In the News (EIA):
Illinois power generation fuel mix changes with coal retirements and natural gas and renewable additions:
Vistra Energy’s latest August 21 announcement to shut down four coal plants continues a decade-long trend of reduced coal use in Illinois’s power generation mix. Vistra Energy decided to retire four coal-fired power plants in Illinois to conform to the requirements of the Multi-Pollutant Standard (MPS) rule imposed by the Illinois Pollution Control Board (IPCB). The new amendments to the IPCB’s MPS rule, which was passed on June 20, require a reduction of at least 2,000 megawatts (MW) of electric generation by coal-fired plants under the jurisdiction of IPCB’s MPS region no later than December 31, 2019. To comply with the MPS standards, Vistra Energy has filed shutdown notices with the Midcontinent Independent System Operator, the PJM Interconnection, and the Federal Energy Regulatory Commission. The four Illinois plants scheduled for shut down are. 151 MW Coffeen 2 plant, in Coffeen, to be retired by November 19, 2019. 329 MW Duck Creek 1 plant, in Canton, to be retired by December 22, 2019. 60 MW Hennepin 1, in Hennepin, to be retired by November 19, 2019. 200 MW Hennepin 2, in Hennepin, to be retired by November 19, 2019. These announced retirements, which continue the trend of declining coal capacity in the Illinois electric generation fleet, will increase the share of natural gas and renewables capacity. EIA power generation data indicate that coal generation in the state fell by 36% between 2010 and 2018. During the same period, generation by natural gas-fired plants more than tripled, from 5.7 gigawatt hours (GWh) in 2010 to 17 GWh in 2018, while generation by renewable sources more than doubled to 12.6 GWh in 2018. Between 2010 and 2018, a total of 3.7 gigawatts (GW) of nameplate coal capacity was retired. During the same period, a total of 12 GW of natural gas and 5 GW of renewable electric generation capacity was added in Illinois. New renewable and natural gas power plants are being built in Illinois. Between 2019 and 2022, 18 new renewable plants, with a total nameplate capacity of 1.6 GW, and two new natural gas plants, with a total nameplate capacity of 1.3 GW, are slated to come online.
Natural gas spot prices rose at most locations this report week (Wednesday, August 28, to Wednesday, September 4). Henry Hub spot prices rose by 8% from $2.24 per million British thermal units (MMBtu) last Wednesday to $2.42/MMBtu yesterday. At the New York Mercantile Exchange (Nymex), the September 2019 Henry Hub natural gas contract expired last Wednesday at $2.251/MMBtu. The October 2019 contract increased to $2.445/MMBtu, up 22¢/MMBtu from last Wednesday to yesterday. The price of the 12-month strip averaging October 2019 through September 2020 futures settlement prices climbed 10¢/MMBtu to $2.474/MMBtu. Net injections to working gas totaled 84 billion cubic feet (Bcf) for the week ending August 30. Working natural gas stocks are 2,941 Bcf, which is 15% more than the year-ago level and 3% lower than the five-year (2014–18) average for this week. The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 19¢/MMBtu, averaging $4.56/MMBtu for the week ending September 4. The price of natural gasoline rose by 1%, ethane by 12%, propane by 1%, butane by 5%, and isobutane by 6%. According to Baker Hughes, for the week ending Tuesday, August 27, the natural gas rig count remained flat at 162. The number of oil-directed rigs fell by 12 to 742. The total rig count decreased by 12, and it now stands at 904.
