FEDERAL ENERGY REGULATORY COMMISSION

888 First Street, N.E. Washington, D.C. 

2012 State of the Markets Report

OFFICE OF ENFORCEMENT

Division of Energy Market Oversight

2012
FEDERAL ENERGY REGULATORY COMMISSION

www.ferc.gov/oversight

i

State of the Markets Report

2012

Table of Contents

Figures................................................................................................................................................................................. ii

Tables ................................................................................................................................................................................. iii

Executive Summary and Overview.......................................................................................................................................... 1

Chapter 1: Market Developments.......................................................................................................................................... 9

 Summary............................................................................................................................................................................. 9

 Natural Gas Increasingly Displaced Coal for Electricity Generation..................................................................10

 New England Faces Seasonal Supply and Pipeline Constraints..........................................................................13

 Record Amounts of Long-Term Pipeline Capacity Contracts Expire in 2012 ...................................................17

 Import Constrained Southern California Experiences Tightened Energy Market..............................................21

 CAISO Ramp Constraint Fails to Support San Diego Operations without SONGS ...........................................23

 New Phase Angle Regulating Transformers between Michigan and Ontario Entered Service.........................24

 MISO Successfully Counters Wind Loss with Spinning Reserves.......................................................................26

Chapter 2: Natural Gas Markets in 2012 ...........................................................................................................................27

 Summary...........................................................................................................................................................................27

 U.S. Natural Gas Prices Fall to 10-Year Lows......................................................................................................28

 Record U.S. Natural Gas Supply in 2012 .............................................................................................................30

 Crude Oil and Natural Gas Liquids Add Value to Natural Gas Production........................................................33

 U.S. Natural Gas Consumption Sets New Record................................................................................................34

 Natural Gas in Storage Sets New Record.............................................................................................................35

 U.S. Liquefied Natural Gas Imports Fall...............................................................................................................35

 New Natural Gas Pipelines Concentrated Near the Marcellus Shale.................................................................38

Chapter 3: Electricity Markets in 2012 ..............................................................................................................................40

Summary ...........................................................................................................................................................................40

 Electricity Prices Decline with Lower Natural Gas Prices...................................................................................41

 Electricity Demand Falls for Second Consecutive Year.......................................................................................43

 Energy Efficiency Policies Contribute to Lower Rates of Load Growth.............................................................46

 Electricity Supply Additions and Retirements Exhibit Shifts in Fuel Use .........................................................49

 Demand Response Continues to Grow..................................................................................................................52

 Investment in Electricity Transmission Infrastructure Investment Continued ..................................................54

Chapter 4: Interplay between Physical and Financial Aspects of the Natural Gas and Electricity Markets .................56

 Summary...........................................................................................................................................................................56

 Traded Volumes Declined for Financial Products, Changes Reflected in Products and Locations...................57

 Participation by Banking Institutions in the Natural Gas and Electricity Markets ..........................................61

 Capital Spending Up and New Debt Issued Where Utilities Possessed Favorable Credit Ratings....................63

Chapter 5: Significant Regulatory Developments in 2012................................................................................................66

 Summary...........................................................................................................................................................................66

 NYISO and ISO-NE Interchange Scheduling Plan................................................................................................67

 NYISO 15-Minute Scheduling with Hydro Quebec and PJM .............................................................................67

 Market Power Mitigation......................................................................................................................................67

 Order No. 755: Frequency Regulation .................................................................................................................69

 Order No. 764: Integration of Variable Energy Resources .................................................................................70
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 Order No. 768: Electricity Market Transparency Provisions ...............................................................................70

 Order No. 770: Revisions to Electric Quarterly Report Filing Process ............................................................... 71

 Order No. 760: Enhancement of Market Surveillance and Analysis through Ongoing Electronic 

 Delivery of Data ................................................................................................................................................... 71

 Order No. 771: Availability of E-Tag Information to Commission Staff ........................................................... 71

Acknowledgements ................................................................................................................................................................72

FIGURES

Fig. 1-1 Monthly Net Generation by Energy Source .................................................................................................... 11

Fig. 1-2 Natural Gas Prices Dip Below Coal Prices for Most of 2011-2012 .............................................................. 11

Fig. 1-3 Major Shifts in Combined-Cycle Plant Capacity Factors in 2012 ................................................................12 

Fig. 1-4 Monthly Electricity Output by Natural Gas-fi red Generation .......................................................................12 

Fig. 1-5 Monthly Electricity Output by Coal-fi red Generation ...................................................................................13 

Fig. 1-6 Gas-fi red Generation Increased Share of New England Natural Gas Demand .............................................14

Fig. 1-7 New England Natural Gas Infrastructure ........................................................................................................14 

Fig. 1-8 Natural Gas Flows on Maritimes & Northeast Pipeline ..................................................................................15 

Fig. 1-9 Flows at Algonquin’s Cromwell Compressor Station Up 39 Percent ..............................................................15 

Fig. 1-10 Days with no Availability of Interruptible Pipeline Capacity on Algonquin .................................................16 

Fig. 1-11 Firm Transportation Contracted Capacity Expiring by Year ...........................................................................17

Fig. 1-12 Firm Transportation Contracted Capacity Expired in 2012 ...........................................................................19

Fig. 1-13 Customer Mix Shifts to Producers ...................................................................................................................19

Fig. 1-14 Great Lakes Gas Transmission Pipeline Receipt and Delivery Points .............................................................20 

Fig. 1-15 California Price Spikes Increase in 2012 .........................................................................................................22 

Fig. 1-16 CAISO Electricity Prices at San Diego Increases with Summer Stresses .......................................................23

Fig. 1-17 Real-time Price Spikes in California Q1 2012 to Q3 2012 ...........................................................................24 

Fig. 1-18 Lake Erie Loop Flow and Surrounding RTOs ...................................................................................................25 

Fig. 1-19 Wind-Powered Generation Falls During Evening Ramp .................................................................................26 

Fig. 2-1 U.S. Natural Gas Supply and Demand – 2011 vs. 2012 ................................................................................28 

Fig. 2-2 Average Spot Natural Gas Prices, 2012 ..........................................................................................................29 

Fig. 2-3 Historical Next Day Natural Gas Prices ...........................................................................................................30 

Fig. 2-4 U.S. Dry Gas Production Growth Slows in First Half of 2012 .......................................................................30

Fig. 2-5 Natural Gas Rig Count Drops with Lower Prices ............................................................................................31

Fig. 2-6 Natural Gas Production by Shale Formation ..................................................................................................32 

Fig. 2-7 Natural Gas Prices Remained Below NGL Prices in 2012 ..............................................................................33

Fig. 2-8 Value Added to Production Stream Based on Natural Gas Liquids Content ................................................34 

Fig. 2-9 Growth in Power Burn Drives Gas Demand in 2012 ......................................................................................34 

Fig. 2-10 Record Natural Gas Storage in 2012 ................................................................................................................35

Fig. 2-11 U.S. LNG Imports Fall in 2012 ..........................................................................................................................36 

Fig. 2-12 World LNG Estimated Landed Prices for January 2013 .................................................................................36
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State of the Markets Report

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Fig. 2-13 New Natural Gas Production and Pipelines Help Reduce Prices in New York City......................................39

Fig. 3-1 Average Electricity Prices 2012 ......................................................................................................................41

Fig. 3-2 10-Year Day-Ahead Spot Electricity Prices ...................................................................................................42 

Fig. 3-3 Northwest Hydroelectric Production ..............................................................................................................43 

Fig. 3-4 Annual Electricity Consumption by Sector 2001 – 2012 ............................................................................44

Fig. 3-5 Monthly Electricity Consumption by Sector 2008 – 2012 ..........................................................................44 

Fig. 3-6 States with Energy Efficiency Programs.........................................................................................................47

Fig. 3-7 Energy Efficiency Program Savings – California............................................................................................48

Fig. 3-8 Energy Efficiency Program Savings – New England ......................................................................................48

Fig. 3-9 Energy Efficiency Program Savings – New York ............................................................................................48

Fig. 3-10 Generating Capacity Additions by Fuel Type ..................................................................................................49

Fig. 3-11 Generating Capacity Retirements by Fuel Type ..............................................................................................50

Fig. 3-12 Generating Capacity Additions by Region and Fuel Type..............................................................................50

Fig. 3-13 Generation Produced by Fuel Type ..................................................................................................................51

Fig. 3-14 Transmission Investment 2005 – 2012...........................................................................................................54 

Fig. 4-1 ICE Electricity Trading Volumes Continue to Decline ...................................................................................58

Fig. 4-2 Financial Trading Volumes in All Areas Except NYISO Decline.....................................................................58

Fig. 4-3 Trading Volumes Decreased in 2012 for All Contract Durations .................................................................59 

Fig. 4-4 PJM West Hub On-Peak Price Volatility Declines .........................................................................................60

Fig. 4-5 Natural Gas Trading on ICE Transitions from Swaps to Futures ..................................................................60 

Fig. 4-6 Electricity Trading on ICE Transitions from Swaps to Futures .....................................................................60 

Fig. 4-7 Average National Daily Volumes Rebounded at the End of 2012 ................................................................61

Fig. 4-8 Financial Companies Account for Ten Percent of Natural Gas Volumes .....................................................61

Fig. 4-9 Electricity Sales Reported by Banks Have Been in Decline ...........................................................................63

Fig. 4-10 Electricity Sales and Revenues in Decline Since 2005 .................................................................................63

Fig. 4-11 Yields for Investment Grade Utilities Continue to Decline ...........................................................................64

Fig. 4-12 Natural Gas and Electricity Sector Holds Investment-Grade Ratings .........................................................65

Fig. 4-13 The Amount of Debt Issued by A-Rated Utilities Increased in 2012 ..........................................................65 

Tables

Table 1-1 Pipeline Flow Utilization Key Locations ........................................................................................................19 

Table 2-1 Shale Natural Gas Production by Basin ........................................................................................................32 

Table 2-2 Types and Uses for Natural Gas Liquids ........................................................................................................33 

Table 2-3 Proposed U.S. LNG Export Projects ...............................................................................................................37 

Table 3-1 Heating Degree Days and Cooling Degree Days by Region .........................................................................44 

Table 3-2 Electricity Consumption Changes from 2011 to 2012 ................................................................................45

Table 3-3 2012 Generating Capacity Additions and Retirements ...............................................................................50 

Table 4-1 Bank Participation in the Physical Natural Gas Market is Limited .............................................................62
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State of the Markets Report

2012

Executive Summary and Overview

Wholesale Natural Gas and Electricity Prices Continued to Exhibit 

Low Levels 

Natural gas production grew to a new record in 2012 which contributed to the lowest nominal natural gas prices since 2002. Prices for natural gas were at or near 10-year lows in 

virtually every region of the United States, with the spot price at Louisiana’s Henry Hub 

averaging $2.74/MMBtu for the year, down 31 percent from 2011 (Figure 2-3). Low natural 

gas prices resulted in much greater reliance on natural gas as the fuel of choice for power 

generation while coal-fired power generation fell to its lowest level in 30 years.

Since natural gas is often the marginal fuel in electric generation, lower natural gas prices 

generally resulted in lower electricity prices nationwide. On average, wholesale electricity prices decreased compared to 2011 in all regions of the United States. A warm winter in 

2012, a slow economic recovery, and increasing energy efficiency contributed to a second 

year of declining electricity demand. 
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2012

Highlights of the Natural Gas and 

Electricity Markets in 2012

Power Generators Ramped Up Their Use 

of Natural Gas

Natural gas-fired generation displaced substantial 

amounts of electricity output from coal-fired generation in 2012, particularly from generators in the PJM 

Interconnection and the Southeast (Figure ES-1). Due 

to low natural gas prices, the nation’s fleet of natural 

gas-fired combined-cycle plants was more heavily 

used than at any time in the past decade. Natural 

gas-fired generation reached 1,193 TWh, 31 percent 

of total net generation in 2012, up from 25 percent 

in 2011. Coal-fired generation fell to 1,506 TWh, 39 

percent of total net generation, down from 43 percent 

in 2011. 

Figure ES-1

Monthly Net Generation by Energy Source

Source: EIA 923 Monthly Utility Power Plant Database, U.S. EPA CEMS

Total average daily U.S. natural gas demand grew 

4 percent to 70 Bcfd in 2012, the highest level on 

record. This occurred despite a 10 percent decline 

in residential and commercial natural gas demand 

(Figure ES-2). For the first time, natural gas used 

for power generation was greater than the combined 

residential and commercial gas demand. 

Figure ES-2

Growth in U.S. Natural Gas Power Burn in 2012

Source: Derived from Bentek Energy

Greater reliance on natural gas as a fuel for power 

generation led to increased awareness about the 

importance of greater coordination between the 

natural gas and electric industries. New England was 

identified as a market particularly at risk for service 

disruption due to limited pipeline capacity into the 

region. Most natural gas-fired generators in New 

England have little or no firm transportation capacity 

in their natural gas supply portfolios and depend on 

interruptible capacity on pipelines for their supplies. 

Moreover, availability of interruptible capacity in the 

region is decreasing. Natural gas-fired generators 

also rely on the capacity release market, but this option may not be available on high-demand days, such 

as during a cold snap when local distribution companies (LDC) need pipeline capacity to meet increased 

customer demand.

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Coal Nat. Gas Nuclear Renewables Hydro

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Residential & Commercial Industrial Power Generation
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2012

While the substitution of natural gas-fired generation 

for coal-fired generation (also referred to as “coalto-gas switching”) was notable in 2012, the trend is 

less likely to be as pronounced in 2013 due to higher 

natural gas prices. However, the level of natural gas 

use in power plants will still be higher than it was 

prior to 2011 as long as natural gas price increases are 

moderate. With the expectation that natural gas will 

retain much of its price gains relative to coal for electric generation, investment decisions for new electric 

generating plants will reflect that new balance.

Record U.S. Natural Gas Supply in 2012

Contributing to natural gas’ lower price was a 5 

percent growth in its production, a 10 percent drop in 

residential and commercial natural gas demand due 

to one of the warmest winters on record in the first 

quarter of 2012, and high storage levels. By spring 

2012, working gas in storage stood at a record 934 

Bcf surplus to the five-year average and robust injections in the spring and fall brought storage to nearrecord levels by November 2012 (Figure ES-3).

Figure ES-3

Natural Gas Storage

Source: Derived from EIA data

Growth in natural gas production was driven by gains 

in drilling rig efficiency and was centered mostly in 

Pennsylvania’s Marcellus Shale, Texas’ Eagle Ford, 

and Arkansas’ Fayetteville Shale. In other major 

shale plays, production stalled or declined as producers focused on liquids-rich natural gas fields. By 

the end of 2012, production from the six major U.S. 

shale formations accounted for 38 percent of total 

U.S. natural gas production, up from 22 percent at the 

beginning of 2011.

During the year, spot natural gas prices at Henry Hub 

fell to a low of $1.82/MMBtu, before gradually rising 

to a high of $3.77/MMBtu in late November. The rise 

was largely a result of high natural gas demand from 

power burn and the onset of the 2012 to 2013 winter 

heating season.

Regional Natural Gas Prices Fall

In 2012, natural gas prices fell 22 to 36 percent across 

the nation. The price difference between major trading hubs and the Henry Hub, also known as basis, in 

many cases was only pennies. 

•	 Capacity expansions on Florida Gas Transmission Co. 

eliminated price spikes at the FGT-Z3 hub, and natural 

gas prices there averaged $2.92/MMBtu.

•	 In New England, the Algonquin Citygate hub near Boston had the highest spot prices in the nation, averaging 

$3.91/MMBtu due to pipeline constraints and a drop in 

liquefied natural gas (LNG) imports (Figure 2-2). 

•	 Except for very cold days, there were few natural gas 

transportation constraints into New York City and spot 

prices at Transco Zone 6 NY averaged $3.19/MMBtu. 

•	 Natural gas prices in the Rocky Mountains were among 

the lowest in the nation. They averaged $2.59/MMBtu 

at the Colorado Interstate Gas hub. Regional natural 

gas producers lost market share to growing production 

closer to the markets in the Northeast and Midcontinent.

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Series3 2011-2012 2012-13
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2012

•	 In California, increased demand for natural gas-fired 

power generation due to the outage at the San Onofre 

Nuclear Generating Station put upward pressure on 

natural gas prices through spring and summer. 

Changes in Regional Natural Gas Supply Pose 

Financial Challenges to Pipelines

Declines in pipeline utilization and changing customer needs pose financial risks to long-haul pipelines. 

More than 10 Bcfd of long-term capacity contracts on 

U.S. natural gas pipelines expired during 2012 (Figure 

ES-4). In cases where customers re-contracted, it was 

generally for shorter durations and smaller volumes. 

The erosion of regional price differences over the 

past few years has reduced the value of many longhaul pipeline routes. Pipelines that move natural 

gas into the Northeast from the Gulf Coast and the 

Rocky Mountains experienced the greatest declines in 

utilization in 2012. The new natural gas flow patterns 

raised the possibility that some pipelines may be unable to find buyers for long-term capacity once their 

contracts expire.

Figure ES-4 

Quantity of Natural Gas Pipeline Firm Transportation 

Contracted Capacity Expiring by Year

Source: Derived from Velocity Suite data based on FERC Form No. 549 B - Index

of Customers data

As a result of declining utilization, some pipeline 

companies are converting or considering converting 

natural gas pipelines to transport crude oil or natural 

gas liquids. Cumulatively, almost 26 Bcfd of longterm capacity contracts are due to expire by 2015, 37 

Bcfd by 2020.

Electricity Prices Decline

Nationwide, average on-peak prices for electricity 

were lower in 2012 than in 2011. The lower prices 

followed natural gas prices, a major determinant of 

electricity prices. Low natural gas prices have largely 

been responsible for relatively low electricity prices 

since the beginning of 2009, but lower electricity demand from continued weak economic activity and energy efficiency were also contributors. Low prices in 

2012 were seen in all regions of the nation, but varied 

due to region-specific conditions. Eastern prices were 

between 10 percent and 31 percent lower than in 2011 

while Western prices fell between 6 percent and 23 

percent (Figure ES-5 on the next page).

Electricity Demand Falls for Second Year

Compared to 2011, sales of electricity dropped by 

1.7 percent or 62.9 TWh in 2012. Annual consumption of electricity across the three principal sectors 

(residential, commercial, and industrial) is shown in 

Figure ES-6 (next page). Demand was down across 

the nation due to three primary factors: a decrease 

in residential demand, lack of demand growth in 

the commercial and industrial sectors, and increased 

energy efficiency. Residential demand decreased because of a drop in heating load due to a warm winter. 

The first quarter of 2012 broke the January to March 

average temperature record for the continental United 

States by a significant 1.4◦F. In 2012, industrial sales 

fell by 1.1 percent, commercial sales by 0.2 percent. 

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Expiring Firm Contracted Capacity (Bcfd)
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2012

Figure ES-5

2012 Average Electricity Prices 

Source: Derived from Platts data

Reduced industrial demand generally reflects a slowly 

recovering economy with commercial consumption 

staying flat as a result of the economy and weather.

Energy efficiency is responsible for a portion of the 

reduction in load. Several states with active energy 

efficiency programs were able to achieve savings that 

amounted to about one percent of total sales. Even 

with just part of the nation represented by active state 

programs, documented results are sufficient to influence the overall trend in consumption. 

Figure ES-6

Annual Electricity Consumption by Sector

Source: Derived from EIA data

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2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Annual Consumption (TWh)

Residential

Commercial

Industrial
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Import-Constrained Southern California 

Experienced a Tightened Energy Market

An extended outage of the San Onofre Nuclear 

Generating Station led to a tightening of the supplydemand balance in already-constrained Southern 

California, particularly in peak load hours. The need 

for local voltage support exacerbated the area’s challenges with imports as the loss of San Onofre stressed 

the power market during 2012, particularly during 

August and September. The stress elevated prices 

(Figure ES-7). With San Onofre offline, replacement 

power came primarily from increased use of natural 

gas-fired generation, including units brought back 

out of retirement. Among other actions, California 

accelerated the in-service date for its new 500 kV 

transmission project, the Sunrise Powerlink. Southern California utilities also made other transmission 

upgrades to improve flows in the region.

Figure ES-7

2012 Monthly Electricity Prices for San Diego Load Zone

Source: Derived from CAISO data

Physical and Financial Markets for Natural 

Gas and Electricity

Trading in financial products continued to fill an 

important role in energy markets. The volume of financial trading significantly exceeds physical trading. 

In 2012, financial trading for both natural gas and 

electricity remained substantial overall, and the markets remained liquid. There were two key trends in 

financial trading of energy products. First, trading on 

IntercontinentalExchange, Inc. for electricity products 

decreased 19 percent compared to 2011 (Figure ES-8). 

One possible explanation for the decline is that there 

was lower volatility in power prices. Lower volatility implies less potential for profit and a decline in 

potential profits might steer investors away from energy products, and into other assets. Second, toward 

the end of the year, market participants desiring to 

trade in financial products for natural gas, electricity, 

or both, were offered new trading products after the 

Dodd-Frank Wall Street Reform and Consumer Protection Act required regulatory changes. In particular, 

markets transitioned by converting some traditional 

swaps products into futures. 

Figure ES-8

Historical ICE Electricity Trading Volumes

Source: Derived from ICE data

chart Fig 1-16

Page 1

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SDG&E Day-Ahead On-Peak Avg LMP ($/MWh)

2011

2012

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Financial Trading (GWh)

Physical Financial
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Participation by banking institutions in physical 

natural gas and power markets continued to wane. 

Declining activity in asset ownership and physical 

energy transactions is part of a multi-year trend with 

banking institutions participating in the natural gas 

and electricity markets peaking in the 2007 and 2008 

period and declining since then.

Public utilities maintained access to investment 

capital through stable credit ratings. A relatively 

favorable credit environment existed for utilities that 

maintained higher credit ratings. With low interest rates available for investment grade utilities, debt 

issuance by the lowest investment grade-rated (BBB) 

utilities stayed flat while A-rated utilities increased 

their issuance by 25 percent in 2012 (Figure ES-9).

