Energy Market Intelligence Webinar. January 23, 2019

Transcription

1 Energy Market Intelligence Webinar January 23, 2019

2 Today s Speakers Andrew Durante Meteorologist Ed Fortunato Managing Director, Wholesale Short-Term Fundamentals Greg Kosier Commodities Management Group Keith Poli Commodities Management Group Brian Habacivch Commodities Management Group 1

3 Today s Webinar Agenda Weather: Winter Reloads in late January? What does balance of winter hold? 2019 Key Fundamental Drivers and Regional ISO Outlooks Near Term Market Fundamentals Gas & Power Pricing Trends 2

4 Weather

5 Short-Term Weather Drivers A cold pattern is expected through the 6-10 and most of the 8-14 day periods. The coldest temperatures are expected to be across the Midwest, with below-zero lows expected for Chicago this week and next week. There are signs that the cold pattern may relax for a short-period of time in early February. Source: NOAA 4

6 January Stats JANUARY 2019 TEMPERATURE DEPARTURES (REALIZED + FORECAST) FIRST HALF (TOP) SECOND HALF (BOTTOM) January 2019 is expected to come in around the 26th warmest January since Gas-weighted heating degree days are expected to come in around 940, which is slightly warmer than the 10-year normal of 947 and the 30-year normal of 952. The first half of January came in as the 10th warmest since The second half of January will likely come in around the 24th coldest since Source: Radiant Solutions 5

7 Future Pattern SHORT-TERM PATTERN: VERY COLD LONG-TERM PATTERN: MODELS MAY BE SHOWING A BRIEF BREAK The short-term models show a very cold pattern with blocking over the northeast Pacific, parts of Alaska and across the north Atlantic. The models show some changes during the late day period as the blocking over the Pacific weakens, allowing some Pacific air to mix into the pattern. Despite this, the models still show a lot of blocking across the Arctic and even across parts of the north Atlantic. This may be a brief break in the cold pattern, however confidence is a little lower than normal. Source: WSI 6

8 March Outlook FAVORED MARCH YEARS AMERICAN MONTHLY MODEL (MARCH) Our research suggests that March could come in warmer than normal as El Niño winters tend to be mild during the early spring. The longer-term weather models support most of this warmer view. Some cold may linger across the Northeast during the first week of March, however warmer trends are seen thereafter. Sources: Radiant Solutions and NOAA 7

9 2019 Key Gas & Oil Market Drivers and Regional Power Market Outlooks

10 2019: Top Level Gas & Power Market Themes A year of record U.S. Energy Exports Rising Production Rising Demand Rising Volatility -- Lots of Wild Cards Natural Gas Production EIA forecasts 2019 Natural Gas Production to average 90 Bcf/day Currently at 86 Bcf/day. This continues growth where 2018 dry gas production averaged 83.3 Bcf/day. Exports Liquefied Natural Gas (LNG): EIA forecasts 4.5 Bcf/day of new LNG export capacity in 2019 as four new export terminals (i.e., Elba Island, Corpus Christi, Cameron and Freeport) double capacity. Watch pipeline project development in Mexico. Power-Generation Demand 2019 to see ~7.5 GW of new gas-fired generation come online and 4.5 GW of additional coal retirements. Natural gas-fired generation will continue to support growing renewable capacity. Crude Oil Production rises from 11.2 million bbls/day to 11.9 million bbls/day by end of the year. Less than $50/bbl is bullish of gas and power -- $50-65/bbl is neutral gas and power $70 and above is bearish of natural gas. (All other things being equal, numerous caveats apply). Economy (Macro): U.S. tariffs with China & China GDP? Fed rate hikes in 2019? Source: EIA 9

11 2019 PJM Outlook: Evolving Fuel Mix Natural Gas is now King in PJM 24 GW of new CCGTs have been added in PJM from ; coal and nuclear retirements continue Energy Price Formation Proposal Proposals to reform reserve pricing in PJM could impact energy, ancillary and capacity costs Capacity Market Reforms to Incorporate State-Subsidized Resources PY22-23 BRA delayed from May until August as PJM capacity market reform proposal is pending at FERC Increasing Renewable Portfolio Standards (RPS) NJ implemented increases its RPS in 2018, and DC is expected to increase theirs in 2019; other states to follow? State/Federal/ISO-level Support for Baseload Generation? Customer Takeaway: Low-cost natural gas and an increase in renewables have transformed the supply stack in PJM as sustained low power prices have led to coal and nuclear unit retirements. As a result, ongoing efforts to ensure grid reliability and resiliency will take center stage in PJM in Source: EIA 10

