Renewable energy: RECs, tariffs and PPAs

The four instruments, and what each one delivers

The U.S. EPA's Green Power Partnership sorts procurement by whether the buyer receives renewable electricity together with its renewable energy certificates, or buys the certificates separately. Unbundled certificates are purchased apart from the commodity: the buyer receives the environmental attribute but not physical delivery of the project's electricity. A utility green tariff is an optional programme, generally in a traditionally regulated market, approved by a state public utility commission, that sells bundled renewable electricity — the power and its attributes — from a specified project through a special rate, usually on a longer term. A physical power purchase agreement delivers the project's electricity and its certificates. A financial or virtual agreement settles in cash against a market reference while the buyer separately receives or retires the project's certificates, and a sleeved agreement is a utility passing a physical contract through to the customer. The trap is that a retail product marketed as renewable is not green power unless the certificates actually transfer to the end-use customer.

• Unbundled certificates: the attribute without physical delivery of the electricity.
• Green tariff: bundled renewable electricity from a named project under a PUC-approved rate.
• Physical PPA: project electricity plus its certificates, delivered into the grid.
• Virtual PPA: cash settlement plus the project's certificates; the buyer keeps its ordinary supply.
• A retail offering is not green power unless the certificates reach the end-use customer.

Where the certificates are tracked, and why geography decides

Certificates live in regional tracking systems, and which one a project sits in constrains what you can claim. EPA identifies nine U.S. systems that together cover every state: ERCOT in Texas, M-RETS in the Midwest, NEPOOL-GIS across the six New England states, PJM-GATS across the PJM footprint of thirteen states and the District of Columbia, WREGIS across the Western Interconnection, plus MIRECS, NAR, NC-RETS and NYGATS. Two of them, M-RETS and NAR, accept generators from anywhere in North America; the others generally require the generator to sit inside their defined footprint. Green-e Energy is a different kind of thing: it is a voluntary certification programme for renewable products and generators rather than a registry, and it requires eligible generators to be registered in an approved tracking system. Registry coverage is also not the same as eligibility — whether a certificate counts for a state renewable portfolio standard depends on that state's statute and commission rules, not on the fact that it appears in a system.

• Tracking systems issue, transfer and retire certificates; Green-e certifies products and transactions.
• NEPOOL-GIS covers New England; PJM-GATS covers the PJM region; WREGIS covers the West.
• M-RETS and NAR accept generators from anywhere in North America; the others do not.
• State programme eligibility is narrower than registry coverage and is set by statute and commission rule.

Why the reporting framework decides the purchase

If you report emissions — to a customer questionnaire, a lender or a voluntary disclosure — the instrument is what makes the claim defensible, and the Greenhouse Gas Protocol's Scope 2 guidance is the framework most of those requests point to. It requires reported figures under two methods, not one. The location-based method uses the average emissions intensity of the grid where consumption occurs; in the United States that grid-average factor comes from EPA's Emissions & Generation Resource Integrated Database, known as eGRID, identified by the applicable subregion for each facility. The market-based method reflects the electricity the company deliberately chose, through emission factors from qualifying contractual instruments. The two numbers answer different questions and are not interchangeable: buying certificates changes the market-based figure and leaves the location-based one untouched.

• Location-based: grid-average intensity, from the applicable eGRID subregion factor.
• Market-based: factors from qualifying contractual instruments the buyer chose.
• Most mature reporting frameworks ask for both figures.
• Certificates move the market-based number; they do not change the grid average.

The Scope 2 quality criteria an instrument has to meet

Not every contract or certificate qualifies for the market-based method. The GHG Protocol sets quality criteria, and an instrument that misses them cannot be used to derive the market-based factor — where no other market-based data exist, the location-based figure is used instead. The criteria are specific, and they are where procurement mistakes become reporting failures: an instrument that conveys the generation's direct emission-rate attribute; that carries an exclusive claim, so no one else can use the same attribute; that is tracked and retired, redeemed or cancelled by or on behalf of the reporting entity; that is issued and redeemed as close as possible to the consumption period it is applied to; that comes from the same electricity market as the consuming facility; that reflects electricity actually delivered to that market; that conveys the claim to the purchaser; and that addresses residual-mix treatment or discloses that no adjusted residual mix is available.

• Convey the direct emission-rate attribute of the generation.
• Carry an exclusive claim — the attribute cannot be double-counted.
• Be tracked and retired or cancelled on the reporting entity's behalf.
• Match the consumption period, and come from the same electricity market as the site.
• Be based on delivered electricity, convey the claim to the purchaser, and address residual mix.

