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Slide 1

Item No. A-3

October 16, 2014

Winter 2014-15 

Energy Market Assessment
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Slide 2

Developments

• Record natural gas production

• Increased natural gas-electric 

coordination

• Enhanced reliability measures

Challenges

• Winter futures prices up 

substantially in some regions

• Below average natural gas 

storage

• Lower coal stockpiles

• Regional pipeline restrictions

• Increased reliance on natural gas 

for electricity

Markets Cautious as 

Winter Approaches

Good morning Chairman and Commissioners. This presentation is the Office of Enforcement’s 

Winter 2014-2015 Energy Market Assessment. The Winter Assessment is staff’s opportunity to 

look ahead to the coming season and share our thoughts and expectations. 

Conditions going into the winter are mixed for natural gas and electricity markets. The U.S. 

natural gas market is amply supplied, with production continuing to break records. Following 

last winter’s polar vortex, natural gas pipelines, electric utilities, Regional Transmission 

Organizations and Independent System Operators, as well as the Commission have taken a 

number of measures to improve system reliability, which are the focus of the next 

presentation. However, challenges remain. While current spot market natural gas prices are 

in the $4.00/MMBtu range over most of the country, winter futures are significantly higher. 

Natural gas storage is below average and coal stockpiles are lower than usual. Although new 

pipeline capacity has been added since last winter, there are still restrictions in New England. 

In some regions, there is an increased reliance on natural gas for electricity generation. 
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Slide 3

Source: Derived from ICE data.

Note: Prices through September 30, 2014. 

Higher 

Natural Gas 

Prices Across 

Most of the 

Country Pricing Point

BOLD – 30 Day Average Price

Green – % increase from previous year

Red – % decrease from previous year

$3.93

5

$3.63

84

$3.77

16

$4.46

12

$4.10

8

$2.98

-23

$3.91

7

$3.75

6

$3.90

6

TCO

$3.82

6

$2.34

-38

$3.74

9

Algonquin

AECO 

Chicago

TZ6-NY

NGPL

Midcon

El Paso

SoCal 

PG&E

CIG

Sumas

HSC

$3.90

14

Henry 

Hub $3.91

5

FGT-Z3

$3.96

5

TZ5

This slide shows natural gas prices around the country as of September 30, 2014. Natural gas 

prices across most of the U.S. are between 15 and 30% higher than last September, primarily 

as a result of lower storage inventories. The exception is the Northeast. Basis at Algonquin 

Citygates, a Boston area pricing point, and the Transco Zone 6 New York City pricing point 

have been negative to Henry Hub since April of this year. Negative basis was driven by 38% 

annual growth in Northeast production and low natural gas demand due to the mild summer. 

The Division of Energy Market Oversight (DEMO) does not expect low prices in the Northeast 

to continue into the winter.

The highest natural gas prices in the country are currently in California, reflecting high 

natural gas demand over the summer from strong power generation consumption. During the 

summer, prices in California reached above $5/MMBtu, and averaged $4.76/MMBtu at PG&E 

Citygate and $4.39/MMBtu at SoCal Border. Due to drought conditions resulting in less output 

from hydro plants and warmer-than-normal temperatures, natural gas storage in the West 

remains at the bottom of the five-year average exerting additional upward pressure on the 

prices in the region. 
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Slide 4

Source: NOAA National Weather Service

Uncertain 

Winter 

Forecast

As always, weather is the key wildcard going into the winter and is the main driver of natural 

gas demand and prices. Most forecasters give a low probability of a repeat of the cold winter 

of 2013-14. However, they believe that a colder than normal winter is a risk, particularly as a 

weak El Nino develops. 

This map shows NOAA’s outlook for the coming winter. December, January, and February 

have elevated odds of warmer-than-normal temperatures across the Northwest part of the 

country, warmer-than-normal temperatures in the upper Midwest and New England, and 

colder-than-normal for the Gulf Coast states. The forecast for the middle part of the country 

and much of the Northeast is particularly uncertain with equal chances of colder-than, or 

warmer-than-normal seasonal mean temperatures.

