We’ve reached a coal cost crossover with renewables – now what?

We’ve reached a coal cost crossover with renewables – now what?

A new analysis released today from Energy Innovation and Vibrant Clean Energy (VCE) indicates we’ve reached a coal cost “crossover” in the United States.  Due to recent rapidly declining wind and solar costs, the combined fuel, maintenance, and other going-forward costs of most existing coal plant generation is now more expensive than the all-in costs of new wind or solar projects.

Click here to view a high resolution image.
Click here to view a high resolution image.

The analysis is simple, but compelling.  Similar to pioneering analysis in Colorado, our analysis compared going-forward operating costs of coal plants to the levelized cost of energy (LCOE) for new wind and solar within 35 miles of the plant.  The analysis raises substantial questions for policymakers and utility stakeholders across the U.S.:

  • Would replacing existing coal with new wind or solar immediately result in cost savings for customers?
  • What are the financial implications of billions in uneconomic assets on utility books?
  • To what extent can local renewable resources also replace tax revenues, jobs, and provide economic development to coal plant communities?
  • What institutional and regulatory barriers are preventing the retirement of these uneconomic assets?

The analysis suggests local decision-makers should consider plans for smoothly shutting down these uneconomic plants—assessing options for reliably replacing that electricity.  Ultimately, this report begins a longer conversation about the most cost-effective coal replacement, which may include combinations of local or remote wind, solar, transmission, storage, and demand response.

The method

To determine which coal plants are facing this cost crossover with renewables, Energy Innovation partnered with VCE to compile a national dataset of coal, wind, and solar costs. For simplicity, the modeling compares each coal plant’s marginal cost of energy (MCOE) to the lowest LCOE of a wind or solar resource within 35 miles of that coal plant. Restricting replacement to local resources makes this analysis conservative, considering most coal, wind, and solar all travel from more remote locations to load centers via transmission.

VCE leveraged its uniquely granular data on wind speed and solar irradiance, creating high-resolution maps of 2018 wind and solar LCOE.  These were used as the basis for comparing coal plants with local wind and solar, taking federal tax credits into account.

The map above illustrates the levelized cost of wind energy in 2018. Click here to view a high resolution image.
The map above illustrates the levelized cost of solar power in 2018. Click here to view a high resolution image.

2025 LCOE figures were based on costs in the National Renewable Energy Laboratory (NREL) Annual Technology Baseline low cost case. 

The map above illustrates the levelized cost of wind energy in 2025. Click here to view a high resolution image.
The map above illustrates the levelized cost of solar power in 2025. Click here to view a high resolution image.

Coal MCOE data were extracted from different publicly available sources, including Energy Information Administration generator data and FERC Form 1 utility filings.  Because such data can be inaccurate and inconsistent, there is unavoidable uncertainty around the exact MCOE of each coal plant. 

The findings

Our research finds that in 2018, 211 gigawatts (GW) of existing (end of 2017) U.S. coal capacity, or 74 percent of the national fleet, were at risk from local wind or solar that could provide the same amount of electricity at a lower cost. By 2025, at-risk coal increases to 246 GW – nearly the entire U.S. fleet.

Furthermore, 94 GW of existing U.S. coal capacity was deemed “substantially at-risk” from new local wind and solar in 2018, meaning these renewables could undercut ongoing costs of existing coal by at least 25 percent. By 2025, substantially at-risk coal increases to 140 GW – almost half the U.S. fleet – even as federal renewable energy tax credits phase out. Even given uncertainties in publicly available coal cost data, the tier of coal plants “substantially at-risk” could, with high confidence, be replaced with renewable energy at an immediate cost savings.

MW RE Cost Wind (2018) Solar (2018) Wind (2025) Solar (2025) Combined (2018) Combined (2025)
Coal substantially at risk >25% less than coal 49,165 69,117 75,778 111,077 93,812 140,073
Coal at risk 0-25% less than coal 118,085 178,871 167,201 229,001 210,842 246,306
Coal potentially at risk 0-25% more than coal 168,563 107,777 119,447 57,647 75,806 40,342
Coal deemed safe >25% more than coal 101,792 49,620 46,289 15,706 21,608 7,866

The VCE dataset reveals the going-forward costs for the vast majority of coal plants fall between $33 – 111 / megawatt-hours (MWh). 2018 solar costs are more tightly clustered, between $28 – 52 / MWh, while wind costs vary more widely from $13 – 88 / MWh based on locational resource quality, with a high number of very costly outliers in windless regions.

Putting the findings in context

The cost crossover between new renewables and existing coal is just one important part of shutting down obsolete coal plants – replacing uneconomic plants with new wind and solar energy is much more complex in practice. This report acts as a conversation primer for stakeholders and policymakers where the math points to cheaper options that could replace coal plants at a savings to customers now. Any decision on how to proceed will require further modeling of grid needs and reliability services, as well as the cost of potential renewable replacements outside of the 35-mile maximum radius considered in this report.

The first step for merchant owners, utilities, regulators, and other stakeholders is taking a hard look at coal retirement. For regulated utility assets, integrated resource plans (IRP) and other long-term planning analytical efforts should always include coal retirement scenarios. Indiana utility NIPSCO has shown how smart analysis can flip planning directions: Their most recent planning effort recommended replacing all their coal in the next decade with renewable energy, including wind and solar, along with battery storage. Consumer advocates elsewhere should be asking whether coal plants receiving state-regulated cost recovery but operating in transparent, competitive regional energy markets should be allowed to run at loss to the detriment of consumers’ pocketbooks.

Consumer advocates faced with utility inertia, environmental advocates concerned about unpriced coal externalities, and advanced energy solutions providers eager to open opportunities can push back against reliability or dispatchability arguments simply by comparing economics. The cost of any single coal plant compared with a combination of local (or distant but easily accessible) renewables and complementary demand-side and storage resources, or virtual power plants (VPP), can make a powerful case. If a VPP drop-in replacement also proves more economic than an at-risk coal plant, it can provide an estimate of the minimum savings available from coal plant retirement.

A more holistic approach leveraging other existing assets on the grid can prove to be even cheaper for integrating low-cost renewables. For example, a VCE study showed how Colorado could replace all its aging coal plants with a mix of wind, solar, natural gas, and storage to save the state’s electric customers more than $250 million annually without affecting reliability. This example is especially notable in the context of the coal cost crossover analysis, because Colorado appears on the tail end of states with coal plants at risk from renewables within 35 miles.

In fact, our cost crossover analysis flags fewer Western plants as at-risk than the reality.  High-quality wind resources in the $15 – 25 / MWh range are often accessible through existing and new large transmission projects in the West, and the hyper-local nature of this analysis leaves these options on the table. Understanding the geographic dimensions of renewable costs – the opportunities visible in our maps – and proper modeling are therefore key to planning analysis and decision-making.

Different approaches in different markets

Depending on the market, it may be particularly important to consider not just at the MCOE of a given coal plant, but also at the remaining balance of long-term costs. This is especially true for coal plants in vertically integrated jurisdictions, which dominate the Southeast and West, and in hybrid setups where coal plants participate in wholesale markets but long-term costs are covered by ratepayers (e.g. many states in Southwest Power Pool and Midcontinent Independent System Operator). Customers are on the hook for these costs; if an at-risk coal plant retires but is not paid off, significant incremental savings await ratepayers, especially if the remaining amortization balance can be refinanced at a lower cost than typical utility rates of return.

In restructured markets, particularly PJM Interconnection and ERCOT, market design matters.  ERCOT has already seen a rapid movement away from coal, as the energy-only market design has allowed new gas and wind to force out high-MCOE coal plants while maintaining reliability.  But in PJM, capacity market revenues are keeping these “zombie” coal plants around.  The swath of red circles in the Ohio Valley signal that those market institutions, not just economics, are creating artificial barriers to coal exit and renewable entry.

Starting the conversation

Stakeholders are beginning to break through on coal retirement arguments by showing coal can be replaced by new wind and solar at immediate savings, but it hasn’t been easy.  Leadership from the Sierra Club and others in the Northwest led Pacificorp to analyze and ultimately release an analysis deeming half of its coal plants were uneconomic compared to new renewables.  In Colorado, a consortium of NGOs analyzed coal versus renewables economics, providing a strong case for proposed legislation that finances a faster transition away from these assets.  NIPSCO’s integrated resource planning process is following a similar track.

In each case, quantitative analysis of these coal plants compared to new options formed the basis of a larger retirement conversations.  Similar analysis can be a starting point to identifying the most at-risk plants, though more in-depth examination of coal plant numbers, particularly with utility assistance, can facilitate a more transparent, inclusive dialogue.  In a separate set of reports, APP experts Ron Lehr and Mike O’Boyle lay out a more comprehensive suite of options to balance consumer, community, environmental, and utility concerns through this financial transition.

Making the most of DER: international insights for regulating transformation in distribution networks

A Q&A with Dr. Gabrielle Kuiper was published on Forbes on March 5, 2019.

