Grid Alpha: Daily Power Market Briefing (ERCOT, PJM, CAISO)

Grid Alpha
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Grid Alpha turns real-time data from all nine North American power markets (ERCOT, PJM, CAISO, ISO-NE, NYISO, MISO, SPP, AESO, IESO) into short, trader-ready signal. Each daily episode is a two-host conversation: Ever asks the questions a trader would ask, and our lead analyst reads the tape: fuel mix, LMP/DART spreads, congestion, storage response, and LinkedIn commentary from analysts, developers, and policy watchers who actually move size. No background music, no fluff, just the setups that matter this week for U.S. power and gas traders. Live dashboards at gridalpha.us.

  1. 22h ago

    CAPITL $907.96 Spike Round-Trips to $34.03 by Friday Open

    CAPITL real-time LMP printed $907.96/MWh in the 21:35 UTC five-minute interval on Thursday, 17:35 EDT, against a 24-hour mean of $46.06/MWh. By the 10:55 UTC bar on Friday morning the Capital Zone was back at $34.03/MWh, below its own mean and not far above the overnight low of $19.68/MWh set at 08:05 UTC. A print that size sitting inside a 288-bar day and still leaving the mean at $46.06/MWh tells you how brief the excursion was. The data confirm the shape, not the cause. No outage, derate, reserve shortage, interface limit or scarcity pricing event is cited anywhere in the pack, and the only congestion detail on hand is Friday morning's snapshot listing GOUDEY–LAUREL L 115, LAKSUCSS–SHORE_RD 138 and FALCONER–MOONROAD 115 with no shadow prices reported. That list is stamped 10:45 UTC, the following morning, so it says nothing about what bound at 17:35 EDT; none of those three elements is an obvious Capital Zone boundary either. System load at 10:45 UTC stood at 15,105 MW with net load of 13,798 MW and dual fuel as the lead source, which reads as an unremarkable shoulder-season morning. N.Y.C. cleared $56.15/MWh at 11:00 UTC, so CAPITL opened Friday at a discount to the city rather than a premium, the opposite of what a persistent upstate constraint would leave behind. Day-ahead CAPITL for Thursday evening is also absent, so the DART on that interval cannot be sized; that gap matters, because a spike priced ahead is a forecast story and one that was not is an operations story. Whether 17:35 EDT was one interval or several, and whether MHK VL, HUD VL or N.Y.C. printed alongside it, is not in the material. A single scarcity bar and a sustained constraint look identical in a daily high and trade nothing alike. The angle's question is repeatability, and the only honest test is the clock. If CAPITL real-time prints above the $46.06/MWh 24-hour mean in the 21:35 UTC interval on Friday, the same slot that cleared $907.96/MWh on Thursday, the evening ramp has a structural component and the day-ahead evening strip is where the mispricing lives. If CAPITL holds at or below $34.03/MWh through that same 21:35 UTC bar, Thursday was a one-off and any premium bid into Friday's DA evening hours is the thing to question. Watch the CAPITL versus N.Y.C. ordering as the second check: Friday opened with the city at $56.15/MWh over CAPITL's $34.03/MWh, and if CAPITL moves above N.Y.C. at 21:35 UTC, something upstate is binding again whether or not a shadow price gets published with it. > A $907.96 print that returns to $34.03 by breakfast is a question, not a regime; Friday's 21:35 UTC bar answers it. Not investment advice. For informational purposes only. Yesterday's tape: CAISO CSADIAB7N001 negativelmp NP15GEN-APND lmppeak Grid Alpha — daily briefs · live dashboards, all nine markets · public call record

