2017 Hydropower Market Report - HydroSource€¦ · • The 2017 Hydropower Market Report provides objective, publicly available, comprehensive information on U.S. hydropower. –

2017 Hydropower Market ReportApril 2018

Rocío Uría-MartínezMegan M. JohnsonPatrick W. O’Connor

2 Managed by UT-Battellefor the U.S. Department of Energy

Introduction

• The 2017 Hydropower Market Report provides objective, publicly available, comprehensive information on U.S. hydropower.

– The first edition of the Hydropower Market Report was released in 2015; this second installment provides updates to the core datasets presented there and adds new content: global hydropower development trends, U.S. hydropower price trends, O&M cost trends, and an analysis of one-hour ramp generation data to explore the contributions of hydropower and pumped storage to load-following flexibility

• It is compiled from many different publicly-available datasets and from information collected to support ongoing Department of Energy R&D projects.

• It provides industry, policymakers, and other interested stakeholders with a data-driven summary of key trends regarding U.S. hydropower development, cost, and performance.

• The report was authored by ORNL researchers Rocío Uría-Martínez, Megan Johnson, and Patrick O’Connor with contributions by

– Shelaine Curd, Nicole Samu, and Adam Witt at ORNL

– Hoyt Battey, Timothy Welch, Marisol Bonnet and Sarah Wagoner at DOE Water Power Technologies Office

• The report was funded by the DOE Water Power Technologies Office and was reviewed by more than a dozen industry stakeholders

• It is available for download at energy.gov/hydropowerreport.


Table of Contents

1. Trends in U.S. Hydropower Development Activity

1.1 U.S. Hydropower Fleet

1.2 Capacity Changes (2006-2016)

1.3 Hydropower Project Development Pipeline (as of December 2017)

1.4 Investment in Refurbishments and Upgrades

2. U.S. Hydropower in the Global Context

2.1 Description of the Existing Global Hydropower Fleet

2.2 International Trends in Hydropower Development

2.3 Investment in Refurbishments and Upgrades

3. U.S. Hydropower Price Trends

3.1 Trends in Hydropower Energy Prices

3.2 Trends in Hydropower Asset Sale Prices

4. U.S. Hydropower Cost and Performance Metrics

4.1 Capital Costs

4.2 Operation and Maintenance Costs

4.3 Energy Generation

4.4 Capacity Factors

4.5 Availability Factors

4.6 Hydropower Operation Flexibility

5. Trends in U.S. Hydropower Supply Chain

5.1 Hydropower Turbine Installations

5.2 Hydropower Turbine Imports/Exports

6. Policy and Market Drivers

7. Conclusions and Further Work


Key Findings

• U.S. hydropower capacity has increased by 2,030 MW from 2006 to 2016; net capacity change was positive in all regions.

• At the end of 2017, there were 214 hydropower projects and 48 pumped storage hydropower (PSH) projects in various stages of planning and development.

– Most hydropower projects propose adding generation equipment to non-powered dams (NPD) or conduits.

– Most PSH projects are closed-loop, in states with ambitious renewable portfolio standards and/or located in ISO/RTO regions.

• Hydropower’s ability to quickly adjust output up or down in response to changes in net load makes it play a key role as complement to the much larger, and also highly flexible, natural gas fleet in providing load following flexibility.

• U.S. hydropower refurbishment and upgrade (R&U) projects worth $8.9 billion have started from 2007 to 2017; U.S. has the oldest capacity-weighted average fleet age and one of the highest levels of R&U investment per installed kilowatt.

• Operation and maintenance (O&M) costs per installed kilowatt are rising faster than inflation for all but the largest hydropower plants.

• The U.S. hydropower availability factor has declined in the last decade; except for small units (<10 MW), the majority of outage hours are planned outages for precautionary maintenance or upgrades to avoid costly forced outages.


1. Trends in U.S. Hydropower Development Activity


Top ten states by installed hydropower capacity, hydropower percentage of in-state generation, and pumped storage hydropower (PSH) capacity

• More than a quarter of installed U.S. hydropower capacity is in Washington and accounts for more than 2/3 of the electricity generated in that state.

• California leads the ranking of installed PSH with 3.76 GW distributed across 10 plants.

Hydropower capacity (MW)

Cumulative (end of 2016)

WA 21,097

CA 10,332

OR 8,471

NY 4,721

AL 3,109

MT 2,638

ID 2,581

TN 2,499

GA 2,181

NV 2,096

Hydropower % of in-state generation

Average (2014–2016)

WA 68.06

ID 57.60

OR 56.72

SD 46.84

MT 36.01

VT 31.05

ME 27.35

AK 25.54

NY 19.26

TN 10.79

Pumped storage hydropower capacity (MW)

Cumulative (end of 2016)

CA 3,756

VA 3,109

SC 2,581

MI 1,979

TN 1,714

GA 1,635

PA 1,541

MA 1,540

NY 1,240

MO 600

Northwest

Southwest

Midwest

Northeast

Southeast

Regions


Net hydropower capacity change in 2006-2016 was positive in all regions; more than 2 GW added nationally

• Most of the capacity additions resulted from refurbishments and upgrades at existing facilities and the addition of hydropower generation equipment to non-powered dams (NPDs) and conduits.

• The largest net capacity increase took place in the Northwest; the Midwest is the only region where the largest component of the capacity increase are new plants (mostly NPDs).

Sources: EIA Form 860, NHAAP, FERC eLibrary

Hydropower capacity changes by region and type (2006–2016)


At the end of 2017, there are 214 hydropower projects and 48 PSH projects in the development pipeline

• The 214 hydropower projects add up to 1.7 GW.

– Non-powered dam projects account for 92% of proposed capacity.

• The combined capacity of all PSH projects is almost 20 GW.

