Gas Supply

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.

This figure shows historical dry-gas production from 2010 to 2018 (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.

• North American gas-production growth is driven by increased demand. Investment in low-cost plays attracts investment capital and grows, whereas investment in higher-cost plays stagnates and production declines accordingly.
• The largest production growth is expected in Appalachia (Marcellus and Utica) with nearly 80% growth from 2018 to 2030, followed by Western Canada with over 55% growth. Production from GOM & Gulf Coast as well as Rockies will have a moderate growth. Production from Mid Continent and Permian non-associated will decline.
• The gas basins are ranked based on the full-cycle cost of gas. Full-cycle cost of gas includes drilling and completion, land and seismic costs, operating cost, overhead, basis differential, taxes and royalties, producer return, and NGL price uplift.

Chart illustrates the continued growth of dry-gas production in North America since 2005.

• The increased maturity of tight-gas plays is forecast to continue in the Rockies and in Mid Continent & gas-focused Permian. Production from Mid Continent will decline over the forecast period. Production in the Rockies will decline until 2023 and then grow again when production cost relative to other basins will improve.
• Production growth from US Gulf Coast (USGC) and Gulf of Mexico (GOM) will reach 17.3 Bcf/d in 2030, primarily due to increased drilling in the Haynesville basin.
• Average initial gas well productivity in these growth basins will increase due to a strong focus on sweet-spot drilling and technology improvements.
• Most associated gas production will come from Permian Basin. Other associated gas production regions include Bakken, Eagle Ford, and DJ Niobrara.

The figure presents dry gas production and well connections by play to 2030. The solid blue areas represent production from wells drilled on or before 2018; hatched blue areas represent production from new wells post-2018. Red bars represent well connections.

The figure represents gas initial productivity by play to 2030.

The figure represents gas production, well connections, and IPs by play to 2030. Solid blue areas represent production from wells drilled before 2018; hatched blue areas represent production from new wells.

The figure represents Rockies and Permian gas production by basin to 2030. Due to play maturity and higher cost compared to other regions, the Rockies region will overall exhibit declining production out to 2030.

• Green River will grow slightly during the forecast period. Currently, major operators in Green River include Conoco, Ultra Petroleum, and Johan Energy.
• Major operators in Piceance are Terra Energy Partners, Laramie Energy, and Cearus Piceance. All of them focus specifically on Piceance.
• Almost no drilling is expected in Powder River and Uinta during the forecast period since these basins have the highest cost in the Rockies.

The figure represents Rockies and Permian IPs to 2030.

The figure represents Rockies and Permian gas connections to 2030.

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 charts represent gas production to 2030, well connections, and IP by basin.

The GOM has two gas-producing areas: the Shelf (shallow water) and the Deepwater. Production from GOM Shelf is expected to continue declining; even though Deepwater has the highest IP wells of all the basins and plays reviewed, its annual production will be marginal relative to the other areas due to the high Finding and Development (F&D) costs.

The figure presents Mid Continent and Permian gas production by basin to 2030.

The figure represents Mid Continent and Permian IPs to 2030. IP for all four basins will remain relatively flat to 2030.

The figure represents Mid Continent and Permian gas connections to 2030. The number of new gas-well connections in the Permian is expected to be around 360 in 2018, down from 570 in 2017.

The charts represent gas production to 2030, well connections, and IP by basin.

The chart shows US Lower 48 gas well connections for four regions: Appalachia, Rockies, Mid Continent & Permian, and GOM & Gulf Coast. US gas well connections will grow during the forecast period. Efficiency gains between 2010–2016 result in less connectivity requirements.

The chart shows rig count forecast in main producing areas.

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 chart shows Western Canada gas production to 2025 by gas type and the growth needed to meet LNG export demand.

• Liquefied natural gas (LNG) exports will be the driver for WCSB demand and production growth. Solomon expects that production of dry gas to meet LNG export requirements will commence in 2022. Until then, WCSB gas production will remain relatively flat.
• Western Canada’s gas supply mix will continue the shift to unconventional gas. By 2025, tight and shale gas will account for 84% of WCSB gas production, produced primarily from the Montney and Duvernay plays.

The figure shows the Montney gas forecast categorized by productivity and associated resource distribution. Montney tight-gas production will continue to grow as evaluation and development progresses, expanding after 2022, when gas supply will be needed for LNG export markets. The current development focus is for NGL-rich gas pools, with follow-up development of dry-gas pools’ downdip later in the forecast period.

