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Slide 1

Item No: A-3

March 20, 2014

2013

State of the Markets

Good morning Madam Chairman and Commissioners.

We are pleased to present the Office of Enforcement’s 2013 State of the Markets Report. The 

State of the Markets Report is staff’s annual opportunity to share our assessment on natural 

gas, electric, and other energy markets. 

This report does not necessarily reflect the view of the Commission or any Commissioner.
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Slide 2

State of the Markets

Highlights

 Spot NG and power prices rise across the U.S.

 Rising NG demand sets new record.

 Shale gas production drives NG supply to record levels. 

 RTOs and utilities adjust to changing resource mixes.

 Trading volumes of NG products on ICE fall, while electric 

trading volumes increase.

 Extreme weather pushes NG and power prices to historic 

highs in early 2014.

During 2013, natural gas spot prices rose across the U.S, driving production growth from shale 

gas plays. As a result, total U.S. natural gas supplies reached record levels. Wholesale power 

prices followed rising natural gas prices. Despite the recent spot price run-up, long-term 

natural gas futures prices fell in 2013, encouraging long-term demand growth. 

A changing generation mix led the electric sector to evaluate and begin making changes to 

address increased dependence on natural gas and the integration of renewable generation. 

Financial trading volumes for natural gas fell on the Intercontinental Exchange (ICE), while 

financial trading volumes for electricity rose. The rise in financial electric trading is related 

to a shift from over-the-counter trading to exchange-based trading.

Finally, extreme weather throughout the U.S. in early 2014 stressed natural gas and power 

markets. 
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Slide 3

Regional NG Prices Rise

Source: Derived from ICE data

NW Sumas

$3.58

63%

AECO

$3.09

30%

PG&E 

Citygate

$3.98

28%

El Paso 

Permian

$3.62

37%

CIG

$3.62

39%

Chicago

Citygate

$3.86

35%

SoCal

Border

$3.85

31%

Houston 

Ship Channel

$3.70 37%

NGPL 

TX-OKLA

$3.69

36%

Columbia

TCO

$3.73

34%

Algonquin

Citygate

$6.93

75%

Transco 

Z6 NY

$5.05

58%

Henry

Hub

$3.73

36%

FGT-Z3

$3.78

29%

Pricing Point

$ = Average 2013 Spot Price

Green = % increase from 2012

During 2013, most natural gas hubs across the U.S. traded 30 to 40 percent higher than the 

historically low prices of 2012. Regionally, the highest prices occurred in the Northeast, 

which occasionally spiked into the $20 to $30 per MMBtu range during high demand periods 

due to pipeline constraints and low liquefied natural gas (LNG) imports. 

Prices over the rest of the country generally traded within a narrow range, indicating a wellsupplied market with few pipeline constraints. The lowest prices in North America occurred 

at AECO, in Alberta, which occasionally traded below $2 per MMBtu, as Canadian gas 

producers lost market share to growing U.S. production. Sub-$2 prices also occurred in 

Appalachia, as takeaway infrastructure struggled to keep pace with growing Marcellus gas 

production.
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Slide 4

0

10

20

30

40

50

60

70

80

2005 2006 2007 2008 2009 2010 2011 2012 2013

Power Burn Residential / Commercial Industrial Other

NG Demand 

Reaches New High

Source: Derived 

from Bentek

Energy data. NG Demand (Bcfd)

The recovery in U.S. natural gas prices was demand driven. Overall demand for natural gas 

increased 2.3 percent in 2013 to 70 Bcfd, the highest on record. Colder than normal weather 

in the first quarter helped drive residential and commercial demand up 16 percent in 2013.

Industrial sector natural gas demand grew 1.8 percent, supported by new natural gasintensive industrial projects in mining, manufacturing, and petrochemicals. 

Natural gas demand from the power generation sector declined 10 percent as the increase in 

natural gas prices reduced natural gas’ competitiveness with coal as a generation fuel. Coal 

use for power generation rose almost 5 percent over 2012. 
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Slide 5

NG Supply 

Hits New Record

Source: Derived from Bentek Energy data. Note: Big 6 Shales include - Barnett, Woodford, Haynesville, Fayetteville, Eagle Ford, and Marcellus NG Supply (Bcfd)

 -

 10

 20

 30

 40

 50

 60

 70

 80

 90

2005 2006 2007 2008 2009 2010 2011 2012 2013

Big 6 Shales LNG Imports

Canadian Imports Offshore

Onshore

While demand growth drove natural gas prices up across the country, supply growth helped to 

moderate some of the price increases. Total U.S. natural gas supply, including production, 

imports via pipeline, and LNG imports, averaged 68 Bcfd in 2013, up 1.0 percent from 2012. 

