MARKET INTEL NEWSLETTER
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1 Constellation s MARKET INTEL NEWSLETTER Energy Market Update for Commercial & Industrial Customers January 2018 Fuels Natural Gas A shot of artic air drove prompt-month NYMEX natural gas from a low of $2.60/ MMBtu on December 21st to $3.628/MMBtu on January 23rd. Midwest and Northeast regional spot gas prices spiked to over $100/MMBtu. These levels haven t been seen since the Polar Vortex of January/February As of January 12, storage inventories are 2,584 Bcf, a -12.5% deficit to year-ago and five-year average levels. EIA estimates dry gas production will average a record high 78.1 Bcf/day for December and average 73.6 Bcf/day for Inside This Issue Natural Gas... 2 Bulls and Bears... 3 Production Updates... 3 Record Gas Demand Set in Jan Summary & Regional Trends Coal Central Appalachian coal is $58.50/short ton (Quandl), a 2.3% decline from year-ago levels. Production averaged 13 million tons/week since Q4, the lower end of its five-year range. Generation increased to 16 million tons in early January, levels usually seen in summer. Oil Prompt-month WTI crude oil showed strength this month moving from $57.46 per barrel on December 19 to $63.44/barrel in intraday trading. Crude oil prices increased nearly 50% since June 2017 on an improving economic outlook, falling inventories of crude oil and refined products, and OPEC discipline to-date, in capping production. The IEA predicted that U.S. crude oil production would increase to 10.4 million barrels/day in 2018, an all-time high since OPEC boosted non-opec production-growth forecast by 16% (Bloomberg), heightening concerns regarding U.S. shale s share in the global market. Power Economy Weather Day-Ahead and Real Time LMP prices in the Northeast averaged over $200/MWh in early January as spot gas prices surged. ERCOT set a new winter load record on January 17 of 65,731 MW. PJM set fourthhighest winter load record of 138,465MW on January Forward power increased for several markets, most notably ISONE (4%), NY (1%), PJM (1%) and ERCOT (3%). Apple announced it will repatriate foreign cash, representing an estimated $38 billion to U.S. Treasury (Bloomberg). ~81 major companies announced bonuses and other employee benefits since tax reform (Washington Free Beacon). Equities markets moved upward, showing an impressive 1,200 point increase since December 19. The National Association of Manufacturers Outlook Survey reported an all-time high confidence rating of 94.6%. January will be colder than the past two years at 970 HDD and the 30-year HDD (952) and 10-year HDD (945). Cold weather in the Northeast and Midwest pulled gas from storage in the South-Central region. Arctic air is set to return to the Midwest and make its way east in early February. Long-range models support its prolonged presence for the month of February. Prompt Month Settlements Nat Gas $/mmbtu Crude Oil $/bbl As of 1/26/2018. Feb 18/ Mar 18 $ Day Change +$0.86/ MMBTU $ $6.17/BBL February Temperature Outlook Source: NOAA
2 MARKET INTEL NEWSLETTER 2 Natural Gas NYMEX prompt month gas futures (February 2018) traded to a low of $2.60/MMBtu in late December before rallying to a 12-month high of $3.63/MMBtu following the coldest start to January on record. NYMEX calendar strip prices were relatively unchanged during the cold snap as the market focuses on forecasts for record natural gas production levels later this year. Total U.S. natural gas demand (including exports) set an all-time record of Bcf/d on January 1st, shattering the previous record of Bcf/d set during the Polar Vortex on January 7, The EIA reported a -359 Bcf withdrawal from storage during the week ended Jan 5th. This is the largest weekly storage pull ever reported, and resulted in 1/8th of total inventories being wiped off the books in a single week. Natural gas production declined by 5 Bcf/d at the height of the cold snap due to wellhead freeze-offs. Although production has begun to bounce back, it remains 2% lower than December s record high of 77 Bcf/d. The Sabine Pass liquefaction facility is operating at full capacity this winter with LNG exports averaging 3 Bcf/d so far this year. The first LNG exports from Cove Point will likely be delayed until spring due to the spike in feedstock gas prices in the Mid-Atlantic region. Natural