Your Questions / Our Answers
Webinar: Natural Gas: A Bridge to Climate Breakdown – An Investor Brief on Overcoming the Power Sector’s Natural Gas Dependence
April 16, 2020
Stephen Byrd, Morgan Stanley
Lila Holzman, As You Sow
Barbara Lockwood, Arizona Public Service
Mike O’Boyle, Energy Innovation
Chaz Teplin, Rocky Mountain Institute
Technology Questions
Are utility-scale clean energy technologies the only options considered as replacements for natural gas infrastructure?
The report is not a comprehensive analysis of what can replace natural gas while maintaining an affordable reliable energy system. Such analyses require extensive modeling, and may answer a range of questions, including looking at replacing single power plants, or transforming entire electricity systems. Each of these perspectives requires different analyses and modeling capabilities.
The Rocky Mountain Institute’s Clean Energy Portfolios work looks at the potential for both utility-scale and distributed energy resources (including efficiency and demand response) to replace individual gas plants while providing the same services. Many institutions and modeling firms have also begun to tackle the feasibility and affordability of transitioning to a renewables-dominant electricity grid, and recent results have been very favorable to heavy reliance on renewables and a declining gas and coal fleet, including analyses by the National Renewable Energy Laboratory, Vibrant Clean Energy, National Oceanic and Atmospheric Administration, Energy & Environmental Economics, and Evolved Energy. We would urge investors to familiarize themselves with these reports, and request that utilities consider a broad range of clean energy portfolio options including energy efficiency, demand response, and distributed and utility-scale renewable generation and storage.
Is comparing clean energy to gas overly simplistic? What about other factors like how renewable intermittency impacts the grid, unavailability of battery storage beyond 4-6 hours, the cost of phasing out natural gas infrastructure, the need to match the location of demand with the availability of clean energy sources?
Looking at reliability requires a systems view, rather than an individual plant comparison. Discussing the levelized cost of renewables plus storage gives investors and others a sense of the benefits of such new investments, given that these two resources can provide nearly the same services as fossil resources given our current system.
Using renewables and storage to replace fossil fuels is more effective when coupled with energy efficiency and demand side resources. To achieve higher renewable penetration levels and decarbonize the last 20% of the generation on the grid it is likely more R&D is needed to scale potential technologies such as green hydrogen, long-duration storage (beyond existing 4-6 hours), CCS, etc. With enough lead time for R&D and innovation and the right signals of demand sent from utilities and policy, some of these solutions should become cost-competitive in as soon as 10 years. Additionally, investments in transmission infrastructure are needed to connect regions with varied availability of on/offshore wind, sun, and hydro generation resources.
For more information addressing these comprehensive questions, please refer to the studies mentioned in the previous question, including RMI’s Clean Energy Portfolios research and renewable integration studies.
Could green hydrogen replace natural gas, thereby repurposing existing infrastructure?
Hydrogen can help decarbonize the natural gas system, especially for industry, which is harder to decarbonize than the power sector. For electricity generation and distribution purposes, hydrogen may be blended in with natural gas, but the percentage up to which it is possible to do so using existing infrastructure is limited and may require significant investments, pipeline replacement, and retrofits of power plants to be capable of carrying and burning hydrogen.
Additionally, hydrogen production using current electrolysis processes is very inefficient and will not be cheaper per unit of energy than natural gas extraction any time soon. Even at very low costs of electricity, the costs of electrolysis need to come down for green hydrogen to be available at scale. Strategically introducing green hydrogen for hard to replace gas uses could be a viable approach, particularly to provide heat for industrial processes. As renewable energy generation expands, overproduction could be channeled into the production of hydrogen, creating a virtuous cycle.
There are still several industries that require the use of natural gas: e.g. steel production. Are there carbon-free solutions that can replace this demand for natural gas?
