IRS Notice 2025-42

Issued in response to Executive Order No. 14,315, the Notice removed the Five Percent Safe Harbor, which was a longstanding IRS-recognized method allowing taxpayers to “begin construction” of renewable energy (and other) projects for tax credit purposes by paying or incurring at least 5% of total project costs, for all wind projects and for solar projects exceeding 1.5 MW (AC).  Under the Notice, these projects could establish beginning of construction only through the Physical Work Test, which requires starting on-site or off-site physical work of a significant nature before the July 4, 2026, statutory deadline in order to avoid the December 31, 2027 placement in service deadline.  The Notice’s removal of the Five Percent Safe Harbor upended over a decade of consistent agency guidance on which the industry had relied since 2013 for tax credit purposes and before that in connection with the since-expired 1603 grant program.

 The Court’s Holding

The court held the Notice was arbitrary and capricious under the Administrative Procedure Act.  In particular, the court found that the IRS (1) failed to provide a reasoned explanation for eliminating the Five Percent Safe Harbor, (2) did not justify singling out wind and large-scale solar projects while leaving the Five Percent Safe Harbor intact for other technology-neutral clean energy projects, and (3) failed to consider serious reliance interests built up over more than a decade of consistent guidance or to evaluate less drastic alternatives proposed by industry commenters.

What This Means: Full Vacatur

The court vacated the Notice in full for all taxpayers.  On its face, this means the pre-Notice framework is restored for all affected taxpayers.  

Uncertainty Remains

Although the Five Percent Safe Harbor has been restored for now, several sources of uncertainty remain.  The court remanded the matter to the IRS, meaning the agency may issue new guidance, provided it engages in the reasoned decisionmaking the Administrative Procedure Act requires, which could in theory reinstate the prohibition on the Five Percent Safe Harbor.  An appeal is also possible, and there are multiple procedural and substantive grounds on which the court’s holding could be overturned on appeal.  Meanwhile, the July 4, 2026 beginning of construction deadline for wind and solar projects to avoid the December 31, 2027 placement in service deadline remains in effect regardless of the court’s decision.  

Key Takeaways for Clients

• Projects paused in reliance on Notice 2025-42 may now resume qualification efforts under the Five Percent Safe Harbor, but time is extremely limited given the approaching July 4 deadline and there remains significant uncertainty as to the ultimate outcome of the court’s opinion (i.e., whether the Five Percent Safe Harbor will be preserved through future IRS guidance and through a likely appeal of the opinion).
• For projects that cannot meet the Physical Work Test prior to the deadline and are expected to be placed in service after December 31, 2027, developers should evaluate whether utilizing the Five Percent Safe Harbor pathway is advantageous, but given the uncertainty of what lies ahead, should be aware of the risks attendant with meeting the Five Percent Safe Harbor now.
• As always, taxpayers should carefully document all expenditures and construction activities to substantiate their beginning of construction approach.

The Â鶹´«Ă˝ team will continue to monitor developments with respect to beginning construction under Sections 45Y and 48E of the Code.  Please reach out to one of the team members identified below with any questions.

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On May 19, the North American Electric Reliability Corporation released its 2026 Summer Reliability Assessment — the annual report card on whether the U.S. and Canadian power grid can handle summer heat. The headline is reassuring: every assessment area in North America is expected to have adequate resources to meet normal summer peak demand. The number of regions carrying elevated risk dropped from six last year to three. On paper, this summer looks better than the last several.

Read the full report, however, and a more complicated picture emerges. The risks that defined last summer — inadequate reserve margins, insufficient generation capacity — have not been eliminated. They have shifted. The threat has moved from “do we have enough power at all” to “do we have the right kind of power at the right moment.” For energy executives, general counsel, and businesses whose operations depend on reliable electricity, that distinction matters enormously.

What Has Actually Improved

The improvement is real and significant. The North American grid added more than 58 gigawatts of new generation capacity since summer 2025 — including 16.4 gigawatts of solar, 14.7 gigawatts of battery storage, 6.7 gigawatts of natural gas, and 1.6 gigawatts of wind. FERC staff, reporting on the same day NERC released its assessment, confirmed that U.S. generating capacity increased by approximately 75 gigawatts this summer compared to a year ago, with about 26 gigawatts of that growth in Texas alone. Power plant retirements, meanwhile, slowed to about 8 gigawatts — well below the pace of additions.

In Texas specifically, ERCOT’s overall resource picture has improved materially. The EIA’s October 2025 Short-Term Energy Outlook projected ERCOT demand would rise 14 percent in the first nine months of 2026 compared to the same period in 2025 — the fastest growth of any U.S. grid operator — and while subsequent EIA forecasts revised that figure downward as large load interconnections came online more slowly than expected, new solar, wind, and battery capacity has kept pace with actual demand growth. NERC now considers the ERCOT area-wide outlook adequate for normal summer conditions, a meaningful improvement from 2025 when parts of Texas were flagged as elevated risk.

There is also an emergency backstop in place. The Department of Energy has used its authority under Section 202(c) of the Federal Power Act to keep multiple coal and gas plants running that would otherwise have retired or been mothballed — a practice the DOE has deployed more than 40 times since May 2025, stalling the retirement of at least 4.4 gigawatts of coal capacity as of April 2026. Those plants were not even counted among NERC’s anticipated resources — they represent additional buffer capacity for the critical spring-to-summer transition period.

Where the Risks Have Shifted

NERC’s director of reliability assessments was careful to frame the improved numbers accurately: “The improved conditions we’re seeing shouldn’t be interpreted as saying that overall reliability risk is declining.” That caveat reflects three specific concerns that run through the 2026 assessment.

The first is the timing problem. Heat events are arriving earlier in the season than they were a decade ago, and NERC’s analysis now identifies spring grid stress as a growing concern in certain regions — a category that barely appeared in utility planning frameworks ten years ago. The assumption that June is preparation time and July and August are the risk months no longer holds uniformly. Early summer heat can coincide with planned maintenance outages — work scheduled during what operators expected to be a lower-demand period — reducing available capacity precisely when it is needed most. The EIA’s 2026 summer energy outlook projects cooling degree days will run above the 10-year average across most of the country, with the heaviest burden in regions where grid capacity is already tightest.

The second concern is resource mix. Most of what has been added to the grid — solar, wind, and batteries — cannot be counted on with certainty at peak demand. Solar drops to zero after sunset. Wind is variable. Battery storage systems, while improving rapidly, are typically designed for four-hour discharge cycles and are not yet a substitute for dispatchable thermal generation during a multi-day heat event. NERC has been explicit that the grid still needs more firm, dispatchable capacity — generation that can be called on whenever it is needed, regardless of weather conditions. That gap is not closing as quickly as the capacity addition headlines suggest.

The third concern is large load unpredictability. NERC’s 2026 assessment specifically identifies the “unpredictability of large loads” as a new and growing reliability challenge. Data centers, hyperscale computing facilities, and large industrial operations are connecting to the grid faster than forecasting models can accurately track. Multiple assessment areas revised their load forecasts downward from mid-2025 projections specifically because large load interconnections are coming online more slowly than requested — but aggregate peak demand still increased by more than 11 gigawatts over 2025 projections. The result is forecasting uncertainty in both directions, which makes resource planning more difficult for grid operators.

The Three Regions Still at Elevated Risk

NERC designates three subregions as elevated risk for summer 2026: New England, the Canadian province of Saskatchewan, and the Pacific Northwest. Elevated risk in NERC’s framework means that resources are expected to be adequate under typical summer conditions, but could fall short during a worse-than-forecast heat wave, an unexpected loss of generation, or unusually low renewable output.

New England’s risk stems from declining firm import commitments from neighboring systems, leaving the region more dependent on non-firm supplies during high-demand periods. The Pacific Northwest faces drought-driven hydropower reductions — hydro has historically been the region’s reliability anchor, and below-normal snowpack is reducing its availability exactly when summer heat peaks. Both situations illustrate a broader point: regional grid reliability is increasingly dependent on interconnections and imports that can become unreliable precisely when they are most needed, because neighboring regions face the same heat events simultaneously.

In Texas, the overall picture has improved but one localized risk remains. NERC flags the far west Texas zone — the area served by the western edge of the ERCOT footprint — as subject to load disruption risk when solar and wind output is low and transmission constraints limit imports from the rest of the grid. That is a specific, known vulnerability in a state otherwise showing improvement.

