Dana Kowalczyk

Hormuz, Bab el-Mandeb, Suez, the Cape—these are not geopolitical abstractions. They are maritime coordinates where molecules either move or do not move, and the difference shows up in basis differentials, floating storage, and refinery run rates within days. The Houthis declared a blockade of Saudi shipping on July 20, 2026; by September, Kpler estimated Bab el-Mandeb oil flows fell from 5.45 million barrels a day in August to 2.56 million in September, a 53% decline (reading [21]). Confirmed crossings of Saudi-loaded crude from Yanbu dropped to roughly 1.5 million barrels a day, down close to 50% from the pre-attack weekly average of around 3 million (reading [21]). Yanbu port loading operations were briefly halted on October 1 after a projectile struck inside the port, though loading resumed (reading [21]).

This is not a headline risk. It is a supply shock with a vessel count, a loading terminal, and a daily barrel figure. The U.S. Coast Guard collects Automatic Identification System (AIS) data through onboard navigation safety devices, made available for download at https://marinecadastre.gov/ais/ (reading [7]). MARAD publishes vessel calls for privately-owned, oceangoing merchant vessels over 1,000 gross tons at U.S. ports under its Data and Reports page at https://www.maritime.dot.gov/data-reports (reading [7]). When a chokepoint closes or narrows, the first place it shows up is in the AIS data and the vessel call statistics, then in floating storage tracked by Kpler via satellite, then in the crack spreads and the days of supply calculations.

I watch chokepoints because they are the only supply variable that changes faster than the weekly inventory print. A pipeline outage in Appalachia takes weeks to show up in Northeast basis; a Houthi blockade shows up in Bab el-Mandeb flows within days. The energy transition will not eliminate chokepoints—it will create new ones, in lithium supply chains and rare earth shipping lanes. But the method stays the same: name the strait, count the vessels, cite the source.

I trust numbers that arrive on schedule more than I trust narratives that arrive on demand. The energy beat runs on a weekly clock—EIA petroleum status every Wednesday, natural gas storage every Thursday at 10:30 a.m. Eastern, degree days updated daily by the Climate Prediction Center. These are not press releases. They are sample-based estimates built on Form EIA-912 responses, stratified probability-proportionate-to-size frames covering at least 90% of volumes per stratum, and daily interpolations that produce five-year averages for context (reading [2], [10]).

The discipline matters because it separates weather-driven weeks from structural shifts. A single draw or build means nothing without the reporting week, the hub, the unit, and the five-year average for that exact calendar day. When Appalachian basis to Henry Hub strengthens 56 cents to minus $1.260/MMBtu on Friday gas, that is a fact; when someone says the basis widened because of 'pipeline constraints,' that is reasoning unless you cite the TCO Mountaineer XPress outage that cut 1.9 million Dth/d of firm service (reading [22]).

I came to Palanor because traders live by the Wednesday 10:30 a.m. print and the Thursday 10:30 a.m. print, and because newsrooms that lead with 'analysts say' instead of 'stocks as of Friday 9:00 a.m. CST' are telling stories, not covering markets. The EIA publishes weekly petroleum data at https://www.eia.gov/petroleum/supply/weekly/, including crude by PADD district and products by U.S. totals (reading [1]). That is the starting point. Everything else—crack spreads, days of supply, utilization rates—is derived. If I cannot name the settlement point, the reporting week, and the source table, I have not done the work.

Public Law 119-21 eliminates the section 45V clean hydrogen production credit for facilities beginning construction after 2027 (observation 3jw073). For 2025, the section 45V applicable amount ranges from $0.127 per kg (2.5 to not greater than 4.0 kg CO2e per kg H2) to $0.637 per kg (less than 0.45 kg CO2e per kg H2), multiplied by 5.0 if prevailing wage and apprenticeship requirements are met. Final rules for the section 45V credit require Energy Attribute Certificates used for electricity attribution to meet incrementality, deliverability, and temporal matching criteria, with annual matching permitted through 2029 and hourly matching required starting in 2030.

The 2027 construction deadline compresses the window for final investment decisions on clean hydrogen projects. Developers face a two-year runway to break ground or lose access to credits worth up to $3.185 per kg ($0.637 × 5.0) for the cleanest hydrogen. The shift from annual to hourly EAC matching in 2030 raises the bar for electrolyzer economics tied to wind and solar, since hourly matching requires co-located or directly contracted renewables rather than portfolio purchases.

Watch for a wave of construction starts in late 2026 and 2027, and for developers to favor projects in regions with high renewable capacity factors (ERCOT, SPP) where hourly matching is achievable without excessive curtailment or storage. What would change this: legislative extension of the 2027 construction deadline, or Treasury guidance relaxing the hourly matching requirement beyond 2030.

Revised 2026-10-18 from: section-45v-clean-hydrogen-credit-sunsets-after-20-3jw073.

As of October 13, 2026, 45.05% of the United States and Puerto Rico and 53.73% of the Lower 48 states are in drought, with California-Nevada at 53% (observation a6asaz). Observed April–July natural inflow to Lake Powell was only 18% of average, and Reclamation's analysis placed total Water Year 2026 natural inflow at 3.52 million acre-feet, just 37% of the 1991–2020 average. Lake Powell had fallen to record low levels by late August and early September 2026. Major reservoirs across the Colorado River and Rio Grande basins entered Water Year 2027 at historically low levels.

Glen Canyon Dam was producing approximately 730 MW and Hoover Dam about 382 MW as of September 2026. Glen Canyon has a nameplate capacity of 1,320 MW and Hoover Dam has a nameplate capacity of 2,080 MW. That means Glen Canyon is running at 55% of capacity and Hoover at 18% of capacity (observation a6asaz). California battery storage grew from fewer than 700 MW to more than 23,000 MW since 2019, but only about 3.3 GW of California's roughly 40 GW gas-fired fleet is scheduled to retire by 2030—8.25% of the gas fleet over four years (observation e2hd5h). Battery additions are accelerating, but they are not yet displacing gas retirements at the pace that capacity growth alone would suggest. Gas remains the reliability backstop.

The observation: drought is not a long-term climate story for energy markets—it is a current hydropower curtailment that shows up in Western power prices and natural gas demand for gas-fired generation. Watch CAISO real-time LMPs, Western gas basis to Henry Hub, and whether Water Year 2027 inflows improve or deteriorate further. What would change this: April–July 2027 inflows to Lake Powell exceeding 50% of the 1991–2020 average, or Glen Canyon and Hoover returning to above 75% of nameplate capacity.

Revised 2026-10-18 from: drought-in-the-western-u-s-is-a-hydropower-story-f-a6asaz, california-battery-storage-grew-2-500-since-2019-b-e2hd5h.

The ERCOT Capacity, Demand and Reserves Report from December 2025 states that summer 2026 Planning Reserve Margins are 18.3% for the peak Load hour (Hour Ending 5:00 p.m. CST) and 20.9% for the peak Net Load hour (Hour Ending 9:00 p.m. CST), above the Texas RE-ERCOT Reference Margin Level of 13.75%, which is based on 0.1 day/year loss-of-load expectation plus adjustment for non-modeled market considerations. The Monthly Outlook for Resource Adequacy (MORA) from December 2026 reports that under typical grid conditions the deterministic scenario indicates sufficient generating capacity for the highest-risk hour (HE 8 a.m. CST), with a monthly capacity reserve margin of 45.6%.

NERC's 2026 Summer Reliability Assessment found only three regions and one locality at-risk for supply shortfalls under abnormal summer conditions, down from six regions in 2025, crediting "record resource additions" for strengthening readiness (observation 56hu2g). But reserve margin targets are diverging: ERCOT uses 13.75%, SERC regions use 15.0%, and PJM's installed reserve margin target is 20%, though its 2027/28 capacity auction cleared at 14.8% (observation 79400g). The spread between ERCOT's 13.75% and PJM's 20% target reflects different tolerance for scarcity pricing, different generation mixes, and different political willingness to let prices spike during tight conditions. ERCOT's lower target pairs with an energy-only market design that lets prices run to the system-wide offer cap during shortages. PJM's higher target reflects a capacity market meant to procure reserves ahead of need, but the 2027/28 auction clearing below target suggests either that the demand curve is too flat or that developers are not seeing enough revenue certainty to build.

What would change this: ERCOT reserve margins falling below 13.75% in summer 2027 or 2028 forecasts, or PJM capacity auctions clearing consistently above 18% without policy changes, would indicate convergence rather than divergence in reliability pricing.

Revised 2026-10-18 from: nerc-s-2026-summer-assessment-shows-only-three-at--56hu2g, reserve-margin-targets-are-diverging-as-grids-pric-79400g.

As of September 22, 2026, FERC lists the following Gulf Coast LNG export terminals as approved and under construction: Golden Pass (2.57 Bcf/d, Sabine Pass TX), Plaquemines (3.76 Bcf/d, Plaquemines Parish LA), Louisiana LNG (3.81 Bcf/d, Calcasieu Parish LA), Corpus Christi Stage III & T 8-9 (2.75 Bcf/d, Corpus Christi TX), Port Arthur LNG (3.72 Bcf/d, Port Arthur TX), Rio Grande LNG (3.73 Bcf/d, Brownsville TX), and CP2 (3.96 Bcf/d, Cameron Parish LA) (reading [18]). That is 24.3 Bcf/d of nameplate capacity under construction. Cheniere completed construction of the Stage Three expansion project at its Corpus Christi LNG export terminal, expanding capacity by 1.3 Bcf/d, as of August 31, 2026 (reading [18]). FERC staff issued a draft environmental impact statement on September 18, 2026, for the Corpus Christi Liquefaction Stage 4 project proposing four new liquefaction trains with a maximum LNG liquefaction capacity of approximately 1,200 Bcf/y (3.3 Bcf/d) plus two 220,000 m³ storage tanks (reading [18]).

