TODAY’S STUDY: How New Energy Can Replace Old Energy For Utilities
A Low-Cost Energy Future For Western Cooperatives Emerging Opportunities For Cooperative Electric Utilities To Pursue Clean Energy At A Cost Savings To Their Members
Mark Dyson and Alex Engel, August 2018 (Rocky Mountain Institute)
The emergence of very low-cost renewable energy pricing in the United States has created unprecedented opportunities for utilities currently reliant on high-cost, legacy generating assets, particularly in the Mountain West. The drop in renewables pricing is also casting into doubt the competitiveness and viability of operators that are slow to transition.
In this report, as an indicative case study of this broader trend, we examine the cost-savings opportunities renewables price declines have made possible for Tri-State Generation & Transmission Association and its member co-ops. Specifically, we consider their opportunity to engage in large-scale procurement of costeffective renewable energy projects, while maintaining system reliability requirements. We analyze two illustrative power supply portfolios based on publicly available data, and find that procurement of new wind and solar projects represents approximately $600 million of cost-savings potential for Tri-State’s members through 2030, versus continued reliance on legacy coal-fired generation. Scaled adoption of renewable energy by Tri-State could also mitigate risks of revenue loss and cost increases associated with reliance on existing assets for electricity supply, reducing the rate increases under a range of risk scenarios by 30% to 60%.
The analysis presented in this case study illustrates that immediate collective action between wholesale energy providers and member co-ops can mitigate risks, identify regionally appropriate solutions, and leverage aggregate buying power, enabling an efficient and equitable transition toward a more cost-effective energy supply mix.
Introduction: A Rapidly Changing Energy Landscape
Renewable energy resource prices are falling at an unprecedented pace, much more quickly than forecasted even a decade ago, and to a level completely unimagined at the time when utilities built much of the legacy generating capacity in the United States. Less than a decade ago, solar and wind projects were expected to remain relatively high-cost resources with only a minor role to play in the grid. However, forecasters and utility planners were unable to predict the dramatic and sustained price declines alternative technologies, particularly utility-scale solar photovoltaics (PV), have experienced (see Figure 1). A common view in official forecasts was that other presently competitive resources, including wind energy and natural gas-fired generation, were also likely to continue playing a small role in the future supply mix, given expectations of future costs that proved to be too high in both cases.
Given forecasts of high costs for alternatives, many utilities thus continued their historical investment trajectory in coal-fired generation. For example, in 2010 and 2011, when utilities were expanding coal mining operations and planning to build new coal-fired generating capacity, forecasts suggested 2015–2020 solar PV costs of $100–240/MWh—significantly higher than the anticipated costs of new coal assets at the time.
But in fact, long-term fixed prices available today for new wind and solar projects entering service in the early 2020s can outcompete just the operating costs of many existing coal assets, let alone the costs to build and run new coal- or gas-fired generating capacity. This rapid transition has caught many utilities by surprise, and thrown into question the future economic viability of legacy generating assets that are no longer necessarily the least-cost option for the customers they serve.
The Shifting Economics Of Energy Supply In The Mountain West
This paper presents a case study of the changing economic situation for electricity supply, in an area of the country where lower-cost alternatives to legacy assets are currently available, but are limited in their uptake to date. In particular, we focus on the opportunities available to cooperative utilities in the Mountain West currently served by Tri-State Generation & Transmission Association, a nonprofit, member-owned cooperative which provides wholesale power to 43 distribution co-op members and, ultimately, over 1 million consumers in Colorado, Nebraska, New Mexico, and Wyoming. Tri-State has historically relied on a mix of owned coal-fired power plants and contracted renewable and fossil resources to serve member loads and offer nonmember sales. Tri-State’s current energy mix is 30% renewable via purchases. In June 2018 it announced a procurement process for new renewable resources, but the majority of its capacity and energy come from a fleet of five coalfired power plants built between 1959 and 2006.
Historically, Tri-State’s owned assets have contributed to lower-than-average rate increases passed along to its end-use consumers, relative to other utilities in the states served by Tri-State. However, the go-forward operations and maintenance costs of Tri-State’s legacy generator fleet, estimated from public data, are now higher than prevailing prices for new renewables resources. Contracted prices available for new renewable resources, publicized in 2018 as part of competitive procurement processes from regional utilities including Xcel Energy and NV Energy, undercut the production costs of Tri-State’s coal fleet (see Figure 2). The wind and solar resources across Tri-State’s service territory are generally as good or better than in peer utilities’ footprints, suggesting that similar pricing could also be available to Tri-State in a well-designed competitive procurement process.
