2015E CapEx = $352 MM(3)

Utica Acreage Per $1 MM Enterprise Value(4)

1. Production CAGR peer companies include: AR, CHK, CNX, COG, EQT, GPOR, MHR, REXX, RICE, RRC, SWN2. Based on analyst consensus estimates, Wall Street research and peer company disclosures3. Per Eclipse guidance4. Acreage peer companies include: AR, CHK,CNX, GPOR, RICE

75%

52%

40%

30% 25% 24% 20% 19% 15% 14% 14%

(3%)-10%

10%

30%

50%

70%

90%

ECR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10Peer 11

Peer avg: 23%

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7

78.5 109.6

186.4

245.5

355.8

$155.3

$253.8

$337.9

$401.2 $509.4

$-

$100

$200

$300

$400

$500

$600

-

100

200

300

400

500

600

Q4-13 Q1-14 Q2-14 Q3-14 Q4-14

PV-1

0 ($

MM

)

Rese

rves

(Bcf

e)

PDP PNP/PBP PUD Net PV-10 ($ MM)

Net Oil (Mbbls)

Net NGL (Mbbls)

Net Gas (MMcf)

Net Total(MMcfe)

Net PV-10 ($M)

PDP 2,967 4,269 93,561 136,978 321,184PNP/PBP 914 2,489 39,398 59,818 113,180PUD 1,816 4,120 123,350 158,972 75,025

Total Proved 5,697 10,879 256,310 355,768 509,389

Growing Proved Reserves(1)

1. Q4-13, Q1-14, Q3-14 and Q4-14 reserves prepared by Eclipse’s independent engineering firm. Q2-14 reserve estimates prepared internally. Based on SEC pricing from Q4 2013 to Q4 2014 for WTI: $96.91, $98.43, $100.27, $99.08, $94.99 and for Henry Hub: $3.67, $3.99, $4.10, $4.24, $4.35. These prices are above NYMEX strip pricing

Total Proved Reserves(1)

Eclipse has been able to achieve significant growth in proved reserves and proved developed reserves since the commencement of its active drilling program in late 2013

85% of Proved Value

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Significant Reserves and Resource Potential

1. Proved reserves PV-10 is based on SEC pricing as of December 31, 2014. Remaining resource potential PV-10s are based on Wall Street consensus estimates as of May 22, 2015; see Appendix for details. Proved reserves prepared by Eclipse’s independent engineering firm as of December 31, 2014. Resource potential estimates prepared internally. Potential categories do not represent proved reserves

2. Pro forma from March 31, 2015 after debt offering; stock price as of June 5, 2015

Resource Potential Overview(1)

Management estimates Eclipse’s asset base generates approximately $4.0 billion of present value at current drilling space and commodity prices

Resource Potential PV-10 ($MM)(1)

Type Curve Area Bcfe PV-10 ($MM)Proved Reserves 356 $509Dry Gas Areas 3,369 2,095 Rich Gas Areas 988 253Condensate Areas 781 585Total Utica Core Area 5,494 $3,442Marcellus Areas 1,045 584Total Resource Potential 6,539 $4,026

Significant additional potential value through:• Downspacing from 1,000’ to 750’ in Dry Gas and 750’ to 500’ in Liquids areas currently being tested, which could

increase net locations by 20-40%• Potential upward revisions in current type curve assumptions• Acceleration of drilling pace back to 3-4 rig program

$4,026

$509

$2,095

$253 $585 $584

Proved Reserves Dry Gas Areas Rich Gas Areas Condensate Areas Marcellus Areas Total ResourcePotential