Venture Global filed a FERC application for an additional expansion of Plaquemines LNG that would increase the plant's total capacity to more than 7 Bcf/d over three construction phases (reading [18]). Catarus plans to add five liquefaction trains to the Commonwealth LNG export project in Cameron Parish, LA, following FID on the initial six-train project, with the expansion entering service in the early 2030s for a total plant capacity of 2.3 Bcf/d (reading [18]). The U.S. Army Corps of Engineers granted fast-tracked permitting to the Plaquemines LNG expansion under the national energy emergency, shortening the public comment period for a project that would expand liquefaction capacity by 2.5 Bcf/d (reading [18]).

The thesis: construction timelines are predictable once FERC approval is granted, but permitting is the binding constraint. The gap between filing a FERC application and receiving a draft EIS is 12-24 months; the gap between draft EIS and final approval is another 6-12 months. Fast-tracked permitting under national energy emergency declarations can compress this by 6-9 months, but only for projects with existing FERC dockets. New projects filed in 2027 will not enter service until 2031-2032 at the earliest. Watch the FERC docket at https://www.ferc.gov for new filings and draft EIS publications. The next wave of LNG capacity is visible in the permitting queue now, not in the construction announcements.

East Daley estimates that by January 2029, Permian crude production reaches approximately 7.9 million barrels per day, effectively matching the basin's estimated 7.89 million barrels per day of nameplate long-haul takeaway capacity (reading [17]). Right now, crude pipelines bound for Corpus Christi are 99.7% utilized, while Houston-bound pipes are 91.7% utilized, per the latest T-1 filings at the Texas Railroad Commission (reading [17]). The Permian-to-Cushing corridor is 68.2% utilized (reading [17]). East Daley estimates only about 500,000 barrels per day of capacity remains on the more direct routes from the Permian toward Gulf Coast markets (reading [17]). Plainview Energy Analytics puts the figure at 500,000 to 600,000 barrels per day of remaining capacity through brownfield expansions and latent capacity before pipelines hit their limits (reading [17]).

Gray Oak wrapped up a two-part 120,000 b/d expansion in May, and Plains All American completed its 75,000 b/d expansion of Cactus III, which went into service in August (reading [17]). That is 195,000 b/d of new capacity in 2026. If Permian production grows by 400,000 b/d per year—a conservative estimate given recent trends—the basin has less than two years of headroom before pipelines are full and WTI Midland basis to WTI Cushing blows out.

The thesis: Permian basis differentials will widen sharply in 2028-2029 unless new pipeline projects are announced and permitted in the next 12 months. WTI Midland is assessed for physical delivery at the Enterprise and Plains terminals at Midland, Texas, with typical specifications of 42.2 API gravity and 0.13% sulfur (reading [4]). When takeaway capacity binds, Midland basis to Cushing will move from minus $0.50-$1.00 per barrel to minus $3.00-$5.00 per barrel, and Permian producers will either curtail drilling or pay the basis. The market is not pricing this yet because the weekly EIA production data is lagged and the T-1 filings are not widely tracked. But the constraint is visible in the data now.

U.S. operable atmospheric distillation capacity totaled 18.2 million barrels per calendar day on January 1, 2026, down over 250,000 b/cd (about 1%) from January 1, 2025 (reading [20]). That is a rounding error at the national level. But PADD 5 tells a different story. Phillips 66 ceased operations at its 138,700-b/cd Los Angeles refinery in October 2025; Valero's 145,000 b/d Benicia refinery ceased refining operations, with capacity removed from monthly estimates beginning in March 2026 (reading [20]). The Phillips 66 closure alone marks a 5% reduction in refinery capacity on the West Coast (reading [20]).

The reason this matters is pipeline geography. Relatively little pipeline capacity exists to supply petroleum products from large refinery hubs on the U.S. Gulf Coast to the West Coast, which means reductions in refinery capacity on the West Coast can have a larger impact on fuel availability in the region compared with other regions in the United States (reading [20]). On the Gulf Coast, the closure of the LyondellBasell Houston refinery (263,776 b/cd) reduced regional capacity by about 3%, but offset by marginal capacity increases at other facilities, regional capacity decreased by less than 2% in 2025 (reading [20]). PADD 3 has spare capacity and interconnected pipelines; PADD 5 does not.

This is not an energy transition story. It is a regional supply adequacy story. West Coast gasoline and diesel prices will decouple from Gulf Coast prices whenever demand tightens or imports are delayed, because the arbitrage that works in PADD 1 and PADD 2—where product can move from the Gulf Coast via pipeline—does not work in PADD 5. The thesis: watch PADD 5 crack spreads and days of supply separately from U.S. totals. When the next West Coast refinery announces a turnaround or a closure, the impact will show up in regional basis, not in national utilization rates.

Thesis: The IEA's October Oil Market Report projects world oil demand falling 2.6 mb/d on average in 2026, while supply declines 5.8 mb/d to 100.7 mb/d this year, then rises 7.7 mb/d in 2027 (reading [8]). If demand stays weak and supply rebounds that sharply, 2027 will see a structural surplus larger than any year since the COVID demand collapse. The IEA notes observed inventories edged down only 10 mb in September as a 113 mb on-land draw was offset by a surge in oil on water—floating storage is already rising.

Reasoning: EIA's October STEO (reading [6]) forecasts Brent averaging $96/bbl in 2026 and $84/bbl in 2027, a $12 drop. That's consistent with a loosening market, but may understate the downside if IEA's supply rebound materializes. U.S. production is forecast at 13.9 mb/d in 2026 and 14.3 mb/d in 2027—a 400 kb/d gain. Major U.S. producers are holding capital discipline: Chevron guided to the lower end of its $18–19 billion capex range, EOG at a $6.5 billion midpoint (reading [5]). If OPEC+ tries to bring back curtailed barrels into a 7.7 mb/d supply surge, the market breaks.

What to watch: Cushing stocks were 26,607 thousand barrels for the week ending October 9, 2026; total U.S. commercial crude was 415,577 thousand barrels (reading [1]). If Cushing builds above 30,000 thousand barrels by year-end and WTI-Brent spread widens, it confirms the U.S. is absorbing the surplus first. Floating storage and contango structure will be the early warnings.

Source: Reading [8] (IEA Oil Market Report), Reading [6] (EIA STEO), Reading [1] (EIA Weekly Petroleum Status Report), Reading [5] (producer earnings)

Thesis: FERC's simultaneous release on October 15, 2026 of updated certificate policy, interim GHG guidance, a blanket-authorization NOPR for LNG facilities, and three major project final EISs (CP2, Rio Grande, Golden Pass amendment) marks a deliberate regulatory reopening after months of stalled approvals. The blanket authorization proposal (Docket RM26-2-001) is the structural tell—it would allow routine LNG plant activities without case-by-case orders, a framework that only makes sense if FERC expects a sustained pipeline of projects.

Reasoning: The timing is coordinated. Staff doesn't issue final EISs for CP2 and Rio Grande (post-remand) on the same day the Commission grants Golden Pass an amendment and proposes blanket rules by accident. This is a policy package. The updated certificate policy (PL18-1) and interim GHG framework (PL21-3) set the substantive guardrails; the blanket NOPR sets the procedural fast lane.

Market implication: Developers who paused FID decisions waiting for regulatory clarity now have a line of sight. The IEA's October Gas Market Report notes that LNG flows through Hormuz remain "well below pre-conflict levels" even after the June U.S.-Iran interim agreement (reading [8]). If FERC's new posture accelerates U.S. export capacity additions in 2028–2030, it directly addresses the supply gap the IEA identifies. Watch for a wave of section 3 filings in Q4 2026 and Q1 2027 as sponsors test the new framework.

Source: Reading [3] (FERC orders), Reading [8] (IEA Gas Market Report)

Electric vehicles and plug-in hybrids rose from 4% of all new car sales in 2020 to 25% in 2025 worldwide, according to the IEA (reading 7). Global EV sales reached 2.15 million vehicles in September 2026, with year-to-date volumes at 15.5 million units up 3% from the same period in 2025 (reading 7). Expanding EV adoption continues to reduce oil demand, with oil displacement growing by 30% to over 1.3 mb/d in 2024 (reading 7). By the end of the decade, EVs are set to displace over 5 mb/d of diesel and gasoline in the STEPS, and China's EVs to account for half of displaced oil (reading 7). Electric LDVs drive most of the oil displacement, accounting for 80% today and around 77% by 2030 (reading 7).

Reasoning: Refinery configurations turn on five-to-seven-year capital cycles. A 5 mb/d displacement by 2030 means gasoline and diesel demand peaks are already behind us in key markets, but refinery capacity adjustments lag. China accounts for half the displaced oil, so watch Asian gasoline crack spreads compress first as domestic EV penetration climbs and export arb windows narrow. U.S. Gulf Coast refiners face margin pressure on gasoline while distillate cracks hold firmer given slower electrification of trucking (electric trucks and buses displace nearly 1 mb/d by 2030, reading 7, but that's 23% of total displacement). Crack spread divergence between RBOB and ULSD widens through 2028. Refinery utilization rates and turnaround schedules will reflect the new demand curve before run cuts show up in EIA weekly data.