Figure ES-9

Investment-Grade Ratings for Natural Gas and Electricity 

Sectors

Source: Derived from Standard & Poor’s data

Note: Major rating categories are grouped by base rating and include all ratings 

with (+) to (-) modifiers

LNG Imports Drop as U.S. Gears Up for 

Exports

United States LNG imports continued to decline in 

2012 (Figure ES-10). Low domestic natural gas prices 

made it difficult to attract LNG cargo to the United 

States, and imports fell 47 percent. Of 12 active U.S. 

terminals, only Everett LNG in Massachusetts and 

Elba Island in Georgia received regular LNG cargo 

throughout the year, albeit with lower frequency than 

in past years. Both have long-term contracts. 

Figure ES-10

Volume of LNG Imports in 2012

Source: Derived from U.S. Department of Energy data

LNG sold in Asia for about $15/MMBtu, four to six 

times higher than in the United States, $10-$11/

MMBtu in Europe, and around $12-$13/MMBtu in 

South America (Figure ES-11 on next page). The price 

spread between the United States and world natural 

gas prices created interest in liquefying and exporting U.S. natural gas. However, it is unlikely that the 

United States will export any LNG before 2016 due to 

the time required to build and permit export facilities.

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AA A BBB BB B CCC and

lower

% of Operating Utility Subsidiaries

Year 2005

Year 2006

Year 2007

Year 2008

Year 2009

Year 2010

Year 2011

As of Nov 2012

Below investment grade

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LNG Imports into U.S. Gulf
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Figure ES-11

Estimated World-Wide LNG Landed Prices

Source: Derived from Waterborne Energy data

Even as companies contemplated LNG exports, U.S. 

natural gas exports to Mexico increased 25 percent in 

2012. Exports of Marcellus Shale gas to Canada also 

began in the latter half of 2012. Natural gas imported 

Federal Energy Regulatory Commission • Market Oversight • www.ferc.gov/oversight

3024

Source: Derived from Waterborne Energy, Inc. Data in $US/MMBtu

World LNG Estimated January 2013 Landed Prices

Updated: January 15, 2013

Natural Gas Overview: World LNG Prices

Cove Point

$4.50

India

$11.55

UK

$8.75

Spain

$9.05

Belgium

$8.84

Japan

$12.40

Korea

$12.40

Lake Charles

$3.96 Altamira

$4.60

 Cove Point

 $4.40

India

$11.55

UK

$8.75

Spain

$9.15

Belgium

$8.99

Japan

$13.10

Korea

$13.10

Lake Charles

$3.93 Altamira

$4.57

Cove Point

$4.50

India

$11.55

UK

$8.75

Spain

$9.05

Belgium

$8.84

Japan

$12.40

Korea

$12.40

Lake Charles

$3.96 Altamira

$4.60

 Cove Point

 $4.60

India

$13.85

UK

$10.76

Spain

$11.80

Belgium

$10.35

Japan

$16.45

Korea

$16.45

Lake Charles

$3.28 Altamira

$3.85

Rio de Janeiro

$12.25

Bahia Blanca

$13.25

China

$16.05

from Canada fell 9 percent in 2012 due largely to the 

fact that U.S.-produced natural gas generally had a 

transportation advantage over Canadian natural gas, 

particularly in the Northeast and upper Midwest.
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State of the Markets Report

2012

Chapter 1: Market Developments

Summary

Low natural gas prices and their effects on power markets spurred key market developments 

in 2012 and increased the interrelationship between the natural gas and electricity markets. 

Overall, natural gas increased its presence and role in the electricity markets as a primary 

and growing resource for power generation. Other key market developments stemmed from 

the implementation of technologies, including the use of phase-angle regulators to aid in addressing loop flow, and the integration of renewable resources. 

Sharply higher output from natural gas-fired generation resulted from natural gas’s increased abundance and lower price. Throughout much of the Eastern Interconnection, particularly in PJM and the Southeast, natural gas-fired power plants realized significant gains 

in output, frequently at the expense of coal-fired generators. This shift was manageable, but 

not seamless.

Robust local natural gas production growth from the Marcellus Shale continued to experience pipeline bottlenecks in the Northeast. While planning for the possibility of extreme 

weather, and facing reduced supplies from liquefied natural gas (LNG), stakeholders in the 
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region focused their attention on fuel supply reliability. In New England, in particular, the growth in 

natural gas use for power generation, together with 

the increased use of natural gas for home heating, led 

stakeholders to seek ways to alleviate stresses on the 

natural gas pipeline delivery system under high load 

conditions. 

Further, long-haul natural gas pipelines saw some 

increases in financial risk as customers with firm 

contracts considered whether to renew expiring transportation contracts. Customers who did not renew 

their contracts faced opportunities for accessing shale 

gas from cheaper local supplies, as opposed to gas 

supplies previously delivered from the Gulf Coast and 

South Central United States.

California increased its dependence on natural gas 

as a result of the lengthy outage at the San Onofre 

Nuclear Generating Station. The plant’s output was 

replaced in part by increased production from natural 

gas-fired generating units both in Southern California and in surrounding areas of the West. Natural 

gas and electricity prices saw some increases in the 

region, particularly during the summer and early fall.

Changing technology implementation occurred with 

the placement into service of phase angle regulators at the MISO-Ontario border which helped reduce 

loop flows at this well-used transmission path. Additionally, wind integration continued to increase, 

providing benefits to consumers when prices drop 

and challenged balancing authorities when congestion occurs. For example, MISO experienced a sudden 

drop in wind generation, which led the grid operator 

to commit and use ancillary services to balance supply on the grid. As use of wind generation and other 

variable resources increase use of ancillary service to 

compensate for fluctuations in their output will take 

on heightened priority.

Natural Gas Increasingly Displaced Coal for 

Electricity Generation

Competitive fuel pressures between natural gas and 

coal led to a marked shift in electricity generation resource utilization. The United States saw a displacement of substantial amounts of electricity output from 

coal-fired generation by increased output from natural gas-fired generation. Broader market declines in 

the price of natural gas as compared to a more modest 

decline in coal prices drove the trends in 2012. These 

trends may drive investment decisions with respect to 

the fuel type of new electric generating plants which 

may lead to further demand for construction of natural gas-fired facilities in the coming year.

The share of electricity generation fueled by natural 

gas increased substantially in 2012. Natural gas-fired 

generation reached 31 percent of total generation 

in 2012, up from 25 percent in 2011. The increase 

resulted in displacement of coal-fired generation, 

particularly generation burning Appalachian coal. 

Coal’s share of net generation declined to 39 percent 

from 43 percent in 2011. While on an annual basis 

coal-fired generation was still the largest source of 

electricity supply, by May 2012 the spread in electricity production between monthly amounts from coal 

and from natural gas had narrowed sharply. The 2012 

changes relative to other fuel sources and the prior 

four years are illustrated in Figure 1-1 on the next 

page.
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Figure 1-1

Monthly Net Generation by Energy Source

Source: EIA 923 Monthly Utility Power Plant Database, U.S. EPA CEMS

Lower natural gas prices have driven the shift in generation resources because of increases in natural gas 

supply from shale gas production in the United States. 

For the first time in over ten years, natural gas began 

to trade at a discount to coal in the third quarter of 

2011. Through the first half of 2012, the price of 

natural gas averaged $2.38/MMBtu, 45 percent lower 

than for the same period in 2011. By April 2012, 

natural gas at Henry Hub traded near $2/MMBtu, 

over $1/MMBtu cheaper than Appalachian coal when 

adjusted for the heat rate difference between the two 

technologies (Figure 1-2).1

 This decline in the price of 

natural gas was the catalyst for the substantial shift 

from coal to natural gas-fired electric generation. 

Further discussion of shale natural gas production 

trends is provided in Chapter 2.

1 In order to show comparable prices in terms of their electricity production value, coal 

prices are adjusted to reflect the lower average heat rate of coal-fired power plants 

compared to that of combined-cycle power plants. Heat rate is a measure of how efficiently a generator converts fuel into electrical energy. It is determined by dividing the 

heat content of the fuel input consumed in the generator by the electrical energy output, 

usually expressed as BTU/kWh. The lower the heat rate, the higher the efficiency of the 

generating unit.

Figure 1-2 

Natural Gas Prices Dip Below Coal Prices for Most of 

2011-2012

Source: Derived from Bloomberg data 

The national shift from coal-fired to natural gas-fired 

generation was reflected in a significant increase in 

the use of combined-cycle power plants. With lower 

fuel prices, natural gas-fired combined-cycle units 

are less expensive to run due to their high efficiency 

fuel prices. As a result, they increasingly operated in 

a baseload mode generation (greater than 50 percent 

capacity utilization, or capacity factors).2

 Figure 1-3 

on the next page shows the relative distribution of 

capacity factors across selected production ranges for 

the last six years. Sixty-three percent of the nation’s 

combined-cycle plants operated above 50 percent capacity factors during 2012, compared to 29 percent in 

2 A baseload supply is a generator that is used throughout the day or throughout the 

year. In contrast, non-baseload supply is typically used during certain parts of the day 

(e.g., high load hours in the afternoon) or part of the year. For this analysis, baseload 

generation was chosen as generators having greater than 50 percent utilization, where 

utilization is measured in terms of capacity factors. A capacity factor is a measure of the 

average output of an electric generator over a specific period of time compared to how 

much the generator could produce if running at its maximum rated production , i.e., at 

continuous full power operation during the same period.

0

20

40

60

80

100

120

140

160

180

200

Electric Energy Generation (1000s of GWh)

Coal Nat. Gas Nuclear Renewables Hydro

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00

Prices ($/MMBtu)

Henry Hub Natural Gas

Central Appalachian Coal
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2007. Nationwide, the share of combined-cycle plants 

running at 70 percent-plus capacity factors reached 

18 percent compared to just 7 percent in 2011.

Figure 1-3

Major Shifts in Combined-Cycle Plant Capacity 

Factors in 2012

Source: Derived from SNL data

The most notable shifts from coal-fired to natural 

gas-fired generation occurred in areas of the Eastern 

Interconnection relying on Appalachian coal. This 

was particularly the case in PJM and the Southeast 

where there is significant use of Appalachian coal, 

but much under-utilized combined-cycle generation 

capacity. For PJM and the Southeast, coal’s share of 

net generation declined to 40 percent of total generation from 47 percent in 2011. Electricity produced 

by natural gas-fired generation was 31 percent of the 

production in 2012, an increase from 24 percent in 

2011.3

 MISO and SPP, utilizing more of the lower cost 

Powder River Basin (PRB) coal, experienced less displacement of coal by natural gas. Appalachian coal 

3 Of note, the Southeast is the nation’s largest consumer of natural gas for power generation, accounting for 30 percent of U.S. power burn in 2012.

costs averaged about $63 per ton in 2012 compared 

to $11 per ton for PRB coal. Even allowing for the 

higher heat content of Appalachian coal, and higher 

transportation costs for PRB coal, PRB coal enjoyed a 

delivered price advantage over Appalachian coal. 

Figures 1-4 and 1-5 (on the next page) illustrate 

natural gas and coal utilization for electricity generation by region. These figures show where the two fuel 

sources are in greatest use and how the displacement 

played out over the past two years. Seasonal peaks 

in electricity output are still greatest in the summer, 

however, the shift in electricity generation between 

the two fuel sources took place in all months of 2012 

compared to the prior year.

Figure 1-4

Monthly Electricity Output by Natural Gas-fired 

Generation

Source: EIA 923 Monthly Utility Power Plant Database, U.S. EPA CEMS
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Figure 1-5

Monthly Electricity Output by Coal-fired Generation

Source: EIA 923 Monthly Utility Power Plant Database, U.S. EPA CEMS

As the price of natural gas and coal decreased relative to 2011, electricity prices declined.4

 In the eastern regions burning Appalachian coal, natural gas 

increasingly became the marginal generation source. 

In PJM, for example, among all marginal resources 

affecting the real-time price in the first 9 months of 

2012, 58 percent were coal-fired generators, down 

from 69 percent of the marginal resources in 2011. 

At the same time natural gas units were marginal 

31 percent of the time up from 26 percent in 2011.5

 

However, since the prices of the fuels were close 

on a $/MMBtu basis, the range of electricity prices 

produced were driven by overall lower costs of the 

fuels. Throughout the rest of nation, natural gas-fired 

generation remained the marginal resource.

4 Discussion of the overall lower prices for natural gas and electricity, and factors that 

contributed to regional price differences, are provided in Chapter 2, for natural gas, and 

Chapter 3, for electricity.

5 Monitoring Analytics, LLC, “2011 State of the Market Report for PJM,” Vol. 2, March 15, 

2012, p. 31. See also Monitoring Analytics, LLC, “2012 Quarterly State of the Market 

Report for PJM: January through September,” November 15, 2012, p. 29. 

Lower utilization of coal-fired generation, along 

with an expected need to invest in emissions-related 

capital equipment, led to announcements by owners 

to schedule retirements of coal-fired power plants.6

 

Some analysts anticipated an upturn in new natural 

gas-fired generation to be constructed in the coming 

years, especially in areas close to shale gas formations.7

 These retirement or build decisions will be a 

key determinant in coming years’ electricity resource 

fundamentals.

As a result of the shift in fuel utilization for electricity 

production, natural gas consumption by power generators (referred to as power burn) grew 20.3 percent 

to 25 Bcfd in 2012, up from 20.8 Bcfd the year prior. 

As explained in Chapter 2, power burn is the fastest 

growing use for natural gas and surpassed residential 

and commercial sector natural gas consumption. 

New England Faces Seasonal Supply and 

Pipeline Constraints 

New England continued to face power and natural gas 

market challenges in 2012 due to growing competition for limited natural gas supply between heating 

and electric load during the coldest winter days. Low 

domestic natural gas prices led to low imports of 

LNG and Canadian natural gas, important sources for 

meeting peak demand days in New England. Lack of 

LNG and natural gas from Canada exacerbated pipeline constraints into New England from the southern 

supply corridor, including Marcellus Shale natural gas 

6 SNL Energy reported that U.S. power companies have announced plans to retire nearly 

30 GW of coal-fired capacity between 2012 and 2021. SNL Energy: “Upcoming, recent 

coal-fired unit retirements,” August 15, 2012. The Energy Information Administration 

estimated 49 GW of retirements from 2011 through 2035. U.S. Energy Information 

Administration (EIA), “Annual Energy Outlook 2012,” DOE/EIA-0383, June 2012, p. 4.

7 Northeast Power Markets Energy Watch, ESAI Power, LLC, December, 2012.
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production, as New England relied more heavily on 

these pipelines for supply. This led to concerns that 

extreme cold weather could result in some service 

interruptions, particularly to power generators that 

generally rely on interruptible pipeline capacity to 

meet their fuel needs. 

New England is a winter-peaking natural gas market 

driven by heating demand from the residential and 

commercial sectors. In the last two years, power burn 

has increased its share of total natural gas demand in 

New England and grew 4 percent during the summer 

of 2012 (compared to 2011). Figure 1-6 illustrates 

growth in New England power burn, which has led 

to constraints on pipelines serving the region. These 

are particularly acute during cold snaps when demand 

from power plants coincides with peak residential and 

commercial natural gas demand. While the higher 

power burn pushed regional pipeline capacity to operating limits at times, New England avoided any major 

supply issues due to an unusually warm winter that 

suppressed residential and commercial load during the 

first quarter of 2012.

Figure 1-6

Gas-Fired Generation Increased Share of New England 

Natural Gas Demand

Source: Derived from Bentek Energy data

Figure 1-7 shows major natural gas supply routes into 

the New England natural gas market, including natural gas pipelines and LNG terminals. Main routes into 

New England include:

•	 Maritimes Canada - This includes Canaport LNG supplies (New Brunswick) and Sable Island (Nova Scotia) 

offshore production via the Maritimes & Northeast 

Pipeline (Maritimes);

•	 LNG - This includes LNG imports through the onshore 

Everett LNG terminal and offshore Northeast Gateway 

and Neptune LNG terminals near Boston. Most of 

Everett’s LNG is used to fuel the Mystic power plant in 

Boston or trucked to local distribution companies’ LNG 

storage tanks and used to meet peak demand. Northeast Gateway and Neptune LNG have not imported any 

LNG since 2010;

•	 Northern Route - This includes Canadian natural gas 

supplies from the TransCanada Mainline via the Iroquois Pipeline and Portland Natural Gas Transmission 

(PNGTS); and,

•	 Southern Route - This includes Gulf Coast, Rocky 

Mountains, and Marcellus Shale natural gas supplies 

via Tennessee Gas Pipeline (TGP) and Algonquin Gas 

Transmission (Algonquin).

Figure 1-7

New England Natural Gas Infrastructure

Southern Route

Maritimes Canada

Northern Route

Marcellus Shale

Sable Island

TGP

Algonquin

Iroquois

Maritimes Canaport LNG

Everett LNG

TransCanada

LNG

Source: Derived from Ventyx data
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LNG imports from Everett LNG and Canaport LNG, 

plus natural gas production from Sable Island have 

historically supplemented natural gas supplies into 

New England on Algonquin and TGP. However, LNG 

imports were at their lowest in 10 years during 2012, 

with Canaport LNG sendout down sharply as cargoes 

were redirected to higher-priced buyers in Asia and 

Europe. As shown in Figure 1-8, natural gas sendout 

from Canaport LNG along the Maritimes pipeline into 

New England was down 44 percent in 2012 while 

natural gas flows from Sable Island fell dramatically 

due to depletion of the offshore field. Not shown in 

the figure, natural gas exports from Everett LNG to 

the Boston market was down 68 percent from 2011.

Figure 1-8 

Natural Gas Flows on the Maritimes and Northeast 

Pipeline

Source: Derived from Bentek Energy data 

Natural gas imports from Canada on Iroquois Pipeline 

at Waddington declined 11 percent in 2012 due to 

high transportation costs on the TransCanada pipeline 

and its lack of competitiveness with new Marcellus 

natural gas production. New England has historically 

imported Canadian natural gas via Iroquois to Algonquin. However, natural gas flows were sometimes 

restricted by bottlenecks on Algonquin. 

The Algonquin pipeline, a 2.4-Bcfd pipeline that runs 

from Lambertville, N.J. to Boston, Mass., experienced 

transportation capacity constraints at a number of 

compressor stations during 2012. Algonquin transports natural gas from the Gulf Coast, the Marcellus 

Shale, and Canada into New England. Algonquin 

receives Marcellus natural gas supplies from TGP at 

the Stony Point Compressor Station. During periods when this point became constrained, natural gas 

flows were restricted downstream to serve the Boston 

market. 

Average natural gas flows through the Cromwell 

Compressor Station in Connecticut have increased 

39 percent since 2010 (Figure 1-9) to serve numerous non-power and power customers in Connecticut 

and Rhode Island. Since the winter of 2008-2009, 

scheduled natural gas flows at Cromwell reached 97 

percent of peak design capacity a total of 24 days (22 

days during winter). Almost half of these days occurred last winter despite mild temperatures. Pipeline 

utilization reached 100 percent of capacity on six of 

those days.

Figure 1-9

Flows at Algonquin’s Cromwell Compressor Station Up 

39 Percent

Source: Derived from Bentek Energy data
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Algonquin’s interconnection with TGP near Mendon, 

Massachusetts provides an alternate supply point for 

the Algonquin pipeline. TGP has expanded its takeaway capacity from the Marcellus Shale and now 

delivers Marcellus Shale natural gas into New York. 

TGP’s 200 line cuts across New York and into Massachusetts. However, constraints into New England 

have not yet been addressed. Consequently, New 

England natural gas often traded at a premium to 

New York during the winter of 2012. In January and 

February 2012, flows on the TGP 200 line into New 

England averaged 80 percent of pipeline capacity, and 

peaked at 94 percent of capacity in March 2012. 

High utilization on pipelines supplying New England 

with natural gas from the Gulf Coast and Marcellus 

Shale resulted in diminished availability of interruptible transportation capacity to power generators in 

2012. Figure 1-10 shows that since 2009, the availability of interruptible capacity on Algonquin fell 

substantially. For the 12-month period ending July 

2010, there were only 19 days with no interruptible capacity. That number jumped to 292 for the 

12-months ending July 2012.

Figure 1-10 

Days with no Availability of Interruptible Pipeline 

Capacity on Algonquin

Source: Derived from Spectra Energy data

Lack of interruptible pipeline capacity is a concern for 

New England with its increased reliance on natural 

gas-fired power plants. Most of these plants have 

little or no firm transportation capacity in their supply portfolios and depend on interruptible capacity on 

the pipeline for their supplies. This option may not be 

available on high-demand days such as during a cold 

snap when LDCs need to meet increased customer demand, and power generators may not have sufficient 

fuel to operate during peak-demand days.

Greater reliance on natural gas as a fuel for power 

generation led FERC to hold a series of regional 

technical conferences during July and August 2012 

on natural gas-electric industry coordination.8

 New 

England was identified as a market particularly at risk 

of disruption. Based on some of the issues highlighted at the New England conference, the New England 

ISO and natural gas pipelines took steps to increase 

coordination by implementing monthly New England 

Gas-Electric Focus Group discussions. The discussions explored common market issues and possible 

resolutions, including changes to natural gas scheduling practices, improved communication and information sharing, and availability of non-firm pipeline 

capacity. 

Participants at the New England conference also 

discussed the cost of pipeline expansions. These 

costs are usually borne by long-term firm customers, 

such as local distribution companies and industrial 

customers. New England power generators generally 

have not contracted for firm capacity because they 

only need it intermittently during peak periods. Most 

participants agreed that the answer to New England’s 

8 Coordination between Natural Gas and Electricity Markets, Notice of Technical Conferences, Docket No. AD12-12-000 (July 5, 2012).
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pipeline constraints is to build more pipeline capacity, 

but the allocation of costs between customers was not 

resolved.

