The road not taken - JP Morgan Asset Management

Transcription

INVESTMENT
INSIGHTS
The road not taken
Pitfalls and opportunities in infrastructure investing
FOR INSTITUTIONAL/WHOLESALE OR PROFESSIONAL CLIENT USE ONLY | NOT FOR RETAIL DISTRIBUTION
M I C H A EL C EM B A L E S T
Chairman of Market and Investment Strategy
J.P. Morgan Asset Management
Michael Cembalest is Chairman of Market and Investment Strategy for J.P. Morgan Asset
Management, a global leader in investment management and private banking, with $1.6 trillion
of client assets under management worldwide (as of December 31, 2013). He is responsible for
leading the strategic market and investment insights across the firm’s Institutional, Funds and
Private Banking businesses.
Mr. Cembalest is also a member of the J.P. Morgan Asset Management Investment Committee
and a member of the Investment Committee for the J.P. Morgan Retirement Plan for the firm’s
more than 250,000 employees.
Mr. Cembalest was most recently Chief Investment Officer for the firm’s Global Private Bank, a
role he held for eight years. He was previously head of a fixed income division of Investment
Management, with responsibility for high grade, high yield, emerging markets and municipal bonds.
Before joining Asset Management, Mr. Cembalest served as head strategist for Emerging
Markets Fixed Income at J.P. Morgan Securities. Mr. Cembalest joined J.P. Morgan in 1987 as a
member of the firm’s Corporate Finance division.
Mr. Cembalest earned an M.A. from the Columbia School of International and Public Affairs in
1986 and a B.A. from Tufts University in 1984.
FOREWORD
O u r I n v e s t m e n t I n s i g h t s s e r i e s f o c u s e s on the building
blocks of managing money. Some of our reports deal with the way we construct
portfolios, while others address opportunities we see in the various countries
and markets that we invest in. From time to time, we also look at the asset
management industry and the value it can provide for institutional investors.
In this paper, we focus on the next phase in the maturation of infrastructure investing.
The need for private capital to finance essential investments in transportation, energy,
telecommunications and services is critical. Institutional investors find infrastructure’s
stable long-term yields, diversification and inflation protection benefits attractive, but
want to avoid the pitfalls encountered in its initial phase. We review the missteps of past
infrastructure projects and show how they can be used to inform a set of guiding
principles we view as essential to successfully navigating the road ahead.
We hope that the research and insights presented here will help you to anticipate and
realize the investment opportunities available in the next phase of infrastructure investing.
ABOUT
J.P. MORGAN
GLOBAL INSTITUTIONAL
ASSET MANAGEMENT
J.P. Morgan Global Institutional Asset Management is a global leader in investment
management, dedicated to creating a strategic advantage for institutions by connecting clients
with J.P. Morgan professionals. With roughly 800 investors on the ground in more than 30
countries, the firm seeks to deliver first-class investment results to some of the world’s most
sophisticated organizations, including corporate pension plans, endowments, foundations,
insurance companies, sovereign wealth funds and government-affiliated institutions.
J.P. Morgan Global Institutional is distinguished by its capital markets knowledge, global
investment expertise and the long-term, proactive partnerships it establishes with clients.
Our innovative strategies span equity, fixed income, real estate, private equity, hedge funds,
infrastructure and asset allocation. J.P. Morgan Global Institutional is part of J.P. Morgan Asset
Management, which has assets under supervision of $2.3 trillion and assets under management
of $1.6 trillion (as of December 31, 2013).
TABLE OF CONTENTS
1
Executive summary
5
Infrastructure pitfalls, past and present
14
Designing an infrastructure investment
strategy for the long run—guiding principles
16
Opportunities: Principles in practice
20
Appendices
I: Infrastructure performance from Preqin
II: Infrastructure performance from the Center
for Private Equity Research
III: Natural gas peaker plants and the
dispatch curve
IV: The problem with accreting swaps applied
to infrastructure projects
24
Sources
E X E C U T I V E
S U M M A R Y
The road not taken:
Pitfalls and opportunities in
infrastructure investing
Infrastructure grabs a lot of headlines. In preparation for this
year’s G20 meetings, participants cited a 2013 report from
McKinsey1 that referred to $57 trillion of infrastructure investment needed globally by 2030. Given the state of sovereign
finances, public entities face challenges financing this on their
own. Funding mechanisms such as gas tax revenues help,
but are typically insufficient. As a result, governments have
increased their reliance on private investment to build
infrastructure assets.
their potential for long-term stable cash flows, diversification
and inflation protection. However, as the historical dispersion
of returns among projects and managers suggests, investment
selection must be based on more than just the societal need
for a given project and a government willing to sponsor its
partial or complete privatization. While there’s a clear link
among infrastructure investing, rising GDP and employment
growth, what matters to investors are adequate protections
and sufficient returns on capital.
The asset class has a lot to offer institutional investors.2 We
review returns on infrastructure investing in Appendices I and II;
both show attractive returns, particularly for the best-performing projects and managers. However, the return dispersion
among projects and managers is extremely wide (according to
one analysis, wider than on venture capital and private equity).
What’s the best approach? Infrastructure investing requires
an acute understanding of the political process, the business
cycle, natural resource risks and very localized competitive
dynamics. In this paper, we review some of the recent pitfalls
that infrastructure investors have faced and how these experiences can be used to develop guiding principles that work
over the long run to help ensure that institutional investors’
objectives are met. We apply these principles to selected
infrastructure sectors to illustrate the role they play in evaluating potential investment opportunities. This approach may
end up deviating from many commonly used strategies. As
such, it is often the road not taken, but we believe it is the
right one.
Infrastructure is still a relatively recent addition to institutional
portfolios. Current allocations among U.S. pension funds, for
example, are roughly 1%–2% but expected to grow to 5% or
more in the coming years (see sidebar on page 4). In our view,
attractive core and core-plus infrastructure investment opportunities are available to institutional investors interested in
1
2
Infrastructure Productivity: How to Save $1 Trillion a Year (McKinsey Global
Institute, January 2013).
Institutional investors can access infrastructure through separately managed
accounts and through listed funds. There are 30 to 40 listed vehicles
globally, a number that has been roughly constant since 2007 (see 2014
Preqin Global Infrastructure Report [Prequin, January 2014]).
J.P. MORGAN ASSE T MA N AG E ME N T
1
EXECUTIVE SUMMARY
Designing an infrastructure investment
strategy for the long run—guiding principles
Our broad review of pitfalls experienced in infrastructure projects over the past decade (detailed on pages 5–13) informs our
list of investment principles for institutions seeking core/coreplus infrastructure exposure (see pages 14–15). To summarize,
we believe investors should assess the extent to which the
funds that they invest in adhere to the following principles:
• Generally confine investment to established assets supplying
essential services, with clear visibility around user demand.
• Avoid excessive leverage and financial engineering.
• Investments in markets, regulatory environments and
jurisdictions without track records of private investment need
to be priced correctly to account for the additional risk.
• Fund managers should concentrate on areas where they
bring a deep knowledge of industry dynamics as well as the
region’s political, economic and competitive complexities.
• Establish control positions to ensure that the fund
manager’s intended strategy for the asset is implemented.
• Negotiate agreements that foster a sharing of investment
risks among stakeholders and ensure adequate compensation for bearing those risks.
• Provide diversified opportunities across region, vintage year
and infrastructure type while being cautious of investments
in market sectors where current popularity can lead to
overpricing of infrastructure assets.
2
Opportunities: Principles in practice
To illustrate the approach, we review these basic principles
and a few select observations on potential opportunities
(discussed at greater length on pages 16–19):
Transportation projects have often suffered from rose-colored
estimates of traffic volumes, reliance on the completion of
subsequent development initiatives or the use of excessive
leverage. There may, however, be select opportunities in new
projects and in the unwinding of prior ones that are now distressed. To take advantage of these opportunities while
addressing some of the pitfalls of the past, our teams are
working on a new approach, which seeks to foster greater
alignment of interests and a sharing of risks among operators,
investors and state and local governments.
We see substantial capital needs in the North American power
sector and the broader energy value chain as the shale gas
story continues to evolve. Evaluation of investment opportunities in midstream pipelines (to deliver natural gas from exploration and production [E&P] sites to regional distributors)
requires a thorough understanding of end-user demand for
natural gas. Negotiating long-term contracts that entail a
return on invested capital can help to mitigate some of the
risks involved with varying decline rates and production costs.
We expect to see continued robust shale gas production,
which is likely to sustain the cost advantage of natural gas,
support demand growth and offer opportunities in natural gas
transmission assets (for delivery of natural gas from treatment
plants to homes and businesses). Rising asset valuations,
however, offer a cautious note. As a result, our understanding
of competitive and relative cost dynamics suggests that
investment in existing local distribution company platforms
may be the preferred investment option.
T H E R O A D N OT T A K EN: PITF AL L S AND O PPO RTUNITIES IN I N FRAST RUCT URE I N VE STI N G
EXECUTIVE SUMMARY
The need for private capital
Infrastructure investing, relative to other real asset categories,
such as real estate, is clearly still maturing and has its own
set of challenges, given its ties to the public sector. However,
the public need for private capital has never been greater
(Exhibits 1 and 2), and the public sector will need to find ways
of compensating private investors. With the right approach,
institutional investors can potentially benefit from investments
with long-term, stable cash flows that are tied to economic
growth, increasing energy demand and continued increases
in urbanization.
