Electric Utility Resource Planning: Past, Present and Future

By Joe Ferrari

Electric Utility Resource Planning: Past, Present and Future covers the balance of renewable costs, energy storage, and flexible backstop mechanisms needed in electric utility resource planning. In addition, it covers the optimization of planning methodologies and market design. The book argues that net load, ramping and volatility concerns associated with renewables call into question the validity of almost a century of planning approaches. Finally, it suggests that accounting for flexibility helps optimize the efficiency of the entire fleet of assets, minimizing costs and CO2 generation simultaneously, concluding that a flexible, independent backstop mechanism is needed, regardless of renewables or storage. 

Case studies provide a mix of hypothetical "what if" scenarios and analyses of real-life utility portfolios drawn from international examples.

• Examines how resource planners and policy specialists can plan to incorporate renewable generation technologies, thus uniting considerations of technology, methodology, business and policy
• Focuses on the reality of long-term decision-making and planning processes in working utilities
• Reviews novel approaches towards resource planning that yield lower costs and CO2
• Emphasizes the need for flexible backstop mechanisms to maintain reliability

• Language: English
• Publisher: Elsevier Science
• Release date: Sep 9, 2020
• ISBN: 9780128226100

Joe Ferrari

Joe Ferrari is General Manager for Utility Market Development at Wartsila North America, Annapolis, MD. He is currently responsible for project origination efforts with large investor owned utilities, evaluating and guiding planning software development used for resource planning and project valuation. He is formerly a market development analyst for utility portfolio and investment optimization responsible for quantifying risks and solutions.

Book preview

Preface

Electric utilities must continually reassess when and how they install new generation capacity to meet load reliably. For many years the pool of technologies utilities could choose from was rather narrow, and associated costs, performance, and other factors were well understood. Accordingly, they could use straightforward approaches toward valuation to make choices they were confident in and were easily understood by shareholders or regulators. These plans are most often contained in an integrated resource plan, or IRP. The IRP is a document prepared on a recurring basis that provides a roadmap of the utility’s plans for capacity expansion, associated costs, and financial impacts, and a description of how valuations were performed to justify choices. While all utilities are not required to produce public versions of IRP documents, practically all electric utilities prepare these plans on a regular basis.

Today the electric power sector is being driven by a common desire to decarbonize, couched in terms of 100% renewable energy. Commitments are made to gradually phase out fossil fuels and replace energy production with solar, wind, hydroelectric, and other carbon-free energy sources, such as nuclear. Energy storage is required to time-shift overproduction of renewable energy to periods with lulls in the same. However, serious complications arise when trying to apply legacy resource planning approaches to more modern power systems. For example, equilibrium energy balance assumptions embodied in load-duration-curve capacity expansion approaches assume all resources are dispatchable and only generate only when needed. Clean power systems, in contrast, have large amounts of nondispatchable solar and wind, which have both seasonal fluctuations and volatile output, requiring new and more explicitly time-dependent approaches for planning purposes. The planning process is made even more complex by the much wider pool of technologies to choose from. For example, it was not too long ago that textbooks on energy economics described electricity as a commodity that had to be instantly consumed because it could not be stored. Today there are a host of renewable energy storage technologies each with different attributes, cost, performance, scaling capabilities, and so on. There is growing awareness of land use requirements for renewables, a new dimension that raises environmental concerns. The thought processes and mathematics behind legacy planning approaches are simply insufficient to support this new renewable dominated world.

While many electric utilities are exploring new and more dynamic planning approaches to form the basis of their IRPs, my observation has been that we are not quite there yet. Utilities use IRP planning approaches they are familiar with, and often this is what is expected from shareholders and regulators. But as we add more variable renewables, the outcomes often fall short of what was expected, evidenced by cost over-runs, higher emissions, and reliability issues. Changing modeling paradigms can be a costly endeavor, involving learning curves not just for utilities, but also for policy makers and regulators. The cost is rather small, however, considering that the outcome will be a far more efficient and robust power system that will save ratepayers billions of dollars.

This book was written to provide guidance for the transition from simple legacy planning to more dynamic state-of-the-art approaches required for high renewable penetration. An overview of the origins of electric utilities and simple planning approaches used in the past sets the stage for how we got to where we are today. The evolution of solar, wind, and other renewable technologies as well as energy storage is presented, with discussion of how their unique features necessitate new planning approaches. New planning approaches are presented along with examples of utilities on the cutting edge of the planning space. Numerical examples are provided to demonstrate concepts. And finally, a review of different approaches to a 100% clean energy state is provided to guide planners and policy makers. The target audience for this work includes utility executives, staff, analysts, policy makers, consultants, regulators, environmentalists, and academics interested in how we can reach 100% clean energy targets.

