Indiana, Kentucky, Tennessee, and the Southeast: Energy Procurement in Regulated States (Hidden Savings)

Let's address the myth directly: "We're in Kentucky — we don't have energy choices."

Wrong. The assumption that regulated states offer commercial and industrial buyers no leverage over their electricity costs is one of the most expensive misconceptions in business energy management. It costs manufacturers in Indiana, Tennessee, Georgia, and across the Southeast millions of dollars every year in savings they never pursued because someone told them the utility had a monopoly and that was that.

The reality is more interesting. While it's true that regulated utilities control electricity supply and delivery — meaning you can't simply hire a competing retail supplier the way you can in Illinois or Pennsylvania — the toolbox available to sophisticated buyers in regulated states is substantial. Economic development rates, special contract riders, voluntary renewable tariffs, integrated resource plan opportunities, demand response programs, and direct utility negotiation rights for large loads all exist in virtually every major regulated state. They just aren't advertised, and they aren't automatic. You have to ask.

This guide is for businesses that have been told they have no choices. Here's what actually exists, state by state, and how to access it.

Why Regulated States Aren't As Locked-In As Most Buyers Think

Understanding why regulated states offer more options than commonly assumed requires a brief look at how regulated utility economics actually work.

The Regulated Utility Model

In a regulated state, a single investor-owned utility (IOU) or cooperative holds an exclusive franchise for electricity supply and delivery within a defined territory. The Public Utilities Commission (PUC) — called the Indiana Utility Regulatory Commission (IURC), the Kentucky Public Service Commission (PSC), the Tennessee Regulatory Authority (TRA), or the Georgia Public Service Commission (PSC) — sets the rates the utility can charge and reviews its capital investments through a formal rate case process.

The utility makes money by earning a regulated return (typically 9–11%) on its rate base of capital assets. It is not fundamentally incentivized to find you the cheapest possible electricity — its financial performance is tied to capital deployment, not cost minimization. This creates the basis for buyer leverage: the utility has institutional reasons to compete for large, stable load.

Large Customers Have Negotiating Rights

Regulated utilities want large commercial and industrial customers. Why?

Large customers provide stable baseload demand that improves system utilization
Economic development activity (new manufacturing, data centers, large employers) is politically valuable for utility regulators and management
Large loads reduce the average cost of serving the utility system, which benefits all ratepayers — giving the PUC a rationale for approving favorable rates

This gives large commercial and industrial customers — generally defined as 1 MW+ peak demand, though thresholds vary by state — significant leverage to negotiate special contract rates, riders, and service agreements that standard tariff customers never see. The mechanism is a direct negotiation with the utility's large account team, often with PUC notification or approval rather than full adversarial rate-setting.

For smaller commercial accounts (under 500 kW), the negotiation leverage is more limited, but green tariff enrollment, demand response participation, and systematic efficiency investment remain viable savings pathways that many businesses overlook.

The Deregulated State Comparison

To calibrate expectations: in fully deregulated states like Illinois or Pennsylvania, competitive retail supply typically delivers savings of 3–10% versus utility default supply through price competition among retail electricity providers. In regulated states, the available savings mechanisms are different — economic development rates, special riders, demand response credits, green tariff programs — but the aggregate potential is comparable for buyers who engage the system.

The difference is that deregulated market savings are relatively automatic (competitive bidding surfaces savings without buyer expertise), while regulated state savings require deliberate engagement with the utility, knowledge of what programs exist, and sometimes participation in PUC proceedings. Most buyers in regulated states never take these steps, which is precisely why the opportunity exists.

Special Contract Riders, Economic Development Rates, and IRP Hooks

The richest savings opportunities in regulated states for large commercial and industrial accounts come from special tariff provisions that are approved by the PUC but rarely publicized. Here's a state-by-state breakdown of the major programs.

Indiana

Indiana's electricity sector is regulated by the Indiana Utility Regulatory Commission (IURC). The primary large-customer utilities are Duke Energy Indiana and AES Indiana (formerly Indianapolis Power & Light), with NIPSCO serving the northern part of the state.

