A 50 MW connection requested in Northern Virginia this quarter energizes in 2033, after posting $75 million of collateral and signing for 14 years. The same 50 MW in Houston posts no rule-mandated security, signs no minimum-take contract, and can be live in 2028. Between those two ends sit thirteen other markets, each with its own threshold, minimum bill, term and exit fee, and until now nobody had put the seven numbers a buyer needs on one page. This piece does: the Open Factory Large-Load Cost Table v0, fifteen utilities side by side, every cell tied to a tariff sheet, a docket or a dated company statement.

We cover the table itself, the 75 MW line that decides which Texas regime you land in, the Ohio and Virginia take-or-pay model, what security actually costs in dollars, how contract terms converged on 12 years, the industrial rate underneath each tariff, nineteen months of rule changes, realistic energization years, and, behind the wall, the three markets where 2028 is still on the calendar.

What a 50 MW connection costs in 15 US markets, side by sideRead down the last column: 2028 to 2029 in three markets, 2033 in Northern Virginia
What a 50 MW connection costs in 15 US markets, side by sideData as of Aug 2026 What a 50 MW connection costs in 15 US markets, side by side Threshold, minimum bill, term, security and realistic energization for a request filed in Q3 2026. Proposed terms marked (p). Full table with fees, exit fees and CIAC in the CSV. Market (utility) Threshold Min. bill Term Security 50 MW live N. Virginia (Dominion GS-5) 25 MW 85% T&D, 60% gen 14 yr $1.5M/MW 2033 Columbus (AEP Ohio DCT) 25 MW 72.5% at 50 MW up to 12 yr 50% of term min. charges 2031-33 Atlanta (Georgia Power) 100 MW yes, contract-specific up to 15 yr contract-specific 2031 Dallas (Oncor) 75 MW none none $50k/MW + $50k/MW fee (p), 75 MW+ 2029 Houston (CenterPoint) 75 MW none none deposits, ~$64k/MW implied 2028-29 W./S. Texas (AEP Texas) 75 MW none none as Oncor 2029 Carolinas (Duke HLF, p) 50 MW at 80% LF 75% 10 or 15 yr cash or LC for min. bills 2029-30 Phoenix (APS XHLF, p) n/p yes, level n/p long-term collateral, formula n/p 2029 Phoenix (SRP E-67) 20 MW 80% of forecast n/p LCIP upgrades upfront 2028-29 Salt Lake City (RMP) 100 MW (SB 132) n/p n/p n/p 2028-29 Louisiana (Entergy) n/p min. charges 5 yr min. n/p 2029 Colorado (Xcel, p) 50 MW 80% 15 yr $120k deposit + 6 mo. bills 2029-30 Chicago (ComEd TSAs) transmission level revenue commitments n/p ~$250k/MW implied 2031 Bay Area (PG&E Rule 30) 50-230 kV service none none 100% facility advance 2031-32 N. Indiana (I&M) 70 MW n/p for IN 12 yr + 5 yr ramp collateral, formula n/p 2028-29 Open Factory Source: Open Factory Large-Load Cost Table (compiled from utility tariffs, PUC dockets, ERCOT and PUCT filings, LBNL/Brattle Aug 2026, JLL 2026; as of August 2026)

Source: Open Factory Large-Load Cost Table (compiled from utility tariffs, PUC dockets, ERCOT and PUCT filings, LBNL/Brattle August 2026, JLL 2026; as of August 2026)

Fifteen rows, and the energization column runs from 2028 in Houston, Phoenix under SRP and northern Indiana to 2033 in Northern Virginia, while the security column runs from nothing at all below Texas’s 75 MW threshold to $1.5 million per MW at Dominion.

Fifteen Markets, Seven Cells

The table records seven things per market: study fee, security or collateral per MW, minimum bill, contract term, exit fee, CIAC exposure, and the realistic year a 50 MW load requested in Q3 2026 takes service. Each cell in data/large-load-cost-table.csv carries its source URL and date, and a verification flag. Where a utility publishes a number we use it. Where only the structure is public (Georgia’s customer-specific contracts, APS’s pending collateral formula) the cell says so, and the market is marked partial.

