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Shale Revolution

The vast majority of new production in the US is from shale formations. It has been understood almost since the beginning of the oil and gas industry that shale deposits are the source rock for conventional crude oil and natural gas deposits. Over geologic time hydrocarbons migrate under pressure and high temperatures from the shales to reservoir traps in conventional sandstone and carbonate reservoirs.

Existing drilling, completion, and production technology did not allow for practical production of this hydrocarbon-rich “unconventional” resource – the shale rock itself – until just over ten years ago. At that time engineers at Mitchell Energy combined advances in horizontal drilling technology with massive hydraulic fracturing (“fracing”) to economically produce the gas from the Barnett Shale. This opened the door to production from other gas shales such as the Marcellus and the Haynesville and oil shales such as the Bakken, the Eagle Ford, and the Wolfcamp.

Shale reservoirs have ultra-low permeability, which means that the “holes” (porosity) in the rock that contain the hydrocarbons are very poorly connected and the fluid does not easily flow through the rock. “Fracing” opens pathways in the shale that allow the hydrocarbons to more easily flow into the wellbore. The wells produce at high rates but with a very rapid initial rate of decline as the fluids and pressure within the fractures are drained. The flow then begins to come from the shale matrix and the production levels out at a low rate.

Bakken Decline Curve (Baja 2215H Well)

GLS - Bakken Decline Curve (Baja 2215H Well)

Source: Five States data


Development of horizontal drilling technology combined with new advances in the 60-year-old hydraulic fracturing technology has made shale development technically viable. Using horizontal drilling through the length of the reservoir instead of across (perpendicular to) the reservoir, one well can now access the same amount of “pay” formation that previously would have required drilling 10 or more vertical wells. The combination of high oil prices and higher production rates has made the shale plays economically viable.

But this technology is expensive. The capital cost to drill and complete horizontal wells is three to five times or more that of conventional vertical wells. The operating costs of horizontal wells are also significantly higher than vertical wells. The capital cost per recoverable barrel of oil of a conventional well is in the $20 to $40 per equivalent barrel range. The capital cost per recoverable barrel of oil of an unconventional well is in the $40 to $80 per equivalent barrel range or more. This technology has a great deal of operating leverage.

Testing the Shale Boom

GLS - Testing the Shale Boom

Forward Curves, Markets & Trading Strategies

Energy commodities—crude oil, natural gas, heating oil and gasoline—are bought and sold globally through Futures contracts (“Futures”). These are legally binding agreements for the physical delivery of a specified volume of a commodity at a specified time and place for an agreed upon price. Futures are not derivatives; they are contracts to actually purchase and sell the physical commodity.

Energy Futures are the most actively traded commodity contracts in the world. These contracts are priced in an auction process on the New York Mercantile Exchange (“NYMEX”), where crude oil and natural gas Futures can be bought and sold for various months over the next 10 years.

A forward price curve (“forward curve”) is the graphical representation of various prices for delivery of a commodity at different points in time.

TVC - NYMEX Oil Futures

There is no preordained shape to a forward curve. The underlying shape is determined by market expectations of future supply and demand. These expectations shift over time, sometimes quickly and quite dramatically based on new information about how political events, general economic factors and even weather will potentially impact supply and demand.

Forward curves tend to take three basic shapes:

  • Backwardated – a “Backwardated Curve” is downward sloping. The current price is highest and prices decline over time. A Backwardated Curve is indicative of a market where current inventories are tight, but future supply is expected to catch-up with demand over time, causing expected future prices to fall. This is typically the normal shape of a commodity futures curve.
  • Contango – a “Contango Curve” is upward sloping. The current price is lowest and prices increase over time. A Contango Curve is indicative of a market where current inventories are in a surplus condition, but expectations of economic growth or geopolitical events, which could disrupt the supply chain, cause future prices to be higher than current prices.
  • Flat – a “Flat Curve” is one where the current price and prices into the future are the same. Flat curves for crude oil and natural gas seldom occur, as this condition tends to happen during a period where market expectations are radically shifting given a political event or there is a general shift in perceptions of global economic growth.

TVC - Backwardation

TVC - Contango

It is important to note that forward markets have historically proven to be poor predictors of actual realized prices at the time of physical delivery. Expectations at a given point in time set the pricing for Futures contracts. But expectations can change—and change quickly. For example, several years ago the 2014 forward price for natural gas was $8/mcf increasing to over $10/mcf in the future. Subsequently, new drilling technology created an opportunity for development of various shale basins, particularly the Marcellus, generating an abundance of cheap natural gas priced in the $3.50 to $4.50/mcf range.

Five States and the Forward Curve

Five States owns long-lived producing oil and gas properties. In trading terminology, we would say Five States is “long” physical oil and gas for some time into the future. Because these producing assets have predictable monthly production volumes, Five States can “lock in” the prices it will receive on future production at the prices available on the forward curve.
Five States hedges to reduce risk. Being able to sell forward, or “short” oil and gas futures at forward prices, allows Five States to lock-in future prices—securing cash flows and returns for our investors.
This type of hedging, based upon our expected physical production, is the opposite of speculating. It actually gives us an opportunity to reduce risk by reducing volatility. An example of this type of hedging transaction is shown below:


Assume the following pricing for 1 Futures Contract (1,000 barrels of crude oil):

  • Hedge “today”: Five States (a Producer) sells 1 Futures Contract, or 1,000 barrels, for delivery in April 2015 on the New York Mercantile Exchange (“NYMEX”). A buyer of the Futures contract has agreed to purchase 1 Futures Contract in April for $90/barrel.
  • Hedge Settlement: In April 2015, Five States, the seller of the Futures Contract, and the buyer of the Futures contract make a cash settlement based upon the final NYMEX price of the April Contract. In this example, Five States will collect the difference between $90/barrel and the current market price of the April Futures Settlement price of $75/barrel, i.e., Five States collects $15/barrel, or $15,000 in total ($15/barrel multiplied by 1,000 barrels per Contract), less transaction costs.
  • Physical Sale: Five States sells 1,000 barrels of production in our regular sales channel for the market price on Settlement day for $75/barrel, collecting a total of $75,000.
  • Hedge Settlement and Physical Sale Combined: The net of the hedge settlement for Five States, a gain of $15/barrel or $15,000 in total funds, combined with the sale of physical barrels at $75/barrel or $75,000, creates a net effective sale of 1,000 barrels at $90/barrel ($15/barrel gain from the Futures Contract plus the physical barrels sold for $75/barrel). This generates a net cash flow to Five States of $90,000 at the April Settlement of the Futures Contract and physical barrels.

Excluding basis risk for location or grade differentials, regardless of the actual price at which physical barrels are sold when the hedge is exited, the net price to Five States will be the same as the price at which the Futures were sold. In the example above, if market prices in April of 2015 had increased to $110, there would have been a loss on the futures contract and the physical barrels would have been sold for $110, but the net to Five States would still have been the same $90/barrel as in the previous example.

Trading Strategies

Many firms employ hedging strategies which use options in addition to buying and selling futures. Options on physical contracts are derivatives, as the economic transaction is derived from a relationship to an underlying physical transaction (in the case of Futures contracts).

Five States can and will employ some options strategies as appropriate. In a broader market view of using options as a hedging tool, the sale of options can act as an accelerant which exaggerates a market move.

Price Differentials

Price differentials are the difference between a market price, such as the NYMEX futures spot price for oil and the price received when the actual physical production is sold (commonly referred to as the “wellhead price”). The difference can be positive or negative depending on numerous factors.

The main factors that determine the price differential are product quality and regional market dynamics. Although the crude oil market is a global market there are regional dynamics that affect the price of crude of differing qualities. The highest quality crude oil is not always the most valuable.

Product Quality

Two of the most important quality characteristics of crude oil are sulfur content and density. Oil with high sulfur content is called “sour” and, conversely, low sulfur oil is considered “sweet.” Typically the lower the sulfur content, the more valuable the crude oil.

The most common measure of the density of a petroleum liquid is the American Petroleum Institute (“API”) gravity. The API gravity is an inverse measure of the relative density of a petroleum liquid. If one petroleum liquid floats on another it is less dense and therefore has a higher API gravity. Typically the higher the API gravity—or less dense oil—the more valuable it is. The reason lighter, sweeter crude oil is more valuable is because gasoline and diesel fuel, which typically sell at a premium to residual fuel oil, can be more easily and cheaply produced using light sweet crude.

Classification API gravity
Light Crude Oil > 31.1
Medium Oil 22.3 – 31.1
Heavy Oil 10 – 22.3
Extra Heavy Oil <10 


There are several benchmark crude oils around the world and within the US. In Europe, the benchmark crude oil that is most actively traded is Brent Crude Oil. Brent is a light, sweet oil produced from the North Sea. In the US, the benchmark crude oil is West Texas Intermediate (“WTI”) which is a light sweet crude oil from west Texas. Although no two reservoirs produce identical oil, reservoirs in the same region often produce similar crudes. Therefore there are numerous international and regional benchmark crude oils to help determine field and wellhead prices.