What This Means for Energy Executives and Businesses

For energy companies operating generation, transmission, or distribution assets, the 2026 assessment is a planning document as much as a report card. The shift from capacity shortfall risk to timing and resource mix risk means that the questions worth asking have changed. The concern is less often “do we have enough generation” and more often “is our generation available at the right moment, and are our commercial agreements structured to reflect that?” Power purchase agreements and capacity contracts written when solar and battery storage were less prevalent carry different performance and availability assumptions than the grid now demands.

For industrial and commercial businesses that are large electricity users — manufacturers, data centers, hospitals, petrochemical facilities — the NERC assessment is a signal to review demand response enrollment, backup generation readiness, and interruptible service agreements before the first major heat event of the season. NERC’s own data show that the consequences of grid stress events have become more expensive as the economy has grown more electricity-dependent. The businesses that manage through summer grid stress best are those that have tested their contingency protocols before they need them.

For general counsel and legal teams, the assessment raises a more specific set of questions. Force majeure provisions in energy contracts apply equally to domestic grid reliability events as they do to international supply disruptions. A grid emergency that causes an operator to curtail, interrupt, or modify performance under a power supply agreement may or may not constitute a force majeure event depending on what the contract says and how the event is characterized. Texas SB 6’s remote disconnect provisions for large loads add another layer: a data center or large industrial customer that is curtailed by ERCOT during a firm load shed event needs to understand how that curtailment interacts with its commercial obligations to its own customers and counterparties.

The Broader Picture

The 2026 Summer Reliability Assessment reflects a grid in genuine transition. Record capacity additions, faster interconnection timelines, and improving storage technology are all real progress. But the grid is also absorbing demand growth faster than most forecasters anticipated, integrating a resource mix that performs differently than the thermal-dominated grid of twenty years ago, and facing weather patterns that are extending and intensifying the reliability stress season.

NERC’s director put the tension plainly: the grid needs more firm and dispatchable resources to maintain reliability and meet rising demand. The additions being made today — predominantly solar and storage — are necessary but not sufficient. That gap between what is being built and what the grid ultimately needs is the central energy infrastructure challenge of the next decade, and its resolution will shape electricity costs, project economics, and operational risk for every business that depends on the grid.

Two statistics from NERC’s broader work put the stakes in sharper focus. NERC’s January 2026 Long-Term Reliability Assessment projects U.S. summer peak load will increase by approximately 224 gigawatts between 2025 and 2035 — nearly 70 percent higher than the prior year’s forecast and the fastest acceleration in demand since NERC began tracking reliability data in 1995. At the same time, NERC’s 2026 Summer Reliability Assessment found that updated modeling of data center behavior during peak periods allowed ERCOT to reduce its summer demand forecast by 1.9 gigawatts, because data centers — when properly incentivized and equipped — can flex their loads rather than draw at maximum capacity during grid stress events. That flexibility is real, growing, and increasingly factored into how grid operators plan for summer. It is also a preview of how the relationship between large industrial power users and the grid is likely to evolve: less passive consumer, more active participant in reliability.

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Not long ago, data centers were invisible. They sat in the background of the economy — the unseen plumbing behind email, online banking, and corporate IT systems. Most executives gave them about as much thought as they gave the utility room down the hall. That era is over. Data centers have become one of the most capital-intensive, politically contested, and strategically significant industries in the country, and Texas sits near the center of it.

Understanding what is happening in the data center space — where it came from, where it stands today, and where it is headed — is no longer optional for businesses of any size. The infrastructure decisions being made right now will shape electricity prices, water availability, real estate markets, and the regulatory environment for years.

Three Eras of Data Centers

The University of Texas Bureau of Economic Geology has described the evolution of modern data centers in three phases that track closely with how technology has reshaped the economy. The first era, from roughly the 1990s through 2010, was defined by corporate IT infrastructure — internal server rooms handling email, accounting, and enterprise software. Facilities were modest by today’s standards, typically drawing kilowatts or low megawatts of power. Texas was already developing a strong presence in this period, with Dallas emerging as a natural hub due to its central geography, robust fiber infrastructure, and favorable business climate.

The second era, from 2010 to 2023, brought hyperscale computing. Amazon Web Services, Microsoft Azure, and Google Cloud transformed data centers into enormous facilities — some drawing 10 to 100 megawatts — supporting streaming, mobile computing, and software-as-a-service platforms used by billions of people. Texas became a top-tier market in this period, attracting major cloud campuses to the Dallas–Fort Worth corridor, Austin, and San Antonio.

The third era — the one we are in now — is driven by artificial intelligence. Training and running large AI models requires orders of magnitude more computing power than anything that came before. Individual facilities are now being designed to draw a gigawatt or more of electricity. To put that in perspective: one gigawatt can power roughly one million average American homes. The CEO of Aligned Data Centers, a major Dallas-based developer, has compared this moment to the early Industrial Revolution — a structural shift in the physical economy, not just a technology upgrade.

Where Texas Stands Today

The numbers are striking. As of April 2026, Texas has 84 operating data centers with a combined capacity of approximately 3,800 megawatts — and 140 additional projects in the planning pipeline that would add another 75,000 megawatts of capacity if built. According to Bloomberg Energy’s 2026 Data Center Power report, Texas is projected to exceed 40 gigawatts of capacity by 2028, representing approximately 30 percent of total U.S. demand. ERCOT’s CEO reported to Texas legislators in April that more than 2,000 projects totaling 453,000 megawatts are currently seeking to connect to the state grid, of which roughly 357,000 megawatts are potential data centers.

The drivers of Texas’s position are well-established: no state income tax, a deregulated electricity market, abundant land, strong fiber infrastructure, and a historically business-friendly regulatory environment. Vacancy rates in existing North American data centers held at a record-low 1 percent for the second consecutive year in 2025, per JLL’s year-end report, with the Texas market operating at virtually zero. Data center rents in the Americas increased 9 percent in 2025, with JLL forecasting annual rent growth of 7 percent in the Americas through 2030.

Texas is also on the verge of surpassing Northern Virginia — historically the world’s largest data center market — in new construction. JLL’s year-end 2025 report found Texas alone accounts for 6.5 gigawatts of capacity under construction, and projects Texas could overtake Virginia as the world’s largest data center market by 2030. Northern Virginia’s Loudoun County has been the global epicenter of internet infrastructure for two decades. Texas displacing it reflects both the scale of investment flowing into the state and the constraints that have emerged in established markets.

The Issues the Growth Is Creating

The scale of the buildout is generating real friction across three areas: power, water, and regulation.

On power, Goldman Sachs Research projects U.S. data center electricity demand will climb from 31 gigawatts in 2025 to 66 gigawatts by 2027. ERCOT’s own long-term forecast projects Texas grid demand could rise above 200 gigawatts before the end of the decade — nearly double the peak demand of two years ago. The Texas Legislature responded in 2025 by passing Senate Bill 6, a wide-ranging law that gives ERCOT new authority over large energy users, including the ability to curtail or remotely disconnect data centers during grid emergencies. SB 6 also requires data centers connecting after December 31, 2025 to build in remote-disconnect capabilities and mandates disclosure of on-site backup generation to ERCOT and utility partners. The Public Utility Commission of Texas is still working through the implementation rulemaking, with major portions expected throughout 2026.

Water is the less-publicized but equally serious constraint. Large data centers use significant volumes of water for cooling — evaporative cooling systems at hyperscale facilities can consume millions of gallons per day. Several Texas groundwater conservation districts have begun scrutinizing high-volume permits, and the Blanco-Pedernales Groundwater Conservation District passed a resolution in April 2026 calling for legislative action to better protect groundwater resources from large industrial users. Nationally, data center water consumption has become a flashpoint in communities that feel the local impact directly.

On regulation, states are moving fast. Moratorium bills targeting data center construction have been introduced in 11 states in 2026. Loudoun County, Virginia — the heart of the world’s largest data center market — eliminated by-right zoning for data centers in March 2025, requiring special exception approval for all new projects. South Carolina and Maryland enacted rate negotiation laws in 2025 to address how large data center loads affect electricity costs for other ratepayers. The regulatory landscape for siting, permitting, and operating a data center is materially more complex than it was three years ago.

