Storage Changing Paradigms in Electric System Design and Operations

by Bob Shively, Enerdynamics President and Lead Facilitator


“Building networks to accommodate peak demand – or lulls in supply – requires overbuilding of infrastructure that leads to extra costs and system inefficiencies.”
Sam Wilkinson, IHS [1]


As we explored in last week’s blog, the gas system has optimized the mix of pipeline capacity, storage, and customer demand management to reduce the costs of building expensive infrastructure.

While the electric grid has utilized demand side management to reduce peak capacity needs, it until recently only had one cost-effective form of storage — pumped hydro — which is only available in limited geographic regions. (As of 2015, the U.S. had 156 pumped hydro plants that made up 2% of the peak summer capacity.) Hence almost all fluctuations in demand are met by adjusting supply through power plant dispatch.  The result is significant power plant capacity that sits idle much of the year.

However, recent advances and falling costs in electric storage technologies, especially lithium ion batteries, suggest that a new paradigm of optimized storage throughout the grid may rapidly change principles of electric system design and operations.

“Similar to the rise of wind and solar generation in the last 15 years, we are now starting to see exponential growth in the deployment of battery-based energy storage systems, thanks in part to a rapid decline in pricing for lithium-ion batteries.” [2]


Cost declines in lithium ion batteries
    Source:  Bloomberg New Energy Finance

The potential for cost-effective electric storage is coming none too soon — the system that once had to accommodate fluctuations in demand now needs to also accommodate lulls in supply as more renewables with variable output are connected to the grid. This is true on the bulk power system as indicated by the now famous California duck curve as well as on specific distribution circuits as demonstrated by the Hawaii “Loch Ness Monster” curve.

duck curve

loch ness curve

Fortunately, the modular nature of batteries allows for the possibility of placing storage on the grid where it is most beneficial, ranging from centralized renewable generators all the way to behind the customer meter. Making distributed storage most useful will require communications systems that allow storage to be operated as part of the greater distribution and/or transmission system. Again, developments in battery technologies are being accompanied by rapid expansion of digital communications networks throughout the distribution grid all the way to the customer meter.

storage deployment across grid

Source: EIA Today in Energy  

Many utilities are now implementing various storage projects to develop the knowledge that will result in growing use of developing storage technology. We will look forward to watching the evolution of the electric grid as cost effective storage allows new forms of optimal design and operations.


Want to learn more about how electric systems work?  Look into Enerdynamics’ Electric Systems Fundamentals seminar available online or live. And if you want to learn more about energy storage, contact us about Enerdynamics’ live seminar Energy Storage: Applications, Technologies, and Economics.


[1] From Reaching peak performance: What the electric power sector can learn from society’s other vital networks, Sam Wilkinson, available at

[2] Ibid, p. 3

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Storage in Design of Gas and Electric Systems

by Bob Shively, Enerdynamics President and Lead Facilitator

“Building networks to accommodate peak demand — or lulls in supply — requires overbuilding of infrastructure that leads to extra costs and system inefficiencies.” ~ Sam Wilkinson, IHS [1]

A key to efficient design of gas networks is the interplay between pipeline capacity that can deliver supply into a region and storage that can supplement supply when flowing pipeline gas is insufficient to meet demand.

As costs for certain electric storage technologies decline, designers and operators of electric systems are beginning to envision a future where electricity storage will be used to significantly improve the efficiency of electric networks in a similar way. Let’s explore the principles behind use of storage to improve system efficiency and look at how storage is used in gas systems. Next week we will discuss how it may be increasingly used in electric systems.

As described by Sam Wilkinson in the IHS whitepaper Reaching Peak Performance, networks are commonly designed to ensure that supply can meet demand even during periods of unusually high demand and or lulls in supply (although this is not always true — failure to build for peak demand is why we end up sitting on the freeway during rush hour or can’t text on our phones during a popular sporting event). Of course, building for peak demand is expensive. The result is that consumers must pay for facilities that sit idle much of the time.

