Top Producer Oil Reserve Replacement for 2017 vs 2018

Updated June 2019

The figure illustrates oil reserve replacement results (2017 vs 2018) for the US and Canada.

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Oil Reserve Replacement, Top 30 US Producers

Updated June 2019

The figure compares Solomon’s analysis of the top 30 public US oil producers since 2012 and the overall oil industry results as reported by the EIA.

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Oil Reserve Replacement, Top 30 Canadian Producers

Updated June 2019

The figure compares Solomon’s analysis of the top 30 Canadian producers from 2012 to 2018.

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North American Primary Oil Play Map

Updated April 2019

The figure provides a map of the main oil-producing basins in North America.

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North American Oil Production Outlook to 2030

Updated April 2019

The chart illustrates historical oil production* through 2017 and the outlook in North America from 2018 to 2030. 

  • Increased oil prices led to the continued growth in North American oil production. 
  • High-productivity, unconventional tight- and shale-oil activity will continue to displace higher-cost conventional crude oil development. The Permian, Bakken, and Eagle Ford basins will provide production growth over the forecast period.
  • Permian oil production will increase. Permian will remain a primary production region on North America during the forecast period.
  • This production growth from tight oil basins will be substantial, but will be partially limited by transportation, associated gas processing and refining constraints. Many US refineries are not configured for lighter grades crudes coming from tight-oil formations. Such crudes may need to be blended with heavier crudes, including oil from Western Canada.

*Includes crude oil and lease condensate production from oil wells. Lease condensate production from gas wells is not included.

**Other US production includes production from other basins in Texas and New Mexico, the Rockies, the Anadarko basin, the Gulf of Mexico Shelf, California, and other areas. It includes oil production from Utica and Anadarko, as well as oil from Eagle Ford area from formations other than Eagle Ford.

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2005–2030 Oil Production, MM bbl/d

Updated April 2019

The figure shows historical oil production from 2005 to 2018, along with each key region’s production forecast to 2030. The major growth basins are presented and summarized. The oil basins or plays within are analyzed based on the full-cycle cost of oil. Low-to-average cost plays attract investment capital and growth; investment in higher-cost plays stagnates and production declines accordingly. All areas with predominantly low-to-average cost unconventional oil development have production growth over the forecast period.

Permian, as one of the relatively lower-cost basins, is forecast to have production increased. Production in Bakken recovered after declining in 2015–2016 and is also expected to increase. Production in Eagle Ford will grow. Deepwater production will remain flat for the next 3 years, after which, it will start to decline. Western Canadian conventional and tight-oil production will decline over the forecast period.

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US Bakken Rig Count, Production, Connections, and Initial Productivity Forecast

Updated April 2019

The top left chart shows the Bakken rig count, which commenced declining in April 2015.

The top right chart shows Bakken crude oil and condensate, as well as associated gas production. The two bottom charts show initial oil well productivity and oil well connections.

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DJ Niobrara Rig Count, Production, Connections, and Initial Productivity Forecast

Updated April 2019

The most Niobrara production in 2018 comes from the Denver-Julesburg (DJ) basin, followed by Powder River and Green River. The top left chart shows the Niobrara oil rig count.

The other three charts show Niobrara crude oil and condensate, as well as raw associated gas production, initial oil well productivity, and oil well connections to 2030.

Production of DJ Niobrara is significantly lower than other tight oil basins due to lower productivity and a smaller resource base.

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Eagle Ford Rig Count, Production, Connections, and Initial Productivity Forecast

Updated April 2019

The Eagle Ford includes various zones differentiated by liquids yield. Currently development is focused on the northern portion of the basin with both oil and condensate zones. Most wells classified as oil in Eagle Ford produce oil, condensate, and associated gas.

The top left chart shows the Eagle Ford oil rig count.

The other three charts show Eagle Ford crude oil and condensate, as well as raw associated gas production, initial oil well productivity, and oil well connections to 2030*. 

*Lease condensate production from well classified as gas wells are not included.

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Gulf of Mexico Deepwater Rig Count, Production, Connections, and Initial Productivity Forecast

Updated April 2019

The Gulf of Mexico (GoM) Deepwater and Shelf average rig count has decreased during the first 10 months of 2018. In 2018, the main drillers in the Gulf of Mexico were Shell, Anadarko, Chevron (Union Oil Company of California), and LLOG Exploration.