How do you create policy and regulation for a complex multi-way energy system to fast-track emissions reductions and improve consumer outcomes?
In October 2018, America’s Power Plan Director Mike O’Boyle team had the pleasure of meeting with Dr. Gabrielle Kuiper, who was awarded a Churchill Fellowship from Australia to visit North America and Europe to search for answers to this question, especially the regulation of distribution networks.  Since that meeting, Dr. Kuiper has interviewed dozens of experts and regulators from leading regions around the world, including New York, the United Kingdom, Canada, France, the European Union, and Norway.
Kuiper recently released her report on this topic, with insights and recommendations highly consonant with America’s Power Plan.  Dr. Kuiper’s research shows that international regulators are exploring many of the policies U.S. states find suitable to maximize cheap but variable renewables, take advantage of demand flexibility, and reshape utility business models away from capital intensity toward system optimization. For example, the report finds the U.K., E.U., and Norway are exploring models for optimizing demand-side resources through a distribution system operator model, similar to (and in some cases inspired by) New York’s Reforming the Energy Vision (REV) process.
Here are some other key policy recommendations coming from international regulators and experts:

  • The need to revise the role of the distribution utility into a distribution system operator and optimizer (DSO).  This is a live, but nascent, conversation in each jurisdiction Dr. Kuiper visited, including the European Commission, which is requiring member states to develop flexibility markets through their DSOs.
  • Distribution system planning.  Like many U.S. states, the U.K. and Norway are updating system planning to include flexible demand and other non-wires solutions.  Norway provides a case study for integrating high levels of electrification into these plans.
  • Performance-based regulation (PBR) as a key tool for balancing societal and customer outcomes.  The UK is refining its approach to PBR after RIIO (Revenue = Incentives + Innovation + Outcomes) led to improved consumer outcomes but very high utility windfalls. Norway, the UK, and Ontario are using benchmarking to evaluate the performance of their distribution utilities.
  • Benefits valuing distributed energy resources based on time and location.  The European Commission’s Clean Energy Package puts time-varying rates at its center by giving customers a right to aggregate their services to the wholesale market, access dynamic pricing, self-generate, and access a smart meter.

In addition, Kuiper evaluated what regulatory reform characteristics make for a successful alignment of public policy objectives and utility regulation. Kuiper found that at the outset of reform efforts, clear leadership, and vision articulated by a legislator and regulator, is necessary to drive the process toward meaningful reform.  Once goals are set and articulated to the relevant agencies, other important regulatory design characteristics include transparency, robust stakeholder participation, and flexibility and agility in regulatory decision-making.
These models help to put some perspective on ambitious reforms in the U.S., like REV and California’s Distributed Energy Resources Action Plan.  Though these models are resource intensive and not replicable in many states today, resonance with international markets facing similar policy and technological shifts indicates they are being followed by other outside the US.  But having additional models can help regulators figure out what approach might fit them best – so we invite you to dig into Dr. Gabrielle Kuiper’s research!

Energy Storage: Still Waiting for Markets to Catch Up

A version of this article was published on Greentech Media on January 24, 2019.

By Eric Gimon

Energy storage is surging across America.  The U.S. Energy Storage Monitor Q4 2018 report estimates 338 megawatts (MWs) of installations in 2018, growing to 3.9 gigawatts (GWs) by 2023, much of it “front-of-the-meter” utility-scale projects.

However, this exponential growth has mainly been driven by state mandates and regulatory actions (especially in California) or limited to vertically integrated utilities operating outside of organized power markets, which serve two-thirds of all U.S. electricity consumers.  Despite the value storage can provide the grid, it has not found matching success in wholesale markets.

The reason behind this mismatch is best captured in two words: rules and revenue.  Wholesale market rules are organized around legacy assets, restricting storage from selling all its potential services if owners were able to operate in the most advantageous ways.  These rules in turn limit storage’s wholesale revenue streams.

Last February, recognizing these barriers, the Federal Energy Regulatory Commission (FERC) issued Order 841 to stimulate access to U.S. wholesale markets.  At the end of 2018, FERC-regulated independent system operators (ISO) responded by submitting their implementation plans.

The Energy Storage Association (ESA) provided a helpful overview of these proposals (see chart), and further filtering comments by affects upon possible revenue streams for storage provides additional insight.


Source: Estimation by Customized Energy Solutions, Ltd.
*Topic letters and numbers correspond to layout of Order 841
**Green: Likely compliant; Yellow: Potentially non-compliant; Red: Non-compliant

Storage can generate revenue in America’s organized power markets three ways: platforms, products, and pay-days.  Because different projects tap these potential revenue streams in different ways, implementation plans for Order 841 will affect them quite differently, so let’s follow this taxonomy.

Platforms: The Best Laid Plans…

ISOs conduct planning processes that identify opportunities for new transmission to improve reliability or market efficiency, and storage is increasingly being considered as a reliability asset as a lower-cost, non-transmission alternative to boost reliability.

Here’s an example: A relatively isolated area on the grid must plan for losing a transmission line or local generator during peak demand.  Rather than adding new transmission or local generation, building a storage project can carry a local grid through an emergency.  If the economics add up, the project can then be built and paid on a cost-of-service basis financed through regulator-approved transmission charges.

Storage in this example plays the same role as transmission for so-called “reliability transmission expansion,” but it can also play the role of “economic transmission” – transmission built to move surplus energy to constrained areas to create benefits (reduced prices) for market buyers and sellers.  This was part of the vision of Order 1000, which required regional transmission operators (RTOs) to consider “non-transmission alternatives” as part of their planning process.  But to date, only one economic storage-as-transmission project exists within U.S. ISOs, located near Baltimore on the PJM grid.

ISOs have hesitated to fund such projects because while “reliability” storage is tied to a definite risk of grid emergency which determines how it will be used, “economic” storage requires instructions from the ISO about when to buy and sell power.  ISOs worry this could challenge their market independence since how they dispatch storage invariably affects prices, which could make them look like self-dealing market participants.

However, ISOs already regulate power flow over transmission, which certainly affects power prices.  When ISOs propose a new transmission project to relieve congestion in an area of the grid with high demand (and thus high prices), local generators are first in line to complain about lost revenue.

What preserves ISO independence in these cases is a combination of transparent cost-benefit-analysis and security constrained economic dispatch with financial transmission rights – a standard methodology for fairly moving power across transmission lines and distributing revenue from arbitraging local price differences.  Markets can dispatch storage in similar ways, according to the transparent optimization, and assign financial storage rights to whomever paid for the storage.  Like transmission, storage would essentially become “open access,” for the benefit of consumers.

Even as storage provides similar services, it must consider benefits over transmission like ease of siting compared to transmission siting and permitting, which can take years to resolve, depending on the proposal’s complexity.  For example, it only took Tesla six months to construct and put into operation a 100 MW storage facility in South Australia providing reliability services comparable to transmission upgrades and saving customers $40 million in one year.

Storage-as-a-Transmission-Asset (SATA) is very much in its infancy, with almost all the focus on its possible role as a reliability asset.  ISOs seem to have had very little to say on how Order 841 will shape this potential revenue stream – but this is a space to watch.

Products: Fee for Services

While ISOs are uncomfortable paying for storage services through transmission access charges that passively incorporate storage into the grid, some have been receptive to storage competing to provide fixed services like fast frequency response, capacity, or regulation that projects can provide on a technology-neutral basis. But technological neutrality may not be achievable in many cases where services were defined before batteries and other clean technologies like renewables changed the game.  Order 841 was meant to push open this door, but implementation plans still leave much to be desired.

Source: Lazard Levelized Cost of Storage 4.0 (2018) https://www.lazard.com/media/450774/lazards-levelized-cost-of-storage-version-40-vfinal.pdf

Theoretically, fitting storage into technology-neutral products should be simple.  But storage resources are energy-limited (they can’t just convert fuel to electricity forever), they must be charged and take more energy to charge then they provide back, and they may be entirely driven by power electronics (no spinning inertia).

These differences mean existing market product definitions are often ill-suited to include storage.  And while most incumbent participants often provide ancillary services for just a fraction of their revenues, storage projects dedicated to a single service (such as regulation) could have their entire business model upended by simple rule changes.

Storage resource attributes like how fast they can change their output, their ability to reduce air pollution, or the quick and modular pace at which they can be deployed, are not always valued in markets.  These attributes provide grid benefits but need revised power market rules to be properly valued.  The standard equivalence for utilities between batteries and natural gas peakers seems to require a 1:4 power ratio, i.e. a 1 MW/4 megawatt-hour (MWh) battery.

Impact of 4-hour storage dispatch on net load in California on the peak demand.

Source: National renewable energy Laboratory, 2018. https://www.nrel.gov/docs/fy18osti/70905.pdf

However, shoehorning batteries into definitions based on other technologies is not necessarily economically efficient – some peak needs may last longer, some may be more sporadic, and others will change over time with the economics of generation sources.  A battery’s highest value application may involve a portfolio including different power ratios.

Incremental peak demand reduction credit as a function of storage capacity in California using 2011 data.

Source: National Renewable Energy Laboratory, 2018. https://www.nrel.gov/docs/fy18osti/70905.pdf.

Collecting storage revenue by providing grid-needs through products aspiring for technology neutrality will always depend on the fine print.  But shaping these products will be an uphill battle without proactive support from regulators and market operators.  As a new competitive entrant to most markets, storage – especially battery storage – is not always in the best position to make sure rules value them at their best.

Consider PJM’s approach to incorporating storage into its capacity performance model.  They propose that storage systems only qualify for capacity payments if they can provide ten hours of storage, a duration that severely disadvantages battery storage economics, even though it may provide much-needed capacity over shorter timescales.

Pay-days: Profiteer or Just an Independent Businessman?

One way for storage resources to avoid being shoehorned into the wrong glass slipper is to compete directly in energy markets.  What could be simpler than arbitrage: buy low, sell high?

Unfortunately, today’s markets just don’t provide enough revenue this way.  Consider daily wholesale electricity price differentials in two ISOs with the most market spikes, California’s CAISO and Texas’ ERCOT, where crudely estimated annual revenues from buying low and selling high each day (with no roundtrip losses) come out to $10-20 per kilowatt-hour (kWh) of storage capacity per year, not quite enough to be in the money yet but close to some of the prices we see coming out of vertical utilities like NV Energy’s recent announcement to add 100 MW of battery storage.

The closer to a real-time market storage operates in, and the higher the power ratio, the more revenue is available from arbitrage.  For example, a battery storage unit with a 4:1 power ratio (4MW to 1 MWh) and 20 percent round-trip losses operating in the 2017 Houston load-zone real-time market could make as much as $57/kWh-year.  This system would likely cost $300-400/kWh plus some extra costs associated to the high power ratio, making it a possibly attractive investment, especially with high prices expected across ERCOT in coming summers.

This contrasts with other ISOs with lower price differentials, and thus highlights the efficiency with which energy-only power markets can point to where investments have the most value.

