Eager to stake their claims, prospectors flocked in droves hopeful that great wealth could be achieved from extracting the regions’ valuable natural resources. The region described is not Northern California in 1849, but New York, Ohio, Pennsylvania, and West Virginia in the present day. The resource is not gold, but natural gas that can now be profitably extracted from the Marcellus and Utica shale plays. And, unlike the California Gold Rush, it is not only the prospectors, supply merchants, and saloonkeepers who will become rich. Landowners holding tracts of what was previously undeveloped or agricultural land in Ohio, Pennsylvania, and surrounding states are the serendipitous beneficiaries of the Great Lakes Gold Rush in the form of upfront bonus payments and subsequent royalties from oil and gas companies leasing the shale gas rights to their land. The wealth created through leasing these shale rights is often not planned for, yet the dollars involved can be significant. The speculative nature of drilling for gas and oil presents challenges in valuing these rights, but also opportunities for gift tax planning.

Shale Gas Overview

Shale gas refers to natural gas and oil trapped inside shale rock formations. Minuscule pores in the shale often hold significant amounts of natural gas that are difficult to recover using traditional vertical drilling methods. Shale gas production can involve multiple hydrocarbons ranging from dry gas, which is predominately methane commonly used in heating homes, cooking, and generating electricity, to wet gas which also contains concentrations of natural gas liquids (propane, butane, and ethane), to crude oil. The natural gas liquids or NGLs must be removed before the natural gas is transported via pipeline. Notable U.S. shale gas plays include Bakken (North Dakota and Montana), Barnett and Haynesville (Texas and Louisiana), and the Marcellus and Utica plays (New York, Ohio, Pennsylvania, and West Virginia). It has been known for some time that these aforementioned domestic shale plays represent large reserves of natural gas and other resources, but until recently it was thought to be uneconomical to recover these resources.

The first U.S. natural gas well was drilled in New York State in the early 1800s, but little gas was produced due to the density of the shale. Whereas vertical wells can draw from an oil reservoir from a single access point, these wells are less effective in extracting shale gas.1 The possibility for large-scale shale gas production was first seen during the 1970s when the Department of Energy and private companies partnered to develop techniques for commercial production of natural gas in the Devonian shale play. Techniques for horizontal drilling and hydraulic fracturing developed from this partnership. Mitchell Energy and Development Corporation experimented with hydraulic fracturing in the Barnett shale in the 1980s and ‘90s, which helped make large-scale shale gas production a commercial reality.2 When used in combination, horizontal drilling and hydraulic fracturing (“fracking”) “create artificial porosity and permeability within the rock”, changing previously undeveloped land into hotspots for natural gas and oil production.3 Fracking involves pumping water and liquids into wells under high pressure to fracture the shale rock to open pores and release trapped gas and oil. After the shale has been fractured, sand and other elements in the pumping fluid hold open the newly fractured pore space, which allows the natural gas to flow into the well.4 Developments in horizontal wells allow drillers to drill down to the level of the shale and turn a well 90 degrees horizontally through the shale rock.5 Horizontal drilling increases the productivity of any single vertical well by up to 10 times. However, horizontal wells cost between $6 million and $8 million to drill as compared to approximately $1 million for a vertical well.6 Due to these recent technological advances, shale plays, such as the Utica and Marcellus, are now seen as an economical source for natural gas and oil. The Haynesville shale play produced only a negligible amount of natural gas in 2008, but now accounts for 8% of total U.S. natural gas output.7

According to the U.S. Energy Information Administration (“EIA”), “shale gas’s portion of U.S. natural gas production has climbed from less than 2% in 2001 to nearly 30% today and EIA projects it will reach 49% by 2035,” or from approximately 5.0 trillion cubic feet today to 13.6 trillion cubic feet in 2035.8,9 For reference, one trillion cubic feet of natural gas represents enough supply to heat 15 million homes for one year.10 Marianne Kah, chief economist for ConocoPhillips, referred to the recent shale boom as the “most significant change in the energy industry since the 1940s”.11 Largely due to the shale gas plays, the Congressional Research Service now claims that the United States “has the world’s largest fossil-fuel resources – greater than Saudi Arabia, Canada and China combined.”12