  2. 1d ago

    CAISO: $1578 Nodal Gap Splits Clear Lake From Diablo Overnight

    The widest real-time nodal spread in CAISO's 10:20 UTC interval hit $1578.40/MWh, printed at 03:20 PDT on a Thursday with nothing on the load side to justify it. CLERLKE6N012 cleared at $313.75/MWh while CSADIAB7N001 settled at -$1264.65/MWh. Both nodes saw the same $54.46/MWh system energy price; every dollar of the gap came from congestion and loss. The decomposition is the story. Clear Lake's N012 and N001 nodes carried a +$246.35 congestion component on top of $54.46 energy and a -$1.43 loss adder, and the premium stepped down cleanly through the neighbors: GRANITE6N001A at $290.03 with +$222.23 congestion, UPPRLKE6N001 and HARTLEY6N004 at $288.94 with +$221.08. That tight band of congestion values across five nodes in the same pocket reads like one binding element pricing an import-constrained load area, though the fact pack does not name it. On the other side, CSADIAB7N001 carried a -$1314.99 congestion component and a -$18.49 loss term, and CONTROLX1N008, N009, N010 and CSADIAB7N003 all printed -$1264.44 with the identical -$1314.99 congestion value. A single shadow price that deep, replicated across a cluster, is the signature of generation that the software wants off the system and cannot physically dispatch down fast enough. What the software is fighting is unconfirmed: the snapshot's listed constraints, EPENETITC, SHERIDANYELLOWTA230 and Base Case, all show no shadow price, and no plant or line outage appears in the source material. System conditions were unremarkable. Load stood at 20,219 MW at 10:55 UTC with net load of 18,745 MW and natural gas as the lead fuel, and THNP15GEN-APND priced at $64.96/MWh at 11:00 UTC, about 40 minutes after the spike. The hub never saw it. Curtailment data is no help either: the feed logs at least 1,668 events over the trailing seven days, but the sampled rows from 2026-10-22 show 0 MW for both solar and wind, which describes nothing about this interval. The angle flags curtailment risk around the Diablo node with no confirmed driver, and the open questions are the trade. First is persistence: a single five-minute print at -$1264.65 is a settlement footnote, while a repeat is a constraint with a name. If CSADIAB7N001 prints below -$1264.65 in any interval of Friday's 10:20 UTC window, treat it as structural rather than a dispatch artifact and expect the Clear Lake side to carry +$246.35 or more of congestion again. If the NP15 hub is still at or below $64.96/MWh at 11:00 UTC Friday while CSADIAB7N001 is still negative, the event is contained to the pocket and the DA/RT exposure sits entirely on nodal, not hub, positions. Second is the Clear Lake cluster: watch whether GRANITE6N001A, UPPRLKE6N001 and HARTLEY6N004 retain their +$221.08 to +$222.23 congestion components in the same interval, which would confirm a shared export limit rather than two unrelated events that happened to overlap. Day-ahead prices at both ends of the spread for the matching hour are still missing, and without them the DART size on either node cannot be stated. > A $1578 spread with $54.46 of energy in it is not a price signal; it is a constraint confessing, and until the binding element has a name, the risk sits at the node, not the hub. Not investment advice. For informational purposes only. Yesterday's tape: ERCOT CEDRVALERN lmppeak >= 358.39 — not triggered (observed 59.83); ERCOT HOVEYGEN negativelmp >= 0 — verified (observed 15.3). Grid Alpha — daily briefs · live dashboards, all nine markets · public call record

  3. 2d ago

    ERCOT's $410 Nodal Spread Runs Through a $25 Hub

    ERCOT's real-time nodal spread reached $410.12/MWh in the 10:50 UTC interval, 05:50 local on Wednesday morning. CEDRVALERN and CDRVLEU1RN topped the stack at $358.39/MWh while HOVEYGEN sat at -$51.73/MWh. The high side is a cluster rather than a single stranded resource. SANDLAKERN cleared at $352.24/MWh, and FAULKNERRN and COYOTSPRRN both printed $306.46/MWh. The low side is even tighter: five nodes, HOVEYGEN, HRBESSBESS, REROCKALL, SGSADGR and TOYAHRN, all settled at an identical -$51.73/MWh. Identical prints across five settlement points usually mean they share the same shift factor on one binding element, and a battery node sitting in the negative cluster at 05:50 local is worth noting for anyone tracking BESS charge economics. System conditions do not explain any of it. Load was 48,038 MW at 10:55 UTC against net load of 31,547 MW with natural gas the main source, implying roughly 16.5 GW of renewable output on the system. That is a loose pre-dawn grid, which is exactly when a local constraint, not scarcity, produces a $410 spread. What is missing is the driver. The live snapshot listed SLKSWAX2H, 6635G and BIGTREVDUPS11 as top constraints but returned no shadow prices, so none of them can be tied to CEDRVALE or HOVEY yet. The trailing seven days show at least 17,991 SCED shadow-price events and at least 1,765 unplanned resource outage events, both sampled counts that may be truncated. The sample includes a CCEC natural gas forced outage removing its full 138 MW, logged 2026-10-24, with a forced extension at 139 MW. Whether CCEC is still out, and whether it sits anywhere electrically near the congested nodes, is not in the data. No Tier 1 public outlet mentioned ERCOT congestion in the last 48 hours. Day-ahead prices for the affected nodes are also absent, so the DART basis cannot be sized from this feed. Treat the geography of both clusters as unknown; the node names alone do not locate the constraint. The angle calls this a persistence watch, and the triggers should be concrete. If CEDRVALERN still prints at or above $358.39/MWh at 13:00 CDT while HBNORTH stays within a few dollars of $25.24/MWh, the constraint has survived the morning load pickup and the solar ramp, and the spread is structural for the day rather than a pre-dawn artifact. If HOVEYGEN clears above zero at 09:00 CDT, the negative cluster was transient and the trade thesis narrows to the high-side nodes alone. The cleaner tell is the SCED shadow-price posting for the 10:50 UTC interval once ERCOT publishes it: a nonzero shadow price on any of SLKSWAX2H, 6635_G or BIGTREVDUPS11 names the element and tells you whether the resolution is a line returning to service or a dispatch solution that holds through the afternoon. > A $410 spread over a $25 hub is a transmission story, and until a shadow price names the line, the only defensible position is a dated watch on whether $358.39 at CEDRVALE_RN survives 13:00 CDT. Not investment advice. For informational purposes only. Yesterday's tape: CAISO THNP15GEN-APND lmp_peak Grid Alpha — daily briefs · live dashboards, all nine markets · public call record