Morgan Stanley estimates a 32 GW US data center power deficit through 2028 (reading 2). ERCOT reports interconnection queue requests total about 474 GW, approximately 90 percent from data centers, though Wood Mackenzie expects grid operators will realistically commit to only around 28% of the 1,000+ GW requested (reading 2). BloombergNEF projects U.S. data center power demand could reach 106 GW in 2035 (reading 2).

EPA Administrator Lee Zeldin signed the final Partial Repeal of the Carbon Pollution Standards for Fossil Fuel-Fired Electric Generating Units on September 14, 2026, repealing emission guidelines for existing coal-, oil-, and gas-fired steam generating units and CCS-based standards (reading 3). EPA also extended compliance deadlines for coal-fired power plants in the Steam Electric Power Generating category on December 23, 2025 (reading 3).

Reasoning: Even with regulatory relief extending coal plant operating windows, the scale of new load dwarfs the capacity freed up. If operators commit to 28% of 1,000 GW queued, that's 280 GW of new demand against a deficit already estimated at 32 GW through 2028. Coal extensions buy time but don't solve for incremental baseload or dispatchable capacity at this scale. Natural gas generation becomes the marginal supply source for data center builds that clear interconnection, tightening regional gas basis and peak power prices in ERCOT, PJM, and MISO through 2030. Watch Henry Hub cash versus forward curves and spark spreads in zones with cluster interconnection approvals.

The Phillips 66 Los Angeles closure in October 2025 (138,700 b/cd) and Valero Benicia shutdown in March 2026 (145,000 b/d) removed 284,000 b/d of West Coast refining capacity in six months, a 5% reduction in PADD 5 capacity per EIA. Combined with the LyondellBasell Houston closure in March 2025 (263,776 b/cd), U.S. operable atmospheric distillation capacity fell to 18.2 million b/cd on January 1, 2026, down over 250,000 b/cd year-on-year.

EIA notes that relatively little pipeline capacity exists to supply petroleum products from Gulf Coast refinery hubs to the West Coast, meaning reductions in West Coast refinery capacity have a larger impact on fuel availability in the region compared with other regions. The closures are permanent: Phillips 66 and Valero cited state environmental mandates and declining gasoline demand as drivers, not refining margins.

Reasoning: West Coast gasoline and diesel now depend on waterborne imports from Asia (South Korea, India, China) and occasional arbitrage cargoes from the Gulf Coast via Panama. The region's refining capacity is shrinking faster than demand, but the gap is filled by imports, not new builds. PADD 5 product prices will trade at a structural premium to Gulf Coast and Midcontinent markets, bounded by the cost of imports plus freight. The closure wave is over for now—no other West Coast refineries have announced shutdowns—but the region's refining base is permanently smaller.

East Daley's January 2029 collision point—when Permian crude production reaches ~7.9 MMb/d against 7.89 MMb/d of nameplate long-haul capacity—marks the end of the basin's brownfield runway. The 500 Mb/d of remaining capacity to Gulf Coast markets cited by East Daley and Plainview Energy Analytics (500–600 Mb/d) represents the last buffer before producers face structural takeaway constraints, not weather or maintenance-driven bottlenecks.

The utilization split tells the story: Corpus Christi-bound pipes at 99.7%, Houston at 91.7%, Cushing at 68.2% per Texas Railroad Commission T-1 filings. Gray Oak's 120 Mb/d expansion wrapped in May 2026 and Plains' 75 Mb/d Cactus III addition in August bought time, but no greenfield projects of scale are under construction. The Permian-to-Cushing corridor still has room, but Cushing is a storage hub, not a demand center—moving barrels north solves logistics, not netbacks.

Reasoning: If production grows 300–400 Mb/d annually (typical Permian cadence), the 500 Mb/d cushion disappears in 15–18 months, not three years. Differentials will widen before pipes hit 100%; traders price the constraint when utilization crosses 95%, not when it maxes out. Permian producers will face a choice: accept wider basis to Cushing, curtail drilling, or wait for the next wave of Gulf Coast capacity—which has no FID dates yet.

Days of supply is supposed to be a simple ratio: stock level divided by monthly consumption, times 30 (reading [1]). But the denominator—what counts as consumption—is where the method fractures. The IEA uses daily net imports for emergency reserve cover (reading [1]). BrentChart.com uses forward OECD daily demand for commercial stocks (reading [1]). UKOilWatch uses monthly consumption (reading [1]). These are not interchangeable.

Net imports as the denominator makes sense for import-dependent countries measuring strategic cover, but it overstates days of supply for a net exporter and understates it for a country whose imports swing seasonally. Forward demand as the denominator is forward-looking, which matters if you are trying to assess whether stocks are adequate for next quarter's demand, but it requires a demand forecast, which introduces model risk. Trailing monthly consumption is backward-looking and smooth, but it misses demand inflections—a mild winter or a refinery outage that cuts gasoline demand will make days of supply look artificially high.

The method also breaks when stocks include barrels that are not available for consumption. EIA inventory data includes crude in transit and pipeline fill, but excludes floating storage for which complete information is not available (reading [5]). Kpler and other consultancies track floating storage in real time via satellite (reading [5]), but that data is not in the weekly EIA release. The Strategic Petroleum Reserve is excluded from the seasonal commercial curve (reading [5]), but SPR releases or refills move the headline inventory number without changing the commercial supply available to the market.

Days of supply is useful for comparing the same region to its own history using a consistent denominator. It is not useful for comparing across regions or for inferring tightness when the stock composition or demand trajectory is changing.

EIA's operable utilization rate—gross input divided by operable capacity—bakes maintenance into the denominator, which means a refiner running flat out during a light turnaround season and a refiner cutting runs on weak margins can both print 90% and look identical in the weekly data. The rate accounts for scheduled downtime but does not separate economic run decisions, per EIA methodology (reading [4]).

This matters because the two scenarios have opposite implications for crack spreads. A high utilization rate during a light maintenance season (470,000 bpd average shutdowns January–May 2026 versus 700,000 bpd the prior year, per Energy Aspects data in reading [4]) signals that refiners are deferring turnarounds because margins justify it—bullish for crude demand, bearish for product prices. A high rate during a heavy maintenance season with refiners still cutting runs means cracks are too weak to cover variable costs—bearish for crude, bullish for products.

Consultancies like Energy Aspects, IIR Energy, and Kpler track planned turnaround schedules separately to distinguish maintenance-driven utilization changes from margin-driven run cuts (reading [4]). Without that layer, the headline utilization number is a blunt instrument. Operators moving fall 2026 turnarounds into 2027 because utilization near 95% incentivizes deferral (reading [4]) tells you margins are strong enough to justify the risk of running longer between outages. The weekly EIA number alone does not.

For anyone trading the crack or trying to forecast product balances, the turnaround calendar is the prior. Utilization is the residual.

WTI Midland crude is assessed for physical delivery at the Enterprise and Plains terminals at Midland, Texas, as Permian-quality WTI with typical specifications of 42.2 API gravity and 0.13% sulfur (reading [4]). Platts requires sulfur of 0.2% or less by weight, API gravity not less than 40 nor more than 44 degrees (reading [4]). WTI Houston (MEH) assessments cover WTI Midland-quality crude delivered FIP at the Magellan East Houston terminal in Houston, Texas (reading [4]).

Mars is a medium sour crude blend with typical specifications of 28-29.7 API gravity and 1.87-1.93% sulfur, assessed for delivery via the Mars pipeline system to Clovelly, Louisiana (reading [4]). Argus Mars reflects spot prices for the US Gulf medium sour crude blend arriving on the Mars pipeline, with typical quality of 29.7 API and 1.95% sulfur (reading [4]).

Cushing, Oklahoma, serves as the delivery point for the NYMEX Light Sweet Crude Oil futures contract with over 90 million barrels of storage capacity (reading [4]). But Cushing is no longer where Permian barrels price. The Midland-to-Houston corridor—via Enterprise, Plains, Magellan—is now the physical market for Permian light sweet. The spread between WTI Midland at the wellhead and WTI Houston at the export terminal is a pure infrastructure play: pipeline capacity, storage at either end, and the cost to move 500,000 or 5 million barrels in a week.

The structural claim: U.S. crude now has two pricing regimes. Permian light sweet prices off Midland and Houston, with Cushing as a financial settlement fossil. Gulf medium sour prices off Mars at Clovelly. The spread between them is not a quality differential you can hedge with a refinery yield curve. It is a basin, a pipeline map, and an export queue. If you are still modeling U.S. crude as "WTI versus Brent," you are missing the domestic arb that moves first.

EIA releases the Weekly Natural Gas Storage Report at 10:30 a.m. Eastern Time each Thursday with working gas estimates as of 9:00 a.m. Central Standard Time on the Friday of the previous week (reading [2]). NOAA's Climate Prediction Center publishes daily heating and cooling degree days with 7-day forecasts and 1981-2010 normals (reading [3]). FERC requires interstate pipelines to post flow volume and capacity data daily on their websites in downloadable formats, available for at least 90 days, under Form 551 (reading [5]).

No single agency publishes the integrated view a fundamentals desk needs: storage position, weather actuals versus normal, and pipeline utilization in the same reporting week. The Thursday 10:30 release tells you what was in the ground nine days earlier. The degree-day forecast tells you what demand should do. The pipeline postings—scattered across dozens of operator websites, each with different formats and retention windows—tell you whether molecules are moving to where the weather is.

