Energy Market Update

By The Numbers:

• NG '22 prompt-month NYMEX closed at $6.50/MMBtu on Monday, June 27th.
• WTI '22 prompt-month crude oil closed at $109.57/bbl on Monday, June 27th.

• The Energy Information Administration (EIA) reported an injection of 74 Bcf into underground storage for the week ending June 17th. Inventories are 2,169 Bcf, which is -305 Bcf (-12%) less than the same period last year and -331 Bcf (-13%) lower than the 5-year average. 
• Storage is -14% below the 5-year average in the East, -12% in the Midwest and -13% in the South Central, the three largest storage regions.  
• For the week ending June 17th, Baker Hughes reported 157 gas-directed rigs, up +4 from the prior week. Oil-directed rigs were at 596 for the same period.

Weekly Power Report:

• Forward prices for 2023 were down -5% in ERCOT as strong cooling demand could return in early July. Out East, PJM was off -11% and -12% for West Hub for 2023 and 2024, respectively, ISONE was off -4% and -2%, and NYISO rounded out the East with -8% and -5% declines. CAISO was off -4% for 2023 and -1% for 2024.  

Great Lakes Electric Summary

• Great Lakes Region forward power prices have come down with natural gas prices over the past two weeks, as lower demand for the next few weeks along with increased levels of natural gas production has weighed downward on forward energy prices. NYMEX near-term natural gas prices have tumbled by -30% over the past two weeks while remaining +62% higher year-to-date. Forward power prices in the GLR region were -6% lower for the entire 2023-2027 term over the past week, but still +12% higher over the past month. The 2023 term was -11% lower on the week, while the 2027 term was only -4% lower. Compared to the all-time lows, the 2023-2027 calendar terms are anywhere from -19% lower on the front year to -5% lower on the back-end years. Day-ahead index settlement prices continue to be supported by higher gas prices and heat rates. Month-to-date day-ahead index power prices in COMED thus far in June are averaging $83.56/MWh, +25% higher than the previous month and +171% higher than the June average from a year ago, while the monthly average settlement price for ADHub is $89.17/MWh, +15% higher than the previous month and +176% higher than last June. In Michigan, day-ahead index power prices are averaging $91.90/MWh, +20% higher than the previous month and +163% above the June average from a year ago, while the average settlement price in Ameren is $89.21/MWh, +14% higher than the previous month and +168% higher than last June.
• On June 21st, PJM posted results for the 2023-2024 Planning Year capacity auction. Capacity prices decreased across the board with RTO printing at $34.13/MWd, down from $50/MWd in the 2022-23 auction. Similarly, the MAAC (i.e., eastern PJM) and BGE zones also cleared down. MAAC cleared at $49.49/MWd, down from $95.79/MWd, and BGE cleared at $69.95/MWd, down from $126.50/MWd. ComEd did not separate from the RTO price for 2023-24 as it had in prior auctions. An additional 5.3 GW of nuclear cleared in the auction substantially increasing ComEd supply. Only 3.3 GW of new generation cleared in the auction. Overall, wind, solar, demand response and energy efficiency cleared volumes were consistent with 2022-23 volumes. In contrast, 7 GW less coal capacity was offered and 5.8 GW less coal cleared due to coal unit retirements.  The total capacity procurement costs for the region were $2.2 billion, compared with $4 billion for the 2022-23 auction.

Northeast Energy Summary

• Despite the sell-off in Henry Hub natural gas futures over the past couple of weeks, New England forward natural gas and power has generally seen prices continue its 2022 upward trend. The reason for the divergence between regional energy in New England and national Henry Hub gas has been renewed buying in the overseas market for natural gas. After reaching an all-time closing high of $72/MMBtu on March 7th in the wake of the first weeks of the Russian invasion on the Ukraine, the Dutch TTF (the European natural gas benchmark) saw a slow and steady decline of its price through May. As the war waged on through March, Europe began to diversify its energy mix and the threat of a significant supply shutoff of Russian natural gas seemed to have eased which coincided with prices settling in the $25/MMBtu area in late May. In early June the news of the U.S. Freeport LNG terminal explosion coupled with material amounts of gas flows cut off to Europe by Russia sparked a price run-up in the TTF. Prompt month prices settled to a high of $39/MMBtu last week and New England forward calendar 2023 prices reached an all-time high of ~107/MWh. A positive correlation between Northeast markets and overseas energy exists because during the natural gas demand heavy winter months, LNG cargoes into Boston often time supplement sometimes limited dry pipeline natural gas (on the coldest days). To incentivize those cargoes to the region the prices must match or surpass global destination prices. The Northeast energy markets continue to trade with tremendous volatility because not only the turmoil overseas but also very large swings in Henry Hub natural gas pricing in the US, the other major component of pricing in the region. Price moves in both Henry Hub and European markets will likely vary greatly as new developments in both markets are revealed.
• New York’s forward power prices retreated further over the last week alongside natural gas, with all zones and terms seeing a pullback relative to the week prior. Variable temperatures throughout the region have kept cooling demand in check recently, but expectations for a warm up beyond the 15-day outlook should support demand and prices moving into July. Index settlement prices for June so far have come in lower this month versus last, but considerably higher than prices a year ago. Day-ahead index power prices in Zone J are averaging $76.26/MWh, -3% lower than last month and +121% higher than the June average from a year ago, while the monthly price for the Zone F is settling at $76.45/MWh, -22% lower than the previous month but +111% higher than in June last year. Forward power prices across zones have retreated by an average of -8% over the past week for the Bal 2022-2027 term with the front end moving more significantly than the back end (Bal’ 2022-2023 terms are down as much as -14% week-over-week in several zones upstate). The 2023 winter strip in Zone G is 180% above year-ago levels, currently trading at $167/MWh, significantly off from May, when it peaked at $212/MWh.

