New data from the U.S. Energy Information Administration (EIA) shows output rose by about 3 per cent, or 350,000 b/d, compared to 2024. The increase came despite a 5 per cent drop in active rigs and fewer wells drilled, highlighting a structural shift in how U.S. producers are growing supply.

The gains reinforce the United States’ position as the world’s largest oil producer and contribute to expectations of a global supply surplus. Reuters has reported that rising U.S. output is a key factor behind forecasts of an oversupplied global market, with production expected to average roughly 13.6 million b/d in 2025.

Efficiency offsets lower prices

The 2025 production increase came as benchmark West Texas Intermediate (WTI) crude prices fell to about $65 per barrel, down from $77 in 2024. Normally, lower prices would dampen output, but U.S. producers continued to extract more oil from fewer wells.

New wells added 2.9 million b/d of production in 2025, while existing wells accounted for 8.3 million b/d. Industry analysts have increasingly pointed to productivity gains — including longer laterals, improved fracking techniques, and better data analytics — as the main driver of growth.

Bloomberg has similarly reported that U.S. shale producers are pumping more oil per dollar invested, allowing output to rise even as capital spending and rig counts decline.

This decoupling of production from drilling activity marks a significant evolution in the shale sector, where companies have shifted focus from rapid expansion to capital discipline and efficiency.

Permian dominates growth

As in previous years, the Permian Basin remained the engine of U.S. production growth. Output in the region rose by 280,000 b/d in 2025 to reach 6.6 million b/d — nearly half of total U.S. supply.

Low breakeven costs continue to underpin Permian growth. According to the Dallas Fed Energy Survey, operators in the Midland and Delaware basins reported breakeven prices of roughly $61–$62 per barrel in 2025, below the annual average oil price. That cost advantage has allowed producers to sustain output even in a weaker price environment.

By contrast, other major shale regions showed limited growth. Production in the Eagle Ford rose modestly to 1.2 million b/d, while the Bakken saw a slight decline to a similar level.

Together, the Permian, Eagle Ford, and Bakken account for nearly two-thirds of total U.S. crude production.

Offshore projects add supply

Production in the Gulf of America also contributed to overall growth, rising by 111,000 b/d to average 1.9 million b/d in 2025.

Five new offshore projects — Whale, Ballymore, Dover, Shenandoah, and Leon-Castile — came online during the year. Unlike shale operations, offshore developments are less sensitive to short-term price fluctuations due to their long lead times and high upfront capital costs.

This steady pipeline of offshore projects is helping to diversify U.S. supply growth beyond shale basins.

Global implications

The global outlook for oil markets has shifted rapidly in recent weeks. The war in Iran and severe disruptions to shipping through the Strait of Hormuz — which typically carries about one-fifth of global oil — have tightened supply and driven prices sharply higher. With tanker traffic collapsing and infrastructure under attack, the market is moving away from fears of oversupply toward a more constrained and volatile environment.

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The CER examined throughput and capacity data for three major pipeline systems — Enbridge Mainline, Keystone and Trans Mountain — which together transport crude oil from the Western Canadian Sedimentary Basin (WCSB) to domestic and international markets. Combined monthly throughput across the systems exceeded 4.6 million barrels per day (MMb/d) at several points in 2024 and remained near that level through mid-2025.

Enbridge Mainline, Canada’s largest crude oil pipeline system, continued to operate at high utilisation levels throughout the period. Average throughput in 2024 was about 3.06 MMb/d, with volumes remaining strong into early 2025. Monthly throughput peaked above 3.2 MMb/d during winter months, when demand for condensate used in oil sands production increased.

The CER noted that throughput occasionally exceeded reported capacity due to operational factors such as changes in product mix and temporary efficiency gains.

Keystone pipeline throughput also remained high, averaging more than 600,000 barrels per day in 2024. An oil release in North Dakota in early 2025 temporarily reduced flows, but throughput recovered quickly. By June, volumes were again close to pre-incident levels, with utilisation typically ranging between 94 and 100 per cent.

The most significant structural change to Canada’s pipeline network came with the completion of the Trans Mountain Expansion Project in May 2024. The expansion nearly tripled Trans Mountain’s capacity, from about 300,000 barrels per day to roughly 890,000 barrels per day.

Following the expansion, Trans Mountain throughput rose sharply. Monthly volumes ranged between about 670,000 and 740,000 barrels per day in late 2024 and averaged roughly 730,000 barrels per day in the first half of 2025. The CER said the expanded system has eased long-standing capacity constraints and increased flexibility in routing Canadian crude.