The Global Picture — and Why It Matters to Every Business

Globally, the data center sector is in the midst of what JLL’s 2026 Global Data Center Outlook calls an “investment supercycle.” JLL estimates total data center expenditures — real estate, debt financing, and tenant infrastructure upgrades — could approach $3 trillion by 2030. The U.S. accounts for the majority of that spending, but other markets are growing rapidly. Singapore, the United Kingdom, Germany, and Japan are all major data center hubs, and investment is accelerating across Southeast Asia, the Middle East, and Latin America. The common thread everywhere is the same: AI demand is outpacing grid capacity, and the infrastructure race to close that gap is one of the most capital-intensive industrial buildouts in modern history.

For businesses that don’t build or operate data centers, this still matters in concrete ways. Electricity rates are affected when large industrial loads join a grid without proportional investment in new generation — a dynamic that Texas regulators are actively working to address through SB 6’s cost allocation provisions. Real estate markets in affected corridors are being reshaped by data center land acquisition. Water availability in fast-growing Texas counties is becoming a planning constraint that affects all users, not just data center operators. And the regulatory changes being made in response to data center growth — in zoning, permitting, utilities, and environmental policy — are creating new compliance obligations and strategic considerations across industries.

The data center boom is not a technology story that stays neatly inside the tech sector. It is an energy story, an infrastructure story, a land use story, and a public policy story — and its consequences are reaching every corner of the Texas economy and well beyond.

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On May 21, 2026, the Federal Energy Regulatory Commission voted unanimously — 5 to 0 — to propose the most sweeping overhaul of its natural gas blanket certificate program since the program was last substantially revised in 2006. The Notice of Proposed Rulemaking, issued as Docket No. RM25-12-001, would roughly double the cost thresholds that allow pipeline companies to build and modify infrastructure without seeking case-by-case FERC approval. It would also expand the categories of projects eligible for streamlined authorization and extend the blanket certificate framework toward LNG facilities for the first time.

For energy executives and general counsel across the oil and gas, midstream, LNG, and power sectors, this NOPR matters — not just as regulatory background, but as a direct driver of project timelines, capital deployment decisions, contract structures, and competitive positioning. Understanding what changed, what is still proposed, and what happens next is essential to acting on it.

What the Blanket Certificate Program Is — and Why It Matters

Under Section 7 of the Natural Gas Act, interstate natural gas pipelines generally need FERC authorization before they can construct, operate, or modify facilities. That process — a full certificate application, environmental review, public comment, and Commission order — can take years and cost millions in regulatory expenses, even for routine infrastructure upgrades.

The blanket certificate program, created in 1982, carves out an important exception. It allows pipeline companies to undertake a defined category of smaller projects — routine modifications, replacements, and certain new construction — without going through the full case-specific authorization process, as long as the project falls below specified cost thresholds. The thresholds have two tiers: automatic authorization, for the smallest projects, which requires no advance FERC review at all, and prior notice authorization, for somewhat larger projects, which requires notifying FERC and waiting a set period before proceeding unless the Commission intervenes.

The problem is that construction costs have risen sharply since the thresholds were last set. The automatic authorization limit of $14.5 million and the prior notice limit of $41.1 million reflect 2006 cost levels, adjusted only by a GDP deflator that has significantly undertracked actual construction cost inflation. Projects that should be routine — compressor station upgrades, meter replacements, short pipe segments — have been pushed outside the blanket certificate thresholds simply because their dollar value has grown with inflation, forcing companies into a full certificate process for work that is neither novel nor controversial.

What the NOPR Proposes

The May 21 NOPR proposes four principal changes. First, it would raise the automatic authorization cost limit from $14.5 million to $30 million — more than doubling it. Second, it would raise the prior notice cost limit from $41.1 million to $86 million. Third, it would expand the categories of projects eligible for blanket certificate treatment, specifically adding certain compressor station modifications and meter and regulating station work that currently require case-specific authorization regardless of cost. Fourth, it proposes extending blanket authorization procedures to certain activities at LNG facilities, a category that has historically been subject to full certificate review.

FERC Chairman Mark Christie framed the action explicitly around reliability: “New and expanded natural gas infrastructure is essential to help America avoid a grid reliability crisis.” The unanimous vote — a 5-0 result in a commission that has at times been divided on natural gas policy — signals broad institutional consensus that the current framework has become an obstacle to the infrastructure buildout the country needs.

The NOPR builds on a series of FERC actions over the past year that reflect the same direction. In June 2025, FERC issued a two-year temporary waiver raising the blanket certificate cost limits while the rulemaking was underway. In the same month, it waived its Order No. 871 policy — which had prohibited pipeline developers from beginning construction while rehearing requests were pending — through June 30, 2026, while pursuing permanent repeal. Yesterday’s NOPR is the next, more permanent step in that sequence.

What It Means for Your Business

Midstream and pipeline companies.

The most direct beneficiaries are interstate natural gas pipeline operators. Projects that currently require a full Section 7 certificate application — with the associated timeline, expense, and regulatory risk — may qualify for automatic or prior notice authorization once a final rule is in place. That compresses project timelines, reduces regulatory carrying costs, and lowers the barrier to executing routine capital programs. For companies with active integrity management, compression expansion, or system upgrade programs, the practical value of the NOPR is immediate and significant.

LNG developers and operators.

The extension of blanket authorization procedures to LNG facility activities is a meaningful development for a sector that has faced long and unpredictable permitting timelines. Even targeted blanket authorizations for discrete categories of LNG work — the approach FERC has signaled — would reduce regulatory friction for modifications and upgrades at existing LNG terminals. Given the global demand environment and the role U.S. LNG exports are playing in the post-Hormuz supply disruption, faster authorization for LNG infrastructure work has both commercial and geopolitical significance.

Upstream producers and industrial gas buyers.

For producers and large industrial customers who depend on pipeline takeaway capacity and system reliability, faster midstream infrastructure build-out means fewer bottlenecks and more predictable access to markets. The Permian and Appalachian basins in particular have experienced periods where production outpaced pipeline capacity; a regulatory environment that accelerates routine infrastructure upgrades helps close that gap. For industrial buyers — power generators, petrochemical facilities, manufacturers — a more nimble pipeline system supports supply reliability and potentially reduces basis differentials.

Contractors and oilfield services companies.

A regulatory framework that speeds pipeline infrastructure decisions translates directly into work. Compression services, pipeline construction, metering and regulation work, and LNG facility modifications are all categories that stand to see accelerated capital deployment if the NOPR is finalized in something close to its proposed form. The OOOOb flaring rules discussed in last week’s post are already pushing midstream companies to expand gas capture and gathering capacity; a streamlined permitting environment for the infrastructure required to do that work compounds the demand signal.

What Happens Next — and What to Watch

The NOPR is a proposed rule, not a final one. FERC will accept public comments — from pipeline companies, environmental groups, landowners, ratepayer advocates, and state regulators — before issuing a final rule. The comment process typically takes several months, and the final rule may differ from the proposal in ways that matter for specific project types or geographies.

In the meantime, the June 2025 temporary waiver raising the cost limits is still in effect, providing immediate practical relief while the NOPR proceeds. Companies planning projects that fall between the current permanent thresholds and the proposed new ones should evaluate whether those projects qualify under the temporary waiver before it expires or is replaced by a final rule.

Three issues are likely to generate the most substantive comment and potential modification in the final rule. Environmental review requirements for projects that move from full certificate to blanket authorization will be contested by environmental groups who argue that streamlining permitting reduces NEPA scrutiny. Landowner protections for prior notice projects — particularly eminent domain rights — will be closely watched by agricultural and property rights interests. And the rate treatment of blanket certificate projects, which the NOPR also proposes to adjust, will draw comment from industrial customers and state commissions focused on cost allocation.

For general counsel at pipeline, LNG, and upstream companies, the comment period is not a passive exercise. Companies with significant capital programs that would benefit from the expanded blanket thresholds have a direct financial interest in the final rule being robust and durable. Detailed, well-documented comments — particularly those that quantify the cost and schedule impact of the current thresholds on specific project types — carry meaningful weight in FERC rulemakings.

