Page 1 of 22

Item No: A-3

March 19, 2015

2014

State of the Markets

Good morning Chairman and Commissioners.

The Office of Enforcement’s Division of Energy Market Oversight is pleased to present the 

2014 State of the Markets Report. This report is staff’s annual opportunity to share our 

assessment on natural gas, electric, and other energy markets developments during the past 

year to better inform the Commission’s understanding of current and future trends.
Page 2 of 22

Slide 2

State of the Markets

Highlights

 Extreme temperatures early in 2014 had lasting impacts 

 Natural gas prices decline through the year, while oil prices plunge

 Natural gas production reaches new records and storage recovers

 Northeast natural gas prices disconnect from Henry Hub

 Organized markets continue to evolve: California ISO launches 

EIM, SPP begins DAY 2 Market, and Entergy joins MISO

 RTOs and utilities adjust to changing resource mix

 Markets performed well in early 2015 despite extreme weather 

During the first quarter of 2014, extreme cold temperatures stressed the country’s natural gas 

infrastructure and power markets. U.S. natural gas prices reached record levels resulting in 

electricity price spikes. After a dramatic start to 2014, natural gas and electricity prices 

were relatively low and stable for the remainder of the year. Despite low prices throughout 

most of the year, natural gas production continued to break records. Oil prices plunged 

during the second half of 2014, which has implications for oil and gas industry activity in 2015 

and beyond. 

In 2014, there were significant developments in the organized markets, with major changes in 

CAISO and SPP, and the expansion of MISO. Electricity markets continue to adjust to a change 

in generation mix, as coal plants retire and new natural gas and renewable generation enters 

service.
Page 3 of 22

Slide 3

Pricing Point

BOLD – 2014 price

Green – % increase from 

previous year

Red – % decrease from 

previous year

Source: Derived 

from ICE & Platts

data

Columbia

TCO

Algonquin

Citygate AECO 

Chicago

Citygate

Transco

NGPL Z6-NY

Tex-Okla

El Paso

Permian

SoCal 

Border

PG&E

Citygate

CIG

NW 

Sumas

HSC Henry 

Hub

FGTZ3

$4.85

34%

$4.83

22%

$4.27

18%

$4.50

17%

$4.26

17%

$4.30

16%

$4.03

42%

$4.31

18%

$4.32

16%

$4.34

15%

$4.30

16%

$5.52

43%

$7.95

14%

$6.22

22%

Average NG Spot Prices 

Higher in 2014

The spot natural gas price at Henry Hub averaged $4.32/MMBtu in 2014, 16 percent higher 

than in 2013. Prices were on average 14 to 43 percent higher at key hubs throughout the 

country, with the Chicago Citygate experiencing the highest increase. Price spikes during the 

Polar Vortex events early in the year drove many of the increases, with Transco Zone 6 NonNY reaching $123/MMBtu in January. Although prices began to moderate in the spring, 

concerns about low storage inventories kept prices up until early summer. Prices fell in the 

fall as storage recovered, and by late December, the Henry Hub price was below $3.00. 

The 43 percent increase in the average price at the Chicago Citygate was a result of both the 

high price levels during the harsh winter, and of continued reliance on natural gas supplies 

from Canada. Canadian prices were 31 percent higher in 2014 than in 2013, as they 

recovered from an oversupply condition in 2013. In addition, natural gas demand in the 

Midwest in 2014 was the highest on record, up 3 percent from 2013. In contrast, the 

Northeast experienced some of the lowest year-on-year price increases, as the region 

benefitted from growing Marcellus Shale supplies.
Page 4 of 22

Slide 4

U.S. NG Demand 

Sets New Record 

0

20

40

60

80

100

120

140

160

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

Bcfd

2009-2013 Range 2014

Source: Derived 

from Bentek

Energy data

On the back of the coldest winter in over a decade, average U.S. natural gas demand for 2014 

reached a new record of 70.7 Bcfd. Residential and commercial natural gas demand grew 3 

percent in 2014, while industrial natural gas demand grew 2 percent as low prices of natural 

gas and natural gas liquids continued to fuel a renaissance in U.S. industry. Despite the 

record-cold winter, however, natural gas demand for electricity generation decreased by 0.5 

Bcfd, or 3 percent from 2013 levels as the result of a cooler-than-normal summer.
Page 5 of 22

Slide 5

Record Injections 

Replenished NG Storage

Source: Derived 

from Energy 

Information 

Administration data

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

2007 2008 2009 2010 2011 2012 2013 2014

Bcf

This chart shows the massive replenishment of natural gas inventories that took place in 2014. 