– But a cluster of 17 projects being evaluated in the Northeast would likely result in just one selected.

• Regional variation in project type:

– New stream-reach developments in the Northwest

– Most conduit projects are located in the Northwest and Southwest

– PSH projects are predominantly in the West and Northeast

• About 50% of hydropower and 83% of PSH projects are at early stages of planning with high attrition rates.

Sources: FERC eLibrary, Reclamation LOPP database, web searches

Note: See technical appendix for detailed definitions of the development stages

Hydropower project development pipeline by project type, region,

and development stage


Small, private developments dominate the project pipeline

• The largest proposed hydropower project is 78 MW.

• Median sizes:

– 6 MW for non-powered dams

– 6 MW for new stream-reachdevelopments

– 0.43 MW for conduit projects.

• Two thirds of all projects are being pursued by private developers.

– Conduits are the only project category more frequently pursued by public entities than private developers because municipalities and irrigation and water supply districts own a large fraction of the conduit infrastructure.

– For investor-owned utilities already owning hydropower facilities, investing in upgrades to their existing assets is typically the preferred strategy to increase hydropower capacity.

Sources: FERC eLibrary,

Reclamation LOPP database,

web searches

Hydropower project development pipeline

by project type and size

Hydropower project development pipeline

by project type and developer type


Most proposed PSH projects are in or adjacent to states with ambitious renewable portfolio standards

• A majority of proposed sites would have access to competitive energy and ancillary service markets.

– ISONE, NYISO, or PJM in the Northeast

– CAISO or the recently created Western Energy Imbalance Market in the West

• Most proposed PSH projects are closed-loop facilities, not directly connected to rivers.

– Closed-looped configuration minimizes environmental impacts and allows for more flexibility in site selection.

• The median size of proposed PSH projects has decreased in recent years.

– Median size was 600 MW at the end of 2014 versus 290 MW at the end of 2017.

Source: FERC eLibrary

Note: The difference between the Renewable Portfolio Standards and Goals shown in this map is that Renewable

Portfolio Standards are mandatory while Goals are voluntary.

Pumped storage hydropower project development pipeline by region and status


U.S. hydropower refurbishment and upgrade (R&U) projects worth $8.9 billion have started between 2007 and 2017

• Tracked R&U projects are heavily weighted towards turbines and generators.

– The scope for two thirds of tracked projects involves work on turbines and 75% of projects involve work on generators.

• R&U investment is not evenly distributed across the fleet.

– Federal hydropower represents 49% of installed capacity but it accounts for 39% of tracked R&U investment during this period.

Source: Industrial Info Resources

Expenditures on R&U of the existing hydropower fleet (as of December 31, 2017)


2. U.S. Hydropower in the Global Context


The United States has the third largest fleet in the world for both hydropower and PSH(fourth largest if European Union (EU27) countries are taken as a unit)

Source: EIA International Energy Statistics, International Hydropower Association 2017 Hydropower Status Report, REN21 Global Status Report 2017

From 2005 to 2016:

• China’s average annual capacity growth rate has been 9.6% for hydropower and 16% for PSH.

• The more mature U.S. and EU fleets have grown on average less than 1% per year during this period.

Evolution of installed hydropower and PSH capacity for the six largest fleets (2005–2016)

1) China

2) European Union

3) Brazil

4) United States

5) Canada

6) Russia

1) European Union

2) Japan

3) China

4) United States

5) India

6) South Korea


Major hydropower clusters include the Pacific Northwest in North America, southeastern Brazil, and southwestern China

Source: Industrial Info resources

Note: The regions shown in this map are used to discuss various attributes of the global hydropower fleet and project development pipeline in the rest of this section.

Map of operational hydropower plants by world region


Hydropower is the largest renewable energy source globally (1,096 GW), but other renewables have grown faster in recent years

• Central and South America is the region with the highest hydropower fraction (43%); hydropower (without PSH) represents 13%-20% of electricity generation capacity in every other region.

• East Asia and Southeast Asia and Oceania are the only two regions where the percentage of hydropower in the electricity generation capacity mix increased from 2005 to 2015; in contrast, the weight of non-hydropower renewables grew in every region.

– In Europe, non-hydropower renewables surpassed hydropower capacity between 2005 and 2015.

Source: EIA International Energy Statistics

Note: Pumped storage hydropower is

included although it is a storage technology.

Electricity generation capacity mix by world region (2005 and 2015)


There has been a resurgence in large (>100 MW) hydropower construction in the 2000s driven by Asia


Globally, large hydropower construction

peaked in the 1960s.

The United States led the way in bringing the environmental impacts from large dam

construction to the forefront through legislation passed in the 1960s and 1970s.

Acknowledgement of environmental and social impacts of large dams

contributed to slower construction rates in the 1980s and 1990s.

Construction of large

projects picked up

again in the 2000s to

address climate change

and the growing energy

demands of developing

Nations.

Timeline of construction of large hydropower plants by world region

• The United States and most OECD countries stopped large hydropower development almost completely decades ago, but a few OECD countries (Canada, Norway, Portugal) are still building large projects.


East Asia has the largest hydropower and PSH project pipeline (251 GW) and 50% of its proposed projects are at an advanced stage of development

Within North America, the

United States and Canada

have significantly different

pipelines.

• In the United States,

planned capacity is

dominated by PSH

projects and less than

1% of total proposed

capacity is in construction.

• In Canada, hydropower

projects account for 74%

of the proposed capacity

and 47% of all proposed

projects are in the Under

Construction stage.


Note: The Under Construction stage includes projects that have completed the

permitting process and secured financing but have not yet broken ground.