GoM 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.

A number of new projects were sanctioned for 2019 which would lead in increase well count first time in 4 years. Among new projects are:

  • Chevron Anchor project in Green Canyon block.
  • Shell Appomattox project in Mississippi Canyon in coming onstream in 2018 and will be first projection from Jurassic reservoir.

The three charts show GoM Deepwater oil and associated gas production, initial oil well productivity, and oil well connections to 2030. Average initial productivity will remain relatively flat. 

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Raw Associated Gas Production, Bcf/d

Updated April 2019

The increased levels of unconventional oil drilling and production result in high levels of associated gas production*. Gas associated with oil production displaces gas-focused exploration and development activity that would otherwise occur.

The chart provides the raw** associated gas production forecast for North America to 2030. Associated gas production growth is attributed to unconventional oil development in the US basins.

*Raw associated gas production is calculated based on historical and forecast oil production as well as historical and forecast gas-oil ratios.

**Gas produced at the wellhead before processing, injection, and flaring (associated gas produced in Alaska is not included).

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North American NGL Yields Distribution

Updated April 2019

Figure shows the distribution of NGL yields (bbl/MMcf) across different basins within North America.

  • NGL yield can vary significantly for different fields and horizons within the same basins. The map shows the distribution of NGL yields in barrels per million cubic feet (bbl/MMcf) across different basins within North America. NGL production from many basins shown on the map is not economical at this point. 
  • Liquids-rich natural gas plays have incremental revenue uplift from NGL extraction. Several basins have NGL production from associated gas (produced with oil). These basins include Williston (Bakken), Permian, and the oil window of Eagle Ford.
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North American NGL Production by Region

Updated April 2019

Figure shows North American NGL production by region. In 2025, most NGL production will come from the Gulf Coast, which includes Eagle Ford and Permian, Western Canada (mostly Montney and Duvernay), and the East Cost (Marcellus and Utica).

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Western Canada NGL Resource Cost

Updated April 2019

As NGL uplift has become a key differentiator between economic success and failure of a well program, Solomon has done an analysis of the cost of resource from an NGL perspective—economics of a well program based on NGLs. This figure illustrates Solomon’s view of Western Canada NGL resource in billion barrels (B bbl), sorted by break-even NGL price.

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Montney & Duvernay Play Areas

Updated April 2019

This figure shows the location of the Montney and Duvernay play areas within Alberta and BC.

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Western Canadian NGL Production

Updated April 2019

Figure presents Western Canada NGL production to 2030 by component. The Montney and Duvernay plays are expected to be significant contributors of NGL production in Western Canada.

Key observations include the following:

  • Attractive producer economics in Duvernay will contribute significantly to the NGL production increase over the forecast period. Portions of the Duvernay could still be considered an exploration play, with significant upside potential as the play is developed and delineated.
  • NGL production from other formations is expected to decline, with the exception of the Spirit River group (including Falher and Wilrich) in the Alberta Deep Basin.

All volumes are recovered NGL at field, straddle plants, and fractionators. Production does not include off-gases and NGL produced at refineries.

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Western Canada Propane Supply by Source

Updated April 2019

  • Figure shows historical propane supply by source and expectations for future allocations. For much of the past decade, plant and gathering facilities were the primary source of propane recovery in Western Canada.
  • With the recent fractionation project developments by Pembina, Solomon expects fractionation recoveries to increase and provide the majority of propane recoveries until LNG is forecast to increase basin natural gas production.
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Western Canada Propane Supply-Demand

Updated April 2019

Figure shows Western Canada propane supply-demand balance, in which growing regional demand is outpaced by a strong growth in supply.

Within Western Canada, propane demand has historically been dominated by conventional industrial heating/crop drying and for oil and gas enhanced recoveries through the use of miscible flooding, solvent injection, or fracking. While space heating demand is generally seasonal and primarily serves remote regions, industrial use in the region is characterized as baseload with increased demand in line with increased drilling activities and unseasonal weather. Overall industrial residential and commercial demand is considered mature with an expectation that Western Canadian conventional demand will remain relatively stable with little appreciable growth throughout the forecast horizon.

