Slide 1

Item No. A-3

May 14, 2015

Summer 2015 

Energy Market and 

Reliability Assessment

Good morning Mr. Chairman and Commissioners.

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

the 2015 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 2015 

Summer Reliability Assessment which will be considered for approval by the Board of 

Trustees this afternoon and still is subject to change.
Slide 2

Reliability and Market 

Outlook Highlights

 Plentiful fuel supplies with low natural gas prices 

and recovering coal stockpiles

 The economy has continued to recover and 

contributed to increased industrial demand, yet 

reserve margins remain adequate

 California drought will limit hydroelectric output

These bullets reflect the key takeaways from today’s presentation.

Market conditions going into the summer will reflect the continued low natural gas 

prices that have resulted from robust production, as well as the recovery of fuel 

stockpiles at coal-fired power plants.

Regional electric system reserve margins are adequate, despite modest growth in 

load, which is primarily attributable to increased industrial activity. 

The historic drought in California and the West has entered its fourth year and is an 

area of particular concern. This may lead to elevated energy prices; however, both 

the NERC and the California ISO have concluded that the current situation is not a 

threat to reliability.
Slide 3

Source: NOAA National Weather 

Service

NOAA 

Forecasts 

a Warm 

Summer

Overall

Weather conditions are among the most important, yet difficult to predict, factors 

affecting the energy markets. NOAA is forecasting potentially warmer than normal 

temperatures across the West and the Southeast, with the greatest likelihood along 

the West Coast. Below normal temperatures are forecasted for portions of Texas and 

eastern New Mexico. 

Citing the likely development of a moderate to strong El Niño pattern, forecasters are 

predicting a below average hurricane season for the Atlantic basin, with only three 

hurricanes forecasted. By comparison, seven hurricanes is considered normal for a 

season. Generally speaking, hurricanes do not have the same level of impact on the 

US energy markets as they did several years ago, due to the substantial shift in 

natural gas production from the Gulf of Mexico to onshore shale production. 
Slide 4

Reliability Issues 

to Monitor

 Coal stockpiles recovering, though some 

areas warrant continued monitoring due to 

localized issues

 California drought continues, but significant 

impacts to capacity availability not expected 

at this time

 Planned pipeline maintenance outage in New 

England could impact capacity availability

The Energy Information Administration reported that power plant coal stockpiles have 

been recovering since summer 2014; however, the forecasted stockpile levels are 

expected to remain modest throughout 2015. In some regions, localized issues have 

resulted in limited rebuilding of these stockpiles. If natural gas prices were to rise 

during the summer, increased coal-fired generator output may result in coal supply 

issues to reemerge in the Midwest.

The ongoing drought conditions in California and the West will limit the availability of 

hydroelectric generation over the summer. We will discuss the drought in greater 

detail later in this presentation.

In late August, ISO-NE may experience some impacts to the region’s natural gas-fired 

generating fleet when Spectra Energy begins maintenance and expansion of the 

Algonquin pipeline.
Slide 5

Capacity Forecast to 

Exceed Demand

Source: Derived from NERC 

data. Actual 2014 demand 

not yet available

0

100

200

300

400

500

600

700

800

900

1000

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

GW

Forecast Demand Forecast Capacity Actual Demand

EIA has forecast a 2.9 percent increase in electric demand from 2014, reflecting an 

expected return to more typical conditions from last year’s unusually mild weather. 

This compares to a weather adjusted increase of approximately 1 percent over last 

year’s forecast. This growth is driven primarily by the commercial and industrial 

sectors, as opposed to the residential sector, which is a reversal from the past few 

years.

The historic correlation between economic growth and increased electrical demand 

has weakened in many markets. A recent report by the NYISO attributed this 

declining linkage to a combination of factors, including the expansion of energy 

efficiency programs and growing impact of behind-the-meter generation, which 

includes residential solar. If continued, this shift may further complicate the 

forecasting of energy demand, based on economic growth.

Meanwhile, the total generating capacity in the U.S. has decreased by about 3 

percent, primarily because of increased coal generator retirements. This is a 

continuation of the trend that was seen last year. In contrast to coal, NERC forecasts 

an increase of approximately 3.5 GW in wind generation capacity over last year, or 

approximately 6 percent and brings the national wind total to approximately 65 GW. 

