Andrew D. Weissman Senior Energy Advisor, Haynes and Boone, LLP Chief Executive Officer, EBW AnalyticsGroup

Transcription

1 Understand the Factors Behind this Winter s Price Spikes, and their Implications on Near and Longer Term Pricing of Electricity and Natural Gas Andrew D. Weissman Senior Energy Advisor, Haynes and Boone, LLP Chief Executive Officer, EBW AnalyticsGroup Andrew.Weissman@HaynesBoone.com Special presentation to GDF SUEZ Energy Resources NA March 11, Haynes and Boone, LLP

2 Andy s Background Andy Weissman Chief Executive Officer at EBW AnalyticsGroup Senior Energy Advisor at Haynes and Boone, LLP Special Contributor for GDF SUEZ Energy Resources On The Horizon quarterly Newsletter Guest Presenter on GDF SUEZ s Current Intelligence quarterly webinar series Guest Presenter for GDF SUEZ s educational seminars in ERCOT, PJM, and NEPOOL Join Andy on LinkedIn Andy Weissman Visit EBWAnalytics.com and EBWMarketPro.com 2

3 Agenda Lessons learned from this winter Increasing frequency of extreme weather events Severity and causes of price spikes Shifts in forward price curve short and long-term Warning signs emerging of far-reaching market shifts Impact on electricity and natural gas prices next months Lasting impact of huge storage drawdown/need for record storage refill Continued weather-related risks Potential supply side response Differences in injection strategies LDCs vs. merchant players Longer-term implications Winter of revealed huge structural deficiencies in U.S. market Could become increasingly severe over time Creates much greater upside price risk than over the past few years 3

4 Critical Take-Aways No longer business-as-usual Mistake to attribute price spikes solely to weather Despite shale revolution, moderate prices no longer guaranteed Forward price curve could rise sharply higher over the next few years Compelling reasons to follow portfolio approach Cover significant portion of future requirements much further out in time Urgent need to develop new solutions to address: Huge and potentially growing weather-driven swings in demand for gas Lack of critically needed pipeline and transmission infra-structure Inadequate incentives to fully utilize available natural gas storage Lack of sufficient natural gas deliverability capability on days of peak demand Inadequate incentives to continue operation of dispatchable generation with low capacity factors and/or to build new capacity Severity of weather-driven demand remains critical factor Mild weather can mask lack of needed infrastructure Market forces alone will not alleviate risk Requires action by end-users, ISOs and regulators 4

5 LESSONS LEARNED THIS WINTER 5

6 Previous Winters Masked Upside Price Risk Lowest prices in ten years in winter of Direct result of extremely mild weather Weather-driven demand last winter only slightly milder than historical norms Kept prices at reasonable levels during winter months But rose sharply in spring NATIONAL NOVEMBER MARCH GAS-WEIGHTED HEATING DEGREE DAYS DURING PREVIOUS TEN WINTERS NATURAL GAS PRICES AT HENRY HUB DURING PREVIOUS TWO WINTERS ghdds 4,200 4,000 3,800 3,600 3,400 3,200 3,000 TEN-YEAR AVERAGE: 3,745 GHDDs $/MMBtu $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 2,800 $1.50 Oct Nov Dec Jan Feb Mar Apr May Jun Jul Source: EBW Analytics, Commodity Weather Group Source: Bloomberg 6

7 No Warning of Price Shocks This Winter Core winter weather (December February) coldest in 32 years Colder-than-normal weather could extend through early April As recently as mid-january, no major weather forecasting firm predicted Many initially forecast mild January and February weather In normal weather scenario, $3.79/MMBtu price would have been likely Market slightly better supplied than last year FEBRUARY 2014 FORECAST FROM CWG 12/23/13 SEASONAL OUTLOOK MARKET EQUILIBRIUM PRICE OF NATURAL GAS, NOVEMBER 2013 TO MARCH 2014 $/MMBtu $6.00 $5.50 $5.00 $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $3.79/MMBtu Most Likely Weather Bcf Source: Commodity Weather Group Source: EBW Analytics 7

8 2/10/2014 2/11/2014 2/12/2014 2/13/2014 2/14/2014 2/16/2014 2/17/2014 2/18/2014 2/19/2014 2/20/2014 2/21/2014 2/23/2014 2/24/2014 2/25/2014 2/26/2014 2/27/2014 2/28/2014 3/2/2014 3/3/2014 3/4/2014 3/5/2014 Extreme Weather Drove Prices Sharply Higher Relentless incursions of Arctic air led to steep increase in natural gas prices Extremes becoming the norm Even short-term forecasts often useless As recently as third week in February, 175 Bcf of expected demand added in just five days! Exacerbated by 200 Bcf+ of lost supply Due to freeze-offs, high line pressures, and completion delays Resulted in all-time record withdrawals and huge price volatility for 12-month strip Record speculative long position by (540,040 contracts) also played a role HISTORICAL AND PROJECTED WINTER STORAGE WITHDRAWALS NATURAL GAS FRONT-MONTH CONTRACT AT 15-MINUTE TRADING INTERVALS, FEBRUARY 10 TO MARCH 4, 2014 Bcf $/MMBtu $6.75 March Contract Expiration Led to Large Price Spike FIVE-YEAR AVERAGE: 2,034 Bcf $6.25 $ $5.25 $ $4.25 1,000 1,500 2,000 2,500 3,000 Source: EBW Analytics, EIA Source: Bloomberg 8