LNG Imports into Boston Fall

LNG imports into the Everett LNG facility outside Boston 

fell 37 percent in 2012, from 137 Bcf to 87 Bcf and the 

terminal declared force majeure during April and May. The 

terminal has firm long-term LNG supply agreements with 

Trinidad and Tobago and Yemen, but repeated terrorist attacks on the natural gas pipeline that supplies the Yemen 

LNG facility sharply curtailed deliveries from that country 

in 2012. This led Distrigas of Massachusetts (DOMA), the 

owner of Everett LNG, to declare force majeure in April 

and May. They curtailed deliveries to firm customers by 

20 percent, and halted deliveries to interruptible customers. DOMA requested accelerated deliveries of LNG from 

Trinidad, but by the fall of 2012, LNG cargoes into Everett 

had dropped from four to five vessels per month to two to 

three per month. As a result, Everett sent out only a small 

amount of re-gasified LNG into the regional grid. Most of 

its send-outs were dedicated to serving the adjacent Mystic 

power plant, and firm customers who truck LNG to storage 

tanks throughout the region.

The supply disruption led to concerns for adequate sendout 

of re-gasified natural gas to the adjacent Mystic power 

plant. Mystic units 8 and 9 can provide up to 1,600 MW of 

electricity supplies into the Boston area. The Mystic units, 

connected to Everett through a dedicated pipeline, are 

directly dependent on Everett for its fuel supply. Subsequent to the supply challenges that emerged in the spring, 

DOMA and ISO-NE worked closely together to ensure that 

the Mystic power plant had enough fuel to run during peak 

electricity demand periods.

Record Amounts of Long-Term Pipeline 

Capacity Contracts Expire in 2012

Regional changes in natural gas production, particularly the growth of shale natural gas in the Northeast, 

resulted in a decline in utilization on some segments 

of long-haul natural gas pipelines. At the same time, 

record amounts of long term pipeline capacity contracts expired in 2012. Declines in pipeline utilization 

and changing customer needs raised concerns about 

how much expiring capacity would be re-subscribed. 

In cases where customers re-subscribed, it was generally for shorter contract terms and smaller contracted 

volumes. Pipelines with available firm capacity faced 

financial pressure either on segments of their lines or, 

in some cases, along the entire pipeline. Some underutilized pipelines proposed conversion to alternative 

fuels such as crude oil or natural gas liquids. 

As shown in Figure 1-11, over 10 Bcfd of long-term 

capacity contracts on U.S. natural gas pipelines 

expired during 2012. Cumulatively, almost 26 Bcfd 

of capacity is due to expire by 2015 and 37 Bcfd by 

2020.

Figure 1-11

Firm Transportation Contracted Capacity Expiring by Year

Source: Derived from Velocity Suite data based on FERC Form No. 549 B - Index 

of Customers data

Note - Pipelines included in analysis: TGP, El Paso, Northern Natural, TETCO, 

ANR Great Lakes, Columbia Gulf, Transwestern, and Trunkline
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Natural gas from new shale plays in the vicinity of 

consuming markets shifted contracted pipeline volumes to closer supply sources. In particular, growing 

Marcellus Shale natural gas production, increased 

available natural gas supply in the proximity of 

Northeast markets, reduced the Northeast’s dependence on natural gas supply from the Gulf Coast, the 

Rocky Mountains, and the Mid-Continent. Similarly, 

natural gas imports from Canada and LNG imports 

into the Northeast also declined. Growing Mid-Continent shale natural gas has reduced the Upper Midwest’s reliance on supplies from the Gulf Coast and 

Rocky Mountains, as well as natural gas imports from 

Canada. 

Growing regional sources of natural gas, coupled 

with plentiful long-haul pipeline capacity resulted in 

erosion of regional price differences in 2012. This 

reduced the value of many long-haul pipeline routes 

and reduced pipeline profitability. A number of 

long-haul pipelines, including Tennessee Gas Pipeline, 

Trunkline, Transwestern, and El Paso reported falling 

rates of return in 2012.

By region, key natural gas pipelines with significant 

capacity contract expirations (above 500 MMcfd) 

between 2012 and 2015 include: 

Midwest Market

•	 ANR pipeline experienced a shift in natural gas supply from the offshore Gulf of Mexico to the Marcellus Shale in the Northeast. Some segments on ANR’s 

southeast mainline began to transport natural gas from 

north to south, reversing the traditional flow direction 

from Louisiana to Michigan. Utilization on the southeast portion of ANR’s mainline was down 20 percent 

in 2012 from 2011, and down almost 50 percent from 

2009. Compensating for the decline, utilization of 

ANR’s southwest mainline, using natural gas sourced 

from the Anadarko Basin, increased to 84 percent in 

2012 from 54 percent in 2009. 

•	 Trunkline traditionally sourced its natural gas supplies 

from East Texas, but during 2012 shifted its source to 

northern Louisiana. Natural gas receipts from northern Louisiana have increased 15 percent since 2010. 

Overall utilization on Trunkline in the South Texas 

zone declined to zero in 2012, while flows in the North 

Texas portion of the pipeline are 5 percent lower than 

in 2011.

Northeast Market

•	 TGP experienced a decline in natural gas receipts from 

the Gulf Coast and a significant increase in natural 

gas receipts from the Marcellus Shale. Flows on TGP 

south of the Kentucky/Ohio border declined 49 percent 

in 2012 compared to 2011, while flows from Marcellusproducing areas in Pennsylvania grew 25 percent. 

•	 Texas Eastern Transmission Co. (TETCO) experienced 

a decline of 60 percent of natural gas receipts from 

South Texas and west Louisiana supply zones on its 

southern leg and 52 percent on the northern leg.

Southwest Market

•	 Transwestern Pipeline delivers natural gas supplies 

from the San Juan Basin in New Mexico and the Permian Basin in West Texas to markets in the Southwest 

and Southern California. The southern line on El Paso 

is now also sourcing some supplies from the growing 

Eagle Ford production in Texas. Flows out of West 

Texas grew 38 percent in 2012 from 2011. Overall 

flows on the north mainline, which transports supplies 

from the Permian Basin as well as San Juan production 

to the Southwest and Southern California markets, declined 3 percent in 2012 from 2011. This has prompted 

talk of converting one of the lines to carry oil and oil 

products. 

Table 1-1 (next page) demonstrates the trend towards 

lower utilization on the highlighted pipelines. Firm 

transportation contract expirations on these pipelines 

amounts to 34 percent of their contracted capacity 

over the next three years. 
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Figure 1-12 demonstrates that TGP, El Paso, and 

Northern Natural had the largest amounts of longterm firm capacity contracts expire in 2012. 

Figure 1-12 

Firm Transportation Contracted Capacity Expired in 2012

Source: Derived from Velocity Suite data based on FERC Form No. 549 B - Index 

of Customers data

During 2012, natural gas marketers reduced their 

share of firm transportation commitments on longhaul pipelines, while natural gas and electric utilities 

retained or grew theirs. Marketers were the largest 

share of customers whose contracted firm transportation capacity expired in 2012, with 46 percent of their 

total firm transportation capacity expiring. 

Marketers comprised about half of the customers 

holding firm transportation capacity on pipelines 

serving the Northeast. Electric and natural gas 

utilities made up the majority of firm transportation 

customers on pipelines serving the Midwest markets, 

since the majority of the capacity is held by local 

distribution companies (LDCs). Nearly 30 percent of 

their firm contracted capacity expired in 2012. 

Figure 1-13 illustrates the decline in contracted 

capacity subscribed by marketers and the relative 

increase in capacity contracted by producers between 

the second quarter of 2008 and the second quarter of 

2012. 

Figure 1-13

Customer Mix Shifts from Marketers to Producers

Source: Derived from Velocity Suite data based on FERC Form No. 549 B - Index 

of Customers data

Table 1-1

Pipeline Flow Utilization at Key Locations

ANR Trunkline NNG TGP TETCO El Paso

Point SE SW N. TX Station Station Northern Southern North San Eunice

Location Mainline Mainline to LA N. LA Nebraska 200 325 Gulf Leg Gulf Leg Mainline Juan Station*

2009 72% 54% 93% 72% 87% NA NA 72% 83% 95% 81% 76%

2010 70% 67% 87% 79% 77% NA NA 77% 86% 80% 79% 73%

2011 50% 80% 75% 96% 62% 37% 89% 59% 75% 66% 73% 66%

2012 39% 84% 79% 83% 58% 34% 82% 24% 38% 62% 69% 89%

Source: Derived from Velocity Suite data * Texas Flows
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As contracts shifted from long haul to shorter haul, 

the term of contracts were reduced. Contracts with 

terms longer than 10 years declined on ANR pipeline, 

while three to four-year and shorter than one-year 

term contracts increased in 2012. In some cases 

producers stepped up their presence and were more 

willing to enter into long-term capacity commitments. 

Shippers on pipelines declined to renew some longterm contracts that sourced natural gas supplies from 

Canada. On October 31, 2012, 1.3 Bcfd, or 60 percent, 

of firm transportation capacity on the Great Lakes Gas 

Transmission Pipeline (Great Lakes shown on Figure 

1-14) expired. TransCanada PipeLines, which owns 

Great Lakes, held more than half of this capacity, 

while marketers held most of the remaining expiring 

contracts, most of which were also not renewed. An 

additional 370 MMcfd of contracted firm transportation capacity is set to expire in 2013, while TransCanada’s remaining contracts on Great Lakes, equaling 

313 MMcfd, are set to expire in 2014. 

Figure 1-14

Great Lakes Gas Transmission Pipeline Receipt/Delivery 

Points

ANR

TransCanada Mainline

Emerson

St. Clair

Farwell

Niagara

Source: Derived from Ventyx data

Due to declining utilization, some pipeline owners 

proposed to convert segments or entire natural gas 

lines to transport crude oil and products. TransCanada filed plans with its regulator, the Canadian National Energy Board, to convert sections of its intercontinental Mainline to carry up to 900,000 barrels/day 

of crude oil from the oil sands in Alberta to refineries 

in eastern Canada. In July 2012, Trunkline Gas Co. 

proposed to convert 770 miles of its loop line to oil.

Pipelines with access to new local production, such 

as the Marcellus, are focused on building capacity 

to relieve local supply bottlenecks. They expect to 

replace expired and expiring long-haul firm contracts 

with short-haul contracts. Anticipation of long-haul 

natural gas pipeline contract expirations in the near 

term have increased the financial risk faced by longhaul natural gas pipelines. A number of pipelines 

are reporting rates of return lower than their allowed 

rate of return, which increases the likelihood they will 

ask the Commission for rate increases in the coming 

years. 
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Superstorm Sandy 

Superstorm Sandy, which landed on Monday, October 29, 

significantly hobbled the Northeast power sector. Northeastern utilities declared that it was the most crippling 

event in their history. Distribution outages were extensive 

and resulted in more than six million customers without 

power by the morning of Wednesday, October 31. Several 

power plants were forced out of service, including three 

nuclear plants. At least one plant, Dynegy’s 500 MW 

Danskammer plant, was rendered inoperable and its owner 

announced it would retire the plant. The most notable 

impacts from the storm were the significant loss of load 

and, generally, lower prices that resulted from the lost 

load. Despite the interruption to financial markets on Wall 

Street, power trading on the Atlanta-based IntercontinentalExchange, Inc. (ICE) and on CME Group (CME) continued 

throughout the storm.

Due to the storm, utilities lost revenue and incurred substantial capital costs. Long Island Power Authority (LIPA) 

was one utility hardest hit by Sandy and the subsequent 

November 11 Nor’easter. LIPA’s load dropped approximately 2,100 MW on the first day of the storm, costing LIPA and 

its suppliers lost revenues. Upon completing early estimates, utilities expected to see capital costs in excess of 

$1 billion. LIPA estimated capital requirements at between 

$800 and $850 million. Consolidated Edison Company of 

New York, Inc. (ConEd) expected response and restoration 

costs to be between $350 million to $450 million. Public 

Service Electric and gas Company (PSEG) estimated restoration costs to be as much as $300 million.

On the natural gas side, lower demand for natural gasfired generation helped mitigate the impact of Superstorm 

Sandy on the Northeast natural gas market. Demand, 

which was already low during this shoulder season, dipped 

lower as outages reduced fuel consumption by natural 

gas-fired generators. Decreased demand was temporary, 

as natural gas-fired generation ramped up to substitute for 

lost nuclear generation. Jurisdictional pipelines did not experience major damage or disruptions. The hurricane had 

no discernible impact on wholesale prices or production.

Import Constrained Southern California 

Experiences Tightened Energy Market

An extended outage of the two-unit San Onofre Nuclear Generating Station (SONGS) in Southern California led to a tightening of the supply-demand balance 

in the southern part of the CAISO market, particularly 

in peak load hours. The outage increased reliance on 

natural gas-fired generation, which in turn increased 

demand for natural gas, affecting both natural gas 

and power prices in the region. Higher-than-average 

hydroelectric generation and increases in wind production in the Northwest helped ease the tight supply 

conditions into the early summer. However, transmission limitations in the Southern California Edison Company (SCE) and San Diego Gas and Electric 

Company (SDG&E) load areas affected the amount of 

power that could flow into the region. 

The two SONGS units (2,200 MW) were unable to 

operate for most of 2012. Unit 3 went off line in 

January due to a steam generator tube leak. 9 Unit 2 

was already out of service for scheduled maintenance 

and remained offline when investigation of the cause 

of Unit 3’s leakage found similar design problems in 

Unit 2’s steam generators. 

The loss of the SONGS units removed a large source 

of power generation, tightening the supply located 

within the greater Southern California and San Diego 

load pockets. Further, the SONGS units had provided 

voltage support for transmission flows into the region, 

so the loss of the two units reduced the amount of 

imports the system could maintain. CAISO, SCE and 

9 The steam generator tube leak in SONGS Unit 3 was caused by tube-to-tube wear from 

excessive vibration. A small amount of radioactive steam was released during the tube 

leak event. The steam generators for both units had been replaced in the past two 

years. Nuclear Regulatory Commission, “Special NRC Oversight at San Onofre Nuclear 

Generating Station: Steam Generator Tube Degradation,” Nuclear Regulatory Commission 

website, http://www.nrc.gov/info-finder/reactor/songs/tube-degradation.html, accessed 

January 4, 2013.
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SDG&E developed contingency plans to address power needs for the summer of 2012. Huntington Beach 

power plant Units 2 and 3 were brought out of retirement to provide generation and local voltage support. 

SDG&E accelerated construction of its new 500 kV 

transmission project, the Sunrise Powerlink, bringing 

it online in June. Sunrise Powerlink supported power 

imports into San Diego and helped achieve import 

levels similar to those occurring before the SONGS 

outage. SDG&E and SCE upgraded other transmission 

facilities to improve flows in the region.10

With the nuclear units offline, replacement power 

came primarily from increased generation at natural 

gas-fired power plants. California’s natural gas-fired 

generation output reached about 37 percent of average hourly generation in the second quarter of 2012, 

compared to about 22 percent of generation in the 

second quarter of 2011. Natural gas-fired generation 

provided about 45 percent of average hourly generation in the third quarter of 2012, up from 33 percent 

in the third quarter the prior year. This contributed to 

a 13 percent increase in natural gas demand in California overall compared to 2011 levels. With nearly 

0.7 Bcfd of additional natural gas demand, the price 

of natural gas at the Southern California Citygate 

price rose. See Chapter 2 for discussion of natural 

gas prices. 

While customers did not lose power as a result of the 

tightened supply of electric generation, the reduction in supply led to increased price levels and price 

spikes. CAISO dispatched less efficient units, increasing the cost of power. Further, CAISO experienced 

price spikes due to insufficient amounts of generation 

available for ramping up or down to meet changes in 

demand (ramp capacity), especially in the San Diego 

area. This lack of local ramp capacity increased the 

incidence of price spikes experienced in the area, as 

shown in Figure 1-15.11 Other power system issues, 

including updated transmission limits for voltage 

stability and unscheduled power flows (also known as 

loop flow), contributed to the price spikes.

Figure 1-15

California Price Spikes Increase in 2012

Source: Derived from CAISO data via Ventyx

Price spikes in the real-time market led to higher 

overall prices particularly in August and September. 

Eventually, these higher prices carried into the dayahead market, in part due to convergence bidding and 

modeling changes. Figure 1-16 illustrates the onpeak, day-ahead prices in the San Diego load zone, 

which were noticeably elevated in August and 

September, but below 2011 levels on average.

10 California Independent System Operator (CAISO), “Briefing on Summer 2012 Operations 

Preparedness,” March 22-23, 2012, CAISO web site, http://www.caiso.com/Documents/

BriefingSummer2012OperationsPreparedness-Presentation-Mar2012.pdf, accessed March 

8, 2013.

11 CAISO experienced price spikes in prior years as well, also due to a large extent to insufficient ramp capability. The ISO has taken steps to address the situation and spikes in 2011 

declined from 2010 levels. In December 2011, CAISO implemented a market software feature, or “constraint,” to procure ramp capability in the 15-minute and five-minute model 

runs of the real-time market. However, the constraint procured ramp capability across 

the entire CAISO transmission system, not by specific locations where it might be needed. 

Without sufficient ramp capability in the ISO’s southern region, real-time market price 

spikes increased. See “California ISO Q4 2012 Report on Market Issues and Performance”, 

Feb. 12, 2013, CAISO web site, http://www.caiso.com/Documents/2012FourthQuarterRepo

rt-MarketIssues-Performance-Feb_2013.pdf, accessed March 27, 2013.
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Figure 1-16

CAISO Electricity Prices at San Diego Increase with 

Summer Stresses and SONGS Outage

Source: Derived from CAISO data

The 2013 summer may again be challenging for 

Southern California. SCE, the plant’s operator and 

part owner, filed with the Nuclear Regulatory Commission to operate Unit 2 at partial capacity for five 

months. However, CAISO is planning its summer 

operations assuming the units will not be available. 

Further, the Huntington Beach generation from Units 

3 and 4 will no longer be available due to a lack of 

air emission permits. The ISO, SCE and SDG&E are 

again pursuing contingency plans for the summer, 

which primarily focus on improving the ability of the 

southern system to move power.

The loss of SONGS also increased the need for carbon 

allowances in the power sector, as natural gas generation replaced lower emitting nuclear generation. This 

additional demand may put upward pressure on carbon allowance prices in the Greenhouse Gas Cap-andTrade Program that California implemented in 2013.

CAISO Ramp Constraint Fails to Support San 

Diego Operations without SONGS

From time to time, CAISO lacks generating capacity that can flexibly increase or decrease output to 

quickly keep up with supply and demand changes. 

Such fast-moving generation is referred to as ramp 

capacity. At times when CAISO lacks ramp capacity, certain market software constraints are violated, 

i.e., constraints associated with requiring supply and 

demand to be equal (in the CAISO market, this is 

called the power balance constraint). When this happens, penalty prices are triggered (at $1,000/MWh for 

energy shortages), and real-time prices spike.

In December 2011, CAISO implemented a constraint 

in its market software to procure sufficient ramp 

capacity in the real-time market. This flexible ramp 

constraint was imposed in the 15-minute pre-dispatch 

and the five-minute real-time model runs to ensure 

that ramping capacity is procured to meet system 

needs. However, CAISO implemented the constraint 

for the ISO as a whole, rather than for specified locations. This failed to prevent insufficient ramp capability to meet load ramping needs around San Diego 

in summer 2012.12 Figure 1-15 on page 22 illustrates 

the rise in price spikes with the SONGS outage.

Price spikes increased for CAISO as a whole as well, 

as shown in Figure 1-17 on the next page. The graph 

shows the number of five-minute intervals when 

prices rose above $250/MWh as well as the instances 

when prices rose above $1,000/MWh. Implementation of the ramping constraint led to decreased price 

spikes in the first quarter of 2012, which was seven 

12 CAISO Department of Market Monitoring, “California ISO Q4 2012 Report on Market 

Issues and Performance,” March 22-23, 2012, CAISO web site: http://www.caiso.com/Do

cuments/2012FourthQuarterReport-MarketIssues-Performance-Feb_2013.pdf, accessed 

March 8, 2013.
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2012

times fewer than the same quarter in 2011. However, 

the number of spikes increased by a factor of four in 

the second quarter of 2012 due in large part to insufficient ramp during adverse conditions around San 

Diego. In the third quarter of 2012, the number of 

spikes increased further, driven mainly by San Diego 

price spikes. 

Figure 1-17 

Real-Time Price Spikes in California Q1 2011 to Q3 2012

Source: Derived from CAISO data via Ventyx

Because ramp is procured system wide, and transmission constraints limit the ability of power to move 

into Southern California and San Diego, not all ramp 

was available to address the ramping needs in that 

part of the state. According to CAISO’s market monitor, the average amount of ramp procured in San 

Diego in the second half of 2012 was 62 MW. Almost 

two-thirds of the procured ramp lies in Pacific Gas & 

Electric’s load area, which falls on the opposite side 

of constrained pathways and therefore cannot help in 

San Diego and may, instead, tend to increase congestion on the constrained path.

CAISO implemented a stakeholder process to develop 

a short-term ramp product and is working with the 

California Public Utilities Commission (CPUC) and 

others in California to develop products that take into 

account locational ramp needs in the CPUC’s resource 

adequacy procurement process.

New Phase Angle Regulating Transformers

between Michigan and Ontario Entered 

Service

ITC, the transmission owner in Michigan at the border 

with Ontario, Canada, installed new phase angle regulator (PAR) equipment in April of 2012. The equipment was installed on one of four lines that cross the 

Michigan-Ontario border. Existing PAR equipment 

was in place on the other three lines. After repairs 

and adjustments to other related equipment, MISO 

and the Independent Electric System Operator (IESO), 

Ontario’s grid operator, placed the interface between 

Michigan and Ontario under full PAR control on June 

29, 2012.