An example of this from the electric world: the California ISO has a typical annual peak load exceeding 46,000 MW while the typical average annual load is more like 22,000 MW. To ensure the peak can be met, the California system maintains about 55,000 MW of capacity plus transmission to import power from out of state. This means that almost half of the system is underutilized during numerous hours of the year. Indeed, looking at the load duration curve for California shows us that the last 15,000 MW of supply is needed for less than 10% of the hours of the year.

Hourly demand in the California ISO for typical summer week

CAISO demand

California load duration curveCAISO load duration curve

Similar disparities exist for gas supply and demand. A typical annual average gas demand in California for “normal” weather is around 6 Bcf/d. This rises to about 7 Bcf/d for a year that includes a cold winter (lots of heating load) and a low hydro year (lots of gas power plant demand). Yet the highest daily sendout recorded in recent years was 8 Bcf/d in the summer and 11 Bcf/d in the winter.

How Gas Operators Use Storage to Meet Peak Demand

Absent storage, the gas companies in California would need to build over 11 Bcf/d of pipeline capacity into the state to ensure ability to meet the peak. And a similar effort would be required to match capacity and peak demand for each local transmission line and each distribution feeder serving a neighborhood. But luckily natural gas can be stored — in the pipeline itself, in underground reservoirs, and in above-ground tanks.  This gives operators the flexibility to pack extra gas into pipelines prior to expected cold days and to draw from underground storage when flowing supplies are insufficient to meet demand.

gas storage slide

California also uses utility regulations that require large industrial and power plant customers to accept curtailment of supply on peak demand days unless the customer wants to pay extra for firm service. Thus, on peak days, there can be a demand response as utilities notify large customers they must curtail gas use. This means that portions of the gas system do not have to be sized to cover these customers on extreme days.

The result of mixing and matching pipeline supply capacity, underground storage capacity, storage in the pipe, and demand response is that California has reliably run its gas system with the approximately 8 Bcf/d of pipeline capacity and 4.5 Bcf/d of storage capacity. This is significantly more efficient than building enough pipeline capacity to cover peak needs.

Historically, the electric industry has built supply capacity to cover peak needs, plus an additional 15% reserve margin for ensuring reliability. In next week’s blog, we’ll explore how storage and demand response may change the paradigm for electricity, allowing the industry to attain some of the system efficiencies gas has achieved.

Want to learn more about how gas systems work?  Look into Enerdynamics’ Gas Systems Fundamentals live seminar.


[1] From Reaching peak performance: What the electric power sector can learn from society’s other vital networks, Sam Wilkinson, available at

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Demand Side Management Key to California’s Changing Grid

by Bob Shively, Enerdynamics President and Lead Facilitator

The role of demand side management (DSM) programs traditionally has been three-fold:
Eco Time or washing

  1. reduce overall usage through energy efficiency (EE) efforts (for example, weatherization or more efficient light bulbs)
  2. reduce usage at times of system peak or system shortages (for example, direct load-control switches on air conditioners or hot water heaters that allow interruption by the utility)
  3. shift demand from peak periods to off-peak periods (for example, ice storage systems for building cooling)

The overriding purpose of such DSM programs has been to offer an alternative to building costly new power plants. But as the grid changes with the rise of renewable and distributed energy resources (DER), the role of DSM itself is positioned for dramatic change.

With California’s renewable goal of 50% by 2030, grid issues are extreme. To determine how DSM might best help support the grid, the Lawrence Berkeley Lab recently worked with consulting firms E3 and Nexant along with various market participants to perform the study 2025 California Demand Response Potential Study – Charting California’s Demand Response Future. Over a two-year period, the team used customer-specific data to evaluate end-use and technology capabilities while focusing on two questions:

  1. What types of demand response services can meet California’s future grid needs?
  2. What is the expected resource base size and cost for demand response services?