The Bigger Picture

Yesterday’s FERC action is part of a broader regulatory reset that has been building since early 2025. FERC has moved to repeal Order 871, raise blanket certificate thresholds on a temporary basis, explore blanket authorizations for LNG and hydroelectric projects, and now propose a permanent overhaul of the program. The direction is consistent and the votes have been unanimous. The regulatory environment for natural gas infrastructure is becoming materially more favorable than it was 18 months ago.

The Strait of Hormuz disruption has accelerated that shift by making energy security a more urgent political and policy priority. A FERC that might otherwise have moved incrementally has instead moved decisively. Whether that momentum survives the comment process, potential litigation from environmental challengers, and future Commission composition changes is uncertain. What is certain is that the window for faster infrastructure development — and for companies positioned to execute in that environment — is open right now.

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Contract disputes in the oilfield services sector are as old as the industry itself. An operator refuses to pay for work it claims wasn’t performed to specification. A service company walks off a job, citing unpaid invoices. Equipment underperforms, a well timeline slips, and both sides have a different explanation for what went wrong. These situations arise constantly, and in the current environment – with compressed margins, volatile pricing, and operators wielding significantly more leverage over their vendors than they did a decade ago – they are arising more frequently.

What has changed is where and how these disputes get resolved. Texas created its new Business Court in September 2024, and effective September 1, 2025, the legislature expanded the court’s jurisdiction by lowering the threshold for commercial contract disputes from $10 million to $5 million. For OFS companies, that change matters: disputes that previously fell below the Business Court’s floor – and landed in general district courts with broader dockets and longer timelines – can now move through a specialized commercial court with judges who hear nothing but complex business disputes. The Business Court conducted its inaugural jury trials in early 2026 and is accumulating a body of decisions that send a clear early signal about the court’s approach: agreements between sophisticated parties will be enforced as written, efficiently and without substituting the court’s judgment for the terms the parties negotiated.

Understanding how breach of contract claims work – what needs to be proven, what defenses are available, and what damages are actually recoverable – is not just a lawyer’s concern. It is essential business knowledge for any OFS executive responsible for managing customer relationships, protecting receivables, and making decisions about when to fight and when to settle.

What a Breach of Contract Claim Actually Requires

Under Texas law, a breach of contract claim has four elements: (1) a valid, enforceable contract exists; (2) the plaintiff performed or had a valid excuse for not performing; (3) the defendant breached the contract; and (4) the plaintiff suffered damages as a result. All four must be established. A party that proves the other side breached but cannot demonstrate resulting damages has a valid claim with nothing to recover.

In oilfield services disputes, the fight usually concentrates on two of those four elements: whether a breach actually occurred, and the amount of damages. The first question turns on what the contract actually required – which is why contract language matters so much before a dispute arises. Courts interpret contracts as written. If an MSA or work order is ambiguous, or if it says something different from what the parties intended, the court applies the plain meaning of the words on the page. Parol evidence – testimony about what the parties meant to say, or what was discussed during negotiations – is generally not admissible to contradict clear written contract language under Texas law.

The second element – plaintiff’s own performance – is frequently underestimated. A service company that has a legitimate non-payment claim against an operator may find its position weakened if the operator can demonstrate that the service company itself failed to meet a contractual obligation, whether that’s a safety requirement, a performance standard, a notice requirement, or a documentation obligation. Texas courts apply the doctrine of substantial performance: minor deviations from contract specifications may not constitute a breach, but material failures on the plaintiff’s side can give the defendant a valid defense or a counterclaim that reduces or eliminates any recovery.

The Most Common OFS Breach Scenarios — and the Legal Issues Each One Raises

Non-payment and slow payment.

The most common OFS breach claim is straightforward: work was performed, invoices were submitted, and the operator didn’t pay. The legal path forward – demand letter, assertion of lien rights, lawsuit for breach of contract – is well-worn. What complicates it is the invoice dispute provision in most MSAs. If the operator raises a “good faith dispute” as to the amount owed, many agreements allow the operator to withhold payment on the disputed portion without being in breach. How broadly that provision is written determines how much leverage the operator has to delay payment on pretextual grounds. Dispute clauses that require disputes to be made in writing within a defined period after invoice receipt, and that require the operator to pay the undisputed portion promptly, are significantly more protective for service companies than open-ended language that allows any dispute to trigger an indefinite payment hold.

Scope disputes.

The second most common scenario: work expands beyond what was originally contracted, the operator verbally directs the service company to continue or expand, and when the expanded invoice arrives, the operator disputes liability for the additional work. The service company’s legal position in this situation depends almost entirely on whether the additional scope was authorized in writing. Most MSAs require written change orders for scope modifications. If a service company performs additional work on oral direction without a written change order, and the MSA requires written authorization, it faces a significant risk that the operator can legally refuse to pay for the additional work while acknowledging the original contract price. The fact that a field supervisor verbally told the crew to keep going rarely carries the legal weight the service company assumes it does.

Performance disputes.

An operator claims the service company’s work failed to meet the contractual performance standard –  cementing job didn’t hold, a completion tool underperformed, a perforating run missed specifications. These disputes turn on what the contract actually warranted. Most OFS agreements disclaim warranties beyond a limited express warranty for workmanlike performance, which means the operator’s ability to recover for consequential losses – lost production, remediation costs, or rig time – depends on whether the limitation of liability and consequential damage waiver provisions are drafted broadly enough to cover those categories. An operator that suffers significant downstream losses from a service company’s substandard work will push hard on those limitations. The service company’s protection rests on how clearly the limitation language is written.

Termination disputes.

An operator terminates a service company midproject, citing a safety incident, performance failure, or change in business priorities. The service company believes the termination was pretextual or improperly executed. Whether the service company has a breach claim – and what damages it can recover – depends on whether the termination was for cause or for convenience, whether the contract’s termination notice and cure provisions were followed, and what compensation is available for work already performed, mobilization costs, and demobilized equipment. Termination disputes are among the most financially consequential OFS contract claims precisely because they often arise mid-mobilization, when a service company has committed resources and personnel it cannot quickly redeploy.

What Damages Are Actually Recoverable

The goal of contract damages under Texas law is to put the non-breaching party in the position it would have been in if the contract had been performed. That sounds straightforward, but the practical scope of recoverable damages is substantially shaped by the contract itself.

Direct damages – the unpaid contract price for work actually performed, or the cost of remedying defective work – are generally recoverable and rarely waived by contract. Consequential damages – lost profits, lost production revenue, business interruption losses, and reputational harm – are a different matter. Most MSAs include mutual waivers of consequential damages, which means neither party can recover those categories of loss from the other regardless of fault. A service company that loses a major customer relationship because of an operator’s wrongful termination cannot recover its lost future revenue if the contract waives consequential damages. An operator that loses two weeks of production because of a service company’s equipment failure faces the same limitation.

Attorney’s fees are recoverable in Texas breach of contract claims under Chapter 38 of the Texas Civil Practice and Remedies Code – but only if the claimant is represented by counsel, presents the claim to the opposing party, and the opposing party fails to tender payment within 30 days of that presentment. No particular form is required – the demand can be written or oral – but a written demand letter is strongly advisable as the clearest way to satisfy the requirement and create a documented record. A service company that wins its case but cannot demonstrate proper presentment may be denied fee recovery entirely, even after prevailing at trial.

Liquidated damages clauses – contract provisions that specify a predetermined amount of damages for a defined breach – appear in some OFS agreements, particularly in day rate contracts where the parties have agreed on compensation for early termination or equipment downtime. Texas courts enforce liquidated damages clauses when two conditions are met: the harm caused by the breach must be difficult or impossible to estimate at the time of contracting, and the amount specified must be a reasonable forecast of just compensation. Courts will not enforce a clause that functions as a penalty – one disproportionate to the anticipated harm, designed to punish rather than compensate.

Common Defenses – and How to Anticipate Them

When an OFS company asserts a breach of contract claim, it should expect the opposing party to raise defenses. The most common ones in energy services disputes are worth understanding in advance.

Prior material breach is the defense that appears most frequently. If the operator can show that the service company itself materially breached the contract before the operator’s alleged breach occurred, the operator’s performance obligation is excused. A service company pursuing a non-payment claim should be prepared to demonstrate that its own performance was substantially compliant with the contract specifications. Documentation of work performed, safety records, inspection records, and contemporaneous communications are essential.