Even if energy arbitrage revenues become sufficient to support storage investments, today’s markets still maintain some barriers.  In ESA’s analysis of Order 841 compliance plans for participation models, bidding parameters, and state-of-charge-management, almost all the ISOs failed to fully comply.

Today’s Energy Storage Opportunity, Tomorrow’s Energy System Disruptor

Storage has jumped from tomorrow’s clean technology to one of today’s regulatory agenda drivers, but the industry’s true potential has yet to be tapped, especially as it covers multiple value streams.

Storage projects are innately well-suited to access multiple value streams.  A clever storage operator in ERCOT will switch between bidding into ancillary regulation markets one day to arbitraging energy price in another day for maximum revenue potential.  But Order 841 compliance proposals can make this type of switching problematic.

Like many leading ISOs, ISO-NE co-optimizes energy and ancillary markets, obviating the need for participating resources to figure which market they should bid in for best revenues.  Theoretically, this arrangement should help storage economics, but instead ISO-NE rules for ancillary markets force resources to “de-rate” (i.e. pretend they can only run at a lower power output) whenever they are bid in the energy market.  This prevents a battery from squeezing out as much output as possible during system peak because it must maintain the ability to provide a full hour of output on the back side of that peak (when it is less necessary) to satisfy ancillary market rules.

These type of issues illustrate how disruptive storage can be to existing market paradigms.  As more and more storage comes online, ISOs will need to evolve through new rules and market structures to accommodate the technology’s potential – and make a better showing of implementing FERC’s Order 841 – in order to maximize benefits for today’s electricity consumers.

Steel for Fuel: Hitting the Sweet Spot on Risk, Return, and Scale for Investors and Customers

A version of this article was published on Greentech Media on December 7, 2018.

By Ron Lehr and Mike O’Boyle

On December 4, two major utilities – Pacificorp and Xcel Energy – made startling announcements indicating that U.S. coal is truly dying or dead.  Pacificorp’s own analysis of its coal fleet indicated that rapid retirement of a majority of the coal capacity would save customers money, while Xcel Colorado announced its intention to reduce its carbon emissions by 80 percent from 2005 levels by 2030, going carbon-free by 2050.

Fast-falling costs of new wind and solar plants precipitated this trend – in 2018 they are already cheaper than operating many fossil generation plants.  Under these conditions, utilities face a dilemma: Retiring coal units early for economic reasons benefits consumers, but shareholders lose an earning opportunity.

But this clean energy transition, if managed well, creates opportunities for utility managers to reduce risks and increase shareholder earnings.

With regulatory approval, utilities may increase equity earnings by shifting capital from uneconomic generation plants requiring very large fuel inputs toward plants that run on free fuel, such as solar and wind.  Xcel Energy, an eight-state utility holding company that has cut carbon emissions 35% since 2005 and targets 55% renewable energy by 2026, branded this strategy “steel for fuel.”

Stakeholder perspectives on steel for fuel

Utility operating cost savings derived from substituting “steel” in the form of new wind and solar generation for “fuel” costs passed along in rates that powers aged, obsolete and uneconomic power plants can provide substantial savings to customers.  And if unpaid investments in early-retired plants are refinanced with securitized or ratepayer-backed bonds, consumers can reap substantial additional savings for paying off obsolete investments.

Once constructed, operating a fossil plant requires continuous fuel supply and delivery.  Fuel costs commonly constitute a large portion of consumers’ bills, treated as an expense for regulatory recovery and usually passed through to consumers through line items on consumers’ bills known as energy or fuel cost adjustments.  Reducing the fuel portion of consumers’ bills also helps to insulate them from fuel cost volatility, risks, and potential liabilities.

For shareholders, early plant retirements with unpaid investment balances left on utilities’ books can threaten earnings per share and share price values, unless regulators agree to allow unpaid investments to be paid by consumers by creating “regulatory assets” – but these unproductive assets carry the risk that regulators could change their minds about whether to allow recovery “of and on” these assets.

Turning this unproductive capital into productive, clean generating assets can simultaneously address shareholder risks and benefit customers and the environment.  This financial transition involves careful consideration of a range of factors examined in a series of issue briefs from America’s Power Plan, including how and which utility costs are recovered, how depreciation schedules for uneconomic assets are adjusted, whether undepreciated retired plant investment balances can be refinanced with cheaper capital from corporate debt or ratepayer-backed bonds, and a more detailed brief addressing equity shareholder perspectives in trading steel for fuel.

Utility Investment Incentives– “Steel for Fuel” Risks, Returns, and Scale

Utilities create value for their shareholders when regulated returns on investment, determined in each rate case, exceed capital costs invested to create returns.  Investment risk, return, and scale can be analyzed to determine whether utility investments create value for shareholders.

Risks like regulators disallowing rate recovery due to asset mismanagement can create or destroy value by impacting returns investors require to account for risks.

While risk and return are commonly analyzed to determine profitability, investment scale also impacts investment risk.  When determining the value of “steel for fuel” investments, early results show the scale of renewable project investments can be substantial enough to maintain or improve shareholder outcomes, more than offsetting investments remaining in early retired fossil plants.

For example, Xcel’s Rush Creek Wind Farm investment, and related transmission infrastructure, will total about $1.2 billion, larger than undepreciated investments remaining in its retired coal plants.  Xcel’s approved plan to retire two coal plants at Pueblo included new clean energy investments of about $2.5 billion.

The risks of investing in new wind and solar projects are common to all generation projects, including future demand uncertainty, site selection and development, technology obsolescence, project financing, construction and commissioning, transmission interconnection, and operations.  In addition, solar and wind projects are subject to resource assessment risks, wildlife impacts, system integration and operations costs, and weather and resource forecasting for system planning and operations.  For utilities that engage in “steel for fuel” transition, these risks are likely to decline as project developers learn through continued deployment of these resources and financial risks decline with experience.

Reliance on large, centralized generation plants dependent on considerable fuel inputs is shifting with new economic and policy realities of renewable energy.  Numerous utilities including Southern CompanyXcel EnergyConsumers EnergyDTE, and MidAmerican, have voluntarily announced that they will rapidly adopt a clean energy or low-carbon portfolio, often accelerating coal plant retirements at significant savings to customers.  “Steel for fuel” is an increasingly appealing method for hitting the sweet spot on risk, return, and scale for investors.

Utility Options– Moving from “Fuel to Steel”

Some utilities are providing options for addressing fuel risks to their consumers by shifting from fuel to steel as a business and investment strategy – but by acquiring and owning new wind and solar projects, utilities can provide advantages to both their consumers and shareholders.

Most utility acquisitions of wind and solar generation plants have been accomplished through power purchase agreements (PPAs) for power produced from generation that is built, owned, and operated by independent power producers (IPPs).  These contracts result in utility expenses, not investments, so regulators may allow cost recovery of the contract expenses, but do not typically allow utilities to earn returns in excess of costs.

Xcel Energy has pioneered a “growth and environmental” benefits strategy by adding wind farms and solar projects to their utility-owned generation portfolios, while retiring ageing coal plants.  These plants are obtained through the utility’s integrated planning process, with state regulatory approval, and result from bidding that produces both plants owned by Xcel’s operating utilities and by third parties under PPAs.

Xcel touts support from their customers and stakeholders for executing this business strategy, due to cost savings from substituting renewable energy for fossil fuel generation and benefits to shareholders as their operating utilities own a portion of new renewable projects that replace old fossil investments.  In a recent earnings callwith investment analysts, CEO Ben Fowke noted that the utility could “. . . invest in renewable generation in which the capital cost could be more than offset by fuel savings.”

When utilities undertake an effective planning and bidding approach to reinvesting in new clean energy, recent competitive bids have revealed very low wind, solar, and storage costs, reinforcing favorable consumer economics of steel for fuel.  Competitive bidding can reveal the lowest-cost projects available in markets for new generation resources, if undertaken in a positive and fair manner.  A mix of IPP and utility ownership is vital, so bidding IPPs and potential utility-owned assets are both subject to competitive pressures.

Financial Analysts’ Assessment of Steel for Fuel

Financial analytical firms are taking notice of the “steel for fuel” trend, evidenced by Credit Suisse Equity Research’s recent categorization of Xcel’s switch from fuel to steel as a “win-win”:

With fuel costs as a pass-through expense (no return earned) for regulated utilities, utilities have a built-in incentive to build more renewables.  Replacing fossil fuel generation with wind resources reduces the fuel portion of a customer’s bill and substitutes it with recovery of and on capital investment in wind turbines (and solar panels). This strategy, which was pioneered by [Xcel Energy] under its “steel for fuel” program, is under consideration by [CMS Energy Corporation] and others. Win-win situation for regulators, consumers, and environmental groups, striking a balance between supporting state RPS goals and stabilizing customer rates.

Other analysts note that steel for fuel provides opportunity for investment that is equal or better than maintaining investment in old equipment because it substitutes capital investment on which utilities an earn equity returns for fuel expenses which are passed through to consumers’ rates without earnings potential.  Popular investment advisory firm Motley Fool recently touted Xcel as a renewable energy stock to consider adding to investment portfolios.

From an equity investor perspective, that substitution is a positive earnings indicator.  Regulatory risks, due to holding old assets or requirements to gain regulatory permission for investment in new assets, are considered about equal.  But these regulatory risks can be managed successfully if approached with advance consultation with stakeholders, as Xcel’s experiences in Minnesota and Colorado have proven, generating positive earnings for its “steel for fuel” investments.

Substitute earnings for expenses

New wind and solar plants are rendering uneconomic the continued operation of ageing fossil units.  This financial transition creates opportunities for utility equity shareholders to both reduce their investment risks and increase potential earnings. By substituting “steel for fuel” utilities can substitute investment with earnings potential for fuel expenses on which no earnings are allowed by regulators.

This model of financial transition implicates shareholders, consumers, utility managers, regulators, and renewable generation project suppliers.  Regulators have a key role in striking a correct balance of these interests that can unlock streams of savings and benefits that can be shared.


