Winter 2013-14 by the Numbers
RTO Insider | April 10, 2014
Winter Peak Demands Set During Polar Vortex PJM wasn’t the only place the winter of 2013-14 made its mark in the record books.
MISO, the Southwest Power Pool and NYISO also hit all-time winter peaks during January’s polar vortex, while ISO New England came up just short.
January 2014 holds eight of PJM’s top 10 winter demand days, including the top spot, 141,846 MW, set Jan. 7. Many areas in MISO, meanwhile experienced their coldest winter in two decades.
PJM and other regions called on demand response, emergency energy purchases, and public appeals for conservation. On Jan. 7, PJM dispatched about 2,000 MW of DR during the morning and evening peaks while NYISO called on 900 MW. PJM also called on more than 2,500 MW of DR Jan. 23 and 28. ISO-NE’s winter procurement program provided 21 MW of demand response on five occasions.
None of the RTOs or ISOs cut firm load.
Natural Gas Prices
Gas Prices in Eastern U.S.While power demand wasn’t as high later in January, natural gas prices hit record highs in some eastern markets that supply PJM, New York and New England. On Jan. 22, prices at Transco Zone 6 (non-NY) peaked at $123/MMBtu, while prices at Transco Z6 NY and Transco Z5 reached $120/MMBtu.
Most other U.S. gas price hubs traded below $6/MMBtu during the coldest days, although Henry Hub hit $7.92/MMBtu in February, the highest since Hurricane Ike in September 2008.
RTOs struggled not only because of record demand but also because of mechanical failures and fuel supply problems. More than one-quarter of the installed capacity in PJM and MISO was idled on Jan. 6 and 7.
Fuel supply problems were responsible for more than half the outages and derates in NYISO, three-quarters of those in SPP and all of those in ISO-NE, according to FERC.
In contrast, lack of fuel was responsible for only one-quarter of the lost generation in PJM. About 5,000 MW of combustion turbines failed to start when called in early January.
Late in January, gas curtailments and start failures for combustion turbines both declined in PJM. Frozen coal and a lack of gas and oil caused outages of as much as 8,000 MW, however.
In much of the country, insufficient fuel oil and coal supplies kept plants from operating.
Barge deliveries were hampered by weather and an inability to transport through shallow water. Ice and sustained cold closed barge operations for a time on the Allegheny River.
Trucks and drivers were also in short supply. At ISO-NE’s request, the governor of Massachusetts approved extended hours for truck drivers transporting fuel.
MISO was challenged by an explosion on the TransCanada pipeline Jan. 25 and limited rail capacity, which pinched coal supplies.
“Some [coal] companies said they were only getting half of what they ordered,” Eric Callisto, chairman of the Wisconsin Public Service Commission, told the FERC technical conference. Some plants “were down to a 10- or five-day supply this winter.”
Rail deliveries “were an ongoing concern years ago,” he added. “It still is.”
Commissioner Tony Clark suggested that one reason that railroads are struggling to complete coal deliveries “is directly related to the lack of pipeline capacity for oil products. Railroads are using all their power to getting oil out” of the region from increased oil production. “It is all interconnected,” Clark said.
Drivers of High Prices Changed
In early January, high prices were driven primarily by record loads, which forced PJM and other operators to dispatch their most expensive generators. LMPs crested at $2,000/MWh for some hours in PJM and MISO while average real-time prices during ranged between $300-$700/MWh during peak hours.
ISO New England had energy market costs of $5.05 billion this winter, almost equal to the $5.2 billion spent in all of 2012. Almost two-thirds of average daily real-time prices were above $100/MWh, versus less than 30% in the winter of 2012-13.
Like PJM, NYISO also won FERC approval for a waiver to lift its $1,000/MWh energy offer cap. Although natural gas prices in NYISO quadrupled from December to January, power prices increased only 176% as oil displaced gas.
Rarely used oil-fired generators were called into service and some dual-fuel units switched to oil due to high gas costs or uncertain supplies.
On many days, oil-fired generation was more economical to dispatch than natural gas units, a rare occurrence since the arrival of cheap shale gas.
In New England, where natural gas prices nearly doubled from the previous winter, oil was ISO-NE’s fuel of choice for more than half of the winter, including 23 days in January. The ISO’s “winter reliability program” funded inventories of 2.7 million barrels of oil, and the ISO burned 1.9 million barrels of that. “We ran oil units hard,” said Peter Brandien, vice president of system operations.
In NYISO, oil-fired generation was cheaper than gas for eight days in December and 18 in January. Oil-fired generation was able to obtain sufficient fuel deliveries at rates close to their oil-burn rates for only short periods, however.
The phenomenon was seen across the country as well. NRG Energy reported burning 1.1 million barrels of oil in January versus 800,000 in all of 2013.
In addition to high LMPs, the severe weather was reflected in uplift as generators sought reimbursement for costs not captured in energy prices and ancillary product sales.
In PJM, uplift for January totaled about $540 million, more than two-thirds what the RTO spent in all of 2013. Most of the uplift came between Jan. 21 and 29.
ISO-NE had uplift of $73 million in January, more than half its 2013 total.
