Slide 1

Item No. A-3

October 15, 2015

2015-16 Winter

Energy Market Assessment
Slide 2

Market Overview

Stable signals

• Low NG & electric prices 

• Abundant NG production 

& storage

• Moderate weather in 

Midwest, Northwest & 

Northeast

• Robust fuel stockpiles—

heating & generation

Challenges

• Low NG and oil rig 

counts

• Cold weather in South

• Potential demand 

increases from NG 

industrial & LNG exports

• New England price 

volatility

Good morning Mr. Chairman and Commissioners. This is the Office of Enforcement’s 2015-16 

Winter Energy Market Assessment. The Winter Assessment is staff’s opportunity to share our 

thoughts and market expectations for the upcoming winter season.

Natural gas and electric spot and futures prices are lower than last year, consistent with 

expectations that energy markets are well positioned to manage potential challenges this 

winter. The U.S. natural gas market is well supplied, with ample production and storage. 

Record breaking production continues despite lower rig counts, increased exports, and the 

collapse of oil prices. New natural gas pipeline expansions and projects to reverse flows on 

some pipelines will also provide more transportation capacity from producing to market areas 

this winter, though no capacity additions have been made in New England. 

Winter weather forecasts indicate cooler than normal temperatures in the South, moderate 

weather in the Midwest, Pacific Northwest, and Northeast and uncertain temperatures in the 

Midcontinent and Mid-Atlantic. Temperate conditions in the Midwest and Northeast should 

help depress total residential and commercial natural gas demand during the winter, although 

LNG exports and industrial facilities could add to total demand as operations begin.

Electricity prices also increasingly track natural gas markets as gas-fired generation increases. 

In addition, increased integration of renewables can cause price volatility, particularly in the 

Western markets.
Slide 3

Source: Derived from ICE and 

Nymex data as of Oct.1

*January and February 2016 

^January and February 2015

*SP-15 2016

*Power Note: Prices in 

$/MWh. Peak financial swap 

prices.

*Gas Note: Prices in $/MMBtu. Regional futures natural gas 

prices are the sum of the 

Henry Hub futures contract 

price plus the regional basis 

futures. 

P

o

w

e

r

G

a

s

Location 2015^ 2016* Δ

Algonquin (bew England) $21.45 $9.69 -55%

Transco Zone 6 non-bY (aid-Atlantic) $9.09 $6.21 -32%

Transco Zone 6 bY (bew York /ity) $12.82 $9.29 -28%

5ominion South (aarcellus) $2.51 $1.97 -21%

Southern /alifornia .order $4.30 $2.85 -34%

Ienry Iub $4.08 $2.77 -32%

aassachussets Iub $183.88 $89.28 -51% 

tWa Western Iub $72.60 $50.56 -30%

borthwest (aid-/) $37.73 $24.88 -34%

Southern /alifornia (St-15) $46.13 $33.76 -27%

Futures Prices Decline

Spot and futures prices generally reflect market expectations for a relatively well-supplied 

winter. Spot natural gas prices traded in a tight range and remained relatively low 

throughout the summer. At times, prices in New York and New England traded under 

$2/MMBtu, well below the U.S. benchmark at the Henry Hub. 

In addition, futures prices for this winter are trading several dollars less than last year. The 

cost to hedge natural gas in Northeast market areas is around $10/MMBtu. In New England, 

traders seem to be factoring in the likelihood of LNG cargoes mitigating price spikes in the 

region. Consequently, Algonquin futures are trading at half the price of last year. Elsewhere, 

natural gas futures prices in Southern California and at the Henry Hub are more than 

$1/MMBtu below last year’s prices.

Power futures prices have followed natural gas futures downward, reflecting the growing 

reliance of power generation on natural gas. Traders are likely recognizing the ample supply 

of natural gas expected for the coming winter as well as the expanded natural gas pipeline 

delivery system.
Slide 4

Source: NOAA National Weather Service

Winter Temps 

Warmer in 

North & Cooler 

in South

As always, weather is one of the primary and least predictable drivers for natural gas and 

electricity markets. A strengthening El Niño in the tropical Pacific could bring warmer than 

normal weather to most Northern states and relatively wet and stormy weather to the 

Southern half of the U.S. NOAA’s 3-month outlook for December 2015 through February 2016 

is consistent with this pattern. It shows a higher probability of warm weather in the 

Northeast, Midwest, and Pacific Northwest, and colder weather in the Gulf and Southeast. 