The prices for renewables in Figure 2 show both estimates of “integration costs” as well as incremental transmission costs to enable connection of wind and solar energy projects into the Tri-State transmission system. A 2015 meta-study on integration costs found that utilities seldom impose adders of more than $5 per MWh of wind or solar production when assessing incremental costs of integration, with a median of approximately $3/MWh; recent integrated resource plans by Western utilities (e.g., Rocky Mountain Power in 2017) have cut that estimate to less than $1/MWh, even including costs for incremental coal asset cycling (typically less than $1/MWh for Western and Colorado-specific regions). We estimated transmission costs based on the incremental transmission included in Xcel Energy’s 2018 120 Day Report associated with its Colorado Energy Plan proposal.
However low their costs, variable renewable resources like solar and wind are not one-for-one replacements for the reliability services that existing coal assets provide. Rather, wind and solar resources can most easily act as a “fuel saver” when they are available, allowing utilities to reduce operating levels of high-cost assets and thus avoiding these assets’ marginal production costs by utilizing low-marginal cost renewable energy production instead. The marginal production costs of Tri-State’s assets shown in Figure 2 are generally higher than wind bids ($11–18/MWh) and in line with solar bids ($23–27) received by Xcel Energy and NV Energy in 2018, even when including an estimated $3/MWh adder for transmission expansion and <$1/MWh adder for other integration costs associated with these variable renewable resources. Thus, by keeping Tri-State’s coal assets operational but choosing to run them less when wind and solar resources are available, there are significant cost savings available…
Risks And Mitigation Opportunities
The cost savings opportunities illustrated by the case study are clear, and though specific to Tri-State’s system, are broadly indicative of the opportunities available to owners of high-cost, legacy generating assets as alternatives fall in price. In addition to these cost savings opportunities, there are also opportunities to mitigate risks to business solvency by transitioning away from legacy assets. Two categories of risks present themselves to owners of such assets: revenue loss caused by load defection, and cost increases due to asset- or portfolio level costs. Both are present under current policy conditions, but could be exacerbated by potential policy changes.
Revenue loss Current risks of revenue loss are driven by the falling costs of alternatives and the potential for member exit from full-service contracts:
• Falling costs of alternatives. Owners of high-cost assets face the risk of load defection, i.e., customers (or, in the case of cooperative utilities, members) choosing to self-supply a growing share of their own energy. In particular, prices for small- and medium-scale solar projects are increasingly competitive with retail and wholesale rates, respectively, in the Mountain West. Medium-scale solar prices fell 60% between 2010 and 2016, and community-scale (i.e., 1–5 MW) solar at recent prices (i.e., <$45/MWh) is approaching cost parity with wholesale energy-only prices in the Mountain West. Commercial-scale (i.e., 100–500 kW) solar pricing declined 50% from 2010 to 2016, while residential rooftop-scale (e.g., 5–10 kW) solar PV systems have declined in price by 56%. Limiting the potential of solar adoption in the case of Tri-State is its Policy 115, which limits members to 5% self-generation to mitigate a perceived cost shift between members. However, PV project costs are forecast to continue declining another 40–50% by 2030, potentially accelerating adoption even under current policy.
• Member exit: As emerging alternative resources fall in price, retail utilities (including co-ops) may seek to exit from all-requirements contracts with wholesale providers that continue to rely on high-cost assets, in order to take advantage of lower-cost wholesale service available from other providers or market purchases. For Tri-State, this risk is not hypothetical; one member, accounting for 1.5% of Tri-State’s load, has already exited Tri-State’s system, and several others are currently in negotiation to exit or are otherwise considering their options.
With new or upheld changes to existing policy, revenue loss could be accelerated through additional load defection and loss of competitiveness due to increased customer access to competitive markets:
• PURPA interpretation upheld: Current policies limit the potential of community-scale and other distributed generation for utilities across the country, including Tri-State’s Policy 115 discussed above. However, the Federal Energy Regulatory Commission (FERC) in 2016 ruled that the 5% limit imposed by Policy 115 did not apply to projects that qualified under the Public Utility Regulatory Policy Act as “Qualifying Facilities.” This ruling effectively allows Tri-State members to procure local resources whose prices fall below their avoided cost of energy, i.e., Tri-State’s wholesale rate. This ruling is being challenged but, if ultimately upheld and acted upon, could result in significant co-op load being economically met by medium-scale solar projects. This ruling could also allow, and even obligate, retail utilities to purchase non-net metered solar from their own members at avoided energy rates, leading to additional adoption from consumers and/or businesses.
