S-P- N W Hydro Assessment - Apr-25-2013.pdf

Credit FAQ:
How Drought And Other Risks Affect
U.S. Hydropower Producers’ Credit
Quality
Primary Credit Analyst:
Michael T Ferguson, CFA, CPA, New York (1) 212-438-7670;
[e-mail]
Secondary Contact:
Kyle M Loughlin, New York (1) 212-438-7804; [e-mail]
Table Of Contents
Frequently Asked Questions
Notes
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Credit FAQ:
How Drought And Other Risks Affect U.S.
Hydropower Producers’ Credit Quality
The 2012 drought, one of the most severe in recent memory, had profound economic effects across a broad array of
industries (see note 1), and, not surprisingly, affected several electric utilities in the Pacific Northwest. These utilities
rely heavily on hydroelectric energy, which supplies roughly 10% of our nation's power (see note 2) but contributes a
much higher percentage in this region, with some utilities obtaining as much as half of their energy in this manner in
some years. These utilities face unique challenges, some of which have direct implications for credit quality.
Standard & Poor's Ratings Services rates several integrated electric utilities in the northwestern U.S. with substantial
hydroelectric power operations, including Idaho Power Co., Puget Sound Energy Inc., Avista Corp., PacifiCorp, and
Portland General Electric Co.
Frequently Asked Questions
Why have these utilities taken to using hydroelectric power to such an extent?
Hydroelectric power has several credit-supportive qualities that distinguish it from other types of generation. First, and
perhaps most important, despite the staggering up-front costs of building dams and other facilities, maintenance
capital spending is often considerably lower than for fossil fuel facilities or other types of comparably sized renewable
energy facilities. For instance, fixed and variable operations and maintenance costs average $10/megawatt-hour
(MWh) while a conventional coal facility averages $32.6/MWh (see note 3). This enhances credit quality from an
operating efficiency standpoint: many utilities that have more conventional generation schemes have been dogged by
unwieldy maintenance costs and insufficient or delayed recovery of these costs. The very nature of hydro facilities
partially mitigates this risk. This is particularly helpful in forestalling regulatory lag where this is common.
Second, hydroelectric facilities may also be assigned the benefits of a renewable project. Variability in output has often
been used as a critique of renewable power projects, but hydro projects are more efficient and less expensive on a
MWh basis, and characteristically show somewhat higher capacity factors than other renewable projects (see note 4).
Utilities in many states are now subject to renewable portfolio standards with varying degrees of intensity, and some,
especially those in challenging regulatory jurisdictions or facing sputtering economic recoveries, are struggling to find
cost-efficient and politically appealing ways to meet them (See "What Renewable Energy Standards Mean For U.S
Electric Utilities' Future," published Oct. 4, 2012, on RatingsDirect. But some northwestern utilities, including Puget
Sound Energy (see note 5), have been able to meet their burden in advance, using significant amounts of hydropower
while still offering lower-than-average electric rates to customers; other utilities relying heavily on wind and solar to
meet this threshold have been criticized for higher rates, though these are now partially masked by low natural gas
prices. California, with its ambitious renewable mandate and customer rates far in excess of surrounding states, has
had particular difficulty meeting its burden. Though there has been some controversy surrounding hydro's
classification as renewable, it is counted as such by every relevant state commission (see note 6); however, this often
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depends (as in Oregon and Washington) on meeting minimum efficiency standards, which may require additional
capital spending, as was the case in 2012 with Puget Sound Energy's Snoqualmie and Baker projects (see note 7). We
view this as a credit enhancing facet; if a utility is forced to meet renewable standards, it's more cost-efficient to do so
with a more proven technology that provides minimal disruption to the current pricing scheme, and one that can enjoy
regulatory and political support when it creates jobs.
Finally, the operational flexibility of some dispatchable hydro facilities helps mitigate cash flow volatility and improves
credit quality. Unlike other renewable facilities, and more akin to fossil fuel facilities, hydroelectric dams (but not
run-of-river facilities) provide the ability to store "fuel" for use at times of peak demand. Wind facilities, for instance,
may have their strongest resource at a time when demand for power is relatively low. Hydroelectricity, furthermore, is
thought to be among the most efficient forms of electricity: by most accounts, 90% of potential electricity can be
converted to use in modern electric dams, compared with about 50% for many fossil fuel varieties and less still for
other renewable sources (see note 8).
What are the risks associated with hydropower, from a credit perspective?