NOAA predicts an equal chance for cold or warm weather in the Mid-Atlantic, Midcontinent, 

and Southwest. Based on NOAA data, some analysts project this winter to be 7 percent 

warmer than last year and 3 percent warmer than the 30-year average. Most commercial 

forecasting services also expect the U.S. to have a warmer than usual winter, with some 

projecting the highest probability for warm weather in December. 
Slide 5

Source: EIA data & staff analysis

Natural Gas Storage Poised To 

Set a Record Entering Winter

0

1

2

3

4

Apr aay Wun Wul Aug Sep Oct Nov Dec Wan Feb aar

Storage Inventories (Tcf)

5 Year Inventory Range

Year to Date Inventory

Iigh Inventory Scenario

Low Inventory Scenario

Storage inventories began this year’s injection season below the 5-year average. However, 

storage refilled quickly throughout the spring and summer, as strong production growth 

outpaced demand. As a result, natural gas inventories may reach 4 Tcf by the end of the 

injection season, which would be a record level. Inventories are robust in all regions, and we 

expect the EIA producing region to set a new all-time high by the end of the month, while the 

East and West regions should be near previous records. In addition, Canadian storage is 

approaching the 5-year average, and imports can quickly respond to meet high winter demand 

in the U.S.

This graphic shows potential withdrawal rates based on two historic scenarios from the past 

five years. The red dotted line shows storage inventory withdrawals based on the cold 

weather events of winter 2013-14, and indicates that similar withdrawals this winter would 

still leave storage within the 5-year range. The green dotted line shows the lowest 

withdrawal rates in the last 5 years, similar to winter 2011-12, indicating that storage could 

remain above the 5-year range. 

Finally, deliverability, scarcity, and record price spikes during the 2013-14 cold weather 

events have largely been addressed for other heating and electric generating fuels, indicating 

strong market preparation for the upcoming winter season. Propane storage at the wholesale 

level is filled far above the 5-year range. Coal stockpiles and deliveries are also at or above 

normal due to improved rail deliveries, as well as capital improvements to railroad tracks and 

locomotives.
Slide 6

Source: EIA data & staff analysis

Winter NG Demand Projections 

Lower than Previous Winters

0

20

40

60

80

100

120

Sep-13

Nov-13

Wan-14

aar-14

aay-14

Wul-14

Sep-14

Nov-14

Wan-15

aar-15

aay-15

Wul-15

Sep-15

Nov-15

Wan-16

aar-16

U.S. Natural Das Demand by Sector 

(Bcfd)

wesidential

Commercial

Electric tower

Lndustrial

trojected

This graphic shows U.S. monthly natural gas demand by sector from September 2013 and 

forecasted demand through April 2016. It shows that peak demand during the previous two 

winters was similar and unusually high. Given average weather and demand patterns, total 

natural gas demand should be lower than the previous two winters. 

Warmer-than-usual temperatures in the Midwest and Northeast should further mitigate peak 

demand from the residential and commercial sectors. In New England, 34 Bcf of liquified 

natural gas imports from Everett and Canaport helped moderate natural gas price spikes in 

the region last winter. With global LNG prices currently below $8/MMbtu, we expect that 

New England will be able to attract LNG cargoes again this winter. We do not expect the 

predicted cold weather in the South to significantly increase demand. 

Power burn continues to rise as coal plants retire and natural gas becomes more price 

competitive for electric generators. During April and July of 2015, monthly natural gas power 

burn surpassed coal-fired generation for the first time at the national level. As the graphic 

shows, power burn peaked this past summer, but should level out through the coming winter. 

Industrial natural gas demand could also increase by 500 MMcfd by year’s end because of new 

industrial facilities.