• Wholesale market expansion: The potential expansion of wholesale markets in the Western United States would introduce competition for owners of high-cost generating assets. A proposal for an expanded Southwest Power Pool market has stalled out due to Xcel Energy leaving the Mountain West Transmission Group, but other proposals are still in play, including expansion of the Energy Imbalance Market, and a potential West-wide regional transmission organization (RTO). While monopoly providers, including Tri-State, have a relatively captive customer base, the increased pricing transparency and lower transaction costs available in an organized market could put pressure on high-cost assets to exit the market.
Risks of cost increases under current policy for owners of legacy generating portfolios are driven by the economics of aging assets as well as by a growing market understanding of the risks facing such portfolios:
• Outage costs: Nationwide, coal-fired generators suffer forced outages (i.e., are unexpectedly unavailable to generate power) approximately 9% of operating hours. Western utilities, including Tri-State and others, operate aging coal-fired power plants that have, in recent years, undergone weeks- or months-long outages related to failures or complications with upgrades. Reliance on a few large legacy assets puts operating utilities at risk of high market price exposure, as well as unexpected compliance costs that need to be borne before the asset can be operational.
• Cost of capital: Utilities rely on the ability to raise and invest low-cost capital to expand and maintain infrastructure. This lending is based on creditors’ belief that utilities’ revenues are low-risk and will be sufficient to cover debt service. In recent years, this belief has been challenged, notably when Barclay’s downgraded the entire US electricity sector in response to perceived threats to traditional utility business models relying on captive customer revenues as alternatives fall in price. Tri-State noted in its 2017 Form 10-K filing that it is considering investing $1.1 billion between 2018 and 2022; higher costs of capital would likely lead to higher member rates associated with this incremental investment.
Under potential policy changes, other risks could confront utilities reliant on legacy fossil assets:
• Renewable portfolio standards: Twenty-nine states, including Colorado and New Mexico but not Wyoming or Nebraska, have renewable portfolio standards (RPS) specifying that utilities must provide a portion of their electricity from renewable resources. While Tri-State is compliant with existing Colorado and New Mexico law with its 30% share from renewables, laws have been passed in four other states (Oregon, New Jersey, New York, and California) specifying targets of 50%, and several states have passed or are actively considering higher targets.
• Greenhouse gas pricing: No national-level pricing scheme exists today for carbon dioxide emissions, but two recent proposals have emerged to support “carbon dividends” or other forms of emissions pricing. Utilities reliant on high-carbon intensity assets would face increased operating costs and competition from lower-emissions resources.
As an indicative example of the impact that these risks might have on Tri-State and its members, we analyzed illustrative scenarios of three of the above eight risk factors and their effect on average rates that Tri-State would have to charge in 2030 to recover its costs in the business as usual and energy transition supply mix scenarios. To estimate average rates in the absence of these risk factors, we divided total revenue requirement (shown in Figure 4) by total sales. To calculate the impact of the three risk factors, we looked at a range of illustrative scenarios for member co-op exits, qualifying facility uptake under PURPA, and greenhouse gas pricing (Figure 5).
Risk mitigation opportunities
A transition to a lower-cost supply mix can also help mitigate the risks outlined above by lowering costs and proactively aligning supply mix more closely with potential policy-forcing devices. The energy transition case in each scenario reduces rate increases by between 30% and 60% by minimizing stranded cost risks with load defection, since more costs are variable (e.g., market purchases) versus fixed in the business-as-usual case, as well as by minimizing exposure to environmental compliance costs. Lowering supply costs and passing those savings along to members can minimize the incentive for members to either adopt local generation or fully exit from the generation and transmission. Lowering supply costs also mitigates the risks of becoming uncompetitive as utilities and regulators consider expanded Western electricity markets. Achieving a low-cost supply mix by proactively prioritizing renewable resources, in particular, also minimizes exposure to greenhouse gas pricing or expanded RPS requirements…