Crude Oil Prices (WTI vs. Brent)

Source: EIA

Source: EIA

Regional Market Dynamics

In terms of quality, WTI is slightly superior to Brent (North Sea) oil. It has less sulfur and is less dense (higher API). However due to various market dynamics, the relative price has not always reflected this fact. In the past, the two crudes traded as one would expect based on their respective quality characteristics. Until the last few years, WTI traded at a slight premium to Brent. This has reversed in the last few years.

The reason for the recent divergence is increasing US supply overwhelming current infrastructure. America’s oil infrastructure has been built around declining domestic production and a large and growing amount of imports. Since the majority of oil in the US has been imported for the last 20 years, much of the oil infrastructure was built around refining imported oil, then moving the refined products—such as gasoline and diesel—around the country. Refined products from the Gulf Coast flowed north, and refined products from both west and east coasts refineries flowed inland. The US infrastructure was not designed to move oil from the interior of the country to the coastal refineries. The US oil pipeline system is not completely interconnected, so increased supply in certain areas can create a regional glut, which can cause significantly high price differentials.

Recent US oil “posted” prices are displayed in the accompanying chart. The price of crude oil in the Bakken (i.e., North Dakota) is represented by the Williston Sweet price. On November 28, 2014, the price was approximately $12 per barrel less than WTI, although the quality of the oil on a sulfur and density basis is very similar. Because North Dakota has limited refinery capacity, the vast majority of the oil produced is shipped out of state.

Crude Oil Prices (11/28/14)

Source: Plains Crude Oil Price Bulletin 2014-211

Source: Plains Crude Oil Price Bulletin 2014-211

Great Expectations: Revisiting Peak Oil

Crude oil supply expectations have changed over the last twenty years. In the late 1990s, the idea of “peak oil” was gaining popularity. The theory was presented by M. King Hubbert in the 1950s and popularized in the last quarter of the 20th century. Working as a geologist for Shell, he predicted US oil production would peak in the 1970s and then decline steadily.

Until recently, it appeared Hubbert was right. Production in the US did peak in the early 1970s and started a three decade decline…a sunset industry indeed. The peak oil theory is based on the premise that the amount of oil under the ground in any geographic region is finite. As resources are produced, pressure in the reservoir decreases, produced volumes follow a skewed bell-shaped curve, and the resource is ultimately depleted. Artificial lift technologies and other secondary recovery methods are used to extend the life of a particular well, but ultimately fields deplete and wells are plugged . . . the end.

US Crude Oil Production (Million Barrels per Day) 1920-2013

Source: EIA

US Crude Oil Imports (Million Barrels per Day) 1920-2013

Source: EIA

What the theory did not take into account was the technological innovation of horizontal drilling combined with the 60-year-old technology of hydraulic fracturing to tap into shale resources that were previously uneconomic to exploit. We always knew shale formations existed and could be exploited, but until the last 10 years it was not technologically or economically viable. Higher commodity prices have made the application of advanced recovery technology viable, thus revolutionizing the industry. Since the mid-2000s, US crude oil production is up 60% and crude oil imports are down 20%.

A technology called 3-D seismic imaging has helped map the earth below the surface. Seismic data is collected and mapped by sending sound waves into the ground that reflect off of different rock layers. Some argue the “shale revolution” is temporary in nature due to the high cost to produce from such resources and the sharp decline production profile. They argue it is simply creating a second peak in production, only to return to its inevitable decline.

Another thought is that we will see “peak consumption” before we see “peak oil.” The introduction of LNG, CNG, etc. into the market could turn more and more consumers away from oil. While oil has long dominated the transportation market, if an alternative fuel comes along that burns cleaner and is just as easy to access, oil’s days could be numbered.

This brings us to the concept of recoverable resources. Technically recoverable resources include all the oil and gas that can be recovered based on current technology and knowledge of the geology. As technology advances and as we learn more about the rock, this category can expand. Economically recoverable resources are a subset of technically recoverable resources that can be produced at a profit given the current price environment. As prices move up, this subset expands, and as prices move down, it contracts. Typically the capital cost to drill and operate in a particular play moves down over time as operators gain efficiency, which expands the volume of economically recoverable resources. Commodity prices and capital cost thus work together to determine how fast and to what extent resources are developed.

The US Energy Information Administration (“EIA”) estimates the US has 223 billion barrels of technically recoverable resources. Of our recoverable resources, 25 billion is “proved reserves.” Proved reserves are the most certain category within recoverable resources that can be produced under current economic conditions. This category expands as new wells are drilled and contracts as existing wells are produced. It also expands or contracts as commodity prices change. This is the category that is typically reported by public companies and filed with the SEC.

JD - Oil and gas resource categories reflecting varying degrees of certainty

OPEC in the Modern Era

Founded in 1960, the Organization of the Petroleum Exporting Countries (“OPEC”) is a coalition currently comprised of 12 member countries predominately located in the Middle East. OPEC’s stated mission is to provide “steady income to producers and a fair return on capital.” This mission has historically been accomplished through production restrictions.

Founding members Saudi Arabia, Iran, Iraq, Kuwait and Venezuela carry the greatest influence within OPEC. As a result, in the mid-1970s, OPEC cut production to drive up world oil prices in retaliation for US aid to Israel during the Yom Kippur War.

In response to falling demand in the early 1980s, OPEC nations cut production again to boost oil prices and cure economic hardship among member states. It is widely believed that Saudi Arabia intentionally collapsed the price of crude in 1985-86 by increasing production as prices fell. The unstated goals of this unilateral move were to punish fellow OPEC members who were cheating on their quotas and to collapse the US oil industry.

By the late 1990s, owing to significant economic declines in Southeast Asia and growing conservation among consumers, lack of demand for crude caused crude prices to fall below $10 a barrel. OPEC responded by cutting production until prices corrected.

Even internal moves within OPEC impact prices. For example, in November 2007, oil prices responded drastically as member countries talked openly about converting cash reserves and the reference pricing of crude oil from the US Dollar to the Euro.

As of 2013, OPEC claims to hold 81% of global crude oil reserves. While this number is likely inflated, the US Energy Information Administration (“EIA”) projects that OPEC member countries produce about 40% of the world’s crude oil and that OPEC oil exports represent approximately 60% of the total petroleum traded internationally.

With respect to total OPEC exports, Saudi Arabia has the greatest concentration of control. Currently Saudi Arabia and Iran are locked in a price war over market share in China. Both countries are competing for what they perceive to be the next big oil import market as the US reduces its imports and achieves greater energy self-sufficiency.

However, OPEC has not given up on the US market. In early November, Saudi Arabia slashed prices specifically for the US. The target: US energy producers. Some commentators have dubbed these moves an “oil price Cold War.” As the US’s second-largest source of imported oil behind Canada, Saudi Arabia is likely taking bold steps to shore up US market share by undercutting US production. By dropping prices near or below break-even points for shale producers, Saudi Arabia seeks to force US companies to take their rigs offline and reduce supply, thus securing Saudi Arabia’s position.

Where We See Opportunities in Oil & Gas

Historically low interest rates continue to drive capital away from traditional “safe” liquid investments such as CDs, money market funds and bonds in pursuit of yield. Investors are paying ever higher prices in an attempt to lock in current return. The increasing flow of capital into riskier assets–such as stocks that pay dividends and income-producing real assets–is resulting in “asset inflation.”   The risk associated with the end of “0% interest rates” is unknown, but I suspect it will not have a “happy ending.” I find this flow of capital concerning. I have always found “chasing yield” to be a lousy investment strategy with the potential of driving the price of income producing assets above their fundamental value.

Valuations of income-producing assets move inversely to changes in yield. As investors become willing to accept lower yields from riskier assets, the value of those assets increases. For example, if the market is willing to accept a 10% yield, an asset paying $100 per year is worth $1,000.

$100 ÷ 10% = $1,000

If the market subsequently accepts 8% as the market yield for the same asset, the asset would price at $1,250.

$100 ÷ 8% = $1,250

When the imputed yield on an income-producing asset is used to calculate the value of the asset, the imputed yield is called the “discount rate.” So as discount rates (i.e., yields) fall, the value of assets rise.

Of course, all of the change in asset values is not due to interest rates. There are other variables impacting valuation. Investor perception of changes in risk and expectations of future performance of the assets also impact value. Additionally, expectations of improvement or deterioration of broader economic conditions (i.e., fear of inflation or recession) impact valuations.

Oil and gas assets have not been immune from the pressure of declining interest rates and yields. As discussed in previous articles, declining discount rates have contributed to higher valuations of producing properties and midstream assets (e.g., pipelines, etc.). The oil and gas sector has been further stimulated by higher oil and gas prices since the late 20th century and by real growth being experienced in the sector due to the renaissance in domestic conventional energy development.

Crude Oil Acquisition and Development (“A&D”), Natural Gas A&D and Midstream Development are three very different segments within the oil and gas industry. Each segment is being impacted by different fundamentals, and the three are not in lock-step. The current risk profiles of each segment and the potential returns have diverged.

Crude Oil A&D

Crude Oil A&D is in favor in the investment world. Valuations are high–a function of high oil prices and low interest rates combined with the success of shale oil development and redevelopment of conventional oilfields (Note: I wrote this section prior to the correction being experienced in the oil sector, so these conditions may be changing).

There are many who believe that current oil prices are sustainable and that lower prices are unlikely. They point to the stability of world prices since 2008 as oil production in the US dramatically increased.

