Iberia Capital Partners Oil and Gas...
Transcript of Iberia Capital Partners Oil and Gas...
Forward-Looking & Other Cautionary Statements
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The fo l lowing presentat io n inc ludes forward - lookin g statements . These statements re late to future events , such as ant ic ipate d re venue s, earnings , bus ine ss strategie s , compet i t iv e pos i t ion or other aspects o f our operat ions or operat ing results or the industr i e s o r markets in which we operate or part ic ipate in genera l , inc ludi ng guidance regarding the t iming and locat ion of addit ional r igs , results o f the Company's dr i l l i ng program, 2015 capita l budget , the pro jected dr i l l i ng and complet ion cost sav ings and the resultant impact on 2015 capita l bud get , pro jected interna l rates o f return, results o f our hedgin g program, the abi l i ty to fund the Company’s 2015 capita l expend i t ur e budget la rgely with f ree cash, pro ject ions regardin g tota l product ion, average da i ly product ion, percentage l iqui ds , operat ing expense s, product ion ta xes as a percentage o f revenu e, G&A expens es and capita l expend i t ur e levels for 2015. Actua l outcomes and results may d i f fer mater ia l l y f rom what is express ed or forecast in such forward - lookin g statements . These statements are not guarantees o f future performance and invo lve certa in r i sks , uncerta int i e s and assumpt ion s that may prove to be incorrect and are d i f f icu l t to predic t such as o i l and gas pr ices; operat iona l hazards a nd dr i l l i ng r i sks ; potent ia l fa i lure to achieve, and potent ia l delays in achiev ing expected reserves or product ion levels f rom exist i ng and futu re o i l and gas develop m e nt pro jects ; unsuccessfu l exploratory act iv i t ies ; unexpect e d cost increases or technica l d i f f icu l t i e s in construct in g, mainta in i n g or modify i ng company fac i l i t ies ; potent ia l l iab i l i ty for remedia l act ions under ex ist i n g or future env iron m e nta l regulat io ns or f ro m pendin g or future l i t igat io n; l imited access to capita l or s igni f icant l y h igher cost o f capita l re lated to i l l iqu i d i t y or uncerta int y in the do mest ic or internat io nal f inanc ia l markets ; genera l domest ic and internat io na l economic and po l i t ica l condit ions, as wel l as changes in tax, env ironm e nta l and other laws appl icabl e to Jones Energy ’s bus in es s and other economic , bus ine ss , compet i t i v e and/or regulatory factors a f fect ing Jones Ene rgy ’ s bus ine ss genera l ly as set forth in Jones Energy ’s f i l ing s with the Secur i t ie s and Exchange Commiss ion (SEC) . We caut ion you not to p la ce undue re l iance on our forward - lookin g statements , which are only as o f the date o f th is presentat ion or as otherwise indicated , and we express l y d isc la im any responsi b i l i t y for updat ing such informat ion.
The SEC require s o i l and gas companies , in their f i l ing s with the SEC, to d isc lose proved reserves, which are those quant i t i e s o f o i l and gas , which, by ana lys is o f geosc ience and engin e er i n g data , can be est imate d with reasonable certa inty to be economica l ly produc ib l e — f ro m a g iven date forward, f rom known reservo ir s , and under ex ist i ng economic condit ions (us ing unweigh te d average 12 -month f i rst day o f the month pr ices) , operat ing methods, and governme nt regulat io ns — p r ior to the t ime at which contracts prov id in g the r ight to operate expire, unless ev ide nce indicates that renewal i s reasonably certa in, regardles s o f whether determi n i st ic or probabi l i s t ic methods are used for the e st imat io n. The SEC a lso permits the d isc losur e o f separate est imates o f probable or poss ib l e reserves that meet SEC def in i t ion s for such reserve s, however , we current ly do not d isc lose probable or poss ib l e reserves in our SEC f i l ings .
Factors a f fect ing u l t imate recovery inc lude our abi l i ty to acquire the acreage we are target ing and the scope of our ongo ing dr i l l i n g program, which wi l l be d i rect ly a f fected by the ava i labi l i t y o f capita l , dr i l l i ng and product ion costs , ava i labi l i t y o f dr i l l in g serv i ces and equip me n t , dr i l l i n g results , lease expirat ion s, t ransportat ion constra ints , regulatory approva ls and other factors ; and actua l dr i l l i ng results , inc ludi n g geo logica l and mechanica l factors a f fect ing recovery rates . Est imates o f resource potent ia l and dr i l l i n g locat ions may change s igni f ica nt l y as Jones Energy pursues acquis i t io ns. In addit ion, our product ion forecasts and expectat ions for future per iods are dependent upon many assum pt ions, inc ludi ng est imates o f product ion dec l ine rates f rom exist in g wel ls and the undertak in g and outcome of future dr i l l i n g act iv i ty , which may be af fected by s igni f icant commodity pr ice dec l ines or dr i l l i n g cost increases. U.S . investors are urged to cons ider c losely the o i l and ga s d isc losur es in our Form 10-K and other reports and f i l ings with the SEC. Copies are ava i lable f rom the SEC and f rom the Jones Energy websi te .
