Texas: A high stakes frontier for US battery energy storage systems

In our last article, we examined how California’s battery storage market reached unprecedented scale, but also revealed early signs of market saturation, revenue compression, and operational constraints. That analysis made one thing clear: While the technology behind BESS may be universal, the economics are anything but. Across the US, battery storage success is shaped not by a single framework, but by the market design, policy structure, and risk tolerance of each regional power system. Nowhere is that more apparent than in Texas.

ERCOT has become the fastest-growing battery market in the country. In just four years, its installed BESS capacity has surged from virtually zero to over 10GW, making it the second-largest in the US after California. But size alone doesn’t define ERCOT. What makes it distinctive is its merchant nature: no capacity market, no procurement mandates, and no federal regulatory oversight. Storage developers in Texas operate in a pure energy-only market[1] – where upside is unbounded, downside is unprotected, and the ability to ride price volatility is essential.

For investors, developers, and policymakers, ERCOT represents the most entrepreneurial – and unforgiving – BESS environment in the US. It is a live laboratory for merchant storage at scale. And it offers a preview of what storage markets might look like when driven by market signals rather than mandates.

[1] In the US, most electricity markets include a capacity mechanism that pays resources to be available to meet future demand. ERCOT, by contrast, is an “energy-only” market: Generators and storage assets are compensated solely for the electricity they deliver, not for standby capacity.

Texas has emerged as the epicenter of utility-scale battery deployment in the US, not through mandates or subsidies, but through market momentum and merchant ambition. By the end of 2024, ERCOT had 8.6GW of operating battery capacity online, up from just 200 megawatt (MW) in 2020 (see figure 1). That’s a more than 40-fold increase in under five years, making Texas the second-largest BESS market in the country after California and the fastest-growing by far. And growth expectations for the coming years are even more extreme: In just three years from now, installed capacity in ERCOT might exceed 70GW.

The growth has been driven by a diverse mix of strategies. Early projects were co-located with solar and wind assets in West Texas and the Panhandle – a northern region of Texas with high wind resource potential. These projects leveraged cheap, surplus generation and interconnection access (see figure 2). But recent waves of development have shifted toward standalone storage deployed near urban load pockets like Houston, Dallas, and Austin. In these areas, batteries can capture congestion-driven price spreads, provide local reliability, and respond quickly to volatility.

Project scale is also growing. Plus Power’s 300MW/600 megawatt hour (MWh) Rodeo Ranch in Pecos County – located in the West zone – is currently the largest standalone battery operating in ERCOT. Other notable entrants include Jupiter Power’s 200MW Callisto project, which targets congestion in the Houston area, and ENGIE, which crossed 1GW of operational battery capacity in Texas in 2024. ENGIE primarily operates fast-ramping, one-hour systems deployed across multiple ERCOT zones, including West, North, and Houston.

While many early installations were one-hour batteries optimized for ancillary services, the duration profile is evolving. By late 2024, six of the top seven BESS operators in ERCOT were averaging more than 1.5 hours per project. This reflects a shift toward two-to four-hour systems, aimed at both arbitrage and emerging products like the DRRS. The DRRS, when launched, will require four-hour duration.[2] This growing emphasis on duration is mirrored in ERCOT’s own reliability modeling.

To understand how ERCOT’s current storage fleet contributes to reliability, the ELCC study published in February 2025 offers valuable insight. ELCC measures the share of a resource’s capacity that can be counted on during periods of peak system stress, such as hot summer evenings or cold winter mornings.

Although ERCOT had just 8.6GW of operational battery storage at the end of 2024, the study models a 2026 planning scenario assuming between 15GW and 18GW of installed storage. Of that modelled capacity, 97% consists of one-hour and two-hour systems. Only 3% falls into the three-hour to five-hour range (see figure 3). This mirrors current development trends but also highlights a gap between what is being built and what ERCOT may soon require.

[2] The Dispatchable Reliability Reserve Service (DRRS) is a new ancillary service planned by ERCOT to enhance grid reliability. It compensates resources that can provide at least four hours of continuous energy during emergency conditions, supporting system stability without requiring formal capacity obligations.

That gap matters. In summer simulations, one-hour batteries delivered just 13.7% of their rated capacity as ELCC during evening peaks, compared to 68.2% for five-hour systems. In winter, the contrast was even more stark: one-hour systems earned 23.1% ELCC, while four- and five-hour batteries exceeded 93% (see figure 4). As ERCOT prepares to launch DRRS and potentially other duration-sensitive products, market signals are increasingly favoring assets capable of sustained multi-hour performance. This reorientation toward longer-duration systems is beginning to influence development strategies.

