Cowen & Co. 5 th Annual Ultimate Energy Conference December 2, 2015

Transcription

1 Cowen & Co. 5 th Annual Ultimate Energy Conference December 2, 2015

2 Forward Looking Statement 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 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 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. 2

3 Unit Corporation: A Diversified Energy Company Tulsa based, incorporated in 1963 We have consistently grown throughout many commodity cycles Integrated approach to business allows Unit to capture margin from each business segment Casper 10 Anadarko Basin Tulsa Headquarters Arkoma Basin Marcellus Pittsburgh 94 Unit Rigs Permian Basin 12 Oklahoma City 6 North La/ East Texas Basin E&P Operations Mid Stream Operations Office Location Houston Gulf Coast Basin 3

4 Lower for Longer? Unit Petroleum has asset packages that can earn strong returns in the current commodity price environment Unit Drilling s new BOSS rigs have been very well received by customers Superior Pipeline cash flow has improved in stability and reliability with increased emphasis on fee based revenue Asset and financial flexibility Our Balance Sheet provides capability 4

5 Key Growth Points Exploration & Production 203% average production replacement since 2005 Liquids production has grown 258% since the fourth quarter of 2009 Proved reserves: 179 MMBoe (1) 76% Proved Developed Drilling Seven BOSS rigs operating under contract; eighth to return to original operator 94 drilling rig fleet Mid Stream 145% increase in daily natural gas processing volumes since % increase in daily liquids sold volumes since 2010 Approximately 1,450 miles of pipeline Strong Balance Sheet Remains conservatively financed as the company has grown (1) As of 12/31/

6 Segment EBITDA Margins (1) in Line with Pure Play Peers 90% 80% 70% EBITDA Margins 60% 50% 40% 30% 20% 10% 0% 12/31/ /31/ /31/ /31/ /31/ /31/ /31/ /31/ /31/ /31/2014 TTM Oil and Gas Contract Drilling Midstream E&P Company Peer Average Land Drilling Peer Average Midstream Peer Average (1) See Segment EBITDA Margins in Appendix (also available at Source: E&P: CRK, EGN, LINE, NBL, NFX, QEP, SD, SGY, SM, XEC; Contract Drilling: HP, ICD, NBR, PES, PKD, PTEN; Midstream: BPL, DPM, ENLK, EPD, ETE, ETP, MMLP, PAA, PAGP, RRMS, SXL 6

7 Conservative Debt Structure No Near Term Maturities Senior Subordinated Notes $650 million, 6.625% 10 year, NC5; maturity 2021 Ratings S&P Moody s Fitch Corporate BB Ba3 BB Senior Subordinated Notes BB B1 BB Key Covenants Coverage ratio 2.25x (1) Actual ratio 9.27x (1,2) Unsecured Bank Facility Current Borrowing Base Elected Commitment Outstanding (2) $550 million $500 million $261.7 million Maturity April 2020 Key Covenants Current ratio 1.0 to 1.0 (1) Actual ratio 2.06x (1,2) (1) As defined in Indenture/Credit Agreement (2) As of September 30, 2015 Leverage ratio 4.0 (1) Actual ratio 1.97x (1,2) 7

8 Strong Capital Discipline Total debt / LTM s adjusted EBITDA of 1.97x (1) Strong access to capital No near term maturities Oil and natural gas segment core plays largely HBP exploration program not driven by lease expirations (1) As of September 30,

9 Track Record of Reserve Growth Proved Reserves (MMBoe) Stable and consistent economic growth of oil and natural gas reserves of at least 150% of each year s production 221% average annual production replacement over last 30 years Oil / NGLs Natural Gas Annual Reserve Replacement (1) Reserve growth driven by Oklahoma and Texas activity and a shift from vertical to horizontal / liquids rich drilling 400% 300% 200% 100% 0% 337% Minimum Target: 150% 261% 221% 202% 204% 186% 171% 176% 164% (2) 161% 113% (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. 9

10 Consistent Production Growth Average Production (MBoe/d) % 8% growth est. Natural Gas Oil / NGLs Prod. Range Net Wells Drilled:

11 Core Upstream Producing Areas 2015 CapEx Breakdown: $309 Million Original Budget $279 Million Revised Budget Other Granite Wash 9% 9% Mississippian 6% 36% Hoxbar Play Mid Continent Region Granite Wash Mississippian SOHOT Upper Gulf Coast Region 40% Wilcox Wilcox Key focus areas include: Gulf Coast: Wilcox (Southeast Texas) Mid Continent: Hoxbar (Western Oklahoma) Granite Wash (Texas Panhandle) Mississippian (Kansas) Upside resource potential: 1,400 1,800 gross wells 75% average working interest gross MMBoe 47% liquids (16% oil, 31% NGLs) 9 Months 2015 Daily Production: 55.8 MBoe/d Oil 20% NGL 26% Gas 54% 11

12 Wilcox (Southeast Texas) Overall Highlights: POLK TYLER Drilled 146 operated wells since 2003 (143 vertical, 3 horizontal) 92% average working interest Q3 15 net avg. production: 82 MMcfe/d 43% liquids (11% oil) Historical ROR: 112% Gilly Field 3D AREA 494 mi.² JASPER Gilly Field Highlights: Resource potential of 506 gross Bcfe HARDIN Produced only 13% of resource potential Prior Years Drilling 2015 Drilling Program Southeast Texas Jazz Wilcox Area 93% average working interest Field size: 1,740 acres 18 vertical, 2 horizontal wells Gilly Blackwood zone: CWC: $4.8 MM; EUR: 9.3 Bcfe *October 2015 Strip Price Deck with 1 st Production Starting 1/1/2016; see Q Economic Prices in Appendix (also available at ROR: 100%* 12

13 Wilcox (Southeast Texas) 2015 Activity: 1 rig gross wells (3 horizontal) 2015 projected 18% growth Upside Resource Potential: 870 Bcfe 95% average WI 43% Liquids (11% oil, 32% NGLs) 90,000 Wilcox Net Production 60,000 Mcfe/d 30, est. NGLs Oil Gas 13

14 Hoxbar (Medrano Sand) Hiram 1 13H IP30: 9,500 Mcfe/d 2/15 Hazel 1 24H IP30: 8,900 Mcfe/d 10/14 GB 2 30H IP30: 7,300 Mcfe/d 4/15 Mary 1 18PH IP30: 7,400 Mcfe/d 3/15 Ellen 1 20H IP30: 9,800 Mcfe/d 12/14 Ellen 2 20H IP30: 9,800 Mcfe/d 12/14 Chester 1 29H IP30: 5,800 Mcfe/d 4/15 Rosey 2H IP30: 7,600 Mcfe/d 5/15 H O X B A R 3, Historical Medrano Highlights: Completed 15 operated wells Avg. IP30: 7.0 MMcfe/d 78% avg. working interest Medrano Core Case: EUR: 4.8 Bcfe IP30: 7.0 Mmcfe/d Well cost: $4.4 million ROR: 18%* 28% liquids core locations 50% avg. working interest 2016 Medrano Activity: No activity currently planned *October 2015 Strip Price Deck with 1 st Production Starting 1/1/2016; see Q Economic Prices in Appendix (also available at 14

15 Hoxbar (Marchand Sand) Historical Marchand Highlights: Completed 7 operated wells Avg. IP30: 1,426 Boe/d Extensional Area Brown 1 11H IP30: 867 Boe/d 1/15 Harper 1 19H IP30: 2,467 Boe/d 1/15 88% avg. working interest Marchand Core Case: EUR: 480 Mboe Rosey 1H IP30: 1,483 Boe/d 9/14 Schenk 18H IP30: 700 Boe/d 6/15 Earl 2 30H IP30: 1,817 Boe/d 8/14 H O X B A R 3, IP30: 1,195 Boe/d Well cost: $5.2 million ROR: >100%* 91% liquids (77% oil) core operated locations 50% average working interest Marchand Horizontal Producer Marchand Vertical Producer Powers 1 15H IP30: 1,233 Boe/d 12/14 GB 1 30H IP30: 1,367 Boe/d 3/ core non operated locations 35% average working interest 2016 Marchand Activity: 1 rig *October 2015 Strip Price Deck with 1 st Production Starting 1/1/2016; see Q Economic Prices in Appendix (also available at wells 15