U.S. Utilities Face Dramatic Change: Here’s How To Succeed At Utility Business Model Reform

A version of this article was published on Forbes on November 19, 2018

By Amanda Myers

The conventional utility business model largely succeeded at delivering affordability, safety, and reliability. However, new public policy priorities and emerging trends are accelerating the need for utility business model reform.

In “Navigating Utility Business Model Reform: A Practical Guide to Regulatory Design,” America’s Power Plan, Rocky Mountain Institute, and Advanced Energy Economy Institute identify ten approaches to help policymakers and utilities better align utility profits with public policy objectives and five companion case studies providing additional detail on implementation.

Regulatory options for policymakers, utilities, and electric customers to support and manage the maturation of a 21st century grid. ROCKY MOUNTAIN INSTITUTE, AMERICA’S POWER PLAN, ADVANCED ENERGY ECONOMY

New Responsibilities Require Utility Business Model Reform

Utilities need to adapt and respond to several new responsibilities, including environmental performance, resilience, expanded choice, and innovation. Even long-standing responsibilities have evolved and become broader.

  • Environmental performance: The electricity sector generates more than a quarter of all U.S. greenhouse gas emissions, making utilities vital partners to reduce emissions, electrify heating and transportation, and cut local air pollution . The traditional utility business model is often at odds with emissions reductions, economic deployment of distributed energy resources (DERs) and energy efficiency measures, and flexible grid operation to complement variable renewable energy resources like wind and solar. This is particularly true where utilities or their holding companies, own and operate fossil fuel power plants.
  • Resilience: Utilities have assumed new customer protection burdensdue to cybersecurity threats and increased extreme weather. Meanwhile, digitization and data collection will increase power grid vulnerabilities. Utilities must implement the right tools to protect consumers through this multifaceted transition, without imposing onerous costs.
  • Expanded choice: Utilities can lower bills and improve customer satisfaction by providing access to technologies such as local solar, storage, efficiency, demand response, and in-home automation. Maryland’s Behavioral Demand Response Program shows how utilities can respond to this responsibility: Baltimore Gas & Electric (BGE) significantly reduced summertime demand from air-conditioning through customer rebates that cut consumption during peak-demand days, peaking at 336 megawatts’ (MW) demand reduction that saved customers $11 million in 2016. But the current utility business model typically supports monolithic top-down planning and utility-owned resource procurement on behalf of customers.  Utilities complicate this dynamic because they can create more shareholder value by investing in large capital projects, undermining their motivation to accommodate non-utility customer choices.
  • Innovation: The pace of technological change for utilities has accelerated, but their business model hasn’t kept up . Utilities recover costs through backward-looking investment planning processes called rate cases, which determine whether utilities can recover the investment costs they have made and plan to make.  To meet the cost recovery threshold, utilities must demonstrate their investment was prudent; however, innovative technologies and programs carry higher risks of failure than proven infrastructure-based solutions.  Risk of experimentation or shifting from an existing asset to a new class of assets is put entirely on the utility, with no upside.  This lack of flexibility means that utilities are punished for pursuing innovation that provides grid benefits and the best possible service to consumers.

Options For Utility Business Model Reform

The report addresses four main issues with the current utility business model and provides pragmatic options to solve the issues.

Utilities make more money under the traditional regulatory model by delivering more power and building more infrastructure. This model disincents reduced electricity consumption and more efficient use of infrastructure, and limits the utilities’ ability to benefit from programs maximizing social welfare – specifically improving environmental outcomes, saving energy, and avoiding investment. Options to solve this issue include:

Adjustments to the cost-of-service model

  1. Revenue Decoupling: Break the link between how much energy a utility delivers to customers and how much revenue it collects.
  2. Multi-year Rate Plans: Fix the time between utility rate cases and compensate utilities based on forecast efficient expenditures rather than historical costs of service.
  3. Shared Savings Mechanisms: Reward utilities for reducing expenditures from a baseline or projection by allowing them to retain some savings as profit.
  4. Performance Incentive Mechanisms (PIMs): Create financial incentives for utilities to achieve performance outcomes and targets consistent with customer and public policy interests.

Leveling the playing field

Regulators set the rate of return on utility investments. The more utilities build, the more opportunity they create to make a profit, while operational savings do not yield long-term profits.

A utility focus on capital expenditures (CapEx) and not operational expenditures (OpEx) means that utilities cannot innovate in important ways, such as by incorporating critical information technology to improve efficiency and aggregate and adjust customer real-time behavior.  Options to reform this aspect of the utility business model include:

  1. Changes to Treatment of CapEx/OpEx: Change the regulatory treatment of CapEx and OpEx to make utilities indifferent between capital and operational solutions.
  2. New Procurement Practices: Expand utility resource procurement approaches to provide customers with the most cost-effective combination of supply- and demand-side resources.

Retirement of uneconomic assets

Due to cost recovery timelines that stretch out over 30 or more years, utilities have difficulty adjusting when new technologies become more cost-effectivethan whatever resources are already on the books. These business model changes would encourage utilities to pursue cleaner, cheaper power generation:

  1. Securitization: Refinance uneconomic utility-owned assets by creating a debt security or bond to pay down an early-retiring plant’s undepreciated capital balance.
  2. Accelerated Depreciation: Adjust rates to speed up asset depreciationso the utility and its customers are not left with stranded costs when an asset retires early.
  3. Platform Revenues: Provide utilities with new revenues for integrating and coordinating third-party energy services and distribution system resources.

Re-imagined utility business models

Utilities should benefit from offering customers more value than what they are required to provide. New grid technologies can generate revenue or increase cost savings for utilities, but regulators must provide a framework for different kinds of transactions between utilities, customers, and third-parties.

Radically new utility business models strive to make utilities flexible enough to offer new value-added services to customers, more like a competitive business:

  1. New Utility Value-Added Services: Provide utilities with the opportunity to earn revenues for offering customers enhanced services made possible by new grid technologies.

Utility reform options support objectives to varying degrees. ROCKY MOUNTAIN INSTITUTE, AMERICA’S POWER PLAN, ADVANCED ENERGY ECONOMY

The last 100 years of utility regulation can be considered a resounding success; utilities have succeeded in delivering safe, reliable, and affordable electricity across the U.S. – but circumstances have changed.

The current utility business model will continue to rub up against public policy goals around the country if regulators don’t take on meaningful reform.  This will allow utilities to improve their bottom line while achieving a clean, affordable, reliable electricity grid.

How Dumb Distribution Spending Crowds out a Smart Clean Energy Future

A version of this article was published on Greentech Media on November 5, 2018

By Ric O’Connell – GridLab

Utilities have doubled down on distribution spending as a primary growth opportunity.  Capital expenditures on the distribution and transmission system have skyrocketed since 2008.  However, this investment in the grid threatens to crowd the value of key distributed technologies that are building blocks for a clean, cheap, resilient energy future.

Load growth, wholesale prices, and utility business models

Falling wholesale generation costs and low load growth are major trends dramatically reshaping utility business models.  As wholesale prices fall and customer load declines, utilities’ primary revenue source decreases and they struggle to grow, fundamentally transforming how utilities recover costs and seek new growth opportunities.

Forecasted load growth is a key input supporting utility investment plans.  Based on forecast increased energy usage, utilities will build capital-intensive power plants and grid infrastructure, using the increased revenue to cover costs, often without raising prices.  These infrastructure investments are what shareholders care about; while wholesale energy costs are typically recovered dollar for dollar through customer rates, infrastructure costs are recovered at a premium, receiving a regulated return on equity that ranges from 8-12 percent. Utilities then recover those costs through increased sales revenue.  Energy use increases, utilities grow, and they continue to satisfy their shareholders.

However, declining load causes gross revenue declines, making it harder for utilities to recover capital investment costs without increasing prices or increasing customer fixed charges.  While shareholders expect growth, it’s increasingly difficult for utility managers to justify more investment to regulators in the face of declining energy use.

Satisfying shareholders in the face of stagnating load

To adapt, utilities are nevertheless finding ways to grow through three traditional investment areas: generation, transmission, and distribution.

New capital-intensive thermal power plants (mostly gas and some ill-advised nuclear plants) and renewable energy projects are getting built, but finding room for new kilowatt-hours (kWh) in an environment of declining energy demand can be difficult, often at the expense of existing generators.  Today markets are awash in generating capacity and low prices, so there’s little incentive to build these plants. Even despite the difficult economics, more than 100 gigawatts (GW) of new natural gas generation are being proposed around the country.

Public policy and economics can nevertheless justify building new generation, even in today’s oversupplied, low-price marketplace.  In many regions, the marginal cost of operating a coal plant exceeds the all-in cost of new wind and solar generation, and hundreds of GW of wind and solar sit in interconnection queues.  Regulated utilities won’t own much of this capacity, however, partly due to some financial barriers around the federal tax incentives, but much of it is driven by the historical bias to clean energy being developed by independent power producers (non-utility generators).

However, vertically integrated utilities like Xcel Energy are starting to get into the solar and wind generation game.  Xcel recently articulated substituting “steel for fuel” as an investment strategy that retires old coal units (fuel) and replacing those kilowatt-hours (kWh) with cheaper renewables (steel) that earn returns for shareholders for decades.  Still, the prospect of building new generation can be difficult in low-growth and low wholesale price environments lacking a clean energy policy.

Utilities can also invest in the transmission system. Transmission is notoriously difficult to build, is hard to justify with regulators, tends to spark local and vocal opposition, and often requires long, arduous planning and permitting processes.  But still, annual transmission spending for investor-owned utilities (IOUs) has almost doubled since 2010, when the trend of flattening load began in earnest.  Increasing connectivity between regions tends to lower wholesale energy costs, as places where generation options are limited by transmission congestion gain access to low-cost energy.

Utilities can further invest in the distribution grid, which links the bulk system to end-use customers at lower voltages. In the past, distribution investments were lower than transmission and generation.

