Gas Supply

* only 20 largest public oil and gas producers are included.

Weighted Average royalty rates are calculated based on net and gross proved oil and gas reserves reported by the producers in their regulatory disclosures.

The data includes non-associated and associated gas production from 25 largest Canadian gas producers operating in WCSB. Data source is public disclosures, such as Annual Information Forms.

Production is gross – before royalties.

Data from some private producers and NOC (such as Pertronas) is not included.

The data includes non-associated and associated gas production from 25 largest US gas producers operating in Low 48. Data source is public disclosures, such as 10-K forms.

Data from some private producers is not included.

The chart shows Western Canada gas production to 2030 by gas type and the growth needed to meet LNG export demand. Key observations include:

• Short- and medium-term natural gas energy outlook in Western Canada is affected by uncertainties with COVID-19. Solomon expects that Western Canada natural gas demand would drop 0.4 billion cubic feet per day (Bcf/d). The drop is attributed to lower industrial and oil sands demand, as well as lower flows on Northern Border as new gas plants are brought online in the Bakken.
• While yearly average Montney and Duvernay production would remain relatively flat, conventional, CBM, and particularly associated gas production will decline.
• Most Western Canada gas production growth before 2030 will come from the Montney, Duvernay, and Alberta Deep Basin plays. Most production growth in Deep Basin will come from Notikewin-Falher, Wilrich, and Spirit River formations
• LNG exports will be the driver for WCSB demand and production growth.

Montney tight-gas production will continue to grow as evaluation and development continue, expanding after 2022, when gas supply will be needed for LNG export markets.

Montney is a tight-gas play with lateral facies variations of fine-grained sedimentary rocks leading to areas of non-commercial, low-gas-rate production.

The chart shows gas well connections to 2030. Well connections peaked at more than 18,000 in 2006 and declined significantly thereafter as gas prices plummeted and producers increased high-productivity horizontal well drilling.

The chart shows the average new gas well IP in Western Canada to 2030. Gas well IP is expected to decline due to continued development of high-yield NGL wells in the Montney, Duvernay, and Deep Basin tight-gas formations. However, after 2022 IP will continue to grow again when liquids-rich areas become more mature, and drilling in lean and wet areas of the basin will proceed to meet LNG requirement.

The figure shows the location of the Deep Basin tight-gas plays in Western Canada as well as the dry-gas production forecast for Notikewin-Falher, Wilrich, and Spirit River. Production from these formations uses the same technology that is used in Montney and Duvernay development: multi-well pads, horizontal drilling, and multi-stage fracing.

Producers have focused on developing the northern portion of the Duvernay play—the condensate-rich, sweet-gas play—which has one of the lowest break-even gas prices in North America due to significant NGL uplift. Development of the southern area (Willesden Green) started a few years ago. Duvernay East area is an oil play with high associated gas content.

Capital costs have been reduced significantly as operators focus on drilling and completion efficiencies with technology enhancements.

The chart shows Western Canadian dry-gas production per play. In 2030, most production will come from Montney BC.

The figure shows locations of wells drilled in 2019 in Western Canada. Almost all wells were drilled in Montney, Duvernay, and Deep Basin Cretaceous.

The chart shows Montney and Duvernay gas well connection forecast to 2030. Montney and Duvernay will represent around two-thirds of all gas well connections in Western Canada.

Rig count is an important indicator for short-term production outlook. Canadian gas rig count has seasonal fluctuations due to winter drilling in most productive areas of the basin, primarily in British Columbia (B.C.). Usually rig count increases in winter months and drop in summer months.

The chart shows Canadian gas rig count since 2011 together with the trend line.

The chart shows average new gas well IP per major North American basin. IP is calculated based on raw gas production reported by producers. It does not include lease condensate or oil extracted at the wellhead, but includes natural gas liquids extracted at gas plants. The Haynesville play holds the record for the highest average raw gas IP of 19 MMcf/d, followed by the Utica West and Marcellus Pennsylvania North East basins. Eagle Ford raw gas IPs increased in the last few years because areas with high condensate yield have matured, and operators are finding more wet, lean gas. In the Montney AB basin, gas well IP declined after 2016 due to producers’ focus on high condensate development with lower gas IPs.