A key part of the study was to move away from just thinking about traditional types of DSM and to ask what specific services does the grid need to best utilize DSM resources. The study identified four demand response (DR) service types that will be most helpful:

  1. The shed service is similar to traditional load management programs where load such as air conditioners or hot water heaters are curtailed during peak times.
  2. The shift service is similar to traditional peak demand shifting, except that in the future grid it is expected that it will be necessary to shift load into the middle of the day to utilize the significant solar generation that will come onto the grid.
  3. The shape service accomplishes the same load movement as shed or shift, but instead a service where the load is moved only when needed, the shape service results in permanent changes in load shapes.
  4. The shimmy service moves loads up or down quickly in response to specific system needs, possibly in time increments as small as every 5 minutes or even less.

Likely end-use technologies included in California programs are:

  • electric vehicles (EVs)
  • behind-the-meter batteries
  • air conditioning and HVAC systems
  • pool pumps
  • commercial lighting
  • commercial refrigeration
  • large industrial processes
  • agricultural pumping
  • data center loads
  • wastewater treatment and pumping

The study’s medium demand response scenario for California found that the current time-of-use (TOU) rates and critical peak pricing (CPP) programs provide 1 GW of shed and 2 GW of shift. New programs could provide up to 10 to 20 GWh of daily shift, 2 to 10 GW of cost-effective shed, and 300 MW of load-following or regulation shimmy. So clearly there is significant potential here.

What is needed to make this happen?

The study cover letter from the California Public Utilities Commission (CPUC) suggests that key steps include:

  • Investing in the integration of demand response into wholesale markets where it can be dispatched consistent with locational marginal prices
  • Enabling a new generation of demand response aggregators capable of delivering tailored options that work for customers with unique needs
  • Committing to default TOU rates for all customers
  • Committing to a greater differentiation of incentives based on relative locational value (meaning that DSM provided at one location might be paid more than the same DSM provided at a less valuable location)

As the grid continues to evolve, it will be necessary to reformulate traditional DSM programs to get the most potential from available flexible customer loads. Our expectation is that load resources will be increasingly important in allowing grids to integrate large amounts of renewables at the least cost possible.

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The Composition of Produced Natural Gas and Why It Matters

by Bob Shively, Enerdynamics President and Lead Facilitator

Typical natural gas composition

Natural gas composition refers to the amount of various constituents that make up a stream of natural gas. Though natural gas is mostly methane, there are many other components. Gas composition varies by well, but a typical composition of raw gas produced from a gas well is as follows:

raw natural gas

Before natural enters a transmission pipeline it is processed. Valuable natural gas liquids (NGLs) are separated to be sold as additional products and impurities are removed and disposed of. The result is pipeline quality gas that can be moved via pipeline and sold to consumers:pipeline gasDepending on the composition of the raw gas stream, there may also be multiple NGL streams that can be sold.

Natural gas liquids stream for a “wet gas” source:

wet gas

Why composition matters

Based on the market price of the various components, producers may receive more revenues from natural gas sales or more from sales of NGLs. The market value of the different components can determine which gas wells are most economic to produce, as well as the optimal mix of components to be removed and/or left in the natural gas stream. 

NGL v HH prices

Source: EIA website

In a low gas price environment, NGL value is a key component of producer revenue. You can especially see the importance of liquids in the 2011 to 2014 time-frame on the above price graph. During this time, producers pushed to produce as much “wet gas” (meaning gas with lots of liquids in the raw stream) as possible. More recently, a glut of NGLs plus a reduction in the price of petroleum has led to reduced NGL revenues. As you might imagine, gas producers closely watch price trends for both NGLs and natural gas in developing and implementing their ongoing production plans.

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Will U.S. Natural Gas Pipelines Get a Piece of the Government’s $1 Trillion Pie?

by Christina Nagy-McKenna, Enerdynamics Facilitator

The Trump administration has sounded the horn: It wants to strengthen United States’ Washington Money.infrastructure to the tune of $1 trillion. Highway projects, bridge projects, water and energy infrastructure projects — the list of needs is long and the corresponding price is hefty. Many in the energy industry hope some of the proposed infrastructure investment money comes their way.

