Utility load, power emissions, and data-center cost allocation shape the energy tape

Key Developments

SRP adds gas, solar, and storage to Arizona’s load-growth toolkit

Salt River Project said it plans to seek board approval in September for the Marigold Energy Center about 45 miles south of Phoenix, a mixed-resource project intended to serve growing demand in Arizona’s Maricopa and Pinal counties (Utility Dive). The proposed project includes 400 MW of battery storage, 600 MW of solar generation, up to 675 MW of gas generation, a new substation, and four miles of 230-kV transmission lines (Utility Dive). SRP also scheduled a July 28 in-person informational session in Stanfield and a July 29 virtual open house, after prior community sessions in December and March (Utility Dive).

The read-through is that Arizona utilities are treating resource diversity as the load-growth hedge, not as a fuel-neutral procurement abstraction. A project that combines solar, batteries, gas, a substation, and short transmission additions points to the practical problem facing fast-growth regions: incremental capacity has to clear local siting, interconnection, and reliability tests at the same time. SRP’s separate June agreement for a 19-MW, 10-hour carbon dioxide battery and October selection of a 5-MW/50-MWh iron-flow battery show that longer-duration pilots are being tested around the same system need, but Marigold’s much larger gas and solar components make dispatchability and permitting the governing variables (Utility Dive).

What to watch: Track SRP’s September board materials, the July community meetings, and any Electrical District No. 3 participation; the key signal is whether the project advances as a bundled local-capacity package or is separated into resource-specific approvals.

Power-sector emissions rise as coal and cooling demand offset renewable growth

Utility Dive, citing EIA, reported that U.S. electric-power-sector carbon dioxide emissions rose 4%, or 58 million metric tons, in 2025 because electricity generation and coal use increased (Utility Dive). Total energy-related carbon dioxide emissions rose 2%, or about 115 million metric tons, compared with 2024 (Utility Dive). EIA said net generation in the electric power sector increased by 3%, or 12 TWh, in 2025 and surpassed 2024’s record annual generation, with hot summer weather, record summer peak electricity demand, data centers, and manufacturing facilities contributing to the increase (Utility Dive).

The operating detail matters more than the headline emissions move. Coal-fired generation rose 13%, adding 78 million metric tons of coal-related CO2 emissions, while natural-gas-fired generation fell 4%, lowering emissions by 23 million metric tons; wind and solar generation rose 3% and 34%, respectively, which helped limit the increase (Utility Dive). The analytical implication is that load growth is testing whether renewables additions can displace high-emissions marginal fuel during weather-driven peaks, not just increase annual clean generation. If demand from cooling, data centers, and manufacturing stays firm, the emissions path will depend on how quickly firm capacity, transmission, storage, and demand flexibility can reduce coal’s peak-period role.

Figure 1 — EIA data cited by Utility Dive show U.S. electric-power-sector generation rose 13% for coal, 3% for wind, and 34% for solar in 2025, while natural-gas-fired generation fell 4%. Source: Utility Dive.

What to watch: Watch EIA’s next power-sector emissions update alongside summer peak-load and fuel-switching data; the important signal is whether coal’s 2025 rebound was weather-linked or becomes a recurring response to load growth and reserve-margin pressure.

Data-center demand pushes electricity and water into the same planning frame

Utility Dive reported that U.S. data centers consumed an estimated 183 TWh of electricity in 2024, more than 4% of total U.S. electricity use, and that demand is projected to grow 133% by 2030 to 426 TWh, citing a Kansas Health Institute report that used Lawrence Berkeley National Laboratory data (Utility Dive). The same report said U.S. data centers directly consumed an estimated 17 billion gallons of water in 2023 and that use could double or quadruple by 2028 across Lawrence Berkeley National Laboratory-modeled scenarios (Utility Dive). Utility Dive also cited the report’s current power-supply mix for data centers: 56% fossil fuels, 22% renewables, and 21% nuclear (Utility Dive).

The more consequential angle is that data-center siting is becoming a multi-constraint infrastructure decision. A load that may more than double electricity use by 2030 and substantially increase water demand by 2028 requires utility planning, local water policy, and economic-development incentives to be evaluated together. Utility Dive separately noted that Bank of America analysts expect the United States will need more than 230 GW of new generating capacity over five years, while regulated utilities are expected to add about 93 GW of accredited supply, leaving a gap of more than 100 GW (Utility Dive). That gap frames why state and local permitting questions are moving from facility-by-facility debates to system-resource planning.

What to watch: Track state disclosure rules, utility interconnection queues, and water-use conditions attached to new data-center approvals; the next pressure point is whether electricity and water reporting become prerequisites for incentives or grid-service agreements.

PJM data-center cost allocation remains unsettled after FERC’s large-load order

Utility Dive reported that ratepayer advocates from five states said FERC’s effort to create a large-load connection framework for PJM fails to adequately protect other consumers from data-center-driven transmission costs (Utility Dive). The advocates said FERC’s June show-cause order for PJM and five other grid operators is flawed because it does not address regional cost allocation of network-upgrade costs caused by data centers (Utility Dive). Utility Dive reported that advocates from Delaware, Illinois, Maryland, Ohio, and Pennsylvania asked FERC to respond quickly, while FERC gave PJM and the other major grid operators 60 days to respond and allowed 45 days for extension requests (Utility Dive).

This is a governance story as much as a load-growth story. A data center can be operationally valuable to a region while still creating disputes over who pays for network upgrades, and the advocates’ filing turns that tension into a tariff question. The practical read-through is that large-load integration may stall or become more expensive if cost-recovery agreements are not standardized before interconnection studies and construction commitments accumulate. That makes PJM’s response to FERC a template risk for other regions facing similar data-center connection requests.

What to watch: Watch PJM’s show-cause response, any extension requests inside the 45-day window, and whether FERC clarifies customer-specific network-upgrade cost recovery; the key issue is whether large loads pay directly for upgrades or costs continue to flow through broader transmission revenue requirements.

This is an AI Briefing — AI-generated analysis published under TLCapital.AI. It is not personal research or positions, and it is not investment advice. Figures are sourced to primary filings with dates noted throughout. Do your own diligence.