...but the public sector may have trouble financing it on its own
EXHIBIT 1: ACTUAL VS. REQUIRED INFRASTRUCTURE SPENDING
EXHIBIT 2: OECD GOVT. NET DEBT, % OF GDP, INCL. STATE AND LOCAL
60
80
50
70
40
60
30
Percent
USD trillions
The world needs a lot more infrastructure spending...
20
40
30
10
0
50
20
Actual infrastructure spending
1996–2013
Source: McKinsey; data as of January 2013.
Required infrastructure spending
2013–2030
10
1969 1973
1977
1981 1985 1989 1993 1997 2001 2005 2009 2013
Source: OECD; data as of year-end 2013.
3
EXECUTIVE SUMMARY
A Q U IC K S N A PSHOT OF I NFRASTR UCTURE INV ESTING
INFRASTRUCTURE IS A CATCHALL TERM THAT REFERS TO A WIDE VARIETY OF FIXED ASSETS USED IN TRANSPORTATION,
ENERGY, TELECOMMUNICATIONS AND SERVICES
Many institutions are interested in infrastructure due to its
diversification benefits, potential for inflation protection and stable long-term yields. Project revenues are derived from a variety
of tolling arrangements, regulated utility models and long-term
contracts for power plants. Despite these benefits, the transition
to a world of greater private ownership has been a gradual one.
To date, Europe has taken the lead, with countries like the UK and
Portugal financing 20%–30% of infrastructure through publicprivate partnerships (PPPs). In the U.S., this approach has been
less widely used, in part due to the heavy historical reliance on
the municipal bond market to finance infrastructure (in which
case taxpayers retain the risks and rewards of ownership); PPPs
in the U.S. have been growing but from low levels.* From 2010
to 2013, private infrastructure funds around the world invested
$30 billion–$40 billion of equity per year, with aggregate deal
values of $200 billion to $300 billion. They have recovered since
the recession but are not markedly above pre-recession levels.
Current pension fund infrastructure allocations are 1%–2%, with
around two-thirds of plans below their long-term targets. Preqin
surveys indicate that many of the underweight pension plans
intend to increase allocations. In addition, Bain & Co. believes
that while the majority of institutional investors allocate less than
5% to infrastructure today, they will allocate 5% or more in the
coming years.
ESTIMATED AGGREGATE VALUE OF INFRASTRUCTURE DEALS
COMPLETED GLOBALLY BY PRIVATE FUNDS
BREAKDOWN OF INFRASTRUCTURE DEALS BY REGION
INFRASTRUCTURE OVERVIEW
Sector
Regulated assets
Transportation
Subsectors
Water and wastewater, electricity transmission, natural gas and power distribution
Toll roads, airports, seaports, rail, parking
Power generation
Conventional (coal, natural gas), renewable
Midstream
Pipelines, storage, gathering/processing
Communications
Cell towers, cable networks, satellite systems
Social infrastructure Hospitals, schools, courts/prisons
Source: J.P. Morgan.
100
300
Lat Am
80
70
200
Percent
USD billions
250
150
100
Australasia
60
50
Asia
40
30
N. America
20
50
0
Other
90
Europe
10
2007
2008
2009
2010
2011
2012
Source: Preqin Infrastructure Group; data as of year-end 2013.
2013
0
2008
2009
2010
2011
2012
2013
* Public-Private Partnerships to Revamp U.S. Infrastructure (The Hamilton
Project, February 2011).
4
T H E R OA D N OT T A K EN: PITF AL L S AND O PPO RTUNITIES IN I N FRAST RUCT URE I N VE STI N G
Infrastructure pitfalls, past
and present
Owning fixed assets with a regulated rate of return set by local
and federal governments seems like a straightforward exercise
in capital deployment, and it is tempting to compare it to
investments in office buildings, retail malls, warehouses and
hotels. However, unlike real estate assets, which exist mostly
in the domain of the private sector, there is often substantial
public sector involvement in the permitting, rate setting,
ownership and oversight of infrastructure assets. That’s what
makes them different and why an investment approach cannot
simply be based on concepts like cap rates, usage volumes
and occupancy levels.
Sometimes investment strategies are best defined by the parameters of what not to do and what to avoid. With that in mind,
we review some challenges that prior infrastructure projects
faced.3 After doing so, we lay out some of our guiding principles
regarding institutional investment in infrastructure assets.
One thing to keep in mind as you read through these case
studies is that they are a mix of cash flow-based investments
related to existing assets and “greenfield” development projects
whose ultimate demand patterns were unknown at purchase.
They are also a mix of projects with stable cash flows and morevolatile ones, with the latter related to merchant energy and
greenfield transportation. These kinds of projects are often
referred to as “core” assets but sometimes turn out to be “noncore” due to mispriced risk, poorly understood market demand
and excessive leverage. Institutions seeking core infrastructure
exposure need to ensure that the funds they invest in are
confined to established assets supplying essential services, with
clear visibility around user demand and appropriate leverage.
These core assets typically exhibit low usage volatility, economic
insensitivity and inflation-protection characteristics.
Pitfall #1: Rose-colored transportation forecasts and the
unknown price of convenience
Pitfall #2:Project success too dependent on subsequent
development initiatives
Pitfall #3:Price swings, supply shocks, contract terms and
regulatory issues affecting energy
Pitfall #4:Too much financial engineering and/or leverage
Pitfall #5:Overly optimistic renewable energy projections
(using wind as an example)
Please see Sources (pages 24–25) for references related to the projects
discussed in this section.
3
5
INFRASTRUCTURE PITFALLS, PAST AND PRESENT
Toll road economics are often based on the notion that drivers
will pay for convenience: a toll in exchange for a faster route
and less gas usage. In a world full of data (credit card and
mortgage prepayments and defaults, customer buying preferences, insurance policy mortality), you might think this is easy
to calibrate. Unfortunately, it hasn’t been. Exhibit 3 shows the
distribution of actual traffic volumes across different countries, measured as a percentage of the original traffic forecast.
Even in countries with prior toll road experiences, the average
is well below 100%.
Exhibit 4 looks at revenues for U.S. toll roads, also as a
percentage of the original forecast; the results are just as
grim. This is not unique to the U.S.: A 2010 study of 14
Australian toll roads found that traffic volumes in the first year
of operation averaged only 55% of the forecast level.4
Performance of U.S. toll roads opened in 1986-2004
EXHIBIT 4: ACTUAL REVENUE AS A PERCENTAGE OF PROJECTED
RESULTS FROM OPERATIONS
160
140
120
Percent
Pitfall #1: Rose-colored transportation
forecasts and the unknown price of
convenience
A measure of rose-colored infrastructure investing
0
81%
Percent
0.4
Year 1
Year 2
Year 3
Year 4
Year 5
Source: National Cooperative Highway Research Program (NCHRP); data as
of 2006.
Countries with
prior toll roads
0.2
60
20
Countries without
prior toll roads
0.0
80
40
EXHIBIT 3: ACTUAL TRAFFIC VOLUMES AS A % OF INITIAL FORECAST
58%
100
0.6
0.8
1.0
Actual/forecast traffic
1.2
1.4
1.6
Note: In each of the five years, each dot represents a different project.
On the following page, we look briefly at three toll road
projects, and at what went wrong.
Source: Robert Bain, Error and Optimism Bias in Toll Road Traffic Forecasts
(University of Leeds, 2009).
ES TI M A T I N G THE VAL U E OF TI ME ( V oT)
Macro-level models of toll road demand are popular because of
their low cost and easy implementation. They typically estimate
the number of vehicle trips based on economic activity, land
use patterns and demographics, and then map each trip to a
mode of transportation and route. However, such models are
primarily designed to forecast traffic volumes on a regional
level rather than for specific roads and have poorly judged the
price points at which drivers have been willing to pay more to
save time/fuel. Micro-level models have gained traction in the
academic community and in practice; time will tell if they are
able to improve traffic forecasting accuracy. These micro-level
models attempt to better capture the value of time (VoT), which
is the value drivers assign to their travel time. Macro-level models
segment the population by income and assign each bracket a
VoT. In contrast, micro-level models argue that VoT varies within
income brackets and even on an intrapersonal level, depending
on the purpose of the trip and time of day. The central principle:
Travel demand is derived from activity demand (e.g., why you are
going from place A to place B). Using this framework, forecasters
conduct household-level analysis (mail-in surveys, studies of GPS/
smartphone activity) and create population-wide distributions to
estimate overall toll road demand.
4
6
David Hensher (University of Sydney) and Zheng Li (University of Sydney).
Toll Roads in Australia: An Overview of Characteristics and Accuracy of
Demand Forecasts (NCHRP Synthesis Report, 2010).
SH-130 Highway, Austin, Texas
In 2007, a 50-year concession was signed by investors to
design, build, finance and operate a 41-mile section of the
SH-130 bypass around Austin. It was built in response to
increasing truck traffic entering Texas from Mexico as well as
congestion on alternate routes; the project was noted for
having some of the highest speed limits in the country at
80–85 mph. However, traffic volumes have fallen short: The
road is often not the fastest route, it runs through undeveloped
areas, and motorists reportedly find the tolls excessive ($8 for
cars and $29 for commercial trucks) compared with free
65-mph alternatives. In October 2013, Moody’s downgraded the
project’s debt to Caa3 due to “substantially weaker than
forecasted traffic and revenue performance” and “a slowgrowth profile rather than a steep ramp-up as would have
been expected.” The Wall Street Journal reported that the
project’s owners have hired restructuring lawyers.