Utica and Marcellus Shale Plays

Over the past several years, significant investments have been made in pursuit of natural gas and oil from the Marcellus and Utica shale plays. The Utica shale play is more geographically extensive than Marcellus, underlying portions of New York, Ohio, Pennsylvania, West Virginia, and Virginia. The Marcellus shale is concentrated in New York, Pennsylvania, and West Virginia. Due to its shallower depth, the Marcellus has experienced more development activity to date with more than 5,000 wells being drilled in Pennsylvania alone since 2005.13 Economists at Penn State University estimate that Marcellus shale gas drilling and production contributed $11.2 billion to the Pennsylvania economy in 2010.14 The success of the Marcellus shale play has led investors to expect similar results from the Utica shale in Ohio. Although the Marcellus may also temporarily be a victim of its own success as the incremental supply of natural gas from Marcellus shale has contributed to the decline of natural gas prices and the refocusing of efforts on more profitable wet gas regions. The higher profit potential from the NGL and oil rich regions of the Utica shale is expected to encourage investment in Utica development at a rate greater than that of the Marcellus.15 Chesapeake Energy alone has invested billions of dollars to acquire nearly 1.3 million net acres in the Utica shale.16 Industry reports predict “that growth in Ohio’s oil and natural gas production could lead to 200,000 new jobs and $14 billion in investments in the next four years.”17

The Utica shale is located several thousand feet below the Marcellus shale and has the potential to be an enormous resource for natural gas. “The Ohio Department of Natural Resources (“ODNR”) estimates a recoverable Utica shale potential between 1.3 and 5.5 billion barrels of oil and between 3.8 and 15.7 trillion cubic feet of natural gas.”18 While over 5,000 wells have been drilled in the Marcellus since 2005, Ohio’s shale gas industry is still in its early stages. Land is still being leased, permits are being acquired, and drilling has only just begun in a few counties, but activity is rapidly increasing. 100 permits for horizontal wells were issued by the State of Ohio in 2011, up from 5 in the prior year. Through May 2012, an additional 121 permits were issued and by 2014 the number of producing wells is estimated to be around 1,000.19

Much of the recent focus of the news media has been on the record number of signings of shale gas leases as oil and gas companies jockey to lock up the more valuable drilling sites. Shale gas leases are negotiated directly with individual landowners, so lease terms vary, but most leases include an upfront bonus payment or “spud fee,” an ongoing royalty payment based on the gas and other resources recovered from the landowner’s property, and delay payments. Delay payments refer to annual payments made to the lessor prior to a well being drilled.20 Leases can be structured as either developmental, which provides the lessee access to the surface for drilling and well operation, or non-developmental, which only provides the lessee with the rights to the subsurface minerals.21 Leases should specify the extent of the mineral estate interest and if water rights are included. The lease period is often split into a primary and a secondary term. The primary term refers to the exploratory period before drilling occurs, which may extend for up to two years. The secondary term refers to the length of the lease after drilling begins and extends for as long as certain production levels are met. Additional points commonly outlined in a shale gas lease include mandatory pooling of surrounding parcels of land; the site of a well, access roads, and pipelines on the landowners’ property; the storage of gas, water, and brine; free gas available for the landowner’s use; lease termination; and the steps involved in restoring the land post-drilling.22

Valuation of Shale Gas Rights

The value of an intangible asset such as shale gas rights is a function of the expected future income generated by the rights. A form of the Income Approach, typically the Discounted Cash Flow Method, is the methodology most often used in valuing shale gas rights. Applying this methodology involves projecting the anticipated royalty income and any expenses associated with the shale gas rights and discounting the cash flows back to a specific valuation date at an appropriate rate of return.

Projecting future cash flows from wells extending thousands of feet below the surface is a challenging exercise. Well production can range from one to two million cubic feet of natural gas per day to as much as twenty million cubic feet per day for the most productive wells.23 Because the natural gas and any related liquids (e.g., NGLs, crude oil, etc.) are trapped inside shale rock, it is difficult to predict when and how much gas or other resources will be recovered. The key variables influencing the projections, including timing, production, and pricing, can be supported by analyzing published data on comparable wells and through due diligence conversations with the landowner.

