Kingdom Exploration LLC offers northern alternative for forward-thinking investors

By Todd Bennington, Kingdom Exploration Media

Despite the fanfare with which advances in hydraulic fracturing technology were met with over the past several years, the fact is that today the profitability of the major U.S. shale plays is in sharp decline. Costs associated with drilling new wells and fracking in tight shale formations remain enormous despite improvements in efficiency. Simply put, U.S. shale projects tend to lack economic feasibility at today’s market prices, which are not expected to rebound substantially for the foreseeable future. Couple this with the steep decline curve in the amount of oil and gas produced by existing unconventional wells and the investment outlook for U.S. shale, perhaps a victim of its own success, doesn’t appear promising.

“Vast volumes of oil were squandered at low prices for the sake of cash flow to support unmanageable debt loads and to satisfy investors about production growth,” writes Forbes analyst Art Berman of the once-heralded Bakken play. “The clear message is that investors do not understand the uncertainties of tight oil and shale gas plays.” [1]

As for conventional plays in the United States, attractive investment opportunities have become hard to come by due to the effects of competition and regulation.

As an alternative, proactive investors may wish to consider available opportunities in Canada, where potential revenues relative to costs have a significantly better outlook. Kingdom Exploration is presently offering just such an opportunity to invest in its project in the Lagarde play in British Columbia. The project proposes ten or more wells utilizing horizontal drilling techniques and initially producing a potential 250 to 1,500 barrels of oil equivalent per day. Potential reserves are estimated at 10 million or more BOE.

With drilling costs at about $2 million per horizontal well, Kingdom Exploration’s Lagarde project compares very favorably with the U.S. shale plays, and the Lagarde area’s high porosity means expensive fracking costs are kept to a minimum. Consider, by comparison, the approximate costs of new wells in the following U.S. shale plays:

• Eagle Ford (Southern Texas) $6.5-$7 million [2]        `
• Marcellus (Appalachian Basin) $5.3 million [2]
• Niobrara (South Dakota, Colorado, Nebraska, Wyoming) $4.5-$5 million [2]
• Anadarko-Woodford (West-Central Oklahoma) $8.5 million [2]
• Granite Wash (Texas, Oklahoma) $7.5-$8 million [2]
• Permian (Texas, New Mexico) $2.2-$3.2 million [3]
• Haynesville (Louisiana, Arkansas, Texas) $9.95 million [4]

Further, costs for new wells in the Bakken play were $5.9 million in 2015, down from $7.1 million in 2014, [5] and have run as high as $10 million in years previous [6].*

In terms of productivity, Kingdom Exploration’s initial Lagarde wellhead in partnership with Cardinal Energy Ltd – Mitsue 10-17 – produced a total of 5,679.18 BOE between February 9 and March 31 of this year for a daily production average of 113.58 BOE. Those figures are expected to rise considerably once certain minor technical difficulties are overcome to the 250 to 1,500 BOE figure cited above.

As a basis for comparison, the U.S. Energy Information Administration provides the following initial production figures for some of the major U.S. shale plays for the months of February and March 2017:

New-well oil production per rig (barrels per day)

• Permian (Western Texas) 660 BPD (February) and 668 BPD (March) [7]
• Eagle Ford (Southern Texas) 1,428 and 1,438 [7]
• Marcellus (Appalachian Basin) 69 and 70 [7]
• Niobrara (South Dakota, Colorado, Nebraska, Wyoming) 1,285 and 1,305 [7]
• Haynesville (Louisiana, Arkansas, Texas) 31 and 32 [7]
• Bakken (Montana, North Dakota) 987 and 990 [7]
• Utica (New York, Pennsylvania, Ohio, West Virginia) 110 and 102 [7]
• Weighted average for the above: 699 and 713 [7]
• Anadarko 370 and 372 [8]**

New-well gas production per rig (thousand cubic feet per day)

• Permian 1,097 (February) and 1,107 (March) [7]
• Eagle Ford 4,436 and 4,518 [7]
• Marcellus 12,865 and 13,028 [7]
• Niobrara 4,156 and 4,266 [7]
• Haynesville 7,011 and 7,112 [7]
• Bakken 1,424 and 1,455 [7]
• Utica 10,371 and 10,472 [7]
• Weighted average for the above: 3,500 and 3,509 [7]
• Anadarko 2,507 and 2,512 [8]**

It’s important to note, however, that the above initial shale play production rates do not last. Unconventional wells produce very high initial rates before quickly declining to substantially more modest production levels, meaning revenues from these wells are highly front-loaded.

“High initial production rate and steep initial decline is characteristic of shale wells (and is a lot different than the slower decline in many conventional gas wells), meaning that most of a project’s revenues – sometimes as high as 80 percent of total lifetime well revenues – can accrue over the first five to seven years of the well’s producing life,” writes Seth Blumsack, Program Chair for Energy Business and Finance at Penn State’s Department of Energy and Mineral Engineering. [9]

Indeed, a recent Uppsala University thesis on the topic described the average Eagle Ford well as reaching peak production within a few months before declining 75 percent from its peak over the first year of operation, followed by an 87 percent decline from peak production in the second year. [10] The Eagle Ford formation accounts for about one-fourth of cumulative tight oil production, according to the U.S. Energy Information Administration. [11]

The bottom line: Kingdom Exploration’s Lagarde project proposes the operation of 10-plus wells, each producing a potential 250 to 1,500 BOE per day, with per-well development and drilling costs running to approximately $2 million. This combines production figures that are comparable to the major U.S. shale plays but with substantially more room for profit potential as they come at a fraction of the drilling and development costs and can be expected to be more consistently productive over time.

*These figures represent estimates at a fixed point in time. Well costs vary between companies and across time due to a variety of factors.

** Because EIA does not provide Anadarko’s figures for February and March, these are August and September 2017’s production figures.

Sources (links current as of October 2017):

[1] https://www.forbes.com/sites/arthurberman/2017/03/01/the-beginning-of-the-end-for-the-bakken-shale-play/#7c7652251487

[2] https://www.usasymposium.com/bakken/docs/Clover%20Global%20Solutions,LP%20-%20The%20Seven%20Major%20US%20Shale%20Plays.pdf

[3] http://oilprice.com/Energy/Crude-Oil/Permian-Drilling-Costs-Surge-Are-The-Days-Of-Cheap-Oilfield-Services-Over13256.html

[4] http://fuelfix.com/blog/2016/03/24/heres-what-it-costs-to-drill-a-shale-well-these-days/

[5] https://link.springer.com/article/10.1007/s11053-014-9229-9

[6] https://www.fool.com/investing/general/2013/05/15/10-incredible-numbers-from-the-bakken.aspx

[7] https://www.eia.gov/petroleum/drilling/archive/2017/02/

[8] https://www.eia.gov/petroleum/drilling/archive/2017/08/

[9] https://www.e-education.psu.edu/eme801/node/521

[10] https://uu.diva-portal.org/smash/get/diva2:762320/FULLTEXT01.pdf

[11] https://www.eia.gov/outlooks/archive/aeo13/