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Appalachia Basin Play Areas

Updated April 2019

This figure shows the location of the Appalachia play areas containing the Marcellus and Utica plays within Pennsylvania, West Virginia, and Ohio.

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Marcellus/Utica NGL Forecast Per Play

Updated April 2019

Figure presents Appalachian NGL production forecast to 2030.

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Marcellus/Utica NGL Forecast Per Component

Updated April 2019

Figure presaents Appalachian NGL production forecast to 2030.

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Permian NGL Forecast

Updated April 2019

Figure shows Permian NGL production to 2030.

Permian natural gas production includes associated and non-associated gas. While Permian non-associated dry gas production is declining, Permian associated dry gas production is increasing. Most NGL production will come from oil wells. Together with Marcellus and Utica, Permian will be the primary NGL producing region in the US Lower 48.

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Eagle Ford NGL Forecast

Updated April 2019

Eagle Ford will produce nearly 30% of Gulf Coast (PADD 3) NGL in 2025. Figure presents Eagle Ford NGL production to 2030.

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Total Lower-48 NGL Forecast

Updated April 2019

Figure shows overall Lower 48 NGL forecast by component. Driven by a focus from North American producers to exploit strong associated liquids revenue opportunities within shale developments, the Lower 48 overall NGL experienced 43% growth between 2010 and 2018.

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NGL Pipeline Infrastructure

Updated April 2019

Figure shows existing NGL pipeline infrastructure.

US NGL interstate pipeline infrastructure is reflective of market trade to end-use consumers, with primary terminus point at the US Gulf Coast, while Canadian infrastructure is primarily designed with delivery to Sarnia, Ontario. The largest market point is Mont Belvieu followed by Conway, while all other points trade over-the-counter as a basis of the two most liquid points. Edmonton and Sarnia have historically traded as an offset of Conway, while Mont Belvieu represents the North American benchmark price for NGL transactions.

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Propane Export Capacity

Updated April 2019

Figure shows the location and size of existing and proposed facilities.

About 80% of the current demand for propane in Japan, South Korea, and China is satisfied by the Middle East. However, a burgeoning supply surplus in North America has increased the interest of Asian buyers (Japan, South Korea, and China) in sourcing propane from North America with US exports increasing 5.5 times between 2013 to 2018.

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Solomon Production Forecast Methodology

Updated April 2019

Figure provides an outline of Solomon NGL production forecast methodology.

NGL production forecasts are based on gas production analysis and average NGL yields per selected basins.

The historical NGL yields were calculated using NGL supply and raw gas well production as a basis. Historical NGL supply is obtained from gas processing plant throughputs and NGL production from oil refineries. For Western Canada, production from the majority of gas processing plants was summarized.

For US Lower 48, gas processing plant throughputs were summarized on a regional basis, using data obtained from the US Energy Information Agency (EIA) and other sources. Historical lease condensate from both the US Lower 48 and Western Canada was obtained from associated and non-associated gas well data. The NGL yield forecast was based on the historical yield, taking into account play maturity and geology.

The associated and non-associated gas production forecast was performed using proprietary Solomon production models for key oil and gas plays in North America. These models take into account the full-cycle gas cost, including NGL uplift, as producers focus their activities on lower-cost areas. Natural gas demand is allocated on the basis of a region’s resources and full-cycle costs. The models analyze production history and forecast annual average production for each play based on the following:

  • Relative economics of play and gas demand
  • Regional drilling and completion activity
  • New well initial productivity (IP) projected from recent trends, taking into account play maturity and the potential for incremental technological improvements
  • Production decline rates
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Oil Sands Locations

Updated April 2019

In 2018, the oil sands accounted for nearly 71% of Canada’s 3.9MM bbl/d of oil production. The figure highlights the location of major Western Canada oil sands deposits and the location of the oil sands mines at the north end of the Athabasca deposit (green highlight area). The Grosmont bitumen deposit is shown in blue.

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Alberta Oil Sands Projects

Updated April 2019

The figure presents the main oil sands project areas—Athabasca (where all of the oil sands mining operations are located), Cold Lake, and the emerging Peace River region. In total, the oil sands deposits cover more than 54,000 square miles, slightly larger than the state of New York.