16 Granite Wash (Liquids) Historical Highlights: Buffalo Wallow Potential: 40,600 N.A. 96% H.B.P. Buffalo Wallow Completed 115 operated horizontal wells since 2008 Average WI: ~80% Q3 15 avg. production: 119 MMcfe/d Average IP30: 5.2 MMcfe/d 52% liquids (12% oil) CAGR: 37% (5 years) 2015 Activity: 0 1 rig total 5 net wells Contiguous operated HBP acreage position with average WI above 90% Saltwater gathering system coupled with water recycling facility significantly reduces produced water handling costs and provides cheap frac water Horizontal well results indicate extended lateral drilling should be economic at current strip prices. Evaluating options to fund extended lateral program 16

17 Expertise in Areas of Operations $16 Unit has experienced management and operating teams and is a leader in minimizing operating expenses Operating Expense / Boe (1) $12 $8 $4 Average: $10.21 $0 Peer 1 Unit Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 (1) Data in table is as of Q Source: CRK, EGN, LINE, NFX, NBL, QEP, SD, SGY, SM, XEC 17

18 Significant Drilling Presence in Attractive Producing Regions 94 rig fleet Fleet average ~1,260 HP rating; Almost all of contracted rigs drilling horizontal wells 33% utilization rate for Q % of the 49 1,200 1,700 HP rigs under contract Pinedale Anticline Niobrara Bakken Mississippian Refurbished 48 rigs since 2009 Seven BOSS rigs operating One BOSS rig going back to original operator Area # of Rigs Anadarko Basin 8 Bakken 4 Granite Wash 4 Mississippi 1 Permian 4 Pinedale Anticline 2 Niobrara 3 Wilcox 1 Total 27 Granite Wash Permian Anadarko Wilcox 18

19 Average Dayrates and Margins (1) $20, % $15,000 75% Margins and Dayrates $10,000 50% Average Rig Utilization $5,000 25% $ mos Margins Dayrates Average Rig Utilization 0% (1) See Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense in Appendix (also available at 19

20 Rig Fleet Snap Shot 82% of Total Fleet < 800 HP 800 1,000 HP 1,200 1,700 HP 2,000 HP 92% 8% 82% 18% 57% 43% 100% M: 8 SCR: 5 A/C: M: 18 SCR: 10 A/C: M: 3 SCR: 38 A/C: 8 M: SCR: 4 A/C: % Utilized % Unutilized Utilization by Type: Mechanical: 0 SCR: 20 A/C: 7 20

21 The BOSS Drilling Rig Optimized for Pad Drilling Multi direction walking system Faster Between Locations Quick assembly substructure truck loads More Hydraulic Horsepower (2) 2,200 horsepower mud pumps 1,500 gpm available with one pump Environmentally Conscious Dual fuel capable engines Compact location footprint 21

22 Midstream Core Operations Brook Field Texas Panhandle 50,100 dedicated acres 135 MMcf/d processing capacity 343 miles of gathering pipeline Northern Oklahoma and Kansas 1,972,000+ dedicated acres 193 MMcf/d processing capacity 565 miles of gathering pipeline Pittsburgh Mills Pittsburgh Regional office Bruceton Mills Snow Shoe Hemphill Reno Bellmon Tulsa Headquarters Central & Eastern OK 60,100+ dedicated acres 12 MMcf/d processing capacity 449 miles of gathering pipeline Appalachia 43,000+ dedicated acres 36 miles of gathering pipeline 200 MMcf/d pipeline capacity Panola East Texas 59 Miles of gathering pipeline Segno Key Metrics 25 Active Systems Three Natural Gas Treatment Plants 340 MMcf/d Processing Capacity Approx. 1,450 miles of Pipeline Processing facilities Gathering systems 22

23 Midstream Segment Contract Mix 2010 Q Contract Mix Based on Volume 49% 51% Fee Based Commodity Based 33% 67% 85% 15% Contract Mix Based on Margin Fee Based Commodity Based 37% 63% Unit vs. 3 rd Party Margin Contribution 41% 59% 3 rd Party Unit 44% 56% 23

24 Appalachian Growth Projects A P PA L A C H I A N P R O J E C T S Constructing Snowshoe Gathering System in Centre County, PA Estimated Total Capital: $97 million Initial 2015 Capital: $30 million Expansion of Pittsburgh Mills gathering system into Butler County, PA Constructing compression station estimated completion Q Scheduled to connect next well pad in Q Four additional well pads scheduled for connection in

