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AD14-8-000

April 1, 2014

Winter 2013-2014 Operations 

and Market Performance in 

RTOs and ISOs

Chairman LaFleur, Commissioners, good morning.

Staff is pleased to start this conference with an overview of the conditions and impacts of the 

Polar Vortex cold weather events. We are presenting our preliminary observations and analysis 

of the operations of the natural gas and the RTO and ISO markets under conditions of severe 

stress and market pressures.

This report does not necessarily reflect the view of the Commission or any Commissioner.
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2014 Severe Weather 

Events

Jan 6-7 

“Early Jan”

Jan 22

“The $100 

Gas Price”

Feb 6

“West Cold”

Jan 27

“Persistent Cold”

The first three months of 2014 were marked by historically cold weather, record high natural gas 

and electric demand, and record high natural gas prices, which translated into abnormally high 

electricity prices. The cold weather tested the performance of natural gas and electricity 

systems and functioning of markets, which at times came under extreme stress. 

Four major cold events occurred in the natural gas and power markets during January and 

February, followed by a less extensive event in early March. The first three major cold events 

occurred on January 6-7, January 22, and January 27 and primarily affected natural gas and 

electricity markets in the upper Midwest, the Northeast, and the Southeast. The fourth major 

cold event occurred on February 6 and affected much of the Midwest reaching all the way to 

the Southwest and West markets. There was also a cold weather event during the first week in 

March, primarily affecting the Midwest markets. 
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National NG Demand Soars 

Beyond 5-yr Averages

Source: Derived from 

Bentek Energy data.

0

20

40

60

80

100

120

140

160

1/1 1/15 1/29 2/12 2/26 3/12 3/26

Bcfd

2009-2013 Range 2014

Jan

7 Jan

22

Jan

27 Feb

6 Mar

3

U.S. daily natural gas demand spiked to record highs in January, coincident with extreme cold 

weather events. Widespread low temperatures, high winds, and snow drove U.S. natural gas 

demand to reach an all-time peak of 137 Bcf on January 7. During the latter January events, 

U.S. natural gas demand topped out at 132 Bcfd on January 27, compared to the 86 Bcfd fiveyear average for that date, but did not breach the previous peak. There were two lesser 

demand spikes in late February and early March that were well above the five-year range. 

Overall U.S. natural gas demand during this period increased 8% over last year, averaging 96 

Bcfd, a record for the quarter. Residential and commercial demand was up 15%, industrial 

natural gas demand was up 2%, while power burn fell 1.5%. The notable decline in power burn 

can be in part attributed to increased reliance on fuel-oil generation, discussed in greater detail 

later in the report. Natural gas supply, including strong production from shales and imports 

averaged 72 Bcfd, up 3% from last year. The gap between natural gas supply and demand was 

filled by storage withdrawals, which set several records during January and February and have 

left U.S. natural gas storage depleted at an 11-year low of 896 Bcf for the week ending March 

21. 
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0

5

10

15

20

25

30

1/1 1/15 1/29 2/12 2/26 3/12 3/26

Bcfd

2009-2013 Range 2014

Jan

7 Jan

22 Jan

27 Feb

6 Mar

3

Northeast & Southeast 

Peak Demand Coincides

Northeast NG Demand Southeast NG Demand

Source: Derived from Bentek Energy data.

0

5

10

15

20

25

30

35

40

45

50

1/1 1/15 1/29 2/12 2/26 3/12 3/26

Bcfd

2009-2013 Range 2014

Jan

7 Jan

22 Jan

27 Feb

6 Feb

28 Mar

3

The eastern United States was subject to three major cold events that stressed natural gas and 

power markets during January. During the early January event, Northeast natural gas demand 

spiked to 42 Bcfd, the highest since 2009. Record cold blanketed the Southeast and natural gas 

demand reached an all-time high of 25 Bcfd there. High natural gas demand in the Southeast, 

coupled with high demand in the Mid-Atlantic and Northeast resulted in constrained conditions 

on numerous eastern gas pipelines spanning from the Gulf Coast to the Northeast.