Prices rise at most locations. This report week (Wednesday, August 28, to Wednesday, September 4), Henry Hub spot prices rose 18¢ from $2.24/MMBtu last Wednesday to $2.42/MMBtu yesterday as the Gulf Coast experienced increasingly hot weather. At the Chicago Citygate, prices increased 15¢ from $2.03/MMBtu last Wednesday to $2.18/MMBtu yesterday. Southern California prices rise with warmer-than-normal temperatures. Prices at SoCal Citygate increased $1.11 from $3.40/MMBtu last Wednesday to $4.51/MMBtu yesterday. EIA’s Southern California dashboard shows temperatures in Los Angeles well above seasonal norms for the past few days, reaching nearly 100 degrees Fahrenheit (°F) on Monday and over 90°F on Tuesday. Forecast temperatures remain above the normal range for the rest of the week as well. Prices at PG&E Citygate in Northern California rose 2¢/MMBtu, reaching $3.02/MMBtu yesterday. Northeast prices mixed. At the Algonquin Citygate, which serves Boston-area consumers, prices went down 3¢ from $2.05/MMBtu last Wednesday to $2.02/MMBtu yesterday despite increased power sector demand in the region. At the Transcontinental Pipeline Zone 6 trading point for New York City, prices increased 11¢ from $1.79/MMBtu last Wednesday to $1.90/MMBtu yesterday. Tennessee Zone 4 Marcellus spot prices increased 10¢ from $1.66/MMBtu last Wednesday to $1.76/MMBtu yesterday. Prices at Dominion South in southwest Pennsylvania rose 10¢ from $1.74/MMBtu last Wednesday to $1.84/MMBtu yesterday. Despite these increased prices, regional prices remain relatively low, likely related to persistent production growth in the Appalachia Basin. Permian Basin prices remain in positive territory. Prices at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $1.22/MMBtu last Wednesday, $1.02/MMBtu lower than Henry Hub prices. Yesterday, prices at the Waha Hub averaged $0.83/MMBtu, $1.59/MMBtu lower than Henry Hub prices. Last Thursday, prices at the Waha Hub reached a weekly high of $1.35/MMBtu, $0.95/MMBtu lower than Henry Hub prices. Permian prices have generally increased recently as the Gulf Coast Express Pipeline prepares to enter service ahead of its announced in-service date of October 1. Hurricane Dorian impacts southeastern United States. Hurricane Dorian devastated the Bahamas last week, and its current path follows the East Coast and is projected to bring heavy rain and flash flooding to the Carolinas. EIA’s energy disruptions map tracks energy infrastructure in the hurricane’s path, and EIA’s Hourly Electric Grid Monitor reports power outages in near real-time. EIA expects that the most significant energy impacts from Hurricane Dorian will be demand-related, as cool weather and power outages in the Southeast decrease power burn. U.S. supply rises with increased imports from Canada. According to data from IHS Markit, the average total supply of natural gas rose by 1% compared with the previous report week. Dry natural gas production remained constant week over week. Average net imports from Canada increased by 8% from last week. Demand down slightly. Total U.S. consumption of natural gas fell by 1% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation declined by 3% week over week. Industrial sector consumption decreased by 1% week over week. In the residential and commercial sectors, consumption increased by 4%. Natural gas exports to Mexico increased by 2%. Exports to Mexico set to increase as new pipeline enters service. EIA expects flows to Mexico to increase in coming months after Mexico’s utility Comisión Federal de Electricidad announced last week that it had renegotiated contracts with three pipeline companies. According to Platts S&P Global, the first pipeline to begin operations, the 2.6 Bcf/d Sur de Texas pipeline, posted flows of 50 MMcf/d on Tuesday, September 3. Platts reports that volumes on the line may increase sharply in the next few days. U.S. LNG exports increase week over week. Twelve LNG vessels (seven from Sabine Pass, three from Corpus Christi, and one each from Cove Point and Freeport LNG export terminals) with a combined LNG-carrying capacity of 43 Bcf departed the United States between August 29 and September 4, according to shipping data compiled by Bloomberg. One vessel was loading at Sabine Pass terminal on Wednesday. Freeport LNG has shipped its first LNG commissioning cargo from Train 1 on September 3, according to the company’s press release. Freeport LNG is a three-train facility with a combined LNG baseload production capacity of 1.98 Bcf/d (2.1 Bcf/d peak capacity) located on Quintana Island in Freeport, Texas. The second and third trains at the facility are currently under construction and are expected to be placed in service in January 2020 and May 2020, respectively. Freeport LNG is the fifth U.S. LNG export terminal in Lower 48 states to come online since 2016.
Net injections into storage totaled 84 Bcf for the week ending August 30, compared with the five-year (2014–18) average net injections of 66 Bcf and last year’s net injections of 64 Bcf during the same week. Working gas stocks totaled 2,941 Bcf, which is 82 Bcf lower than the five-year average and 383 Bcf more than last year at this time. According to The Desk survey of natural gas analysts, estimates of the weekly net change from working natural gas stocks ranged from net injections of 67 Bcf to 90 Bcf, with a median estimate of 78 Bcf. The average rate of net injections into storage is 30% higher than the five-year average so far in the refill season (April through October). If the rate of injections into storage matched the five-year average of 10.8 Bcf/d for the remainder of the refill season, total inventories would be 3,610 Bcf on October 31, which is 82 Bcf lower than the five-year average of 3,692 Bcf for that time of year.