The injection season began in the spring with 822 Bcf of natural gas in storage, the lowest 

level since 2003. However, mild temperatures in the summer and fall, and steady increases 

in U.S. natural gas production resulted in market participants injecting almost 2.8 Tcf during 

the 2014 refill season, nearly 10 percent above the previous high. Inventories reached 3,611 

Bcf by November 1, the traditional end of the injection season, only 5 percent below the fiveyear average. By the end of the year, inventories stood at 3,220 Bcf, 8 percent above 2013 

levels.

Despite strong natural gas withdrawals early in January and February of this year, inventories 

were 47 percent above 2014 levels by March 6. Assuming average withdrawals between now 

and the end of March, inventories are poised to enter the injection season over half a Bcf 

above the same time in 2014, putting downward pressure on prices going into the summer.
Page 6 of 22

Slide 6

Source: Derived 

from Bentek

Energy data

 -

 10

 20

 30

 40

 50

 60

 70

 80

 90

Bcfd

CONV9NTIONAL

S

H

A

L

E

NG From SOale Drives

2014 Production Records

Natural gas production grew 5 percent in 2014, averaging 68.4 Bcfd and breaking the record 

set in 2013. Two shale formations, the Marcellus in Pennsylvania and the Eagle Ford in Texas, 

accounted for 34 percent of the production increase, averaging 14 and 4 Bcfd respectively. 

Crude oil prices fell from $115 per barrel in mid-June to $53 at the end of December, 

reducing drilling activity in the latter half of 2014. However, natural gas production 

continued to climb. There is concern that prolonged low crude oil and natural gas prices 

could result in slower growth or even a decline in natural gas production. However, year-todate production has consistently remained above 71 Bcfd, and by the end of February, it was 

on average 6.4 percent higher than in the first 2-months of 2014.

A backlog of uncompleted wells could help maintain production levels in the near future. As 

of the middle of January, there were approximately 1,100 uncompleted wells in Marcellus.
Page 7 of 22

Slide 7

Low NG Prices Continue 

Through 2015

Source: Derived 

from Bloomberg 

data

0

2

4

6

8

10

12

14

16

$/MMBtu

Chicago

Algonquin (Boston)

Henry Hub (NYMEX)

PG&E

TZ6 NY (NYC)

With the exception of a few moderate weather driven price spikes since the start of 2015, 

prices remained relatively low this past winter. The forward curve at most major trading 

points indicates market participants expect prices to remain low for the rest of 2015. The 

exceptions are Boston and New York City, where futures prices for December 2015 through 

February 2016 average $11.61 and $9/MMBtu, respectively, due to continued pipeline 

constraints into these markets.

For the rest of 2015, the forward curve suggests that natural gas, rather than coal, will be on 

the margin as it was in 2012, which could lead to increased substitution of gas-fired 

generation for coal-fired generation this summer.

Falling oil prices made oil-fired generation economic when compared to natural gas in New 

England and New York this past winter. If oil prices remain at current levels, we could 

continue to see increased use of oil for power generation.
Page 8 of 22

Slide 8

Marcellus Production 

Overwhelms Infrastructure

Source: Derived 

from Staff analysis 

of GPCM data

0

5

10

15

20

25

30

35

40

45

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Bcfd

OH

WV

PA

Total Proposed

Likely Pipeline Capacity

This slide projects growth in natural gas production in the Marcellus and Utica Shales in 

Pennsylvania, West Virginia, and Ohio. Total Northeast production reached over 19 Bcfd at 

the beginning of 2015, up 10 Bcfd since 2011. The two lines show the growth in proposed 

pipeline capacity. Pipeline expansions have not always kept pace with production growth 

leading to sub $2.00 prices in parts of the Marcellus region. Producers are responding to low 

prices by contracting for new pipeline capacity to carry incremental production to consuming 

markets.