Another major winter storm hit the Northeast on January 22, sending temperatures again into 

the low single digits. Northeast natural gas demand reached 41.5 Bcfd, just shy of the record 

set during the early January cold spell, while the Southeast natural gas demand reached 23.9 

Bcfd. Natural gas pipelines serving the region issued capacity constraint warnings and 

operational flow orders (OFOs), holding customers to scheduled flows. Additionally, many 

storage facilities issued restrictions on withdrawals. Local distribution companies also issued 

OFOs and requested that customers voluntarily curtail demand during peak load periods. At 

least 1.5 Bcfd of U.S. natural gas was shut-in due to well freeze-offs, with Northeast gas 

production down 800 MMcfd. More expansive transportation and storage constraints than 

experienced during the earlier January event, coupled with production losses and continued 

strong demand resulted in severe operational strains and manifested in unprecedented natural 

gas price spikes across the eastern U.S. 

The cold temperatures persisted into late January, when natural gas demand once again spiked 

reaching 39 Bcfd in the Northeast and 23.5 Bcfd in the Southeast. 

During each of these cold events, customers who had firm transportation capacity on natural 

gas pipelines generally managed to secure natural gas deliveries. 
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NG Prices Soar in the 

Eastern U.S.

Source: Derived from ICE data.

0

20

40

60

80

100

120

140

Henry

Hub

Chicago

Citygates

MichCon NNGVenturaTZ 5

(nonWGL)

AGT

Citygates

TZ 6

(non-NY)

TZ 6 (NY)

$/ MMBtu

Event #1-Jan 7

Event #2-Jan 22

Event #3-Jan 27

Event #4-Feb 6

Event #5-Mar 3

Jan-Feb 5-Yr Avg

During the early January cold event, record natural gas demand pushed spot natural gas prices 

for delivery on January 7 to spike around $70/MMBtu in the Philadelphia region (Transco Z6 

Non-NY) and the Mid-Atlantic (Transco Z5) with some intraday trades reaching upward of 

$100/MMBtu. In New York, spot prices reached $55.49/MMBtu at Transco Z6 NY. The Midwest 

also saw high spot natural gas prices where they spiked to nearly $14/MMBtu on January 6, one 

day before the cold weather hit the Northeast.

Spot natural gas prices at major Northeast points broke all previous records during the January 

22 event, propelled by more severe and widespread system constraints. At Transco Z6 Non-NY, 

prices spiked to $123/MMBtu, while prices at Transco Z6 NY and Transco Z5 reached 

$120/MMBtu. Those active in the natural gas spot market were at times exposed to these 

record high prices. Similarly, as discussed in detail later, customers purchasing in the RTO 

energy markets were exposed to dramatic price spikes driven by high natural gas prices.

A week later, on January 27, Northeast prices again spiked to almost $100/MMBtu, however 

this time the effects were more widespread and the spot natural gas prices in the Midwest 

reached over $50/MMBtu. Cold weather in the upper Midwest coincided with an explosion on 

TransCanada’s Mainline Line 1 lateral in Manitoba, which disrupted natural gas supplies to the 

Canadian and upper Midwest markets. Spot natural gas price at Northern Natural Gas’ Ventura 

point, feeding the upper Midwest market, spiked to $54/MMBtu, an all-time record, while the 

price at Chicago Citygates reached over $40/MMBtu. 

Use of backup fuel oil by generators, liquefied natural gas (LNG) from the Canaport LNG 

terminal in Nova Scotia, and slightly higher temperatures than experienced in New York and the 

Mid-Atlantic helped ease conditions in New England. During the early January event, prices in 

Boston reached $34/MMBtu at Algonquin Citygates, while during the later January event the 

price peaked at $73/MMBtu. 
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Most other U.S. gas price hubs traded below $6/MMBtu during these cold spells, with Henry 

Hub reaching $7.92/MMBtu in February, the highest since Hurricane Ike in September 2008. 
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New Electric Winter Peak 

Demands Set During Polar 

Vortex

0

20

40

60

80

100

120

140

160

MISO SPP PJM NYISO ISONE

MW

Previous

Winter Peak

Polar Vortex

Peak

Source: Derived from ISO and 

RTO data.

The electric markets in the East were stressed during each of the cold weather events. During 

the early January event, electric demand was at historic levels due to the extremely cold 

weather. New winter peaks were set in MISO, PJM, NYISO, and SPP. ISO-NE reached a peak just 

short of its historic peak. In the cold weather events later in January, regional demand in the 

eastern regions was high, but not at the levels set in early January. However, the latter periods 

did experience stresses, primarily because of historic natural gas prices, fuel delivery 

disruptions, and generator outages.

