[Slide 1 Title Slide]
[Slide 2 Intro Side]

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

presents its 2018-2019 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. The National Oceanic and 

Atmospheric Administration (NOAA) forecasts a warmer than average winter. However, 

a warmer than average winter may still have prolonged periods of cold temperatures that

can stress natural gas and electricity markets despite reserve margins exceeding reference 

levels. 
[Slide 3 Storage]

Natural gas storage inventories began the 2018 injection season in April at 1,354 

billion cubic feet (Bcf), which is on the low end of the 5-year range and has carried over 

to lower storage volumes for this winter.

The Energy Information Administration (EIA) projects natural gas storage 

inventories to start the withdrawal season with 3,308 Bcf. This would be the lowest 

inventory level since 2005 and a 12.7 percent decrease from last year’s level. 

EIA forecasts that the storage deficit will decrease over the withdrawal season, 

with storage levels finally returning to levels within the 5-year range by the beginning of 

February.
[Slide 4 Gas Futures Prices]

The graph above shows the total natural gas futures prices for the past and

upcoming winters for regions across the U.S. As of October 1, 2018, the Henry Hub 

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

$3.12/MMBtu, 24 cents below last winter’s futures price measured on October 1, 2017. 

As a result, total prices across the U.S. (outside of New England and New York City) are 

lower than last year for the upcoming winter.

However, basis futures prices, which approximate the cost to deliver natural gas to 

regional markets this winter, have generally increased across the country. Basis futures 

prices in New York City and Boston averaged $6.03/MMBtu and $8.21/MMBtu, up 

$0.47/MMBtu and $3.40/MMBtu respectively from last year. This suggests a market 

expectation that both regions may face pipeline transportation constraints this winter. 
[Slide 5 Aliso Canyon]

Intrastate and distribution level natural gas infrastructure outages in Southern 

California are likely to impact natural gas and electricity markets this winter. Ongoing 

restrictions on Southern California Gas Company’s (SoCalGas) Aliso Canyon storage 

facility currently limit working gas capacity to 34 Bcf, down 60 percent from the 86 Bcf 

capacity prior to the 2015 leak. Unplanned remediation work on SoCalGas’s Line 4000 

started on September 18, 2017, and a force majeure event related to a pipeline rupture on 

Line 235 began on October 1, 2017. Combined, these outages have reduced receipt point 

capacity in the Northern Zone of the SoCalGas system by approximately 1,070 million 

cubic feet per day (MMcfd).

The restrictions to Lines 235 and 4000 have impacted both deliverability of natural 

gas supplies as well as regional natural gas prices, and will likely continue to affect both 

natural gas and electricity prices this winter when regional gas demand peaks. The 

ongoing restrictions to natural gas pipelines and storage facilities increase the potential 

for natural gas curtailments this winter, but winter power system flexibility and 

cooperation between SoCalGas and CAISO should help maintain electric reliability. 
[Slide 6 Reference Margins]

In its preliminary 2018-2019 Winter Reliability Assessment, NERC estimates that 

reserve margins for all assessment areas will meet reference margins 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 reliability, and must be monitored. 
[Slide 7 Capacity Additions]

The largest share of planned capacity additions this winter are powered by natural 

gas, solar, and wind, according to EIA. PJM will see the most total capacity added this 

winter; these additions are predominantly natural gas-fired capacity. CAISO will add the 

most renewable capacity. 

Expected retirements this winter include coal and natural gas-fired capacity, with 

most occurring in PJM. This follows retirement trends in recent years. 

In recent years, nuclear power plant retirements have occurred in CAISO, ISONE, PJM, MISO, and SPP. For example, Oyster Creek nuclear power plant in New 

Jersey ceased operations in September 2018. In addition, the Pilgrim nuclear power plant 

in Massachusetts will operate through the 2018-2019 winter before closing at the end of 

May 2019.
[Slide 8 Generation Capacity Mix]

Natural Gas Has a High Share of Capacity in RTO and 

Non-RTO Regions

Source: Resource to BAA mappings are as reported by EIA in Form 860M, June 2018.

Note: Percentages based on net winter capacity; excludes AK, HI, and resources that do not report a BAA. Includes resources with

status of operating and standby. 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

CAISO ERCOT ISONE MISO NYISO PJM SPP Non-ISO

Generation Capacity Mix

Other

Petroleum

Wind & Solar

Hydro

Nuclear

Coal

Natural Gas

An assessment of each region’s preparation for the winter season should take into 

account capacity mix and fuel source. Nuclear and coal power plant retirements

combined with natural gas power plant additions are resulting in an increasing reliance on 

natural gas-fired generation. This growing dependence is reflected in the high percentage 

of natural gas-fired capacity in both RTO and bilateral markets.

The widespread dependence on natural gas-fired generation is resulting in RTOs

taking actions to ensure that there are adequate fuel supplies during extended cold 

weather. Both ISO-NE and PJM have amended their capacity constructs to reward 

resources that perform at high levels, and penalize resources who fail to perform under 

emergency conditions. Also, RTOs have instituted formal gas-electric coordination 

programs with pipelines serving natural gas power plants. 
[Slide 9 ISO-NE’s Market Rule Changes]

New England continues to be an area of notable attention for the winter months. 

The region has become increasingly dependent on natural gas for both home heating and 

power generation, yet pipeline capacity into the region is constrained.

Two major market rule changes were implemented on June 1, 2018, which have 

positive implications for ISO-NE’s potential response to challenging winter conditions. 

The first is the full integration of price-responsive demand into the daily energy market.

The second is the introduction of the Pay-For-Performance capacity market 

incentives. These rules established protocols to reward resources that over-perform 

during shortage conditions on the regional power system by requiring underperforming 

resources to pay the over-performers. 

Also, this is the first winter that ISO-NE will operate without its Winter Reliability 

Program, since its start in 2013-2014. 

This concludes our presentation, and the complete 2018-2019 Winter Assessment 

will be publicly available on the Commission’s website. We are available to answer any 

questions.