Market (utility) Threshold Minimum bill Term Security 50 MW live
N. Virginia (Dominion GS-5) 25 MW 85% T&D, 60% gen 14 yr $1.5M/MW 2033
Columbus (AEP Ohio DCT) 25 MW 72.5% at 50 MW up to 12 yr 50% of term min. charges 2031 to 2033
Atlanta (Georgia Power) 100 MW yes, contract-specific up to 15 yr contract-specific 2031
Dallas (Oncor) 75 MW none none $50k/MW + $50k/MW fee (proposed), 75 MW+ 2029
Houston (CenterPoint) 75 MW none none deposits, ~$64k/MW implied 2028 to 2029
W./S. Texas (AEP Texas) 75 MW none none as Oncor 2029
Carolinas (Duke HLF, proposed) 50 MW at 80% LF 75% 10 or 15 yr cash or LC for min. bills 2029 to 2030
Phoenix (APS XHLF, proposed) n/p yes, level n/p long-term collateral, formula n/p 2029
Phoenix (SRP E-67) 20 MW 80% of forecast n/p LCIP upgrades upfront 2028 to 2029
Salt Lake City (Rocky Mountain Power) 100 MW (SB 132) n/p n/p n/p 2028 to 2029
Louisiana (Entergy) n/p minimum charges 5 yr min. n/p 2029
Colorado (Xcel, proposed) 50 MW 80% 15 yr $120k deposit + 6 mo. bills 2029 to 2030
Chicago (ComEd TSAs) transmission level revenue commitments n/p ~$250k/MW implied 2031
Bay Area (PG&E Rule 30) 50 to 230 kV service none none 100% facility advance 2031 to 2032
N. Indiana (I&M) 70 MW n/p for Indiana 12 yr + 5 yr ramp collateral, formula n/p 2028 to 2029

Full table with study fees, exit fees, CIAC exposure, docket numbers and sources: data/large-load-cost-table.csv. n/p = not published.

The first thing the table shows is that 50 MW is the wrong size for half of these tariffs, and that is the buyer’s advantage. The LBNL and Brattle review of 55 large-load tariffs, published August 10, 2026, found thresholds from 0.3 MW to 150 MW with a median of 25 MW and 75% of tariffs between 5 and 100 MW (LBNL brief, p. 3). A 50 MW plant or colocation hall sits above AEP Ohio’s and Dominion’s 25 MW lines and Xcel Colorado’s 50 MW line, and below Texas’s 75 MW, Indiana Michigan Power’s 70 MW, Georgia’s 100 MW and Utah’s 100 MW. Below the line you get the utility’s ordinary industrial tariff and line-extension policy; above it you get the minimum bill, the term and the collateral. The Large-Load Interconnection Cost tool applies this threshold test before it computes anything else, because nothing else in the table matters until you know which side you are on.

The 75 MW Line in Texas

Texas wrote the threshold into statute. SB 6, signed June 20, 2025, applies to new loads of 75 MW or more: a minimum $100,000 study fee, disclosure of duplicate requests, site control, a uniform security requirement, and ERCOT’s right to curtail in an emergency (Greenberg Traurig summary of the PUCT proposal, March 2026). The PUCT’s implementing rule, proposed 16 TAC §25.194 in Project 58481, was published March 12, 2026 with comments due April 17. It would take $50,000 per MW of financial security at the intermediate agreement, of which 80% is forfeited on withdrawal, a further non-refundable $50,000 per MW interconnection fee at the interconnection agreement, study fees of $100,000 for 75 to 250 MW and $300,000 above 250 MW, and 100% CIAC for radial lines and substations with no revenue credit (ERCOT to Senate B&C Committee, April 1, 2026, slide 9). In the documents we could open the rule was still a proposal in August 2026.

At 50 MW, none of that applies. What applies is the TDSP’s standard facilities-extension process and, since June 18, 2026, the shadow of Batch Zero, ERCOT’s batch study for loads of 75 MW and up, approved by the PUCT that day with 438 GW of requests pending and a final transmission plan promised for fall 2027 (ERCOT release, June 18, 2026). Then on August 3 Governor Abbott directed the PUCT and ERCOT to audit every data center in a queue he put at 474 GW, “more than five times Texas’ record peak electricity demand,” before approving any more (Governor’s letter, August 3, 2026). ERCOT told the PUCT on August 20 it is aiming for a December 10 audit report, that the Batch Zero study will not be done by April 9, 2027, and that it will also run a community-impact review on facilities of 25 MW and above (Utility Dive, August 21, 2026).

