Slide 1 

Item No: A-3

April 19, 2012

2011

State of the Markets State of the Markets

Good morning Mr. Chairman and Commissioners. 

We are pleased to present the Office of Enforcement’s 2011 State of the Markets 

Report. The State of the Markets Report is staff’s annual opportunity to share our 

assessment on the natural gas, electric, and other energy markets. 

The presentation is based on conclusions of the staff and not necessarily those of the 

Commission, the Chairman or any of the individual Commissioners. 
Slide 2 

State of the Markets 2011 State of the Markets 2011

 Record natural gas production 

 Record natural gas storage inventories

 Lowest prices in 10 years

 LNG export proposals

 Power prices remained modest

 Stable gas and electric demand

 Gas-fired generators have continued to 

increase utilization

Natural gas production reached an all time record in 2011, surpassing levels last seen 

in the 1970’s. Growing supply outpaced demand, which led to record high natural gas 

storage going into the 2011/2012 winter and natural gas prices fell to lows not seen 

since the early 2000’s. Plentiful natural gas supply and low prices led to talk of the 

need to develop new domestic and foreign markets for natural gas and in 2011 seven 

LNG export projects were proposed in the U.S. with almost 14 Bcfd of capacity. 

The electric markets also experienced low prices as fuel costs fell and demand 

remained stable. Changes in the pricing relationship between natural gas and coalfired generators caused a fundamental shift in the utilization of these plants, with 

natural gas plant production increasing and coal plant output falling. 
Slide 3 

Natural Gas Prices Natural Gas Prices 

Plummet to 10 Plummet to 10-Year Low

Source: Derived from ICE Data

0

4

8

12

16

20

Jan Feb Mar Apr May Jun Jul Aug Sep Oct NovDec

$/MMBtu

2002-2010 Range

2012 2011

In this slide, we compare the current Henry Hub natural gas spot price (shown in red) 

to the ten-year range (show in green) to illustrate how prices fell below that range 

towards the end of 2011. In 2011, natural gas prices at Henry Hub were down about 

9% over 2010. The price of natural gas fell from the mid- $4/MMBtu at the beginning of 

the year to under $3/MMBtu by December. The price remained at the $3/MMBtu level 

through the end of the year and reached parity with Central Appalachian coal. 

The most recent Nymex forward curve for natural gas shows that the market 

anticipates that prices at Henry Hub will remain under $4/MMBtu through 2014. Some 

natural gas producers have voiced concerns that declining revenues due to low natural 

gas prices will affect their ability to explore for and produce natural gas. We have 

already seen some producers announce plans to cut back natural gas production and 

drilling in gas only shales while increasing drilling in shales rich in natural gas liquids. 

These announcements and possible impacts on production are trends we will follow 

closely in 2012. 
Slide 4 

Average Natural Gas Spot Average Natural Gas Spot 

Prices, 2011 Prices, 2011 ($/MMBtu)

Source: Derived from ICE Data

Sumas

$3.89

-5%

AECO

$3.66

-6%

PG&E 

Citygate

$4.23

-7%

El Paso 

Permian

$3.87

-7%

CIG

$3.77

-4%

Chicago

Citygates

$4.11

-8%

SoCal

Border

$4.05

-5%

Houston 

Ship Channel

$3.93 -9%

NGPL 

TX-OKLA

$3.91

-8%

Columbia

TCO

$4.07

-10%

Algonquin

Citygates

$5.02

-5%

Transco 

Zone 6 NY

$5.02

-7%

Henry

Hub

$3.98

-9%

Florida

Citygates

$4.04

-8%

Pricing Point

$ = Year to Date Price

Red = % decrease from 2010

All pricing points declined in 2011. Average natural gas spot prices declined across the 

country by around 7% in 2011, as shown in the map. This winter was the warmest in 

60 years and the Northeast, which usually sees the highest winter prices, saw no 

sustained price spikes. The Transco Z6 NY price for this winter averaged $4.25/MMBtu 

with a peak at only $12/MMBtu, whereas last winter, prices averaged nearly $7/MMBtu 

and peaked in December 2010 at $20/MMBtu. 