gas spot prices at many locations across the country rose to the highest levels since the Polar Vortex in early January. In the pipelineconstrained Northeast market, spot prices in City set a North American record of $175/MMBtu on Jan 5th. NYMEX Futures Pricing Current Price Last Month M/M Change Last Year Y/Y Change Prompt (Feb18) $3.447 $2.667 $0.780 $3.243 $0.204 Winter (Feb18-Mar18) $3.273 $2.649 $0.624 $3.519 ($0.246) 12 Month Strip $3.020 $2.660 $0.361 $3.373 ($0.086) As of 1/26/ $2.824 $2.757 $0.067 $2.910 ($0.086) 2020 $2.807 $2.804 $0.003 $2.891 ($0.840) 2021 $2.863 $2.857 $0.006 $2.907 ($0.044) 2022 $2.910 $2.907 $0.003 $2.919 ($0.009) Month Temperature Outlook Source: NOAA January 2018 will end up colder than the 30-year and 10-year normal temperature averages, however it will end up warmer than January Estimated gas weighted heating degree days (measure of temperature demand) may end up around 992 for the month, compared to the 30-year normal of 952 and last January s 824. In terms of individual days, 4 days during the early January Arctic outbreak ranked in the top 10 coldest of the 2000s. New Year s Day ranked colder than any other day during the Polar Vortex outbreak of January There is some evidence that blocking may return over Alaska by very late January and early February. This may set the stage for more below/much below normal temperatures for the Midwest and parts of the East. The long-term American model shows colder risks for February across the Upper Midwest, while the South may struggle to get cold. Natural Gas Storage Source: NOAA EIA reported a record-breaking withdrawal of 359 Bcf for the week ending January 5th, breaking the previous record of 288 Bcf set four years ago during the period of sustained cold known as the Polar Vortex. The 359 Bcf withdraw compared to a 151 Bcf withdraw for the same week in A much smaller withdraw followed for the report week ending January 12th, with a draw of only 183 Bcf coming in lower than market consensus and well below last year s draw of 230 Bcf for the same week. Storage now stands at 2,584 Bcf or 368 Bcf (12.5%) below year-ago levels and 362 Bcf (12.3%) below the five-year average. In the EIA s most recent Short-Term Energy Outlook, end-of-march storage inventory forecast fell to 1,622 Bcf; weekly withdraws at or below the fiveyear average for the remainder of the season would mean levels nearing the 1,310 range, a significant deficit to the five-year average. While temperatures in the day forecast are expected to ease, models show risks for the return of cold in early February. If strong withdraws continue, we could end the season well below the five-year average and see subsequent price support.
3 MARKET INTEL NEWSLETTER 3 Bulls vs. Bears Bulls Another cold shot similar to the late December/early January period that encompassed much of the country occurs again and spikes regional delivered gas prices and index power prices. For ISO regions susceptible to cold shots, lack of refueling for alternative fuels (oil and LNG) to natural gas puts upward pressure on index power prices during any potential cold snaps. Well freeze-offs continue to impact natural gas production curtailing record December output ~76 Bcf/d by 1 Bcf/d or more if cold shots persist. Large storage withdrawals hold strong through February further widening the underground storage deficit to last year and the fiveyear average, currently 13% and 12% respectively as of January 18. More coal burn during colder natural gas-constrained periods leads to drawdown in coal stockpiles potentially tightening overall coal supplies and prices. Bears The extreme cold that hit much of the country in early January has eased and a continuation of average to above-average temps into February will temper heating demand and delivered gas prices. Production freeze-offs taper as most of the northeast and Midwest/ Upper Plains thaws allowing Lower 48 dry gas production to return to December levels near 76 Bcf/d. Smaller-than-average withdrawals diminish the current deficit to last year and the five-year average to under 10% as we progress through winter means end-of-winter stocks showing neutral to bearish market signals. Declining levels of crude inventories as well as OPEC s ability to comply with intended supply cuts continue to buoy crude oil prices in the $60s which