ERCOT's large-load queue went from 63 GW to 474 GW in twenty months, then Texas paused itThe slope after March 2026 is the rush to file before Batch Zero closed
ERCOT's large-load queue went from 63 GW to 474 GW in twenty months, then Texas paused itData as of Aug 2026 ERCOT's large-load queue went from 63 GW to 474 GW in twenty months, then Texas paused it Large-load interconnection requests pending at ERCOT, GW. About 90% are data centers. Only 17 loads totaling 6.6 GW had cleared every gate but energization by August 2026. 0 GW 100 GW 200 GW 300 GW 400 GW 500 GW Requests pending474 GW SB 6 signed, Jun 2025 PUCT approves Batch Zero, Jun 18 Abbott directive, Aug 3 Dec 2024 Dec 2025 Mar 2026 Jun 2026 Aug 2026 Open Factory Source: ERCOT (board update Dec 2025, Senate B&C update Apr 2026, release 18 Jun 2026), Governor Abbott letter 3 Aug 2026, via Open Factory Large-Load Cost Table

Source: ERCOT (board update December 2025, Senate B&C update April 2026, release June 18, 2026), Governor Abbott letter August 3, 2026, via Open Factory Large-Load Cost Table

The queue grew from 63 GW at the end of 2024 to 233 GW in December 2025, 410 GW on March 26, 438 GW on June 18 and 474 GW on August 3, 2026, while only 17 loads totaling 6.6 GW had cleared every ERCOT gate except energization by August 20. We wrote up the funnel from 474 GW requested to 3.9 GW drawing power in The 1.6% Funnel in July; the point for a 50 MW buyer is narrower. Below 75 MW you are outside SB 6, outside Batch Zero and outside the $100,000-per-MW stack, but not outside the audit, which reaches down to 25 MW. Oncor told analysts on August 6 that of its 298 GW of requests about 44 GW met the Batch Zero criteria and that none of that load is in its $47.5 billion capital plan before 2027 (Utility Dive, August 7, 2026). CenterPoint said on July 28 that 14 GW of its 17 GW of Batch Zero submissions should qualify, backed by signed facility extension agreements and about $900 million of customer cash commitments and deposits, which works out to roughly $64,000 per MW (Utility Dive, July 28, 2026).

Ohio and Virginia: The Take-or-Pay Model

AEP Ohio’s Schedule DCT is the tariff everyone else copied, and it is the only one of the fifteen where every cell is on the utility’s own web page. PUCO approved it July 9, 2025 after a May 2024 filing (AEP release, July 9, 2025). It applies at 25 MW, aggregated across affiliates. The load study fee is $10,000 for 25 to 50 MW, $50,000 for 50 to 100 MW and $100,000 above. The ramp is at most four years at 50, 65, 80 and 90% of contract capacity, followed by eight years. Collateral is 50% of the total minimum charges over the full term unless you carry A- and A3 ratings and ten times the requirement in cash; surety bonds are not accepted. The exit fee is 36 months of minimum charges, available only after the fifth year following the ramp, and before energization a Letter of Agreement makes you liable for 100% of the buildout if you cancel or slip more than 12 months (AEP Ohio Data Center Tariff page).

The headline 85% is not what a 50 MW customer pays. The minimum demand for 25,001 to 75,000 kW is 15,000 kW plus 85% of capacity above 25,000 kW, so at 50 MW the floor is 36,250 kW, or 72.5% of contract, and the 85% cap only binds above 75 MW (AEP Ohio Data Center Tariff page). The tariff did what it was built to do: of 30,000 MW that had expressed interest, 13,022.7 MW paid for a study and 5,642 MW signed binding contracts by February 12, 2026, on top of 12,219 MW signed before the tariff, against a system peak of 8,000 to 10,500 MW (AEP Ohio, February 13, 2026). Those contracts come online “progressively through 2035,” and the next study tranche opens October 1, 2026 for applications received by September 30.

Dominion’s Schedule GS-5 is the harder version. The SCC created the class for loads of 25 MW and up in its November 25, 2025 order in the biennial review (PUR-2025-00058), with a 14-year minimum term, a four-year ramp at no less than 20% of contract capacity a year, minimum demand charges of 85% of contract for distribution and transmission and 60% for generation, and collateral of $1.5 million per MW of contracted capacity (LBNL brief, pp. 4 to 6 and 13). On July 31, 2026 the SCC went further in PUR-2026-00056 and ordered a mandatory CIAC for “direct connect” transmission, meaning the substations and lines that connect a large load to the bulk system, net of the transmission revenue the customer is expected to produce, with Dominion’s amended line-extension policy due within 90 days; the order also floated assigning higher-order transmission costs to the GS-5 class outright (SCC Final Order, July 31, 2026).

