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Winter 2012 Winter 2012-13 

Energy Market Assessment Energy Market Assessment

Item No. A-3

November 15, 2012 November 15, 2012

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Seasonal Outlook Seasonal Outlook

 Outlook for the winter season

• Low gas and power prices 

• Stable gas production 

• Inventories approach last year’s record

 Regional Assessment

• New England

Good morning Mr. Chairman and Commissioners. Today we are pleased to present the Office of 

Enforcement’s Winter 2012-2013 Energy Market Assessment. The Winter Assessment is staff’s 

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

At this point, conditions going into the winter appear favorable. Current natural gas prices and 

winter forwards are the lowest we have seen in ten years. The U.S. natural gas market is well 

supplied, with production at almost forty-year highs and inventories approaching last year’s 

record. This should help keep natural gas prices relatively low into the winter assuming normal 

winter weather, and also help moderate electric prices. Low natural gas prices for most of 2012 

resulted in high usage of natural gas to generate electricity, and staff expects power burn to 

remain high into the winter. High power burn, coupled with high seasonal natural gas demand 

from residential and commercial customers, could lead to higher than usual winter peak demand. 

This may in turn cause congestion on some pipelines in the Northeast which could lead to higher 

than expected prices.

In this year’s Winter Assessment we will take a slightly different approach from past formats by 

expanding our assessment to the New England market, which could see elevated prices if we 

experience a colder than normal winter or extended cold spells. 

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Highly Uncertain Highly Uncertain 

Weather Forecast Weather Forecast

Source: National Weather 

Service forecast as of Oct 

18th.

Equal 

chances 

for A, B

Above

Below 

EC =

A =

B =

A

A

B

EC

EC

EC

In the last month, the National Weather Service (NWS) temperature outlook for the coming winter 

changed dramatically. Previous forecasts indicated there was a high likelihood of above normal 

temperatures in the Northeast, from Maine to Tennessee and northwest to Montana and normal to 

below normal temperatures in the South. This was typical of an El Nino winter forecast. A key 

variable in predicting winter weather is the occurrence of an El Nino - a warming of the water in 

the Pacific Ocean that generally brings wet winter weather to the south and warmer than normal 

temperatures to the northern tier of the country. However, over the last month, Pacific Ocean 

water temperatures have cooled considerably leading NWS forecasters to discount completely the 

possibility of an El Nino this winter. One result is the likelihood of colder weather in the 

Northeast. Another forecaster, Accuweather, calls for a wetter and possibly snowy winter for the 

Eastern Seaboard based on a weak to non-existent El Nino. In fact, the first winter storm hit the 

Northeast last week, bringing cold weather and snow and gas prices in New England doubled to 

nearly $8/MMBtu. This followed Hurricane Sandy, which knocked out power to millions of 

customers in the Northeast and damaged local distribution gas lines on the New Jersey shore.

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Sumas

$2.72

$4.26

-36%

SoCal

$2.74

$4.70

-42%

PG&E

$2.79

$4.15

-33%

CIG

$2.81

$4.21

-33%

Henry

$2.64

$4.13

-36%

Chicago

$3.09

$4.90

-37% TCO

$3.38

$5.13

-34%

TZ6 NY

$2.66

$4.22

-37%

FGT Z3

$2.85

$4.75

-40%

El Paso

$2.99

$4.33

-31%

2012 YTD

2011 YTD

% change from 2011

Source: Derived from ICE data through October 31st.

Low Regional Spot Low Regional Spot 

Natural Gas Prices Natural Gas Prices

HSC

$2.54

$3.92

-35%

Algonquin

$2.47

$3.92

-35%

This slide shows that year-to-date, natural gas prices throughout the U.S. are nearly half what 

they were in 2011. Through the end of October, the Henry Hub natural gas price averaged 

$2.64/MMBtu, 36% lower than last year. The decline can be attributed to plentiful natural gas 

supply, high storage levels, and last year’s mild winter. Inflation adjusted natural gas prices 

haven’t been this low since the early 1990’s, when natural gas prices were deregulated. During 

much of 2012, regional gas prices traded in a tight range of $2/MMBtu in the Gulf Coast and the 

Rockies to $3.50/MMBtu in the Northeast. The highest prices are in New England, New York, and 

Florida due to growing natural gas demand and pipeline bottlenecks. The San Onofre nuclear 

outage in Southern California has resulted in the dispatch of more natural gas-fired generation 

and has elevated prices in the region. Staff expects regional gas prices to remain in this tight 

range through the winter, although there could be occasional regional price spikes due to cold 

weather events or pipeline outages. 

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Forward Prices Forward Prices 

Decline Across U.S. Decline Across U.S.

Location 2013 ^ 2012*

Massachusetts Hub $67.08 $73.25

PJM Western Hub $47.88 $55.25

Northwest (Mid C) $35.25 $33.10

Southern California (SP‐15) $43.43 $37.65

Transco Zone 6 NY $6.59 $8.96

Mid‐Atlantic (Columbia TCO) $3.78 $4.19

Southern California Border $3.88 $4.11

Henry Hub $3.77 $4.13

P

o

w

e

r

G

a

s

Source: Derived from ICE data 

through October 1st.