Who is Jones Energy?
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Experienced Operator
Midcon focus for over 26 years
Horizontal experts with >600 wells drilled
Cost Leader
“Fit for purpose” operations
30% AFE reduction since December
Trusted Partner
Numerous strategic partnerships
Expertise creates opportunities
Steward of Capital
History of value creation
Prepared for market opportunities
Key Statistics
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NYSE Ticker: JONE
Share Price: $10.83
Market Cap: $667 million
Enterprise Value:
$1.5 billion
Sponsor Ownership:
38%
Shares Outstanding:
61.6 million
Production: 26.4 MBoepd
Proved Reserves:
115.3 MMBoe
N o te : P ro v ed res erv es a s o f 1 2 / 3 1 / 1 4 . A v era g e d a i l y p ro d u ct i o n fo r Q 1 2 0 1 5 . S h a re p r i ce a s o f M a y 7 , 2 0 1 5 .
Anadarko BasinKey Formation: Cleveland
Cleveland Production: 19.0 MBoe/dArkoma Basin
Key Formation: WoodfordWoodford Production: 3.5 MBoe/d
Field Office
Austin
First Quarter 2015 Highlights
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1Q15 Production of 26.4 Mboe/d
More than 3,000 Boe/d above 4Q14
Oil production of 8.4 Mboe/d
Cleveland AFE now below $2.65 MM
Margins support additional rigs
Operational efficiencies driving cycle
time reductions
33 stage wells performing as expected
12 drilled / 11 completed
Tracking expected type curve
Borrowing base affirmed at $562.5 MM
Liquidity of ~$500 MM
Cleveland is a World Class Resource Play
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Strong results across Jones Cleveland acreage
Top wells on acreage from all four major acquisitions
Top 4 wells have IRRs greater than 100%
8 out of 10 wells have IRRs greater than 60%
TOP 10 JONE CLEVELAND WELLS1
WellIP30
(Boe/d)
Elmer Graves 615-1H 1,432
Peyton Ranch 417-1H 1,251
Kelln 65-2H 1,116
Buccaneers 11-2H 1,032
Hager Trust 616-2H 933
Robert Doyle B 614-3H 919
Robert Doyle B 614-4H 912
Peyton Ranch 417-2H 894
Elmer Graves 615-5H 838
Hager Trust 616-3H 825
Average 1,015
1 T o p 1 0 Jo n es C lev e la n d w e l l s b y I P 3 0 w i th f i r s t p ro d u ct i o n s in ce th e b eg in n in g o f 2 0 1 4 .
Crusader
Sabine
ChalkerExxonMobil
Well Location
JONE Acreage
Acquisitions
0%
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50%
60%
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100%
2008 2009 2010 2011 2012 2013 2014 2015
US Rig Activity by Region as a % of Total
Midcontinent Activity Resilient
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Midcon activity has composed 20% of total US rig count throughout recent cycles
40% of Midcon rigs operated by private E&Ps
Midcon
East TX/North LA
West TX and NM
North TX
Northeast
Rockies
Other
Consistent Activity Across Multiple Price Cycles
S o u rce : R ig D a ta , T u d o r , P i cker in g , H o l t & C o .D a ta a s o f A p r i l 1 0 , 2 0 1 5
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MB
bls
Cleveland Gross Operated Oil Production
Focused on the Cleveland in 2015
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3 rigs currently running
AFE has dropped 30% since December 2014
Fourth rig by end of May (fifth rig to follow)
>30% oil uplift achieved
Frack optimization successful
33 stage OH completions provide uplift plus savings
High HBP position
>80% HBP
9 wells to be drilled in 2015 to hold leases
2014 leasing added 21,000 net acres
Jones Cleveland Locations Gross: 704Net: 477
~2,500 Cleveland locations remain
JONE Acreage
` 2015 Drilling Targets
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Day
sReduced Cycle Time Improves Efficiency and Returns
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Significant improvement in cycle time since October
Open hole completions driving further improvements
Spud to Spud
Spud to Sales
~50% improvement since Oct peak
$3.8
$2.65
$-
$1.0
$2.0
$3.0
$4.0
Previous AFE Current AFE
AFE
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"All-in" Cleveland AFE Achieved Cost Reductions
Cost Reductions for 33 Stage Open Hole Wells
Over 30% in negotiated cost reductions since 4Q 2014
Achieved Reductions: $1,150,000
Breakdown of Savings:
Frack Services $487,000
Rig Rates $122,000
Downhole Equipment $84,000
Drilling Fluid $73,000
Directional Drilling $66,000
Fuel & Drayage $59,000
Cement & Services $45,000
Other Items $214,000
Total $1,150,000
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Impact of Cost Reductions on Returns
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Note: Based on JONE Cleveland decline curve. IRRs reflect JONE potential cost reductions. Strip as of April 15, 2015.