Over 15 years, Xcel's proposed 80% floor commits a 50 MW buyer to 600 MW-years it may never useThe ramp is worth about 100 MW-years in Virginia and Ohio; Colorado and Duke publish none
Over 15 years, Xcel's proposed 80% floor commits a 50 MW buyer to 600 MW-years it may never useData as of Aug 2026 Over 15 years, Xcel's proposed 80% floor commits a 50 MW buyer to 600 MW-years it may never use Cumulative MW-years of demand billed whether or not consumed, 50 MW contract, by contract year. Dominion and AEP Ohio include their published ramps; Xcel and Duke shown flat because no ramp is published. 0 200 400 600 MW-years committed Xcel Colorado (proposed, 80%, 15 yr)600 Dominion GS-5 (85% T&D, 14 yr)510 AEP Ohio DCT (72.5% at 50 MW, 12 yr)386 Duke HLF (proposed, 75%, 10 yr)375 2 4 6 8 10 12 14 Open Factory Source: Open Factory Large-Load Cost Table (compiled from LBNL/Brattle Aug 2026, AEP Ohio Schedule DCT page, Colorado Sun 2 Apr 2026, Latitude Media 8 Jul 2026; as of August 2026)

Source: Open Factory Large-Load Cost Table

For a 50 MW contract, Dominion’s 85% floor with its published ramp commits 510 MW-years over 14 years, AEP Ohio’s 72.5% formula with its 50/65/80/90 ramp commits 386 MW-years over 12, Duke’s proposed 75% commits 375 over 10, and Xcel Colorado’s proposed 80% over 15 years commits 600, the largest of the four. At a demand charge of $10 per kW-month, an assumption you should replace with your own rate, 510 MW-years is about $61 million of demand charges due whether the plant runs or not, which is why the Large-Load Interconnection Cost tool asks for your expected load factor before it asks for anything else.

The minimum bill has settled at 80% of contract demand, with Oregon and Michigan at 90%AEP Ohio's 50 MW value is below its headline 85% because of the tiered formula
The minimum bill has settled at 80% of contract demand, with Oregon and Michigan at 90%Data as of Aug 2026 The minimum bill has settled at 80% of contract demand, with Oregon and Michigan at 90% Minimum billing demand as a percentage of contracted capacity, by tariff. (p) = proposed as of August 2026. AEP Ohio shown at its 50 MW formula value, not the 85% cap. 0% 20% 40% 60% 80% 100% PGE Oregon Sch. 96 90.0% I&M Michigan Large Power (p) 90.0% Dominion GS-5, T&D 85.0% Xcel Colorado (p) 80.0% SRP E-67 80.0% Evergy Missouri LLPS 80.0% LBNL median, 55 tariffs 80.0% Duke Carolinas HLF (p) 75.0% AEP Ohio DCT at 50 MW 72.5% Dominion GS-5, generation 60.0% Open Factory Source: Open Factory Large-Load Cost Table (compiled from OPUC Order 26-154, LBNL/Brattle Aug 2026, SRP, AEP Ohio, Colorado Sun, Latitude Media; as of August 2026)

Source: Open Factory Large-Load Cost Table

LBNL’s median minimum billing demand across the tariffs it reviewed is 80%; Oregon’s Schedule 96 and I&M’s proposed Michigan tariff sit at 90%, Duke’s proposal at 75%, and Dominion’s generation component at 60% is the lowest published floor among the approved tariffs (LBNL brief, p. 5).

Security: $75 Million or Nothing

The security cell is where the fifteen markets diverge most, and where the fewest utilities publish a number. Dominion’s $1.5 million per MW is a tariff figure: $75 million for 50 MW, posted before a kilowatt-hour flows. ComEd does not publish a rate, but Exelon told analysts on July 30 that about 4 GW of data center load with signed Transmission Security Agreements had posted $1 billion of collateral, an implied $250,000 per MW, or $12.5 million for 50 MW (Utility Dive, July 31, 2026). Those TSAs, approved by FERC in February and March 2026, carry a defined ramp, a facility readiness obligation, committed revenue contributions with shortfall payments and a termination-fee schedule (Utility Dive, March 11, 2026).