Note: Units for Power are 

$/MWh and units for Gas are 

$/MMBtu

^January and February 2013

*January and February 2012

This table shows forward power and gas prices for key regional markets. Regional forward gas 

prices are the sum of the Henry Hub forward price plus the forward basis. Basis is a measure of 

regional price differences. Forward prices are a tool for consumers and producers to lock in 

winter prices to hedge against price volatility. They do not forecast winter spot prices and in 

general are not a good predictor of actual winter prices. 

Based on forward prices from October 1, 2012, a marketer could lock in a price at the Henry Hub 

for January and February at a 10-year low of $3.77/MMBtu, 10% below the forward strip this time 

last year. Consumers in the Northeast can lock in much lower natural gas prices than last year. 

As of October, the winter forward basis was only $2.82/MMBtu in New York, nearly half of last 

year’s values. Record storage and continued growth in Marcellus shale gas production contributed 

to the decline. This means that total forward prices in New York declined from $8.96/MMBtu last 

winter to $6.59/MMBtu for the upcoming winter.

Similarly, forward power prices for the winter are generally lower compared to last year. The 

Massachusetts Hub is 8% below last year’s price, while PJM forwards are down 13%. The decline in 

power prices closely resembles the decline in natural gas prices because natural gas is typically 

the marginal, or the price setting fuel in these regions. In contrast, power forwards in the 

Northwest are 6% higher than last year due to lower than normal hydropower conditions and 

higher natural gas forward prices. In Southern California, the San Onofre nuclear plant outage has 

contributed to the rise in forward power prices there. 

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Total U.S. Natural Total U.S. Natural 

Gas Supply Increases Gas Supply Increases 

Supply (Bcfd) 2012 YTD 2011 YTD % Change

Dry Production 63.5 61.1 4%

Net LNG Send Out 0.40 0.80 ‐53%

Net Canadian Imports 5.40 5.70 ‐5%

Total Supply 69.30 67.60 3%

Storage Inventories (Tcf) 3.93 3.82 3%

Source: Derived from Bentek and EIA data through November 8th.

This slide shows U.S. natural gas supply, including production, imports, and the amount of natural 

gas in storage as of November 8th. Overall supply is up almost 3%, driven by a 4% increase in 

production. Most of the growth was in the Northeast, which grew by 3.1 Bcfd, or 63%, driven by 

strong growth in Marcellus shale gas production. However, the rate of growth in the rest of the 

country has slowed and dry natural gas production appears to have leveled off at around 63.5 Bcfd

in 2012, but still the highest production since the early 1970s. Shale gas now accounts for at least 

34% of total U.S. natural gas production, up from 23% in 2010. 

Offsetting some of the increase in production, LNG imports are down 53% over 2011, while imports 

from Canada are down about 5%. US LNG imports continue to decline as US natural gas prices are 

well below world gas prices. For example, natural gas in the UK is four times more expensive than 

Henry Hub. Imports from Canada are down because Canadian gas is less competitive than new 

Marcellus gas in the Northeast and other shale and Rockies gas in Midwestern markets. 

Storage is an important component of winter natural gas supply, and storage levels indicate the 

ability of the industry to meet peak winter demands. As of November 8th, 2012, U.S. working gas 

in storage set a new record at 3.92 Tcf. Storage withdrawals can contribute as much as 32% of 

U.S. gas supply on a peak winter day. The highest weekly storage withdrawal ever reported by 

the EIA is 274 Bcf (an average of 39 Bcfd), while the highest total U.S demand seen in a given 

winter day is 121 Bcf.

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Power Burn Drives Power Burn Drives 

U.S. Natural Gas U.S. Natural Gas 

Consumption Higher Consumption Higher

Demand (Bcfd) 2012 YTD 2011 YTD % Change

Power Burn 26.00 21.40 22%

Industrial 18.10 18.10 0%

Residential/Commercial 19.30 22.20 ‐13%

Total Demand* 66.90 64.80 3%

Source: Derived from Bentek data though November 8th. *Includes pipeline loss

This slide shows the major components of U.S. natural gas demand. Year to date natural gas 

demand is up 2.1 Bcfd, nearly offsetting the increased supply mentioned earlier. This is a result 

of a 22% increase in natural gas burned by power generators primarily because of low prices. 

Residential and commercial demand is down 13% due to last year’s warm winter. Weather will be 

a main driver of natural gas demand this winter, and we will see a recovery in residential and 

commercial natural gas demand if there is a normal winter. 

I will now turn to Ryan Jett who will discuss the New England region.

