Slide 1

Winter 2016-17

Energy Market Assessment

Item No. A-3 

October 20, 2016
Slide 2

Markets Cautiously 

Optimistic Nearing Winter  Natural gas and power prices are likely to be higher than last winter

 Normal to above average temperatures are expected

 Normal residential and commercial natural gas demand are expected, 

but lower power burn

 Falling production offset by plentiful storage with potential for imports 

from Canada

 New pipelines will reduce regional price differences

 New England and Southern California present challenges

 Renewables are changing California ramping requirements

 Entrants are small to mid-size generators and renewable projects, which 

are accompanied by new transmission projects

 Electric generation mix is changing 

Good morning Mr. Chairman and Commissioners. This presentation is the Office of 

Enforcement’s 2016-2017 Winter Energy Market Assessment. The Winter Assessment is staff’s 

opportunity to look ahead to the coming winter and share our thoughts and expectations 

about market preparedness, including an assessment of risks. Natural gas and power markets 

are well supplied going into the winter, with plentiful storage, a better-connected pipeline 

system, and the ability to draw greater imports from Canada through pipelines and higher 

imports of LNG into New England. However, U.S. natural gas production is down slightly from 

last year, and prices are likely to be moderately higher than last winter. Most forecasters 

expect winter temperatures across the Northern U.S. to be average, while most sectors of the 

gas market should see strong demand relative to last year’s record warm winter. There are 

challenges though, specifically in regional markets like New England and California, where 

operational issues could create some regionalized gas and power risk.
Slide 3

*January - February 2017

^January - February 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. 

Source: Derived from NYMEX and IntercontinentalExchange

P

o

w

e

r

G

a

s

Location 2016^ 2017* Δ

Algonquin (New England) $9.69 $7.71 -20%

Transco Zone 6 non-NY (Mid-Atlantic) $6.21 $6.26 +1%

Chicago City-Gates $2.62 $3.84 +47%

Transco Zone 6 NY (New York City) $9.29 $8.95 -4%

Dominion South (Marcellus) $1.97 $2.14 +9%

Southern California Border $2.85 $3.79 +33%

Henry Hub $2.77 $3.55 +28%

Massachussets Hub $89.28 $78.93 -12% 

PJM Western Hub $50.56 $55.80 +10%

Northwest (Mid-C) $24.88 $32.05 +29%

Southern California (SP-15) $33.76 $41.18 +22%

Futures Prices Higher

This slide shows natural gas and power prices at key trading hubs around the country. Going 

into the winter, natural gas prices are likely to be higher than last year. A warm summer and 

a small drop in natural gas production resulted in natural gas prices at the Henry Hub 

increasing from below $2.00/MMBtu in May to more than $3.00/MMBtu in October. An 

increase in the futures curves for both power and natural gas mirrors cash markets, with 

many points above year-ago levels and the strongest gains in the Midwest and West Coast 

markets. The table shows futures prices for power and natural gas at key regional markets 

for January and February 2017 and compares them to the previous winter futures. In 

Southern California, natural gas futures for SoCal Border for January and February are on 

average 33% higher than in early 2016, while SP-15 power prices rose 22%. The exception to 

these increases is in New England, where winter basis for both gas and power is down from 

2016, due in part to new gas pipeline capacity that will allow more supply to flow into the 

market area. New York City prices are unchanged, as pipeline constraints into the city keep 

it the highest priced natural gas market in the U.S. 
Slide 4

Forecasters 

Call for Broadly 

Normal Winter 

Temperatures

Source: National Oceanic and Atmospheric Administration 

The weather outlook for this winter differs greatly from the warmer-than-normal summer, 

which boosted demand for natural gas, particularly by power generators. While seasonal 

weather forecasts taken months in advance can only give a broad explanation of potential 

patterns, NOAA is calling for a transition into La Nina conditions with normal temperatures 

throughout the Upper Midwest, New England, and Mid-Atlantic. NOAA models show broadly 

above average temperatures in the Gulf Coast and most of the Southwest, where weather 

conditions are expected to show a greater deviation above the median. In another prediction, 

AccuWeather is calling for a snowy, but warmer winter in the Northeast, with cooler 

temperatures in the Plains and warm, dry weather in the Southeast and Southwest. 
Slide 5

Gas Demand Likely to 

Rebound in 2016-17

Sources: Derived 

from Bentek, EIA

-4

-2

0

2

4

6

ResComm LNG Exports Industrial

Bcfd Exports To Mexico Power Generation

This slide shows expected changes in natural gas demand by major consuming sectors for the 

coming winter versus 2015-2016. Total U.S. natural gas demand could rise by more than 5 