Economic Development Rate (EDR): Both Duke Energy Indiana and AES Indiana offer Economic Development Rates for new or expanding industrial and commercial loads meeting specified thresholds — typically 1 MW or more of incremental demand. EDR provisions provide discounts below standard tariff rates for a fixed period (typically 5–10 years) in exchange for commitments on jobs created or retained, minimum demand maintenance, and local investment.

The discount structure varies by negotiation but commonly provides $0.005–0.015/kWh reductions from the standard tariff — significant savings on high-consumption manufacturing operations. Access requires a formal application and negotiation with the utility's economic development team; in some cases, the Indiana Economic Development Corporation (IEDC) can facilitate introductions and advocacy.

Average commercial rates: $0.09–0.11/kWh all-in for standard commercial accounts. Manufacturing facilities qualifying for large industrial tariffs typically achieve $0.07–0.09/kWh before special riders.

Demand response: NIPSCO's Commercial Demand Response program and Duke Energy Indiana's capacity interruption programs offer bill credits of $50,000–$150,000/year for large loads willing to curtail on request. Enrollment requires minimum demand thresholds and curtailment capability verification, but the payment is essentially compensation for flexibility — with no capital investment required if you already have operational flexibility.

Kentucky

Kentucky may be the most underappreciated regulated electricity market in the country from a buyer's perspective. It offers some of the lowest commercial electricity rates in the United States — $0.07–0.09/kWh for standard commercial accounts — and has recently enacted policy that creates additional opportunities for large users.

LG&E and KU (Louisville Gas and Electric / Kentucky Utilities): Both utilities, subsidiaries of PPL Corporation, serve most of Kentucky. They maintain large commercial and industrial tariff schedules with demand ratchet provisions, interruptible service options, and negotiated special contracts for loads above 1 MW.

HB 230 (2022): Kentucky's House Bill 230 established a favorable framework for large energy users by streamlining the process for large industrial facilities to negotiate special contracts directly with utilities, subject to PSC approval. This legislation effectively created a more formalized pathway for the kind of direct utility negotiation that previously required navigating the rate case process.

Economic development framework: The Kentucky Cabinet for Economic Development maintains relationships with utility large account teams specifically to facilitate energy cost discussions for prospective and expanding manufacturers. Companies evaluating Kentucky plant investments should request an energy cost analysis through this channel before finalizing site decisions.

Natural gas: Kentucky is also served by a competitive natural gas supplier market for certain large customers, adding a supply-side flexibility tool that doesn't exist for electricity. This is worth exploring separately through how electricity deregulation works and parallel gas market structures.

Tennessee

Tennessee's energy landscape is dominated by the Tennessee Valley Authority (TVA) — a federal power agency that generates and transmits power throughout a seven-state region including most of Tennessee. Local Power Companies (LPCs) — municipal utilities and electric cooperatives — purchase from TVA and distribute to end customers. This two-tier structure creates both constraints and opportunities.

TVA's Large Power rate structure: Industrial customers taking power at transmission voltage (typically above 10 MW peak demand) qualify for TVA's Large Power rate, which carries significantly lower energy charges than the standard commercial rate. TVA's Industrial Development program actively works with site selectors and manufacturers to structure attractive power arrangements for large new loads.

TVA Economic Development Rates: TVA's Industrial Development Services office can provide prospective industrial customers with preliminary power cost analyses and, for qualifying projects, negotiate Economic Development rates with time-limited discounts for new manufacturing investment. These are not publicly posted tariffs — they are project-specific agreements between TVA, the local power company, and the industrial customer.

EnergyRight program: TVA's EnergyRight program provides commercial and industrial customers with energy assessments, rebates for qualifying efficiency investments, and access to TVA's engineering resources at no cost. For businesses looking to reduce consumption — which directly reduces energy cost — this program provides meaningful technical support that many businesses haven't utilized.

Average rates: Tennessee commercial customers typically pay $0.08–0.10/kWh all-in through their local power company, depending on the LPC's rate structure layered on top of TVA power costs. Large industrial direct-service TVA customers pay less.

Georgia

Georgia is regulated by the Georgia Public Service Commission (PSC), with Georgia Power (a Southern Company subsidiary) serving most of the state.