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Source: Energy Velocity

Canadian

Supply & LNG

Canadian

Supply

U.S. Supply

NE Pipeline Constraints NE Pipeline Constraints 

Algonquin Pipeline

Tennessee Pipeline

Maritimes & Northeast Pipeline

Iroquois Pipeline

Cromwell Compressor Station

Canaport

LNG

Everett LNG

Deep Panuke

& Sable Island

As you are aware, FERC recently conducted a series of gas-electric coordination technical 

conferences, and staff is working on next steps for the Commission to consider. One of the 

regions highlighted in the conferences of particular concern was New England. Accordingly, we 

will focus on this market on the next two slides. 

This map highlights New England natural gas supply options and pipeline constraint points. 

NOAA’s current seasonal weather forecast for New England is highly uncertain. In the event of a 

colder than normal winter, or extended cold spells, New England could experience some 

tightening of supply. In particular, New England could see high winter power burn, which adds to 

winter peak demand from the non-power sectors. Combined with the likelihood of lower LNG 

imports compared to last year and high utilization of pipelines bringing Gulf Coast and Marcellus 

supply into the region, this could lead to price spikes. 

Last winter, LNG imports contributed to 17% of total New England natural gas supply, and 

historically contributed 60% during peak winter days. New England has access to three LNG 

import facilities, two offshore and one in Boston harbor. The Neptune and Northeast Gateway 

terminals, located offshore Boston, are unlikely to see deliveries this winter because of low 

natural gas prices. These offshore LNG terminals were specifically put into service to help 

alleviate problems associated with regional pipeline capacity constraints. Imports into the third 

LNG terminal, Everett in Boston harbor, are down 30% year-to-date. However, Everett’s operator 

expects to see adequate cargoes through the winter because they have long term supply 

contracts. This should ensure that the Mystic power plant units 8 and 9 receive enough gas to run 

throughout the winter, although sendout into the surrounding gas market may be less than 

previous years. 

Continued on Next Page

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Continued from Previous Page

Another issue facing the region this winter is the steep decline in imports of LNG from the 

Canaport LNG terminal, down 49% from last year due to low U.S. gas prices compared to Europe 

and Asia. Also production from the Sable Island Offshore Energy Project is down 55% from last 

year. Production at Sable Island has been on the decline for several years and now supplies only 

80 MMcfd on average into New England compared to 300 MMcfd in 2008. An additional source of 

supply could be the Deep Panuke Offshore Energy Project if it meets its scheduled in-service date 

of December 2012. Initially Deep Panuke is projected to sendout 150-200 MMcfd before ramping 

up to its full capacity of 300 MMcfd. However, Deep Panuke has already missed two scheduled inservice deadlines over the years, which introduces some uncertainty to the December in-service 

date. 

In addition, the Northeast is a region with pronounced dual summer-winter peaks in electricity 

consumption, with the rise of winter peaks increasing total winter gas demand. These issues 

could contribute to increased spot gas prices in the region in the event of a colder than normal 

winter or extended cold spells. 

On the next slide we will discuss the impact pipeline constraints could have in New England on 

supply and spot natural gas prices.

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NE Pipeline NE Pipeline 

Constraints Constraints 

+23%

2008 2009 2010 2011 2012 Source: 

Bentek

Energy

High utilization of pipelines into New England during winter can cause price volatility at regional 

trading hubs. Historically, when pipeline gas flows spike due to cold weather, the result has been 

that regional spot prices spike between $12-$14/MMBtu over the Henry Hub. Constraints can 

occur on both the Tennessee Gas Pipeline near Boston and along the Algonquin Transmission 

System. As an example, the graphic highlights flows versus peak design capacity through the 

Cromwell compressor station, one of the constraints along Algonquin located in central 

Connecticut. The red line is the peak day design capacity. The blue line represents the daily 

natural gas flows. The yellow line is the trend line showing that average flows have increased 

since late 2009. From the graphic you can see that the level of natural gas flows has grown over 

the past two years and last year, despite the very warm winter, gas flows frequently bumped up 

against capacity. 

Constraints like this could result in price spikes for the system given that we have seen a 7% 

growth in demand from power generators in 2012. If we have a cold winter in New England, 

residential and commercial demand will increase along with power demand potentially causing 

instances where there is a sustained flow above peak design capacity. This may result in regional 

price volatility and tightness in supply, with a possibility of interruption to pipeline customers 

with interruptible service. The most vulnerable pipeline customers are power plants with 

interruptible contracts. However, many of these plants could switch to backup fuel supplies if 

needed. All indications are that LDCs have adequate firm transportation capacity to meet their 

expected needs. Also, although imports of Canadian gas from western Canada are down 

substantially this year, they could ramp up if needed.

Continued on Next Page

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Continued from Previous Page

New England could experience some tightness and high prices in the event of extended cold 

periods. However, at the gas-electric coordination technical conferences pipelines and their 

customers stated that they are aware of the challenges facing the market and have begun to take 

some steps to improve reliability, for example stocking up on backup fuel and opening up 

communications between pipelines and their power customers. 

This concludes the Winter 2012-2013 Energy Market Assessment, we are happy to answer any 

questions.

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