But given the barriers to build new transmission or new generation, we are now seeing an explosion of growth in distribution infrastructure.

IOU distribution assets per customer grew an average of $217.50 per year between 2010 and 2016, a compound annual growth rate of about 4.5 percent, well above the rate of inflation over the same period.  Overall distribution system costs grew from around $30 billion in 1997, to $50 billion in 2017, with almost all of the growth coming from capital investment – meaning utilities are increasingly building large, expensive infrastructure on the distribution system.

Source: GridLab, Modernizing the Grid in the Public Interest: A Guide For Virginia Stakeholders

As a result of this investment strategy shift, the cost of delivering energy through transmission and distribution systems has grown relative to the cost of generating electricity.  Major investor-owned utility data shows what percentage of each delivered unit of energy (kWh) is due to generation costs and delivery costs. Delivery costs have expanded from 22 percent of overall costs in 2006, to 36 percent in 2016, while generation costs have fallen from 69 percent to 54 percent.


Exelon is a large investor-owned utility that exemplifies this trend, indicating in a recent investor presentation its plans to double distribution system spending, from $1.5 billion annually now, to $3 billion annually through 2020. Part but not all of this increase is due to Exelon’s acquisition of PEPCO, the utility that serves Washington, D.C. and surrounding areas.

Why does it matter that utilities are spending less on generation and more on distribution?

“Dumb” distribution spending that only focuses on reliability or resilience can crowd out spending on infrastructure to support a grid transition to a cleaner, affordable, reliable grid.  If the dollars go to “grid hardening” like undergrounding lines, then distribution infrastructure that supports value from distributed energy resources (DER), electric vehicle (EV) charging, advanced metering infrastructure, and foundational distribution software will fall to the wayside.

Even more importantly, distribution dollars should go to economic, clean non-wires solutions (NWS) that use non-traditional solutions to generation, transmission, and distribution needs.  These non-traditional solutions include distributed generation, energy storage, energy efficiency, demand response, or grid software and controls.

NWS opens up markets for DER, reduces risk, and moves the distribution system from a closed system to a more open platform. There are high institutional barriers to NWS, as it opens up to competition what was an exclusive domain of distribution utilities.  But as GridLab details in a recent paper, DERs can play an integral role in reducing customer costs and increasing the flexibility of the grid to help handle more renewable energy.

Pacific Gas & Electric’s (PG&E) Oakland Clean Energy Initiative Project provides an example where infrastructure spending would otherwise crowd out a local clean energy solution.  Here, the retirement of a 40-year old gas-fired peaking plant posed risks to local transmission reliability. To replace the plant, the California grid operator (CAISO) and PG&E evaluated whether a portfolio of DER could replace traditional investment options, such as building new gas turbines or transmission lines. The resulting proposal, approved by CAISO, allows PG&E to procure 20 – 45 MW of clean energy and DER, including 19.2 MW of demand response, 10 MW of battery storage, a mix of local generation and energy efficiency upgrades, and some traditional grid upgrades to transformers and substations for a total cost of $102 million — $400 million cheaper than the traditional wires upgrade.

DER can provide a wide range of services that can help displace more expensive, often dirtier infrastructure solutions.  These include avoiding transmission and distribution costs, avoiding the need for generation (usually coal or natural gas) to meet peak load, and improving grid flexibility.  Given this potential, policymakers considering utility investment plans in the distribution system need tools to evaluate a wider range of solutions.

Tools for policymakers

Policymakers around the country facing utility proposals to increase distribution spending and “modernize” the grid should take a few key steps to develop tools that help ensure consumers get the most out of money spent on infrastructure, or alternatively, cheaper DERs that provide the same services.

First, a robust and transparent integrated distribution planning (IDP) process is critical. As detailed in a recent GridLab paper, IDP is a holistic planning process that opens up what has been a traditionally utility-driven planning approach.  IDP also ensures that NWS are considered for major distribution upgrades, and includes hosting capacity analysis to help plan for and interconnect DER – even more important as transportation and buildings electrify and add flexible load to the grid.

Second, policymakers can map out their strategic goals for the distribution grid, and then map proposed smart grid investments into those goals. GridLab’s recent paper on grid modernization in Virginia helps stakeholders evaluate Dominion’s proposed grid modernization investments in the context of strategic goals.  To maximize return on investment for customers and the environment, planning processes must be designed to first identify the most critical capabilities of a modern grid.  Regulators can then use these capabilities to define performance outcomes for utilities and structure investment around the most cost-effective ways to maximize available benefits for customers, from conservation to DERs to smart grid technologies and poles and wires.

We must ensure that the distribution grid investments we make today are thoughtful and carefully planned, or we could end up with “dumb” distribution spending that crowds out the opportunity for a clean, smart distribution system.


Ric O’Connell is Executive Director of GridLab, an organization that provides comprehensive technical expertise to policy makers, advocates and other energy decision makers on the design, operation and attributes of a flexible and dynamic grid.   

Three opportunities for regulators to encourage beneficial electrification

A version of this article was published on Greentech Media on October 1, 2018

By Mike O’Boyle

The 1,500 attendees of Electric Power Research Institute’s (EPRI) Electrification 2018 event spoke often about the concept of “beneficial electrification.”  This captures the idea that converting from fossil energy to electricity in transportation and buildings holds tremendous potential to dramatically increase grid flexibility, reduce total household and business energy costs, and reduce air pollution and GHG emissions.  In this positive vision, the future is all electric.

However, even though electrifying some buildings and many vehicle types is already cost-effective, electricity policy veterans know that change rarely sweeps unchallenged through these highly regulated sectors.  Widespread beneficial electrification requires anticipating and removing technical and institutional barriers to take full advantage of technological trends. Unless policymakers start preparing for the electric wave today, its positive benefits may either be delayed or never materialize.

The first barrier is understanding customer behavior.  Getting customers to adopt electric technologies in a beneficial way requires knowing which customer incentives and education prompt fuel switching, and which electricity pricing schemes, (i.e., rate designs) can make that switch even more cost-effective for all.

The second barrier is the electric utility business model.  We think of electrification as enhancing the electric utility business model because it increases demand, but as we covered in a previous Trending Topics newsletter, getting the most out of electrification requires incenting regulated utilities to optimize vehicle charging and shift new electric loads to minimize costs and improve system flexibility.

Finally, the future of natural gas distribution assets looms large, particularly in states with ambitious decarbonization goals.  Long asset lifetimes for gas distribution infrastructure mean these assets could be stranded by new technologies or policies, potentially forcing non-electric customers to pay for these assets with higher bills, risking a death spiral.

What Makes Electrification Beneficial?

The Regulatory Assistance Project defines “beneficial electrification” to test when electrifying end-uses is in the public interest. “For electrification to be considered beneficial, it must meet one or more of the following conditions without adversely affecting the other two:

  1. Saves consumers money over the long run;
  2. Enables better grid management; and
  3. Reduces negative environmental impacts.”

Meeting these conditions is a win-win for electric utilities and customers, offering new services, and increasing sales.  This requires new frameworks for utility commissions to assess benefits of electrification.

Consider energy efficiency measures; metrics for the success of these programs are generally centered on cost-effectiveness and total megawatt-hours (MWh) reduced.  States with environmental policies may include social benefits of pollution and greenhouse gas emission reductions. These metrics will have to be revisited such that beneficial electrification, which may increase demand and total electricity costs, is not at cross purposes with traditional metrics for electric utility efficiency.

For example, an efficient heat pump may offer lower costs or greater social benefits than gas- or oil-fired heating, particularly in the oil-dominated Northeastern U.S., according to Rocky Mountain Institute’s recent analysis.  Similarly, an electric vehicle (EV) may require less total energy, cost less over the vehicle’s lifetime, or emit less pollution than an internal combustion engine.  Measuring and incentivizing beneficial electrification means considering a holistic picture of total customer energy costs when evaluating efficiency.

Electrifying the Right Way

Electrification’s best case emerges when utilities and regulators actively manage the time and location of new electric end-uses at the local and bulk-system level.

EVs offer tremendous opportunity to reduce costs and eliminate harmful local emissions; electric motors convert energy into vehicle miles three times more efficiently than internal combustion engines. But because EVs represent significant new loads, as recent McKinsey analysis shows, relatively low EV adoption rates can stress the grid and increase costs if charging is not managed effectively.  Some early-adopting local areas of the grid (feeders) could soon see 25 percent EV penetration, increasing peak load by 30 percent, stressing local capacity and potentially requiring costly upgrades.  However McKinsey’s analysis also finds that peak load in the same feeders would only increase 16 percent if 90 percent of the EV owners adopted time-of-use rates encouraging overnight charging.

National electrification was examined by the National Renewable Energy Laboratory (NREL), and their “high electrification” 2050 scenario explores the demand impacts of electrifying most building heating and almost all vehicles (100 percent of cars, 91 percent of trucks, 60 percent of mid-duty vehicles, and 40 percent of heavy-duty vehicles).  Though EV demand dominates total load increase in this scenario, peak load shifts to the winter in colder climates due to the outsized seasonal impact of electrified heating loads.

NREL’s enhanced flexibility scenario also examines what happens when electrified end-uses are shifted to reduce peak demand.  Under very conservative assumptions about load shifting, more flexible loads reduced peak by 17 gigawatts (GW), “avoid[ing] construction of unnecessary peaking capacity . . . and reduc[ing] billions of dollars in system expenditures.”

So how do we make it work?

These studies thoroughly demonstrate the benefits of managing location and timing of new loads from electrification.  However, the amount of load shifting that is possible will vary depending on region and the business models driving it.  This means the key to beneficial electrification is creating a policy environment maximizing flexibility and efficiency of new electric end-uses.