Chapter 1

Introduction to electric utilities and how they plan for the future

Abstract

Electric utilities provide the framework from which electricity is generated and ultimately delivered to customers. The electric utility industry is undergoing massive shifts from fossil fuels towards renewable energy. This transition is a complicated, expensive, and time-consuming process. To appreciate the challenges, it is first necessary to understand the history of the utility industry, the types of technologies they have traditionally relied on for generation, and the planning approaches used to make investment decisions. This history lays the framework for how these same utilities can make the transition toward renewable energy, which in turn relies on how utilities plan for the future. Planning approaches center around the concept of capacity expansion, where utility needs are assessed, and technologies chosen to meet those needs using a range of approaches and criteria. In this chapter special emphasis is given to the evolution of planning and capacity expansion approaches, from simple cost comparisons at the project level to advanced portfolio analyses.

Keywords

Capacity expansion; electric utility; integrated resource plan; long-range plan; resource plan

Introduction

Affordable and reliable electricity is a fundamental building block of modern society. Electricity provides clean lighting in our homes, at our workplaces, on the streets, with no smoke or fumes from open flames. We use it to cool our homes in the summer and heat them in the winter. It breathes life into industrial facilities. Silent and unseen, its unceasing flow allows us to tap into the digital world with our televisions, computers, and smartphones [1].

Billions of people depend on the electrical grid every day without thinking of where the electricity comes from. At most they might think of it in passing when the electricity bill arrives from the local utility. There is, however, a growing consensus, from everyday people through the highest political bodies, to divest from fossil fuel use due to environmental concerns related to CO2 emissions, which are believed to drive climate change. Greater numbers of people are pressuring their governments and utilities to strive toward the use of carbon-free, renewable resources, with some demanding that 100% of our electricity comes from renewables such as wind and solar.

Most people are not aware of the complex industrial, engineering, and economic hurdles that had to be overcome to get to where we are today, let alone what it will take to get where they want to go. Understanding the history of the utility industry, combined with the emergence of new forms of energy production and storage and the analytics required to stitch all the pieces together, is critical for modernizing and advancing toward a world with 100% affordable renewable energy. We must understand fundamental questions and how to answer them—where does electricity come from, and what does it cost?

While there are countless opinions and ideas around the production and consumption of electricity, to understand the issues, we require a common understanding of how electric utilities operate and plan for the future. Long-range plans (LRPs), also referred to in the industry as integrated resource plans (IRPs), are planning documents used by utilities to characterize their best view of the coming years; 5, 10, or more years into the future, and to determine the optimal mix of resources they must maintain to satisfy customer loads and maintain reliability. The plan typically accounts for changing load profiles, variations in expected fuel prices, existing power plants, and potential retirement of the same as well as the need for new resources, what they could potentially be, and their costs. Once these factors are accounted for, they must be analyzed to answer the following question: What mix of resources for some future date provides maximum reliability at lowest cost? As we will see, using the same assumptions for a given utility, one can get dramatically different answers depending on the analytical approach used to address the question.

Many utility systems today still use approaches that were modern 50 years ago, however, more rigorous approaches to planning provide a more accurate picture in a world with high-renewable penetration. Simple approaches that worked in the past do not strictly apply to modern power systems because renewable sources such as wind and solar do not behave at all like traditional fossil-fueled generation. This chapter addresses the history of the electric utility industry and introduces the thought processes and challenges utility planners, policymakers, regulators, researchers, and politicians have faced in the past. It discusses how that institutional momentum is driving some of the outcomes we see today and influencing our plans for tomorrow.

Electric utilities: the basics

There are thousands of electric utilities across the planet, each with its own technology mix in its power generation portfolio, from hydropower to nuclear, from coal to natural gas, from biofuels to renewables. They each have different localized idiosyncrasies to deal with and varying regulatory pressures. Depending on the utility, they can even have different mission statements. For example, a municipal electric utility exists to provide reliable low-cost electricity to the residents of that city, and decisions are made, to a large extent, by elected city councils and/or mayors who must answer to voters. At a broader scale, some government-owned utilities provide similar services to entire nations, with decisions made again by elected officials. Electric cooperatives, member-owned utilities, tasked with providing reliable electricity to residents within their footprint also strive to minimize costs for customers, and decisions are made by their board of directors. Then there are investor-owned utilities (IOUs). These can be large or small. They are required to maintain reliability and competitive pricing, which is generally capped or subject to market rates set by regulatory bodies but are profit-making businesses. Across this, spectrum of utility types is an overlay of government regulations and governing bodies whose purpose is to ensure compliance with laws such as air emission standards or renewable portfolio standards.