Internationally, natural gas imports from Canada will continue to help meet peak U.S. winter 

demand. However, ISO-NE has expressed concerns over operational issues at the Deep 

Panuke offshore facility. In contrast, pipeline capacity and exports to Mexico have increased, 
though because Mexican demand is largely summer peaking, the new infrastructure is not 

expected to add upward price pressure during the winter months. In addition, we understand 

that Cheniere Energy expects its LNG export facility at Sabine Pass, Louisiana to begin full 

operation of 750 MMcfd of contracted exports towards winter’s end. We will monitor these 

develoments closely to see if the added facilities have a market impact. 
Slide 7

Natural Gas Production 

Sets Record

Source: Bentek Energy

0

10

20

30

40

50

60

70

80

Jan-10

Jul-10

Jan-11

Jul-11

Jan-12

Jul-12

Jan-13

Jul-13

Jan-14

Jul-14

Jan-15

Jul-15

U.S. Natural Gas troduction (Bcfd)

aarcellus

Utica

Eagle Ford

Williston

termian

Niobrara

Fayetteville

Barnett

Haynesville

Conventional & Other

The U.S. natural gas market should be well supplied by producers this winter. Gains early in 

the year helped total production set a new year-to-date record at 72 Bcfd, up 4 percent. 

Higher output is the result of: increased drilling efficiencies; improving completion 

technologies and practices; decreased drilling costs; a move by producers to focus drilling in 

high output areas; producers locking in last year’s higher prices through hedging; and bringing 

uncompleted wells into production. Growth in the Marcellus and Utica Shales in Appalachia, 

and the Eagle Ford and Permian basins in Texas, have helped compensate for falling 

production in the Gulf of Mexico and conventional plays. New pipelines serving Northeast 

producing areas have unlocked trapped production, though output growth continues to 

outpace takeaway capacity in the region. 

However, EIA data show that natural gas production growth began to slow this past summer, 

and other data sources show it has even declined in some key producing basins. Year-overyear, natural gas prices have fallen 37 percent, while oil prices—which drive oil-associated 

natural gas production—have fallen 49 percent. Producers have reacted, bringing oil and 

natural gas rig counts to their lowest levels since 2009. Despite these negative indicators, 

spot and winter futures prices are low due to record production, robust storage, and low 

expected seasonal demand.
Slide 8

Source: Staff analysis

Pipeline Projects 

Connect New 

Production to 

Markets

Natural Gas pipeline 

capacity additions in 

2014 & 2015 (Bcfd)

2.0 1.6

Growing Northeast natural gas production and new pipeline takeaway capacity continue to 

reshape the nation’s flow patterns and prices. Since the start of 2014, 9 Bcfd of capacity 

additions have come online to further link production with markets in the Mid-Atlantic, the 

Southeast, and the Midwest. As a result, the Northeast corner of the nation became a net 

exporter of natural gas for the first time this summer. 

Northeast production will also increasingly reach Midwest markets. Rockies Express has 

added 1.2 Bcfd of capacity through its East-to-West reversal project, while Texas Eastern has 

added 550 MMcfd through the OPEN project and 425 MMcfd through the Uniontown-to-Gas City 

expansion project. By the end of 2015, additional projects along Columbia Gas Transmission, 

Transco, and Tennessee will provide another 2 Bcfd of capacity to market from Northeast 

production areas. Furthermore, over 25 Bcfd of additional pipeline capacity by 2018 has been 

either approved by or filed with FERC.
Slide 9

Winter Natural Gas Prices 

Converge in Northeast 

Source: Staff analysis

*Regional composites 

are averages of January 

and February prices. $0

$2

$4

$6

$8

$10

$12

$14

$16

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Composite trice ($/aa.tu)

 bortheast aarket Area

 Appalachian troduction Area

trojected

This graphic shows a composite price of the Mid-Atlantic, New York, and New England regions 

and a composite price of the Appalachian production region during the months of January and 

February through 2020. These averages do not capture day-to-day market volatility, though 

they do demonstrate current trends. Pipeline bottlenecks from increased production have 

caused price divergence between these two regions in recent years. However, capacity 

expansions detailed in the previous slide are helping erode peak winter spreads, as shown 

here. Staff analysis shows that the spread is poised to decline between Appalachian 

producing area prices—primarily the Marcellus Shale—and Mid-Atlantic and Northeast market 

area prices. Our models show that the spread could be more than halved since last year. 

