enercom’s london oil & gas conference corp - enercom london 2013.pdfcalculated ror = 49% - 70%...
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EnerCom’s London Oil & Gas ConferenceJune 11, 2013
Overview of Operations
Tulsa based diversified energy company incorporated in 1963
Integrated approach to business allows Unit to balance its capital deployment through the various stages of the energy cycle
16
18
Bakken
Casper Office
16127 Unit Rigs
E&P Plays
Mid-Stream Operations
Arkoma Basin
Marcellus
North La/ East Texas Basin
Gulf Coast Basin
Houston Office
Oklahoma City Office
Tulsa Headquarters
Anadarko Basin
Permian Basin
2Integrated Business ApproachIntegrated Business Approach
77
3
Key Growth Points
Exploration & Production– 212% average production replacement since 2003– 130% increase in liquids production since Q1 2009, when Unit began focusing
almost entirely on increasing liquids production– Proved reserves: 150 MMBoe (1)
Drilling– Grown rig count 69% since 2003– Sold 15 rigs since 2003– 127 drilling rig fleet
Mid-Stream– 1,134% increase in natural gas processing volumes since 2004– 902% increase in daily liquids sold volumes since 2004– 1,373 miles of pipeline
Strong Balance Sheet– Remains conservatively financed as the company has grown
(1) As of 12/31/2012.
Capital Allocation Criteria
Oil and Natural Gas SegmentMinimum 15% risk-adjusted ROR for new well proposals
Contract Drilling SegmentNew build rigs – minimum contract term of 2 to 3 years at a day ratesufficient to provide a 100% cash on cash payout during a 3 year term
Rig Refurbishments – minimum contract term sufficient to provide a 100%cash on cash payout during the initial term
Midstream SegmentMinimum 25% risk-adjusted ROR for POP/POI projectsMinimum 15% risk-adjusted ROR for Fee Based projects
4
5
Core Upstream Producing Areas
NGL20%
Oil20%
Gas60%
NGL23%
Oil15%
Gas62%
Beginning in late 2008, implemented strategy of increasing focus on liquids-rich and oil prospects
– Forecast 43% liquids production for 2013
Key focus areas include:
– Granite Wash (Texas Panhandle)
– Marmaton (Oklahoma Panhandle oil play)
– Wilcox (Gulf Coast)
– Mississippian (Kansas)
2012 reserves of 150 MMBoe were 62% natural gas and 79% proved developed
– Reserve life of approximately 10 years
2012 Proved Reserves Q1 2013 Daily Production
Proved Reserves: 150 MMBoe Daily Production: 44.1 MBoe/d
MarmatonGranite Wash
Wilcox
Mississippian
GraniteWash
Wilcox
Marmaton
0%
100%
200%
300%
400%
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Track Record of Reserve Growth
6
0
20
40
60
80
100
120
140
160
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
(1) The Company uses the reserve replacement ratio as an indicator of the Company's ability to replenish annual production volumes and grow its proved reserves, including by acquisition, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not imbed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.
(2) 164% based on previous SEC reporting standards.
Stable and consistent economic growth of oil and natural gas reserves of at least 150% of each year’s production
222% average annual reserve replacement over last 29 years
Reserve growth driven by Oklahoma and Texas activity and a shift from vertical to horizontal / liquids-rich drilling
Proved Reserves (MMBoe)
Annual Reserve Replacement(1)
Natural GasOil / NGLs
2003 – 2012 CAGR: 15%
166% 171% 176%202%
285%261%
221%186%
Minimum Target: 150%
164%(2)
116
4858
6979
8695 96
104
150
337%
113%
7
Increasing Production whileImproving Commodity Mix
0
10
20
30
40
50
2008 2009 2010 2011 2012 2013E
Natural GasOil / NGLs Production Range
29 28
43134
Annual Production (MBoe/d)
Net Wells Drilled:
27
33
39
88 82
55%
45
44
80
28%
8
Granite Wash Play
Noble acquisition strategic fit with existing UPC leasehold
Total 47,000 net acres in the Texas Panhandle Core Area (81% HBP)
Approximately 800 potential drilling locations
