In August 2025, the Midcontinent Independent System Operator (MISO) disclosed that a software coding error in its capacity auction calculation had gone undetected since the 2018[RJ1.1][GR1.2]/19 planning year. The fix triggered a $280 million settlement adjustment, dropped effective capacity prices [RJ2.1]in MISO South by 56%, and resulted in two complaints [RJ3.1][GR3.2]to the Federal Energy Regulatory Commission (FERC) from market participants who had built business plans around the original numbers.1 This is what ‘standardized’ looks like in practice.
At a quick glance, the US gas and power markets appear to be standardized. Natural gas is heavily regulated by FERC, with business processes and communication standards implemented and enforced by the North American Energy Standards Board (NAESB).
The power markets are managed by regional Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs), which operate under comparable market structures. Most have day-ahead and real-time markets with similar bid/offer processes and settlements.
NAESB also provides business process and communication standards for the power industry, although not to the same extent as in the natural gas industry. The power industry is further subject to North American Electric Reliability Corporation (NERC) reliability standards along with regional or market-specific tariff rules.
To the outsider, these frameworks suggest consistency and efficiency. However, at the working level, the gas and power markets remain among the most operationally complex industries in the country. While the US gas and power industries are standardized on paper, they are fragmented and complex in practice. Standardization is apparent in form but not in execution. [RJ4.1]
Each ISO/RTO or pipeline operates within the standardized framework, but with its own interpretations, variants and rules – creating thousands of micro-variations that business users and energy trading and risk management (ETRM) systems must constantly manage.
The MISO case above is not an anomaly. It is the visible tip of an operational reality that quietly moves millions of dollars every day across the US gas and power markets.
In this article, we’ll explore a few of the core business processes and their complications – before offering insights on how operational complexity can be turned into competitive advantage[RJ5.1][GR5.2][RJ5.3].
Trade capture and confirmations
Financial trades including futures and cleared forwards are standardized in the US gas and power markets. It is the physical gas and power trades that introduce the complexity. A physical power or gas trade might appear to be straightforward, with two parties agreeing on a location, volume and price. However, the operational details behind those trades quickly transform them into a more complex structure, with physical trades requiring delivery coordination that breaks the illusion of standardization.
Trade confirmations sound straightforward. Two counterparties agree on the economic and operational terms of a trade and exchange confirmations to verify that both sides match. In most financial markets, including standardized energy futures, this confirmation process is fully automated and instantaneous via the exchange or third-party clearing houses.
However, a large share of physical gas and power trades in the US markets are bilateral, requiring each trade to be confirmed between the two counterparties. There is no single standardized clearinghouse or protocol for trade confirmations across the gas or power industry. Many counterparties rely on email, PDFs or spreadsheets, and each counterparty pair may use a different combination of confirmation method and format.
A lack of standardization in naming conventions across these industries generates a surprising number of complications in the confirmation matching process. Data discrepancies with counterparty names, pipeline meter numbers, ISO nodes, and other minor terminology differences significantly complicate this confirmation matching process.
While this seems trivial and solvable on the surface, each company has its own representation of this data, likely across multiple systems, and standardizing naming/numbering conventions is an ongoing challenge across the gas and power markets. All these subtle nuances present barriers to automating these manual processes.
There are also timing differences. The physical delivery characteristics of a trade need to be confirmed with the counterparty, but given the gas nomination cycle deadlines and power ISO scheduling timelines, trades must be scheduled before all the physical delivery details are captured in the ETRM system. This leads to costly reconciliation loops internally and between the counterparties.
Pricing
Pricing appears to be standardized because many market participants rely on common price reporting agencies. [RJ6.1][GR6.2]In practice, it is one of the most persistent sources of operational complexity.
Different pricing providers use different methodologies. Rounding rules differ. Holiday calendars differ. Timing and cutoff definitions differ. The result is that two parties trading the same price curve can receive different prices from different vendors at different times. These differences, delays and corrections require time consuming and costly reconciliation.
The complications run deeper than vendor variation. Many physical gas trades are indexed to third-party price publications, such as the monthly bidweek indices in Inside FERC's Gas Market Report or the daily indices in Platts Gas Daily. That means the choice of index, the publication date, and the specific hub can produce materially different settlement outcomes on the same underlying delivery.