NERC is also projecting a net increase of approximately 2 GW of installed utility-scale 
solar capacity for this summer, though more solar generation is planned to come 

online this summer.

One notable transmission project is the rebuilding of the 500 kV SusquehannaRoseland power line, which runs between Pennsylvania and New Jersey. It was placed 

into service on May 11th and is expected to lower congestion and increase market 

efficiency in this region of PJM.
Slide 6

Reserve Margins 

Adequate in all Regions

Source: Derived from NERC data

0%

5%

10%

15%

20%

25%

30%

35%

40%

FRCC PJM SERC SPP ERCOT WECC NPCC MISO

Reserve Margin (%)

Reserve Margin -Anticipated Reference Margin Level

Data from NERC’s Summer Assessment indicates that reserve margins will be adequate 

for all assessment areas this summer. This chart displays the reference reserve 

margin levels for various markets and regions, along with the anticipated reserve 

margins.

Resource adequacy is forecast to improve this summer in MISO, ERCOT and New York. 

In ERCOT, a new load forecasting methodology that has resulted in higher available 

wind capacity, coupled with new natural gas-fired capacity, have increased the 

reserve marginfrom 15 to 15.6 percent. In New York, margins have also improved 

because of repowered generation capacity and lower forecast demand.
Slide 7

The available generator capacity in WECC has increased by approximately 5 GW since 

last summer, with approximately 6 GW of additions and 1GW of retirements. These 

additions include over 2 GW of solar and approximately 1 GW of wind resources. 

In ERCOT, approximately 2 GW of natural gas and 2 GW of wind capacity have entered 

commercial service since the last summer assessment. This includes the Panda Temple 

2 natural gas combined cycle project and the Goldsmith peaker project with a 

combined summer capacity of approximately 1 GW.

Notably, in the Eastern Interconnection, the 615 MW Vermont Yankee Nuclear Power 

Plant retired in late December 2014. This brings the total to five nuclear power 

plants that have been decommissioned since 2012. While the loss of Vermont Yankee 

leaves New England even more dependent upon natural gas, 178 MW of new energy 

efficiency projects are expected to be in place this summer. Despite the loss of 

Vermont Yankee, the grid operator forecasts adequate resources to meet demand.

Slide 8

MATS - Factor in Fossil Plant 

Retirements/Retrofits

Source: Derived from RTO 

data [Note: excludes 

resources whose response 

is “repowering” or “yet to 

be determined”]

0

10

20

30

40

50

60

PJM MISO

Capacity (GW)

Retirements Retrofits

The Mercury and Air Toxics Standards (MATS) rules took effect in April and require 

advanced pollution controls on coal and oil-fired units larger than 25 MW. This has 

caused units in MISO and PJM to make capital-intensive pollution control retrofits to 

comply with the rule, as illustrated in this chart. While SPP has not published 

statistics that are similar to these regions, a recent Boston Pacific report, 

commissioned by the SPP Board of Directors, indicated that 1.1 GW of generation was 

expected to be retired as a result of EPA regulations.

Adding pollution controls increases the non-fuel operating and maintenance costs of 

coal plants, but provides added flexibility to burn lower-cost, higher sulfur coal. 

Many plants have elected to install pollution controls with comparatively lower 

capital costs and higher variable O&M costs. This can increase total plant operating 

costs by up to one-third, which is typically reflected in higher energy market offers or

directly incorporated in the retail rates of vertically integrated utilities. In a low 

natural gas price and load growth environment, the MATS related costs were 

uneconomic for many older and less efficient coal plants and many of these units 

were retired. The closures have exceeded conventional generation replacements and 

may result in lower reserve margins and increased transmission congestion in the 

near-term, as well as a greater dependence upon natural gas for generation.
Slide 9

CA/Western Drought not 

Expected to Affect Reliability 

Source: USDA Western 

Regional Climate Center 

Below average precipitation and warmer than normal temperatures left the West with 

extremely low snowpack levels on April 1, the day at which snowpack traditionally 

peaks. California’s snowpack fell to a record 5 percent of normal on April 1, reaching 

historical lows for the second year in a row. However, reservoir levels in the state 

rose over last year’s levels because of early snow melt and rain.