  4. 3d ago

    CAISO's $1,612.92 Nodal Gap Is All Congestion, No Constraint Named

    CAISO's real-time nodal spread reached $1,612.92/MWh in the 10:20 UTC interval, which is 03:20 PDT on a Tuesday, deep in the overnight trough. BRUNSWCK1N101 printed $706.89/MWh at the top of the stack; DRUM57B1 printed -$906.03/MWh at the bottom. Forty minutes later the NP15 hub, THNP15GEN-APND, sat at $43.39/MWh, as if none of it had happened. Decompose the two extremes and the energy component is the same figure at every listed node: $35.95/MWh. BRUNSWCK1N101 carried $662.45 of congestion and -$2.50 of losses; DRUM57B1 carried -$949.32 of congestion and -$3.65 of losses. The spread is congestion plus losses and nothing else, with a system energy price that says the grid itself was slack: 19,646 MW of load, 16,099 MW of net load, natural gas the main source. The cluster shape is the more useful tell. BRUNSWCK1N008 and BRUNSWCK1N003 printed the identical $706.89 with the identical $662.45 congestion, and BOWMAN7N002, ROLLINSF7B1, HAYPRESS6N002 and HAYPRESS6N003 all sat within four cents of DRUM5 with the same -$949.32 congestion component. Five nodes sharing one congestion number to the penny is the signature of a single binding element with a large shift factor onto that pocket, not of dispatch noise. The next tier down falls off a cliff: RIOOSO1N033 at $157.43 with $111.35 congestion, PIKECTY6N001 at $154.94 with $107.58. Whatever is binding is local to the BRUNSWCK and DRUM5 groups and barely touches anything else. Which element it is remains unconfirmed. The congestion feed at 11:01 UTC listed EPESNMICITC, Base Case and TOTALWYOMINGEXPORT with no shadow prices attached, so there is no named constraint to pin this on. No outage appears in the material, no day-ahead comparison is available, and only the single 10:20 UTC interval is in hand. The anomaly feed counts at least 1,668 CAISO curtailment events over the prior seven days, but the five sampled records all show zero megawatts curtailed, so that count is a lower bound on log entries, not evidence of energy actually shed. The angle's curtailment-risk read is plausible given a -$949.32 congestion component; it is not yet demonstrated. The test is persistence, node by node. If DRUM57B1's congestion component still prints at or below -$949.32 in the 10:20 UTC interval on 28 October, the constraint is structural overnight rather than a one-interval artifact, and the negative-side units in that pocket are the ones carrying the exposure. If BRUNSWCK1N101's congestion component has retreated below $662.45 at that same 10:20 UTC interval while DRUM57B1 stays negative, the element is relieving on the high side first and the asymmetry is the trade to understand. Watch THNP15GEN-APND at 11:00 UTC on 28 October against $43.39/MWh: if the hub is unmoved while the nodes repeat, this is a nodal story and hub-level positions will neither capture nor cover it. > A $35.95 energy price under a $1,612.92 spread says the system had the power; it could not move it past one element nobody has named. Not investment advice. For informational purposes only. Grid Alpha — daily briefs · live dashboards, all nine markets · public call record