Waiver and course of dealing defenses arise when a party has accepted non-compliant performance over time without objection. If an operator has consistently paid late and the service company has continued working without formally reserving its rights, a court may find that the service company waived its right to treat the late payment as a breach. Similarly, if an operator has routinely approved oral scope changes and paid for them without written change orders, an OFS company asserting that a different oral scope approval was unauthorized may face a course-of-dealing argument that the parties had modified their contract practices by their conduct.

Failure to mitigate damages is a defense that limits recovery even when liability is clear. The non-breaching party has a duty to take reasonable steps to reduce its losses after a breach. A service company that demobilizes equipment following a wrongful termination and then lets it sit idle for six months when comparable work was available will find its damage claim reduced by the losses it could reasonably have avoided.

The Texas Business Court: A New Forum Worth Understanding

The Texas Business Court, now in its second year of operation, is becoming an important forum for energy contract disputes. It has statewide jurisdiction, specialized judges, and procedures designed for sophisticated commercial cases. Since the jurisdictional threshold dropped to $5 million in September 2025, a significantly larger share of OFS contract disputes qualify for Business Court jurisdiction.

The court’s early decisions are establishing a clear methodology. In Primexx Energy Opportunity Fund, LP v. Primexx Energy Corp. – one of the first substantive merits opinions from the Business Court, involving a private-equity-backed oil and gas partnership dispute – the court applied a statute-first, contract-enforcement approach, holding sophisticated parties to the plain terms of their negotiated agreement and granting summary judgment within six months of filing. The Texas Lawbook described the ruling as “a clear message to the business community: The Texas Business Court will enforce agreements as written, and it will do so quickly without years of litigation.” That philosophy applies equally to contract claims across the energy sector.

The practical implication for OFS companies is that the forum where a dispute gets resolved now depends on the dollar amount, which determines whether the Business Court has jurisdiction, and the venue provision in the MSA, which may designate a specific county or forum. If your MSA designates Harris County district court as exclusive venue and your dispute qualifies for Business Court jurisdiction, there may be a conflict between the contractual venue selection and the statutory forum. These procedural questions are worth resolving before a dispute arises – not during litigation, when the stakes of getting it wrong are higher.

Before the Dispute: Five Practices That Change the Outcome

The best time to manage a contract dispute is before it becomes one. These five practices consistently make the difference between a strong legal position and a compromised one.

• Document everything in writing at the time it happens. Contemporaneous records – daily job reports, written confirmations of verbal direction, email summaries of field conversations, notice letters – are exponentially more persuasive than reconstructed timelines prepared months later during litigation. Train field personnel to document scope changes, performance issues, and any deviation from contract specifications in writing before leaving the wellsite.
• Send a written demand letter before filing suit. Under Texas law, recovering attorney’s fees under Chapter 38 requires presentment of the claim to the opposing party and a 30-day opportunity to pay. While presentment can technically be oral, a written demand letter is the clearest and safest way to satisfy the requirement, create a documented record, start the 30-day clock, and give the other party a genuine opportunity to resolve the dispute before litigation costs accumulate.
• Preserve your lien rights while pursuing contract remedies. A breach of contract claim and a mineral lien are separate legal remedies that can be pursued simultaneously. The lien clock runs regardless of whether a contract dispute is ongoing. OFS companies that focus on contract negotiations while the six-month lien window expires lose one of their most powerful collection tools. The two tracks should run in parallel, not sequentially.
• Reserve your rights explicitly when accepting partial payment. If an operator sends a check for less than the full amount owed, cashing it without expressly reserving your right to the balance can be treated as an accord and satisfaction under Texas law – meaning you may have waived your claim to the remainder. Any partial payment in a disputed situation should be accepted under a written reservation of rights that makes clear the payment does not satisfy the full obligation.
• Assess settlement value honestly and early. Litigation in Texas is expensive, slow, and uncertain even for parties with strong cases. A breach of contract lawsuit that takes two to three years to reach trial, costs several hundred thousand dollars in legal fees, and results in a judgment that takes additional time to collect may be a worse business outcome than a negotiated settlement at 75 cents on the dollar reached in the first few months. Understanding the realistic range of outcomes – including the possibility of a defense verdict, an appeal, and collection difficulty against an insolvent counterparty – is essential to making a rational decision about when to litigate and when to resolve.

The Underlying Point

Contract disputes in the oilfield services sector are not primarily legal problems. They are business problems that have legal consequences. The service companies that manage them best are those whose operations teams understand what their contracts require, document their performance in real time, and escalate potential disputes to legal counsel before positions harden and options narrow.

The Texas Business Court’s growing docket of energy decisions will add clarity over time to how courts treat MSA provisions, scope disputes, and performance standards in OFS agreements. Its consistent emphasis on enforcing commercial contracts as written – demonstrated clearly in its first round of substantive opinions – is a reminder that the language in your agreements matters more than what everyone assumed it meant at signing.

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Nine Energy Service filed for Chapter 11 bankruptcy protection on February 1, 2026. The Houston-based completion services company entered the process carrying approximately $388 million in total funded debt — most of it traced to a 2018 acquisition of Magnum Oil Tools that never quite penciled out. It emerged from bankruptcy on March 5, having shed roughly $320 million in senior secured notes through a debt-for-equity swap that wiped out existing shareholders entirely. The whole process took 32 days.

Nine’s restructuring was pre-packaged and orderly, and its first-day court filings included a commitment to pay trade vendors in full. That is a better outcome than many creditors see in an OFS bankruptcy. But Nine is now operating on a $135 million exit ABL facility in a sector where, according to the Dallas Fed’s Q1 2026 Energy Survey, operating margins for oilfield services firms remain negative — improving from -31.7 to -7 over the quarter, but not yet in positive territory. And based on the broader market signals, Nine is unlikely to be the only oilfield services company to file in the current environment.

The question every OFS company should be asking right now isn’t just “what happens if my customer files for bankruptcy?” It’s a more foundational one: “Do we have the legal tools in place to protect our receivables before a problem arrives?” In Texas, the answer depends almost entirely on whether you understand and properly use the state’s mineral lien statute.
 

The Market Backdrop Has Shifted — But Not in a Comfortable Direction

The Dallas Fed’s Q1 2026 Energy Survey, published in late March, showed the broadest measure of oil and gas business activity turning positive for the first time in nearly a year — jumping from -6.2 in Q4 2025 to 21.0 in Q1 2026. That improvement is real and is directly tied to the Strait of Hormuz conflict driving WTI prices, which averaged $94.65 per barrel during the survey collection period. For OFS firms specifically, the equipment utilization index moved from -12.2 to 30.2, and the prices received for services index jumped from -30 to 9.3.

The optimism, however, comes with a significant caveat. The Dallas Fed’s outlook uncertainty index climbed to 53.7 in Q1 — its highest reading in years — and the April 2026 special survey update, published just two weeks ago, tells a more complicated story. An OFS executive respondent put it plainly: “Within the oilfield services sector, the low-cost environment is starting to put companies out. We are having founders approach us to take them over. The balance sheet is drained, and the pathway to make money for immature firms with low capital reserves is difficult.”

The picture that emerges is a bifurcated market. Larger, better-capitalized OFS companies are benefiting from higher oil prices and increased activity. Smaller and mid-size firms are still navigating the hangover from 18 months of compressed margins and operator capital discipline — many with weakened balance sheets that leave little room for a slow-paying customer. The Dallas Fed’s April update found that 86 percent of executives believe future Strait of Hormuz disruptions are “very likely” or “somewhat likely” within the next five years, meaning price volatility and the conditions it creates for OFS payment risk are not going away.

When operators feel margin pressure — or when uncertainty freezes their capital planning — they slow-pay vendors. When they face serious financial stress, they stop paying entirely. OFS companies are typically unsecured creditors in a bankruptcy unless they have taken deliberate steps to protect themselves before the crisis arrives.
 

What the Texas Mineral Lien Statute Actually Does

Chapter 56 of the Texas Property Code gives oilfield services companies a collection tool that most other types of creditors simply don’t have. A mineral lien allows a contractor or subcontractor who has performed work or furnished materials in connection with oil and gas activities to attach a lien directly to the mineral property — the land, the leasehold, the well, the pipeline, the equipment on the lease — securing the unpaid debt against that property.