will keep drilling investments in place and bring more associated gas supply to the market. Production Updates Production surged in Q to average a record high 78.1 billion cubic feet per day (Bcf/d) during December In its January STEO, EIA estimated that dry gas production averaged 78.1 Bcf/d for December and that 2017 production will average 73.6 Bcf/d, up 1% (0.7 Bcf/d) from 2016 average production of 72.9 Bcf/d. For 2018 and 2019, EIA estimates production will average 80.4 Bcf/d (+9%) and Bcf/d (+3%), respectively. EIA s weekly production figure for January 17th, shows dry gas production averaging 75.7 Bcf/day. January saw shut-ins in the Northeast, Bakken (ND) and Texas due to well freeze-offs. Shut-ins have totaled 48 Bcf in Lower 48 and 8.5 Bcf in Canada. More freeze-off can be expected February with the turn in forecasts. Source: EIA Record Gas Demand Set in Jan got off to a strong start, with national demand reaching Bcf/d on New Year s day, surpassing the previous record of Bcf on Jan 7th R&C consumption was similar to 2014 levels but pipeline exports to Mexico (4 Bcf/d) and LNG exports from Sabine Pass (3 Bcf/d) boosted overall demand. Since 2014, approximately 65 GW of coal generation have retired, a lot of which has been replaced by gas-fired generation and renewables. Source: EIA
4 MARKET INTEL NEWSLETTER 4 Great Lakes Electric Summary: Customer Takeaways The recent cold snap has had a relatively muted impact on Midwest forward power prices. Prices in Illinois and Michigan are within 2% of all-time lows, while Ohio prices remain slightly elevated due to an increase in regional gas prices. A spike in spot gas prices and strong electricity demand has driven PJM day-ahead index prices to the highest levels since the Polar Vortex. Since the start of the year, day-ahead LMPs have averaged ~$45/MWh in Illinois and Michigan, while hourly prices in Ohio have averaged closer to ~$85/MWh. PJM load set its fourth-highest winter peak on record (138.5 GW) on Jan 5th. MISO loads peaked at GW on Jan 2nd, only 2 GW below the grid s current all-time January peak load. Per PJM, around 14% of the grid s generation capacity was forced offline at the height of the cold snap due to weather-related issues; however, the grid functioned reliably. Great Lakes Retail Power Price Trends % Change in Forward Power ComEd ComEd Mich Hub Mich Hub AEP-Day 2018-AEP-Day Ameren Ameren DAY Year-over-Year -4% -3% -6% -7% -1% 1% -5% -6% Month-over-Month 1% 0% 1% 0% 2% 2% 1% -1% Year-to-Date -4% -5% -6% -9% 0% -2% -5% -8% Compared to All-Time Low 2% 2% 2% 0% 5% 7% 2% 0% ComEd Mich Hub AEP-Dayton Hub Ameren
5 MARKET INTEL NEWSLETTER 5 Mid-Atlantic Electric Summary: Customer Takeaways Forward prices in PJM through 2022 are trading at price levels that are 8% higher, across the board, from the historic lows for each of those calendar year contracts. Moderate demand through the summer coupled with the recovery of gas production helped push prices to these levels at the time, but tighter gas storage levels heading into this current winter along with the recent cold temperatures has helped support prices to where they are presently. PJM forward energy prices are trading roughly 3% higher month-over-month throughout the curve through 2022 as a result of the extremely cold temperatures experienced from the end of December to the early part of January. Some of the temperatures and demand levels experienced during that term were some of the highest recorded in decades. Compared to the Day-Ahead index prices in eastern PJM last year for the month of December (2016), this past December s (2017) index prices were +22% higher on a monthly average, directly attributable to the extremely cold temperatures that existed at the end of December Mid-Atlantic Retail Power Price Trends 24-Month Fwd Trading Range PSEG PSEG PECO PECO APS APS BGE BGE PPL PPL vs High ($/MWh) -$4.61 -$6.79 -$5.06 -$6.21 -$2.49 -$2.72 -$5.96 -$4.63 -$4.55 -$4.60 vs Low ($/MWh) $2.25 $2.19 $2.13 $2.09 $2.39 $2.44 $2.83 $2.92 $2.53 $2.15 vs High (%) -13% -18% -14% -17% -7% -8% -14% -11% -12% -13% vs Low (%) 8% 7% 8% 8% 8% 8% 8% 9% 8% 8% Index Pricing AECO APS BGE DPL DUQ JCPL PEPCO PPL PSEG MetEd PECO Penelec December '16 $31.45 $32.16 $35.99 $32.38 $30.93 $31.06 $34.58 $30.93 $31.97 $31.55 $30.50 $31.07 December '17 $39.47 $35.88 $41.59 $43.73 $33.15 $39.34 $40.64 $39.34 $41.69 $39.84 $39.60 $34.55 % Change 25% 12% 16% 35% 7% 27% 18% 27% 30% 26% 30% 11% PSEG PECO APS BGE