The Commodity Weather Group expects a weak El Nino winter, with colder-than-normal 

temperatures in the East and South, but not as cold as last year. Another weather forecaster, 

MDA EarthSat, shows colder-than-normal temperatures for the Upper Midwest, Midcontinent, 

Southeast, and Mid-Atlantic this winter and warmer-than-normal temperatures for Northern 

Nevada and Eastern Oregon. MDA forecasts normal temperatures for the rest of the country, 

including the Northeast. They expect January and February to be colder-than-normal, but to 

fall well short of last year’s extremely cold temperatures. The Old Farmer’s Almanac 

forecasts a cold winter for the eastern two thirds of the country, with wet conditions in the 

Northeast, Midwest, and Southwest. Mild temperatures are forecasted for the West.
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Slide 5

Mid-Atlantic* Gas Demand at 

Historical High Levels

Source: Derived from GPCM data. 

*Mid-Atlantic also 

includes KY and OH

ResComm

PowerBurn

Industrial

Other

Seasonal 

Normal

 -

 5.0

 10.0

 15.0

 20.0

 25.0

 30.0

Bcfd

Winter 13/14

max: 25.7 Bcfd

Winter 14/15

max: 26.3 Bcfd

This slide shows natural gas demand for the Mid-Atlantic, including Ohio and Kentucky, since 

the winter of 2012. It also includes a forecast through the next three winters and the historic 

seasonal norm. The next slide will show a similar forecast for New England. 

Last winter’s persistent cold drove total U.S. natural gas consumption 15% higher than the 

prior winter, reaching an all-time peak of 137 Bcfd on January 7. Mid-Atlantic natural gas 

demand averaged nearly 26 Bcfd last January, which resulted in the highest natural gas prices 

in the country.

DEMO analyzed the Mid-Atlantic natural gas market under conditions similar to last winter to 

explore the market implications of colder-than-normal conditions for the upcoming winter. 

Under these conditions, natural gas demand in the Mid-Atlantic peaks at 26.3 Bcfd in January 

2015. This is slightly higher than last January due to natural gas demand increase from the 

power sector. Under normal winter temperatures, January 2015 natural gas demand peaks at 

around 23 Bcfd.

The impact of high winter demand on prices may not be as severe as last year however, as 

new pipeline capacity in the Northeast should alleviate some bottlenecks within the Marcellus 

producing region and the New York market area. The additional pipeline capacity could 

reduce pipeline utilization into New York from peaking at nearly 100% of capacity last winter 

to around 60% during the coming winter.
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Slide 6

Fuel Diversity Helps New 

England Gas Demand

Source: Derived from GPCM data. 

ResComm

PowerBurn

Industrial

Seasonal 

Normal

This slide shows monthly natural gas demand for New England since the winter of 2012, with a 

forecast through the next three winters and the historic seasonal norm. Last winter New 

England avoided significant spikes in natural gas demand, despite high residential and 

commercial demand. Various other sources of generation including oil and coal, plus power 

imports, helped reduce natural gas demand from New England power generators by 20%. This 

in turn reduced total natural gas demand to around the same level as the prior three warm 

winters of about 3.4 Bcfd. This winter natural gas-fired plants will have to make-up for 

generation lost from the retirement of some non-gas-fired units. 

With no new pipeline capacity planned until 2016, the region will need to rely on fuel 

diversity to meet the region’s energy needs. 
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Slide 7

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

U.S Storage Levels (Tcf)

FORECAST

Source: Derived from EIA data and GPCM data.

Storage Levels:

Production Area

West Storage

East Storage

5-yr Avg. 

Record Storage Injections Help 

Close the Storage Shortfall 

This graph shows that U.S. natural gas storage remains below the five-year average and is 

trailing the last two injection seasons. During last winter’s extreme cold, the gap between 

natural gas supply and demand was supplemented by record storage withdrawals, leaving U.S. 

natural gas storage at an 11-year low, about 1 Tcf below the five-year average. However, 

record natural gas production coupled with the mild summer helped refill storage levels at 

above-average injection rates. Most forecasters expect storage inventories to recover to 

around 3.5 Tcf in early November, below the five-year average. Assuming a colder-thannormal winter in the Northeast and normal winter weather elsewhere, storage withdrawals 

would average around 74 Bcf per week with storage levels entering the 2015 refill season at 

about 1.8 Tcf, 1 Tcf higher than last spring.
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Slide 8

Source: Derived from staff analysis.