In our assessment, the risk of a price correction in the intermediate term remains. Production is increasing in the US at an amazing rate. But production overseas has declined by more than the increase in the US. Over the last three years, oil production in the US has increased by over 3.0 million barrels per day, while over 3.5 million barrels per day worldwide have been lost due to disruptions, primarily in the Middle East. Without this loss of production overseas, it is almost certain that the increase in supply would have driven prices lower.
Growth in Tight Oil ProductionGrowth in Supply Disruptions

The consensus is that, barring a price collapse, US oil production will continue to increase. Without further supply disruptions overseas, this will likely result in a decline in oil prices. As it has been for the last several years, the expectation of a decline in oil prices is reflected in the futures price of oil. The increased US production volume is from high cost/rapid decline shale formations, so a price correction will likely result in a quick decline in US production.

Crude Oil Futures Prices

NYMEX Futures Prices for Crude Oil, October 20, 2014

The risk of a decline in oil prices makes new investments in producing oil properties and high cost development riskier. As discussed last quarter, many shale oil projects become marginal if the reference price of crude oil drops into the $70 to $80 range.

In the oil sector, Five States continues to focus on mezzanine financing. Participating in new transactions in a preferred position provides us a lot of downside protection if prices decline, while allowing us to continue to participate in the attractive returns available in this space.

The shale oil boom appears to be peaking. We expect to see continuing development financing opportunities as long as prices remain at current levels. Slightly lower prices will materially reduce the borrowing capacity of shale projects, which could stimulate more mezzanine opportunities as independents need additional capital to shore up their financial condition to continue their development projects.

The shale oil “land rush” appears to be slowing down. The major shale plays are all identified, and the open acreage in these plays has been leased. Most oil companies participating in shale plays have all of the land inventory they can develop.

We have been marketing our interests in the Bakken in North Dakota through the summer. If we can capture the future value of the development in today’s market, we would like to sell these assets. If we cannot capture the value of future development, we will continue to hold them for current income.

Focus on conventional oil redevelopment

Those of you who have been investing with Five States since before 2008 will recall that one of our primary expectations when we modified our investment strategy was the tremendous potential in the redevelopment of conventional tight oil fields.

One of our most successful investments in Five States Energy Capital Fund 1, LLC (“FSEC Fund 1”) is the OSR Halliday, which is a conventional oil redevelopment project. In our legacy funds, we own interests in several other conventional fields that are attractive for redevelopment. Our primary engineering consultant is completing a development analysis of one of our largest holding, the S.E. Adair in Five States Consolidated III, Ltd. We plan to redevelop this field in 2015, and use it as a prototype for pursuing opportunities to fund redevelopment of other fields with independent producers in the Permian Basin.

Financing redevelopment is an ideal investment for Five States Energy Capital Fund 2, LLC (“FSEC Fund 2”). The financing need tends to be small–in the $10 million to $25 million range. This size tends to keep our larger competitors out of the space. “Dry hole” risk is very low. The development is “down spacing” (i.e., where new wells are drilled in defined fields between producing wells) and, unlike the shale plays, the break-even is well below $40/barrel. Our knowledge in this area provides us a competitive advantage. Over the last 15 years, we have invested and developed extensively in this area. The rate of return is lower than in riskier mezzanine shale financing, but the return is still in the double digits. We think such a focus is ideal for investors with our level of risk tolerance. We are actively doing the research to identify private independent producers we believe will be interested.

Natural Gas A&D

Natural gas prices remain soft. The low natural gas prices in North America are due to the success of shale development in the last decade. The success of the development resulted in a huge increase in production volumes and drastically lowered prices for natural gas throughout the US.

Marcellus Impact on US Production

Until the last couple of years, the consensus was that natural gas prices would recover quickly. This expectation seems to have reversed. Although the current spot price for natural gas is higher than a few years ago, futures prices have fallen to new lows. This results in a lower net present value for producing properties, leading to more attractive valuations for any given asset.

Futures prices are now at a level where the discounted cash flow valuation is practical to buy and hold, regardless of the length of time until recovery. Before the decline in futures prices, a large part of the imputed value on many gas properties was the value of new wells expected to be drilled. At today’s lower futures prices, the expectation of the future drilling has been pushed into the future, decreasing the present value significantly.

The cost of most shale gas development is high. The imputed cost is between $3.50 to $5.50 per mmbtu, depending on the formation (i.e., location). With natural gas trading at $3.50 – $4.00, drilling new wells in many areas would, at best, be a breakeven proposition.

Due to low natural gas prices, little drilling for conventional dry gas is being undertaken. The number of rigs drilling for gas has been decreasing over the past five years. The increasing demand for gas is currently being met by associated gas from oil wells and continued development in the lower cost shale plays. Demand is projected to exceed supply in the next several years. When demand exceeds supply, gas prices should increase, and we expect to see a resurgence of natural gas development. When prices are over $5.00, there are material volumes of gas to develop.

US Drilling Activity


The current returns on new natural gas production acquisitions are lower than could be achieved when discount rates were higher. We believe the downside risk on gas prices is low, and, unlike crude oil assets, limited value is being imputed to future development.

The potential for a cyclical recovery in natural gas prices appears high. Due to depletion and increasing demand, it does not seem possible for natural gas prices to remain below replacement cost for more than five to seven years. Natural gas demand is increasing.  The low cost of natural gas translates into materially lower costs for industries that directly consume natural gas as both a feedstock and an energy source, as well as a primary fuel for electric generation. The technology is evolving for using Liquefied Natural Gas (“LNG”) as a large fleet transportation fuel. LNG is discussed in depth in Jim’s article “Liquefied Natural Gas,” and in the Midstream section of this article.  An additional indirect cost is the material reduction in emissions from shifting from coal or diesel to natural gas.

If we can identify good quality acquisition targets, we believe we can buy them on a valuation that will provide an attractive yield while we wait. We are putting contract land people in the field this fall to directly solicit these types of assets. Patient acquisition of producing gas properties at this time may be a good longer-term play.

Midstream Development

Midstream (e.g., pipelines, rail terminals, processing plants and other infrastructure) has been the “sweet spot” for Five State over the past three years. Great Northern Midstream in FSEC Fund 1 may prove to be our best investment of the last decade. Advantage Pipeline is also proving to be a strong performer despite the delays, budget overruns and management issues we experienced earlier in the investment. Our expectations for the Tenawa natural gas processing plant in FSEC Fund 2 also remain strong.

Economic fundamentals are driving the growth in midstream. There is a lot of demand for the development of new infrastructure. Many are small projects in the $50 million to $100 million range. These projects are typically too small for the larger public energy capital firms. Many of these projects are “one off”, not lending themselves to mass production. Such projects are management intensive, so they are typically being developed by industry veterans, ideal for our type of private equity.

We have positioned Five States to provide “Independent Capital for Independent Producers”®, which is proving to be a competitive advantage. Many independents recognize that they need a partner who will not be predatory in such projects, where unexpected timing events and underlying business changes are likely. Independents are recognizing the advantage of a financing source that has considerable experience with working interest investments, operations, and upstream activities; one that will look at the ups and downs of the industry practically and not like a classic investment banker.

There are two changes to our historic investment profile as we add more midstream. The investment in each project is a larger percentage of each fund. Unlike the acquisition of producing properties which generate operating cash flow almost immediately, midstream development projects may take a year or more before they start generating cash distributions. The returns generated from these investments in the intermediate term more than compensate for the lack of yield during the construction period.


New investments in oil acquisition and development are tough. Helping capitalize independent producers in conventional redevelopment plays is a sweet spot for us. At current valuations, direct participation in shale deals do not provide the return we believe appropriate for the risk.

We perceive good long term value in natural gas. Acquisitions based on current prices should provide good yield, with upside in future price increases and additional development. Natural gas properties are still not actively trading. We have seen few gas deals this year. We assume that this is partially due to the fact that independent producers do not see a development play at current prices. Some natural gas producers must be financially stressed. We are putting in place a program to actively solicit gas properties.

Good values and high returns for the risk are available in midstream development. We expect continued growth in this area, even if there is a correction in oil prices and if drilling slows down.

We continue to add value to our legacy funds through increased density drilling. This is a very high return for the incremental investment. Unlike shale development, the break-even oil price on conventional redevelopment is very low.

The outlook for FSEC Fund 1 is getting stronger. At this time, we anticipate returns greater than the target pro forma for the fund, despite the long time it took to fully place the fund. We liquidated two of our weaker performing assets in the third quarter at values materially higher than the values used in our year-end report. These sales added over six percent to the value/return of the fund. Realizing returns on sale higher than our “carrying value” continues to support our disciplined value investing thesis.

We hope to have FSEC Fund 2 fully committed in 2015. At this time, we plan to open FSEC Fund 3 in the first half of 2015.

A Shakeout at $100 Oil?

I have received several inquiries regarding recent articles (such as “Shakeout Threatens U.S. Shale Patch as Drillers Go for Broke” which I distributed in June) asking my thoughts on a shakeout for the industry and the impact such an event could have on Five States. The following are my comments on (1) the Case for a Shakeout, (2) the Impact on the Five States Energy Capital Funds and (3) the Impact on the Five States Legacy Funds (i.e., Consolidated I, II & III).