9 Near-Term Impact on Electricity Market Just as Severe Electricity demand far above year-earlier levels, particularly in Northeast, Mid- Atlantic and Midwest For both natural gas and electricity, forward price curve for remainder of this year and first quarter of 2015 has risen sharply Except in New England, however, prices after March 2015 have barely budged 88,000 86,000 84,000 82,000 80,000 78,000 76,000 74,000 72,000 70,000 GWh NATIONAL WEEKLY ELECTRICITY GENERATION, JANUARY AND FEBRUARY 2013 AND 2014 Average Weekly Generation 5.3% Higher in ,000 4-Jan 11-Jan 18-Jan 25-Jan 1-Feb 8-Feb 15-Feb 22-Feb 1-Mar $/MMBtu $6.00 $5.50 $5.00 $4.50 $4.00 $3.50 NYMEX NATURAL GAS FUTURES STRIP, Source: EBW Analytics, EEI Source: Bloomberg Strip on 11/29/13 Strip on 3/4/14 9

10 Most Important Story Regional Increases in natural gas prices at Henry Hub only small part of story Price spikes in high-demand regions far more severe NEW ENGLAND ISO NEW YORK ISO Algonquin Natural Gas Hub (ISO-NE), Winters of and ISO-NE Internal Hub Day-Ahead Peak Price, Winters of and TETCO M3 Natural Gas Hub (NYISO), Winters of and NYISO Zone G Day-Ahead Peak Price, Winters of and New England Sees Worse, Persistent Gas Basis Differentials Chronic Electricity Price Spikes in New England Despite New Pipeline, Deliverability Remains Major Constraint Scarcity Pricing Frequency and Severity Greatly Increased 10

11 Not Limited to Northeast Almost as severe in PJM Even ERCOT and CAISO briefly saw prices spike PJM ISO ERCOT ISO Transco 6 Natural Gas Hub (PJM), Winters of and PJM Western Hub Day-Ahead Peak Price, Winters of and Carthage Natural Gas Hub (ERCOT), Winters of and ERCOT North Day-Ahead Peak Price, Winters of and Deliverability Constraints Drive Scarcity Prices Price Spikes in Demonstrate Relationship of Gas and Electricity Prices Proximity to Henry Hub and Producing Region Keeps Basis Differentials Low Year-over-Year Prices Significantly Grow 11

12 Increase in Average Monthly Price Just as Significant Startling year-over-year increases $200 $150 $100 $50 ISO-NE Internal Hub Day-Ahead Peak Prices, Winter 2013 and 2014 $/MWh $250 $/MWh $250 $200 $150 $100 $50 NYISO Zone G Hub Day-Ahead Peak Prices, Winter 2013 and 2014 $0 January February $0 January February PJM Western Hub Day-Ahead Peak Prices, Winter 2013 and 2014 ERCOT North Day-Ahead Peak Prices, Winter 2013 and 2014 $/MWh $180 $160 $140 $120 $100 $80 $60 $40 $20 $0 January February $/MWh $70 $60 $50 $40 $30 $20 $10 $0 January February Source for all: EBW Analytics, Bloomberg 12

13 Increased Demand for Natural Gas Nationally Not Pricing Drivers Year-over-year increase in prices at Henry Hub generally accounted for just $6 $24/MWh of electricity price increase More critical drivers were: Pipeline congestion and transmission constraints Failure to inject sufficient natural gas into storage to protect against colder-than-normal winter Lack of adequate natural gas deliverability to meet total demand for space heating and power on coldest days Resulted in huge amounts of shut-in gas-fired generation Need to rely on ultra-expensive alternative sources of supply Reveals stunning break-down in planning and huge gaps in infrastructure required to serve market Could become far more severe over next few years Lack of weather predictability and expectation prices will soon fall below $4.50/MMBtu makes injecting gas into storage a risky bet for merchant players Drop-off in forward curve after first 9-12 months reduces incentives to producers to ramp-up drilling DAILY U.S. NATURAL GAS DEMAND, JANUARY FEBRUARY 2013 AND 2014 Source: Reuters Colder Winter Drives Much Higher Demand in