Georgia Power Large Commercial / Industrial Tariffs: Georgia Power maintains separate tariff schedules for Large General Service and Industrial customers. At 1 MW+ demand, customers qualify for LGS-TOU (time-of-use) rates that can deliver significant savings for operations with flexible load scheduling. At 5 MW+ demand, customers may qualify for transmission-level service.

ElectroFlux and economic development programs: Georgia Power's economic development team works directly with the Georgia Department of Economic Development on large employer attraction. New manufacturing facilities meeting minimum job creation thresholds may access ElectroFlux or similar program structures providing rate credits during ramp-up periods.

Natural gas competition: Unlike electricity, Georgia's natural gas market has a competitive supplier component — the Georgia Natural Gas Regulated Return program allows competitive marketers to serve residential and commercial customers. This doesn't affect electricity procurement but means multi-energy buyers have additional leverage in the gas market.

Average rates: Georgia Power commercial rates average $0.09–0.12/kWh, with industrial rates notably lower for qualifying load profiles.

Green Tariffs, Rider RR, and Voluntary Renewable Programs

The growth of renewable energy in regulated utility territories has produced a range of green tariff programs that allow commercial customers to purchase renewable electricity at a modest premium — without the complexity of a direct PPA. These programs are relevant both for sustainability goal progress and for businesses needing to document their electricity supply for CBAM compliance or customer sustainability questionnaires.

How Green Tariffs Work in Regulated States

A green tariff is a utility-sponsored program in which the utility procures new renewable capacity — wind, solar, or other eligible sources — and offers it to enrolled commercial customers at a cost-plus-premium rate. The utility purchases the associated RECs and retires them in enrolled customers' names, supporting market-based Scope 2 zero-emission claims.

Key characteristics that distinguish regulated state green tariffs from competitive market renewable options:

Utility-administered: No separate supplier relationship required; renewable supply is billed through the standard utility account
Additionality: Most programs require new renewable capacity to be built to serve enrolled customers (rather than repurposing existing generation), strengthening sustainability claims
Simpler documentation: EAC documentation is handled by the utility; customers receive annual retirement statements for CDP and sustainability reporting purposes
Modest premium: Typical cost premium is $0.005–0.015/kWh above standard tariff — lower than most competitive market green products

State-by-State Green Tariff Programs

Duke Energy Indiana — REsourcing: Duke Energy Indiana's voluntary renewable program allows commercial customers to enroll for 25%, 50%, or 100% renewable electricity. RECs are sourced from Duke's Indiana-based wind and solar facilities. Available to customers on any commercial tariff with no minimum demand requirement.

TVA — Green Power Switch: TVA's Green Power Switch program allows residential and commercial customers (through their local power company) to purchase blocks of renewable energy (100 kWh blocks) at a premium of approximately $0.04/block above standard rates. For large commercial accounts, this translates to a modest additional cost for documented renewable supply.

Georgia Power — Green Energy Tariff (Rider RE): Georgia Power's Green Energy Tariff — structured as Rider RE in its tariff schedule — allows large commercial customers (500 kW+ demand) to subscribe to renewable energy equivalent to a portion or all of their consumption. The tariff sources power from Georgia Power's renewable portfolio and retires the associated RECs in the subscriber's name. The premium is approximately $0.003–0.008/kWh over standard tariff — among the most cost-effective green tariff options available from any regulated utility.

AES Indiana — Clean Energy Rider: AES Indiana offers a clean energy rider that provides eligible commercial customers with access to renewable power from solar projects in the Indiana utility territory. Available for accounts meeting minimum demand thresholds.

RFP Strategies for Regulated-Market Manufacturers and Multi-Site Operators

Even without a competitive retail electricity market, manufacturers and multi-site operators in regulated states can use a systematic request-for-proposal (RFP) approach to drive value — just targeted at different service providers and program types than in deregulated markets.