Gas pipeline companies are already linking shale fields to parts of the East where capacity is tight and winter supply prices are vulnerable to severe price spikes. More is needed, they say, particularly in New England where memories of the winter price spikes of 2014 and 2015 are still fresh. Clean energy advocates are hoping to see new electric transmission lines get built and integrate with renewable projects that reduce the industry’s carbon footprint. The urgency to do both of these is further driven by the closure of coal and nuclear power plants and the christening of new natural gas-fired power plants in their place.

Who pays for new natural gas and electric transmission lines is still up for debate as is exactly how the financing will come together. Officials within the new administration have mentioned tax incentives to stimulate infrastructure spending and possible public-private partnerships. In the regulated utility world, distribution and transmission companies historically have recovered costs from their utility ratepayers, however a recent Massachusetts Supreme Court ruling flatly turned down the idea that electric rate payers fund a natural gas pipeline project.

The August 2016 decision put an immediate chill on Spectra Energy’s (now Enbridge) Access Northeast pipeline project. The expansion of the Algonquin pipeline and new LNG storage was to provide enough gas to make 5,000 megawatts of power. After the Supreme Court ruling, utilities Eversource and National Grid pulled out of the project as did four additional area utilities. Enbridge will continue to try build the project, but the uncertainty of the pipeline’s funding has slowed progress.

The Access Northeast pipeline project uncovered another issue: the tension between those who believe that more natural gas pipelines are needed and those who believe that no new pipelines should be built and that demand side management (DSM) is the key. In this case, Attorney General of Massachusetts Maura Healey not only disagreed that the electric utilities interested in the Access Northeast project should pass the costs onto their customers, she also questioned the need for more natural gas pipeline capacity in the area. She commissioned a research study, “Regional Electric Reliability Options Study,” that found the region could maintain current reliability standards until 2030 without making infrastructure changes. The study also found that demand response programs and energy efficiency programs would help reduce customer demand while keeping customer risk low.

Other pipeline projects making recent headlines include:

  • TransCanada’s Keystone Pipeline and Energy Transfer’s Dakota Pipeline projects —  Both projects faced intense public protests before being issued permits by the new administration. Even though both pipelines were meant to ship oil, there is a concern in the natural gas industry that its pipelines may be subject to increased environmental scrutiny simply because they too are pipelines like Keystone and Dakota.
  • Dominion Energy’s Atlantic Coast Pipeline —  Federal Energy Regulatory Commission (FERC) staff determined this project should move forward even though it will mean impacts to the surrounding environment. Opponents do not believe that mitigation measures will make up for the damage, and others have questioned whether the 1.5 Bcf/day of natural gas is necessary. This tension between those who would build and those who would preserve the environment will likely continue.


Ultimately, pipeline projects that can show they are necessary and in the public interest will likely be built regardless of the new administration’s $1 trillion plan. So far in 2017, before it lost its quorum, FERC certified 7 Bcf/d of pipeline capacity. This is in addition to the 17.6 Bcf/d of pipeline capacity it certified in 2016. FERC certification does not guarantee that a pipeline will be built, thus the industry will need to continue to be aware of environmental, regulatory, and customer issues.



Regional Electric Reliability Options Study,” The Analysis Group on behalf of Office of the Attorney General Maura Healey, 2015.

“FERC Certifies Several New Natural Gas Pipelines in 2017,” U.S. Energy Information Administration, March 7, 2017.

“NE Natural Gas Pipeline Capacity Increases for First Time in 6 Years,” Oil and Gas, February 2017, Vol. 244, No. 2.

Moran, Paul, “Northeast Natural Gas Pipelines:  Is More Capacity Needed?”, Oil & Gas, February 2017, Vol. 244, No. 2.

“P&GJ’s 2017 Worldwide Pipeline Construction Report, Oil & Gas, January 2017, Vol. 244, No. 1.

Shallenberger, Krysti, “NARUC 2017: A Little Less Climate and a Lot More Infrastructure,” Utility Dive, February 16, 2017.

Walton, Robert, “As Utilities Ramp up Gas, Enbridge Play for Spectra Highlights Increasing Value of Pipelines,” Utility Dive, September 16, 2016.

