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Slide 1

Item No. A-3

March 17, 2016

State of the Markets Report 

2015 
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Slide 2

Highlights

• Increased gas supply led to lower gas prices, and in turn, lower 

electricity prices.

• Declining oil and natural gas prices have put significant stress on 

producers.

• U.S. exported LNG from the lower 48 for the first time in history on 

February 24, 2016.

• Natural gas power generation exceeded that of coal in seven months 

during 2015.

2015 was an eventful year in the energy markets as oil and natural gas prices fell 

substantially due to surging supply and strong storage builds. Low prices were 

beneficial for consumers, but have placed significant stress on producers and some 

pipeline companies that have contracts with them. Despite low natural gas prices, 

Marcellus and Utica natural gas production, the primary source of all new U.S. 

production, reached record levels in 2015. Low gas prices resulted in natural gas 

generation surpassing coal generation for seven months during 2015 and helped boost 

exports to Mexico. In addition, low natural gas prices enabled the first U.S. LNG 

exports in history from the lower 48. Production growth in the Marcellus and Utica 

has resulted in the addition of 51 Bcfd in new pipelines in the past five years and 

approximately 49 Bcfd of capacity is proposed or planned to come online by 2018 to 

transport natural gas to markets. 
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Slide 3

Highlights (continued)

•Capacity markets in PJM and New England became larger revenue 

sources while the generation mix continues to change.

• Distributed energy resources continued to grow in capacity and energy 

markets. 

• SPP’s footprint expanded while LMPs declined.

• Generation from renewables continued to set records nationwide, 

particularly from California and MISO.

In the wholesale electricity markets, the generation fuel mix has changed, led by the 

growing supply of natural gas and renewables. Distributed energy resources 

continued to grow, as plans to integrate them into the wholesale markets were 

approved by the California Public Utilities Commission and became more detailed in 

New York. In the upper Midwest, SPP’s footprint expanded. Finally, generation from 

renewable sources continued to grow rapidly nationwide.
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Slide 4

NG Prices Fall Across U.S.

Spot Natural Gas Prices 2015 Average ($/MMBtu)

Source: Derived from Platts data

Fundamental changes in the North American natural gas market substantially drove 

down U.S. natural gas spot prices in 2015. Production and storage reached record 

levels, while demand rose modestly, tempered by the El Niño warm weather during 

the 2015-2016 winter. Natural gas demand increases came from the addition of new 

gas-fired generation and increasing utilization rates at existing gas-fired plants. 

Despite a warmer than average summer, non-winter prices fell to their lowest levels 

in 20 years, which in turn led to lower wholesale electricity prices, as gas-fired 

generation set the price in many power markets. 

With the exception of the Northeast, including New England, regional price 

differences across the country were not large, a sign that midstream investments over 

the past 10 years have largely relieved natural gas transportation constraints. 

However, insufficient pipeline takeaway capacity in the producing regions of Ohio, 

West Virginia, and Pennsylvania has led to a local gas surplus in the area, resulting in 

lower prices for producers. In contrast, pipeline constraints near Algonquin Citygates 

at Boston, Transco Zone 5 in the Mid Atlantic, and Transco Zone 6 New York, resulted 

in higher prices for consumers in 2015. Still, prices at these demand hubs decreased 

substantially from the previous year due to the warmer than normal winter, greater 

LNG imports, and increased production close to the region.
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Staff analysis indicates that new capacity additions should significantly relieve 

transportation constraints in these regions by 2019 if projects that are planned and 

under construction are approved and completed by the scheduled in-service dates. 

The outlook for 2016 continues to point to low prices because of continued strong 

production and high storage. 
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Slide 5

Natural Gas Futures Decline

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

Apr-16

Jul-16

Oct-16

Jan-17

Apr-17

Jul-17

Oct-17

Jan-18

Apr-18

Jul-18

Oct-18

Jan-19

Apr-19

NYaEX Futures Curve ($/aaBtu) 

Jan-15 Jul-15 Dec-15

Source: Derived from 

Bloomberg data

The price of natural gas futures contracts has dramatically decreased over the past 

year, primarily because of the increase in supply from the Appalachian Basin. Over 

the course of one year, the futures curve fell by approximately $1.00/MMBtu, a 27 

percent decrease. It is unlikely that Henry Hub prices will surpass $4.00/MMBtu in the 

near future due to the massive shale gas resource base available below this price, 

which effectively places a cap on prices.