Bcfd from last winter, which was exceptionally mild. With normal winter temperatures 

forecasted for the Upper Midwest and Northeast, most analysts expect the residential and 

commercial sector to show the largest change in demand, adding between 5 and 6 Bcfd 

relative to last year. This would return residential and commercial demand to more typical 

winter levels, or slightly above the 5-year average. Industrial gas demand, which is also 

sensitive to weather, could add about 1 Bcfd this winter, year-over-year. Natural gas exports 

were a growth story in 2016 and will remain so into the winter. Exports to Mexico on 

pipelines from the U.S. and to international markets in the form of LNG, combined, could 

increase by more than 1.9 Bcfd this winter in comparison to last winter. The only sector 

likely to see a decrease in demand is in power generation, which could fall nearly 2 Bcfd from 

last winter, as higher natural gas prices make other generation fuels more economical, 

especially during times of large natural gas price spikes.
Slide 6

Demand Response on Higher 

LNG and Mexico Exports

Sources: Derived 

from Bentek, EIA

As noted previously, U.S. exports have played a significant role in natural gas demand growth 

in 2016. The opening of the border-crossing NET Mexico Pipeline, as well as the expansion of 

several pipelines on the Mexican side, has enabled more export volumes from Texas, New 

Mexico, and Arizona. Flows from the U.S. to Mexico topped 4 Bcfd on several days this 

summer, marking an all-time high. This will fall back slightly during the winter in a typical 

seasonal drop due to lower Mexican power generation. LNG exports also emerged as a 

demand side driver in 2016 with the commissioning and commercial startup of Cheniere’s 

Sabine Pass terminal in Louisiana. Since February, the company has exported more than 30 

cargoes from the terminal for a cumulative volume of more than 110 Bcf. So far, the export 

volumes have had little measurable impact on gas prices and we do not expect a significant 

impact this winter.
Slide 7

Production Sees First 

Decline of Shale Era

Sources: Derived 

from Bentek, EIA

This slide shows year-to-year changes in U.S. natural gas production for the past five years. 

2016 is the first year since the beginning of large-scale shale gas production to show a yearover-year decline. Lower gas and oil prices resulted in a 0.2 Bcfd decline in U.S. gas 

production for the first 9 months of 2016. This compares with a 4 Bcfd incremental gain 

during the same period of 2015. Changes in production vary by region. Appalachian Basin gas 

production—including output from the Marcellus and Utica shale plays— rose by nearly 3 Bcfd 

from 2015 levels, but losses in other regions offset those gains. Texas, with a 2.4 Bcfd drop 

year-over-year, saw the largest decline, while the Rockies, Midcontinent, and Louisiana also 

saw sizeable losses. This inevitable and necessary rebalancing of natural gas supply and 

demand in response to low prices has not impeded the ability of gas to get to markets. The 

expansion of the pipeline network has improved connections between supply basins and 

demand areas, particularly in Appalachia, which could enable producers to bring hundreds of 

drilled but uncompleted wells online this winter in Pennsylvania, Ohio, and West Virginia. 

This, among other factors, could lead to a recovery in production in the final months of 2016 

and into 2017. Analysts expect the increase to continue going forward after the brief pause 

in production growth.
Slide 8

Strong Storage Inventories 

Keep Market Well Supplied

Sources: 

Derived from 

Bentek, EIA

0

1

2

3

4

5

2010-2011 2011-2012 2012-2013 2013-2014 2014-2015 2015-2016 2016-2017

Start Season (Nov) End Season (Mar)

Tcf

This slide shows U.S. natural gas storage balances for the past six years, with a forecast for 

the coming winter. Gas storage levels have remained above the five-year average throughout 

the summer after beginning the traditional refill season at record high levels at the end of 

last winter. As of October 7, storage sits at 3.76 Tcf, about 200 Bcf greater than the 5-year 

average and nearly 60 Bcf higher than at this time in 2015. Consequently, the market is likely 

to remain well supplied throughout this winter. 
Slide 9

Canada and LNG Imports 

Fill in Supply Gaps

Sources: 

Derived from 

Bentek, EIA

Winter

Though natural gas imports to the U.S. from Canada have generally been declining in recent 

years, cross-border flows are up year-to-date and should see year-over-year gains this winter. 

Output from Canadian fields is on pace to average more than 15 Bcfd in 2016, the highest 

annual average level since 2008. A high level of pipeline connectivity between Canada and 

the U.S. provides adequate potential to tap into this supply if conditions warrant. 

