The use of Demand Response (DR) by utilities to help manage coincident peak is very common in the electric utility industry. The evolution of energy markets, with help from strong economic incentives, has enhanced the value of this DR capability and flexibility. As customers become more sophisticated in their energy management practices, there are more and more opportunities to exercise this flexibility on an operational basis. What happens when the complexity of managing multiple customers, each with specific flexible capabilities, grows beyond the ability of group to manually dispatch, control, and evaluate effectiveness of these resources?
Many utilities use a Flexibility Management System to optimize, control, and measure DR for retail customers in response to this added complexity and specificity. Customized flexibility products not practical in manual dispatch are enabled by the Flexibility Management System, and it can become an important milestone in the strategic future of an organization.
To develop a business case for investing in a Flexibility Management System, planners need to identify and quantify the costs and benefits, just as any capital investment, but also capture the many less obvious and strategic aspects of this decision. Part 1 of this article will discuss the basic elements of such a business case, with an overview of how to develop these elements into a financial analysis. Part 2 will dive deep into an example case, with detailed assumptions and inputs, along with conclusions and other observations.
What is the DR potential in the system?
The first practical step is to evaluate the potential for demand side flexibility, both in peak and total energy reduction. A really good profile of your customer population is essential. For utilities with a certificated service territory, or other stable retail customer obligation, extensive research into the quantity and patterns of power usage will reveal areas of potential.
- Is usage primarily driven by air conditioning? If so, modeling Cooling Degree Days (CDD) especially if historical info is present, can give a glimpse of available flexibility. Areas where air conditioning is utilized 2-3 months of the year will not yield as much as hotter regions in which A/C is used 6-8 months. More importantly, the weather patterns should be evaluated to identify whether and how often sharp spikes in temperature (and related A/C usage) happen.
- For thermostat control programs, analytics should be used to develop a correlation between demand reduction and the amount of thermostat setback. A general rule of thumb is about 1% demand reduction per 1 degree of setback. This is applicable to hot days, but of course not as much to temperate weather where air conditioning is less in use.
- What other factors drive peak power usage? In certain areas where natural gas distribution is scarce, residential customers rely on electric heating in winter. This can drive sharp, extreme spikes on cold winter mornings. Also, the degree of electric vehicle penetration in a market could drive power consumption spikes during prime charging hours.
- What additional programs will be enabled by the new Flexibility Management System? Will it increase the participation rate of residential customers, and by how much? What are the investment costs per customer to realize this incremental potential?
- Based on these concepts, a model can be developed that yields an expected reduction in demand based on specific residential customer programs.
- Does the system contain large office buildings, hotels, distribution warehouses, schools and colleges, and other institutions? Most companies and entities with large loads actively manage their energy use, seeking ways to reduce costs. This is where close engagement with the customer is important to identifying potential for participation. All other factors being equal, increasing the amount of flexibility derived from commercial customers relies on increasing participation rates.
- The new Flexibility Management System could provide new capabilities, generating new programs and higher participation rates. What is this incremental participation?
- Once again, close partnership with these entities can lead to creative approaches, such as process changes, maintenance scheduling, etc., to enable the customer to make energy reduction available to the utility during peak use periods. Again, the increased participation of this customer class due to improved deployment decisions and new capabilities enabled by the Flexibility Management System can enlarge the flexibility portfolio.
The total flexibility potential of the system is just a starting point. Dynamics such as notice time, duration, and frequency of interruption impact the realistic demand response potential available to the utility. (These concepts are discussed in a separate article.) All these factors open up new and different products for customers. An estimate of the incremental amount of demand reduction, both in peak megawatts as well as megawatt-hours, enabled by the Flexibility Management System should be developed.
What is the value of this flexibility?
There are several streams of value to be estimated. These have also been discussed in the ‘Value of Demand Response Participation to the Retail Customer‘ blog post, but for the purpose of creating a business case for an integrated control platform, a systematic approach to summing up this value could look like this:
- What historical grid-related costs have been allocated based on coincident peak, and what is the trend going forward? In many regions, the reduction of one megawatt in peak demand translates directly into a hard savings in grid costs that are allocated based on load ratio share.
- What are spot electricity prices during peak times? In many markets, these prices can be many times higher than average real time prices. Whether one uses these prices to value potential sales of excess power due to demand reduction, or to calculate cost avoidance, the value is the same. In estimating the value of the energy that demand side flexibility produces, it is useful to analyze both forward prices for power as well as historical spot prices. A forward curve for power can be developed over the analysis time frame. Also, historical spot price analysis should focus only on the daily hours that flexibility is deployed (typically afternoon and evening periods).
- What is the option value of demand side flexibility? More than just the value of the energy saved (or sold), the ability to call on a resource when needed is additive to the other value streams. Although an explanation of how to develop option values for electricity is beyond the scope of this article, the forward curve for power and other market price forecasts is a first step in this calculation. There are many other sources available which can assist with this analysis, or one can simply ask power market participants for quotes. In any case, the more flexible the DR asset, the more option value.
- What are other long-term benefits? Perhaps less concrete, but no less real, are the intrinsic, longer term benefits of this DR potential. These will be discussed later in this article.