Summary: Poor underwriting of driver cost/time/
speed preferences.
M6 Toll, Birmingham, UK
The M6 Toll is Britain’s first tolled highway, completed in 2003.
A greenfield project with a 50-year concession, the tollway was
designed to alleviate congestion on the busiest section of the
free-to-use M6 motorway around Birmingham—and link London
more easily to northern industrial centers and Scotland
(Exhibit 5). While the original forecast for the M6 Toll called for
72,000 vehicles per day, traffic volumes peaked at only 55,000
vehicles per day in 2006 and have at times fallen as low as
25,000 (35% of the initial forecast). The reason: Many drivers
are opting to use the free M6 motorway, which is operating at
2x capacity. This has resulted in suggestions that the toll road
should be nationalized and the toll revoked to alleviate congestion on the free M6 motorway. The toll road’s finances are
struggling: Its debt to cash-flow multiple of 26x compares with
3x to 7x for global toll road portfolios. In November 2013, the
EXHIBIT 5: M6 TOLL, BIRMINGHAM, UK
to Edinburgh
M6 Toll
M6 free motorway
M6 Toll
M42
M6
free motorway
M5
Birmingham
to London
Source: J.P. Morgan. For illustrative purposes only.
owners sought to restructure with creditors. Note: The debt
multiple includes the impact of an accreting interest rate swap,
which is now out of the money and effectively adds debt to the
project (see Appendix IV for more details).
Summary: Misjudgment of driver preferences for speed
and convenience.
Cross City Tunnel, Sydney, Australia
The Cross City Tunnel opened in 2006 and averaged 30,000
vehicles per day in 2007, a third of the 89,000 projected when
the deal was financed. Forecasts were based on overly
optimistic assumptions about traffic growth and drivers’
attitudes toward toll roads. The original forecasts appear to
have disregarded the project’s engineers, who capped the
tunnel’s maximum traffic capacity at 50,000 to 70,000.
Despite this apparently finite cap, the project’s consultants
projected 100,000 vehicles per day for 2016 and 200,000 for
2034. Why were they wrong? Consultants apparently misjudged the number of feeder routes into the tunnel. The
project defaulted within 16 months of opening and defaulted
again in 2013.
Summary: Consultants should never override engineers.
7
Pitfall #2: Project success too dependent on
subsequent development projects
Sometimes infrastructure projects rely on the completion
of other, related public or private sector assets. If they are
not completed on time, the value of the infrastructure
project is at risk.
Northwest Parkway, Denver, Colorado
South Bay Expressway, San Diego, California
The project: a 10-mile express toll road in Southern California,
designed to facilitate travel between San Diego and the
Mexican border (Exhibit 7). Built as part of a public-private
partnership, the expressway took 13 months longer than
anticipated and was completed in 2007. Projected 2009 traffic
EXHIBIT 7: SOUTH BAY EXPRESSWAY, SAN DIEGO, CALIFORNIA
In 2007, local authorities signed a $603 million, 99-year concession agreement to operate the nine-mile piece of highway
(Exhibit 6). Part of the $603 million package: $40 million paid
by investors if the remaining part of the beltway was completed
and a further $60 million if it was completed by 2020.
8
125
94
San Diego
5
805
EXHIBIT 6: NORTHWEST PARKWAY, DENVER, COLORADO
75
Pacific Ocean
Northwest Parkway
E
470
36
Denver
International
Airport
25
76
Unbuilt beltway
portion
76
CALIFORNIA
MEXICO
70
70
6
225
E
470
E-470 tollway
25
The deal’s price represented one of the largest multiples of
revenues ever paid for a U.S. toll road (90x 2006 revenues),
reflecting the confidence the buyers had in the eventual completion of the beltway (red dotted line) and increased traffic
on the Northwest Parkway. Despite political assurances that
the beltway would be completed by 2020, recent city council
reports reveal that it is behind schedule and running into
financing and design obstacles; its eventual completion is in
doubt. Current traffic levels on the Northwest Parkway are
only 17% of capacity.
volumes of 60,000 vehicles per day were not met; actual
volumes have ranged from 23,000 to 29,000. The project’s
primary failures appear to be overly optimistic projections
regarding suburban development outside San Diego and an
underestimation of competition from free-to-use roads that
connect to major Mexican traffic arteries. An additional headache: a $40 million litigation with contractors as a result of
construction delay disputes. Citing lower than expected traffic
and toll revenue, the expressway filed for Chapter 11 bankruptcy protection and was eventually purchased at a price
representing a haircut of approximately 30% for the lenders
and a complete write-down of equity.
Summary: There’s a big difference between building
infrastructure linking established commercial and
residential areas and infrastructure reliant on subsequent
development on either end.
Summary: Discount politicians’ assurances regarding things
they cannot control.
8
905
5
270
70
Free-to-use road
South Bay Expressway
54
T H E R OA D N OT T A K EN: PITF AL L S AND O PPO RTUNITIES IN I N FRASTRUCT URE I N VE STI N G
Pitfall #3: Price swings, supply shocks,
contract terms and regulatory issues
affecting energy
Energy investing offers perhaps the most attractive returns in
the infrastructure universe, but it is accompanied by the most
complicated set of regulatory, technology, business cycle and
production risks. The supply shocks resulting from the shale
revolution will reverberate for decades and are changing the
landscape for energy investments. The examples below deal
with coal and natural gas plants used for both baseload and
peaking power; we review the unique risks and opportunities
of owning natural gas peaker plants in Appendix III.
Longview coal power plant, West Virginia
Longview came online in 2011 as one of the last coal plants
built and financed by private investors. The plant sits on a rich
coal mine, an advantage that lowers both fuel and operating
costs. When the project was planned in 2006, coal was much
cheaper per British thermal unit (Btu) than natural gas (see
Exhibits 8 and 9 and box below). This was before the shale
revolution; the U.S. planned on importing natural gas from
Qatar and Russia at the time. Given this backdrop and the perceived strong competitive position of coal, the project’s owners
only secured a five-year contract for 50% of the plant’s capacity.
Then came the shale revolution at Barnett, Marcellus and
Haynesville, which led to the 2009–2011 price collapse in natural gas relative to coal. Add in some plant-specific construction
problems at Longview, and the result was that natural gas
became a preferred alternative for local utilities. Longview
filed for Chapter 11 bankruptcy in August 2013 after not being
able to re-contract the plant.
Summary: Energy supply shocks like the shale gas revolution
reduced the long-standing margin of safety for coal plant
owners across the industry.
The consequences of the shale revolution: the collapse in the price of natural gas relative to coal
6
Operation begins
Planning
4x
3x
2x
3
2004
2006
2008
Source: Bloomberg; data as of February 2014.
As per the EIA, below this line
natural gas is more
cost-efficient than coal
1x
Coal
0
2002
5x
Ratio
9 Natural gas
6x
Bankruptcy filed
USD/MMBtu
12
Operation begins
Planning
15
Bankruptcy filed
EXHIBIT 9: NATURAL GAS/COAL PRICE RATIO*
EXHIBIT 8: U.S. NATURAL GAS AND COAL PRICES
2010
2012
2014
0x
2002
2004
2006
2008
2010
2012
2014
Source: Bloomberg, Energy Information Administration (EIA); data as of
February 2014.
*Both natural gas and coal prices are expressed as USD per million Btu.
P R I C E S P E R BT U U ND ERSTATE TH E COST A DV A NTA G E OF USING NA TUR A L G A S
(V S . C O A L) TO GENERATE EL ECTRICITY
In other words, don’t confuse the price of the fuel’s heat content with the economics of converting it into electricity. Just because coal
and natural gas prices may be equal on a Btu basis, it doesn’t mean that the economics of generating coal-fired electricity are the same
as generating electricity from natural gas, particularly when newer gas plants are involved. Coal plants (and older natural gas plants)
have slower ramp-up rates and other operating drawbacks that translate into lower electricity production efficiency rates. When such
plants burn coal in large boilers to generate steam for steam turbogenerators, their efficiency rates are 35% (for older plants) to 41%
(for the newest plants). However, combined cycle natural gas plants burn natural gas in gas turbines and then use waste gas to power
steam turbogenerators. Their combined efficiency rates are 60% (1.5x better). As a result, the EIA cites a 1.5x ratio of natural gas to coal
prices as the rate at which the economics of electricity generation are similar.
9
Panda Energy, Texas
In 2010, a private company secured financing to construct three
natural gas-fired combined cycle power plants at a projected
cost of approximately $1,000 per kilowatt (kW), for completion
in 2014. These costs appear notably higher than what the
company could have paid for existing capacity (Exhibit 10).
It could be the case that the company was forecasting higher
electricity prices in Texas based on growing demand and a
declining reserve margin in the Electric Reliability Council of
Texas (ERCOT), as well as the closure and retirement of coal
plants. Another possibility is that the company believed that
ERCOT would shift from “production pricing” (plants only get
paid for actual energy produced) to “capacity pricing” (plant
owners also get paid for their capacity to produce, which covers
their fixed costs; ERCOT is the only regional power system in
the U.S. without capacity pricing). In regions subject to capacity
pricing, power generators are reimbursed for construction
costs when building new plants but not for premiums paid for
existing ones. As a result, if ERCOT became a capacity market,
plant construction costs could have been more easily reimbursed than acquisition costs of new plants. However, ERCOT
has not abandoned its production pricing approach,5 and the
company will have to compete in merchant power markets with
a very high cost base. In September 2012, S&P expressed
concerns about the project’s high future cash flow volatility in
the absence of stabilizing power purchase agreements or
capacity market payments.