Map of hydropower project development by region and development stage


East Asia and Europe have added gigawatts of new PSH capacity since 2006 and are constructing many more plants; the United States has only added 1 new PSH facility since 1995 and has none in construction

• The disparity in PSH development activity between the United States and these other regions could be due to differences in:

– authorization process

– available revenue streams

– available alternatives to provide grid flexibility

• Cheap and abundant domestic natural gas in the United States might have resulted in greater reliance on natural gas peakers for grid flexibility than in other regions.

Source: Industrial Info Resources, FERC e-Library

Pumped storage hydropower development by world region


South Asia has the largest development pipeline by number of projects but it is outpaced by East Asia in terms of planned new capacity


Tracked hydropower project development pipeline by world region and size category

• Globally, 208 Very Large (>500 MW) projects are in the development pipeline; the largest is Belo Monte in Brazil (11 GW)

• East Asia, principally China, is the region with the most Large and Very Large projects. On the other hand, South Asia tops the count of Medium and Small projects.


As of the end of 2017, ongoing and planned capital expenditures for the existing hydropower fleet add up to $83 billion globally(54% goes toward expansion of existing plants; the rest is dedicated to refurbishments and upgrades)

Expenditures on hydropower refurbishments, upgrades, and plant expansions by region


• North America is the region with the largest tracked capital expenditures.

• The breakdown of total investment between the two project categories varies significantly across regions:

– In most Asian regions, tracked capital investments in the existing fleet go largely toward plant expansion projects.

– In regions with older fleets (North America, Europe, Russia, and Central and South America), most tracked expenditures are geared towards R&U.


North America leads the R&U investment ranking in $ per installed kilowatt

Expenditures on hydropower refurbishments and upgrades per kilowatt installed by world region


• Planned and ongoing R&U projects in North America started since 2015 amount to an investment of $79/kW; one third of the total corresponds to projects in the Under Construction stage.


The United States has the oldest fleet and one of the largest expenditures per refurbished/upgraded kilowatt


Expenditures on hydropower refurbishments and upgrades per kilowatt refurbished/upgraded and fleet age

• There is a positive relationship between the average age of refurbished or upgraded plants and the R&U investment per refurbished kilowatt.


3. U.S. Hydropower Price Trends


Hydropower prices vary by ownership type and region depending on market structure

Footprints of power marketing administrations and

independent system operators

As of 2017:

• Electricity produced by 44% (35.2 GW) of U.S. hydropower capacity and 6% (1.32 GW) of PSH capacity is marketed by one of the four power marketing administrations (PMAs).

• Electricity produced by 28% (22.4 GW) of U.S. hydropower capacity and 59% (12.7 GW) of PSH capacity is marketed through one of the seven organized wholesale markets administered by ISO/RTOs.

• Electricity produced by the remaining 28% (22.4 GW) of U.S. hydropower capacity and 35% (7.6 GW) of PSH capacity is sold by vertically-integrated utilities to their customers or through bilateral contracts, power purchase agreements, or transactions in wholesale market trading hubs.


Post 2008, average federal hydropower prices do not differ significantly from average wholesale market prices in most regions

Average federal hydropower price versus average wholesale electricity prices at selected hubs

Sources: EIA Form 861, EIA Wholesale Electricity and Natural Gas Market Data

• The average federal price includes capacity and energy charges as well as rate adders to cover the costs that PMAs incur in managing imbalances between available hydropower generation and firm power volumes contracted by their customers.

– Many of the spikes in the federal hydropower price series are related to drought events.


Utilities paid higher energy prices for hydropower than the average across all technologies in 2006–2016

Median and generation-weighted average FERC Form 1 purchased power prices for hydropower versus all technologies

• Most hydropower purchases reported in FERC Form 1 correspond to small plants for which the power purchase prices paid by utilities are typically based on Public Utility Regulatory Policies Act (PURPA) avoided cost rates.

• Higher hydropower prices relative to the average for all power purchase transactions might be due to:

– Technology-specific PURPA avoided cost rates which are higher for hydropower

– Start year of the transactions: most small hydropower plants were built decades ago and locked in avoided cost rates at a time in which they were significantly higher than in the last decade.

Source: FERC Form 1


The price paid for hydropower by utilities varies significantly across and within regions

Hydropower price by region and report year from long-term firm power sales

reported to FERC Form 1

Source: FERC Form 1

Note: Points correspond to the median hydropower purchase price based on FERC Form 1 data, and the range represents the

10th–90th percentile FERC Form 1 hydropower purchase price range. Trend lines correspond to the average on-peak wholesale

price at selected electricity trading hubs in each region (Mid-Columbia Hub for Northwest, Palo Verde Hub for Southwest,

Indianapolis Hub for Midwest, Massachusetts Hub for Northeast, and PJM West Hub for Southeast).

• The median energy price paid for hydropower in this sample of transactions in 2006–2016 was $62.78/MWh.

• Hydropower prices in the Northwest carried the larger premium relative to the regional average wholesale market price.

• Median hydropower prices in the Northeast and Midwest have followed closely the regional wholesale market price, particularly after 2008.


In much of the country, long-term hydropower purchase agreements initiated in recent years come with lower prices than older ones

Average hydropower price for individual buyer-seller pairs versus agreement start year

Source: FERC Form 1

• Market conditions at the time a purchase agreement is being negotiated influence the prices to be paid throughout the life of the contract.

• For projects in the Northeast and Southwest, long-term purchase agreements initiated in recent years receive lower prices.

• In the Northeast, the range of energy prices paid by utilities to hydropower owners has widened over the last decade.


Changes in ownership have taken place for hundreds of U.S. hydropower plants during the last decade

Hydropower ownership transfers by year and authorization type

Source: FERC e-Library, NHAAP

• The total number of hydropower plant transfers between 2004 and 2017 was 491.

• The pace of transfers increased after 2011, particularly for exemption-holding plants.