In contrast, futures prices at hubs near the Marcellus and Utica producing regions 

began to strengthen towards the end of 2015. Prices at hubs near production areas in 

the Northeast have been among the lowest in North America over the past few years 

because supply in the area has been confined by a lack of pipeline takeaway capacity. 

However, new pipeline capacity such as REX East-to-West and other projects planned 

for 2016 will relieve gas transportation constraints into the Midwest, Northeast, 

including New England, and Southeastern markets.
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Slide 6

2015 Prices of Crude and OilIndexed Products Decline

Source: Derived 

from EIA data

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

Spot Price ($/MMBtu) 

Brent Sakai LNG UKNBP

The price of crude oil dropped 66 percent between June 2014 and December 2015, 

which has implications for North American natural gas markets in a multitude of ways. 

First, although there are important differences between oil and gas markets, many 

North American companies are involved in the production of both. Nearly a sixth of 

U.S. natural gas is a by-product of crude oil production, so a decline in oil production 

directly reduces associated natural gas output. Additionally, LNG is an important 

potential source of future demand growth for U.S. natural gas producers. The price 

of LNG in most long-term contracts is indexed to oil, and low LNG prices may reduce 

the prospects of U.S. LNG exports. Finally, low prices have strained many producers’ 

balance sheets, leading to potential credit defaults, consolidation, and lay-offs. 

U.S. producers have been surprisingly resilient to the price declines so far by reducing 

costs. However, continued low prices are negatively affecting U.S. oil and natural gas 

producers, and present a downside risk to future production. Although many of these 

companies are not under FERC jurisdiction, their failure could impact certain 

midstream companies that rely on long-term contracts with producers to finance 

pipeline projects. The effects of the price decline on capital investment have been 

profound. Over $380 billion worth of global investment in oil and natural gas projects 

has been postponed, the U.S. oil rig count dropped by 807 rigs over the course of 

2015, a 61 percent year-on-year decline, and the U.S. upstream oil and natural gas 
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industry shed approximately 17,000 jobs in 2015 according to the Bureau of Labor 

Statistics. 
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Slide 7

U.S. NG Production 

Plateaus in 2015

0

10

20

30

40

50

60

70

80

2010 2011 2012 2013 2014 2015

Production Rate (bcfd)

Southeast (onshore) GOM Midcon Midwest Rockies Southwest Texas (onshore) Northeast

Source: Derived 

from Bentek

Energy data

The global oil situation notwithstanding, U.S. natural gas production has increased 3.6 

percent per year since 2010, hitting a new record of 72.6 Bcfd in 2015. However, 

there are signals that natural gas production has plateaued and may begin to decline. 

Nearly all production growth in North America over the past 5 years came from the 

Marcellus and Utica Shale formations in the Appalachian Basin, as seen in the top teal 

layer of the graph. Production from the Eagle Ford shale in Texas (included in the 

gold layer) experienced increases as well, although low liquids prices increasingly 

challenge producers there. 

The North American natural gas market will likely remain oversupplied and prices low 

in the near term, pushing high cost producers out of the market. However, as 

producer prices recover, there appears to be ample low cost resources waiting in the 

wings, with some producers in the Marcellus and Utica shales reporting a $2.50/MMBtu 

or lower breakeven price. Total U.S. proven natural gas reserves have steadily 

increased since the onset of the shale revolution and stood at 388 trillion cubic feet 

(Tcf) at the end of 2014. As natural gas demand increases and prices rise, additional 

supply can be brought online relatively quickly because shale gas projects in wellestablished areas require relatively less lead-time than conventional projects. In 

addition, there are a large number of drilled but uncompleted wells, and some 
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producers are cutting back output from existing wells in the current low price 

environment.
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Slide 8

Storage Levels Reach 

All Time Record

Source: Derived 

from EIA data

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

U.S Storage Levels (Bcf)

SOUTH CENTRAL MIDWEST EAST

PACIFIC MOUNTAIN 5 YEAR AVERAGE

Natural gas storage levels reached a record high 4 Tcf in November despite starting 

the winter season below the 5 year average. The 2,469 Bcf net injection in 2015 is 

second only to 2014’s record 2,746 Bcf net injection. Based on demand so far this 

winter, it is likely that the natural gas in storage will be at near record levels come 

spring, putting further downward pressure on prices for the rest of 2016.