12 2019 ISO-NE Outlook: Three Chapters of Fuel Security Winter Energy Security Cost to Serve/Chapter 1* Jun 2022 Dec 2023 Feb 2024 May 2024 Dec 2024 Feb 2025 December 2026 and Beyond * All dates subject to change, Chapter 1 Jun22-May23 is the only period accepted and approved. Long-Term Fuel Security/Chapter 3 1. On December 3rd, FERC approved of ISO-NE s request to retain resources critical to reliability with out-ofmarket compensation (aka Fuel Security Chapter 1, Cost to Serve ). Namely, Mystic units #8 & 9 and in effect the adjacent Everett LNG facility that serves as fuel supply The compensation is expected to be awarded to the units will be allocated to real-time load obligation (i.e. load-serving entities) from June 2022 through May An interim program is being designed as a bridge to a longer-term fuel security program and is being called Winter Energy Security (aka Chapter 2 ). This can be analogous with the now defunct Winter Reliability Program. Resources would receive additional revenues to provide Energy Inventory during Trigger Conditions under this voluntary program and would be effective Winter 2023/2024 and 2024/ Chapter 3 which is considered the long-term fuel security solution could begin as early as Winter 2024/2025. This would feature a Multi-Day Ahead Market; additionally, a new Energy Inventory Reserve Constraint and Forward Inventory Reserve Mechanism could be new billing items allocated to real-time load obligations. Customer Takeaway: Despite the actual lag in actual billed costs expected in June 2022 for Chapter 1, load-serving entities must account for all of these costs when serving retail load. Constellation has broken out this component in the retail contract for all New England accounts. Sources: ISO-NE, FERC, Exelon Winter Energy Security 11

13 2019 NYISO Outlook: Carbon Proposal Gross SCC RGGI, Inc. Net SCC $nominal/us-ton $nominal/us-ton $nominal/us-ton 2020 $ $ 6.56 $ $ $ 6.98 $ $ $ 7.39 $ $ $ 7.81 $ $ $ 8.45 $ $ $ 9.09 $ $ $ 9.73 $ $ $ $ $ $ $ $ $ $ $ $ $ Cal 22 & 23 strips up 20-25% y-o-y since draft proposal (Apr 18) In December, the NYISO released its final proposal to implement the social cost of carbon in its electricity markets to better align with the state s decarbonization policies. Earliest possible implementation is late As part of the proposal, the New York Public Service Commission would set the Gross Social Cost of Carbon (SCC) in accordance with the regulatory process. Current gross SCC values are represented in the chart above. The carbon charge would raise energy market clearing prices when carbon-emitting resources are on the margin. Load-serving entities (LSE) would continue to be charged LBMP for wholesale energy purchases, and the NYISO would return the carbon charge residuals collected back to LSEs. While the recent proposal addresses seams issues and double payments, there still remain several issues to be resolved by the Public Service Commission and stakeholders with a final vote targeted for Q Customer Takeaway: Forward power markets responded strongly to the NYISO proposal to implement carbon into the wholesale market. Expect continued volatility as policy and pricing mechanics are vetted though state and federal approval processes. If approved, this policy will likely raise wholesale power prices in the state. Source: NYISO 12

14 2019 ERCOT Outlook: Reserve Margin Tightens for Summer Illustration of ERCOT Operational Reserve Demand Curve (ORDC) NERC Reserve Margin Target 13.75% $9,000/MWh The decline in the reserve margin from 11% for summer 2018 to 8.1% for December 2018 was driven by demand factors, such as growth from oil and gas production, and a strong Texas economy. On the supply side, ERCOT saw cancelled renewable and gas projects that contributed to a lower reserve margin. The recently announced retirement of the 470 MW Gibbons Creek coal plant further reduces capacity from 8.1% to 7.4% for 2019 per ERCOT and will likely be ~10% for 2020 (under current assumptions). The Texas PUC on January 17th passed a motion to amend the Operational Reserve Demand Curve (ORDC) by 0.25 standard deviation as a measure to address tight generation reserve margins in an energy only market. Customer Takeaway: Over last few years, ERCOT has seen coal and older gas units retire as a result of low natural gas prices along with expanding renewable (wind and solar) capacity. Fewer new thermal gas plants have been constructed to keep up with load growth in ERCOT that has averaged 1-1.5% annually. Source: ERCOT 13

