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Little Judson Prospect | Homework Help Websites

Case Study 3: Little Judson Prospect

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October 15 was another beautiful, blue-sky day in western Albany County, Wyoming. Mick McMurry could see some cattle grazing the fields on the high- plains dessert out in front of him. He was grateful for the bucolic setting and his generous circumstances which were made possible by his doing very well with some of his investments, one of which now required some concentration. Mick was the founder and President of Nerd Gas Company. The decision at hand was whether to drill an oil well known internally as the Little Judson Prospect or not, in his effort to try to chaset he Niobrara shale oil play.

 

The Company

Founded by Mick McMurry in 1996, Nerd Gas Company, LLC is a private, Wyoming-based energy investment company whose primary focus is on the efficient and responsible exploration of hydrocarbons in Wyoming and the northern Rocky Mountain region. Nerd Gas Company is one of Wyoming’s leading entrepreneurs in energy projects in a state recognized for the depth and breadth of its extensive mineral resources.

Nerd is currently involved in conventional oil and gas exploration projects in the Wyoming-Utah Over- thrust Belt and the Rocky Mountain region. Zones
of interest are primarily traditional oil or gas-bearing Cretaceous sand reservoirs, traditional carbonate reservoirs and both structural and stratigraphic traps. Nerd is also currently invested in other potential energy-producing projects in Wyoming, including a “pure play” uranium exploration project in the Powder River Basin.

Nerd Gas Company is proud of its talented group of professionals on staff that have spent the majority of their careers focusing on Rocky Mountain reservoirs and solving energy production challenges. Profession- al expertise includes land management, drilling and extraction, completions and production, and in-house energy financial analysis. The combination of strong capital, seasoned professionals and the owner’s entre- preneurial spirit allows Nerd Gas to take advantage of rapidly developing opportunities. In 2007, Nerd Gas Company was awarded the Torch Award for Business Ethics by the Rocky Mountain Region Better Business

Bureau and was the state of Wyoming’s first-ever recipient of the award.

In 2008, Nerd Gas Company contracted with the Idaho National Laboratory (INL) to conduct a feasibility study investigating the technical and economic viability of locating a natural gas-to-liquids (GTL) facility in the state of Wyoming. Initial feedback delivered by INL suggested Nerd continue to advance the project. Nerd has been working with technology providers and the state of Wyoming in a proposed, modular-designed GTL project located in central Wyoming.

In 2011, Nerd Gas, along with three local partners possessing significant geologic and exploration expertise, formed Stakeholder Energy, LLC. Stakeholder was formed to pursue large-scale uranium exploration in Converse County, Wyoming. Stakeholder has leased significant acreage ideally positioned between a uranium processing facility and the uranium mine sites.

The list of Nerd Gas affiliated companies included: High Country Fabrication, Jonah Bank, M&N Field Services, Nerd Technology, and Stakeholder Energy. In 2013, McMurry-related companies employed over 225 people.

Another extension of these companies was the very generous McMurry foundation, which has given out $49 million dollars to charitable causes in the State of Wyoming since it started in 1998. Among the many beneficiaries of their kindness is the University of Wyoming (UW). The foundation had given millions of dollars each to the Wyoming Technology Business Incubator, the Jonah field at War Memorial Stadium, the College of Business, and most recently the new Gateway Center.

 

NERD’s Entry into Oil & Natural Gas

At the time of its founding, Nerd Gas Company was a successful working interest partner in the discovery and nine-year development of both the prolific Jo-
nah and Pinedale Anticline Fields in Sublette County, Wyoming. These fields presented geological challenges which required new drilling and hydraulic fracturing technology in order to successfully extract natural
gas in these areas. Jonah Field, which was one of the largest on-shore natural gas discoveries in the USA
in the early 1990s with 10.5 trillion cubic feet of gas, was sold to Alberta Energy (later changed its name to EnCana) in June 2000, and the Anticline Field was sold in November 2001 to Shell Oil.

Mick had wanted the company to find some investment opportunities and became convinced that the company could enjoy higher potential returns (30-40% after tax) from natural resource exploration than from other investment opportunities, including real estate, which were yielding 8-10%. Although natural resource exploration was clearly riskier, Mick felt the risk could be lessened by drilling only sites that were part of existing natural resource plays, like the Bakken shale in North Dakota and the Niobrara shale in southeastern Wyoming.

