Slide 1 – 2019-2020 Winter Energy Market Assessment

2019-2020 Winter Energy Market Assessment

October 2019 

Good morning Mr. Chairman and Commissioners, the Office of Enforcement and the 

Office of Energy Policy and Innovation present their 2019‐2020 Winter Energy Market 

Assessment. The Winter Energy Market Assessment is staff’s opportunity to look ahead 

to the coming winter and share its thoughts and expectations about market preparedness, 

including a high‐level assessment of risks and challenges anticipated in the coming 

operating season.
Slide 2 - Highlights

Weather remains one of the largest determinants of outcomes in the energy markets. As 

we will discuss on the next slide, the National Oceanic and Atmospheric Administration 

(NOAA) forecasts a high chance for a warmer than average winter. 

Going into this winter, natural gas storage levels are close to the five-year average and

natural gas futures prices are lower than last winter. Also, pipeline additions in the 

Permian and Marcellus Basins have bolstered the fuel supply chain, allowing additional 

natural gas supplies to reach markets. However, certain regions are more dependent on 

natural gas than others, and pipeline outages have the potential to increase both electric 

and natural gas price volatility. Coal and oil-fired generation continue to play an 

important role in maintaining electric reliability during the winter, especially in the 

Northeast, where winter demand for natural gas can exceed pipelines’ capacity. 

The North American Electric Reliability Corporation, or NERC, annually assesses the 

on-peak fuel mix and the availability of generators capable of serving peak winter loads. 

According to NERC’s draft assessment, winter reserve margins are expected to exceed 

the reserve margin targets in all assessment areas. NERC will release its 2019 Winter 

Reliability Assessment at a later date and therefore this assessment is still subject to 

change. 
Slide 3 – Forecasts Predict Warmer than Normal Winter

As mentioned, the current NOAA three‐month outlook for December 2019 through 

February 2020 predicts a higher than average probability for warmer temperatures across 

much of the continental United States. Warmer than average winter temperatures are 

expected in the Northeast, West, Texas, and Florida, with the Upper Midwest 

experiencing more normal conditions. 

A warmer than average winter would moderate fuel and electricity demand. However, as 

seen in previous winters, acute cold weather events can occur during warmer than 

average seasons. These events increase the short‐term demand for natural gas and 

electricity, which could create significant operational and market challenges.
Slide 4 – Natural Gas Storage Levels Expected to be Slightly Above Five-Year 

Average

Natural gas storage inventories for the 2019 injection season, running from April 1 to 

October 31, began at 1.2 trillion cubic feet (Tcf), 30 percent lower than the prior five-year 

average. However, by November, inventories are expected to be slightly above the fiveyear average, reflecting robust storage injections throughout the season.

This year, natural gas storage levels have increased at the highest rate since 2015. As of 

September 6, natural gas inventories were at 3.0 Tcf, which is 15 percent higher than last 

year’s levels at this time. According to an Energy Information Administration (EIA)

forecast, the rate of natural gas injections into storage will be above the five-year average 

of 10.8 billion cubic feet per day (Bcfd) for the remainder of the injection season. This 

injection rate would result in natural gas inventories exceeding 3.7 Tcf by the end of 

October, a 16 percent increase over October 2018 levels and slightly above the five-year 

average. The EIA projects that the total withdrawals over the coming winter will be 2.1

Tcf, which is slightly more than last winter’s total withdrawals of 2.0 Tcf. 
Slide 5 – Futures Market Signals Lower Natural Gas Prices This Winter

This graph shows the total natural gas futures prices for the past and upcoming winters 

for regions in the United States. Regional natural gas prices are calculated by adding the 

NYMEX Henry Hub winter futures price to the winter basis futures prices at major

trading hubs in the United States. As of October 4, 2019, the NYMEX Henry Hub 

futures price, which measures the general cost of the natural gas commodity, was 73

cents below last winter’s average futures settlement price, with an average price of 

$2.56/MMBtu for January and February 2020.