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Growing Canadian Oil Production

Updated April 2019

The chart shows Canadian oil production.

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Alberta Oil Sands Producing & Sustaining Cost

Updated April 2019

The chart presents the estimated producing and sustaining costs for oil sands projects, grouped into in situ and mining projects. The two horizontal black lines indicate the price received for bitumen and the price for SCO in 2018. Projects are sorted based on remaining reserves.

The oil price crash has had a massive impact on producer’s cash flow and, therefore, their ability to fund sustaining and growth activity. Some producers with strong balance sheets are taking the opportunity to invest at the low in the price cycle through selective acquisitions and continued capital investment to take advantage of lower costs.

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Alberta Oil Sands Production Growth

Updated April 2019

After posting an 8.1% per year growth rate from 2010 to 2018, Solomon forecasts Canadian oil sands growth to slow with the completion of new large-scale mining projects.

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Western Canada Oil Supply and Pipeline Capacity

Updated April 2019

The chart 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 believes 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.
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Alberta Oil Sands Carbon Dioxide Emissions

Updated April 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 MT/yr. This is an increase of 24% from 81 MT in 2018 and allows for an increase in oil sands production of 0.9MM bbl/d at current emission intensity. The policy includes an oil sands-specific emission performance standard with a 30 CAD/t carbon price applied to the highest performing facilities, effectively shifting capital dollars towards the most carbon efficient projects.

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East Coast Offshore Production History and Forecast

Updated April 2019

As shown on the map, there are four producing regions offshore Newfoundland (Hibernia, White Rose, Terra Nova, and Hebron).

The chart shows Newfoundland production history and forecast.

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Conventional Light, Heavy, and Tight Oil Production Areas in Western Canada

Updated April 2019

The figure shows conventional light, heavy, and tight oil production areas in Western Canada.

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Conventional Light and Heavy Oil Production in Western Canada

Updated April 2019

The figure shows conventional and tight oil production outlook in Western Canada. Conventional and tight oil production grew from 2010 to 2014 mostly due to the development of tight oil in Pembina Field. Production started to decline in 2015 and will continue to decline during the forecast period.

East Duvernay Tight oil play in Alberta has some potential. It remains in early exploration and development stages.

Currently, new oil well productivity in the Cardium, Duvernay, and other tight plays in Western Canada is lower than in US Lower 48 plays, such as Bakken, Permian, and Eagle Ford, while tight oil well costs in the WCSB are compatible with US plays. As a result, the full-cycle cost of tight oil production in WCSB is higher than in US plays.

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Permian Basin Area

Updated April 2019

The figure provides a map of the Permian basin. It is one of the most mature and largest oil-producing basins in North America, with three sub-basins—the Midland and Delaware separated by the Central Basin Platform, and the deeper Val Verde sub-basin to the southwest. The Permian basin includes both conventional and tight-oil development. The unconventional growth plays include the San Andres, Spraberry, Wolfcamp, Avalon, Bone Spring, and Yeso.

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Permian Rig Count, Production, Connections, and Initial Productivity Forecast

Updated April 2019

This figure shows the Permian oil rig count, crude oil and condensate including associated gas production, initial oil well productivity, and oil well connections.

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Growth of Permian Oil Production

Updated April 2019

Permian has become the fastest growing tight oil production region due to lower cost compared with other tight oil basins, such as Bakken, Eagle Ford, and Niobrara.

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Remaining Oil Resources for Different IP Ranges for Permian Vertical and Horizontal Wells

Updated April 2019

The charts show remaining resources for different IP ranges for vertical and horizontal wells. Resource assessment is performed based on estimation of remaining well location and well expected ultimate recovery (EUR). The assessment includes opportunities for well recompletion and re-fracing.

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Distribution of Wells, Bone Spring

Updated April 2019

This figure shows distribution of wells with different IP for the Bone Spring formation.

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Distribution of Wells, Woflbone/Spraberry

Updated April 2019

Figure shows distribution of wells with different IP for Wolfbone/Spraberry plays.

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Distribution of Wells, Wolfcamp

Updated April 2019

This figure shows distribution of wells with different IP for the Wolfcamp formation.

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Permian Oil Infrastructure Capacity Outlook

Updated April 2019

The chart shows Permian oil infrastructure capacity in excess of production going forward to 2025.

