Full-Cycle Cost Forecast for Permian Basin

Updated April 2019

Permian full-cycle cost will remain the lowest among US Lower 48 tight oil basins. The chart shows the forecast of full-cycle cost for the Permian Basin. Full-cycle cost is affected by cyclical and structural factors. Structural factors include technological improvement and changes to well productivity. Until 2015, technological improvement as well as improvements to operational efficiency in the Permian Basin will lead to full-cycle cost decline. Also, full-cycle cost includes differential to WTI, which is a function of infrastructure availability. Solomon expects that removing infrastructure constraints in the next few years will lead to a drop in full-cycle cost.

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Full Cycle Cost for Different IP Ranges for Permian Vertical and Horizontal Wells

Updated April 2019

Average full-cycle cost of the basin is calculated based on average IP of all vertical and horizontal wells in the basin. The charts show full-cycle cost relative to WTI for different ranges of IP for vertical and horizontal wells.

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Cost of Capital

Updated April 2019

The chart presents cost components for US oil.

Oil and gas cost components:

  • Producer Return – Calculated based on rate of return (15%) before income tax; equivalent to cost of capital. Individual producer’s actual rate of returns may be higher or lower.
  • Basis Differential – Differential between the oil price at the point of sale (in the producing basin) and WTI; used to compare the cost of gas from different basins on a consistent basis. The differential is estimated based on proprietary Solomon data, which are based on average prices of crude produced in the basin. Basis differential is very sensitive to infrastructure available.
  • Operating Cost – Lifting and field processing costs. The cost is calculated based on information reported by producers and Solomon proprietary data. In most cases, producers report total operating cost per project. It is then divided on total resources for the particular project. Operating cost is generally very similar for different basins. Operating cost per unit of production increases if initial productivity decreases.
  • Royalties & Production Taxes – Taxes for government and royalties for freehold owners and others. Taxes include severance, conservation, and other taxes and are different for different jurisdictions.
  • Overhead – Includes all general and administrative (G&A) expenditures (head office); these costs are necessary expenses for doing business. Producer usually reports overhead for whole operation rather than a particular project. Because for most producers, conventional oil production is not very significant compared to unconventional oil and gas production, it is hard to allocate corporate G&A to each project. Therefore, Solomon assumes that G&A is 1.5 United States dollars per barrel (USD/bbl) for all basins. G&A cost per unit of production increases if initial productivity decreases.
  • Finding & Development (F&D) – Capital costs calculated based on producer’s disclosure and proprietary Solomon data. F&D cost includes:
    • Drilling
    • Completion including casing, cementing, fracing
    • Land and seismic
    • Tie-in, facilities, and other incremental infrastructure costs
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Current Average Oil Full-Cycle Cost per Area

Updated April 2019

The chart shows current average full-cycle cost per area, estimated based of well average IPs drilled since 2013. The cheapest Tight Oil basin is Permian, followed by Bakken and Eagle Ford. The cheapest convention area is the Louisiana, Mississippi, Alabama Gulf Coast Basin.

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Oil Full-Cycle Cost vs Oil Resources

Updated April 2019

The figure shows full-cycle cost versus oil resources for study areas of interest. The ability to consistently target low-cost resource from vertical wells is much more difficult than horizontal wells in Tight Oil plays.

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Permian Horizontal Wells Full-Cycle Cost of Oil vs Remaining Resources

Updated April 2019

Permian Basin is located in West Texas and southeast New Mexico. 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.

The chart shows full-cycle cost of oil versus remaining resources for Permian horizontal wells.

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Permian Horizontal Wells Full-Cycle Cost Breakdown for Different Components

Updated April 2019

The chart shows breakdown for different ranges of well Initial Productivity for Permian horizontal wells.

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Permian Vertical Wells Full-Cycle Cost of Oil vs Remaining Resources

Updated April 2019

Permian Basin is located in West Texas and southeast New Mexico. 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.

The chart shows full-cycle cost of oil versus remaining resources for Permian vertical wells.

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Permian Vertical Wells Full-Cycle Cost Breakdown for Different Components

Updated April 2019

The chart shows breakdown for different ranges of well Initial Productivity for Permian vertical wells.

