Every large energy or data-center project that arrives in a Kansas county comes with a story about who benefits. The story is usually true, as far as it goes — jobs are created, tax revenue eventually flows, and a landowner or two receives a genuinely life-changing check. What the story leaves out, more often than not, is the second half of the ledger: who fronts the money before those benefits arrive, who bears the risk if the promised load never fully materializes, and how much of the "public benefit" was actually paid for by the public. American Rural Heritage Foundation believes rural Kansans deserve the whole ledger, not the half that fits on a press release. This is our attempt to lay it out plainly.
How a project actually gets built and connected
Nothing gets built without first connecting to the grid, and that process itself allocates cost in ways worth understanding.
When a wind or solar developer wants to connect a new project, the Southwest Power Pool — the regional grid operator covering Kansas — requires a formal interconnection study before anything is built. The developer pays for that study, and under SPP's "direct assignment" rule, a developer is responsible for the full cost of any transmission upgrade needed solely to connect its own project. If an upgrade will also benefit other generators, the cost is shared among the generators who benefit (SPP Generator Interconnection Guide).
But the larger backbone of the grid — the high-voltage transmission lines that move power across the region — is paid for differently, under a FERC-approved formula SPP calls "highway/byway." Lines carrying 300 kilovolts or more are treated as regional "highways" and their cost is spread across every utility customer in the fourteen-state SPP footprint. Lines between 100 and 300 kV split the cost roughly one-third regionally and two-thirds locally. Anything under 100 kV is paid entirely by the local zone (SPP Highway/Byway Cost Allocation Order, FERC Docket ER10-1069). In plain terms: when a major transmission line is built to move Kansas wind or solar power out to distant markets, a meaningful share of that cost is often paid not by the developer profiting from the project, but by ratepayers across a fourteen-state region — including many who will never see the project or the power it generates.
How your electric rate actually gets set
Kansas electric rates are not set by the market. They are set by the Kansas Corporation Commission through a legal process called a rate case, and understanding that process is the key to understanding who pays for new infrastructure.
The KCC describes ratemaking as a two-step process: first, determine the utility's total allowed revenue — based on its rate of return, its total capital investment ("rate base"), depreciation, operating expenses, and taxes — and second, design the rates that collect that revenue from customers (Kansas Corporation Commission, "How Rates Are Set"). The Citizens' Utility Ratepayer Board, a state-created office, represents residential and small-business ratepayers in these proceedings, but the utility itself drives the case, and Kansas courts have held that once a rate is set it is "prima facie reasonable" (Kansas Corporation Commission, "Ratemaking 101"; K.S.A. 66-1222(a), cited via FindLaw).
Here is the mechanism that matters most for large industrial projects: Kansas law allows a utility to recover a current financial return on a plant it is still building — a mechanism known as Construction Work In Progress, or CWIP — before that plant has generated a single kilowatt-hour for any customer. Kansas statute (K.S.A. 66-1239) also lets a utility ask the KCC in advance for a "predetermination" locking in favorable rate treatment before construction even begins, and if the Commission does not act within 240 days, the utility's request is automatically approved (Kansas Statute 66-1239, Kansas Legislature). Evergy used exactly this mechanism in November 2024 for new natural gas plants and its "Kansas Sky" solar project (SEC filing, Evergy Inc. 10-Q).
The plainest on-the-record acknowledgment of what this means for ordinary Kansans came from Evergy's own witness at a June 2025 public hearing on a rate increase, who testified that "at the same time, customers are made to pay for CWIP and rate base and PISA accounting to help serve these same new loads" tied to growth from the Panasonic facility in De Soto — with the company's stated position being that ratepayers would eventually share in the benefit (KCC Public Hearing recording, June 16, 2025). Whether that eventual benefit fully offsets the upfront cost is Evergy's characterization, not an independently audited outcome — but the upfront mechanics are not in dispute. Evergy's 2025 rate case sought a $196.4 million increase and settled for $128 million, raising the average residential bill by about $8.47 a month, on a rate base of $6.7 billion (KCC News Release, Sept. 25, 2025; Evergy Investor Relations rate case summary).
The data center question, and the tariff built to answer it
The rise of hyperscale data centers forced Kansas regulators to confront a version of this question directly: should everyone's rates rise to build infrastructure for one enormous new customer?
