Electric service agreements, large-load tariffs and PPA terms

The commercial terms of power supply are set in contracts that can run to hundreds of pages and last for decades: the electric service agreement with the utility, the large-load tariff that governs it, power purchase agreements with generators, and gas and transportation contracts. The headline price is only one term among many. Minimum payments, ramp schedules, curtailment rights, credit support, change-in-law clauses and termination provisions often decide how much a contract really costs and who bears the risks. This lesson explains the structure of electric service agreements and the large-load tariffs that regulators have adopted as data centre demand has surged, and the key terms of PPAs, with worked examples of the exposures they create and the points worth negotiating.

The electric service agreement

A large data centre is connected under an electric service agreement (ESA), sometimes called a contract for electric service or connection agreement, which supplements the utility's tariff. Typical provisions:

• Contract capacity: the maximum demand the utility commits to serve, in MW, and how it ramps over time (for example 50 MW in year one rising to 300 MW in year five).
• Facilities and cost responsibility: the substation, lines and network upgrades the utility will build, and how much the customer pays upfront (contribution in aid of construction) versus through rates.
• Term: often 10 to 20 years for large loads, with renewal options.
• Minimum bill or minimum demand: the customer pays for at least a set percentage of contract capacity whether it uses it or not.
• Credit support: letters of credit, parent guarantees or cash deposits securing the customer's obligations, often sized to the cost of facilities or several years of minimum bills.
• Exit and termination: fees if the customer terminates early or reduces contract capacity, covering stranded costs of facilities built for it.
• Curtailment and interruptibility: any rights of the utility to reduce service, and the terms of flexible connections (Lesson 4).
• Technical requirements: power quality, ride-through behaviour, power factor, protection settings and telemetry.

In Canadian provinces, connection costs for large customers on transmission systems are set by regulatory codes and utility tariffs. In Ontario, the Transmission System Code governs connection cost responsibility: transmitters perform an economic evaluation, and customers make capital contributions for connection facilities not justified by expected revenues, with true-ups if forecast load does not materialize. Hydro-Québec allocates power for new large loads above 5 MW through ministerial approval under rules adopted in 2023, giving priority to projects judged to bring the greatest economic and environmental benefit. Other provinces have their own tariffs and allocation processes.

Large-load tariffs: why and how

Utilities are being asked to plan and build generation and transmission for unprecedented load growth, much of it from a small number of very large customers whose forecasts are uncertain: many requests are speculative, duplicated across utilities, or slower to materialize than projected. If the utility builds for load that never arrives, other customers can end up paying. Large-load tariffs try to ensure that the customers who cause the costs bear them, through:

• Long minimum terms, typically 10 to 20 years.
• Minimum demand charges of 60% to 90% of contracted capacity.
• Collateral scaled to the customer's credit rating and the utility's investment.
• Exit fees covering the remaining cost of dedicated facilities and a share of generation built for the customer.
• Load ramp schedules agreed in advance, with penalties or re-queuing for slipping more than a set margin.
• Study deposits and milestones to discourage speculative requests (Lesson 3).

For credit-worthy hyperscale operators these terms are manageable; for smaller developers they can be decisive, because collateral ties up capital before revenues begin.

Key terms of power purchase agreements

Lesson 5 described physical and virtual PPAs. Beyond price, the terms that matter most are:

• Term and price structure: fixed price, escalating price (for example 2% a year), or a price with collars; terms are typically 10 to 20 years.
• Settlement point: the node or hub where energy is priced and settled; settling at the project node gives the buyer basis risk exposure to congestion between the project and its load or hub (Lesson 2), while settling at a hub shifts basis risk to the seller.
• Shape: as-generated (the buyer takes whatever the project produces), or shaped/firm products in which the seller delivers a fixed block, taking the shape risk at a higher price.
• Curtailment and negative prices: who bears the cost when the grid operator curtails the project or prices go negative; many PPAs exclude payment for energy produced during negative-price hours.
• Commercial operation date and delay damages: the date the project must start delivering, and liquidated damages if it is late, important when the data centre needs the energy (or attributes) for a target year.
• Performance guarantees: minimum annual output or availability, with damages for shortfalls.
• Environmental attributes: transfer of renewable energy certificates or equivalent, with hourly data where required for 24/7 accounting (Lesson 6).
• Change in law: how new taxes, tariffs (for example on imported solar panels), carbon rules or market changes are shared.
• Credit support and default: collateral from both parties, events of default, termination payments based on the mark-to-market value of the remaining contract.

Negotiating well

Good contract outcomes come from understanding the counterparty's constraints and allocating each risk to the party best able to manage it:

• Utilities need protection against stranded costs and must treat customers consistently under regulation; customers gain more by proposing realistic ramps, phased commitments and appropriate credit than by fighting minimum terms outright.
• Developers of generation need bankable contracts to finance projects; buyers can obtain lower prices by accepting risks they can manage (for example, taking basis risk at a node near their own load).
• Model each contract under scenarios (slow ramp, early exit, low and high market prices, project delays) to understand the real exposures rather than relying on the headline price.
• Coordinate across contracts: the ESA ramp, PPA delivery dates, gas supply for bridging generation and data centre construction all need to line up; a mismatch can leave the owner paying for power it cannot use, or without power when the building is ready.
• Involve legal, finance, energy and engineering staff early, and keep a register of obligations, notice dates and milestones across all contracts.

Gas supply and transportation contracts

A data centre with on-site generation also signs gas contracts (Lesson 8), whose terms parallel those of electricity contracts. A gas supply agreement with a producer or marketer specifies the daily and annual quantities, the price (fixed, index plus a margin, or a mix), the delivery point, and whether supply is firm or interruptible; many use a standard master agreement, such as the NAESB base contract in North America, with negotiated special provisions. Take-or-pay clauses require the buyer to pay for a minimum annual quantity even if it uses less, the gas equivalent of a minimum bill, which matters for a bridging plant whose use will fall once the grid connection arrives. A transportation agreement with the pipeline sets the contracted daily capacity, reservation charges, receipt and delivery points, the term (often 10 to 20 years for new capacity, backed by credit support) and balancing obligations that penalize large differences between scheduled and actual consumption. Rights to release or resell unused capacity reduce the cost of over-commitment.