During the cold weather events, the historically high peak demand combined with high levels of

generation outages placed the regions near their capacity in meeting system demand. The RTOs 

and ISOs declared emergency conditions on several occasions and some implemented 

emergency procedures, including emergency demand response, voltage reduction, emergency 

energy purchases, and public appeals for conservation. They issued several maximum 

generation warnings and some maximum generation actions during the period. A maximum 

generation action means that all generation is to be made available and that generators may be 

asked to produce in the emergency range of their capacity, above normal operating limits. It is 

important to note that the RTOs and ISOs cut no firm load during this period.

Demand response resources were activated to help manage the emergency. PJM activated 

about 2,000 MW of demand response resources for several hours during the morning and 

evening peaks of January 7. Over 2,500 MW of demand response resources were activated for 

several hours on January 23 and on January 28. NYISO requested voluntary reduction from 

about 900 MW of its demand resources on January 7. Demand resources were notified of 

possible deployment on January 28, but were not activated. ISO-NE’s Winter Procurement 

Program provided 21 MW of demand response on five occasions during the winter. MISO did 

not activate their demand response programs during the winter events. Staff continues to 

examine the performance of demand response resources.
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Generator Outages Add 

to Market Stress

*Forced outages and derates. Source: RTOs and ISO.

Early January Peak Day Generation Outages (January 6 and 7)

ISO Peak load 

MW

Lost 

Generation* 

MW

% of 

Peak

Fuel 

Supply 

Issues MW

% of Lost 

Generation

PJM 141,312 41,336 29% 9,718 24%

ISONE 21,320 1,473 7% 1,473 100%

NYISO 25,738 4,135 16% 2,235 54%

MISO 107,770 32,813 30% 6,666 20%

SPP 36,602 3,185 9% 2,412 76%

Mechanical failures in generator systems, fuel deliverability and fuel handling problems in the 

extreme low temperatures experienced this winter led to high levels of forced generation 

outages. These levels contributed to the stressed conditions in the markets that lead to 

emergency actions and higher prices.

During the early January event, the RTOs estimate generation on forced outages and derates 

ranged from about 7 to 30% of the load on the peak day. Significant portions of those outages 

were related to fuel issues including gas curtailments, no fuel, oil delivery and frozen coal. For 

example, PJM estimates that about one-quarter of the forced generation outages on January 7 

were fuel related. In addition, 5,000 MW of combustion turbines failed to start when called. 

During the latter January events, gas curtailments declined in PJM as did start failures for 

combustion turbines. However lack of fuel, oil delivery and frozen coal persisted in causing 

forced outages of 5,000 MW and 8,000 MW in late January. Similarly, MISO experienced a large 

volume of outages on January 7, about 20% of those were fuel related, and lower but still 

significant outages during the later January cold weather events. NYISO also experienced a high 

level of fuel and cold weather related outages on January 7, which declined significantly during

the latter January and early February cold events. Although SPP lost generation on January 6 

due to gas supply constraints, they experienced no weather-related outages during the later 

January and early February cold weather events. ISO-NE experienced a lower level of forced 

generation outages on January 7 relative to other RTOs, however all of the outages were 

attributed to intraday natural gas procurement difficulties. ISO-NE experienced similar levels of 

outages on January 22 and 27 with under 15% attributed to fuel issues. However, as noted 

above, these forced outages did not cause the ISO or RTOs to drop firm load and overall, 

generator performance generally improved after the January 7 event. 

Staff continues to examine the causes of the forced outages, including ascertaining the extent to 

which the fuel issues were supply or delivery related.
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Natural Gas Burn Dips in 

January

0

20

40

60

80

100

120

140

160

180

Net Generation (TWh)

Coal Natural Gas Oil

Source: Derived EIA data.

Coal and natural gas generally maintained their shares as fuel for electricity generation during 

2013. Preliminary data for January 2014 indicates that the sizable increase in electric demand 

was served from mostly coal-fired generation while natural gas-fired generation actually 

declined slightly between December 2013 and January 2014. Oil-fired generation increased 

from 1.3 to 5.7 GWh in the same time frame, although the January total only amounted to 

about two percent of the total generation nationwide. In New England and the Mid-Atlantic, 

the proportional shift was more dramatic. The oil-fired generation replaced natural gas due to a 

combination of high natural gas prices and stable, but now relatively lower oil prices in some 

cases because of the price of natural gas, particularly at the end of January. In other cases, oil 

was used because non-firm transportation service was unavailable to many generators.