$1.6 billion of Enterprise Value

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9 -

1

2

3

4

5

-

100

200

300

400

500

Q1-14 Q2-14 Q3-14 Q4-14 Q1-15 Q2-15 Q3-15 Q4-15 Q1-16 Q2-16 Q3-16 Q4-16

Ope

rate

d Ri

g Co

unt

MM

cfe/

d

Efficiently Growing Production through the Drill Bit

2015 Net SpudsMap of 2015 ActivityEclipse expects to grow year-over-year production by ~150% from 2014 to 2015

1. Based on company estimates

2015 Net TTS

Net Production(1) vs. Rig Count

5 5

4

5

-

1

2

3

4

5

6

Q1 Q2E Q3E Q4E

11

2

9

2

-

2

4

6

8

10

12

Q1 Q2E Q3E Q4E

• Expect ~145-160% growth from 2014-2015 with one operating rig• Expect ~60-80% growth from 2015-2016 with one operating rig and

completion of 15 net drilled not-completed wells in liquids area

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Top Tier Drilling Performance Enhancing Capital Efficiency Eclipse has participated to date in drilling 187 gross

Utica Shale wells to Total Depth (TD)– 70 operated wells– 117 non-operated wells with 8 different operators

Eclipse has drilled its last 20 operated wells to TD in an average of 18 days (normalized to 15,600 TMD)

– Recently drilled well with total measured depth of ~21,000’ (~10,500’ lateral) in just 17 days

Since commencing operated drilling in 2013, Eclipse has increasing lateral length by 33%, while decreasing wells costs by 23% from 2014

Type Well Cost per Lateral Foot

1. Normalized to 15,600’ TMD

Lateral Length (Ft) Drilling Days(1)

6,239 6,836

8,300

-

2,000

4,000

6,000

8,000

10,000

2013 2014 2015

1.6

1.2

1.8

1.4

-

0.5

1.0

1.5

2.0

2.5

2014 2015 2014 2015

Wet Gas Dry Gas

31

2629

18

0

10

20

30

40

Non-Op Eclipse Non-Op Eclipse

All WellsSince Inception

Last 20 Wells

19% Faster

38% Faster

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Single Well Economics (8,000’ lateral)

1. Consensus prices based on Wall Street consensus estimates as of May 22, 2015; Strip pricing as of June 17, 2015; see table in Appendix for details; Type curves do not represent proved reserves

Type Curve IRR and Net Locations

Rich Lean Condensate Rich Dry Gas Dry Gas Marcellus MarcellusCondensate Condensate / Rich Gas Gas West East West East

EUR (Bcfe/1000 ft) 0.7 1.1 1.2 1.7 2.1 2.7 0.7 1.5%Gas 45% 50% 59% 69% 100% 100% 41% 45%Assumed Well Spacing (ft) 750 750 750 750 1,000 1,000 750 750Net Locations 25 103 85 51 216 66 114 91

Type CurveMetrics

Condensate Areas Rich Gas Areas Dry Gas Areas Marcellus Areas

Gas Oil Gas Oil($/Mcf) ($/Bbl ) ($/Mcf) ($/Bbl )

2015 2.93$ 60.70$ 3.18$ 60.29$ 2016 3.23$ 62.96$ 3.70$ 68.64$ 2017 3.38$ 64.56$ 4.08$ 74.10$ 2018 3.46$ 66.16$ 4.25$ 76.81$ 2019 3.64$ 69.93$ 4.25$ 75.00$ 2020+ 4.00$ 75.00$ 4.25$ 75.00$

Strip Consensus

19%

37%25%

31%

49%

74%

27%

109%

13%26%

16% 19%

32%

50%

19%

86%

0%10%20%30%40%50%60%70%80%90%

100%110%

RichCondensate

LeanCondensate

Condensate/Rich Gas

Rich Gas Dry GasWest

Dry GasEast

MarcellusWest

MarcellusEast

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21

0.6%

3.6%

28.4%

9.7%12.2%

45.6%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

2015 2016 2017 2018 2019+ Fee/HBP

<5% of Eclipse's acreage expires before 2017

Favorable Lease Expiration Schedule~58% of leases have a 5-year extension option

Utica Core Area Leasehold Expiration(1)

1. As of December 31, 2015 assuming current drilling program

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22

Rich Condensate Lean CondensateCondensate /

Rich GasRich Gas Dry Gas West Dry Gas East Marcellus West Marcellus East

Identified Net Drilling Locations 25 104 78 53 220 66 115 92

Type Curve Assumptions

Gas CharacteristicsInitial Production (MMcf/d) (1) 2.0 3.2 4.5 7.0 10.5 13.5 1.8 4.3