Supported by relatively high prices for natural gas liquids (NGLs) and crude oil, associated 

natural gas production rose 1.9 percent to 65 Bcfd. The Marcellus and Eagle Ford Shales were 

the largest contributors to higher production. Production from the Marcellus Shale rose 44 

percent to average 12 Bcfd in 2013, while Eagle Ford production rose 36 percent to average 

4.5 Bcfd.

Growth in U.S. domestic natural gas production displaced imported natural gas. Net imports 

from Canada shrank 1.8 percent to 5.2 Bcfd. LNG imports fell to 0.3 Bcfd, a 36 percent 

decrease from 2012.
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Slide 6

Storage Falls Below 

5 Year Minimum

Source: Derived 

from EIA data. Inventories (Bcf)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

2008-12 Range 2012-2013 2013-14

Natural gas in storage was well above the 5-year average for most of the 2012/2013 winter, 

but late winter cold weather pushed inventories below the 5-year average in the spring. 

Injections into storage rebounded during late summer and early fall because of mild weather 

and moderate natural gas demand. By November, storage reached 3,800 Bcf, about 2 percent 

above the 5-year average.

In contrast to the previous three warmer than normal winters, the winter of 2013/2014 has 

been much colder than normal, resulting in record storage withdrawals. This has left storage 

inventories well below the 5-year minimum, and storage could fall to as low as 900 Bcf, a 

level not seen at the end of winter since 2003.
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Slide 7

Shale Gas Displaces 

Traditional Supplies (MMcfd)

Source: Derived from 

Bentek Energy data.

(180) (400)

+1,200

+390

+3,500

This map shows natural gas flows and production changes along generalized pipeline corridors 

from 2012 to 2013. Green arrows represent an increase from 2012 while orange arrows 

represent a decline from 2012. Circles represent increases at shale gas production areas. 

Shifts in pipeline flows across the U.S. emerged as natural gas production from shale 

displaced conventional sources. Marcellus gas located in the Northeast is a closer and often 

cheaper source of natural gas for major Northeast demand centers. The 3.5 Bcfd increase of 

Marcellus gas production displaced natural gas supplies from the Southeast, the MidContinent, and Canada. Supplies from those regions fell from around 12 Bcfd in 2008 to less 

than 6 Bcfd in 2013. In some instances, pipelines reversed physical flows to provide Marcellus 

gas to the Southeast, Canada, and the upper Midwest.

The 1.2 Bcfd increase in Eagle Ford shale production located in the Gulf Coast, led to an 

increase in pipeline flows to the Midcontinent, which primarily displaced Midcontinent 

production. This led to sub-$2 Midcontinent prices during the summer. Growing demand 

from gas-fired generation in Mexico has also absorbed some Eagle Ford gas production, with 

year-over-year exports up 8 percent.
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Slide 8

Declining Futures Drives 

Long-Term NG Demand

Source: Nymex Futures Prices ($/MMBtu)

$0

$2

$4

$6

$8

1/1/2013 12/30/2013

By the end of 2013, growth in U.S. natural gas production had lowered the long-term natural 

gas futures curve on Nymex. The long-term outlook for low cost natural gas is contributing to 

investments in natural gas-fired generation and encouraging industrial customers, including 

petrochemicals and manufacturing, to re-enter the U.S economy. Over 90 new gas-consuming 

industrial projects or expansions began operations in 2013 and almost 220 new projects or 

expansions have 2014 in-service dates.

Ample and relatively low cost natural gas is also driving two other potential sources of 

demand, natural gas exports to Mexico and LNG exports. Proposed pipelines to Mexico total 

over 4 Bcfd, which would bring total export capacity to Mexico to 9.6 Bcfd in the next few 

years. LNG exports could also add 6 to 12 Bcfd of natural gas demand by the end of the 

decade. 

All told, these new exports could add as much as 16 Bcfd to overall U.S. natural gas demand 

by 2020. The decline of the long-term futures curve shows the market expects long-term 

supply growth to more than meet the growth in long-term demand.
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Slide 9

NYISO ZJ

$61

30%

$ = Average 2013 Spot Price

Green = % increase from 2012

2013 Average On-Peak 

Electric Spot Prices ($/MWh)

Source: Derived from Platts 

NP 15

$44

40%

Palo Verde

$37

26%

Mid- Columbia

$37

66%

Minnesota 

Hub

$36

15%

SPP

$34

19%

ERCOT

$36

2%

Entergy

$33

20%

Florida

$36

5%

Southern

$35

16%

Indiana

$38

10%

NI Hub

$37

6%

SP 15

$49

42%

NYISO ZG

$58

31%

COB

$40

49%

Four Corners

$38

27% TVA

$35

7%

PJM West

$44

22%

Mass Hub

$63

54%

Electricity spot prices rose across the country in 2013, despite a slight decline in demand. 