New builds can be much more expensive than buying
existing capacity
EXHIBIT 10: SELECT COMBINED CYCLE NATURAL GAS PLANT
TRANSACTIONS IN TEXAS, 2010–2013
Name of
asset(s)
Panda Energy plant
construction
4/16/2010
Colorado Bend Energy
Center, Quail Run
1,124
365
10/26/2010
Oyster Creek Unit VIII
430
100
233
10/27/2010
Freestone Energy
Center
257
215
836
12/30/2010
Quail Run
573
185
323
1/13/2011
Guadalupe
1,142
351
307
5/12/2011
Wolf Hollow
720
305
424
6/24/2011
Odessa-Ector
1,135
335
295
3/14/2012
Rio Nogales
800
480
600
8/4/2012
Bosque
800
432
540
4/2/2013
Gregory Power
411
244
565
Source: UBS, SEC filings, FactSet, Bloomberg, Sparkspread; data as of
August 2013.
Summary: It’s risky to assume that Texas will become like
the rest of the U.S.; establish convincing evidence of future
regulatory shifts.
5
The likelihood of a switch to capacity pricing in Texas may have gone down,
given statements from ERCOT indicating that it sees the Texas power grid as
having a comfortable margin of supply for the next few years (i.e., no need
to reserve capacity).
10
Deal size
Capacity
(USD
(megawatts) millions)
1,800
1,800
Date
announced
2010
USD/
kW
1,000
325
Regional differences in natural gas prices can create substantial
basis risk for hedgers
Swap agreement entered
35
30
USD/MMBtu
25
20
15
New England nat gas
(actual gas purchase price)
Mid-Atlantic nat gas
(reference gas price)
Swap unwound
EXHIBIT 11: REGIONAL DIFFERENCES IN NATURAL GAS PRICES
In April 2008, investors acquired a portfolio of natural gas power
plants. The region where the plants are located (Western U.S.)
operates on a long-term bilateral contract basis in which power
plants with such contracts receive both fixed payments on their
capacity and the right to sell their megawatt hours (MWh) of
electricity to the grid at the prevailing spot price. As a result,
non-contract holders are subordinated in the queue when selling
MWh. The buyers’ average portfolio contract life was 6.8 years,
around three-quarters of which expired in 2012–2013. The
owners anticipated stable electricity demand from surrounding
areas and environmental pressure leading to accelerated coal
plant retirements, both of which would presumably result in their
contracts being extended. Coal plants went offline as expected,
but electricity demand fell sharply due to the recession and
remained weak (Exhibit 12). When the bilateral contracts
expired, they were not renewed, and the owners suffered on two
fronts: Their capacity payments ended, and existing contract
holders supplied all the electricity needed by local utilities.
Following contract expiration, some plants operated on a
merchant basis before being re-contracted, while others
remained uncontracted. As a result, the owners only received
minimal dividends and had to contribute additional equity.
Summary: Given business cycle risks, diversification of
contract lengths in regions subject to bilateral contracts and
queuing is critical.
The risk of contract maturity concentration
EXHIBIT 12: COLORADO ELECTRICITY PRODUCTION: ACTUAL VS.
PROJECTED MEGAWATTS
8,100
Bulk of
contracts
expiry
This makes sense except for one flaw: The natural gas price
that was incorporated into this swap arrangement was
different from the natural gas price the plant actually paid in
its normal operations. The latter was based on prices in New
England for gas the plant actually purchased, while the former
was linked to prices for gas in the Mid-Atlantic region. At the
time this swap arrangement was designed, the two prices had
been moving in tandem. Unfortunately, three years into the
transaction, regional natural gas prices diverged sharply, a
by-product of different regional supply constraints and the
proximity to Marcellus and other shale deposits. Higher natural
gas prices caused a decline in the company’s cash flow from
operations that was not offset by lower swap payments to its
counterparty because the reference gas price did not rise
nearly as much, as shown in Exhibit 11. The portfolio suffered
losses when the buyers unwound the swap at the end of 2013.
Southwest Natural Gas Generation, Western U.S.
Portfolio
acquisition
One large natural gas plant in this regional portfolio was located
in New Hampshire, a region where capacity payments only
extend for one year. As a result, it can be difficult to obtain
financing, given lender concerns around sufficient utilization
of the asset. The buyers decided to improve the cash flow stability of the plant by entering into a complex agreement in
which they received a fixed payment stream and paid out a
volatile one that was based on both electricity prices (their
revenues) and natural gas prices (their input costs). If the payments made by the plant owners are similar to their net cash
flows from operations, they have effectively converted their
business from a volatile one to a more stable one that banks
would finance.
Summary: Power plant valuations can be heavily impacted by
poorly structured hedges subject to basis risk across regions.
7,700
Megawatts
U.S. portfolio of gas and coal power plants, with
hydroelectric plants mixed in
7,300
erv
ic S
do
ora
Col
6,900
bl
Pu
ast
rec
fo
ice
10
6,500
5
0
2009
2010
2011
2012
Source: Bloomberg; data as of February 2014.
2013
2014
6,100
2004
2006
2008
2010
2012
2014
Source: Public Service Company of Colorado; data as of year-end 2012.
J.P. MORGAN ASSE T MAN AG E ME N T
11
Pitfall #4: Too much financial engineering
and/or leverage
The negative impact from an accreting swap
EXHIBIT 14: INDIANA TOLL ROAD ANNUAL DEBT METRICS
A 75-year concession was given to the Indiana Toll Road
Concession Company in 2006. The financing package contained a nine-year, interest-only bullet loan hedged with a
20-year accreting interest rate swap whose rates were preset
at 3% to 11.3% by 2023. As with most accreting swaps, the
owners expected to refinance it before its coupons rose to
high levels. While revenue and operating cash flow improved
substantially from 2006 to 2011 (Exhibit 13) and traffic patterns
were stable, total project debt nearly doubled, from $3.4 billion
at acquisition to $6.0 billion in 2011, a consequence of declining interest rates creating mark-to-market losses on the swap
(see Exhibit 14 and Appendix IV). This prevented an early refinancing from happening, and increased the project’s debt load
and effective interest cost. While debt to cash flow multiples
remained stable, they were elevated at 40x cash flow. The
project’s owners in all likelihood expected to see significant
declines in debt multiples over time as the project’s revenues
grew (debt to cash flow would have been 20x in 2012 if not for
the swap—still high, but more manageable).
Summary: Financial engineers can create more problems
than civil engineers.
EXHIBIT 13: INDIANA TOLL ROAD ANNUAL REVENUE
Ebitda
Ebitda margin
USD millions
180
82
80
160
140
78
120
76
100
74
80
60
2007
2008
2009
2010
2011
2012
72
Source: Statewide Mobility Partners, Macquarie; data as of year-end 2012.
12
Ebitda margin (%)
Total revenues
Swap liability
Debt multiple
60x
6
5
50x
4
3
40x
2
1
0
30x
2006
2007
2008
2009
2010
2011
Source: Statewide Mobility Partners; data as of year-end 2011.
Diversified global marine and rail terminal
operating company
Sometimes infrastructure managers purchase interests in
operating companies and do not just confine portfolios to individual projects. In one instance, a manager acquired a 49%
stake in a diversified company that owns 210 terminal facilities
and rail operations around the world (Exhibit 15). The price
was 20x cash flow (on the high side for a minority stake), and
debt was 13x cash flow. The price reflected the presumed benefits of global revenue diversification. From 2006 to 2012,
there was a 7% annual decline in revenue—weak but not
always catastrophic. In this case, the financing required
increased coupons if debt to cash flow multiples rose, which
resulted in higher costs just when the project could not afford
them. Under new owners, the deal was refinanced more conservatively: shorter-term debt, less leverage and more equity.
Summary: Geographic diversification is great, but
globalization has increased the correlation of country
growth patterns; if highly leveraging global infrastructure
portfolios, do so with caution.
Revenues and gross margins have grown as expected
200
Long-term debt
Debt to cash flow multiple
Indiana Toll Road
7
USD billions
In this section, we review projects whose revenues and operating
cash flows were within the realm of initial expectations but
whose financing structures caused serious problems.
EXHIBIT 15: COMPARISON OF FINANCING APPROACHES
2007
2014
Loan to value
65%–75%
55%–60%
Equity
Cost of financing
25%–35%
L + 130 bps & step-up
based on Ebitda multiple
1.0x–1.1x
40%–45%
L + 220–250
bps
1.4x
Debt coverage ratio
minimum before default
Source: J.P. Morgan.
Pitfall #5: Overly optimistic renewable
energy projections (using wind as
an example)
Wind farm economics are affected by government subsidies,
state requirements for renewable energy production, raw
materials pricing (e.g., rare-earth metals such as neodymium,
used for high-performance magnets), technological improvements vs. operational degradation, ongoing operating and
maintenance expenses, involuntary curtailment6 and the
variability of the wind itself. It can be (and is) done profitably,
but there are risks involved.
Exhibit 16 shows projected and actual capacity factors (actual
generation as a percentage of potential nameplate capacity)
at two locations, in Ohio and New York. This is by no means a
representative sample, and these are far from optimal wind
locations. However, they indicate how wind variability7 and
technological issues can result in less electricity than
consultants originally laid out to investors and utilities.