This is not an accident of bureaucracy. It reflects the way energy markets were regulated before real-time data mattered to price discovery. Storage was a monthly inventory problem (EIA-191). Weather was a climatology question. Pipeline capacity was a certificate proceeding. The weekly 912 sample, covering 80-85 respondents and at least 90% of volumes in each stratum (reading [2]), was built for federal statistics, not trading signals.

The structural claim: any firm that can automate the triangulation—scraping pipeline postings, normalizing degree days by census division, and modeling the nine-day lag in the storage print—has an edge that comes from data engineering, not better weather or storage opinions. The opinion is table stakes. The architecture is the alpha.

Facts read directly off the source pages in the browser, each resting on a sentence quoted from the page.

• United States propane stocks stood at 106.4 million barrels as of Oct 9, 2026, 4.8% above the 5-year median of 101.5 million barrels for this point in the year. (The Fill Line, 2026-10-09)
• Nationally the low comes at the end of the heating season, ordinarily March, after five months of draw. (The Fill Line, 2026-10-09)
• The West North Central census division comprises Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, and South Dakota. (FRED/St. Louis Fed)
• For the week ending October 30, 2025, the West North Central region had 118 heating degree days. (NOAA CPC, 2025-11-01)

What moved on the energy beat in the seven days to 2026-10-19, and what is scheduled next.

• On October 15, 2026, the U.S. Energy Information Administration released Wholesale Electricity Market Data through October 13, 2026. (U.S. Energy Information Administration, 2026-10-15)
• On October 15, 2026, the Federal Energy Regulatory Commission issued Order No. 1920-A affirming and modifying its long-term transmission planning rule with expanded state regulator provisions. (Federal Energy Regulatory Commission, 2026-10-15)
• On October 16, 2026, the U.S. Department of Energy announced selection of 38 research projects across 21 states and Puerto Rico to receive a combined $36 million through the Established Program to Stimulate Competitive Research. (U.S. Department of Energy, 2026-10-16)
• The U.S. Energy Information Administration schedules the Weekly Natural Gas Storage Report for release every Thursday at 10:30 a.m. Eastern Time. (U.S. Energy Information Administration)
• The U.S. Energy Information Administration schedules the next Short-Term Energy Outlook for release on November 10, 2026. (U.S. Energy Information Administration, 2026-10-15)
• The U.S. Energy Information Administration schedules the Heating Oil & Propane Update for release every Wednesday at 1:00 p.m. Eastern Time from October through March. (U.S. Energy Information Administration)

Research for the week of 2026-10-19. Propane distributors and utilities in the West North Central region face a sharp demand surge as heating degree days climb 700% in 30 days, signaling earlier-than-normal inventory draws and potential supply tightness if the cold persists.

• PADD 2 propane/propylene stocks (excluding propylene at terminal) were 25,685 thousand barrels for the week ending October 9, 2026. (EIA, 2026-10-15)
• PADD 2 (Midwest) propane stocks were 25.7 million barrels for the week ending October 9, 2026, 5.1% below the five-year median. (The Fill Line, 2026-10-09)
• The West North Central census division comprises the states of Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, and South Dakota. (FRED/St. Louis Fed)
• Nationally, propane inventories typically reach their seasonal low at the end of the heating season in March. (The Fill Line, 2026-10-09)
• West North Central region heating degree days totaled 118 for the week ending October 30, 2025. (NOAA CPC, 2025-11-01)
• Wholesale propane spot prices at Conway, Kansas were shown in charts with data through October 7, 2026. (EIA, 2026-10-09)

• World oil demand is forecast to fall by 2.5 mb/d y-o-y in 4Q26 and 2.6 mb/d on average in 2026. (IEA, 2026-10-14)
• Oil supply is projected to post an average annual decline of 5.8 mb/d, to 100.7 mb/d, this year, before reversing course and rising by 7.7 mb/d in 2027. (IEA, 2026-10-14)
• Global observed oil inventories edged down by 10 mb in September as a further 113 mb decline in on-land stocks was largely offset by a surge in oil on water. (IEA, 2026-10-14)
• The Middle East conflict has profoundly distorted the global natural gas market... flows of LNG cargoes through the Strait of Hormuz have been on the rise since the United States and Iran reached an interim peace agreement in June, they remain well below pre-conflict levels. (IEA)

• On June 15, 2026, Xcel Energy filed an application with the Colorado Public Utilities Commission to approve a portfolio of resources for 2027-2028 needs, including extension of Comanche Unit 2 coal plant retirement from December 31, 2026, to March 31, 2028. (Colorado Public Utilities Commission, 2026-10-14)
• On September 28, 2026, Xcel Energy filed an unopposed settlement agreement in Colorado PUC Proceeding 26A-0235E recommending Commission approval of a modified portfolio including operating Comanche Unit 2 through December 31, 2027, with limits on operation. (Colorado Public Utilities Commission, 2026-10-14)
• The California Public Utilities Commission requires load-serving entities to procure 6,000 MW of new net qualifying capacity from non-emitting, storage, and/or RPS-eligible resources, with 2,000 MW due online by June 1, 2030, and an additional 4,000 MW by June 1, 2032. (California Public Utilities Commission, 2026-03-02)

• The October 2026 Short-Term Energy Outlook (released October 6, 2026) forecasts the Brent crude oil spot price to average $96 per barrel in 2026 and $84 per barrel in 2027. (U.S. Energy Information Administration, 2026-10-06)
• The October 2026 Short-Term Energy Outlook forecasts U.S. crude oil production to average 13.9 million barrels per day in 2026 and 14.3 million barrels per day in 2027. (U.S. Energy Information Administration, 2026-10-06)
• The October 2026 Short-Term Energy Outlook forecasts U.S. liquid fuels consumption to average 20.6 million barrels per day in 2026 and 20.8 million barrels per day in 2027. (U.S. Energy Information Administration, 2026-10-06)
• The October 2026 Short-Term Energy Outlook forecasts the U.S. retail gasoline price to average $3.91 per gallon in 2026 and $3.56 per gallon in 2027. (U.S. Energy Information Administration, 2026-10-06)
• The October 2026 Short-Term Energy Outlook forecasts the U.S. retail diesel fuel price to average $5.19 per gallon in 2026 and $4.49 per gallon in 2027. (U.S. Energy Information Administration, 2026-10-06)
• The October 2026 Short-Term Energy Outlook forecasts the WTI crude oil spot price to average $88 per barrel in 2026 and $80 per barrel in 2027. (U.S. Energy Information Administration, 2026-10-06)

• ExxonMobil reported second-quarter 2026 earnings of $14.5 billion GAAP and $14.7 billion adjusted, with year-to-date cash capital expenditures of $13.0 billion. (ExxonMobil, 2026-07-31)
• Chevron reported second-quarter 2026 earnings of $12.1 billion GAAP and $12.0 billion adjusted, with organic capital expenditures of $4.4 billion for the quarter and full-year guidance at the lower end of its $18 billion to $19 billion range. (Chevron, 2026-07-31)
• ConocoPhillips reported second-quarter 2026 earnings of $3.9 billion GAAP and $4.0 billion adjusted, with capital expenditures and investments of $3.0 billion for the quarter and full-year guidance items reaffirmed. (ConocoPhillips, 2026-08-06)
• EOG Resources reported second-quarter 2026 net income of $2.72 billion and adjusted net income of $2.68 billion, with free cash flow of $2.8 billion and full-year 2026 capital expenditures guidance at a $6.5 billion midpoint. (EOG Resources, 2026-08-04)
• Chevron's Q2 2026 earnings call summary noted $19.7 billion cash flow from operations excluding working capital and $15.4 billion adjusted free cash flow. (StockAnalysis, 2026-07-31)

• NERC’s 2026 Summer Reliability Assessment finds that record resource additions have strengthened readiness for the summer season, even as elevated risks remain in some areas. (North American Electric Reliability Corporation)
• All areas are assessed as having adequate anticipated resources for normal summer peak load conditions. (North American Electric Reliability Corporation)
• In 2026, only three regions and one locality are at-risk for supply shortfalls in abnormal summer conditions, down from six regions in 2025. (North American Electric Reliability Corporation)
• The North American bulk power system (BPS) continued to perform reliably in 2025 even as the grid experienced increasing operational complexity. (North American Electric Reliability Corporation, 2026-06-24)
• Major weather events in 2025, including severe winter storms, thunderstorms, and tornadoes, were analyzed and collectively found to have had less of an impact on the BPS than in previous years. (North American Electric Reliability Corporation, 2026-06-24)
• NERC’s 2025–2026 Winter Reliability Assessment finds that while all areas are assessed as having adequate resources for normal winter peak-load conditions, more extreme winter conditions extending over a wide area could result in electricity supply shortfalls. (North American Electric Reliability Corporation)