Walton, Robert, “Constitution Pipeline Court Case Could Open Path to More Challenges from Greens,” Utility Dive, November 23, 2016.

Walton, Robert, “Eversource Mulls Pipeline Funding Options Following Massachusetts Court Setback,” Utility Dive, September 7, 2016.

Walton, Robert, “FERC Staff:  Atlantic Coast Pipeline Should Move Forward Despite Environmental Impacts,” Utility Dive, January 3, 2017.

Walton, Robert, “Massachusetts Court Bars Electric Utilities from Charging Ratepayers for Gas Pipeline Construction, Utility Dive, August 18, 2016.

Walton, Robert, “National Grid, Eversource to Pull Out of Access Northeast Gas Pipeline Project,” Utility Dive, August 24, 2016.

Walton, Robert, “New Study Says Atlantic Coast, Mountain Valley Pipeline Projects Unnecessary,” Utility Dive, September 14, 2016.

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Utility of the Future: Recent Study’s Six Key Findings

by Bob Shively, Enerdynamics President and Lead Facilitator

Electric utilities across the world are working diligently to identify new business models Ener_GOF_w_Header_4-11-17.pngthat will provide success in such a future world. Then each must begin the arduous task of implementing the models in a typically slow-moving industry.

To assist utilities in this task, the MIT Energy Initiative (MITEI) recently released the study Utility of the Future. The study was based on more than two years of primary research and analysis on how the provision and consumption of electricity services is likely to evolve over the next 10 to 15 years. According to the report authors, the study “aims to serve as a guide for policy makers, regulators, utilities, existing and startup energy companies, and other power-sector stakeholders to better understand the factors that are currently driving change in power systems worldwide.”

The study highlights six core findings:

    • Prices and regulated charges for electricity services must be dramatically improved: Locational time-based pricing should replace existing flat, volumetric tariffs. Grid injections and withdrawals should be priced the same regardless of time and place. They also support peak-based capacity charges that “unlock flexible demand and distributed resources and enable significant cost savings.” Lastly, MITEI recommends that care be taken in applying social goods and other network charges with the risk that inefficient grid defection may occur. To facilitate such pricing, all consumers and producers will need Advanced Metering Infrastructure (AMI).


    • Regulation of distribution utilities must be improved: Forward-looking, multi-year revenue requirements with profit-sharing mechanisms for cost-savings investment and operations will result in better outcomes for consumers and market participants. This includes equalizing financial incentives related to capital and operational expenditures so that utilities are not incented to build infrastructure when other solutions are more cost-effective. And, MITEI supports use of outcome-based performance incentives and incentives for longer-term innovation.


    • The structure of the electricity industry should be evaluated to minimize potential conflicts of interest: “Network providers, system operators, and market platforms constitute the critical functions that sit at the center of all transactions.” In the future, maintaining a data hub or data exchange is likely to become a fourth key function. Properly assigning responsibilities for these functions is critical. MITEI suggests that it is best if the entity or entities responsible for system operations and system planning are financially independent of competitive market participants. Without financial independence, strong regulatory oversight is necessary.


    • Wholesale market design should be improved to integrate distributed resources and create a level playing field for all technologies: Services traded in wholesale markets need to be updated to reflect the operational realities and new distributed resources as well as the new ways that conventional power plants are operated on systems with a high level of renewable and/or distributed resources.  Markets needing updates include capacity mechanisms, day-ahead and real-time markets, and payments for operating reserves and other ancillary services.


    • The importance of cybersecurity and privacy protections will continue to increase: Robust regulatory standards for cybersecurity and privacy must be developed and implemented across all sectors of the electricity network.


    • Better utilization of existing assets and more optimal energy consumption: Use of DERs for optimizing the system holds great potential for cost savings, but market participants must also be aware of potential for uneconomic deployment of resources if rate or market signals are improper.