Phase angle regulators are electrical devices that help 

control electricity flows, typically across key transmission elements or paths.13 When actual electricity 

flows diverge substantially from scheduled contract 

paths, resulting loop flows can adversely affect power 

markets.14 By controlling the flow of electricity, PAR 

equipment helps align electricity flows with scheduled 

transactions. Loop flows can cause congestion on 

systems that are not part of a particular transmission 

transaction. Participants in affected transmission 

systems have no direct way to be compensated for 

 13 Phase angle regulators are special purpose transformers that change the phase angle 

at their location, allowing power flows to be regulated. Power flows may not match 

contract paths in that power flows follow Ohm’s Law in which electricity takes its own 

path in inverse proportion to the impedance of the lines in a parallel circuit. So, power 

transfers use every available electrical path between source and sink, regardless of 

contract schedules.

14 On an interconnected grid of transmission, the movement of electricity from generator 

to load typically spreads and flows along one or more parallel paths. Loop flow refers to 

electricity’s flow along a path or paths that departs from the scheduled or contract path. 
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the congestion or to control flows for reliability. For 

reliability, balancing authorities must rely on cumbersome Transmission Loading Relief (TLR) procedures to 

prevent potentially harmful flows from other parties’ 

transactions. 

From July through December, loop flow across the 

MISO-Ontario interface averaged 79 MW, and has 

steadily declined with increased operational experience. This was much narrower than 157 MW for the 

same period in 2011. MISO has studied the success 

of the installation thus far and reports that congestion costs in Michigan are lower with fewer binding 

constraints.15 According to MISO, the control of loop 

flow has also reduced the need for TLR procedures 

and has boosted the interchange capacity across the 

Michigan-Ontario interface.

The time over which the Michigan-Ontario PAR 

equipment was in full service in 2012 was a relatively 

short period. For years, loop flow around Lake Erie 

has caused difficult-to-manage congestion and reliability costs in the four surrounding regions, NYISO, 

IESO, MISO, and PJM. PAR control on the interface 

was the culmination of more than 20 years of projects.

Completion of the final parts of the project became a 

topic of interest in the discussions that stemmed from 

an increased incidence of costly loop flow experienced by the NYISO in 2007 and 2008. The flows 

increased uplift costs in NYISO by approximately 

$95 million because of uncompensated congestion in 

western New York. NYISO prohibited select transactions to control loop flows. This issue prompted a 

general study of Lake Erie loop flow and a multi-region program to find solutions. One of the solutions 

discussed in the program was the use of PAR equipment.16

As MISO and IESO gain experience in the operation 

and effects of the PAR equipment, they may identify 

further needed adjustments to the operation procedure to better control loop flow. Since the use of PAR 

equipment on the Michigan-Ontario interface affects 

the pricing, congestion costs, and reliability of various market regions, Commission staff will continue to 

examine the operational protocols used, behavior of 

market participants, and pricing implications. 

Figure 1-18

Lake Erie Loop Flow and Surrounding RTOs

Lake Erie

MISO

PJM

IESO

Mich-Ont

Interface

Source: Derived from Ventyx data

15 MISO, “Market Impact of Michigan-Ontario Phase Angle Regulators,” Report to the 

Market Subcommittee, February 5, 2013, MISO web site, https://www.midwestiso.org/

Library/Repository/Meeting%20Material/Stakeholder/MSC/2013/20130205/20130205%20

MSC%20Item%2006a%20PARS%20Market%20Impact.pdf, accessed March 12, 2013.

16 The Commission explicitly directed NYISO to include a discussion of the use of PAR 

equipment in the report on solutions to loop flow. See New York Independent System 

Operator, Inc., 128 FERC ¶ 61,239 at P 8 (2009).
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MISO Successfully Counters Wind Loss with 

Spinning Reserves

Nationally, variable energy resources make up an 

increasing percentage of new generating capacity.17 

Wind generation, in particular, has reached a point 

where it has become a substantial component of the 

nation’s energy supply. Total wind generating capacity surpassed 50 GW in August of this year, twice the 

25 GW the U.S. had by year-end 2008 and 10 times 

the 5 GW mark reached in 2003. While events such 

as the following have been rare, the successful commitment and use of ancillary services to balance supply at a time of supply variability was an important 

example of the manner in which such resources can 

be managed in the electricity markets. 

Figure 1-19

Wind Powered Generation Falls During Evening Ramp 

(February 20, 2012)

Source: Derived from MISO data

In one of the largest wind-generating regions, MISO 

reported total wind capacity of 10,600 MW or almost 

10 percent of its installed capacity. On February 20, 

2012, on one of the market’s higher wind production 

days where wind output had been averaging about 

6,000 MW since the night before, MISO suddenly lost 

500 MW of wind-powered generation. Occurring 

during the evening ramp (Figure 1-19), MISO called 

on 500 MW of spinning reserves to successfully stay 

within reliability limits during the 10-minute loss. 

Prices spiked by almost $100/MWh from the previous 

$18-$24 range for two five-minute periods, though 

MISO did not analyze the dispatch to separate the 

effects of the sudden wind loss from the increasing 

load. 

The historic peak at year-end 2012 was 9,885 MW set 

on November 23. Except for this event, MISO had 

previously managed the large amount of wind in its 

system without reliability-based reserves.

17 A Variable Energy Resource is a device for the production of electricity that is characterized by an energy source that: (1) is renewable; (2) cannot be stored by a facility owner or 

operator; and (3) has variability beyond the control of the facility owner or operator. This 

includes, for example, wind, solar thermal and photovoltaic, and hydrokinetic generating 

facilities. See Integration of Variable Energy Resources Notice of Proposed Rulemaking, 

FERC Stats. & Regs. ¶ 32,664, at P 64 (2010).
FEDERAL ENERGY REGULATORY COMMISSION

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Chapter 2: Natural Gas Markets in 2012

Summary

2012 was a year for breaking records in the U.S. natural gas industry, with plentiful natural 

gas supply satisfying a growing market. Natural gas prices were at or near 10-year lows 

across the nation for most of 2012. Driven by shale natural gas, average daily natural gas 

production grew 5 percent to a record 65.7 Bcfd, a level unseen since the 1970s (Figure 2-1). 

Low prices and strong domestic production contributed to the lowest natural gas imports 

via pipeline from Canada or LNG from overseas since 1998. Overall, U.S. natural gas supply 

grew 3.2 percent to 71.5 Bcfd.

Spurred by low natural gas prices, average daily U.S. natural gas demand grew 4.4 percent 

to 70 Bcfd, the highest level on record. Growth was led by the power sector, which saw a 4 

Bcfd18 or 21 percent year-over-year increase in natural gas demand, as natural gas-fired generators were increasingly utilized in preference to coal generation, particularly in PJM and 

the Southeast states. However, high natural gas demand for power generation was offset by 

a 2.3 Bcfd or 10 percent decline in residential and commercial demand following one of the 

warmest winters on record.

The warm winter and plentiful natural gas supply resulted in relatively low winter withdraw-

 18 Includes pipeline loss and exports to Mexico.
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als from natural gas storage during the first quarter of 

2012 and the highest storage level ever at the beginning of the traditional refill season in April. This, 

coupled with strong spring and fall injections, contributed to record levels of natural gas in storage by 

the beginning of the 2012-13 winter. 

North American LNG import facilities were not able 

to attract many cargoes in 2012 because U.S. natural 

gas prices were four to five times lower than the rest 

of the world, and net imports fell 131 Bcf for the year. 

As a result LNG sendout into the U.S. pipeline system 

fell 53 percent and averaged 342 MMcfd. Furthermore, abundant U.S. natural gas supplies led to proposals to build liquefaction facilities to export cheaper 

domestic natural gas to the higher priced markets in 

Asia and Europe. 

Even as companies contemplated LNG exports, U.S. 

natural gas exports to Mexico increased 25 percent in 

2012, to 1.7 Bcfd. Exports of Marcellus Shale natural 

gas to Canada also commenced in the latter half of 

2012. Figure 2-1 shows the major components of U.S. 

natural gas supply and demand in 2012 compared to 

2011.

Figure 2-1

U.S. Natural Gas Supply and Demand – 2011 vs. 2012

0

10

20

30

40

50

60

70

80

2011 2012

Average Daily Volume (Bcfd)

US Natural Gas Supply

0

10

20

30

40

50

60

70

80

2011 2012

Average Daily Volume (Bcfd)

US Natural Gas Demand

Total Change in Demand:

Power 

Generation

Net Dry Gas

Production

Net Inports 

From Canada

3.2%

5.0%

-47.3%

-8.8%

20.6%

2.8%

Net LNG 

Imports

Industrial

Total Change in Supply 4.4%

-10.0% Residential/ 

Commercial

Net Exports to 

Mexico 24.9%

Lease/Production 

& Pipeline Fuel 5.0%

Source: Derived from EIA data

U.S. Natural Gas Prices Fall to 10-Year Lows

Strong production growth from shale natural gas 

helped push U.S. natural gas prices to a 10-year 

low in 2012. The spot price at Henry Hub averaged 

$2.74/MMBtu for the year, down 31 percent from 

2011. Natural gas prices at all trading points in the 

U.S. experienced price drops in the 22 to 36 percent 

range. Regional differences in prices (basis) also fell. 

This was driven by rising shale natural gas production closer to consuming markets and additional 

pipeline infrastructure that eliminated transportation 

constraints from most regions. Growing Marcellus 

Shale natural gas production in the Northeast caused 

the basis between most Northeast price points and 

the Henry Hub to flatten. In the Southeast, energy 

efficiency savings and capacity expansions on Florida 

Gas Pipeline reduced price spikes at the FGT-Z3 hub.

Although the convergence of regional natural gas 

prices was good for consumers, it put financial pressure on some long-haul pipelines, which experienced 

flows falling either on segments of the pipelines or 

sometimes the entire route. Pipelines which move 

natural gas from the Gulf Coast and the Rocky Mountains into the Northeast experienced the greatest 

declines in utilization. Marcellus natural gas displaced Gulf natural gas to the Northeast, which led to 

underutilization on the southern portion of pipelines 

such as Tennessee Gas Pipeline and Texas Eastern 

Pipeline. Similarly, the Rockies Express Pipeline, 

which moves natural gas from the Rocky Mountains 

to Ohio, experienced a sharp drop in volumes in 2012. 

The new natural gas flow patterns raised the possibility that some pipelines may not be able to find buyers 

for long-term capacity once their current contracts 

expire. Further discussion of natural gas pipeline 

contract expiration and re-contracting is provided in 

Chapter 1.
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The only region to experience sustained pipeline 

constraints in 2012 was New England. There were no 

significant pipeline capacity additions into this region 

in 2012 and New England was not able to fully benefit from nearby Marcellus natural gas production. As 

a result, the Algonquin Citygate, near Boston, experienced the highest spot prices in the nation, averaging $3.91/MMBtu for the year. With the exception of 

very cold days, there were few natural gas transportation constraints into New York City and spot prices 

at Transco Zone 6 NY averaged $3.19/MMBtu for 

the year. In California, increased demand for natural 

gas-fired power generation due to the outage of the 

SONGS nuclear plant put upward pressure on natural 

gas prices through spring and summer. In contrast, 

prices in the Rocky Mountains were among the lowest, averaging $2.59/MMBtu at the Colorado Interstate 

Gas (CIG) hub (Figure 2-2). 

Figure 2-2

Average Spot Natural Gas Prices, 2012 ($/MMBtu)

Federal Energy Regulatory Commission • Market Oversight • www.ferc.gov/oversight

Average Spot Natural Gas Prices, 2012 ($MMBtu)

2181

Columbia

TCO

Algonquin

Citygate

AECO 

Hub

Pricing Point

BOLD – Year to Date Price

Green – % increase from 

previous year

Red – % decrease from 

previous year

Chicago

Citygate

Transco

Z6-NY NGPL

Tex-Okla

El Paso

Permian

SoCal 

Border

PG&E

Citygate

CIG

NW 

Sumas

HSC

Henry 

Hub

FGT-Z3

2.68

-31%

2.26

-34%

2.84

-31%

3.91

-22%

2.59

-31%

3.11

-27%

2.91

-28%

2.66

-31%

2.70

-31%

2.77

-32%

3.19

-36%

2.70

-32%

2.74

-31%

2.92

-28%

Source: Derived from Platts data
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Natural gas prices began to strengthen in late October 

and November, largely as a result of high natural gas 

demand from power generators and the onset of the 

winter heating season (Figure 2-3). Forward contracts 

showed continued strength into the 2013 spring and 

summer. Higher forward contracts were supported 

by forecasts of colder temperatures for the winter 

of 2012-2013 than those seen the previous winter, 

and continued strong demand from natural gas-fired 

power generators.

Figure 2-3

Historical Next-Day Natural Gas Prices

Source: Derived from Platts data

Record U.S. Natural Gas Supply in 2012

The breakneck rate of U.S. natural gas production 

growth seen over the past five years slowed during the first half of 2012 due to a combination of 

low natural gas prices, cutbacks in natural gas drilling, and the shift toward more profitable oil drilling 

(Figure 2-4). However, U.S. natural gas production 

began to pick up again in the second half of the year, 

driven primarily by rapid increases in Marcellus Shale 

(Pa.) and Eagle Ford Shale (Tex.) natural gas production, and overall U.S. natural gas production rose 5 

percent. This led to 3.2 percent growth in total U.S. 

natural gas supply despite a large fall in natural gas 

imports via pipelines from Canada and as imported 

LNG.

Despite an active hurricane season, weather did not 

have a significant impact on U.S. gas production in 

2012. Tropical Storm Debby and Hurricane Isaac 

both entered the Gulf of Mexico. However, the loss in 

production due to offshore well shut-ins amounted to 

only 32 Bcf a tiny fraction of U.S. natural gas production that totaled more than 24 Tcf in 2012.

Figure 2-4

U.S. Dry Gas Production Growth Slows in First Half of 

2012

Source: Derived from Bentek Energy data

The slowdown in production growth during the first 

half of 2012 was caused by a 55 percent drop in the 

rig count. The number of active rigs drilling for 

natural gas fell from 936 in October 2011 to 416 on 

December 31, 2012 (Figure 2-5). Despite the drop in 

rigs, production continued to climb in part due to 

improved drilling technology and practices. Increased 

rig efficiency allowed producers to cut the number of 

days it takes to drill a well and drill more wells per rig 

(See Box on next page). 
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Drilling Rig Efficiencies Offset Falling Natural Gas Rig Count

The drive to exploit shale oil and natural gas reserves 

coupled with falling natural gas prices touched off a race 

to reduce drilling costs and improve rig operating efficiency. 

These improvements resulted in production increases even 

as the gas-directed drilling rig count fell.

The revolution in drilling began in the early part of the last 

decade as years of experimentation with horizontal drilling 

techniques, three-dimensional (3-D) seismic analysis and 

hydraulic fracturing in the Barnett Shale finally began to 

yield results. Using enhanced 3-D seismic analysis, drillers perfected the technique of drilling horizontally along a 

natural gas-bearing formation. This stood in stark contrast 

to the previous method of drilling vertical wells to try and 

strike the sweet spot of a known natural gas reservoir. 

Drilling advances reduced the number of dry holes drilled, 

thereby increasing the well success rate and reducing the 

cost of exploration and development. These techniques, 

once refined, were particularly suited to shale deposits 

because of their wide geographic extent and easily defined 

pay zone, where natural gas was abundant.

The overall oil and natural gas well success rate in 1998 was 

79 percent, meaning 21 percent of oil and gas wells drilled 

came up dry. By 2002, Barnett Shale natural gas production began to rise, driving success rates of all wells up to 85 

percent. As the techniques were applied first to other shale 

natural gas deposits and later to oil-bearing shales, success 

rates for wells climbed above 90 percent in 2012.

Rig design has also improved to better exploit shale deposits. Drillers, who use electricity to power their rigs, moved 

from DC- to AC-powered rigs for greater mobility and 

reliability, plus quieter operations. Newer rigs have more 

precise digital controls that result in less downtime from 

breakdowns. Because of these efficiencies, drilling a well 

takes less time. In the Barnett Shale, an average of 20 days 

to drill a well near the end of 2007 fell to only 13 days at 

the end of 2011. Now, between eight and 25 wells can be 

drilled on a single well pad. Drilling multiple wells on one 

pad saves time and money, since the rig does not have to be 

broken down, moved, and re-assembled between wells.

Technology has extended to drilling bits, which have been 

improved through new designs and materials. These stateof-the-art bits can be used for longer periods before servicing, and allow companies to drill a horizontal well with one 

bit, without having to pull the drill to change or service a bit.

Figure 2-5

Natural Gas Rig Count Drops with Lower Prices

Source: Derived from Baker Hughes and Platts data

The impact of the declining natural gas rig count on 

natural gas production was mitigated by new production from wells that had been previously drilled, 

but not completed and brought into production. By 

the end of 2011, approximately 2,500 wells had been 

drilled but not completed due to the lack of available pipeline capacity to transport the natural gas to 

market. Some of the wells were completed and began 

producing in 2012 as new gathering systems and 

pipelines were placed into service. Uncompleted wells 

are not the same as natural gas in storage, since they 

are either not yet connected to the pipeline system, 

or are at different stages of completion, and can take 

several weeks or months to bring into production. 

However, once connected they provide an immediate 

bump in production. Drilling companies also shifted 

drilling rigs from dry natural gas areas to areas rich 

in natural gas liquids (NGL). Rigs drilling in oil and 

NGL areas are generally not counted as natural gas 

rigs. However, oil and NGL production yields substantial amounts of associated natural gas.
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Natural gas production growth in 2012 was driven 

by large increases from the Eagle Ford and Marcellus 

Shale formations. Fayetteville Shale also increased 

moderately in natural gas production, but the other 

three major shale plays saw production stall or decline (Table 2-1). 

Marcellus Shale natural gas production grew because 

companies migrated to the NGL-rich regions in western Pennsylvania and West Virginia from dry natural 

gas areas in northeastern Pennsylvania. Also, Marcellus Shale natural gas is of high value because of 

its proximity to Northeast natural gas markets. Eagle 

Ford Shale natural gas production in Texas grew as 

producers increased drilling in NGL and crude oil-rich 

areas of the formation.

At the end of 2012 production from the six major 

shale formations made up 38 percent of total U.S. 

natural gas production, up from 22 percent at the 

beginning of 2011. Overall growth of shale natural 

gas production and a breakdown by basin is shown in 

Figure 2-6. 

Figure 2-6 

Natural Gas Production by Shale Formation

Source: Derived from Bentek Energy data

 

Table 2-1 

Shale Gas Production by Basin (Bcf/year)

Basin Type (Wet/Dry) 2011 2012 Percent Change

Marcellus Wet/Dry 1,515 2,632 73.7

Haynesville Dry 2,308 2,295 -0.6

Barnett Wet/dry 2,062 2,059 -0.15

Eagle Ford Wet/dry 815 1,250 53.4

Fayetteville Dry 1,052 1,103 4.9

Woodford Dry 578 562 -2.8

Total 8,330 9,901 18.9

Source: Derived from Bentek Energy data
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Crude Oil and Natural Gas Liquids Add Value 

to Natural Gas Production

Much of the new natural gas produced in 2012 was 

associated with crude oil and NGL production. Drilling companies shifted drilling rigs from dry natural 

gas areas to areas rich in oil and NGLs, such as the 

Eagle Ford Shale and Bakken Shale, because the price 

of U.S. benchmark West Texas Intermediate (WTI) 

crude oil in 2012 averaged $94.58/barrel, or $16.30/

MMBtu. This made WTI over six times more valuable 

than natural gas on a dollar per MMBtu basis.

Natural gas marketed to and used by consumers is 

primarily methane. Liquids-rich natural gas formations produce methane in combination with other, 

higher Btu products such as ethane, propane, butane, 

isobutane, and natural gasoline. The exact amount of 

NGLs and other components varies by well. Table 2-2 

shows the makeup of a representative NGL barrel, and 

the main uses for each component.

Table 2-2

Types and Uses for Natural Gas Liquids

Component Content in Typical Barrel Primary Uses

Ethane 40% Petrochemical feedstock in production of ethylene, which in turn is used to 

 make plastics, detergents, lubricants, etc.

Propane 29% Heating, cooking, and transportation fuel, petrochemical feedstock

Natural Gasoline (condensate) 16% Motor gasoline production

Butane 10% Motor gasoline production, torch fuel, petrochemical production

Isobutane 6% Refrigerant, aerosol propellant, petrochemical production

Source: Typical barrel content derived from Tudor Pickering data

The price of ethane fell 48 percent in 2012, while the 

price of propane fell 32 percent. Rapid expansion in 

NGL production coupled with a drop in processing capacity due to plant maintenance resulted in oversupply. However, prices for higher value NGLs including butane and natural gasoline remained relatively 

strong, as these products are more closely tied to oil 

prices, see Figure 2-7. The price of a representative 

barrel of NGLs averaged $14.54/MMBtu in 2012 compared to $17.52/MMBtu in 2011, a 17 percent drop. 

Figure 2-7 

Natural Gas Prices Remained Below NGL Prices in 2012

Source: Derived from Bloomberg data
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The value NGLs added to a well’s production stream 

can be significant, although NGL content differs 

depending on the shale formation, the drilling site 

within a shale formation, and even the number of 

wells on a drilling pad. For example, a well producing 75 percent dry natural gas and 25 percent NGLs 

could sell its production stream for about $5.64/

MMBtu, while a production stream composed of 25 

percent dry natural gas and 75 percent NGLs could 

be sold for $11.43/MMBtu. Figure 2-8 shows values 

added to a natural gas/NGL well for three different 

NGL content levels. 

Figure 2-8 

Value Added to a Production Stream Based on NGL 

Content

Source: Derived from Bloomberg data

U.S. Natural Gas Consumption Sets New 

Record

Low natural gas prices helped drive average daily 

U.S. natural gas demand up 4.4 percent to a record 

70 Bcfd. This occurred despite a 10 percent decline 

in residential and commercial natural gas demand 

brought about by a mild winter in early 2012. Responding to very low natural gas prices, power burn 

grew 21 percent to 25 Bcfd in 2012. (Figure 2-9). 

Further discussion of the record use of natural gas in 

power generation is presented in Chapter 1.