Demand for natural gas in industry, such as steel, will indeed continue. Significant improvements and R&D in alternative technologies are needed to address harder-to-decarbonize industries. Examples include electric arc furnaces or green hydrogen, but these cannot yet compete on price with natural gas. In the near-term, ‘renewable natural gas’ can replace fossil natural gas to decarbonize such uses. Such discrepancies between price and need argue for strong policies to signal investment in zero-carbon fuels to power industrial processes and provide long-term storage in the electricity sector, such as a strong economy-wide carbon price and industrial efficiency and carbon policies.
How feasible is it to “electrify everything" by 2050? Buildings in cold-climate regions - like the upper Midwest of the U.S. - would require massive buildout of the renewables grid to meet peak requirements.
Great progress is being made to electrify buildings by using electric heat pumps and induction stoves. Analysis by RMI on the economics of building electrification, including in colder regions, has found that it is becoming increasingly cost-competitive. Electrification of both buildings and transportation will indeed lead to sizable growth in demand for clean electricity, providing a strong business opportunity for renewable energy buildout.
The scale of the challenge is considerable with current technology, which is why developing long-term policy signals is crucial. Policies that drive electrification and require continuous improvement in appliance performance can spur investment in already improving heat pump technologies and drive down the cost of these applications as they scale. This was the success story of renewable portfolio standards and can be emulated by other sectors as they seek to decarbonize by switching fuels from fossil to clean electricity.
Finally, it is also worth noting that new electrified end-uses can reduce costs for all if their use is integrated into the operation of the grid. Pre-cooling and pre-heating of homes and water tanks is a massive storage opportunity that can potentially take advantage of excess renewable generation and reduce the need to overbuild the system. Likewise, converting over a hundred million light-duty vehicles alone to battery-electric represents a massive opportunity to shift demand to times when solar, wind, hydro, or nuclear are running in excess. This obviates some of the need for “flexibility” from the supply side, which is a primary service provided by natural gas generation in today’s grid.
Why has Xcel Energy been highlighted as a company making progress on decarbonization while it continues to claim it needs natural gas plants to meet demand?
In comparison to peer utilities, Xcel has set ambitious targets for the electricity generation arm of its business: 80% by 2030 and net-zero by 2050. Xcel has acknowledged that to fully decarbonize its energy generation and provide required reliability, it does not yet have all the answers. Xcel is working to develop solutions to reach net zero emissions and, in the near-term, finding savings through retiring coal plants early and replacing them with wind power. While investors should give credit where due, they should also continue to question whether Xcel’s investment plans for gas plants have been sufficiently evaluated and compared to clean energy alternatives.
How do risks vary for utilities that are both electric and natural gas distribution providers, and should utilities continue to invest in pipe replacement to reduce methane emissions?
Hybrid utilities – those who sell electricity and natural gas and own distribution infrastructure – face significant risks and opportunities if we begin to wind down natural gas use now. Competition from renewables and complementary resources like storage, and state climate and renewable energy goals, put pressure on new and existing gas for electricity generation. Large pipelines that supply both distribution and gas-fired power plants will see their costs spread over fewer and fewer hours of consumption, increasing gas rates for both. These pipelines typically are paid for over as many as 70 years, meaning anything built today would need to run until 2090, or paid for much sooner, further increasing costs and risk of stranded assets. Utilities recognizing this today can avoid investing in assets that would potentially be stranded as clean options get cheaper and public pressure increases.
Hybrid utilities also have an opportunity to gain from supporting “electrify everything”, and providing for an orderly transition away from natural gas infrastructure. As transportation and building sectors transition from being oil and gas-powered to electricity, there will be a huge surge in demand for power and a corresponding fall in natural gas demand. Deft hybrid utilities could seize on this opportunity and wind down the natural gas distribution side of the business and lean into the electrification transition.
Regarding distribution, electrification en masse (driven by both policy and cost declines of electric heating applications) would drive a downward spiral of natural gas demand, as capital and maintenance costs would be paid in greater proportion by a dwindling number of gas customers (likely low-income customers if not managed well), leading to further defection and impetus to electrify buildings. Such cost increases would be amplified if the electricity sector no longer relied on pipelines to deliver gas. With this trend and looming disruptions, gas distribution companies must fully evaluate and justify further investment in pipeline infrastructure with long lifetimes. The potential death spiral for gas distribution of a hybrid utility, and the potential pathway for orderly wind-down, was explored for California by Gridworks and a consortium of California gas stakeholders in California’s Gas System in Transition.