These evolving performance requirements are already shaping the development pipelines. ERCOT’s interconnection queue reflects the scale of this change. As of April 2025, the queue includes more than 411GW of proposed storage and generation capacity. Battery storage leads with 42% of all queued capacity, followed by solar with 39%, wind with 10%, and gas-fired generation with 8% (see figure 5). This marks a dramatic shift from previous cycles where wind and solar dominated queue volume. Battery projects now compete head-to-head with these resources not only for interconnection space, but also for revenue opportunities on the same congested grid.

S&P Global data shows that developers plan to add more than 40GW of battery capacity by the end of 2026 (see figure 6). Yet when viewed through the lens of ERCOT’s historical buildout rates, the outlook becomes more conservative. Based on a volume-weighted completion rate of 24% – as reported in Berkeley Lab’s Queued Up: 2024 Edition study – a more grounded estimate suggests the state is on track to add another 7GW to 10GW of operational capacity by 2026, building on the 8.6GW already online. This gap reflects the reality that interconnection queue volume does not equal build certainty. Technical constraints, permitting friction, and grid congestion are slowing the pace at which projects can move from queue to construction.

This projected growth in operational battery storage capacity has been aided by ERCOT’s interconnection process. Unlike CAISO’s cluster study model, ERCOT uses a “first-ready, first-served” model, with a typical timeline of 18 to 30 months for large projects.[3] While not every queued project reaches completion, developers are able to move forward without waiting on centralized procurement or long-term contracts – accelerating progress for the most viable and strategically located assets.

Put simply, Texas has become the national testbed for merchant battery storage at scale. Its deployment profile – favoring speed, optionality, and developer-led execution – reflects the belief that arbitrage, ancillary services, and market-based innovation can unlock storage value faster than top-down mandates ever could.

[3] ERCOT Interconnection Process, Generation Entity Winter Weather Preparedness Workshop, October 2024

In ERCOT’s energy-only market, battery revenues are earned, not awarded. Without capacity payments or long-term contracts, developers must extract value from volatility: buying low, selling high, and delivering flexibility when the grid needs it most. That reality has shaped a revenue model built on two primary legs – ancillary services and energy arbitrage. Both of which are now undergoing rapid transformation.

In 2023, batteries in ERCOT earned an average of USD 168,504 per MW-year from ancillary services, according to Modo Energy (see figure 7).[4] This figure reflects the average of weekly earnings reported throughout the year, with revenues spiking between June and September as reserve scarcity and extreme weather drove up clearing prices. Ancillary revenues were primarily derived from Regulation Up and Down, which are used to maintain frequency balance on the grid. Another contributor was the Responsive Reserve Service (RRS), a fast-responding reserve. Batteries are particularly well-suited for RRS due to their near-instantaneous ramp capability.[5]

[4] Modo Energy reports average BESS revenues in USD per MW-year. The figure cited is based on weekly revenue data for 2023. The revenue data comes from the Modo BESS ERCOT Index, which tracks the performance of all commercially operational utility-scale battery storage assets in ERCOT. Revenues are normalized to dollars per MW-year and reflect gross revenues from real-time energy, day-ahead energy, and ancillary service markets. For full methodology, see: Modo Energy ERCOT Methodology.

[5] Responsive Reserve Service (RRS) provides 10-minute reserves to respond to unexpected grid events. Regulation Up and Down maintains system frequency by automatically adjusting output in response to minor fluctuations.

By 2024, average ancillary service revenues fell to USD 36,317 per MW-year – a nearly 80% decline (see figure 8). The drop was not driven by reduced system need but by oversupply. The battery fleet expanded rapidly, but the volume of ancillary services procured by ERCOT remained fixed. As more batteries competed for the same products, clearing prices fell sharply, particularly outside the summer months.

While ancillary services remain the largest source of average annual revenue for most batteries, they no longer dominate the revenue stack to the same degree. In relative terms, the importance of arbitrage is growing. In 2023, batteries earned USD 29,386 per MW-year from real-time market (RTM) energy trading. That figure fell to USD 13,853 per MW-year in 2024 due to fewer extreme price events and lower volatility outside peak summer months. However, day-ahead market (DAM) energy earnings increased from USD 1,522 per MW-year in 2023 to USD 4,803 per MW-year in 2024, signaling a shift in operational strategy.[6]

Some operators are enhancing their strategies by increasing participation in the DAM, aiming to smooth earnings and reduce their dependence on price spikes in the RTM. This shift does not displace ancillary services as the dominant revenue source, but it reflects how operators are layering DAM participation to stabilize returns and dynamically manage exposure across market opportunities.