Figure 2-9

Growth in Power Burn Drives Gas Demand in 2012

Source: Derived from Bentek Energy

Industrial gas demand grew 3 percent in 2012 to 19 

Bcfd. Precious metals, car manufacturing, and petrochemicals drove this growth. The expectation is for 

industrial gas demand to rise in the next few years as 

economic growth picks up and new industrial facilities, particularly petrochemical plants, are built to 

take advantage of expected low domestic gas prices 

and plentiful NGL supply. 

U.S. exports of gas to Mexico rose 25 percent in 2012 

to 1.7 Bcfd, primarily to meet increased power and 

industrial natural gas demand there. Also, exports 

of Marcellus Shale natural gas to Canada began in 

November 2012. 
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Natural Gas in Storage Sets New Record 

Natural gas storage is an indicator of the overall balance of the U.S. natural gas market. Plentiful storage 

indicates a market is well supplied relative to natural 

gas demand, while low storage indicates a market 

that is undersupplied relative to demand. Overall in 

2012, there was plenty of natural gas in storage, particularly at the end of the 2011-2012 winter heating 

season and the start of the 2012-2013 winter heating 

season. Robust storage fills during the spring and fall 

slowed during the summer as competition for natural 

gas supply grew from natural gas-fired power generators. Underground working natural gas storage 

capacity increased by more than 43 Bcf in 2012, all 

of it in the Gulf region.

Working gas in underground storage set a record for 

the second year in a row, peaking at 3,852 Bcf going into the 2012-13 winter as seen in Figure 2-10. 

Record storage resulted from a 934 Bcf surplus to the 

five-year average at the beginning of the refill season 

and robust spring and fall injections. The surplus 

was gradually worked off during the third-warmest 

summer on record and increasing utilization of natural gas for power generation. With less natural gas 

available for injection, storage injection rates over 

the summer were low, averaging 46 Bcf/week, when 

compared to a five-year average summer injection 

rate of 69 Bcf.

Figure 2-10 

Record Natural Gas Storage in 2012

Source: Derived from EIA data

U.S. Liquefied Natural Gas Imports Fall

U.S. liquefied natural gas (LNG) imports declined 

substantially in 2012 as low U.S. natural gas prices 

compared to the rest of the world made it difficult for 

U.S. import terminals to attract cargoes. Of the 12 

active U.S. terminals, only two, Everett LNG in Massachusetts and Elba Island in Georgia, received regular 

LNG cargoes throughout the year, albeit with lower 

frequency than in past years. The total volume of 

net LNG imports (i.e., imports into U.S. LNG terminals 

minus LNG that is re-loaded into tankers for delivery 

to other countries) at U.S. terminals in 2012 dropped 

77 percent compared to the amount imported in 2007, 

and 47 percent from 2011 imports, as shown in Figure 

2-11 on the next page. In addition, the Canaport LNG 

import terminal in New Brunswick, Canada, which 

primarily serves consumers in the Boston market, saw 

a sharp drop in incoming cargoes.
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Figure 2-11

U.S. LNG Imports Fall in 2012

Source: Derived from U.S. Department of Energy data

LNG prices in international markets are generally 

priced via long-term contracts linked to oil prices. 

LNG sold in Asia for around $15/MMBtu, four to five 

times higher than in the U.S. Prices were slightly 

lower in Europe, around $10-$11/MMBtu, while in 

South America imported LNG prices were around 

$12-$13/MMBtu. Figure 2-12 summarizes estimates 

of landed prices for LNG in global trade as of January 

2013.

Figure 2-12

World LNG Estimated Landed Prices for January 2013

Cove Point

$4.50

India

$11.55

UK

$8.75

Spain

$9.05

Belgium

$8.84

Japan

$12.40

Korea

$12.40 Lake Charles

$3.96 Altamira

$4.60

Cove Point

$4.40

India

$11.55

UK

$8.75

Spain

$9.15

Belgium

$8.99

Japan

$13.10

Korea

$13.10

Lake Charles

$3.93 Altamira

$4.57

Cove Point

$4.50

India

$11.55

UK

$8.75

Spain

$9.05

Belgium

$8.84

Japan

$12.40

Korea

$12.40 Lake Charles

$3.96 Altamira

$4.60

Cove Point

$4.60

India

$13.85

UK

$10.76

Spain

$11.80

Belgium

$10.35

Japan

$16.45

Korea

$16.45

Lake Charles

$3.28 Altamira

$3.85

Rio de Janeiro

$12.25

Bahia Blanca

$13.25

China

$16.05

Source: Derived from Waterborne Energy data

The abundance of low-priced U.S. natural gas production, combined with high prices in other regions of 

the world, created interest in exporting U.S. natural 

gas as LNG to markets in Asia, Europe, and South 

America. Attention shifted from LNG imports to 

future exports of U.S. natural gas as LNG. Table 2-2 

shows proposed U.S. LNG export projects and their 

status. It is unlikely that the U.S. will export any LNG 

before 2016 due to the long time horizon for building 

and permitting export facilities.
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Table 2-3

Proposed U.S. LNG Export Projects

U.S. Projects Location Quantity DOE FTA DOE Non-FTA FERC Approval Capacity

(Bcfd) Approval Approval Contracted

Sabine Pass LNG LA 2.20 Approved Approved Approved 96%

Freeport LNG TX 1.40 Approved Under Review Filed 50%

Freeport LNG Exp. TX 1.40 Approved Under Review Filed 0%

Lake Charles LNG LA 2.00 Approved Under Review Filed 0%

Cove Point LNG MD 1.00 Approved Under Review Filed 61%

Cameron LNG LA 1.70 Approved Under Review Filed 93%

Gulf LNG MS 1.50 Approved Under Review Filed 0%

Elba Island LNG GA 0.50 Approved Under Review Filed 0%

Golden Pass LNG TX 2.60 Approved Under Review NF 0%

Jordan Cove LNG OR 1.20 Approved Under Review Filed 0%

Oregon LNG OR 1.25 Approved Under Review Filed 0%

Excelerate Liq. TX 1.40 Approved Under Review Filed 0%

Gulf Coast LNG TX 2.80 Approved Under Review NF 0%

Corpus Christi LNG TX 1.80 Approved Under Review Filed 0%

Main Pass Energy Hub LA 3.22 Approved NF NF 0%

CE FLNG offshore TX 1.10 Approved Under Review NF 0%

Pangea LNG TX 1.10 Approved NF NF 0%

TOTAL 28.17 

Source: Derived from DOE data, FERC Docketed Proceedings, and Company Press Releases

In 2012, several organizations released studies assessing the impact of LNG exports on U.S. natural gas 

prices. The most anticipated was the U.S. Department 

of Energy (DOE)-commissioned study that analyzed 

the impact of LNG exports on the U.S. economy. 19 The 

report was required before DOE would approve U.S. 

LNG exports to countries with which the U.S. does not 

have a free trade agreement. Like most other studies, the DOE report concluded that the impact on U.S. 

prices would be limited. It also concluded that LNG 

exports will have a net economic benefit to the U.S., 

as price effects are more than offset by economic 

gains that result from trading LNG.

19 NERA Economic Consulting, “Macroeconomic Impacts of LNG Exports from the United 

States,” Report prepared for DOE, December 3, 2012, DOE website: http://www.fossil.energy.gov/programs/gasregulation/reports/nera_lng_report.pdf, assessed March 13, 2013.
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The Challenge for U.S. LNG Exports

As of the end of 2012, 16 companies had proposed more than 27 Bcfd of LNG export projects (Table 2-2). This includes exports to 

countries that have Free Trade Agreements (FTA) with the U.S., and non-FTA countries. If all projects are built and utilized, the U.S. 

would become the largest exporter of LNG in the world. In order for these projects to proceed, they must receive the necessary 

financial backing through firm capacity contracts as well as the appropriate Department of Energy approvals as well as an environmental impact assessment from FERC before construction.

Cheniere Energy’s Sabine Pass LNG is the sole project with secured financing backed by firm contracts and that has received the 

necessary regulatory approvals to export to countries with both FTA and non-FTA status. Cheniere contracted nearly all of its export 

capacity to global customers looking for a cheaper, more secure supply source. Holders of Sabine Pass capacity include Korea’s Kogas, India’s GAIL, Spain’s Gas Natural, and BG. The price of LNG sourced from Sabine Pass will be linked to the U.S. domestic natural 

gas price indexed at the Henry Hub, with an added liquefaction tolling fee, plus transportation costs.

Even if approved, it is highly unlikely that more than a handful of the proposed projects will be built, and the advantage is likely to 

go to early entrants such as Cheniere. By one estimate, the total world LNG market adds up to 30 Bcfd, and any U.S. project will 

have to compete against companies and countries that are already in those markets. Some U.S. competitors, such as Qatar, have the 

advantage of producing natural gas at nearly no cost.

Although current price spreads between U.S., Asian and European LNG markets support U.S. LNG export project proposals, the dynamics are likely to change as international competitors lower their prices to maintain market share. Despite price uncertainty, some 

countries such as Japan and Korea value access to stable and politically friendly LNG supplies. 

Liquefaction facilities generally need to run at high and stable utilization rates to be economically viable. Liquefaction facilities, on

average, run at 88 percent of capacity, and the newest facilities, such as those in Qatar, run at 99 percent. For U.S. LNG exports to 

be competitive in the global market, demand for U.S. LNG exports would have to be sustainable under firm contracts.

Another obstacle to long-term U.S. LNG exports is the potential for significant natural gas production from shale in other countries, 

such as China, Argentina, India, and Poland, which have been working to develop their shale natural gas potential. These countries 

have not yet been able to duplicate the U.S. shale gas success, but significant shale production from these regions would put downward pressure on LNG markets and make U.S. exports less competitive.

New Natural Gas Pipelines Concentrated Near 

the Marcellus Shale

There were a total of 22 FERC-approved gas pipeline 

projects completed in 2012, representing 3.1 Bcfd of 

additional capacity at a cost of $2.2 billion. The most 

significant natural gas infrastructure developments 

in 2012 took place in the Marcellus Shale region 

(Pennsylvania and points south and west), where a 

number of projects, mostly producer-supported, were 

developed to gather shale gas production and connect 

it to the interstate pipelines that traverse the region. 

Examples of large interstate pipelines that added 

capacity include Tennessee Gas Pipeline, Millennium 

Pipeline, and Texas Eastern. 

Marcellus Shale natural gas production, along with 

the new transportation, increasingly displaced Gulf 
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Coast and Rocky Mountains natural gas from the 

Northeast. Western Canadian natural gas was also increasingly displaced and, by November 2012, natural 

gas flows at the Niagara interconnect between TransCanada and TGP reversed as Marcellus natural gas 

began to flow into Canada. 

The New York City area, which had been one of the 

most constrained and highest-priced markets in the 

nation, is benefitting from growing Marcellus natural gas production and the new pipelines. New York 

City is now generally well supplied by several pipelines transporting Marcellus Shale natural gas. As a 

result, the basis between the Transco Zone-6 NY Hub 

and Henry Hub shrunk and saw less-frequent price 

spikes. By the end of 2012, natural gas in New York 

City became routinely cheaper than in New England 

(Figure 2-13). However, New England has remained 

constrained as the new production and infrastructure has simply moved the constraint points further 

downstream.

Figure 2-13

New Natural Gas Production and Pipelines Help Reduce 

Prices in New York City

Source: Derived from Platts data

The most notable pipeline infrastructure developments 

outside the Northeast did not involve new natural gas 

pipeline capacity, but the proposed conversion of natural gas pipelines into oil or NGL pipelines. Pipeline 

operators look for new means to extract value from 

underutilized natural gas pipeline capacity. Chapter 

1 discusses lower utilization of long-haul natural gas 

pipelines and proposals to convert them to transport 

crude oil.
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Chapter 3: Electricity Markets in 2012

Summary

In 2012, electricity prices continued to exhibit the low levels seen since the 2008 financial 

crisis and, in fact, decreased compared to 2011 in all regions of the U.S. The single prominent driver of this phenomenon was the price of natural gas, the price-setting fuel for most 

of the nation. Natural gas prices, already low going into 2012, fell even further the first half 

of the year. Other factors contributing to low electricity prices were the moderate level of 

electricity demand due to a mild winter, a slow economic recovery, and energy efficiency 

gains.

The past year saw these additional market trends and influences: 

•	 Most notably, the weather in 2012 was the warmest on record for most of the nation and was 

consistently warmer in both winter and summer. This weather caused lower demand in the winter. It also contributed to summer peaks, although summer increases in load were more moderate than the decline in winter loads, compared to the recent history of weather or temperature 

extremes.

•	 State-level energy efficiency programs contributed to lower growth rates in electricity consumption. In state programs reviewed for recent years, the average annual savings in electric energy 
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due to efficiency programs was approximately one 

percent of total electricity sales. While a one percent 

figure may not seem like a large quantity, if extended 

to the nation overall, a one percent savings in electricity usage has a value of approximately $3.5 billion at 

average retail electricity rates. Some regions explicitly 

incorporated projected energy efficiency savings as 

inputs into their ten-year forecasts and regional transmission plans.

•	 Capacity from renewable energy resources, particularly 

wind generation, continued to increase in 2012. Some 

areas, particularly the Midwest and Southwest see periodic market price effects from wind production, providing benefits to the consumer when prices drop and 

challenges to grid operators when congestion occurs.

•	 Growth was experienced in the eastern RTOs’ and 

ISOs’ capacity-based emergency demand response (DR) 

programs. The increase in capacity enrolled in the 

programs has been substantial, rising from 3 GW of 

capacity in 2007 to 12 GW in 2012 and has become 

an increasingly important resource for grid operators 

during periods of system stress. The greater participation of DR resources in capacity markets may lead to 

an increased frequency of deployments and reliance on 

DR activations into the future. 

•	 Three large new high-voltage transmission projects 

went on line in 2012. Development of these projects 

involved various parties working together to accomplish planning and construction. The projects are 

expected to provide substantial benefits by supporting 

the transmission of power from renewable sources in 

rural areas to load centers.

Electricity Prices Decline with Lower Natural 

Gas Prices

Electricity prices nationwide were lower in 2012 

than in 2011. Lower prices followed natural gas 

prices, which fell to 10-year lows in the first half of 

2012 and which are a major determinant of electricity prices. Low natural gas prices have been largely 

responsible for relatively low electricity prices since 

the beginning of 2009, but lower electricity demand 

due to reduced levels of economic activity after the 

financial collapse was also a contributor. Figure 3

shows average electricity prices at principal trading

locations across the U.S., along with the change in

prices compared to 2011.

Figure 3-1

Average On-Peak Electricity Prices 2012

2181

Pricing Point

BOLD – Year to Date Price

Red – % decrease from 

previous year

COB

$26.61

-18.3%

NP 15

$31.64

-11.7%

$22.22

-23.6%

Mid-Columbia

SP 15

$34.57

-6.2% Palo Verde

$29.39

-18.6%

Four Corners

NI Hub

SPP

ERCOT North

Entergy

Minnesota Hub

Indiana

$34.80

-15.5%

Southern Florida

TVA

NYPP Zone G

PJM West

NYPP Zone J

Mass Hub

$34.79

-13.7% $28.75

-21.0%

$35.46

-42.4%

$43.94

-18.6%

$27.70

-25.4%

$30.09

-17.2%

$31.06

-10.2%

$41.32

-21.5%

$34.46

-22.8%

$32.74

-19.5%

$46.67

-25.6%

$35.86

-31.0%

$29.84

-25.4%

Source: Derived from Platts data.
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Generally, electricity prices have been lower since 

2009 than they were in the six prior years. This is 

largely attributable to shale natural gas development 

and the resulting decline in natural gas prices. A secondary factor includes a slowly recovering economy. 

Figure 3-2 shows the trend in wholesale electricity 

prices over the last 10 years at two commonly traded, 

illustrative locations.

Figure 3-2

10-Year Day-Ahead Spot Electricity Prices

Source: Derived from ICE data.

All regions of the nation experienced lower power 

prices in 2012. However, the level of price reduction 

varied because of region-specific conditions. Prices 

in the East were between 10 to 31 percent lower, 

primarily due to lower natural gas prices. Western 

power prices fell between six and 23 percent. Key 

factors influencing the regional price changes follow.

The Northeast, particularly New England, experienced 

brief price increases during cold-weather events. This 

is normal for this region because limited import capability for natural gas pushed up the natural gas price. 

Import limitations into New England are discussed 

in Chapter 2. However, price effects from the cold 

weather did not prevent the region from experiencing 

a drop in average electricity prices for 2012 because 

of overall lower natural gas prices.

Electricity prices were also significantly lower in the 

Southeast in 2012 compared to 2011. As discussed 

in Chapter 1, natural gas-fired generation was dispatched ahead of coal-fired generation for much of 

the 2012 production. For example, generators such 

as Southern Company have trended away from coalfired generation to natural gas generation over the 

past two years. As more generation comes from power burn, the falling natural gas price between 2011 

and 2012 had a greater overall impact. Prices across 

the Southeast fell 20-25 percent during that period.

In the Midwest, electricity prices were lower for most 

of the year compared to 2011. Lower prices reflected 

moderate temperatures during the heating months and 

low natural gas prices. Natural gas supplies were unconstricted and occasional high usage did not impact 

prices. Wind resources increased their penetration 

in the electricity supply stack which put downward 

pressure on prices in some periods. However, wind 

resources also caused congestion in SPP and the western areas of MISO and PJM. 

While average electricity prices in the Pacific Northwest in 2011 were already low compared to the past 

10 years, in 2012 average prices were even lower. 

This area’s electricity prices were influenced by abundant hydroelectric generation the region receives. 

Availability of hydro generation is a function of the 

amount of precipitation. The amount of snow, how 

fast it melts, and additional rain all contribute to the 

amount of inexpensive generation available and its 

effect on prices in the region. In 2012, hydro genera-
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tion in the Pacific Northwest was above average and 

extended further into the summer than normal. This 

low-cost generation supported lower-than-normal 

prices in the Northwest during spring and summer. 

Figure 3-3 shows how hydro production continued at 

higher-than-normal levels into the summer.

Figure 3-3

Northwest Hydroelectric Production

Source: Derived from USACE data reflecting the output of the 24 largest facilities 

in the Northwest.

While electricity prices in California, too, were influenced by lower natural gas prices, electricity prices 

were generally higher than elsewhere in the West. 

In contrast to the Pacific Northwest, which saw an 

increase in hydro generation, hydro generation within 

California was lower than normal. Further, the outage 

of the San Onofre Nuclear Generating Station (discussed in Chapter 1), reduced the amount of generation available to serve San Diego and other parts of 

Southern California. 

Electricity Demand Falls for Second 

Consecutive Year

Sales of electricity in the U.S dropped by 62.9 TWh 

or 1.7 percent in 2012 compared to 2011.20 Demand 

was down across the nation due to three primary 

factors: a decline in residential retail sales due to 

warm winter weather, a lack of demand growth in 

the commercial and industrial sector tied to economic 

factors, and increased energy efficiency stimulated by 

state energy efficiency policies. In addition to lower 

fuel prices, discussed earlier in this report, decreased 

demand nationwide placed downward pressure on 

electricity prices. Thus, in part, lower demand levels 

yielded electricity prices lower than they otherwise 

would be because utilities operated at the lower, less 

costly parts of their supply curves.21 As discussed later 

in this section, the warm winter, particularly in the 

South, was a major driver of the decline in electricity 

demand in 2012.22

Annual consumption of electricity across the three 

sectors of residential, commercial and industrial 

customers is shown in Figure 3-4 on the next page. 

From 2011 to 2012, industrial and commercial demand stayed flat but residential demand showed a 

steep decline. 

 20 Form EIA-826, Monthly Electric Sales and Revenue Report with State Distributions Report 

and Form EIA-861, Annual Electric Power Industry Report, Table 5.1.

 21 Lower demand also typically results in fewer hours that electricity systems operate at 

higher “stressed” demand levels that can lead to elevated prices or price spikes.

 22 Regions in this section are designated by the U.S. Census Bureau as follows: Northeast 

(New England, Maine, New Hampshire, Vermont, Massachusetts, Rhode Island, Connecticut, New York, Pennsylvania, and New Jersey); Midwest (Wisconsin, Michigan, Illinois, 

Indiana, Ohio, Missouri, North Dakota, South Dakota, Nebraska, Kansas, Minnesota, and 

Iowa); South (Delaware, Maryland, District of Columbia, Virginia, West Virginia, North 

Carolina, South Carolina, Georgia, Florida, Kentucky, Tennessee, Mississippi, Alabama, 

Oklahoma, Texas, Arkansas, and Louisiana) and, West (Idaho, Montana, Wyoming, Nevada, 

Utah, Colorado, Alaska, Washington, Oregon, California, and Hawaii).
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Figure 3-4

Annual Electricity Consumption by Sector 2001-2012

800

900

1,000

1,100

1,200

1,300

1,400

1,500

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Annual Consumption (TWh)

Residential

Commercial

Industrial

Source: Derived from EIA data.

Low residential consumption was the largest component of the overall decline in electricity demand in 

2012. Residential demand dropped 48 TWh (3.4 percent) year over year. The biggest driver of the decline 

in residential demand was the reduced heating load in 

the cold-weather months, due to an unusually warm 

winter. The residential sector generally has higher 

demand in winter and summer, because this sector 

relies on electricity for heating, cooling, and increased 

lighting load in winter. Relative to the winter peaks 

of prior years, a decline in the 2011-2012 winter peak 

is seen in Figure 3-5 for residential electricity. In 

January through April 2012, consumption in the residential sector was down nine percent compared to the 

same period in 2011. The residential sector used less 

electricity in that period than in any year since 2007.

Figure 3-5

Monthly Electricity Consumption by Sector 2008-2012

Source: Derived from EIA data.