Since the value of some electricity services varies significantly by location on the grid, it is “impractical to define a single value for any distributed resource.” Locational pricing will allow resources to be located in the right spot on the grid for highest value and unlocking this value can be an efficient alternative to traditional generation, transmission, or distribution investment. Due to economies of scale, widely distributed deployment of many technologies may be inefficient in some locations, but this may continue to change as new innovations transform the economics of any given application.

It’s clear that the future world envisioned by MITEI is far from where most utilities are today. To assist with the transformation, the last 18 pages of the study are devoted to a toolkit for regulators and policy makers. The electric industry must prepare for yet another huge market transformation. MITEI’s Utility of the Future study is a good reference manual to envision how the industry is likely to evolve.

Want to learn more about the future of the electric utility? Enerdynamics offers a one-day seminar titled The Future of the Utility: Business Models, Regulation, and Opportunities. Fill out the form below for more information on upcoming dates or on-site opportunities at your location.

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Updates Made to Most Popular Online Energy Industry Courses

When you purchase or site license any of Enerdynamics’ online courses you are able to access, without additional fees, the periodic updates made to these courses. Enerdynamics recently updated its two most popular online courses: Gas Industry Overview and Electric Industry Overview (including Canadian and Global versions). These updates are important as the industry evolves rapidly. Within just a few short years, energy industry data including customer, economic, and even regulatory information can change dramatically. These are the type of updates now found in both courses.

If you have site licensed either course and are running the files on your LMS, Enerdynamics already has or will contact you soon with download information for the new files. If you purchased subscriptions that run on Enerdynamics’ LMS, any new starts to either course will refer to the updated version. Those employees who already started a course prior to the update will continue with the existing course.

Gas Industry Overview and Electric Industry Overview present comprehensive introductions to each industry and are ideal for new employees or those who need a better “big picture” understanding of the industry.

For a demo of Electric Industry Overview, click here or on the image below:

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For a demo of Gas Industry Overview, click here or on the image below:

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For more information on these updates or how to make these courses available to your employees, contact John Ferrare at or 866-765-5432 ext. 700.

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A Typical Day at an ISO (Independent System Operator)

by Bob Shively, Enerdynamics President and Lead Facilitator

To prepare for an operating day, the independent system operator (ISO) must schedule units one day ahead of time to kansas_city_2_lprovide supply across the upcoming 24 hours. This is handled by the day-ahead scheduling process. Units are scheduled hourly, meaning that units will receive 24 schedules – one for each hour of the following day. The schedule tells the unit what services it is expected to provide and the amount of megawatts (MW) associated with each scheduled service.

For instance, for a given hour a unit with a capacity of 200 MW might have 150 MW scheduled to provide energy and 50 MW scheduled as spinning reserves. This tells the unit operator that for the given hour, it is expected to provide 150 MW of energy and must be prepared to ramp up an additional 50 MW if called on by the ISO.

Day-ahead Scheduling

The day-ahead process works as follows:

  • At a specified time in the morning, unit scheduling coordinators submit an offer to the ISO. This offer includes services the unit is willing to provide at a given price as well as various operational characteristics such as start-time, ramp capability, willingness to be started and then stopped, and minimum and maximum run times.
  • Simultaneously, load-serving entities (LSEs) submit hourly bids for buying energy to supply loads. Although LSEs sometimes state an unwillingness to buy energy above a certain price level, in most cases LSEs simply state a forecast load plus a willingness to pay whatever the price is to receive supply.
  • The ISO inputs expected system conditions including transmission availability and then runs optimization software to determine the least-cost dispatch available to serve the required loads given the various generation offers.
  • By the early afternoon, the ISO sends out schedules to each unit that was selected in the optimization process and notifies other generators that they have not been scheduled. The ISO also notifies all LSEs of the amount of load scheduled to be served. The optimization model creates day-ahead energy prices for each location on the grid and zonal prices for ancillary services. The energy prices are called locational marginal prices, or LMPs, and reflect the actual marginal cost of serving load at each location.
  • Since day-ahead schedules are considered firm, units are paid the LMP for their scheduled output, and loads are charged the LMP for their scheduled deliveries regardless of what actually happens in real time.
    day-ahead scheduling