The Utica shale is located in the Appalachian Basin, a few thousand feet below the Marcellus shale. The map shows the extent of the Utica shale in Ohio, Pennsylvania, New York, and West Virginia. The Utica also extends under the Great Lakes and into Canada. Currently, development is focused on the western portion of the Utica in Ohio and western Pennsylvania, where wells yield large amounts of gas, natural gas liquids, and crude oil.

Utica East is deeper, contains mostly dry gas, and is located mainly in Potter and Tioga counties in Pennsylvania.1 Utica East’s thickness in this area could reach 400–500 feet (ft). Solomon estimates Utica East to contain 68 trillion cubic feet (Tcf) in resources, including 10 Tcf with a full-cycle cost below 3.00 United States dollars (USD). The average full-cycle cost for Utica East wells is 3.12 USD, higher than the average full-cycle cost of 1.45 USD in Utica West. Average liquids uplift in Utica West is 2.05 USD versus no uplift in Utica East. However, condensate sweet spots in Utica West will mature over time and the relative economics of Utica East will improve, leading to modest production growth in Utica East.

The figure shows the remaining gas resource in Canada based on the number of wells already drilled at the end of 2018.

Note: Resource analysis was conducted based on wells drilled.

• Since 2002, Horseshoe Canyon coalbed methane (CBM) has moved from pilot projects through commercial development to maturity.
• Horseshoe Canyon coals are dry—only small amounts of water are produced.

The figure shows North American natural gas resource by type of gas resource and by region based on the number of wells drilled by the end of 2018. The size of the pies corresponds with the regions’ remaining gas resources.

Note: Resource analysis was conducted based on wells drilled.

Appalachian gas production is predominantly lower-cost gas from Marcellus and Utica shales.

The figure shows Solomon’s estimate of Appalachian shale gas resources based on the number of wells drilled by the end of 2018. The size of the pies corresponds with the regions’ remaining resources.

Note: Resource analysis was conducted based on wells drilled.

• East cost natural gas remaining resources include Appalachia and Eastern Canada.
• Almost all Appalachian remaining resources are in Marcellus and Utica, Marcellus shale resources.

Note: Resource analysis was conducted based on wells drilled.

The figure shows the US gas rig count to 2030 for key basins.

Shale – Newest & fastest growing gas source in the US, most growth from Appalachia (Marcellus and Utica).

• Shale is much tighter (lower permeability) than sand & carbonate reservoirs. Associated gas from tight oil is not included; the chart shows dry gas from gas wells.

The figure shows historical dry-gas production (associated gas is not included) from 2010 to 2019 (blue bars), and each key region’s anticipated production forecast to 2030 (red bars). Only major basins and plays within the major producing regions are presented and summarized.

The chart illustrates the continued growth of dry-gas production in North America.

The charts present gas production, well connections, and IP by play to 2030.

The charts present gas production, well connections, and IP by play to 2030.

The charts present gas production, well connections, and IP by play to 2030. Solid blue areas represent production from wells drilled before 2019; hatched blue areas represent production from new wells.

The charts present gas production, well connections, and IP by play to 2030. Solid blue areas represent production from wells drilled before 2019; hatched blue areas represent production from new wells.

The charts present gas production, well connections, and IP by play to 2030. Solid blue areas represent production from wells drilled before 2019; hatched blue areas represent production from new wells.

The charts present gas production, well connections, and IP by play to 2030. Solid blue areas represent production from wells drilled before 2019; hatched blue areas represent production from new wells.

The charts present gas production, well connections, and IP by play to 2030. Solid blue areas represent production from wells drilled before 2019; hatched blue areas represent production from new wells.

