T-01 · T-07 · Live Analytics
| Utility | St | Excess $M | Yrs | $/MMBtu |
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| Utility | St | Savings $M | Yrs | $/MMBtu |
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Over the eighteen-year period from 2008 through 2025, above-peer electric utilities collectively paid $26.4 billion more than their regional peer-average procurement costs for natural gas. This figure — drawn from 39,098 monthly observations across 252 regulated utilities in 45 states — represents the aggregate additional burden borne by ratepayers of utilities that consistently procured gas at above-market prices relative to comparable regional operators.
The gap is not narrowing. The three highest above-peer years in the dataset are 2022 ($2.50B), 2023 ($2.37B), and 2009 ($2.11B). The post-2021 energy market disruptions — driven by Russia's invasion of Ukraine, record U.S. LNG export volumes, and domestic pipeline infrastructure constraints — amplified procurement cost differentials rather than compressing them. Utilities with disciplined hedging programs and diversified supply portfolios outperformed spot-exposed peers by a wider margin than at any point since the 2009 shale gas price crash.
The geographic concentration is striking. The Southeast (SERC region) accounts for 57% of all above-peer procurement costs nationally — $17.7 billion out of $26.4 billion total — despite representing a smaller share of total U.S. gas consumption. Florida Power & Light alone drives $9.19 billion of that figure, having paid above regional peer averages in every single year of the study period. Duke Energy Progress in North Carolina adds $1.79 billion over 14 consecutive years above peers.
The best procurers demonstrate that the peer benchmark is attainable. Tennessee Valley Authority (Mississippi operations) saved $1.81 billion relative to SERC peers over eighteen years — a direct consequence of TVA's scale, multi-state supply diversification, and access to competitive pipeline receipt points. Portland General Electric in Oregon saved $833 million, reflecting the West's competitive Rockies gas supply and PGE's disciplined contracting practices. The fact that best and worst procurers exist within the same regional markets confirms that the differential reflects procurement strategy, not just geography.
Search for any of the 252 regulated electric utilities in the dataset to view their 18-year procurement cost history versus regional peer averages. The tool shows actual weighted-average costs, peer group comparisons, year-by-year excess or savings, and a written analytical summary of the utility's procurement record.
Data covers 2008 through 2025 from EIA Form 923 (Fuel Receipts and Costs). Peer groups are defined by NERC reliability region for 2008–2017 and by Balancing Authority area for 2018–2025. All costs are in dollars per MMBtu.
| Utility | St | Spot % | Risk Rating | Risk Months | Ann Cost | Peer Avg |
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The T-07 Hedging Performance Monitor reveals a striking structural vulnerability in U.S. electric utility gas procurement: 67.2% of all utility-years in the dataset are classified as HIGH risk, meaning the utility purchased more than 80% of its gas on the spot market with no fixed-price or indexed contract protection. For most of the study period, this was a manageable strategy — Henry Hub prices remained relatively low from 2009 through 2020, averaging $2.87/MMBtu. But it created catastrophic exposure in high-price years.
The ten utilities with 18 risk-months — meaning they were simultaneously highly spot-exposed and facing Henry Hub prices above $6/MMBtu in every year of the study — include some of the nation's largest gas purchasers: Southwestern Electric Power Company (Arkansas), Arizona Public Service, LADWP, San Diego Gas & Electric, and Public Service Company of Colorado. Each of these utilities paid materially above peer averages in the high-price years of 2008, 2021, 2022, and 2023.
The counterexample is instructive. Portland General Electric (Oregon) maintained spot exposure below 20% across the study period, achieving 17 of 18 years below regional peers at an average of -$1.039/MMBtu. Florida Power & Light, despite being the worst overall procurer in dollar terms, actually maintained near-zero spot exposure — its above-peer costs reflect contract structure and supplier selection, not hedging failure. The data confirms that spot exposure alone does not determine outcomes, but it dramatically increases variance and amplifies losses in volatile years.
All 45 states with regulated gas-fired generation — click any state to see detail
The state-level data reveals sharp geographic clustering in procurement performance. Florida is the single most significant state, with $13.8 billion in net above-peer costs — driven almost entirely by Florida Power & Light's consistent above-peer performance over eighteen years. Even excluding FPL, Florida's other regulated utilities (Duke Energy Florida, JEA, Kissimmee Utility) contribute an additional $2 billion, suggesting a state-level regulatory environment that has not effectively disciplined procurement costs.