Real-time Operations

A separate group at the ISO runs the system to ensure that supply and demand are kept in balance in real time during the operating day. This process works as follows:

  • The real-time operators have various units available to ramp up or down given the resources selected in the day-ahead scheduling process.
  • As the supply-demand balance fluctuates, the ISO ramps units as needed based on the offers accepted in the day-ahead. A real-time LMP is determined based on the price for marginal units used in ramping.
  • After the hour, the ISO calculates each unit’s actual output compared to the output scheduled in day-ahead. The real-time LMP is applied to any deviation from scheduled, and each unit is paid or charged (depending on whether the unit generated more or less than scheduled) based on the LMP at that unit’s location.
  • Similarly the ISO compares each LSE’s schedule at specific grid locations to the LSE’s actual usage. Again, the deviation from day-ahead schedule is either charged or paid depending on whether the LSE used more or less than scheduled.

Real-time operations

Want to learn more about ISOs and how they operate? ISO Market Basics, an online course by Enerdynamics, gives a thorough overview of how ISO markets work, how services (capacity, energy, operating reserves, and financial transmission rights) are bought and sold in an ISO, the role of ISOs and various market participants, and the various types of electric markets available to market participants.

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What is the Least-cost Source of Electricity in Your Community?

by Bob Shively, Enerdynamics President and Lead Instructor

Average Costs Across the U.S.

In our June 2016 blog post titled Economics, Not Policy Mandates, Drive the Growth of Renewables we described how the price of utility-scale wind and solar projects was becoming competitive with traditional forms of generation. The discussion was centered on data developed in 2015. Costs for renewables are decreasing so rapidly that an update using more recent numbers shows even more dramatic results. Stunningly, wind and utility-scale solar PV are now the two lowest-cost generation sources.

Levelized Gen Costs 2016

Source: Lazard’s Levelized Cost of Energy Analysis – Version 10.0, December 2016

Costs in Your Community

The University of Texas at Austin recently performed a related study titled New U.S. Power Costs: by County, with Environmental Externalities that takes into account generation costs similar to those shown above, but it also considered additional externalities. The complete list of factors considered include:

  • Power plant costs including operating plus capital costs
  • Fuel costs
  • Environmental and health costs including air quality and greenhouse gases
  • Infrastructure costs including transmission and distribution, rail, and gas pipelines
  • Integration costs for renewables and distributed energy resources
  • Opportunities for energy efficiency
  • Government financial support for electricity

The University of Texas study analyzed the lowest-cost form of generation by county across the U.S.:

lowest cost generation map.png

Source: Natural gas and wind are the lowest-cost generation technologies for much of the U.S., new UT Austin research shows, December 8, 2016

Here we see the dominance of wind in the Midwest, solar in sunny regions of the West, and natural gas combined-cycle turbines in much of the rest of the country. Interestingly, in a smaller number of counties nuclear power is the low-cost resource.

How Costs Affect U.S. Generation Mix

Not surprisingly, planned generation additions and retirements are reflective of cost data. 

Summer capacity additions.png

Source:  EIA website as of March 2017

Given that generation decisions are made at the local and state levels, it seems logical to conclude that regardless of federal policies the movement to gas and renewable generation will continue.



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Corporate Purchasers Are As Important as Utilities in Renewables Growth

by Bob Shively, Enerdynamics President and Lead Facilitator 

In recent years, new wind and solar electric generating capacity has outpaced all other sources of power. In 2016, the two renewables sources grew by more than 20,000 MW compared to the next largest source, natural gas, which grew by about 7,000 MW.

net changes in U.S. Summer Gen Capacity.jpg

Source:  Based on data from the EIA website

Much of this capacity has been built under power purchase agreements (PPAs) with utilities either because the utility needs the power to fulfill a state-mandated renewable portfolio standard or, increasingly, because renewable power has become the low-cost supply choice when the utility performs its periodic Integrated Resource Planning (IRP) process. But another key factor leading to the growth of renewables is growth of corporate end-use buyers who sign PPAs with renewable developers.