Exponential Phase

Initial Decline (%) 20% 20% 20% 20% 20% 20% 20% 20%

Months 8 8 8 8 8 8 8 8

Hyperbolic Phase

Initial Decline (%) 55% 55% 55% 55% 55% 55% 55% 55%

B Factor 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0

Terminal Decline (%) 6.0% 6.0% 6.0% 6.0% 6.0% 6.0% 6.0% 6.0%

Condensate Characteristics

Initial Cond. Yield (Bbl/MMcf) 175 120 60 15 N/A N/A 150 100

Terminal Cond. Yield (Bbl/MMcf) 70 48 15 5 N/A N/A 60 35

Cond. Yield Transition Time (Mth) 12 12 10 8 N/A N/A 8 8

NGL Characteristics

NGL Yield (Bbl/MMcf) 92 88 80 60 N/A N/A 125 125

Gas Shrink 85.1% 85.2% 86.2% 90.0% N/A N/A 81.0% 81.0%

BTU 1,300 1,287 1,265 1,200 1,050 1,025 1,400 1,400

Residue BTU 1,125 1,120 1,100 1,085 1,050 1,025 1,130 1,130EUR (MMcfe) (2) 4,254 6,320 7,457 10,462 12,391 16,116 3,913 8,973

Oil (MBbl) 187 210 99 47 0 0 135 201

NGL (MBbl) 205 322 410 485 0 0 248 622

Residue Gas (MMcf) 1,904 3,130 4,400 7,271 12,391 16,116 1,610 4,033

% Liquids 55.2% 50.5% 41.0% 30.5% 0.0% 0.0% 58.9% 55.1%

Lateral Length (ft.) 6,000 6,000 6,000 6,000 6,000 6,000 6,000 6,000

Differentials

Gas ($/MMBtu) ($0.80) ($0.80) ($0.80) ($0.80) ($0.80) ($0.80) ($0.80) ($0.80)

Condensate ($/Bbl) (8.00) (8.00) (8.00) (8.00) (8.00) (8.00) (8.00) (8.00)

NGL (% of WTI) 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0%

Operating Costs ($MM)

Fixed OPEX ($/well/mo) $8,500 $8,500 $8,500 $8,500 $8,500 $8,500 $8,500 $8,500

Gathering & Compression ($/Mcf) $0.89 $0.89 $0.89 $0.89 $0.49 $0.49 $0.89 $0.89

Processing ($/Dth) $0.75 $0.74 $0.70 $0.60 $0.00 $0.00 $0.75 $0.75

Oil Transportation Expense ($/Bbl) $3.50 $3.50 $3.50 $3.50 N/A N/A $3.50 $3.50

Severance Tax (%) 6.0% 6.0% 6.0% 6.0% 6.0% 6.0% 6.0% 6.0%

Capital Cost ($MM)

Pad $0.5 $0.5 $0.5 $0.5 $0.4 $0.4 $0.1 $0.1

Drilling 2.7 2.7 2.7 2.7 3.3 3.3 2.4 2.4

Completions 3.5 3.5 3.5 3.5 3.8 3.8 3.1 3.1

Facilities 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7

Type Curve & Cost Assumptions

1. 24-hour rate2. Assumes ethane rejection with contractual 30% recovery

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Operated Producing Well Detail

1. Assumes ethane rejection with contractual 30% recovery

Firs

t Qua

rter

201

5Well Name

Completed Lat Length

Type Curve Area Turn-to-Sales Month 24-Hr Peak Sales Rate (Mcfe/d) Producing 30-Day Avg Sales Rate(1) (Mcfe/d) % Gas % NGL % Oil

