Fifteen utilities, eight tariff cells each, and 45 of the 120 cells carry no published number. That is the honest headline of the Open Factory Large-Load Cost Table, which launches as version 0.1: for a 50 MW connection in fifteen US markets, the study fee, security per MW, minimum bill, contract term, ramp, exit fee, CIAC exposure and a realistic energization year, each cell tied to the tariff sheet, commission order, statute or dated statement it came from. Fifty-three cells come from a primary document, 20 from a trade-press report of a filing we could not open, 2 from our arithmetic on a disclosed total, and 45 from nothing, because the utility has put the number nowhere public. The 15-market walk-through argues what the numbers mean; this piece is about the table as a product.

It covers what each column means and how it was read from a tariff or a docket, the verification flag and what “not published” means, how the fifteen markets were chosen, the known biases, how the table is refreshed, how to use it with the Large-Load Interconnection Cost tool, and what version 1 adds.

Where every cell of the Large-Load Cost Table came from: 53 primary, 20 press, 2 implied, 45 not publishedread the Study fee column, 13 of 15 cells are n/p, then the Threshold column, 12 of 15 are documents
Where every cell of the Large-Load Cost Table came from: 53 primary, 20 press, 2 implied, 45 not publishedData as of Aug 2026 Where every cell of the Large-Load Cost Table came from: 53 primary, 20 press, 2 implied, 45 not published Version 0.1, 15 markets x 8 tariff cells plus an energization estimate. primary = tariff sheet, order, statute, utility page or national-lab brief; press = report of a filing; implied = our arithmetic on a disclosed total; n/p = not in any source opened; (p) = proposed. Market (utility) Threshold Study fee Security Min. bill Term Ramp Exit fee CIAC Live year Flag Columbus (AEP Ohio DCT) primary primary primary primary primary primary primary primary est. Verified Bay Area (PG&E Rule 30) primary n/p primary primary primary primary primary primary est. Verified Dallas (Oncor) primary n/p primary primary primary primary primary primary est. Partial N. Virginia (Dominion GS-5) primary n/p primary primary primary primary n/p primary est. Verified W./S. Texas (AEP Texas) primary n/p n/p primary primary primary primary primary est. Partial Houston (CenterPoint) primary n/p implied primary primary primary n/p primary est. Partial Atlanta (Georgia Power) primary n/p n/p primary primary n/p n/p primary est. Partial N. Indiana (I&M) primary n/p n/p n/p primary primary primary n/p est. Partial Phoenix (SRP E-67) primary n/p primary primary n/p n/p n/p primary est. Partial Louisiana (Entergy) n/p n/p n/p n/p primary n/p n/p press est. Thin Phoenix (APS XHLF, p) n/p n/p n/p n/p n/p n/p n/p primary est. Partial Colorado (Xcel, p) press press press press press n/p press press est. Partial Carolinas (Duke HLF, p) press n/p press press press n/p press press est. Partial Chicago (ComEd TSAs) n/p n/p implied press n/p press press press est. Partial Salt Lake City (RMP) press n/p n/p n/p n/p n/p n/p press est. Thin 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)

Read the columns down: the threshold is a primary document in 10 markets and a press report in 2, the CIAC column is documented in 14 of 15, and the study fee is published by one utility of the fifteen (AEP Ohio, on its own page) and reported for one more (Xcel Colorado, by the Colorado Sun). The full table, 15 rows by 22 columns with a source URL and date in every row, is large-load-cost-table-v0.1.csv, and the cell-by-cell coding behind the figure is verification-matrix.csv.

Nine Columns, One Row per Market

Each row is one utility territory and the instrument governing a new large load there. The nine cells a buyer reads first, and how each was read:

Threshold is the MW at which the large-load regime starts, read from the tariff’s applicability clause or the statute’s definitions. Dominion’s Schedule GS-5 applies at 25 MW of contract demand per the SCC’s November 25, 2025 order in PUR-2025-00058 as carried in the LBNL and Brattle brief; AEP Ohio’s Schedule DCT at 25 MW aggregated across affiliates per the utility’s own tariff page; Texas SB 6 at 75 MW; Georgia’s PSC rule at 100 MW per the January 23, 2025 release. A yes/no column, applies_to_50mw, records which side of the line a 50 MW load falls on, because nothing else in the row applies until you know.