Despite this evolution, ERCOT’s market structure still limits optimization. Key ancillary services impose duration thresholds that many current batteries cannot meet. Non-Spinning Reserve Service (NSRS), for example, requires a minimum of four hours of continuous discharge capability, effectively excluding the majority of ERCOT’s one- and two-hour battery fleet. ERCOT Contingency Reserve Service (ECRS) is somewhat more accessible, requiring two hours of sustained output, but even that rules out participation for most one-hour systems.[7] These constraints create a growing mismatch between the duration profile of the operating fleet and the market’s most lucrative services. While stakeholders have proposed reforms such as reducing ECRS duration requirements implementation remains uncertain.

Another constraint is the absence of Real-Time Co-Optimization (RTC). Unlike other US ISOs that simultaneously optimize the dispatch of energy and ancillary services in real time, ERCOT requires pre-commitment to one or the other. This design limits flexibility, especially during volatile periods when shifting between markets could maximize returns. RTC is expected to be introduced in late 2025, and its implementation will be critical to improving monetization for flexible assets like BESS.[8]

[6] The DAM allows resources to submit bids and offers a day in advance, locking in price spreads. The RTM reflects intra-day price volatility and dispatches resources based on actual system conditions.

[7] NSRS requires resources to deliver energy within 30 minutes and sustain output for four continuous hours.

[8] RTC is a dispatch mechanism used in other markets (e.g., PJM, CAISO) to allocate energy and ancillary service commitments based on real-time system needs and marginal value.

Unlike in CAISO, policy has never been the primary catalyst for battery deployment in ERCOT, but it is beginning to shape the terrain. While Texas remains opposed to mandates and capacity markets, a series of state and federal developments are introducing new risks, constraints, and subtle incentives that storage developers can no longer ignore.

The clearest near-term signal is the introduction of the DRRS in 2026. The program will compensate resources capable of delivering four hours of sustained energy during grid emergencies – a structural nod to duration without introducing formal capacity obligations. While DRRS will be voluntary and modest in scale at launch, its design encourages the buildout of two- to four-hour systems and aligns with ERCOT’s broader emphasis on resource performance under stress.

At the state level, legislative pressure is mounting – even if no new restrictions have taken effect. In the most recent session, three bills (SB 388, SB 715, and SB 819) passed the Texas Senate before stalling in the House of Representatives. Together, they signaled a coordinated effort to reshape ERCOT’s generation mix by requiring that half of all new capacity be dispatchable, mandating backup power for renewables, and introducing new permitting requirements. While these proposals ultimately failed, their advancement through one chamber highlights a political climate increasingly skeptical of intermittent and inverter-based resources, including storage. Developers should expect continued scrutiny in future sessions, especially around siting, interconnection, and dispatchability.

At the federal level, the Investment Tax Credit (ITC) for standalone storage – introduced by the IRA and currently available through 2032 – remains a critical enabler of project viability in ERCOT. But its future is no longer guaranteed. In March 2025, the House passed the One Big Beautiful Bill, which proposes to accelerate the ITC phase-down, tighten foreign entities of concern restrictions, and increase documentation requirements for domestic content bonuses. The bill is now awaiting Senate negotiation, and its final provisions could materially impact the financial feasibility of battery projects.

Meanwhile, the reimposition of Section 301 tariffs on Chinese battery cells and minerals has already raised EPC costs for 2025 projects. For developers in ERCOT, many of whom operate without long-term offtake contracts, the combination of higher import costs and potential ITC limitations presents a real financing challenge.

Taken together, these signals mark a shift in how storage will scale in Texas. Duration is beginning to matter more, not because of mandates, but because reliability products like DRRS are quietly reshaping the revenue stack. Siting risk, whether from political pressure or grid saturation is becoming as critical as price volatility. And while the merchant thesis still holds, developers must now navigate a more fragmented policy environment, where the speed of development is no longer its own safeguard. In ERCOT, success will increasingly depend on aligning project timing with tax credit eligibility, siting with interconnection headroom, and performance with market adaptability – without the cushion of long-term contracts or centralized planning.

ERCOT’s battery deployment boom has outpaced the grid’s physical evolution. Over the past four years, developers have rapidly added BESS capacity, often sited to capitalize on price volatility, without parallel upgrades to the transmission system. As a result, batteries are increasingly concentrated in areas where the grid lacks the physical capacity to deliver their energy efficiently. The result isn’t system failure – it’s localized friction. Transmission constraints are beginning to define the boundary between commercially bankable storage projects and stranded merchant ambition. And unlike regulatory headwinds or price cannibalization, these frictions are not abstract. They are mapped, measured, and increasingly inescapable.

