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SLIDE 1 Title Slide
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Contents

SLIDE 1 Title Slide......................................................................................................................................1

SLIDE 2 Summer Reliability and Market Highlights...................................................................................3

SLIDE 3 Electric Capacity Sufficient to Meet Forecast Demand................................................................5

SLIDE 4 Reserve Margins Adequate in All Regions....................................................................................6

SLIDE 5 Generating Capacity by Fuel Type................................................................................................7

SLIDE 6 U.S. Wind and Solar Capacity .......................................................................................................8

SLIDE 7 Temperature Forecast and Market Prices ...................................................................................9

SLIDE 8 Natural Gas Storage and Production..........................................................................................10

SLIDE 9 Natural Gas Prices Expected to Rise Relative to Coal ................................................................12

SLIDE 10 Natural Gas Prices Rise Compared to Previous Summer.........................................................13

SLIDE 11 Summer Basis Swaps Narrow between Marcellus and Markets .............................................14

SLIDE 12 Congested Nodes from Summer 2016.....................................................................................15

SLIDE 13 Summer Power Futures............................................................................................................16

SLIDE 14 Capacity Performance..............................................................................................................17

SLIDE 15 Demand Response....................................................................................................................18

SLIDE 16 Diverse Fuel Mix for Summer Electricity Generation in the West...........................................19

SLIDE 17 Natural Gas Storage in California .............................................................................................20

SLIDE 18 Anticipated Effects on CAISO of the August 21 Solar Eclipse...................................................22
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SLIDE 2 Summer Reliability and Market Highlights

The Office of Electric Reliability and the Office of Enforcement are pleased to present the 2017 Summer 

Seasonal Assessment. This is staff’s annual opportunity to share our summer outlook on the electricity 

and natural gas markets and reliability matters to better inform the Commission’s understanding of 

current and future trends.

NERC anticipates that power resources will be able to meet the reference margin levels in most

Assessment Areas this summer. The anticipated reserve margin in ISO-NE is projected to be at 

14.88 percent, which is slightly below their Reference Margin Level of 15.1 percent.

Snowpack in the West, measured by snow water equivalents, reached levels well above average. The 

snow water equivalent in the West, particularly in California, had been tracking near the record-high

levels that were set in 1982-1983. However, the statewide levels have started to shift downwards since 

February and are now at approximately 65 percent of the April 1st average. Given the abundance of 

accumulated snow water, high hydro generation is likely to continue into the early part of the summer,

which could be leveraged to reduce natural gas constraints in Southern California.

FERC and other agencies continue to monitor the situation at the Aliso Canyon natural gas storage 

facility. This year marks the second summer that Aliso Canyon will be restricted. While the restrictions 

on Aliso Canyon did not pose any major issues during the 2016 summer, the limited availability of the 

Aliso Canyon natural gas storage facility in Southern California may pose a risk to gas and electric 

reliability this summer if hotter than normal weather conditions and unplanned gas pipeline outages 

materialize. This resource had been used to help maintain natural gas pipeline pressures, which are 
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necessary for supporting gas-fired generation during swings in power plant demand. Currently, Aliso 

Canyon has less working gas than last summer because of withdrawals this past January, and current

physical and regulatory limitations may affect the amount of stored gas that could be used this summer. 

Finally, the State of California has imposed new restrictions on all natural gas storage facilities, requiring 

facilities to inject and withdraw only through the well pipe, not through the casings, as has been done in 

the past. These limitations will reduce the rate at which injections and withdrawals can occur.
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SLIDE 3 Electric Capacity Sufficient to Meet Forecast Demand

Data from NERC’s Summer Assessment indicates that the total U.S. load forecast, when weatheradjusted, will be approximately 1.1 percent higher than it was last summer. Meanwhile, the total 

generating capacity in the U.S. has increased by approximately 1.0 percent since last summer and over 

20 GW of new generating capacity is expected to be installed nationwide through the summer. A 

majority of the capacity additions will come from renewable resources such as wind and solar.

Approximately 10 GW of generating capacity has retired since May 2016, including approximately 

4.0 GW of coal-fired capacity and 6.0 GW of natural gas-fired capacity. The 1,509 MW Moss Landing 

Power Plant in California, along with the 1,087 MW Willow Glen and 847 MW Michoud plants in 

Louisiana were the largest natural gas-fired facilities to retire over the past year. The 478 MW Fort 

Calhoun Nuclear Generating Station in Nebraska retired in October 2016.

