In previous articles in this series, I’ve written about how the grid operates, the sources of the power that supply the energy needs of our members, and how the cooperative finances its operations. In this month’s article, I’d like to dive more deeply into this latter topic...how utilities set rates and the purpose for the various rate components. Before going any further, I’d like to acknowledge there are probably more interesting subjects than utility rate design. Regardless, I encourage you to read on to gain a deeper understanding of how your electric, water, sewer, and phone bills may be structured as they are. This article will obviously focus on the most interesting and important of them…your electric bill!
First, let’s begin with an illustration. The image to the left shows a $100 bill. The top line of the chart shows the total revenues that were collected through our rates in 2022 and how those revenues were used, or spent, during that year. Specifically, in 2022, KEC collected $57,948,718 from members through its rates and spent $25,884,494 purchasing or producing the power our members used in that year. Stated differently, $44.67 of every $100 our members paid in rates (or 44.7%) was used to purchase or produce the power they used.
Another $16.24 was used to operate and maintain the electrical system that delivers power to members’ homes and businesses. Also included are the costs of restoring power in the aftermath of storms and other events causing outages. $12.32 out of every $100 collected in rates was used to provide administrative service and support to members.
$21 out of every $100 collected in rates was used to cover depreciation expense, property taxes, and interest expense on long-term debt. Net of all expenses incurred, KEC closed the year with $3,341,174 in net margins which reflect our members’ contribution to equity. At the discretion of the board of directors, that contribution is allocated to members in the form of capital credits. Recall from my article on Cooperative Finance 101, capital credits are retained by the cooperative as an equity investment in the cooperative for a period of time approximately equal to the life of the facilities those investments were used to finance.
Let’s consider next what drives our expenses. Interest expense, for example, is a function of the long-term debt used to finance the cooperative’s electrical infrastructure. This includes the poles and wires that carry power to your home or business, the trucks and equipment used to install and maintain them, the cost of materials in inventory needed to support construction, maintenance, and outage restoration, the investment in the computer systems used by the cooperative, etc. When new debt is issued to fund capital investments, the terms of those loans are generally correlated to the anticipated life of the assets they are invested in, typically about 30 years. Interest expense is therefore an example of a cost that is “fixed.” It does not vary with the amount of power used by our members.
Depreciation is another fixed expense. Depreciation reflects the value of an asset that is “used up” during the year. Consider a pole that is installed for $3,000 and will last around 30 years. Each year, $100 of that pole’s value is considered “used up.” At the end of its life, that pole will likely need to be replaced with a new one. Even though depreciation is a non-cash expense, accounting rules require depreciation of assets be treated as an expense.
Member services and support reflect the administrative costs related to supporting our members and operating the cooperative. Operations and maintenance expenses relate to the day-to-day costs of maintaining lines and rights-of-way and restoring power in the wake of outages. These costs vary based on the number of members the cooperative serves and the number of miles of power lines the cooperative owns, respectively. Like interest and depreciation expense, they do not vary with the amount of power our members consume, so they are also “fixed.”
The cost of purchasing or producing power amounts to $44.67 of every $100 collected in rates (or 44.7%). It’s logical to conclude that these costs are volumetric in nature and vary in proportion to the amount of power our members consume. In actuality, only a fraction of these costs are volumetric. Why is that?
As mentioned in prior articles (July 2024 in particular), KEC purchases about 70% of its power from the Bonneville Power Administration (BPA). That power is produced by the federally owned dams that operate on the Columbia and Snake Rivers and is sold to utilities like KEC “at cost.” Like KEC, BPA must cover its costs through the rates it charges. Since water produced from snow melt and rain fall is essentially free, nearly all of BPA’s costs are related to the recovery of the fixed costs (interest, depreciation, and operations and maintenance expenses) of the hydro infrastructure used to turn water into electricity and deliver it to market. These costs do not vary with the amount of power produced and sold.
The other 30% of our power comes from non-federal resources. Here, too, the cost of power produced by those resources is primarily fixed. These resources must be brought to load as flat blocks of power for all hours of the year and are based on forecasts of future power requirements of our members. Similar to our BPA contract, these contracts are structured on a “take or pay” basis.
When our members use more or less power than supplied through these “take or pay” arrangements, BPA supplies or remarkets the difference. However, the price BPA customers pay for additional power is usually higher than the “take or pay” rate and the rate reimbursed for remarketed power is lower than the “take or pay” rate. The reasons for this are good but well beyond the scope of this article. Suffice it to say that the “take or pay” rate is one that has been fully planned, scheduled, and hedged for risk while differences in energy requirements have not been. That comes at a cost. So, the power purchased at the “take or pay” rate is fixed while deviations from it are volumetric. More specifically, these volumetric costs are referred to as “energy based” costs and vary by how much energy is consumed or avoided.