New pipelines completed during 2011 linked growing supply sources to markets and 

contributed to shrinking regional price differences. In some cases, the market price of 

natural gas between regions declined to less than variable transportation costs. When 

prices drop below the variable cost of transportation, it becomes uneconomical to 

move natural gas to try to capture price differences between pricing points. 

We have also seen a decline in the seasonal difference between winter and summer 

natural gas prices. Falling seasonal spreads reflect increased production and storage 

capacity, as well as greater year-round use of natural gas by power generators. This 

decline has developed over the past several years and we expect the trend to 

continue. 
Slide 5 

Natural Gas Storage Natural Gas Storage 

Builds to New Record Builds to New Record

Source: Derived from EIA Data

0

500

1,500

2,500

3,500

4,500

AM J J ASOND J FM

Volume (BCF)

5 year range

2011-2012

The recent warm winter, relatively low natural gas demand, and strong production 

exacerbated the current oversupply in the market. By the end of March, natural gas in 

storage was over 50% higher than the 5-year average which is shown in green on the 

graph. Natural gas in storage has never been at such high levels going into the spring 

and this will help inventories rebuild for next winter. 

Although very high storage levels so early in the refill season indicate a need for 

additional storage, market conditions do not generally support the building of new 

storage. As mentioned in the last slide, winter-summer gas price spreads are at 

historically low levels and barely cover the cost of storing gas. 
Slide 6 

NG Production Up 7%, NG Production Up 7%, 

Breaches Previous Records Breaches Previous Records

Source: Derived from 

Bentek Energy Data

Eagle Ford 

Barnett 

Woodford 

Fayettville

Haynesville 

Marcellus (WV, PA)

Offshore 

"Conventional“

Onshore

-

10

20

30

40

50

60

70

Bcfd

2005 2006 2007 2008 2009 2010 2011 2012

This slide shows natural gas production over the last seven years by source. Dry 

natural gas production grew 7% in 2011 to 65 Bcfd, surpassing an all-time record last 

set 25 years ago. Growth was primarily driven by robust on-shore shale gas 

production, which accounted for a third of total U.S. dry natural gas production by 

December 2011. This is up from 23% the previous year and just 13% three years ago. 

Dry gas shales, such as the Haynesville in North Louisiana, the Fayetteville in Arkansas 

and the Barnett in the Dallas/Fort Worth area, remained the largest producing shales 

in 2011. However, the fastest growing shales were found in the liquids-rich shale 

basins. The Marcellus Shale is a liquids-rich play in parts of Pennsylvania and West 

Virginia and production doubled over the year to nearly 6 Bcfd by the end of 2011. 

Production from the Eagle Ford Shale in South Texas grew 64% to 3 Bcfd over the same 

period, the highest growth of any shale. Some Eagle Ford wells produce as much as 

70% natural gas liquids, which can double profitability compared to a gas-only well. 

The rapid increase in natural gas liquids production outstripped liquids processing and 

takeaway capacity in many regions, resulting in development and production 

bottlenecks for both natural gas and liquids. The liquids infrastructure in the 

Appalachian region was not designed to handle the volumes produced by the Marcellus 

Shale. The Eagle Ford Shale in Southeast Texas faces similar problems. Industry plans 
to add over 700 thousand barrels of fractionation and processing capacity and 1.3 

million barrels per day of liquids pipeline takeaway capacity by 2014 to alleviate these 

bottlenecks. 

Low prices and the drive to tap shale gas reserves have touched off a race to reduce 

drilling costs and improve rig operating efficiency. These improvements resulted in 

production increases even as the natural gas rig count declined. In 2011, the natural 

gas directed rig count dropped 6%, even as production increased. There are many 

shale gas wells that have been drilled but not completed because producers are 

waiting for higher prices. This will enable gas production to come on-line quickly as 

market conditions warrant. 