One common factor cuts across all utility types. They plan in a way that minimizes costs, which is challenging as there are numerous costs to consider; operational costs such as fuel, staffing, and maintenance; capital costs such as new power plants or major overhauls; compliance costs such as addition of complicated and expensive emission controls on an older plant. Lower costs mean lower customer pricing or, for IOUs, greater profit.

If the utilities are focused on reducing cost, it would be natural to ask how cost is defined and/or calculated. This seems like a simple question, until you dig into the details. Several factors were mentioned above such as fuel, capital cost, compliance costs, etc. These are each complicated, interrelated, and often time-dependent. For a utility to prove they are minimizing cost, either to themselves, to regulators, or to customers or voters, there must be some common basis, or so one would think. In reality, the concept of quantifying costs is an evolving discipline. There are countless peer-reviewed articles in engineering and economics journals over the course of decades dedicated to questions related to how costs are calculated for utilities. And there are a host of approaches used in practice that can vary dramatically from one utility to the next. Given greater resource choices, ever greater regulatory and societal pressures, and evolving technologies, the complexity of the question has only increased over time.

All utilities are at some stage on the evolutionary scale of cost calculations that started with the simplistic approaches of the first utilities and progressed through ever-more complex methodologies to what is considered the state-of-the-art today. The complexity of the cost question increased as the number of power plants grew to keep pace with the dramatic explosion of electricity consumers across broader geographic expanses. New technologies emerged with varying costs and reliant on a wider array of fuels, in addition to having widely disparate technical features such as start times, start costs, minimum up and downtimes, minimum stable loads, varying needs for emission controls, and water use. Approaches that worked well for the early utilities are not applicable for the large modern utility. There are, however, legacy issues. Utility staff and management may be comfortable with a certain methodology and apprehensive of investing in the training and software necessary to apply more complex approaches. The trend toward modern cost optimization approaches is happening, but not everyone is at the same place on the evolutionary scale.

To understand how and why this range of cost-economic calculations even exists requires understanding a bit about the early history of electric utilities and the evolution of the approaches in time. This first chapter of the book is dedicated to an exploration of the early history of electric utilities through the modern day and an introduction to basic planning approaches. This information will form a building block for the following chapters.

The early history of the electric utility

The first examples of electric utilities emerged in the 1870s with the world’s first generating stations, facilities that used something, be it water/hydropower, or combustion of fossil fuels, to generate electricity. The initial driver was to take advantage of the newly invented light bulb as an alternative to gas/kerosene lamps and/or candles. One of the first generating stations was installed by Lord Armstrong to power his house in 1878. Lord Armstrong built an estate called Cragside, located in Northumberland, England, in which he integrated a hydroelectric generator to produce electricity to power everything from electric lights to a dishwasher [2]. The nearby city of Godalming, in 1881, built the first street lamps that took advantage of electricity from hydropower [3].

In 1882, Thomas Edison’s Edison Illuminating Company built the first coal-fired generating station in Manhattan, United States. This facility was called the Pearl Street Station and initially served fewer than 100 customers, including street lighting and building lighting. Within 2 years, the number of customers had increased to 500. The concept of a generating station within a municipality spread rapidly. For example, the Borough of Chambersburg, PA, less than 300 miles from Manhattan, started official discussions of what it would take to build a power plant in their town in August of 1888. By September 1889, the residents of Chambersburg voted on a bond resolution to fund the plant, and by February 1890, the lights went on, powering a total of 40 street lamps. The Borough of Chambersburg is still in the utility business and is one of the oldest municipal utilities in the United States [4]. The emergence of municipal utilities quickly spreads across North America. For example, while Chambersburg, Pennsylvania was considering a power plant, the city of Albuquerque opened its first electric light utility in 1883, almost 30 years before the state of New Mexico was admitted to the United States as its 47th state [5]. In 1886, Japanese immigrant Hutchlon Ohnick was granted a franchise for gas and electric service by the City Council of Phoenix, Arizona, giving rise to the Phoenix Electric Light Company (Fig. 1.1). The first power plant they built was a fifty horsepower unit that could power 45 lights at 1500 candlepower each, by burning mesquite wood collected in the surrounding desert and hauled to the site by mules [6]. The Phoenix Electric Light Company was the foundation of what would later become Arizona Public Service, a regulated IOU now serving 2.7 million customers [7]. Emergence of utilities and expansion of electrical power was mirrored across the globe in quick succession. For example, Tokyo Electric Lighting commenced operation in Japan in 1886 [8]. The Municipal Council of Sydney (Australia) first powered electric lights in 1904 [9]. Practically all of these first electric utilities started with a single generating plant primarily dedicated to street lighting.

Figure 1.1 Display in lobby of Arizona Public Service headquarters (Phoenix, AZ, United States) commemorating the beginnings of the utility.