The first quarter of 2012 broke the January-March 

average temperature record for the continental U.S. 

by 1.4 degrees Fahrenheit, a major increase. Heating 

degree days (HDD) during the first half of 2012 were 

significantly lower than 12-year averages as shown in 

Table 3-1. 23

Table 3-1

Heating Degree Days and Cooling Degree Days by Region,

2012 Compared to 12-year Average

Heating Degree Days Cooling Degree Days

Northeast -12% 17%

Midwest -13% 20%

South -18% 6%

West -9% 9%

Source: Derived from Energy Velocity data

 23 Heating and cooling degree days are measures that track the expected effects of temperature on demand or load. Average daily temperatures are compared to a standard of 

65 degrees Fahrenheit. Average daily temperatures below 65 degrees yield HDD. Those 

days with average temperatures that exceed 65 degrees yield cooling degree days (CDD).

0

20

40

60

80

100

120

140

160

180

Jan-08 Jul-08 Jan-09 Jul-09 Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12

Monthly Consumption (TWh)

2012's low 

winter peak
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Table 3-2 shows that from 2011 to 2012 more than 

half of the decline in electricity consumption is attributable to reduced residential electricity demand in 

the South. Southern residential demand was below 

average in January through March of 2012 when temperatures were well above average.

Table 3-2

Electricity Consumption Changes from 2011 to 2012 

(TWh)

Northeast Midwest South West Sector Total

Residential -3.3 -7.0 -38.4 0.5 -48.2

Commercial -2.3 -1.0 0.5 -1.4 -4.2

Industrial -2.3 0.7 -7.1 -1.8 -10.5

Totals -7.9 -7.3 -45.0 -2.7 -62.9

Source: Derived from EIA data

The South experienced well below-average demand 

during the winter (January through March, and December) and only slightly above-average demand in 

summer, with 18 percent fewer HDD than the 12-year 

average. That region, which represented 53 percent 

of all residential retail electricity sales, also had the 

highest dependence on electric heating of any census 

region, and therefore the strongest correlation between load and HDD of any region. Thus, the South’s 

drop of more than 38 TWh in electricity sales made 

up the largest proportion of the fall in overall residential electricity consumption (or 80 percent of the total 

decline in residential demand). 

Nationally, high average temperatures in summer 

2012 made it the third hottest on record. As a result, 

residential electricity consumption driven by cooling load was above average during June and July. 

However, the increased cooling load did not have as 

large an influence on overall annual consumption as 

the decreased heating load in winter. Also, not all 

regions experienced the same amount of deviations 

from normal as seen in Table 3-2.24 

The South saw an increase of 6.3 percent more cooling degree days than normal. The Midwest and the 

Northeast also experienced a hot summer, but did not 

have as high a cooling load as the South.

When controlling for HDD and CDD,25 and analyzing 

monthly demand statistics over the past 10 years, residential electricity demand increased throughout the 

2001 to 2008 time period, and then leveled off. Since 

2010, residential demand has fallen slightly even after 

controlling for the effects of weather. From 2011 to 

2012, demand fell about 11 TWh after controlling 

for weather compared to a fall of about 37 TWh due 

to weather. Consumption can fall due to changes in 

demographics, technology, and, as discussed below, 

energy efficiency.

Industrial and commercial sales fell by a more modest 10 TWh (1.1 percent) and 4 TWh (0.2 percent) year 

over year, respectively. Changes in industrial demand 

generally reflect changes in the economy. Industrial 

demand in 2012 declined following a slowly recovering economy. Commercial consumption, like residential, is somewhat dependent on weather and creates 

a smaller, but significant winter peak. The fall in 

commercial consumption can be attributed to weather, 

meaning that non-weather related commercial consumption stayed flat compared to 2011 due to weak 

economic growth. Changes in the gross annual consumption for both sectors have leveled off since the 

24 National Climatic Data Center, “Summer 2012 Recap,” National Oceanic and Atmospheric 

Administration web site, http://www.climatewatch.noaa.gov/article/2012/summer2012-recap, accessed March 11, 2013.

25 Results are based on a linear regression of monthly residential load statistics from 

2001-2012 and controlled for weather (HDD and CDD), weekend days and weekdays, and 

daylight hours.
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2008 recession, and both remain shy of their all-time 

high annual demand in 2007. Industrial demand fell 

four percent and commercial demand fell one percent 

compared to 2007. As energy efficiency programs 

have been implemented in the industrial and commercial sectors as well as in the residential sector, 

those programs have also played a role in electricity 

consumption in certain areas.

Energy Efficiency Policies Contribute to 

Lower Rates of Load Growth

Energy efficiency improvements have played a role 

in keeping overall consumption levels nationwide flat 

during the period 2009 to 2012. In particular, statelevel energy efficiency (EE) programs have played a 

role in curbing growth in electricity consumption. 

According to a recent DOE-funded Lawrence Berkeley 

National Laboratory report, “in 2010, electric energy 

efficiency programs in the U.S. achieved incremental 

energy savings of 18.4 TWh, equivalent to 0.49 percent of electric utility retail sales nationally.”26

A review of selected state EE programs since 2009 

shows notable electricity savings in the states of 

California, Connecticut, Maine, Massachusetts, New 

Hampshire, New York, Rhode Island, and Vermont.27 

The average annual electricity savings (in energy, 

or megawatt-hours) from 2009 to 2012 due to EE in 

these states was approximately one percent of total 

electricity sales. If extended to the nation overall, a 

one percent savings in electricity usage has a value of 

approximately $3.5 billion at average retail electricity 

rates.

Efficiency Policies

The eight states selected for review are part of a 

broader set of 30 states with long-term policies that 

specify EE savings, as depicted in Figure 3-4 on page 

44. These policies include Energy Efficiency Portfolio 

or Resource Standards (EEPS), which require utility 

reductions in average annual retail sales (in megawatt-hours) over time, a voluntary EE goal assigned 

to utilities by states public utility commission, or a 

hybrid EEPS and Renewable Portfolio Standard. 

26 Galen Barbose, et al., .Lawrence Berkeley National Laboratory (LBNL), The Future of Utility 

Customer-Funded Energy Efficiency Programs in the United States: Projected Spending 

and Savings to 2025 (December 2012).

 27 The selected states were chosen because of accessibility to energy efficiency data and 

because they also include some of the top states in 2012 for EE initiatives. The states 

were ranked by the American Council for an Energy-Efficient Economy (ACEE) in the 2012 

State Energy Efficiency Scorecard (October 2012). Additionally, because the selected 

states are in three RTO markets (California, New England and New York) additional data 

was available, and the connection between state-level electricity savings and long-term 

RTO planning could be assessed.
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Figure 3-6

States with Energy Efficiency Programs

Energy efficiency in 

voluntary goal

Hybrid EEPS-RPS

EEPS by regulation or 

law (stand-alone)

Source: Derived from ACEE, database of State Incentives for Renewables and Efficiency (dSIRE); Institute for Electric Efficiency; state agency report data.

Electricity Use Savings

Electricity savings in each of the states reviewed 

contributed to the recent flattening of electricity consumption. Figures 3-7 through 3-9 depict the cumulative electricity savings from 2009 through 2012 as 

compared to the annual electricity sales reported by 

EIA for all customer classes (residential, commercial, 

and industrial) in the eight states.28 The lower, blue 

section of each bar depicts actual electricity sales in 

each year. The higher, green section shows electricity savings. The total bar height represents what total 

electricity sales would likely have been but for electricity savings from EE programs.29

29 State EEPS often cover only investor-owned utilities (IOUs) but set similar non-binding 

targets for public power authorities (PPAs). California’s graphs include measured savings 

from its three IOUs. The California Public Utility Commission (CPUC) does not collect 

energy savings data from the large PPAs. New England includes all measured savings 

state program administrators reported to the ISO. The New York graph includes data 

both from the Long Island Power Authority (LIPA) and the Department of Public Service 

(NY-DPS) for IOU and NYSERDA programs.

 28 Electricity savings shown include direct program savings only. That is, savings quantities 

do not include savings from consumer choices made irrespective of efficiency programs. 

Graphs show cumulative electricity savings because EE reductions persist for more than 

one year.
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Figure 3-7

Energy Efficiency Program Savings - California

Source: Derived from EIA and California Public Utilities Commission data.

Figure 3-8

Energy Efficiency Program Savings - New England

Source: Derived from EIA and ISO-NE data.

Figure 3-9

Energy Efficiency Program Savings - New York

Source: Derived from EIA, NY-DPS, and LIPA data.

Overall, the states reviewed have years of experience 

with energy efficiency programs prior to the period 

shown. 

Load Forecasts and Wholesale Markets

Looking ahead, some RTO and ISO long-term plans 

account for future electricity savings from EE programs. 10 New York and New England explicitly 

incorporate projected electricity savings by using 

state-level program data as inputs to both their 10-

year forecasts and regional transmission plans. For 

example, NYISO includes electricity savings in its 

biennial Reliability Needs Assessment (RNA) and 10-

year demand forecasts. In its September 2012 RNA, 

NYISO determined that, without expected electricity 

savings, some transmission upgrades may need to be 

accelerated. In another example, ISO-NE stated last 

December that expected electricity savings from EE 

will allow it to defer 10 transmission upgrades that 

earlier studies deemed necessary for system reliability 

and save an estimated $260 million.31

Efficiency Costs and Funding

Some states have calculated what EE program costs 

are on a KWh basis for energy saved. Average costs 

to save a kilowatt-hour of electricity in New England between 2009 and 2011 were 3.5¢.32 Costs in 

 30 EIA’s latest base-case forecast for the next decade assumed that total U.S. retail 

electricity sales will grow at an average compound annual growth rate of 0.58 percent, 

substantially lower than the actual 1.6 percent growth rate during the last two decades. 

It is notable that the LBNL study found that “EIA’s model does not explicitly account for 

the impact of future utility customer-supported efficiency programs.”

 31 ISO-NE, “ISO on Background: Energy Efficiency Forecast,” December 12, 2012, page 22.

 32 Derived from ISO-NE, “Draft 2013 Energy-Efficiency Forecast 2016 – 2022,” November 14, 

2012, ISO-NE website, http://www.iso-ne.com/committees/comm_wkgrps/othr/enrgy_effncy_frcst/2013mtrls/iso_ne_draft_2013_ee_forecast_2016_2022.pdf, accessed April 10, 

2013.
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New York’s Long Island programs averaged 3.9¢.33 

EE programs are funded by a variety of mechanisms 

including energy bill surcharges, sometimes called 

system benefit charges. American Recovery and Reinvestment Act grants helped fund some programs in 

2010 or 2011. In the Northeast, some proceeds from 

Regional Greenhouse Gas Initiative (RGGI) auctions 

(participating states in ISO-NE, NYISO, and PJM) have 

been set aside to help fund EE programs. 

Besides state programs to fund energy efficiency, 

some participants in energy efficiency efforts are 

eligible to receive capacity payments that go toward 

their projects’ funding. Utilities in two markets (ISONE and PJM) can bid into wholesale forward capacity 

market auctions. An analysis by ISO-NE’s energy efficiency forecast working group projected that about 

15 percent of state program funding for EE programs 

in the seven years beyond the current forward capacity market delivery period will come from designated 

RGGI and cleared capacity market funds.34

Electricity Supply Additions and Retirements 

Exhibit Shifts in Fuel Use

The shift from coal-fired generation to natural gasfired generation, as discussed in Chapter 1, was further bolstered by additions and retirements of generating capacity. This is part of a longer-term trend 

that has been accelerated by more recent industry 

responses to low natural gas prices and environmental regulations. Wind-powered generating capacity 

also made up a large share of the new generating 

capacity, an outcome of Federal and state policies that 

influenced investment decisions. Increased production from natural gas-fired generation, and to a lesser 

extent, wind and solar generation, was manifest in 

greater market shares for these electricity supplies.

During 2012, over 29 GW of new generation capacity, including changes in existing capacity ratings, 

came into service. Figure 3-10 shows that natural 

gas-fired and wind generation additions have dominated capacity additions, and that coal-fired generation amounts to a smaller, but notable portion of the 

new generation. Because of long lead times for the 

technology, the recent coal-fired additions are the 

result of decisions made years ago. Market conditions 

for new electricity supply made it less likely that new 

coal capacity would be initiated today with current 

technology.

Figure 3-10

Generating Capacity Additions by Fuel Type

Source: Derived from Energy Velocity data.

Generator retirements, led by 9.6 GW of coal-fired 

steam units, amounted to 15 GW for the year. Figure 

33 Derived from Opinion Dynamics Corporation, Energy & Resources Solutions Inc. and 

Megdal & Associates, “LIPA Efficiency Long Island PY2009 Assessment,” prepared for Long 

Island Power Authority, May 2010, and subsequent year reports for 2010 and 2011, Long 

Island Power Authority website, http://www.lipower.org/eli/reports.html, accessed, April 

10, 2013. 

34 ISO New England, Energy Efficiency Working Group, “Draft 2013 Energy-Efficiency Forecast 2016- 2022”, November 14, 2012, and email correspondence with ISO staff.
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3-11 shows the acceleration in coal retirements that 

occurred in 2012.

Figure 3-11

Generating Capacity Retirements by Fuel Type

Source: Derived from Energy Velocity data.

Table 3-3 shows how these additions and retirements 

were distributed across the regions.

 Table 3-3

2012 Generating Capacity Additions and Retirements 

(MW)

Region Capacity Capacity Net

Additions Retirements Additions

WECC (outside-CAISO) 4,766 331 4,435

SPP 3,266 137 3,128

CAISO 2,685 112 2,573

Southeast (outside-RTO) 6,642 4,216 2,427

MISO 4,343 1,827 2,516

ERCOT 1,387 -- 1,387

ISO-NE 536 176 360

NYISO 889 398 492

PJM 4,494 7,569 -3,075

Totals 29,007 14,764 14,242

Source: Derived from Energy Velocity data 

Regional differences in additions are evident in both 

the total size of capacity additions and fuel type. 

Figure 3-12 shows these differences graphically, 

region by region for major fuel types.

Figure 3-12

Generating Capacity Additions by Region and Fuel Type

Source: Derived from EEI data

The Southeast stands out as the region where the 

largest amount of natural gas-fired generation entered service. This capacity addition reinforced the 

major shift in production (discussed both in Chapter 

1 and below) from coal to natural gas in that part of 

the nation. Wind development was well represented 

in major parts of the Midwest and the West. Solarpowered generation is achieving a foothold in parts of 

the West.

Changes in environmental regulations influence electricity supply decisions. Just prior to the beginning of 

2012, transmission owners, operators, and Balancing 

Authorities in the Eastern Interconnect were focused 

on finding ways to maintain reliability in the face of 

new EPA regulations under the Cross State Air Pollution Rule (CSAPR). Those regulations were scheduled 
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to become effective at the beginning of 2012, with 

more extensive restrictions set to take effect in 2014.35 

The CSAPR was proposed as an allowance-based 

regulation to reduce sulfur dioxide and nitrous oxide 

emissions and their interstate transport.36 In addition, 

in December 2011, the EPA promulgated the Mercury 

and Air Toxics Standards (MATS) rule.37 The MATS 

rule establishes new emissions control requirements 

for coal-fired power plants.

At the end of 2011, the United States Court of Appeals for the District of Columbia Circuit stayed the 

CSAPR rule, and in August 2012 the court vacated 

the rule. The EPA is rewriting its regulations and the 

implementation schedule is yet to be determined. The 

MATS rule remains in place and has a compliance 

deadline of April 2015. This deadline spurred planning decisions for some owners of coal-fired plants to 

retire or retrofit with pollution control equipment. 

In addition to the impact of new regulations, owners 

of coal-fired power plants must consider increased 

competition from natural gas-fired generation. As 

discussed in Chapter 1, natural gas prices have fallen 

recently to a level that makes natural gas-fired 

combined-cycle generation competitive with coal-

 35 RTOs and other utilities from the Midwest to the Mid-Atlantic described reliability 

concerns because of the time frame of coal-fired generators that were preparing to 

retire rather than retrofit to meet new requirements. Also, some operators of coal-fired 

generators have argued the need to take extensive outages simultaneously to retrofit 

equipment to comply with new regulations. Examples of communications and initiatives 

included: PJM 2012 Regional Transmission Expansion Plan Report, Book 2, page 47, 

http://www.pjm.com/~/media/documents/reports/2012-rtep/2012-rtep-book-2.ashx, 

accessed March 12, 2013 and The Brattle Group, “Supply Chain and Outage Analysis of 

MISO Coal Retrofits for MATS,” Report prepared for MISO, May 2012, The Brattle Group 

web site, http://www.brattle.com/_documents/UploadLibrary/Upload1039.pdf, accessed 

March 14, 2013.

 36 Environmental Protection Agency, Cross-State Air Pollution Rule, EPA website, http://

www.epa.gov/airtransport/CSAPR/index.html, accessed February 28, 2013.

 37 Environmental Protection Agency, Regulatory Actions Final Mercury and Air Toxics 

Standards (MATS) for Power Plants, EPA website, http://www.epa.gov/airtransport/CSAPR/

index.html, accessed February 28, 2013.

fired steam generation for the first time since the major building boom in combined-cycle plants about a 

decade ago. The combination of low expected natural 

gas prices and the MATS rule may accelerate the retirement of many old coal units by April 2015. MISO 

and PJM each expect over 10 GW of coal capacity to 

retire by April 2015. However, the two RTOs currently 

view any system-wide and local reliability issues that 

result from these retirements as manageable. 

Energy Production

Production statistics also reflect the shift from coalto natural gas-fired plants. As described in Chapter 1, 

natural gas-fired combined-cycle plants have moved 

ahead of coal-fired generation in dispatch order for 

much of the Eastern Interconnection. This substitution combined with retirements of coal plants are illustrated in Figure 3-13. Coal was still the most used 

fuel overall with 39 percent of production nationwide in 2012. This figure is down from 43 percent in 

2011. Natural gas moved up from 25 percent to 31 

percent of production over the same period.

Figure 3-13

Generation Produced by Fuel Type

Source: Derived from Energy Velocity data
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Renewables

Several government programs influenced the level of 

investment in wind and solar-powered plants, as well 

as other renewable sources. Production and investment tax credits for wind-powered generators have 

been an incentive for the wind capacity expansion 

over recent years. Since its inception, the production 

tax credit has a history of short-term renewals. The 

most recent extension was in the American Tax Relief 

Act of 2012 on January 1, 2013.

Under this law, solar generation installations are 

eligible for a 30 percent investment tax credit. This 

credit is targeted toward small scale residential installations and large commercial facilities. The credit 

is set to expire on December 31, 2016. From 2009 

through 2011, a cash grant was available in lieu of the 

tax credit. A surge in solar installations occurred as 

year-end 2011 approached. Capacity in 2012 continued to grow with an addition of approximately 3.3 

GW according to industry estimates, the highest oneyear increase.38

Renewable capacity is also influenced by renewable 

standards set by the states. These requirements and 

goals vary markedly from state to state in terms of 

the percentage of renewable resources involved and 

specific rules that apply. For example, some programs 

allow imports from other states to contribute while 

others do not.

38 Solar Energy Industry Association (SEIA), “U.S. Solar Market Insight 2012 Year in 

Review,” SEIA website, http://www.seia.org/research-resources/us-solar-market-insight2012-year-review, accessed May 21, 2013. This estimate includes grid-connected and 

behind-the-meter installations. Industry sources vary on the amount of added capacity 

attributable to solar resources. According to EIA, national solar capacity is growing 

rapidly and tracking the additions requires accounting for many small, distributed solar 

installations. U.S. Energy Information Administration (EIA), “New EIA data show total 

grid-connected photovoltaic solar capacity,” October 24, 2012, EIA web site, http://www.

eia.gov/todayinenergy/detail.cfm?id=8510, accessed April 10, 2013. Ventyx’s Energy 

Velocity database reports approximately 1.8 GW of solar capacity added to the grid in 

2012.

Nuclear Capacity

Increases in nuclear capacity in recent years have 

come through uprates of existing plants as opposed 

to new plant construction.39 However, during the last 

two years, nuclear power plant capacity in the U.S. 

declined by more than 1.6 GW in contrast to previous 

years. Since 2000 there have been 4.6 GW of nuclear 

capacity uprates. Capacity uprates do not involve 

construction of new nuclear units but are the result 

of modifications to existing units, including upgrading existing equipment such as steam generators and 

improved telemetry, allowing for more accurate and 

frequent measurement of nuclear reactor conditions.

Much of the capacity benefit from these enhancements may be negated due to equipment problems, 

suboptimal plant performance, and low natural gas 

and coal prices. Nearly 3.5 GW of nuclear capacity 

went into long-term outage between 2009 and 2012 

with no firm assurance that operations will resume. 

To the extent that further nuclear plant capacity is 

deactivated, the markets will face greater demand for 

capacity and likely experience new orders for additional natural gas-fired generation.

Demand Response Continues to Grow

Demand response (DR) resources provide a means 

by which market participants offer to reduce load to 

help meet resource adequacy requirements, help lower 

peak demand, and resolve other system constraints, 

along with other benefits.40 DR resources are de39 Uprate refers to the increase in an existing generator’s capacity.

40 Demand response is defined as “(c)hanges in electric use by demand-side resources from 

their normal consumption patterns in response to changes in the price of electricity, or 

to incentive payments designed to induce lower electricity use at times of high wholesale 

market prices or when system reliability is jeopardized.” Federal Energy Regulatory Commission, “2012 Assessment of Demand Response and Advanced Metering,” December 

2012, FERC web site, http://www.ferc.gov/legal/staff-reports/12-20-12-demand-response.

pdf, accessed March 7, 2013.
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ployed or activated through programs ISOs and RTOs 

administer, as well as load serving entities (LSEs). DR 

programs allow market participants to provide a variety of products such as capacity, energy, and ancillary 

services. The capacity-based emergency DR programs 

in the Northeastern ISOs and RTOs are among the 

largest of these programs.41 Growth of these programs 

has been substantial, rising from 3 GW of capacity in 

2007 to 12 GW in 2012, and DR programs have become an increasingly important resource for grid operators during periods of system stress. This growth 

may lead to increased frequency of deployments and 

reliance on DR activations into the future.42

The capacity-based DR program in the NYISO and 

certain PJM DR programs provide suppliers with 

payments for both capacity and energy.43 However, 

in ISO-NE energy payments will not take effect until 

2017 when DR resources will be obligated to bid into 

the energy markets. In each of these three markets, 

DR accounted for approximately 10 percent of the 

installed capacity in the most recent auctions, which 

include the 2015-2016 forward capacity market auctions for PJM and ISO-NE, and the NYISO’s semiannual reliability period capacity market for 2012.