The output from other fuels, not shown on the graph, was relatively flat for the period. 
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RTO and ISO Prices

Winter 2014

0

100

200

300

400

500

600

700

800

12/02/13 01/02/14 02/02/14 03/02/14

$/MWh

PJM Western Hub

NYISO-Zone J

Mass Hub

Indiana Hub

Source: Derived from 

Velocity Suite data.

During the early January event, the high loads faced by the electric markets were the main 

factor that led to high prices, requiring the RTOs and ISOs to dispatch more expensive 

generation to serve the higher loads. The electricity prices also included the impact of high 

natural gas prices and the impact of scarcity prices during a limited number of hours. During 

this event the LMPs were near or even above $2,000/MWh for a number of hours in PJM and a 

few hours in MISO. On-peak average real-time prices ran from $300-$700/MWh in these 

regions.

The subsequent cold events in January, February and March also resulted in similarly high prices 

but key drivers changed. During those later events, the prime factor leading to the high electric 

prices in the East and Midwest was historically high natural gas prices.

Due to the elevated levels of demand most of the regions were operating at the high-cost levels 

of their supply stacks and in many cases this meant oil units that are not often used because 

they are not in economic merit order were dispatched. Additionally, some dual-fuel generators 

were forced to use oil when non-firm transportation of natural gas became unavailable. And on 

some days, high natural gas prices made oil-fired generation more economic to dispatch than 

natural gas generation. Head-to-head price competition between oil and gas for power 

production is not something that has occurred much in recent years.
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Electricity Prices Follow 

Natural Gas Prices

0

10

20

30

40

50

60

70

80

90

0

100

200

300

400

500

600

700

800

1/1/14 1/21/14 2/10/14 3/2/14

DA Gas Price ($/MMBtu)

PJM Real-Time Price ($/MWh)

PJM-RTO Real

Time Avg

TETCO M3 DA

Price

Source: Derived from 

Velocity Suite data.

As natural gas is the marginal fuel for most electricity energy markets, the price of natural gas 

plays a leading role in setting the price of electricity. As natural gas prices soared and retreated 

through the period, electricity prices followed, as illustrated by this graph of PJM’s experience.

Unprecedented natural gas prices raised the possibility that some generators would need to 

offer below their variable fuel costs if they were to stay below the $1,000 offer cap. PJM, NYISO 

and CAISO sought and were granted waivers of the existing market rules in order to allow 

generators to offer power at higher prices or otherwise recover their high fuel costs. 
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Record NG Prices in the 

West

Source: Derived from ICE data.

0

10

20

30

40

50

60

PG&E

Citygate

PG&E

Topock

Cheyenne

Hub

SoCal

Border

$/MMBtu

Event #1-Jan 7 Event #2-Jan 22

Event #3-Jan 27 Event #4-Feb 6

Event #5-Mar 3 Jan-Feb 5-Yr Avg

In contrast to the earlier events, the February cold weather primarily affected the Midwest and 

West. Natural gas demand and cash prices soared as persistent and widespread arctic 

temperatures blanketed the regions. Natural gas demand rose sharply in both the consuming 

and producing regions. During this event, Texas demand spiked to over 17 Bcfd, over 1 Bcf 

greater than the highest demand recorded during the Southwest outages of February 2011. At 

the same time, the weather had significant effects on production in New Mexico, Texas, and 

Kansas, as well freeze-offs knocked out at least 1.1 Bcfd of regional natural gas production. 

Numerous interstate pipelines invoked operational flow orders, which limited supplies to 

interruptible customers, primarily power plants. Some storage operators in Texas and Louisiana 

warned interruptible customers that their service could be unavailable. 

High gas demand and prices pulled supplies away from California, leaving natural gas end users 

in California to rely more on in-state natural gas storage and less on inflows on interstate 

pipelines. SoCalGas and SDG&E issued system-wide alerts due to the low customer deliveries, 

which resulted in curtailments to several power plants. 

Already elevated prices in the Midwest and the Mid-continent spread to the West Coast. The 

spot natural gas price at PG&E Citygate settled at almost $22/MMBtu on February 6, while 

SoCal Border hit $20.17/MMBtu and PG&E Topock spiked to a record $40/MMBtu. Prices at 

Cheyenne Hub in the Rockies reached over $30/MMBtu. Prices in the Midwest, at Chicago 

reached almost $30/MMBtu.