Despite an abundance of storage on average, there are challenges in southern 

California. A leak was discovered at SoCalGas’ Aliso Canyon natural gas storage field 

on October 23, 2015. To rectify the problem, SoCal began to rapidly draw down the 

field while at the same time reducing imports from pipelines at the California border, 

and on February 18, 2016, SoCal permanently sealed the leaking well. Aliso Canyon 

represents 63 percent of SoCal’s storage, and could be shut down for the foreseeable 

future. The closure is having impacts on SoCal’s system reliability, flexibility, and 

prices. Moreover, natural gas forward prices in California have risen steadily since 

November 2015 due to expectations that increased spot gas purchases will be 

necessary to substitute for the lost Aliso Canyon storage withdrawals during next 

winter’s peak demand season. There are also concerns regarding the impact on power 

generation this summer, since nearby plants rely on Aliso Canyon storage to meet peak 

requirements.
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Slide 9

Total U.S. Natural Gas 

Demand - All Sectors

Source: Derived 

from Bentek

Energy data

 -

 20

 40

 60

 80

 100

 120

 140

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Bcfd

2010 - 2014 Range 2015

In general, natural gas demand growth has trailed supply, contributing to low prices. 

Total U.S. natural gas demand grew only 1.3 percent in 2015, driven by a 3.8 percent 

growth in power burn. Industrial natural gas demand fell slightly, while residential 

and commercial gas demand fell by 2 percent. 

Natural gas demand exceeded the 5-year range during the summer due to an 18 

percent increase in summer power burn over the summer of 2014. Due to low natural 

gas prices, for the first time in U.S. history, natural gas power generation surpassed 

coal based generation on both a quarterly and monthly basis. Summer temperatures 

were 8 percent warmer than in 2014, but the 2015-2016 winter was relatively mild 

due to El Niño, which moderated residential and commercial demand at the end of 

the year. 

Long term demand growth for U.S. natural gas will likely come from increased gasfired electric generation, particularly in the Southeast, growing industrial demand, 

LNG exports, and pipeline exports to Mexico.

Over the past 3 years, the Southeast added approximately 6.5 GW of nameplate gasfired electric generating capacity and total natural gas demand in the region during 

2015 increased 5.2 percent over 2014 levels. Staff expects this trend will continue 
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with an additional 17 GW of gas-fired capacity to be added in the Southeast by 2020. 

Not only has the amount of gas-fired capacity increased, but capacity factors have 

increased as well because low natural gas prices relative to other fuels has increased 

the economic dispatch of gas-fired units. Capacity factors in the Southeast increased 

by 5-11 percent in each month in 2015 compared to the same months in 2014 and 

2013. 

Industrial gas demand declined slightly in 2015, but we expect that it has the 

potential to grow by approximately 2.5 Bcfd over the next five years as major 

projects are added.
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Slide 10

LNG Exports Could Add to 

U.S. Natural Gas Demand

Source: FERC data

0

2

4

6

8

10

12

14

16

Jan-2016 Jan-2017 Jan-2018 Jan-2019 Jan-2020

LNG Export Capacity (Bcfd)

LNG Export Capacity (Bcfd)

LNG exports are a significant potential source of future natural gas demand growth. 

The first export of LNG from the U.S. mainland shipped from Cheniere’s Sabine Pass 

terminal on February 24th, 2016. At this time, it is difficult to predict the volume of 

LNG exports in coming years because falling global prices have made potential U.S. 

exports less profitable. 

Staff estimates that exports could reach 8.5 Bcfd by 2020, once all of the six 

terminals where construction has begun or which have secured funding, are 

completed. However, the long-term success of American LNG exports remains 

uncertain. The U.S. could add approximately 15 percent to world liquefaction 

capacity in a market that is currently oversupplied. New entrants in Australia are also 

bringing online significant new capacity into a global market that is already soft as 

demand for imports into North America and Asia weakens. 
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Slide 11

Financial Natural Gas 

Trading Declines

Source: 

InterContinental 

Exchange (ICE)

 -

 2

 4

 6

 8

 10

 12

 14

 16

 -

 100

 200

 300

 400

 500

 600

 700

 800

2008 2009 2010 2011 2012 2013 2014 2015 

thysical Trading Volumes (Tcf)

inancial Trading Volumes (Tcf)

ICE Cinancial (left axis) ICE thysical (right axis

Trading of natural gas financial products on the InterContinental Exchange (ICE) fell 

10 percent in 2015, while ICE physical trading increased 1 percent from 2014, 

breaking the downward trend seen since 2010. Financial trading volumes on ICE still 

significantly outweigh physical trading volumes, but they have fallen at a faster rate 

than physical trading volumes. In 2015, the ratio of ICE financial to physical trading 

volumes was 38 to 1, a decline from 43 to 1 seen in 2014. 