  5. 4d ago

    SPP North Hub: $360.96 Sunday Ramp Spike Unwinds to $39.43 Open

    SPP North Hub real-time LMP printed $360.96/MWh at 22:55Z on Sunday, 17:55 CDT, squarely inside the evening ramp. The trailing 23.8-hour mean across 286 five-minute bars sits at $42.65/MWh, so a single interval carried most of the window's price mass. By Monday's 10:50Z bar the hub series had settled at $39.43/MWh, and the live snapshot shows $37.18/MWh for the 11:00Z interval; the two prints are ten minutes apart and the sources do not reconcile them, so treat the open as high-thirties rather than a single quotable number. The round trip ran through an overnight floor of $7.83/MWh at 05:00Z, midnight local, before lifting back toward the mean. The shape is wind-driven. At 10:50Z SPP system load was 28,275.5 MW against net load of 14,790 MW with wind the main generation source, meaning roughly half of load was served by wind and the thermal stack was covering the remainder. The three constraints at the top of the 11:01Z snapshot, TMP48631685, TEMP9026027 and TMP410_33247, carry no reported shadow price, so there is no binding-constraint cost to attach to the Sunday spike and no congestion signal this morning either. The outage picture is stale: the anomaly feed logged at least 1,173 generation-capacity-on-outage events and at least 1,943 variable-energy-resource curtailment events over seven days, both sampled lower bounds, but the only detailed records date to 2026-10-19 and show coal on outage between 4,693 MW and 5,487.9 MW, 422.8 to 426.8 MW of diesel and fuel oil, and 684 to 710 MW of hydro. Nothing in the source material ties a constraint, a unit trip or a wind drop to the 22:55Z interval. That leaves one scarcity print with no documented driver, which is the class of event that either repeats on a similar net-load profile or disappears without explanation. The angle frames today as a repeat-or-fade decision on the 22:00Z to 00:00Z window, and the inputs are observable. If SPP net load at 22:00Z tonight prints below the 14,790 MW seen at 10:50Z, wind is still carrying the system into the ramp and the same thermal units asked to step up on Sunday are asked again. If any five-minute North Hub bar between 22:00Z and 00:00Z clears above $360.96/MWh, Sunday was the first of a pattern; if the highest bar in that window stays below the $42.65/MWh trailing mean, the spike has washed out and the ramp exposure was a one-off. Watch whether TMP48631685, TEMP9026027 or TMP410_33247 acquire a non-null shadow price by 22:00Z; if all three still read n/a, congestion is not the mechanism and the search for a cause moves to the outage and wind-forecast feeds, neither of which is in today's sources. No day-ahead North Hub price for the evening hours is available, so the DART spread on the ramp cannot be assessed from this fact set. Separately, SPP told RTO Insider on 2026-10-25 that it is 90% compliant with FERC's show-cause order on large load interconnection, pointing to a new participation model for flexible price-sensitive loads. > One five-minute print at $360.96 does not make a regime; until a constraint or an outage is pinned to 22:55Z, the Sunday spike is noise to be priced, not a trend to be chased. Not investment advice. For informational purposes only. Yesterday's tape: PJM WESTERN HUB lmppeak >= 47.1 — verified (observed 518.71); PJM WESTERN HUB lmppeak Grid Alpha — daily briefs · live dashboards, all nine markets · public call record

