In-depth analysis of the opportunities (attn: investors) and challenges (grid failures) posed by future Polar Vortex(es).

1. WHITE PAPER
Polar Vortex Energy Pricing Implications—
Commercial Opportunities and System Reliability
By Judah Rose, Shanthi Muthiah, Frank Brock, John Karp, and Trishagni Sakya
ICF International
Executive Summary
For the second time in just over three years, a major weather event (the so-called polar vortex) has
generated significant profits for generators, particularly in the eastern and southern United States.
Wholesale power price increases were caused by many factors, notably high and fluctuating delivered
natural gas pricing, generation supply shortages, and differing market structures. Changing weather
patterns will accelerate the number and size of these opportunities for investors who understand the
relationships among these factors.
These weather patterns are also revealing potential reliability risks to the current grid. To the outside
observer, the grid performed adequately during the polar vortex. But a more detailed look shows that grid
reliability is a growing problem in many areas. Resource levels and mix, market structure and seasonal
resource participation are creating inadvertent consequences that may undermine grid reliability. The
shortages highlight the need for a forensic review of the regulatory structures to ensure reliable power
grids and appropriate price signals and the potential need for new reliability-driven investments.
Power Pricing on January 3, 6, and 7
Daily average power prices fluctuated wildly from $40/MWh to nearly $800/MWh over this period. Prices
spiked on January 6 in ERCOT and on January 7 in most other markets in the US. Natural gas prices ranged
from $4/MMBtu to $40/MMBtu (Figures 1 and 2).
Figure 1. Percent Increase on Day Prior–Day-Ahead, Real-Time, and Gas Pricing; January 6 and 7.
1400%
Day-Ahead Energy
% Increase on previous day
1200%
Real-Time Energy
1000%
800%
600%
Daily Gas
Power price increases driven
by gas spike in New York,
ISO-NE and PJM
Power price increases driven
by other factors, such as
shortages in ERCOT
400%
200%
0%
NYISO - New
York City
ISONE - Mass
Hub
PJM - Eastern
Hub
MISO - Illinois
Hub
ERCOT Houston
CAISO - NP-15
Source: SNL, ISO data
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2. Figure 2. Daily Real-Time, Day-Ahead Power Prices ($/MWh), and Natural Gas Pricing ($/MMBtu).
NYSIC—New York City
©2014 ICF International, Inc.
All Rights Reserved.
Any views or opinions expressed
in this paper are solely those of
the author(s) and do not
necessarily represent those of ICF
International. This White Paper is
provided for informational
purposes only and the contents
are subject to change without
notice. No contractual obligations
are formed directly or indirectly
by this document. ICF MAKES NO
WARRANTIES, EXPRESS, IMPLIED, OR
STATUTORY, AS TO THE INFORMATION
IN THIS DOCUMENT.
No part of this document may be
reproduced or transmitted in any
form, or by any means
(electronic, mechanical, or
otherwise), for any purpose
without prior written permission.
ISONE—Mass Hub
MISO—Illinois Hub
Power
Power
Gas
Power
Power
Gas
Power
Power
Gas
RealTime
DayAhead
Iroquois
Zone 2
RealTime
DayAhead
Algon
Gates
RealTime
DayAhead
Chicago
Friday Jan 3
259
179
36
192
222
28
45
34
5
Monday Jan 6
104
121
12
133
143
16
94
49
13
Tuesday Jan 7
419
204
39
248
215
38
219
68
7
Day
PJM—Eastern Hub
ERCOT—Houston
CAISO—NP-15
About ICF International
Since 1969, ICF International
(NASDAQ:ICFI) has been serving
government at all levels, major
corporations, and multilateral
institutions. With more than 60
offices and more than 4,500
employees worldwide, we bring
deep domain expertise, problemsolving capabilities, and a resultsdriven approach to deliver
strategic value across the lifecycle
of client programs.