The TMX expansion meant increased access to tidewater and has enabled Canada to significantly increase crude oil exports to overseas markets, particularly in Asia. Statistics Canada data show that crude exports through British Columbia rose sharply after TMX entered service, with shipments reaching destinations including China, South Korea, Japan and Singapore.

While the United States remains Canada’s dominant export market, the ability to move oil westward has allowed producers to access higher-value international markets and reduce reliance on a single customer. CER analysis indicates that the expansion has also contributed to a decline in crude-by-rail shipments, as pipeline capacity became more available and cost-competitive.

Reuters has reported that Asian refiners have shown growing interest in Canadian heavy crude blends since TMX entered service, attracted by supply diversification and competitive pricing relative to other heavy grades. Analysts cited by Reuters say the expanded pipeline has improved Canada’s negotiating position by narrowing price discounts and giving producers optionality when U.S. markets are saturated.

Despite strong utilisation, commercial conditions around the expanded Trans Mountain system continue to evolve. Reuters has reported that the pipeline operator recently revised its longer-term throughput forecasts downward, citing slower uptake of spot capacity and ongoing negotiations with shippers over tolls.

Those reports underscore that pipeline utilisation depends not only on physical capacity, but also on toll structures, crude price differentials and shipping economics — particularly for long-haul exports to Asia, which face higher transportation costs than shipments to U.S. markets.

High pipeline utilisation reflects strong Canadian crude production. The CER previously reported that Canada set new production records in 2024, with output remaining elevated into 2025, driven largely by oil sands operations.

Reuters has also reported that major Canadian producers expect production to remain robust through the middle of the decade, supporting continued demand for pipeline capacity even amid oil price volatility.

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By Jeff Barron

Slower oil demand growth in 2024 led to less crude oil processed by China’s refineries and fewer crude oil imports compared with the record high set in 2023. China, the world’s largest importer of crude oil, received 11.1 million barrels per day (b/d) in 2024, down from 11.3 million b/d in 2023. Even though total imports decreased about 2 per cent, imports from some countries increased while others decreased.

Why did China’s crude oil imports decrease last year?

We estimate that 16.3 million b/d of petroleum and other liquid fuels were consumed in China last year, second only to the United States globally. China’s domestic crude oil production averaged 4.3 million b/d in 2024, so the country had to import crude oil to meet the demand from its domestic refined petroleum product and petrochemical manufacturing sectors. China’s refiners imported 11.1 million b/d of crude oil and processed 14.2 million b/d. Both crude oil imports and refinery runs decreased in China from record levels in 2023, when the country imported 11.3 million b/d of crude oil and processed 14.8 million b/d.

Net decreases in the consumption of transportation fuel (gasoline, diesel, and jet fuel) last year meant China’s refineries processed less crude oil. Monthly data from China’s National Bureau of Statistics and General Administration of Customs indicate that consumption of both gasoline and jet fuel grew in China during 2024, but consumption of diesel fuel offset this growth with a large decline from 2023. These estimates are preliminary and subject to revision until late 2025, when China publishes annual consumption data, which we use to update our International Energy Statistics.

Instead of transportation fuels, liquefied petroleum gases (LPG), naphtha, or other petroleum products that can be imported directly for petrochemical manufacturing instead of refined from crude oil have led China’s growth in petroleum consumption. As a result, the net decline in transportation fuel demand reduced both refinery runs and import demand for crude oil in China last year.

Which countries do China’s refiners import crude oil from?

China’s refiners purchase crude oil from dozens of countries, with Russia, Saudi Arabia, Iraq, Oman, and Malaysia being the largest sources. Imports from Malaysia increased significantly last year to 1.4 million b/d, which is more than Malaysia’s domestic crude oil production of around 0.6 million b/d. The large difference stems from crude oil cargoes that were initially shipped from Iran but were then relabeled or transferred to avoid sanctions.

Imports from Russia increased in 2024 for the third consecutive year and averaged 2.2 million b/d, 1 per cent more than in 2023. China increased imports from Russia after the Group of Seven (G7) country import bans and sanctions limited Russia’s ability to sell crude oil after its full-scale invasion of Ukraine in 2022. These actions prompted Russia to sell some of its crude oil at discounted prices, making it more attractive to certain buyers.

On January 10, 2025, the United States announced additional sanctions on several oil vessels transporting crude oil from Russia. Because of potential disruptions from these actions, refiners in China may reduce purchases from Russia and replace those barrels with others from crude oil exporting countries not subject to sanctions, such as Brazil, Canada, the United States, or countries in the Middle East.

China’s second-largest source of crude oil imports was Saudi Arabia, although these imports decreased for the third consecutive year and averaged 1.6 million b/d, 9 per cent less than in 2023.

