Should a Montney Gas Producer Develop LNG or Just Buy Devon Oil Sands Asset?

May 16, 2019

Producers holding reserves in the Western Canadian Montney play have been searching for monetization solutions since last year’s open season for the Alliance Pipeline expansion capacity fell flat. LNG liquefaction presents a potentially large gas demand market with Henry Hub plus 15% pricing for Western Canada producers. However, would a more direct monetization route be to purchase a producing oil sand asset with ~100 million cubic feet per day (MMcf/d) of gas demand for in situ steam production instead?

Why Marcellus Drilling Activity Increased in 2018 While Montney Activity Declined

May 14, 2019

Drilling activity in the Appalachian basin, particularly in the Marcellus shale play, has increased significantly in 2018 compared to drilling that took place in 2017. A total of 1,066 gas wells were drilled in the Marcellus in 2018, a 59% increase from 670 wells drilled in 2017. Most of these wells were drilled in NE Pennsylvania, producing dry gas that does not require significant processing.

Is There a Public-Private Partnership Solution for West Coast LNG?

April 30, 2019

The Western Canadian natural gas industry is facing unforgiving competition from burgeoning US Lower 48 supply. Due to its relative location to market and existing infrastructure, production growth in Marcellus shale gas and associated shale oil has displaced Canadian gas supply traditionally exported to the US Midwest and Northeast markets. Small-scale solutions within the Western Canadian Sedimentary Basin are being explored to increased intra-basin demand. However, LNG remains the way to replace Bcf/d level market demand that has been lost.

Application of Nanotechnology in the Oil and Gas Industry

April 26, 2019

Since the late 1980s, countless technological advancements in many industries have been attributed to the application of nanotechnology. Nanotechnology is a multidisciplinary field that involves the manipulation of matter at the nanoscale level (1 – 100  10-9m). The unique physical and chemical properties of the resultant nanomaterials allow nanotechnology to serve as an advance platform to provide solutions to complex problems. In the wake of rising challenges facing the oil and gas industry, properties such as large surface area, high aspect ratio, mechanical strength, and high chemical reactivity have the ability—through the application of nanotechnology—to provide durable, less risky, and cost-effective alternative solutions to overcome technical and environmental issues associated with various oil and gas activities.

Will Permian Have Sufficient Pipeline Capacity?

April 25, 2019

Growing Permian production and tight pipeline capacity saw Midland-WTI spreads widen in 2018. Permian production rose from 0.4 million barrels per day (MM bbl/d) in 2010 to 2.05MM bbl/d in 2017. However, in 2018, production did not increase as quickly as previous years due to infrastructure constraints (i.e., oil pipelines, associated gas processing, NGL and gas pipeline infrastructure, and water infrastructure for fracking operations, etc.).

Moving forward, Solomon expects continued expansion of oil pipeline capacity to exceed production; however, the ability of refining capability to handle light barrels has started to reach its limits, shifting the bottleneck toward very large crude carrier (VLCC) export capabilities.

Will Permian Oil Production Continue to Grow?

April 18, 2019

Permian crude oil and lease condensate production in December 2018/January 2019 reached 4 million barrels per day (4MM bbl/d) and 13 billion cubic feet per day (13 Bcf/d) of gas. But will this trend continue until 2030? Does Permian have enough economically viable resources to ensure production growth? Solomon analysis confirms that Permian full-cycle cost will remain the lowest among United States Lower 48 tight oil basins, and lower than other tight oil basins such as Bakken and Eagle Ford. Significant resources at relatively low cost will lead to production growth in the next few years.

Why Do US Refineries Need Canadian Heavy Oil?

April 18, 2019

Refining capabilities to handle light barrels is nearing existing designed capacity limits, shifting light barrels to export markets. Near-term export bottlenecks will be solved with the completion of an additional 2 to 3 Very Large Crude Carrier (VLCC) export loading facilities. Economics and cost of upgrades to increase refinery capacity of light barrels require long-term planning and investment. Current assets supporting the imports of heavy oil continue to remain an economic alternative to satisfy refinery input diets.

Canadian East Coast Oil Production Summary

April 11, 2019

There are four producing regions offshore Newfoundland (Hibernia, White Rose, Terra Nova, and Hebron).

Overall offshore Newfoundland oil production averaged 230M bbl/d up from 220M bbl/d in 2017. Hebron production offset declining production of White Rose, Terra Nova, and Hibernia.

Canadian Oil Sands Production Forecast

April 9, 2019

After posting an 8.1% per year growth rate from 2010 to 2018, Solomon forecasts Alberta oil sands growth to slow with the completing of new large-scale mining projects. Solomon now forecasts an average annual growth rate of 2.9% (from 2.9MM bbl/d in 2018 to 4.2MM bbl/d in 2030). This represents nearly 80% of total Canadian oil production in 2030.

Will Gulf of Mexico Production Continue to Grow After 2019?