Current Operations Versus Incremental Gains
An important consideration when developing estimates of total value of the available flexibility on the demand side is a realistic look at current operations. What DR actions now being utilized? What system (even if it’s manual) is being used, and how much value is currently being derived? What are the costs for current DR programs, both in terms of revenue loss and direct capacity payments to commercial and industrial customers? For transparency to decision-makers, the steady state, current conditions should be presented, and then the incremental value of implementing an integrated, intelligent optimization/deployment/validation system.
Cost estimates on new Flexibility Management System
Now that we have a reasonable estimate of the value that an integrated Flexibility Management System can bring, let’s focus on costs. The most obvious and visible cost will be the direct capital cost of the system, but several other costs must also be calculated. Implementation of the system usually includes a fairly large effort involving networking, systems integration, communication upgrades, investment in field devices, potential SCADA upgrades, training, and certification.
Some Flexibility Management System incur an up-front investment, along with annual costs for maintenance of the system, licenses, upgrades, and system support. These should be estimated on a yearly basis going forward, with escalation, and should include hardware upgrades on a periodic basis. Hardware costs, both upfront and ongoing, should be part of the analysis as well.
Other Flexibility Management System are presented as an on-going service, with no direct up-front charge. However, there will be costs to integrate with other systems, to purchase field devices if necessary, and to manage the project. While this lessens the up-front capital investment, it may raise the ongoing annual costs.
Incremental flexibility program costs
Since the Flexibility Management System will enable more flexibility in DR deployment, an array of new and innovative DR products will become available for discussion with customers. Customers will expect to be compensated for offering higher value products. These incentives and payments may be denominated in $/kW-month, $/year, or similar measures. Even though some organizations treat these costs as purchased power and allocate them to fuels expense, they are still real costs, and should be included.
Finally, what can be expected in terms of lost revenue due to DR deployments? For completeness, the business case should contain mostly likely deployment scenarios, with estimates of incremental annual kilowatt-hour savings (and lost revenue). This section of the business case should also include a discussion of whether these losses are material to the company’s overall finances, as well as impact these losses in revenue have on payments to the owner, on taxes, and other factors. Finally, expected increases in retail rates should be factored into the forecast and the associated revenue losses calculated.
Now we have a comparison of DR value and costs, both initial and on-going. A table of expected revenues and costs over the organization’s typical investment horizon (let’s say 10 years) is developed. Next, we tabulate the initial and ongoing incremental costs of the system, with escalation, over the same time horizon, then discount these costs back to the present. Then the net present value of the incremental revenue stream is calculated. This will give an initial screen related to the payoff of the investment.
After this screen, it’s time for sensitivity analysis. What are the largest drivers of value and cost, and what is the uncertainty surrounding each? Rather than a single projection of annual performance, a band of high and low cases can be developed to help decision-makers see the possible upside and downside possibilities.
Analysis of the initial screen and sensitivities may yield high positive annual returns and short payback period, moderate returns and longer payback period, or even negative returns. Is this the end of the project? Far from it. Less quantifiable costs and benefits are as important, or perhaps more so, than the numerical projections listed above.
- In regions experiencing load growth, use of demand side flexibility as part of meeting peak obligations will blunt the growth of the peak, and can even delay investments in new power generation or other incremental power purchases. This also applies to distribution and transmission upgrades. A delay in a major capital investment reduces pressure on rates and financial metrics. This factor can be compared to the “do-nothing” option, and this difference should be part of the decision.
- Reduction in customer load, even across relatively short periods of time, can be readily translated into decrease in equivalent environmental emissions from power generation. Reduced carbon dioxide, SOX, NOX, and particulates are directly accomplished, but actual fuel savings should be acknowledged too.
- The hardest to quantify, but probably the most important intangible benefit of an integrated, intelligent Flexibility Management System is its enablement of other future technologies and operational approaches. The introduction of new, creative flex products has been mentioned, but more broadly, the same platform that supports active flexibility optimization and deployment can be extended to the deployment, monitoring, and settlement of distributed energy resources (DERs). A universe of possibilities such as distribution-level energy storage, thermal resources, solar, micro-grids, electric vehicle charging systems, and other innovations not even conceived of now. Data interface standards such as Open ADR have been developed to enable this complex system to interact. Leading experts in the industry predict an explosion of technology solutions and businesses opportunities in this area. The Flexibility Management System is necessarily a first step in the evolution of the utility into this “smart grid” paradigm. The investment is therefore a strategic step for the organization, preparing it to move forward into the future.
As we’ve seen, there are many complex and dynamic factors involved in developing the business case for investment in a Flexibility Management System. These elements require involvement from diverse groups across the organization from customer service managers, to system operators, resource planners, accounting, finance, information technology, and leadership. Thoughtful vision is also necessary to grasp the strategic nature of this type of investment. It could be the most important decision the organization makes for many years.
Part 2 of this discussion will dive into an example of a hypothetical company with an active demand response program. We will look at the base assumptions and the incremental gains that a Flexibility Management System could bring. Detailed cost and revenue assumptions will be presented, and a 10-year table of cost versus benefit will be presented, along with a short sensitivity analysis.
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