Evergy's answer, approved unanimously by the KCC on November 6, 2025 in Docket 25-EKME-315-TAR, is a new Large Load Power Service tariff aimed at any new customer whose demand exceeds 75 megawatts. The tariff requires these customers to sign contracts of twelve to seventeen years, pay a minimum monthly bill equal to 80 percent of their contracted demand even in months they use less, post two years of collateral, and pay directly for any transmission upgrade built solely to serve their facility (Utility Dive, Nov. 10, 2025; Citizens' Utility Ratepayer Board, Q4 2025 newsletter). The Commission's own order estimated that large-load customers under this tariff will pay 7 to 10 percent more than ordinary industrial rates as a built-in premium meant to protect other ratepayers (Utility Dive, quoting the KCC order) — though a subsequent legislative committee hearing cited a higher figure of 16 to 19 percent, and the Kansas City Star separately reported estimates running as high as 20 percent (Kansas House Committee on Energy, Utilities and Telecommunications, Jan. 15, 2026; Kansas City Star, March 16, 2026). These figures likely reflect different methodologies or baselines rather than a straightforward contradiction, but the range itself is worth noting honestly: even the regulators charged with protecting ratepayers do not agree on a single number for how much protection this tariff actually provides.
It is also worth being honest that this tariff did not exist when some of the largest recent projects were negotiated. Meta's data center in the Kansas City area predates the new rules, falls under the 75-megawatt threshold that would trigger them, and — according to Evergy — required no new infrastructure and is fully paying its own way (Kansas City Star, March 16, 2026). That is Evergy's characterization; it has not been independently audited in the reporting reviewed for this essay, and it illustrates precisely why timing matters — the protections in place today did not always exist for the deals already on the books.
Whether large loads shift costs onto ordinary ratepayers nationally is a genuinely contested question in the research literature, not a settled fact in either direction. A 2026 study by the energy consultancy E3 — funded by the Data Center Coalition but conducted with an independent methodology — reviewed eleven quantitative studies and found "no quantitative evidence to date that data centers have historically been subsidized by other customers," and in some cases found data centers put downward pressure on rates by spreading fixed costs across a larger customer base (E3, "Understanding the Drivers of Rising Electricity Rates and the Role of Data Centers," 2026). EPRI's independent econometric analysis similarly found that data center growth was associated with modestly falling, not rising, average retail rates between 2015 and 2024 (EPRI, "Have Data Centers Raised Your Electric Bill?"). But a separate Lawrence Berkeley National Laboratory analysis found that in constrained markets, data centers have already pushed wholesale generation costs up 5 to 15 percent — a different metric, measured in different, more strained markets, than the retail-rate studies above (LBNL working paper, hosted via UC Berkeley eScholarship). LBNL's own flagship report is the most candid statement of the real risk, and it is not "your rates will definitely rise" — it is uncertainty about who absorbs the loss if a data center's promised load never fully shows up after the grid investment has already been made: "if investments are made on the grid side but the expected load fails to show up, ratepayers could be unduly burdened by cost recovery" (LBNL, "2024 United States Data Center Energy Usage Report"). That is the honest state of the evidence, and rural Kansans are entitled to hear it stated that carefully rather than simplified in either direction.
The tax incentive side of the ledger
Alongside the utility rate mechanics sits a second, separate financing channel: public subsidy through tax abatement, revenue bonds, and industrial recruitment programs.
Kansas cities and counties can issue Industrial Revenue Bonds under a 1961 state law, and doing so allows the underlying property to receive up to a 100 percent property tax abatement for as long as ten years, plus a sales tax exemption on construction materials and equipment (Kansas Department of Commerce, "Industrial Revenue Bonds"). Most of these bonds are not really financing tools in the traditional sense — the company finances the project itself or borrows commercially, and the bond mechanism exists mainly to unlock the tax break (Wyoming Legislative Research Memorandum, citing Kansas practice). Kansas's own Legislative Division of Post Audit found that from 2005 to 2020, roughly 640 such exemptions statewide reduced property tax revenue by an estimated $100 million a year, or $1.2 to $1.5 billion over that period — a figure the auditors themselves flagged as an estimate, since "no comprehensive IRBX data exist" (Kansas Legislature, Legislative Division of Post Audit testimony, 2025).