While the cold weather impacted the West, CAISO did not experience unusual increases in 

electricity demand on February 6. However, the RTO did respond to the disruption and 

curtailments in the natural gas market in order to avoid interrupting firm electric load. CAISO 

redispatched gas-fired generation that had been scheduled in the day-ahead market, restricted 

maintenance, procured additional imports, issued system warnings, called for demand 

response, and cut interruptible load and experienced ancillary services shortages which 
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triggered scarcity pricing for these services. Real-time prices averaged $120/MWh during the 

day, up significantly compared to the average real-time price of about $59/MWh for the month 

of February as a whole. However, the prices do not fully reflect the out-of-market actions taken 

to address the disruption to the market and the uplift that will be incurred.
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Uplift is High in 

January

0%

10%

20%

30%

40%

50%

60%

70%

80%

PJM ISONE NYISO

January 

Monthly Uplift 

Compared to 

2013 Annual

Uplift

Source: Derived from ISO and RTO data.

The high LMPs in the RTOs and ISOs did not reflect the entire costs of these events. A large part 

of uplift goes to reimburse generators for costs that are not covered through normal LMP and 

ancillary service sales. Some of the actions taken by the regions resulted in high, in some cases 

historically high, uplift payments. In the face of high demand and possible fuel problems 

compared to normal operations, the RTOs and ISOs took certain conservative measure to 

maintain reliability such as to cancel planned transmission outages, require the commitment of 

additional generation, and require generators to confirm fuel availability.

The uplift costs for the month of January rival the total uplift incurred by the RTOs for an entire 

year.
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Propane Price Spikes

Source: Derived 

from Bloomberg 

data.

0

10

20

30

40

50

60

$/MMBtu

Propane Conway KS Spot

Another way that the cold weather events affected the energy markets was through the 

increase in demand in the propane market. By the time of the January cold weather events, 

propane inventories were already depleted because of exceptional agricultural drying use, 

particularly for the corn harvest after a rainy fall. The January weather caused further inventory 

reductions as propane went to serve a strong heating demand. The price of propane spiked to 

$54/MMBtu at Conway Kansas, a major propane storage and trading hub on January 23. On 

February 7, the Commission exercised its emergency powers under the Interstate Commerce 

Act to order temporary priority treatment of propane in pipeline shipments. Propane shares 

pipeline capacity with other petroleum products and the Commission action was needed to 

help alleviate a shortage in the Midwest and Northeast.
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Analytics and 

Surveillance Response

 Automated computer routines (“screens”) that sift through both 

public and non-public data, such as EQR data, ISO/RTO market data, 

including offer, uplift, and outage data and FTR holdings, e-Tags, ICE 

transaction data, large trader reporting data, Form 552 data, Bentek, 

and Platts.

 Built by DAS staff based on:

 Known manipulative schemes

 Market rules

 Behavior that could constitute manipulation if entered 

into

 Statistical measures that help identify market anomalies

 Persistence measures

The Office of Enforcement’s Division of Analytics and Surveillance routinely monitors wholesale 

natural gas and power markets to look for potential market manipulation and any other 

inappropriate behavior by running automated screens that sift through a variety of public and 

non-public data. The screens were built by Division staff and based upon known manipulative 

schemes, Market Rules, behavior that could constitute manipulation, statistical measures that 

help identify market anomalies and persistence measures.
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Analytics and 

Surveillance Response

 Analysts routinely run screens and analyze the 

output, sharing the results with all division 

staff, including management.

 While DAS surveillance screens are based on 

different parameters and theoretical 

approaches, many follow a common 

framework composed of three building blocks:

 Tool  Target  Benefiting Position

Analysts regularly review and analyze the output of these screens to determine whether the 

behavior identified by the screen requires additional analysis or follow up. Many screens have a 

common framework with the potential manipulative tool being physical energy trades or virtual 

transactions, the manipulative target being an index or LMP and the benefiting position a swap 

or an FTR.
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Analytics and 

Surveillance Response  Algorithmic surveillance screens generated multiple alerts in January and February for 

New England, the Mid-Atlantic, the Midwest and California. 

 Staff followed up on these alerts and other information it received to identify potential 

market misbehavior.