The commercial success of these small generating stations was not guaranteed, as street lighting was traditionally provided by gas companies. Fierce competition arose between the newly founded electric utilities and gas suppliers particularly for lighting of public spaces such as streets [10]. As generation and distribution of electricity became more cost-effective, it was natural for municipalities to consider electric lighting as a cost-effective alternative to traditional sources. The invention of electric street cars in the 1880s greatly expanded the potential need for electricity from a strictly night-time service to something that was needed to some extent all day, every day [11]. This, in turn, drove up demand, which led to competition and technological advances, which in turn led to rapidly growing economies of scale and reduction of electricity price.

In the United States, by 1900 electricity sales exceeded 100 million US dollars [12], and the service was expanding beyond a few simple light poles directly connected to a generating station. It became quickly apparent that the industry had to provide infrastructure to serve the demand based on three central pillars that are still the backbone of every electric power system in existence today;

Generation: The sources that generate MW for delivery across transmission and distribution systems.

Transmission: The infrastructure needed to move large volumes of high-voltage electricity from generators to the distribution system(s) to serve load. Volumes of electricity are moved at high voltage because it is more efficient and cost-effective to do so in this manner.

Distribution: The infrastructure needed to step-down high-voltage electricity to lower voltages that can be used directly by the end user(s).

Early on the electric needs of consumers were met by a mix of small private enterprises, such as the Pearl Street Station, or municipals, such as the Borough of Chambersburg. Municipals dominated in the United States with more than 3000 municipally owned power companies in the early 1920s. However, private utility holding companies were formed and in the business of buying and consolidating to take advantage of economies of scale. So much so that by the early 1930s more than 1200 municipal electric utilities had gone out of business or been sold [11,13]. By 1932 in the United States privately held IOUs generated and received revenues for more than 95% of all MWh sold in the United States and provided electricity to more than 90% of all customers [10,11,14]. Some or all of the transmission and distribution services were retained by municipal or state agencies and have since been overtaken by the same consolidation, so that today’s transmission and distribution are often held by large IOUs as well. In 2019, the electricity generated by IOUs in the United States served more than two-thirds of the US population, with the remainder being provided by a mix of municipal utilities, member-owned electric cooperatives, and a small number of federally chartered, government-run utilities.

The early stages of the evolution of cost approaches

Regardless of the organization of an electric utility, public or private, economic planning for a small station in the early 1900s was rather straightforward. The decision variables included at a minimum, and not taking consideration of transmission or distribution, the following;

– Capacity (MW): an estimate of capacity needs, how many kW or MW the plant could be expected to serve at any one instant in time, typically sized for the maximum or peak load.

– Energy (MWh): an estimate of the energy that would be generated, in terms of MW need times the time needed to provide for that load, often expressed as MWh.

– Owners’ cost ($ per kW of capacity): cost to build the power plant, including the cost of the equipment, cost to install the equipment, land purchase, any infrastructure improvements such as roads, and the cost to connect the plant to transmission or distribution networks as well as permitting and legal costs.

– Fuel: type of fuel used and cost of the fuel.

– Efficiency: efficiency of the power plant determines the amount and subsequent cost of fuel needed to generate MWh.

– Operational cost: annual costs to run and maintain the facility, from the cost of payroll and benefits to property taxes and/or utilities such as sewer or water.

Putting all of these factors together allows one, via a number of simple algebraic approaches, to estimate the total cost of providing power to customers. This allows the plant owner to determine what they must charge per MWh of electricity generated, also allowing for any profit margins or required return on investment. If the cost per MWh to provide for street lighting, for example, is less than the alternative gas-fired lamps then electric lighting is competitive.

In the early stages of utility development, the investment decisions were rather straightforward as there were only a handful of companies that made equipment that could generate electricity. The equipment was based on a very narrow pool of technology choices and fuel options were limited. As time went on, a host of changes happened across the electric utility space, including the consolidation of smaller utilities into larger ones and covering broader geographic ranges. Now cities became loads, and the generators were not always near the load, requiring transmission lines to move energy from where it was produced to step-down stations that energize distribution systems. A utility could no longer simply say they had 100 customers being served by 1 plant, they could have tens of thousands of customers across broad expanses being served by 10, 20, 50, or more generators. Power delivery increasingly became a network problem, with the loads considered as nodes or sinks (of MWh), the generators being sources (of MWh) and the transmission system being the network of physical cables moving MWh from sources to sinks. While complexities related to network systems are relevant, the idea of how changing technology and fuel types complicate cost decisions was, and still is, a fundamental issue in utility planning, so let us look at some of the technologies that emerged during the early years, up to the 1960s and