In 2000, natural gas production from shale formations was only 1 percent. Currently, it is about 10 percent, and the U.S. Department of Energy projects that it will increase to 34 percent by 2030. Current media attention has focused on the Marcellus Shale, as that gas play has seen a lot of activity in recent years. Michigan is slowly entering this arena because of the emerging Collingwood Shale play.
What Sparked the Hype?
For about two years, Calgary-based Encana Corp. quietly accumulated about 250,000 net acres in seven Michigan counties, centered in Cheboygan, Kalkaska and Missaukee counties, at an average of $150 per acre (with mineral rights pursuant to seven-year terms). Then in the spring of 2010, Encana’s subsidiary Petoskey Exploration LLC revealed that it had successfully tested a well in Missaukee County (commonly known as the Petoskey Pioneer 1-3 well or Pioneer well) in the Collingwood Shale formation. The Pioneer well produced at an average rate of 2.5 million cubic feet equivalent per day (including natural gas liquids constituents and condensate) during the first 30 days of production. This well targeted the Collingwood Shale at 9,500 ft. true vertical depth, with a 5,000 foot horizontal penetration utilizing a process known as hydraulic fracturing (also referred to as "fracking" or "fracing").
Fresh on the heels of the success of the Pioneer well, a state auction of mineral lease rights in May 2010 netted the state more than $178 million in bonus payments (breaking the record of $23.6 million set in 1981). The average price per acre paid at the auction was $1,507 (as compared to $26 per acre in previous auctions), with the highest price paid equal to $5,500 per acre. To understand the significance of this auction, the Michigan Department of Natural Resources and Environment (MDNRE) noted that the sum of all previous auctions dating back to 1929 totaled $190 million.
The follow-up state auction in October 2010, however, did not produce nearly the interest the May 2010 auction sale did, raising only $10 million from the lease of 273,000 acres (the state had offered a total of 450,000 acres for lease), amounting to an average price of $40 per acre. This was a far cry from the average price per acre paid at the May 2010 auction.
It can be speculated that sales at this auction were tempered because the production of the Pioneer well dropped to 800,000 cubic feet per day (as compared to 2.5 million cubic feet for the first 30 days of production). It is possible, however, that the oil and gas companies themselves may be trying to cool interest in the Collingwood Shale to drive prices down.
In addition, environmental concerns have been reported in other states where hydraulic fracturing is used, which may have led to speculation that the MDNRE may change the rules regulating this process.
It is not clear, however, whether the October auction signals a return to the typical sales for a Michigan auction of mineral lease rights or a temporary cooling of interest. As Mary Dettloff, spokeswoman for the MDNRE stated: "We know that there’s still interest in [the Collingwood Shale], given the enormous natural gas capacity in the state. I think we will have to wait a few more auctions to see if a trend emerges." The next state auction is scheduled for May 3, 2011. The MDNRE is offering approximately 44,000 acres of state-owned oil and gas lease rights.
What Is the Utica/Collingwood Shale?
The Collingwood Shale is a natural gas field between 10,000-12,000 feet below much of northern third of Michigan, in the heart of the Michigan Basin. It is about 40 feet thick and is sandwiched between the Utica Shale (above) and Trenton Black River limestone formation (below).
The Collingwood Shale is sometimes referred to as the Utica Collingwood Shale or Collingwood Utica Shale. The Utica and Collingwood Shales are, however, two separate shale formations, with the Utica Shale overlying the Collingwood Shale. In any event, the Michigan Utica Shale is not to be confused with the Utica Shale that underlies the Marcellus Shale on the east coast, which some have estimated is an even bigger play than the Marcellus Shale. To date, there is no known drilling or production from the Utica Shale – only the Collingwood Shale. It is believed, however, that natural gas produced from the Collingwood Shale will have some contribution from the overlying Utica Shale (as was the case with the Pioneer well).
The Hydraulic Fracturing (Also Referred to as ‘Fracking’) Process
Natural gas has long been produced from shales that have "natural" fractures that enable some movement of gas. Deep subsurface non-porous gas shales, however, have small fissures that provide little natural gas movement, which does not permit viable production from these formations using traditional methods. The fissures in these shales require "artificial" fractures to allow the natural gas to move more freely from the rock pores to the production wells. The process of creating these artificial fractures is known as hydraulic fracturing. This process has led to a boom in these so-called "unconventional" gas plays such as the Barnett Shale of Texas, the Marcellus Shale in the Appalachians, and the Fayetteville Shale in Arkansas.
Hydraulic fracturing begins with the construction of a vertical well bore – which could range from hundreds to thousands of feet below the surface – into the productive zone of the shale. Once the vertical well has reached the productive zone of the shale, it is then extended horizontally, for a distance ranging from 1,000 to 6,000 feet. Then, a mixture of water and chemical additives is pumped into the geological formation to open or enlarge the fissures – that is, to create the "artificial" fractures. After the fractures are created, a propping agent is pumped into the well to keep the fractures from closing after the pumping pressure is released. Once the fracturing process is complete, the internal pressure of the shale causes the injected water mixture to rise back up to the surface wellhead. The mixture that returns to the surface is referred to as the flowback. After the water mixture is removed, the artificial fractures will allow the natural gas to flow through the opened fissures and rise toward the surface to be captured by the producer.
Hydraulic fracturing has been used throughout the United States for more than 60 years (although this process has not been widely used for natural gas development until recently). Michigan has a relatively long history with the use of hydraulic fracturing. Since the mid-1980s, approximately 12,000 wells have been hydraulically fractured in Michigan, with most of these wells in the Antrim Shale formation in the northern Lower Peninsula. For a typical Antrim gas well, a fracture treatment requires about 50,000 gallons of water since these wells are shallow (typically ranging from 150 feet to 1,500 feet). It is estimated that the deeper Collingwood Shale will require about 5 million gallons of water, or 100 times more than used in a typical Antrim well.
Lease Issues from a Lessor’s Perspective
As a result of these recent developments, many owners of land in areas known for their shale formations are receiving inquiries. Agents for gas companies, commonly referred to as "landmen," approach owners of rights to the gas-containing shale deposits with a proposal to lease these rights. While an oil and gas lease may look like a form document that is non-negotiable, the person that owns the mineral rights (the lessor) should know that gas companies are often willing to compromise on many provisions in the form lease that are otherwise unfavorable to the lessor.
When a lessor negotiates its lease, in addition to focusing on the monetary rewards (i.e., royalty and per-acre lease payments), it should be sure to focus on other equally (or more) important provisions in the lease (e.g., provisions to protect the lessor from potential negative consequences that arise from the exploration and production activities taking place on their property). Lessors in areas where the gas play is considered "hot" will have the ability to negotiate more favorable terms than those lessors in areas where unproven reserves are more speculative in nature.
Various issues in a lease the lessor should consider in negotiating a lease with a gas company include: (a) accurately describing the surface and subsurface rights that are to be leased to the gas company, (b) accurately describing the substances to be explored and produced, (c) length of term issues, (d) the best royalty payment provision in light of all circumstances, (e) pooling provisions and ensuring the lease has a "Pugh" clause, and (f) surface issues specifically limiting the types of operations and structures that are constructed on the surface and protecting the surface area from environmental impacts arising out of the operations of the lessee. The lessor’s lawyer knowledgeable in these types of matters can help the lessor navigate the various issues that may arise from this relationship.