SPP RTOE Early Market Impacts and Data Access
Yes Energy: Power Market Report
SPP Post-RTOE Analysis
SPP has expanded into the Western Interconnect and will have long-lasting impacts on market decisions. This blog will examine various aspects of SPP’s Integrated Marketplace as they relate to the market’s response to RTO Expansion (RTOE). The primary purpose is to clarify the market rules governing RTOE to help market participants better interpret the market signals from SPP going forward.
The addition of SPP West has created new price formation, from which we have been seeing high volatility and uncertainty in the first two months. To understand and even anticipate the price separation, we will unpack some market rules, data changes, and market results since RTOE went live on April 1st.
Review of SPP RTOE Changes
Background
Power markets throughout the West are evolving quickly, and for them to function properly, to achieve the benefits of market efficiency, market participants need to understand new complex economic pricing signals from RTO and day-ahead markets. Analyzing market data requires a strong understanding of topology, and the market relationships are critical to interpret and make decisions based on the data. Unlike in Eastern RTOs, understanding isolated RTO market data along with interchange schedules is sufficient to be successful, but participating in Western Interconnect will require an understanding of all markets.
To understand market relationships as it directly relates to the SPP RTO Expansion (RTOE) project, which went live on 4/1/2026, it is helpful to look back a couple of years. SPP taking on a massive undertaking to extend its integrated marketplace to the Western Interconnect might seem like it happened abruptly, but it took several years for SPP West BAA to evolve. Let’s go back a couple of years and see how the past culminating events helped shape SPP RTOE and future Markets+
Imbalance Reserves Timeline:
2016 - The Joint Dispatch Agreement (JDA) united entities like PSCo, Black Hills Colorado Electric, Platte River Power Authority (PRPA), and Colorado Springs Utilities to coordinate dispatch primarily through hourly bilateral sharing to create imbalance services.
2021 - SPP launched the Western Energy Imbalance Service (WEIS), a sophisticated 5-minute real-time imbalance market, covering WAPA BA boundaries (including Basin Electric and Tri-State Generation and Transmission)
2023 - JDA Entities Join WEIS, which introduced a key distinction in the WEIS market rules, where not all entities are active “participants” and others are more passive “non-participating” (e.g., PSCo, Black Hills of CO), meaning they were obligated to follow WEIS dispatch setpoints due to their assets being under BA & JDA that actively participated in WEIS. The main difference was that non-participants lacked voting rights and did not settle costs directly with SPP’s WEIS market structure.
The implementation of the RTOE project caused a divergent split across entities on the Western Seam, structurally replacing the close-knit JDA local pool with a formalized market-to-market interface. WEIS active participant wanted to come together to create a single BAA under SPP RTO, but many “non-participating” WEIS entities did not want to lose their sovereign BA boundary due to concerns around loop flow and lack of control in transmission and generation planning.
April 1, 2026 - RTOE went live and retired the existing WEIS framework and fully transitioned into the full SPP RTO Expansion (RTOE), creating SPP RTO West BAA (BAA Code = SWPW) from many WEIS entities. This event dissolved the unified JDA front in CO as entities voted to cede grid control to SPP RTO benefits.
- Opt-out entities (seen in yellow) in the interim period until Markets+ goes live are currently managing their energy imbalance through bilateral arrangements operating outside of a centrally optimized dispatch market
Oct 2027 - Markets+ Plans to launch and form new Day-ahead and RT imbalance services for entities who want to maintain sovereign control of their planning and infrastructure ownership
In the interim until Markets+ goes live in 2027, PSCo has committed to joining Markets+, will operate in bilateral agreements, and trade on the seam of SPP West RTO — as discussed later in External Market Response to SPP’s Import/Export Market Mechanism. Bilateral trades between PSCo and SPP RTO West now settle financially at the PSCo interface, which acts as an aggregate settlement point.