HIGHLIGHTS
Current AFE CWC: $5.3 MM
Estimated reserve range: 3.5 – 4.0 Bcfe
Calculated ROR = 49% - 70% (Flat $90 oil, $30 NGL, $3.25 gas)
First sales on 29 GW horizontal wells 2012
2012 30-day average IP = 4.1 MMcfe per day
Production up 41% in 2012 over 2011
2013 ACTIVITY
Q1 2013 = average net 88 MMcfe per day (46% oil & NGLs)
Q1 – 4 wells completed – 30 day IP = 4.7 MMcfe per day
4-6 Unit rigs: First sales on 30 gross wells
Estimate capital expenditures $140 million net
First Noble well spud in Q2
11,000’ +/-200’
13,400’ +/-200’
GW Type Log - Buffalo Wallow Field
Total 113,000 net acres in focus area (47% HBP)
HIGHLIGHTS
Completed 95 operated horizontal wells since 2010
150 potential locations on 640 acre spacing
Estimated reserve range: 120 - 130 MBoe per well
Current AFE CWC: $2.7 million per well
Calculated ROR 80% - 100% (Flat $90 oil, $30 NGL, $3.25 gas)
First sales on 32 horizontal wells (includes two extended
laterals) in 2012
30 day IP 391 Boe per day for 2012 wells
Production up 61% in 2012 over 2011
2013 ACTIVITY
Q1 2013 average net 4,148 Boe per day (92% oil & NGLs)
Q1 – 10 wells completed – 30 day IP = 393 Boe per day
Two Unit rigs (3rd rig for 4 wells)
Estimate first sales on 40 gross wells (includes 3 extended laterals)
Estimate capital expenditures $90 million net 9
Marmaton Oil Play
FocusArea
WILCOX HIGHLIGHTS
Completed 122 wells since 2003 with 73% success rate
72,000 net acres
“Gilly” Field Discovery – announced July 2012
Total reserve potential = 168 Bcfe net (262 Bcfe gross)
Eight Wilcox potential pay zones (4 zones currently producing)
Six “Gilly” Field producing wellsAverage 255’ net potential pay/well
Estimated AFE CWC: $5.4 million
2013 ACTIVITY
Q1 2013 = average net 35 Mmcfe per day (42% NGLs)
One - two Unit rigs in Wilcox
12 gross wells (includes 4 Gilly field vertical wells / 7 other prospects / one horizontal well)
Estimate capital expenditures $60 million net
10
Wilcox Liquids Play
Unit Prospect Area
“Gilly” FieldDiscovery
“Gilly” Field Discovery1,000 Acres
Completed wells2013 wellsFuture wells
11
Mississippian Play
Central Kansas Uplift
Mississippian Trend
Focus Area
Initial Well
105,000 Net Acres
Mississippian Wells
Total 110,000 net acres in focus area (5% HBP)
HIGHLIGHTS
Approximately 300 potential locations (320 acre spacing)
Average well depth +/- 8,000’ (includes 4,000’ lateral)
Mississippian pay zone +/- 50’ thick
Estimated reserve range = 125 - 180 MBoe (92% oil & liquids)
Calculated ROR 40% - 66% (Flat $90 oil, $30 NGL, $3.25 gas)
Estimated AFE CWC: $3.0 million
2012
Drilled 4 horizontal Miss wells in Kansas focus area
Initial well completed May 2012; second well December 2012
30 day average IP 240 Boe per day (89% oil and liquids)
2013 ACTIVITY
Drill 3 wells in Q1 – wait on pipeline infrastructure to be built – estimate Q3 completion
Resume drilling in Q3 with one Unit rig and anticipate adding second rig in Q4
First sales on 13 gross wells
Estimate capital expenditures $40 million net
12
Significant Drilling Presence inAttractive Producing Regions
127 Unit Rigs
HoustonOffice
TulsaHeadquarters
OklahomaCity Office
18
16
77
CasperOffice
16
127 rig fleet
– Fleet average ~1,200 HP rating;~16,724 ft depth capacity
– 97% of contracted rigs drilling horizontal wells
52% utilization rate for Q1 2013
– 69% of 45 1,200-1,700 HP rigs under contract
Refurbished / upgraded 19 rigs in 2011and 15 rigs in 2012
2012 – placed 2 new build rigs into service (1,500 HP)
Contracted Rig
Commodity MixGeographical Location
Liquids Rich 99%
Dry Gas1%
AnadarkoBasin60%E. TX, LA
GC, S. TX13%
Rockies/Bakken
27%
Note: Based on 65 contracted rigs. All charts represent total 127 rig fleet.
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Average Dayrates and Margins (1)
0
30
60
90
$0
$5,000
$10,000
$15,000
$20,000
2009 2010 2011 2012 Q1 2013
(1) Margins are before elimination of intercompany rig profit.