Imports from other Middle East OPEC countries including the United Arab Emirates (UAE) and Kuwait also declined, but imports from Iraq increased. Although small, crude oil imports from Canada increased, particularly in the second half of the year after the Trans Mountain expansion (TMX) project began commercial operations in May 2024. This pipeline expansion brings increased crude oil export capacity to Asia from Canada’s West Coast, which contributed to imports at more than 0.3 million b/d from Canada in September, an all-time high.

What factors will affect China’s crude oil imports and refining this year?

We forecast petroleum consumption in China will grow more slowly in 2025 and 2026 than in previous years in our latest Short-Term Energy Outlook. Because we expect growth in China’s consumption will outpace China’s domestic production of crude oil and other liquids, we believe net imports will increase. Last summer, we released a study on refinery capacity expansions in China and other countries through 2028. Several integrated refining and petrochemical complexes will open or expand over the next few years, suggesting crude oil imports will continue growing to meet feedstock demand from these facilities.

However, a tax change implemented in December 2024 creates considerable uncertainty for China’s petroleum trade balance this year. China reduced a value-added tax rebate offered on some petroleum product exports, which reduces their competitiveness in world markets. Depending on the effects of this change on Chinese refiners’ operations and profitability, refinery runs and crude oil imports could decline.

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By Matthew French

Crude oil production cuts among OPEC+ members are limiting the global supply of medium, sour and heavy, sour grades of crude oil. These cuts are increasing prices for these grades compared with sweet crude oils, reversing typical price relationships.

Crude oil is classified into categories based on the oil’s density (light, medium, or heavy) and sulphur content (sweet or sour). Light, sweet crude oils typically trade at a premium compared with any sour crude oil because sweet crude oils cost less to refine and produce higher yields of more valuable products.

Medium, sour Dubai Fateh (an Asia-Middle East benchmark), however, recently traded at a premium to light, sweet Dated Brent (a global benchmark). Dated Brent traded at an average premium of $2.56 per barrel (b) compared with Dubai Fateh between January 4, 2021, and June 20, 2023. However, between June 21 and September 19, the roles reversed, and Dubai Fateh traded at an average premium of $0.48/b compared with Dated Brent. Trade press reports similar movement in the price of Norway’s Johan Sverdrup—a medium, sour crude oil—as refiners offer increased prices to attract constrained supply.

In North America, the spread between the price of medium, sour Mars crude oil and the light, sweet Magellan East Houston (MEH) has declined since late 2022, and Mars sold at a small premium briefly in July 2023. The price of MEH reflects the price of light, sweet crude oil at the Enterprise ECHO terminal in Houston, Texas. The spread between Mars and MEH has increased over the past few weeks, although it is still lower than earlier this year.

In June 2023, OPEC+ members announced they would extend crude oil production cuts through 2024, limiting global crude oil supplies, particularly sour crude oils. On top of the OPEC+ production cuts, Saudi Arabia announced it would reduce crude oil production by an additional 1 million barrels per day (b/d) for July. These additional voluntary production cuts were extended several times, and Saudi Arabia announced on September 5 that it would extend them through the end of 2023. In our September Short-Term Energy Outlook, we estimate that OPEC crude oil production averaged 27.0 million b/d in August, the lowest since August 2021, and crude oil production in Saudi Arabia averaged 8.7 million b/d, the lowest since May 2021.

Most of Saudi Arabia’s crude oil contains more than 1 per cent sulphur, our threshold for classifying crude oil as sour, and production cuts have put more upward price pressure on sour barrels than sweet. Saudi Arabia also increased the official selling price (OSP) of Arab Light (a medium, sour crude oil) to Asia and Europe, further pushing up sour crude oil prices. As a result, sweet and sour crude oil price spreads have narrowed in most major trading hubs, including those in North America, Europe, and the Middle East.

The extent and duration of the current market dynamics, with sour crude oil prices trading unusually high, remain uncertain against a backdrop of production cuts, higher OSPs, and heightened demand for sour crude oil as several new Middle East refineries come online.

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This article was published by the US Energy Information Administration on Aug. 2, 2019.

Petroleum, which consists of crude oil and refined products such as gasoline, diesel, and propane, is the largest primary source of energy consumed in the United States, accounting for 36 per cent of total energy consumption in 2018.

Crude oil is processed at petroleum refineries to make many different products, such as motor gasoline, distillate fuel oil, hydrocarbon gas liquids, and jet fuel. More than two-thirds of finished petroleum products consumed in the United States are used in the transportation sector.