• On October 15, 2026, FERC issued two policy statements updating its certificate policy for new interstate natural gas projects under NGA section 7 and an interim GHG policy for pipeline and LNG projects (Docket Nos. PL18-1, PL21-3). (Federal Energy Regulatory Commission, 2026-10-15)
• On October 15, 2026, FERC issued a Notice of Proposed Rulemaking (NOPR) to establish a blanket authorization program for certain activities at LNG plants under NGA sections 3 and 7 without case-specific orders (Docket No. RM26-2-001). (Federal Energy Regulatory Commission, 2026-10-15)
• On October 15, 2026, FERC staff issued the final EIS for the CP2 LNG and CP Express Projects (Docket Nos. CP22-21-000, CP22-22-000) proposed by Venture Global entities in Louisiana and Texas. (Federal Energy Regulatory Commission, 2026-10-15)
• On October 15, 2026, FERC issued an order amending Louisiana LNG Infrastructure LLC’s NGA section 3 authorization and vacating in part Driftwood Pipeline LLC’s section 7 certificate for the KMLP Interconnect (Docket Nos. CP26-537-000, CP17-118-000). (Federal Energy Regulatory Commission, 2026-10-15)
• On October 15, 2026, FERC staff issued the final supplemental EIS for the Rio Grande LNG Terminal and Rio Bravo Pipeline Project to address a D.C. Circuit remand (Docket Nos. CP16-454-000 et al.). (Federal Energy Regulatory Commission, 2026-10-15)
• On October 15, 2026, FERC granted Golden Pass LNG Terminal LLC’s requested amendment of its 2016 NGA section 3 authorization for the Golden Pass LNG export terminal (Docket No. CP14-517-001). (Federal Energy Regulatory Commission, 2026-10-15)

• Working gas in underground storage in the Lower 48 states was 3,567 Bcf as of October 9, 2026, according to EIA estimates, a net increase of 67 Bcf from the prior week. (U.S. Energy Information Administration, 2026-10-15)
• Stocks of 3,567 Bcf on October 9, 2026 were 143 Bcf less than the same week in 2025 and 45 Bcf (1.3%) above the five-year (2021-25) average of 3,522 Bcf. (U.S. Energy Information Administration, 2026-10-15)
• The EIA estimates U.S. natural gas inventories at 3,523 Bcf at the end of September 2026, with a forecast build of 328 Bcf in October to reach 3,850 Bcf at end-October 2026, 2% above the five-year average. (U.S. Energy Information Administration, 2026-10-15)
• Weekly working gas totals for the Lower 48 states were 3,254 Bcf on September 4, 2026; 3,298 Bcf on September 11; 3,351 Bcf on September 18; 3,415 Bcf on September 25; 3,500 Bcf on October 2; and 3,567 Bcf on October 9. (U.S. Energy Information Administration, 2026-10-15)

• For the week ending October 9, 2026, U.S. commercial crude oil stocks excluding the Strategic Petroleum Reserve were 415,577 thousand barrels. (U.S. Energy Information Administration, 2026-10-15)
• Crude oil stocks at Cushing, Oklahoma, were 26,607 thousand barrels for the week ending October 9, 2026. (U.S. Energy Information Administration, 2026-10-15)
• For the week ending October 9, 2026, total U.S. commercial petroleum inventories excluding the Strategic Petroleum Reserve were 1,224,016 thousand barrels. (U.S. Energy Information Administration, 2026-10-15)

• US LNG shipments to China halted in February 2025 following China's imposition of additional tariffs on US imports during the latest escalation in US-China trade tensions. (Kpler, 2026-10-15)
• US-China tariff cuts exclude key energy commodities including LNG, crude oil and coal, with tariffs on US LNG, coal and crude oil remaining at 25%, 25% and 20%, respectively. (World Ports Organization, 2026-10-15)
• Trump’s 25% tariffs on steel and aluminum, heavily used at LNG facilities, have complicated construction of new US LNG export plants and could raise costs by about 1% for projects like CP2. (World Energy News, 2026-10-17)
• The Energy Department approved the final export authorization for the Venture Global CP2 LNG Project allowing exports of up to 3.96 billion cubic feet per day of natural gas as LNG to non-FTA countries. (Department of Energy, 2025-10-22)
• The White House issued an executive order implementing the Lindsey O. Graham Sanctioning Russia and Iran Act of 2026, increasing the rate of duty on goods from the Russian Federation by 500% ad valorem. (The White House, 2026-10-17)

• Worldwide, electric vehicles and plug-in hybrids rose from 4% of all new car sales in 2020 to 25% in 2025, according to the IEA. (Pew Research Center, 2026-05-28)
• Global EV sales reached 2.15 million vehicles in September 2026, with year-to-date volumes at 15.5 million units up 3% from the same period in 2025. (Reuters, 2026-10-15)
• Expanding EV adoption continues to reduce oil demand, with oil displacement growing by 30% to over 1.3 mb/d in 2024. (IEA)
• By the end of the decade, EVs are set to displace over 5 mb/d of diesel and gasoline in the STEPS, and China’s EVs to account for half of displaced oil. (IEA)
• Electric LDVs drive most of the oil displacement, accounting for 80% today and around 77% by 2030. (IEA)
• Electric trucks and buses together displace nearly 1 mb/d in the STEPS by 2030. (IEA)

• The U.S. Department of Energy closed a $1.6 billion loan guarantee under the Energy Dominance Financing Program to a subsidiary of American Electric Power to reconductor and rebuild around 5,000 miles of transmission lines across Indiana, Michigan, Ohio, Oklahoma, and West Virginia on October 16, 2025. (Department of Energy, 2025-10-16)
• DOE issued a final environmental assessment and finding of no significant impact on October 9, 2026, for potential federal loan guarantee assistance supporting construction and operation of photovoltaic energy generation and battery energy storage system facilities in Puerto Rico. (Department of Energy, 2026-10-09)
• The Office of Energy Dominance Financing manages a portfolio of loan guarantee programs with billions of dollars in loan authority available for projects in advanced vehicle manufacturing and supply chains, tribal energy development, critical materials production, energy infrastructure revitalization, and grid enhancement and resilience. (Department of Energy, 2026-02-12)
• The Energy Dominance Financing Program (Section 1706) guarantees loans to projects that retool, repower, repurpose, or replace energy infrastructure that has ceased operations, enable operating energy infrastructure to increase capacity and output, or support provision of electric supply to maintain or enhance grid reliability. (Department of Energy)
• The Energy Infrastructure Reinvestment Financing program authorizes up to $250 billion in loan guarantees supported by $5 billion in credit subsidy appropriations under section 1706 of the Energy Policy Act of 2005, with authority to remain available for commitment through September 30, 2026. (Department of Energy, 2026-03-23)
• As of September 30, 2025, under the Section 1706 program DOE obligated approximately $19.2 billion for five closed loans and disbursed approximately $1.9 billion in FY 2025, with another $28.7 billion in conditional commitments issued to 12 prospective borrowers. (Department of Energy, 2025-12-12)

• On 6 September 2026, seven OPEC+ countries (Saudi Arabia, Russia, Iraq, Kuwait, Kazakhstan, Algeria, and Oman) decided to maintain their September 2026 required production levels for October 2026. (Organization of the Petroleum Exporting Countries, 2026-09-06)
• OPEC+ agreed on 4 October 2026 to keep oil production targets steady for November at the levels set for September and October. (Reuters, 2026-10-04)
• The seven core OPEC+ members pumped 25 million barrels per day in August 2026, up 630,000 bpd from July but roughly 5 million bpd below prewar February levels. (Reuters, 2026-10-04)
• OPEC+ pumped an average of 39.07 million barrels per day in September 2026, up about 900,000 bpd from August, according to secondary sources. (Reuters, 2026-10-13)
• Gulf OPEC+ producers have been pumping well below output targets, with exports fluctuating at 60% to 80% of normal levels in recent months due to disruptions from the US-Israeli war on Iran. (Reuters, 2026-10-04)
• OPEC+ still has about 2 million bpd of output cuts in place covering most members, with a capacity review needed to decide 2027 quotas delayed by uncertainty over future production potential. (Reuters, 2026-10-04)

• Public Law 119-21 eliminates the section 45V clean hydrogen production credit for facilities beginning construction after 2027. (Internal Revenue Service, 2026-10-17)
• For 2025, the section 45V applicable amount ranges from $0.127 per kg (2.5 to not greater than 4.0 kg CO2e per kg H2) to $0.637 per kg (less than 0.45 kg CO2e per kg H2), multiplied by 5.0 if prevailing wage and apprenticeship requirements are met. (Internal Revenue Service, 2026-10-17)
• A verification report from an unrelated party and, if applicable, DOE emissions value documentation must be attached to claim the section 45V credit on Form 7210. (Internal Revenue Service, 2026-10-17)
• Final rules for the section 45V credit require Energy Attribute Certificates used for electricity attribution to meet incrementality, deliverability, and temporal matching criteria, with annual matching permitted through 2029 and hourly matching required starting in 2030. (U.S. Department of the Treasury, 2025-01-03)
• For calendar year 2026, the section 45Y clean electricity production credit applicable amount is 0.6 cents per kWh (base) or 3.1 cents per kWh (alternative amount if requirements met), after inflation adjustment. (Internal Revenue Service, 2026-10-05)
• Qualified clean hydrogen for the section 45V credit must be produced through a process resulting in lifecycle greenhouse gas emissions of not greater than 4 kg CO2e per kg of hydrogen. (Internal Revenue Service, 2026-10-17)