Study fee is the one-time fee to enter the utility’s load study. AEP Ohio prints three tiers on its page: $10,000 for more than 25 to under 50 MW, $50,000 for 50 to under 100 MW, $100,000 at 100 MW and above, payable within 45 days. The PUCT’s proposed 16 TAC 25.194 sets $100,000 for 75 to 250 MW and $300,000 above, plus actual study costs, per Greenberg Traurig’s summary of the March 12, 2026 proposal; below 75 MW the TDSP’s own study fee is not published, so the Texas cells at 50 MW say so. Thirteen of fifteen study-fee cells are “not published.”

Security or collateral is what you post before energization, and the table keeps three sub-columns: the instrument as written, the dollar figure for 50 MW where it can be computed, and the basis of that computation. Dominion’s $1.5 million per MW of contracted capacity is a tariff figure (LBNL brief, p. 6), so the 50 MW cell is $75 million with basis “tariff.” ComEd’s cell is $12.5 million with basis “implied,” because Exelon told analysts that about 4 GW of signed Transmission Security Agreements had posted $1 billion, a portfolio average of $250,000 per MW, not a quote. AEP Ohio’s collateral, 50% of total minimum charges over the term, is recorded as a formula and not dollarized, because that needs your demand charge.

Minimum bill is the share of contract demand billed whether or not consumed, and the table records the formula, not the headline. AEP Ohio’s page says 85%, but its formula for 25,001 to 75,000 kW, 15,000 kW plus 85% of capacity above 25,000 kW, gives 36,250 kW at 50 MW, or 72.5%. Dominion’s is three numbers, 85% for distribution, 85% for transmission and 60% for generation (LBNL brief, p. 5). Where the regime has no minimum by design, the cell says “none” and why: an ERCOT TDSP delivers power a retail electric provider sells, so no take-or-pay contract carries a floor.

Contract term, ramp and exit fee are read together, because they interact. AEP Ohio’s term is a ramp of at most four years at 50, 65, 80 and 90% of contract plus eight years, its exit fee 36 months of minimum charges allowed only after the fifth year following the ramp (AEP Ohio tariff page). Indiana Michigan Power’s settlement, approved February 19, 2025 in IURC Cause 46097, runs at least 12 years after a ramp of up to five and lets a customer cut up to 20% after year five with 42 months’ notice free (AEP release; Utility Dive). Where a tariff says an exit fee exists but not how much, as Dominion’s GS-5 does in the documents we opened, the cell says “amount not published.”

CIAC exposure is what you pay toward the wires, and at 14 of 15 it is the best-documented column because it is where regulators have written the most: the SCC’s July 31, 2026 final order in PUR-2026-00056 makes a contribution mandatory for “direct connect” substations and lines net of expected transmission revenue; PG&E’s Electric Rule 30 takes an advance equal to the project-specific estimate for service facilities, interconnection upgrades and network upgrades at 50 to 230 kV and refunds it over up to ten years; the Texas proposal takes 100% of radial lines and substations with no revenue credit.

Realistic energization year is the one cell that is an estimate; its energization_basis column says what it rests on.

How a Cell Is Read

The source hierarchy is fixed and the CSV’s source column shows which rung each row reached. First, the tariff sheet or the commission’s order, read directly: PG&E Rule 30, the SCC’s two Dominion orders, Georgia Power’s TOU-SC-16 sheet, Oregon’s Order 26-154. Second, the statute or the utility’s own page or release: AEP Ohio’s tariff page and its February 13, 2026 load update, the Georgia PSC’s release and fact sheet, ERCOT’s June 18, 2026 Batch Zero release and April 1, 2026 Senate deck, the Governor’s August 3, 2026 letter. Third, a national-lab compilation that read the tariff and cites the docket, which means the LBNL and Brattle brief of August 10, 2026 with its Appendix 1 of docket numbers; a page-cited LBNL figure counts as primary and the cell says “LBNL p. 6.” Fourth, a trade-press report of a filing we could not open, printed “as reported by”: Latitude Media on Duke’s Schedule HLF filing in NCUC E-7 Sub 1329, the Colorado Sun on Xcel’s 26AL-0137E filing, Utility Dive on the FERC orders approving ComEd’s TSAs. Fifth, arithmetic on a disclosed total, labelled “implied.”