Three institutional and technical opportunities electrification can maximize public benefits:

  1. Using electric rate design to optimize demand and adoption
  2. Develop business models for managing and optimizing new electric end-uses
  3. Address the elephant in the room – natural gas utilities

Rate design is a key tool for getting the most out of electrification.  Customers with the right price signals and tools to automatically manage their loads can electrify at even lower costs without sacrificing convenience.  Automated devices controlled by the utility or another aggregator could become system resources that help balance supply and demand, and provide potential customer revenue streams.  And the right rates and incentives will help promote electrification where local congestion is not a problem.  But this dynamic relationship between customer adoption, final price paid for energy, consumption habits, and automation technologies is not well understood.

The better we understand this relationship, the better utilities can plan for and affect rates of electrification.  Due to localized electrification impacts, utilities could geo-target customers with load management technologies, reducing all customer system costs, keeping concerns about inter-customer equity in mind.  Utilities could build on successful models for integrated distribution planning to encourage other complementary local distributed energy resources like efficiency and distributed generation.

To mitigate this knowledge gap, regulators and utilities should pilot different rate designs and management schemes for electrified end-uses.  Pacific Gas & Electric’s ChargeForward pilot demonstrates the potential for future EV program development.  In their pilot, BMW seeks to optimize customer charging in response to two factors; wholesale energy prices and renewable energy penetration (which are highly correlated in California).  Customers can see the value of charging when energy is cheapest, and don’t have to manage charging themselves.  BMW shares aggregate data with the utility, creating a record of response to pricing that the utility can build into future planning and resource management schemes.

Building electrification can also take advantage of time-varying rates, particularly electric water heaters. Because customers only care about availability of hot water, not when water is being heated, heat pumps can overheat in times of low-cost electricity, effectively shifting load away from system peak.  Grid-interactive water heaters managed by the distribution utility are already proving their value to manage grid frequency, voltage, and peak demand in several state pilots, as highlighted in a recent report from the American Council for an Energy Efficient Economy (ACEEE).

Developing business models for flexible electric end-uses can help meet environmental goals, improve reliability, and reduce overall customer energy costs, but it’s unclear who should or will manage these flexible loads.

Utilities are the leading candidates, with their unique knowledge of the distribution system, but current cost-of-service regulation limits the amount of flexible demand management utilities will do on their own.  In their eyes, increased peak loads created by unmanaged charging can justify new infrastructure investments, both on the grid and in power plants.  That’s good business for electric utilities, who want to contain costs enough to keep regulators and customers happy, but lack a true incentive, other than maintaining reliability, to proactively manage the timing and location of electrification to optimize utility asset use.

Efficiency performance incentives are proven tools to motivate utilities to reduce sales.  Efficiency targets aligned with state and local policy goals should accurately capture carbon savings as a result of fuel switching, even if electric load increases.  Regulators can build on these mechanisms and create performance incentives that incorporate efficiency of total energy use rather than just electricity use.  New efficiency metrics will need to be developed under these mechanisms, such as CO2/customer, where environmental benefits are considered, or total energy bills as a new affordability metric alternative to total electricity bills.

These changes can be complemented by new performance incentive mechanisms and performance-based ratemaking to encourage utilities to manage these end-uses as system resources that displace power plants and reduce emissions.  For example, incentives to reduce peak demand and improve load factor (the ratio between peak and average demand) will encourage utilities to shift vehicle charging and other electric end-uses away from times when energy is most expensive.

Addressing the natural gas elephant in the room is required in states that are serious about addressing carbon and methane emissions. These states will need to electrify most end-uses to meet standards like the international reference goal of 80 percent greenhouse emissions reductions below 1990 or 2005 levels by 2050.  With just over 30 years to achieve this goal, a conflict quickly emerges: Natural gas pipeline infrastructure has an assumed lifetime of 35-50 years, during which its value depreciates and the companies that own the infrastructure get paid a regulated return on remaining value.  Anything built within the last 5-15 years or so will have value on the books but they will be mostly or completely out of use.

According to the Energy Information Administration, since 1984, 650,000 miles of distribution pipeline were added to the U.S. natural gas distribution system, an increase of about fifty percent – billions in annual spending on assets that will see decreased usage.  Simultaneously, nearly 50 percent of U.S. natural gas pipeline infrastructure was built in the 1950s and 1960s, meaning they will soon need replacing or decommissioning.  But replacing outdated cast iron and steel pipes throughout the natural gas distribution system will cost an estimated $270 billion, and could be stranded within decades.

Like phone customers with land lines today, remaining natural gas customers will be stuck with a higher portion of the network’s fixed costs, increasing average bills and further weakening natural gas economics versus electricity.  To avoid this death spiral, regulators need tools to manage the “decapitalization” of natural gas assets.  RMI’s report on ways to managing capital transitions away from coal assets provides lessons in the natural gas context.

Future build-out of the regulated natural gas system deserves heavy scrutiny as well; shorter, truncated depreciation schedules and cost-sharing agreements with building developers who choose natural gas could be considered.  Workforces deserve consideration as well; natural gas infrastructure — including processing facilities, pipelines, and distribution systems — supported nearly 1.3 million U.S. jobs and created $165.7 billion in value-added for the U.S. economy in 2015.

In the case of hybrid gas and electric utilities, the business implications are less grim, but they still need to prepare.  Along with managing decapitalization, policymakers should start integrating gas and electric system planning to ensure these separate departments of the same company are co-optimizing planning for electrification.


These next steps on beneficial electrification open up huge new lines of work for utilities, commissioners, and advocates. They also require exploring models like new value-based rate designs and incentive-based resource management schemes, performance-based ratemaking and new utility business models, and anticipating changes to regulated natural gas utilities. Only then can we achieve the scale of electrification envisioned by EPRI and others.

Proactive support for coal and nuclear communities

A version of this article was originally published August 23, 2018 on Greentech Media.

By Sonia Aggarwal

Coal and nuclear facilities are facing a tough economic reality in the United States.  Competitive power markets are oversupplied, while natural gas and renewable energy are undercutting coal and nuclear on cost.

State policymakers face hard choices about how to define a pragmatic approach to nuclear facilities, depending on how they value pollution.  But there are no good reasons to believe coal will become competitive on cost or pollution grounds anytime soon.

Last year, the Department of Energy (DOE) proposed a federal bailout for power plants that could prove they had a 90-day supply of fuel on site, suggesting that imminent coal and nuclear retirements would constitute a national emergency.  But the five bipartisan members of the Federal Energy Regulatory Commission (FERC) unanimously rejected DOE’s proposed market intervention in January of 2018, citing a lack of evidence that retiring coal and nuclear facilities would cause reliability or grid resilience concerns out of the normal course of business for the nation’s power grid.

However, a DOE memo made public earlier this summer suggests the agency is still considering exercising emergency authority to require electric consumers (or possibly taxpayers—the same individuals!) pay above-market rates to ensure certain coal and nuclear plants stay online, despite mounting evidence from grid operators that these power plants are not needed.  Analysis of the original bailout proposal, conducted by Energy Innovation and the Climate Policy Initiative last year, suggested that keeping uncompetitive coal and nuclear facilities in the black could cost consumers up to $12 billion per year.

FirstEnergy – A Case For A Proactive Transition Plan

FirstEnergy has been among the loudest voices clamoring for a coal and nuclear plant financial rescue, and it’s no wonder why – new economic realities are hitting the company hard.  Its competitive subsidiary filed for bankruptcy last spring after filing a deactivation notice for three of its uncompetitive nuclear power plants, and last week it filed worker retraining plans for these plants with federal regulators.

FirstEnergy’s market-exposed power plants would need about $1 billion per year to keep running profitably.  Assuming the two-year price support referenced in DOE’s memo from earlier this summer, that would imply subsidies of about $2 billion over two years to keep six of First Energy’s uneconomic plants operating.

$2 billion over two years to one company is a shocking amount of money to squander in the face of underlying economic trends that show no signs of reversal.  So, assuming price supports went forward, it’s quite reasonable to think that the same retirements would be imminent for FirstEnergy at the end of the period.  And the affected communities would still face the same tough economic and employment questions in two years.

But what if funds were instead directed to support impacted workers and the communities that host power plants that can no longer compete in power markets?  What if funds went directly to communities to support the inevitable transition, diversifying local economies and setting the stage for longer-lasting solutions?

In the case of FirstEnergy, if the same $2 billion was directed toward locally-led solutions in each of their six affected communities, instead of keeping these uneconomic power plants running for two more years, it could provide more than $300 million per community.

The idea may seem far-fetched, but it’s already been implemented in New York.  Consider Tonawanda, located outside Buffalo, where a 750 megawatt coal plant recently announced retirement.  The town released a redevelopment blueprint to replace lost tax revenue and jobs after a coal plant closure, and New York State’s legislators passed a budget bill with funding to cover nearly 80 percent of a $6 million gap in tax revenue for the first year after the coal plant closes, plus additional support to fill a declining share of the tax revenue gap for another six years as Tonawanda fosters an economic transition.  The total spending for a seven-year cushion will likely be around $45 million.

Compare that to the $300 million for each of the six power plant communities that could be available if two years of bailout funds were reallocated in this way.

If political will exists to make federal or state funds available to keep uncompetitive plants online for a few more years, those same funds could be better used to cover gaps in tax revenue, help workers retrain for new jobs, and help fuel local economic development in affected communities as they transition away from reliance on the power plant.

For example, since the initial Tonawanda support was approved, the New York State legislature and the governor has acknowledged broader electric sector economic trends and recently increased this kind of transition support to $45 million, making it available to other communities facing power plant retirements.

The Wave Is Building

FirstEnergy won’t be the last case of coal or nuclear plants being priced out of power markets, be they competitive or monopolistic.  Coal plant retirement has accelerated in recent years, and is projected to continue.  According to the RhodiumGroup, between 28 and 50 percent of the existing coal fleet will retire by 2030, though only 18 percent has announced retirement today.  Depending on how policymakers choose to value carbon-free electricity, nuclear power could also continue to suffer.