• On September 14, 2026, EPA Administrator Lee Zeldin signed the final Partial Repeal of the Carbon Pollution Standards for Fossil Fuel-Fired Electric Generating Units. (US EPA)
• On December 23, 2025, the EPA published the final Deadline Extensions Rule, an action that extended compliance deadlines for coal-fired power plants in the Steam Electric Power Generating category (40 CFR Part 423). (US EPA)
• This final rule allows facilities more time to assess potential compliance pathways to continue producing low-cost electricity into the future while meeting wastewater standards. (US EPA)
• The final Partial Repeal repeals the emission guidelines for existing coal-, oil-, and gas-fired steam generating units; the CCS-based standards for coal-fired EGUs undertaking a large modification; and the CCS-based standards for new base load stationary combustion turbines. (US EPA)
• EPA supplemented the September 14, 2026 final rule with the proposed Rescission of the Greenhouse Gas Findings for Fossil Fuel-Fired Power Plants and Repeal of Regulations for Power Plant Greenhouse Gas Emissions Under Clean Air Act Section 111. (US EPA)

• Global datacenter power demand capacity will reach 161GW in 2026, up by 31% YoY, mainly driven by AI servers. (EE Times Asia (TrendForce), 2026-10-08)
• U.S. data center power demand could reach 106 GW in 2035, BloombergNEF said. (Utility Dive (BloombergNEF), 2025-12-03)
• Interconnection queue requests total about 474 GW, approximately 90 percent of the new power requests are data centers. (Utility Dive (ERCOT/Abbott letter), 2026-08-05)
• US grid operators are sitting on more than 1,000 gigawatts of data centre interconnection requests, but will realistically commit to only around 28% of that figure. (Capacity (Wood Mackenzie), 2026-08-25)
• Morgan Stanley estimates a 32 GW US data centre power deficit through 2028. (BW Businessworld (Morgan Stanley), 2026-10-17)
• The global electricity demand of data centres grew by 17% in 2025. (IEA, 2026-10-17)

• The predominant factor driving the recent pickup in headline inflation is energy prices, including gasoline and diesel costs. (Federal Reserve Board, 2026-10-01)
• I remain concerned about the risk of higher energy prices leading to a persistent rise in inflation more broadly. (Federal Reserve Board, 2026-10-01)
• The current gap between 12-month inflation readings and the Federal Reserve’s 2% inflation goal mostly reflects elevated contributions from energy and core goods categories linked to the Middle East conflict and higher tariff rates. (Federal Reserve Bank of San Francisco, 2026-10-15)

• 53% of California-Nevada is in drought. (Drought.gov, 2026-10-16)
• Observed April–July natural inflow to Lake Powell was only 18% of average, and Reclamation's analysis placed total Water Year 2026 natural inflow at 3.52 million acre-feet, just 37% of the 1991–2020 average. (Drought.gov, 2026-10-15)
• Glen Canyon Dam was producing approximately 730 MW and Hoover Dam about 382 MW as of September 2026. (NAES, 2026-10-15)
• Lake Powell, the second largest reservoir in the United States, had fallen to record low levels by late August and early September 2026. (SciTechDaily, 2026-10-15)
• Major reservoirs across the Colorado River and Rio Grande basins entered Water Year 2027 at historically low levels. (Drought.gov, 2026-10-15)
• As of October 13, 2026, 45.05% of the United States and Puerto Rico and 53.73% of the Lower 48 states are in drought. (Drought.gov, 2026-10-15)

• The ERCOT Capacity, Demand and Reserves Report December 2025 states that the base scenario's summer 2026 Planning Reserve Margins are 18.3% for the peak Load hour (Hour Ending 5:00 p.m. Central Standard Time) and 20.9% for the peak Net Load hour (Hour Ending 9:00 p.m. CST). (ERCOT, 2025-12-19)
• The ERCOT Capacity, Demand and Reserves Report December 2025 projects that summer and winter Planning Reserve Margins for 2026 through 2030 decrease significantly from year to year under the base scenario, crossing to negative values in 2028. (ERCOT, 2025-12-19)
• The Monthly Outlook for Resource Adequacy (MORA) December 2026 reports that hourly reserve shortage risks are highest during morning hours, with the highest EEA probability of 2.95% at Hour Ending 8:00 a.m. CST, below the 10% elevated risk threshold. (ERCOT, 2026-10-02)
• The Monthly Outlook for Resource Adequacy (MORA) December 2026 states that under typical grid conditions the deterministic scenario indicates sufficient generating capacity for the highest-risk hour (HE 8 a.m. CST), with a monthly capacity reserve margin of 45.6%. (ERCOT, 2026-10-02)
• ERCOT no longer produces the Seasonal Assessment of Resource Adequacy (SARA) report and now prepares the Monthly Outlook for Resource Adequacy (MORA) instead. (ERCOT)

• The Appalachian basin produces about 35.5 Bcf/d while consuming 9 Bcf/d, leaving ~25 Bcf/d that has to leave every day, meaning pipeline capacity sets the price. (Aegis Hedging, 2026-10-16)
• Egress remains the binding constraint, with the Northeast-to-South corridor running at 89% of capacity over the past 30 days. (Aegis Hedging, 2026-10-16)
• Columbia Gas Transmission’s (TCO) Mountaineer XPress (MXP) outage cut MXP segment capacity to zero, affecting an estimated 1.9 million Dth/d of firm service. (Natural Gas Intelligence, 2026-10-16)
• For Friday gas, NGI’s Columbia Gas basis to Henry Hub strengthened 56.0 cents to minus $1.260/MMBtu, while Eastern Gas South and Texas Eastern M-2 discounts widened 38.5 and 42.5 cents, respectively. (Natural Gas Intelligence, 2026-10-16)
• Pennsylvania producers cannot get their gas out of the Basin, they have received, on average, 20% less for their natural gas than standard NYMEX and Henry Hub price benchmarks. (Marcellus Shale Coalition, 2026-10-16)
• From April to July 2026 the Appalachia regional average hub price was 77 cents/MMBtu below Henry Hub, the second-widest discount EIA has reported. (OilPriceAPI, 2026-10-04)

• Confirmed crossings of Saudi-loaded crude from Yanbu through Bab el-Mandeb have dropped to 6 vessels moving roughly 1.5 million barrels a day since the July 22 attacks, a decline of close to 50% from the pre-attack weekly average of around 3 million barrels a day. (Kpler, 2026-10-15)
• Kpler estimates Bab el-Mandeb oil flows fell from 5.45 million barrels a day in August to 2.56 million in September 2026 after the Houthi blockade of Saudi shipping and pipeline attacks. (Orbis, 2026-09-29)
• The Houthis declared a blockade of Saudi shipping including any ship loading or unloading at a Saudi port on July 20, 2026, and made 12 attacks or attempted attacks by September 22. (Orbis, 2026-09-29)
• Saudi crude exports through Bab el-Mandeb remain ongoing despite the Houthi embargo and a marked decline in transit volumes. (Kpler, 2026-10-15)
• An attempted attack on a tanker was reported south of Mokha, Yemen, near Bab el-Mandeb on October 16, 2026, with UKMTO advising vessels to proceed with caution. (The Maritime Executive, 2026-10-16)
• Yanbu port loading operations were briefly halted on October 1, 2026, after an unidentified projectile struck inside the port, though loading resumed. (DefenceWeb, 2026-10-16)

• U.S. operable atmospheric distillation capacity totaled 18.2 million barrels per calendar day (b/cd) on January 1, 2026, down over 250,000 b/cd (about 1%) from January 1, 2025. (U.S. Energy Information Administration, 2026-06-29)
• LyondellBasell ended refining operations at its 263,776-b/cd refinery in Houston in March 2025, and Phillips 66 ceased operations at its 138,700-b/cd refinery in Los Angeles in October 2025, for a combined reduction of about 400,000 b/d in operable U.S. refinery capacity. (U.S. Energy Information Administration, 2026-06-29)
• The Phillips 66 Los Angeles refinery closure marks a 5% reduction in refinery capacity on the West Coast (PADD 5). (U.S. Energy Information Administration, 2026-06-29)
• Valero’s 145,000 b/d Benicia refinery ceased refining operations, and its capacity was removed from monthly estimates beginning in March 2026. (U.S. Energy Information Administration, 2026-06-29)
• Relatively little pipeline capacity exists to supply petroleum products from large refinery hubs on the U.S. Gulf Coast to the West Coast, which means reductions in refinery capacity on the West Coast can have a larger impact on fuel availability in the region compared with other regions in the United States. (U.S. Energy Information Administration, 2026-06-29)
• On the U.S. Gulf Coast (PADD 3), the closure of the LyondellBasell Houston refinery reduced regional capacity by about 3%, but offset by marginal capacity increases at other facilities, regional capacity decreased by less than 2% in 2025. (U.S. Energy Information Administration, 2026-06-29)

• The CAISO’s probabilistic assessment of all Resource Adequacy eligible resources shows a surplus of 2,547 MW for meeting a 1-in-10 LOLE planning target. (California ISO)
• Since 2019, battery resources serving California grew from fewer than 700 megawatts to more than 23,000 megawatts. (Governor of California, 2026-10-13)
• Total battery storage capacity is 21,112 MW, an increase of more than 2,500% since 2019. (California Energy Commission, 2026-08-07)
• AES Alamitos and Huntington Beach, with a combined capacity of 1,368 MW, are scheduled to retire in 2026 as the largest natural gas retirements that year. (U.S. Energy Information Administration, 2026-02-23)
• Only about 3.3 GW of California’s roughly 40 GW gas-fired fleet is scheduled to retire by 2030. (East Daley Analytics, 2026-06-25)
• From September 1, 2025 through April 1, 2026, 2,127 MW of new resource adequacy eligible nameplate capacity was added to the CAISO grid, with an additional 6,194 MW expected by June 30, 2026. (California ISO)

