Vedeni Energy’s Deep Dive

Wholesale power markets entered the first week of July with summer reliability risk shifting from a planning concern to an operating condition, especially in the eastern United States. PJM faced the most acute stress, with hot-weather alerts, maximum-generation and load-management actions, low-voltage procedures, a Department of Energy emergency-order request, and materially elevated real-time price volatility during the heat event. NYISO also issued an Energy Watch on July 2 as operating reserves declined, while ISO New England continued to report day-ahead and real-time prices through normal market channels and maintained its summer preparedness posture. The week underscored that extreme heat, tight reserves, and transmission constraints remain primary drivers of marginal reliability risk in North American wholesale markets.

The power business has always rewarded patience. Big plants take years. Transmission takes even longer. Regulators move on their own clock. For decades, utility leadership could be judged by whether the plan made sense over ten or twenty years. That is still part of the job, but it is no longer enough. A clearer leadership test has emerged in the U.S. power sector: who can deliver real power to real load faster than everyone else. Regulators are acting on it. Grid operators warn that demand is arriving faster than the system can comfortably absorb. And the heat wave now bearing down on the eastern half of the country is showing what happens when growth, congestion, and thin margins converge.

Over the past week, one management theme kept surfacing in workplace coverage: recognition is increasingly treated not as a nice gesture but as a direct tool for employee engagement, retention, and day-to-day performance. SHRM’s upcoming webinar, The Recognition Edge: Activating the Most Underused Tool in Your Total Rewards Strategy, frames the issue clearly. Recognition is often treated as secondary to compensation and broader rewards, even though it shapes motivation, visibility, and momentum in daily work. That matters because many companies are still trying to solve engagement and retention with bigger, slower levers first. They focus on compensation, benefits, headcount plans, and systems. Those things matter. But they can also overlook a simpler fact: people decide whether work feels worth giving themselves to, one conversation at a time.

North American wholesale power markets entered the final week of June with a distinctly summer reliability profile: higher temperatures, elevated cooling load, tighter focus on resource adequacy, and renewed scrutiny of interconnection and transmission processes. Price behavior was uneven across regions, but the clearest volatility occurred in markets exposed to heat-driven peak demand and congestion. PJM saw real-time prices rise materially during the June 24-25 operating period, with public market dashboards showing system prices above $500/MWh during periods of stress. ISO New England, NYISO, IESO, and MISO also operated amid tightening summer conditions, though available official information generally indicated managed operations rather than an emergency market failure.

For years, business leaders have treated retention as an automatic good. Lower turnover has been seen as evidence of a healthy workplace, stable leadership, and strong employee loyalty. In many cases, that remains true. Losing high performers, institutional knowledge, customer relationships, and experienced managers is costly and disruptive. But 2026 has raised a sharper management question: What happens when the people who stay are not the people the organization most needs to retain?

As the U.S. power system decarbonizes, the reliability challenge is shifting from annual energy sufficiency to dependable performance during scarcity hours, steep ramps, renewable shortfalls, fuel constraints, and extreme weather. This white paper examines the future role of flexible generation in that environment and argues that dispatchable resources will remain necessary, but in a narrower, more strategic, and lower-emission role than in the past. It assesses the operational value and limitations of gas-fired flexibility, hydrogen-capable turbines, advanced peaking resources, and hybrid configurations, and considers how these resources should be coordinated with storage, demand-side flexibility, transmission, and other clean firm options.  Read the full whitepaper here

If you manage people in the power business, the old picture is gone. Software no longer sits quietly behind the scenes. Operators still run the control room, planners still build the cases, market teams still place the bids, and IT still keeps the servers alive. But those functions now depend on software that must work together under time pressure. Grid operations, transmission planning, outage scheduling, interconnection studies, market clearing, forecasting, and customer-facing commitments are increasingly tied to the quality of the code and data behind them.

