Slide 1

Summer 2016 

Energy Market and Reliability 

Assessment

Item No. A-3

May 19, 2016

Good morning Mr. Chairman and Commissioners.

 

The Office of Electric Reliability and the Office of Enforcement are pleased to present the 2016 

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.

 

Please note that some information in this presentation comes from NERC’s 2016 Summer 

Reliability Assessment which will be released at a later date and is still subject to change.

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Slide 2

Summer Reliability and 

Market Issues to Monitor

 Electric capacity sufficient to meet forecast demand

 Near record storage levels and robust natural gas 

production are expected to suppress fuel and power prices

 Near-term gas and electric reliability risks posed by the 

Aliso Canyon gas storage outage

 Organized wholesale electricity markets have introduced 

rule additions and changes

Market conditions going into this summer continue to reflect the impact of low natural gas 

prices that have resulted from robust production and near record levels of natural gas in 

storage. Moreover, despite modest load growth, regional electric system reserve margins are 

forecast to be adequate. 

 

However, despite an optimistic national outlook, the recent events at the Aliso Canyon natural 

gas storage facility in California present an area of particular concern. The loss of this resource 

may pose a risk to local electric reliability and has the potential to result in elevated energy 

prices.

 

Additionally, we’ll take a look at recent changes to the organized wholesale electricity markets – 

including the expansion of the California ISO’s Energy Imbalance Market and the recent 

expansion of the Southwest Power Pool’s footprint – and discuss the market impacts that we 

expect to see this summer.

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Slide 3

Electric Capacity Sufficient 

to Meet Forecast Demand

0

100

200

300

400

500

600

700

800

900

1000

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

GW

Forecast Demand Forecast Capacity Actual Demand

Source: NERC Actual 2015 demand not yet available.

Preliminary data from NERC’s Summer Assessment indicates that the total U.S. load forecast, 

when weather-adjusted, is essentially unchanged over the past few years. This can be 

attributed to little to no load growth in the commercial and residential sectors.

 

Meanwhile, the total generating capacity in the U.S. has decreased by approximately 2 percent 

since last summer. The ongoing downward trend in capacity over the past several years is 

primarily due to coal retirements across the nation. The factors that prompted these closures 

include increased competition from natural gas, environmental regulations and an average fleet 

age that exceeded 50 years old.

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Slide 4

Reserve Margins 

Adequate in All Regions

0%

5%

10%

15%

20%

25%

30%

FRCC tJa SERC Stt ERCOT WECC NtCC aISO

Reserve aargin

Reserve aargin - Anticipated Reference aargin Level Source: NER

NERC’s Summer Assessment data indicates that reserve margins for all 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 Texas continues to be tighter when compared with the other 

regions this summer. However, the region is expected to have sufficient generating capacity to 

serve peak demands during the expected weather conditions for this upcoming summer season.

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Slide 5

Generating Capacity 

by Fuel Type

Source: NERC *Available On-Peak Capacity

West

Coal, 

17%

Hydro, 

16% batural

Gas, 

50%

buclear,

4%

Other, 

5%

Solar, 

3%

Wind, 

4%

Coal, 

32%

Hydro, 

4%

batural

Gas, 

41%

buclear,

13%

Other, 

9%

Solar, 

0%

Wind, 

1%

ERCOT East

Coal, 

26%

Hydro, 

1%

batural

Gas, 62%

buclear,

7%

Other, 

0%

Solar, 0%

Wind, 4%

This map shows the breakdown of the on-peak generating capacity by primary fuel type for 

power generation in the three interconnections. Over 18 GW of new generating capacity will be 

installed nationwide through the summer, with a majority of these capacity additions coming 

from renewables such as wind and solar.

 

Looking at the Western Interconnection, approximately 1 GW of natural gas, 3 GW of solar and 

1 GW of wind will be added to the system. 

 

In ERCOT, approximately 2 GW of natural gas will enter commercial service by the end of 

season.