Current and Future Market Status:
| WEIS Entities as 3/31/2026 | Market Status as of 4/1/2026 |
|---|---|
| Basin Electric Power Cooperative | SPP RTO West |
| Colorado Springs Utilities | SPP RTO West |
| Deseret Generation & Transmission Cooperative | SPP RTO West |
| Municipal Energy Agency of Nebraska (MEAN) | SPP RTO West |
| Platte River Power Authority | SPP RTO West |
| Tri-State Generation and Transmission Association | SPP RTO West |
Western Area Power Administration
|
SPP RTO West |
| Public Service Co. of Colorado (PSCo / Xcel Energy) | Future Markets+ |
| Black Hills (Colorado) | Future Markets+ |
| Wyoming Municipal Power Agency (WMPA) | No DA Market (Western RC) |
SPP’s Integrated Marketplace - Two BAAs, One Engine
Now that we are familiar with the background and how SPP West BAA materialized through the RTOE project, let’s take a look at the post-implementation of SPP RTO Expansion on April 1, 2026, and early signals of the market dynamics across SPP West.
Though the SPP RTO Expansion project was successful, SPP West has been volatile compared to its RTO peer in the East. As seen below, the SPP East (light purple) has had smoother LMP than its new western neighbor, SPP West (dark purple). This should not be too alarming, as this new market change will take time to settle. Market participants will continue to evolve to efficiently meet the demand of the new consolidated BAA. Load and renewable forecasts will continue to improve, and building familiarity with net load profiles interacting across the BAA seam will be important to mitigate uncertainty.
This presentation will dig through different aspects of SPP’s Integrated Marketplace dynamics and see exactly how the greater market is responding to the addition of a SWPW BAA. The market is creating price separation when SWPW LMP becomes highly volatile due to uncertainty. To understand and anticipate the price separation, we will cover three main topics while unpacking market rules, data availability, and market results over the outage maintenance season, during which RTO Expansion launched.
Learning Objectives:
Dual Reference Hub Price Formation - understanding the evolving constraints at the BAA-level, and how the market solves for shadow prices on the Marginal Energy Component (MEC) and causing price separation within an RTO.
Internal Market Responds to SWPW Volatility - explore how the newly consolidated SWPW BAA is responding to SWPW Volatility and leverage power flow across internal DC Ties.
External Market Response to SPP’s Import/Export Market Mechanism - highlight how new SWPW market signals dictate power transfers being economic across the Western Interconnect.
Dual Reference Hub Price Formation
SPP’s RTO Expansion has introduced a dual-BAA system, making SPP the first RTO to operate two unique reference buses simultaneously managed by a single clearing engine. Under this new market structure, the West DC Ties creates an internal BAA seam separating the SPP East and West. Power now flows over the seam over dispatch interchange, making the interchange over the DC ties, and is no longer BA-to-BA scheduled. The dispatch economically links the DC Ties as withdrawal and injection pairs. The optimal use of these DC ties and the resulting Locational Marginal Prices (LMPs) are now determined through SPP’s Integrated Marketplace and a co-optimized solution for each BAA.
Each BAA reference bus will have a hub pricing node that will represent an imaginary 0 shift factor point. Allowing the hub LMP to provide accurate market signals for the marginal energy component for the entire system, or specifically for each of the AC island SPP footprints. This will, by design, create price separation across the BAAs in SPP. When price separation occurs, it is due to two conditions:
The MEC price will separate when the DC Ties hit their capacity, increasing the shadow price
The MEC will then reflect the BAAs ability to supply their own resources to serve the next increment of load
Tip
SPP DA and RT LMP separation will no longer derive from MCC, but the MEC will also drive price separation across the BAAs.
The MEC will now be the market signal when DC tie operating capacity will bind and inform the market that each BAA is providing its own marginal unit and not shared across the SPP RTO footprint. Therefore, the MEC reflects the DC Ties’ ability to quickly respond to market signals and ramp to capacity, as well as each BAA meeting demand and uncertainty requirements.
Now, when we look at the West DC Ties, the LMP is calculated and posted for each side of the tie. And subject to follow market price signals, power will economically flow from the lower-priced node (the “Source”) to the higher-priced node (the “Sink”). So far, the West DC Ties are showing strong compliance with pricing signals compared to their bi-directional dispatch.
However, it is important to note that physical constraints—like maximum capacity limits—can cause the LMPs between the two sides to quickly separate once those operating parameters bind.
| DC Tie Name | Capacity |
|---|---|
| Miles City | 200 E-W/150 W-E |
| Stegall | 110 bi-directional |
| Sidney (* 2026 Outage) | 200 bi-directional |
When the ties are unconstrained, the SCED allows resources to influence costs in both BAAs, leading to MEC parity across BAAs. Where resources can be pooled to meet the collective next marginal increment of load.