The U.S. Energy Information Administration’s (EIA) U.S. petroleum flow diagram helps to visualize U.S. petroleum supply (production, imports, and withdrawals from storage) and disposition (consumption, exports, and additions to storage).

The large number of refined products and outlets for sale (e.g., gasoline stations) makes data difficult to collect and end-use consumption difficult to calculate.

EIA uses petroleum product supplied to estimate petroleum consumption. EIA calculates product supplied by adding field production, refinery and blender net production, and imports and then subtracting stock change, refinery and blender net inputs, and exports. Petroleum product supplied increased for the sixth consecutive year in 2018, totalling about 20 million barrels per day (b/d).

In 2018, U.S. exports of crude oil reached a record high of 2.0 million b/d, an increase of about 0.8 million b/d from 2017. U.S. crude oil exports have increased significantly since the beginning of 2016, after the U.S. Congress lifted restrictions on exporting crude oil.

In addition, U.S. exports of total petroleum products reached a record high of 5.6 million b/d in 2018, an increase of 0.3 million b/d from the previous year.

The United States imported about 8 million b/d of crude oil in 2018, a 3 per cent decrease from 2017. Net imports of crude oil and petroleum products were down to about 2 million b/d, the lowest level since 1967. The United States still imports crude oil because of geographic and quality considerations.

In 2018, total field production, which includes crude oil, lease condensate, and natural gas liquids, reached a record high of more than 15 million b/d. U.S. crude oil production reached a record high of nearly 11 million b/d in 2018, a 17 per cent increase from the record set in 2017.

Production of natural gas liquids reached a record high of more than 4 million b/d, a 15 per cent increase from the record set in 2017. Increased production from tight oil and shale formations drove these record highs.

Most crude oil is refined into petroleum products used for transportation, such as motor gasoline, diesel, and jet fuel. The transportation sector has been the largest consumer of petroleum products in the United States since at least 1949, the earliest year for which EIA has data.

Transportation accounted for about 14 million b/d of petroleum consumption in 2018. This level was the second highest since its peak in 2007.

After transportation, the industrial sector accounts for the second-largest share of petroleum consumption, accounting for about 5 million b/d in 2018. Examples of industrial use of petroleum products include hydrocarbon gas liquids used as feedstocks for chemicals and plastics, as well as asphalt and road oil used for construction and road maintenance.

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This article was published by the United States Energy Information Administration on May 10, 2019.

Net income for 43 US oil producers totalled $28 billion in 2018, a five-year high. Based on net income, 2018 was the most profitable year for these US oil producers since 2013, despite crude oil prices that were lower in 2018 than in 2013 on an annual average basis.

Lower production costs per barrel of oil equivalent (BOE) and increased production levels contributed to a higher return on equity for these companies for the fourth quarter of 2018 than in any quarter from 2013 through 2018.

The companies included in the analysis are listed on US stock exchanges, and as public companies, they must submit financial reports to the US Securities and Exchange Commission. EIA calculates that these companies accounted for about one-third of total US crude oil and natural gas liquids production in the fourth quarter of 2018. However, these companies were not selected as a statistically representative sample but instead because their results are publicly available. Their results do not necessarily represent the US oil production industry as a whole.

Most of these companies operate in Lower 48 US onshore basins, with some in the Federal Offshore Gulf of Mexico and Alaska, and some in several other regions across the globe. Because of various corporate mergers and acquisitions in 2018, the number of US producers that EIA examined in this analysis fell from 46 companies in 2017 to 43 companies in 2018.

The aggregated income statements for these 43 companies reveal a trend of relatively low increases in expenses directly related to upstream production in 2018. Although these upstream production expenses per barrel typically correlate with crude oil prices, the magnitude of these increases in 2018 was small compared with the increase in prices.

The annual average West Texas Intermediate (WTI) crude oil price increased 28 per cent from 2017 to average $65 per barrel (b) in 2018, but expenses directly related to upstream production activities increased 16 per cent between 2017 and 2018 to $24/BOE. When including depreciation, impairments, and other costs not directly related to upstream production, expenses for these 43 companies averaged $48/BOE in 2018, the lowest amount from 2013 to 2018.

In contrast to production expenses, between 2017 and 2018, upstream revenue for these 43 companies increased 31 per cent to average $48/BOE in 2018, mainly because of the increases in average energy prices and production. As crude oil prices fell in late 2018, their upstream revenue declined 11 per cent between the third and fourth quarters of 2018.

However, this group of companies reported financially hedging nearly one-third of their fourth-quarter 2018 production at prices in the mid-$50/b range, offsetting revenue declines when WTI prices fell lower than $50/b by the end of the year. Consequently, even with their decline in upstream revenue in the last quarter of 2018, total revenue increased for these 43 companies because of the gains from financial derivatives.