AEP Ohio is the only market with a primary document behind all eight cells; six markets have one or noneblue is a document we read, orange is a press report of a filing, green is our arithmetic, grey is nothing public
AEP Ohio is the only market with a primary document behind all eight cells; six markets have one or noneData as of Aug 2026 AEP Ohio is the only market with a primary document behind all eight cells; six markets have one or none Eight tariff cells per market (threshold, study fee, security, minimum bill, term, ramp, exit fee, CIAC) by the kind of source behind each, version 0.1. Primary document Press report of filing Implied from disclosure Not published 0 2 4 6 8 Columbus (AEP Ohio DCT) Bay Area (PG&E Rule 30) Dallas (Oncor) N. Virginia (Dominion GS-5) W./S. Texas (AEP Texas) Houston (CenterPoint) Atlanta (Georgia Power) N. Indiana (I&M) Phoenix (SRP E-67) Louisiana (Entergy) Phoenix (APS XHLF, p) Colorado (Xcel, p) Carolinas (Duke HLF, p) Chicago (ComEd TSAs) Salt Lake City (RMP) Open Factory Source: Open Factory Large-Load Cost Table

Source: Open Factory Large-Load Cost Table

AEP Ohio is 8 of 8 primary, PG&E and Oncor 7, Dominion and AEP Texas 6, CenterPoint 5 plus one implied; at the other end Xcel Colorado and Duke are 7 and 6 press-reported cells with none primary, ComEd 4 press plus one implied, Rocky Mountain Power 2 press, and APS and Entergy one primary cell each. The market-level flag follows from that: VERIFIED where every filled cell is primary (Dominion, AEP Ohio, PG&E), PARTIAL where the regime is verified but cells rest on press or are missing, THIN where only the statute and the docket number are confirmed (Rocky Mountain Power, Entergy Louisiana).

“Not published” means the number was not in any document we could open, and it is a finding about the utility, not a gap in our reading. Dominion’s public business rates page lists Schedules GS-1 through GS-4 and no GS-5 sheet as of September 2026, ten months after the SCC created the class; the collateral, term and minimums are in the order and the LBNL brief, the study fee and the exit-fee dollar amount are not. Georgia Power’s 100 MW-plus contracts are customer-specific by design and filed with the PSC 30 days before execution, so the fee and collateral cells will stay “not published” until a contract is made public. APS’s XHLF update is a pending rate case, E-01345A-25-0105, with the formulas in testimony we did not open. The 45 cells fall as 13 study fees, 7 ramps, 7 exit fees, 6 security formulas, 4 minimum bills, 4 terms, 3 thresholds and 1 CIAC. A cell that says “none” is different: it means the regime has no such term, and the document that shows that is cited.

Every cell also carries a status and a date. Proposals are marked (p) in the figures and “pending” in the status_as_of column; the PUCT’s 25.194, Duke’s HLF, Xcel’s Colorado tariff and APS’s XHLF are opening positions, not rules. An approved tariff carries its approval date; PG&E’s Rule 30 carries “interim,” because its refund rules are still being set in Application 24-11-007.

How the Fifteen Markets Were Chosen

Three filters, applied in order. First, the territories holding the most requested or contracted large load: Dominion’s queue of about 70 GW against a 24.6 GW peak, Oncor’s 298 GW of requests, AEP Ohio’s 17,861 MW under contract, Southern’s 17 GW contracted, CenterPoint’s 14 GW of Batch Zero-eligible load, Duke’s 7.6 GW executed, ComEd’s roughly 9 GW of high-probability load, PG&E’s 12.7 GW pipeline. Second, the five markets JLL charts by name for a new 50 MW data center in its 2026 outlook: Northern Virginia, Dallas, Phoenix, Atlanta and Chicago. Third, one instance of each regime type, so a factory in a territory we do not cover can find its nearest analogue: PJM take-or-pay tariffs (Dominion, AEP Ohio, I&M), a PJM wires company on FERC-jurisdictional agreements (ComEd), ERCOT TDSPs under a statute (Oncor, CenterPoint, AEP Texas), Southeastern non-RTO utilities (Georgia Power, Duke) and a MISO one (Entergy), Western utilities under a rate case (APS), a public power board (SRP), a state law (PacifiCorp under Utah SB 132) and a proposed tariff (Xcel Colorado), and CAISO under a cost mechanism rather than a tariff (PG&E Rule 30).

