Continental starts completing Bakken DUCs

Spanish Market: Crude oil, Natural gas
03/11/16

Continental Resources will start to deplete its inventory of drilled but uncompleted (DUC) wells particularly in North Dakota's Bakken formation.

It now expects to end the year with an inventory of about 175 Bakken DUCs compared with an earlier target of 190 to 195.

Continental had stopped completing wells amid the plunge in crude prices, and had chosen to focus operations instead on its Scoop and Stack acreage in Oklahoma. Work on completing another 15 will start at the end of the year, with completion and first output expected in early 2017.

"Our 14 month pause in Bakken completion activity since September 2015 has created real incremental value here," chief executive Harold Hamm said on an earnings call. "During this time we build up our uncompleted well inventory while testing and developing the very best enhanced completion technology."

Producers like Continental and Whiting have built up a large inventory of DUCs through the downturn because it made little sense to start up new wells at a time of extreme market volatility and a bleak price outlook. They drilled those wells anyway because they had rigs with them that were already under contract and turning on a DUC takes much less time and is a lot cheaper. That has positioned the companies to take advantage of a price recovery.

Continental's DUCs "will be a key driver of the company's production and cash flow growth in 2017 and 2018," Hamm said. "We clearly have the inventory to support double-digit production growth for many years."

The independent is completing its DUCs in part amid expectations of steady growth in both global oil demand and supply, which will help push prices gradually higher, he said. Prices will move up regardless of whether Opec and non-Opec producers are able to reach a final agreement later this month to curb production, Hamm said.

"We believe the world of energy markets are at a turning point," he said.

Continental will be cash flow positive by about $100mn for this year, excluding proceeds from asset sales, at current prices even as it plans to step up spending given the steep cuts it has made in drilling costs, chief financial officer John Hart said in the call.

The independent yesterday said it is raising its capital expenditure (capex) guidance for this year by 20pc, to $1.1bn compared with $920mn given in August. While it is finalizing its budget for next year, spending and operational plans will be dictated by staying cash flow neutral.

The company has sold $630mn in assets this year and is expected to end the year with $6.5bn in long-term debt, Hart said. Continental aims to keep total debt below $6bn.

Related news posts

Argus illuminates the markets by putting a lens on the areas that matter most to you. The market news and commentary we publish reveals vital insights that enable you to make stronger, well-informed decisions. Explore a selection of news stories related to this one.