14 PRICES OVER THE NEXT MONTHS 14

15 Record Storage Refill Requirement Keeps Natural Gas Prices High Primary market driver during this year s injection season = need to inject record amounts of natural gas into storage Potentially 2,800-2,850 Bcf to achieve full storage refill Far surpasses previous high 2,545 Bcf in 2003 Requires record injections for seven straight months Average increase of 3½ Bcf/day U.S Significant risk end-of season storage will fall well below 3,834 Bcf peak last year ACTUAL AND PROJECTED NATURAL GAS STORAGE INJECTIONS, Bcf 3,000 2,600 2,200 1,800 1,400 FIVE-YEAR AVERAGE: 2,056 Bcf Bcf REQUIRED STORAGE INJECTIONS VS ACTUAL 2013 INJECTIONS Much Larger Injections Needed to Reach Sufficient Storage 1, April May June July August September October Actual Projected Source: EBW Analytics, EIA Source: EBW Analytics, EIA 15

16 Storage Refill Requirement Not The Only Factor Other major market drivers include: Weather driven demand particularly next summer Nuclear power plant performance and hydro availability Growth in U.S. production/decline in Canadian imports Different in price Local Distribution Companies (LDCs) and merchant players willing to pay to inject natural gas in storage LDCs largely insensitive to price Merchant players maybe very reluctant to inject at $4.50/MMBtu prices Impact on prices likely to vary by season Gas Generation Needed to Replace Refueling Nuclear Plants, 2014 NYMEX Natural Gas Forward Curve, April 2014 December 2015 Bcf/Day Gas Needs Expected to Peak in Mid-April $/MMBtu $4.80 $4.70 $ $ $4.40 $4.30 $ $ $4.00 $3.90 $ /6/2014 4/6/2014 5/6/2014 6/6/2014 Source: EBW Analytics Source: Bloomberg 16

17 4/1/2013 4/3/2013 4/5/2013 4/9/2013 4/11/2013 4/15/2013 4/17/2013 4/19/2013 4/23/2013 4/25/2013 4/29/2013 5/1/2013 5/3/2013 5/7/2013 5/9/2013 5/13/2013 5/15/2013 5/17/2013 5/21/2013 5/23/2013 5/28/2013 5/30/2013 6/3/2013 6/5/2013 6/7/2013 6/11/2013 6/13/2013 Natural Gas Prices Most Certain to Be Strong This Spring While natural gas prices could dip later this month, by mid-april prices likely to strengthen significantly Spillover effect on electricity Injections likely to be very strong Planned nuclear refueling outages and heavy coal plant maintenance will keep price insensitive demand for natural gas fight Too little lead time to materially increase supply If weather-driven demand in early April or late May is higher than normal, or forced outage rates are high, significant price spikes are possible Likely to drive up prices for remaining 2014 contracts HISTORICAL AND PROJECTED APRIL/MAY STORAGE INJECTIONS Bcf 900 Very High Early-Season Injections Needed FRONT-MONTH NATURAL GAS CONTRACT IN 2013 VS 2014 CONTRACTS $/MMBtu April 2014 $4.70 Contract: $4.60 $4.52 $4.50 $4.40 $4.30 $4.20 $4.10 $4.00 $3.90 $3.80 $3.70 May 2014 Contract: $4.48 Historical Projected Source: EBW Analytics, EIA Source: Bloomberg 17

18 Summer Natural Gas Prices Less Certain Role of injections could reverse the normal summer pattern LDCs generally schedule most injections for spring and fall <20% in mid-summer While forecast reliability is very low, current indications suggest potential for significantly milder weather than typical in recent years Nuclear and coal units likely to be back in service Use of natural gas for coal displacement likely to be much lower Demand for natural gas and prices could be relatively weak HISTORICAL AND PROJECTED JULY-AUGUST STORAGE INJECTIONS FRONT-MONTH NATURAL GAS CONTRACT IN 2013 VS 2014 CONTRACTS Bcf Despite Summer Power Sector Demand, High Injection Levels Likely to Continue $/MMBtu $4.80 $4.60 July 2014 Contract: $4.54 August 2014 Contract: $ $ $ $ $ $ $ $3.20 Historical Projected Source: EBW Analytics, EIA Source: Bloomberg 18

19 Weather Remains Key to Electricity Severity of summer weather remains key driver for electricity market Weather has huge impact on demand Far more significant than impact of potential swings in natural gas prices Unless summer weather is very hot, prices could be only slightly higher than last year Could even be lower if summer weather is cool and natural gas prices soften PJM WESTERN HUB DAY-AHEAD HISTORICAL PEAK AND FUTURES PRICES $/MWh $170 $150 ERCOT NORTH DAY-AHEAD HISTORICAL PEAK AND FUTURES PRICES $/MWh $150 $130 August 2014 Future: $118 $130 $110 $90 $70 June 2014 Future: $55 July 2014 Future: $72 August 2014 Future: $64 $110 $90 $70 June 2014 Future: $59 July 2014 Future: $80 $50 $50 $30 $30 Source: Bloomberg Source: Bloomberg 19