Instances of overly optimistic wind projections
EXHIBIT 16: PROJECTED VS. ACTUAL WIND CAPACITY FACTORS—
ACTUAL GENERATION AS A % OF POTENTIAL
On wind variability, Exhibit 17 shows the distribution of wind
capacity factors from a U.S. Department of Energy (DoE) study
based on vintage year.8 Operating and maintenance (O&M) costs
can vary as well; according to the DoE, annual project O&Ms
vary from $5 to $20 per MWh.
To be clear, wind has plenty of positive momentum; it represented 40% of all U.S. capacity additions in 2012. GE reportedly
has new turbine technology that can deliver capacity factors as
high as 50%, and more-recent projects are already delivering
capacity factors of 40%–50% in areas with Class 5–7 wind
speeds. The same is true for Danish offshore wind farms, many
of which post capacity factors in the mid-40s. Part of the
improvement is related to increases in rotor diameters and
tower heights, designed to improve productivity. Even without
subsidies, some wind projects generate electricity at levelized
costs that are now competitive with combined cycle natural gas
plants. Nevertheless, one should not assume that the results
generated by a nationwide portfolio of 446 wind farms will
be consistently realized on much smaller subsets. As shown,
there can be a very broad range of outcomes.
Individual wind project performance can differ substantially from
industry averages
EXHIBIT 17: WIND CAPACITY FACTORS BY YEAR OF INSTALLATION
60
38
30
31
29.8
26.7
29
27
26
Projected
2013
Blue Creek Wind—Ohio
2012
Projected
Actual
New York Wind—Class 3–4
Source: EIA, American Municipal Power, New York State Energy Research and
Development Authority (NYSERDA); data as of year-end 2013.
6
7
Curtailment: when wind farm electricity is available but not drawn upon due
to grid congestion or instability, or the need to maintain minimum operating
levels on thermal generators or hydroelectric facilities.
The power of wind is a function of wind velocity cubed; as a result, a
10% reduction in wind speed results in a roughly 30% reduction in wind
electricity generation. A recent study cited in Der Spiegel notes 2.5%
annualized returns on 1,150 wind farm investments in German closed-end
funds, a function of less wind speed than projections, higher than expected
O&M expenses, and fees.
40
30
20
10
25
22
Individual projects
50
34.7
Actual generation
as a % of potential
Percent
34
Power generation-weighted average
0
Vintage: 98–99 00–01 02–03 04–05
# projects: 23
Megawatts: 776
24
1,514
36
1,908
27
3,417
06
07
08
20
34
76
1,640 4,931 8,513
09
10
11
95
9,561
48
4,731
63
5,854
Source: Lawrence Berkeley National Laboratory, U.S. Department of Energy;
data as of August 2013.
8
While rotor diameters and tower heights are increasing, the DoE notes that
many newer wind farms are built in less optimal wind locations, offsetting
part of the technological productivity improvement.
13
Designing an infrastructure
investment strategy for the
long run—guiding principles
The observed pitfalls highlight the ways in which infrastructure
is different from other fixed assets, such as real estate. The
operational and governance risks are more complex and need
intense focus both during the planning stages and throughout
an asset’s life. The inherently political nature of infrastructure
provides an additional layer of complexity across geographies
and sectors that needs to be managed and priced in from a
risk perspective. With the recent pitfalls in mind, we believe
the following basic principles emerge as being best suited for
infrastructure investing over the long run.
“The missteps of past infrastructure projects can be used to inform
a set of guiding principles we view as essential to successfully
navigating the road ahead.”
14
T H E R OA D N OT T A K EN: PITF AL L S AND O PPO RTUNITIES IN I N FRASTRUCT URE I N VE STI N G
DESIGNING AN INFRASTRUCTURE INVESTMENT STRATEGY FOR THE LONG RUN—GUIDING PRINCIPLES
GUIDING PRINCIPLES FOR INFRASTRUCTURE INVESTING
1. Control positions, acquired either through majority equity percentages or through governance rights, help ensure that
the investor’s strategy for the asset is implemented and prevent it from being “hijacked” in favor of other constituencies.
2. Assets that fall outside the range of “core” and “core-plus” introduce development and operational risks that have to be
actively managed and priced correctly. Core/core-plus generally refers to existing assets with stable income streams that
can be used as a platform for growth and new construction. Pure greenfield project risks are often underpriced due to
both construction risk and the lack of visibility on eventual usage and demand. Some of these greenfield project risks
can be mitigated through partnerships with public entities that allow private investors to earn a predetermined rate of
return on invested capital that is backed by a revenue stream not tied to the usage of the new asset (i.e., a sales tax).
3. Assets that rely excessively on back-ended appreciation in exchange for lower yields are typically mispriced and require
overly optimistic localized growth forecasts to make sense.
4. Markets, regulatory environments and jurisdictions without proven track records showing how they implement reform,
resolve disputes, handle pressure from citizens and legislators, and treat investors require adequate additional compensation.
5. Leverage and financial engineering (e.g., accreting interest rate swaps) should be kept in check.
6. Renewable energy projects often benefit from production tax credits, feed-in tariffs and minimum renewable standards
set at the state level. These policies are inherently variable and create risks around resale value for existing projects.
However, such projects can be attractive if they have long-term contractual agreements with utilities.
7. Diversify by region, vintage year and infrastructure type, particularly when there are regions or sectors that are
generating too much investor interest. Europe is currently generating a lot of interest from investors. Global institutional investors have made funds of $1 trillion available for investment in European infrastructure over the next 10 years,
typically focusing on Northern Europe as a preferred destination, given its more stable operating, economic and
legislative environment. However, the lack of available assets has driven prices higher and caused some investors to look
at Southern and Eastern Europe instead. Examples of aggressive investing in Northern Europe over the last year include
the following:
• A regional airport was priced as a trophy asset despite being highly dependent on a single, low-cost carrier, and
having airline and merchandising revenue that is subject to regulatory caps.
• Sale of a regional Scandinavian electricity distribution network was priced at over 16x cash flow, well above the typical
8–10x multiples in the sector. Portfolio managers owning shares in the selling company noted a deal price that was
10%–15% higher than they expected.
15
Opportunities: Principles
in practice
To provide a sense of how this strategy works in practice, we
review below some thoughts on four of the major infrastructure sectors and how the basic principles we’ve identified
apply to them.
Transportation
The U.S. public sector, both federal and municipal, faces
numerous transportation financing challenges. Public demand
for improved transportation options, weak job and economic
growth, the specter of construction cost inflation, the decline
of insured municipal financing and a dearth of federal funds
all contribute to a growing need for innovative financing solutions. However, we view the U.S. privatization model as flawed
and inefficient, as evidenced by its mixed track record. The
asymmetric risk profile of a typical PPP project provides core
returns but is accompanied by significant downside risk and
requires return-sharing above certain thresholds.9 This dynamic
creates some tensions among construction firms seeking
short-term profits, infrastructure investors bearing the risks of
up-front forecasts, project users and taxpayers.
9
One alternative now gaining traction in the U.S. is the idea, mostly for new
greenfield projects, of having bidders selected based on how cheaply they
can deliver, operate and maintain the asset, with their bids being based
upon fixed payments for the life of the concession. The owners are paid
based on construction milestones and facility performance standards, and
do not have volume/usage exposure to the asset, which remains with the
municipality. These transactions are referred to as “availability payments.”
16
As a result, caution is warranted on transportation investments, given the pitfalls and value destruction observed in this
sector (and in toll road and port acquisitions in particular)
from the 2005–2008 vintage. However, there may be select
opportunities in some new projects and in the unwinding of
distressed assets as owners face refinancing deadlines and/or
decide to exit projects. The best (and virtually only) example
so far in the U.S. is the South Bay expressway. In 2011, after a
competitive bidding process, the expressway was acquired out
of bankruptcy for $345 million. The concession was originally
awarded to private investors for $635 million.10
To respond to these broader challenges, our teams are working on a new solution that pools institutional capital and accelerates the delivery of multiple transportation projects under a
20- to 30-year partnership framework. The approach seeks to
create greater alignment of interests among the various stakeholders, so that they share risks instead of transferring them.
10
David Tanner. “New agency slashes toll rates on South Bay Expressway,”
Land Line Magazine. (July 5, 2012).
OPPORTUNITIES: PRINCIPLES IN PRACTICE
Power generation
In the U.S., a volatile regulatory/policy environment creates
both challenges and opportunities. Deep industry expertise and
knowledge of local regulatory developments are critical in
order to navigate the regional power markets in the U.S. In
particular, as coal plant retirements accelerate in the coming
years due to the competitiveness of natural gas-fired plants
and environmental regulations, an understanding of self-build
alternatives for utilities can drive investment opportunities.
As a quick review, an electric utility shutting down a coal plant
generally has three options: Buy a natural gas plant or alternative resource to replace it; build a new plant; or contract with a
third party to purchase power directly. Utilities often opt to
build or buy a plant rather than contracting for power, in order
to boost their rate base the most. However, regulatory commissions and public advocacy groups may intervene to secure the
cheapest alternative for ratepayers. When infrastructure investors cultivate relationships with all these constituents, they are
in a better position to participate in the most economic solution and earn an attractive return on capital.
An example: In August 2010, PSCo (Colorado’s largest electric
utility) submitted a plan to the state regulator to replace retiring coal plants with new natural gas plants that it would build.