 

Finally, the generating capacity in the Eastern Interconnection will see an additional 1 GW of 

natural gas, 2 GW of solar, and 4 GW of wind. Additionally, Tennessee Valley Authority's Watts 

Bar Nuclear Unit 2 will also go into commercial operation this summer, adding over 1 GW in 

generating capacity and will mark the first time in over two decades that a new nuclear unit will 

come on-line in the United States.

 

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Slide 6

Wind and Solar Capacity

0

20

40

60

80

100

2008 2009 2010 2011 2012 2013 2014 2015 2016

Nameplate Capacity (GW)

Wind

Solar

Source: NERC

This summer’s installed nameplate wind capacity is forecast to increase by 7 GW, or 

approximately 10 percent from 2015, according to NERC. This would bring the total capacity of 

wind resources to 76 GW nationwide. 

 

NERC is also projecting that about 4 GW of new utility-scale solar capacity will come on-line this 

summer.

Renewable sources of power production have grown substantially over the past few years, as 

both wind and solar power now have a significant presence in many electricity markets. 

However, as renewable’s share of the generation fuel mix portfolio increases, grid operators are 

continually seeking operational solutions to address the challenge of integrating wind and solar 

resources. 

 

In the California ISO, solar production is the fastest growing form of capacity. Solar production 

falls into two classes, utility-sized projects that are visible to and controllable by the ISO, and 

behind-the-meter installations at the customer level that are not clearly visible to the ISO. 

System loads have become more difficult to measure and predict as more demand is met by 

behind-the-meter solar generation. 

 

This year wind has provided half of the production in SPP in some hours. This increased wind 

generation can pose challenges for grid operators and both MISO and SPP have developed 

systems and procedures to take advantage of this seasonal output, while also managing its 

volatility and contribution to congestion. However, wind generation tends to be lower during 

the summer, especially on the hottest days when there is little wind. 

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FERC 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 met. 

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Slide 7

NOAA Forecasts Above 

Normal Summer Temps

Weather is always a significant factor in the energy markets and warmer temperatures coupled 

with low natural gas prices this summer could lead to near record generation of natural gasfired electricity. The National Oceanic Atmospheric Administration (NOAA) has forecasted 

above-normal temperatures for the continental U.S. this June, July and August, which should 

lead to increased power generation to meet cooling load. NOAA’s forecast shows the strongest 

possibility for above-normal temperatures in the Northeast, Mid-Atlantic, and the Western 

quarter of the U.S. Parts of the West, Upper Midwest, East and Southeast are likely to see 

above-normal temperatures as well, while, the Midcontinent and Texas show the lowest 

possibility for above-normal temperatures. 

 

In addition, Colorado State University is predicting an average hurricane season with a 40% 

probability of at least one major hurricane tracking into the Caribbean. 

 

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Slide 8

Power Burn Expected to Rise

as NG Prices Fall Below Coal

 $-

 $1

 $2

 $3

 $4

 $5

 $6

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 5

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 15

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 25

 30

 35

 40

Apr-12

Aug-12

Dec-12

Apr-13

Aug-13

Dec-13

Apr-14

Aug-14

Dec-14

Apr-15

Aug-15

Dec-15

Apr-16

Aug-16

Average Monthly Fuel 

Price ($/MMBtu)

Average Monthly Power 

Burn (Bcfd)

NG Generation Forecast

Henry Hub Central App Coal

Source: Nymex and Bentek

Traditionally, coal has been one of the least expensive fuels for power generation. However, 

natural gas prices reached a 17-year low in early March, making it less expensive than coal 

when adjusting for relative power plant efficiency. As coal plants continue to retire and natural 

gas power plants remain price competitive, we expect natural gas fired generation to remain 

robust. Natural gas fired generation has surpassed coal plant output since July 2015 and EIA 

projects this will continue through 2016. Coal and gas futures prices support this view, and 

power burn could reach 34.5 Bcfd in July, three percent higher than last summer’s peak. 

 

This decrease in coal generation has led to an increase in coal stockpiles. EIA reports that coal 

stockpiles are 22 percent higher than last year and 12 percent above the 5-year average.