25 Segment Contribution Revenues ($ millions) Adjusted EBITDA ($ millions) (1) $1,600 $1,573 $800 $758 $1,400 $1,200 $1,208 $1,315 $1,352 $600 $603 $657 $640 $1,000 $800 $600 $682 $400 $311 $400 $200 $200 $ mos $ mos Oil and Natural Gas Contract Drilling Midstream (1) See Non GAAP Financial Measures in Appendix (also available at 25

26 Capital Expenditures (In Millions) $1,500 $1,000 $500 $ Original Forecast Oil and Natural Gas Contract Drilling Midstream Acquisitions 2015 Revised Forecast 26

27 Investment Considerations In a commodity price challenged world: Unit Petroleum has asset packages that can earn strong returns in the current commodity price environment Unit Drilling s new BOSS rigs have been very well received by customers Superior Pipeline cash flow has improved in stability and reliability with increased emphasis on fee based revenue Asset and financial flexibility Our Balance Sheet provides capability 27

28 APPENDIX 28

29 Segment EBITDA Margin 12/31/ /31/ /31/ /31/ /31/ /31/ /31/ /31/ /31/ /31/2014 TTM Revenues Oil and Gas (Including Cash Flow Derivatives Settled) $318,208 $357,599 $391,480 $552,696 $362,245 $399,771 $514,614 $567,944 $649,718 $740,079 $474,847 Drilling $462,141 $699,396 $627,642 $622,727 $236,315 $316,384 $484,651 $529,719 $414,778 $476,517 $350,101 Gas Gathering $100,464 $101,863 $138,595 $181,730 $108,628 $154,516 $208,238 $217,460 $287,354 $356,348 $235,542 Derivatives Settled (Non designated) $0 $0 $0 $0 ($2,422) $0 ($711) $0 ($1,764) ($6,038) $45,102 Expenses Oil and Gas Operating cost $60,779 $81,120 $97,109 $116,239 $87,734 $105,365 $131,271 $150,212 $184,001 $187,916 $183,808 DDA $67,282 $108,124 $127,417 $159,550 $114,681 $118,793 $183,350 $211,347 $226,498 $276,088 $277,508 Impairment $0 $0 $0 $281,966 $281,241 $0 $0 $283,606 $0 $76,683 $1,217,736 Drilling Operating cost $266,472 $313,882 $304,780 $312,907 $140,080 $186,813 $269,899 $289,524 $247,280 $274,933 $201,625 Depreciation and impairment $42,876 $51,959 $56,804 $69,841 $45,326 $69,970 $79,667 $81,007 $71,194 $159,688 $149,341 Gas Gathering and Processing Operating Cost $92,467 $88,834 $119,776 $150,466 $87,908 $122,146 $174,859 $187,292 $243,406 $306,831 $193,746 Depreciation, amortization, and impairment $3,279 $6,247 $11,059 $14,822 $16,104 $15,385 $16,101 $24,388 $31,191 $47,502 $50,048 G&A $14,343 $18,690 $22,036 $25,419 $24,011 $26,152 $30,055 $33,086 $38,323 $42,023 $38,251 G&A Allocation Oil and Gas $5,182 $5,767 $7,451 $10,352 $12,259 $12,008 $12,799 $14,288 $18,393 $19,686 $17,127 Drilling $7,525 $11,280 $11,947 $11,652 $8,073 $9,492 $12,046 $13,327 $11,758 $12,731 $12,628 Gas Gathering $1,636 $1,643 $2,638 $3,400 $3,711 $4,636 $5,176 $5,471 $8,146 $9,520 $8,496 EBITDA Margin Oil and Gas 79% 76% 73% 77% 72% 71% 72% 71% 69% 72% 61% Drilling 41% 54% 50% 48% 37% 38% 42% 43% 38% 40% 39% Gas Gathering 6% 11% 12% 15% 16% 18% 14% 11% 12% 11% 14% 29