  6. 5d ago

    Western Hub Spiked to $384 on Saturday; Sunday Prints $30.70

    Western Hub real-time LMP touched $384.00/MWh at 08:25 ET on Saturday, against a trailing 23-hour mean of $47.10/MWh. By 06:50 ET Sunday the hub was at $30.70/MWh, and PJM-RTO sat at $29.92/MWh on the same five-minute bar. The round trip fit inside one session: the window's low of $22.33/MWh printed at 13:35 ET Saturday, roughly five hours after the peak. The shape is the story, because the feed offers no cause. The series runs 276 five-minute bars, about 23 hours rather than a full day, and a $47.10 mean sitting that far above both the $22.33 low and the $30.70 current print says the window traded cheap for most of its length and expensive for very little of it. Whether $384 was a single bar or a sustained multi-interval event is not stated. Sunday's snapshot at 07:00 ET shows system load of 79,720.68 MW, net load of 77,471 MW, and gas on the margin. Three constraints head the congestion list: Paradise-Branch Tap 161 kV, Person-Hendrick 230 kV, and the LOCKWOOD 138 kV line. All three carry shadow prices reported as n/a, so there is no binding-cost evidence to pin Saturday's spike on and none to argue it repeats today. The outage picture is thinner still. GridAlpha logged 147 daily-outage anomaly events over the trailing seven days, but the only rows shown date to 2026-10-19, with planned outages between 23,295 and 24,783 MW, forced between 3,005 and 5,681 MW, and maintenance between 4,087 and 5,799 MW, several of them conflicting for the same timestamp. The angle frames today as ramp-or-flat, and the clock on that test is earlier than midday: Saturday's peak was an 08:25 ET print, squarely in the morning ramp. If Western Hub real-time LMP is above $47.10/MWh, the trailing 23-hour mean, on the 08:25 ET bar Sunday, the morning ramp has repeated and the flat-tape read is wrong. If the 08:25 ET bar is at or below $30.70/MWh, the level the hub carried at 06:50 ET Sunday, the hub is pinned and Saturday reads as a one-off with no follow-through. Watch two things alongside the price. First, whether any of the three listed constraints posts a shadow price in the 09:00 ET snapshot, which would be the first congestion cost on record this weekend. Second, whether Western Hub separates from PJM-RTO on the 09:00 ET bar; at 06:50 ET the two were printing nearly on top of each other, which is what a hub with no local constraint looks like. > A $384.00 print that leaves a $47.10 mean and a $30.70 tape behind it within a day is volatility with no fingerprints, and the 08:25 ET bar is where you look for a second set. Not investment advice. For informational purposes only. Grid Alpha — daily briefs · live dashboards, all nine markets · public call record

  7. 6d ago

    Pine Portage Prints -$100 as Northwest Ontario Congestion Hits -$173

    PINEPORTAGE-LT.AG12 cleared at -$100.00/MWh in the 10:50Z real-time interval on Saturday, 06:50 local, the most negative node in IESO at the interval. Sister node PINEPORTAGE-LT.AG34 printed the identical -$100.00/MWh with identical components. Ten minutes later the ONZP reference stood at $68.5/MWh, roughly $168.5/MWh above the Pine Portage print. The decomposition is unambiguous about what moved. The energy component sat at +$83.41/MWh, the loss component at -$10.05/MWh, and the congestion component at -$173.36/MWh, so congestion alone outweighed the energy component by a wide margin and pushed the node through zero. Three neighbouring northwest nodes, Caribou Falls, Whitedog and Minaki, shared a shallower common congestion component of -$62.14/MWh and cleared between $17.68 and $18.92/MWh, with loss components of -$3.59, -$2.98 and -$2.35/MWh respectively. That two-tier signature, one congestion value at both Pine Portage nodes and a different common value across the cluster, has the shape of a nodal group sitting behind a limited element, with Pine Portage deepest behind it. What is not in hand is the element itself. The 11:01Z snapshot lists SMR1SCT, BASE CASE and A36NSCT_MIS as the top constraints with no shadow prices attached, and the seven-day real-time shadow-price feed sampled only zeros. Whether -$100.00/MWh is a floor or a coincidence is also unconfirmed, though two nodes clearing to the cent on the same figure is suggestive. System context offers no province-wide explanation: load was 14,382.5 MW, net load 13,450 MW, and nuclear was the lead supply source, which is unremarkable for an early Saturday morning. The basis exposure here lives in the Pine Portage congestion component, not the headline LMP. If the PINEPORTAGE-LT.AG12 congestion component is still at or below -$173.36/MWh at the 13:00Z interval, the condition has survived the morning ramp and nodal basis against ONZP remains the live risk for the rest of the session. If instead it has decayed to the -$62.14/MWh level that Caribou Falls, Whitedog and Minaki carried at 10:50Z by the 15:00Z interval, the deeper discount was specific to Pine Portage rather than a cluster-wide event, and the trade narrows to that one node pair. Watch the ONZP-to-PINEPORTAGE-LT.AG12 gap at 15:00Z as well: anything wider than the $168.5/MWh observed between the 10:50Z node print and the 11:00Z ONZP reading means the problem is deepening rather than clearing. The IESO planned transmission outage feed shows at least 101,464 records over the past seven days, but the sample was truncated to five rows, so no northwest outage is confirmed to anchor a view on duration, and the energy-versus-ONZP gap between $83.41 and $68.5/MWh is itself an open question about interval timing versus reference construction. > A -$173.36/MWh congestion component with no named constraint is basis risk you can measure but not yet explain, and that is precisely when the reference price stops behaving like a hedge. Not investment advice. For informational purposes only. Yesterday's tape: NYISO N.Y.C. lmp_peak >= 80.69 — verified (observed 182.98). Grid Alpha — daily briefs · live dashboards, all nine markets · public call record