Additionally, the Brayton Point coal- and oil-fired generators in ISO-NE were retired in May, representing

a loss of approximately 1,500 MW of capacity.
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SLIDE 4 Reserve Margins Adequate in Most Regions

NERC’s Summer Assessment data indicates that planning reserve margins for most assessment areas are 

anticipated to be adequate this summer. The columns shown on this chart display the anticipated 

reserve margins for various markets and regions, while the black bars indicate the Reference Margins.

The anticipated reserve margin in ERCOT continues to be tight when compared to the other regions, 

although ERCOT expects to have sufficient generating capacity to serve peak demand during this 

upcoming summer season. However, the Lower Rio Grande Valley, Laredo, and West Texas are a few 

areas in ERCOT that risk experiencing localized reliability issues due to strong load growth, transmission 

constraints, and limited generation resources.

If forecasted peak summer conditions in ISO-NE occur, tighter supply margins could develop as 

approximately 700 MW of new resources have been delayed and may not be placed into commission 

this season as expected. ISO-NE may be required to rely on additional imports from neighboring regions 

as well as implementing operating procedures to maintain reliability during possible periods of supply 

deficiencies.
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SLIDE 5 Generating Capacity by Fuel Type

This graphic shows a breakdown of this summer’s on-peak generating capacity by primary fuel type for 

power generation across the Western, Texas, and Eastern Interconnections. 

The Western Interconnection expects to add approximately 6 GW to the system: 3 GW of solar

photovoltaic and 3 GW of wind capacity to the system.

In Texas, approximately 1 GW of renewable capacity is expected to be added to the region, with most of 

the capacity coming from wind installations.

Finally, the Eastern Interconnection expects to add approximately 13 GW of additional capacity: with 

2 GW of natural gas-fired capacity, 6 GW of solar photovoltaic capacity, and 5 GW of wind capacity.
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SLIDE 6 U.S. Wind and Solar Capacity

NERC anticipates that the total installed nameplate wind capacity this summer will be 82 GW,

approximately 8 percent higher than in 2016. NERC also anticipates that about 6 GW of new utility-scale 

solar capacity will come on-line this summer.

The growing importance of renewable resources has continued in recent years, as both wind and solar 

capacity continue to expand. Grid operators are pursuing operational solutions to better integrate wind 

and solar resources as part of their operational and planning activities.

Notably, the Blue Cut Fire event in August 2016 illustrates why grid operators must work to integrate 

and minimize risks posed by new technologies such as increased penetration of solar units with 

inverters. As a result of the fire, multiple transmission line faults occurred across Southern California 

Edison’s bulk electric system and resulted in a simultaneous disconnect of approximately 1,200 MW of 

inverter-connected generation. In response to the event, NERC, in collaboration with inverter 

equipment manufacturers and other interested parties, formed a group to investigate the event and to

develop solutions to avoid similar future occurrences. This group concluded in a June 2017 NERC report 

that the loss of inverter power injection was primarily due to a perceived low-frequency condition and 

low-voltage blocking of the inverters. Through this effort, NERC also recommended long-term actions to 

allow the solar photovoltaic generation fleet to ride-through similar future events and in the near term 

will issue a NERC alert to raise awareness prior to the summer season to minimize the potential for 

abrupt disconnection of inverter-connected generation. These issues have also been the focus of recent 

Commission action on voltage requirements and frequency ride-through.

Staff will continue to monitor how the organized markets are managing the growing impacts of 

renewable generation this summer and how these challenges are being addressed. 
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SLIDE 7 Temperature Forecast and Market Prices 

The National Oceanic Atmospheric Administration (NOAA) forecasts above normal temperatures for 

most of the continental U.S. in June, July, and August. NOAA’s forecast shows that nearly all regions are 

likely to see above normal temperatures, with the strongest possibility for above normal temperatures 

in the North Atlantic, Southeast, and Gulf of Mexico regions. Much of the Central, Great Lakes, and 

Western regions are also likely to see above normal temperatures. At this time, it is unclear whether

the northern part of the Central region is likely to see normal, below average, or above average 

temperature levels. 