Investment in best practices for methane management can indeed be an effective way to reduce short-term greenhouse gas emissions. Such investments should focus on infrastructure that is most likely to remain in use under low-demand scenarios as well as infrastructure that is leaking the most methane. In the longer-term, some distribution companies could also help decarbonize hard-to-abate industrial sectors and innovate with the use of green hydrogen. At the same time, companies – especially hybrid companies – should begin planning for a managed transition as is happening in California with the CPUC’s recent rulemaking announcement.
How much nuclear power is in APS’ "clean" portfolio?
According to APS’ parent company Pinnacle West’s 2019 annual report the share of nuclear in the generation mix is 31.2%.
What specific policies enabled APS to make its 100% clean energy commitment?
APS has not implemented any new policies. Its process has and will continue to be procuring generation through a competitive process that seeks to identify the most economic resources capable of meeting its generation needs. With the continuing decrease in cost for clean energy technologies, it believes this process will allow it to meet its near-term clean energy goals. However, it recognizes new technologies that do not yet exist will be required to achieve its ultimate goal of 100% clean energy by 2050.
While it has not changed its policies, APS did develop a set of principles to guide its path toward a low-carbon economy. Through these efforts, it intends to succeed as a next-generation energy company, while preserving the reliability, affordability and service its customers have come to expect from it. Creating a sustainable energy future demands a commitment to forward-thinking practices that will allow the company and Arizona to thrive for years to come.
Does APS have plans to retire coal more rapidly and replace it with solar, as solar costs have dropped below the operating costs of coal-fired power plants? If so, what is the timeline for retirement? What savings for customers does APS expect? What barriers and problems exist to that switch?
APS announced its plan to exit coal by 2031, which is 7 years earlier than its previous commitment. It will evaluate the technology options available to replace its coal generation at the time new resources are needed. Its process has and will continue to be procuring generation through a competitive process that seeks to identify the most economic resources capable of meeting its generation needs.
One challenge with the transition out of coal is the economic impact from the plant closure to the surrounding communities. Providing sufficient time for these communities to prepare for the closure is important. APS plans to engage in a collaborative dialogue with stakeholders to examine possible strategies for mitigating those impacts and continuing partnerships with local communities.
Why do utilities typically sign PPAs with developers rather than investing directly in wind and solar?
The use of PPAs has to do with the current tax incentives, the investment tax credit (ITC) and production tax credit (PTC). Because of how these incentives are structured, it is usually not possible for utilities to take advantage of them. Thus, it is easier to sign a PPA with a 3rd party that can build the wind or solar and take advantage of the ITC or PTC.
Utilities vary how they utilize ownership and PPA contracts throughout the country. Often times the difference can be driven by market structure/regulatory rules or the duration of a contract structures.
Additionally, PPAs for existing resources can add flexibility for utilities by providing a limited duration contact that gives the utility the option, but not the requirement to continue to take service through a PPA. APS has recently utilized some 5-7 year contracts (PPAs) to act as a bridge to developing alternative resources.
APS is a vertically integrated utility, it owns generation, transmission and distribution resources and utilizes both ownership and PPAs to meet its generation needs and will continue to do so to maintain a strong balance sheet, maintain a healthy financial outlook, and meet its customer needs in an affordable manner. APS utilizes a balanced approach to meet the needs of both its shareholders and its customers that considers both shorter duration purchases (PPAs) and the entire life of new owned assets on our system in providing reliable and safe electric service.
Energy & Economic Trend Questions
Regarding the potential for investing in renewables to save customers’ money, does this apply for residential customers with distributed solar that are connected to the grid with no net-metering or is the cost advantage of solar limited to utility-scale solar?