The charts present gas production, well connections, and IP by play to 2030. Solid blue areas represent production from wells drilled before 2019; hatched blue areas represent production from new wells.

The charts present gas production, well connections, and IP by play to 2030. Solid blue areas represent production from wells drilled before 2019; hatched blue areas represent production from new wells.

The chart shows US Lower 48 gas well connections for four regions: Appalachia, Rockies, Mid Continent & Permian, and GOM & Gulf Coast.

The chart shows rig count forecast in the main producing areas.

Appalachian gas production is predominately lower-cost development from the Marcellus and Utica shales. Appalachia’s rig count dropped significantly in 2015–2016.

US Gulf Coast (USGC) and Gulf of Mexico (GOM) gas production is a mix of conventional (mostly offshore) and unconventional onshore (tight and shale gas) as shown on the map. The USGC includes the South Texas region with liquids-rich Eagle Ford shale gas and East Texas/North Louisiana (ET/NL), which includes Haynesville shale gas.

The map shows new gas well initial productivity distribution for Eagle Ford.

The map shows new gas well initial productivity distribution in Haynesville.

The Rockies region consists of the Green River, Piceance, Uinta, Powder River, and San Juan basins.

The figure illustrates gas reserve replacement results (2017 vs 2018) for the 30 largest public gas producers in the US and Canada.

The figure compares Solomon’s analysis of the top 30 public US gas producers since 2010 and the overall gas industry results as reported by the US Energy Information Agency (EIA).

The figure illustrates the Lower 48 gas reserves “added” versus “produced” for the top 30 producers.

The figure illustrates the Lower 48 gas reserves “added” versus “produced” for the top 30 producers (box detail).

The figure shows the proved Gas Reserve Life Index for the top 30 US gas producers.

The figure shows the proved Gas Reserve Life Index for the top 30 US gas producers (box detail).

The figure compares Solomon’s analysis of the top 30 Canadian producers from 2010 to 2018.

The figure presents the proved gas reserve replacement for the top 30 Canadian gas producers.

The figure presents the proved gas reserve replacement for the top 30 Canadian gas producers (box detail).

The figure shows the Canadian proved Gas Reserve Life Index.

The figure shows the Canadian proved Gas Reserve Life Index (box detail).

Figure shows dry gas production change between 2005–2016 and 2017–2030. Green represents low full cycle cost, yellow represents average full cycle cost, and red represents high cost.

Chart on left shows all Marcellus well IPs.

• Plays are not homogeneous.
• IPs range from 1 MMcf/d to 16⁺ MMcf/d (dark red dots).
• Most productive areas are drilled first as they will generate highest producer returns.
• As highest productivity areas are exhausted, less productive and higher-cost areas are targeted.
• Solomon’s supply forecast methodology:
  • Historical well data are collected, filtered and formatted to ensure quality and consistency. Then, estimated ultimate recovery (EUR) is calculated for each well using traditional decline analysis. In each basin, all wells are plotted in a map based on their initial productivity (IP) or EUR. A contour is used to group wells into ranges based on their IP. These groups of IP/EUR ranges are called bins. Accordingly, the total area associated with different bins is estimated. After that, GIS analysis and data reported by producers (lateral length, frac width, etc.) are used to calculate well spacing for each bin. The number of potential drilling locations in a bin is estimated from the total bin area divided by the area per well. Total resources per bin is then obtained by multiplying well EUR by the number of drilling locations for that particular bin. There is a full cycle cost associated with each bin calculated per unit of production. Thus, areas with higher productivity within a play will have lower full cycle cost.