Financial trading on ICE fell to 404 Tcf in 2015, a 46 percent decline from the 2011 

peak of 746 Tcf. The majority of the decline can be attributed to the Nymex Henry 

Hub futures lookalike product, ICE’s largest financial product. Low and stable natural 

gas prices have reduced market activity, and the decline in trading follows larger 

financial industry trends. Commodities trading revenues at the world’s twelve largest 

banks declined 18 percent relative to 2014. 

Although physical natural gas trading on ICE rose to 10.6 Tcf in 2015, physical trading 

on ICE is down 21 percent since it peaked in 2010 at 13.8 Tcf. ICE physical volumes 

are only a subset of the total physical natural gas market and there are significant 

index based transactions done off-exchange reported on the FERC Form 552. These 

transactions accounted for over 43 Tcf (75 percent) of the physical natural gas market 

in 2014, but the 2015 Form 552 data will not be available until May 1st, 2016.
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Slide 12

On-Peak Day-Ahead 2015 

Electric Spot Prices Fall

Sources: NYMEX and CME Clearport market data

$ = Average 2015 Spot trice

% 5ecrease from 201

NP 15

$36

-31%

Palo Verde

$27

-35%

Mid- Columbia

$26

-32%

Indiana 

Hub

$33

-30%

SPP

$29

-35%

ERCOT

North

$30

-32%

PJM West

$43

-32%

NYISO ZJ

$48

-35%

Mass Hub

$49

-35%

Into 

Southern

$31

-27%

Turning to the power markets, wholesale electricity prices were down 27-35 percent 

across the nation in 2015 compared with 2014 at major trading hubs on a monthly 

average basis for on-peak hours. For example, New York LMPs were the lowest they 

have been in 15 years. The decline in wholesale power prices was largely attributable 

to lower natural gas prices. Because natural gas-fired generation sets the marginal 

price in many markets, wholesale electricity prices are sensitive to changes in natural 

gas prices. 

Monthly average wholesale electricity prices were typically highest in New York and 

New England, as in 2014. Prices were often the lowest at Mid-Columbia in the Pacific 

Northwest, where hydroelectric dams are a plentiful and low-cost resource, even 

though water and snowpack levels in 2015 were low compared to historical averages. 

In both regions, the average market-clearing prices were consistent with the 

downward pricing trend nationwide.
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Slide 13

Capacity and Energy Prices 

Diverge in New England & PJM  New England ISO (Mass Hub)

• Average Day-Ahead LMP (2013-15): -25.35%

• Forward Capacity Auction Clearing Price for 2018-19 period relative to 2016-17 period: 

+203%

• Forward Capacity Auction Clearing Price for 2019-2020 period relative to 2018-2019

period: -26% 

 PJM (Western Hub)

• Average Day-Ahead LMP (2013-15): -6.02%

• Base Residual Auction Clearing Price for Base Capacity 2018-19 period relative to 2016-17

period (Rest of RTO): +152.6%

• Base Residual Auction Clearing Price for Capacity Performance in the 2018-2019 period Sources: Derived 

from PJM and 

ISO-NE data

relative to the 2016-2017 period (Rest of RTO): +23.1%

Across eastern RTOs, capacity market prices have been diverging from wholesale 

energy prices for several years because of changes in the generation mix, notably 

lower natural gas prices.

Between 2013 and 2015, average day-ahead LMPs for the ISO New England’s 

Massachusetts Hub have fallen by 25 percent, while average day-ahead LMPs for the 

PJM Western Hub have fallen by six percent. These falling prices are the direct result 

of lower natural gas prices. These lower natural gas prices have driven out nonnatural gas fired capacity like coal-fired Salem Harbor plant and the Vermont Yankee 

nuclear facility in ISO New England, and have forced the Byron and Quad Cities 

nuclear plants to rely upon capacity market auctions for additional revenues in PJM.

Pressure from lower natural gas prices and environmental requirements have led to 

tightening supply in both regions. As a result, we have seen increasing capacity prices 

in those markets. These lower LMPs and higher capacity prices in PJM have resulted 

in the “all-in” costs of energy, capacity, transmission, and ancillary services to 

increase by five percent between 2013 and 2015.