In the U.S., the cost of residential solar is closer to $150/MWh, compared to an all-in cost of new natural gas of $40-70/MWh. Residential solar is different than wholesale power, however. It has the potential to also provide services such as distribution deferral because it displaces demand. In other countries, such as Australia, the economics of distributed generation are much better, showing there is room for improvement in business model development in the U.S. These issues are nuanced, and the economics of distributed solar very much depend on the market barriers to mass adoption, rate design, amount of deployment, and the needs of the grid.
How does the cost of renewable development and deployment change when accounting for additional costs, such as higher ROEs from federally regulated transmission and regional grid integration to ensure greater reliability? How do such additional costs impact the economics of renewables versus natural gas? Are there examples of regional grid integration to enhance renewable reliability?
Federally regulated transmission, and corresponding ROEs, impact all power generation, not just renewable energy. Nevertheless, it is true that renewable energy faces unique siting challenges because of the space it takes up and the disparity in resource quality between locations, particularly wind.
However, additional costs of transmission are not always prohibitive – they may actually be net beneficial to all power customers in a given footprint. In general, new transmission co-optimized with high-production renewable energy sites can save customers money, by introducing low-cost power into new markets offsetting high prices and fuel costs. However, models for regional and interregional transmission cost recovery are outdated and do not reflect the win-win of transmission and renewable build-out: The costs of transmission generally must be borne by renewable developers, and are not recovered from the beneficiaries, which may be customers throughout a regional grid.
MISO does a decent job of this, through its Market Efficiency and Multi-Value Projects cost allocation methodologies adopted in response to FERC Order 1000. The tariffs allow for cost allocation in part based on a beneficiary-pays principle, and consideration of public interest goals, rather than simply requiring a renewable developer to shoulder the cost of interconnection.
What natural gas prices are assumed in this levelized cost analysis?
$3.45/MMBTU was assumed in the unsubsidized Lazard 2019 analysis, which also contains sensitivities later on in the report.
Much of the proposed new natural gas generation seems to be concentrated around areas of gas production. Do the economic arguments around stranding risk change if you are close to the wellhead?
Anything that reduces fuel costs will help the economics of gas generation. Generally, it does lower prices to locate generation closer to the fuel source. Closing a plant before the end of its useful life is the main risk for stranded costs. The locating near a wellhead may impact the project development costs and potentially the magnitude of the stranded costs, but it does not alone create stranded cost risk.
In Energy Innovation’s model, it appears that nuclear's contribution remains constant in the later years of the analysis. What does this model assume regarding retirements and relicensing of nuclear generation?
The Energy Policy Simulator (EPS) measures the impact of policy on a range of outputs, including most significantly greenhouse gas and criteria pollutant emissions, and cashflows to different actors in the economy. The model chooses the least-cost portfolio of resources to meet these policies; in the graphic shown in the presentation, the model is meeting a 100% clean energy standard for the electricity sector. It finds that relicensing most of the nuclear fleet is a cheap solution compared to others. It is worth noting however, that the model is NOT a reliability model, though it does have meaningful mechanisms for ensuring enough flexibility and resource adequacy to meet load. It relies heavily on other, more robust grid modeling studies checks on what resource mix would be realistic to maintain reliable service. Everything in the EPS is open source, meaning anyone can download the model, understand the inputs, and even change it to suit their desired set of assumptions. One of the limiting factors in the EPS and other models is the rate of deployment for renewable energy as well, which argues again in favor of keeping nuclear around. To get to a very high share of renewable energy by 2050, or even sooner, we need to build unprecedented amounts of renewable energy, though the U.S. has built similar scale of natural gas capacity and other public infrastructure works in its history. China in particular has already achieved the scale of wind and solar deployment needed to meet the challenge of reaching net zero emissions by 2050.
Is it better to accelerate the clean transition or leave it until closer to 2050?
Given what science demands to stay under 1.5 or 2 degrees Celsius, it is clear that the faster and earlier the clean transition occurs and emissions are brought to net zero, the less catastrophic the impacts will be. The faster the transition happens in sectors of the economy where there are current cost-effective solutions, such as the power sector, the more time is given to ‘hard to abate’ sectors such as aviation, cement, and steel, that need more time to find technological solutions and drive down costs.