Power markets carry their own version of this problem. ISO-published locational marginal prices are subject to revision after initial publication, and downstream settlement systems must accommodate those revisions across the entire trade book.
Even slight variations in pricing have outsized implications considering the number of trades and the volumes tied to a single curve. These variations impact internal risk and exposure calculations, but they also have external counterparty implications for confirmations and settlement. The timeliness and quality of forward and settlement pricing is a major input to the overall efficiency of a trading company’s operations.
Scheduling
Each ISO/RTO operates a day-ahead and real-time market, offering between 8 and 15 specific traded products categorized as energy, capacity and ancillary services. They each offer different products, bidding windows, capacity and congestion rules and settlement intervals. In practice, these markets also differ in how they manage capacity, co-optimize energy and ancillary services, synchronize with the natural gas markets, and interact with environmental and carbon markets.
Managing transmission losses, capacity, congestion zones and intertie scheduling therefore requires specialized knowledge and configuration. This diversity across ISOs burdens the power schedulers and creates complications for the trading systems and interfaces to ISOs.
Consider a generation portfolio with assets in both the Electric Reliability Council of Texas (ERCOT) market and PJM Interconnection (PJM). In ERCOT, the scheduler is operating in an energy-only market, where revenue depends entirely on real-time delivery against locational prices, with no separate capacity payment to fall back on.
In PJM, the same scheduler is also managing capacity commitments made one to three years in advance, with non-performance penalties that can dwarf the energy revenue itself. The bidding windows differ. The settlement intervals differ. The dispute forums differ: ERCOT answers to the Texas PUC while PJM answers to FERC. Same trader, same screen, two completely different operating models underneath.
In natural gas, the trade must be scheduled with consideration for each pipeline’s transportation contract and capacity rules, along with differences in each pipeline’s electronic bulletin board. While deadlines and cycles are standardized on interstate pipelines, there are still many pipeline and contract specific rules the schedulers must navigate.
Interstate pipelines must comply with FERC’s [RJ7.1][GR7.2]minimum standards, but many have implemented additional complexities such that no two interstate pipelines operate in exactly the same way. When stepping outside of the FERC-regulated interstate pipelines into the hundreds of intrastate pipelines, the variations become more widespread and apparent.
Consider one such variation. A shipper may buy natural gas at one location from one counterparty, yet physically receive it at an entirely different location from a different counterparty. This is enabled through displacement, where gas is moved by backhaul or exchange rather than by physically transporting the same molecules from receipt to delivery. The point where title transfers and the point where gas physically flows are decoupled, and the party selling the gas is not the party delivering it.
Arrangements like this are perfectly workable, but they break the tidy one-trade, one-location, and one-counterparty assumption that scheduling and settlement systems are often built around.
The scale of this fragmentation is striking. According to the most recent annual report data from the Pipeline and Hazardous Materials Safety Administration (PHMSA), approximately 1,372 distinct pipeline operators submitted reports for natural gas transmission and gathering systems in the US, covering more than 413,000 miles of pipe.2
The US Energy Information Administration (EIA) further reported that approximately 65% of the natural gas pipeline capacity built in the US in 2025 was intrastate, meaning the fastest-growing segment of the network is explicitly outside the FERC standardization regime.3 Gas schedulers must gain specialized knowledge for each pipeline, making it difficult to schedule or switch between pipelines. Just like power scheduling, these deviations by pipeline create complications within trading systems and interfaces to the pipelines.
Settlements
Settlements should simply involve taking the confirmed trade data, multiplying the trade price by the volume and issuing an invoice for that calculated amount. While this is simple for many financial or exchanged-traded products, physical gas and power settlement is a multi-dimensional problem. There can be multiple prices, multiple volumes, timing differences, losses, fees, penalties and adjustments.
Physical gas and power are delivered continuously over the term of the deal and need to be invoiced accordingly. The pricing varies by interval, and the intervals might be partial hours, an hour, a day, a month or longer.
The final measured volumes from pipeline meters or ISOs may be reported with lags of days or weeks. These final allocated volumes may be revised over time, many months later. Multiple revisions to actual quantities are frequent in both the gas and power businesses.
Gas and power invoicing is therefore submitted with estimated or ‘best available’ volumes that are subject to multiple subsequent revisions. For natural gas, revisions for the past six months are common, and the NAESB base contract permits dispute claims for up to 24 months after delivery.4 For power, revisions commonly occur during the first 90 days, and some ISOs allow resettlement up to one year after the initial invoice was issued.