What that leaves out is the subject of the biases section: no cooperative, one public power district, nothing in New York, the Pacific Northwest or the Plains. Portland General’s Schedule 96 is a context row, not a market.

What the Table Dollarizes

Only two of fifteen markets publish a security figure per MW. Everything else the table can put a dollar sign on is a fee, a deposit or our arithmetic, and the chart says which.

Only two of fifteen markets publish a per-MW security figure; the rest are fees, deposits or arithmeticDominion's tariff figure doubles from 50 to 100 MW; the Texas stack goes from zero to $10.1 million because the rule starts at 75 MW
Only two of fifteen markets publish a per-MW security figure; the rest are fees, deposits or arithmeticData as of Aug 2026 Only two of fifteen markets publish a per-MW security figure; the rest are fees, deposits or arithmetic Cash posted before energization for 50 MW and 100 MW, $ millions. Tariff figures where published; ComEd and CenterPoint are averages implied by disclosed totals; Texas is a proposed rule that starts at 75 MW. 50 MW 100 MW $0M $50M $100M $150M Dominion GS-5 collateral ($1.5M/MW, tariff) $75.00M $150.00M ComEd TSA credit (implied ~$250k/MW) $12.50M $25.00M Texas TDSPs, proposed 25.194 (security + fee + study) $0.00M $10.10M CenterPoint extension deposits (implied ~$64k/MW) $3.20M $6.40M Xcel Colorado deposit + studies (proposed, not per MW) $0.60M $0.60M AEP Ohio load study fee (collateral formula not dollarized) $0.05M $0.10M Open Factory Source: Open Factory Large-Load Cost Table (compiled from LBNL/Brattle Aug 2026, Exelon and CenterPoint Q2 2026 calls as reported by Utility Dive, ERCOT Apr 2026 deck, Greenberg Traurig Mar 2026, Colorado Sun Apr 2026, AEP Ohio DCT page; as of August 2026)

Source: Open Factory Large-Load Cost Table

Dominion’s collateral is $75.0 million at 50 MW and $150.0 million at 100 MW; ComEd’s implied credit is $12.5 million and $25.0 million; a Texas project posts nothing at 50 MW and about $10.1 million at 100 MW under the proposed 25.194: $5 million of security of which 80% is forfeited on withdrawal, a $5 million non-refundable interconnection fee and a $100,000 study (ERCOT deck, slide 9). CenterPoint’s implied deposits are $3.2 million and $6.4 million on top of that, Xcel’s proposed $600,000 does not scale with MW, and AEP Ohio’s study fee is $50,000 and $100,000 while its collateral waits for your rate. Georgia Power at 100 MW enters the PSC rule and the collateral becomes customer-specific, so that bar cannot be drawn.

The minimum bill dollarizes for four tariffs, because four publish both a floor and a term.

Four tariffs let the table dollarize the minimum bill; a 50 MW contract commits 375 to 600 MW-yearsthe yellow ramp segment is worth about 85 MW-years in Virginia and 96 in Ohio; Colorado and Duke publish no ramp so their bars start at full contract
Four tariffs let the table dollarize the minimum bill; a 50 MW contract commits 375 to 600 MW-yearsData as of Aug 2026 Four tariffs let the table dollarize the minimum bill; a 50 MW contract commits 375 to 600 MW-years MW-years of demand billed whether or not consumed over the full term, 50 MW contract. Ramp years use the published ramp; SRP (80%) and Georgia (contract-specific) publish no term, so no bar. Ramp years Post-ramp years 0 200 400 600 Xcel Colorado (proposed, 80%, 15 yr, no ramp published) 600 MW-yr Dominion GS-5 (85% T&D, 14 yr, 4-yr ramp at 20% steps) 510 MW-yr AEP Ohio DCT (72.5% at 50 MW, 12 yr, 50/65/80/90% ramp) 386 MW-yr Duke HLF (proposed, 75%, 10 yr, no ramp published) 375 MW-yr 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

Xcel Colorado’s proposed 80% over 15 years commits 600 MW-years for a 50 MW contract, Dominion’s 85% over 14 years with its 20%-a-year ramp commits 510, AEP Ohio’s 72.5% formula over 12 years with its 50/65/80/90 ramp commits 386, and Duke’s proposed 75% over 10 years commits 375. SRP’s E-67 floor of 80% of forecast has no published term and Georgia’s is contract-specific, so neither gets a bar. At $10 per kW-month, which is an assumption the Interconnection Cost tool makes you replace, Dominion’s 510 MW-years is $61.2 million of demand charges due whether or not the plant runs.