Contributions to revenue from derivative hedges—which increase in value when prices decline—for these 43 companies reached the largest total for any quarter since the fourth quarter of 2014. Financial hedging can act like an insurance policy, reducing risk by stabilizing revenue for producers. When oil prices fall lower than the prices at which producers established a hedge, the producer effectively receives higher revenues than selling at market prices. When oil prices rise higher than the hedged price, hedging results in a loss that is treated as an operating expense.

More information on these 43 producers’ financial statements, including a comparison of these companies’ cash from operations relative to their capital expenditures, is available in This Week in Petroleum.

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A week in and  the consensus seems to be that Rachel Notley made the right decision to cut back Alberta oil production by 325,000 b/d. What about her other energy policies? Or her handling of controversial energy issues, like pipelines? Experts give the Premier high marks as an oil and gas policymaker and manager, a fact not well appreciated by Albertans.

Calgary-based pollster Janet Brown says that voters like the NDP leader, but they’re very anxious about the economy and lack faith in Notley’s team to do a good job getting the province back on track.

“People have very positive impressions of the Premier. People do think that she is quite competent and she is doing a good job,” Brown said in an interview.

“People don’t have nearly as much faith in the team around her and her caucus. So, I think that is one of the things that Rachel Notley is suffering from.”

Dr. Allan Fogwill is an economist and head of the non-partisan, Calgary-based Canadian Energy Research Institute. He says energy is a tough file for politicians to manage because widely divergent stakeholder views mean consensus is impossible.

“So, what’s the most reasonable approach that you can take which tries to address everyone’s views but keeps us moving forward?” asks Fogwill. “I think, to the extent possible, the policies that have been adopted by the Alberta government have been reasonable.”

He says the Notley government has done a good job balancing support for the oil and gas industry and competing issues, like beefing up environmental protection and ensuring the public treasury gets its fair share from royalties.

“There were concerns by some parts of the population that the royalties were not high enough. The government went forward with a very inclusive stakeholder consultation process [during the review in 2015], then struck a resonable balance,” he told Energi News. 

“They didn’t really change the royalty structure to any great extent. They streamlined it and made it easier to manage, but given the economic challenges of the industry they didn’t really change the quantum of royalties that they were going to collect.”

Dave Collyer is a long-time Shell Canada executive who was CEO of the Canadian Association of Petroleum Producers from 2008 to 2014 and served as co-chair of the Oil Sands Advisory Group.

He gives the Notley government “high marks” for its work on the oil and gas royalty review, climate policy as it affects energy, and says “she has been a strong advocate for pipelines and market access.”

“I think has taken some sound decisions in Alberta’s interest. So, I think when you sum it all up, as a relates to the energy file, she has been very solid,” he said in an interview.

Prof. Kent Fellows is an energy economist with the University of Calgary. Notley’s commitment to extensive consultations with stakeholders and the public has been a distinguishing feature of her government, he argues.

“I think the NDP has been good at offloading the workload to the regulator whenever possible and then engaging in consultation so that they try to avoid unintended consequences of these policies,” he told Energi News in an interview.

“A lot of this stuff ends up being fairly technocratic. I’m not convinced that the policies would be a whole lot different if we had a different government in place.”

Some of the criticism levelled at Notley’s handling of the energy file can be ascribed to partisan politics, says Ed Whittingham, former CEO of the Pembina Institute and one of the environmental group executive directors involved in the climate policy discussions with oil sands CEOs.

“Many in corporate Calgary, though not all, voted for the other team in the last election,” he said in an interview. “I think those criticisms come with a certain political bias.”

Oil and gas industry leaders were nervous after the 2015 election of a government that was perceived to be “activist.”

“If you were worried about an activist government coming in and not resting on its [electoral] laurels, then during the first six months you had lots of reasons to be suspicious. I think their moves since then have proved to be good ones,” he says.

“I am still a supporter of the Climate Leadership Plan and I think it will ultimately lead to a pipeline being built. We just have to go through some more process.”

Gil McGowan, president of the Alberta Federation of Labour and co-chair of the Energy Diversification Advisory Committee, argues that Notley’s response to the oil price crisis takes a page out of the playbook of former Premier Peter Lougheed.

“If you put all those four pieces together – the continued push for pipeline expansion, plans for more upgrading and refining, a medium-term solution in the purchase of rail cars, and the temporary oil production cuts – it’s clear that this is a premier who really has a good understanding of the problems that are currently besetting our industry,” he said in an interview.