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Eagle Ford Basin Full-Cycle Cost of Oil vs Remaining Resources

Updated April 2019

The chart shows full-cycle cost of oil versus remaining resources for Eagle Ford basin.

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Eagle Ford Basin Full-Cycle Cost Breakdown for Different Components

Updated April 2019

The chart shows breakdown for different ranges of well Initial Productivity for Eagle Ford basin.

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Bakken Full-Cycle Cost of Oil vs Remaining Resources

Updated April 2019

The chart shows full-cycle cost of oil versus remaining resources for Bakken.

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Bakken Full-Cycle Cost Breakdown for Different Components

Updated April 2019

The chart shows breakdown for different ranges of well Initial Productivity for Bakken.

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Niobrara Full-Cycle Cost of Oil vs Remaining Resources

Updated April 2019

The chart shows full-cycle cost of oil versus remaining resources for Niobrara.

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Niobrara Full-Cycle Cost Breakdown for Different Components

Updated April 2019

The chart shows breakdown for different ranges of well Initial Productivity for Niobrara.

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Black Warrior Basin Full-Cycle Cost of Oil vs Remaining Resources

Updated April 2019

Black Warrior basin is in northwestern Alabama and northeastern Mississippi (map).

The chart shows full-cycle cost of oil versus remaining resources for Black Warrior basin. High full-cycle cost in Black Warrior basin is due to low productivity, low EUR, and relatively high well capital cost.

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Black Warrior Basin Full-Cycle Cost Breakdown for Different Components

Updated April 2019

The chart shows breakdown for different ranges of well Initial Productivity.

Full-cycle cost is estimated based on data from six projects: two in Alabama and four in Mississippi.

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Appalachian Basin Full-Cycle Cost of Oil vs Remaining Resources

Updated April 2019

Appalachian basin is located in five states: Ohio, Pennsylvania, West Virginia, Kentucky, and Tennessee (map).

The chart shows full-cycle cost of oil vs remaining resources for the basin. High full-cycle cost in Appalachian basin is due to low productivity, low EUR, and relatively high well capital cost.

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Appalachian Basin Full-Cycle Cost Breakdown for Different Components

Updated April 2019

The chart shows breakdown for different ranges of well Initial Productivity.

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Louisiana, Mississippi, Alabama Gulf Coast Basin Full-Cycle Cost of Oil vs Remaining Resources

Updated April 2019

The map shows location of Louisiana, Mississippi, Alabama Gulf Coast Basin.

The chart shows full-cycle cost of oil vs remaining resources for the basin.

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Louisiana, Mississippi, Alabama Gulf Coast Basin Full-Cycle Cost Breakdown for Different Components

Updated April 2019

The chart shows breakdown for different ranges of well Initial Productivity.

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Wyoming Conventional Wells Full-Cycle Cost of Oil vs Remaining Resources

Updated April 2019

The chart shows full-cycle cost of oil vs remaining resources for the Wyoming conventional wells.

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Wyoming Conventional Wells Full-Cycle Cost Breakdown for Different Components

Updated April 2019

The chart shows breakdown for different ranges of well Initial Productivity.

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Oklahoma, Kansas, and North Texas Full-Cycle Cost of Oil vs Remaining Resources

Updated April 2019

The chart shows full-cycle cost of oil vs remaining resources for the Oklahoma, Kansas, and North Texas conventional vertical wells.

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Oklahoma, Kansas, and North Texas Full-Cycle Cost Breakdown for Different Components

Updated April 2019

The chart shows breakdown for different ranges of well Initial Productivity.

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Capital and Operational Cost for Oil Sands, Deepwater, and Major Tight Oil Areas

Updated April 2019

The chart shows capital and operational cost per barrel for Oil Sands, Deepwater, and major Tight Oil areas. Royalties, taxes, G&A expenditure, differential, and cost of capital are not included. The full-cycle capital and operational cost are calculated by dividing total capital and operational expenditure for all projects in each category on total booked reserves in this category. This methodology allows us to compare projects developed using different technologies. The data were obtained from public disclosures of oil producers. However, this methodology has a number of limitations. Among them are:

  1. Booked recoverable reserves and actual reserves produced during lifecycle of the project can be significantly different due to geological uncertainties. It is especially prevalent for offshore projects.
  2. Capital cost and especially operational cost reported by producers may not fully reflect future cost escalation. For example, unplanned maintenance of offshore or oil sands facilities may result in significant cost escalation.
  3. Capital and operational cost of projects may be inconsistent for different projects due to inclusion or exclusion project extension, different accounting practices, etc.
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Cost Curve Calculation Methodology

Updated April 2019

The figure shows methodology of cost curve calculation.