The Case for a Shakeout

The domestic oil sector has been booming for a decade, primarily due to higher sustained world oil prices. For the last ten years, crude oil has averaged $77.55 per barrel compared to $22.55 per barrel in the previous decade. The use of horizontal drilling technology to develop shale reserves is commercially viable with oil prices above $50 per barrel, so development projects that were not viable a decade ago are profitable at current oil prices.

U.S. Crude Oil Production through April 2014 (1000 bbl/day)

U.S. Crude Oil Production through April 2014 (1000 bbl/day)

Fundamental changes in the domestic oil industry have increased certain risks. Three changes—(1) Increased Differential Volatility, (2) Increased Operating Costs and (3) Increased Capital Cost—have increased operating leverage. In addition to increased operating leverage, the level of financial leverage (i.e., use of debt in the capital structure) is very high for many companies.

Increased Differential Risk

Wellhead price differentials(1) have increased materially in the last five years. Increases in price differential are due to differences in crude oil quality and transportation costs. Through the late 20th century, oil price differentials were small and fairly constant. This has changed with the increase in domestic production. Today differentials range from a few dollars per barrel in Texas to $11 per barrel in North Dakota. In the past few years we have experienced short-term differentials as high as $25 per barrel, lasting for weeks at a time.

Prior to the recent increase in domestic production, the U.S. had sufficient capacity to transport the vast majority of oil production by pipeline. Pipelines are the safest and most cost effective method for transporting oil. Today, due to the increased volume, the pipeline network is effectively full, so more oil is being moved using higher cost options such as rail, barge and truck, increasing the transportation differential. To compound the problem, much of the older infrastructure is antiquated, so increased production volumes and/or increased line pressure result in more frequent accidents. When parts of the pipeline network go down for maintenance or due to accident, the resulting higher transportation cost puts downward pressure on wellhead prices.

Expectations are that over the next three to five years new pipelines will be built and rail capacity increased, mitigating the differential risk. But delays in expansion of capacity are possible. There is increased resistance to pipeline development in some parts of the country, and recent rail accidents have slowed the transport of crude by rail. Half the production from a shale well is typically recovered in the first eighteen months, so delays in increasing the take-away capacity could materially impact new well performance over the next several years.

 Williston Basin Oil Production & Export Capacity (June 2014) Source: North Dakota Pipeline Authority

Williston Basin Oil Production & Export Capacity (June 2014)
Source: North Dakota Pipeline Authority


Ironically, quality differentials have moved inversely to the quality of the new crude being produced. Much of the crude produced from shale formations is low gravity (high quality and energy content). However, the majority of U.S refineries were designed to refine lower grade crude such as that produced in Mexico and Venezuela, the primary sources of new U.S. supply in the late 20th century. This is contributing to increased negative differentials for higher quality crude oil.

Increased Operating Costs

The increase in oil and gas development has also put upward pressure on oilfield services, wages, supplies and taxes. There is a correlation between increasing oil and gas prices and operating costs, as increasing demand puts price pressure on oilfield services. Over the last five years, operating costs on legacy producing properties owned by the Five States consolidated partnerships have increased seven to ten percent per year. Cost escalation usually abates as new service supply comes on-line in response to the increased demand. However, the current boom has been so strong and lasted so long that we are just now starting to see some slowing in cost escalation.

Increased Capital Cost

The development cost of the new oil plays is much greater on a per barrel basis than oil developed in the late 20th century. This results in much higher operating leverage for companies in the development business.

WTI Breakeven Price for 15% After-Tax Return Source: Credit Suisse research report released April 2012

WTI Breakeven Price for 15% After-Tax Return
Source: Credit Suisse research report released April 2012

Operating Leverage

Increases in each of the three aforementioned factors (Price Differentials, Operating Costs and Capital Cost) result in increased Operating Leverage. Operating Leverage is the ratio of a company’s fixed costs to its variable costs. The higher the Operating Leverage ratio, the greater the relative impact of a cost increase or revenue decrease on the net profit percentage. Example 1 below compares the hypothetical profit and loss of a shale well today to a conventional West Texas well (like Five States purchased in the ’90s), calculated on a per barrel basis.

Example 1

Shale Property Conventional Pre-2005
NYMEX Reference Price  $ 100.00  $   20.00
Wellhead Price Differential (10.00) (0.25)
Net Wellhead Price Received  $   90.00  $   19.75
Operating Cost (20.00) (4.00)
Operating Profit  $   70.00  $   15.75
Capital Cost (50.00) (8.00)
Net Profit per Barrel  $   20.00  $     7.75
Quantity * (Price – Variable Cost)  $   90.00  $   19.75
Quantity * (Price – Variable Cost) – Fixed Cost $   20.00 $     7.75
Operating Leverage Ratio           4.5           2.5
* Quantity is one barrel in both cases


The Operating Profit per barrel has increased by almost 4½ times, but this has come at an increased capital cost of over six times the former level. When higher capital costs are combined with higher wellhead differentials and operating costs, there is a material increase in Operating Leverage risk.

The potential consequences of high Operating Leverage are significant. Even a small decrease in the wellhead price received or increase in expenses can have a material negative impact on profit. For example, doubling the wellhead differential on the shale property in the example, a $10/barrel increase, would reduce the net profit per barrel from $20/barrel to $10/barrel, reducing it by half. In the case of a conventional well operating in the ‘90s in a low Operating Leverage environment, a doubling of wellhead differential would have been immaterial. Any combination of cost increases or revenue decreases totaling $10/barrel would have the same impact on the shale property.

When Operating Leverage is high, even slight changes in the wellhead differential or costs can have a material impact on the net profit of a property. As seen in Example 2, a relatively minor 10% change in these factors results in a 40% drop in the net profit.

Example 2

Shale Property
Base Case Increased Differential/Costs
NYMEX Reference Price  $  100.00  $      100.00
Wellhead Price Differential (10.00) (11.00)
Net Wellhead Price Received  $    90.00  $       89.00
Operating Cost (20.00) (22.00)
Operating Profit  $   70.00  $      67.00
Capital Cost (50.00) (55.00)
Net Profit $   20.00 $      12.00

Increased Financial Leverage

Many companies have been using large percentages of debt to finance their growth, which further magnifies the impact on their operations of changes in costs and price differentials. A prudent loan on rapid decline shale production should have a short amortization. If it is assumed that the principal is repaid over three years and has a 3% interest rate, then the cash flow from production may not be sufficient to repay the debt. If the well cost were fully funded with debt, the well would be about a break-even investment after debt service even at $100/barrel NYMEX. The same figures shown in Example 2 above, coupled with increased financial leverage, actually result in a negative cash flow scenario, as shown in Example 3.

Example 3

Shale Property
Base Case Increased Differential/Costs
NYMEX Reference Price  $  100.00  $      100.00
Wellhead Price Differential (10.00) (11.00)
Wellhead Price Received  $    90.00  $        89.00
Operating Cost (20.00) (22.00)
Operating Profit  $   70.00  $       67.00
Capital Cost (50.00) (55.00)
Net Profit before Debt Service  $   20.00  $       12.00
Debt Service (18.17) (18.17)
Cash Flow after Debt Service $     1.83 $      (6.17)

The Impact on Five States Energy Capital Funds

Hopefully, a shakeout will result in rationalization of asset valuations in the oil and gas sector. Over the past few years we have seen others value assets at levels we thought were unrealistically optimistic. Corrections are always a good thing for value investors like us when we are trying to deploy capital.

The Impact on Five States Legacy Funds

I do not expect a shakeout to have much impact on the Five States production partnerships, other than the net impact it might have on wellhead oil prices and operating costs. As supply in various regions exceeds offtake capacity, the wellhead price relative to the reference price decreases as total U.S. volume exceeds domestic pipeline capacity. A slow-down in the pace of shale development, or increases in the midstream capacity to handle the oil produced, could mitigate some of the pressure on wellhead differential volatility. Operations and maintenance expenses have increased significantly in the last five years as demand increased. Less demand should result in more stable or possibly even lower expenses.

We have listed the North Dakota Bakken properties owned by Consolidated I & II for sale. These are our highest operating leverage/lowest profit per barrel properties in the legacy portfolios, making them the most susceptible to price and cost risk. The Bakken is one of the hottest plays in the country, and we have profited from participating in the development. But if we can capture “full present value” in a sale, I would like to take this opportunity to “prune the profit tree”.

Concluding Thoughts

A primary driver in our shift in investment tactics in 2007 was the belief that both systematic risk and leverage were increasing. Low interest rates led to inflated value of just about everything: real estate, stocks, bonds, and oil and gas properties. Oil price volatility has also decreased, contrary to my expectations. But leverage risk has materially increased. The shale development plays are profitable, but they have a different risk profile than conventional plays. Well-financed companies can be successful. Overleveraged smaller participants are taking a high degree of risk.

Oil production in the U.S. may continue to grow at a faster rate than demand in the near-term, which is very good for the U.S., as it is materially decreasing our balance of trade deficit (a major economic stimulus that I rarely see discussed). But it does not solve the long term issue. Oil is an international commodity, and the only seriously viable transportation fuel for the foreseeable future. Continued growth in the emerging economies will continue to put upward pressure on world oil prices.

