Energy Q&A. NAESB, 8 April 2015 BEG/CEE-UT, 1

Transcription

1 Energy Q&A NAESB, 8 April 2015 BEG/CEE-UT, 1

2 PRICE TRENDS BEG/CEE-UT, 2

3 Oil Price History $160 $140 $120 Cushing, OK WTI Spot Price FOB (Dollars per Barrel) Europe Brent Spot Price FOB (Dollars per Barrel) WTI-Brent Spread "Arab Spring" 2010 $10 Saudi Market $5 Share Strategy II 2014 $0 Price, $/BBL $100 $80 $60 $40 $20 Saudi Market Share Strategy I, 1986 Desert Storm, 1990 USD Neutral Asia Financial Collapse, China "Coming Out: Party, Iraq War, U.S.-Europe Financial Collapse, USD Neutral US LTO Glut -$5 -$10 -$15 -$20 -$25 WTI minus Brent, $/BBL $0 -$30 CME/NYMEX, EIA, CEE compilation BEG/CEE-UT, 3

4 Gas Price History $16 $14 Henry Hub Monthly Average Spot Price ($/MMBtu) Avg Feb 89-Feb 92 ($1.61) Avg Mar 92-Dec 98 ($2.11) U.S. shale gas drilling boom U.S. shale oil drilling boom $12 $10 $8 Avg Jan 99-Dec 01 ($3.46) Avg Jan 02-Sep 09 ($6.32) Avg Oct 09-Present ($3.83) GOM Hurricane Events El Paso pipeline explosion, Carlsbad, NM August 19, 2000 California market failure, Peak LNG imports with new regas capacity March-August 2007 Feb 2007, "Henry Hub at $3 or $5 published (Foss, OIES NG 18) Dec 2011, "Henry Hub at $3 or $10 published (Foss, OIES NG 58) $6 $ Energy Policy Act $2 Enron bankruptcy December 4, 2001 Lehman Brothers bankruptcy September 15, 2008 $0 Feb-89 Feb-90 Feb-91 Feb-92 Feb-93 Feb-94 Feb-95 Feb-96 Feb-97 Feb-98 Feb-99 Feb-00 Feb-01 Feb-02 Feb-03 Feb-04 Feb-05 Feb-06 Feb-07 Feb-08 Feb-09 Feb-10 Feb-11 Feb-12 Feb-13 Feb-14 Feb-15 CME/NYMEX, EIA, CEE compilation BEG/CEE-UT, 4

5 Price Drivers and Expectations Oil Saudi/GCC market share strategy and demand response US LTO surplus (condy) Iran, Iraq current/potential capacity, 9 MMBD (black oil) ST still price shoes to drop, MT long recovery ( at least 5 years until see $100 oil, if), 1990s scenario Gas Domestic drivers: unmotivated producers, motivated customers Policy impacts NAM trade ST already see effects of oil price, MT wellhead value likely sustained by HH BEG/CEE-UT, 5

6 PRODUCTION BEG/CEE-UT, 6

7 Shales: A Quick History Long history of production from shales example, Antrim in Michigan Upper Bakken vertical wells drilled, 1976 Upper Bakken horizontal wells drilled, 1987 Mitchell Energy drills vertical wells in Barnett (Texas) in 1989 Baker Hughes acquires Eastman Christensen for horizontal drilling tool and other technology 1990 National Petroleum Council seminal natural gas supply study points to role of non-conventional sources (CBM, shale, tight sands), 1992 Chevron drills Barnett vertical wells and improves measures of oil and gas in place (OGIP) measures, 1997 Mitchell absorbs CVX talent, demonstrates hydraulic fracturing, use of 3-D seismic, slick water frac Devon acquires Mitchell, 2002, spawns a series of transactions that expanded or created new unconventional players BEG/CEE-UT, 7

8 Perspective Helps Everybody looked at that technology (Mitchell Energy) was developing of hydraulic fracturing and said it doesn t work, said Devon Energy s co-founder and chief executive officer, Larry Nichols recalls in a company video here. It s old, it s tired... there s nothing there. Everyone knows that. Don t waste your time. From The Energy Fix, Jim Pierobon, 5 August BEG/CEE-UT, 8