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 forecast based on cost curves: basins with lower full-cycle cost will be developed first.

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2016 New Gas Supply Cost and Break-Even Gas Price by Play – Company Data

Updated December 2017

This figure compares the average full-cycle cost of the 23 assessed gas plays with results sorted from low to high break-even gas price (black bars), referenced to Henry Hub. As a benchmark, Solomon presents the average 2016 Henry Hub gas price to allow a quick comparison of gas costs with price. Gas-condensate plays have the lowest break-even gas prices, remaining economic with a Henry Hub gas price of 2.00 USD/Mcf.

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2016 New Gas Supply Cost and Break-Even Gas Price by Play – Solomon Assessment

Updated December 2017

This figure presents the full-cycle cost components and break-even gas prices (white horizontal bars) for the assessed plays based on Solomon’s analysis of Estimated Ultimate Recoveries (EURs). Solomon has developed production models based on a representative sample of recent gas wells and has derived EURs for each play assessed. The Solomon gas cost models correlate quite well with producer average data for most basins and plays; however, the Anadarko, Bluesky-Glauconite, and Montney British Columbia (BC) South Wet plays have higher F&D costs due to Solomon’s assessment of lower EURs.

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2016 Play Ranking

Updated December 2017

This figure provides a play ranking, using the remaining gas resource potential and Solomon’s average 2016 break-even gas price for key plays. The area of the bubble is based on the production added in 2015. As a benchmark, Solomon presents its forecasted 2025 Henry Hub gas price to allow a quick comparison of available resource with the expected longer-term natural gas price.

Observations on the play ranking include the following:

  • Gas condensate plays have the lowest break-even gas price due to the significant condensate revenue, which is based on the price of oil.
  • NGL-rich gas and gas-condensate plays tend to have smaller remaining gas resources because these gas types exist in a narrow range of geothermal temperatures.
  • Dry gas is stable across a wider temperature range, which consequently results in the largest resources.
  • Drilling still occurs in higher-cost plays—in sweet spots that are less expensive—and anticipated future costs may be expected to fall as drilling and completion effectiveness improves.
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US Full-Cycle Cost Changes, USD/Mcf

Updated December 2017

This figure compares the full-cycle play cost of various gas basins and plays across the US. The full-cycle play cost continued to fall in 2016 for virtually all plays. Only plays with high condensate yields were profitable in 2016. The most significant drop in full-cycle play cost occurred in Eagle Ford, where producers focused on the high-productivity sweet spots of the play. A significant drop in the East Texas/North Louisiana full-cycle play cost is associated with the growth of well initial productivity (IP) in the Haynesville, a result of technology enhancements as well as a focus on sweet-spot drilling. Arkoma, and particularly the Woodford and Fayetteville plays, have become mature, which has led to a higher full-cycle play cost.

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Western Canadian Full-Cycle Cost Changes, USD/Mcf

Updated December 2017

This figure compares the full-cycle play cost of various gas plays in Western Canada. Observations of the full-cycle play cost changes include the following:

  • The full-cycle play cost and break-even gas price continued to fall in 2016 for all plays.
  • Montney Alberta condensate and Duvernay plays have a zero break-even gas price due to significant liquids uplift.
  • The Montney full-cycle play cost and break-even gas price is on average lower than for the Marcellus. Montney and Marcellus will remain the fastest-growing plays in North America.
  • The break-even gas price and full-cycle play cost in the Bluesky-Glauconite, Wilrich, and Notikewan-Falher are compatible with the Montney break-even gas price and full-cycle play, which will lead to further development of these plays over the next several years.
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2016 Break-Even Henry Hub Gas Price