2014 Pipeline Expansions 

Target Northeast Production

Construction

Online

NY PA OH IL IN MS KY LA

Northeast Midwest Southeast

Destination

1.4

1.2

1.0

0.8

0.6

0.4

0.2

0

Bcfd

Nearly 4.3 Bcfd of new pipeline capacity is scheduled to come online by the start of the 

winter. Most of this capacity is producer-sponsored to move natural gas out of the Marcellus 

and Utica Shales and into the regions shown on this slide. The majority of proposed and 

planned pipeline infrastructure for the next several years is targeting areas outside of the 

Northeast to serve the upper Midwest, Mid-Atlantic, and Southeast markets. Only a few 

expansions are planned for the New England market.

Much of the natural gas pipeline capacity scheduled to go online in 2014 still remains under 

construction through at least November. DEMO expects about 1.1 Bcfd of pipeline capacity 

will begin operation by this winter to serve the New York market and 1.5 Bcfd will address 

production area constraints in Pennsylvania and Ohio. By the end of 2014, the Midwest 

markets will have gained access to cheaper Marcellus and Utica supplies with the addition of 

425 MMcfd of pipeline capacity. 

The Transco Rockaway Delivery Project will enable Transco to deliver an additional 647 

MMcfd into the New York City distribution system, which is fully contracted by local 

distribution companies. The project will work directly with Transco’s 100-MMcfd Northeast 

Connector Project adding capacity from the mainline at Station 195 near the PennsylvaniaMaryland border to delivery points at Long Island. This could help alleviate some price spikes 

as experienced during the polar vortex last winter in the Mid-Atlantic and New York markets. 

That said, the additional capacity planned to increase access to Northeast production does 

little to alleviate localized New England constraints. 
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Slide 9

 Volatility in electricity prices in the 

Northeast from increased dependence on 

natural gas

 California may face electricity supply 

issues, such as increased ramp 

requirements

Winter Electric Market 

Challenges

Gas-fired generation in New England has grown from approximately 44% of capacity in 2013 to 

47% in 2014 as two large non-natural gas plants that supplied the region last year retire. The 

increased dependence on natural gas in New England should tend to increase the volatility 

and overall price of power in the region. 

California may face supply and market issues as it relies more on natural gas-fired generation 

this winter and faces increased evening ramps. Gas-fired generation will replace hydrogeneration lost because of the drought and import declines of 1000 to 3100 MW because of 

maintenance occurring on the Pacific DC Intertie transmission line. Higher solar generation 

will increase the evening ramp required of natural gas generation and fast-start units will 

increase the rate of draw from gas pipelines. Southern California enters the winter with gas 

storage levels 15% below last year and generators continue to face the risk of gas supply 

disruptions. Under current tariff provisions, Southern California LDCs normal winter 

operations allow shippers to bring in only 50% of their gas needs over a five-day period. 

However, twice last winter, gas users, including power plants, took more gas off the system 

than they delivered, causing pipeline pressures to fall to critical levels. As a result, LDCs 

called their first ever Emergency Standby Curtailments. When emergency curtailments occur, 

shippers are required to bring in supplies to meet 90% of their daily use for the period the 

emergency is in effect. The LDCs filed with the California Public Utilities Commission for 

authority to implement operational flow orders that allow them to call for additional gas 

supplies earlier and on a more gradual scale, thereby reducing the likelihood of pipeline 

pressures dropping to critical levels. While the LDCs requested a January 1, 2015 adoption 
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date, it is unclear whether these proposed tariff changes will be approved or implemented in 

time for the coming winter.
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Slide 10

Coal Stockpiles Decline

Source: Derived from Velocity Suite, based on EIA data.

0

10

20

30

40

50

60

70

80

90

Jan-10

Jun-10

Nov-10

Apr -11

Sep-11

Feb-12

Jul-12

Dec-12

May-13

Oct-13

Mar-14

Million Tons

PRB

Central App

Other

Illinois

Basin

Power plant coal stockpiles stood at 132.9 million tons at the end of June. That is 16% below 

the 10-year average and 22% below last year. This represents approximately 56 days of coal 

consumption. Industry estimates put the supply at the end of September at approximately 

111 million tons, or 47 days. The continued decline has been attributed to lower target 

inventory rates in some regions and continued deliverability issues that are most acute with 

Powder River Basin (PRB) coal. Separately, there have been declines in Southeast stockpiles 

as generation is converted away from more expensive Central Appalachian coal to cheaper 

natural gas. 