Before any of that, the threshold. It is the first test the tool runs and the first column in the CSV.

At 50 MW you are inside five of the eleven published thresholds and outside sixevery dot to the left of the dashed line means the tariff applies to a 50 MW request; four markets publish no MW figure at all
At 50 MW you are inside five of the eleven published thresholds and outside sixData as of Aug 2026 At 50 MW you are inside five of the eleven published thresholds and outside six MW threshold at which each market's large-load regime starts. Four markets (APS, Entergy, ComEd, PG&E) publish no MW figure and are not drawn. (p) = proposed. 0 MW 20 MW 40 MW 60 MW 80 MW 100 MW 120 MW a 50 MW request Phoenix (SRP E-67) 20 MW N. Virginia (Dominion GS-5) 25 MW Columbus (AEP Ohio DCT) 25 MW Carolinas (Duke HLF, p) 50 MW Colorado (Xcel, p) 50 MW N. Indiana (I&M) 70 MW Dallas (Oncor) 75 MW Houston (CenterPoint) 75 MW W./S. Texas (AEP Texas) 75 MW Atlanta (Georgia Power) 100 MW Salt Lake City (RMP) 100 MW Open Factory Source: Open Factory Large-Load Cost Table

Source: Open Factory Large-Load Cost Table

SRP at 20 MW of forecast load, Dominion and AEP Ohio at 25, Duke’s proposal and Xcel’s at 50 sit at or below a 50 MW request; I&M at 70 MW per site, the three Texas TDSPs at 75, and Georgia Power and Rocky Mountain Power at 100 sit above it, per SRP’s general manager, the Utah SB 132 summary and the documents above. APS, Entergy, ComEd and PG&E publish no MW threshold; ComEd’s TSAs and PG&E’s Rule 30 are defined by transmission-level service, not by megawatts.

Energization Year Is an Estimate, and Says So

The last column is the one buyers ask about first and the only one no utility publishes as a number. The table carries it as an Open Factory estimate with the basis printed beside it.

A 50 MW request filed in Q3 2026 energizes in 2028 in three markets and 2033 in Northern Virginiadots are single-year estimates, bars are ranges; every market left of 2030 is either below its state's threshold at 50 MW or in a territory building generation for someone bigger
A 50 MW request filed in Q3 2026 energizes in 2028 in three markets and 2033 in Northern VirginiaData as of Aug 2026 A 50 MW request filed in Q3 2026 energizes in 2028 in three markets and 2033 in Northern Virginia Realistic energization year, Open Factory estimate per market. A dot is a single-year estimate, a bar a range. Basis printed in the CSV: JLL 2026 market averages, utility statements, a CPS Energy planning presentation. 2026 2028 2030 2032 2034 2030 Houston (CenterPoint) 2028 2029 Phoenix (SRP E-67) 2028 2029 Salt Lake City (RMP) 2028 2029 N. Indiana (I&M) 2028 2029 Dallas (Oncor) 2029 W./S. Texas (AEP Texas) 2029 Phoenix (APS XHLF, p) 2029 Louisiana (Entergy) 2029 Carolinas (Duke HLF, p) 2029 2030 Colorado (Xcel, p) 2029 2030 Atlanta (Georgia Power) 2031 Chicago (ComEd TSAs) 2031 Bay Area (PG&E Rule 30) 2031 2032 Columbus (AEP Ohio DCT) 2031 2033 N. Virginia (Dominion GS-5) 2033 Open Factory Source: Open Factory Large-Load Cost Table (compiled from JLL 2026 Global Data Center Outlook p.18, CenterPoint and Duke 2026 calls, AEP Ohio DCT page, CPS Energy PowerGen 2026 presentation via Avanza Energy; as of August 2026)