  • Timing: Projecting the timing of a well’s cash flows depends upon the stage in its life cycle. If a lease is not in place, then the timing to negotiate a signed lease and the corresponding upfront cash bonus payment should be factored into the projection. Significant time may pass between the signing of a lease and the actual drilling of a well. Areas in which significant production is anticipated or where wet gas is thought to be present will be the initial focus of drillers. Areas outlying the epicenters of drilling activity or that contain only dry gas may not experience activity for years after a lease is signed or at all until the price of natural gas rises. On average, a shale gas well takes about two months to drill and up to an additional six months for the post-production infrastructure to be put in place.24
  • Production: The amount of gas or oil extracted from a well is location-specific and is particularly difficult for geologists to estimate in pre-production shale plays. It is important to rely on production data from wells in similar geographies or that are otherwise analogous when developing production assumptions. The type and quantity of oil and gas differs by shale play and even within the same region. The Utica shale play is relatively new in terms of the number of wells being drilled, so limited production data is available. Based on 2011 production data released by Chesapeake Energy, the company has drilled a total of 59 wells in the Utica shale. Nine of these wells are producing and all but one well are located in wet gas areas.25 Chesapeake’s largest producing well in the Utica is the Buell 8H Well, which is located in Harrison County, Ohio. The Buell 8H Well produced approximately 1.52 billion cubic feet of gas and 13,500 barrels of oil equivalent over 198 days, which is approximately 2% of total gas production in the entire state of Ohio.26 Experience in more mature shale plays has proven that the first few years of a well are the most productive and the highest production is concentrated in the first few months. “Approximately 25% of a shale gas well’s gas production emerges in the first year and 50% within four years. Thereafter, the output falls very slowly and wells are expected to continue supplying gas for about 30 to 50 years.”27
  • Pricing: Those who have paid a gas bill over the last several years are familiar with the recent pricing fluctuations of natural gas. Between May 2008 and May 2012, natural gas prices declined from a high of approximately $13 per thousand cubic feet (“Mcf”) to $2 per Mcf.28 Depressed natural gas prices are slowing drilling and production activity in dry gas shale plays in favor of the more profitable wet gas plays or in areas where oil is also present. The decline in natural gas prices is projected to reverse over the next several years, which should boost production in dry gas regions and drive the drilling of additional wells. Respondents to Grant Thornton’s Annual Energy Survey expect the spot price of natural gas to increase to approximately $3.91 per Mcf in 2012, $4.30 per Mcf in 2013, and $4.69 per Mcf in 2014.29 The New York Mercantile Exchange (“NYMEX”) forward pricing curve suggests similar increases in natural gas prices.

 

The upfront cash bonus payment and the negotiated royalty rate on the gas produced are additional variables that need to be factored into the analysis. Bonus payments often range from $1,000 to $5,000 per acre and royalty rates can range from 12% to 20% depending on location. Once the cash flow forecast is developed, it should be present-valued at a rate of return that reflects the risks associated with achieving the cash flows. The appropriate rate of return will vary based on the stage of production of the well. Shale gas rights on land where drilling is complete and production has begun are inherently less risky and therefore more valuable than rights to land where drilling has not begun and no lease is in place. The applicable discount rate should also incorporate the risk associated with fluctuations in natural gas prices, the potential for variances in well output, and the risk of any associated environmental liabilities.

Conclusion

Through detailed analysis of data from comparable wells and observations of more mature shale plays, reasoned and supportable valuations of Utica and Marcellus shale gas rights can be developed. For owners of land where productive wells are drilled, significant wealth can be created virtually overnight. But any Fair Market Value analysis of pre-production shale gas rights must also factor in the risk that this asset could ultimately have little or no value. Even if a shale gas lease is in place, it is possible that drilling may be delayed for years or may never happen at all. Wells may be less productive than predicted. Natural gas prices may remain depressed, resulting in lower than expected royalty payments and additional delays in drilling new wells. This risk profile means that the Fair Market Value of pre-production shale gas rights will be highly discounted relative to the post-production rights of the well. The potential for substantial appreciation and income generation make shale gas rights an ideal asset for gift tax planning.

Gift and estate tax planning works best with an asset that has the potential to significantly increase in value after it is transferred to a donee. With a stagnant stock market and troubled real estate industry, many traditional assets that were staples in gift tax planning are no longer assets viewed as possessing the potential for significant value increases in the hands of the donee. However, shale gas royalty lease rights represent the type of asset that can be an estate and gift homerun. A pre-production shale gas right is an uncertain asset with a boom or bust potential outcome. Because of the bust prospect, the current Fair Market Value is constrained. However, if the future well is successful, a high value asset exists for the donee and the substantial appreciation occurs outside the donor’s estate. For landowners in the Utica and Marcellus shale, the Great Lakes Gold Rush may represent a once-in-a-generation opportunity to transfer wealth to the next generation at a low gift Fair Market Value.