At ICF, we partner with clients to
conceive and implement solutions
and services that protect and
improve the quality of life,
providing lasting answers to
society’s most challenging
management, technology, and
policy issues. As a company and
individually, we live this mission,
as evidenced by our commitment
to sustainability and carbon
neutrality, contribution to the
global community, and
dedication to employee growth.
2
Power
Gas
Power
Power
Gas
Power
Power
Gas
RealTime
DayAhead
Transco
Zone 6
Non-NY
RealTime
DayAhead
Houston
Ship
Channel
RealTime
DayAhead
PG&E
Gate
Friday Jan 3
197
106
17
27
34
4
42
43
5
Monday Jan 6
ICF and ICF INTERNATIONAL are
registered trademarks of ICF
International and/or its affiliates.
Other names may be trademarks
of their respective owners.
Power
193
108
12
341
47
4
51
49
5
Tuesday Jan 7
761
317
40
35
48
5
47
49
5
Day
Source: SNL, ISO data
Natural Gas Prices Spike on Demand, Pipeline Constraints
Natural gas prices in New England and eastern New York reached record highs on January 7, with midpoint
prices ranging from $35 to $40 per MMBtu and bids as high as $100 per MMBtu. While there are
unconfirmed reports of some wellhead freeze-off in the Marcellus area and the Texas Eastern
Transmission compressor station in Pennsylvania was out of service for a portion of the day, there appear
to have been no major gas supply disruptions during the cold snap; in other words, the high prices at New
England and eastern New York hubs were due to high demand and pipeline constraints, not an
interruption of upstream gas supplies.
In many markets, the increase in delivered natural gas prices was a key contributor to the increase in
power prices. The principal exception to this appears to be ERCOT, where gas prices did not increase while
power prices increased dramatically (Figures 1 and 3).
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3. Figure 3. Daily Day-Ahead vs. Daily Real-Time Energy Prices; January 6 and 7.
1,000
Nominal $/MWh
800
50
40
600
30
400
20
200
Nominal $/MMBtu
Daily Day-Ahead
Energy
Daily Real-Time
Energy
Daily Gas Price
10
0
0
NYISO - New ISONE MISO PJM York City Mass Hub Illinois Hub Eastern Hub
ERCOT Houston
CAISO - NP15
Source: SNL, ISO data
Generation Supply and Power Demand
The highest prices in the US occurred in the ERCOT region. This market has had low reserve margins
relative to other markets and concerns about resource adequacy since 2011.
Generally, many ISOs experienced high levels of forced outages on January 6 and 7 (Figure 4).
Additionally, winter peak demand hit records or near-records in all eastern ISOs. Many ISOs were
forced to issue emergency alerts and call reserves or reduce voltage. This raises the question as to
whether the system operated reasonably well under extreme circumstances, or alternatively,
whether changes in the resource mix with coal retirements, increased reliance on natural gas,
increased reliance on summer-only resources (notably demand resources, but also increasingly
generation), and increased penetration of intermittent supply, combined with market structure
changes, may be inadvertently compromising grid reliability and/or resulting in very high prices that
might be avoided. We believe this question can be answered only with detailed forensic evaluation
and this activity should be undertaken in the near-term.
Figure 4. Shortage Event Causes and Timeline by ISO.
ISO
Shortage Event Cause
Loss of 3,700 MW due to forced outages
ERCOT
PJM
13,000 MW of planned outages
Record winter peak demand
Loss of 36,600 MW due to forced outages
Record winter peak demand
Beaver Valley 1 Nuke went down Jan 6
Record winter peak demand
MISO
NYISO
ISO-NE
Possible record winter demand
Indian Point 3 Nuke went down Jan 6
High winter demand (not record)
Timeline
Jan 6 6:52 am: Energy Emergency Alert (EEA) Level 1
(call reserves)
Jan 6 7:01 am: EEA Level 2 (risk of outages)
Jan 6 9:23 am: Back to normal conditions
Jan 6 6:30 pm: EEA level 1 (call reserves)
Jan 6 7:50-8:50 pm: EEA level 2 (voltage reduction)
Jan 8: EEA level 1 canceled
Jan 4 10 pm: Cold weather alert
Jan 7 7:15 am: Max Gen Alert
Jan 7 7:30 am: Max Gen Warning (next step EEA Level 1)
Jan 7 11:15 am: Drop from Max Gen Warning to Alert
Jan 7 10 pm: Back to normal conditions
Jan 7 4 pm: Activate voluntary demand resources
Jan 7 10 pm: Back to normal conditions
No shortage events recorded
Source: SNL, ISO reports.