• Most of the transactions involve small plants and private buyers and sellers.

– In some cases, buyer and seller are entities within the same corporate structure.


The Northeast is the region with the most hydropower plant transfers from 2004 to 2017

Region and size distribution of transferred hydropower plants between 2004 and 2017

Sources: FERC e-Library, NHAAP

• The Northeast and Southeast are almost tied in terms of total capacity transferred.

• Within the Large and Very Large size categories, there were total or partial changes in ownership for 17 plants, 6 of which are PSH plants, but the majority (73%) of plants transferred are small.


The average sale price per installed kilowatt within a sample accounting for 34% of transferred capacity in 2004–2017 was $1,072/kW, but there was considerable variability around this central value

• The capacity-weighted average price was $1,345/kW suggesting that larger plants tend to be valued more than small ones.

• There is no large difference in the average price for plants holding a FERC exemption ($935/kW) versus a FERC license ($1,096/kW).

U.S. hydropower plant sale prices by year and region of sale

Sources: web searches and SEC filings

Note: The Average price type corresponds to transactions in which multiple plants were sold but only the total

price was reported


4. U.S. Hydropower Cost and Performance Metrics


The capital costs of recently developed hydropower plants remain highly variable

U.S. hydropower plant sale prices by year and region of sale • Developers with access to low-cost, long-term financing pursue targeted opportunities at low-head NPD, small NSD and conduit projects.

• Average costs since 1980:

– $4,200/kW for NPDs

– $5,200/kW for NSDs

– $4,700/kW for conduits

• Much of the cost variability is due to site-specific factors but, at a macro scale, hydraulic head is one of the most significant cost drivers.

Sources: O’Connor et al (2015), Industrial Info Resources, web searches


NPD and conduit projects exhibit strong economies of scale with respect to hydraulic head; all else equal, higher head leads to less expensive projects

U.S. hydropower plant sale prices by year and region of sale

Sources: O’Connor et al (2015), Industrial Info Resources, web searches

• All else being equal, a

higher head project requires less flow to achieve the same power output than a lower head project which translates into

– Savings in the cost of equipment

– Reduced size and cost of associated civil works and water conveyance infrastructure


Operation and maintenance (O&M) costs per kilowatt installed exhibit strong economies of scale with respect to project size

2016 O&M expenditures for hydropower plants reporting on FERC Form 1

1 10 100 1000

ro ect Ca acit ( )

10

100

1000

O C

ost (201 r)

er ar e ar e ediu S all

Sources: FERC Form 1, Bureau of Labor Statistics

Notes:

- The FERC Form 1 dataset covers a specific subset of the U.S. fleet, mostly hydropower owned by vertically-integrated, investor-

owned utilities and municipalities. The dataset covers ~25% of the U.S. hydropower fleet.

- Six of the seven Very Large plants included in the dataset are PSH plants.

• Small projects face the highest O&M costs per kilowatt and display the largest O&M cost variability.

• Average 2016 O&M costs:

– $8/kW for Very Large plants (>500 MW)

– $22/kW for Large plants (100 MW–500 MW)

– $40/kW for Medium plants (10 MW–100 MW)

– $113/kW for Small plants (<10 MW)


Except for the largest hydropower plants, operation and maintenance (O&M) costs have risen at rates higher than inflation for the last decade

Trend in O&M costs for hydropower projects by size class

Sources: FERC Form 1, Bureau of Labor Statistics

*https://digital.hydroreview.com/hydroreview/201803/MobilePagedArticle

• Small, Medium, and Large size categories have all experienced inflation-adjusted real O&M cost increases of up to 20% since 2007; the CPI baseline increased by 16% over the same timeframe

• Among the reasons for the cost increases are:

– Compliance with increasingly stringent regulatory requirements

– Ageing workforce

– Declining quality assurance/quality control on newly purchased equipment*


Despite significant year-to-year fluctuations at the regional level, total U.S. hydropower generation has remained stable over the last decade

Annual hydropower generation by region (2003-2016)

Sources: EIA Form 923

• Average annual U.S. hydropower generation was 270 TWh in 2003–2016

– In 2014–2016, hydropower has accounted for 6.3% of total U.S. electricity generation

• On average, the Northwest produced half of U.S. hydropower each year

– Southwest, Northeast, and Southeast each produced about 15% of the total

• The peaks and troughs in each of the regional generation series are highly correlated with wet and dry years


U.S. gross pumped storage hydropower generation has declined slightly during the last decade

Annual gross pumped storage hydropower generation by region (2003–2016)


Notes:

- The Northwest region was left out because it has very little PSH capacity (314 MW).

- PSH facilities are net consumers of energy because they use more electricity for pumping water from the lower to

the upper reservoir than they produce when they release water from the upper reservoir to pass through turbines

and generate electricity. The figure shows gross generation without netting out pumping energy consumption

• The Southeast has the largest installed PSH capacity and produced, on average, 54% of all electricity output from the U.S. PSH fleet in 2000–2016.

• The peaks and valleys in regional PSH generation do not always coincide with wet and dry years; instead PSH generation is influenced by:

– electricity market conditions (e.g., clear reduction in Northeast PSH generation in 2008–2011 coinciding with low electricity demand and prices during economic recession)

– unplanned outages (e.g., large drop in PSH generation in Southeast in 2012–2013 partly due to TVA’s Raccoon Mountain outage)


Seasonal distribution of hydropower generation is largely driven by hydrology; PSH generation correlates more closely to seasonal electricity use patterns


Notes:

- The central lines depict

the median levels for

each variable and the

surrounding bands

enclose the 10th–90th

percentile intervals.

- *The Northwest region

only has 314 MW of

PSH. Gross PSH

generation is extremely

small for most of 2003–

2016. However, it

averaged 78 GWh per

month in the spring of

2003 and 59 GWh in the

spring of 2004 resulting

in the peak observed in

the figure.