22/12/25

Viewpoint: US, European LNG spread may narrow in 2026

Houston, 22 December (Argus) — The spread between US and European LNG prices will likely narrow further in 2026, but forward prices indicate US LNG supply under long-term contracts will remain comfortably profitable in international spot markets until at least summer 2027 as a wave of new supply comes on line. A recent rally in the US natural gas market highlighted US LNG's tightening margins. The indicative long-term LNG contract price — 115pc of US benchmark Henry Hub plus a $3/mn Btu liquefaction fee — surpassed the Argus Gulf coast (AGC) spot fob price in early December for the first time in more than two years amid cold weather in the US, mild weather in Europe and high Atlantic basin freight rates. But the premium over the spot price was brief and caused no change to export schedules. The front-month Henry Hub contract quickly shed its gains on warmer weather, falling to $3.89/mn Btu on 16 December from a nearly three-year high of $5.29/mn Btu on 5 December. Prices hovered around $4/mn Btu through 19 December. The impact was solely on profit margins rather than fundamentals. Customers of US LNG facilities did not need to cancel cargoes under take-or-pay provisions because a profit incentive to maximize exports remained. Liquefaction costs are considered sunk, and the spread between Henry Hub and European LNG prices remained wide enough to more than cover shipping costs. Though rising exports may add to domestic pricing volatility during cold winter weather through the end of the decade, US and European gas futures today indicate long-term offtake from US LNG terminals will remain profitable until the summer of 2027, assuming freight rates of $80,000/d and a 50¢/mn Btu discount to the European benchmark TTF for northwest European deliveries. At that time, contracts with $3/mn Btu liquefaction fees could surpass delivered LNG prices in northwest Europe, though the arbitrage for US gas would remain open for contracts with lower fees (see chart) . Fees now range between $2.50-2.80/mn Btu for US supply coming on line toward the end of the decade. Contracts with fees on either end of that range remain below European LNG prices until summer 2029 and summer 2028, respectively, assuming freight rates of $80,000/d. But cargo cancellations are not always necessary when long-term US LNG contract prices surpass international prices. Terminal operators and their customers finalize annual delivery plans as well as upward and downward delivery tolerances before the start of each year, leaving less flexibility later in the year. If a customer wishes to cancel a cargo, they typically must notify the terminal up to two months in advance, which would likely only happen in an environment where the cost of 115pc of Henry Hub plus freight stabilizes above European LNG prices. The spread between Henry Hub and delivered European prices is wide enough to absorb freight costs through winter 2030-31. If an offtaker opts for a lower quantity in its delivery tolerance or cancels a cargo, the volume returns to the terminal operator, which could still market and sell the cargo on the spot market. This effectively shifts the seller of a cargo from the LNG customer to the LNG terminal operator. The likelihood of cancellations beyond 2027 may be higher in the spring and autumn shoulder seasons, when demand in Europe is typically lower. Depending on the previous winter, this may be more likely to occur in autumn, given the annual rebuild of Europe's underground gas inventories that begins in the spring. Additional liquefaction capacity has already helped tighten margins for US LNG since Europe's conflict-driven volatility in 2022 . The AGC fob's premium over the long-term indicative contract averaged $3.95/mn Btu through 19 December this year, down from $4.63/mn Btu, $5.37/mn Btu and $20.13/mn Btu in 2024, 2023 and 2022, respectively. But the anticipated convergence of US and European LNG is not guaranteed. Geopolitical conflict could disrupt existing trade patterns. And lower prices in Europe will be contingent on new LNG projects, led by the US and Qatar, maintaining their timelines, which are prone to delays from supply chain issues and workforce constraints. This would add upside risk to international prices and downside risk for Henry Hub if the delays are in the US. By Tray Swanson European LNG spot prices vs long-term US LNG $/mn Btu Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

US shale firms see subdued spending next year

22/12/25

US shale firms see subdued spending next year

New York, 22 December (Argus) — US president Donald Trump took to prime-time TV this week to reassure voters that 2026 will see a stronger economy, but US shale executives see little prospect of an imminent upturn in their business. US oil and gas firms plan to keep capital spending flat to slightly lower next year, according to a closely watched survey by the Federal Reserve Bank of Dallas, as the industry grapples with lower oil prices. Although activity edged lower in the fourth quarter, uncertainty grew and companies remained increasingly wary about future prospects in the poll of 131 executives from Texas, southern New Mexico and northern Louisiana that was carried out earlier this month. "Decreasing oil prices are making many of our firm's wells uneconomic," one exploration and production (E&P) executive said. "Capital efficiencies and returns drive our investment decisions," another respondent said. "If economic conditions worsen, drilling and completion activities will cease in 2026." The muted outlook for spending next year comes as producers have adopted a wait-and-see approach in recent months, given an increasingly uncertain macro backdrop, with crude prices trading near four-year lows this week on fears of global oversupply. A number of shale operators have posted higher-than-expected production this year. At the same time, spending has come in below expectations as drilling operations become more efficient, a trend UK bank Barclays says could be repeated in 2026. The executives who took part in the Dallas Fed survey gave varied responses when asked about their spending plans for next year depending on their size. Large producers — or those with output of 10,000 b/d or more — were more likely to say they expect capital expenditure to remain close to this year's levels. The most selected response among smaller firms — with production under 10,000 b/d — was for a slight increase. Although there are more small firms in the US, the larger companies account for more than 80pc of total US output. When asked about the oil price they were using for capital planning in 2026, the average response among executives was $59/bl for WTI. That was down from the $68/bl average price for the US benchmark that firms planned to use this year. The Dallas Fed said it was not necessarily a surprise that companies were not planning to trim spending further given weaker oil prices. Capital-intensive care "Oil and gas is a capital-intensive business," the bank's senior business economist, Kunal Patel, said. "It takes a lot of money to sustain the wells, even to keep production flat, and so that's why I don't think you're seeing as many people looking to significantly cut." Also, the prices that companies are using to plan next year's budgets are not too far from current breakeven levels. And producers may yet respond with deeper cuts to spending if prices tumble again. Oil and natural gas production was relatively unchanged in the fourth quarter, the survey showed, while costs rose at a slower pace than in the previous three months. "While oil prices have not been low enough this quarter to force a substantial cutback in activity, they were not high enough to support any growth either," Dallas Fed assistant vice-president Michael Plante said. In its annual E&P spending survey, Barclays expects upstream capital expenditure in North America to fall by 5pc in 2026, on lower US activity, reduced reinvestment ratios, and the impact of drilling and well completion efficiencies. That would mark its third consecutive annual decline. Barclays also revised down this year's upstream spending forecast to a decline of 5pc, from an initial estimate of a 3pc drop. The change was driven by further US rig count losses after Opec+ started to ramp up supplies, as well as the hit from Trump's tariff wars. By Stephen Cunningham Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Canada’s oil sands to demonstrate durability in 2026