Well level IRRs for 2015 Cleveland drilling program
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10%
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30%
40%
50%
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70%
80%
90%
$2,200$2,500$2,800$3,100$3,400
IRR
Well Cost ($ thousands)
Unhedged Cleveland Well Level IRRs
Strip +20% Strip +10% Strip Strip -10%
$2.65 MM AFE
Cleveland Frack Optimization Successful
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Number of Frack Stages
2004 - 2006 2007 - 2009 2010 2011 2012
4-5
8-12
20
12
20
2014
43
2015
33
2013
60
Open Hole Completion
Perf and Plug Completion
Sliding Sleeve Completion
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Avg
Cu
mu
lati
ve O
il (M
bb
l)
Effective Frack Stages
Cumulative Oil vs. Frack Stages (at 280 days)
Strong correlation between frack stages and cumulative oil production
33 stages is appropriate frack density for Cleveland
Supported by historical Cleveland production data and frack trial
33 Frack Stages: Ideal Cleveland Density
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Actual frack trial production60
Estimated production
60 Expected frack trial production
Actual production
33 frack stages: Right answer for
Cleveland
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20
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0 50 100 150 200 250 300 350
Oil
Rat
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bp
d)
Days
Oil Uplift Comparison
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Optimization Drives Oil Uplift
2015 20 Stage Type Curve
Production Data from Wells with Over 20 Stages
EUR
20 stage 33 stage
Oil (Mbbls) 81 112
Gas (MMcf) 541 545
NGL (Mbbls) 70 71
Total (Mboe) 241 274
+38% increase
2015 33 Stage Type Curve
0%
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% o
f w
ells
wit
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iven
IP9
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Oil IP90 (Boe/d)
Increased Oil with Greater Predictability
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Increased frack density means more oil and more predictable results
Only 30 Cleveland wells required to achieve type curve
Expected range of outcomes more narrow and higher on average
IP90 highly correlated with EUR
> 20 Stages
≤ 20 Stages
Cleveland Oil IP90
$0
$100
$200
$300
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$500
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$700
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$55 Strip $75
$ in
th
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san
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Incremental PV-10 Value
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$55 Strip $75
$ in
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Incremental Oil Revenue(1)
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Oil Uplift Has Created Significant Value
(1) Incremental oil revenue for a 33 stage open-hole well as compared to a 20 stage open-hole well for full productive life of the well. Assumes 2015 Cleveland type curve. Strip as of April 15, 2015.
$270,000 investment translates to:
$1,250,000 – $1,750,000 in incremental oil revenue per location
$475,000 – $765,000 in incremental PV-10 value per location
Value accelerates as oil price increases
~$600,000 PV-10 value
$1.0
$1.5
$2.0
$2.5
$3.0
20 stage well 33 stage well
$ in
mill
ion
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Cleveland Well Cost Comparison
~$270,000increase
~$1,500,000 oil revenue
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2014 LOE and G&A Costs Among the Best
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LOE per Boe Cash G&A per Boe
Note: LOE and Cash G&A per Boe calculated on full-year 2014 basis. LOE excludes ad valorem and production taxes. Peers include AREX, BBG, BCEI, CRK, CRZO, CWEI, FANG, GDP, LPI, MHR, MPO, MTDR, PDCE, PQ, REN, REXX, ROSE, SFY, and SGY.