Nerd Gas (NG) had drilled four wells recently. It had not been difficult operationally to drill the four wells, but it had been challenging to find enough high-quality investment opportunities. Mick considered wells to be “good” if they met all the following criteria: (1) payback of initial cash investment in 36 months or less, (2) at least 25% internal rate of return (IRR) on an after-tax basis, and (3) a positive Net Present Value (NPV).

In the first five months of production, one of the wells had already paid back 52% of its initial investment–well ahead of its target 36-month payout. The other wells were also doing well, and most of them were at least on schedule for meeting their targeted return on investment. Even though things had gone favorably for Mick so far, he knew the pressure was still on him to make good decisions because NG was planning to drill four more in the coming year.

Investment Strategy

NG acted as the operating partner in the oil and gas drilling ventures it formed, which gave it full responsibility for choosing sites and managing the well if
oil were found. NG gathered information from the states of Wyoming, Utah and Colorado and from other companies drilling in the vicinity of a well (if they were willing to engage in “information trading”). Mick would then put together a lease package for drilling 10, up to 50 wells that he considered good investments based on all the information he had gathered. The total initial investment for a typical package would be around $6 million up to $30 million. NG would retain about 25% ownership and sell the rest to several other working interest partners.

As project operator, NG was responsible for hiring

a general contractor who would actually hire a firm to do the drilling, and NG’s engineer Joe Nicholas, who also had an MBA degree from UW, would determine whether there really was enough oil to make it worth completing a well. If the decision was to go ahead, the operator would also be in charge of the day-to-day operations of a well. NG had entered into a joint venture with Allen and Crouch Petroleum (A&C) of Casper, Wyoming, in which they agreed that A&C would act as the general contractor for all the wells on which NG acted as managing general partner.

The first-year production level varied significantly from well to well. Joe found the uncertainty could be described with a lognormal probability distribution with a mean of 30 barrels of oil per day (BOPD), a standard deviation of 14 BOPD and a minimum value of zero, of course.

 

Drilling and Developing a Well

The most common drilling rig in operation was the rotary rig composed of five major components-the drill string and bit, the fluid-circulating system, the hoisting system, the power plant, and the blowout-prevention system. To facilitate the drilling process, generally a fluid known as drilling mud (composed of water and special chemicals) was circulated around the hole being drilled. In some cases, such as the Little Judson, air was used as the “drilling mud.” The major purpose of the drilling mud was to lubricate the drill bit and to carry to the surface the cuttings that could otherwise remain in the hole and clog it.

In the case of the Little Judson, the drilling procedure was divided into 3 stages. The first 300 feet of hole was drilled with a 12-1/4” bit, before running 8-5/8” diameter metal pipe, referred to as casing into the wellbore. The casing was then cemented in place, stabilizing the first section of the hole. The second stage of the well was similar to the first, except a 7-7/8” drill bit was used to drill down to 2700 feet, before running another casing string (production casing) into the hole. After cementing the production casing in place NG would be ready to test the well. Because NG was worried about the drilling fluids causing formation damage, they planned to drill into the productive Niobrara formation using air. If the well was found to be productive, the producing zone would be left as an ‘open hole completion’ without any casing supporting the productive zone. This would allow oil to flow

through the open hole completion and up through the production casing to the surface. The cost to drill an “average” well in Albany County, Wyoming, location of the Little Judson Prospect, was $625,000. There was some uncertainty, however, in the cost from well to well because of such factors as differing depths of wells and different types of terrain that had to be drilled. Experts in the local area said that there was a 95% chance that the cost for any given well would be within $62,500 of the average cost, assuming a normal distribution.

 

The “Little Judson” Prospect

Nerd had originally leased the rights to drill on
 32, 400 acres in Albany County, Wyoming back in early 2009. They later split the project into two—called the Big Judson and the Little Judson. The Big Judson (28,000 acres) was farmed out to a third party operator, with Nerd Gas just carrying a small working interest
of 20% in the two wells that were drilled by the third party. Upon drilling, they found hydrocarbon but the wells were considered “uneconomic,” so nothing else was done with the Big Judson. Now, the drilling leases are about to expire on the Little Judson. Below is a picture of the actual potential drilling site, along with representatives from Nerd Gas and the UW football team, that was taken for the cover of the football pro- gram for a Fall 2013 game.