Like other forms of renewable power, hydroelectricity's output depends on meteorological conditions. Both rainfall and
snowpack affect the hydro forecast each year; until last year, it had been quite high in the previous few yearsin the
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Credit FAQ: How Drought And Other Risks Affect U.S. Hydropower Producers’ Credit Quality
Pacific Northwest, including a historically strong 2011. Even within typically damp regions, however, there is still
substantial variability, and the 2012 experience, when water levels started off somewhat higher than historical average
but dwindled as the drought took effect and as hotter-than-average spring temperatures accelerated snow melting,
illustrates this. This is a meaningful credit negative; should a utility need to purchase power in order to offset reduced
output, it often does so at an increased price (due to constrained power supply and possible warmer weather
conditions that can correlate with low water years), but, as mentioned earlier, a hydro facility's ability to store water
may mitigate this risk partially. In addition, there may be some regulatory lag associated with the recovery of
purchased power costs, which can affect cash flow in the short term. Thus, even in utilities that have strong purchased
power pass-through mechanisms, it's not uncommon to see year-to-year variability in cash flow measures as a result of
under collections, and, to the extent that pass-through mechanisms have dead bands, which essentially are thresholds
that must be exceeded to share gains or losses with customers, or are otherwise incomplete, the utility can bear
purchased power costs itself. Our criteria also stipulate that debt levels should be adjusted to account for the presence
of power purchase agreements, which are frequently used to allay concerns about market exposure; this can have a
negative effect on credit quality by effectively making the company more leveraged than otherwise similar peers.
Along the same lines, hydroelectricity suffers from extreme concentration risk in this regard. If one hydro facility is
adversely affected by a drought or less-than-adequate snowpack, it's very likely others in the same region will be too;
this is a weaker type of resource diversity that many other utilities possess, especially those that use multiple fuel
sources.
Furthermore, the very substantial up-front investments made in building hydro facilities, especially dams, can raise
long-term credit concerns. Naturally, there is an agreement in place that facilitates recovery of these costs, whether
this is construction work in progress or depreciation recovery. However, to justify the staggering financial investment,
these behemoths must operate for long periods of time, perhaps 40 or 50 years, which compares with or exceeds what
is typical for some fossil fuel facilities. Although hydro facilities are frequently designed to last well longer than that,
this duration prompts some concerns about so-called "tail" events--low-probability/high-impact ones. The enormity of
these construction and maintenance costs, though ultimately justified by the inexpensive power that arises from them,
necessitates the ongoing participation of a credit-supportive regulatory jurisdiction to ensure recovery. The duration of
these projects lends itself to the possibility that the regulatory philosophy or management's ability to influence it could
change meaningfully during the project's life, especially in states in which commissioners are popularly elected, or
where regulatory outcomes have been inconsistent. This challenge is compounded by the Federal Energy Regulatory
Commission's participation in the regulation of dams, owing to their use of interstate rivers, even though the
commission has historically been credit supportive. In projects that have significant amounts of depreciation, we
consider whether recently implemented bonus depreciation provisions will persist and to what extent they will be a
boon to cash flow.
In addition, hydropower facilities are somewhat akin to nuclear facilities in that they can be affected by heightened
catastrophe risk. The day-to-day operational risks of a hydroelectricity facility are minimal, but a dam built with any
structural deficiencies can potentially be breached, resulting in a total loss or destruction, as seen most recently in the
failure of the Taum Sauk station in Missouri, which resulted in severe injuries and flooding (see note 9). Obviously,
events such as this are outliers, especially as engineering improvements have strengthened them, but one accentuated
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Credit FAQ: How Drought And Other Risks Affect U.S. Hydropower Producers’ Credit Quality
by the long life span of dams. In addition, despite their inclusion in the "renewable" category, hydroelectric facilities
are often criticized by influential environmental advocacy groups, which remain concerned about the effects of
displacing wildlife.
How are the risks of hydropower mitigated by these utilities?
Certain utilities that employ hydropower may also boast purchased power adjustment clauses to complement their
output; the effect of this, in short, is that it permits the pass-through of power costs to customers that end up becoming
necessary when a low water year prevents a hydro-dependent utility from meeting its load requirements exclusively
through owned generation. Although such utilities will partially or fully recover the higher costs of purchasing power
from merchant facilities, there is generally a lag associated with doing so, and the extent of this varies from state to
state. For instance, Avista has an energy recovery mechanism in Washington, where excess costs beyond retail rates
are assumed by the company up to $4 million per year (a dead band), but are shared with consumers beyond that, in
increasing percentages as costs increase (see note 10). Notably, this can sometimes cause recovery lag; Puget Sound
Energy uses a similar mechanism, but has a wider dead band. Idaho Power, by contrast, assumes 5% of net power
supply expenses, but recovers the other 95% from ratepayers, protecting it from excessive payments, and does so on a
partial forward-looking basis; the recovery of cash relies heavily on management's ability to make accurate projections
about future purchased power needs.