During negotiations with the state regulator and public advocacy groups, Southwest Gen, an electricity generation company,
argued that contracting for power from a third party with
existing natural gas plants would be cheaper and save consumers money. As a result, the utility’s original plan was modified and Southwest Gen signed a 10-year contract for one of
its facilities. Infrastructure investors can benefit in this case
when they have ownership stakes in electricity generation
companies that intervene in the process.
As for renewable energy, solar generation can be an attractive
investment under a very specific set of circumstances: a high
minimum state/federal requirement for renewable energy;
higher solar capacity factors; declining technology costs
(either for photovoltaic or thermal) and improved productivity;
and the availability of tax credits for projects built before
2016. More broadly, renewable energy policies across many
countries remain in flux. Recent grid reliability issues and price
increases in Germany cast doubt on a continuation of current
subsidies for wind power. In fact, to help offset rapidly rising
residential electricity prices in Germany and manage generation resource availability, 10 new coal plants are scheduled to
start producing electricity in the next two years.11 As explained
earlier, pricing regimes must offer investors in renewable
energy sufficient protection against intermittency risks, changing government policy and underestimation of O&M expenses.
On a global basis, around 30% of all deals in the infrastructure
industry since 2008 have been related to renewable energy
(the largest slice); our preferences are likely to concentrate on
other sectors of the pie (Exhibit 18).
Recent infrastructure investment trends
EXHIBIT 18: BREAKDOWN OF INFRASTRUCTURE DEALS BY INDUSTRY,
2008–2013
Energy
15%
Social
(Hospitals, schools, prisons)
18%
Transportation
18%
Utilities
14%
Telecoms
3%
Other
3%
Renewable energy
29%
11
McCown, Brigham. “Germany’s energy goes kaput, threatening economic
stability,” Forbes. (December 30, 2013).
17
Regulated gas sector (delivery of natural gas from
treatment plants to homes and businesses)
In the U.S., we see a sustained cost advantage in using natural
gas vs. propane or fuel oil in regions where the differential in
pricing has exceeded 20%–30%. We expect continued robust
shale gas production to keep this price differential high, with
positive longer-term impacts on natural gas demand. As a
result, we see potential value in natural gas transmission
assets. However, caution is warranted due to rising valuations
observed in some transactions, some of which have been 1.6 to
1.8x the project’s rate base (the value upon which owners are
given a return on capital). As a result, reinvestment and capital
expenditure into an existing local distribution company
platform can often generate the highest expected returns,
given the ability to build assets at 1.0x their effective rate base.
Midstream pipelines (delivery of natural gas from
E&P sites to regional distributors)
We see substantial capital needs in the North American power
sector and the broader energy value chain as the shale gas
story continues to evolve. As an example of how capitalintensive the shale oil and gas E&P process has become,
consider this: The 4,000 wells brought online in 2012 in the
U.S. outpaced the total number of wells (conventional and
unconventional) brought online in the same year in the rest of
the world, excluding Canada.
An investment in this sector requires a thorough understanding of demand from end users in order to analyze the
impact on supply-side infrastructure development and
operation. Long-term contracts that entail a return on
invested capital provide certainty of demand and are aligned
with our long-term investment horizons. We generally avoid
volumetric contracts, because individual wells can exhibit
volatile production characteristics.
The comments above relate to current opportunities for
infrastructure investors. It is also interesting to consider the
ways in which natural gas may change the infrastructure
investment landscape in the years ahead. To do so, consider
its four main demand drivers in the context of the overall
picture of energy sources and uses (Exhibit 19):
Power generation
As shown in the diagram, the single largest use for natural gas
is electricity generation. Since 1990, coal’s share of electric
power has declined from 53% to 41%, while natural gas has
risen from 11% to 24%. We believe this process will continue,
even with capital investment in coal plants reducing nitrogen
oxide and sulfur dioxide emissions by 90% since 1990.
Sources and uses of primary energy
EXHIBIT 19: PRIMARY U.S. ENERGY CONSUMPTION BY SOURCE AND SECTOR
100
Nuclear (9%)
90
Percentage of total
70
9
Renewables (9%)
80
Coal (18%)
8
100
52
<1
<1
75
26
13
7
8
16
Industrial
(22%)
11
43
Residential & commercial
(10%)
39
91
60
50
Natural gas
(28%)
36
40
4
3
28
34
93
3
Transportation
(28%)
30
20
Petroleum
(36%)
10
23
5
41
72
Source
21
24
1
0
Electric power
(40%)
12
1
Breakdown by source/use (%)
Source: EIA; data as of year-end 2012. Some breakdowns by source/use may not sum to 100% due to rounding.
18
T H E R O A D N OT T A K EN: PITF AL L S AND O PPO RTUNITIES I N I N FRASTRUCT URE I N VE STI N G
Sector (use)
Industrial processes
Transportation
Industrial users represent the second-largest users of natural
gas. On a national level, there’s still a roughly even mix of
natural gas and petroleum use. In our annual energy note
last year, we reviewed how marginal costs for oil are rising,
a function of decline rates on existing fields and more-complex
locations required to bring new supplies online (Nigeria
deepwater, Canada heavy oil and some U.S. shale). As a
result, we expect more fuel switching in favor of natural gas
vs. petroleum products such as propane (Exhibit 20).12
This is where the future may become more interesting for
natural gas. It currently represents a small portion of
transportation energy sources, but this could change with
increased use of natural gas vehicles. The National Academy
of Sciences loves the idea: “With further expected improvements in vehicle technology and fuel efficiency, natural gas
powered vehicles will provide superior benefits in terms of
criteria pollutant reductions compared to nearly all other
types of vehicles, even electric and plug-in hybrid electric
vehicles.”13 The U.S. is behind other countries, with only about
110,000 out of 15 million natural gas vehicles (NGVs) globally,
ranking 39th in per capita use. For passenger cars driven
10,000 miles per year, the payback periods can be very long
(10+ years). However, for garbage trucks, transit buses, school
buses, taxis and other high-use, centrally fueled vehicles,
NGVs can make more sense. According to a 2011 analysis from
the National Renewable Energy Laboratory, including all costs
and credits, garbage truck and transit breakeven payback
times were 2.5–3.5 years. Since the report was published, the
cost of diesel has gone up and the cost of natural gas has
declined, reducing payback breakevens further. One sign of
rising expectations: Navigant Research projects 35 million
NGVs around the world by 2020 vs. today’s 15 million.14
Natural gas increasingly attractive to industrial users
EXHIBIT 20: NATURAL GAS/PROPANE PRICE RATIO*
1.2x
1.0x
Ratio
0.8x
0.6x
0.4x
0.2x
0.0x
2002
2004
2006
2008
2010
2012
2014
Source: Bloomberg, EIA; data as of February 2014.
*Both natural gas and propane prices are expressed as USD per million Btu.
Residential and commercial users
In this category, natural gas has won the battle, representing
75% of total sources. There may be some additional transitions away from petroleum, but only on the margin.
13
12
According to the EIA, propane represents 38% of industrial petroleum
consumption; other petroleum products account for less than 6% each,
which is why we compare propane to natural gas in the chart above.
14
Hidden Costs of Energy: Unpriced Consequences of Energy Production and Use
(National Academies Press, 2010).
Josie Garthwaite, “For natural gas-fueled cars, long road looms ahead,”
National Geographic (September 4, 2013).
19
APPENDICES
Exhibits A1.1 and A1.2 show median, top quartile and bottom
quartile internal rates of return (IRRs) and net multiples from
Preqin data. The lower net multiples for more-recent years
may reflect the marks on unrealized transactions that will
change as the funds mature. More-recent vintages also still
have substantial amounts of uncalled and uninvested capital.
However, as with private equity and venture capital, there were
transactions in 2006 and 2007 that entailed high prices paid,
so some of this recent underperformance may be permanent.
The charts demonstrate substantial performance dispersion
among top, median and bottom quartile funds.
Preqin also tracks the return expectations of infrastructure
managers whose funds closed from 2010 to 2013 (Exhibit
A1.3). While infrastructure investing is generally thought of as
being heavily cash-flow-based with stable returns, this distribution shows a very wide range of perceived risks taken
across the industry.
40
Top quartile IRR boundary
Median net IRR
Bottom quartile IRR boundary
Net IRR since inception (%)
35
30
25
20
15
10
5
0
1992–99
2000–05
2006
2007
2008
Vintage year
2009
EXHIBIT A1.2: NET MULTIPLES ON INVESTMENT FOR UNLISTED
INFRASTRUCTURE FUNDS BY VINTAGE YEAR
1.7x
Top quartile net multiple boundary
Median net multiple
Bottom quartile net multiple boundary
1.6x
1.5x
1.4x
1.3x
1.2x
1.1x
1.0x
0.9x
0.8x
2006
2007
2008
2009
Vintage year
2010
2011
EXHIBIT A1.3: DISTRIBUTION OF UNLISTED INFRASTRUCTURE FUNDS
CLOSED 2010–2013, BY TARGET NET IRR
20
15
10
5
0
10% or less 10.1–12% 12.1–14% 14.1–16% 16.1–18% 18.1–20% Over 20%
Target net IRR
Source: Preqin Infrastructure Online; data as of year-end 2013.
20
2010
Net multiple since inception
Preqin is an alternative investment data management and
consulting firm with performance histories covering private
equity, venture capital, real estate and hedge funds. Infrastructure investment by institutional investors is a more
recent phenomenon. As a result, the Preqin performance
history for infrastructure is not as deep as for other
categories. The firm’s infrastructure performance database
covers 140 closed-end funds, most of which were launched
after 2004. For comparison purposes, Preqin private equity
and hedge fund performance databases incorporate 6,700
and 14,700 funds, respectively. In other words, we would
interpret the Preqin infrastructure data more cautiously,
given its more concentrated and recent nature.