Indeed some analysts have suggested that corporate buyers have become as important as utilities. The Business Renewables Center tracks publicly announced corporate renewable deals and is showing  4,810 MW of new corporate-funded renewable capacity over the last two years.

corporate renewable deals.jpg

Source: Rocky Mountain Institute

Buyers include many well-known companies including Amazon, Apple, Dow Chemical, Google, Microsoft, and Walmart. Google announced that in 2017 they expect to buy enough renewable energy to account for 100% of their usage[1], (which is about equivalent to the energy usage by the city of San Francisco!).

Why Do Corporate Buyers Sign PPAs to Buy Renewables?

Corporate buyers are signing renewable deals for two key reasons. One is that a growing number of corporations have adopted corporate sustainability goals and/or believe that buying clean power enhances their marketplace image. But in many cases, corporate buyers are committing their dollars because they believe it is the best way to lock in reasonably priced power supply over the long-term.

As quoted in a recent Utility Dive article[2], Google’s director of energy and sustainability said: “We are not doing this because it will make us feel good.  These are economic decisions that are also good for the world.”

I’ve heard similar sentiment from the corporate energy buyer for Walmart who said when he goes to the Walmart board for approval for his plans, he doesn’t even mention sustainability; he simply sells renewables deals based on what is the most economic source of energy supply for Walmart. The key is that by signing fixed-price long-term PPAs, corporations are reducing their risk of future electricity price increases.

How Does a Corporate PPA Work?

In competitive retail markets where end users are allowed to buy directly from generators, it is easy to see how a company like Google can lock in fixed power prices through a PPA since the power they buy can be directly used by their end-use facilities[3].

corporate PPA

Source: Google whitepaper[4]

To make things work in a market where the utility is responsible for supplying power to end-use consumers is a bit more complex as demonstrated by the above graphic.

  1. Google buys energy bundled with renewable energy credits (RECs) from a renewable project in a long-term fixed price PPA. The PPA gives Google the rights to all MWh generated plus all RECs associated with the MWh.
  2. As energy is generated, Google resells the MWh into the wholesale market place. The revenue that Google receives varies depending on the market price of electricity. In some cases it will be higher than what Google paid to the renewable developer; in others is will be lower.
  3. Google buys energy supply for its data center from the local utility and pays the regulated utility supply rate. While the cost of the utility supply rate may not exactly match up with the revenues Google receives from selling power in the wholesale market in Step 2, there should be a decent correlation between the two prices since the utility also buys power from the market.
  4. Google applies the RECs to its consumption to verify that its use of electric supply is backed by renewable generation.

While the renewable PPA isn’t a perfect price hedge relative to the cost of utility supply, it is expected to be a reasonable hedge against utility rate movements. And Google gets one other significant benefit — the output from the renewable project does not have to match up in time with consumption by the data center since the utility grid is being used to “store” power when generation and usage doesn’t match.

What is the Future of Corporate Renewables Purchases?  

The Rocky Mountain Institute estimates that over 60,000 MW of new renewables will be needed by 2025 to meet corporate clean power goals. Sixty-five key companies have created a set of Corporate Buyer’s Principles that are intended to guide utilities and regulators in setting rules that allow for ease in signing long-term PPAs.  Signatories include most of the companies already mentioned here plus other well-known companies including Target, Gap, GM, Kellogg’s, Hilton, Starbucks, and McDonald’s. By all indications, corporate support for renewable projects will continue to grow even if U.S. government policy does not support renewables.


[1] See ‘We’re set to reach 100% renewable energy — and it’s just the beginning’ at

[2] See ‘Mutual needs, mutual challenges: How corporate PPAs are remaking the renewables sector’ at

[3] There is still an issue associated with the locational value of power if the generator is not located at the same point on the grid as the consumer, but we will explore that issue in a future blog.

[4] See  ‘Achieving Our 100% Renewable Energy Purchasing Goal and Going Beyond’ at

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