Updated December 2017

This figure shows the break-even gas price supply curves (based on company data) for North American gas basins using the results from the last three Economic Ranking Assessments. The supply curve is based on the amount of production added on an annualized basis, by basin or play. Observations of the break-even gas price supply curves include:

  • While break-even gas prices have continued to decline, most new gas supply added early in 2016 was uneconomic with the 2016 Henry Hub gas price.
  • Overall, break-even gas prices have fallen as drilling has shifted from higher-cost conventional plays to low-cost high-NGL-yield resource plays and as oil and gas prices have fallen.
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Utica Gas Resource and 2016 Break-Even Gas Price Distribution

Updated December 2017

This chart shows Utica Gas Resource and 2016 Break-Even Gas Price Distribution. Development has been constrained by a lack of adequate infrastructure and take-away capacity, leading to large gas basis differentials and deteriorating drilling economics. With significant new pipeline capacity coming on-stream in the 2017–2018 period, basis differentials will decrease, driving the gas-condensate break-even gas price to the lowest of North American gas plays. The map on the right illustrates the hydrocarbon distribution in the Utica play ranging from dry gas (blue) to the southeast and gas condensate (red) to the northwest. The top left chart illustrates Solomon’s assessment of the break-even gas price for the remaining Utica gas-condensate, rich-gas, and wet-gas resource, estimated from the supply cost analysis of this play. The bottom left chart presents Solomon’s assessment of the break-even gas price for the remaining Utica dry-gas resource.

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Marcellus Gas Resource and 2016 Break-Even Gas Price Distribution

Updated December 2017

This figure shows Marcellus Gas Resource and 2016 Break-Even Gas Price Distribution. As with Utica, Marcellus gas production growth has been constrained by a lack of adequate infrastructure and take-away capacity for gas and NGL, leading to an increased gas basis differential and deteriorating drilling economics. The map on the right illustrates the hydrocarbon distribution in the Marcellus play ranging from dry gas (blue) to the southeast and northeast and gas condensate (red) to the west. The figure also identifies the two core areas—northeast Pennsylvania (dry gas), and southwest Pennsylvania and West Virginia NGL-rich and dry gas.

The top left chart illustrates Solomon’s assessment of the break-even gas price of the remaining Marcellus Southwest gas-condensate, rich-gas, and wet-gas resource, estimated from the supply cost analysis of this play.

The bottom left chart illustrates the break-even gas price of the remaining Marcellus Southwest and Northeast dry-gas resource. The condensate and NGL-rich gas resource is quite extensive, though with a moderate break-even gas price. The Marcellus and Utica dry-gas plays have extensive resources that become economical at gas prices greater than 3 USD/Mcf.

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Eagle Ford Gas Resource and 2016 Break-Even Gas Price Distribution

Updated December 2017

This figure shows Eagle Ford Gas Resource and 2016 Break-Even Gas Price Distribution. The Eagle Ford shale-oil and gas play has developed rapidly, with production surpassing that of the Bakken. This analysis is of the high-condensate-yield gas in the center of the play, which greatly improves producer economics. With the low break-even gas price, drilling for gas-condensate will increase as oil and gas prices recover.

The map on the right illustrates the hydrocarbon distribution in the Eagle Ford play ranging from dry gas (blue) to the southeast, to oil in the northwest.

The top left chart illustrates Solomon’s assessment of the break-even gas price for the remaining Eagle Ford gas-condensate, rich-gas, wet-gas, and dry-gas resource, estimated from the supply cost analysis of this play. The gas-condensate resource is quite extensive, with a low break-even gas price.

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Haynesville Gas Resource and 2016 Break-Even Gas Price Distribution

Updated December 2017

This chart shows Haynesville Gas Resource and 2016 Break-Even Gas Price Distribution. Production in the Haynesville over-pressured dry gas play has declined over the last several years as drilling has shifted to liquids-rich plays. With typical well IPs, it is one of the lowest-cost dry-gas plays in North America. The Bossier shale has potential in the core of the Haynesville play.

The map on the right illustrates Solomon’s assessment of natural gas resource geographic distribution using initial well productivities in the Haynesville play in East Texas–North Louisiana and the Lower Bossier play.