The statute is deliberately broad in who qualifies. A “mineral contractor” is any person who performs labor or furnishes material, machinery, or supplies used in mineral activities under a contract with the property owner. A “mineral subcontractor” is anyone who does the same under a contract with a mineral contractor. That covers the vast majority of oilfield services companies, from major completion service providers to equipment rental operations.

There is also a less obvious feature of Chapter 56 that many companies overlook. If you are a mineral subcontractor — meaning you contracted with an operator’s general contractor rather than with the operator directly — a properly served lien notice can “trap” funds in the hands of the property owner. Once the mineral property owner receives proper notice of your lien, it may withhold payment to the contractor in the amount claimed until the debt is settled. That is meaningful protection when a contractor in the middle of the chain is the one with the cash flow problem.
 

The Deadlines That Get Companies in Trouble

The mineral lien is a powerful remedy, but it comes with strict deadlines that Texas courts enforce without exception. Miss the window and the right is gone — period.

The lien affidavit must be filed within six months after the indebtedness accrues. For materials or services, the indebtedness accrues on the date those materials or services were last furnished. For labor performed by the day or week, it accrues at the end of the week the labor was performed. That six-month clock starts running the moment your work is done — not when the invoice goes unpaid, not when the dispute starts.

If you are a mineral subcontractor, there is an additional requirement: you must serve written notice on the property owner at least 10 days before filing your lien affidavit. That notice is a condition precedent to enforceability. Texas courts have held that failure to provide it is fatal to the claim.

The practical problem is the math. A typical OFS company may not begin formal collection efforts until an invoice is 60 or 90 days past due. By the time a customer relationship sours, conversations stall, and someone decides to escalate, two to three months may already have passed. At that point, the six-month deadline is not a comfortable cushion — it’s an emergency. And if that customer files for bankruptcy before the lien is perfected, an unperfected lien provides essentially no protection. You become an unsecured creditor and wait in line.

Once a lien is properly filed, there is a separate deadline to enforce it: a lawsuit to foreclose must be brought within two years after the last day to file the lien affidavit, or within one year after completion or termination of the work under the original contract, whichever is later. Miss that window and the lien is discharged by operation of law.
 

The Lien Waiver Hidden in Your MSA

Even companies that know about mineral liens sometimes discover — too late — that they waived the right to use them before they ever started work. This is one of the most consequential and least understood traps in standard oilfield services contracting.

Many operator-drafted MSAs contain language stating that the service company “irrevocably waives any and all rights to lien, sequester, attach, seize or assert a privilege over” the operator’s property. Sometimes the waiver is framed more subtly — as a “credit reliance clause” stating that the service company “relies on the creditworthiness” of the operator and will “look solely and exclusively” to the operator for payment. Courts have treated both formulations as enforceable mineral lien waivers.

In the 2019 Texas appellate case Mesa Southern CWS Acquisition v. Deep Energy Exploration Partners (No. 14-18-00708-CV, Tex. App.—Houston [14th Dist.] Nov. 21, 2019), a service company signed an MSA containing exactly that kind of language, performed work on multiple wells in Milam County, and went unpaid when the operator filed bankruptcy. The service company recorded mineral lien affidavits against the wells and sued the operator’s parent company to foreclose on them. The court held that the MSA’s credit reliance language was an enforceable waiver, dismissed the service company’s claims in their entirety, and ordered it to release its liens. The company recovered nothing from the property.

This isn’t an obscure edge case. Language of this type appears routinely in operator-drafted MSA forms and is easy to miss when the focus is on getting to work. If your company has signed agreements containing a lien waiver or credit reliance clause, your mineral lien rights may be gone before you ever knew you had them. Review your active MSAs now, before a collection situation arises.
 

What a Good Lien Program Looks Like

The companies that use mineral liens effectively don’t treat them as a last resort. They treat them as a routine part of accounts receivable management. That means building a system, not reacting to each situation individually.

• Collect job information at the start of every engagement, not after a problem develops. The lien affidavit requires a description of the property subject to the lien, including the mineral property owner, the leasehold or well, and the county where the property is located. The easiest time to gather that information is before work begins.
• Set a trigger for lien review at 90 days past due, not 120 or 180. Given the six-month deadline, the 10-day subcontractor notice requirement, time to prepare the affidavit, county clerk processing, and potential disputes about the accrual date, waiting too long is a real risk. A 90-day trigger gives counsel enough runway to act.
• Know whether you are a mineral contractor or a mineral subcontractor on each project. The distinction matters because subcontractors have the additional 10-day notice requirement before filing. Companies that work across multiple projects may be a contractor on some and a subcontractor on others, and conflating the two is a common source of error.
• Review your MSA templates for lien waiver and credit reliance language before signing new agreements. Negotiate to remove or narrow any provision that limits your recourse exclusively to the contracting entity or waives your right to encumber the operator’s property. If the operator insists on retaining some version of that language, push to limit it to disputed amounts that are made in writing within a defined timeframe.
• Be cautious about filing a lien without a valid claim. An improperly filed lien affidavit can constitute slander of title, exposing the claimant to damages. The remedy is powerful precisely because it creates a cloud on the operator’s title — which means it should not be used carelessly or as a negotiating tactic.
   

One More Layer: Bankruptcy’s Automatic Stay

When a customer files for bankruptcy, the automatic stay under Section 362 of the Bankruptcy Code immediately halts virtually all collection activity, including the filing or perfection of liens. If your lien was not filed before the bankruptcy petition date, you generally cannot file it after — doing so without court permission is a violation of the stay. This is why waiting for clear signs of financial distress before acting on lien rights is a losing strategy. By the time a customer’s troubles are obvious to the market, the window for protection may already be closed.

A properly perfected mineral lien, filed before the bankruptcy petition, gives you secured creditor status against the liened property. That is a fundamentally different legal position than being an unsecured trade creditor. In a liquidation, unsecured creditors often recover cents on the dollar, if anything. Secured creditors have priority against the collateral securing their claim.

Nine Energy’s pre-packaged reorganization was structured to pay trade vendors in full, which is not uncommon for a company trying to emerge as a going concern and preserve relationships. But that outcome was a business decision Nine made — it was not a legal obligation to unsecured creditors. OFS companies that were paid only because Nine chose to do so learned something worth understanding: goodwill and legal protection are not the same thing, and in a messier restructuring, the distinction is everything.
 

The Takeaway

The Dallas Fed’s April 2026 survey update captured the current OFS market accurately: activity is picking up for companies positioned to take advantage of higher prices, but the underlying financial fragility built up through 18 months of compressed margins hasn’t disappeared. Smaller operators and service companies with thin capital reserves remain vulnerable, and the uncertainty about how long elevated prices will last — 86 percent of executives expect future Hormuz disruptions — makes multi-year planning difficult.

Texas mineral lien law gives oilfield services companies a meaningful tool to protect themselves in that environment. It is not complicated to use, but it requires discipline — particularly on timing and on MSA review. The companies that benefit from it are those that have a system in place before any specific customer relationship goes sideways. The companies that miss out are the ones that start asking about lien rights only after a customer has stopped returning calls — or after they’ve already signed away those rights without realizing it.

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These price movements are not cyclical blips. They reflect a fundamental shift in the supply-demand balance. U.S. electricity demand is rising at the fastest pace in a generation, fueled by data center buildouts, manufacturing reshoring, and electrification of transportation and buildings. [2] The country commissioned 54 GW of new utility-scale generation and storage in 2025—the most in over two decades—and invested a record $115 billion in grid expansion and reinforcement. [3] [4] Yet even that record-setting buildout has not been enough to ease pricing pressure in congested regions, particularly in the Northeast and Mid-Atlantic, where natural gas dependence amplifies weather-driven volatility.

The January 2026 winter storm underscored this vulnerability. Frigid temperatures and restricted natural gas supplies triggered widespread power plant outages across the Eastern U.S., sending prices spiking and raising fresh concerns about resource adequacy during peak demand periods. [5] These events are not hypothetical risks—they are the operating environment in which PPAs, capacity market positions, and project finance assumptions must perform.