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4. Price Spike Levels Dictated by Market Structure
The electricity price caps in the US vary depending on the RTO and the regulator. The highest $/MWh
prices occurred in ERCOT, which is regulated by the Texas PUCT and not FERC with respect to price
caps (Figure 5). ERCOT has a $5,000/MWh price cap, the highest established thus far in North
America. This cap will increase to $9,000/MWh by 2015. In contrast, the price cap in PJM, the
nation’s largest RTO, is $1,800/MWh (excluding congestion). Thus, it is not surprising that during
shortages of generation capacity—e.g., periods when insufficient operating reserves were
available—prices would be higher in ERCOT than PJM. The differences in price caps relate to
difference in market structure: ERCOT does not have a capacity market while PJM does.
Figure 5. Daily Day-Ahead, Daily Real-Time, and Max Real-Time Energy Prices; January 6 and 7.
6,000
ERCOT Price Cap:
$5,000/MWh
Daily Day-Ahead Energy
5,000
Daily Real-Time Energy
Max Real-Time
Nominal $/MWh
4,000
3,000
PJM Price Cap:
$1,800/MWh
2,000
1,000
0
NYISO - New
York City
ISONE - Mass
Hub
MISO - Illinois
Hub
PJM - Eastern ERCOT - Houston CAISO - NP-15
Hub
Source: SNL, ISO data
Predictability of the Problems
ICF in its recent report*, and others have identified ISO NE as having insufficient gas delivery capacity
to avoid high prices for gas, and hence power, especially during colder than normal weather
conditions. Hence, ISO-NE’s price explosion was the most predictable in the country and ICF has
worked with commercial clients to anticipate and structure business activities around this
opportunity. Indeed, for the winter season, ISO-NE delivered gas prices have been high on many
occasions, even before this most recent cold snap.
*http://www.iso-ne.com/committees/comm_wkgrps/prtcpnts_comm/pac/mtrls/2013/dec182013/a3_icf_phase_2_gas_study_presentation.pdf
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5. Substitutability of Demand Response (DR—also referred to as contracted
Interruptible Load) and Generation
PJM has a very large reliance on interruptible load—it represents more than half of the expected
reserves in some periods, with the remainder being physical generation supply. PJM also contracts
resources for the summer season only; this arrangement is especially prevalent for DR (most PJM DR
is contracted for summer only), but generation is increasingly attempting to have a comparable
arrangement. PJM reported significant problems maintaining system security during the evening of
January 6 (in addition to having high prices) and indicated that it interrupted load with interruptible
contracts. The performance of this interruptible load in comparison to generation will be an
important issue forensic activity. It will also be complex, because it must address not only the
performance of the DR that was called, but what would have happened if PJM had contracted with
generation instead of DR to begin with. In contrast, ISO NE does not rely heavily on interruptible
load. This may be surprising since ISO NE has contracted more demand resources than any other
region in its three year-ahead resource procurement auctions. However, only 27% of contracted
interruptible load was actually in place compared to the initial results of its capacity auctions.
FERC and NERC Treatment of Reliability
NERC, the Electric Reliability Organization (ERO) of the US, has recently adopted new rules for
assessing resource adequacy and required reserve margins. NERC has also worked with FERC and
others on issues related to gas delivery and generation reliability. ICF has been active in these areas
and has demonstrated the importance of fuel supply reliability in addition to generation supply
reliability.