CAISO expects that the reduced hydro generation will be offset by moderate load 

growth and 2.1 GW of new generation, of which 2 GW is solar. Solar generation now 

exceeds 6 GW at its peak output. Additionally, new transmission upgrades in the San 

Diego and Orange County areas will improve local resource adequacy. Staff will be 

monitoring the load area around Fresno, which is typically served by significant 

amounts of hydro generation. If the drought persists, power will need to be brought 

in from other areas and could potentially result in increased transmission congestion 

and elevated local power prices.

Snow pack was also below normal throughout the remainder of the West. For 

example, in Washington, precipitation was near normal, at 101 percent of typical, but 

warm temperatures kept snowpack from accumulating and was only 22 percent of 

normal on April 1.
Lastly, these conditions may create challenges during California’s fire season, as there 

may be a dramatically increased risk of wildfire activity, which has the potential to 

affect power grid operations. Lastly, these conditions may create challenges during 

California’s fire season, as there may be a dramatically increased risk of wildfire 

activity, which has the potential to affect power grid operations.
Slide 10

DR Capacity in Eastern 

RTOs

Source: Derived from 

public RTO/ISO Data

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

ISO-NE NYISO PJM

MW

2013 DR Capacity

2014 DR Capacity

2015 DR Capacity

2015 DR % of RTO Capacity

Demand response has traditionally been a summer resource to shave peaks on hot 

days or during other periods of stress. This chart shows participation in the capacitybased demand response (DR) programs in the three Northeastern RTOs. The colored 

bars indicate the actual amounts of enrolled demand response capacity, which have 

fallen in each of the regions from last year. This has occurred most notably in PJM, 

which has the largest of these programs, dropping by nearly 2,500 MW. Additionally, 

the current 6,900 MW of participation is less than half of the original 14,800 MW of DR 

that cleared in the forward capacity auction that was held in 2012, for the 2015/16 

capability period. This reduction occurred when a substantial number of market 

participants traded away these positions in the RTO's capacity reconfiguration 

auctions and through other transactions.

In the NYISO and ISO-NE, the reductions were much more modest than in PJM, in 

terms of both megawatts and percentage of cleared capacity. In the case of New 

York, the amount of DR fell by 65 MW or 5 percent, and in New England it was 62 MW 

or 9 percent.

Last summer, there were no activations of the capacity based DR programs in these 

regions, primarily because of the mild weather and moderate system conditions. 
However, if above normal temperatures occur this summer, we could expect to see 

demand response resources activated and dispatched in the real-time energy markets.
Slide 11

Forward NG Prices 

Lower than 2014

Source: Derived from 

Nymex & Bloomberg

 $-

 $1.00

 $2.00

 $3.00

 $4.00

 $5.00

 $6.00

Futures Prices ($/MMBtu)

2014 2015

Forward prices are not a predictor of actual prices, but reflect the cost of hedging 

market risk and can help us understand market dynamics. 

Going into the summer, the average Nymex futures price for June through August is 

$2.89/MMBtu, which is 40 percent lower than in 2014. This is consistent across the 

country, with the Boston area’s Algonquin Citygate showing the largest differential, at 

46 percent below last year, and averaging $2.96/MMBtu for the summer. This can be 

attributed to a 5.7 percent year-on-year increase in natural gas production and 

storage inventories that are 71 percent higher than in 2014, or 4 percent below the 5-

year average. 

The injection season began on April 3 with 1.5 Tcf of natural gas in storage, 79 

percent above last year. Since then, weekly injections have averaged 65 Bcf, versus 

47 Bcf last year. If injections continue at this rate, inventories could set a new record 

by the end of the injection season on October 31. 
Slide 12

Market Dynamics Indicate 

Coal-to-Gas Switching 

This Summer

Source: Derived from 

Bloomberg data

$0

$1

$2

$3

$4

$5

$6

$/MMBtu

Natural Gas

Coal

Natural Gas Futures

Coal Futures

With summer futures prices below $3.00/MMBtu in most regions, natural gas is 

expected to be competitive with coal on a $/MMBtu basis, when adjusted for the 

relative efficiency of natural gas versus coal-fired electric generation units. The only 

region where summer futures are above $3.00/MMBtu is Northern California; however, 

since the region has no coal-fired plants, it will not experience any coal-to-gas 

switching. 