The PPA Market Is Repricing Risk

For renewable energy developers and corporate offtakers, the most consequential trend is the repricing of risk in the PPA market. S&P Global reports that spreads between buyer and seller price expectations have widened significantly in key markets, as both sides reassess the economics of long-term contracting in a higher-price, higher-volatility environment. [6] Solar capture rates—the ratio of a project’s average realized revenue to the market clearing price—are deteriorating as more solar capacity compresses midday prices, exposing projects to growing periods of zero or negative pricing.

This dynamic is driving several important structural shifts in PPA terms. Contract durations are trending shorter, reflecting buyer reluctance to lock in long-term price commitments amid uncertainty about future wholesale price trajectories. Downside protections, including floor prices and shape guarantees, are becoming more common as developers seek to de-risk revenue streams. [7] And battery energy storage is increasingly being integrated into PPA structures—both co-located and standalone—as a mechanism to shift generation into higher-value hours and mitigate capture rate risk. Standalone and co-located BESS deals are rising rapidly, with particularly strong growth in Texas, California, and the PJM footprint. [8]

Capacity Markets Under Pressure

The capacity market overlay adds another layer of complexity. PJM’s capacity market—the largest in the country—has been a flashpoint for litigation and regulatory action, as stakeholders contest whether current market designs adequately compensate the resources needed to ensure reliability in a rapidly changing resource mix. The D.C. Circuit recently found that FERC erred in declining to consider Section 206 relief in the 2024/25 PJM capacity auction re-run case, a decision that could have significant implications for future auction design and pricing. [9]

At the state level, regulators are grappling with the affordability implications of wholesale price increases. The combined share of electricity and natural gas costs as a percentage of total household expenditure rose to 1.62% in 2025, a departure from the recent trend of declining energy cost burdens. [10] Several state commissions are placing greater emphasis on how utility programs align with affordability goals and grid reliability, and are scrutinizing whether rate designs adequately protect consumers from wholesale price pass-through. [11] Massachusetts provides a compelling case study: Governor Healey’s March 2026 executive order establishing the “10X10X10 Plan”—targeting 10 GW of new energy resources over 10 years with $10 billion in projected customer savings—was driven explicitly by ISO New England’s projection that electricity consumption could rise nearly 15% by 2035. [12]

What This Means for Market Participants

For corporate energy buyers, the current environment demands a more sophisticated approach to energy procurement. Companies that have relied on standard virtual PPAs may find that basis risk—the divergence between the contract settlement point and the buyer’s actual load zone—has become a material financial exposure. Physical PPAs and behind-the-meter generation options warrant fresh evaluation, particularly for companies with concentrated load in high-price regions. The strategic case for energy risk management has never been stronger—energy should appear alongside cybersecurity, supply chain, and regulatory risk in enterprise risk management frameworks. [13]

For renewable developers, the key challenge is structuring projects and offtake agreements that can attract financing in a market where merchant tail risk is increasing and capture rates are compressing. Lenders and tax equity investors are asking harder questions about revenue assumptions and hedge coverage, and project finance underwriting is tightening in response to wholesale price volatility. [14] Developers who can pair generation with storage, offer shaped products, and demonstrate grid-positive attributes will be best positioned to compete for offtake and financing.

The throughline connecting these developments is straightforward: the repricing of wholesale power is simultaneously reshaping PPA economics, pressuring capacity market design, and tightening project finance underwriting—and these forces are reinforcing one another. [14] [15] Higher wholesale prices widen the gap between contracted and market revenues, which intensifies capture rate risk in PPAs, which in turn makes lenders demand more conservative debt sizing and hedge coverage, which raises the cost of capital for new projects at precisely the moment when record new capacity is needed to meet surging demand. [14] [7] [3] The market participants who navigate this cycle successfully will be those who treat PPA structuring, capacity market positioning, and financing strategy not as separate workstreams but as an integrated discipline—and who act on that recognition now rather than after the next price spike forces their hand.

References

9. D.C. Circuit Finds FERC Erred in Declining to Consider …
13. The New Energy Trade War: Why Every CEO Must Rethink Their Power Strategy Now | Â鶹´«Ă˝

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Most oilfield services companies have signed hundreds of Master Service Agreements. Most have read relatively few of them in any depth. That’s understandable — the pressure to get to work is real, the documents are long, and the language is dense. Operators frequently present their standard MSA as non-negotiable, which tempts service companies to sign quickly and move on.

But the MSA is not an administrative formality. It is the document that controls what happens in every difficult situation: when someone gets hurt on location, when equipment is damaged, when the operator stops paying, when a project scope expands beyond what was originally agreed, or when either party decides to walk away. In a tightening market with consolidating customers, rising liability verdicts, and more volatile project economics, what your MSA says matters more than it did five years ago.

What follows is an overview of the provisions that carry the most weight, written for the executive who wants to understand what’s at stake, not a technical legal analysis of every clause.

1.  Indemnity: Who Pays When Something Goes Wrong

The indemnity provision is the most consequential clause in any MSA. It determines who bears the financial cost when someone is injured, equipment is damaged, or property is lost, regardless of who caused it.

The standard structure in oilfield services is called “knock-for-knock” indemnity. Each party takes responsibility for its own people and its own property. The operator covers injuries to its employees and damage to its equipment. The service company covers injuries to its employees and damage to its equipment. Neither party can sue the other over whose negligence caused the incident. This model works well because it eliminates endless fault-finding after accidents and lets each party insure against its own known risks.

The danger is in the exceptions. Many MSAs carve well control incidents, blowouts, and subsurface losses out of the knock-for-knock framework.  This means that if a service company’s actions cause or contribute to a well control event, it may face liability for costs that can run into tens of millions of dollars. Gross negligence carve-outs are equally important: standard knock-for-knock protection often evaporates if a party’s conduct rises to the level of gross negligence. Service company executives frequently assume they are fully protected under knock-for-knock when the actual contract language tells a different story.

Under Texas law, the Texas Oilfield Anti-Indemnity Act (TOAIA) voids any indemnity provision that requires one party to indemnify the other for the indemnitee’s own negligence — unless both parties agree in writing to carry mutual insurance to support their respective indemnity obligations. If the insurance levels are unequal, the enforceable indemnity is capped at the lower amount. The indemnity language must also be conspicuous in the contract — typically in bold or all-capital letters — or a Texas court may refuse to enforce it at all.

What to look for: Read the carve-outs carefully. Understand what is excluded from knock-for-knock protection, particularly around well damage and gross negligence. Make sure your insurance program actually covers the obligations you’ve agreed to assume.

2.  Insurance Requirements: The Gap Between What You Agreed to Carry and What You Actually Have

Every MSA specifies minimum insurance requirements — the types and dollar limits of coverage each party must maintain. For service companies, this typically includes commercial general liability, workers’ compensation, employer’s liability, commercial auto, and umbrella/excess coverage, with specific minimum limits for each.

Two problems arise in practice. First, the insurance requirements in an MSA signed several years ago may no longer reflect the actual cost of a serious claim today. Jury verdicts in personal injury cases have risen dramatically — nuclear verdicts (those exceeding $10 million) rose 52 percent in 2024, and the average nuclear verdict now exceeds $51 million. An indemnity obligation backed by a $5 million umbrella policy that felt adequate in 2020 may be wholly insufficient against the litigation environment that exists in 2026. Texas led all states in nuclear verdicts in 2024 with 23 such awards and approximately $3 billion in total damages.

Second, operators sometimes require service companies to name them as additional insureds on the service company’s policies. This is generally permissible under Texas law as a standalone obligation — separate from indemnity — but it means that a claim against the operator may be paid out of the service company’s own insurance program, reducing the limits available for the service company’s own claims.

What to look for: Compare the insurance requirements in your MSAs against your actual current coverage. Identify any gaps. Review additional insured obligations carefully to understand how they affect your available limits.

3.  Payment Terms: Getting Paid, Disputing Invoices, and the Lien Trap Hidden in Plain Sight

Payment terms govern when you get paid and what happens when you don’t. Most MSAs specify a payment window — typically 30 to 45 days after invoice — along with a process for the operator to dispute charges. Pay close attention to the dispute mechanism. Some MSAs allow operators to withhold payment on any “disputed” invoice without requiring that the dispute be made in writing, be specific, or be raised within a defined timeframe. A poorly drafted dispute provision can give an operator an indefinite basis for non-payment with no meaningful obligation to resolve the dispute.

