A company buying renewable energy in Texas, California, and the Mid-Atlantic can negotiate similar commercial terms across all three markets. That does not mean it has negotiated the same risk. The underlying projects operate under different grid rules, transmission structures, interconnection agreements, emergency procedures, and market requirements, and those differences matter when a project is curtailed, transmission becomes unavailable, market rules change, or a generator cannot perform as expected. For procurement teams accustomed to using standardized contract templates across regions, that creates a problem: the language may travel more easily than the risk allocation behind it.
ERCOT is providing a timely example. The Texas grid operator is considering changes to its Standard Form Market Participant Agreement that include an amended definition of a Force Majeure Event and revisions responding to Texas Supreme Court rulings involving ERCOT. The proposal, NPRR1312, remains pending in the ERCOT stakeholder process. The revision does not govern corporate PPAs. It shows something more consequential for companies buying energy across multiple markets: even the agreements and definitions sitting beneath private energy contracts are not static or uniform.
ERCOT Is Reconsidering Force Majeure Language
ERCOT filed NPRR1312 as a broader revision to its Standard Form Market Participant Agreement, the agreement governing the relationship between ERCOT and market participants. Among other changes, the proposal would amend the definition of a Force Majeure Event, move certain breach and default provisions into ERCOT's protocols, modernize notice requirements, and revise the agreement in response to the Texas Supreme Court's decision in CPS Energy v. ERCOT, which held that ERCOT is an arm of government entitled to sovereign immunity and subject to the Public Utility Commission of Texas' exclusive jurisdiction. ERCOT held a workshop on the proposal in January 2026 and continued accepting stakeholder comments; the proposal remains listed as pending in ERCOT's protocol tracking. For an enterprise buyer, the significance is not whether ERCOT's eventual definition appears verbatim in its PPA. It probably will not. The significance is that the market framework governing the seller's operations can change while the corporate contract remains in place, creating two layers of obligations: what the project must do under the applicable market and interconnection rules, and what the seller has promised its corporate customer it will do when those rules affect performance. Those layers need to work together.
The Same Words Can Sit Above Different Rules
California illustrates the hierarchy within the grid operator's own governing framework. CAISO operates under a FERC-approved tariff that is amended as market and regulatory requirements change. CAISO states plainly that if a provision of an existing ISO contract, business practice manual, or operating procedure conflicts with the tariff, the tariff prevails to the extent of the inconsistency, and its current conformed tariff incorporates amendments effective through May 2026. That matters because the commercial PPA between a generator and corporate buyer sits alongside, rather than above, the regulatory framework governing the project. PJM's pro forma interconnection framework provides another example. Its force majeure provisions define qualifying events as causes beyond the affected party's control that could not reasonably have been avoided or overcome through due diligence, and they make clear that force majeure does not suspend payment obligations, excusing affected performance only for the duration of the event while the party exercises reasonable efforts to alleviate the problem. Those provisions do not automatically become terms of a corporate PPA. They help define the operating and contractual environment in which the project must perform, and that is the distinction procurement teams need to preserve.
Standardization Can Hide the Difference
There are good reasons companies standardize energy contracts. Common templates reduce negotiation time, create consistency across portfolios, simplify internal approvals, and let procurement, finance, legal, and sustainability teams compare projects using familiar terms. The problem begins when standardization is treated as equivalent to identical risk. A force majeure clause negotiated for a project in one market may use language broad enough to cover government orders, grid directives, transmission failures, or other events beyond the seller's control. Applying the same wording to a project elsewhere does not guarantee that the underlying market produces the same events, imposes the same obligations, or creates the same economic consequences.
The same is true outside force majeure. Curtailment provisions can allocate the financial consequences of lost generation. Change-in-law clauses can allocate the consequences of new market requirements. Interconnection-related provisions govern how the consequences of transmission or interconnection delays get divided, a risk that has already stretched project timelines across much of the country. Replacement-power provisions can shift delivery risk, and settlement language can determine how congestion or reduced output affects a virtual PPA. Those provisions interact, and a standard template can therefore produce consistency in wording while masking differences in exposure.
Multi-Region Buyers Need a Market Overlay
For companies procuring electricity across multiple regions, the solution does not have to be abandoning standard contracts. It is adding a market-specific risk overlay before the template is approved. For each project, procurement and counsel should identify the grid operator, applicable tariff, interconnection structure, curtailment rules, transmission responsibilities, and market procedures that could interfere with expected performance. They should also identify which of those rules can change during the contract term and which contractual provision absorbs that change. Then the contract needs to answer what happens when those risks materialize.
If the grid orders the generator down, which provision governs?
If a transmission outage prevents delivery, does the seller receive relief?
If a new market rule increases project costs, is that force majeure, change in law, or seller risk?
If interconnection upgrades are delayed, how long can comme
rcial operation slip before the buyer has termination rights?
If the project produces fewer megawatt-hours, what happens to settlements and environmental attributes?
The answer may be different from market to market even when the corporate template begins with identical language.
Contract Governance Has to Follow Market Governance
The risk is particularly relevant for companies building national renewable-energy portfolios. A buyer may execute PPAs in ERCOT, PJM, MISO, and CAISO as part of one corporate energy strategy, and internally those agreements may be evaluated against the same procurement policy and approved through the same investment process. Externally, the projects do not operate under one power market, a divergence that mirrors how multinational buyers have already had to split their procurement strategies by region as policy environments pull apart rather than converge. ERCOT is currently considering revisions to its standard agreement, including force majeure language. CAISO's tariff expressly takes precedence over inconsistent ISO contracts and procedures. PJM's interconnection agreements establish their own conditions for when performance is excused and what obligations continue during force majeure, and grid risk assessments themselves are updated on different timelines from region to region, which adds another reason the same PPA template can carry different exposure depending on where the project sits. Those differences do not make standardized procurement impossible. They make standardization incomplete without market-specific diligence. For corporate buyers, the question should no longer be whether the company's approved force majeure clause appears in every PPA. The better question is whether that clause has been tested against the market where each project actually has to perform. A standard contract can travel across the country. The grid underneath it cannot.