20 Natural Gas Prices Planned injections will increase Refueling and maintenance outages will resume Weather still important Likely to be increasingly apparent that full storage refill not likely Key issues: Potential increase in U.S. production Merchant players appetite to inject natural gas into storage at relatively high prices HISTORICAL AND PROJECTED SEPTEMBER-OCTOBER STORAGE INJECTIONS FRONT-MONTH NATURAL GAS CONTRACT IN 2013 VS 2014 CONTRACTS 1, Bcf Large Injections Likely Still Needed as Storage Season Comes to a Close $/MMBtu $4.80 $4.60 September 2014 Contract: $4.50 October 2014 Contract: $ $ $ $ $ $3.60 $3.40 Historical Injections Projected Injections Source: EBW Analytics, EIA Source: Bloomberg 20

21 Weather Remains Key to Next Winter Current forward curve builds in a /MMBtu premium vs. the April October 2015 contracts Starting point for next winter could be closer to winter of than might first seem likely Start of season-storage could be Bcf below November 2013 peak Canadian imports could decline But U.S. production could significantly exceed year-earlier levels HISTORICAL AND PROJECTED ONSHORE U.S. NATURAL GAS PRODUCTION Source: EBW Analytics Domestic Supplies Poised to Grow Year-Over-Year 21

22 LONGER-TERM IMPLICATIONS 22

23 Profound Changes On The Horizon Potential huge increases in U.S. demand Massive coal plant retirements starting in spring of 2015 Huge growth in Mexican exports Industrial boom LNG exports starting in 2016 Use of LNG for heavy duty trucks and marine transport Potential increases not yet priced into market CUMULATIVE INCREASE IN DEMAND FOR US PRODUCTION , BY SOURCE SCHEDULED COAL RETIREMENTS BY YEAR AND REGION Capacity (MW) 16,000 14,000 12,000 10,000 8,000 6,000 4,000 California ISO Midcontinent ISO New York ISO SPP ERCOT ISO New England ISO PJM ISO Non-ISO 2, Source: EBW Analytics Source: EBW Analytics, Ventyx 23

24 Obama Climate Action Plan Could Have Significant Further Impact Far greater potential impact than generally recognized First-time federal restrictions on emissions of greenhouse gases for existing coal-fired plants Proposed U.S. EPA rules expected June 1, 2014 Implementation by states in 2016 Could lead to: Retirement of additional 60,000 MW of coal-fired generation by 2020 Up to 10 Bcf/day of additional demand for natural gas STATE-BY-STATE COAL SHARE OF ELECTRICITY GENERATION POTENTIAL GREENHOUSE GAS EMISSIONS REDUCTIONS REQUIRED UNDER UPCOMING GHG REGULATIONS, TOP FIVE EMITTERS Most Vulnerable States Have High Coal Use State 2011 Fossil Fleet Carbon Emissions (million MtCO2) Potential 2020 Emissions Reductions Under Climate Action Plan Required Reduction from 2011 Emissions Texas 267,445 41,434 15% Pennsylvania 116,031 15,625 13% Ohio 112,293 24,240 22% Florida 111,918-0% Indiana 109,284 23,169 21% Source: EBW Analytics, EIA Source: EBW Analytics 24

25 Major Structural Challenges Becoming Apparent Lack of adequate incentives to build new generation or keep existing generation online Questions regarding reliability of demand side management Huge planning void Flawed methodology Ignores natural gas side of the equation Structural deficiencies highlighted this winter Potential impact of extreme weather/difficulty in adjusting to huge swings in weather-driven demand Exacerbated by increased dependence upon natural gas Lack of critically needed pipeline and transmission infrastructure Inadequate incentives to fully utilize storage Lack of adequate deliverability 25

26 Huge Upside Risks for Customers/Downside Risks for Producers Problems as much institutional as structural No effective mechanism for planning or even identifying risks Dysfunctional regulatory system Creates huge upside risks for end users Deters expanded use Paradoxically, natural gas producers remain highly vulnerable to downside risks Prices likely to periodically crater whenever weather-driven demand slumps Production growth likely to continue to exceed expectations Power producers exposed to huge regulatory risks without assured means of recovering capacity costs Cries out for: Long-term supply agreements/partnership Portfolio approach by energy users purchasing at market price 26

27 Energy Risk Report Our analysis of price risks in regional electricity markets specially designed to help energy buyers adopt an informed, creative and effective procurement strategy. FOR FREE ENERGY RISK REPORT: VISIT 27

28 For more information: Andy Weissman and Haynes and Boone, LLP