0%
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100%
$60 oil / $3.25 gas $30 oil / $2 gas $10 oil / $1 gas
Pro
ject
ed
Rev
en
ue
Unhedged Revenue Hedge Gain
Hedges Protect 2015 Revenue
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Hedging Impact on 2015 Revenue
Only ~5% change in total revenue due to hedges
Ready for Market Opportunities with Strong Balance Sheet
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$562.5 million borrowing base reaffirmed
~$500 million in liquidity
~90% of debt outstanding matures in >7 years
2.8x net debt/EBITDAX for trailing twelve months2
1 Undrawn credit facility as of April 15, 20152 Based on net debt as of year-end 2014 and full-year 2014 EBITDAX
$0
$100
$200
$300
$400
$500
$600
2015 2016 2017 2018 2019 2020 2021 2022 2023
$ in
mill
ion
s
Debt Maturities Summary
Undrawn credit facility1
Jones Energy – Prepared for Today and Focused on the Future
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Solid Financial Position
Plenty of liquidity; spending within cash flow
Substantial hedges at favorable prices
Mid-Continent Focus
History of success for over 26 years
Expertise creates opportunities
Operational Excellence
“Fit for purpose” operations
A leader in cost management
Focused on Value Creation
Oil uplift drives returns
Beginning to ramp activity as planned
Substantial Footprint with Running Room
Lots to do in our own backyard
Stacked pays provide growth opportunities
2015 Cleveland Type Curve
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Key Statistic: Oil Gas NGL TotalIP Bbl/d Mcf/d Bbl/d Boe/d
IP30 228 641 83 418 IP90 189 612 80 371
Cumulative Production Mbbl MMcf Mbbl Mboe
1 Year 36 141 18 78 5 Year 68 294 38 155 EUR 112 545 71 274
% of Total 41% 33% 26% 100%
Key statistics shown below for 2015 Cleveland type curve (274 Mboe EUR)
Cleveland 3P EUR of 305 Mboe, but with a higher gas component
The Anadarko Basin – Prolific History with Stacked Pay Potential
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MarmatonSandstone
Lease Acreage: ~97,000Gross Locations: 566
ClevelandSandstone
Lease Acreage: ~163,000Gross Locations: 704
TonkawaSandstone
Lease Acreage: ~122,000Gross Locations: 324
Stacked pay zones provide significant development opportunities
Current Target Formations
JONE Acreage
Tonkawa – An Untapped Opportunity
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Drilled 6 wells in 2014
Target AFE of $3.5 million
Drilling program halted due to oil drop
Ready to scale when economics dictate
Industry continues to derisk acreage
Extensive vertical production footprint
Over 500 horizontal wells drilled by industry
Underdeveloped compared to Cleveland
Jones has identified 324 gross (190 net) locations as of year-end 2014
Over 3,000 additional play locations
Cleveland technical expertise derisksfuture Tonkawa development
Tonkawa2.9 million acres
Average formation depth:Tonkawa: 7,500 feetCleveland: 8,500 feetMarmaton: 9,000 feet
JONE Acreage
Marmaton Shows Promise As Others Drill Ahead
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Marmaton lies just below Cleveland
Majority of Jones Anadarko acreage lies within the Marmaton fairway
Results by other operators indicate EURs and production profiles on par with other targets in the basin
No locations booked in 1P
Jones has identified 566 gross drilling locations (334 net) as of year-end 2014
Over 2,500 additional locations in play fairway
Similar geology to Cleveland
Often referred to as “Lower Cleveland”
Completed geological study across 5 counties
Marmaton Lime1.0 million acres
Marmaton Sand2.1 million acres
Average formation depth:Tonkawa: 7,500 feetCleveland: 8,500 feetMarmaton: 9,000 feet
JONE Acreage
0
20
40
60
80
100
120
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2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Wel
ls D
rille
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Drilling History by Formation
Brown Dolomite
Tonkawa
Cleveland