“It’s clear that she has a more robust vision for managing our energy resources in the public interest.”

Another issue where Notley has done a good job balancing policy objectives, according to Fogwill, is greenhouse gas emissions and economic development.

“In particular, I point to the output based allocation process that they went through with industry and other stakeholders to really design the benchmarks, not looking at it from a purely theoretical point of view, but what was actually happening in various industrial sectors,” he said. 

“It was such a well-thought-out strategy that the federal government has adopted it as part of their carbon pricing mechanism.”

No government is perfect, including Notley’s.

For instance, Collyer points out that while the oil and gas carbon pricing policy – known as the Carbon Competitiveness Incentives Regulation – is well designed, there have been implementation issues that concern industry.

And some issues – such as reforming the Alberta Energy Regulator to improve efficiency for producers or tackling the oil and gas liabilities problem (think oil sands tailings ponds and orphan wells) – still are not properly addressed.

But that’s the nature of government. There is never a shortage of issues to resolve and challenges to tackle.

On balance, considering the sources interviewed for this column and the hundreds interviews conducted by Energi News for news stories and columns over the past three and a half years, the consensus is that Rachel Notley is an able policymaker and has managed energy issues well despite being dealt a tough hand that included two years of rock bottom oil prices, an economic recession, and less than ideal handling of the pipeline file by Ottawa.

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Royalty credit for production curtailment provides middle ground for industry players

To curtail or not to curtail: that is the question Rachel Notley is grappling with right now as Canadian oil prices remained depressed due to a 140,000 b/d mismatch between supply and outtake capacity. The Alberta premier is under intense pressure to act, and industry is divided on the issue. But there may be a middle ground that pleases both sides: a royalty credit for voluntarily shutting in production.

How serious is the problem for industry and the provincial government?

Scotiabank estimates that in 2019, Alberta’s upstream industry could lose between CDN$15 billion and CDN$39 billion in royalty-applicable earnings, while the Alberta government could lose between CDN$1.5 billion and CDN$4.1 billion at a time when public coffers are starving for revenue.

In the Alberta government’s last fiscal update, oil-related royalty revenues were forecast to come in around CDN$3.6 billion and make up 7.4% of total government receipts, assuming average West Texas Intermediate prices of US$61/b and a WCS discount of US$24/b, according to Scotiabank.

The excess supply amounts to only three per cent of Western Canadian oil production and some companies, like Canadian Natural Resources, Cenovus, and Athabasca Oil, have already voluntarily limited their supply.

The problem is that there are no easy short-term options.

Enbridge’s 375,000 b/d Line 3 won’t come on-stream for another year. Shipping more crude by rail is difficult because there aren’t enough tanker cars and locomotives. The Trans Mountain Expansion and Keystone XL are bogged down in litigation.

To make matters worse, the big integrated producers (Suncor, Imperial Oil, Husky Energy) that have their own refineries, most of them in the United States, are actually profiting from the differential crisis because their downstream operations are buying feedstock at rock bottom prices. Integrated companies are protecting about 80 per cent of production from the discount, so naturally they argue that markets are working properly and oppose curtailment.

Other large producers (Cenovus, CNRL) are only able to protect 50 to 60 per cent of their production, which means they’re still feeling a fair amount of pain from the differential and support limiting production in order to reduce it.

Hardest hit are the juniors and midcaps, which are forced to sell their production in Alberta and (absent any hedging) suffer the full brunt of discounts that have now spread from heavy grades to lighter crudes. No surprise, they also support curtailment.

Offering a royalty credit for voluntary curtailment might be a strategy that pleases both sides – or at least makes the greatest number of industry players the least unhappy.

The per barrel credit could be set an initial rate the government thinks will be high enough to remove the excess production from the market. The rate can be adjusted over time if new supply comes onstream or the lower rate fails to curtail sufficient production.

Why don’t producers voluntarily cut back production?

The Scotiabank economists provide a tidy explanation: “current curtailment plans are insufficient to completely clear the market and companies that pursue this strategy alone are enduring a first-mover disadvantage as some producers benefit from others’ restraint without enduring any of the pain of cutting. This free-rider dilemma is further complicated by the fact that any efforts to negotiate some kind of regional production alliance or supply restraint pledge would likely run afoul of competition laws…”

As an added bonus, Premier Notley can request the Canadian government share the cost of the program. After all, less industry activity affects federal and provincial tax revenue, which averaged $7.3 billion a year from 2012 to 2016, according to Natural Resources Canada.