Recent congestion trends already reflect this shift. According to ERCOT’s 2024 constraints report, several transmission bottlenecks ranked among the most congested on the grid. These include the Tonkawa Switch–Morgan Creek SES 345 kV, Odessa EHV–Yarbrough Sub 138 kV, and the Panhandle Interface. Congestion rents in these transmission lines have reached as high as USD 156m annually.[9] These are not theoretical risks; they are already impacting dispatch economics and curtailing output across wind-heavy and storage-attracting regions.

Looking ahead, the grid picture tightens further. Projected congestion rents for 2026 and 2029 highlight zones where storage developers are already active. These include the West Texas Export Interface, MacKenzie to Northeast 115 kV line, Panhandle Interface, and North–Houston Interface. Without grid reinforcement, each of these constraints is expected to incur between USD 100m and USD 180m in congestion rent annually. These same areas are often targeted for merchant BESS siting due to nodal price volatility – but persistent congestion may reduce access to real-time market pricing, distort arbitrage strategies, or trigger physical deliverability limits.

Relief is on the roadmap – but not evenly distributed. ERCOT has scheduled a slate of upgrades between 2025 and 2029, including the Roanoke Area Upgrades, the Bearkat–North McCamey–Sand Lake 345 kV addition, and the Lower Rio Grande Valley System Enhancement Project. However, these investments are primarily load-serving or reliability-focused – not specifically tailored to unlock storage value. Some projects, like the Temple Area Project or West Texas Infrastructure Rebuild Project, may alleviate stress near known battery hubs, but their timelines (2027-2028) mean storage developers must bridge a multi-year gap with heightened nodal risk.

The Long-Term System Assessment (LTSA) sharpens the picture. High electrification and economic growth scenarios underscore a clear directional trend: Load is growing fastest in Central Texas, South Texas, and the Lower Rio Grande Valley. These are regions where battery siting could reduce system stress and improve local resilience. Yet many of these zones remain transmission-limited today. The LTSA doesn’t provide a siting map, but it highlights the system’s structural misalignment: Batteries are being built faster than the grid is adapting.

As ERCOT's storage fleet grows, transmission is no longer just an interconnection hurdle – it’s a defining input into project economics. Navigating congestion, substation limits, and future load centers requires developers to bring the same level of locational precision they once reserved for revenue modeling. What was once a market driven by price signals is now one shaped by physical access and grid topology. For storage to scale sustainably in ERCOT, transmission risk must be analyzed as rigorously as market opportunity.

[9] Congestion rents refer to the financial value created when transmission constraints prevent the lowest-cost electricity from being delivered across the grid. When demand exists on one side of a bottleneck and cheap supply is stuck on the other, price differences arise at different nodes. These price spreads are captured as congestion rents and indicate the economic impact of limited transmission capacity.

ERCOT’s battery storage capacity continues to grow, but the drivers of that growth are shifting. Storage projects are now being evaluated as much for their grid compatibility as for their revenue potential. Duration, siting, interconnection, and policy exposure have become central to development decisions, each carrying implications for performance and bankability.

The growing role of longer-duration storage (>two hour) is a response to both market signals and planning expectations. With new reliability products like DRRS on the horizon and ELCC metrics informing system planning discussions, batteries offering sustained output are more aligned with ERCOT’s evolving system needs.

At the same time, siting strategies are becoming more complex. Transmission constraints, substation headroom limits, and localized congestion risks are increasingly relevant in assessing project feasibility. Interconnection queue access remains relatively fast compared to other ISOs, but technical viability now depends on a clearer understanding of physical bottlenecks and future grid topology.

Federal policy still supports the economics of standalone storage, but deal structuring now requires more attention to compliance risks, timing, and growing uncertainty. Developers pursuing IRA tax credits must navigate domestic content thresholds and anticipate potential changes under pending legislation. Meanwhile, efforts to reshape state-level policy – even when unsuccessful – reflect a more contested political environment.

What defined ERCOT’s storage buildout in earlier years – speed, merchant optionality, and flexible siting – is being rebalanced. Projects that integrate duration value, siting precision, and policy uncertainty are better positioned to succeed in the market’s next phase. Although the path forward is complex, the underlying momentum hasn’t faded. With over 170GW of storage in queue, investor interest remains strong, and ERCOT continues to offer one of the most dynamic and consequential electricity markets for battery deployment in the US.