A package of capital spending riders is also effective in mitigating some of the risks of hydropower. As mentioned
earlier, though hydroelectric projects have comparatively low maintenance costs (see note 11), they too are subject to
occasional spikes, when major repairs are required to keep the facility functional or when upgrading its efficiency. A
rider allows more comprehensive and immediate recovery of these costs, allowing the company somewhat more
discretion, rather than compelling it to file new rate cases. In addition, the presence of capital spending riders provides
benefits for the liquidity profile of the utility that uses hydropower. The ability to quickly pass through increased capital
spending to customers prevents the utility from having to commit too much working capital to this task to cover
variability in capital spending and prevents some of the uncertainty associated with deferrals.
Mitigating the concentration and operational risks attendant in hydropower is somewhat more challenging. By their
very nature, hydro projects are somewhat larger, in terms of output, than other renewable projects; in fact, the nation's
largest power project is Washington's 6,809 MW Grand Coulee Dam. Thus, it becomes more difficult to adequately
diversify, and to be sure, resource diversity is a material consideration in our ratings criteria: one operational issue at
the facility can affect a greater swath of a utility's power supply. These facilities are inherently influenced by
geography; hydro facilities are perhaps more concentrated than any other power type, and unfavorable weather
patterns for one hydro facility generally equate to similar problems for other facilities. Strong power cost adjustments
help minimize these risks, but, in addition, adequate access to peaking power facilities, both fuel and natural gas, is
requisite.
Finally, and perhaps most important, liquidity is an important credit consideration for hydro-dependent utilities.
Liquidity is crucial for all utilities, but especially so for hydro-based utilities. Hydro utilities often must purchase large
quantities of power, and don't typically have the lead time or flexibility to fund these purchases with large scale,
long-term debt offerings. Consequently, though the majority of utilities have an "adequate" liquidity descriptor, most of
the utilities discussed herein have a "strong" descriptor, complete with sizable credit facilities and proactive refinancing
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Credit FAQ: How Drought And Other Risks Affect U.S. Hydropower Producers’ Credit Quality
of debt maturities, as well as dividend ratios that are often somewhat lower than average for the industry.
How did utilities with significant hydro generation fare in 2012?
The historic drought that gripped the nation during much of 2012 had significant ramifications for a number of hydro
utilities, and, for the most part, they underperformed against historical figures and projections. This effect was
particularly pronounced, coming as it did immediately after one of the more fruitful hydro years in recent history. The
drought led to more purchased power, an effect accentuated by the atypically hot summer that increased load
requirements throughout much of the U.S.; these purchased power costs carried with them the attendant issues for
utilities, described above.
From a meteorological perspective, 2012 was an aberrational year. In a typical year, where the hydro forecast remains
mostly consistent throughout the year, a utility that depends on hydropower can make accurate projections about how
much purchased power it will need, which, by admission, is driven by multiple factors. However, in 2012, optimistic
forecasts in the early part of the year were dashed by the summer's historic drought, and an unusually hot summer
called for greater power purchases still. As a result, several hydro-based utilities underperformed from a cash flow
perspective, performing as much as 2% funds from operations to debt lower than historical averages. Much of this
deficiency will likely be collected in 2013 and 2014, but it's this sort of year that illustrates the challenge that these
utilities face. However, notably, this volatility does not seem to significantly affect leverage measures, because such
utilities most often have sufficient liquidity to weather unusual conditions, preventing them from having to access the
capital markets to fund higher-than-anticipated seasonal power purchases.
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Credit FAQ: How Drought And Other Risks Affect U.S. Hydropower Producers’ Credit Quality
Table 1
U.S. Renewables And CO2 Emissions Summary
2011 2012 2013 2014
U.S. renewables consumption (quadrillion btu)
Hydroelectric power 3.1 2.7 2.6 2.7
Geothermal 0.2 0.2 0.2 0.2
Solar 0.2 0.2 0.3 0.4
Wind 1.2 1.4 1.6 1.7
Wood biomass 2.0 2.0 1.9 2.0
Ethanol 1.1 1.1 1.1 1.2
Biodiesel 0.1 0.1 0.2 0.2
Waste biomass 0.5 0.5 0.5 0.5
Total 8.3 8.2 8.4 8.8
Source: U.S. Energy Information Administration.
Are there current events that could affect the presence of hydropower in the future?