Dominion wants $75 million of collateral for 50 MW; Texas wants nothing below 75 MWOnly Dominion and Texas publish a per-MW number; the others are implied averages or fees
Dominion wants $75 million of collateral for 50 MW; Texas wants nothing below 75 MWData as of Aug 2026 Dominion wants $75 million of collateral for 50 MW; Texas wants nothing below 75 MW Upfront security or fee for a 50 MW connection, $ millions. Tariff figures where published; ComEd and CenterPoint are averages implied by disclosed totals; Texas shown at its 75 MW floor (proposed rule). $0M $20M $40M $60M $80M Dominion GS-5 collateral ($1.5M/MW) $75.00M ComEd TSA credit (implied $250k/MW) $12.50M Texas at 75 MW: security + fee (proposed) $7.50M CenterPoint deposits (implied $64k/MW) $3.20M Xcel Colorado deposit + studies (proposed) $0.60M AEP Ohio load study fee $0.05M Open Factory Source: Open Factory Large-Load Cost Table (compiled from LBNL/Brattle Aug 2026, Exelon Q2 2026, PUCT Project 58481 proposal, CenterPoint Q2 2026, Xcel filing as reported by Colorado Sun, AEP Ohio DCT; as of August 2026)

Source: Open Factory Large-Load Cost Table

Dominion’s $75.0 million is six times ComEd’s implied $12.5 million, ten times the $7.5 million a 75 MW Texas project would post and forfeit under the proposed rule, 23 times CenterPoint’s implied $3.2 million of deposits, and 125 times Xcel Colorado’s proposed $600,000 of deposit and studies. Collateral, not the minimum bill, is the line item that decides whether a 50 MW project pencils in Virginia, because $75 million of letters of credit costs a developer roughly $1 to 2 million a year to carry before the first demand charge. AEP Ohio’s collateral is a formula, 50% of term minimum charges, that steps down by one year of minimum charges for each year of on-time payment (LBNL brief, p. 7). PG&E’s Rule 30 takes no collateral as such; it takes an Advance equal to the project-specific cost estimate for service facilities, interconnection upgrades and network upgrades at 50 to 230 kV, refunds it over time under rules the CPUC will finalize in Application 24-11-007, and forfeits all remaining refunds if you terminate after the facilities are in service (PG&E Electric Rule 30, effective December 4, 2025).

Terms Are Converging on 12 Years

Contract length moved faster than any other cell. LBNL found the median minimum term was five years for tariffs proposed before 2025 and 12 years for tariffs proposed since, with a range from one to 20 years (LBNL brief, p. 4). Georgia’s PSC raised the allowed term for 100 MW customers from 5 to 15 years on January 23, 2025, added minimum bills, required contracts to be filed 30 days before execution, and made those customers pay for upstream generation, transmission and distribution “as construction of the data centers progresses” (Georgia PSC release, January 23, 2025). Georgia Power’s TOU-SC-16 sheet now bars any customer with an expected peak of 100 MW or more from the standard price option unless it contracted before February 1, 2025 (Georgia Power TOU-SC-16, June 2026).

Minimum contract terms run from 5 years at Entergy Louisiana to 30 years in OregonEvery tariff proposed in 2026 sits at or above the 12-year median
Minimum contract terms run from 5 years at Entergy Louisiana to 30 years in OregonData as of Aug 2026 Minimum contract terms run from 5 years at Entergy Louisiana to 30 years in Oregon Minimum contract term in years by large-load tariff, range where the term scales with load size. (p) = proposed. LBNL medians: 5 years for tariffs proposed before 2025, 12 years since. 0 yr 5 yr 10 yr 15 yr 20 yr 25 yr 30 yr LBNL median since 2025: 12 yr Entergy Louisiana LL-HLFPS 5 yr 5 yr Georgia Power 100 MW+ contracts 5 yr 15 yr Duke Carolinas HLF (p) 10 yr 15 yr PGE Oregon Sch. 96 10 yr 30 yr AEP Ohio DCT 12 yr 12 yr I&M Indiana (12 yr + up to 5 yr ramp) 12 yr 17 yr Dominion GS-5 14 yr 14 yr Xcel Colorado (p) 15 yr 15 yr El Paso Electric Rate 50 (p) 20 yr 20 yr Open Factory Source: Open Factory Large-Load Cost Table (compiled from LBNL/Brattle Aug 2026, Georgia PSC, AEP Ohio, IURC Cause 46097 coverage, OPUC Order 26-154; as of August 2026)

Source: Open Factory Large-Load Cost Table

Entergy Louisiana’s Large Load High Load Factor rate keeps a five-year minimum, Duke’s proposed HLF runs 10 or 15 years by load size, AEP Ohio 12, I&M 12 after a ramp of up to five, Dominion 14, Xcel Colorado’s proposal 15, and Portland General’s Schedule 96 scales from 10 years at 20 MW to 30 years at 220 MW under Oregon’s May 7, 2026 order (OPUC Order 26-154). Indiana Michigan Power’s settlement, approved February 19, 2025, is the model for how term and exit interact: loads of 70 MW at a site or 150 MW across a company sign for at least 12 years after a ramp of up to five, may cut contract capacity by up to 20% after year five with 42 months’ notice at no charge, and pay an exit fee for anything larger, with reductions over 20% now needing IURC approval (Utility Dive, November 25, 2024; AEP, February 19, 2025). Duke’s version, filed in late June 2026 for a 2027 start, is lighter: 75% minimum, security for the minimum bills, and an exit penalty of 25% of remaining bills, which Latitude Media’s analyst called “pretty light-touch” against Dominion (Latitude Media, July 8, 2026).