• FERC staff issued a draft environmental impact statement on September 18, 2026, for the Corpus Christi Liquefaction Stage 4 project proposing four new liquefaction trains with a maximum LNG liquefaction capacity of approximately 1,200 Bcf/y plus two 220,000 m3 storage tanks on the La Quinta Ship Channel in Texas. (Federal Energy Regulatory Commission, 2026-09-18)
• Cheniere completed construction of the Stage Three expansion project at its Corpus Christi LNG export terminal, expanding capacity by 1.3 Bcf/d, as of August 31, 2026. (Aegis Market Insights, 2026-09-22)
• As of September 22, 2026, FERC lists the following Gulf Coast LNG export terminals as approved and under construction: Golden Pass (2.57 Bcfd, Sabine Pass TX), Plaquemines (3.76 Bcfd, Plaquemines Parish LA), Louisiana LNG (3.81 Bcfd, Calcasieu Parish LA), Corpus Christi Stage III & T 8-9 (2.75 Bcfd, Corpus Christi TX), Port Arthur LNG (3.72 Bcfd, Port Arthur TX), Rio Grande LNG (3.73 Bcfd, Brownsville TX), and CP2 (3.96 Bcfd, Cameron Parish LA). (Federal Energy Regulatory Commission, 2026-09-22)
• Catarus plans to add five liquefaction trains to the Commonwealth LNG export project in Cameron Parish, LA, following FID on the initial six-train project, with the expansion entering service in the early 2030s for a total plant capacity of 2.3 Bcf/d. (Aegis Market Insights, 2026-09-22)
• The U.S. Army Corps of Engineers granted fast-tracked permitting to the Plaquemines LNG expansion under the national energy emergency, shortening the public comment period for a project that would expand liquefaction capacity by 2.5 Bcf/d. (Aegis Market Insights, 2026-09-22)
• Venture Global filed a FERC application for an additional expansion of Plaquemines LNG that would increase the plant's total capacity to more than 7 Bcf/d over three construction phases. (Aegis Market Insights, 2026-09-22)

• Crude pipelines bound for Corpus Christi were 99.7% utilized, while Houston-bound pipes were 91.7% utilized, per the latest T-1 filings at the Texas Railroad Commission. (East Daley, 2026-10-15)
• The Permian-to-Cushing corridor was 68.2% utilized, according to the T-1 filings. (East Daley, 2026-10-15)
• East Daley estimates that only about 500 Mb/d of capacity remains on the more direct routes from the Permian toward Gulf Coast markets. (East Daley, 2026-10-14)
• The basin has only 500,000 to 600,000 barrels per day of remaining capacity to the Gulf Coast through brownfield expansions and latent capacity before pipelines hit their limits. (Plainview Energy Analytics, 2026-10-12)
• Gray Oak wrapped up a two-part 120 Mb/d expansion in May, and Plains All American completed its 75 Mb/d expansion of Cactus III, which went into service in August. (RBN Energy, 2026-10-16)
• By January 2029, Permian crude production reaches ~7.9 MMb/d, effectively matching the basin’s estimated 7.89 MMb/d of nameplate long-haul takeaway capacity. (East Daley, 2026-10-15)

• The IEA Breakthrough Agenda Report uses installed regional capacity and generation share of low-emissions power generation as quantitative indicators for success in the power sector transition. (International Energy Agency)
• The IEA’s clean energy transition indicators track changes in the economy’s energy intensity, the carbon intensity of energy supply across end-use sectors, and power generation decarbonisation. (International Energy Agency)
• The Energy Institute Country Transition Tracker assesses national progress via primary energy intensity, the extent of renewable energy penetration in energy systems, and the change in energy-related CO2e emissions between 2017 and 2024. (Energy Institute)
• Ember’s Global Electricity Review tracks the share of renewables in global power generation (33.8% in 2025) and how clean power met new electricity demand growth. (Ember, 2026-10-17)
• IRENA’s World Energy Transition Outlook tracks renewable power capacity additions and the share of electricity in final energy consumption as key transition metrics. (International Renewable Energy Agency, 2026-10-13)
• The Energy Transitions Commission notes that clean electricity supplied 40% of new energy demand in 2025, distinguishing capacity and generation growth from overall emissions outcomes. (Energy Transitions Commission, 2026-09-01)

• Planning Reserve Margins are a long-term resource adequacy indicator calculated as the difference in anticipated resources and net internal demand divided by net internal demand and shown as a percentage. (NERC, 2025-04-24)
• Reserve Margin (%) = (Resource Capacity – net internal demand)/net internal demand X 100. (NERC, 2025-02-19)
• Planning Reserve: This is the difference between a BA’s expected annual peak capability and its expected annual peak demand expressed as a percentage of the annual peak demand. (NERC)
• Texas RE-ERCOT Reference Margin Level is 13.75% Target Reserve Margin based on 0.1 day/Year LOLE plus adjustment for non-modeled market considerations, approved by ERCOT Board of Directors. (NERC)
• SERC-East, SERC-Florida Peninsula, and SERC-Southeast Reference Margin Levels are 15.0%, reviewed by member utilities or Florida Public Service Commission. (NERC)
• PJM’s 2027/28 capacity auction resulted in a 14.8% reserve margin, below PJM’s 20% installed reserve margin target. (PJM via FERC statements, 2025-12-19)

• The 3:2:1 crack spread approximates the product yield at a typical U.S. refinery: for every three barrels of crude oil the refinery processes, it makes two barrels of gasoline and one barrel of distillate fuel. (U.S. Energy Information Administration, 2013-02-04)
• To calculate the 3:2:1 crack spread, add the spot price for two barrels of Gulf Coast conventional gasoline to the spot price for one barrel of Gulf Coast ultra-low sulfur diesel, multiply product prices by 42 gallons per barrel to convert to dollars per barrel, subtract the spot price for three barrels of LLS crude oil, and divide the result by 3. (U.S. Energy Information Administration, 2013-02-04)
• The crack spreads are calculated by subtracting the value of a gallon of crude oil from the value of a gallon of RBOB or ULSD. (U.S. Energy Information Administration, 2026-10-15)
• The most common type of crack spread is the simple 1:1 crack spread, which represents the refinery profit margin between the refined products (gasoline or diesel) and crude oil. (CME Group)
• A typical refinery adopts a 3:2:1 ratio as gasoline output is approximately double that of distillate fuel oil. (CME Group)
• Other spreads exist: 5-3-2 (more realistic, but less liquid), 2-1-1 (even more realistic for some refineries). (Global Oil Shock, 2026-10-15)

• The Strategic Petroleum Reserve is deliberately excluded from the seasonal commercial curve. (StorageCurve, 2026-10-09)
• In addition, crude oil is often stored on ships at sea. The lack of complete information on inventories creates additional uncertainty in oil markets, which can also influence oil prices. (U.S. Energy Information Administration (EIA), 2026-10-15)
• Real-time floating storage data to incorporate a key supply metric into market analysis. (Kpler, 2026-10-14)
• Floating storage tracked in real time via satellite. (Kpler, 2026-10-14)
• The U.S. Energy Information Administration publishes regular inventory statistics for crude oil and refined products like gasoline and distillate. (U.S. Energy Information Administration (EIA), 2026-10-15)
• Petroleum inventories refer to the stockpiles of crude oil and refined petroleum products that are stored in various locations, such as at refineries, storage terminals (including tank farms), pipelines, and floating storage on large vessels or barges. (U.S. Energy Information Administration (EIA), 2026-10-15)

• EIA calculates the operable utilization rate by dividing gross input to atmospheric crude oil distillation units by operable calendar day refining capacity, where operable capacity accounts for scheduled downtime due to maintenance and turnarounds but does not separate economic run decisions. (U.S. Energy Information Administration)
• Planned refinery outages tend to occur during spring and fall and during times of relatively low margins as measured by the crack spread, while unplanned outages are negatively associated with capacity utilization rate. (Energy Economics, 2015-07-01)
• Refiners deferred maintenance turnarounds in 2025-2026 when margins were strong, resulting in lighter maintenance seasons with average shutdowns of 470,000 bpd from January-May 2026 versus 700,000 bpd the prior year per Energy Aspects data. (Bloomberg, 2026-06-01)
• Consultancies such as Energy Aspects, IIR Energy, and Kpler track planned turnaround schedules separately from EIA utilization data to distinguish maintenance-driven utilization changes from margin-driven run cuts. (Kpler, 2026-02-18)
• High utilization near 95% or above incentivizes deferral of planned maintenance, with some operators moving fall 2026 turnarounds to 2027, as reported in IIR Energy schedule comparisons. (Industrial Info Resources, 2026-09-16)

• Spark spreads are calculated using the following equation: Spark spread ($/MWh) = power price ($/MWh) – [natural gas price ($/mmBtu) * heat rate (mmBtu/MWh)]. (U.S. Energy Information Administration, 2013-02-08)
• EIA uses a benchmark heat rate of 7,000 Btu/kWh for spark spread calculations, representing a fairly new and efficient natural gas combined-cycle generator. (U.S. Energy Information Administration, 2013-02-08)
• One kWh has a heat content of 3,412 Btu; a generator that uses 7,000 Btu to produce one kWh has a conversion efficiency slightly below 50%. (U.S. Energy Information Administration, 2013-02-08)
• In the UK, a non-rounded efficiency of 49.13% is used for calculating the gas conversion; Spark Spread = Power Price – (Gas cost/0.4913). (Wikipedia)
• Heat rate is the ratio of energy input required to produce one unit of power output, expressed in Btu per kilowatt-hour (Btu/kWh); a lower heat rate implies higher unit operating efficiency. (ScienceDirect, 1998-03-01)