15 2019 CAISO Outlook: PG&E Chapter 11 & SoCalGas Pipelines The Wall Street Journal estimates damages from wildfires could cost PG&E $30 billion. PG&E s CEO resigned recently, and the company announced it was preparing to file for bankruptcy by the end of January. On January 17th, S&P downgraded PG&E s credit rating to a D. A PG&E bankruptcy filing in the short term could increase gas and power markets volatility if fewer counterparties transact with PG&E. Meanwhile, in SoCal the major pipeline maintenance in eastern CA still does not have a stated end date per SoCal Gas, which has reduced capacity into SoCal systems from 3.5 to 2.5 Bcf/day. Customer Takeaway: PG&E s pending bankruptcy could increase uncertainty in the short term, while in SoCal limited import capacity (2.5 Bcf/day) may lead to a repeat of last summer s spot gas volatility. Sources: PG&E WSJ, EIA 14

16 Near Term Fundamentals

17 Storage Deficit Slashed to -77 Bcf from -700 Bcf Storage stands at 2,533 Bcf, or -77 Bcf (3%) below year-ago levels and -327 Bcf (11%) below the five-year average. The storage deficit has narrowed in past month after peaking at -722 Bcf (-20%) for the week of December 7th. The narrowing of the storage deficit has reduced the risk of very tight supplies for end of March, with EIA January Short- Term Energy Outlook (STEO) forecasting the end of March underground storage to be 1.4 Tcf, just above last year s 1.35 Tcf. NYMEX prices retraced in January as warm weather allowed the deficit to narrow, and the market is turning its attention to end of January/February weather that will likely see the storage deficit expand again in February. Customer Takeaway: Storage inventories have improved over the past 30 days, alleviating concerns for now of critically low storage levels for end of March but cold February weather will likely stop the narrowing of the storage deficit. Source: EIA 16

18 Will Production Keep Up with Demand in 2019? EIA forecasts 2019 natural gas production to average 90.2 Bcf/day in 2019, up from a 2018 average of 83.3 Bcf/day. Production has begun 2019 at approximately 86 Bcf/day by some analyst estimates. In 2018, the Northeast saw the largest growth in production at ~3.5 Bcf/day, while Texas is higher by ~2.5 Bcf/day. Both were driven by new pipeline takeaway capacity in PA data thru October shows production up 27% year-over-year and new well permits remain active in Southwest and Northeast PA. In its January STEO, the EIA lowered its gas price forecast for 2019 by 22 cents to $2.89 for Henry Hub based on continued production growth. Customer Takeaway: Dry gas production continues to break records, ending 2018 at likely near 86 Bcf/day. Despite record production, strong demand drivers kept the year-over-year storage deficit consistent at 20% until mild weather in January reduced the deficit. The Northeast, Texas and Louisiana will remain key producing regions in Sources: EIA, Platts, PA DEP 17

19 Gas & Renewables Dominates New Generation in Review: New gas-fired generation accounted for 75% of the 25 GW in total electric resources added in That 19 GW of gas-fueled capacity more than offset the 16 GW total retirements nationally, most of which was coal Outlook: EIA is forecasting 23.7 GW of new capacity vs. 8.3 GW of retirements; 53% being coal. 7.5 GW of new gas capacity; mostly combined cycle units are expected to be online by June. 11 GW of new wind scheduled along with 4.3 GW utility scale and 3.9 GW small scale solar scheduled for end of year. Coal: 1 large coal unit in AZ accounts for over 50% of 4.5 GW coal retirements, down from 13.7 GW in Customer Takeaway: Gas-fired generation will continue to replace coal and nuclear as well as back up intermittent wind and solar resources in Source:: EIA Constellation Energy Resources, LLC. The offerings described herein are those of either Constellation NewEnergy-Gas Division, LLC or Constellation NewEnergy, Inc., affiliates of each other and ultimate