But when the DC ties hit their transfer limit with no additional capacity available, the MEC decouples, and the market experiences a stark price separation across the BAAs. The SCED must serve the next increment of load within each BAA separately, using only the marginal resources available in that BAA.
Before RTOE, the DC Ties were governed by a schedule interchange from bilateral agreements managed by e-tags. The power flows across the DC ties were only determined by the scheduling entity.
After RTOE, the DC ties are now governed by dispatch interchange. The DC ties are internally dispatched as withdrawal/injection pairs that are fully controllable and dispatchable. Optimized by SPP’s Integrated Marketplace: SCUC - determine the direction of the flow after the DA clears (E→W or W→E). RTBM runs the SCED every 5 minutes to determine the volume of flows (MW)
In other words, DC ties are not like traditional AC ties within a synchronized grid - DC ties are fully controllable, and there is no limit to overloading above capacity. So the shadow price does not reflect congestion that would have to incentivize the market to re-dispatch based on shift factors to mitigate/relax the congestion over a source-to-sink path. This source-to-sink path can be seen more as a dispatchable resource. But since these assets do not participate in the energy market like a resource, they are actually more like a Storage as a Transmission-Only Asset (SATOA) that is optimized based on market conditions.
Now that this seam is no longer scheduled from BA to BA across the interchange. There are considerable data impacts in how to review this data.
Warning
Market Data Impacts:
DC Tie Flow Interchange Schedule reporting: SGE, SCSE, MCWEST ties are still shown in SPP Interchange Reports but will show as zero NSI and NAI since RTOE is now dispatching these ties internally.
DA and RTBM Congestion reporting: DC congestion is not like traditional congestion within the AC synchronized grid where shift factors can determine market efficiency to help solve for the constraint. So the shadow price of the DC Ties will not be represented in Congestion reporting.
Reporting DC Tie Flow DA & RTBM reporting: New reports are being published to represent DA and RT MW power flow that is dispatched and the associated shadow price as the power flow approaches the capacity limit of the DC Tie.
DA and RT LMP reporting:
The MEC will now separate across BA when DC ties are approaching capacity and reflect each BAA’s ability to meet the next marginal MW unit.
If you see MCC > 0 related to the pnodes on either side of the DC Ties that represent congestion within the BAA not congestion over the DC Tie
Initial Observations from SPP RTOE Data
Internal Market Responds to SWPW Volatility
Let’s look at market data since RTOE launch, specifically how the newly consolidated SWPW is responding to not only the new “Dual-Reference Hub” MEC. As RTOs success is dependent on both long-term and short-term price signals, having only two months of data, we can’t do a deep dive into how the new SWPW BAA is responding to SPP Integrated Marketplace. But we can now interpret the market rules and how the market is reacting to volatility and uncertainty as this new BAA enters the RTO marketplace structure.
Hub LMP Separation
We have been seeing a large price divergence across the SPP East and West seams. This will be seen directly in the MEC, rather than what typically drives price separation, the MCC. Because the two BAAs have separate reference buses, the “congestion” (delivery limitation) across the DC Ties does not show up as typical constraints. Therefore, you will not see the DC Capacity bind in the DA and RTBM Constraint reporting or reflected in the MEC.
The large price divergence you are observing is the result of the two independent MECs decoupling when the DC tie hits its transfer limit. The shadow price of the DC tie (μ DC) is mathematically the difference between these two diverging MECs.
Tip
DC Tie Constraint is not Nodal:
The shadow price when the DC ties are at capacity is the difference between the MECs on either side of the tie. The MEC price separation equals how each BAA independently meets the next increment of load.
Unlike traditional constraints from congestion seen at RTOs, the market does not need to solve the constraint across the DC Ties nodally. Like any shadow price, if you relax the tie capacity by 1 MW, the total system dispatch cost would fall by exactly the shadow price ($/MWh). This constraint is fundamentally a BAA-level construct. Shift factors should not be applied to understand how the market relaxes or solves for the constraint, because this is not part of the congestion component of an LMP.
So how can we tell when the DC Ties have no available capacity and bind, the two interconnections decouple, and we will see MEC separate on either side of the tie? Meaning the next increment of load within each BA must be served exclusively by resources within its own BAA. The shadow price of the DC Tie (μ DC) is the difference between the two MECs.