What to "Bid Out" in a Regulated State

In regulated states, the RFP process shifts focus from electricity supply pricing (which the utility controls) to:

Energy management services: Request proposals from energy advisors and facility management firms for comprehensive energy management programs — audit, monitoring, efficiency project development, and demand response enrollment. The competition among service providers delivers better economics than single-vendor arrangements.
Demand response programs: Multiple demand response aggregators may operate in your utility territory alongside the utility's own DR program. Soliciting competitive enrollment proposals from both the utility and independent aggregators reveals the best combination of payment rate, curtailment requirements, and operational constraints.
On-site generation: For manufacturers with large rooftops or adjacent land, competitive bids for solar installation and financing (through EPC contractors and solar developers) deliver substantially better terms than accepting any single developer's standard proposal. An RFP for 500 kW of rooftop solar across a manufacturing facility should draw 5–8 competitive bids, with significant variation in price and contract structure.
Energy efficiency financing: PACE (Property-Assessed Clean Energy) financing, utility incentive programs, and third-party efficiency financing are available in most regulated states. Competitive solicitation of financing structures for qualified efficiency projects drives down capital cost and improves project economics.

For running a competitive energy RFP in a regulated market context, the evaluation criteria differ from deregulated markets — but the discipline of structured competitive solicitation still drives materially better outcomes than bilateral negotiation without alternatives.

Participating in Utility Rate Cases

Large commercial and industrial customers in regulated states have the right — and sometimes the strategic interest — in participating in utility rate cases. A rate case is the formal regulatory proceeding in which a utility proposes new rates, and the PUC evaluates and approves them. Large commercial intervenors can:

Advocate for rate structures more favorable to commercial customers (e.g., higher demand charge vs. energy charge ratios that benefit high-load-factor operations)
Challenge proposed rate increases with evidence of customer impact
Request utility-provided data on cost allocation methodologies
Propose alternative rate designs in written testimony

Rate case participation requires legal and regulatory expertise but can deliver lasting rate structure improvements that outweigh the engagement cost for large industrial customers. Several industrial trade associations in Indiana, Kentucky, and Tennessee facilitate collective intervenor participation, spreading the cost across multiple members.

Multi-Site Regulated-State Strategy

For multi-site operators with locations in regulated states (covered in detail in our energy procurement case studies), the aggregate opportunity across regulated locations often exceeds what's available at any single site. Key elements of a multi-site regulated-state program:

Portfolio audit: Review all locations for rate class accuracy, demand response enrollment eligibility, and green tariff participation. Many multi-site operators find 20–30% of locations on suboptimal rate classes.
Coordinated demand response: Multi-site enrollment in utility DR programs — particularly for restaurant chains or retailers where operational flexibility is consistent across locations — maximizes total DR payment while minimizing operational disruption.
Consolidated green tariff enrollment: A single green tariff enrollment covering all locations in a utility territory is simpler and often qualifies for higher-volume pricing than individual location enrollment.

For a full understanding of how deregulated and regulated state procurement strategies complement each other in a mixed-state portfolio, how electricity deregulation works provides the foundational market structure context.

Conclusion

The myth that regulated states offer no energy choices costs businesses real money — not as an abstraction, but in concrete terms: economic development rates they never applied for, demand response programs they never enrolled in, green tariffs they never activated, and rate class errors they never caught because they assumed the utility had already optimized their account.

The regulated utility model does limit competitive supply options. It does not limit the sophisticated buyer's ability to extract meaningful value from the system that exists. Economic development rates can reduce per-kWh costs by $0.005–0.015 for qualifying loads. Demand response can generate $50,000–$300,000 in annual credits for operations with demand flexibility. Green tariff programs provide documented renewable supply at cost premiums far lower than most businesses expect. And the rate-case and regulatory engagement process provides a formal mechanism for large users to shape the rate structures they operate under.

The businesses getting this right in Indiana, Kentucky, Tennessee, and Georgia are the ones that treat their utility relationship as a strategic partnership to be managed proactively, not a passive cost to be paid and forgotten. They have account managers on speed dial. They know when rate case proceedings are scheduled. They are enrolled in every DR program for which they qualify. And they review their rate class annually, not never.

That level of engagement is exactly what Commercial Energy Advisors provides for our regulated-state customers. We know the programs, we know the utilities, and we know how to navigate PUC processes on your behalf. If your business operates in Indiana, Kentucky, Tennessee, Georgia, or any other regulated market, there is likely more opportunity in your current utility relationship than you realize. Call us at 833-264-7776 or contact our team to find out how much.