Granite Wash
Morrow
Woodford
Dropped all rigs in 4Q08, but ramped activity in 2010 after
prices recovered
Able to Ramp Activity as Margins Dictate
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Operational flexibility allows us to ramp activity up and down
Reduced 2015 activity with focus on the
Cleveland
2015 Full Year Guidance and 2Q Production Guidance
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2015E 2Q15E
Total Production (MMBoe) 7.9 – 8.7 2.05 – 2.15
Average Daily Production (MBoe/d) 21.7 – 23.7 22.5 – 23.5
Oil (MBbls/d) 6.6 – 7.1 6.7 – 7.0
Natural Gas (MMcf/d) 54.8 – 60.3 57.0 – 60.0
NGLs (MBbls/d) 6.0 – 6.6 6.3 – 6.6
Lease Operating Expense ($/Boe) $4.75 – $5.25
Production/Ad Valorem Taxes (% of Unhedged Revenue) 6.5% – 7.5%
Cash G&A Expense ($mm) $25.0 – $28.0
Total Capital Expenditures ($mm) $210.0
Hedge Positions
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2015 2016
2Q 3Q 4Q 1Q 2Q 3Q 4Q
Crude Swaps (Mbbl) 613 595 572 492 465 457 411
Hedge Price / Bbl $82.93 $84.60 $84.05 $83.53 $83.67 $83.64 $83.35
Natural Gas Swaps (MMcf) 5,095 4,740 4,636 4,340 4,130 3,960 3,800
Hedge Price / Mcf $4.41 $4.47 $4.45 $4.65 $4.45 $4.45 $4.37
NGLs (MBbl)
Ethane 110 101 92 15 14 12 12
Propane 226 192 168 160 146 135 126
Iso Butane 15 15 12 6 6 4 -
Butane 45 42 41 12 11 9 6
N. Gasoline 60 57 53 24 22 21 16
Total NGL 456 407 366 217 199 181 160
Hedge Price ($/gal)
Ethane $0.27 $0.27 $0.27 $0.21 $0.21 $0.21 $0.21
Propane $0.85 $0.89 $0.93 $0.55 $0.55 $0.55 $0.56
Iso Butane $1.23 $1.23 $1.25 $1.30 $1.30 $1.39 N/A
Butane $1.21 $1.21 $1.20 $1.26 $1.28 $1.32 $1.26
N. Gasoline $1.94 $1.95 $1.95 $1.99 $1.88 $1.89 $1.82
NGL Hedge Position Detail
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2015 2016
2Q 3Q 4Q 1Q 2Q 3Q 4Q
Mt. Belvieu NGLs (MBbl)
Ethane 55 50 46 - - - -
Propane 42 39 39 - - - -
Iso Butane 3 3 3 3 3 3 -
Butane 15 15 16 6 6 6 3
N. Gasoline 24 24 23 18 18 18 13
Sub-Total Mt. Belvieu 139 131 127 27 27 27 16
Hedge Price ($/gal)
Ethane $0.34 $0.34 $0.34 N/A N/A N/A N/A
Propane $1.01 $1.01 $1.01 N/A N/A N/A N/A
Iso Butane $1.55 $1.55 $1.55 $1.48 $1.48 $1.48 N/A
Butane $1.36 $1.36 $1.31 $1.42 $1.42 $1.42 $1.42
N. Gasoline $2.06 $2.06 $2.05 $2.09 $1.93 $1.93 $1.85
Conway NGLs (MBbl)
Ethane 55 51 46 15 14 12 12
Propane 184 153 129 160 146 135 126
Iso Butane 12 12 9 3 3 1 -
Butane 30 27 25 6 5 3 3
N. Gasoline 36 33 30 6 4 3 3
Sub-Total Conway 317 276 239 190 172 154 144
Hedge Price ($/gal)
Ethane $0.20 $0.20 $0.20 $0.21 $0.21 $0.21 $0.21
Propane $0.81 $0.86 $0.90 $0.55 $0.55 $0.55 $0.56
Iso Butane $1.16 $1.16 $1.15 $1.13 $1.13 $1.13 N/A
Butane $1.13 $1.13 $1.13 $1.11 $1.11 $1.11 $1.11
N. Gasoline $1.87 $1.86 $1.87 $1.70 $1.70 $1.70 $1.70
NGL Barrel Component Detail
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Cleveland Conway
Woodford Mont Belvieu
*Assumes ethane rejection in the Woodford
Ethane – 37%
Propane – 34%
Iso Butane – 5%
Butane – 12%
Natural Gasoline – 12%
Ethane – 13%
Propane – 45%
Iso Butane – 5%
Butane – 19%
Natural Gasoline – 18%
Woodford
Cleveland
Basket Ethane 37% Propane 34% Butane 12% Iso Butane 5% Natural Gasoline 12%
Basket Ethane* 13% Propane 45% Butane 19% Iso Butane 5% Natural Gasoline 18%
(80% of forecasted 2015 NGL production)
(20% of forecasted 2015 NGL production)
Corporate Structure
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Jones Energy, Inc.(NYSE: JONE)
Jones Energy Holdings, LLC
(JEH LLC)
Metalmark,Management
& Other Investors
PublicShareholders
Class A Common Stock
41% of voting power in Jones Energy, Inc.
59% of total economic interest
of JEH LLC
41% of total economic interest of
JEH LLC
Class B Common Stock
59% of voting power in Jones Energy, Inc.
Updated for recent capital markets transactions
Stock trading liquidity has improved significantly post-recent transactions
JONE company ownership summaryMetalmark 38%Jones Family and Management 22%JVL Advisors 7%GSO Capital Partners 4%Magnetar Capital 4%Remaining Shareholders 25%Total 100%