Source: Open Factory Large-Load Cost Table

Houston, Phoenix under SRP, Salt Lake City and northern Indiana are 2028 to 2029; Dallas, AEP Texas, Phoenix under APS and Louisiana 2029; the Carolinas and Colorado 2029 to 2030; Atlanta and Chicago 2031; the Bay Area 2031 to 2032; Columbus 2031 to 2033; Northern Virginia 2033. The bases are of three kinds. JLL’s 2026 outlook charts average grid-connection lead time for a new 50 MW data center by market, about 2.5 years in Dallas and Phoenix, 5 in Atlanta and Chicago, 7 in Northern Virginia (JLL, p. 18), and we read those values off a bar graphic, not from text, which the basis column discloses. A CPS Energy planning presentation at PowerGen 2026 puts Columbus at 84 months and Silicon Valley at 72, and reaches us second-hand through Avanza Energy. Utility statements fill the rest: CenterPoint’s 8 GW energized by 2029 with 3.5 GW under construction, Meta’s Entergy contract effective 2028 per UCS’s reading of the April 2026 filing. The year in that column is gated by transformers as much as by dockets: the Lead-Time Monitor carries 128 weeks for power transformers, and the Lead-Time-Adjusted Schedule tells you whether a utility promising 2028 has ordered the unit yet.

Twenty Months of Rule Changes, and the Refresh

Every cell has a date because most of them changed between January 2025 and August 2026. The Large-Load Policy Tracker keeps the list; the table records which entry changed which cell.

Twenty-one rule actions in twenty months, fourteen of them since March 2026the flat stretch from July to November 2025 is the only quiet period; after March 2026 a cell changed roughly every twelve days
Twenty-one rule actions in twenty months, fourteen of them since March 2026Data as of Aug 2026 Twenty-one rule actions in twenty months, fourteen of them since March 2026 Cumulative count of orders, statutes and filings that changed a cell in the 15-market table, January 2025 to August 2026. (p) = proposed. 0 5 10 15 20 25 actions Rule actions, cumulative21 Texas SB 6 AEP Ohio DCT Dominion GS-5 PUCT 25.194 (p) Batch Zero, FERC Texas pause Jan 2025 Apr Jul Oct Jan 2026 Apr Jul Open Factory Source: Open Factory Large-Load Policy Tracker (compiled from PSC, PUC, SCC, ERCOT, PJM, FERC and Governor documents listed in data/04-rule-timeline.csv; as of August 2026)

Source: Open Factory Large-Load Policy Tracker (compiled from PSC, PUC, SCC, ERCOT, PJM, FERC and Governor documents listed in data/04-rule-timeline.csv; as of August 2026)

Seven actions in 2025, from Georgia’s rule on January 23 to Dominion’s GS-5 on November 25, then fourteen in the five months from the PUCT’s forecasting rule on March 1, 2026 to its good-cause exception for ERCOT on August 20, with Batch Zero and FERC’s show-cause orders landing on the same day, June 18. The rows and their documents are in 04-rule-timeline.csv.

The refresh follows the dockets: every row is reviewed on the first business day of the month, and a cell changes the day its document lands, with the old value kept in the history and the docket entry dated. Already on the calendar: AEP Ohio’s second study tranche opens October 1, 2026; the PUCT’s 25.194 proposal reaches the six-month mark from publication on September 12, 2026, after which Texas law treats an unadopted rule as withdrawn (PUCT SB 6 roadmap memo); Dominion’s amended line-extension policy is due within 90 days of July 31; ERCOT’s audit report is targeted for December 10; PJM’s backstop auction results land December 2; Duke’s HLF would start in 2027. The headline table stays free. The history of every cell is Pro, and docket alerts, sent when a cell in a market you name changes, are institutional.