The Rate Underneath the Tariff

None of these instruments sets the price of energy. The industrial rate does, and it now varies 3.2 to 1 across the fifteen markets. EIA’s May 2026 table puts Texas industrial power at 6.33 cents per kWh, Louisiana at 6.88, Georgia at 7.04, Arizona at 7.54, North Carolina at 7.78, Utah at 8.10, Indiana at 9.08, Colorado at 9.47, Ohio at 9.87, Illinois at 10.20, Virginia at 10.53 and California at 20.20, against a US average of 8.71 (EIA Electric Power Monthly, July 2026, Table 5.6.A).

Texas industrial power is 6.33 cents; Virginia is 10.53 and up 14% in a yearThe three PJM states in the table (Ohio, Illinois, Virginia) posted the three largest increases
Texas industrial power is 6.33 cents; Virginia is 10.53 and up 14% in a yearData as of May 2026 Texas industrial power is 6.33 cents; Virginia is 10.53 and up 14% in a year Average industrial retail electricity price, cents per kWh, May 2026, states of the 15 markets plus the US average. Ohio rose 30% and Illinois 14% year over year; Arizona fell 9%. 0 5 10 15 20 25 Texas 6.33 Louisiana 6.88 Georgia 7.04 Arizona 7.54 North Carolina 7.78 Utah 8.10 US average 8.71 Indiana 9.08 Colorado 9.47 Ohio 9.87 Illinois 10.20 Virginia 10.53 California 20.20 Open Factory Source: EIA Electric Power Monthly, Table 5.6.A (July 2026 edition, May 2026 data) via Open Factory Large-Load Cost Table

Source: EIA Electric Power Monthly, Table 5.6.A (July 2026 edition, May 2026 data) via Open Factory Large-Load Cost Table

Ohio’s industrial rate rose 29.7% in twelve months, from 7.61 to 9.87 cents, Illinois 14.3% and Virginia 14.0%, while Texas fell 3.9% and Arizona 8.6%. The three risers are PJM states, and the driver is the capacity charge: $333.44 per MW-day for 2027/28 is about $122,000 per MW-year, and we walked through how that lands on a plant’s bill in A Factory Owner’s Guide to the PJM Capacity Charge in May. For a 50 MW load at full contract demand the PJM Capacity Charge Estimator puts the 2027/28 capacity line near $6.1 million a year before any tariff minimum, and PJM’s board decided on July 27 to exclude new large loads that do not bring their own supply from future auction forecasts and to make them curtailable near emergencies from June 2027 (Utility Dive, July 28, 2026). Rate and tariff pull the same way: the three markets with the longest terms and largest collateral also have the most expensive and fastest-rising energy.

Nineteen Months of Rule Changes

Every cell in the table has a date on it because most of them changed between January 2025 and August 2026. The Large-Load Policy Tracker carries the running list; the eighteen entries that touch these fifteen markets are below.