Basis futures prices, which approximate the cost to deliver natural gas to regional 

markets, were lower for the upcoming winter compared to last year’s futures settlement 

prices across all regions except New England. In Boston, basis futures prices averaged 

$6.54/MMBtu, a $1.16 rise from last winter. New York City experienced the largest 

declines from last winter. Basis futures prices in New York City averaged 

$2.92/MMBtu, down $1.56 from last year. Basis futures prices in the Southwest, 

Chicago, Southern California, and the Marcellus shale region all experienced moderate 

declines compared to last year.
Slide 6 – Natural Gas Production to Increase While Demand Changes Are Mixed

Dry natural gas production, or the process of producing consumer-grade natural gas, set 

new record highs in the first half of 2019, averaging 90 Bcfd through June, a 12 percent 

increase from the 2018 level over the same period. The Marcellus Basin, located in 

Pennsylvania, West Virginia, Ohio, and New York, led all production regions with an 

average of 22 Bcfd of production through June 2019. The Permian Basin, located in 

Texas and New Mexico, averaged 9 Bcfd in 2019 through June, which represents a 38 

percent increase year-over-year. The EIA Short Term Energy Outlook forecasts that

production growth will continue through the winter, averaging 93 Bcfd from November

2019 through March 2020.

While production continues to grow, the EIA forecasts U.S. demand will average 100

Bcfd from November to March, a 1 percent increase from the previous winter. EIA 

forecasts domestic demand in January 2020 will average 112 Bcfd. This is nearly 3 Bcfd 

higher than the record for average monthly demand, which was observed in January 

2019. 

Electric power generation is a driver of the forecasted increase in domestic demand this 

winter, with an expected year-to-year increase of 6 percent to 27 Bcfd, a projected alltime winter high. Industrial natural gas demand is also expected to increase, but only by

2 percent to 25 Bcfd. However, residential natural gas demand, which is typically the 

biggest driver of peak winter demand, is expected to decrease 3 percent to 25 Bcfd.
Slide 7 – New Pipeline Eases Permian Bottleneck

More than 12 Bcfd of new pipeline capacity, including 3.9 Bcfd of Commissionjurisdictional capacity, has been placed in-service across the U.S. since last winter. Some 

notable projects include Columbia Gas Transmission, LLC’s 2.6 Bcfd Mountaineer 

Xpress and Kinder Morgan’s 2.0 Bcfd Gulf Coast Express. Gulf Coast Express is a nonjurisdictional intrastate pipeline that transports Permian Basin natural gas from the Waha 

hub in west Texas to Agua Dulce in south Texas. Permian Basin natural gas production

has exceeded local demand and saturated nearby markets. The regional oversupply 

caused 41 instances of negative prices at the Waha hub between March and August of 

this year. In August, spot natural gas prices at the Waha hub averaged just 

$0.68/MMBtu. 

Since Gulf Coast Express began commercial operation on September 25, spot natural gas 

prices have converged with other regional hubs. The project has eased binding local 

constraints, and placed upward pressure on pricing in nearby markets. This phenomenon 

is expected to continue through the winter and beyond. Basis futures at the Waha hub for 

January 2020 were priced at $2.33/MMBtu on September 16.

Looking forward, two additional natural gas pipeline projects are currently under 

construction to transport Permian Basin natural gas to the Southeast and Gulf Coast 

markets. Specifically, the 2.0 Bcfd Permian Highway Pipeline project is planned to be 

in-service in late 2020 and the 2.0 Bcfd Whistler Pipeline in 2021.
Slide 8 – Capacity Additions Boost LNG Exports

Since the beginning of 2019, the consumption of feedgas, which is natural gas used as a 

raw material for LNG liquefaction, has grown over 1.5 Bcfd—from 4.5 Bcfd to more 

than 6 Bcfd. From March to October 2019, more than 3 Bcfd of new LNG export 

capacity went in-service, representing the largest concentration of capacity additions in 

the short history of U.S. LNG exports. During that time, operations started on the first 

trains of LNG export plants at Corpus Christi and Freeport in Texas, Cameron in 

Louisiana, and Elba Island in Georgia. Additionally, a second LNG train at Corpus 

Christi and a fifth LNG train at Sabine Pass, in Louisiana, went in-service during that 

period. Increased demand for feedgas from all operational facilities should continue 

through this winter as utilization rates are expected to remain high. Second LNG trains at 

both Cameron and Freeport are expected to start operations during the winter months. 