9 *Feeling the need the need for shale: Oil 350,000 Federal OCS--Gulf of Mexico Field Production Midwest (PADD 2) Field Production Gulf Coast (PADD 3) Field Production U.S. Field Production of Crude Oil 300, ,000 Production from shale is about 70% of U.S. total Thousand Barrels 200, , ,000 Mainly West Texas and Eagle Ford 50,000 Mainly Bakken 0 Top Gun BEG/CEE-UT, 9

10 Feeling the need the need for shale: Gas 35,000,000 Canada remains about 10% of total dry gas supply 30,000,000 Now 50% of production Million Cubic Feet 25,000,000 20,000,000 15,000,000 10,000,000 Onshore (Conventional) CBM Shale 5,000,000 - Offshore (Federal, State) Note: 2014 data are estimates Gross withdrawals; CEE based on EIA and other sources BEG/CEE-UT, 10

11 Do producers like to lose money? Oil 50% 40% Y-Y Chg U.S. Crude Oil Production Y-Y Chg WTI Initial shale oil tests 200% 150% 30% 20% 100% Y-Y Chg Production 10% 0% -10% 50% 0% Y-Y Chg WTI -20% -30% Many reasons for recent production growth including: lease requirements, hedging, need to sustain cash flows -50% -100% BEG/CEE-UT, 11

12 Do producers like to lose money? Gas 20% 15% Y-Y Chg U.S. Natural Gas Marketed Production Y-Y Chg Henry Hub Dry Gas production drop 300% with low gas price 250% 10% 200% Y-Y Chg Production 5% 0% -5% 150% 100% 50% 0% Y-Y Chg HH -10% -15% -50% AG production surge with high oil price -100% BEG/CEE-UT, 12

13 Eagle Ford Shale BEG/CEE-UT, 13

14 Bakken Shale: Middle Bakken TudorPickeringHolt & Co. Note: Represents cumulative 12-month production (mboe) from all wells drilled in the Middle Bakken from Source: ESRI, Drilling Info, TPH Research BEG/CEE-UT, 14

15 Bakken Shale: Three Forks TudorPickeringHolt & Co. Note: Represents cumulative 12-month production (mboe) from all wells drilled in the Three Forks from Source: ESRI, Drilling Info, TPH Research BEG/CEE-UT, 15

16 Shale Oil View: TPH Comments on Bakken Industry focused on driving down well costs over the last few years after costs surged on tight service capacity and accelerated drilling programs. With held by production (HBP) commitments met and well costs reduced 15-20%, the industry focused in earnest on optimizing completions. While drilling efficiencies may continue to improve, many operators saw spud to total depth (TD) times approaching 20 days, making additional drilling cost reductions harder to achieve. One size will NOT fit all. Operators testing a variety of completion designs across the basin with a particular interest in slickwater fracs and a trend towards larger volumes of smaller mesh proppant. In general, better quality acreage is the focus of new completions designs. Tests expanding into Tier 2 positions. Ceramics: To use or not to use? That is the question. Some operators in the deeper part of the basin are doubling down and increasing ceramic use, while others are shifting their capital in favor of larger volumes of sand (100 mesh and #40/70 mesh sand). Completions being tested Slickwater hydraulic fracturing Increased proppant volumes: 2-10x standard completions in the basin Increased stage count combined with higher density clusters on plug and perf designs BEG/CEE-UT, 16

17 Barnett Shale BEG Shale Gas Resource Assessment (Sloan Foundation) BEG/CEE-UT, 17

18 Haynesville Shale OGIP free Productivity Overpressured BEG Shale Gas Resource Assessment (Sloan Foundation) BEG/CEE-UT, 18

19 Fayetteville Shale OGIP free Natural Fractures Productivity BEG Shale Gas Resource Assessment (Sloan Foundation) BEG/CEE-UT, 19

20 Type Curves and Costs: Preliminary Results Do not cite BEG Shale Gas Resource Assessment (Sloan Foundation) BEG/CEE-UT, 20

21 Well Economics $18 $16 $14 $12 $10 $8 $6 $4 $2 Barnett Low Btu Barnett High Btu Fville Shallow Fville Medium Fville Deep Hville PA Dry PA Wet PA Rich Do not cite $0 Tier 1 Tier 2 Tier 3 Tier 4 Tier 5 Tier 6 Tier 7 Tier 8 Tier 9 Tier 10 What matters most: Costs (depth & length), by-products (ng vs. liquids), taxes. BEG Shale Gas Resource Assessment (Sloan Foundation) BEG/CEE-UT, 21