Further convergence of producer and consumer prices should narrow the spread to under $2 

by winter 2016-17 and to under $1 in the following winters. 
Slide 10

RTO/ISO Winter 

Preparations

 Gas electric coordination

 Seasonal modeling assessments

 Adequate reserve margins with load pockets

 Winterization testing

 Situational awareness

In last month’s Commission meeting, most RTOs generally expressed confidence in their 

abilities to achieve reliable winter operations. However, ISO-NE and NYISO were more 

cautious. To ensure reliability, a number of efforts have occurred and are ongoing. 

Categories of efforts include: seasonal reliability assessments, gas electric coordination, 

winterization testing, and improved situational awareness. 

RTOs continue their efforts to improve gas electric coordination following Order 787. ISO-NE 

has developed a gas usage tool, CAISO provides gas burn forecasts to pipelines for feasibility 

analysis, and PJM has a new memorandum of understanding with gas pipelines to further gas 

electric coordination. Fuel inventory surveys have also become the norm, allowing RTOs to 

better realize, incorporate, and prepare for potential fuel shortages before the winter begins. 

Seasonal modeling assessments and winterization testing is also common. Seasonal 

assessments often form the baseline for winter preparedness efforts. These assessments 

remain ongoing and have identified reserve margins in excess of targets. At the individual 

generator level, many RTOs are working with plants, running workshops to target peaker 

facilities that ensure readiness for cold temperatures.

RTOs have also increased situational awareness and understanding of natural gas market 

fundamentals. Maps highlighting natural gas pipelines that overlay electric transmission maps 

exist in many RTOs, including NYISO, ISO-NE, and SPP. These maps help system operators 

plan for fuel restrictions on their system when making dispatch decisions. More generally, 
RTOs and particularly CAISO, have learned more about natural gas system outages and the 

domino effects on the electric grid.
Slide 11

CAISO Winter Ramp

Source: Derived 

from CAISO data 

via Ventyx

18000

20000

22000

24000

26000

28000

30000

32000

3 6 9 12 15 18 21 24 3 6 9 12 15 18 21 24

December January

Net Load (MW)

Iour 9nding

CALSO Winter Average bet Load

2011/12 2012/13 2013/14 2014/15

Demand in winter months differs from other seasons, not only in the amount of demand but 

also in the pattern during the day. MISO, SPP, ISO-NE, and CAISO, for example, experience 

two demand ramps during the winter months, one in the morning and one in the evening as 

customers turn on their lights. The evening ramp is especially notable during the December 

holiday period. These large changes in load can present challenges to power operators.

In California, significant amounts of solar generation compound this effect. Utility-scale solar 

capacity has grown to 6,912 MW as CAISO added 598 MW so far in 2015, and behind-the-meter 

solar has reached an estimated 3,000 MW. This is a particular challenge in the winter when 

the sun sets well before the evening peak load. The winter 3-hour ramp requirement climbed 

to a maximum of 9,131 MW in winter 2014-15, from 6,247 MW in 2011-12, and this winter 

could be the highest ever on the CAISO system. This ramp requires other generators to be 

online and available as needed. 

Renewable generation remains insensitive to market prices and is not dispatchable in CAISO. 

Together, the need for gas-fired generation and the lack of dispatchable renewable 

generation increases the likelihood of price volatility and possible over or under generation 

conditions.

This increased power ramp creates a natural gas ramp as power plants pull natural gas from 

pipelines to fuel their output. In the winter of 2013 – 2014, CAISO and Southern California 

Gas encountered problems serving generator natural gas demand, at least in part because 
SoCal Gas lacked adequate tools to deal with low pressure situations. SoCal filed with the 

California Public Utilities Commission (CPUC) for a low operational flow order (OFO) program 

similar to that in the northern part of the state. The CPUC granted the request, but it is 

unclear whether the OFO will be operable this winter.