Concerns regarding environmental issues associated with hydraulic fracturing remained 

at the forefront in 2011. At the federal level, the Environmental Protection Agency 

continues its study of the relationship between hydraulic fracturing and drinking water 

with its final study plan released in November 2011 and the final results not expected 

until 2014. At the state level, actions on fracking range from outright bans, such as 

the one in the New York City watershed, to the reassessment of current regulations in 

Ohio, as that state prepares for oil and natural gas development in the Utica Shale. 

There have been some reports of increased flaring levels of gas associated with the 

increase in oil production, but these are mostly a localized phenomenon. The overall 

level of flaring in the U.S. in 2010 (last year available) remained less than 1% of dry 

natural gas production, essentially unchanged from the average amount flared for the 

last 30 years. 
Slide 7 

NG Demand Up < 1%, NG Demand Up < 1%,

Led by Power Sector Growth Led by Power Sector Growth

Source: Derived from Bentek Energy Data

Industrial +0.1%

Residential &

Commercial -0.7%

Power

Generation

+3.1%

0

10

20

30

40

50

60

70

2010 2011

Bcfd

U.S. natural gas consumption in 2011 was up less than 1% over 2010. As shown, most of 

the growth came from natural gas-fired power generation, which was up slightly more 

than 3%. There was virtually no change in industrial natural gas consumption, and 

residential and commercial use fell 0.7%. However, while overall natural gas 

consumption varies year to year, strong growth in natural gas-fired power generation 

supported 10% growth in consumption over the last 10 years as Lance will discuss in 

more detail later in the presentation. 

The greater reliance on natural gas has increased the importance of coordination 

between gas-fired generators and the natural gas pipeline companies that supply 

them. Concerns about coordination have been particularly strong in the Northeast, 

which is heavily dependent on natural gas and has experienced coincident peaks in 

both electric and natural gas demand during the winter season. It can also be a 

concern in parts of the Southwest that lack robust storage infrastructure. Also, 

upcoming coal plant outages for emission retrofits are expected to lead to greater use 

of natural gas-fired plants. Regional grid operators continue efforts in areas of 

planning, reliability and market operations. 

Over the past year, as focus has increased on gas-electric coordination, natural gas 

and electric companies have launched initiatives such as enhanced communications 
between the various industry segments including generators, RTOs, and pipeline 

companies. In February 2012, the Commission issued administrative docket AD12-12 

requesting comments on the issue of natural gas and electricity interdependence. 

Approximately 80 interested entities submitted comments, and commission staff is 

currently reviewing these submissions. 
Slide 8 

Long & Short Long & Short-haul Pipelines haul Pipelines 

Increase Market Access Increase Market Access

REX ~1680 miles

Bison ~303 miles

Ruby ~680 miles

Acadian ~270 miles

FGT Ph. VIII ~483 miles

TGP Line 300 ~127 miles

TEMAX/TIME III

(Completed 2008-2010) ~10-38 miles

Note: Acadian Haynesville Extension pipeline is an 

intrastate pipeline and is FERC non-jurisdictional

Source: Derived from 

Ventyx Data and pipeline 

company websites

REX 

Completed 2008-10

~1680 miles

Last year transportation capacity values dropped on many long-haul pipelines as strong 

production growth in the Marcellus and other shale basins displaced some natural gas 

flows from traditional supply basins. For example, we saw Rockies natural gas flows to 

the Northeast on Rockies Express Pipeline (REX) decline more than 40% since early 

November 2010, from 1.7 Bcfd to 1 Bcfd. The decline was so severe that S&P reduced 

REX’s credit rating. The downgrade is the result of persistent low profitability in 

shipping Rockies natural gas eastward, which has occurred because Rockies natural gas 

has been displaced in the Northeast by increased flows of less-expensive Marcellus 

Shale gas from Pennsylvania. Also, the new Ruby pipeline competed with REX 

providing Rockies producers access to a more profitable market in Northern California. 