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Slide 9

NG Summer Futures 

Cheaper Than Last Year

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

Cutures trice: Nymex +

Basis($/aaBtu)

Summer 2015 Summer 2016

Source: Nymex

This slide shows that natural gas futures prices for July and August have fallen by as much as 36 

percent compared to the summer of 2015. The decline is primarily due to a 22 percent drop in 

the Henry Hub summer futures price. The only region not to see a significant drop in natural 

gas prices this summer is Boston, which is nearly flat from last year. Generators are able to lockin these low prices if they choose to do so.

 

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Slide 10

Change in Basis 

Swap Futures

 $(0.40)

 $(0.20)

 $-

 $0.20

 $0.40

 $0.60

 $0.80

TZ6 Non NY

TZ6 NY

Chicago

Boston

CIG

TC

SoCal

tG&E

Change in Summer Basis Swap 

Cutures ($/aaBtu

Source: Nymex

This slide shows the summer-over-summer change in basis swap futures prices at major hubs. 

Natural gas basis swaps are financial instruments that represent the natural gas price 

differential between a specific point and the Henry Hub. Basis swaps help indicate the true cost 

to hedge natural gas and generally are a good indicator of pipeline congestion into a region. 

 

Basis swaps futures for the New York City and Mid-Atlantic markets fell 32 cents on average 

from last summer indicating those markets expect to be well supplied with Marcellus gas this 

summer. The Boston area basis swap is 60 cents higher than last summer, suggesting 

expectations for greater congestion due to above-normal temperatures and a reduction in 

capacity along the Algonquin pipeline because of planned maintenance to tie in the Algonquin 

Incremental Market (AIM) expansion project this summer. The Southern California basis swap is 

flat from last summer, signaling the Aliso Canyon storage field outage may not have a large 

effect on natural gas prices at the border this summer. Finally, basis swap futures in Northern 

California are down 17 cents from last summer, a product of cheap natural gas deliveries from 

the Rockies and Western Canada.

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Slide 11

NG Storage Forecasted to 

Near Last Year’s Record

 -

 500

 1,000

 1,500

 2,000

 2,500

 3,000

 3,500

 4,000

 4,500

Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar

Storage Inventories (Bcf)

5 Year Range Last Year 2016 Forecast

Source: EIA and Bentek

The 2015/2016 winter was the warmest on record, with total heating Degree Days (HDDs) 

across the U.S. down 17 percent from the previous winter and 13 percent below the 30-year 

average. As a result, winter natural gas demand was well below-normal and storage inventories 

on April 1, the traditional start of the injection season, were at the highest level ever seen (68 

percent higher than last year and 52 percent greater than the five-year average).

 

Low gas prices and increasing production helped storage inventories set a record at the start of 

the 2015/2016 winter. Similar conditions this injection season would leave storage inventories 

again at historically high levels by the fall. However, a variety of factors may reduce storage 

injections this summer. First, production is likely to fall by 2 Bcfd (3 percent) from last summer 

as falling fuel prices have made wet and dry plays less profitable. Second, above-normal 

temperatures across the U.S. this summer should lead to near record power burn, it’s expected 

to rise 1 Bcfd (3 percent). Third, Mexican demand for natural gas has grown significantly, and 

gas exports to Mexico could rise by 0.83 Bcfd (27 percent) from last summer. Finally, Cheniere’s 

Liquefied Natural Gas (LNG) export terminal at Sabine Pass sent its first cargo from the U.S. in 

February. Cheniere’s LNG export capability is currently about 600 MMcfd and is forecasted to 

reach approximately 1 Bcfd by the end of the summer. To date, Cheniere has sent out 8 cargoes 

for a total of 26 Bcf. 

 

Our analysis shows total U.S. supply falling 2.9 percent and total U.S. demand growing 2.6 

percent from last summer. Although this change in the supply demand balance could slow 

injections this summer, we still expect natural gas inventories to approach last year’s record at 

the end of the 2016 injection season. While storage is expected to be robust nationally, the 

Aliso Canyon storage outage may create regional issues in California. 

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Slide 12

Aliso Canyon Event

Source: Staff

After this presentation, there will be a panel to talk more in detail about the restricted 

operation of the Aliso Canyon Natural Gas Storage Facility and its impact on electric supply in 

Southern California. 