DART Distribution by Hub
This plot compares the months of April/May pre- and post-RTOE market launch. SPP North and South Hub derive from a single MEC, meaning that hub LMP separation is due to congestion. We see that SPP North has been more volatile, but is unlikely due to RTOE going live, but due to uncertainty around load and wind resources. What we do observe is that the SWPW DART distribution is 2x wider compared to SPP East. Indicating SWPW DA market has increased uncertainty in the DA market. Creating volatility in the Reserve and RTBM markets.
Std Dev:
SWPW: 87.7 $/MWh
North: 36.7 $/MWh
Negative Price Freq:
SWPW: 31.3%
North: 18.8%
Mean DART Spread by Hour (Post RTOE)
In this plot, we drill into the temporal components that drive uncertainty by analyzing the variance (std dev), as in the plot above, but for each hour. Here we see that only two hours on average have been more volatile in the East: HE 13 and 18 due to the solar ramp.
The line graph represents the actual DART spread, where DA minus RT, so as the line goes negative, that means RT prices are much larger than anticipated. Conversely, a positive DART spread indicates RT prices are low, even negative. Throughout this report, let’s dig deeper into the data and understand why the market is showing that the cost to produce power over periods of low load will be so high, and what the different ramping periods are that have been causing uncertainty and driving price premiums.
Additional Volatility Metrics by Hub — Post RTOE
Note
SPP proactively issued a few advisories for the West BAA to manage interchange and generation uncertainty. Which leverage important market products like uncertainty ramp. SPP is still fine-tuning renewable forecast and refining uncertainty process to ensure risk profiles are properly modeled for the new BAA. But the market dynamics are showing a promising future picking up RTO market mechanics successfully.
DC Tie Flow Capability
SPP has confirmed that the two active DC Ties (Stegall & Miles City) have been correctly following pricing signals dispatched by the Dual Reference Hub. The dispatch interchange will economically flow power from the lower-priced reference node to the higher-priced node. (centralized SCED engine that will minimize total system production cost by dispatching the most economically efficient resources, including the DC Ties)
“Ties are doing what they’re told” (SPP)
DA Directional
Miles City: 89.2%
Stegall: 95%
RTBM Directional
Miles City: 58.4%
Stegall: 69%
Meaning the power is flowing in the economical direction of low LMP (source) to high LMP (sink) over the pnodes:
| DC Tie | Pnode (E → W) |
| Miles City | WAUE.UGPM - WAUW.UGPW |
| Stegall | WACM.TSPM - WAUE.BEPM |
| Sidney ⚠️ (outage) | NPPD LAPM - WACM LAP |
The DA market and RUC market process is working successfully by creating transparent price signals to determine the direction and flow across the DC Ties. SPP’s own data confirms 89-95% optimization in DA, but in real-time, that same price signal erodes and is only translating to economic dispatch 58-69% of the time, which is expected.
But let’s go deeper and investigate exactly how the DC ties are responding to the shadow price when the MEC separates. The energy spread duration curve is the product of the dual reference bus visual. The zero crossing point tells you what fraction of intervals SWPW is cheaper vs more expensive than SPP East, inferred by the μ_DC shadow price seen in the MEC.
Implied DC Tie Flow Duration Curve — Post RTOE (April/May 2026)
By looking at the MEC price signal and the capacity limit of each DC tie we can see in a perfect market the flow of power across DC ties.
Implied flow assumptions:
MEC price spread > ±$10/MWh
100% DC tie compliance (power flows low-to-high LMP)
Power flows across the DC Tie will reach the capacity limit with no ramp limitations
From the implied duration curve we can see that:
37% of 5-min intervals: W→E price signal (SWPW cheaper)
28% of 5-min intervals: E→W price signal (SPP cheaper)
35% of 5-min intervals: within ±$10/MWh parity
However, in reality, we are uncertain of the power flow across the DC ties by just looking at the MEC signal.
Interpreting the price separation of the MEC: ‘SWPW Hub’ and ‘SPP Hub’ price signals would indicate power flowing across the DC Ties. As seen below, we cannot see two things by just looking at the MEC signal alone:
The power flowing ramping from 0 MW to capacity as the shadow price increases
Any power flows that is not flowing signals of low to high cost
Therefore SPP recently started to publish internal power flows across the DC ties from both a DA and RT dispatch!