Nineteen months of large-load rules, January 2025 to August 2026Five of the eighteen entries fell in the eight weeks before this piece
Nineteen months of large-load rules, January 2025 to August 2026Data as of Aug 2026 Nineteen months of large-load rules, January 2025 to August 2026 Every order, statute or filing that changed what a large connection costs in the 15 markets, by date. Proposals marked (p). Date Jurisdiction Rule What it does 2025-01-23 Georgia PSC Large-load rule 100 MW+: contracts to 15 yr, minimum bills, upstream costs 2025-02-19 Indiana URC I&M settlement, Cause 46097 70 MW+: 12 yr after 5 yr ramp, exit fees 2025-03 Utah SB 132 100 MW+ may contract own generation; pays studies, upgrades, transmission rate 2025-06-20 Texas SB 6 75 MW+: $100k study, security, curtailment, batch process 2025-07-09 Ohio PUCO AEP Ohio Schedule DCT 25 MW+: 85% min., 12 yr, collateral, 36-month exit fee 2025-07 California PUC D.25-07-039, PG&E Rule 30 Transmission-level service on customer advances with refunds 2025-11-25 Virginia SCC Dominion GS-5 25 MW+: 14 yr, 85/85/60% min., $1.5M/MW collateral 2026-03-12 Texas PUC Proposed 16 TAC 25.194 (p) 75 MW+: $50k/MW security + $50k/MW fee, 100% CIAC 2026-04-02 Colorado PUC Xcel large-load tariff (p) 50 MW+: 15 yr, 80% min., $120k deposit, exit = remaining bills 2026-05-07 Oregon PUC Order 26-154, PGE Sch. 96 20 MW+: 90% min., 10 to 30 yr, 1c/kWh above 100 MW 2026-06-18 Texas PUC Batch Zero approved 438 GW queue studied in batches; plan fall 2027 2026-06-18 FERC Show-cause orders Six RTOs must justify large-load interconnection rules 2026-06 Duke Energy Schedule HLF, E-7 Sub 1329 (p) 50 MW+ at 80% LF: 75% min., 10 or 15 yr, 25% exit 2026-07-27 PJM board Backstop and IRAS Loads without supply excluded from forecast; curtailable 2026-07-31 Virginia SCC Final order PUR-2026-00056 Mandatory CIAC for direct-connect transmission 2026-08-03 Texas Governor Audit directive 474 GW queue audited before any approval; Batch Zero delayed 2026-08-10 LBNL / Brattle Rate designs brief 55 tariffs: median 25 MW, 80% min., 12 yr 2026-08-20 Texas PUC Good-cause exception ERCOT audit report targeted 2026-12-10 Open Factory Source: Open Factory Large-Load Policy Tracker (compiled from PSC, PUC, SCC, ERCOT, PJM and Governor documents listed in data/rule-timeline.csv; as of August 2026)

Source: Open Factory Large-Load Policy Tracker (compiled from PSC, PUC, SCC, ERCOT, PJM and Governor documents listed in data/rule-timeline.csv; as of August 2026)

Eighteen actions in nineteen months, eleven of them since March 2026: Georgia’s rule (January 23, 2025), Indiana’s I&M order (February 19, 2025), Utah SB 132 (March 2025), Texas SB 6 (June 20, 2025), AEP Ohio’s DCT (July 9, 2025), PG&E Rule 30 (July 2025), Dominion GS-5 (November 25, 2025), the PUCT’s forecasting rule (March 1, 2026) and proposed interconnection standards (March 12), Xcel Colorado’s filing (April 2), Pennsylvania’s model tariff (April), Oregon’s Order 26-154 (May 7), Batch Zero and FERC’s show-cause orders (June 18), Duke’s HLF filing (late June), PJM’s board decision (July 27), the SCC’s CIAC order (July 31), Abbott’s directive (August 3), the LBNL brief (August 10) and the PUCT’s good-cause exception for ERCOT (August 20). Utah’s law is the outlier in direction: SB 132 defines a large load as 100 MW within five years, gives Rocky Mountain Power 90 days to evaluate, and if the utility cannot serve without major investment lets the customer contract with separate generation, paying the studies, upgrades and transmission rate itself (Latitude Media, April 15, 2025). Xcel’s Colorado filing goes the other way: 50 MW threshold, a $120,000 deposit plus studies for about $600,000 upfront, a 15-year contract at 80%, security of six months of operations, and an exit fee equal to every remaining minimum monthly bill (Colorado Sun, April 2, 2026).

Energization: 2028 to 2033

The last column is the one buyers ask about first and utilities publish last. JLL’s 2026 outlook is the only source we found that charts average grid-connection lead time specifically for a new 50 MW data center by market: about 2.5 years in Dallas and Phoenix, about 5 in Atlanta and Chicago, about 7 in Northern Virginia, with the primary-market average above four years (JLL 2026 Global Data Center Outlook, p. 18). A CPS Energy planning presentation at PowerGen 2026 puts Columbus at 84 months, Silicon Valley at 72 and Pittsburgh, Chicago, Houston and Dallas at 36 (as reported by Avanza Energy, 2026). We combined those with utility statements to set a range per market.