Chart shows the steps to put a well on production (adding to gas supply):

• Start drilling a well (spud)
• Finish drilling (rig release)
• Completing the well
• Connecting the well to a gas plant via a gathering pipeline system

Technology revolution is an important lever; however, its impact on costs has been masked by the large effect of reserve size changes and cost inflation. Figure shows some changes of this decade including:

• Exploration – High frequency seismic with seismic processing, natural fracture identification by seismic.
• Drilling – Coiled tubing and top drive rigs, horizontal and multilateral wells, multi-well locations, multi-well pads and programs, real-time data, geo-steering with near bit sensors, under-balanced drilling, slim hole wells, monobore wells/expandable casing & tubulars, new bit designs, high pressure & high temperature wells, and automation (such as pipe handling).
• Completions – Multi-zone completions, optimized, standardized programs, non-damaging low polymer fluids, ceramic proppants, micro-seismic for fracture propagation detection, re-fracturing, re-completions, soak time.
• Production – Automated controls, remote well telemetry, optimizing well spacing and production, choke initial production increases EUR.
• Pipelines – Smart pigs, high pressure pipe, improved compressor efficiency.

1. DEWATER/DEPRESSURE: Water is pumped from the fracture and cleat system in the coal.
2. DESORPTION: Coal formation pressure falls, natural gas, which is absorbed on the surface of organic material, is desorbed from the organics and diffuses through the coal to the cleat and fracture system.
3. GAS FLOW: As more water is pumped out, more gas and less water are produced.
4. With further gas production, the rate of desorption falls (less gas remains absorbed on the surface of the organic material) and gas production falls.
5. Water production and disposal is expensive, lower cost (shale) gas is being developed; CBM production is declining.

The chart provides our forecast for East Coast gas production.

Alaska

• Alaska Government in 2007 approved the proposal submitted by TransCanada Pipeline (TCPL) under the Alaska Gasline Inducement Act (AGIA). Gas would be transported to Alberta and tied-in to the TCPL system & includes an option to build a line to transport gas to Valdez for LNG.
• Decision made in 2014 that the pipeline project to Alberta was not economical.
• Alaska Gasline Development Corporation (AGDC) signed agreement with BP PLC and ExxonMobil to help advance the 43.4B USD LNG project to be built in Nikiski on the Kenai Peninsula south of Anchorage. This project includes the construction of a 1,300 km pipeline from the North Slope.

Mackenzie Delta

• Mackenzie Valley Pipeline designed for 1.2 Bcf/d.
• Cost details: pipeline, field development & gathering system, gas plant & liquids pipeline.
• March 11, 2011 – NEB issued a certificate of public convenience and necessity following federal cabinet approval.
• Dead, a victim of the technology revolution.

Chart shows yearly gas well connections by major US basins from 2005–2018 (blue bars) and Solomon‘s forecast (red bars).

Figure presents gas well connections by area from 2010 to 2018, and Solomon‘s outlook for connections to 2030.

Figure shows the fall in new gas well initial productivity (IP) in both regions of Gulf of Mexico.

Figure presents our production outlook reflecting gas well connections, new gas well productivity, and gas well declines.

• Many plays have been evaluated; few plays live up to early promise and quietly drop off the radar.

Anadarko basin has liquids-rich gas, mostly in southern portion of the basin, and tight oil and the north.

• Hydrates are solid, crystalline, ice like substances containing methane/water with methane trapped in in a water-ice lattice.
• Form under moderately high pressure at temperatures near freezing, in permafrost areas, sea bottom or under seabed.
• Shows data for US and Canada only.

The figure illustrates Solomon assessment of Duvernay NGL yield distribution based on well and processing plant data allocated to the particular wells.

The figure shows dry gas production for major US gas basins to 2030. The solid blue area represents production from gas wells drilled before 2018; the hatched blue is Solomon‘s forecast of production. In 2018, US natural gas production growth and development is primarily focused in three basins: Marcellus, Utica, and Haynesville.

The chart shows North American dry gas production to 2030 by gas type: Associated (Solution), Conventional, Coalbed Methane (CBM), and Shale & Tight Gas.

• North American gas supply is demand driven.
• North American gas supply mix is “Unconventional” Gas—the new conventional gas.
• Higher-cost conventional gas production will continue to decline.
• Shale and tight gas growth will come mostly from liquids-rich areas of Utica, Marcellus, Haynesville, Montney, and Duvernay.
• Associated gas will increase mainly because of the growth of tight oil production in Permian, as well as in Bakken, Eagle Ford, and Niobrara.