Recent reports estimate that the in-service date for Freeport’s second train will be in 

January 2020, while the in-service date for Cameron’s second train will be in February

2020.
Slide 9 – Southern California Gas Company Restrictions to Continue

For the past several winters, service over the Southern California Gas Company’s system 

has been limited due to outages and repairs on pipeline segments. Staff has observed 

increased prices and price volatility in both the regional natural gas and electric power 

markets during periods of high demand in winter and summer. 

Southern California Gas Company continues to experience difficulty returning pipeline 

segments back to commercial operation due to their remote locations and permitting 

delays. For instance, 530 million cubic feet per day (MMcfd) of import capacity on Line 

235-2 has been offline for the past two years. However, the repairs on Line 235-2 were 

recently completed on October 14, 2019, and 173 MMcfd of import capacity was 

returned while further inspections are conducted.

Southern California Gas Company’s 540 MMcfd Line 4000 has also experienced 

outages. 270 MMcfd of Line 4000 capacity has been offline since last winter, and 

Southern California Gas Company has also said that it took the remaining 270 MMcfd on 

Line 4000 out of service starting September 19, 2019, with a preliminary return-toservice date of November 4, 2019. This additional outage will lengthen the time before 

the system’s northern import path returns to full service. Thus, a total of 900 MMcfd of 

pipeline capacity in the company’s system is currently unavailable, leaving 2.94 Bcfd of 

import capacity for the system. 

Storage injections have slowed as a result of these outages, with the storage inventory 4

Bcf below last year’s storage inventory at this time. The return of these pipeline
segments should better position the Southern California Gas Company system to deal 

with system stress and meet peak natural gas demand.
Slide 10 – Pipeline Integrity Testing in the Northeast

Algonquin Gas Transmission and Texas Eastern Transmission have announced capacity 

reductions to accommodate pipeline safety and integrity testing. The restrictions vary by 

both location and magnitude; however, the publicly available schedules posted by the 

companies suggest most restrictions should end by December. Staff will continue to 

monitor the timelines and any potential impacts on natural gas and electric markets.
Slide 11 - Anticipated Reserve Margins Meet Reference Margins in All Regions

In its preliminary 2019-2020 Winter Reliability Assessment, NERC estimates that 

reserve margins for all assessment areas will exceed their reference margin targets this 

winter. The columns on the chart display the anticipated reserve margins for the regions 

comprising the U.S., while the black bars indicate the reference margins identified by the 

RTO or reliability region. Although all regions are expected to maintain healthy reserve 

margins through the winter, reserve margins are not always guarantors of reliable 

operations during the winter. Staff notes that fuel availability, particularly natural gas 

and fuel oil, can affect electric operations and must be monitored.
Slide 12 – Dual-fuel Capability Provides Price Hedge for Generators in the 

Northeast 

In PJM, NYISO, and ISO New England, dual-fuel generators play an important role in 

moderating electricity prices during the winter by offering optionality to plant operators 

and dispatchers when the system is facing natural gas pipeline constraints. Typically, 

dual-fuel generators run on natural gas except when high heating demand creates natural 

gas scarcity, or when they are required to consume fuel oil to maintain electric reliability

in anticipation of a sudden loss of natural gas supply. 

Fuel oil can be price-competitive during periods when natural gas prices spike. For 

instance, in New England, there were 19 days during the 2017-2018 winter when the 

next-day natural gas price, adjusted for heat content, exceeded the price for No. 2 fuel oil. 