22/12/25

Canada’s oil sands to demonstrate durability in 2026

Calgary, 22 December (Argus) — Canadian oil sands heavyweights will show durability in 2026 with modest production gains in a lower oil price environment, while tempting investors with bigger, longer-term plans at a time of renewed interest in pipeline projects. Canadian Natural Resources (CNRL), Cenovus, Suncor and Imperial Oil plan to pump out a combined 3.9mn b/d of oil equivalent (boe/d) in 2026, with 75pc of that focused on Alberta's oil sands region. Production gains among the Calgary-based firms will be 1-4pc, with CNRL and Cenovus leading the charge after sizeable acquisitions but also internal growth that has been years in the making. CNRL will push output to a record 1.6mn boe/d across 2026 after becoming sole owner in the 315,000 Albian oil sands mines in Alberta following an asset swap with Shell. The additional bitumen production also simplifies operations for the country's largest oil producer, which can now share trucks and personnel across its oil sands mines, which also includes its fully owned Horizon project. For its part, Horizon skipped a turnaround in 2025 to add 28,000 b/d of production, part of a growing theme of trimming downtime in the oil sands. Meanwhile, Cenovus seems poised to be the second Canadian operator to surpass 1mn boe/d with the upper end of its 2026 guidance just 15,000 boe/d shy of that mark. Boosted by two major acquisitions of cross-town rivals and sizeable organic growth, Cenovus will have doubled production since 2020 when output stood at 471,000 boe/d. It closed on its C$8.6bn ($6.1bn) purchase of MEG Energy in November to bring another 110,000 b/d into its fold, with plans to grow that to 150,000 b/d by 2028. Cenovus five years ago swallowed Husky Energy in a deal to increase its downstream and upstream exposure in Canada and abroad. And the company recently completed a three-year growth investment cycle and expects roughly 100,000 b/d of new production, also by 2028, at Sunrise, Lloydminster and West White Rose in Atlantic Canada combined. Capital spending for the four largest oil sands producers will climb to $14bn in 2026, up by 5pc from 2025, led by CNRL and Cenovus eyeing future growth. Endurance runners The production and spending plans come against a backdrop of global oversupply, highlighting oil sands operators' ability to not only weather, but grow, in a lower oil price environment with their suite of long-life, low-decline assets. Cenovus said its oil sands operating costs will be only $9/bl in 2026, while CNRL in another metric reports its corporate breakeven, including dividends, is just above $40/bl. In other words, oil sands producers would still have breathing space should WTI fall to the $51/bl predicted by the US Energy Information Administration in 2026 . But beyond 2026, an export pipeline capacity crunch is forecast to unfold from the third quarter of 2028 and that could put pressure on domestic prices, according to US bank TD Cowen. Trans Mountain and Enbridge plan for expansions to come on line in mid-to-late 2027, delaying the potential bottleneck by a year. Operators across the basin may be eyeing more growth but may not be ready to accelerate those plans until confidence grows on takeaway capacity. Acquisitions of producing assets may offer more assurance of that. "It's easier to grow by buying. If you grow organically, you pull that egress time forward," TD Cowen's managing director of institutional equity research, Menno Hulshof, said. CNRL has also outlined several projects it may pursue in the longer term, with front-end work due to start in 2026, potentially to unlock up to 260,000 b/d of new capacity between three oil sands projects. Significant output could come on line from 2030, and Alberta's recently proposed 1mn b/d pipeline to the Pacific will be key to an investment revival in the province. By Brett Holmes Oil sands capex guidance ($bn) 2026 2025 ±% 2026/25 CNRL 4.6 4.2 9 Cenovus 3.7 3.5 7 Suncor 4.1 4.2 -2 Imperial Oil 1.5 1.4 5 — company budgets Oil sands production guidance (boe/d) Oil sands Other Total ±% 2026/25 CNRL 867,500 752,500 1,620,000 3 Cenovus 767,500 197,500 965,000 4 Suncor 797,500 57,500 855,000 1 Imperial Oil 450,500 0 450,500 4 — company 2026 budgets Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: Biogas growth uneven, shipping drives 2026