The Northeast became a net exporter of natural gas for the first time last summer and future 

pipeline expansions are targeting exports to eastern Canada, the Midwest, the Southeast, and 

the Gulf Coast. As Marcellus Shale gas makes its way into neighboring regions, its impact on 

markets and basis relationships will broaden. Last summer New York and Boston experienced 

prices below Henry Hub for the first time. Market Oversight expects that Marcellus exports 

will moderate prices in other regions over the next few years.
Page 9 of 22

Slide 9

U.S. Natural Gas Exports 

Continue to Rise

Source: Derived 

from EIA data

0

500

1,000

1,500

2,000

2,500

2010 2011 2012 2013 2014

MMcfd

Pipeline Natural Gas Exports to Mexico

Exports to Mexico reached 2 Bcfd in 2014, up from 1.8 Bcfd in 2013 supported by the growth 

in Eagle Ford Shale production in South Texas and by new pipeline infrastructure across the 

border. Exports will likely continue to rise as Mexican power generation demand increases, 

and as more pipeline capacity goes into service, including the 2.1 Bcfd NET Midstream Rio 

Grande pipeline, scheduled to enter service in 2016.

Plans to export LNG from the U.S. continue to move forward. As of the end of 2014, eight 

projects had been approved, with four under construction including those at Sabine Pass, 

expected to enter service in 2016, and at Freeport LNG, Cove Point LNG, and Cameron LNG. 

Meanwhile, reliance on LNG imports continued to decrease. Sendouts from U.S. LNG 

terminals averaged 100 MMcfd in 2014, 67% below the 2013 levels, while imports from 

Canaport LNG into New England averaged 49 MMcfd, 52% below 2013.

Gross natural gas imports from Canada averaged 7.2 Bcfd. However, exports from the U.S. to 

Canada averaged 2.1 Bcfd. This makes net Canadian imports 5.2 Bcfd. Marcellus shale 

production continued to displace Canadian imports, with flows from the Northeast into 

Ontario reaching 350 MMcfd in August.
Page 10 of 22

Slide 10

Significant Changes 

in RTO Markets

 SPP implements Day 2 Market and moves 

to increase its footprint

 CAISO revamps real-time market

 The CAISO Energy Imbalance Market 

launched on November 1

 MISO sees first full year of Entergy 

integration

On March 1, Southwest Power Pool transitioned to its new, financially binding Day 2 Market. 

The Day 2 Market launch included new features for SPP such as a Day-Ahead (DA) Market, 

Transmission Congestion Rights, price-based Operating Reserves procurement, and the 

consolidation of 16 Balancing Authorities. In 2015, the RTO expects to expand its footprint 

with the addition of the WAPA-Great Plains, Basin Electric, and Heartland balancing areas.

On May 1, CAISO revamped its real-time market, replacing the hour-ahead market used to 

schedule and price imports and exports, with a 15-minute market, which prices and schedules 

internal generation as well as interchange. This new construct provides more discrete price 

signals for generators. CAISO also revised the minimum price floor to encourage renewables 

to become more price sensitive – to decrease output when supply outstrips demand and prices 

become negative.

Additionally on November 1, CAISO launched its Energy Imbalance Market (EIM).

Finally, Entergy and five other balancing areas joined MISO at the end of 2013 and that new 

area now accounts for about 25 percent of MISO’s total load. The integration of Entergy adds 

a new dimension to the greater southeastern power market because of the way interchange is 

priced. Entities that ship power into, out of, or through the Entergy area are now assessed 

congestion charges for the MISO portion.
Page 11 of 22

Slide 11

On-Peak Day-Ahead 

2014 Electric Spot Prices

Source: Derived from SNL and PLATTS data

NP 15

$52

17% Palo Verde

$42

13%

Mid- Columbia

$39

3%

Indiana 

Hub

$48

26%

SPP

$40

18%

ERCOT

North

$45

20%

PJM West

$63

38%

NYISO ZJ

$73

19%

Mass Hub

$76

18%

Into 

Southern

$42 $ = Average 2014 Spot Price 22%

% Increase from 2013

Electricity average spot prices rose across the country in 2014, primarily driven by high prices 

in the first quarter.