A 50 MW request filed today energizes in 2028 in Houston and 2033 in Northern VirginiaEvery market below the 4-year line is either outside its state's large-load threshold at 50 MW or in a vertically integrated territory with generation under construction
A 50 MW request filed today energizes in 2028 in Houston and 2033 in Northern VirginiaData as of Aug 2026 A 50 MW request filed today energizes in 2028 in Houston and 2033 in Northern Virginia Years from a Q3 2026 request to energization, realistic range by market. JLL 2026 market averages for 50 MW data centers where published; utility statements and planning presentations elsewhere. 0.0 yr 2.0 yr 4.0 yr 6.0 yr 8.0 yr JLL: primary-market average exceeds 4 years Houston (CenterPoint) 2.0 yr 3.0 yr N. Indiana (I&M, below 70 MW) 2.0 yr 3.0 yr Salt Lake City (RMP) 2.0 yr 3.0 yr Phoenix (SRP) 2.5 yr 3.0 yr Dallas (Oncor) 2.5 yr 3.5 yr W./S. Texas (AEP Texas) 2.5 yr 3.5 yr Phoenix (APS) 2.5 yr 3.5 yr Louisiana (Entergy) 2.5 yr 3.5 yr Carolinas (Duke) 3.0 yr 4.0 yr Colorado (Xcel) 3.0 yr 4.0 yr Atlanta (Georgia Power) 4.5 yr 5.5 yr Chicago (ComEd) 4.5 yr 5.5 yr Bay Area (PG&E) 5.0 yr 6.0 yr Columbus (AEP Ohio) 5.0 yr 7.0 yr N. Virginia (Dominion) 6.5 yr 7.5 yr Open Factory Source: Open Factory Large-Load Cost Table (compiled from JLL 2026 Global Data Center Outlook p.18, CenterPoint and Duke Q1 2026 calls, AEP Ohio DCT page, CPS Energy PowerGen 2026 presentation; as of August 2026)

Source: Open Factory Large-Load Cost Table

Houston, northern Indiana and Salt Lake City sit at 2 to 3 years from a Q3 2026 request, Phoenix under SRP at 2.5 to 3, Dallas, AEP Texas, Phoenix under APS and Louisiana at 2.5 to 3.5, the Carolinas and Colorado at 3 to 4, Atlanta and Chicago at 4.5 to 5.5, the Bay Area at 5 to 6, Columbus at 5 to 7 and Northern Virginia at 6.5 to 7.5. Behind the Virginia number is a Dominion queue of 70 GW against an all-time peak of 24.6 GW, growing by about 10 requests a month (former FERC Chairman Christie, Utility Dive, February 2026). Behind the Columbus number is 17,861 MW of signed contracts scheduled through 2035. Behind the Houston number is a utility with 3.5 GW under construction, 8 GW of data center load it expects to energize by 2029, and a pipeline in which 90% of projects are 500 MW or less and sited near existing substations (Utility Dive, April 23, 2026).

The years in that column are gated by equipment as much as by paperwork. A 50 MW service at 138 kV needs a 60 to 75 MVA transformer, and the Lead-Time Monitor carries 128 weeks as the published lead time for power transformers and 144 weeks for GSUs, numbers we traced back to Butler Works and one steel mill in Transformer Lead Times Hit 160 Weeks. The Lead-Time-Adjusted Schedule tool will tell you that a utility promising 2028 energization must have ordered the transformer before this article was published, and the Transformer Sizing and Cost tool will tell you what to budget if you are asked to buy it yourself under a CIAC.

What to Do Monday

Size the request against the threshold. At 50 MW you are inside AEP Ohio, Dominion, Xcel Colorado and SRP’s tariffs and outside Texas, Indiana, Georgia and Utah’s; a 49 MW request in Columbus saves $40,000 on the study fee and nothing else, while a 74 MW request in Dallas avoids the entire proposed $100,000-per-MW stack and Batch Zero. Ask the utility for three numbers in writing before you sign a letter of intent: the collateral formula in dollars for your load, the minimum demand in kW for your contract capacity (not the headline percentage), and the exit fee in months. Write the energization date into the ESA with a term adjustment if the utility misses it; AEP Ohio’s contract term starts on the actual energization date and lets you petition PUCO if infrastructure is late, and that clause is worth copying into every other market. Price the minimum bill at your realistic load factor, not the contract capacity, and if that number exceeds what a 50 MW bridge of engines or fuel cells would cost, run the Genset TCO tool and read Recips vs Turbines vs Fuel Cells before you sign for 14 years. And if you are in a PJM state, budget the capacity charge as a separate line, because no tariff in this table waives it.

Every market above 4 years on the energization chart is one where a 2028 plant needs a bridge, and we covered what bridges cost and how long they take in Behind the Meter, In Front of the Queue and the slot deposits behind them in The $60 Million Deposit. The three markets below 3 years are a different problem: there the question is which tariff mechanics get a 50 MW load to 2028 without a 12-year floor. Behind the paywall: the three markets where a 50 MW buyer can still energize in 2028, the specific threshold, deposit and study rules that make it possible in each, and the one clause in each that can take the date away, all drawn from the Large-Load Cost Table.