Dispatched DC Tie Flow Duration Curve (Actual vs MEC Signal)
Now we can see the power flowing across the DC Ties is indeed following market signals, but not perfectly. The Miles City has a long duration of zero power flows despite market signals to move power across the tie. The Stegall tie is much more responsive and follows the market signals closely by moving power source-to-sink low-to-high LMP.
| Market | DC Tie | Binding Intervals | Agrees | Opposes | % Aligned | Avg |Spread| ($/MWh) |
|---|---|---|---|---|---|---|
| DA | Miles City | 602 | 193 | 409 | 32.1% | 54.85 |
| DA | Stegall | 602 | 349 | 253 | 58% | 54.85 |
| RT | Miles City | 7,525 | 2,397 | 5,128 | 31.9% | 64.36 |
| RT | Stegall | 7,525 | 4,143 | 3,382 | 55.1% | 64.36 |
So the MEC volatility is, in part, how the DC ties are responding to price signals. They help move power, but with only ~ 310 MW capacity, this certainly moves the needle, but does not account for large price swings. In times of uncertainty, these ties can definitely smooth prices across the BAAs, but there is something else at play - let’s dig deeper!
Demand for Ramp Flexibility
The market reacts when SWPW has been experiencing large amounts of uncertainty compared to SPP East. Especially during times of off-load hours throughout the night - this is not due to high demand for power and the market dispatching expensive marginal resources on the merit order, but the demand for flexible ramping capability to meet uncertainty. The DA energy market will clear enough resources to meet load, but when there is high uncertainty, it relies on ancillary service products, like Uncertainty (UncUp), which puts upward pressure on LMP when there are lost opportunity costs.
Mean RT LMP by Hour — SWPW vs SPP North Hub
Three distinct patterns emerge by time of day. Morning (HE 1–7): Post-RTOE prices are consistently lower than pre-RTOE when the overnight period and SWPW’s hydro and wind resources act as a sink for SPP East surplus via the DC ties. Midday (HE 10–12): SWPW solar creates a load that absorbs SPP East wind, producing the largest absolute price reduction post-RTOE. Late evening (HE 22–24): Post-RTOE prices are slightly higher when SWPW is ramp-stressed, and the DC tie may be reversing direction rather than providing relief.
With the DC ties limited to W→E 310 MW capacity, SPP East’s vast resources can only provide so much flexible resources when SPP West experiences high uncertainty.. Simultaneously during these same periods is when ancillary services market clearing prices (MCP) are greater than zero, ensuring that SWPW’s limited flexible resources are reserved for the event of wind shortfalls and unexpected demand that needs to be met.
When the Uncertainty Reserve Up (UncUp) product binds in the Day-Ahead market with an MCP greater than $0, but drops to an MCP of $0 in the Real-Time Balancing Market (RTBM) for the same interval, it reflects a shift in the availability and cost of 1-hour upward flexibility between the two market timeframes.
SPP with a proportionally large wind fuel in their supply stack, they see evening ramp uncertainty that would require ramp-down products as uncertain when the evening high winds will kick up. There is also an increase in uncertainty coincident with system peak periods in the early afternoon. Which has spiked since RTOE go-live this year.
UncUp MCP by Reserve Zone and Hour
The UncUP product will clear greater than $0 to clear additional resources for a given period:
RZ21 (SWPW) DA UncUp averages $8.23/MW at HE 19-21
SPP East zones (RZ 1-5) will clear DA MCP > 0 but will rarely materialize in the RTBM (when there is zero opportunity cost MCP = $0)
The DC tie capacity prevents SWPW from importing ramp from the East, forcing the western BAA to self-source ramp from an uncertain renewable stack. So when the UncUp MCP clears > 0 in the DA market, we see those same price spikes in the RT energy market. There is a premium being paid in SWPW for flexible resources to counteract sudden wind shortfalls.
Wind Curtailment (and LMP)
Now that we see the market reaction to sudden shortfalls, sending ramp-up signals. Let’s see when the wind is high and requires ramping down and/or curtailment signals. With both SPP East and West containing meaningful wind resources, wind can be curtailed due to oversupply.
Wind Curtailment by Hour — Pre vs Post RTOE (Weather-Normalized)
A small impact on wind curtailment, but interesting patterns, where Pre/Post = DC tie (260 MW max) is too small to absorb SPP wind surplus and even adds to it over the low-load periods, but expanded territory decreases some wind curtailment during the higher peak periods throughout the day.