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

part, variations in natural gas prices. The largest increases were in PJM, where average onpeak day-ahead prices at the Western Hub rose 38 percent due to price spikes in the first 

quarter. 

Prices in the Pacific Northwest, where increased hydro generation kept prices down, were the 

lowest in the country. CAISO had some of the lowest price increases in the country with 

average on-peak day-ahead prices rising by 17 percent. Prices remained modest in the 

Southeast throughout the year, averaging $42/MWh at the Into Southern pricing point. 
Page 12 of 22

Slide 12

NG and Renewables 

Continue to Displace Coal

Source: Derived 

from Energy 

Velocity data -10000

-5000

0

5000

10000

15000

20000

Nuclear Coal Gas Wind Solar Oil Total

Net Capacity Change (MW)

2011

2012

2013

2014

Nationally, total generating capacity increased 10.8 GW in 2014, compared to a net loss of 3 

GW of mostly coal and nuclear units in the year before. Substantial coal retirements began in 

2012 and continued into 2014, however the 2014 decrease in net coal capacity was lower than 

that of the previous two years. Greater coal retirements are expected in 2015, largely due to 

the April effective date of the Mercury and Air Toxics Standards requirements, with natural 

gas providing the bulk of capacity replacements given its economic advantage. 

The largest year-on-year change came from natural gas capacity additions, which rose by 7.7 

GW in 2014, compared to a gain of 1.9 GW in 2013. Net wind installed capacity increased by 

5 GW in 2014, driven in part by the renewal of the Federal Production Tax Credit. Net utility 

scale solar capacity additions, which had grown dramatically from 2011-2013, plateaued in 

2014 at nearly 4 GW.
Page 13 of 22

Slide 13

Electricity Demand 

Flat in 2014

Source: Derived 

from EIA data

800,000

900,000

1,000,000

1,100,000

1,200,000

1,300,000

1,400,000

1,500,000

Annual Electricity Sales 

(Million KWh)

Residential

Commercial

Industrial

Nationally, electricity demand remained flat compared to 2013. Residential and commercial 

demand rose slightly driven in part by the extreme weather in the first quarter, while 

industrial demand declined. Energy efficiency measures and growth in behind-the-meter 

generation, such as rooftop solar, helped moderate the growth in electricity demand at 

utilities.
Page 14 of 22

Slide 14

2014 Financial Trading of 

Electricity Products Mixed

Source: Derived from 

Intercontinental 

Exchange data

PJM

CAISO

NW

ISO-NE

MISO

NYISO

SW

SPP

This pie chart shows all cleared futures traded on the Intercontinental Exchange for power 

outside ERCOT in 2014. Last year, 96 percent of the financial trading of U.S. electricity 

products outside ERCOT took place at an RTO hub, up from 92 percent in 2013. Most regions 

in the country experienced a slight decrease in financial trading volumes compared with 2013 

with the exception of the NYISO and PJM. PJM’s financial products continue to be the most 

traded on ICE, with 73 percent of the total financial trades involving a PJM product, up from 

68 percent of 2013.
Page 15 of 22

Slide 15

Financial Liquidity in NG 

Markets at 5-Year Low

Source: Derived from 

Intercontinental

Exchange data

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

2008 2009 2010 2011 2012 2013 2014

Trading (Bcf)

Physical Financial

The red line on this graph represents the sum, of all domestic natural gas financial products, 

in billion cubic feet, traded on ICE, including futures, swaps, and spreads at all hubs. The 

majority of the volume, approximately 90% in 2014, consists of trading in the Nymex LookAlike futures contract. The yellow line represents the sum of all physical volumes traded on 

ICE at all hubs, including spot and monthly transactions. The financial to physical ratio is 

approximately 30 to 1. 

Natural gas trading volumes declined in 2014, for the fourth straight year. Financial volumes 

on ICE declined over 25 percent, in step with the drop on the Chicago Mercantile Exchange. 