The declines in PRB coal stockpiles began in the summer of 2013 and were further drawn 

down last winter. Lingering effects of the 2013-2014 winter have continued to stress the rail 

transportation system as well as a combination of factors that include ongoing rail 

maintenance, rail crew shortages and competition for rail transport from consumer goods, 

strong agricultural production and the transport of oil from the Bakken Shale region of North 

Dakota. Replenishment of coal stockpiles at some power plants captive to a single supply 

source and transportation route has proven more challenging on the more constrained rail 

system. Rail deliveries are predicted to improve in 2015 and 2016. 

Through industry outreach, staff has learned that certain coal-fired generators have 

experienced reduced coal deliveries due to smaller train unit sizes and increased times 

between shipments. To mitigate these issues, some generators have begun implementing 

coal conservation measures and considered changing their offer parameters.
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With deliverability issues expected to continue into 2015, staff will monitor coal stockpiles at 

affected plants, especially with regard to any potential effects next summer. 
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Slide 11

Source: Derived from ICE 

and Nymex data.

^January and February 

2015 as of October 1 

2014

*January and February 

2014 as of October 1 2013

*SP-15 2014 prices from October 31 2013

*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^ 2014*

Algonquin (New England) $21.45 $11.76

Transco Zone 6 non-NY (Mid-Atlantic) $9.09 $4.78

Dominion South (Marcellus) $2.85 $3.66

Southern California Border $4.30 $3.95

Henry Hub $4.08 $3.87

Massachussets Hub $183.88 $99.88

PJM Western Hub $72.60 $44.90

Northwest (Mid-C) $37.73 $35.75

Southern California (SP-15) $46.13 $42.25

Futures Prices Elevated

This table shows that futures markets are largely consistent with the winter assessment. The 

futures prices are the average of January and February 2015 contracts for power and natural 

gas at key regional markets as of October 1, 2014. Futures prices are not a predictor of 

actual winter prices, but do indicate the cost to producers and consumers to hedge prices.

Generally, winter futures prices are elevated compared to last October. Markets have 

incorporated the risk of a reoccurrence of last winter’s polar vortex events plus greater 

tightness in the market due to low natural gas storage. Natural gas futures in New England 

are 82% higher than last October, averaging around $21/MMBtu. Futures at Transco Zone 6 

non-NY, representing the Mid-Atlantic region, are $9/MMBtu, almost double from last winter. 

Transco Zone 6 non-NY experienced the highest natural gas and power prices in the nation 

last winter. Average natural gas futures at Henry Hub for January and February are only 5% 

above the futures strip this time last year, averaging $4/MMBtu. The Gulf Coast region 

experienced some of the lowest prices last winter. 

The impact of higher natural gas futures prices is most apparent in New England, where 

winter electricity futures prices have increased by 84% to $184/MWh. The higher electricity 

prices reflect the increased cost of natural gas in New England this winter and are consistent 

with the historical relationship between the pricing of gas and power within the region. 

Similarly, prices at the PJM Western Hub are 62% higher than last year at $73/MWh. Changes 

are more moderate in the West, which has greater access to natural gas pipelines. The Mid-
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Columbia trading hub increased from $36 to $38/MWh this winter, while the SP-15 trading hub 

increased 9% to $46/MWh.
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Slide 12

 Market Rule Changes

 Improve communication between natural gas 

pipelines and electric transmission operators

 Increased winterization and testing for 

generators

Actions in Response 

to Last Winter

Natural gas pipelines, electric utilities, RTOs, ISOs, and the Commission have taken a number 

of steps to address the challenges posed by extreme and prolonged cold weather last winter, 

some of which are noted on this slide. The next presentation will focus in more detail on 

actions by the Commission and the industry to address issues that arose last winter and plan 

ahead for this coming winter. 
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Slide 13

Item No. A-3

October 16, 2014

Winter 2014-15 

Energy Market Assessment

This concludes the Winter 2014-2015 Energy Market Assessment. 

We are happy to answer any questions you may have.