• Seasonal electricity use peaks in summer in all regions, except for the Northwest.

– PSH generation also peaks in summer.

– Hydropower generation peaks in late spring (coinciding with snowpack melt) in the Northwest and Southwest; in the Northeast and Southeast, hydropower generation peaks during winter and early spring.

Seasonal profiles of hydropower generation, pumped storage hydropower gross generation, and electricity

consumption by region (2003–2016)


Hydropower generation scheduling is also influenced by competing purposes of storage reservoir space and water flows

Generation and hourly load-following by the Federal Columbia River Power

System (FCRPS), 2008-2017

• A comparison of the ability of the Federal Columbia River Power System (FCRPS) generation to follow net load in 2015 (snowmelt flows far below long-term average) versus 2017 (snowmelt flows far above long-term average) provides an example.

– In the low-flow environment of 2015, the FRCPS managed to follow net load more closely than average.

– In 2017, near record early spring flows resulted in flood control operations and management of total dissolved gas levels (for fish protection) taking precedence over hydropower operations; as a result, hydropower could not be scheduled to follow market signals closely.Sources: Bonneville Power Administration, USACE/USGS


The hydropower and PSH fleets provide substantial load-following flexibility

• The average shape of hydropower (including PSH) generation closely resembles the electricity load profile.

– In summer, hydropower generation tends to ramp up from early morning to late afternoon to meet air conditioning electricity use peaks.

– In fall and winter, hydropower generation typically displays two peaks coinciding with electricity demand use peaks in the early morning and early evening.

• The California market (CAISO) is the only one where high penetration of variable renewables (mostly solar) has notably changed the typical daily hydropower generation profile to date

– In CAISO, hydropower generation follows net load more closely than load.

Sources: ISO/RTO websites

Note: Plots for other ISO/RTOs are included in the 2017 Hydropower Market Report full document.

Average hourly hydropower and PSH generation, electricity load

and electricity net load by season (2014–2017)


In California, high penetration of variable renewables is likely driving changes in PSH operations

Annual pumping energy consumption by Helms PSH versus CAISO

net load in the last week of March (2012–2017)

Sources: Pacific Gas & Electric Company, California ISO

Note: Total MWh of pumping in 2014 and 2015 was reduced due to rotor replacement projects and other

planned outage work at Helms.

• Up until 2013, the bulk of pumping energy consumption at Helms PSH plant took place during night hours.

– PSH owners schedule pumping during the hours of lowest electricity demand and prices, which are typically at night.

• In recent years, during the early spring timeframe, net load and prices in California decrease considerably in the middle of the day because of a combination of low demand (due to mild temperatures) and strong solar production making it attractive for PSH owners to pump during the day.

– In 2016 and 2017, the number of daytime pumping hours at this time of year has surpassed night-time pumping.

– The energy stored during the day is then used to meet the substantial ramping requirements that arise during the early evening hours as solar production tapers down.


The median U.S. hydropower capacity factor has been 38.1% in 2005–2016, but it varies widely across plants

Sources: EIA Form 923, EIA Form 860, NHAAP

Note: Distributions based on average 2005–2016 plant-level capacity factors

Plant-level distribution of capacity factors (2005–2016)• Median capacity factor is

substantially lower for hydropower plants in the Southwest and Southeast than in the rest of the country.

• Older plants tend to display higher median capacity factors than newer plants.

– Consistent with highest quality sites having been developed first

• Facilities with the highest operational flexibility (peaking plants) tend to display capacity factors below the fleet-wide median.

• The fleet segment owned by wholesale power marketers displays the highest median, 10th and 90th percentile capacity among all owner types.


Interannual variability in median capacity factors is linked to hydrologic conditions

Sources: EIA Form 923, EIA Form 860, NHAAP

Plant-level distribution of capacity factors by year

• The highest median capacity factor (44.7%) corresponds to 2006 and 2011.

– Those two years were characterized by favorable hydrology in the Northwest and Southwest which together produce about two thirds of U.S. hydropower.

• Much of the most recent subperiod (2012–2016) has been affected by drought conditions in the West and displays lower median capacity factors.

– More data points are needed to determine the importance of factors other than hydrology (e.g., increases in unplanned hydropower unit outages) as drivers of long-run trends in capacity factors.


U.S. hydropower unit availability displays a slight decreasing trend in 2005–2016

Source: NERC GADS

Note: Operation and outage state definitions from the NERC Glossary of Terms: Forced Outage (unplanned component

failure or other conditions that require the unit to be removed from service immediately, within six hours or before the next

weekend), Maintenance Outage (unit removed from service to perform work on specific components that can be deferred

beyond the end of the next weekend but not until the next planned outage), Planned Outage (unit removed from service to

perform work on specific components that is scheduled well in advance and has a predetermined start date and duration),

Reserve Shutdown (a state in which the unit was available for service but not electrically connected to the transmission

system for economic reasons), Pumping Hours (hours the turbine-generator operated as a pump/motor), Condensing

(units operated in synchronous mode), and Unit Service Hours (number of hours synchronized to the grid).

This infor ation is fro the North A erican Electric Reliabilit Cor oration’s c-GAR software and is the property of the

North American Electric Reliability Corporation. This content may not be reproduced in whole or any part without the prior

express written permission of the North American Electric Reliability Corporation.

Percentage of U.S. hydropower fleet coverage for each unit size shown in the panel titles varies slightly year to year.

On average, 16% of U.S. hydropower units <=10 MW, 65% of U.S. hydropower units >10 MW and <=100 MW, and 76% of

U.S. hydropower units >100 MW reported data to NERC GADS in 2005–2016.