ERCOT Energy Summary

• After nearly a week of deep summer temperatures in and around the century mark, California starts to cool off tomorrow as the CAISO net load falls from ~24 GWa to 18 GWa for the rest of the week. Reduced cooling load will bring SoCalGas’s sendouts back to the 2.1 Bcf level, down from 2.5 Bcf in recent days, and put pressure back on grid operators to balance the system at the border points, especially given reduced demand over the long holiday weekend. With SoCalGas’ storage caverns still tipping the scales at 87 Bcf, system flexibility is minimal as there is nowhere to stick the excess gas … at least until heat reappears. The current 11-15-day outlook suggests that there isn’t any major heat storms on the horizon for the state which will help PG&E continue to recover from its five-year low storage deficit at the end of winter. A few notable updates to pipeline maintenance that could influence prices: On PG&E’s grid, they confirm significant outages along the Redwood line into September. Currently, the Redwood path is cut from 2.1 to 1.6 Bcf, which will last through the end of the week. Then, in July, the throughput will climb back to 2 Bcf through first week of August, after which there will be alternating outages in the range of 0.2-0.6 Bcf through the first week of October. The cuts in flow will hamper the refill efforts across the PG&E cavern network. Down south, SoCalGas is nearing the end of its pipeline maintenance after numerous cuts to receipt capacity into Wheeler Ridge and North Zone. When the line maintenance wraps, attention will flip to the storage caverns. Over the next few months, each facility will see a period of restricted ops which will constrain balancing ops from September through early November. The most impactful will be when Aliso Canyon goes down from late September through the second week of October.
• No mention of the El Paso line and the seeming endless maintenance? Does this mean that it’s fixed? No. The segment of the El Paso Pipeline that brings Permian gas into the West Market, which had an “unplanned outage” last August when a portion exploded, continues to see that segment of the pipe inaccessible to daily scheduling activity. The uncertain end to this outage is what encouraged SoCalGas to ask the CPUC for additional storage injection capability last October, invoking the name Winter Storm Uri, knowing that this would capture regulators attention after many watched their ERCOT-based colleagues granted more time to spend with family in the aftermath. SoCalGas quickly filled the additional 7.2 Bcf of storage capacity they were allowed at the Aliso Canyon facility last November. On the back of some minor improvements to import capability elsewhere on their system and a heating season that whiffed, they now find themselves with storage caverns that are packed, awaiting prolonged summer heat. It remains to be seen how gas will be drawn from the system this summer as the CAISO continues to see battery capacity sync to the grid. In recent weeks, anywhere between 1.8 and 2.5 GW of discharge is showing up each day, displacing a decent chunk of in-state thermal generation that was needed in past years to balance the grid in the early evenings.
• For those with sites in PG&E territory, the utility issued an update last week that it had expanded its instant power line shutoffs to cover more high-risk areas. The new safety settings reportedly kill the power to a circuit “within one-tenth of a second” of a fault, such as a tree branch falling onto a line. Since faults linked to PG&E equipment have sparked massive wildfires in recent years, including last year’s Dixie Fire and the 2018 Camp Fire, which led to felony manslaughter charges, millions of dollars in fines and a Chapter 11 bankruptcy filing. After this year’s expansion, PG&E said, the program covers 1,000 circuits, 25,000 miles of distribution lines in high-risk areas, and about 3 million people. So far this year, there have been 205 outages on circuits covered by the program with an average restoration time of 3.5 hours, the company said. The utility also launched a new tool for customers to check whether their addresses may be affected by pending shutoffs.

Stay up-to-date on the latest energy news and information:

• Fortunato & Friends Webcast - Please join us on Thursday, July 7th at 2 p.m. ET for Fortunato & Friends, a webcast series featuring our Chief Economist Ed Fortunato and a special guest each month. This month's webcast features return guest Laura l. Gamble, Regional President of PNC Bank, Greater Maryland, and a discussion on "The State of the Economy and where we 'R' going?"
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