 Coordinated with RTO/ISO and market monitoring staff to discuss market 

conditions and operations and any issues they identified related to their 

markets

 Conducted dozens of interviews with generators, gas suppliers and traders 

to gather market insights and facts relating to operations and bidding

 Used Order 760 datasets to gather generator uplift payments and offers

 Used the recently received CFTC Large Trader Report data to identify 

financial incentives by company at volatile hubs

 Data requests were issued to certain companies

This routine screening initially revealed the unprecedented volatility in the natural gas markets. 

At the time, staff wanted to determine if this was scarcity pricing, and whether any participants 

were engaged in market manipulation. Some of the initial data points were screen alerts for 

natural gas market participants with high market concentration seeming to purchase at ever 

escalating price levels, primarily in the East and the Midcontinent. Staff interviewed natural gas 

suppliers, traders and generators, as well as coordinated with system operators and market 

monitors.

Following interviews, staff used Order 760 data to verify what we were told. Further staff were 

able to utilize data from the feed we are now receiving from the CFTC of the Large Trader 

Report. 
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Analytics and Surveillance 

Observations

Preliminary observations:

 Natural gas spot prices were at record levels, 

driven by high demand, pipeline flow restrictions, 

covering of physical short positions and concern 

for pipeline penalties .

 Pricing issues aggravated by power users not 

knowing gas needs within the gas trading window 

and pipelines restricting hourly usage flexibility. 

Users reflected expectation of low Northeast basis 

in their supply planning (e.g., due to increased 

Marcellus supply and new transport).

Natural gas prices were high and deliverability into market areas was a concern. Although shale 

supplies are plentiful, some gas did not make it to market demand centers in the east due to 

pipeline constraints, contributing to the extreme basis. Some counterparties sold physical 

options, often to natural gas utilities, and then had to scramble when they were called or pay 

high financial penalties. Going into the winter, many market participants expected plentiful 

supply and pipeline capacity. When bid-week trading for January came in so high, almost 

$22/MMBtu in New England for instance, some companies went short physical, thinking prices 

could only go down. Anybody shorting January stood to have large losses in the daily market as 

January prices began to spike. 
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Analytics and Surveillance 

Observations

 Preliminary observations:

 Higher levels of uplift related to conservative operations 

and high natural gas prices

 Unable to re-supply oil as quickly as needed due to 

significant oil for power generation (fewer problems in New 

England due to this winter’s fuel program) 

 Spot market supply was reduced. Firm users were able to 

buy gas but certain interruptible customers (especially 

power peaking units) were unable to obtain gas for some 

periods. 

 Our review is ongoing and we will report to the Commission upon 

completion.

Generators were hit particularly hard by market stresses and high spot natural gas prices. 

Market stress was exacerbated by operational logistics, whereby generators had to consume gas 

on a 24-hour ratable basis due to pipeline restrictions. Some generators found it difficult to 

accommodate dispatch directions that required them to buy intra-day gas. System operators 

managed the high demand periods and generator inflexibility with conservative operations that 

led to high amounts of uplift. Examples of this conservatism include earlier than normal 

commitment of units to ensure gas availability, and not committing fuel oil units that were 

economic, instead conserving them for an anticipated peak, thereby putting more pressure on 

the gas market.

Staff’s review is ongoing; our data has served as well in this effort. The ICE data feed we receive 

assisted us as did the Order 760 data we receive from RTOs on a daily basis. In addition the 

Large Trader Report that we now receive from the CFTC under the new MOU was useful.

We will report to the Commission upon completion. 
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AD14-8-000

April 1, 2014

Winter 2013-2014 Operations 

and Market Performance in 

RTOs and ISOs

Not many months ago staff described the market effects of the extraordinarily low natural gas 

prices. Staff does not expect the historic prices at the high end of the spectrum to become the 

norm. However, the range in prices has tested some of the market systems and procedures 

used by the RTOs and ISOs and revealed difficulty in achieving efficient market results in 

stressed system conditions. Included, for example, are the need to use out-of-market 

operations that largely result in uplift, bid caps that required adjustment, and limitations of 

intra-day natural gas procurement and transportation during high demand periods. Further, 

increasing natural gas demand for industrial uses and power burn in the long-term, and 

continuing infrastructure constraints in the near-term, may exert upward pressure on natural 

gas prices which staff would expect to see reflected in electricity prices. Staff will continue to 

conduct analysis of the events of this winter, and look further into how well market procedures 

functioned.

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

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

NOTE: to see full size slides go to: http://www.ferc.gov/CalendarFiles/20140401083844-

Staff%20Presentation.pdf