Source: Rhodium Group, 2018

A transition plan becomes vital in this context, and we still have time to be proactive.  Other states may be able to follow the Tonawanda model, and in some cases coal generation sites may be suitable for redevelopment ( promising work on brownfields to brightfields, for example) to can help moderate economic damage.

Another model is emerging – leveraging utility balance sheets to transition from fossil to clean.  In vertically integrated markets like Public Service Company of Colorado, uneconomic coal power plants are being retired, and utility funds reinvested in clean energy located in the same communities, like the plan to retire a coal plant in Pueblo County and replace it with local solar and wind power plants.  In Arizona, where the Navajo Generating Station retirement threatens to devastate two Native American Tribes’ economies, the future is less clear.  Solar and wind resource potential on Navajo lands holds promise for longer-lasting benefits that can similarly be contrasted with proposals to prop up coal plants temporarily.

In short, communities where these plants are located—not the federal government and power plant owners—should be in charge of deciding how any available funds can best be spent to support them in this economic transition.  If state or federal policymakers want to put workers first and support communities facing power plant closures, they could generate a more positive impact by giving any available funds to the affected communities to use however they want to support a just transition, diversifying local economies for long term success.

Putting D.C.’s “DER Authority” proposal into context of utility reform options

A version of this article was published in Utility Dive

By Mike O’Boyle

Regulators have a utility information problem.  People who want to see a cleaner electricity system know it well.  As both the identifiers of and profiteers from new infrastructure needs, utilities have embedded incentives to identify solutions that involve utility-owned infrastructure.  Regulators have insufficient information to compare utility proposals against alternatives, and so the litigious, adversarial nature of utility ratemaking continues to lag behind technological potential for a cleaner, cheaper, more reliable grid.

In a May 2016 Trending Topics piece, we wrote that regulators can pursue either outcome-oriented or information-intensive approaches to solving the utility information problem, and get the most out of clean, distributed energy resources (DERs).  We urged experimentation with both approaches, concluding that in an era of ever-increasing options for power system optimization and ever-rising information asymmetry, regulators will have to find ways to improve outcomes through a combination of utility incentives and improved data access.  (see also our submission to the Smart Electric Power Alliance 51st State Initiative on this subject)

Two years later, experimentation is happening and solutions are emerging, albeit relatively slowly.  Integrated distribution planning (IDP) is an information-intensive solution being tested in at least 11 states.


Meanwhile performance-based regulation is being explored or implemented in at least 12 states (in many cases concurrently with IDP) as a way to motivate utilities toward system optimization.


Six states are testing both approaches at once, and combining the two approaches may make great sense if the aim is to move a slow-moving system a bit more quickly. And in Washington D.C., a new model has emerged as a possibility – vesting the authority for data sharing and distribution system optimization into a public third-party entity.


What we’re getting from Integrated Distribution Planning

Studies consistently confirm there is massive potential for cost-effective demand-side participation, including rooftop solar PV, storage, demand response, energy efficiency, and managed vehicle charging.  For example, Rocky Mountain Institute’s recent report The Economics of Clean Energy Portfolios shows the system-wide potential for portfolios of DERs and clean energy resources to replace natural gas power plants, improving affordability, reliability, and environmental performance.  A recent analysis from LBNL showing efficiency is the cheapest resource available, rigorous studies of the value of solar, National Renewable Energy Laboratory’s 2025 California Demand Response Potential Study, and numerous state-level cost-benefit analyses of utility EE and DR programs further support the potential for demand-side participation to reduce system costs.

A few states have already had success operationalizing DERs as system resources, even before going through a full IDP process.  Examples include successful non-wires alternatives (NWA) demonstration projects in New York and California, including a recent decision to permit Pacific Gas & Electric to procure storage and DERs to replace uneconomic gas resources.

Even with what seems like overwhelming evidence showing these resources provide benefits, in specific instances regulators, stakeholders, and even utilities can’t tell whether and to what extent they should be a part of utility system planning.  Environmental and consumer advocates cry out for cheaper, cleaner options to be included, but lack the information necessary to rebut specific utility proposals. This happens in integrated resource plans, grid modernization plans, and utility rate cases.

Integrated distribution planning (IDP) is uncovering information essential to incorporating demand-side resources into utility planning.  IDP in California and New York has revealed system needs such as local generation and substation upgrades that can be met with a combination of conventional resources and DER.  Calls to undertake hosting capacity analysis have resulted in improved distributed generation connection times in California and Hawaii, but the full potential for demand-side resources and more comprehensive NWAs to become part of grid planning still eludes even DER vanguard-states.

Efforts to organize and release publicly available data are essential to realizing an affordable, reliable, clean electric grid.  These data illuminate the potential and value of dynamic load, storage, and other resources to balance the variability of inexpensive solar and wind on daily and instantaneous timescales.

But a more fundamental question is emerging out of this information: Who should process, manage, and share all this data, and who should administer competitive solicitations for NWAs?  The tension was apparent in a recent Utility Dive article covering the Interstate Renewable Energy Council’s Guide for State Regulators on Hosting Capacity Analyses.  In the article, utility and Electric Power Research Institute representatives argued that mandates to share system capacity for DERs in real-time are premature, while DER advocates argued that policymakers need to take bold steps and move quickly.

Given the underlying incentives that virtually punish utilities for collaborating with DER providers, the old question of utility incentives and information needs comes up again in the context of IDP itself: Given the incentives at play, can utilities really do IDP well?


An outcome-oriented approach for integrated distribution planning

Under the conventional approach to IDP (if we can yet say there is a conventional approach), utilities are required to do a lot of things they never did before:

  • Quantify and reveal DER hosting capacity
  • Quantify and reveal system needs before investing in solutions,
  • Anticipate DER deployment and incorporate into other planning exercises
  • Communicate the data more or less in real-time
  • Create a means for customers to share their energy demand data to DER providers
  • Solicit proposals from DER providers to aggregate customers and provide grid services

Utilities are infrastructure companies with less experience in information and data management, meaning they may need to develop new internal capabilities to meet these demands.  But cost of service regulation provides no upside for this kind of innovation.  In fact, the more successful a utility is at integrated distribution system planning, the more likely they are to defer or displace the need for utility-owned infrastructure. Under cost of service regulation, that winning proposition for ratepayers is actually a losing proposition for utility investors.

Without changing the utility’s business model and its financial incentives at the front end, the chances of a successful IDP at the back end are pretty slim.

Performance-based regulation can align utility incentives to ensure they will become more profitable if they roll-out IDP in a way that maximizes system and customer benefits.  In particular, putting capital expenditures on equal footing with operational expenditures is an important nut to crack. Utility Earnings in a Service-Oriented World by Advanced Energy Economy Institute highlights the opportunities and challenges of equalizing solutions that require utility CapEx versus utility OpEx.

For example, in New York’s DER alternative demonstration projects, the utilities can place expenses for DER contracts into regulatory asset accounts, meaning they can earn a regulated rate of return on certain operational expenses.  This is accompanied by a shared savings mechanism that allows the utility to make additional profits that scale with the size of the savings relative to the conventional solution.  This approach is being tried in Rhode Island as well, and explored in Hawaii, California, and Minnesota.

States are also exploring performance incentive mechanisms (PIMs) that reward the utility for improving system efficiency and reducing cost.  New York, Massachusetts, and Rhode Island utilities earn extra returns when they reduce system peak demand; this targeted incentive approach is being explored further in Minnesota, Oregon, and Hawaii.

Getting these incentives right could motivate utilities to get the most out of DERs, even when it means investing less capital in their systems.


A new information-intensive approach – outsourcing IDP

One approach to solving the potential conflict of interest that a utility might have in conducting integrated distribution planning is to hand responsibility to a third party.  The Distributed Energy Resources Authority Act (DERA Act) being debated at the D.C. Council would vest authority for IDP with a non-utility nonprofit entity called a DER Authority.  The proposal is an information-intensive approach to system optimization; it requires the utility to share unprecedented data about its system needs and customer usage in real-time, and relies on a new entity to synthesize this data to procure DERs.

It’s worth noting this model of outsourcing functions that antagonize the existing utility business isn’t new; energy efficiency utilities such as Efficiency Vermont, Energy Trust of Oregon, and Hawaii Energy are effective nonprofit entities that administer public efficiency budgets to maximize energy savings.  And even these entities’ mandates are no longer limited to efficiency.  Efficiency Vermont and Hawaii Energy have targets for peak demand reduction as well, while the Energy Trust of Oregon helps customers adopt small-scale renewable energy projects; perhaps a sign that the D.C. proposal is not as radical as it seems.

Under the DERA Act, the DER Authority takes over many of the functions the utility would typically do under IDP, including:

  • Creating forecasts of system load and DER deployment that feed into utility resource planning
  • Analyzing DER alternatives to utility infrastructure investments over $25m and soliciting bids from DER providers
  • Standardizing distributed smart inverter data to share with the DER authority
  • Creating recommendations for changes to rate design and other programs that could accelerate cost-effective DER deployment
  • Creating a customer-facing website and platform to connect customers with DER providers

Even with the creation of this new authority, the utility’s role in optimizing DERs would still be significant.  The utility is required to supply public information in real-time about its hosting capacity for DERs on every circuit, as well as its larger-scale infrastructure needs, defined by the services they provide – e.g. capacity, energy, voltage support – giving the utility significant control over what becomes a NWA candidate.  The utility will also have to provide the DER Authority with real-time data about customer usage at the meter level and ensure smart meters can communicate easily with in-home devices.  These are new functions the utility is likely unprepared for today, and so it may need new revenue and potentially performance incentives or investment opportunities as carrots to accomplish these tasks.

From a public policy perspective, the D.C. proposal has several merits.  First and foremost, it creates (or endeavors to create) an entity with a clear directive, resources, and incentives to maximize DER deployment comprehensively for the public good.  It solves aspects of the utility information problem by requiring the utility to provide massive amounts of crucial information necessary to identify the highest-value opportunities for DERs.  It also provides a pathway to develop the market for elusive DERs, particularly demand flexibility, which can complement variable low-cost generation without increasing environmental impacts.