Warmer temperatures require increased power generation to meet increased demand for home and 

office cooling. In 2016, for example, the hottest average days correspond to above-average locational 

electricity prices. However, increased demand due to temperature is only one factor that could affect 

market prices this summer.
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SLIDE 8 Natural Gas Storage and Production

Despite entering this past winter with record high storage levels of 4,047 Bcf, several factors increased 

the demand for storage withdrawals. A 3 percent year-over-year drop in natural gas production and 

relatively normal December temperatures created a tight natural gas market at the start of the 2016 –

2017 winter. Storage withdrawals totaled 1,998 Bcf during the most recent withdrawal season, 

30 percent more than last year’s withdrawal during the mild 2015 – 2016 winter. As a result, storage 

levels began the injection season this year at approximately 2,092 Bcf, or 401 Bcf below the levels at the 

start of last year’s season. The 2016 – 2017 winter temperatures were overall significantly warmer than 

normal, as total heating degree days (HDDs) were 15 percent below the 30 year average. Specifically, 

February was 10 degrees Fahrenheit above the average monthly temperature over the past 30 years. 

During the week of February 24, 2017, the warm weather fostered the earliest net natural gas injection 

on record, posting a 7 Bcf net storage injection.

This summer’s natural gas injections into storage will depend in part on countervailing forces in natural 

gas supply and demand fundamentals. Current natural gas futures show prices at the Henry Hub 

increasing this summer by $0.02/MMBtu to $3.09/MMBtu, indicating that market participants expect 

demand increases to more than offset increases in supply. A 125 percent year over year increase in the 

number of active oil and natural gas drilling rigs should strengthen natural gas supply during the 2017 

injection season. However, much of the drilling activity is in oil-rich plays with associated gas production 

which exposes much of this future natural gas production to oil prices instead of natural gas prices. 

There are currently 907 active drilling rigs in the U.S., up 504 rigs or 125 percent from last year. Of 

these, 722 are targeting oil rich plays which may contain associated natural gas and 185 are targeting 

natural gas rich plays. However, temperatures, LNG exports, and exports to Mexico all increase 

competition for natural gas that may otherwise be injected into storage. Exports to Mexico have 
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increased 306 percent from a 912 MMcfd average in 2010 to 3,707 MMcfd in 2016. Bentek Energy 

estimates storage volumes will end the 2017 injection season at 3,775 Bcf, 272 Bcf below last year’s 

record level 4,047 Bcf, and closer to the five year average of 3,871 Bcf. 
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SLIDE 9 Natural Gas Prices Expected to Rise Relative to Coal

Electricity production from natural gas fired generation surpassed that of coal fired generation in 2016 

for the first time ever on an annual basis, in part due to relatively low natural gas prices. However, both 

natural gas and coal prices have increased since bottoming out at a five-year low during 2016. As of 

May 2017, average monthly natural gas spot prices increased $1.44/MMBtu from the March 2016 fiveyear low of $1.81/MMBtu to $3.25/MMBtu. Although coal prices have increased from their May 2016 

five-year low of $1.87/MMBtu, they have not increased to the same extent as natural gas prices. Since 

May 2016, coal prices have increased by $0.97/MMBtu to $2.84/MMBtu. The price premium for natural 

gas relative to coal persists in the current summer futures contracts for both commodities. The current 

$0.42/MMBtu natural gas price premium to coal is $0.32/MMBtu higher than the $0.10/MMBtu 

premium during 2016, and as of May 31st, 2017 this summer’s futures contracts of natural gas were 

trading at a $0.43/MMBtu premium to coal. 
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SLIDE 10 Natural Gas Prices Rise Compared to Previous Summer

Lower storage inventories, a 1.7 percent year over year decrease in natural gas production rates, and a 

warmer than average forecasted summer have all contributed to increased gas futures prices in 

absolute terms across the country during summer 2017 relative to the previous summer. Summer over

summer futures contract increases ranged from a $0.38/MMBtu increase at Boston to a $0.88/MMBtu

increase in Mid-Atlantic prices. Although there has been a significant annual increase in futures prices, 

the price levels are still substantially below 2014 summer prices which exceeded $4.00/MMBtu at Henry 

Hub.
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SLIDE 11 Summer Basis Swaps Narrow between Marcellus and Markets

The chart above shows the summer over summer change in the value of basis swap futures prices at 

major hubs. New York basis has increased from -$0.37/MMBtu in summer 2016 to -$0.25/MMBtu in

summer 2017, a $0.12/MMBtu increase. Meanwhile, Boston basis has decreased $0.37/MMBtu, from 