Furthermore, lagging in the ongoing clean energy transition gives less time for innovation and problem solving. A utility like Xcel that has a target of 80% reduction by 2030 is giving itself a 20 year period from 2030-2050 to find solutions of how to cost-effectively decarbonize the final 20% of its generation. Other utilities are leaving themselves less flexibility by leaving only 20 years for 50% or more decarbonization.
Another cost to consider for natural gas is the cost of environmental cleanup from drilling waste and other waste created from oil and gas production. How can these costs, which are not on the books of oil and gas companies, be considered?
Upstream externalities are indeed a significant issue, especially regarding legal and reputational risks, which could increase upstream costs. For more information on company best practices, please see As You Sow, Boston Common Asset Management, and the Investor Environmental Health Network’s Disclosing the Facts report series.
Currently ISO NE show a fuel mix of 51% gas, 15% renewables, 12% hydro, and less than 1% oil and coal. What does the modeling show in regards to costs/savings associated with removing gas? Assuming that the majority of consumers are moved by cost rather than environmental concerns.
While we can’t speak to ISO-NE specifically, there are national-scale studies showing a high share of renewable energy, plus a robust transmission build-out, can be achieved at a lower cost than the current system, including a decline in natural gas burn.
Policy & Utility Business Model Questions
Will the Atlantic Coast Pipeline be built?
According to analysis by Morgan Stanley, the bank finds that the Atlantic Coast Pipeline will not be built due to court disputes over whether it can be permitted in certain biologically sensitive areas. Recent legislation passed in Virginia and a subsequent integrated resource plan from Dominion Energy, which owns a majority of the pipeline, have put natural gas demand and the need for the pipeline in the region into further question.
Does guaranteed return on capital provided by some public service commissions for capital investments provide a market distorting incentive for gas electricity generation? Is stranded asset risk viewed differently in a regulated utility versus an independent power producer?
Yes. Regulated utilities have a certain level of ‘protection’ from stranded asset risk due to being granted a guaranteed return on investment for infrastructure that has been accepted by regulators to be built. This can buffer those utilities to a certain extent from being outcompeted by lower-cost renewables or from policy forcing some fossil fuel generation to be retired early. However, risks remain that customers of regulated utilities could either be caught with higher rates or move off-grid or opt to choose other options like community choice aggregators (CCAs), driven by a lack of clean generation options. All natural gas infrastructure, whether owned by regulated utilities or independent power producers, is at risk of stranding due to its expected long lifetime, the likelihood of being outcompeted on cost by clean alternatives, and the introduction of climate policy, with competitive producers being hit first.
However, regulated utilities receiving healthy rates of return for capital investments also have a huge opportunity to invest in renewables, which are more capital intensive per unit of output than fossil generation. Xcel is pioneering (and others are following) a “steel for fuel” strategy, where coal is being retired early at a savings to customers, and replaced by a combination of utility-owned and independently produced (competitive) renewable generation. As Morgan Stanley’s “Second Wave of Clean Energy” report notes, this is a multi-billion dollar growth opportunity for regulated firms.
As described in our report, a shift toward policy that falls in the category of “Performance Based Regulation” can help better incentivize priorities like reducing carbon emissions and efficiency. Reducing the incentive to build, and linking utility profits to public interest outcomes can shift utility decision-making away from maximizing infrastructure build-out toward meeting customers with the cheapest, most resilient, cleanest generation fleet.
Will regulators implement natural gas decommissioning charges as a part of gas revenue requirements if natural gas power plants are retired early?
If natural gas plants are to retire early, then most likely customers will have to continue paying off the initial investment and its guaranteed return for investors. Securitization has proven effective as coal assets are replaced with wind and solar to enable lower bills, as fuel costs are replaced with low-cost renewable generation, and this could potentially be a viable strategy for natural gas assets too.
What are the prospects for extending federal tax credits for renewable energy?
This appears to not be a current priority during the COVID-19 crisis and was not included in the first round stimulus bill. Holding up the stimulus bills to try get such tax credits included has been considered unwise, as it could turn people against clean energy. Pushing for renewable energy tax credit extensions may wait for future recovery funding packages.