Electricity Is Getting More Expensive — And It’s Not Because Power Is Scarce
Electricity customers in Minnesota are told that rising rates are the unavoidable price of grid modernization, reliability, and clean energy. That explanation sounds reasonable—but it avoids a harder truth. Electricity is getting more expensive not because energy is scarce, but because the system that delivers it has become increasingly centralized, capital-intensive, and insulated from accountability.
Wholesale energy prices across much of Minnesota remain relatively low. In organized markets like MISO, this is visible in locational marginal prices (LMPs), which frequently clear at modest levels outside of a limited number of constrained hours. Wind and solar are no longer premium resources, and in many hours energy itself is abundant. If the market price of energy is often low, why are many Minnesota ratepayers paying 12 cents per kilowatt-hour or more? The answer lies not in energy scarcity, but in the growing share of costs tied to capacity, reliability procurement, and cost recovery.
Reliability remains a core obligation of utilities. What has changed is how that obligation is met. Rather than relying primarily on local planning, owned assets, and demand-side solutions, utilities increasingly satisfy reliability requirements through purchased capacity, reserves, and centralized market products. These costs are recoverable through rates, largely opaque to customers, with capx costs and rates steadily increasing.
Here is the critical asymmetry: utilities readily pay centralized markets (MISO, PJM, etc) for capacity and reliability, but they strongly resist paying owners of smaller, customer-side resources that can provide many of the same services.
This is not because customer-owned resources lack value. As energy-market analyst Rao Konidena has observed, much of the capacity and reliability value from residential, commercial, and storage resources is not recognized in wholesale markets or enabled for aggregation. That value is nonetheless captured indirectly by utilities—through reduced peaks, lower system risk, deferred infrastructure, and avoided procurement—without being explicitly credited or paid to the asset owners who created it. The capacity exists, but it remains latent because utilities largely control whether customer-side resources are registered, aggregated, and operationally relied upon.
While this issue has been publicly documented in PJM—where roughly 1,500 MW of residential demand response existed but never appeared in capacity auctions because utilities did not enable registration or aggregation—the scale of the problem in MISO and in particular Minnesota is likely larger. Estimates suggest that on the order of 8,700 MW of customer-side capacity in MISO remains unregistered or uncredited.
Perhaps the barriers in MISO look different than in PJM: legacy constructs, utility exemptions, limited aggregation pathways, and wholesale contract structures that mute price signals. But the outcome is the same. The system behaves as if this capacity does not exist, even while benefiting from it at the margin. The outcome is similar. Minnesota rates climb when they don’t need to.
That capacity didn’t disappear from the grid. It disappeared from accounting.
The predictable outcome is tighter capacity margins on paper, higher clearing prices, and higher costs passed on to ratepayers—without a corresponding improvement in service or reliability.
Importantly, this exclusion is not a technology or telemetry problem. For more than a decade, inverter and storage manufacturers—working through organizations such as the SunSpec Alliance and IEEE—have developed robust, interoperable communications protocols that support monitoring, verification, and control of distributed resources. Many modern grid-interactive inverters and batteries can provide real-time data and respond to dispatch signals with minimal additional hardware, often requiring only a gateway. These same protocols are already being used in other states to aggregate and compensate distributed capacity. Where behind-the-meter storage remains uncounted, the limiting factor is not technical capability, but whether utilities choose to enable, trust, and pay for capacity delivered by assets they do not own.
If capacity and reliability procurement are the primary drivers of rising costs, it follows that transmission is increasingly being justified as a solution to a capacity problem—not an energy problem. But large-scale transmission does not necessarily reduce capacity costs, nor does it guarantee lower rates. In many cases, it simply shifts where capacity is sourced while adding substantial capital expense that must be recovered from ratepayers over decades. Transmission can move power, but it does not create new capacity, eliminate peak demand, or replace the need for local reliability resources.
Against that backdrop, one of the largest contributors to rising rates in Minnesota is the massive transmission build-out now underway across the region. Tens of billions of dollars in new transmission—often cited at $30 billion or more—are being planned or constructed to move power from remote generation sites to load centers, in support of Minnesota’s statutory requirement to reach 85% carbon-free electricity by 2030.
On paper, this transition should lower costs. Renewable generation is generally cheaper than fossil-fuel generation. In practice, however, much of the new clean energy is being built hundreds of miles from where it is actually used, requiring extensive transmission, substations, interconnections, and system upgrades. Those infrastructure costs are layered on top of generation costs and passed directly to ratepayers. The full rate impact often isn’t clear until years later—after projects are approved, built, and their costs have escalated.
What makes this more troubling is that utilities are not required to meaningfully project long-term retail rate impacts in a way that creates real accountability. Projects are proposed with cost estimates that appear reasonable at the time, approved by regulators such as the Minnesota Public Utilities Commission, and then built. But what a project is expected to cost in “2026 dollars” often increases substantially by the time it is completed. Those overruns are rarely borne by utilities or investors; they are absorbed by customers. Capital spending grows, financial returns are protected, and ratepayers are left carrying the obligation.
Behind-the-meter solar illustrates the dynamic clearly. Solar reduces net load and system peaks whether it is registered or not. Battery storage is different. Most of its system value depends on timing, verification, and deployment. When utilities decline to operationally rely on customer-side storage, that value remains latent. Utilities may still benefit indirectly through reduced peaks and lower system risk, but customers are not paid because their assets are not formally recognized or dispatched under existing structures.
Local battery energy storage systems (BESS), whether paired with solar or standalone, can shave peaks, reduce congestion, defer transmission, and provide fast-responding reliability. These benefits are real. What’s missing is transparency—and compensation. Commercial and industrial customers are charged based on coincident and non-coincident peaks, yet when they invest in batteries that reduce those peaks, most of the economic value accrues to the system, not the customer. Residential batteries are often treated as if they do not exist at all.
Local Authority, Delegated Away
This system was never supposed to function this way.
Public power and cooperative utilities were originally intended to have the ability—and the responsibility—to pursue local resources when they were cheaper, more reliable, or better aligned with community needs. Over time, many co-ops and municipal utilities have voluntarily delegated or waived that authority, relying instead on centralized wholesale contracts and market procurement to meet their obligations.
The result is that local generation, local capacity, and local flexibility are no longer evaluated on their merits. Even when customer-owned or community-scale resources are demonstrably cost-effective, utilities are often structurally prevented—or contractually discouraged—from using them. Centralized procurement becomes the default, not because it is cheaper, but because it is administratively easier and financially familiar. Paying centralized markets for capacity and reliability is treated as prudent. Paying local customers or communities for providing the same services is treated as an exception.
This is not a failure of clean energy. It is a failure of how capacity, reliability, and cost recovery are planned and compensated. Minnesota’s clean-energy transition does not require ever-larger transmission projects, rising capacity costs, and the systematic exclusion of local solutions. It requires recognizing, enabling, and paying for resources that already exist—whether they are owned by customers, communities, or local utilities themselves.
The question is no longer whether these resources can contribute.
The question is whether the system is willing to use them.
I started this blog because after many years working in renewable energy and electrical construction, I’ve watched the gap widen between how the utility industry explains rising costs and how those costs are created. The system is esoteric and opaque.
I’ve raised concerns privately, in meetings and discussions with policymakers and industry participants, and often felt they were politely acknowledged—and then ignored.
This space is an attempt to say some of those things publicly. At a minimum, it offers a field-level perspective from someone who builds and connects these systems. At best, it might help broaden the conversation about reliability, cost, and the role of local resources.
This is the first of several posts. My focus is on distributed generation and storage.