EXHIBIT A1.1: NET IRRS FOR UNLISTED INFRASTRUCTURE FUNDS BY
VINTAGE YEAR
Percent of funds
Appendix I: Infrastructure performance
from Preqin
APPENDICES
Appendix II: Infrastructure performance
from the Center for Private Equity Research
EXHIBIT A2.1: DISTRIBUTION OF INFRASTRUCTURE DEALS BY YEAR
(1971–2007)
14
A study from the Center for Private Equity Research (CEPRES)
covers 360 investments made from 1971–2009. The study, dominated by U.S. and European telecom privatizations in the late
1990s, cites investment returns that significantly exceeded
those on venture capital and private equity in similar vintage
years. However, dispersion across infrastructure investments
was extremely high, much higher than for private equity and
even higher than for venture capital. In other words, there were
a lot of high-performing assets and some that performed very
poorly. Note that the telecom privatization process of the past
may not bear any resemblance to privatizations of the future.
Percentage of deals
12
8
6
4
2
0
1971 1974 1977 1980 1983 1986 1989 1992 1995 1998 2001 2004 2007
Source: Bitsch, Buchner and Kaserer, Risk, Return and Cash Flow Characteristics
of Infrastructure Fund Investments (EIB Papers, 2010).
Key findings (Exhibit A2.2):
Details
Professors at Technische Universität in Munich, Germany, analyzed returns and risks on specific private equity infrastructure
transactions (not funds). CEPRES collects monthly cash flows
from individual private equity deals as reported by managers.
The authors categorized a transaction as “infrastructure” if it
was in transport, energy, telecom or natural resources, or if it
was initiated by a self-designated infrastructure fund. The data
sample consisted of 363 infrastructure deals between 1971 and
2009, centered in 1999, with 75% of all deals between 1994
and 2002 (Exhibit A2.1).
The majority of the study’s infrastructure deals were related to
telecommunication investments (59%); the remainder were in
natural resources and energy (25%), transportation (13%) and
alternative energy (3%). Geographically, Europe represented
43%, North America 43%, Asia 8% and the rest of the world 6%.
10
• On both an IRR and a multiple on invested capital (MOI) basis,
median returns for infrastructure (19%, 1.69x) were higher than
for non-infrastructure (6%, 1.13x). The median infrastructure
MOI was significantly lower than the mean (2.69x), indicating
a very large dispersion with a few outlying positive returns.
• The authors compared early-stage, greenfield infrastructure
investing with venture capital, and brownfield (established)
deals with later-stage private equity. Both infrastructure
categories outperformed their respective counterparts.
• The authors found that private equity investing in
infrastructure had significantly less risk of complete loss of
capital compared with non-infrastructure investing (5.26%
of brownfield infrastructure deals ended up being complete
write-offs vs. 9% for late-stage private equity).
• The authors found that median infrastructure investments in
Europe outperformed those in other regions. According to
the authors, higher returns in Europe may have reflected
governments not maximizing sales price as a universal goal,
and the ability of private sector owners to make substantial
reductions in operational inefficiencies.
EXHIBIT A2.2: COMPARISON OF PRIVATE INVESTMENT PERFORMANCE (1971–2007)
Infrastructure Non-infrastructure
Greenfield
infrastructure
Venture capital
Brownfield
infrastructure
Late-stage
private equity
IRR (%)
Average
Median
Standard deviation
67
19
300
20
6
197
46
5
306
6
-22
221
91
36
292
40
25
155
MULTIPLE (X)
Average
Median
2.7
1.7
2.5
1.1
2.2
1.2
2.1
0.4
3.3
2.5
2.9
2.0
Source: Florian Bitsch, Axel Buchner and Christoph Kaserer, Risk, Return and Cash Flow Characteristics of Infrastructure Fund Investments (EIB Papers, 2010).
21
APPENDICES
Appendix III: Natural gas peaker plants and
the dispatch curve
Natural gas peaking facilities represent a unique subset of
energy investing, whose dynamics are important to
differentiate from baseload plants. Peaker plants are called
into operation when baseload power sources are insufficient
to meet cresting demand (often during hot summer days).
Most regulated jurisdictions allow for a return on capital costs
for peaker plant owners, but even so, the return profile of
peaker plants is much more variable than for baseload plants.
To get a sense of the variability of peaker facility demand, see
Exhibit A3.1. Peaker demand rises in the summer but not
always to the same degree. This chart is for all peaker plants
nationally; individual peaker portfolios are more concentrated,
in which case their usage would be less predictable. While
peaker compensation rates are very high when the plants are
called into service (Exhibit A3.2), the overall revenue equation
entails greater operating risk and puts more importance on
paying the right price.
Peakers called into service only when demand is at its highest
EXHIBIT A3.1: MONTHLY CAPACITY FACTORS
EXHIBIT A3.2: HYPOTHETICAL DISPATCH CURVE FOR THE U.S.
100
Percent
70
Geothermal
60
Coal
50
Nat gas CC
40
Wind
30
Hydro
20
10
0
Jan-11
Nat gas
“peakers”
Jul-11
Jan-12
Jul-12
Jan-13
Jul-13
Source: EIA; data as of November 2013.
Early-morning
demand
80
300
Variable operating cost ($/MWh)
Nuclear
90
250
200
150
Renewables
100
Nuclear
Hydro
50
0
0
Coal
Nat gas
combined
cycle
Peak
demand
Demand seasonality by energy source
Petroleum
Nat gas
single
cycle
Nat gas
peakers
20
40
60
80
100
Capacity available to meet electricity demand (GW)
120
Source: EIA. J.P. Morgan; data as of February 2014.
H O W A D IS P ATCH CU RVE W ORKS
The electricity grid requires a balancing act between supply and demand. If demand exceeds supply by more than 5%–10%, brownouts
can occur. On the other hand, if supply substantially exceeds demand, in the absence of electricity storage, electrical equipment could
burn out. In Western Europe, for example, Czech grid operators have had to take defensive measures against surges in wind-powered
electricity coming from Germany to prevent blackouts. In order to maintain a proper balance, grid operators constantly bring generators
on- and offline. Some sources are obviously much easier to bring on- and offline than others (natural gas plants being the easiest).
The dispatch curve shown in Exhibit A3.2 is from the EIA and represents the order in which electricity sources are called into service
on a hypothetical day. All providers called into service are paid for their electricity at a marginal rate per MWh, which is determined by
the last marginal MW of capacity needed at that point in time. Baseload power sources (hydroelectric, nuclear) and renewable energy, when
available, are called upon first and receive this marginal price as well. As shown in the chart, combined cycle natural gas plants typically set the
marginal price, and as electricity demand increases during peak hours of the day, more units are added according to their marginal cost.
There are three types of natural gas electricity generation in the dispatch curve. Combined cycle plants are the most efficient and
typically used for baseload power: Waste heat from the original cycle is captured and used to boil water and generate additional steam/
electricity. Single cycle plants can also be used for baseload power but have lower efficiency rates. Combustion turbines (peakers) refer
to less efficient single cycle plants that are dedicated to providing power on demand: They can be started almost instantly and are called
upon when demand is greatest.
Wind and solar power providers are typically price-takers, given their low variable costs. However, on very windy or sunny days, there
could be a spike in the power they generate. Then what? In some jurisdictions, grid operators are required to take all the renewable
energy produced and scale back not only natural gas production but coal and hydroelectric as well. This is expensive, and there are
limits on the extent to which it can be done. At the extreme (i.e., when a hydroelectric dam would otherwise overflow), renewable
energy is “curtailed,” which means that grid operators do not use it.
22
T H E R OA D N OT T A K EN: PITF AL L S AND O PPO RTUNITIES I N I N FRAST RUCT URE I N VE STI N G
APPENDICES
Appendix IV: The problem with accreting
swaps applied to infrastructure projects
Many infrastructure projects are financed with bank loans,
whose interest payments are almost always floating rate (a
function of how banks finance themselves with short-term
deposits and interbank loans). Because infrastructure project
revenues (particularly for toll roads) are more bond-like in
nature, project owners sometimes elect to swap floating rate
loan exposure for fixed rate. Why an “accreting” swap? A traditional swap has a single fixed rate, while an accreting swap
starts out with a low rate and rises over time to compensate.
This presumably suits projects whose cash flows are expected
to rise over time.
The problem: A fixed rate loan is not the same as a floating
rate loan combined with an interest rate swap. Consider the
following stylized example. The project owners take out a
nine-year floating rate loan and overlay a 20-year accreting
swap (the swap term is longer than the loan, with the goal of
making refinancing by year nine easier). Now let’s assume that
interest rates fall. It looks like a lost opportunity for the project’s owners, as they could have benefited from a lower cost
of debt. But it’s worse than that, because the mark-to-market
loss on the interest rate swap adds to the project’s total debt
and jeopardizes its ability to refinance, even when there’s no
change in the project’s cash flow.
This scenario is shown as 1 in Exhibit A4.1. The table
computes changes in an owner’s net equity position based on
interest rate shifts and cash flow changes vs. original underwriting. There are even cases where the project’s cash flow
rises vs. original expectations, but the swap mark-to-market
loss more than offsets its impact 2 . Of course, the worst case
outcome is when the project’s cash flow underperforms
expectations and interest rates fall 3 .