Over the past week, one leadership issue kept surfacing across workplace research, management reporting, and current commentary: layoffs are no longer treated as rare emergencies. In more firms, they are becoming a standard management tool. That shift changes the job for every leader, but it lands hardest on middle managers. They are expected to explain decisions they did not make, steady teams they may no longer fully control, and keep work moving while employees wonder whether another cut is coming.

Wholesale power markets for the seven-day period ending June 12, 2026, were shaped more by early-summer readiness, interconnection reform, large-load integration, and mounting pressure on transmission buildout than by emergency conditions. ERCOT and PJM produced the week’s most consequential near-term developments: ERCOT continued to manage reliability risks associated with rapidly growing large-load interconnections, while PJM secured federal approval for an expedited interconnection track to bring qualified capacity resources online more quickly. CAISO’s activity focused on daily real-time market reporting, interconnection and deliverability process work, and the continued implementation of EDAM and the Western market.

For U.S. power companies, wildfire season is no longer a regional operating problem that a few Western utilities can manage on the margins. It is a leadership test that spans operations, fieldwork, customer care, regulatory affairs, public safety, and finance. Over the past week, Northern California entered its first red-flag warning of the season, PG&E began public safety power shutoffs in parts of nine counties, and reliability groups kept pointing to the same fact: wildfire is now a standing grid risk, not a side case.

The leadership topic gaining the most traction right now is not some shiny new theory. It is an old problem appearing in new forms. Organizations are changing course more often, moving faster, and asking people to absorb more uncertainty. Employees can live with change. What they struggle with is change that arrives without a clear explanation. That is where trust starts to crack. When leaders keep shifting direction and fail to explain what changed, why it changed, and what stays the same, people stop arguing with the plan and start doubting the people behind it.

Wholesale power markets for the seven-day period ending Friday, June 5, 2026, moved decisively out of late-spring shoulder conditions and into an early-summer risk posture. The clearest stress emerged in the East, where PJM issued a Hot Weather Alert for June 5–6 across its Mid-Atlantic and Southern regions ahead of 90-degree temperatures. ISO New England and NYISO, by contrast, remained in summer-readiness mode without a comparable public reliability signal. In the West and central regions, conditions were steadier: CAISO continued routine real-time and EDAM reporting; SPP and MISO maintained active planning and stakeholder calendars; and ERCOT posted largely routine operating notices despite a notable June 1 generation-loss event that did not escalate into a broader emergency.

Much of the utility leadership conversation lately has centered on a simple fact: plants once slated for retirement are still operating because Washington ordered them to remain available. That may sound like a legal story, but inside a utility, it is first and foremost a management story. The Department of Energy has continued to use Section 202(c) emergency authority to keep certain coal and gas units available beyond their planned retirement dates. In 2026 alone, DOE orders have covered plants in Pennsylvania, Michigan, Indiana, Washington, Colorado, Maryland, and Puerto Rico. On May 21, DOE issued one order keeping Eddystone Units 3 and 4 available through August 22 and another keeping Wagner Unit 4 available through August 19. Days earlier, DOE also authorized PJM to use backup generation at data centers and other major sites as a last resort before rolling blackouts.

Many companies still make the same bad trade. They take the person who produces the strongest individual work, give that person direct reports, and call it leadership development. Sometimes it works. Often, it does not. The company loses a strong producer, gains an unsteady manager, and then acts surprised when the team slows down.

The U.S. electric power system has entered a reliability era defined by compound stress. Extreme weather is no longer an occasional external disruption managed through emergency restoration after the fact. Heat waves, winter storms, hurricanes, wildfires, drought, high winds, and flooding now shape core assumptions about resource adequacy, transmission planning, distribution investment, fuel assurance, operating reserves, and emergency procedures. This shift is forcing utilities, ISOs/RTOs, state regulators, FERC, NERC, and reliability coordinators to reconsider long-standing planning practices developed around historical weather patterns, deterministic contingency analysis, and relatively stable load growth. The grid reliability challenge is no longer limited to whether enough nameplate capacity exists on paper.