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Permian Gas Processing Capacity

Updated April 2019

The chart shows Permian gas processing capacity from 2015–2022 in relation to overall Permian gas production. Gas processing continues to be built out in a timely matter, allowing for continued growth in overall Permian oil production.

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Proposed Permian Natural Gas Pipelines

Updated April 2019

The figure shows the four intrastate pipeline projects running from the Permian Basin relative to emerging LNG liquefication demand on the Gulf Coast.

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US Refining by Oil Type and Domestic Share

Updated April 2019

The chart shows US Refining input by oil type and domestic share from 2006–2016; US domestic production inputs are shown in lighter color. Observations include:

  • Overall refining inputs have remained flat over the observed time period.
  • US market share of inputs did not materially change for heavy, medium, or light-sour grades.
  • US market share for light-sweet did increase.
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Gulf of Mexico VLCC Projects

Updated April 2019

The figure shows two operating and six proposed Large Crude Container (VLCC) loading ports in the Gulf Coast.

Two factors driving exports of light oil from the Gulf Coast are its oversupply into complex refineries built to process heavy crude and European demand for light-sweet oil to ensure compliance with IMO 2020. Currently only the LOOP terminal can fully load VLCCs. A number of other proposals are currently contemplated to enhance VLCC export capability.

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Shale Oil Impact on Texas/Louisiana Refining

Updated April 2019

The figure shows increased impact of growing Texas oil production, especially light oil, on Gulf Coast refining (Texas/Louisiana). Coinciding with Permian growth, the processing of Texas produced barrels has increased market share from 5% in 2006 to 32% in 2016—almost entirely light sweet barrels.

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Map of US Conventional and Unconventional Oil Basins

Updated April 2019

Solomon performed detailed analysis of full-cycle cost for conventional and Tight Oil wells in the following oil basins shown in the map:

Unconventional Basins

  • Permian
  • Bakken
  • Eagle Ford
  • Niobrara

Conventional Basins

  • Black Warrior
  • Appalachian Conventional Basin
  • Louisiana, Mississippi, Alabama Gulf Coast Conventional Basin
  • Conventional basins within the state of Wyoming
  • Conventional basins within the states of Oklahoma, Kansas, and North Texas
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Permian Basin Horizontal Wells IP Distribution Map

Updated April 2019

Solomon analyzed full-cycle cost of horizontal and vertical wells separately.

The figure provides a new oil well IP map of the Permian basin drilled by horizontal wells.

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Permian Basin Vertical Wells IP Distribution Map

Updated April 2019

Solomon analyzed full-cycle cost of horizontal and vertical wells separately.

The figure provides a new oil well IP map of the Permian basin drilled by vertical wells.

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Eagle Ford Basin Oil Initial Productivity Distribution Map

Updated April 2019

The Eagle Ford includes various zones differentiated by liquids yield. Development is currently focused on the northern portion of the basin with both oil and condensate zones. Most wells classified as oil in Eagle Ford produce oil, condensate, and associated gas. The figure provides a new oil well IP map of the Eagle Ford basin (crude oil only).

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Bakken Basin Initial Productivity Distribution Map

Updated April 2019

The figure provides an IP map of the Bakken.

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Niobrara Initial Productivity Distribution Map

Updated April 2019

The most Niobrara production in 2017–2018 comes from the Denver-Julesburg (DJ) basin (90%), followed by Powder River and Green River. The figure provides an IP map of the Niobrara. Niobrara full-cycle cost is slightly higher than in the Permian, Bakken, and Eagle Ford basins due lower productivity. Well cost in Niobrara is lower than in those basins.

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Black Warrior Basin Initial Productivity Map

Updated April 2019

The figure shows IP map for Black Warrior basin. The basin resources are estimated at 0.5B bbl. Most of these resources are uneconomical.

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Appalachian Basin Initial Productivity Map

Updated April 2019

The figure shows IP map for Appalachian basin.

Conventional formations include Maxon Sandstone, Ravencliff Sandstone, Salt Sand, Pennington Sand, and Mississippian Sand. Additional formations include Clinton Sand, Elk, Fifth, Gordon, and others.