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1 Moseman, Andrew. “U.S. Natural Gas Boom: The Race to Tap Shale’s Potential” 18 December 2009 <www.popularmechanics.com/science/energy/coal-oil-gas/4318390>.

2 “Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays” U.S. Energy Information Administration. July 2011, page 4.

3 King, Hobart. “Shale” <www.geology.com/rocks/shale.shtml>.

4 King, Hobart. “Hydraulic Fracturing of Oil & Gas Wells Drilled in Shale” <www.geology.com/articles/hydraulic-fracturing/>.

5 King, Hobart. “Shale” <www.geology.com/rocks/shale.shtml>.

6 “Vertical vs. Horizontal Drilling – Differences” <www.knappap.com/content/impactfee.pdf>.

7 Secretary of Energy Advisory Board. “Shale Gas Production Subcommittee 90-Day Report” U.S. Department of Energy. 18 August 2011.

8 “Annual Energy Outlook 2012 Early Release Overview” U.S. Energy Information Administration.

9 Williams, Susan. “Discovering Shale Gas: An Investor Guide to Hydraulic Fracturing” IRRC Institute. February 2012, page 8.

10 “Producing Natural Gas From Shale” U.S. Department of Energy. 26 January 2012. <http://energy.gov/articles/producing-natural-gas-shale>.

11 Schoenberger, Robert. “Cheap Energy From Shale Gas May Fuel Manufacturing Boom, Economists Say.” The Cleveland Plain Dealer 1 June 2012; pages C1 – C2.

12 Ridley, Matt. “The Shale Gas Shock” The Global Warming Policy Foundation. 2011.

13 “More Than 5,000 Marcellus Wells Drilled Since 2005” The Business Journal. Youngstown, Ohio, 7 May 2012. <http://businessjournaldaily.com/drilling-down/more-5000-marcellus-wells-drilled-2005-2012-5-7>

14 Hunt, Spencer. “Fracking Future: Controversial Method of Extracting Fuel from Shale Expanding in Ohio”. The Columbus Dispatch 25 September 2011. <www.dispatch.com/content/stories/local/2011/09/25/fracking-future.html>

15 Ohio Shale Coalition. “An Analysis of the Economic Potential for Shale Formations in Ohio”, page 26.

16 “Chesapeake Reports New Utica Production Volumes” The Business Journal. Youngstown, Ohio, 2 May 2012.

17 Hunt, Spencer. “Fracking Future: Controversial Method of Extracting Fuel from Shale Expanding in Ohio”. The Columbus Dispatch 25 September 2011. <www.dispatch.com/content/stories/local/2011/09/25/fracking-future.html>

18 King, Hobart. “Utica Shale – The Natural Gas Giant Below the Marcellus?” <www.geology.com/articles/utica-shale/>

19 Smith, Robert L. “Northeast Ohio’s Economy Could Get Boost It Needs from Gas Drilling” 21 May 2012. <www.cleveland.com/business/index.ssf/2012/05/northeast_ohios_economy_could.html>

20 Ohio Department of Natural Resources. “Landowners and Leasing for Oil and Gas in Ohio” <www.ohiodnr.com/oil/oil_landowner/tabid/17732/Default.aspx>

21 Ohio Department of Natural Resources. “Oil and Gas Leasing in Ohio” <www.ohiodnr.com/Portals/11/pdf/leasing-fact-sheet.pdf>

22 Ohio Shale Coalition. “Shale Gas Development in Ohio: Landowner Leasing”. Powerpoint presentation.

23 King, Hobart. “Production Decline of a Natural Gas Well Over Time” <www.geology.com/royalty/production-decline.shtml>

24 Ohio Shale Coalition. “An Analysis of the Economic Potential for Shale Formations in Ohio”, page 15.

25 “Chesapeake Reports New Utica Production Volumes” The Business Journal. Youngstown, Ohio, 2 May 2012.

26 “Statehouse Report” County Commissioners Association of Ohio. 6 April, 2012.

27 Ridley, Matt. “The Shale Gas Shock” The Global Warming Policy Foundation. 2011.

28 U.S. Energy Information Administration: Independent Statistics and Analysis. “Natural Gas” <www.eia.gov>

29 Grant Thornton LLP. “The State of the Industry – An Engine for U.S. Growth” Survey of Upstream U.S. Energy Companies 2012.