22 Tcf / year Production Sensitivity to Price 6$/MMBtu EIA price 4$/MMBtu Do not cite We expect liquids rollover to follow a similar, perhaps faster, path BEG Shale Gas Resource Assessment (Sloan Foundation) BEG/CEE-UT, 22

23 ECONOMICS BEG/CEE-UT, 23

24 Wellhead BE does not necessarily = Company BE Fast NPV attractive to investors Companies need enough tails to support business Continuous outlays of capital Onshore shale oil and offshore deep water can demonstrate comparable returns over time ainabilitypossible/shale-bubble/ 3% Challenge for companies is building robust portfolios Companies report only best wells ( 3% of total ) Company portfolios are highly variable (acreage, liquids, recovery, cost) Companies routinely deploy 100% of capital across portfolios in which, on average, 80% of production comes from 20% of fracs 67% 30% Best Wells, NPV>0 BE Wells, NPV=0 Worst Wells, NPV<0 BEG/CEE-UT, 24

25 Upstream Matters! Part Deux We add 2014 reporting data and affirm key considerations going forward Our sample represents the top tier of U.S. producers including leading shale players. We have *restated work from earlier research for changes to our sample and methodology The 15 publicly traded companies we use comprise 68% of Top 40 gas producers (NGSA.org) and 33% of U.S. marketed natural gas production In this snapshot including 2014 reporting we state results mainly in barrel of oil equivalent terms Overall, while FD capex has dropped, largely a result of increased volumes, cash costs remain substantial and stubborn High Cost Producer Average Low Cost Producer High Cost Producer Average Low Cost Producer High Cost Producer Average Low Cost Producer High Cost Producer Average Low Cost Producer High Cost Producer Average Low Cost Producer High Cost Producer Average Low Cost Producer $0 $20 $40 $60 $80 $100 3-Yr MA FD Costs/3-Yr MA Additions ($/BOE) Annual Cash Costs per Bbl of Production ($/BOE) FD = capital spending for exploration and development, calculated on a 3-year basis and applied to 3-year reserve additions as a moving average (MA) Cash cost = current year lease operating expense, general and administra tive, marketing, taxes (including state production tax), interest on debt, applied to current year production The cheapest producers are also the gassiest smaller companies that, for the most part, did not move out of gas and into liquids because of cost and capital constraints. BEG/CEE-UT, 25 *

26 How much spending? With what results?? 3-Year Capex Spending ($MM) $300,000 15,167 $250,000 11,969 3-Year Reserve Additions (MMBOE) 16,000 14,409 13,767 14,000 12,107 12,000 In the complex commodity markets of today, U.S. producer performance and cost is increasingly relied upon as a guide to possible floor prices and longer term price trends. We use 3 year rolling total FD spending against 3 year reserve additions to reach FD/BOE. The capex requirements to high grade upstream, especially shale, portfolios has been considerable, exceeding $270 billion by Substantial write downs and impairments were taken in 2012 (slide 3) as a result of the steep fall in gas prices. Reductions in capex are discernible when 2013 data are added but rose again in We use cash cost against current production for cash cost/boe. Companies have grown production on a BOE basis by about 22 percent since Natural gas remains the dominant proportion of production streams but 2014 showed a marked shift. This pattern holds when we compare our results to other research. 9 of the 15 companies in our sample are predominantly gas producers (50 to nearly 100 percent of production) including 6 that are among the shale specialists and 1 integrated major. Capex Total Production (MMBOE) $200,000 8,993 10,000 $150,000 8,000 $270,763 $210,908 $228,185 $100,000 $224,103 $241,876 6,000 $170,556 4,000 $50,000 2,000 $ U.S. Total Production (MMBOE) Ratio of Natural Gas:Total U.S. Production 3,000 64% 2,500 2,000 1,500 1, % 62% 2,466 2,511 61% 61% 2,380 60% 2,215 2,059 59% 2,036 58% 57% 56% 54% 53% 52% 50% Additions Natural Gas Split % BEG/CEE-UT, 26

27 Bonus: Sources of Additions 8,000 6,000 Most booked additions come from drilling out acreage as opposed to improved recovery. 4,000 2, ,000-4,000 Purchases of Reserves (MMBOE) Extensions & Discoveries (MMBOE) Improved Recovery (MMBOE) Total Revisions (MMBOE) BEG/CEE-UT, 27