The plot has been weather normalized by accounting for wind speed differences; the remaining pattern should reflect market structure, not weather-driven.
Overnight & midday: RTOE has reduced, where SWPW acting as a sink for oversupply
Late evening (HE 22-24): When wind is at its highest there is a slight increase, where SWPW wind supply adds to the oversupply
External Market Response to SPP’s Import/Export Market Mechanism
Traders in the Western Interconnect are learning the new ways to calculate revenue/risk when scheduling DA power transfers across market seams and how to profit from wheeling power from or through to create economic opportunity and support reliability.
RTOE fundamentally changed power transfers across the West. Now there are two giant RTOs on either side of the Western Interconnect that govern power flows at a macro level across the western grid. RTOE dissolved many bilateral agreements, replaced by economic interchange scheduling that also relies on SPP’s dual reference bus model. LMP formation for the Interface Pnodes reflects SPP BAA not as a whole. The newly created Interface pnodes across the West reflect pricing signals in relation to the SPP West reference hub.
Since RTOE has gone live, a few things have changed. Not only for SWPW, where physical e-tagging is now eliminated for paths inside SWPW. But for the greater Western region RTOE is impacting transactions into SWPW that now settle at Interface Settlement Locations (or just Interface pnodes). Interface pnodes aggregate points weighted average of multiple POIs along the BA’s seam. Settlement Locations mapping is available to see how the POR/PODs schedule will clear against the Interface pnodes.
The Interface LMP is calculated by SWPW reference bus MEC + local MCC + MLC at the boundary. This is no different than how Interface pnodes clear in the Eastern Interconnection, but they will behave differently as they relate to either SWPW or SPP East hubs.
Interface PNode Pricing Signals
SPP RTOE created ~71 of Interface Pnodes to manage economic import and exports with SWPW, in relation to their reference hub.
Interface Pnode Network
This network reflects a graph (edges and nodes) ability to calculate revenue by which route/path is scheduled. The Western Interface LMPs do not vary much, but they will at times when there is a lot of traffic across the Western Interconnect, creating local congestion. Economic trades will mostly be determined by when to trade with SPP based on their MEC. As this report has explored MEC volatility, trades can benefit from the volatility and help solve for the uncertainty in SWPW when there are price premiums. Unfortunately, bilateral scheduling is still mostly determined by DA markets. Until SPP releases its dynamic schedule in real time, known as the Real-Time Dispatch Transaction, traders will need to anticipate DA market volatility.
This plot is displaying a market interval when there is price separation across the West. In these times, congestion and tariffs will also determine the cost of delivering power across BAs. Traders will need to arbitrage across Western markets to see which market will create the highest revenue margins and create the most reliability. The plot is showing SWPW prices, but other DA markets will publish their own price on the same BA to wheel through or from power.
The RTOE project was not in scope to cover market-to-market coordination, though it was pointed out it will be needed to effectively trade across new western SPP Interface pnodes. Market coordination will be heavily considered in Markets+ project scope and should expect changes with SPP as it goes live in 2027. As Markets+ and EDAM markets mature, scheduling power transfers across the Western Interconnect will be more market-driven. In current conditions, we have not seen a strong relationship between economic trades and SWPW.
Despite stakeholders’ concerns, SPP and FERC agreed that Markets+ tariffs will need to be mature before creating this market-to-market (M2M) coordination to create a tangible benefit across all the market seams in the West to jointly manage transmission congestion that affects neighboring
DA Market Clearing In Sync with DA Scheduled Interchange | RT LMP Volatility Creates Uneconomic Interchange
| label | interconnection | r | n | strength |
|---|---|---|---|---|
| SPP DA LMP → SPP DA NSI | Eastern Interconnection | -0.521 | 981 | Strong (r=-0.52) |
| SWPW DA LMP → SWPW DA NSI | WECC | 0.037 | 981 | Weak (r=0.04) |
| SPP RT LMP → SPP RT NAI | Eastern Interconnection | -0.279 | 965 | Moderate (r=-0.28) |
| SWPW RT LMP → SWPW RT NAI | WECC | 0.026 | 965 | Weak (r=0.03) |
The plot analyzes how the power flow across the DC Ties is influenced by import/export interchange for the specific BAA. DA Schedule Interchange with SPP East has a strong relationship where power moves across the DC Ties can be influenced by import/export obligations not due to native demand. Conversely, there is a weak relationship between internal power flows and import/export interchange obligations with SPP West. Indicating SWPW power transfers with West are not relied on from SPP East resources, and that many are still performing bilateral agreements despite DA economic signals.