30 Non GAAP Financial Measures Adjusted EBITDA ($ in Millions) Net Income (Loss) Income Taxes Depreciation, Depletion and Amortization Impairments Interest Expense (Gain) loss on derivatives not designated as hedges and hedge ineffectiveness Settlements during the period of matured derivative contracts (Gain) loss on disposition of assets Nine months ended September 30, $179 $(728) 112 (439) , $ (2) 1 Years ended December 31, $23 $ (19) 32 (2) (6) (9) 6 1 (17) (9) Adjusted EBITDA $578 $311 $603 $657 $640 $758 (13) $ (30) Unit Petroleum Income (Loss) Before Income Taxes (1) Depreciation, Depletion and Amortization Impairment of Oil and Natural Gas Properties EBITDA $ $441 $(1,163) 202 1,141 $180 $ $383 ($77) $418 $ $465 $ $552 Unit Drilling Income Before Income Taxes (1) Depreciation and Impairment EBITDA $84 61 $145 $40 51 $91 $ $215 $ $240 $96 71 $167 $ $202 Superior Pipeline Income Before Income Taxes (1) Depreciation, Amortization and Impairment EBITDA $10 30 $40 $ 32 $32 $17 16 $33 $6 24 $30 $11 33 $44 $2 48 $50 (1) Does not include allocation of G&A expense. 30

31 Non GAAP Financial Measures Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense (In thousands except for operating days Nine months ended September 30, Years ended December 31, and operating margins) Contract drilling revenue $ 341,530 $ 215,114 $ 484,651 $ 529,719 $ 414,778 $ 476,517 Contract drilling operating cost 197, , , , , ,933 Operating profit from contract drilling 144,505 91, , , , ,584 Add: Elimination of intercompany rig profit and bad debt expense 20,674 3,666 19,900 15,583 17,416 29,343 Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense 165,179 95, , , , ,927 Contract drilling operating days 20,073 10,175 27,619 26,704 23,720 27,516 Average daily operating margin before elimination of intercompany rig profit and bad debt expense $ 8,229 $ 9,343 $ 8,496 $ 9,578 $ 7,796 $ 8,392 31

32 Derivative Summary Crude Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Subfloor Price Weighted Average Ceiling Price Period Structure Volume Bbl/Day Oct'15 Dec'15 Swap 1,000 $95.00 Oct'15 Dec'15 Collar 2,000 $58.00 $64.40 Jan'16 Jun'16 3 Way Collar 700 $46.50 $35.00 $57.00 Jan'16 Jun'16 Collar 2150 $46.36 $55.62 Jul'16 Dec'16 3 Way Collar 1,400 $47.00 $35.00 $60.25 Jul'16 Dec'16 Collar 1,450 $47.50 $56.40 Jan'17 Dec'17 3 Way Collar 750 $50.00 $37.50 $63.90 Natural Gas Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Subfloor Price Weighted Average Ceiling Price Period Structure Volume MMBtu/Day Oct'15 Dec'15 Swap 40,000 $3.98 Nov'15 Dec'15 3 Way Collar 13,500 $2.70 $2.20 $3.26 Jan'16 Dec'16 Swap 10,000 $3.25 Jan'16 Dec'16 3 Way Collar 13,500 $2.70 $2.20 $3.26 Jan'16 Dec'16 Collar 27,000 $2.50 $

33 Q Economic Prices October 27, 2015 Strip Case Crude Natural Gas MB C2 MB C3 MB NC4 MB ic4 MB C5+ CW C2 CW C3 CW NC4 CW ic4 CW C $ $2.293 $0.208 $0.420 $0.583 $0.592 $0.977 $0.178 $0.390 $0.550 $0.613 $ $ $2.604 $0.242 $0.455 $0.627 $0.639 $1.049 $0.185 $0.429 $0.596 $0.658 $ $ $2.884 $0.267 $0.540 $0.716 $0.734 $1.157 $0.207 $0.541 $0.697 $0.772 $ $ $2.961 $0.278 $0.569 $0.754 $0.774 $1.220 $0.218 $0.570 $0.734 $0.814 $ $ $3.039 $0.287 $0.590 $0.783 $0.803 $1.266 $0.227 $0.592 $0.762 $0.844 $ $ $3.237 $0.302 $0.596 $0.791 $0.811 $1.279 $0.242 $0.597 $0.770 $0.853 $1.240 Thereafter $ $3.237 $0.302 $0.596 $0.791 $0.811 $1.279 $0.242 $0.597 $0.770 $0.853 $

34 Cowen & Co. 5 th Annual Ultimate Energy Conference December 2, 2015