With respect to capacity prices for auctions conducted during this period, the clearing 

price for capacity in Rest of RTO zone in PJM rose by 152.6 percent. For ISO-NE, the 
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capacity auction clearing price has risen by over 200 percent for auctions held during 

those same years. However, ISO-NE’s most recent auction, for the 2019-2020 delivery 

period, resulted in a 26 percent decrease in prices over the prior delivery year, which 

reflects new capacity entering the market. 

Both PJM and ISO New England instituted enhanced performance requirements in 2015 

in their capacity markets. Nearly 90 percent of the capacity that cleared in PJM’s 

capacity auction is subject to these performance requirements during the 2018-2019

commitment period. And 100 percent of the capacity that cleared in ISO New 

England’s capacity auction is subject to the performance requirements during the 

2018-2019 and 2019-2020 periods. 
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Slide 14

Electricity Demand 

Slightly Down in 2015

Source: Derived 

from EIA data

0

200

400

600

800

1,000

1,200

1,400

1,600

Annual Sales in aillions of aWIs

Residential

Commercial

Industrial

As depicted in this chart, electricity demand fell by 1.1 percent in 2015, led by the 

declining usage of electricity in the industrial sector, and little or no growth in the 

residential and commercial sectors. The flattening in electricity consumption has 

been a product of relatively low economic growth and increased efficiency in 

electrical appliances and processes. 

Residential electricity consumption during the first quarter of this year was projected 

to be 5.8 percent lower than the first quarter of 2015, when the country experienced 

colder-than-normal weather, with heating degree days seven percent above the 10-

year average. 
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Slide 15

SPP’s Expansion Brings New 

Generation and New Load

Source: Derived 

from Yes Energy 

data

Turning to market expansions in 2015, SPP expanded its market footprint on October 

1st by incorporating the Western Area Power Administration’s Upper Great Plains 

Region (WAPA-UGP), Basin Electric Power Cooperative (Basin) and Heartland 

Consumers Power District (Heartland)—now collectively known as the Integrated 

System (IS). The new members have a peak winter load of about 5,000 MW and serve 

electricity customers in six states.

With the expansion, SPP has nearly 5,000 substations and over 800 generating units. 

In total, the Integrated System increased SPP capacity by 7.6 GW and increased the 

winter peak load forecast from over 35 thousand MW in the winter 2014/15 to nearly 

42 thousand MW in the winter 2015/16. Moreover, hydroelectric generating capacity 

has also increased by approximately three times in the SPP footprint, with the IS 

system.

Focusing on the graph, LMPs in the South Hub of SPP have been declining since July 

2015, matching the trend of declining wholesale energy prices nationwide. 

Specifically, average real-time LMPs were about $37.78/MWh in South Hub in 2014 and 

declined to about $25.38/MWh in 2015. Staff expects that SPP will issue a report on 

the performance and contributions of the Integrated System to the SPP market when 

more data become available. 
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Slide 16

Net Metering and Distributed 

Energy Resources Growing

Source: Derived 

from EIA Form 

826 data

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Jan Apr Jul Oct Jan Apr Jul Oct Jan Apr Jul Oct Jan Apr Jul Oct Jan Apr Jul Oct

2011 2012 2013 2014 2015

TOTAL ELECTRIC ENERGY SOLD BACK TO THE

UTILITY FOR ALL STATES SERVED (MWh)

This bar chart shows that the total energy sold back by net metering customers to 

utility companies has grown year on year, since 2011. The total electric energy sold 

back to utility companies by net metering customers nationwide has increased by an 

average of nearly 500 percent from 2011 through 2015, while the net generation by 

power plants nationwide has increased by an average of 1.2 percent over that time 

span. 

For example, New York ISO has made integrating distributed energy resources one of 

its four Strategic Initiatives for the period 2016-2020. The New York State Energy 

Research and Development Authority has estimated that residential photovoltaic 

installations will have a potential of 881 MW of cumulative peak capacity and 2,836 

GWh of energy by 2020 in New York state.