Green tariffs, and how a regulator approves one

For a state-regulated utility, a green tariff is filed as tariff sheets with the public utility commission, which reviews the rate design and cost allocation, whether participants bear the incremental cost of the renewable procurement, the treatment of project cost and certificate value, and whether non-participants are protected from subsidising the buyers. Washington's Puget Sound Energy runs its Green Direct programme under Schedule 139, approved and revised by the Washington Utilities and Transportation Commission, with separate accounting so the programme's costs and benefits are tracked apart from other power costs; the commission periodically resets the energy-charge credit rate the tariff applies. TVA's Green Invest sits outside that model because TVA is a federally owned corporation rather than a state-regulated utility: it matches business and local-power-company commitments to new projects through competitive procurement, on agreements advertised up to twenty years. In every structure the customer keeps taking delivery through the grid — renewable describes the contractual allocation of output and attributes, not electrons physically routed to the meter.

• Commissions review rate design, cost allocation and whether non-participants are protected.
• A tariff can allocate a utility-owned project, a utility contract, or a sleeved physical PPA.
• Puget Sound Energy's Green Direct runs under Schedule 139; the Washington UTC resets the credit rate.
• TVA Green Invest is a federally owned corporation programme, not a state tariff.
• The customer still receives grid delivery; attributes are contractual, not physical.

Physical versus virtual PPAs

The two agreement shapes carry different risks, and the difference is where the electricity goes. A physical agreement buys power from a specified project delivered to a defined node, hub or market. The buyer pays the agreed energy price subject to the contract's volume, delivery and settlement terms, and takes on the commercial exposures of physical delivery: basis differences between the project's node and where the power is valued, congestion, curtailment and imbalance rules. Certificates transfer if the contract includes them. A virtual agreement, also called a financial or contract-for-differences structure, does not change the buyer's physical supply at all: the project sells its output into the wholesale market and the buyer keeps buying from its ordinary utility or retail supplier. The parties settle the difference between a fixed contract price and a floating market reference on a settlement volume, and the buyer typically receives the project's certificates for its claim. That is the whole trade: the virtual structure isolates the price exposure while leaving delivery alone, which is why it scales, and why it requires comfort with settlement mechanics.

• Physical PPA: delivery to a defined node with exposure to basis, congestion and curtailment.
• Virtual PPA: settlement equals fixed contract price minus floating market price, times volume.
• A virtual agreement leaves the site's ordinary electricity supply untouched.
• Certificates usually convey to the buyer in a virtual structure, supporting the claim.

Additionality, vintage and the claims you can make

Beyond the reporting mechanics, buyers increasingly get asked whether their purchase actually caused new renewable capacity to exist. That is the additionality question, and it is why strategy increasingly distinguishes certificates from existing generation against contracts with a new project. Vintage — the period in which the generation occurred — matters because the criteria above ask the instrument to be issued and redeemed as close as possible to the consumption period being reported. The purchase should also be sized against what it is claiming: certificates can be bought to match the volume actually consumed, which keeps them flexible but reprices them every year at whatever the market is doing, while a physical or virtual commitment is struck on a contracted volume and settles on that volume whether or not you used it. A claim without the retirement paperwork is difficult to defend.

• Buying from an existing facility supports renewable generation but does not itself add capacity.
• Long-term contracts with new projects are the common route to an additionality claim.
• Certificate vintage should align with the period you are reporting.
• Match the purchased volume to what you are claiming, and keep the retirement records.

Questions to settle, and how HighGround handles a request

The failure mode in renewable procurement is rarely price; it is a contract that does not support the claim the business wanted to make, or a certificate that cannot be retired in the right market and period. Settle the questions first and the instrument choice usually becomes obvious. Renewable content can then be specified in an energy request, with the market and term attached. Energy supply is sourced through the Broker Online Exchange supplier network, which covers licensed gas and electricity markets; the services that support the same site — connectivity, security, cloud and software — are sourced through AppDirect. Nothing here guarantees a particular environmental claim or a particular supply arrangement, availability varies by jurisdiction and supplier, and an inquiry places no order and commits you to no term.

• Which reporting framework are we satisfying, and what evidence does it require?
• Do we need attributes bundled with electricity, or are certificates enough?
• What term can the business genuinely commit to, and who retires the certificates?
• If the volume does not match consumption, what happens to the surplus?
• Green content is specified as a requirement in your inquiry, with market and term attached.
• HighGround may receive provider compensation when a purchase completes; it is disclosed site-wide.

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