22/12/25

Viewpoint: Biogas growth uneven, shipping drives 2026

London, 22 December (Argus) — Europe's biomethane market faces uneven growth in 2026, with numerous unsolved policy hurdles and as adoption of the EU's revised renewable energy directive (RED III) reshapes national compliance frameworks. Shipping demand will remain a key driver, particularly for certified subsidised product. RED III's overall 2030 target gives EU member states the option to reduce greenhouse gases (GHGs) by 14.5pc, or reach a 29pc renewable energy share. RED II only required countries to reach a 14pc renewable energy share. Some states have already transposed RED III, including the Netherlands and Germany , and pivoted incentive schemes to reward fuels on a GHG reduction basis. This is setting up biomethane with low or negative carbon intensity (CI) as a fuel of choice for suppliers obligated to comply with the regulation in the Netherlands, where previously it lagged behind cheaper, energy-intense biofuels. Another EU regulation that favours biomethane use is FuelEU Maritime, which came into effect in January 2025 requiring shipowners to reduce fleet emissions by 2 pc/yr in 2025 and 2026. Over-compliance can be sold under pooling schemes — which have proven profitable for bio-LNG bunkering. The mandate became a major market price driver for renewable gas guarantees of origin (RGGOs) — certificates issued to companies producing gas made from non-fossil fuel sources — and this should continue into 2026. New schemes, either under RED III or domestic obligations, that will come into effect in 2026 will compete with maritime demand for supply. Most 2026 Dutch and Danish supply has already been sold to the maritime sector. Growing Netherlands As well as a pivot to GHG-based compliance with a new ERE ticket system under RED III, the Netherlands began work on a Green Gas Blending Obligation in November. While implementation before late 2027 seems unlikely, progress should boost RGGO forward pricing. Dutch biomethane liquidity could be bolstered if the government approves mass-balancing , a method to track and verify biomethane when it is injected into the gas grid system and becomes indistinguishable from conventional gas. A motion was proposed in parliament in November, but a recent government response indicates this is unlikely. Bio-LNG must be unsubsidised, certified and physically delivered to qualify for ERE tickets, otherwise it will be treated with a fossil gas CI of 94g CO2e/MJ when calculating a fuel supplier's overall mandate level. Steady Germany, France Germany will remove double-counting for waste-based biofuels under its GHG reduction quota (THG) in 2026, but biomethane should remain the cheapest compliance route for fuel suppliers, as rising mandates will support demand. Most German imports come from the UK or Denmark. The former may benefit from Danish prices inflated by maritime demand, despite questions about UK eligibility with German schemes. France's biogas production certificate (CPB) blending mandate starts in January, which should significantly boost domestic demand. But the country has delayed its RED III transposition , which includes a new GHG-based IRICC ticket system, to 2027. The current energy-based TIRUERT transport ticket system will remain in place for a year, limiting transport-sector uptake. It is unclear if IRICCs can be generated from biomethane in 2027, but 3pc renewable gas obligations for transport will start in 2028, increasing thereafter. Cross-border trade and bio-LNG bunkering should remain limited. French biomethane can only be exported as an ex-domain cancellation , the cancellation of RGGOs in one country's registry for use in a different country. This carries risk to buyers, as ownership is not necessarily transferred. Subsidised biomethane cannot be liquefied at French LNG terminals for use outside the country. French bio-LNG must be exported via mass-balancing to other terminals in the EU, for use under FuelEU Maritime. Uncertain UK The UK's access to EU markets hinges on access to the Union Database for gaseous Biofuels (UDB), now targeted for launch by end-summer 2026. Uncertainty about third-country treatment could restrict EU trade — a critical issue given the UK exported more than half its RGGOs in the first three quarters of 2025, mostly to Germany, Norway and Switzerland. The UK is consulting on replacing volume-based RTFC tickets with a GHG-based system, but any changes would not be enacted until 2027. Overall in Europe, biomethane remains well positioned in GHG-based systems, but policy implementation delays will probably slow overall market growth. The Netherlands, Denmark and Germany should remain anchors for European pricing, and Spain should consolidate its role as a maritime hub. But several countries risk lagging behind without RGGO registries, export hub access, policy incentives and subsidy reform. By Madeleine Jenkins Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Japan's Niigata assembly backs Tepco's nuclear return