S&P said that lower profitability now has increased the recontracting risk on REX as 

well. As with the Rockies, traditional U.S. Gulf Coast supplies have been displaced by 

largely liquids-rich Mid-Continent production. 

In 2011, FERC jurisdictional natural gas pipeline companies added roughly 2,100 miles 

of new pipe or about 9.3 Bcfd of transportation capacity, while major intra-state 

pipelines added another 400 miles of new pipe and 4.7 Bcfd of transportation 

capacity. The six largest projects, shown on the map, accounted for 57% of new 

transportation capacity. Major projects include Ruby Pipeline, Florida Gas 
Transmission Phase VIII Expansion and the Bison Pipeline. In 2011, pipeline 

developments shifted to projects focused on relieving local bottlenecks in new 

producing basins rather than long-haul pipelines. Most are located in the Northeast 

and Southeast and include the Tennessee Gas Pipeline Line 300 Expansion, the Texas 

Eastern TEMAX/TIME III project and the Acadian Haynesville Extension, an intrastate 

pipeline which feeds into the Henry Hub. 
Slide 9 

Vacated Order No. 720 Vacated Order No. 720 

Reduces NG Market Transparency et Transparency

Source: Derived from Bentek Energy Data

0

10

20

30

40

50

60

70

JJAS

2010

OND J FMAM J

2011

JASONDJ

2012

F

Bcfd

Interstate Pipelines

Intrastate Pipelines

Dry Production Supply Estimate U.S.

FERC Order No. 720, issued in October 2010, required major non-interstate pipelines 

to post daily nominated receipts and deliveries on their systems, the blue area of the 

graph. This resulted in a sharp increase in market transparency during 2011, with 97% 

of daily dry natural gas production visible to the market through pipeline receipts. 

Order No. 720 data made visible to the market daily natural gas production from some 

of the fastest growing shale plays. Demand visibility also increased significantly with 

implementation of Order No. 720. Prior to Order No. 720, the market did not have 

thorough information on the intra-state pipeline customer mix. For example, the 

amount of daily natural gas consumption from industrials or power generators in 

markets served predominantly by intrastates was not visible. 

The Order No. 720 postings also allowed the market to see the impact of daily changes 

in natural gas supply and demand and effects on interstate price formation and 

fundamental market dynamics. For example, in February 2011, Order No. 720 postings 

enabled market participants to quickly assess the regional extent and impact of 

natural gas well freeze-offs as shown in the graph by the sharp dip in intrastate 

pipeline flows during February 2011. 

In 2011, the Fifth Circuit Court of Appeals vacated Order No. 720 and most noninterstate pipeline postings ceased at the beginning of 2012. Now the market is only 
able to observe about 70% of daily changes in dry natural gas production and even less 

demand. 

Recently many producers announced a dial back of natural gas production in response 

to low natural gas prices. With the loss of Order No. 720 data and with it producer 

deliveries into intra-state pipelines, it has become more difficult for market analysts 

to assess whether announced well shut-ins are actually occurring and if so, what 

affect they are having on market fundamentals. Less information usually injects 

greater uncertainty, price volatility, and risk into markets. 
Slide 10 

LNG Export Plans Proceed LNG Export Plans Proceed

Source: Derived from Ventyx Data and based on DOE and NEB Data

10

9

5

2 3 4

1 7

6

8

10

9

5

6

2

3 4

1 7

8

ALL approvals received

FTA approval received and 

non-FTA approval pending

FTA approval received, 

greenfield project

FTA approval pending, 

greenfield project

U.S. producers are seeking new foreign markets for growing supply and nearly 14 Bcfd 

of LNG export capacity was proposed in 2011 at various locations shown on the map. 

To put this into perspective, 14 Bcfd is about 21% of average daily U.S. natural gas 

production. EIA recently completed an assessment of the domestic price impact of 

U.S. LNG exports and concluded that U.S. natural gas prices could rise 9% at 6 Bcfd of 

exports and 11% at 12 Bcfd. A number of other studies have also analyzed various U.S. 