We remain bullish on oil prices in the intermediate to long term. But we need to remain defensive against near-term risks to protect our current returns. We will continue to hedge to manage near-term oil price risk and focus on accumulating the highest quality assets. Today, this is leading us away from the shale plays and toward more focus on conventional assets. As always, we will continue to follow our disciplined value investing methodology to continue to replace depletion and accumulate new quality assets.

When Things Change, Things Change

Only a decade ago, many economic seers were predicting that oil prices would be in the $150 to $200 per barrel range in this current decade.  But there is an old adage in commodity industries: “the cure for higher prices is higher prices”.  It is analogous to a most basic economic concept, “change begets change”.  Changes in prices lead to change in behavior by both consumers and producers.  These changes manifest on both the supply and demand side of the equation.

Twenty-five years ago, in classic Malthusian[1] thinking, many economists believed “energy was different” because the supply is finite.  The following chart illustrated a “truth” that was widely believed: that energy prices would continue to increase in the future at an accelerating rate because we had “used up” the existing supply.  In that environment, future oil prices were higher than the spot price[2].

Wellhead Crude Oil Prices

History has shown us repeatedly that extrapolation of extreme trends following changes do not accurately predict future results.  In this case, higher oil and natural gas prices have led to the development of new technology that was considered unrealistic a decade ago.  Consumption behavior, both at the consumer and industrial level, has changed demand.

Today, industry consensus is that oil will trade in the $70 to $100 per barrel range for the long term, and that natural gas will stay below $8/mmbtu for decades.  As discussed in my third quarter 2012 article “Sunset to Sunrise”, the energy outlook for the United States has changed materially.  Once again, Malthusian expectations have been debunked by free market economic forces and human ingenuity.  The development of new technologies such as 3-D seismic and horizontal drilling led to the ability to tap huge unconventional[3] formations that were previously uneconomic.  These new technologies, combined with improvements in hydraulic fracking (a core extraction technology in the oil and gas business since the 1940s), have led to a bonanza in oil and gas development.

For the foreseeable future, rising oil prices may no longer be the norm.  Tremendous success in the development of unconventional oil and natural gas reserves in the United States is reversing this trend.  Prices for crude oil to be delivered in the future are now much lower than the spot price.  Spot prices have been fluctuating between $85 and $100 per barrel for the past several years, while the contract for crude oil delivered in five years is now fluctuating between $75 and $80 per barrel.  This may reflect expectations of lower prices in the future–or it may be that buyers are not as afraid as they were a few years ago, and are less interested in locking in future prices.

Commodity Prices - Crude Oil (WTI)

This change in U.S. energy is very stimulative.  The average U.S. family spends over $4,000 per year on gasoline (over 11% of their disposable income).  Total U.S. household expenditure for gasoline last year was about $461 billion.  A few years ago this expenditure was expected to increase by 150% to 200% in this decade.  Now it looks like it may decrease by as much as $100 billion per year.  The net change in expectation is equal to over half of the total amount spent on the American Recovery and Reinvestment Act of 2009, but every year!  And we no longer have such a strong national interest in “protecting” unstable foreign governments to protect our energy supplies.

We have seen comparable reductions in natural gas prices and expectations.  Lower energy prices for natural gas and electricity, combined with more secure supplies, are increasing corporate profits and are a leading reason for the renaissance in U.S. manufacturing.  They are also resulting in stable to declining utility costs for consumers.  As an added bonus, the shift from coal to natural gas has resulted in the greatest reduction in emissions of any country in the world.  Although not a signatory to the Kyoto protocol, the U.S. is the only country in the world expected to achieve the emission reductions that would have been required by that treaty.

Change in Drilling Risk

The biggest risk in oil and gas investing has changed.  The primary risk in the 20th century was unsystematic, or project risk.  The risk of a project resulting in a dry hole was the primary focus.  New technology has greatly reduced the risk of drilling a dry hole.

Today the vast majority of drilling for both oil and natural gas is in unconventional fields.  There is also a significant amount of increased density drilling[4] in existing conventional fields.  In both cases the reserves being developed were previously known to exist.  The higher price of oil and natural gas makes it economically viable to develop reserves that would not have been cost effective ten years ago (even if the new technology had been available).  For example, our legacy partnerships have participated in 38 Bakken wells in North Dakota in the past seven years on leases that we owned, all of which have been economically productive properties.

The chief risk in new development is systematic, or market price risk.  If oil prices do not continue to trade in the expected range of $75 to $100 per barrel, the newly developed oil fields will not generate the expected returns.  If prices fall below $70, some investments will lose money.

Systematic risk has already resulted in material disruption in the natural gas industry.  The unconventional development of the last decade was so successful and generated so much new supply that prices collapsed.  This occurred despite the increase in consumption from electrical generation.

Change in Decline Rates – Unconventional Wells

Unconventional wells deplete more rapidly than conventional wells, resulting in a faster rate of decline of production.  Therefore new wells must be drilled at a faster pace to maintain production rates.  The cost of these new wells is high.  Depending on the formation, a working interest owner must receive somewhere between $40  to $60 per barrel to recover their investment. If the price falls below this level, drilling will slow and the supply will decline.  This is 50% to 100% higher than the price needed to break even on conventional wells, where breakeven averages between $30 to $40 per barrel.  The ratio between unconventional and conventional natural gas is similar.

West Texas Intermediate Crude Oil Breakeven Price for 15% After-Tax Return by Play

Source: Copano Energy Presentation (data per Credit Suisse Small/Mid Cap E&Ps research report released April 10, 2012)

Change in Leverage

This shift in the basic economics has resulted in a greater degree of operating leverage[5].  The risk of this increased leverage is the most disconcerting factor in underwriting many of the investments we see.  In addition to operating leverage, financial leverage (debt) is continuing to grow as a percentage of capital deployed in the industry.  When you combine the operating and financial leverage, the volatility in cash flow as wellhead prices change is greatly amplified.  The potential volatility of profit (or loss) is much greater than a decade ago.

Change in Natural Gas

Natural Gas Futures (NYMEX)

Natural gas remains out of favor. Future price expectations have changed materially, resulting in more attractive valuation for a buyer of producing natural gas properties.  The current spot price and the expectation of future prices are now about half of what they were six years ago.

Most independent producers are interested in projects that can add value through drilling additional gas wells, but drilling new gas wells in most shale developments is not attractive at current natural gas prices.  We continue to seek opportunities in this sector where we can make acquisitions based on the existing production income, with the potential for future development when prices warrant.

Change in Midstream Opportunities

One of the most exciting new opportunities is that we once again find midstream[6] investments attractive.  At the time of the 1980s energy collapse, there was sufficient infrastructure to handle the decreasing volumes of domestic production in the U.S.  Public MLPs[7] were aggregating income producing midstream assets, creating investment vehicles much like portfolios of utilities stocks.  This drove up the valuations of midstream assets beyond levels that were attractive to private equity.  Oil and gas production volumes have now recovered to levels where the existing infrastructure is “full”.  This is driving demand for new midstream infrastructure and creating attractive development opportunities.

Five States is pursuing investments in midstream development.  Projects in the “first 100 miles from the wellhead” are well-suited to independents.  The primary risk in these projects is the economic volumes of the oil and gas fields that they service.  The development cycle time of these projects is long (around two years) and these projects tend to be “one of a kind”.  It is a very “clubby” part of the business, where teams of investors like Five States partner with developers.  The developers tend to want sophisticated industry partners rather than Wall Street money.  Projects can be operated for an attractive yield once completed, with the MLP market providing a viable conduit for future sales at attractive valuations.


The current price of crude oil is $100 per barrel, compared to the replacement cost of $40 to $60.  Typically, one does not get to earn a gross profit of this magnitude in a commodity.  However, demand is still growing at a strong pace and may overwhelm the recent increases in production.  Some experts are predicting a slow-down in the rate of production growth.  As is always the case in finance, uncertainty is risk.  Because of our sensitivity to oil price risk, we will continue to invest in oil projects in a mezzanine structure, where our preferred position will mitigate some of this price risk.  We will also continue to aggressively hedge our oil prices in new transactions.

Natural gas continues to look attractive from a macro perspective for value investing.  However, the transactions we expected following the natural gas crash in 2008 – 2010 have not materialized.  We are currently evaluating an investment in a large natural gas acquisition with a Midland independent with whom we have a long-term relationship.  We expect to see more opportunities in natural gas over the next few years.

By far the most lucrative area has been midstream.  The need for new infrastructure is an excellent fit for Five States.  The continued expansion of domestic oil and natural gas development should continue to provide opportunities throughout the next decade.

In recognition of the shift in risk, we are taking more unsystematic risk than we did in our first twenty years.  We are moving away from areas with higher systematic risk and where plays are overpriced or overleveraged on a value basis.  The last few years, midstream has been the most attractive area.  However, we will continue to base our investment decisions on fundamental analysis and true value investing, rather than following the most popular trends.

We at Five States remain bullish on the domestic oil and natural gas industry.  It will take a generation or longer to transition from traditional fossil fuels.  Until viable options are developed, the most efficient direction for the United States from both an economic and ecological perspective is to prudently develop our bountiful resources and use those resources more efficiently.  We can continue to lead the world in emission reduction while achieving the economic growth needed to finance future energy research and development.