6 MARKET INTEL NEWSLETTER 6 Northeast Electric Summary: Customer Takeaways Peak load in the NYISO hit 25,081 MW at the height of the cold weather on Jan 5, which is just slightly below the NYISO record winter peak of 25,738 MW that occurred on January 7, 2014 during Polar Vortex winter. During the peak of the early January cold shot, dual-fuel supplies provided approximately 29% of s electricity, followed by nuclear at about 28%, hydro at almost 19% and natural gas at about 13%, with wind and other resources making up the remainder. ISONE real-time demand reached a high of 20,639 MW on January 2, still short of the 10th-highest winter demand level of 21,563 on December 13, 2005 and well short of ISO NE s highest winter peak was 22,818 MW on January 15, A typical fuel mix during the late December/early January cold blast period featured approximately 34% oil, 21% nuclear and 20% gas, which reflects higher demand and prices for gas as heating fuel distributors absorb more pipeline capacity due to the extreme cold. By contrast, coal and oil supplied only 3% of the grid operator s energy in NY Zone A December day-ahead index averaged $37/Mwh, up $9 from its November average, while Zones G and J saw $20 increases to their December average, coming in around $53/Mwh. The November to December index price increase was even more pronounced in which showed almost a $37/Mwh increase as December prices averaged $75/Mwh. Halfway through January NY Zones A, G, J, and the have seen day-ahead index prices skyrocket from the extreme cold shot during the first week of the month, averaging $91, $127, $150, and $142/Mwh, respectively. Northeast Retail Power Price Trends 3-Year Price Trend Current Price vs 3-Year Average Current Price vs 3-Yeat Maximum Current Price vs 3-Year Minimum Zone J 2018 Zone J 2019 Zone J 2020 Zone J 2021 Zone J % -2% -1% -3% -4% -10% -11% -10% -10% -15% -31% -25% -29% -33% -37% -29% -31% -35% -39% -46% 5% 7% 10% 11% 11% 4% 1% 1% 3% 3% Zone A Zone J NE & NY v.s. NYMEX
7 MARKET INTEL NEWSLETTER 7 Texas Electric Summary: Customer Takeaways ERCOT set a new all-time record load for winter months at 65,731 MW for HE 8 on Jan 17th as temperatures dropped into the teens. ERCOT saw some of the highest volatility in index pricing for winter months since February The generation reserve margin in ERCOT was reduced to 9.3% for 2018 and 11.75% for 2019 and 2020, well below NERC s 13.75% recommended level. The December CDR reserve has pushed forward prices up, primarily for 2018 & 19 with 2018 up ~15% from all-time lows and 2019 up 8-10% from all-time lows. Texas Retail Power Price Trends % Change in Forward Power Houston 2018-Houston North Zone North Zone South Zone South Zone West Zone West Zone Year-over-Year 5% -2% 6% -3% 7% 0% 6% -5% Month-over-Month 2% 1% 2% 1% 3% 1% 3% 2% Year-to-Date 5% -3% 4% -4% 6% -2% 3% -7% Compared to All-Time Low 10% 4% 13% 7% 11% 4% 15% 9% ERCOT North Zone ERCOT Houston Zone ERCOT South Zone ERCOT West Zone
8 MARKET INTEL NEWSLETTER 8 California Electric Summary: Customer Takeaways Pac NW hydro flows are forecasted to be up by 3.9 GW/day in February and higher by about 3 GW/day in March. FERC approved on Jan 17th changes to CA-ISO Resource Adequacy (RA) rule. This change will impact how local power plants obtain replacement power during an outage. Plant owners can now procure system vs. local capacity. California Retail Power Price Trends % Change in Forward Power NP Cal 2018 NP Cal 2019 NP Cal 2020 NP Cal 2021 SP Cal 2018 SP Cal 2019 SP Cal 2020 SP Cal 2021 Mid Cal 2019 Mid Cal 2020 Mid Cal 2021 Year-over-Year 0% 4% 6% 8% 5% 5% 7% 9% -14% -11% -8% Month-over-Month -2% -3% -2% -1% -2% -3% -2% 0% -4% -3% -2% Year-to-Date 0% 2% 4% 7% 4% 4% 6% 7% -16% -13% -9% Compared to All-Time Low 9% 10% 12% 12% 13% 13% 15% 15% 1% 0% 3% NP 15 7X24 SP 15 7X24 Mid C 7x24 The information contained herein has been obtained from sources which Constellation NewEnergy, Inc Constellation NewEnergy-Gas Division, LLC (collectively, Constellation ) believes 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. Electricity Natural Gas CPower LR/DR Renewable Energy Energy Efficiency Onsite Generation constellation.com
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