LNG export levels, with some showing no appreciable effect on prices and others 

showing a greater impact than EIA. 

Cheniere Energy’s Sabine Pass LNG, which has been approved by the Department of 

Energy to export domestically produced gas as LNG, is the furthest along with 90% of 

its proposed export capacity contracted by buyers in Korea, India and Spain. These 

buyers are likely willing to pay a price premium for the security and diversity that the 

U.S. natural gas market provides. So far, the Lower 48 has only re-exported small 

quantities of previously imported LNG. In its 2012 Annual Energy Outlook forecast, EIA 

projects that U.S. LNG exports will begin in 2016 at 1.1 Bcfd, doubling to 2.2 Bcfd by 

2019. 

I will now turn the presentation over to Lance Hinrichs to discuss developments in the 

electric markets.... 
Slide 11 

2011 Average On 2011 Average On-Peak 

Electric Spot Prices Electric Spot Prices ($/MWh) ($/MWh)

Source: Derived from Platts Data

NP 15

$36, -10%

Palo Verde

$36, -7%

MidColumbia

$29, -19%

Minnesota 

Hub

$33, -6%

SPP

$34, -6%

ERCOT

$57, 40%

Entergy

$36, -7%

Florida

$44, -12%

Southern

$39, -5%

Cinergy

$39, 0%

NI Hub

$38, -2%

PJM

Western Hub

$50, -3%

Mass Hub

$51, -6%

SP 15

$37, -8%

NY Zone J

$60, -4%

= Pricing Point

$ = Current Price

Green = % increase /previous year

Red = % decrease /previous year

Power prices in 2011 were down throughout the U.S., with the exception of the ERCOT 

RTO and the Cinergy trading hub. This largely tracked the drop in natural gas prices 

that Valeria described and highlights the role of natural gas as the marginal, or price 

setting, fuel in most markets. On average, nationwide power prices were down 0.5% 

from last year, despite a warmer than normal summer. 

Prices in the East were between 3 to 12% lower, primarily due to the lower natural gas 

prices. Western power prices fell between 7 and 19% supported by the robust 

hydroelectric output in the Pacific Northwest that was 27% above the 5-year average. 

The most dramatic change occurred in ERCOT, where prices rose by 40% due to 

extreme summertime heat that set a record breaking 41 straight days at or above 100 

degrees. As a result, in August, there were 9 days in which ERCOT’s energy-only 

market saw day-ahead prices rise to the $3,000/MWh price cap. This was in contrast 

to the Southwest Power Pool (SPP) region, which also experienced a hot summer. 

However, prices in the SPP region fell by 6%, primarily due to a robust capacity surplus 

and power imports of 2 to 3 GW during peak periods. 
Slide 12 

NG-fired Generation Increasingly fired Generation Increasingly 

Displaced Coal Displaced Coal-fired Generation

Source: Derived from Ventyx Data

0%

10%

20%

30%

40%

50%

60%

2002 03 04 05 06 07 08 09 10 2011

Coal Steam Gas Combined Cycle

Natural gas-fired combined cycle generation (shown in red on the chart) continues to 

move up in the nations’ supply stack, displacing coal-fired generation (shown in 

green). Coal generation, as a percentage of total output, declined steadily to 44% in 

2011 from about 51% in 2002. Over the same period, generation from natural gas-fired 

combined cycle plants grew to more than 20% from 10%. 

The underlying reasons for increased natural gas-fired generation use are well known: 

it is cheaper to build, has shorter construction times, and offers more flexible 

operations with fewer environmental restrictions. Coal plant construction, however, 

has not come to a halt. Coal still maintains a fuel-cost advantage for large base-load 

plants in certain locations, particularly where delivered coal costs are low. 