CAISO and SoCal Gas discovered further areas for coordination this past summer. Maintenance 

on SoCal’s system, combined with a record natural gas generation dispatch in the LA Basin, 

led SoCal to notify CAISO that it could not serve all the power plant demand. CAISO’s 

dispatch resulted from significantly lowered imports and cloud cover that reduced solar 

output. Overcast conditions, which are common during winter months, can reduce solar 

output and can increase the amount of natural gas required by generators, as well as add to 

operational uncertainties. 
Slide 12

ISO-NE Relies on Winter 

Fuel Diversity

Source: Derived 

from Ventyx data

Nuclear 

31%

Oil 

10%

Coal 13%

Das 35%

Iydro 

2%

Wind 2% Renewables 6%

Wan-Feb 2015

Nuclear 

34%

Oil 0%

Coal 2%

Das 50%

Iydro 4%

Wind 2%

Wul - Dec '14 & aar - Wun '15

Renewables 7%

In early September, the Commission approved a three year extension to the ISO-NE’s Winter 

Reliability Program. The Program is designed to prevent overreliance on natural gas-fired 

generators, as well as to implement other proactive measures during the winter months. The 

three year term is intended as a bridge to the initiation of the Pay-for-Performance, capacity 

market reform. Once Pay-for-Performance has been implemented, ISO-NE believes that the 

winter reliability program will no longer be needed.

These pie charts show how much the ISO has relied on coal and oil-fired power plants in 

winter. They contributed 6 percent of all the energy produced in New England last year, but 

when demand peaks and when natural gas-fired generators cannot get fuel, they are crucial 

for reliability. During last winter’s extreme cold weather, they contributed 24 percent of the 

energy in January and 18 percent in February. 

The Winter Reliability Program provides incentives for three types of resources: oil and dualfuel generators to increase oil inventories, LNG to augment natural-gas-fired generators’ 

pipeline gas, and demand response. The program includes compensation for up to ten days of 

oil supply at full load per generator, 6 Bcf of LNG, and 100 MW of demand 

response. Additionally, last year, six units representing about 1,700 MW decided to take 

advantage of incentives for generators to add dual fuel capability.

Over the past two winters, the program cost approximately $75 and $46 million, respectively. 

It is forecasted to cost between $36 and $66 million, each year going forward, depending on 
factors such as the amount of unused oil at the end of the winter, actual fuel prices, and the 

number of hours when demand response is called.

In addition to the Winter Reliability Program, the ISO has initiated several other measures 

over the past year to increase operator flexibility and provide incentives to market 

participants to enhance reliability. Participants now have the flexibility to adjust their supply 

offers in the day-ahead and real-time markets and to make negative offers as low as -

$150/MWh. Additionally, the reserve constraint penalty factor levels were increased to 

better reflect scarcity and incent participation during shortage conditions.

Even with these initiatives, however, ISO-NE reports that the loss of any major non-gas unit or 

significant disruptions in gas supply and pipeline capability will create major challenges for 

ISO operations.
Slide 13

 SPP Expanded Membership with 

Integrated Systems

 NV Energy may join EIM

 NYISO increased reserve requirements 

and scarcity prices

 SPP-MISO improve interregional 

coordination

Power Market Developments

The Southwest Power Pool added the Western Area Power Administration’s Upper Great Plains 

region in Billings, Montana, the Basin Electric Power Cooperative in Bismarck, N.D., and the 

Heartland Consumers Power District in Madison, S.D., collectively known as the Integrated 

System, to its operations on October 1, 2015. This is the first time a federal power marketing 

administration has joined an RTO. 

The integration added more than 5,000 MW of peak demand and 9,500 miles of transmission 

infrastructure, expanding SPP to 14 states. The Integrated System will increase SPP’s 

generating capacity by about 10 percent, about a third of which will come from hydro 

generation. The greater fuel diversity and increased infrastructure should enhance SPP’s 

ability to serve customers and help manage price volatility. 

CAISO expects to add its second participant, NV Energy, to its Energy Imbalance Market this 

winter, and to make changes in its market operations. NV Energy integrates with the 

southern part of CAISO’s system, expanding the market into the Southwest. 

RTOs have made other market changes that should improve market performance this winter. 

For example, NYISO increased its Total Operating Reserve Requirement from 1965 MW to 2620 

MW and will implement Enhanced Reserve Shortage curves on November 1. Further, MISO and 

SPP have established market-to-market coordination protocols to improve market efficiency 

across their seams.
Slide 14

Item No. A-3

October 15, 2015

Winter 2015-16 

Energy Market Assessment

This concludes the 2015-2016 Winter Energy Market Assessment. 

We are happy to answer any questions you may have.