The De Soto Panasonic battery plant is the largest recent example of what this can look like at scale. The state's incentive package — built through a program created specifically for this deal — totaled $829.2 million, combining a $500 million investment tax credit, a $234 million payroll rebate, and smaller training, relocation, and sales tax components, paid only after Panasonic invests and hires (Kansas Department of Commerce, official Panasonic announcement; Kansas City Star, July 13, 2022). Local government added more on top: $15 million from Johnson County, $26 million from the state transportation department, and a state-owned building in Olathe worth nearly $5 million, transferred for free (Kansas City Star, July 28, 2022). De Soto's own twenty-year tax-increment financing deal is projected to redirect an estimated $202.6 million in future property tax growth back to the developer rather than into city and fire-district coffers, at a cost to the city and fire district of roughly $70.3 million in forgone revenue over that period (City of De Soto, project page; Lawrence Journal-World, Oct. 7, 2025). The nonprofit subsidy tracker Good Jobs First separately estimates Panasonic could receive up to $6.8 billion in federal manufacturing tax credits with no attached job or wage requirements — a projection, not a confirmed disbursement, since those credits are paid only as production actually occurs — which, combined with state and local support, could put total public backing near $8 billion against roughly $4 billion in private investment, or an estimated $2 million in public subsidy per job created (Kansas City Star, July 13, 2023, citing Good Jobs First analysis). Whatever one concludes about whether that trade was worth it, the honest starting point is that the public commitment was not a footnote to the private investment. It was comparable to it.
What this means for the landowner at the kitchen table
None of this changes the arithmetic facing an individual family deciding whether to sign a solar lease. Recent Kansas offers have run $500 to $1,300 an acre annually during the operating phase, according to the Kansas Farm Bureau, which also notes candidly that because Kansas solar development has been so limited to date, "it is difficult to suggest fair rates" — an admission worth taking seriously from the state's own leading agricultural advocacy group (Kansas Farm Bureau, "A Guide to Solar Leasing for the Agricultural Landowner," May 2025). The Farm Bureau also draws a distinction landowners should understand clearly: wind lease income is typically supplemental, since farming can often continue around the turbines, while solar lease income functions as a replacement for agricultural income, because the land under panels is usually taken fully out of production — and it frequently loses its favorable agricultural property-tax classification in the process, which "can increase real estate taxes exponentially" unless the lease explicitly requires the developer to cover the difference (Kansas Farm Bureau guide).
Federal tax policy is also compressing the timeline landowners are being asked to decide under. The One Big Beautiful Bill Act, signed July 4, 2025, sharply accelerates the phase-out of the federal wind and solar tax credits that make many of these projects financially viable in the first place — developers must now begin construction by July 4, 2026, or place a project in service by the end of 2027, to qualify at all (Jackson Walker law firm analysis, Aug. 26, 2025). That deadline pressure is very likely part of why lease offers have accelerated across the Midwest in 2025 and 2026 — and it is a reason for a landowner to be more careful with a contract offered under deadline pressure, not less.
Who actually captures the value
Put all of this together and a single honest picture emerges, even where the research remains genuinely unsettled: developers capture value through federal tax credits that can run 30 percent of project cost, plus decades of revenue from a facility built largely on land they lease rather than own outright. Utilities capture a guaranteed rate of return — Evergy's most recent settlement used rates in the range of 8.45 to 9.70 percent depending on the accounting purpose — on every dollar of infrastructure added to their rate base, whether or not the underlying industrial customer's demand fully materializes as projected (KCC Settlement Order, Docket 25-EKCE-294-RTS). Landowners capture a real and often meaningful lease payment, but one that is difficult to benchmark fairly in a state where large-scale solar is still new. Local governments capture jobs and eventual tax revenue, discounted by whatever share of the tax base they abated to get the deal in the first place. And ratepayers — the households and small businesses with no seat at the negotiating table — capture whatever is left over: a rate case here, a surcharge there, and the residual risk if a promised data center's demand never fully shows up after the poles, wires, and power plants built to serve it are already standing.
No comprehensive Kansas study yet exists that nets all of these flows against each other in a single, authoritative distributional accounting. That is a real gap in the public record, and American Rural Heritage Foundation believes filling it — county by county, project by project — is some of the most important work ahead for anyone who wants Kansans to negotiate these deals from a position of knowledge rather than trust. Until that accounting exists, the only responsible posture for a landowner, a county commissioner, or a legislator is to ask, plainly and in writing, exactly who is paying for what — and to be skeptical of any answer that arrives without a number attached.
Sovereign soil. Enduring heritage.
This essay is provided by American Rural Heritage Foundation for informational purposes only and reflects a synthesis of public regulatory filings, government sources, and independent research current as of mid-2026. Figures involving projected tariff impacts, pending legislation, and evolving project valuations should be verified against the most current primary sources before being relied upon for a specific transaction. This is not legal, financial, or tax advice.