This brings us to a more recent situation where decreases in natural gas prices are 

causing natural gas combined cycle plants to replace some coal plants in the 

generation supply stack. Some of this transition was starting to take place when 

natural gas prices were $1 to $1.50/MMBtu higher than they are today. However, 

there is now additional pressure for natural gas-fired plants to compete with coal 

production. Low natural gas prices in 2011 helped push the proportion of coal 

generation down during the year, ending at 39% of total U.S. generation in December. 
Over roughly the last decade, the largest volume of natural gas-fired combined cycle 

generation construction occurred from 2000 to 2005. Their capacity factors have been 

growing steadily since that time, from the low 30% range to nearly 40%. 
Slide 13 

Industrial Consumption Industrial Consumption 

Unchanged from 2010 Unchanged from 2010

Source: Derived from EIA data in Electric Power Monthly

840

880

920

960

1,000

1,040

1,080

2002 03 04 05 06 07 08 09 10 2011

(1,000s of GWh)

In last year’s State of the Markets Report, we told you that the consumption of 

electricity had partially recovered from a recession-induced decline in 2009. In 2011, 

this rebound appeared static and overall demand was down by 1%, with little change 

in each of the three major consumer categories. 

This chart shows industrial demand, which was up last year by less than 1% from 2010 

levels and mirrors economic activity which rose at a moderate pace, according to the 

Federal Reserve. 

Commercial sales, which are driven by a combination of weather and economic 

activity, also rose slightly in 2011 from the year before. 

Residential sector consumption, which is primarily driven by weather, fell 1.5% in 

2011, despite record peak loads in many areas of the country during the summer. Last 

year’s dip in residential electricity sales runs counter to a longer term trend towards 

more energy-intensive technologies in homes and larger residential structures. 
Slide 14 

New TrAIL Project in PJM New TrAIL Project in PJM 

Reduces Congestion Reduces Congestion

Source: Derived from Ventyx Data

0

4

8

12

16

$ per MWH

Price Difference (Dominion Hub – AEP-Dayton Hub) 

2010 2011

The 218-mile, 500-kV, TrAIL power line in PJM went into service in May 2011. The line 

begins in southwestern Pennsylvania, crosses northern West Virginia, and terminates in 

Loudon County, Virginia. It increased west-to-east transfer capability by over 2,600 

MW and has helped reduce congestion bringing prices in eastern and western PJM 

closer together. The graph shows the drop in the price difference between the 

Dominion Hub and the AEP-Dayton Hub, falling from $14.67/MWh in the summer of 

2010 to $6.68/MWh in the summer of 2011. 

Over the two interfaces that benefit most from TrAIL, congestion declined sharply and 

allowed lower cost generation in western PJM to flow to eastern and southern PJM. 

On the AP South interface, congestion declined by over 1,000 hours while congestion 

on the Bedington-Black Oak interface declined by over 1,800 hours. Total congestion 

costs over these two interfaces dropped by half to $262 million in 2011. 

TrAIL’s benefits were also evident in PJM’s forward capacity market. The Reliability 

Pricing Model, or RPM, provides load serving entities a means of procuring capacity 

three years in advance of the actual delivery year. This was first seen in the May 2008 

auction for the 2011/2012 delivery year, when the line’s projected capacity was 

included in the auction’s assumptions for those delivery years. As a result of the line’s 

increased deliverability of capacity, the difference in capacity prices between the east 
and west regions dropped to zero for the 2011/2012 delivery year from more than 

$100/MW-day for 2009/2010. 

TrAIL has also enhanced system reliability and operational flexibility by making it 

possible for the RTO to accelerate the re-construction of the 100-mile long Mt. StormDoubs 500 kV line, which runs on a roughly parallel path to the TrAIL. TrAIL’s new 

capacity allows operators to take longer outages on Mt. Storm-Doubs during 

construction and will make it possible to have the line rebuilt by June 2015, about five 

years earlier than would otherwise happen. 
Slide 15 

2011 Demand Response 2011 Demand Response 

Increasingly Important Increasingly Important

Source: Derived from RTO data

0

5,000

10,000

15,000

20,000

25,000

2009 2010 2011

MW

DR Cleared in Northeast Capacity Markets 

Demand response participation in the RTOs has been increasing and grew by 40% last 

year in the Northeast to 20 GW of cleared capacity. 