The world may not be in a period of rising prices.  But the oil and gas industry is in a period of tremendous growth, and the need for capital to sustain this growth is at an all-time high. Recognizing the impact of the changes of the last decade will contribute to our ability to more accurately assess risk and allow us to continue to find attractive value investment opportunities in domestic oil and gas for the foreseeable future.


[1] Robert Malthus (18th/19th century) espoused the idea that human population increases geometrically while supply increases only arithmetically, which eventually leads to calamity.   In the case of energy, demand is expected to increase exponentially while supply is finite, resulting in increasingly higher prices.

[2] The “spot” price is the price being paid for a commodity sold and delivered at the current time, as compared to a price for delivery at a time in the future.

[3] Unconventional reservoirs are shale formations.  These low permeability reservoirs have been known to contain hydrocarbons since the beginning of the industry.  The pores that contained the hydrocarbons are not well connected, so in earlier times it was not economically viable to produce these reservoirs.  The oil and natural gas produced from unconventional reservoirs is the same as that produced from conventional reservoirs.

[4] Increased density drilling is drilling between existing wells in a producing field to recover oil in-between the existing wells that will not be produced from those wells.

[5] An investment has high operating leverage when it has a high fixed-cost component.  In the case of oil and gas development, when the capital cost per unit of recoverable hydrocarbon is high, small changes in prices have a big change in project profitability.

[6] Midstream is the infrastructure between the wellhead and the refinery; pipelines, gathering systems, storage facilities, compression and processing facilities, rail facilities and rail tank cars, ships, barges, tanker ships, etc.   It is the “middle of the stream” between the wellhead and the refinery.

Fracking Good

America’s shale is changing the dynamics of world energy. The reemergence of the United States as a global energy superpower is addressing many of the major problems in the United States and is having profound strategic and geo-political effects throughout the world. In November 2012, the U.S. replaced Saudi Arabia as the world’s largest producer of crude oil. The U.S. had already overtaken Russia as the leading producer of natural gas, and the International Energy Agency predicts that the U.S. could become the world’s largest natural gas producer by 2017.

In his 2012 State of the Union address, President Obama claimed credit for presiding over the largest reduction in oil imports in modern history and for achieving the lowest level of dependence on oil imports in years. He attributed that remarkable performance partly to increased oil production from tight sands in the Dakotas, but primarily to the massive increase in gas production that has resulted from fracking.

The Energy Information Administration (“EIA”) predicts that the U.S. will have enough gas to satisfy domestic demand for a century and that the U.S. will soon have a surplus sufficient to begin exporting gas to Asia. As a result of fracking, natural gas costs less than one-third of the energy-equivalent price of oil in the U.S. The developing use of natural gas in fleet passenger automobiles and in medium to heavy long-haul trucks has the potential to reduce gasoline sales, fuel costs and prices of manufactured goods delivered to stores.

Natural gas currently generates 30% percent of the electricity in the U.S. (coal 37%, nuclear 19%, all others 14%). Low relative prices of source fuels in the U.S. are improving U.S. economic conditions and are increasing manufacturing activity by significantly reducing the cost of energy.

The fortuitous increase of U.S. oil and natural gas production is resulting from the synergistic application of two petroleum technologies, one old and one new.  Hydraulic fracturing, developed in the 1940s, has been safely employed in more than a million U.S. wells. More recently, the industry has commercialized the ability to drill wells horizontally. Such wells are drilled vertically to a depth of one to two miles then turned to drill horizontally within the oil or natural gas bearing strata. Steel pipe is cemented through the entire length of the wellbore and holes are opened in the pipe. Hydraulic fracturing of the rocks in the horizontal portion of the well releases the oil and natural gas and allows them to be recovered at the surface. Without the combined use of both technologies, little of the new oil or gas production in the U.S. would be possible.

Since 2004, various senior federal regulatory officials from both the Bush and Obama administrations (including the EPA and Department of Energy), state regulatory agencies, and university researchers have repeatedly noted the lack of evidence connecting groundwater contamination with hydraulic fracturing. Peer reviewed research studies in 2012 and 2013 found groundwater contamination from vertical migration of fracturing fluids “not physically plausible” and “unsupported by any empirical data.” In August of 2013, newly appointed US Secretary of Energy, Ernest Moniz, said “To my knowledge, I still have not seen any evidence of fracking per se contaminating groundwater” (emphasis added).

Fracking is improving the U.S. environment by replacing some coal with natural gas. Even though the economy has expanded by more than half, U.S. greenhouse gas emissions are lower today than they were 20 years ago. This is because of the greater use of natural gas for power generation and industrial boilers.  Although the U.S. was not a signer of the Kyoto Protocol, the U.S. emissions are already below the limits that would have been imposed by the protocol as a result of the switch to natural gas released by fracking. The U.S. is the only industrialized country in the world to meet this level of Kyoto Protocol compliance.

Fracking will improve the global economy. Natural gas is far more expensive in Europe and Asia than it is in North America. Fracking in other countries has great potential to reduce the price of gas in those areas. The EIA has identified 48 shale gas formations in 32 countries that have the potential to yield new gas supplies comparable to those that have nearly doubled U.S. gas reserves in the last decade. Horizontal drilling and hydraulic fracturing in basins outside the U.S. can, at minimum, triple global gas supplies.

Fracking will improve the global environment. As fracking increases the global supply of natural gas and reduces the price of natural gas in Europe and Asia, the same kinds of dramatic beneficial effects on the global environment will occur that are already beginning to impact the U.S. environment. The International Energy Agency (“IEA”) predicts that by 2030 gas will displace coal as the dominant source of energy in the world. China is poised to become a particularly large beneficiary of the gas boom. IEA has identified several promising basins in China. IEA also predicts that by 2030 China will consume more gas than the entire E.U. Since China is the world’s largest source of greenhouse gas emissions and by far the largest source of emission increases, any replacement of coal with inexpensive natural gas has the potential to greatly reduce China’s problems with air quality.

Fracking should also improve geopolitical conditions. The process is reducing–and may ultimately eliminate–U.S. dependence on oil and gas from insecure foreign sources such as the Middle East. Fracking can reduce Russia’s leverage over Europe via new gas supplies, Iran’s leverage over India via India’s reliance on energy supplies from Iran, and the risk that Russian President Vladimir Putin will be successful in his efforts to create a natural gas version of the OPEC cartel.

In the U.S., continued development of our vast natural oil and gas resources will be accomplished only if regulators and producers are able to work together to satisfy citizens and regulatory agencies that horizontal drilling and hydraulic fracturing of shale formations can be accomplished with tolerably low environmental costs. As active participants in the oil and natural gas industry, we see this as a tremendous opportunity to create jobs, wealth and energy security for our country. Continued development will reverse the decline in U.S. industrial competitiveness, the standard of living and the undesirable geopolitical position that reliance on imported energy is creating for us.

A Correction in Oil Prices?

The media has recently hopped on the possibility of a decline in oil prices due to the success of the new development in the United States. This has prompted three questions from Five States investors:

  1. Do we agree that there will be a correction in oil prices?
  2. How would a correction affect the Five States funds?
  3. What would the impact of a correction be on Five States Energy Capital Fund 2?

Oil Prices

The oil market is already reflecting the expectation of lower prices in the future. Although the spot price of oil has remained fairly constant over the last year, the NYMEX prices for delivery in the future have declined to below $80 per barrel over the last five years (note that the forward curve has not been a statistically good predictor of realized prices in the future).

Crude Oil NYMEX Prices

Spot and Future Oil Prices

The price of commodities (including oil) is quoted for delivery to a specific location at a point in time. The price for a barrel bought/sold/delivered today is called the “spot price.” Prices are also quoted and contracts traded for delivery in the future (referred to as “futures prices” and “futures contracts”).

Each day the market “clears” all volume offered for sale at the spot price. That is, every physical barrel offered for sale is sold and delivered. Ninety million barrels of oil are bought and sold worldwide daily. If supply increases relative to demand, prices fall. If demand increases relative to supply, prices rise. This equilibrium in the market is a function of daily deliverable supply and daily demand. Future expectations have nothing to do with this pricing at the moment the physical transaction occurs. This leads me to believe that speculators may affect the futures market, but they cannot affect the price of those 90 million barrels when they actually change hands each day. At this point, all transactions “cash settle” and the game is over.

The physical market prices can be manipulated to some degree by OPEC. To the extent OPEC producers are willing to withhold excess capacity from the market, they can reduce physical supply. OPEC (i.e., Saudi Arabia) can also increase production to decrease prices, as they did in the mid-1980s. Speculators buying oil to place in storage or selling oil out of storage can have a similar effect. However, the purchases or sales would have to be large and sustained to make a material difference in the trend of spot prices. Buying and storing crude oil for future delivery is an expensive way to speculate on oil prices. Although the ability of OPEC to manipulate world oil prices is given a lot of credence by some analysts, we believe this ability, especially over any significant time period, has been reduced by the shift in supply fundamentals.