But the proposal may still struggle to live up to its intention.  As an extremely detailed legislative proposal, the bill is proscriptive but also may leave unforeseeable loopholes that regulators may find challenging to counteract.  For example, the requirement that utilities define system needs and share them with the DER Authority for a request for proposals for DER alternatives are vague.  Left unspecified are the specific capabilities that must be defined and replaced, though the bill does create a stakeholder process to resolve many unspecified details.

Also, the requirement that these needs must meet a $25m threshold to be subject to NWA analysis means that utilities can break infrastructure proposals into components that fall under this threshold.  And it does not solve the underlying information incentive problem – without a change to the underlying business model of the utilities, which here would be excluded from profiting off of the optimization of DERs, there are few reasons to play ball.


The DER Authority is a new experiment in the information-intensive approach to promoting system optimization.  Equally important are reform combinations that increase regulatory focus on rewarding utility outcomes.  Other states should watch carefully, particularly those who are frustrated with the utility’s willingness to proactively engage customers and embrace cost-effective DERs.


Connecting the Dots – Saving Time, Money, and the Environment with Smart Planning for Power Lines and Renewable Energy Development

A version of this article is available on Greentech Media

By Alex Daue, Assistant Director of Energy & Climate, Wilderness Society

As the United States renewable energy market continues growing and our energy needs evolve and shift to cleaner sources, the way clean power is transmitted to our communities must follow the same responsible siting as the energy projects themselves.

Wilderness-quality lands, important wildlife habitat, and cultural resources areas are not appropriate for transmission lines and energy development. Thankfully, an ongoing process shows how we can build regional transmission projects crucial to a clean, reliable, affordable energy future without sacrificing environmental stewardship.

Smart infrastructure development is good for business – it makes permitting more efficient and increases economic benefits by focusing construction where the least amount of conflicts exist and projects are most likely to succeed.  This realization has become apparent over the last few years with the re-evaluation of the federal West-wide Energy Corridors planning process for 6,000 miles of transmission and pipeline corridors spanning public lands in 11 western states.

The planning process identifies continuous strips of federal land across jurisdictional boundaries suitable for transmission and pipeline development.  Robust stakeholder engagement minimizes environmental, cultural, and other stakeholder conflicts.  Eventually, this will streamline federal siting, review, and permitting processes for transmission developers, though there is no guarantee of similar success with private landowners crucial to completing many of the corridors.

These corridor re-evaluations are a rare bright spot for infrastructure on public lands, quite in contrast to recent federal actions to encourage fossil fuel development and production. Initially designated by the Bureau of Land Management (BLM), U.S. Forest Service (USFS), and Department of Energy (DOE) in 2009 (“the Agencies”), the corridors are currently undergoing expansive stakeholder engagement through this review.

The Agencies’ efforts to improve corridors by gathering input from local communities, stakeholders, and energy and transmission developers are providing lessons for other regional and interregional transmission proposals. This collaborative effort will be crucial to advance responsible development, while protecting our communities and wild places.

How we got here

Identifying appropriate infrastructure corridors helps facilitate efficient development and protection of public lands.  Planning ahead identifies opportunities and potential problems early in the process, providing time to work with stakeholders to find solutions, instead of bogging projects down with unforeseen conflicts and delays while carving up our natural heritage with poorly sited development.

Criticism of the original 2009 corridor designations included corridors inappropriately sited in areas important for wildlands and wildlife, and neglect of critical pathways to areas ripe with renewables potential.

This led one Colorado county and conservation groups to file suit challenging the designations; resulting in a settlement agreement in 2012.  The agreement required the Agencies to update their guidance and training, and re-evaluate the energy corridors.  Regional reviews of corridors are currently underway. The reviews will result in reports from the Agencies recommending changes to the corridors that follow the “siting principles” established in the 2012 settlement agreement:

  • Sited to provide maximum utility and minimum impact to the environment
  • Promote efficient use of the landscape for necessary development
  • Appropriate and acceptable uses are defined for specific corridors
  • Corridors provide connectivity to renewable energy generation to the maximum extent possible while also considering other sources of generation.

After gathering baseline information from western stakeholders in 2014 and completing internal studies, the Agencies wisely divided the west into regions to be sequentially reviewed rather than reviewing all 6,000 miles of corridors at once. Regional reviews are being staggered, with the last review to be completed in 2019. After the reviews are completed, the Agencies will change the corridors through future land use planning, using the reports as a guide.


What does good stakeholder engagement look like?

On January 10, 2018, the Agencies published draft “energy corridor abstracts” that detail siting opportunities and challenges for the corridors in Regions 2 and 3, which include 53 energy corridors situated in Arizona, Colorado, Nevada, New Mexico, and Utah.

The release initiated a 45-day stakeholder review period, with the Agencies requesting input from the public on the corridor abstracts by February 25, 2018; comments by The Wilderness Society and conservation partners drew attention to review process flaws likely to create persistent conflicts with national parks and wilderness quality lands.

After analyzing stakeholder comments, the Agencies published revised corridor abstracts in May which include important improvements, such as identifying all locations where corridors intersect with wilderness-quality lands – and in a few cases identifying potential corridor adjustments to reduce impacts. That said, additional improvements are still needed to address these conflicts, and the Agencies should acknowledge their requirement to analyze those conflicts in future land use planning and authorizations while considering ways to reduce impacts.

Without these improvements, the corridors will fail to facilitate efficient and responsible development while protecting the environment.  Future project development in corridors will face more conflicts, delays, and increased risk of legal challenges – underscoring the importance of following-through on a strong approach to the regional reviews.

The Agencies also hosted five well-attended public workshops in early June (one in each state) to gather input from developers, non-governmental organizations, and other stakeholders on ways to make the corridors more useful. These workshops dug into the details of tradeoffs for possible corridor adjustments, and provided a wealth of additional information the Agencies can use to inform the Regions 2 and 3 draft report ahead of completing the Regions 2 and 3 Review by the end of 2018.


The BLM’s other Western regions will follow similar processes through 2019. Each review will generate detailed recommendations from the Agencies for ways to improve corridors through future land use planning changes by the BLM and the USFS to help facilitate responsible infrastructure development while protecting natural and cultural resources.

The Agencies’ public engagement has many ideal elements for an infrastructure development planning process. It created a clear, step-wise approach that allows stakeholder input throughout the process, including commenting on draft documents, using the project website and excellent online mapping tool, and attending public workshops and webinars. Through this process, Agencies are gathering a wealth of information and helping the public understand and participate effectively in the reviews.

The Agencies are also improving their methods and approach as they proceed, as well as incorporating stakeholder input into their detailed documents and online mapping tool.

However, the Agencies face a significant challenge in the scope of their task and timeframe for completing it.  Continued strong investment in agency staff time and resources is crucial for meeting the terms of the settlement agreement and succeeding in the goals of creating a truly useful system of energy corridors.

And despite the Agencies’ efforts to engage with project developers, they have not created and communicated sufficient incentives (e.g. clear commitments to more efficient permitting) to encourage developers to site their projects within the corridors instead of in higher-conflict areas. Getting this element right is a crucial companion to improving the locations of the corridors.


Getting transmission corridors right in practice

While the Agencies are required to re-evaluate all corridors through the regional reviews, a few examples of corridors with major conflicts or opportunities to advance renewable energy development illustrate this effort’s importance.  In many cases simple corridor boundary adjustments would dramatically reduce environmental conflicts while still allowing for development in the remaining portion of the corridor, though some cases will require eliminating a corridor altogether.

For example, Arizona-California corridor 30-52 is a crucial pathway for delivering renewable energy and sharing benefits between the two states. This corridor along Interstate 10 could provide a route for the proposed Ten West Link transmission line, and is a much lower-conflict alternative than the route proposed by the developer. That route would cut through the Kofa National Wildlife Refuge, causing serious harm to the wildlife and habitat it was designated to protect.

In eastern Nevada, the north-south 232-233 E corridor is a key corridor to address. A nearby corridor follows an existing highway and transmission line, but 232-233 E inexplicably detours through BLM-inventoried lands with wilderness characteristics in a large wildlands complex. In addition to impacting wilderness-quality lands, this corridor also cuts through a BLM Area of Critical Environmental Concern designated to protect the threatened Mojave Desert Tortoise.

Through the regional reviews, the Agencies can complete additional corridors analyses that will help projects like Ten West Link use lower-conflict pathways and gain permitting efficiencies, ultimately reducing cost, speeding up development, and increasing the likelihood these lines will materialize. Clear conflicts like Nevada’s 232-233 E corridor designation underscore the importance of regional reviews also recommending changes to reduce wildlands and wildlife habitat impacts. The regional reviews may also identify the need for new corridors through appropriate areas to facilitate renewable energy development.


Looking ahead – completing the Regional Reviews and reflecting on lessons learned for future transmission planning

To help meet our nation’s infrastructure needs while protecting our natural and cultural heritage, the Agencies should build upon the good progress they have made to date. They should ensure regional reviews are all completed in 2019 as planned, with continued strong stakeholder engagement. Ultimately, the Agencies must adjust the corridors through land use plans to create a truly functional system, a goal which is very much in sight.

Public engagement has also provided lessons for future transmission planning conducted by different entities in different regions, such as the eastern U.S. Robust stakeholder engagement including local governments, conservation and other public interest groups, project developers, and utilities is crucial for successful planning. Getting input early and often will provide more opportunities to solve challenging issues and ensure corridors open access to high renewable energy potential areas while minimizing impacts on the cultural, historical, and community resources that weave the East together.

Addressing the complex mix of public and private land ownership while gathering information to avoid and minimize conflicts for as many potentially affected lands as possible is important, even if planning entities only have jurisdiction over a subset of lands. Finally for corridors to be truly useful, meaningful incentives must exist to attract developers to site projects within them, or disincentives for siting projects outside of them.