Model simulation: Infrastructure project financed by a nine-year bank loan plus 20-year accreting swap
EXHIBIT A4.1: TIME-WEIGHTED NPV GAIN/(LOSS) ON USD2 BILLION INVESTMENT BASED ON CHANGING INTEREST RATES AND CASH FLOW GROWTH
Annual cash flow
growth vs. original
underwriting
-5.0%
-4.0%
-3.0%
-2.0%
-1.0%
—
1.0%
2.0%
3.0%
4.0%
5.0%
Changes in long-term interest rate swap curve
-2.5%
(2,685)
(2,352)
(2,000)
(1,628)
(1,235)
(821)
(384)
77
563
1,075
1,614
-2.0%
(2,521)
(2,188)
(1,836)
(1,464)
(1,071)
(657)
(220)
241
727
1,239
1,778
-1.5%
(2,357)
(2,024)
(1,671)
(1,300)
(907)
(493)
2 (55)
405
891
1,403
1,942
-1.0%
(2,193)
(1,859)
(1,507)
(1,135)
(743)
1 (328)
109
570
1,055
1,567
2,106
3
-0.5%
(2,029)
(1,695)
(1,343)
(971)
(579)
(164)
273
734
1,219
1,731
2,270
—
(1,865)
(1,531)
(1,179)
(807)
(415)
(0)
437
898
1,384
1,895
2,435
0.5%
(1,700)
(1,367)
(1,015)
(643)
(250)
164
601
1,062
1,548
2,060
2,599
1.0%
(1,536)
(1,203)
(851)
(479)
(86)
328
765
1,226
1,712
2,224
2,763
1.5%
(1,372)
(1,039)
(687)
(315)
78
492
929
1,390
1,876
2,388
2,927
2.0%
(1,208)
(875)
(523)
(151)
242
656
1,093
1,554
2,040
2,552
3,091
2.5%
(1,044)
(711)
(358)
13
406
820
1,258
1,718
2,204
2,716
3,255
ASSUMPTIONS FOR MODEL SIMULATION
Deal size:
Leverage:
Debt:
Equity:
Purchase multiple of free cash flow:
Required internal rate of return:
Implied annual cash flow growth:
Bank loan credit spread:
10,000
80%
8,000
2,000
20
12%
4.09%
1%, 9-year term, refinancing
and project valuation in Year 8
YEAR
1
2
3
4
5
6
7
8
9 10
Swap coupon
(%)
3.13 3.13 3.13 3.13 3.40 3.65 3.65 4.15 4.15 4.90
YEAR
11 12 13 14 15 16 17 18 19 20
Swap coupon
(%)
5.95 6.15 6.65 7.35 7.83 9.38 9.54 11.29 11.29 11.29
Source: J.P. Morgan. Stylized example. For illustrative purposes only. See text for definition of highlighted scenarios.
23
SOURCES
“$1B power plant approved in W. Va.,” AFX News. (June 27, 2006).
forecast on power demand,” Star–Telegram. (March 2014).
2014 Preqin Global Infrastructure Report, (Preqin, January 2014).
Garthwaite, Josie. “For natural gas-fueled cars, long road looms
ahead,” National Geographic. (September 4, 2013).
Annual Energy Review 2011, (U.S. Energy Information
Administration, September 2012).
Bain, Robert. Error and optimism bias in toll road traffic forecasts,
(University of Leeds, 2009).
Ben-Akiva, Moshe and John Bowman. Activity based travel demand
model systems, (Massachusetts Institute of Technology [MIT], 1996).
Berke, Jon and Seth Brumby, Eugene Gilligan. “Indiana Toll Road
paves the way for restructuring with advisors,” Financial Times.
(November 7, 2012).
Bitsch, Florian and Axel Buchner, Christoph Kaserer. Risk, Return
and Cash Flow Characteristics of Infrastructure Fund Investments,
(EIB Papers, 2010).
City Council’s 2013 Priorities Update, (City and County of
Broomfield, Colorado, January 24, 2014).
Declaration of Anthony G. Evans, Chief Financial Officer of Southbay
Expressway, L.P., in Support of the Debtors’ Chapter 11 Petitions
and First Day Motions, (United States Bankruptcy Court, Southern
District of California, March 22, 2010).
Dunning, Michael. “Toll road bankruptcies: why there are
many lessons, but few straightforward solutions,” InfraNews.
(April 29, 2013).
Estimating toll road demand and revenue, (Transportation Research
Board, 2006).
Evans, Rohanda and Jason McNichol. S.S.A. Marine, (University of
California, February 2006).
Fitzgerald, Patrick and Emily Glazer. “Longview Power, coal
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“Fund sells stake in port operator,” Reuters. (January 7, 2014).
Fuquay, Jim. “Overhaul of Texas electricity market put off by new
24
Global infrastructure investment to reach four trillion dollars by
2017, (Bain & Company, February 2014).
Grad, Paul and Peter Kenyone. “Australia suffers toll concession
failures,” TunnelTalk. (July 16, 2013).
Hensher, David (University of Sydney) and Zheng Li (University of
Sydney). Toll Roads in Australia: An Overview of Characteristics and
Accuracy of Demand Forecasts, (National Cooperative Highway
Research Program (NCHRP) Synthesis Report, 2010).
Hidden Costs of Energy: Unpriced Consequences of Energy
Production and Use, (National Academies Press, 2010).
Hogan, Steve. Introduction of a Private Concessionaire on the
Northwest Parkway—Colorado, (Northwest Parkway PHA,
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Urban Land Institute, 2012).
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(McKinsey Global Institute, January 2013).
Johnson, Kirk. “No Closure for Denver’s Beltway Loop,” New York
Times. (January 2012).
Koppel, Nathan and Emily Glazer “Fast Texas toll road struggles to
pick up drivers,” Wall Street Journal. (January 2, 2014).
Lane, Thomas. “M6 Toll debt at 26x EBITDA, MQA reports,”
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Latsch, Gunther. “Weak returns cripple German renewables,”
Der Spiegel. (January 30, 2014).
Macquarie Atlas Roads—Analyst Pack 2012, (Macquarie, 2012).
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(Maquarie, June 30, 2013).
T H E R O A D N OT T A K EN: PITF AL L S AND O PPO RTUNITIES IN I N FRASTRUCT URE I N VE STI N G
SOURCES
McCown, Brigham. “Germany’s energy goes kaput, threatening
economic stability,” Forbes. (December 30, 2013).
Samuel, Peter. “Northwest Parkway in Colorado concessioned to
Brisa for $603m,” TOLLROADSnews. (August 30, 2007).
Miecamp, Julie. “Macquarie’s M6 Toll Road seeks court backing for
loan extension,” (Bloomberg, November 26, 2013).
Samuel, Peter. “South Bay Expressway company files for
bankruptcy in San Diego,” TOLLROADSnews. (March 24, 2010).
Moody’s Downgrades SH 130 Concession Company, (Moody’s
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Samuel, Peter. “Sydney Cross City Tunnel bankrupt—receivers take
over,” TOLLROADSnews. (January 2, 2007).
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(National Renewable Energy Laboratory, March 2011).
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Painvin, Nicolas and Dan Robertson, Toll Road Networks Peers’
Positioning, (Fitch Ratings, June 2013).
Tanner, David. “New agency slashes toll rates on South Bay
Expressway,” Land Line Magazine. (July 5, 2012).
“Panda closes $420m private equity fund raising,” SparkSpread.
(November 16, 2011).
“Transurban buys doubly broke Sydney Cross-City Tunnel,”
TOLLROADSnews. (November 12, 2013).
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(OECD—Project on Strategic Transport Infrastructure to 2030,
September 2011).
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(January 24, 2007).
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(The Hamilton Project, February 2011).
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Broomfield PD,” Broomfield Enterprise. (July 10, 2013).
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TOLLROADSnews. (October 23, 2013).
25
26
T H E R O A D N OT T A K EN: PITF AL L S AND O PPO RTUNITIES I N I N FRAST RUCT URE I N VE STI N G
FOR INSTITUTIONAL/WHOLESALE OR PROFESSIONAL CLIENT USE ONLY—NOT FOR RETAIL DISTRIBUTION
NOT FOR RETAIL DISTRIBUTION: This communication has been prepared exclusively for Institutional/Wholesale Investors as well as Professional Clients as
defined by local laws and regulation.
This document is intended to report solely on investment strategies and opportunities identified by J.P. Morgan Asset Management. Additional information is available upon request. Information herein is believed to be reliable but J.P. Morgan Asset Management does not warrant its completeness or accuracy. Opinions and
estimates constitute our judgment and are subject to change without notice. It is not intended and should not to be taken as an offer or solicitation to buy or sell any
security or interest to anyone in any jurisdiction or to acquire any security or interest. Furthermore, nothing in this document constitutes or should be taken as an
advice or recommendation to buy or sell any investment and the material should not be relied upon as containing sufficient information to support an investment
decision. Any investment decision should be based solely upon the information contained in the product’s offering materials. J.P. Morgan Asset Management and/or
its affiliates and employees may hold a position or act as market maker in the financial instruments of any issuer discussed herein or act as underwriter, placement
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The investments discussed may fluctuate in price or value. Investors may get back less than they invested. Changes in rates of exchange may have an adverse effect
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WP_ ROAD NOT TAKEN
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© JPMorgan Chase & Co., March 2014

The road not taken - JP Morgan Asset Management

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