Known Biases

Six, and each is a reason to read the flag before the number. First, the table is large investor-owned utilities plus one public power district; no cooperative or municipal utility is in it, although co-ops serve much of the land where 50 MW plants get built. Second, sub-75 MW regimes are underrepresented by construction: the three Texas rows describe an SB 6 regime a 50 MW load is outside of, and the TDSP facilities-extension fees that govern it are the cells we could not find. The sub-5 MW line-extension tariffs we did read for Ohio, Georgia, California and Illinois live in the 2 MW service upgrade piece, not yet here. Third, docket portals fought the fetcher: PUCO’s DIS, the NCUC, Utah PSC, ACC, LPSC and ICC systems are JavaScript-only or returned errors, Oncor publishes its tariff as a PDF our text fetcher refuses, georgiapower.com and srpnet.com returned 403 or 404 during compilation, and Dominion’s rates page opens with no GS-5 sheet on it. That is why 20 cells rest on press reports, and version 0.2 fixes it first. Fourth, the two implied figures are portfolio averages: CenterPoint’s $64,000 per MW is $900 million over 14 GW, and a 50 MW load beside an existing 138 kV substation will post less and a greenfield one more. Fifth, the JLL and CPS Energy lead times were read from a graphic and a second-hand report. Sixth, the table is a snapshot with four proposals in it: Duke’s 75% floor and 25% exit penalty are what Duke asked for, not what the NCUC will order.

Using It With the Interconnection Cost Tool

The Large-Load Interconnection Cost tool is the table with your numbers in it. It takes a market, a requested MW and your demand charge in $/kW-month, and returns whether the regime applies at your size, the study fee and security scaled by MW where the source gives a per-MW figure (labelled implied where it does not), the minimum-bill exposure in MW-years and dollars with the published ramp applied, and the energization year with its basis. Cells the sources do not publish render as “not published” in the tool too; it estimates nothing the table does not.

Run 50 MW in Northern Virginia at $10 per kW-month and it returns GS-5 applies, $75 million of collateral, 510 MW-years and $61.2 million of minimum demand charges over 14 years, exit fee amount not published, 2033. Run the same 50 MW in Houston and it returns SB 6 does not apply, no rule-mandated security, deposits implied at about $3.2 million, no minimum bill, 2028 to 2029, and a note that the Governor’s audit reaches down to 25 MW. Run 100 MW in Dallas and the Texas stack appears: $100,000 study, $5 million security, $5 million fee, 100% CIAC. In a PJM market the tool hands you to the PJM Capacity Charge Estimator, because no tariff here waives the capacity charge and at $333.44 per MW-day a 50 MW load carries about $6.1 million a year of it (the PJM guide). Where the minimum bill exceeds a bridge’s cost, the Genset TCO tool and Recips vs Turbines vs Fuel Cells are next; where a CIAC hands you the transformer, the Transformer Sizing and Cost tool prices it.

What to Do Monday

Pull the CSV and sort on the verification column before anything else. A VERIFIED row can go into a board memo with the docket number beside it; a PARTIAL row goes in with “as reported by” and the outlet; a THIN row is a phone call, not a number. For every cell in your market that reads “not published,” ask the utility for it in writing before the letter of intent, in the table’s units: study fee in dollars, collateral formula in dollars for your load, minimum demand in kW for your contract capacity, exit fee in months. Then run the threshold test at your true size and one hall smaller: a 74 MW request in Texas is outside SB 6 and Batch Zero; a 49 MW request in Columbus saves $40,000 on the study fee and nothing else, because the DCT reaches down to 25 MW. If the document you receive contradicts a cell, send it to us. The table changes the day we can read it, the correction is dated, and the history keeps the old value.

What Version 1 Adds

Version 0.1 is the public record, read and dated. Version 1 adds four things. Developer interviews on actual study outcomes: what the study fee bought, how many months the study took against the tariff’s 45 or 60 days, what the facilities estimate came back at, and the energization date offered against the year in our column; interview counts print on the model page only when true, the rule the Lead-Time Monitor follows for its panel. Sub-100 MW regimes as their own rows: the standard industrial and line-extension tariffs a 5 to 75 MW plant lands in, starting with the sub-75 MW TDSP facilities-extension terms in Texas and the four CIAC formulas already read for the 2 MW piece. Alerts, so a cell change in a market you name reaches you the day the docket moves. And the docket documents behind the twenty press-reported cells, opened in a browser session, so that Duke, Xcel, ComEd and Rocky Mountain Power move from PARTIAL and THIN to VERIFIED or to an honest “not in the filing.” The Texas funnel piece and the 15-market walk-through are the first two articles built on the table; the CSV under them is this file, and it will say version 0.2 when any of the above lands.