Milder weather during the 2018-2019 winter created only four days where the next-day 

natural gas price exceeded oil prices in New England. 
Slide 13 –New Generation Plants Continue Shift toward Natural Gas and 

Renewables

The past three years have seen significant additions of natural gas-fired and renewable

generation across RTO/ISO and non-RTO/ISO regions, offsetting retirements of coal 

capacity and nuclear capacity. This chart shows actual and planned capacity additions 

and retirements in the 48 contiguous states from March 2019 to February 2020, as 

reported to the EIA. 

More than 3.4 GW of coal capacity retired from March 2019 to June 2019, and another

6.2 GW of coal capacity is expected to retire between July 2019 and February 2020. 

Approximately 680 MW of nuclear capacity retired from March 2019 to June 2019, and 

an additional 829 MW of nuclear capacity has announced plans to retire between July

2019 and February 2020. 

From the end of last winter through the upcoming winter, 5.6 GW of natural gas capacity 

has been or will be added across the United States. The installed capacity of renewable 

resources continues to increase, including significant additions of wind in MISO and SPP

and of solar photovoltaic in CAISO. In both cases, this follows capacity addition trends 

from the past three years. 
Slide 14 – Power Markets Meet Winter Weather with Market Enhancements

In recent winter seasons, generator outages during extreme cold weather have led to 

emergency events and stressed system conditions. Events like the 2014 Polar Vortex

have highlighted the need to ensure resource availability to meet winter peak demand. 

Instances of generator outages and fuel unavailability became issues that led to new 

market and regulatory solutions, some of which continue to be developed. A brief 

summary of the winter reliability initiatives in MISO, PJM, and ISO New England

follows.

In MISO, a cold weather event in January 2018 caused emergency conditions in MISO 

South and disruption in neighboring regions. FERC and NERC staff published a joint 

report on the event in July 2019. The loss of generators due to the cold weather itself was 

the major cause of the event. The report recommends—through market rules, Reliability 

Standards, and outreach—improvements in the winterization of generators and in the 

assessments of the capabilities of generators, transmission lines, and gas pipelines during 

cold weather. MISO and SPP have revised their coordination protocol to better manage

such events. MISO’s Resource Availability and Need (RAN) initiative changed existing 

rules—some effective for the 2019-20 capacity auction and some for the 2020-21 

auction—requiring testing of demand response resources, making demand response more 

available in non-summer months, and improving the timing of generator outages.

PJM and ISO New England have implemented performance requirements designed to 

incentivize capacity resources to perform during critical load periods throughout the year. 

Specifically, in 2014, the Commission approved ISO New England’s Pay-for-
Performance capacity market redesign which ties capacity payments to resource

performance during stressed system conditions. Similarly, in 2015, the Commission 

approved PJM’s Capacity Performance Program, which imposes penalties and bonuses 

during capacity critical periods.

In addition, ISO New England has been working actively with its stakeholders to develop 

market-based fuel security enhancements. In an order issued in July of 2018, the 

Commission directed ISO New England to develop short-term and long-term marketbased mechanisms to ensure regional fuel security. In response, ISO New England 

proposed an interim solution for the 2023-2024 and 2024-2025 winter seasons in the 

form of the Inventoried Energy Program, providing a compensation mechanism for 

generators beginning in the Capacity Commitment Period starting June 2023. That

proposal became effective May 28, 2019. ISO New England is still working to develop

long-term market-based mechanisms, which are expected to be filed in April 2020.
Slide 15 – 2019-2020 Winter Energy Market Assessment

This concludes staff’s prepared comments. A copy of this presentation will be posted on 

the Commission’s website. The online version of this report contains additional 

information on pipeline additions, pipeline restrictions in Southern California and the 

Northeast, dual-fuel capability in the Northeast, and winter reliability initiatives. We are 

available to answer any questions you may have.