The financial consequences of these long revision windows, combined with settlement finality rules, can be severe. In 2024, faulty meter data from a third-party provider led to roughly $6 million in overcharges to BP Energy Retail from ISO-New England (up to $9.5 million including renewable energy impacts). ISO-NE opposed the refund because the dispute window had closed, and the matter is now before FERC.5 Finality rules, meter data flows, and counterparty handoffs can lock in disputed amounts worth millions long after a trade is booked.[RJ8.1]
The pricing for physical gas and power trades is not always the simple, standardized index publication prevalent with financial trades, and this also drives settlement complexity. Physical trades involve price formulas, shaped pricing profiles, tiered pricing scenarios and volume-weighted pricing calculations. Actual fuel and loss adjustments are embedded in the trade pricing or explicitly priced as a credit from the seller or a surcharge to the buyer.
Generation and production trades utilize tolerance bands intended to incentivize production to match market conditions. Similarly, consumption trades penalize under- and over-usage measured by varying timeframes.
Even when counterparties agree on all of these pricing parameters at the time of trade confirmation, each company’s systems are liable to interpret and calculate them differently, down to rounding. Small discrepancies are a very common source of settlement disputes in the gas and power business. [RJ9.1]
What this means for trading organizations
The instinct, when faced with this much operational complexity, is to treat it as back-office friction, a cost to be minimized and otherwise ignored. That instinct is the mistake. The organizations that pull ahead are the ones that recognize the operational layer as a capability worth investing in deliberately, rather than a tax to be quietly absorbed.
In practice, that recognition shows up in three ways. First, it means treating data and reference standardization, the unglamorous work of reconciling counterparty names, meter numbers, and ISO nodes across systems, as a competitive asset rather than a clerical chore. The firms that get this right confirm faster, settle cleaner, and spend less of their day in reconciliation loops.
Second, it means building systems and processes designed to absorb variation rather than resist it. The pipelines and ISOs are not going to converge on a single standard, so the advantage goes to organizations whose operating model expects difference by design and configures for it, instead of treating every new market or counterparty as a one-off integration.
Third, it means investing in the disciplines that catch value before it leaks – shadow settlement, exception management and proactive dispute monitoring – so that errors surface inside the revision window rather than after finality has closed the door.
None of this is visible on a trading screen or in a market design document. It is built quietly, over time, in the operational layer. But it is precisely where the difference between firms is made.
Conclusion
Energy executives often perceive their markets to be relatively standardized, but traders, risk analysts, schedulers and settlement teams frequently experience the opposite. These hidden complexities drive up operational cost as well as risk exposure, silently eroding trading margins.
They also create opportunities because the companies that master operational complexity can differentiate themselves from competitors. Effective operating models and[RJ10.1][GR10.2] systems solutions can provide a competitive advantage that allows trading companies to grow and expand.
The practical test for any trading organization is whether it could absorb a doubling of transaction volume, or an expansion into a new market, without a corresponding doubling of staff. Organizations that have mastered the operational layer can. Those that have not, cannot. That is where competitive advantage in the US natural gas and power markets is quietly built and lost.
How Capco can help
Capco focuses on the gap between market standardization on paper and operational reality. We work with energy traders, marketers, and producers across the US gas and power markets to close that gap. Our work spans trade capture and confirmation workflows, pricing data governance, multi-ISO and multi-pipeline scheduling operations, and shadow settlement and exception management. The common thread is helping clients turn operational complexity from a tax on their business into a source of competitive advantage that scales.
References
1 https://www.utilitydive.com/news/midwest-miso-ferc-pelican-complaint-capacity-auction/807985/; FERC Docket Nos. EL26-26-000 and EL26-35-000
2 https://www.phmsa.dot.gov/data-and-statistics/pipeline/annual-report-mileage-natural-gas-transmission-gathering-systems; https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-operators-opids
3 https://www.eia.gov/todayinenergy/detail.php?id=67225&utm
4 NAESB Base Contract for Sale and Purchase of Natural Gas, Version 2.1 (2006), Section 7 (Billing, Payment, and Audit)
5 https://www.utilitydive.com/news/iso-ne-bp-energy-eversource-ferc-nstar/807876/; FERC Docket No. EL26-5-000
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