Solomon calculates initial productivity (IP) as the average of raw gas peak month production for all gas wells per basin.

The figure shows average initial raw gas productivity of gas wells since 2010; dark-red bars are history, red bars are Solomon‘s forecast.

In this low-price capital-constrained environment, producers drill only the best (i.e., highest productivity wells), so IP increases.

The figure shows the rig count over the forecast period (2018–2030).

• Appalachia’s rig count dropped significantly in 2015–2016 due to low regional gas prices and pipeline and processing infrastructure constraints. Also, due to significant improvements in well productivity and reduced drilling times, fewer wells are required to sustain or increase production.
• Haynesville rig count started to climb in 2016. Eagle Ford gas rig count also increased starting the fourth quarter of 2017. The total rig count will continue to grow during the forecast period mostly due to increased drilling in Haynesville.
• The Mid Continent and Permian region shows a stable rig count during the forecast period. Currently, there is only one rig operating in Fayetteville, three rigs in Barnett, and six rigs in Arkoma Woodford. There is no new gas drilling in Granite Wash and Woodford Cana.

The figure presents the supply-demand balance for the Appalachia region. Overall demand growth (2.0% per year) is expected to be outstripped by supply (7.3% per year), creating a need to move excess supply to regions outside of the US Northeast.

• The North American pipeline grid is interconnected and responsive to changes in Henry Hub pricing.
• In 2017, the region had net outflows of natural gas on an annual basis.
• Marcellus and Utica gas will continue to grow, backing out Rockies, Western Canadian, and US Southwest gas supply.
• As infrastructure enhancements are completed, excess supply will look to flow to high-value LNG markets* and those markets along the eastern seaboard.
• Gulf Coast and Midwest markets will provide the least value for Appalachian natural gas supply in excess of demand.

*Cove Point in Maryland shipped its first LNG export cargo in March 2018.

The figure shows the variation in dry non-associated gas production trends between strategy areas, the forecast for dry-gas production to 2025 based on gas demand, Deep basin strategies in BC and Alberta will remain the fastest growing production areas in Western Canada.

Central Alberta, Southern Shallow, and Northern gas production will continue declining, with limited development of mature, high-cost conventional gas, and coal bed methane (CBM).

The figure illustrates Solomon’s assessment of the Duvernay natural gas resource geographic distribution using initial well productivities (IPs). Average Duvernay well dry-gas initial productivity in 2017 was 2.2 MMcf/d.

Solomon maintains proprietary models for key plays and basins in North America which are used to forecast annual average production based on:

• Allocation of aggregate demand for natural gas to the regions with the lowest relative gas supply cost first then the next lowest cost using gas resource-cost curves bearing in mind that producers will continue drilling to keep their infrastructure full (or optimized) and to fulfill contractual obligations.
• Drilling and completion activity trends considering availability of cash flow for capital investment, NGL content, play maturity (well density and remaining potential resource) and availability of equipment.
• New well initial productivity (IP); projected from recent trends and linked to Solomon’s gas resource mapping, considering play maturity.
• Production decline rates are applied to new and existing wells considering the age of the wells.

The models generate a raw-gas production forecast, which is converted to dry gas using shrinkage factors calculated from public sources and previous Solomon analyses.

This figure illustrates Solomon’s view of the distribution of North American ultimate potential natural gas resources subdivided by region and by break-even gas price. The size of the pie area corresponds with the regions’ ultimate natural gas resource potential. Ultimate potential resource is the amount of resource that is thought to be technically recoverable, without regard to the economics of extraction.

This figure shows Estimated Ultimate Recovery (EUR, measured in Bcf per well) for major North American Gas Basins in 2010, 2017, and 2025.