• EIA calculates five-year averages for the Weekly Natural Gas Storage Report using a daily interpolated average approach: daily linear interpolations of working gas inventory values between weekly report days in the Historical Weekly Storage Estimates Database, then five-year averages for each day of the year from the preceding five years of those daily estimates (current method since the week ended January 7, 2005). (U.S. Energy Information Administration, 2018-09-10)

• Days of net import cover is the result of: emergency reserves ÷ daily net imports. (IEA, 2026-08-12)
• The IEA minimum stockholding obligation is based on the average daily net imports of the previous calendar year. (IEA, 2026-08-12)
• Days of Forward Demand Cover = Total OECD Commercial Stocks / Forward OECD Daily Demand. (BrentChart.com)
• Days of supply = (Stock level ÷ Monthly consumption) × 30. (UKOilWatch)

• The 50 U.S. states and the District of Columbia are divided into five Petroleum Administration for Defense Districts (PADDs), with PADD 1 further split into three subdistricts; PADDs 6 and 7 cover U.S. territories but are excluded from U.S. totals. (U.S. Energy Information Administration, 2026-10-15)
• PADD 2 (Midwest) consists of Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, and Wisconsin. (U.S. Energy Information Administration, 2026-10-15)
• PADD 3 (Gulf Coast) consists of Alabama, Arkansas, Louisiana, Mississippi, New Mexico, and Texas. (U.S. Energy Information Administration, 2026-10-15)
• PADD 4 (Rocky Mountain) consists of Colorado, Idaho, Montana, Utah, and Wyoming; PADD 5 (West Coast) consists of Alaska, Arizona, California, Hawaii, Nevada, Oregon, and Washington. (U.S. Energy Information Administration, 2026-10-15)
• Within PADD I, the East Coast refining district includes the District of Columbia and the states of Maine, New Hampshire, Vermont, Massachusetts, Rhode Island, Connecticut, New Jersey, Delaware, Maryland, Virginia, North Carolina, South Carolina, Georgia, Florida, plus specified counties in New York and Pennsylvania. (U.S. Energy Information Administration, 2026-09-25)
• Within PADD I, subdistricts are New England (Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, Vermont), Central Atlantic (District of Columbia, Delaware, Maryland, New Jersey, New York, Pennsylvania), and Lower Atlantic (Florida, Georgia, North Carolina, South Carolina, Virginia, West Virginia). (U.S. Energy Information Administration, 2026-09-25)

• Vessel traffic data, or Automatic Identification System (AIS) data, are collected by the U.S. Coast Guard through an onboard navigation safety device and made available for download and analysis via the Marine Cadastre at https://marinecadastre.gov/ais/. (Marine Cadastre (BOEM/NOAA/USCG), 2026-09-30)
• MARAD's Office of Policy and Plans publishes statistical reports including on vessel activity at U.S. ports under the Vessel Calls section of its Data and Reports page at https://www.maritime.dot.gov/data-reports. (Maritime Administration (MARAD), 2026-10-14)
• MARAD published a factsheet with calculated vessel calls for privately-owned, oceangoing merchant vessels over 1,000 gross tons calling at U.S. ports and terminals for 2013-2015 at https://www.maritime.dot.gov/sites/marad.dot.gov/files/docs/outreach/data-statistics/6781/dsvesselcallnotes.pdf. (Maritime Administration (MARAD), 2020-06-10)

• ERCOT provides both Day-Ahead Market (DAM) prices on a daily basis and Real-Time Market (RTM) prices on an interval basis. (ERCOT)
• PJM Data Viewer dashboard includes a Real-Time & Day-Ahead LMP display updated as of the current interval. (PJM)
• Through the IFM the CAISO calculates LMPs for each Trading Hour of the next Trading Day; through the FMM the CAISO calculates distinct financially binding fifteen-minute LMPs; through the Real-Time Dispatch, the CAISO calculates five-minute LMPs. (California ISO, 2026-06-30)
• MISO Market Reports offer analysis and status of market operations related to all aspects of real-time and day-ahead energy and ancillary services markets. (MISO)
• ISO New England publishes Hourly Day-Ahead LMPs, Final Real-Time Hourly LMP, Preliminary Real-Time Hourly LMPs, and Preliminary Real-Time Five-Minute LMPs reports. (ISO New England)
• MISO provides Day-ahead ExAnte/ExPost Locational Marginal Price and Real-time ExAnte/ExPost Locational Marginal Price through its Pricing API on the Data Exchange. (MISO)

• Interstate natural gas pipelines must post on their Internet websites, in downloadable file formats, information on the availability of all transportation services whenever capacity is scheduled, including total design capacity of each point or segment, amount scheduled, planned and actual outages or reductions, and volumes of no-notice transportation. (Electronic Code of Federal Regulations)
• Form No. 549B requires interstate pipelines to report peak day capacity and storage capacity assignments, with the note that information can be obtained from the company's websites. (Federal Energy Regulatory Commission, 2020-06-20)
• FERC-551 requires interstate pipelines to post flow volume and capacity data daily on their websites in downloadable formats, available for at least 90 days. (Federal Register, 2025-12-31)
• As of August 1, 2025, FERC Form No. 552 annual natural gas transaction data is accessible on Data.ferc.gov rather than the prior download page. (Federal Energy Regulatory Commission, 2026-09-03)
• Data.ferc.gov provides public access to categories including FERC Form 552 natural gas transactions data, with additional categories to be added. (Federal Energy Regulatory Commission, 2026-10-15)
• Annual capacity reports, such as the 2025 Annual System Capacity Report, are filed in FERC's eLibrary. (Federal Energy Regulatory Commission, 2025-08-23)

• Cushing, Oklahoma, serves as the delivery point for the NYMEX Light Sweet Crude Oil futures contract with over 90 million barrels of storage capacity. (CME Group, 2025-08-08)
• WTI Midland crude is assessed for physical delivery at the Enterprise and Plains terminals at Midland, Texas, as Permian-quality WTI with typical specifications of 42.2 API gravity and 0.13% sulfur. (CME Group, 2025-08-08)
• Platts WTI Midland specifications require sulfur of 0.2% or less by weight, API gravity not less than 40 nor more than 44 degrees, and mercaptans of 75 ppm or less. (S&P Global Platts, 2026-08-10)
• Mars is a medium sour crude blend with typical specifications of 28-29.7 API gravity and 1.87-1.93% sulfur, assessed for delivery via the Mars pipeline system to Clovelly, Louisiana. (GX, 2025-06-05)
• WTI Houston (MEH) assessments cover WTI Midland-quality crude delivered FIP at the Magellan East Houston terminal in Houston, Texas. (S&P Global Platts, 2026-08-10)
• Argus Mars assessment reflects spot prices for the US Gulf medium sour crude blend arriving on the Mars pipeline, with typical quality of 29.7 API and 1.95% sulfur. (CME Group, 2025-08-08)

• The U.S. Climate Divisional Dataset (nClimDiv) from NOAA's National Centers for Environmental Information provides temperature, precipitation, drought indices, heating degree days, and cooling degree days for U.S. climate divisions, states, multi-state regions, and the nation from 1895–present. (Drought.gov / NCEI)
• NOAA Monthly U.S. Climate Divisional Database (NClimDiv) includes heating and cooling degree days with coverage for climate divisions, states, multi-state regions, and the nation. (NCEI, 2014-03-01)
• The Climate Prediction Center publishes daily heating and cooling degree days data for climate divisions, states, Census divisions, and the CONUS, along with 7-day forecasts and 1981-2010 normals. (CPC / NWS)
• Climate at a Glance from NOAA provides maps and data for heating and cooling degree days by each of the 344 climate divisions in the U.S. Climate Divisional Database. (NOAA Climate.gov)

• EIA releases the Weekly Natural Gas Storage Report at 10:30 a.m. Eastern Time each Thursday, except in weeks with federal holidays when alternate dates and times apply as listed on the schedule page. (U.S. Energy Information Administration, 2018-09-10)
• The report provides estimates of working gas in underground storage as of 9:00 a.m. Central Standard Time on the Friday of the previous week, collected via Form EIA-912 from a sample of operators. (U.S. Energy Information Administration, 2018-09-10)
• Estimates are prepared using a stratified probability-proportionate-to-size sample drawn from the EIA-191 monthly underground storage operator frame, typically including 80-85 respondents covering at least 90% of volumes in each stratum, combined with 12-month moving averages from the latest available EIA-191 data to estimate non-sampled operators. (U.S. Energy Information Administration, 2018-09-10)
• The Weekly Natural Gas Storage Report is published every Thursday at 10:30 a.m. Eastern Time (with holiday exceptions) and the supplement by 5:00 p.m. the same day. (U.S. Energy Information Administration)
• Holiday-adjusted release dates for the Weekly Natural Gas Storage Report include shifts to Friday, Wednesday, or Monday at 10:30 a.m. or 12:00 p.m. Eastern Time for specific 2025 and 2026 federal holidays. (U.S. Energy Information Administration, 2025-01-08)

• The U.S. Energy Information Administration publishes the Weekly Petroleum Status Report, including data on U.S. petroleum balance sheet, stocks of crude oil by PAD district and stocks of petroleum products U.S. totals, on its website at https://www.eia.gov/petroleum/supply/weekly/. (U.S. Energy Information Administration, 2026-10-15)