Tervane’s municipal electricity buyers have encountered a problem concealed by an apparently complete clean-power ledger: purchasing enough renewable generation to cover a year’s consumption does not mean that generation arrives when the city uses electricity. In the invented procurement scheme, an illustrative portfolio buys renewable output equal to 100% of annual demand, yet matches consumption within the same hour only 61% of the time. Closing part of that gap is possible, the model suggests, but requires a more expensive and operationally demanding approach than balancing annual certificates.

The fictional city’s comparison puts the central trade-off in financial terms. Raising the modelled hourly match to 84% increases annual procurement costs by $9 million, taking the illustrative budget from $60 million to $69 million, a rise of 15%. Against assumed annual electricity demand of 1 million megawatt-hours, that adds $9 per megawatt-hour of consumption. The exercise is not a forecast for an actual municipality. It tests whether a stricter purchasing standard delivers sufficient system benefit to justify its cost, and whether annual claims communicate more certainty than the underlying supply arrangements warrant.

Annual renewable purchasing is comparatively straightforward. A buyer acquires generation, or the associated contractual attributes, equivalent to its total consumption over a year. That can support renewable investment without requiring the buyer’s demand to coincide with production. Tervane’s baseline illustrates the limitation: surplus renewable output during favourable generating periods offsets purchases recorded during other hours, but does not establish which generators supply the network then. An annual balance is therefore an accounting result, not a continuous description of the electricity system’s operation.

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The model assumes municipal demand is unchanged between the two portfolios, allowing the comparison to isolate procurement choices rather than savings from lower overall consumption. In the baseline, solar contracts account for 65% of annual contracted renewable volume and wind supplies the remaining 35%. That combination achieves the annual purchasing target but leaves substantial timing mismatches. Municipal offices, water infrastructure and other services do not collectively follow the production curve of either technology. Buying additional output from the same mix can deepen surpluses in already well-supplied hours without adequately addressing the periods that remain uncovered.

The higher-matching portfolio changes both purchasing and operations. Its illustrative allocation of the additional $9 million comprises $5 million for a different mix of generation contracts, $3 million for storage services and $1 million for demand-management arrangements and verification. These are net annual increases against the baseline, rather than estimates of construction spending. Demand-management arrangements allow up to 8% of annual municipal consumption to be shifted within defined operating windows, without changing total yearly use. Storage moves some contracted renewable output into later periods, with losses accounted for rather than treated as new generation.

The resulting improvement is 23 percentage points, from 61% to 84% of hours matched. That distinction matters: the percentages describe the frequency of matching, not necessarily the proportion of electricity consumption covered by contemporaneous renewable production. An unmatched hour with heavy demand can carry more economic and environmental significance than one with light demand. Even after the additional expenditure, 16% of hours remain unmatched. The model consequently supports a narrower conclusion than round-the-clock clean supply: a redesigned portfolio substantially improves temporal alignment, while leaving a residual gap that annual totals alone cannot reveal.

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The case for spending more rests on what happens in those difficult hours. Supporters of tighter matching argue that procurement should reward generation, storage and flexibility when they are useful, rather than simply maximise renewable volume over the year. Contracts designed around timing could encourage a more diverse supply portfolio and make municipal purchasing better aligned with network conditions. But an improved matching score is not itself a measured emissions reduction. Establishing that benefit would require assumptions about the generators displaced, transmission constraints and the treatment of storage charging, among other factors.

The competing view starts with the opportunity cost of the $9 million premium. A municipality could instead consider efficiency improvements, additional renewable purchasing or other investments, comparing their expected benefits on a common basis. More detailed accounting also demands reliable consumption records and contract data, creating work that a headline matching percentage does not capture. Tervane’s illustrative figures do not establish which alternative offers the greatest return. Nor does a 15% increase in procurement spending translate automatically into an equivalent increase in consumer tariffs: the scheme covers municipal purchasing, not the entire electricity bill.

What comes next is a test of robustness rather than a declaration that one percentage settles the policy question. The fictional exercise would need to examine different weather years, demand patterns and contract prices, while checking that renewable attributes are not counted twice. Decision-makers would also need a clear rule for assessing the remaining unmatched hours and disclosing verification costs. Tervane’s result is specific to its assumed grid and load profile, not a universal price estimate. Its broader lesson is that annual adequacy and hourly alignment answer different questions—and that choosing between them requires more than a cleaner-looking ledger.