 

Given the situation at Aliso Canyon following the sealing of the natural gas leak in February, 

CAISO, LADWP and state agencies produced a Reliability Action Plan that identified actions 

intended to preserve gas and electric reliability in the region.

 

Aliso Canyon plays a major role in the delivery of natural gas into the Los Angeles Basin and 

maintaining gas system pressures in the region. As long as Aliso Canyon’s storage fields remain 

out-of-service, there is an increased risk of natural gas curtailments which could lead to 

disruptions in electricity supply to the region. 

 

In addition to the significant reliability concerns presented by the loss of the Aliso Canyon 

facility, we anticipate commensurate market effects. With 86 Bcf of capacity, Aliso Canyon is one 

of the largest natural gas storage sites in the US and is also the only field that can effectively 

support demand and pipeline pressure in the Los Angeles Basin because of pipeline limitations 

into the area. Aliso Canyon is uniquely important because it is a critical summertime resource 

for 17 large power plants in the Los Angeles Basin that represent approximately 10 GW of 

capacity. Over the past four years, summer withdrawals were frequent from Aliso Canyon.

 

One of the potential impacts of the loss of Aliso Canyon is the lessened flexibility to serve 

generator needs, especially during ramping periods. Aliso Canyon provided or absorbed natural 

gas, helping maintain pipeline pressures. Without it, generators’ operating flexibility drops in 

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real time, as natural gas cannot be delivered from the pipeline interconnections in time to 

supply more than planned-for generation. Changes in demand and in wind and solar 

generation, for example, can require increased natural gas generation. Yet those generators 

may not have scheduled enough gas into the system to meet those additional needs. We may 

see increased transmission congestion, localized price spikes and greater than normal uplift as 

California ISO’s market mechanisms reflect these operational difficulties in its pricing outcomes.

 

Because of these concerns, staff will be closely monitoring this situation and maintaining 

contact with the other parties during this period. 

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Slide 13

Summer Power Prices

Lower in 2016

 -

 10

 20

 30

 40

 50

 60

LSO-NE NYLSO-NYC Mid-C SP-15 PJ

$/

MW

2015 2016

Source: BloomNer

Similar to natural gas prices, futures prices for on-peak power this summer are 5 to 47 percent 

lower than 2015, which is a continuation of the downward trend that occurred last summer. As 

depicted in this chart, prices have dropped 5 percent at the ISO-NE internal hub and 47 percent 

at the Mid-Columbia hub (reflecting improved snowpack in the Pacific Northwest). These price 

changes appear to be consistent with market fundamentals, such as marginal generating 

resources in varying regions, fuel input costs and other factors such as the previously mentioned 

Algonquin pipeline restrictions in New England, which may create regional fuel delivery 

constraints.

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Slide 14

California ISO’s

Energy 

Imbalance 

Market

Source: Ventyx

In November 2014, California ISO began operating its Energy Imbalance Market, or EIM, outside 

of its Balancing Authority Area. When the EIM started-up, there was only one market 

participant, PacifiCorp. However, on December 1, 2015, NV Power joined the EIM. This fall, 

Arizona Public Service and Puget Sound Energy plan to join the EIM, with Portland General and 

Idaho Power after that.

 

The startup of the EIM introduced significant challenges, particularly the inability of the 

California ISO market model to see the capacity available to the EIM Balancing Authority, but 

not offered in the market. This lack of visibility caused a number of scarcity pricing events in 

periods when capacity was actually available. However, recent enhancements to the EIM have 

resulted in increased visibility to CAISO and the successful integration of NV Power. FERC Staff 

will be watching the performance of this new market operation this summer to monitor how 

well the market design changes are achieving efficiencies.

 

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Slide 15

Demand Response

0%

2%

4%

6%

8%

10%

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

ISO-NE NYISO PJ

aW

2014 DR Capacity

2015 DR Capacity

2016 DR Capacity

2016 DR % of RTO Capacity

Source: RTOs

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 available demand response capacity in the three northeast RTOs has increased 

modestly since last summer. This has been most notable in PJM, where demand response has 

increased by 765 MW and now represents 7 percent of the RTO’s capacity.