Natural gas remained a major driver of electricity prices, with regional prices reflecting, in 

part, regional variations in natural gas prices. The largest increases were in the Northeast, 

where prices at the Mass Hub rose 54 percent, and in the West where prices at Mid-Columbia 

rose 66 percent. Constraints in natural gas supply to the Northeast during periods of extreme 

weather helped push up prices in the region. Prices in the Northwest and California reflected 

reductions in hydroelectric generation due to water supply conditions. California’s prices also 

reflected the introduction of Cap and Trade compliance.
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Slide 10

Electricity Demand Falls 

for Third Straight Year

Source: Derived 

from EIA data

0

200

400

600

800

1,000

1,200

1,400

1,600

1990 1995 2000 2005 2010

Annual Electricity Sales 

(TWh)

Residential Commercial Industrial

Nationally, electricity demand fell for the third consecutive year, dropping by 0.1 percent. 

Residential and Commercial demand rose slightly despite overall weather conditions being 

comparable in 2013 and 2012, as differences in winter and summer weather offset each 

other. Energy efficiency measures and growth in behind-the-meter generation, such as 

rooftop solar, helped moderate the growth in electricity demand at utilities. The increase in 

the residential and commercial sectors was offset by the change in industrial demand, which 

fell 3.1 percent. 
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Slide 11

-10

-5

0

5

10

15

Coal Oil NG Nuclear Wind Solar Total

Annual Net Summer 

Capacity Change (GW)

2010 2011 2012 2013

Renewable & Gas Replace 

Nuclear & Coal Capacity

Source: Derived from EIA 

data

Resource additions stemmed not from an increase in demand for electricity but from changing 

fuel economics and federal and state policies. Markets across the country are adjusting to 

the changing resource mix, addressing both a growing reliance on natural gas for electric 

generation and the integration of renewable generation. Total net generating capacity 

increased approximately 2 GW in 2013. 

Natural gas-fired generation capacity posted the largest net increase, almost 5 GW, and 

continues to constitute the largest share of electric capacity. Greater use of natural gas for 

generation increased the sensitivity of the electric sector to natural gas prices and supply 

issues. For example, New England has experienced price volatility, transportation 

disruptions, and greater use of oil-fired generation during extreme weather events, while 

California has seen strained natural gas supplies during region-wide cold spells. 

Retirements of aging nuclear and coal plants reached almost 3 and 4 GW, respectively. Some 

RTOs have looked to interim measures to keep generators running until transmission or 

generation alternatives can be developed.

Utility-scale solar resource additions were up over 3 GW and set a new record. Wind 

generation additions, while down from 2012, added more than 1 GW of nameplate capacity. 

Markets across the country are evaluating and taking steps to address their changing resource 

mix, particularly growing use of natural gas and renewable resources. Examples include New 

England, where the ISO developed a winter reliability program to bolster fuel oil inventories 

at power plants, and California, where the ISO proposed market changes to encourage 

renewables to respond to price signals and ensure that sufficient ramp capability is available.
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Slide 12

0

1

2

3

4

5

6

7

2009 2010 2011 2012 2013

NYISO PJM ISO-NE No Activations

Source: Derived from 

RTO data

DR Activations 

Increase in 2013

Days

Northeast RTOs called upon their emergency demand response programs for a combined total 

of 13 days in 2013, more than in any of the last five years, underscoring the resource value of 

demand response during periods of tight supply conditions. 

The amount of demand response offered and cleared fell in RTO auctions held in 2013 for 

capacity to be delivered in upcoming periods, reversing a multi-year trend. In PJM and ISONE, cleared demand response capacity fell by approximately 2,400 MW and 900 MW in their 

respective markets. In NYISO, rule changes implemented to improve the accuracy and 

responsiveness of demand response resources were followed by 550 MW less eligible demand 

response resources clearing the New York capacity auction.
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Slide 13

RTOs Expand Borders

Source: Derived from 

Energy Velocity data Source: Derived from 

Energy Velocity

Market participants continue to see value from Regional Transmission Organizations. In 2013, 

MISO expanded to the Gulf of Mexico as Entergy, Cleco Corporation and other utilities joined 

its market. Entergy expects its customers to see benefits of $1.4 billion over the first 

decade, while MISO estimated that other Midwest region members will see a similar benefit. 