28 Computing Returns U.S. producers have demonstrated success in key shale plays but it is not an easy business. In BOE terms, on average and as of 2014, the full cycle cost for our sample is close to $50 per BOE with a 10 percent return assumed. However, a 10 percent return does not provide sufficient recovery of capital spent in a current year. Alternatively, we use a return equal to capex spent that year against current production. With the alternative criteria imposed, the average full cycle cost for 2014 was about $80 per BOE. We believe this suggests an oil price signal of at least $80 is needed to sustain activity for our sample and the industry. We note that many producers realize considerably less than the traded domestic oil prices. Condensate, the main component of many production streams, typically sells $20-25 below West Texas Intermediate. Overall, the industry remains predominantly cash flow negative. Companies have had to spend capital well above cash flow from operations to replace production and improve leasehold positions. With lower oil prices companies are working to adjust capital spending to fall within cash flows. $50 $40 $30 $20 $10 $0 $100 $80 $60 $40 $20 $0 10% Return ($/BOE) Annual Cash Costs per Bbl of Production ($/BOE) 3-Yr MA FD Costs/3-Yr MA Additions ($/BOE) Return of Current Capex ($/BOE) Annual Cash Costs per Bbl of Production ($/BOE) 3-Yr MA FD Costs/3-Yr MA Additions ($/BOE) BEG/CEE-UT, 28

29 Implications for Gas While the pressure is on from oil prices, the implications for natural gas are more interesting to consider. With a 10 percent return assumed, the minimum back to producers and their investors, the implied natural gas price is close to $8 per million Btu (MMBtu). However this only returns a portion of current capex. To return 2014 capex producers would have needed an implied price of more than $13, on average. Much of the incremental gas supply for the U.S. in recent years has come in association with liquids production or where enough ethane is present and can be captured to justify drilling in nonassociated (dry) gas locations. Perhaps as much as 50 percent or more of U.S. gas supply is linked to liquids prices. As a result, oil prices are being watched closely for hints about gas supply and price impacts. Our full report with 2014 data is forthcoming in April $9 $8 $7 $6 $5 $4 $3 $2 $1 $0 $18 $16 $14 $12 $10 $8 $6 $4 $2 $0 10% Return ($/MCFE) Annual Cash Costs per Bbl of Production ($/MCFE) 3-Yr MA FD Costs/3-Yr MA Additions ($/MCFE) Henry Hub Spot Price $ Return of Current Capex ($/MCFE) Annual Cash Costs per Bbl of Production ($/MCFE) 3-Yr MA FD Costs/3-Yr Additions ($/MCFE) Henry Hub Spot Price $ BEG/CEE-UT, 29

30 Bonus: It Takes an Industry An industry leader with an early shift to liquids 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% U.S. NGL Production (MMBOE) U.S. Gas Production (MMBOE) $120 $100 $80 $60 $40 $20 $ EOG Resources U.S. Oil and Liquids Production (MMBOE) U.S. Total Production (MMBOE) Return of Current Capex ($/BOE) Annual Cash Cost ($/BOE) 3-Yr MA FD Costs ($/BOE) 0 Note: Began separating oil and NGLs in % 90% 80% 70% 60% 50% 40% 30% 20% 10% % U.S. NGL Production (MMBOE) U.S. Oil and Liquids Production (MMBOE) $70 $60 $50 $40 $30 $20 $10 $0 A successful gassy player U.S. Gas Production (MMBOE) Range Resources U.S. Total Production (MMBOE) 71 Return of Current Capex ($/BOE) Annual Cash Costs ($/BOE) 3-Yr MA FD Costs ($/BOE) BEG/CEE-UT, 30

31 Comparative View Capex exceeds cash flows Bernstein Research BEG/CEE-UT, 31

32 Comparative View and has done so historically Bernstein Research BEG/CEE-UT, 32

33 Weighted Average NOC Breakeven Costs* ($/BOE) $120 $100 $94 $101 $80 $60 $40 $65 $76 $81 $80 10% ROI Annual Cap. Exp. $20 $ *10% ROI represented 30% of capital expenditures CEE analysis based on company reports BEG/CEE-UT, 33