Wholesale power markets for the seven-day period ending May 29, 2026, reflected typical shoulder-season conditions, with a clear regional split between modest prices in Western and central markets and firmer prices in parts of the East. CAISO and the broader Western Energy Markets footprint continued to publish daily real-time and EDAM materials, with prices shaped by steep net-load ramps, solar output, congestion, and EDAM's early operating phase. ERCOT, SPP, MISO, AESO, IESO, NYISO, and ISO-NE were generally orderly, while PJM stood out for stronger real-time pricing and continued market-design pressure tied to large-load growth, resource adequacy, and investment incentives.

There is a kind of utility work that nobody used to make speeches about: tree trimming, hazard-tree removal, and routine access to a right-of-way. It sits low on the glamour scale and high on the list of things that quietly keep the lights on. That is exactly why it deserves more attention now. In parts of the U.S. electric power industry, especially where lines cross federal land, routine maintenance has become a management problem with real consequences for reliability, wildfire risk, crew scheduling, customer costs, and executive credibility.

This week’s leadership conversation has not focused on perks, personality, or another round of buzzwords. It has focused on uncertainty. Leaders are grappling with shifting economic signals, tariff questions, uneven demand, geopolitical shocks, and pressure from boards to move faster with less room for error. The result is a management problem that shows up in everyday work: teams stall, meetings multiply, forecasts soften, and people start waiting for certainty that never comes.

Wholesale power markets across North America remained broadly orderly during the seven-day period ending May 22, 2026. The week’s clearest stress points were localized transmission constraints, operator notices, and ongoing market-implementation work—not broad emergency conditions. Real-time pricing reflected typical late-spring fundamentals: moderate load across most regions, recurring congestion-driven price separation, and episodic nodal volatility around outages and facility constraints. Public postings highlighted ERCOT manual action for an unsolved contingency in the Taylor County area; PJM post-contingency local load relief warnings on May 20; CAISO daily real-time market and EDAM reports; MISO pricing approvals and report-availability notices; ISO-NE daily market postings; IESO renewed-market engagement activity; and AESO REM readiness work.

When load growth accelerates, the industry’s reflex is familiar: build the next substation, the next line, the next major capital project. In many cases, that is the right response. But not always. One of the most important questions for utility leaders today is simpler and more consequential: are we using the grid we already have as effectively as possible?

Performance management should be one of the simplest parts of a manager’s job. Set expectations. Watch the work. Give useful feedback. Correct problems early. Help good people get better. Instead, many companies have turned it into a ceremony. Managers spend days collecting notes, filling out templates, assigning ratings, and preparing for a single formal conversation that tries to do too much at once. Employees walk in expecting judgment, politics, or surprise. Managers often arrive tired and late, hoping to get through the meeting without a fight.

Wholesale power markets across North America moved through the week ending May 15 in a generally stable shoulder-season pattern, with little evidence of broad regional reliability stress in the reviewed materials. Public daily market publications across the organized markets showed a routine operating cadence, while available real-time price reporting suggested that peak pricing was driven mainly by localized congestion, renewable ramps, and ordinary weather-related load variation rather than systemwide scarcity. In the West, CAISO and the WEIM footprint remained focused on market-integration execution and stakeholder processes, while SPP and Markets+ continued to advance western governance and large-load-related work rather than responding to acute operating events.

If you work in the U.S. electric power industry, you are used to hearing that everything takes longer than expected. Permits take longer. Interconnection studies take longer. New generation takes longer. Transmission siting takes longer. What has changed is that a single piece of equipment can now derail an otherwise sound plan on its own: the transformer. That is why transformer shortages have shifted from a purchasing headache to a leadership problem. When a utility, developer, or grid operator cannot get the transformer it needs, the schedule on the wall no longer means much.

If you manage a plant, field team, service operation, branch, hospital unit, warehouse, or support function that depends on experienced people, you already know the problem. The opening is approved. The budget is in place. The work is ready. The applicants are not. Or they arrive without the needed skills, leave after three months, or are poached as soon as they become useful.