• A hydropower unit is available when it is connected to the grid or stands ready to connect as needed.

• A tradeoff between planned and unplanned outages is visible when comparing the change in availability factor for large and small units

– Average forced outage hours have increased over time across all unit sizes but most noticeable for small (<=10 MW) units

– For large (>100 MW) units, there have been increases in both planned and forced outages. Longer or more frequent planned outages are meant to prevent forced outages at times in which they would be most costly based on hydrologic or market conditions.

Average hydropower operational status by unit size


As a storage technology, a key PSH contribution to grid reliability stems from being ready to connect to the grid and meet demand peaks as they arise

Source: NERC GADS

Note: Operation and outage state definitions from the NERC Glossary of Terms: Forced Outage (unplanned component

failure or other conditions that require the unit to be removed from service immediately, within six hours or before the next

weekend), Maintenance Outage (unit removed from service to perform work on specific components that can be deferred

beyond the end of the next weekend but not until the next planned outage), Planned Outage (unit removed from service to

perform work on specific components that is scheduled well in advance and has a predetermined start date and duration),

Reserve Shutdown (a state in which the unit was available for service but not electrically connected to the transmission

system for economic reasons), Pumping Hours (hours the turbine-generator operated as a pump/motor), Condensing

(units operated in synchronous mode), and Unit Service Hours (number of hours synchronized to the grid).





On average, 53% of U.S. PSH units reported data to NERC GADS in 2005–2016.

Average pumped storage hydropower operational status

• The most common operational status for PSH units is Reserve Shutdown in which the unit is available but not connected to the grid.

• On average, PSH units reporting to NERC GADS spend less than half of the hours in a given year generating or pumping.

• Average planned outage hours per year for PSH units increased from 741 in 2005–2010 to 944 in 2011–2016.


Availability factor is highest in summer for both types of units

Capacity-weighted hydropower and PSH unit availability factor by season

Source: NERC GADS





On average, 28% of U.S. hydropower units and 53% of hydropower units reported data to NERC GADS in 2005–2016.

• Higher summer availability indicates that plant owners tend to schedule planned and maintenance outages in other seasons because hydropower’s contribution to meet summer peak demands is highly valuable.

• For hydropower units, the availability factor does not vary widely across seasons.

• For PSH units, availability factor is much higher in the summer than the rest of the year.

– The drop in summer availability in 2011–2013 is more indicative of a few units being out of service than a fleet-wide drop in average availability factor.


Hydropower’s ability to quickly adjust output following changes in net load makes it a key complement to the larger natural gas fleet in providing grid flexibility


Average and 10th–90th percentile interval for one-hour ramps per

installed megawatt for hydropower and PSH vs. natural gas by ISO/RTO• The average one-hour ramp

per installed megawatt for the hydropower fleet (including PSH) is larger than the average one-hour ramp from the natural gas fleet.

– This result is consistent across ramp types and markets despite there being significant differences in the sizes and composition of the hydropower/PSH fleets across ISO/RTOs.

• Hydropower adjusts its output up or down by more than 5% of its installed capacity more often than natural gas, especially in ISO/RTOs with large fractions of PSH in their fleet (e.g., PJM, MISO).


Hydropower performs more one-hour ramping “mileage” work per year than natural gas but its ramps are less correlated with net load

2014 2015 2016 2017

ISO Hydro Natural Gas

Hydro Natural Gas

Hydro Natural Gas

Hydro Natural Gas

CAISO NA NA 167.49 147.79 207.23 138.57 182.92 159.60ERCOT 144.24 207.10 170.51 193.53 308.45 194.93 *285.26 *167.63SPP NA NA 284.74 92.36 254.43 112.76 264.85 105.41MISO 344.29 113.09 232.95 132.83 362.11 150.35 376.64 139.39PJM NA NA *184.86 *66.96 366.59 125.00 396.69 144.54NYISO NA NA NA NA 309.72 161.16 278.63 176.24ISONE NA NA NA NA *109.62 *95.10 301.67 264.32

2014 2015 2016 2017

ISO Hydro Natural Gas

Hydro Natural Gas

Hydro Natural Gas

Hydro Natural Gas

CAISO 0.77 0.88 0.79 0.91 0.83 0.88 0.79 0.87ERCOT 0.19 0.83 0.20 0.87 0.27 0.88 *0.33 *0.86SPP NA NA 0.38 0.79 0.59 0.79 0.57 0.74MISO NA NA 0.40 0.91 0.43 0.91 0.39 0.84PJM NA NA *0.45 *0.80 0.48 0.79 0.50 0.82NYISO NA NA 0.62 0.84 0.66 0.85 0.64 0.83ISONE NA NA NA NA *0.46 *0.82 0.50 0.83


Ramping Mileage (One-Hour Ramps) for Hydropower and Natural Gas per

Installed Megawatt by ISO/RTO and Year

Correlation between One-Hour Ramps and Changes in Net Load for

Hydropower and Natural Gas by ISO/RTO and Year

Note: Ramping mileage is calculated by adding up all the ramps in absolute value over a year.

• Except for ERCOT in 2014 and 2015, total annual mileage per installed megawatt is larger for hydropower and PSH than natural gas in all ISO/RTOs.

– Low values for ERCOT in 2014–2015 can be traced back to low hydropower generation during those years in that market.

• The lower correlation between one-hour ramps and net load exhibited by hydropower is likely due to competing uses of reservoir space or water flows influencing the timing of ramps.


PSH units typically start more than once per day; for hydropower units, the median number of starts increases with unit size

Source: NERC GADS





On average, 16% of U.S. hydropower units <=10 MW, 65% of U.S. hydropower units >10 MW and <=100 MW, 76% of

U.S. hydropower units >100 MW, and 53% of PSH units reported data to NERC GADS in 2005–2016.