Financial volumes continue to significantly outweigh physical volumes and were 30 times 

larger in 2014. The sustained increase of natural gas production across the U.S. led to lower 

and more stable natural gas prices over the past several years. Less volatile prices hurt 

speculative trading profits, this caused companies, particularly large banks, to reduce or 

eliminate their trading exposure. As a result, physical and financial trading has fallen 

significantly from its highs in 2011. 
Page 16 of 22

Slide 16

Extreme Weather Tests 

Energy Markets in 2015

Source: The University 

of Illinois WW2010 

Project

We will now provide a brief recap of how the energy markets fared in this current winter.

By many measures, this winter rivaled last year's in terms of record low temperatures across 

much of the country, and in overall demand for electricity. However, compared to last 

winter, with its series of Polar Vortex events in early 2014, the wholesale power markets and 

natural gas pipeline system performed remarkably well. 

As reflected by this map, extreme cold temperatures prevailed on February 20 and records 

were set in 72 cities including Washington DC, Detroit, Cleveland and Pittsburgh. On that 

day, PJM set a new winter peak record of approximately 144,000 MW, beating its previous 

record of about 142,000 MW, set in January 2014. The Southwest Power Pool also set a new 

winter peak record of 36,993 MW on January 8, and MISO, NYISO, and ISO-NE all experienced 

peak demands this winter that nearly matched last year’s winter records.
Page 17 of 22

Slide 17

Market Readiness 

Moderates Weather Impact

Source: Derived 

from PJM data

0

5

10

15

20

25

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

1/7/2014 2/20/2015

Forced Outage Rate (%)

Forced Outage (MW)

Forced hutages in t

Forced Outage (MW)

Forced Outage Rate

Despite challenging winter conditions, prices in the electricity markets remained moderate, 

helped by stable natural gas prices and lower forced outage rates. This stands in contrast to 

last winter, when outage rates were high, price spikes were common, and PJM and NYISO 

both sought and received authority to waive their $1,000 MWh offer caps to ensure that 

generators would be able to recover their fuel costs. Last winter, many generators also 

complained that they were unable to secure sufficient natural gas supplies to operate their 

plants. 

Notably, actions taken since last winter by the RTOs and market participants, such as PJM's 

new Cold Weather Preparation Guidelines and the continuation of ISO-NE's Winter Reliability 

Program for a second winter, appear to have improved operational performance and the 

availability of units, which helped to moderate prices. For example, real-time prices at the 

PJM Western Hub were $400 MWh lower on PJM's peak day this winter, than on last winter's 

peak day. The drop in real-time prices can also be attributed to an improved forced outage 

rate, with PJM's outage rate dropping from 22% last winter to 12% this winter.

Across the RTOs and ISOs, no significant outages or major operational issues were reported 

and the bulk electrical system performed well despite changes to the resource supply mix. In 

particular, ISO-NE, which found itself in a stressed operational state last year, did not 

experience any significant reliability issues this winter despite the retirement of the Vermont 

Yankee nuclear station in late December, which removed 615 MW of baseload capacity from 

the grid.
Page 18 of 22

Slide 18

Markets Perform well 

During 2015 Winter

Source: Derived from ISO data

0

50

100

150

200

250

Jan. Feb. Jan. Feb.

2014 2015

$/MWh On-Peak Average RT Prices

IS0-NE ISO-NE NYISO PJM

As shown by the price differentials in this chart, the contrast between last year's and this 

year's winter cannot be understated. While no single reason can explain why the wholesale 

power markets performed better this winter, the relative improvements seen in terms of 

prices and operations are likely the result of several factors.