Additionally, LNG terminals along the East Coast received 19 cargoes last winter comprising 

more than 37 Bcf, with 17 of those shipments supplying the Everett and Northeast Gateway 

facilities serving New England. With global LNG prices significantly lower than in previous 

years, more spot cargoes could find their way to U.S. terminals should the need arise and 

prices allow.
Slide 10

Pipeline Additions Help 

Ease Market Area Prices

Sources: Derived from 

Velocity Suite, ABB 

Enterprise Software and 

Bentek, in MMcfd

New pipeline capacity in and around the Appalachian Basin has allowed growing production to 

better reach markets. This slide shows pipeline capacity additions scheduled this winter. 

Roughly 6 Bcfd of new transport capacity was added to the region since early 2015, and 

another 2 Bcfd of new transport capacity will be added before the start of 2017, with much of 

that focused on carrying Marcellus gas to market areas. The pipeline expansions and 

additions include Spectra’s Algonquin Incremental Market, which will add about 350 MMcfd of 

new transport capacity into the greater Boston and Massachusetts market. The added 

capacity should help mitigate the worst price spikes. New England natural gas prices have 

routinely reached winter peaks above $30/MMBtu and during the 2014 polar vortex soared to 

nearly $90/MMBtu. While those price levels may recur under extreme circumstances, staff 

estimates that on average the new transport capacity will lower New England basis 

significantly this winter. Under normal winter conditions, prices at Algonquin city-gates could 

be as much as $4 to $5/MMBtu less than they would be under the same conditions without the 

pipeline additions.
Slide 11

NYC has Nation’s Highest

Winter Gas Prices ($/Mmbtu)

Source: Derived from 

IntercontinentalExchange

Futures markets are signaling expectations that New York City will have the highest natural 

gas prices in the country this winter. Peaking in January, basis futures for Transcontinental 

Gas Pipe Line Zone 6 - New York neared $9.00/MMBtu in trading October 12. Futures for 

Algonquin City-Gates in the greater Boston area are trading at a discount of more than $1.00 

to New York City prices, while futures for Transco Non-New York, which covers an area 

between Virginia and New Jersey, are over $2.50 less than the New York price. Supply area 

prices in the Appalachian Basin are significantly lower than the market area, trading between 

$6 and $7 lower than New York at TCO and Dominion South, respectively. These basis futures 

reflect current market sentiment for prices over an average of the month, though prices on 

peak winter days could be considerably higher. 
Slide 12

Aliso Canyon Outage 

Stresses California Markets

As the Commission knows, one area that may face challenges outside the Northeast is 

Southern California. As discussed in a recent technical conference, the leak and subsequent 

closure of the Aliso Canyon natural gas storage field has created operational challenges for 

gas and power markets in the Southern California market. Aliso Canyon is vital to power 

generators in the LA Basin, which will have to pull more supply from interconnecting regional 

pipelines as testing and inspection of Aliso Canyon’s 114 wells continues. As of October 7, 

state regulators have approved 27 wells to continue service, while taking 78 out of operation, 

limiting injection and withdrawal capability. SoCalGas’ total inventory sits at 61.7 Bcf as of 

October 11, a significant reduction from the 122 Bcf in storage at this point last year. Low 

storage levels leave the region susceptible to upstream supply issues like freeze-offs or major 

pipeline operation problems. State regulators have said the prices in the region should be 

stable without additional capability from Aliso Canyon given normal winter conditions, but 

may face up to a 1 Bcfd shortage if winter weather reaches extremes, potentially causing 

price dislocations. 
Slide 13

CAISO: Adapting to the 

Widening “Duck” Curve

Sources: Derived 

from Velocity Suite, 

ABB Enterprise 

Software 

Barring extreme weather conditions, California officials have concluded that Aliso Canyon’s 

reduced capacity should not compromise Southern California's electric reliability in the 

coming winter. Moreover, CAISO should be able to re-dispatch generation off Southern 

California Gas Company’s system if gas supply becomes constrained during the winter; 

however, the Los Angeles Department of Water and Power has less flexibility to re-dispatch 

generation. Given the uncertainty of weather and system conditions, conservation and other 

mitigation measures are expected to help meet winter electricity needs. Nonetheless, 

Southern California may face additional challenges, especially during evening ramps. 

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

demand but also in the pattern during the day. 