The plot analyzes the relationship of power flows, import and export (MW), to the MEC price signal. A strong relationship will indicate economic trades where the source to sink is moving from low to high. The y-axis represents interchange flows (MW), and the x-axis shows Interface LMP.
Though the same LMP formation mechanic is identical for the East and West, we see weaker economic signals that drive interchange flows out of SWPW. The SPP East shows that as LMP increases, so do imports (shown as negative in interchange reporting), and as LMP decreases and even goes negative, then SPP exports increase. SWPW, we see no direct relationship.
SPP East has strong economic correlation in the East because these are mature markets and have sophisticated market-to-market coordination with the eastern neighbor, MISO. The Eastern Interconnect is much more dense, creating more trade opportunities and scheduling flexibility. In the west, there are few paths, and most are governed by transmission rights over the lines, which rely on long-term bilateral agreements and not day-to-day economic trading.
| Market | BAA | Interconnection | Mechanism | Correlation (r) | Strength | Market Design Status |
|---|---|---|---|---|---|---|
| DA | SPP | Eastern Interconnection | SCUC/SCED DA Schedules (NSI) | -0.521 | Strong (r=-0.52) | Working as designed |
| DA | SWPW | WECC | SCUC/SCED DA Schedules (NSI) | 0.037 | Weak (r=0.04) | Partial — bilateral agreements limiting signal |
| RT | SPP | Eastern Interconnection | RTBM Dispatch (NAI) — RTDT not yet active | -0.279 | Moderate (r=-0.28) | Gap — RTDT pending implementation |
| RT | SWPW | WECC | RTBM Dispatch (NAI) — RTDT not yet active | 0.026 | Weak (r=0.03) | Gap — RTDT pending implementation |
TipReal-Time Dispatchable Transactions (RTDT)
There are some changes ahead to improve RT market signals influencing power transfers . Currently, SPP dispatchable imports and exports were only scheduled in the DA Market and are mostly fixed in real-time. SPP is now creating “Dynamic Schedule”, known as Real-Time Dispatchable Transactions (RTDT), which will allow interface transactions to actively respond in the real-time balancing market as LMP fluctuations every five minutes.
SPP is targeting to implement real-time dispatchable transactions (RTDT) in 2026. The mechanism designed to close that gap is Real-Time Dispatchable Transactions — which allows the MCE to re-optimize DC tie dispatch intra-hour as RT prices diverge from DA. RTDT isn’t live yet, and this data shows exactly what that costs: roughly 1 in 3 RT intervals where the DC tie is likely flowing in the sub-optimal direction relative to the price signal.
FERC has accepted these proposed revisions and the placeholder date. To finalize the implementation, SPP is required to submit a compliance filing notifying the Commission of the actual, precise effective date no less than seven days before the RTDT design goes live in the market
Closely follow Yes Energy to track market changes and related impacts!
Transfer Power with Basis Risk
Since interchange with SPP is largely determined in the day-ahead market (until RTDT), scheduling flows to trade with SPP can be tricky. Creating a series of POR/PODs to determine what Settlement Interface node you want to trade with SPP will be critical.
Since there is currently little DA LMP separation across the Western Interface Pnodes, traders should understand the SPP’s market prices and dual-reference bus model we discussed earlier.
EDAM launched in May this year with PacifiCorp, and Markets+ is planned to launch in Q2 2027. There will be further changes. Power schedules will be fully price-driven. Markets+ will rely on price formation along the Western seams. If a constraint binds, energy will automatically be incentivized to flow from the lower-priced to the higher market price.
Until then and anticipation to be successfully in EDAM/Markets+ era, knowing the market seams will be critical. The day-ahead markets will further increase data sharing, congestion management, and transmission rights and use availability.
Until then, calculating revenue from SPP interchange can help determine profitable trades. Determining the routes for how you settle at the SWPW border can determine profit, based on SWPW internal congestion and other pricing signals that inform MEC price separation. Shown here are some of the larger BAs in the West of graph network analysis in how many (market seam) hops it takes to reach different SWPW borders.