The East Kentucky Power Cooperative became part of PJM and CAISO expanded outside 

California when Nevada’s Valley Electric Association joined the ISO. 
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Slide 14

NG Trading Volumes 

Decline

Source: Derived from ICE data.

Note: Does not include block trades

Financial Trading 

Volumes (Bcf/Month)

Physical Trading 

Volumes (Bcf/Month)

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Financial (left axis) Physical (right axis)

Natural gas financial and physical trading volumes declined in 2013, with financial volumes on 

ICE falling 14 percent, similar to the decline of financial products on the Chicago Mercantile 

Exchange. Physical trading volumes on ICE dropped 30 percent. Financial volumes continue 

to significantly outweigh physical volumes, and were 36 times larger in 2013. The decline in 

traded volumes coincided with falling trader profitability due to relatively stable natural gas 

prices in 2013. 
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Slide 15

Source: Derived from ICE data

Electric Financial Trading 

Volumes Increase

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

2012 2013

MWh (Millions)

SW

NYISO

MISO

ISO-NE

NW

CAISO

PJM

Reported electric financial trading volumes on ICE rose 19 percent from 2012 to 2013, led by 

longer-term transactions. Trades with duration between two months and one year increased 

44 percent overall. 

In October 2012, ICE converted cleared energy swaps to futures to address regulatory 

requirements raised by the Dodd-Frank Act. One of the goals of the Dodd-Frank Act is to 

facilitate increased transparency in the markets. The 2013 increase in trading volume 

reflects this improved transparency as transactions previously conducted bilaterally are now 

cleared on exchanges such as ICE. 

During 2013, 92 percent of the financial trading of U.S. electricity products outside ERCOT 

took place at an RTO hub, up from 90 percent in 2012. Most regions in the country 

experienced increased financial trading volumes compared with 2012. PJM’s financial 

products continue to be the most traded on ICE, with 68 percent of the total financial trades 

involving a PJM product, up from 63 percent of 2012.
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Slide 16

Extreme Weather Stressed 

Natural Gas and Electricity 

Markets in 2014  Record cold temperatures during January resulted in 

record gas demand, well freeze-offs, large storage 

withdrawals, and constrained pipelines.

 In the mid-Atlantic and Northeast, spot natural gas 

prices soared to over $120 per MMBtu.

 On-peak power prices spiked to over $1,000 per MWh. 

 Staff monitored the winter events as they occurred and 

continues to assess what happened in the markets and 

whether market manipulation potentially took place.

In recent years, natural gas and electricity markets have benefitted from growing natural gas 

supply and mild weather. The winter of 2014 illustrates how extreme weather can still stress 

natural gas and electricity markets.

In January 2014, U.S natural gas demand set a new daily record of 137 Bcfd. Well freeze-offs, 

record storage withdrawals, and high pipeline utilization led spot natural gas prices at the 

Henry Hub to jump to a January high of $5.70 per MMBtu. In the mid-Atlantic and Northeast, 

spot natural gas prices soared to over $120 per MMBtu at key trading points. RTO on-peak 

prices spiked to greater than $800 per MWh in Boston and Chicago and greater than $1,000 

per MWh in Eastern PJM. Some non-firm customers faced challenges in obtaining natural gas 

and others were voluntarily curtailed. Although markets were stressed, there were no 

widespread natural gas or power outages because of a lack of fuel supply. The Commission 

recently announced that it will hold a technical conference on April 1 to explore the impacts 

of recent cold weather events on the Regional Transmission Organizations and Independent 

System Operators, and discuss actions taken to respond to those impacts. 

The Office of Enforcement’s market oversight and surveillance functions routinely monitor 

both wholesale natural gas and electric markets and their results. Staff monitored this 

winter’s extreme weather events as they unfolded and is looking closely at the developments 

surrounding them. Enforcement staff followed up on screen trips from its algorithmic 

surveillance screens with data requests and phone interviews with numerous market 

participants, including generators, gas suppliers, and ISO staff to determine if market 

manipulation potentially took place. To date, staff has not uncovered any activity it believes 

to be manipulative. However, staff’s work in this regard is ongoing and OE will report to the 

Commission when its inquiries are completed.
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Slide 17

Item No: A-3

March 20, 2014

2013 State of the Markets 

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

Commission’s website. We are available to answer any questions you may have.