Margins Day Rates
Mar
gin
s /
Day
Rat
es($
)A
verage Nu
mber of R
igs Utilized
Rigs Utilized
14
Diverse and Versatile Rig Fleet
Average Depth Capacity: 16,724 feet82 rigs equipped with integrated top drives
4531 38 7 6Number of Rigs: 71%
0
20%
40%
60%
80%
100%
400-700 h.p. 750-1,000 h.p. 1,200-1,700 h.p. 2,000 h.p. >2,500 h.p.
UtilizationPercentage
(51% as of 6/4/13)
31 of 45 working
15
Optimized for Pad Drilling Multi-direction walking systemFaster Between Locations Quick assembly substructure 32 truck loadsMore Hydraulic Horsepower (2) 2,200 horsepower mud pumps 1,500 gpm available with one pumpEnvironmentally Conscience Dual-fuel capable engines Compact location footprint
Introducing the New BOSS Drilling Rig
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Granite Wash 29,000 dedicated acres 1 processing facility 135 MMcf/d processing capacity 308 miles of gathering pipeline $12MM capital budget for 2013
Mississippi Lime 875,000+ dedicated acres 7 processing facilities 168 MMcf/d processing capacity* 477 miles of gathering pipeline $34.5MM capital budget for 2013
Marcellus Shale 43,000 dedicated acres 23 miles of gathering pipeline
Central & Eastern OK 197,000+ dedicated acres 497 miles of gathering pipeline 1 processing facility with
12 MMcf/d processing capacity 2 treating facilities with
combined capacity of 190 GPM
East Texas 41 Miles of gathering
pipeline
*Includes 28 MMcf/d from Reno, which will be operational in Q3
Indicates Company Headquarters in Tulsa, OklahomaIndicates Regional office in Pittsburgh, Pennsylvania
Hemphill
Reno
Bellmon
Segno
Pittsburgh Mills
Mid-Stream Core Operations
Processing facilities
Gathering systems
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Historical Performance
NGLs Volumes (Bbl / d)
Contract Mix (Based on Operating Margin)(1)Contract Mix (Based on Volume)(1)
Historical Daily Gathering Volumes (MMBtu / d)
(1) POP represents percent of proceeds. POI represents percent of index.
2012 Q1 2013
Fee Based39%
POP59%
POI2%
Fee Based46%
POP52%
POI2%
2012 Q1 2013
Fee Based25%
POP69%
POI6% Fee Based
25%
POP69%
POI6%
0
100,000
200,000
300,000
400,000
2009 2010 2011 2012 Q1 2012 Q1 20130
5,000
10,000
15,000
2009 2010 2011 2012 Q1 2012 Q1 2013
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Midstream Segment 2013 Outlook
Mississippian Reno County, KS: 28 MMcf/d Cryogenic Plant(Q3 2013)
Mississippian Bellmon: 60 MMcf/d Cryogenic Plant (Q4 2013)
Marcellus pipeline expansions
164 expected well connects in 2013
Consistent growth through greenfield construction of pipelines and processing plants in unconventional resource basins
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Balance Sheet Summary
Total Assets 3,814.8 3,761.1
Long-Term DebtSenior Subordinated Notes 645.4 645.3Bank Facility 70.0 71.1
Total Long-Term Debt 715.4 716.4
Shareholders’ Equity 2,010.0 1,974.3
Credit Line Undrawn 430.0 428.9
Long-Term Debt toTotal Capitalization 26% 27%
(In Millions)
3/31/13 12/31/12
20
Debt Structure (1)
Senior Subordinated Notes $650 million, 6.625%
10-year, NC5; maturity 2021
Unsecured Bank Facility Borrowing Base $800 million
Elected Commitment $500 million
Outstanding $70.0 million
Maturity September 2016
Ratings S&P Moody’s FitchCorporate BB Ba3 BBSenior Subordinated Notes BB- B1 BB-
(1) As of March 31, 2013
0
2,000
4,000
6,000
8,000
10,000
2013 2014
21
Hedges
0
20,000
40,000
60,000
80,000
100,000
2013 2014
Natural GasMMBtu/d
Crude OilBbls/d
Target 50–70% of current year projected oil and natural gas production
$97.94
$91.16
$3.67
$4.24
22
Segment Contribution
Oil and Natural Gas Contract Drilling Midstream
(1) See appendix for adjusted EBITDA reconciliation.