Example Route (North vs South Route)
These examples show the use of graph plot (shown above) by first asking what the two routes are that will produce the most revenue (by paying a 10% tariff for each market seam “hop”). It produced two routes that have very different market characteristics.
Applying what we learned about MEC price formation and basis risk, we can see how Interface pnodes can be scheduled to create a route from a source (POR) to the SWPW sink (POD) or vice versa. The Interface pnodes send signals when DA markets should import or export with SWPW, and also which route to schedule to transfer power across the West.
Southern Route: favored during peak hours — WALC-side pricing better reflects SWPW Hub spreads when renewables drive the seam
Northern Route: consistently competitive overnight aligns with wind-heavy SWPW generation profile
When scheduling power transfers in the DA market, take into account the volatility. The first plot shows revenue from the RT market, but you schedule power based on DA signals. The DART spread across the two routes varies, resulting in the difference between what you expected to earn when you scheduled in DA vs what you actually settle in RT. As virtuals can also be traded on the Interface, the basis risk impacts both physical and financial trading.
Both routes are negative, meaning RT revenue was consistently more profitable than DA revenue
DA market consistently underestimates how profitable these routes would be in RT
Main Takeaways
Dual Reference Bus
The SPP RTO Expansion (RTOE) has fundamentally shifted market operations through a dual-Balancing Authority Area (BAA) system. Key takeaways from the first two months include:
Dual-Reference Bus Mechanism: The market now utilizes two unique reference buses under a single clearing engine. When DC ties are unconstrained, the Security Constrained Economic Dispatch (SCED) pools resources for MEC parity. When ties reach capacity limits, MECs decouple, reflecting each BAA’s independent ability to serve the next increment of load.
DC Tie Dynamics: DC ties are fully dispatchable, similar to SATOA resources, and do not require market redispatch (shift factors). They are not at risk of overloading, like typical ties in the AC grid. The DC Tie shadow price represents the delta between SWPW MEC and SPP MEC, proportional to the DC Tie capacity, and now drives energy price separation. This shifts the primary driver of separation away from the traditional Marginal Congestion Component (MCC)!
Market Volatility (First Two Months): SPP West continues to exhibit significantly higher volatility compared to SPP East:
LMP Std Dev: 87.7 $/MWh (SWPW) vs. 36.7 $/MWh (SPP)
Negative LMP Frequency: 31.3% (SWPW) vs. 18.8% (SPP)
Initial Market Response
Our post-RTOE analysis indicates that while the current market structure facilitates basic alignment, it will be important to track DC Ties capability to transfer power and SWPW’s ability to manage uncertainty and flexible resources to mitigate localized volatility:
Directional Price Signals: DC ties are effectively following economic signals, with the majority of RT intervals (37%) requiring power to flow West-to-East.
Localized Isolation: The ~310 MW tie capacity acts as a significant bottleneck, particularly during the overnight period (HE 19-21), where the SWPW UncUp peak ($8.23/MW) detaches from the SPP East ramp.
Impact on Curtailment: The limited tie ceiling has shown negligible impact on curtailment reduction, shifting only 0.6% (from 9.7% to 9.1%). Though the impacts are small, the trends indicate market design has successfully demonstrated system-wide economic integration.
Import/Export Behavior
SPP RTOE created 71 interface nodes across the West, representing one of the many market changes to come in the West. The West is still in the early stages of a fundamental shift toward DA Markets and interchange optimization. While the current framework provides the rules for integration, actual efficiency is still maturing:
SPP Interchange Divergence: Although SPP and SWPW operate under unified market rules, topology, reliability governance, and Market-to-Market (M2M) coordination differences result in vastly different regional behaviors.
The MEC Catalyst: Marginal Energy Component (MEC) separation at SWPW is the primary mechanism for driving economic interchange. However, trade volumes between SWPW and the SPP/EI footprint have yet to reach their theoretical market potential.
Evolutionary Market Changes: We anticipate significant changes over the next few years. As EDAM and Markets+ frameworks scale, the market will move toward more robust, efficient power transfers and expanded capacity.
Strategic Arbitrage: Success in this new landscape will increasingly rely on arbitrage across different markets. Western power transfers will eventually clear across a fragmented market topology, but participants should prepare for a market-driven environment where clearing engines dictate the highest revenue opportunities.
Analysis prepared by Rob Strange | Yes Energy | June 24, 2026