 

There are two new market developments that could have a bearing on demand response this 

summer. The first is the NYISO’s revisions to its scarcity pricing mechanism, which affect the 

real-time markets and incorporates scarcity pricing into the real-time optimization by 

establishing a 30-minute reserve requirement in real-time when NYISO calls upon demand 

resources. This change should improve real-time price formation, reduce the potential for uplift 

payments and increase price transparency.

 

The second development is the Capacity Performance initiative in PJM, which has created new 

requirements and penalties with the intent to encourage resources, including demand response 

resources, to meet their supply commitments during system emergencies. 

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Slide 16

Capacity Performance

 PJM and ISONE have added performance 

elements to their capacity markets

 In PJM: 60% of market has performance 

requirements for 2016-17

 Staff to monitor the market effects this 

summer

As just mentioned, capacity performance is an enhancement and new market feature in PJM 

and ISO New England. In ISO New England, the new Pay for Performance rules were included in 

the Forward Capacity Auction, held in 2015, and will take effect in June 2018. The PJM capacity 

market, however, is currently phasing in its new requirement that 60% of its total capacity 

requirement for the 2016-17 planning year be met by resources that can meet the performance 

requirements. The performance portion for this coming period was achieved through a 

transitional auction held last fall.

 

Staff will be monitoring the effect of the capacity performance standards on overall 

performance and outage rates and to what extent any penalties are assessed.

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Slide 17

0

1,000

2,000

3,000

4,000

5,000

6,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Net Flows - West to East (MW

Hour

PJM Summer Power Flows

2013 2014 2015

Power MMrket HmpMcts 

Plentiful NMturMl 

Source: Ventyx

The summer is particularly important for generators because it is the period of highest demand 

and is traditionally when generators earn a substantial portion of their net revenues from the 

energy market. With falling fuel prices and other factors, power prices have declined summerover-summer since 2011, despite similar loads.

 

As previously noted, lower natural gas prices have prompted a shift away from coal to natural 

gas-fired generation. While PJM continues to depend substantially upon coal-fired generation 

to meet demand, the region’s generation contribution from coal-fired units has fallen from 44%

five years ago to 34% in 2015. In addition to contributing to the rate of coal generator 

retirements, the shift to natural gas has had an impact on power flows.

 

Historically, power has flowed from lower-cost generation located in the western half of PJM to 

more expensive markets in eastern PJM. In 2015, power flows across the central PJM 

transmission interfaces dropped to about 3,000 MW, from almost 5,000 MW in 2013. Given the 

forward price indicators for power and natural gas, we expect this trend to continue this 

summer. 

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Slide 18

SPP Market 

Expansion

In our final slide, we’d like to provide an update on Southwest Power Pool’s recent market 

expansion. As you know, on October 1 of last year, SPP’s footprint added three new entities, the 

Upper Great Plains Region of the Western Area Power Administration, Basin Electric Power 

Cooperative, and Heartland Consumers Power District. The three entities, known as the 

Integrated System, added about 5 GW of peak demand and 7.6 GW of generating capacity to 

SPP.

 

This will be the first summer in which the Integrated System will participate directly in the SPP 

power market. Notably, abundant hydro-production in the newly integrated northern part of 

the RTO has introduced a low-cost supply of power to SPP’s fuel portfolio. This has put 

downward pressure on prices in SPP and increased flows from the Integrated System into the 

rest of SPP.

 

One of the challenges in implementing this expansion was the complex interweaving between 

the transmission systems of the Integrated System and MISO, which are connected by 178 

transmission ties. The flows on either system have implications for potential congestion on the 

other. However, all indications are that SPP has succeeded in integrating this new area into its 

operations and is effectively managing congestion in coordination with MISO. As the summer 

progresses, FERC Staff will closely monitor changes and events in this newly expanded market. 

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Slide 19

Summer 2016 

Energy Market and Reliability 

Assessment

Item No. A-3

May 19, 2016

This concludes staff’s assessment. A copy of this presentation will be posted on the 

Commission’s website. Thank you.

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