For participating suppliers of the resources, the 

majority of overall DR revenues come from capacity 

payments, which accounted for $331 million or 95 

percent of the amount received by providers in PJM 

in 2012, while compensation for energy comprised 

the remainder. This compared to 89 percent in the 

NYISO and 100 percent in ISO-NE of DR revenue from 

capacity markets. Between the two revenue streams, 

participating suppliers receive annual payments for 

capacity and receive payments for energy in periods 

when DR activations occur.

Providers in the programs offered their DR resources 

into the capacity markets as do conventional generation resource, but were typically priced below the 

market’s marginal unit. Thus, in general, the additional supply added by DR resources contributed to 

overall downward pressure on capacity market clearing prices. In New England, in the Forward Capacity 

Market auction conducted during 2012 for the delivery period of 2015-2016, the capacity market price 

cleared at the administratively-set floor price.

There were two emergency DR activations in PJM, 

six in NYISO and none in ISO-NE in 2012. This is 

roughly comparable to 2011 in which there were two 

activations in ISO-NE and three in both PJM and NYISO. Emergency DR activations have historically been 

infrequent and, in some years, not called upon other 

than for testing. During events requiring DR activation, real-time prices typically were volatile during 

the ramp period for the DR resources, coinciding with 

tight supply-demand conditions. 44 The emergency DR 

 41 Individual DR programs that comprise emergency DR go by various names and vary 

by ISO and RTO. Examples include Special Case Resources in NYISO, and Capacity and 

Energy Load Management in PJM. As discussed in this section, emergency demand 

response includes load as a capacity resource (LCR). NERC defines LCR as “a resource 

that commits to pre-specified load reductions when system contingencies arise.” North 

American Electric Reliability Corporation (NERC), “2012 Summer Reliability Assessment – 

Seasonal Outlook,” May 2012, p. 177, NERC web site, http://www.nerc.com/files/2012SRA.

pdf, accessed March 13, 2013. Shifts have occurred over time in the composition of the 

demand response programs. FERC, “2012 Staff Report on the Assessment of Demand 

Response and Advanced Metering,” December 2012, p. 24.

 42 The RTOs also have economic DR programs which are a smaller category than the emergency programs. The economic program in PJM had revenues of $9.3 million, which was 

three percent the size of the emergency program.

 43 PJM does not provide energy payments to Capacity Only Emergency Load Response 

Resources when dispatched during an emergency event; it provides an energy payment 

(either the submitted bid floor or the LMP, whichever is higher) to Full Program Option 

Emergency Load Response Resources.

 44 Requirements vary for the timing of activation in each of the markets, ranging from 30 

minutes in ISO-NE to two hours for certain assets in PJM. The time between deployment 

of DR resources and the deadline to have all curtailments operational is known as the 

“ramp period.”
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helped reduce real-time load and price volatility, and, 

ultimately, prices themselves declined. While it is not 

easy to separate and quantify the effect of DR on the 

market from other variables, such as weather changes 

and load variations by non-DR loads, the DR activations contributed, in part, to lower real-time energy 

costs for LSEs. 

Investment in Electricity Transmission Infrastructure Investment Continued

Electric transmission infrastructure additions continued to grow in 2012 and, in part, help meet the 

infrastructure needed for integrating renewables and 

upgrading the grid. According to the Office of Energy 

Projects Energy Infrastructure Update for October 

2012, more than 1,191 miles of transmission lines of 

230 kV or greater were added. The Edison Electric 

Institute (EEI) said this represented more than $13 

billion in capital investment and continued a trend of 

increased spending that has equaled 12 percent annually for investor-owned utilities from 2005 to 2012. 

Figure 3-14 shows transmission investment from 

2005-2012 (last two years projected).

Figure 3-14

Transmission Investment 2005 - 2012

Source: Derived from EEI data

Most new power lines that began service in 2012 were 

in South Central and Western states. Some projects 

received Commission-approved incentives that allowed for increased return on investment (ROI).45

The projects below were brought online in 2012 and 

were notable because of their scope and importance to 

the markets. They represent large, high-voltage projects that span substantial distances and required parties to work together for planning and construction. 

Additionally, the projects are expected to provide 

substantial benefits by supporting the transmission of 

power from renewable sources in rural areas to load 

centers and bolstering reliability of the transmission 

system. 

San Diego Gas and Electric’s $1.9 billion Sunrise 

Powerlink Transmission project was the most expensive to come on line in 2012. This 117-mile, 500 kV 

and 230 kV power line has the capacity to transmit 

1,000 MW and connects the San Diego region to the 

Imperial Valley’s solar, wind and geothermal resources. Completion of this line was particularly important 

due to local reliability concerns associated with San 

Onofre Nuclear Generating Station units now offline. As a response, SDG&E finished and energized 

the line early to help the region meet its power needs 

by increasing transfer capacity, voltage stability, and 

import capability. 

SPP activated seven new transmission projects, with 

450 miles of transmission lines, making it the region of the nation with the most new facilities and 

45 The ROI incentives are a function of the Commission’s Order No. 679, Promoting Transmission Investment through Pricing Reform, Order No. 679, 71 FR 43294 (Jul. 31, 2006), 

FERC Stats. & Regs. ¶ 31,222 (2006), order on reh’g, Order No. 679-A, 72 FR 1152 (Jan. 10, 

2007), FERC Stats. & Regs. ¶ 31,236, order on reh’g, 119 FERC ¶ 61,062 (2007).
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growth in miles of new transmission. Oklahoma Gas 

& Electric’s $200 million, 130-mile, 345 kV Hugo to 

Sunnyside line, ITC Great Plains and Nebraska Public 

Power Districts’ $170 million, 125-mile, 345 kV Post 

Rock to Axtell line, and the $106 million, 89 mile 345 

kV ITC Holdings’ Spearville to Post Rock line were the 

longest and most expensive high voltage projects in 

the region. All of these projects’ costs were allocated 

across the SPP region under the SPP Highway-Byway 

or Balanced Portfolio cost allocation methodologies.46 

Another notable project is the Bonneville Power 

Administration’s (BPA) $216 million, 500 kV, 79-mile 

McNary-John Day transmission line. This facility was 

completed 10 months ahead of schedule and came 

in $124 million under its original cost estimate of 

$340 million. It received funds through the borrowing authority provided by the American Recovery and 

Reinvestment Act. The line allows BPA to offer transmission service to 495 MW of additional wind energy 

awaiting its completion. 

 46 Under SPP’s Highway Byway and Balanced Portfolio cost allocation methodologies, 100 

percent of the costs of projects above 300 kV are allocated on a regional postage-stamp 

basis.
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Chapter 4: Interplay between Physical and Financial Aspects 

of the Natural Gas and Electricity Markets

Summary

In 2012, financial products continued to play an important role in energy markets. The 

volume of financial trading significantly exceeds physical trading. As discussed in previous 

State of the Markets reports, financial trading of natural gas including financial basis swaps 

and prompt month contracts exceeds physical trading by an order of magnitude. Financial 

trading allows participants to hedge and arbitrage prices without the risk of physical delivery requirements or related costs. Similarly, in electricity markets, financial trading plays 

a prominent role with approximately 90 percent of financial trading taking place at RTOs’ 

and ISOs’ trading hubs. Unlike four years ago when commodity prices were rising, in 2012 

traders evaluated trading opportunities in a market environment of declining prices, reduced 

volatility, and lower profit margins.

In 2012, financial trading volumes for both natural gas and electricity remained substantial overall, and the market remained liquid. There were two key trends in financial trading. First, trading for electricity continued to decline in 2012 even as end use consumption 

remained flat. The volume of electricity trading on the IntercontinentalExchange, Inc. (ICE)
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decreased 19 percent compared to 2011, as part of a 

longer-term trend. Physical transactions reported in 

the Electric Quarterly Report have also been in decline 

since 2008. However, open interest in the markets 

remained high particularly in the Nymex futures and 

swaps markets as producer and merchant participation 

held steady and managed money trading increased to 

replace declines by banking institutions.

Second, toward the end of 2012, financial trading 

of both natural gas and electricity shifted as trading platforms offered revised products in response to 

regulatory changes required under the Dodd-Frank 

Wall Street Reform and Consumer Protection Act of 

2010 (Dodd-Frank Act).47 A goal of the Dodd-Frank 

Act is to facilitate increased transparency in the markets; new requirements to place energy derivatives 

on exchanges should improve data to better gauge 

financial trading activity and interrelationships that 

may develop between physical and financial positions. 

Participation by banking institutions in physical natural gas and electricity markets continued to wane. 48 

The declining activity in asset ownership and physical 

energy transactions can also be seen as the continuation of a multi-year trend, with banking institutions’ 

participation in the natural gas and electricity markets 

peaking in the 2007 and 2008 period, and declining 

since then.

While banking and financial institutions took a smaller role as physical energy market participants, utilities maintained access to investment capital through 

stable credit ratings. A relatively favorable credit environment existed for utilities that maintained higher 

credit ratings. With low interest rates available for 

investment grade utilities, debt issuance by the lowest 

investment grade (BBB) rated utilities stayed flat while 

A-rated utilities increased their issuance by 25 percent 

in 2012. 

Traded Volumes Declined for Financial 

Products, Changes Reflected in Products 

and Locations 

While financial trading volumes for both natural 

gas and electricity remained substantial, volumes 

traded in financial products for electricity declined in 

2012 based on data from ICE and CME Group.49 The 

volume of electricity trading on ICE decreased 19 

percent compared to 2011. One possible explanation 

for the decline is that there was lower volatility in 

power prices. Lower volatility implies less potential 

for profit. The decline in potential profits might steer 

investors away from energy products, and into other 

assets.

Also, market participants faced uncertainty as to the 

details of new regulations required by the Dodd-Frank 

Act. While the Dodd-Frank Act led to new requirements to place energy derivatives on exchanges, the 

market’s experience with this has been limited so 

far. To address expected customers’ trading needs, 

 47 The Dodd-Frank Act brought major change to financial regulation. Particularly, as it 

relates to financial products related to energy, the law implements changes that improve 

the oversight and supervision of financial institutions, introduce major changes in the 

regulation of over-the-counter derivatives, tighten requirements on proprietary trading 

by banks, and set new record keeping and reporting requirements, among other provisions. See Dodd-Frank Wall Street Reform and Consumer Protection Act, Pub. L. No. 

111-203, 124 Stat. 1376 (2010) (Dodd-Frank Act).

 48 Banking institutions include entities acting as insured depository institutions with 

deposits insured by the Federal Deposit Insurance Corporation (FDIC) or receiving Federal 

Reserve Bank (FRB) services such as access to the discount window.

 49 Financial products for natural gas and electricity are contracts that can be bought and 

sold. Financial contracts generally do not result in delivery of the commodity; instead, 

they provide a financial payout. Financial products are derivatives and include such 

items as swaps and futures contracts.
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exchanges that offer financial energy products converted most of their cleared energy swaps into futures 

contracts. ICE and CME Group made the conversion 

of cleared energy swaps to futures in October 2012. 

Between January and September 2012, financial trading (with respect to cleared transactions) on ICE for 

both natural gas and electricity declined. However, 

reported volumes of cleared transactions increased 

in October through December as traders began using 

futures contracts. In general, futures cleared on exchanges are expected to have lower costs than cleared 

and uncleared swaps traded over the counter. New 

requirements from the Dodd-Frank Act should improve data transparency by moving over-the-counter 

transactions to exchanges (including futures exchanges) and allowing market participants and the public to 

better assess trends in financial trading. 

Electricity Trading on ICE Declines

Total electricity trading volumes cleared on ICE 

decreased approximately 19 percent compared with 

2011 as indicated in Figure 4-1. In addition, trading 

volumes for financial products were about two thirds 

of the volumes traded in 2008. Nevertheless, the volume of financial products traded in electricity markets 

continue to significantly exceed the volume of physical products traded. Financial volumes represented 

about 100 times the physical volumes in 2011 and 

2012. 

During 2012, 89 percent of the financial trading for 

electricity products on ICE took place in an RTO or 

ISO hub, with most hubs experiencing decreased financial trading volumes compared with 2011. Figure 

4-2 shows the financial trading volumes from ICE for 

key trading locations over the last four years.

Figure 4-1

ICE Electricity Trading Volumes Continue to Decline

Source: Derived from ICE data

Trading Volumes include U.S. non-ERCOT hubs only.

Figure 4-2 

Financial Trading Volumes in all Areas except NYISO 

Declined in 2012

Source: Derived from ICE data
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PJM’s financial products continued to be the most 

traded electricity products on ICE, with 63 percent of 

total financial trades involving a PJM product. PJM 

West Hub was the most popular trading hub; in 2012, 

its volumes represented 85 percent of the total PJM 

market and 53 percent of the total financial trading 

on ICE for the U.S. power market.

However, from 2009 through 2012, long-term (30 

days or more) trading for all regions experienced an 

average 14 percent annual decline while short-term 

(less than three days) trading rose an annual average of nine percent. As illustrated in Figure 4-3, the 

change in short-term and long-term trading volumes 

varied significantly between regions. For example, in 

2012, PJM’s West Hub experienced a similar decline 

in short-term and long-term trades from 2011 while 

SP-15’s decline was mostly concentrated in the longand medium-term (three to 29 days) trades. Overall, 

trading volumes in 2012 versus 2011 declined 19 

percent for long- and medium-term trading and 16 

percent for short term trading. On the other hand, 

open interest in the markets remained high particularity in the Nymex futures and swaps markets as 

producer and merchant participation held steady and 

managed-money trading increased replacing declines 

by banking institutions.

Price volatility for electricity declined in 2012, signaling a decrease in risk and profit margins. Price volatility levels are key factors that drive speculative trading profits. Figure 4-4 on the next page shows that 

for the PJM West Hub, the 30-day window historical 

price volatility was near four-year lows in May 2012 

and by December 2012 was 34 percent of its peak. 

Figure 4-3 

Trading Volumes Decreased in 2012 for All Contract

Durations

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

SP-15 Mid-C PJM WH Nepool

GWH

Long Term Contract Volumes Traded on ICE (2008-2012)

2008 LT 2009 LT 2010 LT 2011 LT 2012 LT

Source: Derived from ICE data

0

50,000

100,000

150,000

200,000

250,000

300,000

SP-15 Mid-C PJM WH Nepool

GWH

Short Term Contract Volumes Traded on ICE (2008-2012)

2008 ST 2009 ST 2010 ST 2011 ST 2012 ST
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Figure 4-4 

PJM West Hub On-Peak Price Volatility Declines

Source: Derived from Bloomberg data

Markets Shifts to Futures from Swaps

During 2012, the markets transitioned from swap 

products to the converted futures product. The distinction between a swap and a future ultimately determines the costs for producers, end users, exchanges, and brokers. In October 2012, ICE and CME Group 

converted cleared energy swaps to futures to address 

regulatory requirements raised by the Dodd-Frank 

Act. The conversion required financial transactions to 

be cleared and to have standardized units, resulting in 

increased transparency. 

In natural gas trading on ICE, the revised futures 

products traded 17 percent of total annual financial 

volumes (over 116,000 Bcf) in the fourth quarter of 

2012 as shown in Figure 4-5.50 In electricity trading 

on ICE, the revised futures products traded over 1,141 

TWh in the fourth quarter of 2012 or 30 percent of 

total annual financial volumes as shown in Figure 

4-6. 

50 The settlement price for most of ICE’s financial contracts for natural gas is tied to the 

natural gas futures settlement price on Nymex. The trend described may vary with other 

trading platforms.

Figure 4-5

Natural Gas Trading on ICE Transitions from Swaps to 

Futures

Source: Derived from ICE data

Figure 4-6

Electricity Trading on ICE Transitions from Swaps to 

Futures

Source: Derived from ICE data

Between January and September 2012, financial 

trading on ICE for both natural gas and electricity 

declined. However, reported transaction volumes 

increased in October through December as traders 

began using the futures contracts. In general, futures 

cleared on exchanges are expected to have lower 

costs and regulatory requirements than cleared and 

uncleared swaps traded over the counter. As shown 

in Figure 4-7, average daily volumes of financial 

electricity products increased 26 percent in the fourth 

quarter of 2012 over the same period in 2011. 
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Figure 4-7

Average National Daily Volumes Rebounded at the End of 

2012

Source: Derived from ICE data

While volumes of financial products traded for natural gas and electricity remain substantial, small movements in physical positions can have large influences 

on the value of financial positions. Greater ability to 

assess market trends should be possible through access to data on financial trading activity facilitated by 

the market’s use of exchanges.

Participation by Banking Institutions in the 

Natural Gas and Electricity Markets

The continued economic downturn, decreased profit 

margins in trading, and new trading restrictions and 

compliance requirements have caused some market 

participants to scale back operations or exit the energy trading business. For example, in January 2012, 

Société Générale Energy Corp. sought waivers of 

capacity release and tariff provisions to facilitate sales 

of assets and thus allow the parent company, Société 

Générale SA, to depart from the physical natural gas 

and electricity trading business in North America.51

Physical Wholesale Natural Gas Sales

by Banking Institutions Decline

Physical natural gas trading by banking institutions 

peaked in 2007 and 2008. However, this trading activity has steadily declined since that time, according 

to data from the Commission’s Form No. 552 Annual 

Natural Gas Transactions Reports.52 As shown in 

Figure 4-8, financial companies, which include banks, 

accounted for 10 percent of natural gas purchase and 

sales volumes in 2011. 

Figure 4-8 

Financial Companies Account for Ten Percent of Natural 

Gas Volumes

Source: Derived from FERC Form 552 data 

2012 annual physical natural gas market data observed by FERC Form 552 will be 

available after May 2013.

 51 Recent examples include the Royal Bank of Scotland Group Plc and Sempra Energy which 

exited their RBS Sempra Commodities LLP joint venture in 2010. Also that year, FERC approved temporary waivers of capacity release rules and related tariff provisions requested 

by Nexen Marketing USA Inc. to facilitate its exit from the marketing and trading business.

52 The FERC Form No. 552 collects transactional information from natural gas market participants. Calendar year 2012 data will be available after the May 1, 2013 filing deadline. 

Thirteen financial companies filed Form No. 552 reports for calendar year 2011, and three 

reported transactions to index publishers that used the transactions to form daily and 

monthly indexes.
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Natural gas sales volumes for many individual financial companies have declined since 2008.53 Several financial companies, such as UBS AG, exited 

the physical natural gas market after 2010. Despite 

these companies’ exit, and a general decrease in 

the remaining financial companies’ exposure to the 

gas market, trading volume that the financial sector 

contributed to the total physical gas market remained 

relatively unchanged between 2008 and 2011. A 

reason for the unchanged volume is that J.P Morgan 

stepped in to replace those exiting the market. J.P. 

Morgan’s natural gas sales more than doubled between 2008 and 2011.

Table 4-1

Bank Participation in the Physical Natural Gas Market is Limited 

Respondent Bank Purchases Sales Reports to 

(Trillion Btu) (Trillion Btu) Index Publisher

JPMorgan Ventures Energy Corp JPMorgan Chase 1,536.2 1,414.2 No

Citigroup Energy Inc Citigroup Inc 959.6 960.8 Yes

Barclays Bank PLC Barclays Bank PLC 408.0 412.9 No

DB Energy Trading LLC Deutsche Bank AG 389.7 404.3 No

J Aron & Co Goldman Sachs 457.2 402.9 Yes

Wells Fargo Commodities LLC Wells Fargo & Co 92.6 97.3 No

Merrill Lynch Commodities Inc Bank of America 316.3 262.0 Yes

Credit Suisse Energy LLC Credit Suisse 111.1 91.0 No

Morgan Stanley Capital Group Morgan Stanley 172.2 68.5 No

Royal Bank of Canada Royal Bank of Canada 59.5 59.5 No

Sempra Energy Trading Royal Bank of Scotland 44.5 10.2 Yes

Source: Derived from FERC Form 552 data

Eleven banking institutions participated materially in 

the physical natural gas markets in 2011. Table 4-1 

lists the participating banks.

Physical Wholesale Electricity Sales

by Banking Institutions Decline

Physical trades of electricity by banking institutions

also peaked in 2007 and 2008. This trading activi

has steadily declined since that time.54 A year-overyear decline in market-based sales by banks or ba

affiliates is shown in Figure 4-9 on the next page.

53 Id. 

54 Derived from Electric Quarterly Reports (EQR) filed with FERC.
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Figure 4-9 

Electricity Sales Reported by Banks Have Been in Decline

$0

$5

$10

$15

$20

$25

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

2005 2006 2007 2008 2009 2010 2011 2012

Billions

GWh

Bank (GWh)

Total $

Source: Derived from EQR data volumes (assume kWh to MWh conversion)

After the 2001 collapse of Enron, many market 

participants withdrew from merchant projects that 

relied on robust trading. Some assets were transferred to lending banks as owners defaulted on debt 

obligations. Other assets were sold to hedge funds at 

distressed values as owners monetized units to secure 

credit ratings and trim portfolios. By the end of 2004, 

banking institutions and financial entities had acquired five to 10 percent of U.S. generating capacity.55 

As generation owners, financial institutions made 

significant wholesale sales, and some ranked among 

the top electricity traders including Morgan Stanley 

Capital, J. Aron, and Merrill Lynch. Today, banking 

institutions only own a fraction of the assets used to 

enable those sales. 

Reduction in traded volume is not unique to banking 

institutions. Overall, energy volumes reported in the 

EQR have declined in line with revenue. There was a 

slight resurgence in 2008, coincident with high prices 

and favorable conditions in the market. The decline 

continued in later years as shown in Figure 4-10.