Montney AB and BC rich-gas areas will provide the majority of Montney gas production growth in the forecast period. In conjunction with higher new gas well initial productivity (IP), these areas provide the most attractive well economics.

• Main operators in Montney BC area include Encana, Tourmaline, ARC, Crew Energy, and Shell.
• Actual average C3+ Montney yield in NGL-rich areas ranges from 40 barrels per million cubic feet (bbl/MMcf) in Montney BC North to more than 100 bbl/MMcf in Montney AB. Because of this, the AB rich-gas area will have a lower break-even gas price, due to the NGL revenue.
• Development of Montney dry gas will be limited due to poor economics resulting from low NGL yields.

The chart shows gas well connections to 2025. 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.

• Number of connections will remain in a narrow band through 2018–2022 due to flat demand for Western Canada gas supply. This number will slightly increase after 2022 to meet LNG export demand.
• With a continued increase in new gas well productivity from horizontal drilling in the western portion of the basin, fewer gas connections will be required to replace gas production lost to decline and provide for production growth.

The chart shows the average new gas well IP in Western Canada to 2025. Gas well IP is expected to increase due to continued development of the Montney, Duvernay, and Deep Basin tight-gas formations. However, growth of initial productivity after 2019 will slow down due to maturity of most plays and technological limitations.

In recent years, drilling has focused on liquids-rich gas. Economics are also improved by using existing infrastructure. Since our previous cost assessment, development has focused on Lower Cretaceous plays, including the Notikewin-Falher, Wilrich, and Bluesky-Glauconite, in the southern part of the basin.

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.

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 Solomon’s estimate of Appalachian shale gas resources. The size of the pies corresponds with the regions’ ultimate resource potential. Solomon estimates the total Appalachian ultimate resource potential to be 1,089 trillion cubic feet (Tcf) and includes Marcellus and Utica shale gas, undiscovered tight, conventional gas, and coal-bed methane (CBM).

Ultimate resource potential is the amount of resource that could be technically recovered with existing technology or small enhancements without regard to the economics of extraction. The estimates are presented on the basis of dry gas.

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).

Duvernay Play

• Producers have focused on developing the northern portion of the condensate-rich sweet-gas play, which has one of the lowest break-even gas prices in North America.
• Currently, development is limited to the narrow condensate window in the north core area. Duvernay East area is an oil play with high associated gas content. Evaluation of the southern portion of the play has lagged behind the north, due, in part, to continued infrastructure development and pool delineation.
• Capital costs have been reduced significantly as operators focus on drilling and completion efficiencies with technology enhancements. Particularly producers reported well drilling and completion cost of 6 thousand United States dollars (M USD) and less.

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.

The figure illustrates gas reserve replacement results (2016 vs 2017) for the 30 largest public gas producers in 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 Energy Information Agency (EIA).

The figure illustrates the Lower 48 gas reserves “added” versus “produced” for the top 30 producers. Reserves added on the charts include reserve additions through the “drill bit,” “improved recoveries,” and “revisions” of prior estimates.

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

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

This 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 2017.

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

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

This figure shows the Canadian proved Gas Reserve Life Index based on proved gas reserves for the top 30 Canadian gas producers.

This figure shows the Canadian proved Gas Reserve Life Index based on proved gas reserves for the top 30 Canadian gas producers (box detail).

This figure shows the gas resource potential of Western Canada and the East Coast.

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 dry-gas production change for 2005 to 2016 and 2017 to 2025. Green represents low full-cycle cost, yellow represents average full-cycle cost, and red represents high cost.

• The largest production growth is expected in Marcellus and Utica (Appalachian Basin).
• WCSB grows in response to gas demand for LNG exports after 2022.
• All growth areas are associated with lower full-cycle cost, which includes NGL price uplift.
• Although Green River and Barnett have average full-cycle cost, these basins will not experience growth due to maturity of the plays.

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

• 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.
• CBM is high-cost relative to other opportunities in Western Canada and North America and production is declining.
• Horseshoe Canyon gas-in-place resource is estimated to be 66 Tcf, though most of it is uneconomic.
• Mannville CBM was a pilot that failed to deliver commercially. Mannville coals are typically deeper and commonly wet, requiring costly water handling and disposal (re-injection back into deep disposal wells).

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.

This figure shows North American natural gas resource by type of gas resource and by region. The size of the pies corresponds with the regions’ ultimate resource potential.

Ultimate resource potential is the amount of resource that could be technically recovered with existing technology or small enhancements without regard to the economics of extraction. The estimates are presented on the basis of dry gas.