$0.43/MMBtu in summer 2016 to $0.06/MMBtu in summer 2017. The changes relative to the previous 

summer reflect a narrowing of the basis between Marcellus and Utica supply hubs and market hubs 

such as Boston and Chicago, which are increasingly supplied by Marcellus and Utica natural gas. The 

narrowing basis is a price signal that the transportation costs between these points has decreased 

overall, which may reflect increased transportation capacity from production areas in the 

Marcellus/Utica and corresponding market destinations. 
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SLIDE 12 Congested Nodes from Summer 2016

The map above identifies nodes that had elevated congestion prices last summer and did not have 

elevated prices the rest of the year. The larger “bubbles” correspond with highest prices.

During the summer, grid congestion can be a significant issue, as system operators focus on moving 

power from areas of greater supply to those of greater demand. These situations can occur for a 

number of reasons, such as extreme weather; transmission or generator outages; seasonal load changes 

for cooling and other needs; grid maintenance; and other factors.

Staff analyzed 2016 prices to identify nodes, or specific grid locations, which experienced higher

congestion pricing during summer 2016 than during the other three seasons of the year. To identify 

specific locations of interest, staff analyzed nodal price extremes and volatility, relative to the broader 

RTO/ISO market. These high congestion prices indicate where it is relatively more difficult to deliver 

power or where additional generation is particularly valuable for relieving congestion. Last summer, this 

occurred in various locations including Maryland and Northern Illinois in PJM, Central and Southern 

California in CAISO, and near the seams between RTOs. Staff will continue to analyze congestion in 

RTO/ISO markets during the summer months of 2017. 

Since last summer, more than $5 billion of transmission upgrades entered operation in the six RTO/ISO 

markets. These infrastructure investments may help relieve grid congestion and could reduce some of 

the high price volatility in summer 2017. 
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SLIDE 13 Summer Power Futures

As depicted in the figure above, average monthly on-peak futures prices since 2016 have risen

15 percent at SPP South, 11 percent at MISO Indiana Hub, 11 percent at SP-15 in California, 9 percent at 

ISO-NE internal hub, and 11 percent in NYISO Zone J. Futures prices at PJM’s Western hub have 

decreased 3 percent. 
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SLIDE 14 Capacity Performance

June 1, 2017 marks the start of PJM’s second year transitioning toward the full implementation of its

Capacity Performance program. These rules set performance requirements on capacity resources 

during system emergencies and impose substantial penalties for non-performance. Additionally, 

generators that exceed performance commitments during these events are entitled to funds collected 

from generators that underperform and fail to meet their power supply obligations.

The stronger incentives were needed to encourage investment for better generation performance. The 

RTO noted that the rapid and significant shift from coal to natural gas-fired generation has driven 

electricity prices sharply lower and inhibited needed investments in plant upgrades and modernization, 

highlighting the importance of these reliability standards.
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SLIDE 15 Demand Response

Demand response is an important resource that is used to maintain reliability during periods of market 

stress, such as peak summer days or during system emergencies. As shown in this chart, the amount of 

cleared demand response capacity in the three northeast RTOs has shifted since last summer. This has 

been most notable in PJM, where demand response has increased by 2,256 MW, or 28 percent from last 

year, and now represents 6.3 percent of the RTO’s total capacity. In comparison, the amounts of 

demand response in NYISO and ISO-NE are much lower than in PJM, in terms of both absolute 

megawatts and percentage of capacity. This gap is continuing to expand as the rates of participation in 

NYISO and ISO-NE have continued to decline for 2017. This chart reflects the amount of demand 

response that cleared and received a capacity supply obligation in 2015 through 2017. FERC staff’s 

annual Assessment of Demand Response and Advanced Metering issued in December 2016 reflected a 

notably higher number of 2,696 MW of demand response in ISO-NE — a higher number that includes

energy efficiency and all enrolled demand response.