Unit start distributions by year, unit type, and unit size • The stark differences in typical number of unit starts across unit types reveal substantially different modes of operation.

• Median number of unit starts in 2005–2016:

– 8-12 for small (<10 MW) units; equivalent to roughly one start per month

– significant increase in 2013-2016 for medium (10MW-100MW) units likely reflecting differences in composition of the sample rather than a significant trend in number of starts

– more than once per week on average for large units (>100 MW)

– more than one per day on average for PSH units

• decreasing trend in 90th percentile number of starts


5. Trends in U.S. Hydropower Supply Chain


At least 223 hydropower turbines with a combined capacity of almost 9 GW have been installed in the United States since 2007

Sources: Industrial Info Resources, NHAAP

Annual installations of hydropower turbines in the United States by manufacturer

• 74% of the new units correspond to unit additions, replacements, or major R&U projects at existing hydropower plants.

• Three turbine manufacturers (Andritz, GE Alstom, and Voith) accounted for 83% of tracked installed turbine capacity and 67% of installed units during this period.

– They manufactured 90% of installed units greater than 10 MW.

• Based on the location of manufacturing facilities of each company, it can be estimated that machining and assembly operations were performed domestically for at least 50% of installed turbines.

Overhaul of

Ludington PSH

turbines (Toshiba)


For turbines installed at existing facilities, Francis is the most common type. Kaplan turbines were used in 54% of installations at new plants


• Kaplan turbines are well suited for low-head sites which are majority amongst newly developed projects.

• Other manufacturers mostly specialize in small units.

• The bigger manufacturers appear to focus on R&U of existing larger units where they see more business potential in the United States.

– For large units, each design is highly customized and only a handful of manufacturers have the infrastructure required to machine and assemble them.

– In the small turbine segment, the trend is toward standardization that will enable cost reductions.

Installed hydropower turbines in the United States

by type and manufacturer (2007–2017)


Since 2013, U.S. hydraulic turbine export value has been increasing while import value has decreased


• Much of U.S. hydropower turbine trade is conducted with neighboring countries.

– Trade with Canada is strong in both directions.

– Exports to Mexico have gone from very small to representing 10%-15% of total export value since 2012.

• Turbine imports from Europe have decreased significantly over the last two decades.

– 50% of turbine import value originated in Europe in 1996–2000 versus less than 30% since 2006.

• China has stopped importing U.S. turbines and has become the source of 30% of U.S. turbine import value during the last 3 years.

U.S. hydropower turbine import and export values by country


6. Policy and Market Drivers


Multiple legislative proposals to modify the hydropower authorization process are under consideration

Bills introduced in the 115th U.S. Congress (2016-2018)

Objective Status as of 12/31/2017*

H.R. 3043 (Hydropower Policy Modernization Act of 2017)

Designate FERC as leading agency in licensing process for purposes ofcoordinating all federalauthorizationsandcomplyingwith NEPA; improve thetrial-type hearingprocess to resolve disputes about license conditions; improve study portion of licensing process through compilation of bestpractices and avoidance of duplicativestudies; streamline process for obtaining license amendments associated with qualifying project upgrades

Passed House

H.R.2274 (Hydropower Permit Extension Act or HYPE Act) and S.724

Extend maximum duration of preliminary permits (four years instead of current three-year duration with possibility of an additional four-year renewal if adequate progress is shown); extend maximum time allowed for FERC-authorized projects to start construction (up to eight years instead of current two-year period)

Passed House (H.R. 2274);Introduced in Senate (S.724)

H.R. 2872 (Promoting Hydropower Development at Existing Nonpowered Dams Act)

Establish an expedited licensing process for nonfederal hydropowerdevelopment at NPDs (two years or less from license application to final licensedecision); identify the NPDswith the greatest potential for development

Passed House

H.R. 2880 (Promoting Closed-Loop Pumped Storage Hydropower Act)

Establish an expedited licensing process for closed-loop PSH projects (two yearsor less from license application to final license decision); explore opportunitiesfor development of closed- loop PSH projects at abandoned mine sites

Passed House

S. 1029 (A bill to amend the Public Utility Regulatory Policies Act of 1978 to exempt certain small hydroelectric power projects that are applying for relicensing under the Federal Power Act from the licensing requirements of that act)

Allow small projects(a) <10MWor(b)<15 MWlicensedafter 1991 and notlocated in critical areas for EndangeredSpecies Act (ESA) species to switch fromlicense to exemption during the relicensing process

Introduced

H.R. 2786 (To amend the Federal Power Act with respect to the criteria and process to qualify as a qualifying conduit hydropower facility)

Reduce time for FERC decision in applications for qualifying conduit status(from 45 days to 30 days after public notice of developer’s intent) andexpand the size limit for qualifying conduits

Passed House

H.R. 1967 (Bureau of Reclamation Pumped Storage Hydropower Development Act)

Amend Reclamation Project Act of 1939 to authorize nonfederal PSHdevelopment in projects where all reservoirs are under Bureau of Reclamationjurisdiction

Passed House

* At the time of publication of this report (end of April 2018), the status of these bills remain unchanged.


The landscape of federal and state incentives available to hydropower owners or developers has changed in recent years

• Several federal incentive programs have expired.

– Renewable Electricity Production Tax Credit (PTC) and Business Energy Investment Tax Credit (ITC)

• The Renewable Electricity Tax Credit Equalization Act [H.R.4137] introduced in 2017 proposes restoring PTC and ITC eligibility for hydropower.

– Build America Bonds (BABs) and Clean Renewable Energy Bonds (CREBs) are no longer available to support public financing of hydropower projects.

• Other federal incentives remain in place.

– Hydropower projects in rural areas are eligible for loans or grant support under several US Department of Agriculture programs.