Tippens 6HS 5,850 Dry Gas West December-13 23,585 18,601 100% 0% 0%Herrick A 3H 5,761 Dry Gas West June-14 17,068 13,511 100% 0% 0%Herrick B 5H 6,380 Dry Gas West June-14 14,616 10,828 100% 0% 0%Herrick C 8H 6,232 Dry Gas West June-14 16,590 14,503 100% 0% 0%Shroyer 2H 8,235 Dry Gas East August-14 30,144 24,848 100% 0% 0%Shroyer 4H 6,608 Dry Gas East August-14 23,663 22,131 100% 0% 0%Mizer 2H 5,986 Lean Condensate August-14 7,910 5,540 39% 24% 37%Mizer 4H 5,903 Lean Condensate August-14 7,798 5,856 40% 24% 36%Mizer 6H 5,811 Lean Condensate August-14 6,173 4,473 40% 24% 36%Mizer 8H 5,970 Lean Condensate August-14 7,559 5,978 41% 25% 34%Mizer 10H 5,943 Lean Condensate August-14 6,999 5,522 41% 25% 34%Duane Weisend 4H 8,853 Dry Gas West September-14 15,525 13,770 77% 23% 0%Mizer Farms 1H 6,421 Lean Condensate September-14 6,882 3,491 40% 25% 35%Mizer Farms 3H 6,467 Lean Condensate September-14 5,299 2,343 39% 24% 37%Mizer Farms 5H 6,343 Lean Condensate September-14 6,795 2,747 38% 24% 38%Mizer Farms 7H 5,826 Lean Condensate September-14 6,904 3,556 40% 24% 36%Mizer Farms 9H 5,823 Lean Condensate September-14 7,761 4,781 38% 23% 39%Fritz 3H 7,431 Lean Condensate November-14 7,535 4,627 36% 23% 41%Fritz 5H 7,436 Lean Condensate November-14 6,931 4,532 37% 23% 40%Fritz 7H 7,315 Lean Condensate November-14 7,155 4,310 37% 23% 40%Hayes 2H 6,201 Lean Condensate November-14 7,022 3,486 35% 21% 44%Hayes 4H 6,324 Lean Condensate November-14 7,557 4,256 39% 24% 37%Hayes 6H 6,347 Lean Condensate November-14 6,710 3,790 40% 25% 35%Hayes 8H 6,320 Lean Condensate December-14 5,929 3,419 41% 25% 34%Pora 2H 7,862 Lean Condensate December-14 7,211 4,538 40% 24% 36%Pora 4H 7,741 Lean Condensate December-14 7,127 4,546 42% 26% 32%Pora 6H 7,812 Lean Condensate December-14 5,210 3,760 41% 26% 33%Pora 8H 7,771 Lean Condensate December-14 5,190 3,982 42% 26% 32%Frank Miller 2H 6,755 Lean Condensate February-15 6,701 5,079 38% 23% 39%Frank Miller 4H 6,771 Lean Condensate February-15 6,593 5,143 37% 24% 39%Frank Miller 6H 6,646 Lean Condensate February-15 6,830 5,295 38% 23% 39%John Mills West 1H 8,516 Lean Condensate February-15 8,961 7,670 36% 22% 42%John Mills West 3H 7,285 Lean Condensate March-15 8,546 7,612 36% 22% 42%Andy Yoder A 1H 7,323 Lean Condensate March-15 8,762 7,230 37% 22% 41%Andy Yoder D 2H 6,242 Lean Condensate March-15 7,143 6,807 39% 25% 36%Andy Yoder A 3H 6,978 Lean Condensate March-15 8,684 7,607 37% 23% 40%Andy Yoder D 4H 6,262 Lean Condensate March-15 7,074 6,716 40% 25% 35%Andy Yoder A 5H 6,762 Lean Condensate March-15 8,272 7,381 38% 23% 39%Andy Yoder D 6H 6,256 Lean Condensate March-15 6,961 6,656 40% 24% 36%

Average 6,738 9,471 7,203First Quarter 2015 Average 6,891 7,684 6,654

ecr corporate presentation - amazon s3utica.pdf · 1. as of june 5, 2015 2. as of march 31, 2015....

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