There is almost always some surplus in deliverable capacity. While all of the oil delivered to the market on any day is sold, all of the oil that could be brought to market worldwide is not being produced. Small percentage changes in deliverable capacity can result in large fluctuations in price. During the 1990s, oil averaged about $20/barrel with lows below $10 and highs of over $30. Studies of that period concluded that a difference in daily deliverable capacity of ~2% to ~4% resulted in this volatility. It is possible that the increasing deliverable supply today could have similar results.

Shale Development

The US shale development boom is real. Results are exceeding many early industry expectations. Production is increasing at an accelerating rate throughout the US. The increases in production in Texas and North Dakota are staggering. There are many more large new shale plays on which development has barely begun.

US Crude Oil Production: Texas and North Dakota
Texas crude production is up 158% in the last five years;
North Dakota is now the second largest producing state

A Correction in Oil_North Dakotata Field Production of Crude Oil.fw

Source: US Energy Information Administration (EIA).
Production data through September 2013.

Historical and Projections

The technology used to develop shale reservoirs is also being applied very successfully to the redevelopment of conventional assets. Horizontal and vertical drilling, multi-stage hydraulic fracking and increased density drilling in low permeability conventional reservoirs are having excellent results.

Ban on US Export of Crude

Further distorting the market in US crude oil prices is the US ban on crude oil exports. Prior to the current development boom, West Texas Intermediate (“WTI”, the primary US reference oil) traded at a premium to Brent (the European reference oil). WTI is a superior quality crude. This trend has reversed because of increased supply in the US. The domestic supply has overwhelmed the existing midstream facilities (pipelines, storage facilities, etc.) and refining infrastructure, resulting in a domestic “glut” compared to world demand.

As US supply continues to increase, volatility of domestic crude oil prices will likely increase. This creates the potential for a domestic price correction, even if international prices remain at current levels. The ban on export of domestic crude could cause the pricing of US crude to behave like a domestic commodity on the downside. We could have a situation where wellhead prices fall when world prices fall because of international competition, but prices might not increase at the wellhead when world prices rise due to regional infrastructure constraints that would keep the US production from being sold outside of the regional market.

Energy Demand by Region
By 2040 Non-OECD demand will be
more than double 
that of OECD demand

Energy Demand by Region

Source: Exxon Mobil 2012 Energy Outlook.
OECD – Organization for Economic Co-operation and
Development (34 countries).

We do not know if there will be a correction in oil prices, but the possibility of a near-term correction is high enough that we are defensive. Calling the timing of a crude oil price correction is impossible, and a price correction may not happen. It is possible that growth in world demand will stay in equilibrium with growth in world supply, and prices will remain stable, or that world demand will increase relative to growth in world supply and prices will once again increase. Most of the new oil investments we are considering are mezzanine structured, which adds additional safety against a near-term price decline. If there is a correction in the price of crude oil, we expect that it will be short-lived, maybe six months to two years.

Valuations & Distributions from Existing Funds

In the short-run, the impact of an oil price correction on distributions would be small, primarily due to our high level of hedges. We have the majority of our production hedged for the next two years, locking in current prices on the majority of our production.

Swap Positions

Since 2007 distributions have remained fairly constant. This is because the decline in oil and natural gas prices has been in the futures market, but not in the spot market. The impact of price volatility on distributions has also been reduced by our hedges.

The most material impact will continue to be on the calculation of net present value. As reported over the last several years, the calculated net present value of our producing properties has decreased as futures prices have decreased. Further decline in futures prices would cause this trend to continue, even if wellhead prices and distributions remain constant.

Impact of a Decline in Prices on FSEC Fund 2 (the new fund)

A correction in oil prices at this time could actually be very beneficial to FSEC Fund 2. Lower prices have three positive features in our analysis of new investments:

  • Forecast future income is lower, resulting in lower valuations of potential new investments. This can result in better values (“buy low . . . “).
  • Competition for oilfield services decreases, decreasing future expenses, further improving future results.
  • Expectations of those with whom the Fund will do business decrease, resulting in less euphoria and less competition for individual assets.

Discount Rates

For the last few years, demand for oil and gas investments has been very strong. It has almost appeared that investors could do nothing but win in this sector, despite the erosion in oil futures prices.

Largely masking much of the decline in futures prices has been the decline in discount rates used in calculating the net present value of oil and gas properties. This decline in discount rates has loosely followed the decline in interest rates.
Producing properties are depleting assets. In a flat price model, they calculate as a declining annuity.

The increasing prices over the last decade have somewhat masked depletion, causing forecasted cash flow from producing properties to calculate as a perpetuity. Combined with the expectation of continued development of new reserves, many properties have calculated as appreciating assets rather than depleting assets.

Valuing Producting Properties


Declining prices can cause a reversal in forecasts of new development. Declining prices will slow the pace of development in some shale plays. If interest rates rise, discount rates used to value producing properties could also rise, resulting in further declines in the calculated present value of producing properties. This would materially amplify the decline in calculated net present value during a correction in oil prices.

We have seen the exuberance in the market play out in oil and gas public equities. E&P companies that have focused on acquiring acreage in “hot” plays in order to grow reserves are experiencing strong valuations in the marketplace. These strong valuations in the public market have resulted in a dramatic increase in new public offerings. In 2013 $65 billion was raised in 494 equity offerings compared to 8 offerings in 2012, totaling $1.4 billion. We believe this level of activity is indirectly contributing to higher valuations of proved properties. If oil prices decline, this trend could reverse and the prices of properties could come more in line with our valuation.

Energy Sector: Public Equity Offerings by Year
(Includes Initial Public Offerings and Secondaries)

Energy Sector: Public Equity Offerings by Year (Includes Initial Public Offerings and Secondaries)

Data Source: Bloomberg


Operating leverage in domestic oil production has increased materially. The break-even for full cost recovery in most shale plays now averages over $50 per barrel and over $5.00 per mmbtu for natural gas. Break-even is higher in the most mature plays such as the Barnett Shale in North Texas (gas @ $5+) and the Bakken Shale in North Dakota (oil @ $60+). These are wellhead prices, not NYMEX. Wellhead prices are typically 5-10% below NYMEX.

Shale production also has a much steeper decline rate than conventional production. This increases risk in present value calculations much like operating leverage.

West Texas Intermediate Crude Oil Breakeven Price
for 15% After-Tax Return by Play

West Texas Intermediate Crude Oil Breakeven Price  for 15% After-Tax Return by Play

Source: Copano Energy Presentation (data per Credit Suisse
Small/Mid Cap E&Ps research report released April 10, 2012)

Volatility of actual wellhead prices from reference prices such as NYMEX tends to increase as the various plays mature because the increasing physical supply swamps existing infrastructure. As the pipelines and storage facilities “fill up”, the price buyers are willing to pay goes down. For example, Bakken crude is extremely high quality, but Bakken crude is currently trading about $12/bbl below NYMEX at the wellhead. This differential has been as high as $25/bbl in the last few years. In the near-term, this trend of higher and more volatile differentials will likely manifest in newer plays as supply overwhelms existing regional infrastructure and markets. A good example of this is the Great Northern Midstream opportunity. The opportunity was created by the huge increase in Bakken production in North Dakota. New development like Great Northern Midstream will reduce these problems in the intermediate term. We expect to see other opportunities like Great Northern Midstream as the various plays develop around the country.

I suspect financial leverage (debt) is also increasing. Succumbing to the push for growth in loans, commercial banks have lowered risking of the valuation of Proved Undeveloped (“PUD”) reserves. It appears that oil and gas bank credit is as loose as it has been since 1982, and this is likely resulting in increased financial leverage on top of the increased operating leverage.

Risk Perception

The impact of the reversal of investor sentiment in oil and gas is huge. The risk attributed in valuing new development has decreased, resulting in higher valuations. In many of the oil acquisitions we underwrite, the winning bidder is valuing oil PUDs as if they are producing. Their illogic is that since there is little dry hole risk, there is no PUD risk. But costs have increased materially, and Estimated Ultimate Recovery (“EUR”) is not well documented in many plays. The increased leverage in the sector will magnify negative errors in the PUD value calculations in the event of a crude oil correction.

The combination of factors discussed above has reduced the calculated net present value of Proved Producing reserves. The reduction is due to three factors:

  1. Lower forecast cash flow from the Proved Developed Producing portion
  2. Shortening of the economic life of the Proved Developed Producing portion (the lower prices result in the properties reaching economic limit sooner)
  3. Delaying and reducing (and in some cases eliminating) the present value of Proved Non-producing (PDNP & PUD; Proved Developed Non-producing and Proved Undeveloped)

With the high degree of inherent leverage and misunderstanding by many market participants of true downside risk, the potential for a material correction in the value of domestic producing properties is high. Corrections in the oil and gas market are rarely forecast. If one occurs now, it should provide some excellent investment opportunities. Most of the new oil investments we are considering are mezzanine structured, which adds additional safety against a near-term price decline.


In summary:

  1. 1. Do we agree that there will be a correction in oil prices?
    Yes, we believe the potential for a correction in crude oil prices exists, especially domestically. We are managing the funds defensively in case a correction occurs.
    Our “expected case” is for oil prices to average at or near current levels, increasing over the long-term. We expect a correction would be short-lived (six months to two years).
  2. How would a correction affect the Five States funds?
    We believe that the distributions would remain fairly constant for a couple of years. A correction longer than two years would have a material impact on distributions.
    Calculated valuations would be affected in the short-term.
  3. What would the impact of a correction be on FSEC Fund 2?
    We believe the impact would be favorable, because we should be able to invest the Fund capital more advantageously.