– Awards under Section 242 of the Energy Policy Act of 2005 to developers of NPD and conduit projects for the first 10 years after development

• These are direct incentive payments equivalent in magnitude to the PTC up to $750,000 per year per project.

• From 2014 to 2017, 63 hydropower projects have received a total of $14.1 million in Section 242 payments.

• State renewable energy policies can be a significant source of value for qualifying hydropower projects.

– Renewable energy credits (RECs) from some of the 29 state-level Renewable Portfolio Standards (RPS) in place provide an additional revenue stream for qualifying hydropower projects but

• Many RPS programs limit hydropower eligibility by size, age, or type criteria.

• REC values in the Northeast have recently fallen sharply (e.g., the value of Class I RECs in Massachusetts went from $60 in 2015 to $20 in 2017).


Upcoming potential changes in policies related to Canada and its hydropower resources could impact the value of U.S. hydropower for decades to come

• Renegotiation talks for the Columbia River Treaty are expected to start in 2018 and can have important consequences for the operation of the Columbia River Power System and Western electricity markets.

– The Columbia River Treaty was implemented in 1964 to coordinate U.S.-Canada water resource decisions in the Columbia River basin for flood control and hydropower generation optimization.

– One of its original provisions established the “Canadian entitlement” by which the United States pays Canada 50% of the incremental downstream power benefits created by Canadian storage reservoirs ($200M-$350M per year) as compensation for the flood control benefits they provide to the United States.

• the United States seeks to revise this provision arguing that power benefits are being overestimated.

• Multiple transmission line projects to import additional Canadian hydropower are in various stages of permitting and development.

– The Great Northern Transmission Line (883 MW) in Minnesota is the most advanced; preconstruction activities started in 2017.

– At least one of several transmission projects in the Northeast is likely to be constructed in the next few years backed by recent requests for proposals by Massachusetts and New York for procurement of large scale renewables.


7. Conclusions

• Hydropower represents 7% of U.S. electricity generation capacity and PSH provides 95% of utility-scale electrical energy storage capacity.

• U.S. hydropower and PSH capacity increased by more than 2 GW each from 2006 to 2016.

– Most of the capacity increases resulted from capacity additions to the existing fleet or additions of hydropower generation to NPDs and conduits.

• Based on the project development pipeline and planned R&U investments as of the end of December 2017, it is expected that U.S. hydropower capacity will continue growing through a combination of upgrades to the existing fleet, NPD, and conduit projects.

– NPD projects account for 92% of proposed capacity; the success of recent initiatives to improve the efficiency of the authorization process for this type of project is crucial.

– Continued R&D to reduce the cost of developing low-head sites is important as they constitute a large fraction of remaining potential sites.

• Two PSH projects (Eagle Mountain in California and Gordon Butte in Montana) have received FERC licenses and could become the first new large U.S. PSH facilities in more than 20 years

– In contrast, dozens of PSH facilities have been built in the last decade in other regions of the world (mostly East Asia and Europe).

– Most proposed PSH projects are closed-loop and their median size has decreased in recent years.


7. Conclusions (II)

• Beyond providing generation and storage capacity, hydropower and PSH contribute to grid flexibility and reliability through significant ramping capability and provision of ancillary services.

– For hydropower, year-to-year variability in generation volume is tightly linked to hydrologic conditions; no visible trend in generation volumes emerges from 2003–2016 data.

– For PSH, there has been a slight decrease in gross generation volumes in recent years.

• An important question is whether this decline responds to a decrease in peak/off-peak price differentials or to a change in mode of operation whereby PSH owners dedicate more hours/more capacity to provision of grid services.

– The non-hydropower competing purposes of storage reservoirs and water flows influence seasonal distribution of hydropower generation throughout the year and constrain the timing of ramping; PSH generation correlates more closely with electricity use patterns than hydropower.

• Increases in O&M costs per kilowatt installed and declines in unit availability are challenging trends for the U.S. hydropower fleet.

– Both of these trends are more pronounced for small hydropower plants.

• Hundreds of small hydropower plants have changed ownership since 2004 and companies are emerging whose expertise and focus are geared towards controlling costs and improving the performance of these plants.

– Ageing workforce, compliance with increasingly stringent regulatory requirements and declining quality assurance/quality control of equipment are among the likely causes for the O&M cost increases .

– For large units, a significant fraction of the decrease in availability responds to longer/more frequent planned outages to conduct preventive maintenance that will avoid costlier forced outages.

• An increased need for preventive planned outages results from a combination of ageing assets and, in some regions, changes to mode of operation involving more frequent ramping and starts/stops.


Technical notes

Slides 8 and 10:

* Pending Permit includes projects pending a preliminary lease in the LOPP process and projects pending issuance of a preliminary permit. Issued Permit includes projects that have received a preliminary lease in the LOPP process, projects that have obtained a FERC preliminary permit, and projects with an expired preliminary permit but that have submitted a Notice of Intent to file a license or a draft license application. Projects in the Issued Permit stage have high attrition rates.

** Pending Application includes projects that have applied for an original FERC license or a FERC exemption or have requested to be considered a “qualifying conduit” hydropower facility by FERC. Issued authorization includes projects that have been issued an original FERC license or FERC exemption, have been approved by FERC for “qualifying conduit” hydropower status, or that have received a final lease contract under the LOPP process.

Slide 11:

• The full value of each project is assigned to the project start year. The green portions of the bars correspond to projects that have not yet been completed as of December 2017.

• Minimum total investment value of projects tracked by Industrial Info Resources (IIR) is $1 million.

Documents

2017 Hydropower Market Report - HydroSource€¦ · • The 2017 Hydropower Market Report provides objective, publicly available, comprehensive information on U.S. hydropower. –