It is also important to note that, this summer, demand response providers in PJM will be subject to the 

Capacity Performance obligations mentioned on Slide 14 and that similar rules will be enacted in ISO-NE 

next year. Lastly, there were no activations of these emergency resources last summer in PJM and 

ISO-NE. However, the NYISO relied upon demand response statewide on August 12th, when the system 

operator projected reserve shortages due to high demand. NYISO also activated a voluntary New York 

City program on four other days to address local system reliability problems at the request of its

Transmission Owners.
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SLIDE 16 Diverse Fuel Mix for Summer Electricity Generation in the West

As shown in the figure above, the mix of generation in the West comes from a diverse set of resource 

types during the summer months. As mentioned earlier on Slide 2, the snow water equivalent in the 

West has been high this year, providing relatively high hydro generation in the spring and early summer. 

The combination of strong hydroelectric generation, coupled with high spring renewable output, led to 

warnings from CAISO that up to 8,000 MW of renewable generation could be curtailed to maintain 

reliability during the spring. Over the course of the summer, hydro generation typically drops by June, 

and is replaced with natural gas-fired generation and, to a lesser extent, coal-fired generation. 

However, because of this year’s abundant Northwest and California snowpack levels, it is possible that 

high hydro generation could extend until July, if temperatures remain moderate in the early summer. 

The Energy Imbalance Market, or EIM, helps to manage energy imbalances and integrate diverse 

resource types across a wide geographic area. In this regard, the EIM has provided an outlet for CAISO 

to sell renewable energy that it cannot use on its own system. For instance, in recent months, CAISO 

has sold into the EIM during the middle of the day when solar output peaks, often at negative prices. 

During summer months, this pattern may change as CAISO uses more of its renewable generation to 

meet its own summer load.
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SLIDE 17 Natural Gas Storage in California

The summer season is when electric generation demand for natural gas typically peaks. Although 

overall natural gas demand is lower in the summer, generator demand for natural gas requires natural 

gas pipeline operators to balance their pressures as generator demand surges and subsides to serve load 

and balance rapid daily ramps and intra-hour fluctuations, which result from unexpected swings in

renewable generation and load, unexpected generator and transmission outages, and other factors. 

California state regulators continue to review whether Aliso Canyon should resume operations, and if so, 

at what levels. Consequently, Aliso Canyon is not expected to be available this summer except in cases 

of emergency. Further, Aliso Canyon has 14.77 Bcf of working gas this summer, slightly less working gas 

than last summer. This reduction may affect whether the state would use the remaining inventory to 

aid electric generation, if necessary this summer, since it may need it to support winter demand.

As mentioned earlier, California state regulators have required natural gas storage fields to limit their 

injections and withdrawals to the pipes, and not use the casings. This will further reduce the rate at 

which gas companies can inject and withdraw, reducing their ability to quickly inject gas from storage 

into their systems to support pressure. 

However, the construction of additional electric transmission into Southern California will help ease the 

stress on natural gas-fired generation in the region and the associated natural gas systems. SoCal Edison 

has completed construction of the 173 mile Tehachapi Renewable Transmission Project, which will bring

non-local generation into Southern California. 

Finally, other measures implemented to address the loss of Aliso Canyon will remain in place, including 

CAISO’s ability to implement a natural gas constraint and the ability of the natural gas pipelines to

require that shippers balance their supplies. Staff also expects that the Los Angeles Department of 
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Water and Power will continue to have dual fuel capability at most of its LA Basin gas units, which allow 

these units to continue generating in the event of natural gas curtailments. 
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SLIDE 18 Anticipated Effects on CAISO of the August 21 Solar Eclipse

On August 21st of this year, the California ISO will be observing the effects of the first solar eclipse to 

occur since the region added significant amounts of combined utility scale and rooftop solar capacity. 

This is anticipated to affect system operations, as up to 5,000 MW of output from these resources 

declines over an 80 minute period, then subsequently returns back to normal. This drop is equal to 

more than 10 percent of a typical summer day’s peak load and could result in rapid ramping conditions 

and other challenges. In addition to California, NERC has identified a similar concern for utility 

operations in North Carolina because of the significant installed solar capacity in the state. 

A similar event occurred in Germany two years ago, causing operators to rely upon neighboring areas to 

provide capacity and reserves. In anticipation of this event, both NERC and the CAISO have undertaken 

studies to examine the potential effects and develop mitigating actions to address them. Staff will be 

monitoring the anticipated market and reliability effects of the eclipse. These include ramping and 

balancing concerns on the bulk power system, procuring additional non-photovoltaic generation during 

the period of obscuration, potential negative and positive price movements, reserve pricing conditions 

and a likelihood that there will be greater than normal transactions within the EIM.