34 Weighted Average NOC Breakeven Costs ($/BOE) $120 $100 $80 $60 $40 $ $94 $ Annual Cap. Exp. Fiscal Contribution Cash Op. Exp. Find. & Dev. Costs $20 $ CEE analysis based on company reports BEG/CEE-UT, 34

35 NOC Breakeven Costs 2013 ($/BOE) $200 $180 $160 $140 $120 $100 $80 $60 $40 $20 $0 $78 $8 $8 $96 $98 $119 $120 $12 $107 $145 $18 Cap. Exp. Fiscal Contribution Cash Op. Exp. Find. & Dev. Costs *Ecopetrol production taxes included in production costs **CNOOC capital expenditures increased from $12 billion in 2012 to $41 billion CEE analysis based on company reports BEG/CEE-UT, 35

36 DEMAND BEG/CEE-UT, 36

37 World Oil Demand (MBD) Governments are seizing the opportunity to eliminate subsidies North Amwerica Europe & Erasia Central & South America North America Africa & Mid East Asia-Pacific Based on data from EIA BEG/CEE-UT, 37

38 A strong demand stack scenario TCF LNG Exports 2030 = 1.0 (EIA ER = 3.5) Pipe Exports 2030 = 3.9 (EIA ER = 3.4) LNG exports CEE Pipeline exports CEE Power generation CEE Power 2030 = 15.9 (EIA ER = 10.1) CEE assumes all possible EPA actions Industrial 2030 = 8.8 (EIA ER = 8.5) Industrial CEE Other (Res, Comm, Trans) EIA ER Dec 2013 Total demand CEE High Case 5 Other 2030 = 10.8 (residential+ commercial 10.5) Total supply EIA ER Dec 2013 CEE analysis; EIA ER refers to EIA 2014 Early Release, Dec 2013 (reference case) BEG/CEE-UT, 38

39 Industrial Demand: Robust Plans BCFD Steel MTG Hydrogen Chlor-Alkali Methanol Nitrogen fertilizers Propylene Polyethylene Ethylene Base Demand (2012) CEE s industrial projects inventory BEG/CEE-UT, 39

40 Gas Demand by Region, End User BCFD Steel MTG Hydrogen Chlor-Alkali Methanol Nitrogen fertilizers Propylene Polyethylene Ethylene 0 LA TX Rest of US CEE s industrial projects inventory BEG/CEE-UT, 40

41 Investment by Region $billion LA Rest of US TX CEE s industrial projects inventory BEG/CEE-UT, 41

42 Projects by Region Project type LA Rest of US TX Total Chlor-Alkali Ethylene GTL Hydrogen Methanol MTG Nitrogen fertilizers Polyethylene Propylene Steel Grand Total BEG/CEE-UT, 42

43 Drivers: Relative Prices BEG/CEE-UT, 43

44 Drivers: BEG/CEE-UT, 44

45 Power: Competing Views Based on data from EIA AEO 2013 and IHSE BEG/CEE-UT, 45

46 Coal Retirements About 50 GW of coal capacity may retire by 2020 Almost 21 GW already retired (mostly older units) Announced about 29 GW ( ) BEG/CEE-UT, 46

47 Nuclear Relicensing? 4 recent announcements, more possible but our modeling does not retire nuclear units 5,500 MW in 3 plants under construction BEG/CEE-UT, 47

48 Resulting Scenario on Gas Use in Power Incorporates a higher, more volatile gas price. BEG/CEE-UT, 48

49 Exports: The Crude Oil Debate Is exporting crude oil a problem?? yes no Upstream economics, impacts on wellhead value Regulatory efficiency (political risk of alternative approaches) Value chain integrity supporting infrastructure ( both regulatory process and infrastructure are so 70s ) Enough companies can get exemptions, approvals Revoke EAA or remove all hydrocarbon components (chance of success?) Streamline existing process for long term optionality (exports, imports) Transport modes, risks, policy/regulatory considerations Perception of risk view: less drilling = less production = fewer nuisances and hazards Quick fix to add condensate to CCL (or remove, whichever is correct) BEG/CEE-UT, 49

50 TRADE BEG/CEE-UT, 50

51 O Canada! Getting Their Dander Up Enbridge Eastern Access TransCanada Energy East BEG/CEE-UT, 51

52 Gas Exports: The Future? 2013: U.S. is 29% of Canadian consumption 2013: U.S. is 29% of Mexican consumption ~2x current NA exports by 2020? ~9+ BCFD Map presents a possible gas flow scenario, Foss, Ch. 3 in Pricing Internationally Traded Gas, Oxford, 2012; gas trade data from EIA BEG/CEE-UT, 52