Over the last decade, domestic producing properties have been in the strongest bull market I have seen in my career. Consensus expectations have not been this uniform since the early 1990s. The current bull market is driven by high oil prices, low discount rates and positive investor sentiment. This is an 180? reversal since our entry into the acquisition of producing properties in 1985. The one certainty in finance is that when fundamentals change, things change. The reversal of any of these three core fundamentals in any industry would be sufficient to reverse valuation in any industry.

Sometimes I feel that investing in the oil and gas sector is like riding a roller coaster blindfolded. There will be lots of unexpected ups and downs, but as long as we do not get thrown out of the cart we will have a great ride! I will close with an example of how wrong consensus expectations can be. The following was widely circulated in the late 1990s:

“Oil prices have fallen below $12 a barrel for basic grades, a level at which it is hard for even efficient companies to produce, refine and distribute oil profitably as gasoline, heating oil and jet fuel.

“And prices are likely to remain low. The once powerful Organization of Petroleum Exporting Countries, the 11-nation OPEC cartel that ruled the oil world in the 1970s, lacks the will or ability to control oil supplies these days. On Thursday, OPEC ministers at their winter meeting in Vienna, Austria, failed to agree on even a slight production cutback to ease the current oil glut. That signals continued low prices through this winter.”

LA Times, “If Exxon, Mobil Merge, Would Biggest Be Best?” November 27, 1998,

Sunshine and Clouds

January is the time of year when we look back at our previous year of work and accomplishments, and get operations underway for the new year. For Five States, 2013 was productive. We stayed busy throughout, evaluating 115 individual submittals, representing $140.2 million. Of these, only five made it across the finish line by December 31, for a total of $36.7 million of new commitments. However, 14 of the year’s submittals are still “in progress”, awaiting additional data or negotiated terms, so perhaps one or two more could still be accepted. Although the “yield” may seem low, it is typical of previous years’ results. Our challenge for the current year is to continue to increase the number of proposals we receive for review, and to stay alert for projects that can substantially enhance partnership size, quality and financial returns.

By the beginning of spring we had allocated the last of Fund 1’s capital to projects and opened Fund 2 for subscriptions. Fund 2 was closed in late December with commitments of $112 million. During December we agreed to participate in construction of a liquids extraction plant in Kansas (“Haven”) together with the same partner who introduced us to the successful oil gathering and rail transportation project in North Dakota. Our initial allocation of Fund 2 capital is $15 million toward building the Haven plant.

Each year Exxon publishes its global long term energy forecast, updating previous forecasts with new data. For individuals and companies with long investment horizons, Exxon’s view of the future for the oil and gas industry is bright. Exxon expects world energy demand to grow 35% by 2040 as electricity and other energy requirements reach people in the developing world.

According to the forecast, fossil fuels will still supply most of the world’s demand in 2040, with oil and natural gas supplying 60% of total demand. Liquid fuels—gasoline, diesel, jet fuel, and fuel oils—will remain the primary transportation fuels because of their unique combination of affordability, availability, portability, and high energy density. Exxon also predicts that by 2040 the world will consume 40% more energy from natural gas than coal. Coal, currently the second most consumed fuel after oil, is expected to level off and fall to third place by 2025 as countries displace it with less carbon-intensive natural gas.

Optimistically, Exxon estimates that 65% of the world’s recoverable crude oil will still be in the ground in 2040. But because oil will be harder to develop and produce, it will be more expensive, even with continued technological advances in techniques of seismic exploration, horizontal drilling and multistage hydraulic fracturing.

For Five States, Exxon’s projections indicate that opportunities should exist for us to make viable investments into the foreseeable future. We plan to continue development of our business along three primary strategic paths: (1) providing collateralized loans to others for development drilling and lease enhancements, (2) acquiring, enhancing and managing producing properties, and (3) using our equity dollars for construction of midstream assets.

In the shorter term, several issues are clouding the future. Prejudice against the industry is pervasive and deep, and manifests itself through a myriad of adverse policies and activities, from the top down, through many governmental agencies. The results to the industry are delayed or denied operating permits, more intensive regulation, higher taxes, and lack of cooperative governmental support. These conspire to create bottlenecks in activities and uncertain energy policies for all.

A related concern, perhaps engendered by the one above, is the recent trend toward politicization of education about the energy industry, in which science takes a back seat to the politics de jour. A spate of recent industry-related issues are being decided not on the basis of validated facts and decades of experience, but by the pleadings of movie actors, country singers, local politicians or other such authorities.

Hydraulic fracturing may be a hot topic of debate, but few know what the term “fracking” actually means, according to a recent survey gathered by researchers at Oregon State, George Mason and Yale universities. Yet, despite the fact that since 1947 more than a million oil and natural gas wells in the United States have been hydraulically fractured with no reliably validated adverse consequences, industry opponents show up in large numbers to protest the practice wherever hearings are conducted. Largely based on public attitudes, several states have declared absolute moratoriums on fracking, thereby effectively shutting down all petroleum development in those states, and with it all industry-related employment and potential tax revenues.

Perhaps it is no wonder that critical tests of logic are absent from discussions of many substantive issues. Basic math and science courses have generally been given little emphasis in U.S education curricula. In fact, the National Commission and Mathematics and Science Teaching for the 21st Century reports that 25% of high school mathematics teachers and 20% of high school science teachers do not have the academic credentials or back ground necessary to teach these subjects. Until the level of science education is substantially elevated, we may continue to see decisions made by less than well-informed groups who deny scientific knowledge and methodology in forming their opinions, to the ultimate detriment of us all.

Whirlwind of Change

Looking back, I am astonished by the changes that have occurred in the development of U.S. energy supplies over the last decade. In fewer years than a kindergartner becomes a teenager, the U.S. oil and gas industry has found the keys to unlock literally billions of barrels of oil and trillions of cubic feet of natural gas in our country, and to completely reverse the trend of ever increasing dependency on foreign oil. The consequences are truly profound.

As recently as 2000, the energy industry’s consensus was that all the large fields in the United States had been found, oil and gas production in the U.S. would continue to decline, and oil imports from abroad would continue to increase. Although hydraulic fracturing (fracking) has been a standard industry practice since 1947, applied to more than a million wells in the U.S., its use in opening dense oil and gas-bearing shale formations had never been successful. All that changed in 2000 when Mitchell Energy Company finally demonstrated that new hydraulic fracturing techniques, utilized in horizontal sections of wells, could economically recover the treasures stored in tight rocks deep underground.

U.S. oil production peaked in 1970 at 9.6 million barrels of oil per day (bopd). However, by 2009 production had declined to 5.0 million bopd. A Malthusian projection of the trend would have led to the expectation that today’s production would be near 4.5 million bopd. However, owing to the “shale revolution,” U.S. production has risen to almost 7.5 million bopd, and continues to increase . . . a three million bopd difference. At an average price of $90 per barrel the differential amounts to $270 million dollars a day, or almost $100 billion per year, that will not be sent abroad. Perhaps that’s small potatoes by government standards, but it is still very significant to the U.S. balance of trade.

Consider U.S. crude oil imports. In 2005 the U.S. was importing oil at the rate of 10.1 million bopd. By the end of 2012 imports had dropped to 8.5 million bopd, a 1.6 million bopd reduction. In June of this year, Bloomberg reported that U.S. domestic crude oil production exceeded imports for the first time in 16 years. The resurgence of industry activity resulting from the combination of new horizontal drilling techniques and improvements in the sixty-five year old hydraulic fracturing technology has created a tidal wave of new business formations and elicited strategic changes throughout the industry.

Soon after George Mitchell’s early successes in producing oil and gas from the Barnett shale formation in north Texas, other companies immediately seized upon the new technologies to rapidly develop the Fort Worth basin’s Barnett shale and to apply them in other basins. A land grab that rivaled the early days of the 1800s gold rush began.

For the next several years, until around 2007, legions of agents representing individuals and companies of all sizes leased as many acres as they could finance. Larger companies bought acreage to drill; individuals typically bought leases with the intention of “flipping” them to the large companies at a profit.

The beginning of 2013 marked the beginning of a new phase of their operations. By now, most companies have acquired all the leases they could, consolidated their positions into a few core areas, established a drilling inventory that can keep them busy for years or decades, and laid out plans to develop their acreage, or prepare for an IPO, sale or merger.

For Five States Energy the shale revolution has been exciting to witness, but it has offered few opportunities for our participation. A primary strategy of our business is collateral-based investing, not speculative lease buying and selling, technology development, or exploratory drilling. Although massive amounts of capital have been required to fuel the party to date, only a very few situations have been appropriate for Five States to participate.

However, we believe our time is at hand. As new wells are drilled and put on production, money will be needed for pipelines, oil storage facilities, gathering systems, truck and rail terminals, water treatment plants, water supply and disposal wells, and construction of other midstream assets. Without these, producers cannot produce or sell their products. With value created by production from new wells, collateral will be available to support senior and mezzanine debt and development equity.