• Western Canada Conventional EUR on an average basis is very low, which makes the unit cost of adding reserves very high.
• The bright spot in Western Canada is the Montney tight-gas play in the NGL-rich part of the play.
• Appalachian EUR includes the Marcellus Shale; East Texas, North Louisiana EUR includes the Haynesville Shale; GoM Coast EUR includes the Eagle Ford Shale. 

This figure shows a schematic cross-section of the Ultra-Deep play and a map showing its relation to the Deepwater plays.

• The Deep Shelf lies more than 15,000 feet below the outer continental shelf, in water depths ranging to 1,000 feet.
• Much of the Deep Shelf could access existing Shelf infrastructure, saving development costs.
• The region is mature with today’s technology—3D seismic has been very successful in delineating shallower prospects, and production has declined since 2002.
• Potential remains for the pre-Miocene (productive onshore and in Deepwater) of the Ultra Deep Shelf (20,000 to 30,000+ feet), as demonstrated by McMoRan’s Davy Jones discovery.
• Advanced drilling technology is needed for these high-pressure, high-temperature Ultra Deep wells, which can cost over 100MM USD.

This figure shows the relative areal extent of key US shale plays; the Utica is a little smaller than the Marcellus. Note: The maps are sized to the same distance scale.

• Maps show initial productivities (IPs) used in Solomon’s production forecasting.
• The highest gas well productivity is shown in red, the lowest in dark blue.
• Wells are ranked based on their IPs; polygons with different ranges of initial productivity are generated; and the area of each polygon is calculated.
• Well density is calculated for each basin and each range of IP.
• Well connection forecasts are constrained by well density and maximum number for each range of IP.

This figure illustrates the hydrocarbon distribution in the Montney play ranging from dry gas (blue) to the southwest and oil (olive green) to the northeast. The figure also identifies the three core areas—BC North, BC South, and Alberta—which are further subdivided based on the hydrocarbon type.

• Condensate: over 80 bbl/MMcf
• Rich: 25–80 bbl/MMcf
• Wet: 10–25 bbl/MMcf
• Dry: less than 10 bbl/MMcf

Tight gas is not defined in Canada; Solomon defines it as:

• Laterally continuous, generally thick sands, conglomerates, and carbonates with low matrix permeability.
• Saturated with sweet gas and often liquids rich.
• Includes Greater Sierra (Jean-Marie) and the extended Deep Basin.
• Excludes Eastern shallow gas and the Foothills.
• Consistent need for large fracture stimulation to connect pore space to the well bore.
• Jean-Marie peaked at 520 MMcf/d in 2004; wells commonly horizontal and underbalanced.

Extended Deep Basin

• A thick section of Mesozoic low-permeability sands and conglomerates.
• Economics are improved by natural gas liquids (NGLs), using existing infrastructure, and commingling production.

• The two key technology advances for unconventional gas (and oil) are horizontal drilling and fracturing.
• Horizontal wells rapidly became the majority of gas wells drilled. The well is drilled vertically, but then, at the producing zone, the drill bit is steered until the well bore is horizontal. Drilling continues horizontally until the end of the well is reached. The horizontal section can be up to 5,000 ft long, and a number of horizontal sections may be drilled from the same vertical well.
• Horizontal wells increase the reservoir volume, which is in contact with the well so the well will produce at higher rates. Though horizontal wells cost more to drill than vertical ones, the higher cost is usually more than offset by the higher production. Pad drilling—multiple wells drilled from a single surface location—reduces the environmental footprint and costs.
• The figure presents a horizontal well schematic and the multi-stage hydraulic fracture stimulation that have been key to surging Shale Gas production and the growth of some Tight Gas plays. Each of the eight frac stages depicted in the figure is carried out sequentially, starting with the one furthest from the vertical part of the wellbore. Now over 2 dozen fracs can be done. The flow from an unconventional well mainly reflects the money invested in fraccing, not a natural flow rate, so we refer to it as a “manufactured” well. The initial rate is high, but drops off.