April 4, 2019

Oil production in the Gulf of Mexico (GoM) Deepwater grew to 1.4 thousand barrels per day (M bbl/d) in 2018 from 1.2M bbl/d in 2015. But will it continue to grow in the future? The Gulf of Mexico Deepwater oil development requires significant capital and lead time for exploration and development drilling, construction, and installation of production facilities and pipelines. However, the size of the resource and the production capability of the wells have the potential to make the projects economical. Although high, the capital cost of GoM Deepwater is 14 United States dollars per barrel (USD/bbl) and higher, the operating cost for GoM Deepwater is only 5.27 USD/bbl compared with around 9 USD/bbl in Permian basin. Solomon estimates that Gulf of Mexico Deepwater production will be only 8% of total North American Oil Production in 2030, down from 10% in 2019.

What are the NGL Resources in Western Canada?

April 2, 2019

Natural Gas Liquids (NGL) are components of natural gas separated from raw gas in form in liquids. They include ethane, propane, butane, pentane, and other components and used as an input for petrochemical industry, heating, or can be blended with gasoline into vehicle fuel. In Western Canada pentane plus is used for diluent for bitumen to transport it by pipeline. Western Canada currently produces 820 thousand barrels per day (M bbl/d) of NGL or 300 million barrels per year (MM bbl/yr). NGL production in Western Canada will grow to up to 1,000M bbl/d in 2030. But does Western Canada have sufficient NGL resources?

What is a Sustaining Cost of Oil Sands Projects in Western Canada?

March 24, 2019

Solomon analyzed sustaining cost of all major in-situ and mining oil sands projects. The analysis shows that sustaining cost for most projects was lower than average 2018 WCS price for in situ project and 2018 SCO price for mining project. However full-cycle cost of new projects is significantly higher. Full-cycle cost for new projects include full-cycle capital and cost of capital. New in situ projects need a bitumen price of 47 United States dollars per barrel (USD/bbl) to break even under today’s cost structure. Mining projects are able to cover their cash cost, overhead costs, and sustaining capital. New mine projects need an SCO price of 58 USD/bbl to break even.

Western Canadian Pipeline Capacities and Flow: Will We Have Enough Pipeline Capacity After 2021?

March 14, 2019

The figure shows total Western Canada oil supply, pipeline capacity, Alberta refinery demand, and potential pipeline expansions through 2030. In the near term, oil production in excess of demand and pipeline capacity will be transported to market by rail cars. Forecast observations:

  • With regulatory uncertainty and government intervention, oil sands producers have switched from business development strategy to an operations strategy. Therefore, Solomon believe producers will take a cautious wait-and-see approach and production will lag pipeline developments.
  • Enbridge flows are expected to increase until 2020 as Line 3 comes into service.
  • TransMountain Expansion completion in 2021 diverts rail and Enbridge Midwest directed flows toward West Coast/Asian markets.
  • In 2022, Keystone XL in service further erodes flows on Enbridge towards Cushing and Gulf Coast markets.
  • With incremental new pipe completed in 2022, rail shipments are no longer economic.

What are the Effective Oil and Gas Royalties in 2017–2018?

March 12, 2019

The figure shows effective royalty rates for the Western Canadian Sedimentary Basin for oil and gas. The last 4 years were based on the analysis of data from 30 publicly traded producers. Effective royalty rate for oil for 2017 was around 14% and for gas around 8%. Solomon expects that 2018 royalty rates will be similar.

Oil Sand CO2 Emissions: Will Alberta Exceed the Cap?

March 7, 2019

As part of the current Alberta New Democrat government’s climate change policy introduced in November 2015, emissions from oil sands development will be capped at a maximum of 100 metric tonnes per year (MT/yr). The figure shows CO2 emission forecast, based on Solomon’s forecast of oil sands production and emissions intensity. Solomon expects that as new technologies are more widely integrated (solvent injection, incremental infill wells), emissions intensity will decline. The hashed line illustrates a 1.2% per year increased efficiency in mining and in situ intensity and would effectively lower Solomon’s forecast for carbon emissions, which does not reflect any improvement in emissions intensity. The bottom line—Solomon expects that Alberta Legislative Emission cap will not be exceeded before 2030, which is good news for both producers and the environment.

How Break-Even Cost of Tight Oil and Shale Gas Would Change Over Time

March 5, 2019

Solomon developed a model to forecast full-cycle cost for individual basins and across large regions. This model includes all factors listed in the article. The figure presents full-cycle cost forecast for Bakken oil. Current average full-cycle cost for Bakken oil based on data from all wells drilled in Bakken in 2017–2018 is about 43 United States dollars (USD). This cost will decline due to improved well productivity. New pipeline infrastructure will also contribute to the cost decline. However, after 2028, the cost will grow due to the maturity of the basins.

E&P Company Cost Reductions – Cyclical or Structural?

July 1, 2017

When studying economic conditions for a given market, economists often consider whether determining factors are “cyclical” or “structural” in nature. A cyclical disturbance is thought of as a business cycle impact that will revert back toward previous levels over a short-term time horizon (months to years); costs rise and fall with the overall economy’s expansion/contraction cycle. Structural changes are thought to be longer-term to permanent. Examples illustrating a structural change entail regulatory changes (regulations reducing sub-prime lending on homebuilding) or disruptive technology (Ford assembly line innovation on horse whips).