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Louisiana, Mississippi, Alabama Gulf Coast Basin Initial Productivity Map

Updated April 2019

The figure shows the IP map for Louisiana, Mississippi, Alabama Gulf Coast Basin.

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Wyoming Conventional Wells Location

Updated April 2019

The map shows that most conventional wells in Wyoming are drilled in the following basins:

  • Big Horn (Cody, Curtis, Frontier, Madison, Muddy, and other formations)
  • Denver-Julesburg (Codell Sand formation)
  • Green River (Dakota, Wasatch, Shannon, Lewis, Almond, and other formations)
  • Power River (Muddy, Newcastle, Sundance, Teapot, Leo, Lakota, Lance, Success, Minnelusa, and other formations)
  • Wind River (Cody, Curtis, Embar, Steele, Wall Creek, Phosphoria, Turner, Parkman, Sundance, and other formations)
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Wyoming Conventional Wells Initial Productivity Map

Updated April 2019

The figure shows IP map for Wyoming conventional basins.

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Oklahoma, Kansas, and North Texas Basins Location

Updated April 2019

The map shows that most conventional wells in Oklahoma, Kansas, and North Texas are drilled in the following basins: Anadarko, Palo Duro, Sedgwick, and Central Kansas Uplift.

The major formations include Mississippi Lime, Wilcox, Oswego, Rant, Cleveland, Marmaton, Hunton, Hogshooter, Chester, Meramac, and others.

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Oklahoma, Kansas, and North Texas Initial Productivity Map

Updated April 2019

The figure shows IP map for vertical wells in Oklahoma, Kansas, and North Texas conventional basins.

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Oil Sands Recovery Techniques

Updated December 2017

This chart provides an overview of Bitumen Recovery techniques for mining and in situ projects in Alberta.

  • Generally, bitumen can be mined through open pits when the overburden is less then 75 meters (250 ft). Deeper deposits are accessed through in situ methods. The oil sands resource is shallowest in the farther Northern projects (North of Fort McMurray) and deepest in the south.
  • As bitumen is very viscous, in situ removal requires “heat energy” to increase bitumen flow to the surface. The heat energy is supplied by steam, which is generated by heating water with natural gas. To produce the deeper bitumen, Steam Assisted Gravity Drainage (SAGD) in situ is viable deeper than 75 meters (250 ft), and Cyclic Steam Stimulation (CSS) in situ is viable at more than 200 meters (660 ft).
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Oil Sands Mining and Upgrading Process

Updated December 2017

This slide shows the Oil Sands Mining and Upgrading process.

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Forecasting Oil Costs & Supply

Updated December 2017

Solomon Natural Gas Methodology

Solomon maintains proprietary production models for key oil and gas plays in North America. These models analyze production histories and forecast annual average production for each play or basin based on:

  • Regional drilling and completion activity. This depends on new well supply costs relative to costs in other plays, expected oil prices, natural gas liquids content, play maturity (well density and resource potential), and availability of equipment.
  • New oil well initial productivity (IP), projected from recent trends, considering play maturity and the potential for incremental technology improvements.
  • Production decline rates. Decline rates are applied to new and existing wells considering the age of wells.

The models generate an oil production forecast. The associated gas production is estimated based on the historical and forecasted gas-oil ratio. Total production is sensitive to even small changes in these parameters, decline rates in particular. Production of each individual basin is forecasted based on cost curves: basins with lower full-cycle cost will be developed first.

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Average Oil Full-Cycle Production Costs for Three Growth Basins

Updated December 2017

This chart provides Solomon’s summary of full-cycle costs for 90B bbl of undeveloped and recoverable US unconventional-oil resources in the Bakken, Eagle Ford, and Permian basins.

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Effect of Cost Escalation on Oil Resources

Updated December 2017

This chart shows how capital and operating cost escalation will affect oil resources. Capital and operating cost escalation will affect the profitability of production, but will not significantly affect recoverable resources under short-term oil prices.

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Eagle Ford Maintaining Tight Oil Production

Updated December 2017

This chart shows that despite high decline of tight oil wells, they remain productive for a long time (based on the example of a typical Eagle Ford well).

  • The chart compares 20 tight oil wells (20 wells per year, or around 1 pad per year).
  • 10 additional wells are required to maintain production after the first 3 years.
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