Prime Minister Justin Trudeau arrived in Calgary last Thursday for a day of speechifying and meeting with energy leaders, and was criticized for not contributing something to the resolution of the oil price crisis beyond a few tax breaks announced in Ottawa’s fall fiscal update.

Notley quite rightly pointed out in her speech to drilling contractors the same day that the market access problem is not of Alberta’s making, that pipeline reviews and approvals are federal jurisdiction, yet the province is being left to struggle alone to find solutions.

While industry debates the merits of curtailing production, economists have weighed in against the idea.

Prof. Kent Fellows is an economist with the School of Public Policy at the University of Calgary. He says that “the first and best place to look for solutions is in find ways to increase export capacity. Literally every additional barrel of export capacity will help as long as the transportation cost is lower than the portion of the differential associated with the transportation constraint.”

The idea of a royalty credit to encourage curtailment doesn’t appeal to him, either.

“While some level of production shut in may be necessary, the market will end up dictating this over time anyway. I don’t see a reason why the province needs to provide an additional incentive here,” he wrote in an email to Energi News.

The answer to Prof. Fellows’ objection may be political.

Unlike economists, politicians must calculate the cost of acting versus not acting when an economic crisis arises. The Premier has already appointed a trio of envoys to meet with industry leaders to suss out potential solutions and she expects a report from them in a few weeks.

With an election only six months away, she can’t afford to wait for market forces to fix the problem. UCP leader Jason Kenney, who is strongly supported by the smaller producers most harmed by the high differentials, has already said Alberta should “leave the door open” to mandated production cuts.

The Premier appears to have little wiggle room and little time to make a decision. If she must order producers to curtail production under the authorities granted by the Alberta Mines and Minerals Act, she should seriously consider making the cuts voluntary using a royalty credit.

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Texas oil production is booming like never before, especially in the prolific Permian Basin, but just like Alberta, job numbers are not climbing at the same rate as output. Economist Karr Ingham says a new generation of technology is responsible and many oilfield jobs are not coming back. Just like Alberta.

Texas is the primary beneficiary of the “shale gale,” as IHS founder Daniel Yergin called it. From a low of just 1 milllion b/d in 2005, oil supply peaked at 4.2 million b/d (including condensate) in May and the US Energy Information Administration is forecasting a lot more growth over the next five to 10 years.

When prices peaked in late 2014, Texas was producing 3.5 million b/d of crude oil. Despite West Texas Intermediate prices falling below $30/b, supply kept growing during the downturn, according to the EIA.

Oilfield employment did not.

Ingham estimates that by the time employment bottomed out in early 2017 Texas had lost 231,500 total direct oil and gas jobs and the state economy lost four times that number of indirect jobs.

Upstream employment has begaun to recover, but is far below what levels that would have been expected during historic upturns given production levels.

As of midyear 2018, about 47,000 jobs have been added back to upstream oil and gas company payrolls following the loss of over 115,000 jobs over the course of the downturn, according to Ingham.

“Jobs have certainly been added back in the current expansion, and job growth continues moving into the second half of 2018,” he said. “But again, estimated upstream oil and gas employment as of June 2018 is down by over 68,000 jobs compared to peak industry employment levels in late-2014, and still crude oil production is at record levels and continues to climb.”

The Texas Alliance of Energy Producers staff economist attributes the decoupling of employment and production to aggressive innovation by industry.

“The efficiencies achieved by Texas oil and gas producers, service companies, and drilling companies are nothing short of stunning, and in part were borne of necessity during the deep contraction of 2015 and 2016. But this is what all industries strive to do – produce more with less and at lower costs,” Ingham said in a press release last week.

New technologies are affecting employment in two ways.

One, technologies that directly affect production. Ingham says the three big ones are hydraulic fracturing, horizontal drilling, and drilling multiple wells from a single pad, innovations that are a decade old.

“It used to be, not that long ago, that one rig meant one hole drilled. Now, because of pad drilling, you park a rig in a spot and you drill eight or 10 wells from there,” he said during an April interview.

There are plenty of smaller innovations, such as better drill bits, that are an important part of that leap forward in production efficiency.

Two, technologies that are transforming the oil and gas business model, the way companies conduct their business.

Those technologies include big data/analytics, artificial intelligence and machine learning, blockchain, automation, robotics, and much more.

The oil and gas business has always been about better technology, but the high tech equipment streaming into the market provide efficiencies that are a quantum leap ahead of the way industry did business in the past, Ingham says.

“It’s not something new, but it seems new to us because we’re watching it play out in a specific industry before our very eyes and more rapidly than ever before,” said Ingham. 

He says rapidly adopting new technologies to replace workers is now a permanent feature of the Texas oilfield.