Most reliability activities in the power sector are focused on maintaining grid reliability during the
summer peak. This is because summer peak demand in the US has historically been higher than
winter peak demand. In addition, there has been a trend to rely on summer-only resources.
Reliability during the winter peak is, however, extremely critical in order to maintain home heating
and public health and safety. This, combined with the recent cold snap, should lead to a review of
the robustness of reliability rules in light of the actual experience of the winter of 2014.
ICF International will continue to monitor the developments of the polar vortex and its effects on
energy markets and will provide incremental updates in the future.
For questions, please contact:
Judah Rose  +1.703.934.3342  judah.rose@icfi.com
Shanthi Muthiah  +1.703.934.3881  shanthi.muthiah@icfi.com
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6. About the Authors
Judah L. Rose joined ICF in 1982 and has over 30 years of experience in the energy industry. Mr. Rose’s
clients include electric utilities, financial institutions, law firms, government agencies, fuel companies,
and Independent Power Producers (IPP). Mr. Rose is one of ICF’s Distinguished Consultants, an
honorary title given to three of ICF’s 4,500 employees, and has served on the Board of Directors of ICF
International as the Management Shareholder Representative. Mr. Rose has supported the
development, acquisition, and financing of tens of billion dollars of new and existing power plants and
is a trusted counselor to the utility, IPP, and financial community. Mr. Rose frequently provides expert
testimony and litigation support. Mr. Rose has testified as an expert in scores of state and other legal
proceedings including in nearly 25 states, federal and international jurisdictions. Mr. Rose has also
addressed approximately 100 major energy conferences, authored numerous articles published in
Public Utilities Fortnightly, the Electricity Journal, Project Finance International, and written numerous
company studies. Mr. Rose received an M.P.P. from the John F. Kennedy School of Government,
Harvard University, and an S.B. in Economics from the Massachusetts Institute of Technology.
Shanthi Muthiah joined ICF International in 1995 and directs the Power team within the Energy
Advisory Solutions practice. Her power industry experience has spanned regional markets in North
America, Europe, Australia, Asia, and the Caribbean. Transactional experience includes acquisition
support for potential bidders (largely private equity and IPPs) and sellers of generation assets and
portfolios; energy markets advisor for the Dynegy and Calpine Unsecured Creditor Committees and
NRG Energy in the bankruptcy and restructuring processes; financing and development due diligence
support for various IPP and utilities including for gas, coal, hydro and wind projects and portfolios;
litigation and regulatory support to utilities; and advisor to power companies in contracting and asset
optimization for new or existing power plants.
Frank Brock has more than 17 years of experience in energy economics and modeling. His areas of
expertise include the analysis and modeling of natural gas end-use demand, natural gas use for
electric power generation, and renewable energy and energy efficiency technologies. At ICF
International, Mr. Brock has participated in dozens of studies for both public and private sector clients
on such topics such the valuation of energy infrastructure assets, the impacts of environmental
policies on energy markets, and long-term trends in energy demand.
John Karp joined ICF International’s Wholesale Power team in 2007. With over 6 years of experience,
John has helped provide power market valuations, cash-flow forecasts and energy market forward
price curves for many different types of clients, such as independent power producers, investment
firms, utilities and state, federal and local governments and regulators. Mr. Karp has significant
experience using ICF’s proprietary energy model, IPM, to deliver long-term energy price forecasts and
power portfolio valuations. Mr. Karp received a BS and MS in Systems Engineering and Operations
Research from the George Washington University.
Trishagni Sakya is a Research Assistant in ICF’s Energy Advisory Solutions practice for the Wholesale
Power Markets team. She has expertise in power price forecasting, plant valuations and power
market analysis. Trishagni uses ICF’s proprietary energy models, IPM and SRAM for detailed price
forecasts and analysis. Prior to working at ICF, Trishagni attended the Smith College and earned a B.A.
in Economics and Mathematics
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