NG has the opportunity to drill and/or renew the leases for $40 per acre. They reviewed an offsetting well in the area, drilled in the 1970s, and the geologist noticed a high reading on the resistivity log, which normally indicated hydrocarbons were present. He further felt that there was a high probability of being able to use ‘natural’ fracturing to obtain the oil, rather than having to use the more expensive ‘hydraulic’ fracturing.

Exhibit 1 shows the spreadsheet (LittleJudson.xlsx) that Joe had developed to analyze the one well, called the Little Judson Prospect (LJP), as a potential member of the package of 10 wells he was currently putting together for Mick and his investors (years 12-25 are not shown). As Joe thought about the realization of this one well, he knew the LJP had other producing wells 
in the region (Niobrara Shale region). It was therefore about a 25% chance that NG would hit the formation and decide to complete the well, but there was a much larger, 75% chance that either they would hit a dry hole, or have an operational failure that would cause zero production. In either of these cases, the pretax loss would be $625K. In the optimistic case, there would be oil produced and Joe would then find out how much the well would produce in the first and sub- sequent years. He would also learn what gravity the oil was, which would affect the total revenue generated by the well.

Revenues and Expenses. The spreadsheet was basically an income statement over the well’s life. The price per barrel was calculated from the market value of West Texas Intermediate at Cushing, Oklahoma, which today was $104.25. The production in barrels
of oil per day (BOPD) was then estimated for the first year and calculated for each succeeding year based on the percentage decline value given in the assumptions. The gross revenue was just the product of the price per barrel times the barrels of oil produced in a given year. Out of the gross revenue came a 17% royalty payment to the owner of the mineral rights, leaving net revenue. Several expenses were deducted from net revenue to arrive at the profit before tax:

1. Monthly operating costs of $500 were paid to contract operators in addition to a budgeted amount of $12,000 for other operating expenses that might occur on an annual basis. These costs were increased annu- ally by the inflation factor.

2. Local taxes of 6.4% times the NG gross revenue (after royalties) were paid to the county and a severance tax of 6% times the gross revenue (after royalties) was paid to the state of Wyoming.

3. Depreciation expense for year 0 equaled the in- tangible drilling cost, which was 72.5% of the
total well cost. The remainder of the initial drilling cost was depreciated on a straight-line basis over seven years.

To compute profit after tax, the following equations applied:

Profit after tax = Profit before tax – Depletion – Federal Income Tax

Where: 
Depletion = minimum of .5 * (Profit before tax)

or .15 * (Net revenue)
Federal Income Tax = Federal tax rate * (Profit before

tax – Depletion)

 

Initial Results and Investment Considerations.

To find the net present value (NPV), Joe added back the depreciation and depletion to the profit after tax to come up with the yearly cash flows. These flows were then discounted at the company’s hurdle rate of 25% for projects of this risk (see Exhibit 2 for a listing of rates of return for investments of varying maturities and degrees of risk) to calculate the NPV through any given year of the well’s life. His pro forma analysis indicated the project had an amazing IRR of 113% and an NPV of $1.13 million.

Joe was feeling good about the LJP, even though
he knew he had made many assumptions. He’d used an API (American Petroleum Institute) gravity index of 40 to estimate the density of the oil because it was the expected (mean) value, when in reality he knew it could be as low as 33 or as high as 43, with the most likely value (mode) being 41. The density of the oil affected the price that NG could sell the oil at. An API gravity reading of 43 degrees commanded the highest price. Below 43, the molecular chains become larger and less valuable to the refineries. It was safe to assume that you should deduct $0.015/barrel from the price for every 1/10 degree that the oil’s reading was below 43. For example, oil with an API reading of 40 would cause a deduction of $0.45/barrel in the price sold i.e., it would move the price sold from $100 down to $99.55). He also guessed that inflation, as measured by the Gross National Product (GNP) Deflator (a measure similar to the Consumer Price Index or CPI), would average 2.5% over the 25-year project life, but he thought he ought to check a couple of forecasts and look at the historical trends.