The more serious issue — and one that many OFS executives don’t discover until it’s too late — is the mineral lien waiver. Texas law gives oilfield service companies a powerful collection tool under Chapter 56 of the Texas Property Code: the right to file a lien directly against the operator’s mineral property if you aren’t paid. That lien can force payment before the property is sold or refinanced, and it elevates you above unsecured creditors in a bankruptcy.

Many MSAs contain language that effectively waives that right. In the 2019 Texas appellate case Mesa Southern CWS Acquisition v. Deep Energy Exploration Partners, a service company agreed in its MSA that it was “relying on the creditworthiness” of the operator and would “look solely and exclusively” to the operator for payment. When the operator went bankrupt, the service company tried to foreclose on its mineral liens against the parent company. The court held that the MSA language was an enforceable waiver, dismissed the service company’s claims, and ordered it to release its liens. The service company received nothing.

This is not an obscure edge case. Language limiting a service company’s recourse “exclusively” to the contracting operator — sometimes framed as a credit reliance clause rather than an explicit lien waiver — appears in standard operator MSA forms. If your company has signed agreements containing that language, your mineral lien rights may be gone before you ever knew you had them.

What to look for: Review your MSAs for any language limiting your payment recourse exclusively to the contracting entity, or waiving your rights to lien, attach, or encumber the operator’s property. Negotiate to remove or narrow that language before signing. Ensure dispute provisions require written notice and a reasonable resolution timeline.

4.  Limitation of Liability: The Cap That Cuts Both Ways

Many MSAs include a limitation of liability clause that caps the total damages one party can recover from the other — often equal to the value of the work order or the fees paid over a defined period. These clauses also commonly exclude consequential and indirect damages entirely: lost profits, lost production revenue, and business interruption losses are frequently waived by both parties.

From a service company’s perspective, consequential damage waivers offer real protection. If your equipment failure causes an operator to lose production for two weeks, a waiver of consequential damages prevents the operator from claiming lost revenue — which could dwarf the value of the underlying service contract. But the same clause works in reverse: if the operator’s actions cause your company to lose a significant business opportunity, you likely cannot recover those losses either.

Watch for asymmetry. Some operator-drafted MSAs include a consequential damage waiver that applies to the service company’s claims but carve out the operator’s claims for well damage, lost production, or pollution. That is not a mutual limitation — it is a one-sided cap that protects the operator while leaving the service company exposed to the largest categories of potential loss.

What to look for: Confirm that liability caps and consequential damage waivers are truly mutual. If the operator has carved out well damage or production losses from the waiver, your exposure on those categories is uncapped. Make sure that is intentional and reflected in your insurance and pricing.

5.  Termination: How Either Party Gets Out — and What It Costs

MSAs typically include two types of termination rights: termination for cause (one party has materially breached the contract) and termination for convenience (either party can exit without a specific reason, usually with advance notice). Termination for convenience clauses are common and often favor operators, who may want the flexibility to stop using a service company if commodity prices drop, project plans change, or a preferred vendor becomes available.

For service companies, the critical question is what compensation is available upon termination for convenience. Some MSAs provide for payment of work already performed but nothing more — meaning if you’ve mobilized equipment, hired crews, and committed resources to a project that the operator terminates the following week, you recover only what you’ve billed for work done, not your mobilization costs, demobilization costs, or lost margin on the remaining scope. Negotiating for demobilization fees or a minimum notice period tied to compensation can materially reduce that exposure.

On the cause side, pay attention to what constitutes a breach and how it must be cured. Some MSAs define breach broadly enough to include missed performance targets or safety incidents that did not result in injury. An automatic termination trigger — one that fires without a notice-and-cure period — can put a service company out of a contract with no opportunity to fix the underlying issue.

What to look for: Understand the notice period required for termination for convenience, and whether any compensation beyond earned fees is available. Confirm that termination for cause includes a written notice and cure period before the termination becomes effective.

6.  Governing Law, Venue, and Dispute Resolution: Where Disputes Get Resolved Matters

Governing law and venue clauses determine which state’s law applies to the contract and where any dispute must be litigated or arbitrated. For Texas-based OFS companies, a Texas governing law clause is generally favorable — the Texas Oilfield Anti-Indemnity Act, Texas mineral lien statutes, and Texas case law on indemnity and insurance are well-developed and broadly understood. A governing law clause selecting a different state can change those protections significantly. As noted in a recent federal court decision, even a contract with an express Texas choice-of-law clause can have that provision overridden by another state’s anti-indemnity law if the work was performed there and that state’s interest is found to substantially outweigh Texas’s.

Venue provisions determine where litigation or arbitration takes place. An operator headquartered in another state may designate its home jurisdiction as the exclusive venue for disputes — which means that if a payment dispute arises, your company may need to retain counsel in that state and litigate there, adding cost and complexity to what should be a straightforward collection matter.

Arbitration clauses have become more common in MSAs and carry tradeoffs. Arbitration can be faster and more confidential than litigation, but arbitration awards are difficult to appeal, discovery is limited, and arbitration costs — particularly for larger disputes — can rival or exceed litigation costs. If your MSA includes mandatory arbitration, understand the rules that govern it, who pays the arbitrator fees, and whether there is any right of appeal.

What to look for: Prefer Texas governing law when your work is performed in Texas. Review venue provisions to ensure disputes can be resolved in a forum that is practical and cost-effective for your company. Understand the mechanics and cost allocation of any mandatory arbitration clause before signing.

7.  Scope of Work and Change Orders: The Gap Between What You Agreed to Do and What You End Up Doing

The MSA typically governs the overall commercial relationship. The actual work is described in individual work orders or job orders that are issued under the MSA. If those two documents conflict, the MSA usually controls — which matters when a work order describes one scope and field conditions require something different.

Scope creep is one of the most common sources of payment disputes in oilfield services. Work expands beyond what was originally contemplated — additional runs, longer intervals, expanded services — and the question becomes whether that additional work was authorized and at what rate it will be compensated. MSAs that require written change orders for any scope modification give service companies the clearest protection. Oral approvals — even from someone with apparent authority on the operator’s side — are difficult to prove and often disputed.

What to look for: Confirm that the MSA requires written work orders for each job and written change orders for scope modifications. Train field personnel to document any verbal direction to expand scope and follow up in writing before performing the additional work.

8.  Force Majeure: What Happens When the World Intervenes

Force majeure provisions excuse a party from performance when events beyond its control make performance impossible. Pandemics, hurricanes, acts of war, government orders, and supply chain disruptions have all tested force majeure clauses in recent years — and in the current environment, with the Strait of Hormuz disruption affecting global supply chains, these clauses are actively relevant to oilfield services contracts right now.

Texas courts interpret force majeure clauses strictly and narrowly. The clause must specifically list the type of event that occurred. Economic hardship — a job became more expensive because of tariffs or material cost increases — does not qualify as a force majeure event under Texas law. Only genuine impossibility of performance, caused by a listed event, triggers the protection. If your MSA’s force majeure clause lists only “acts of God” and does not specifically include government orders, military conflict, trade restrictions, or supply chain disruptions, your protection is narrower than you may think.

Notice requirements matter here too. Most force majeure clauses require prompt written notice once a triggering event occurs. Missing that deadline can forfeit the protection even when the underlying event would otherwise qualify.

What to look for: Ensure your force majeure clause specifically lists government orders, trade restrictions, military conflict, and supply chain disruptions. Understand the notice requirements and confirm your operations team knows when and how to send them.

The Bottom Line

MSAs are framework agreements — they are designed to govern multiple jobs over an extended period, which means the risk they allocate compounds over time. An indemnity clause, a lien waiver, or an insurance gap that seems manageable on a single job becomes a systemic exposure across every project you run under that agreement.

Operators have sophisticated legal teams that draft these documents to protect the operator’s interests. That is not a criticism — it is simply the reality of the negotiation. The service companies that are best positioned are those that treat the MSA as a business document, understand what they are agreeing to, and engage counsel to negotiate the provisions that carry the most risk before the agreement is signed — not after something goes wrong on location.

The provisions discussed here — indemnity, insurance, payment and lien rights, liability caps, termination, governing law, scope, and force majeure — are the ones that appear most frequently in disputes and that carry the greatest financial consequences when they don’t say what a service company assumed they did. Understanding them is not a legal exercise. It is a business one.

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