North American wholesale electricity markets remained operationally stable during the week ending May 8, but institutional and infrastructure pressures continued to intensify across nearly every major organized market. Spring shoulder-season conditions generally moderated real-time pricing, with most markets avoiding sustained scarcity despite localized volatility tied to transmission congestion, renewable intermittency, and weather-driven load swings. In the western markets, CAISO and the WEIM footprint continued to emphasize operational readiness, transmission planning, and EDAM implementation. SPP and Markets+ likewise focused on governance and market development as Western integration efforts increasingly evolved into competition among alternative regional market structures.

If you spend your days running utility operations, planning outages, dealing with regulators, or trying to keep projects moving through a company already juggling too many priorities, this week offered a fresh reminder that market design is not some distant policy subject. It becomes a management subject the moment a new market goes live and begins to change how power is scheduled, how transmission is used, how risks are shared, and how accountability is spread across state lines. That is why the launch of the Extended Day-Ahead Market, or EDAM, stood out this week as the most important leadership and management topic in the U.S. electric power industry.

Succession planning is treated like a board exercise until someone leaves at the wrong time. Then leaders discover how much was riding on one person, how thin the internal bench truly was, and how little confidence anyone has in the handoff. By that point, the company is not building a pipeline. It is managing a problem. That is the wrong way to handle leadership continuity. A sound succession process is not only about replacing the chief executive. It is about ensuring the business can keep moving when a division head retires, a founder steps back, a plant leader is recruited away, or a top operator burns out and decides he has had enough. In plain terms, it is about whether the company has enough ready people to run the place without drama.

North American wholesale power markets spent the week in a broadly orderly spring operating posture, with few signs of acute reliability stress across the major organized markets reviewed. In the West, CAISO and the WEIM footprint continued to operate under relatively mild shoulder-season conditions, and the more important developments were institutional rather than operational: EDAM readiness work, market-simulation activity, queue publication, and transmission governance remained the focus. SPP’s newly expanded western footprint continued to settle into routine committee and stakeholder cadence, while Markets+ remained centered on governance, design, and implementation work rather than live market outcomes. In Alberta and Ontario, short-run market conditions were similarly calm, but both AESO and IESO used the week to advance tariff, planning, procurement, and transmission frameworks designed to accelerate demand growth.

For years, wildfire planning sat in a few boxes. Safety handled emergency response. Vegetation teams cleared rights-of-way. Regulatory staff handled filings. Finance dealt with recovery after the damage was done. That division no longer fits the facts. In the U.S. electric power industry, wildfire exposure now reaches capital planning, liability, insurance, credit, rate design, field operations, communications, and how boards judge management. It is no longer enough to treat wildfire as a seasonal hazard that can be managed with a few operating procedures and a public update when the weather turns bad.

Many change efforts do not fail in a dramatic way. They wear people out. A company launches a new reporting structure, then adjusts office expectations, then changes performance language, then installs a new tool, then resets priorities after a rough quarter. None of those moves is shocking on its own. Taken together, they can leave people feeling as though the ground never quite holds still. Work still gets done, but with more drag. Managers repeat themselves. Teams keep asking what matters now. Good employees begin to conserve energy instead of giving it freely. That is change fatigue.

North American wholesale electricity markets moved through a spring shoulder week, with public disclosures pointing more to implementation work, scheduled meetings, settlement readiness, and refinement of transmission or interconnection processes than to broad reliability stress. In the West, California ISO continued to advance policy prioritization, interconnection-rights retention, and EDAM and DAME settlement readiness, while SPP’s western-facing calendar showed immediate post-expansion follow-through in both core RTO governance and Markets+ user forums. ERCOT’s public notices similarly reflected a system operating without a major headline emergency, yet still managing the practical demands of maintenance windows, market-system availability, and routine qualification activity. Across much of the footprint, that combination is typical of an orderly shoulder-season interval: fewer weather-driven extremes, but no reduction in the volume of market-design and readiness work that will shape the second half of 2026.