The expiration of the Energy Policy Act of 2005, effective Jan. 1, 2014, could influence the building of hydropower
facilities. This act was geared toward existing technology. It created the Section 1301 tax credit, which conveyed tax
benefits for power facilities looking to improve their energy efficiency. Because hydro facilities have been an enduring
source of power and there are many aged plants (the average age is somewhere between 41 and 54 years in the U.S.
and Canada) (see note 12), there was generally substantial room for upgrading them, so this tax credit was an effective
incentive. There is still ample opportunity to upgrade existing hydro facilities, but the absence of this credit would slow
such investment, especially if other fuel-specific energy-related tax credits are renewed. Given the current budgetary
situation in the U.S., as well as the very public controversy over extending the production tax credit in late 2012, it's
still too early to tell how this may be modified, if at all.
Certainly, the presence of renewable portfolio standards and goals in many American states could prompt increased
use of hydroelectric facilities. Renewable standards have generally been embraced by the American public, but there
have been concerns about the cost of these programs. What makes hydroelectric power somewhat resistant to this
pressure is that it can end up being markedly less expensive to the consumer, as demonstrated by the characteristically
lower power prices in the hydro-rich Northwest. Consequently, a number of utilities have added assets to their
renewable portfolios without palpable jolts to customer bills, by relying heavily (though not exclusively) on
hydropower. To the extent that renewable portfolio standards are strengthened in the future, those utilities that
currently use a heavy allotment of hydroelectric power should be better positioned to meet these mandates, but the
costs of competing renewable technologies, which are less mature, are likely to decrease at a faster rate in the future.
No discussion of power would be complete in 2013 without mentioning natural gas. Despite the national inclination
toward natural gas power in light of its historically low prices, the infrastructure in the Northwest is less developed (see
note 13) and has been slow to keep up with increasing demand; there are fewer pipelines leading to the Pacific
Northwest, which makes natural gas somewhat less appealing due to enhanced supply risk, but this is changing
somewhat. The preference for natural gas has thus manifested more slowly in this part of the country, and coal is
becoming increasingly challenging to justify given the current and, possibly, future environmental constraints
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Credit FAQ: How Drought And Other Risks Affect U.S. Hydropower Producers’ Credit Quality
associated with it. This seems to suggest that there will continue to be a place for hydropower in the Northwest, but it
will be inherently constrained by its own finite supply, as well as the aforementioned risks and the need for sufficient
replacement power.
In addition, as we forecast our expected measures for 2013, we remain influenced by the experience of 2012, which
started off as a robust hydro year, but was adversely impacted by the drought. Several independent hydro forecasters,
including the Energy Information Administration, have revised their long-term estimates downward, and, even so,
many are still forecasting that 2013 levels will be below that mark as a result of a drier-than-expected winter (see note
14). As we rely on these forecasts, we believe that hydro-dependent utilities will be required to purchase higher than
historical average amounts of market power. Obviously, the presence of purchased power recovery mechanisms
prevents the utility from bearing the bulk of this cost, but this of course makes the utility more staked to the quality of
its recovery mechanism, and its ability to project accurately it power needs, especially if it uses a forward-looking
mechanism. If it fails to do this, under-collections on the mechanisms may cause cash flow volatility, eating some
excess power costs, and substantial deferrals that are not credit supportive.
Notes
(1)
https://www.globalcreditportal.com/ratingsdirect/showArticlePage.do?rand=2T4G7D4tE2&object_id=7509776&rev_id=6&sid=1006662&sind=A&
(2) http://www.usbr.gov/uc/power/hydropwr/benefits.html
(3) http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
(4) http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
(5)
https://www.globalcreditportal.com/ratingsdirect/showArticlePage.do?rand=PRksrSlpVQ&articleId=1064806&from=MRA-
(6) http://www.c2es.org/docUploads/State%20rps%20eligible%20resources.pdf
(7) http://www1.snl.com/InteractiveX/article.aspx?ID=16219985&KPLT=2
(8) http://www.mpoweruk.com/energy_efficiency.htm#comparison
(9) http://www.eoearth.org/article/Hydroelectricity?topic=49469
(10) http://www.sec.gov/Archives/edgar/data/104918/000119312512340791/d371580d10q.htm
(11) http://www.eia.gov/forecasts/aeo/electricity_generation.cfm
(12)
http://www.hydroworld.com/articles/hr/print/volume-30/issue-5/articles/executive-interview-viewpoints-from-the-board-room-alstom-hydro-north-america.html
(13) http://www.nwga.org/wp-content/uploads/2012/06/infrastructure.pdf
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Credit FAQ: How Drought And Other Risks Affect U.S. Hydropower Producers’ Credit Quality
(14) http://www.eia.gov/todayinenergy/detail.cfm?id=10091
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Credit FAQ: How Drought And Other Risks Affect U.S. Hydropower Producers’ Credit Quality
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