In 2011, two notable events demonstrated the important role that demand response 

plays as capacity that resource operators can call upon to more flexibly balance supply 

and demand. 

On July 22, a heat wave hit the Northeast and Mid-Atlantic, sending temperatures 

soaring to 104 degrees in New York City and pushing electricity demand to near-record 

levels. In the most stressed markets – NYISO, PJM and ISO-NE – grid operators invoked 

emergency measures and called upon real-time demand-response programs that 

activated 4,800 MW of demand response. 

Also, on December 19, ISO-NE experienced a deficiency in operating reserves during 

the morning ramp and activated 504 MW of demand response. The deficiency was 

caused by a combination of factors: forced outages, higher than expected load, and 

unit trips. 

During both the July and December events, the programs helped to maintain system 

reliability and provided operators with alternatives to the most expensive generating 

units or curtailing service to customers. 
Demand response continued to account for substantial capacity in the RTO capacity 

market auctions held in 2011. In the PJM and ISO-NE forward capacity auctions, which 

were held for the 2014-2015 delivery period, demand response resources represented 

10% of the capacity cleared for PJM and 8% for ISO-NE. In the New York ISO, where its 

capacity auction was held for the 2011 Summer Capability Period, demand response 

represented 6% of the cleared statewide capacity. 

Providing upwards of 95% of their compensation in PJM and New England, and more 

than 50% in New York, the capacity markets provided the demand response resources 

participating in these grid events with significant incentive to enter the market. 

In the forward capacity market auctions held in 2011, the PJM and ISO-NE capacity 

market payments represent between 37 and 60% of the net cost of new generation 

entry in their regions. In New York, the ISO-provided capacity payments represent 

approximately 58% of the cost of new generation entry for New York City. 
Slide 16 

Renewables See Strong Renewables See Strong 

Growth

 Grid connected solar PV installations 

double in 2011

 Wind in the Heartland increases

 MISO starts a program to make wind 

resources dispatchable

 Hydro generation in the Pacific 

Northwest finishes strong in 2011

With the Treasury Department’s cash-grant program expiring and costs falling, 

developers rushed to connect photovoltaic solar capacity to the grid last year. There 

was 1.9 GW in new capacity, or a 109% increase from 2010 levels, led by California and 

New Jersey. At year-end, total capacity reached 4 GW. In each of the top states, 

solar investment was encouraged through policies such as solar set-asides in their 

renewable standards. Additionally, photovoltaic construction costs fell 20% last year, 

after an 18% drop in 2010. 

U.S. wind generation capacity grew by 6.8 GW last year. More than a third of this 

increase came online in the Midwest ISO (MISO) and SPP. With capacity factors 

between 30 and 37%, now 1 of every 11 MWh in these regions comes from wind. 

As wind generators provide an increasing portion of markets’ energy, they need new 

tools to manage its output more efficiently. On June 1, MISO instituted a voluntary 

tariff category for variable energy resources, principally wind. By allowing registered 

resources to be dispatched economically in real-time, “DIR” provides more efficient 

curtailment through market software to manage congestion, a common need in 

Minnesota, Iowa and other parts of MISO’s western region. Previously, wind resources 

might be manually curtailed as often as three times daily, with the system instructing 
wind generators to turn off large blocks of production for long periods of time. By 

December, 19% of MISO’s 10.6 GW of wind had registered as DIR resources. 

Hydro generation in the Pacific Northwest finished 27% higher in 2011 than the 5-year 

average, with roughly 160 TWh generated in 2011. California hydro generation hit 

roughly 40 TWh, 60% more than the previous 5-year average. As a result, 

hydroelectric generation displaced natural gas-fired generation in much of the West. 

For example, California burned 23% less natural gas in their power plants than the 5-

year average, while Washington burned 43% less. 

This completes our presentation. We would be happy to answer any questions at this 

time. 
Slide 17 

Item No: A-3

April 19, 2012

2011

State of the Markets State of the Markets