 

Exhibit 1

Little Judson Prospect Base Case Spreadsheet

See Exhibit 3 for historical oil prices and both fore- casts of GNP Deflator values as well as historical GNP Deflator values. Joe’s idea was to use the GNP Deflator to forecast oil prices after their four-year contract expired.

Further Questions and Uncertainties. When
Joe showed the results to Mick and Dick Bratton, a potential partner of Mick’s, Dick was impressed with the “expected” scenario but asked, “What is the down- side on an investment such as this?” Joe had done his homework and produced Exhibits 4 and 5 together (again years 12-25 are not shown). Exhibit 4 showed the results if there was not enough oil to develop. Exhibit 5 showed what would happen if there was enough oil, but all other uncertain quantities were set at their 1 chance in 10 worst levels. Dick was some- what disturbed by what he saw but said, “Hey, Mick, we’re businessmen. We’re here to take risks; that’s how we make money. What we really want to know is the likelihood of these sorts of outcomes.”

Joe realized he had not thought enough about the probabilities associated with potential risks that a project of this kind involved. He also put his mind to work thinking about whether he had considered all the things he had seen that could change significant- ly from one project to another. The only additional uncertainty he generated was the yearly production decline, which could vary significantly for a given well. He had used what he considered the expected value in this case (12% per year), but now he realized he ought to multiply it by some uncertain quantity, with a most likely value of 1.0, a low of 0.67, and a high of 1.67, to allow for the kind of fluctuation he had seen.

Joe wondered what would be the most effective way to incorporate all six of the uncertainties (total well cost, whether the well produced oil or not, first-year production of oil, the API gravity, rate of production decline, and the average inflation over the next 25 years) into his investment analysis. He remembered doing “what if ” tables with spreadsheets back in busi- ness school (the old College of Commerce and Indus- try or C&I), but he had never heard of a six-way table. As he skimmed back through his decision science book, he saw a chapter on Monte Carlo simulation and read enough to be convinced that this method was ideally suited to his current situation.

When Joe told Mick about this new method of evaluation he was contemplating, his boss laughed and said, “Come on, it can’t be that hard. What you’re talking about sounds like something they’d teach brand-new MBAs. You and I have been doing this type of investing for years. Can’t we just figure it out on the back of an envelope?” When Joe tried to estimate the probability of his worst-case scenario, it came out to .001%–not very likely! There was no way he was going to waste any more time trying to figure out the expected NPV by hand based on all the uncertainties, regardless of how intuitive his boss thought it should be. Consequently, Joe thought a little more about how Monte Carlo simulation would work with this deci- sion.

In his current method of evaluating projects, he had used the three criteria mentioned earlier (< 36-month payback of initial cash investment, > 25% IRR on after-tax basis, and a positive NPV). He could see that calculating the average IRR after several Monte Carlo trials wouldn’t be very meaningful, especially since there was a 75% chance that you would spend $625K on a pretax basis and get no return! It would be im- possible to find an IRR on that particular scenario. He did feel he could calculate an average NPV after sev- eral trials and even find out how many years it would take until the NPV became positive. As he settled into his chair to finish reading the chapter, which looked vaguely familiar, he looked up briefly at the arid land and wondered for a moment what resources were under that land.

 

Questions

1. Based on the base case scenario and the two alternative downside possibilities, is this invest- ment economically attractive?

2. What benefit can Monte Carlo simulation add to Joe and Mick’s understanding of the eco- nomic benefits of the Little Judson Prospect?

3. Incorporate uncertainties into the spreadsheet using Crystal Ball. What do the Monte Carlo results reveal? What is the probability that the NPV will be greater than zero? How sensitive is the NPV to the different inputs?

4. Think about the proper discount rate—should it be adjusted now that much of the risk has been modeled explicitly with Crystal Ball? Should Mick invest?

Exhibit 2 US Treasury and Corporate Bond Yields

Exhibit 3 Historical and Forecast Data

Exhibit 3 (continued)

Exhibit 4 Spreadsheet with No Oil Produced

Exhibit 5

Spreadsheet with Oil Found but All Other Uncertainties Set at 1 Chance in 10 Worst Level

 

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