Revenues ($ millions) Adjusted EBITDA ($ millions)(1)
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
2009 2010 2011 2012 Q1 2013$0
$200
$400
$600
$800
2009 2010 2011 2012 Q1 2013
$319
$707
$871
$1,208
$1,315
$373
$441
$602
$657
$148
23
Adjusted Earnings per Share (1)
(1) See appendix for adjusted EPS reconciliation.
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
2009 2010 2011 2012 Q1 2012 Q1 2013(1) (1)
$1.12
$2.55
$3.08
$4.05 $4.16
$0.92
24
Capital Expenditures
$0
$500
$1,000
$1,500
2008 2009 2010 2011 2012 2013 Budget
Oil and Natural Gas Contract Drilling Midstream Acquisitions
(In Millions)
Forward-Looking Statement
25
This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management’s expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced in the “Risk Factors” section of the Company’s Offering Memorandum provided in connection with this offering, risks relating to financial performance and results, current economic conditions and resulting capital restraints, prices and demand for oil and natural gas, availability of drilling equipment and personnel, availability of sufficient capital to execute the Company’s business plan, the Company’s ability to replace reserves and efficiently develop and exploit its current reserves and other important factors that could cause actual results to differ materially from those projected. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In this communication, the Company uses the term “unproved reserves” which the SEC guidelines prohibit from being included in filings with the SEC. “Unproved reserves” refers to the Company’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. Unproved reserves may not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or proposed SEC rules and does not include any proved reserves. Actual quantities that may be ultimately recovered from the Company’s interests will differ substantially. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves may change significantly as development of the Company’s core assets provide additional data. In addition, our 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.
This presentation contains financial measures that have not been prepared in accordance with U.S. Generally Accepted Accounting Principles (“non-GAAP financial measures”) including LTM EBITDA and certain debt ratios. The non-GAAP financial measures should not be considered a substitute for financial measures prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). We urge you to review the reconciliations of the non-GAAP financial measures to GAAP financial measures in the appendix.
Non-GAAP Financial Measures –Adjusted EBITDA
(1) Does not include allocation of G&A expense.
Years ended December 31,($ in Millions) 2009 2010
Net Income ($56) $146Income Taxes (32) 91Depreciation, Depletion and Amortization 177 205Impairment of Oil and Natural Gas Properties 281 -Interest Expense 1 -
Unit PetroleumIncome Before Income Taxes(1) ($121) $176
Depreciation, Depletion and Amortization 115 119Impairment of Oil and Natural Gas Properties 281 -
Adjusted EBITDA $275 $295
Unit DrillingIncome Before Income Taxes(1) $51 $60
Depreciation and Amortization 45 70Adjusted EBITDA $96 $130
Superior PipelineIncome Before Income Taxes(1) $5 $17
Depreciation and Amortization 16 15Adjusted EBITDA $21 $32
2011
$196123281
-4
$200183
-$383
$13580
$215
$1716
$33
Three months ended March 31,2012 2013
$52 $4033 2579 77- -2 4
$48 $5952 52- -
$100 $111
$43 $2421 17
$64 $41
$5 $15 7
$10 $8
2012
$2316
31928414
($77)211284
$418
$15981
$240
$624
$30
(Gain) loss on unrealized value of commodityderivatives (2) 1 2(7) (2) (1)
Adjusted EBITDA $373 $441 $602$173 $148 $657
Reconciliation of Adjusted Net Income and Diluted Earnings Per Share
Years ended December 31,($ in Millions) 2009 2010 2011
Three months ended March 31,2012 2013 2012
Adjusted Net Income:Net income $ 52.4 $ 40.2 $ (55.5) $ 146.4 $ 195.9 $ 23.2Eliminate:Unrealized value of commodity derivatives
gain (loss) (1.2) (4.3) (1.2) 0.6 1.5 (0.7)Impairment of oil and natural gas properties - - (175.1) - - (176.6)Adjusted net income $ 53.6 $ 44.5 $ 120.8 $ 145.8 $ 194.4 $ 200.5
Adjusted Diluted Earnings Per Share:Diluted earnings per share $ 1.09 $ 0.83 $ (1.18) $ 3.09 $ 4.08 $ 0.48Eliminate:Unrealized value of commodity
derivatives gain (loss) (0.03) (0.09) (0.03) 0.01 0.03 (0.01)Impairment of oil and natural gas properties - - (3.70) - - (3.67)
Adjusted diluted earnings per share $ 1.12 $ 0.92 $ 2.55 $ 3.08 $ 4.05 $ 4.16
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