53 LNG: Europe or Asia? Neither? 12 JCC Feb NBP April JKM April Europe Europe Europe Asia Asia Asia Henry Hub Liquefaction Shipping JKM JCC NBP Pertamina, Endesa SA, Iberdrola, EDF, EDP, Gas Natural fenosa, Woodside Energy Trading have signed PSA for $3.50/MMBtu BEG/CEE-UT, 53

54 Is U.S. LNG Competitive? $/MMBtu $10 Japan pre- Fukushima $9-11 NBP Regasification Shipping Liquefaction Field to Terminal Henry Hub Sep 14 NBP $ $14-19 Asia spot The Attraction "Reality" High Cost Delivery to Atlantic Basin High Cost Delivery to Pacific Basin Sep 14 LNG $ Super High Cost Delivery to Pacific Basin mpetitive.pdf BEG/CEE-UT, 54

55 OTHER BEG/CEE-UT, 55

56 Impact of anchoring Dan Ariely, Predictably Irrational, 2009 BEG/CEE-UT, 56

57 Predictable irrationality Anchor prices, arbitrary coherence Herding, self-propelling Perception of value with anchoring Persistence of perception with herding Impact of initial decision on future expectations Price manipulation (by both private market participants and governments) Dan Ariely, Predictably Irrational, 2009 BEG/CEE-UT, 57

58 In short, we re a mess Illusion of truth Confirmation bias Hindsight bias Halo effect Sunk-cost fallacy Loss aversion Self-serving Lady Macbeth effect Framing Availability heuristic We re more likely to believe a familiar statement Tendency to favor information that confirms our beliefs Duh! principle One trait influences others as we make judgments They matter (!), because we are more afraid of incurring losses than acquiring gains, and we ll happily claim responsibility for success more often than failure, but just to be sure Out, damn spot! We have blinders and silos Predict frequency based on how easily an example comes to mind BEG/CEE-UT, 58

59 In love with fear itself Beard/dp/ /ref=sr_1_1?s=books&ie=UTF8&qi d= &sr=1-1&keywords=paranoiaca BEG/CEE-UT, 59

60 Why this stuff matters It is much easier [and] more enjoyable to identify and label the mistakes of others than to recognize our own Most of our judgments and actions are appropriate most of the time We are often confident even when we are wrong In at least some cases, an accurate diagnosis may suggest an intervention to limit the damage that bad judgments and choices often cause BEG/CEE-UT, 60

61 unusual (but not unprecedented) Texas Insider; Mulvaney, et.al., BEG/CEE-UT, 61

62 Courtesy Dr. John Christy, NOAA-University of Alabama Huntsville, above as appeared in Wall Street Journal, right as appeared in What s Up with That. BEG/CEE-UT, 62

63 Dynamic Earth Sea Surface Temp. Although warming of the northeastern Antarctic Peninsula began around 600 years ago, the high rate of warming over the past century is unusual (but not unprecedented) in the context of natural climate variability over the past two millennia. JRI Ice Core Temp. Mean (black lines are estimates of open water based on sediment cores) BAS Ice Core Temp. Mulvaney, et.al., Nature 11391; SOTU 2014 BEG/CEE-UT, 63

64 The Role of Science BEG/CEE-UT, 64

65 The 6X Gap BEG/CEE-UT, 65

66 An Impact (Scale) 5 Energy GHG (Climate) 4 Energy Security Web Envt (Land, Water) 0 Safety Coal Natural Gas LNG Nuclear Envt (Air) Reliability Hydroelectric Solar, Wind (grid-based) Solar, Distributed Market Friendly BEG/CEE-UT, 66

67 An Energy Web GHG (Climate) Impact (Scale) Energy Security 2 1 Envt (Land, Water) 0 Safety Coal Natural Gas LNG Nuclear Hydroelectric Envt (Air) Reliability Solar, Wind (grid-based) Solar, Distributed Market Friendly BEG/CEE-UT, 67

68 Contact Information All work in progress is located on CEE address - energyecon@beg.utexas.edu BEG/CEE-UT, 68