The Mississippi-Georgia-Alabama corridor shows the opposite pattern: $7.3 billion in combined below-peer savings across those three states, driven by TVA's procurement operation, Mississippi Power, Georgia Power, and Alabama Power. These utilities benefit from TVA's enormous scale and competitive supply diversity, as well as Georgia Power and Alabama Power's systematic use of fixed-price contracts and diversified pipeline access.
The Western states present a mixed picture. Oregon, driven by Portland General Electric, is consistently below peers. California's LADWP consistently overpays despite being in one of the most competitive gas markets in the country. Colorado's Public Service Company and Wyoming's PacifiCorp both show persistent above-peer costs, reflecting the region's limited pipeline competition and basis risk from Rocky Mountain supply volatility.
Across 18 years of Form 923 data, natural gas procurement costs follow a consistent seasonal U-shape: highest in December through February, lowest in March through May, modestly elevated in summer due to cooling demand, then rising again in late fall as utilities enter winter contracting. The average winter premium (December through February) over summer (June through August) is +$1.07/MMBtu — meaning spot-dependent utilities pay approximately one dollar more per MMBtu in winter than utilities that locked in supply during the spring window.
February is the single most dangerous month in the dataset. Its 18-year standard deviation of $6.32/MMBtu dwarfs every other month, driven almost entirely by Winter Storm Uri in February 2021, when the national average procurement cost reached $30.36/MMBtu. Utilities with fixed-price contracts that month paid $2–4/MMBtu. Those with spot exposure paid $15–30/MMBtu. The spread was procurement strategy, not market luck.
March through May is the optimal procurement window. These three months consistently show the lowest absolute costs, the lowest Henry Hub basis differentials, and the lowest year-over-year volatility. Utilities that use this window to lock in annual supply contracts systematically outperform spot-dependent peers. The seasonal pattern amplifies in high-price environments — in 2008, 2021, and 2022, winter months drove above-peer costs dramatically higher for spot-exposed utilities, compounding ratepayer harm precisely when markets were most stressed.
| Utility | St | Named Suppliers | Spot % | Top Supplier % | vs Peer |
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The Form 923 Purchase Type column (S / C / T) records how each gas transaction was structured — spot market, bilateral contract, or tolling. The SUPPLIER column names the counterparty. Together they measure purchase mechanism diversity: how many named bilateral counterparties does this utility maintain, and what share of its volume flows through anonymous spot market purchases?
Purchase mechanism diversity is a necessary but not sufficient condition for below-peer costs. Duke Energy Carolinas — 59 named suppliers, near-zero spot, yet persistently above-peer — demonstrates that having many bilateral contracts does not guarantee competitive pricing. What matters is the price set in those contracts, which is what the Supply Contract Pricing tab measures.
The 18-year trend shows slow improvement in supplier diversity nationally — from an average of 4.1 named suppliers per operator in 2008 to 6.2 in 2024 — but the share of pure spot-only operators has remained stubbornly at 48–58% throughout, indicating that roughly half the industry never developed bilateral supply relationships at all.
| Utility | St | Fixed % (F) | Indexed % (I) | Blended Cost | Peer | Excess |
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These are three distinct Form 923 columns measuring different things. Purchase Type (S/C/T) tells you the transaction mechanism. Natural Gas Supply Contract Type (F/I) tells you the commodity pricing structure for contracted purchases only. Natural Gas Delivery Contract Type (F/I, not yet analyzed) tells you the pipeline transportation pricing structure — a separate dimension entirely.
FPL's paradox resolves here. MINIMAL spot exposure but above-peer costs: FPL buys almost entirely on contract, but those contracts are fixed-price arrangements set above market at the time of negotiation. Fixed price does not mean cheap — it means the price was locked in, for better or worse.
The national 2025 split (79% fixed, 21% indexed) has been remarkably stable since 2014 at roughly 80/20. The post-Uri shift toward fixed contracts that many expected did not materialize at the national level — the industry was already heavily fixed-price before Uri.