CAISO experiences two pronounced demand ramps during the winter months, one in the 

morning and one in the evening. This graph shows how CAISO’s “duck” curve has changed 

between January 2011 and January 2016. The “duck” curve is widening, indicating that 

renewable generation serves more load during the middle of the day, but natural gas-fired 

generation is increasingly called upon to ramp up output in the afternoon and evening as solar 

generation declines and load increases. CAISO’s widening “duck” curve is in part due to 

increased solar generation. 
Slide 14

Recent/Upcoming Developments: 

Power Plants & Transmission

Sources: Data derived from U.S. Electric Transmission Projects ©2016 The C Three Group LLC and map created using 

Velocity Suite, ABB Enterprise Software; Note: Winter 2016-2017 Expected In-Service Transmission Projects

Number of Expected 

Transmission Projects 

120kV+ October 2016-Feb 2017

>12

9-12

5-8

<5

Looking ahead, on the power generation side we continue to see a shift away from large 

centralized power plants. The majority of new entrants expected to come on-line between 

now and February 2017 are primarily small to mid-size generators, which are less than 400 

MW, and renewable projects. These generators will make-up nearly 90 percent of the new 

generating capacity expected to become available and renewables will account for nearly 80 

percent of new generating capacity over that time frame. Ensuring that the electricity 

generated by these new plants can be delivered to where it is needed requires a 

comprehensive transmission planning process. This map shows various regions by number of 

proposed new transmission projects. In the darkest shaded region you will see that there are 

more than 20 high voltage transmission line projects expected to be completed in MISO 

between now and February 2017. Many of these projects will serve areas that have been 

identified by staff as having persistent price divergences, and may help to alleviate those 

divergences.

In terms of upcoming generator retirements, the Fort Calhoun nuclear power plant in 

Nebraska is the only major announced nuclear plant retirement this winter. However, 

significant price impacts are not anticipated from its closure as two previously retired units 

are being brought back into service and one that was scheduled for retirement is no longer 

being retired. 
Slide 15

Historical Year-over-year 

Electric Capacity Change

Source: Derived from 

Velocity Suite, ABB 

Enterprise Software

This chart shows the annual change in electric generation capacity since 2010 for ISO-NE, 

NYISO, and PJM. It illustrates a decrease in overall generation capacity of nearly 7,500 MW 

from 2014 to 2015. The chart also highlights the decrease in coal-fired generating capacity 

and the increasing importance of natural gas for electricity generation. 

This change in the resource mix can pose challenges for winter operations, especially in ISONE, where approximately 44% of generation capacity is now gas-fired and disruptions in gas 

supply and pipeline capability can occur due to the configuration of the system. Historically, 

ISO-NE has been able to rely on coal and oil-fired power plants in the winter when residential 

and commercial demand peaks. However, coal accounts for a relatively small amount, 

approximately 6 percent, of ISO-NE’s system capacity. To help maintain reliability with its 

changing resource mix, ISO-NE has implemented a Winter Reliability Program that is designed 

to prevent overreliance on natural gas-fired generators, as well as to implement other 

proactive measures during the winter months. The Winter Reliability Program provides 

incentives for three types of resources: oil and dual-fuel generators to increase oil 

inventories, LNG to augment natural-gas-fired generators’ pipeline gas, and demand 

response. 

More broadly, residential gas customers served by local utilities have priority on the pipeline 

system to meet heating needs during the winter. The high demand for natural gas during 

periods of extreme cold weather over a large portion of the country can reduce the 

availability of natural gas for generation plants. NYISO and PJM experience winter problems 

similar to ISO-NE. In NYISO, nearly 50 percent of capacity is natural gas-fired and NYISO’s 

demand response programs, which reduce energy use at peak times, can be activated to help 

support regional reliability and manage demand during the winter months. 
In PJM, natural gas accounts for more than 30 percent of generating capacity. PJM continues 

to build on the gas-electric coordination efforts established after the 2014 Polar Vortex. 

Also, this winter will be the first year that PJM’s new capacity performance market design 

will be in effect. For the delivery year that began June 1, 60 percent of all resources that 

cleared are capacity performance resources that must be available when called on during 

times of system stress or else they must pay significant penalties that may equal or exceed 

capacity revenues.
Slide 16

Conclusion

 Supply and demand are balancing in the natural gas market

 Prices in both power and natural gas have responded to 

rebalancing, but remain relatively low

 New pipeline connections have strengthened deliverability

 Gas storage leaves markets well supplied for winter

 The Northeast and Southern California may experience localized 

challenges 

 Increased renewable generation requires flexible resources for 

evening ramp in CAISO

 Transmission projects may help to relieve price divergences

 Natural gas for electricity generation continues to increase

In summation, the outlook for winter is cautiously optimistic, with markets well supplied for 

the coming season. Normal to above average temperatures are expected and should lessen 

possible gas delivery constraints. New infrastructure, in terms of pipelines and transmission 

lines, will transport gas and electricity to alleviate price differences and mitigate spikes. 

Staff will continue to monitor developments within the electric and natural gas markets, with 

particular attention paid to the issues at Aliso Canyon and in the Northeast.

This concludes the 2016-2017 Winter Energy Market Assessment.

We are happy to answer any questions you may have.
Slide 17

Winter 2016-17

Energy Market Assessment

Item No. A-3 

October 20, 2016