22/12/25

Japan's Niigata assembly backs Tepco's nuclear return

Osaka, 22 December (Argus) — Japan's Niigata prefectural assembly has supported its prefectural governor's decision to approve the restart of the Kashiwazaki-Kariwa nuclear reactors operated by utility Tokyo Electric Power (Tepco). The assembly passed a vote of confidence on Niigata governor Hideyo Hanazumi on 22 December. He had sought the assembly's judgement on his plan to authorise the restart of the No.6 and No.7 reactors at the Kashiwazaki-Kariwa, each with a capacity of 1,356MW. Hanazumi had previously indicated that he would step down if the motion was rejected. The motion was attached to a supplementary budget request of ¥31mn ($197,048) for the April 2025-March 2026 fiscal year, intended to support activities related to the restart of the Kashiwazaki-Kariwa nuclear plant. Hanazumi plans to meet Japan's trade and industry minister Ryosei Akazawa on 23 December to discuss the restart of the nuclear plant. The endorsement will allow Tepco to move towards restarting its reactors for the first time since they triggered the Fukushima-Daiichi nuclear disaster, after a powerful earthquake and tsunami in March 2011. The plant, which has remained off line since March 2012, is Tepco's sole nuclear station, after it scrapped the damaged Fukushima Daiichi and nearby Fukushima Daini plants. The Kashiwazaki-Kariwa plant comprises of seven reactors with a combined capacity of 8,212MW, of which the No.6 and No.7 units have cleared the stricter post-Fukushima safety inspections. Tepco has yet to file an application with the country's nuclear regulation authority (NRA) for screening of the five other reactors. The utility is also mulling scrapping the No.1 and No.2 reactors. Tepco is expected to prepare for the restart of the No.6 reactor first, given that the No.7 unit will be required to remain shut until August 2029 for the installation of anti-terrorism facilities. The No.6 reactor is expected to resume operations after clearing pre-use inspections, which typically last for three weeks to one month. This means that Tepco will be able to restart the No.6 reactor in January at the earliest. The return of the Kashiwazaki-Kariwa plant could be a milestone in Tepco's progress in nuclear power generation after the Fukushima disaster, with the No.6 unit marking Tepco's first reactor to be restarted after the disaster. Electricity from the nuclear plant will be sent to the Tokyo metropolitan area, with the nuclear plant — located in the Tohoku region — mitigating the risk of a power shortage in Japan's capital. A single nuclear reactor can produce 10 TWh/yr of electricity, and can save the company an estimated ¥100bn/yr, Tepco previously said. The return of the No.6 reactor is also expected to reduce CO2 emissions by around 3.3mn t/yr, it added. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Argus Asia Crack Spread Forward Curves

Herramienta de valoración de mercado independiente para respaldar las decisiones de inversión y negociación en los mercados asiáticos del petróleo.

Argus Carbon

Benchmarks de precios del carbono, noticias sobre políticas y proyectos, y análisis exhaustivos, a diario.

Informe Argus Low Carbon Hydrogen Strategy

Tercera parte: América del Norte Un análisis en profundidad de los sectores, países y políticas claves que permiten el crecimiento del hidrógeno.

Argus Russian Domestic Crude Market

Cobertura detallada del mercado nacional de crudo ruso.

Argus Hydrogen and Future Fuels

El punto de vista global sobre el hidrógeno y los mercados de productos derivados.

Business intelligence reports

Get concise, trustworthy and unbiased analysis of the latest trends and developments in oil and energy markets. These reports are specially created for decision makers who don’t have time to track markets day-by-day, minute-by-minute.

Learn more