  8. Oct 23

    Negative Nodes Everywhere, but Only the Hub Trade Paid

    Writing the briefing now, with the fact-pack numbers only and no placeholders. PJM-RTO printed $289.64/MWh at 10:50 UTC Friday while SPP North Hub cleared $22.48 and ERCOT North $28.09 in the same hour. The divergence is the week in one line: PJM carried 90,058 MW of load against 88,299 MW of net load, so gas was setting price on almost every megawatt, while SPP carried 28,934 MW of load against just 8,091 MW of net load with wind as the main source. One footprint was starved of renewables and one was drowning in them, and the spread trade between them was supposed to be the easy money. It was not, and CAISO shows why. The reported maximum nodal spread was $230.59/MWh, but it came from a handful of Owens Valley generator nodes: PODBISHOP1UNITS-APND printed -$148.50/MWh at 11:00 UTC with a congestion component of -$188.09 against an energy component of $29.09, and PODBISHOP1ALAMO-APND printed -$147.66 on congestion of -$187.90. The load side of that spread was tame. San Ysidro and Border nodes in the SDG&E area topped out at $61.75 and $61.62/MWh with congestion of only $6.36 to $6.54, and the NP15 hub sat at $46.80. So the headline spread was a local congestion artifact on the generator side, not a stressed-load signal, and nothing tradeable at hub granularity. The same disconnect held elsewhere: ERCOT's 46,324 MW of load against 31,777 MW of net load implies deep renewable penetration, yet the hub never went negative, and SPP logged zero solar curtailment in every sampled 5-minute interval on 2026-10-16. Shadow prices for the top constraints were unavailable in all six ISOs, so the constraint behind PJM's $289.64 print cannot be named from this tape either. The one call that worked was the simplest. NYISO N.Y.C. printed $80.69/MWh at 11:00 UTC with 15,561.8 MW of load and 15,229 MW of net load, gas on the margin and renewables contributing almost nothing. That is a hub-level thermal-stack trade with no nodal congestion to unwind, and with the Algonquin Weymouth outage complete and the AGT force majeure lifted, the gas-side supply risk that could have broken it is off the board. The dek's scorecard is the lesson: a regime that looks uniform on the tape did not pay uniformly, and the leg that paid was the one with the fewest moving parts. For Monday 2026-10-26, three checks at 11:00 UTC. If the congestion component at PODBISHOP1_UNITS-APND is still below -$100/MWh, the Owens Valley bottleneck is structural and worth mapping; if it has recovered above -$50, treat Friday's $230.59 spread as noise and fade any nodal negative print that lacks a named constraint behind it. If N.Y.C. real-time prints above $80.69/MWh with net load above 15,229 MW, hub-peak continuation holds and the gas stack remains the only thing that matters in the zone. If SPP North Hub holds above $22.48 while net load stays below 8,091 MW, the wind-heavy regime is failing to transmit into negative hub prices for a second session, which is the confirmation the fade needs. > Nodal negatives are a congestion story told one busbar at a time; the trade that verifies is the hub where gas still sets the price. Not investment advice. For informational purposes only. Yesterday's tape: ERCOT DUFRN negativelmp STPG1 negativelmp STPG2 negativelmp Grid Alpha — daily briefs · live dashboards, all nine markets · public call record

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Grid Alpha turns real-time data from all nine North American power markets (ERCOT, PJM, CAISO, ISO-NE, NYISO, MISO, SPP, AESO, IESO) into short, trader-ready signal. Each daily episode is a two-host conversation: Ever asks the questions a trader would ask, and our lead analyst reads the tape: fuel mix, LMP/DART spreads, congestion, storage response, and LinkedIn commentary from analysts, developers, and policy watchers who actually move size. No background music, no fluff, just the setups that matter this week for U.S. power and gas traders. Live dashboards at gridalpha.us.

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