Figure 4-10

Electricity Sales and Revenues in Decline Since 2005

$0

$50

$100

$150

$200

$250

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

2005 2006 2007 2008 2009 2010 2011 2012

Billions

GWh

Bank (GWh)

Other (GWh)

Total $ = Other + Banks

Other ($)

Source: Derived from EQR data volumes (assume kWh to MWh conversion)

Capital Spending Up and New Debt Issued 

Where Utilities Possessed Favorable Credit 

Ratings

Capital markets provide the money to make investments in infrastructure such as power plants or natural gas pipelines, to operate plants and companies and 

to trade or conduct transactions. Access to capital depends both on the health of capital markets and also 

on the perceived risk of the entity seeking the capital. 

To measure relative riskiness, many providers of capital consider varied measures, including credit ratings. 

In 2012, the industry experienced low interest rates, 

an abundance of low-cost natural gas, and, in most 

55 FERC, Division of Energy Market Oversight, “2004 State of the Markets Report,” June 

2005, Federal Energy Regulatory Commission web site, http://www.ferc.gov/market-oversight/reports-analyses/st-mkt-ovr/som-rpt-2004.pdf at pages 31, 62 and 63, accessed 

March 11, 2013. 
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areas, reductions in electricity consumption. Many 

utilities experienced reduced levels of revenue. In 

this business environment, companies with favorable 

credit invested in new capital projects and refinanced 

older debt. These companies were able to increase 

capital spending because investment grade credit 

ratings allowed borrowing and refinancing on better 

terms in current markets.

Overall net capital expenditures for electric utilities 

reported on FERC Form 1 grew at an average annual 

rate of eight percent from 2005 to 2011. According to 

SNL’s index of 48 natural gas and electric utility parent companies, utility capital spending was projected 

to reach $90 billion in 2012, a 19 percent increase 

over 2011.56 The new spending was directed at transmission and distribution enhancements, new baseload 

generation projects, and environmental upgrades. 

Yields on corporate debt instruments such as corporate bonds, a measure of the cost of debt, declined 

for investment grade utilities after a spike during the 

2008 financial crisis. Figure 4-11 shows that, while 

low at the beginning of the year, yields for corporate debt on investment grade utilities declined over 

the course of the year. Note that while the nominal yields declined, the credit spread (the difference 

between corporate bonds and a 10-year Treasury 

bond) remained at about 1.3 percent for investmentgrade utilities, indicating that the risk of investmentgrade utilities’ corporate debt had not fundamentally 

changed as a whole. However, for noninvestment 

grade utilities as of early November, the credit spread 

was a relatively high 7.5 percent.

The electricity and natural gas sector reflected a 

relatively stable credit situation since its deterioration 

from the average A rating earlier in the decade. According to Standard and Poor’s (S&P) data, 86 percent 

of regulated natural gas and electric utilities were 

expected to maintain an investment grade rating of 

BBB or better.57 

Figure 4-11

Yields for Investment Grade Utilities Continue to Decline

Source: Derived from Bloomberg data

Most utilities maintained a BBB rating in 2012. Figure 4-12 shows how the distribution of credit ratings changed over the last eight years for utilities in 

the natural gas and electricity sector. Six percent 

of companies in the overall sector have experienced 

downgrades from the top AA and A ratings since 

2010. Only two percent of companies migrated to 

below-investment grade. Downgrades may be partially explained by adverse economic conditions, an 

increase in debt burden, and changes in regulations. 

56 Regulatory Research Associates, Inc., Capital Expenditure Update, “Spending up in 2011 – 

heading higher in 2012” SNL Energy, May 25, 2012, p. 1.

57 S&P issues short-term and long-term credit ratings based on S&P’s opinion of a bond 

issuer’s creditworthiness. Long-term credit ratings are ranked on scale from AAA 

(extremely strong capacity to meet financial commitments) to D (payment default on 

financial commitments). Between these extremes S&P ratings from AA to CCC may 

include a (+) or (-) sign to show relative standing within the major rating categories.
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In 2012, S&P issued only 50 upgrades compared with 

136 downgrades. Still, S&P expected the sector to 

maintain its stable outlook despite the economy’s 

projected slow growth rate. 

Figure 4-12

Natural Gas and Electricity Sector Hold Investment 

Grade Rating

Source: Derived from Standard & Poor’s data

Note: Major rating categories are grouped by base rating and include all ratings 

with (+) to (-) modifiers

A-rated utilities increased debt issuance in 2012.58 

Since the 2008 financial crisis, investment-graderated utilities increased borrowing levels or refinanced 

previous debt for longer durations. Companies sought 

to issue longer-term debt to lock in low interest rates. 

In 2008, 39 percent of the bonds issued by A-rated 

U.S. utilities in the Bank of America Merrill Lynch 

Investment Grade Utilities Index had maturities longer 

than 18 years. In 2012, this percentage rose to 64 

percent. Utilities with A ratings increased their issuance by 25 percent to $25 billion in 2012 while the 

rate of debt issuance by BBB-rated utilities stayed flat. 

 58 Capital comes from two general sources of financing (equity and debt). Debt financing 

involves borrowing money to be repaid over time, along with interest at a fixed or variable interest rate. Some common types of debt include bonds, which are securities that 

companies issue in financial markets with maturities of more than a year. 

Figure 4-13

The Amount of Debt Issued by A-Rated Utilities Increased 

in 2012

$0

$5

$10

$15

$20

$25

$30

2008 2009 2010 2011 2012 2008 2009 2010 2011 2012 2008 2009 2010 2011 2012

A Rating BBB Rating Below Investment Grade

Rating

Billions

0-8 Years 9-17 Years Over 18 Years

Source: Derived from Bloomberg data

Despite increases in debt issued by companies at 

the A credit ratings, overall utility debt issuance fell 

nine percent compared to 2011. Utilities rated below 

investment grade (BB and under) decreased their issuances by 41 percent in 2012 as illustrated in Figure 

4-13. In 2011, the below-investment-grade utilities 

benefited from increased investment in high-yield 

bonds as investors sought higher interest rate alternatives to government and investment-grade corporate 

bonds. Below investment-grade utilities, too, experienced a previous record-breaking surge in 2009 due 

to high-yield utility bond issuances. 
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Chapter 5: Significant Regulatory Developments in 2012

Summary

Several market reforms enacted since 2011 sought to improve wholesale electricity

market performance through better market power mitigation methods, resource compensation rules, transaction scheduling, and multi-party coordination and information sharing. These changes are intended to improve market transparency, boost inter-control ar

transaction efficiencies, and better compensate and accommodate a variety of resources.

Some may also reduce anticompetitive behavior and price and generator output uncertainty. Reforms occurred through a combination of Commission rules and RTO and I

actions.
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NYISO and ISO-NE Interchange 

Scheduling Plan

On April 19, 2012, the Commission accepted tariff revisions for NYISO and ISO-NE markets, with effective 

dates on or after August 1, 2013, designed to improve 

scheduling of electricity sales and reduce consumer 

costs in both regions.59 The revisions implement 

Coordinated Transaction Scheduling (CTS) between 

NYISO and ISO-NE. CTS is intended to enable market 

participants to optimize cross-border transactions by 

providing scheduling mechanisms that take into account price differences between the regions. Among 

other measures, CTS will allow for 15-minute scheduling between NYISO and ISO-NE. Today, scheduling 

occurs every hour. The external market monitor for 

both regions estimates that CTS will result in $129 

million to $139 million in annual consumer savings. 

CTS allows market participants in NYISO to import or 

export energy at the NYISO/ISO-NE border by submitting a single bid, using a common bid submission 

platform, to indicate a desire to simultaneously buy 

in one control area and sell in the other. CTS further enhances efficient exchanges by increasing the 

frequency of scheduling energy transactions. Bi

clear if the offered price is less than the expected

LMP difference across the external interface at the

time the interface is scheduled. Both ISOs schedule the proposed transactions. Tariff revisions 

eliminated transaction fees that inhibited efficient

inter-regional exchanges.

NYISO 15-Minute Scheduling with Hydro 

Quebec and PJM

In 2012, NYISO enacted provisions, as part of a multiphase effort, to enable 15-minute transaction scheduling at its borders.60 These initial actions targeted 

borders with Hydro Quebec and PJM. NYISO stated 

that the actions are consistent with a broader regional 

action plan proposed by NYISO, MISO, PJM, and the 

Ontario Independent System Operator. Further, as 

discussed previously, the Commission has approved 

tariff provisions that will allow for 15-minute scheduling between NYISO and ISO-NE. 

Enhanced interregional transaction coordination 

intends to enable more frequent scheduling of interbalancing authority transactions than on an hourly 

basis. Reducing the lag time between the scheduling commitments of participants and subsequent 

pricing determination may lower the resulting price 

risk. These transactions occur at interfaces known as 

“proxy generator buses,” which are twinned pairs of 

modeled import and export buses between neighboring control areas. 

In June 2012, NYISO implemented 15-minute variable 

scheduling at the PJM Keystone Proxy Generator Bus 

and in July, NYISO implemented 15-minute variable 

scheduling at its interface with Hydro Quebec at its 

Chateauguay Proxy Generator Buses. 

Market Power Mitigation

In 2012, ISO-NE and CAISO launched new automated 

market power mitigation systems, and the Commis-

 59 New York Independent System Operator, 139 FERC ¶ 61,048 (2012), ISO New England, et 

al., 139 FERC ¶ 61,047 (2012). 60 New York Independent System Operator, 134 FERC ¶ 61,186 (2011).
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sion approved mitigation reforms for MISO and SPP. 

An entity that has market power has the ability to bid 

into a market in an uncompetitive manner and inflate 

market prices. To detect and guard against such occurrences, market monitors have developed and continue to enhance market power mitigation practices. 

ISO-NE

In April 2012, ISO-New England launched an automated mitigation system.61 The system replaces a 

manual process used for several mitigation procedures, particularly for pivotal suppliers, who own 

resources required to meet demand. The new system 

looks ahead in five-minute intervals at supply offers with respect to two separate conduct and impact 

tests. From January through March 2012, the number 

of mitigations averaged seven per month. Following the automated mitigation, the number of mitigations jumped to an average of 33 per month for the 

rest of 2012. It is not surprising that, with the new 

automated mitigation procedures, the triggers for 

mitigation may be more sensitive than in the prior 

manual process. While greater capabilities to screen 

and review market offers should be possible through 

the automation process, further reviews of the new 

process should be useful for assessing the changes.

CAISO

CAISO implemented the first phase of a new automated market power mitigation system on April 11, 

2012.62 This phase applies to the day-ahead market. 

The second phase, for the hour-ahead scheduling 

process and real-time market, is scheduled for spring 

61 ISO New England Inc., Docket No. ER12-1242-000 (2012) (unpublished letter order).

62 California Independent System Operator Corp., 138 FERC ¶ 61,154 (2012). See also “California ISO Q2 2012 Report on Market Issues and Performance”, August 14, 2013, CAISO 

web site, http://www.caiso.com/Documents/2012SecondQuarterReport-MarketIssuesPerformance-August2012.pdf, accessed March 28, 2013.

2013. Transmission paths determined to be uncompetitive are subject to market power mitigation. Previously, the market monitor conducted quarterly competitive path assessments to assess transmission paths 

with the potential market power. The new methodology uses a market run in the day-ahead market 

process to dynamically determine congested paths. 

Since assessment of transmission path congestion 

is done in conjunction with each day-ahead market 

run, it better reflects current grid conditions than the 

previous quarterly process. The new process allows 

for mitigation of those paths. Further, the mitigation 

run now includes virtual as well as physical bids and 

clears the market to bid-in demand instead of forecast 

load. Finally, the automated approach bases mitigation on the higher of LMP or the mitigated generator’s 

cost (default energy bid), whereas previous mitigation 

only used cost. 

The ISO’s Department of Market Monitoring (DMM) 

reported that the automation improved mitigation 

accuracy. In the second quarter of 2012, the predicted 

congestion in the new system was accurate 93 percent 

of the time, up from 45 percent for the same quarter 

in 2011. The new methodology over-predicted congestion three percent of the time and under-predicted 

four percent of the time, a significant improvement 

from over the 18 percent and 37 percent, respectively, 

that occurred in the second quarter of 2011. Underprediction is under-identification of potential local 

market power. In such cases, the exercise of local 

market power may occur but not be mitigated.

The Commission also approved a proposal by CAISO 

to expand mitigation of exceptional dispatches and 

residual imbalance energy in specific circumstances 

when there is the potential to exercise market power. 63 

63 California Independent System Operator Corp., 141 FERC ¶ 61,069 (2012).
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Exceptionally dispatched resources are those generators dispatched manually outside the market model 

runs. The ISO issues exceptional dispatch instructions 

primarily to manage transmission constraints that are 

not modeled in market software, but may also do so 

for reliability reasons or because of software failures. 

MISO

In August 2012, the Commission approved a mitigation mechanism for MISO with regard to offers for 

resources committed to address voltage or local reliability concerns.64 This change allows MISO to use 

conduct thresholds to prevent market participants 

from abusing their market power by submitting bid 

levels or bidding parameters substantially different

from those in their reference levels.

SPP

In October 2012, the Commission approved a revised market power mitigation plan for SPP as part

of its new Integrated Marketplace.65 The plan see

to reduce anticompetitive behavior in the day-ahead

market. Once implemented in 2014, the Integrat

Marketplace will include day-ahead and real-time

energy and operating reserve markets. Therefor

the Commission stated that a more comprehensive

monitoring and mitigation program is appropriate,

including the addition of frequently constrained area

mitigation.

Order No. 755: Frequency Regulation 

In October 2011, the Commission issued Order No. 

755, which revised regulations governing compensation of frequency regulation resources.66 Frequency 

regulation is an ancillary service that protects the grid 

by correcting frequency deviations through balancing resources with load. An automatic control signal 

directs resources to adjust output to maintain system 

frequency. Besides electric generators, resources that 

can provide this service include demand response, flywheels, and other storage devices. 67 The Commission 

found that existing compensation methods for such 

service in RTO and ISO markets failed to acknowledge 

key elements such as the degree of output change 

provided by resources whose output is able to increase 

or decrease rapidly. The Commission also found that 

the practices of some RTOs and ISOs resulted in economically inefficient dispatch of frequency regulation 

resources. 

The rule revision ensures frequency regulation service 

providers receive just and reasonable compensation 

by requiring RTOs and ISOs to compensate frequency 

regulation resources based on the actual service provided using a two-part payment methodology. Providers will receive a capacity payment that includes 

the foregone revenue of standing ready to provide 

service when needed. In addition, a performance 

payment will reflect the amount of work resources 

perform in real-time in response to the grid operator’s 

signal. The market rule changes that followed the 

64 Midwest Independent Transmission Operator, 140 FERC ¶ 61,171 (2012)

65 Southwest Power Pool, 141 FERC ¶ 61,048 (2012), order on reh’g, 142 FERC ¶ 61,205 

(2013).

66 Midwest Independent Transmission Operator, 140 FERC ¶ 61,171 (2012).

Southwest Power Pool, 141 FERC ¶ 61,048 (2012), order on reh’g, 142 FERC ¶ 61,205 

(2013).

66 Frequency Regulation Compensation in the Organized Wholesale Power Markets, Order 

No. 755, FERC Stats. & Regs. ¶ 31,324 (2011), order denying reh’g, Order No. 755-A, 138 

FERC ¶ 61,123 (2012), order on compliance filings, 141 FERC ¶ 61,105 (2012).

67 A flywheel is an energy storage device capable of rapidly responding when needed. This 

makes it suitable to moderate fluctuations in grid demand. 
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order should result in improved ability to align compensation with a resource’s rapid output adjustment 

ability and accuracy. 

Compliance filings submitted by CAISO and MISO 

have been approved by the Commission.68 NYISO, 

ISO-NE, and PJM submitted amended compliance 

filings on January 15, February 6, and February 22, 

2013, respectively, which are pending before the Commission.

Order No. 764: Integration of Variable Energy Resources

In June 2012, the Commission issued a final rule, 

Order No. 764, to facilitate the integration of variable 

energy resources in electricity markets.69 A variable 

energy resource is an electricity generator whose output variability is beyond a facility owner or operator 

control. The difficulty of predicting and controlling 

the output of variable resources presents challenges to 

their operators and grid operators. The rule reformed 

existing market rules designed for resources whose 

output could be held relatively constant and increased 

or decreased to follow load changes. 

Implementation of the rule will reduce costs and 

removes barriers to the integration of variable energy 

resources through two new reforms. The rule requires 

each public utility transmission provider to offer 

transmission scheduling on 15-minute intervals. By 

offering scheduling in intervals of less than an hour, 

transmission customers should be better equipped to 

manage changes in wind output. Specifically, shorter 

offering schedules reduce transmission customers’ exposure to excessive imbalance service charges caused 

by an inability to adjust service schedules within an 

operating hour. The rule also requires interconnection 

customers using variable energy resources to provide 

meteorological and forced outage data to the transmission provider for power production forecasting. 

The Commission found that such data should improve 

transmission providers’ ability to manage resource 

variability. 

Order No. 768: Electricity Market 

Transparency Provisions 

In September 2012, the Commission issued Order No. 

768, to facilitate price transparency in electricity markets.70 Public access to electric sales and transmission 

information improves market participants’ ability to 

evaluate supply and demand fundamentals and price 

interstate electric market transactions. It also enhances the Commission’s ability to evaluate price formation and market concentration and to detect exercises 

of market power or manipulation. 

The rule revised the Commission’s regulations by 

requiring entities that are excluded from the Commission’s jurisdiction under Federal Power Act (FPA) 

section 205 and have more than a de minimis market 

presence to file EQRs with the Commission. 71 These 

entities include publicly-owned utilities, municipal 

utilities, public utility districts, rural cooperatives, and 

Federal entities (i.e., non-public utilities). 

68 California Independent System Operator Corp., 142 FERC ¶ 61,233 (2013). Midwest Independent Transmission Operator, Docket No. ER12-1664-001 (2013) (unpublished letter 

order).

 69 Integration of Variable Energy Sources, Order No. 764, 139 FERC ¶ 61,246 (2012). 77 FR 

41482 (July 13, 2012), FERC Stats. & Regs. ¶ 31,331 (2012), order on reh’g, Order No. 764-

A, 141 FERC ¶ 61,232 (2012).

70 Electricity Market Transparency Provisions of Section 220 of the Federal Power Act, Order 

No. 768, 77 FR 61896 (Oct. 11, 2012), FERC Stats. & Regs. ¶ 31,336 (2012), order on reh’g, 

Order No. 768-A, 143 FERC ¶ 61,054 (2013).

71 16 U.S.C. 824d.
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Order No. 770: Revisions to Electric 

Quarterly Report Filing Process

In November 2012, the Commission issued a final 

rule, Order No. 770, which amends the process for 

filing EQRs to accommodate changes in technology 

while providing flexibility for EQR filers.72 Among 

other measures, the EQR provides transparency with 

respect to electricity prices and contract information. 

Because technology changes will render the current 

filing software ineffective, outmoded, and unsustainable, the rule discontinued use of Commission-distributed software and adopted a web-based EQR filing approach. This will allow a public or non-public utility 

to file directly through the Commission’s website via 

a web interface or by submitting an Extensible MarkUp Language-formatted file. Dual options provide 

added flexibility to accommodate EQR filers’ technical 

preferences. 

Order No. 760: Enhancement of Market 

Surveillance and Analysis through Ongoing 

Electronic Delivery of Data 

In April 2012, the Commission issued a final rule, 

Order No. 760, which requires ongoing data delivery 

from RTOs and ISOs to enhance the Commission’s 

electric market surveillance and analysis functions.73 

Improved market oversight will facilitate the Commission’s development and evaluation of its policies and 

regulations. Also, it will bolster Commission efforts 

to detect ineffective market rules and anti-competitive 

or manipulative behavior. The required data includes 

72 Revisions to Electric Quarterly Report Filing Process, Order No. 770, 77 FR 71288 (Nov. 30, 

2012), 141 FERC ¶ 61,120 (2012).

73 Enhancement of Electricity Market Surveillance and Analysis through Ongoing Electronic 

Delivery of Data from Regional Transmission Organizations and Independent System 

Operators, Order No. 760, FERC Stats. & Regs. ¶ 31,330 (2012).

physical and virtual offers and bids, marginal cost 

estimates, financial transmission rights, and uplift and 

interchange prices. The rule attempts to minimize the 

burden on RTOs and ISOs by phasing-in implementation requirements, not requiring uniform data formatting, and replacing burdensome ad hoc data requests. 

Order No. 771: Availability of E-Tag 

Information to Commission Staff

In December 2012, the Commission issued a final rule, 

Order No. 771, to provide itself with access to complete electronic tags (e-Tags) to enhance its market 

surveillance and enforcement endeavors.74 E-Tags are 

used to schedule the transmission of electric power 

interchange transactions in electricity markets. 

Access to e-Tag data will aid the Commission in 

monitoring market efficiency, better inform Commission policies and decision-making, and help in detecting market manipulation and anticompetitive behavior. Specifically, e-Tag data better equips Commission 

staff to identify interchange schedules that appear 

anomalous or inconsistent with rational economic 

behavior. E-Tag access also provides more complete 

information for audits, investigations, and evaluating 

power flows and market rules.

74 Availability of E-Tag Information to Commission Staff, Order No. 771, 77 FR 76367 (Dec. 

28, 2012), FERC Stats. & Regs. ¶ 31,339 (2012).
Acknowledgements

Development of the 2012 State of the Markets Report 

was a group effort that required the teamwork and substantial efforts of staff in the 

Office of Enforcement’s Division of Energy Market Oversight. 

In alphabetical order, principal contributors include:

Valeria Annibali, James Burchill, R. Omar Cabrales, Christopher Ellsworth,

Rebecca Gillespie, Devin Hartman, Alan Haymes, Lance Hinrichs, 

Kenneth Kohut, Jonathan Ly, Steven Michals, Susan Pollonais,

Eric Primosch, Astrid Rapp, Roxana Royster, Patricia Schaub, John Sillin, 

Ryan Stertz, Thomas Russo, Carol White, and Rama Zakaria.

Disclaimer: This report does not necessarily reflect the view of the 

Commission or any Commissioner.

72