Meanwhile, in July 2015, the California ISO approved a plan that made it the “first 

U.S. wholesale power market to allow aggregators of distributed energy resources to 

sell into the wholesale market,” although this matter is currently pending before this 

Commission. More recently, the California Public Utilities Commission voted to 

sustain the net metering credit at the retail rate until 2019. 
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Slide 17

DR Revenues Have Grown 

Through Capacity Markets

Source: Derived 

from PJM and 

ISO-NE

0

100

200

300

400

500

600

700

2016/2017 2017/2018 2018/2019

Total Demand Response 

Revenues from Capacity 

Payments (Million USD)

PJM ISO-NE

On a related matter, demand response programs in certain RTOs have experienced a 

growth in revenues because of rising capacity market prices, as shown in this slide. 

For the delivery periods 2016-17, 2017-18, and 2018-19, the revenues to demand 

response participants in PJM and ISO New England have increased with each new 

delivery period. 

In some markets, demand response program participation has increased, such as in 

New York. The recent Supreme Court ruling on the Commission’s Order 745 is 

expected to result in faster growth in demand response in wholesale electricity 

markets.

Moreover, demand response programs led to energy savings of 1.4 million MWh in 2014

nationwide, with 9.3 million enrolled demand response customers. 
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Slide 18

Renewables Output Continues 

to Grow in CAISO and MISO

Source: Derived 

from MISO and 

CAISO data

In recent years, continued investment in solar and wind energy increased output from 

national renewable generation. Between 2013 and 2015, wind generation rose from 

4.1 percent to 4.6 percent of total generation from utility-scale facilities. Overall 

solar generation rose from two-thirds of one percent to nearly one percent of total 

generation between 2014 and 2015.

Consider these two graphs, showing the ratio of solar energy to total load in California 

ISO (CAISO) on the left and the ratio of wind energy to total load in the Midcontinent 

ISO’s (MISO) Midwest zone on the right. 

On the left side, you can see that solar generation has made significant in-roads in 

California, with over 6 GW of installed utility-scale solar—and about half of the 

nation’s capacity at present. Solar capacity amounts to 13 percent of installed 

capacity (75 GW) and 21 percent of peak load (47 GW) in the California ISO, and it has 

lowered LMPs, particularly in the mid-day hours.

The right side of the slide shows that, in MISO Midwest, wind energy has served more 

load, year on year, for each hour of the day from 2013 through 2015. During the past 

year, wind capacity grew from 13.7 GW to over 15 GW. In November 2015, MISO wind 

set a new hourly peak of 12.6 GW, or 5.8 percent higher than the 2014 peak, although 
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a new record has been set this year. Moreover, 2,234 MW of additional wind capacity 

are expected to come online in MISO in 2016, bringing the total to over 17 GW in 

installed capacity by the start of 2017. 

SPP also set a record for renewables generation in 2015, as output exceeded 2014 

output by approximately 1.5 million MWhs.
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Slide 19

2015 Hydropower was 

Below Average in West 

Source: Derived 

from EIA data

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

million aWh

2010-14 Avg. 2015

As noted earlier, hydropower production in the West was below historical averages 

last year, largely because of continued drought and reduced snowpack. Total net 

generation at 23 hydroelectric plants across the Pacific Northwest was 18.4 percent 

below the year-ago level and 6.9 percent below the 12-year average. As you can see 

from this chart, hydroelectric generation remained especially low throughout the 

summer, about 32 percent below the average of the previous five summers (2010-14). 

The current hydropower outlook in the West is positive. At the end of 2015, snowpack 

levels were significantly higher than a year earlier, lifting the year-to-date levels 

above the median across multiple Western states. Hydropower production was above 

average in the Pacific Northwest in February this year and increased slightly above the 

January total, bringing year-to-date levels in line with historical averages. 
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Slide 20

Financial Trading of 

Electric Products in 2015

Source: Derived 

from InterContinental 

Exchange data

ISh-NE tJ

NYIS

CAIS

NW Iubs aIS

SW IubsStt

(units in aWh)

In our final slide, this chart shows all cleared futures traded on the InterContinental 

Exchange (ICE) for electric products outside ERCOT in 2015. Last year, 94 percent of 

the financial trading of U.S. electricity products outside ERCOT took place at an RTO 

hub, down from 96 percent in 2014. Most regions in the country experienced a 

decrease in financial trading volumes compared with 2014 with the exception of SPP, 

CAISO, and NWPP. PJM’s financial products continue to be the most traded on ICE, 

with 64 percent of the total financial trades involving a PJM product, down from 73 

percent in 2014.
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Slide 21

Item No. A3

March 17, 2016

State of the Markets Report 

2015 

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

on the Commission’s website. We would be happy to answer any questions you may 

have. Thank you.