20 Natural Gas and Power Pricing Trends

21 NYMEX Pulls Back on Falling Storage Deficit Customer Takeaway: NYMEX prompt-month to below $3/MMBtu as milder temperatures in the near-term keep pushing back the return of colder forecasts for January and cut into the storage deficit. Weather will hold the key to price direction as cold temperatures into February could support gas demand. Source: NYMEX 20

22 NYMEX Natural Gas Calendar Strips $/MMBtu 12-mo Price $ 3.03 $ 2.75 $ 2.65 $ 2.66 $ 2.70 vs. 1-yr Avg 4% 2% -1% -2% -2% vs. 1-yr Max -11% -2% -8% -8% -8% vs. 1-yr Low 12% 6% 4% 5% 4% Customer Takeaway: The NYMEX 12-month strip has rebounded after plummeting from previous highs due to a return to colder weather. Record production keeping pressure on deferred calendar strip prices. Sources: Constellation, NYMEX; Prices as of COB 1/22/19 21

23 Forward Power Price Trends (6-Month History) New England Texas Southern CA Mid-Atlantic Northern Illinois NYC (NY) Note: These energy-only power prices are an indicative, non-transactable snapshot of the wholesale market as of COB 1/22/19. Customer Takeaway: The storage deficit and early cold has spurred a rally in near-term prices, while record gas production has kept pressure on the outer years. Backwardation in many markets favors extended contract terms. Source: Constellation; Prices as of COB 1/22/19 22

24 Index Power Prices (6-Month History) New England Texas SoCal Mid-Atlantic Northern Illinois Hudson Valley (NY) Note: These energy-only power prices are an indicative, non-transactable snapshot of the wholesale market as of COB 1/22/19. Customer Takeaway: The first Arctic blast of winter resulted in a brief uptick in index power price volatility for parts of the Midwest and the Northeast markets. While index prices are still below levels seen during sustained cold periods in previous winters, there is still opportunity for cold weather into February to drive volatility. Source: Indicated ISOs 23

25 Forward Power Prices vs. All Time Lows Regional power forward prices can reflect regional ISO issues such as in ISO-NE, NYISO, ERCOT and CAISO, where either tight gas supply, pending carbon legislation or tight generation reserve margins are key drivers. PJM and MISO continue to reflect the NYMEX forward curve of balance of 2019 and 2020 at a premium to outer years or a backwardated market. Customer Takeaway: Forward power markets continue to be influenced by forward gas prices but also regional driven supply and demand drivers. There is also the opportunity to blend outer year prices at a discount to current prices. Source: Constellation 24

26 Until Next Time February 20th Thank you for your participation. Please join us on Wednesday, February 20th, at 2 p.m. ET, for our next webinar we will update listeners with key weather drivers, the storage outlook for March and production metrics, along with a look at continued growth in demand drivers, the key being the liquefied natural gas (LNG) terminals entering service in the first quarter of Feel free to reach out to the Commodities Management Group (CMG) with questions/requests at CMG@Constellation.com. We look forward to and appreciate your feedback. 25

27 Disclaimer The information contained herein has been obtained from sources which Constellation NewEnergy, Inc. and Constellation NewEnergy-Gas Division, LLC (together, Constellation ) believe to be reliable. Constellation does not represent or warrant as to its accuracy or completeness. All representations and estimates included herein constitute Constellation s judgment as of the date of the presentation and may be subject to change without notice. This material has been prepared solely for informational purposes relating to our business as a physical energy provider. We are not providing advice regarding the value or advisability of trading in commodity interests as defined in the Commodity Exchange Act, 7 U.S.C. 1-25, et seq., as amended (the CEA ), including futures contracts, swaps or any other activity which would cause us or any of our affiliates to be considered a commodity trading advisor under the CEA. Constellation does not make and expressly disclaims, any express or implied guaranty, representation or warranty regarding any opinions or statements set forth herein. Constellation shall not be responsible for any reliance upon any information, opinions, or statements contained herein or for any omission or error of fact. All prices referenced herein are indicative and informational and do not connote the prices at which Constellation may be willing to transact, and the possible performance results of any product discussed herein are not necessarily indicative of future results. This material shall not be reproduced (in whole or in part) to any other person without the prior written approval of Constellation.