In addition to better cold-weather preparation of assets and measures approved by the 

Commission, such as New England's Winter Reliability Program, electric transmission and 

natural gas pipeline operators are now communicating more effectively during periods of 

stress to improve coordination and the reliability of their systems. Moreover, as discussed 

below, record natural gas production, plentiful storage inventories, new pipeline 

infrastructure, and low oil prices, are factors that also contributed to this winter's moderate 

electricity prices and the improved performance of the electricity markets.
Page 19 of 22

Slide 19

2015 Energy Uplift 

Payments Fall Markedly

Source: Derived 

from PJM and 

ISO-NE data

0

100

200

300

400

500

600

700

800

2014 2015

Total Uplift (Million $) 

Uplift for January and Februar

PJM ISONE ISO-NE

This chart highlights the decline in uplift payments made to generators in PJM and ISO-New 

England between last winter and this winter. These “make whole” payments are made to 

generators to ensure that they are not running at a loss during critical periods. While uplift is 

a legitimate cost, this out-of-market compensation is often unpredictable for market 

participants, particularly load serving entities. In January and February of 2014, PJM 

collected a record $667 million in uplift charges, which is largely attributed to the high cost 

of fuel during the midst of the Polar Vortex. However, PJM Uplift charges during the same 

period in 2015 fell to $105 million, largely because of moderate fuel prices and fewer 

constraints on the natural gas pipeline system.
Page 20 of 22

Slide 20

Winter 2015 NG Prices 

Lower than in 2014

Source: Derived from 

Intercontinental 

Exchange data

$0

$5

$10

$15

$20

$25

$30

Jan Feb Jan Feb

2014 2015

$/MMBtu

SoCal

Chicago

Transco Z6 Non NY

Transco Z6 NY

Algonquin

Compared to last winter, natural gas prices this winter have been lower and less volatile, 

notwithstanding the fact that natural gas demand in January and February of 2015 was 2 

percent higher than for the same period in 2014. Driving this increase was a 13 percent jump 

in gas used for power generation.

Yet, despite higher demand, natural gas prices had fewer and smaller spikes than in 2014. 

The Henry Hub spot price averaged $2.91/MMBtu for January and February 2015, down 44 

percent from the same period in 2014. As the graph shows, prices at major hubs throughout 

the country were lower than last year. January and February prices in 2015 were below 2014 

by an average of 41 percent in both Boston and New York City, 46 percent in Southern 

California, and 65 percent in Chicago. 

Several factors accounted for the lower prices and lower peaks, including increased 

production, new pipeline capacity moving supplies from producing to market areas, fewer and 

less widespread pipeline disruptions, and better gas-electric coordination. In addition, 

imports into Northeast LNG terminals, including Cove Point in Maryland, and Everett and 

Northeast Gateway near Boston, averaged 94 Bcfd this winter, 45% above the 2013-2014 

winter. Furthermore, this past winter the incidences of extreme cold weather came later in 

the season, when storage inventories were still robust and market participants were less 

concerned about having sufficient supplies to see them through spring.
Page 21 of 22

Slide 21

Added NG Infrastructure 

Curbed Winter 2015 Prices

Source: Staff research

Top 5 tipeline trojects that went hnline Q4 2014 to trov

hutlet for bortheast Gas troduce

State Served tipeline troject bame Capacity (aac

tA Equitrans Wefferson Compression Statio

Expansio

600

hI, bY, LA TETCh – TEAa 201

tA biSource West Side Expansion troject

tA Equitrans I-164 tipeline trojects

tA TCh – Smithfield III Expansion 

Increased pipeline capacity to move natural gas into major Northeast demand centers, 

particularly New York City, was a major reason for the moderate price volatility the region 

experienced this past winter. This table shows some of the pipeline projects that went into 

service in 2014 in the Northeast. Operators put nearly 4 Bcfd of new pipeline capacity into 

service in the Marcellus and Utica Shale regions, with approximately 2.5 Bcfd of this new 

capacity serving Northeast demand and 1.5 Bcfd providing takeaway capacity for producers. 

The Texas Eastern’s TEAM 2014 expansion and Transco’s Northeast Connector added new 

capacity to move supply into the New Jersey and New York markets. 

Another factor helping moderate prices was better gas-electric coordination. Gas-electric 

coordination initiatives, which FERC began to actively encourage in 2011, led to concrete 

actions by participants in both industries. These efforts have enhanced communications and 

understanding across these industries, and have reduced or eliminated some of the language 

barriers that up until recently were common. We note that the Commission’s efforts to 

promote gas-electric coordination are continuing. 
Page 22 of 22

Slide 22

Item No: A-3

March 19, 2015

2014

State of the Markets

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

Commission’s website. Thank you.