Any further downward price pressure would give natural gas an even greater 

advantage in the supply stack and is comparable to 2012, when the Henry Hub price 

dropped to the lowest level in over ten years, averaging $2.65/MMBtu. According to 

industry estimates, this resulted in 5.1 Bcfd coal-to-gas fuel switching. Estimates for 

this summer indicate that a $2.50/MMBtu natural gas price could result in 4-5 Bcfd of 

incremental natural gas demand from power generators.
Slide 13

Forward Electricity 

Prices Lower for 2015 

Source: Derived from 

Bloomberg data

 -

 10

 20

 30

 40

 50

 60

 70

MID-C SP-15 PJM-West NYISO NYC ISO-NE Internal

Hub

Prices ($/MWh)

2014 2015

Similar to natural gas, forward peak power prices are down by an average of 24 

percent from this time last year. By region, this ranges from down 34 percent at the 

ISO-NE internal hub to down 13 percent at the Mid-Columbia hub, reflective worsening 

drought conditions in the Pacific Northwest. These price changes are further driven 

by regional differences in generating resources, fuel input costs, and other market 

fundamentals.
Slide 14

PJM & NYISO’s Coordinated 

Transaction Scheduling

Source: PJM

Non-CTS Iour-Ahead External Transaction

CTS Real-Time External Transaction

0

0

-75 -30 -15

-75

Bid

Submitted

Bid

Submitted

Transaction

Evaluated

Transaction

Scheduled

-45

Transaction

Scheduled

Transaction

Evaluated

-60

In November, PJM and NYISO implemented Coordinated Transaction Scheduling, which 

provides market participants with the option to submit intra-hour bids between the 

two regions. These 15-minute transactions are an additional way trade power 

between these RTOs and represent approximately 5 percent of the total flows 

between the two regions. They are based on forward-looking prices, as determined 

by PJM and the NYISO’s dispatch and real-time commitment tools. CTS transactions 

are intended to improve the overall efficiency of electricity sales between the regions 

by allowing market participants to access the least-cost source of power, thus helping 

to lower the combined energy production costs of both RTOs. 

This graphic depicts the timelines of the typical hour-ahead, or non-CTS, transaction 

as well as the new CTS transaction. The major difference between the two is that the 

CTS transaction is finalized 15 minutes before the actual flow of power, which 

increases the likelihood that a transaction will be economically efficient, or flowing 

from a region with lower prices to one with higher prices. Additionally, CTS integrates 

both the bid evaluation and checkout processes, which reduces the potential for a 

transaction to be scheduled, but subsequently cancelled.

CTS transactions have been economic in the vast majority of instances, averaging 83 

percent of the time since their inception in November. By comparison, non-CTS 
trades were only economic 56 percent of the time in 2014. Staff will be monitoring 

the volumes and pricing trends of the CTS transactions over the course of this 

summer.
Slide 15

Significant Changes in 

the RTO/ISO Markets

 CAISO Energy Imbalance Market

 ISO-NE now allows hourly offers and negative 

pricing

 Full LMP markets in SPP and MISO South enter 

their second summer

Significant changes have recently been made in both the structure and operation of 

the wholesale power markets. 

The California ISO Energy Imbalance Market started in November and will be entering 

its first summer. The EIM enables entities with balancing authority areas outside of 

the CAISO to voluntarily take part in the imbalance energy portion of the CAISO realtime market, alongside participants from within the CAISO balancing area. This 

market provides services to five western states served by PacifiCorp.

This will be the first summer where ISO-NE makes use of hourly offers in its market. 

Hourly offers were initiated in December and allow resource owners to submit up to 

24 separate hourly offers for the following day, and to allow participants to update 

their offers during the operating day. Previously, resources were limited to a single 

offer for all hours of the following day, and were only provided with a single 

opportunity to revise the offer before the operating day. Additionally, resources could 

not alter their offers during the operating day. The ISO has also enabled resources to 

submit negative offers as low as -$150 per MW/hour. This is intended to improve 

price signals to resource owners to reduce output or shut down when consumer 

demand is low and there is a risk of excess generation. This should help to enhance 

reliability and efficiency during periods of system-wide stress.
The operation of MISO South, as part of the greater MISO footprint, will enter its 

second summer this year. Similarly, SPP has completed its first full-year of operating 

a full nodal market in March.

Staff will be monitoring these developments and market performance to assess any 

implications that may arise under this summer’s peak load conditions.
Slide 16

Item No. A-3

May 14, 2015

Summer 2015 

Energy Market and 

Reliability Assessment

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

Commission’s website. Thank you.