Not surprisingly, the surplus of oilfield labour natural led to lower wages for those workers who managed to keep their jobs.

“When prices go down, producers and everyone involved in the industry has to find a way to cut costs. One of the ways they do that is just to shed themselves of hundreds of thousands of employees. And the ones that are left get paid less,” he said, pointing out that rates in the services sector have still not recovered, which prevents employers from paying higher wages.

There is no shortage of applicants for new oilfield jobs, says Ingham, even at lower wages: “Even though wages are lower than they were at their peak periods, they’re still higher than you can find in many other sectors of the Texas economy.”

The type of worker required by oilfield companies is also changing.

“As the industry becomes more technologically advanced, it requires at least at some levels more technically advanced skills,” he said. “Your skill set, which may have been just fine for that period of time where there were 150,000 more jobs out there than there are right now, now may be lacking because you may not be competitive.”

Ingham is upbeat about the future of the Texas oilfield given rising production and the improving financial health of shale oil companies.

Every one of his observations about the adoption of new technologies and rising labour productivity coupled with lower employment levels applies to Alberta, as I described in my long-form report, Technology and the 21st century energy worker: Where are the jobs? 

The takeaway for Albertans, the most important lesson, is that these changes are structural – baked into the cake, as it were. Every oil producing jurisdiction is wrestling with them.

Unemployed petroleum engineers and geoscientists roaming Calgary’s office towers looking for a job even as the provincial industry recovers is now a feature, not a bug, of the modern oil and gas economy.

The post Rising oil production with fewer workers: Albertans can learn from Texas example appeared first on Thoughtful Journalism About Energy's Future.

In 2017, a group of the world’s largest publicly traded oil and natural gas producers added more hydrocarbons to their resource base than in any year since 2013, according to the annual reports of 83 exploration and production companies, according to the U.S. Energy Information Administration.

Collectively, these companies added a net 8.2 billion barrels of oil equivalent (BOE) to their proved reserves during 2017, which totaled 277 billion BOE at the end of the year. Exploration and development (E&D) spending in 2017 increased 11% from 2016 levels but remained 47% lower than 2013 levels.

Of the 83 companies, 18 held more than 80% of the 277 billion BOE in proved reserves at the end of 2017.

Although many of these companies have global operations, some are national oil companies with reserves concentrated in their home countries, including Russia, China, and Brazil.

Proved reserves change from year to year because of revisions to existing reserves, extensions and discoveries of new resources, purchases and sales of proved reserves, and production.

Organic additions to proved reserves, or reserves added through improved recovery and extensions and discoveries, are linked directly with capital expenditures in E&D.

Proved reserves acquired through purchases do not represent E&D capital investment but rather reflect transfers of assets between companies.

Revisions to proved reserves are usually more significantly influenced by changes in crude oil and natural gas prices than by E&D investment.

Of the 17.7 billion BOE in organic proved reserves added in 2017, slightly less than half (8.5 billion BOE) were in the United States, while Russia, Central Asia, and the Asia-Pacific region accounted for 24% (4.3 billion BOE).

Canada (which includes oil sands and synthetic crude oil), Latin America, and the Middle East and Africa regions each added more than 1.1 billion BOE.

Regionally, Europe accounted for the fewest organically added proved reserves for the sixth consecutive year, adding 0.3 billion BOE (2% of world total) of proved reserves in 2017.

Global E&D spending by region was similarly distributed. Of the $285 billion companies spent on E&D in 2017, 33% ($95 billion) was in the United States, with the Russia, Central Asia, and Asia-Pacific region accounting for 30% ($85 billion) and all other regions each accounting for 10% or less.

Changes in nominal year-over-year E&D spending varied across regions, increasing by 36% in the United States and by 15% each in Canada and the Russia, Central Asia, and Asia-Pacific region. Spending declined by 24% in Europe, 16% in the Middle East and Africa, and 15% in Latin America.

Because of a disparity between the timing of companies’ capital expenditures and the formal reporting of changes to their proved reserves, standard practice is to average the results over several years.

Analyzed this way, E&D costs declined significantly on a per BOE basis from the 2012–2014 average to the 2015–2017 average. Three-year average E&D capital expenditures per BOE of organic proved reserves additions decreased in all regions except Latin America.

On an annual basis, 2017 represented the lowest E&D capital expenditures per additional BOE to proved reserves during the 2012–2017 period at $16.12/BOE.

First-quarter 2018 capital expenditures for this set of companies were 16% higher than in first-quarter 2017, suggesting that many of these companies have increased their E&D budgets, which will likely contribute to further organic proved reserves additions in 2018.

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