In addition to energy based volumetric charges, the cooperative also incurs costs related to how much energy its members simultaneously use during the hour of the month when consumption is the highest. This is known as a demand charge and is measured in kilowatts. Let’s say you have a 100-watt light bulb that stays on for 10 hours per day during a month with 30 days in it. That light bulb will consume 30,000-watt-hours, or 30 kilowatt-hours, in that month. That light had a demand of 100 watts or 0.1 kilowatt.
Why is this important? Presume for a moment that the electrical consumption for your home or business remained unchanged day and night and season to season. If that were true, the transformer and electrical cables connecting your home or business to the electrical grid could be sized smaller than they actually are and would cost less to install. In reality, this just isn’t the case. Electrical consumption varies greatly between times of minimal use, like at 3 a.m., and times of higher use such as when the Thanksgiving dinner is being prepared or when the temperature outside is below zero. For this reason, the transformer and electrical cables connecting your home or business to the grid need to be sized to meet that peak demand. The additional cost associated with building the grid needed to serve the peak load of a utility’s customers is recovered through demand charges.
In addition to the fixed, energy, and demand charges you may see on your utility bill, you may also see charges like taxes, regulatory charges, and franchise fees. The first of these, taxes, is intuitive. Regulatory charges are similar to taxes but typically relate to the costs of complying with governmental policy and are passed directly on to utility customers. Reflecting these charges on a bill in this manner is the utility’s way of informing customers of the costs imposed on them by others. Franchise fees are a form of regulatory charges imposed by cities in which utilities operate. They are assessed by cities as a form of tax intended to cover the costs of city operations related to regulating utility services provided to its constituents. Customers of the utility living within these jurisdictions pay these costs while those living outside them do not. Franchise fees are also passed directly on to the utility customer.
By now, you may have pulled out a copy of your recent electric bill and seen the following charges:
- Service Availability Charge: Covers the fixed costs of providing service to your home. As described above, these costs do not vary with the amount of power used.
- Energy Charge and Power Cost Adjustment Charge (PCA): Collectively, these two charges cover the volumetric costs of producing and delivering the energy, measured in kilowatt hours, consumed during the billing period. The energy charge reflects the cost of this energy as of 2016 when the PCA was reset to zero and embedded in the energy charge. The PCA reflects the incremental cost of producing and delivering energy to our members since that time. Interestingly, all rate increases our members have experienced since that time are wholly attributable to the incremental cost of obtaining power from BPA and other power suppliers. The impact of all other cost increases realized by the cooperative since that time have been overcome by the growth in our membership. In other words, growth in our member base has helped keep costs lower than otherwise possible.
- Demand Charge: If you are a commercial member, you will also see a demand charge on your bill, measured in kilowatts. If you’re a residential member, the cost of demand is actually included in the energy charges and service availability charge you pay. This is done for two reasons. The first is billing simplicity: most residential members would prefer not to think about when they use power. The second reason is that in the past the electrical grid had a surplus of generation and transmission capacity. Unfortunately, as discussed in previous articles, this is no longer the case. The cost of power, and in particular the cost of capacity which is recovered through demand charges, is increasing significantly. This is a function of supply and demand.
Public policy has made it difficult to develop new generation resources. Those that are being built are not the right kinds to keep up with load growth. Public policy has placed emphasis on non-dispatchable renewable resources (wind, solar) as opposed to those that can be ramped up or down to follow changes in system load. See my articles from May and June for more information about this. At the same time, electrical use nationwide, and specifically in the Pacific Northwest, is skyrocketing.
The cost of power produced by the federal dams, which reflects 70% of our total power requirements, will increase 10% next year. The cost of purchasing the balance of our power requirements from non-federal resources will increase by 20% next year. The cost of transmission, which reflects 10% of our total power supply costs, will also increase by 20% next year. Demand costs will increase by 24% next year. Recognizing that nearly 45% of our total revenues collected through rates is related to the cost of purchased power, retail rates will need to increase by at least 7% just to cover that expense.
Despite how sobering those impacts on rates can feel, there is some good news I’d be remiss not to point out. The industry as a whole, and the Pacific Northwest in specific, are making the investments necessary to ensure we have the power needed to meet the needs of our members for the foreseeable future. What this means is that the risk for blackouts or brownouts is being addressed so that they do not occur or, if they do, their impact is minimal and manageable.
You can also rest assured that KEC is doing everything within its power to ensure the impact of the rate increase which we can directly control is also minimized.