Frequently Asked Questions

Can I switch electricity suppliers in Indiana, Kentucky, or Tennessee?

No — for electricity. These states do not have competitive retail electricity markets. The local regulated utility provides both transmission/distribution and electricity supply. You cannot hire a competing retail supplier for electricity in these states. However, natural gas in some areas (particularly Georgia) has a competitive supplier component, and energy management services (auditing, demand response, efficiency financing) are fully competitive.

What is an Economic Development Rate and how do I qualify?

An Economic Development Rate (EDR) is a special tariff provision approved by the PUC that allows utilities to offer discounts below standard rates to attract or retain large commercial and industrial customers. Eligibility typically requires new or expanding load of 1 MW or more, commitment to minimum job creation or retention figures, and minimum investment in the facility. Application is made directly to the utility's economic development or large account team. Some states also allow the economic development state agency to facilitate introductions and advocate on behalf of qualifying companies.

How much can demand response programs pay a manufacturer in a regulated state?

Payment rates vary by program, utility, and grid conditions, but large industrial facilities typically earn $10–30/kW-year in demand response credits from utility DR programs. A manufacturer with 5 MW of curtailable load might earn $50,000–$150,000/year in DR credits — essentially payment for agreeing to reduce consumption when the grid is stressed. Actual curtailment events are typically infrequent (5–15 hours per year for most programs), making DR participation a high-value, low-disruption savings mechanism for operations with any load flexibility.

Are green tariffs in regulated states credible for Scope 2 reporting purposes?

Yes, most regulated utility green tariffs qualify for market-based Scope 2 accounting under the GHG Protocol, provided they meet the GHG Protocol Scope 2 quality criteria: supplier-specific emission factor, retired certificates, and verifiable documentation. Request annual REC retirement statements from the utility specifying the generator, location, and volume retired in your name. Some green tariff programs use RECs from older vintage projects — if SBTi alignment is a goal, verify that the program sources from recently built (within 5 years) renewable capacity.

What is an Integrated Resource Plan (IRP) and why does it matter for large buyers?

An IRP is the utility's long-range planning document — filed with the PUC every 3–5 years — that describes how it plans to meet future electricity demand through generation, transmission, and demand-side resources. IRP proceedings create opportunities for large commercial customers: to provide load data that shapes utility planning, to advocate for procurement of cost-effective renewable resources, and in some cases to participate in the utility's competitive procurement process as a demand-side resource. Regulatory filings in IRP proceedings are public records, and large customers with legal or regulatory resources can file comments or intervene formally.

Is the natural gas market competitive in regulated electricity states?

It varies significantly by state. Georgia has a competitive natural gas supplier market through the Gas Natural Gas Regulated Return program. Tennessee is served by gas utilities with no competitive market for most accounts. Indiana and Kentucky have regulated gas utilities (Vectren/CenterPoint, Columbia Gas, Atmos Energy) for most commercial customers, though very large industrial loads may have direct access to pipeline gas and competitive supply options. Evaluate gas and electricity markets separately — the regulatory structure governing each is independent, and competitive options in one doesn't necessarily imply competition in the other.

How often should a regulated-state manufacturer review its utility rate class?

At minimum, annually — and immediately after any of these events: a change in peak demand that crosses a rate class threshold, a major equipment addition or process change, a new meter installation, or a significant change in operating hours or shift patterns. Rate class eligibility criteria are tied to demand levels, service voltage, load factor, and sometimes industry classification. As your facility evolves, your rate class eligibility may change in ways the utility won't proactively flag. Periodic review by someone familiar with your utility's tariff schedule is the most reliable protection against persistent misclassification.

What should I say when calling my utility's large account team?

Start with: "I'd like to schedule a rate analysis and discuss our account's eligibility for any economic development rates, demand response programs, or voluntary renewable options." A good large account representative will review your consumption history, identify rate class optimization opportunities, walk through available DR programs, and introduce you to any special tariff options you might qualify for. If the representative you reach isn't familiar with these programs, ask to be connected with the economic development or large commercial accounts team specifically — most regulated utilities have a dedicated team for accounts above certain demand thresholds.

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