Half of Power Plant Capacity Additions in 2013 Came from Natural Gas
EIA | April 10, 2014
Natural gas-fired power plants accounted for just over 50% of new utility-scale generating capacity added in 2013. Solar provided nearly 22%, a jump up from less than 6% in 2012. Coal provided 11% and wind nearly 8%. Almost half of all capacity added in 2013 was located in California. In total, a little over 13,500 megawatts (MW) of new capacity was added in 2013, less than half the capacity added in 2012.
Natural gas. Natural gas capacity additions were less than in 2012, as 6,861 MW were added in 2013, compared to 9,210 MW in 2012. The capacity additions came nearly equally from combustion turbine peaker plants, which generally run only during the highest peak-demand hours of the year, and combined-cycle plants, which provide intermediate and baseload power.
Nearly 60% of the natural gas capacity added in 2013 was located in California. The state is facing resource adequacy concerns as well as the need for more flexible generation resources to help complement more variable-output renewable resources, particularly solar, being added to the system.
Solar. Solar photovoltaic (PV) added 2,193 MW of capacity in 2013, continuing the trend of the past few years of strong growth, helped in part by falling technology costs as well as aggressive state renewable portfolio standards (RPS) and continued federal investment tax credits. Nearly 75% of the capacity added was located in California, followed by roughly 10% in Arizona. (Note: these figures do not include distributed capacity under 1 MW. Distributed solar PV capacity additions also grew in 2013, with industry reports estimating nonutility additions of 1,900 MW. Most of this capacity was also located in California.)
After many years of little activity, the solar thermal industry completed several large-scale solar thermal plants in 2013 located in Arizona and California totaling 766 MW of capacity, more than doubling the total solar thermal capacity in the United States. A few more projects are expected to be completed in 2014-16; however, several other announced projectes have since been cancelled or suspended because of a number of challenges such as environmental impacts on desert wildlife and water resources, cost-competitiveness, and delays in transmission development.
Coal. Two coal plants, both delayed projects that were originally scheduled to be completed in 2011-12, accounted for all of the coal capacity added in 2013. The Sandy Creek Energy Station in Texas is a 937 MW conventional steam coal plant that was badly damaged during testing in 2011 and required major repairs before becoming operational. The Edwardsport plant in Indiana is a 571 MW integrated gasification combined-cycle (IGCC) plant, one of only two of the many proposed IGCC projects that actually advanced into construction as natural gas prices dropped (the Kemper County IGCC project in Mississippi is still under construction).
Wind. Wind capacity additions (1,032 MW) dropped sharply in 2013 to less than one-tenth of the capacity added in 2012 (12,885 MW). This was a widely expected result of the rush to complete wind projects in 2012 to qualify for the federal production tax credit. Unlike previous versions of the tax credit, the one-year extension for 2013 allowed developers to claim the tax credit for projects that began construction in 2013 even if the project will be completed in a later year. Consequently, developers were not as pressured to complete wind projects by the end of 2013. At this time, there have not been any subsequent extensions of the tax credit. More than 90% of the wind generation capacity additions in 2013 were located in five states: California, Kansas, Michigan, Texas, and New York.
Natural Gas and Oil Market Update
Natural Gas Prices Turn Higher After Supply Data
MarketWatch | April 10, 2014
Natural Gas futures on Thursday turned higher after the U.S. Energy Information Administration reported that supplies of natural gas rose 4 billion cubic feet for the week ended April 4. That was smaller than the market expected as analysts surveyed by Platts forecast an increase of between 13 billion cubic feet and 17 billion cubic feet. Total stocks now stand at 826 billion cubic feet, down 849 billion cubic feet from a year ago and 997 billion cubic feet below the five-year average, the government said. May natural gas was at $4.64 per million British thermal units, up nearly 6 cents, or 1.3%. It was trading at $4.53 before the data.
Brent Crude Premium to WTI Narrows to Least Since Sept.
Bloomberg | April 10, 2014
Brent crude fell, eroding its premium to West Texas Intermediate to the least since September, amid signs Libyan exports may recover as stronger gasoline demand buoys U.S. prices. The spread between the two benchmark grades narrowed to $4 a barrel, the smallest gap since Sept. 20.
Brent for May settlement decreased as much as 72 cents to $107.26 a barrel on the London-based ICE Futures Europe exchange and was at $107.44 by 13:16 p.m. The European benchmark crude’s premium to WTI slipped to as little as $4 a barrel on ICE.
WTI for May delivery fell 24 cents to $103.36 a barrel in electronic trading on the New York Mercantile Exchange. The contract rose $1.04 to $103.60 yesterday, the highest close since March 3. The volume of all futures traded was about 27 percent above the 100-day average for the time of day. Prices have advanced 5 percent this year.
EIA - Weekly Natural Gas Storage Report
Working gas in storage was 826 Bcf as of Friday, April 4, 2014, according to EIA estimates. This represents a net increase of 4 Bcf from the previous week. Stocks were 849 Bcf less than last year at this time and 997 Bcf below the 5-year average of 1,823 Bcf. In the East Region, stocks were 448 Bcf below the 5-year average following net withdrawals of 5 Bcf. Stocks in the Producing Region were 411 Bcf below the 5-year average of 772 Bcf after a net injection of 9 Bcf. Stocks in the West Region were 137 Bcf below the 5-year average after no net change. At 826 Bcf, total working gas is below the 5-year historical range.
NYMEX Natural Gas Week-to-Week Price Change
Natural Gas Futures - Five Year Price
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