The top left chart illustrates Solomon’s assessment of the break-even gas price of the remaining Haynesville dry-gas resource, estimated from the supply cost analysis of this play. The gas resource is quite extensive, with a moderate break-even gas price.

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Duvernay Gas Resource and 2016 Break-Even Gas Price Distribution

Updated December 2017

This chart shows Duvernay Gas Resource and 2016 Break-Even Gas Price Distribution. Producers in the Duvernay have focused on developing the northern part 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. Here, wells have both high production rates and high condensate yields.

Evaluation of the southern portion of the Duvernay play has lagged the north, due in part to the ongoing infrastructure development and the more exploration-oriented context of this area. Drilling costs have been reduced significantly, with efficiencies and technology enhancements in drilling and completion techniques.

The map on the right illustrates the hydrocarbon distribution in the Duvernay play ranging from dry gas (blue) to the southwest and oil (olive green) to the northeast. The figure also identifies the developing north Duvernay gas-condensate core area.

The top left chart illustrates Solomon’s assessment of the break-even gas price of the remaining Duvernay gas-condensate, rich-gas, wet-gas, and dry-gas resource, estimated from the supply cost analysis of this play.

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Alberta Montney Resource and 2016 Break-Even Gas Price Distribution

Updated December 2017

This figure shows Alberta Montney Resource and 2016 Break-Even Gas Price Distribution. In contrast to the previously discussed shale-gas plays, the Montney is a tight-gas play with lateral facies variations of fine-grained sedimentary rocks. This may lead to areas of non-commercial or low gas-rate production. The gas ranges from sweet to 6% H2S. Currently, drilling is focused on the condensate- and NGL-rich portions of Alberta and of BC southwest of Fort St. John. In the northern BC area of the play, most drilling has been in anticipation of west coast LNG development.

The map on the right 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.

The top left chart illustrates Solomon’s assessment of the break-even gas price of the remaining Alberta Montney gas-condensate-rich wet- and dry-gas resource, estimated from the supply cost analysis of this play.

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BC Montney Resource and 2016 Break-Even Gas Price Distribution

Updated December 2017

The charts on the left illustrate the break-even gas price of the remaining BC South and North Montney gas resource. The map on the right 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.

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Utica Shale Condensate Cost Components

Updated December 2017

This figure summarizes the full-cycle costs and break-even gas prices for 2016 drilling programs, previous studies, and Solomon’s assessment for the Utica gas-condensate play.

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Utica Rich Gas Cost Components

Updated December 2017

This figure summarizes the costs and prices for the Utica NGL-rich gas play.

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Utica Dry Gas Cost Components

Updated December 2017

This figure summarizes the costs and prices for the Utica lean-dry gas play.

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Northeast Marcellus Dry-Gas Cost Components

Updated December 2017

This figure summarizes the full-cycle costs and break-even gas prices for 2016 drilling programs, previous studies (in 2009, the basis differential for the Marcellus was positive (i.e., Marcellus gas price was higher than Henry Hub); this gives a break-even gas price that is lower than the full-cycle cost), and Solomon’s assessment for the northeast dry-gas Marcellus play.

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Southwest Marcellus Wet-Gas Cost Components

Updated December 2017

This figure shows the costs and prices for the southwest rich-gas Marcellus play.

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Southwest Marcellus Dry-Gas Cost Components

Updated December 2017

This figure presents the costs and prices for the southwest dry-gas Marcellus play.

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Eagle Ford Gas Condensate Cost Components

Updated December 2017

This figure summarizes the full-cycle costs and break-even gas prices for 2016 drilling programs, previous assessments, and Solomon’s assessment for the gas-condensate Eagle Ford play.

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Haynesville Gas Cost Components

Updated December 2017

This figure summarizes the full-cycle costs and break-even gas prices for 2016 drilling programs, previous studies, and Solomon’s assessment for this play.

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Duvernay Gas Cost Components

Updated December 2017

The figure summarizes the full-cycle costs and break-even gas prices for 2016 drilling programs, previous studies, and Solomon’s assessment for the north Duvernay gas-condensate play.

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