Category Archives: Arthur N. Budge, Jr.

Oil Fundamentals: Supply & Demand

As with all commodities, the price of oil is determined by supply and demand. People often think that oil is “special” because we are “running out,” and do not understand how prices can fall. But like all commodities, the daily price of oil is determined by daily demand and deliverable supply. When supply is tight or demand increases, the price increases. When supply exceeds demand, the price declines.

Until five years ago, it was widely believed (much like in the 1970s), that the price would keep rising forever, until oil became too expensive to use as a fuel. But the US “Energy Renaissance” has reversed that trend.

World Supply Growth

World oil supply is growing at a rate unforeseen just five years ago. The source of this new supply is the US Energy Renaissance. New sources of oil are being developed from “tight formations”, primarily in Texas and North Dakota.

US Oil Production

US Oil Production

US Oil Production (Texas & North Dakota)

US Oil Production (Texas and North Dakota)

The long-term decline in world-wide oil production has reversed, but the oil produced from the Shale Revolution has a high price tag. The cost to develop shale oil is +/-$50/barrel—over twice the price of crude in the late 20th Century.

The idea of imminent “Peak Oil,” widely accepted early in the last decade, has been proven incorrect. See Jeff Davis’ article, “Great Expectations: Revisiting Peak Oil,” for a detailed discussion. At the end of the 20th Century it was believed that US production would continue to decline, while consumption would continue to increase as the economy grew. Although the rate of consumption per unit of economic growth was expected to decrease due to conservation, alternatives and renewables, it was believed that total demand would still continue to grow. The scenario of increasing demand coupled with decreasing supply would ultimately result in a Malthusian scenario where oil prices would continue a long-term increase with prices dictated by the market manipulation of the OPEC cartel.

World GDP vs. Petroleum Demand

World GDP Change vs Petroleum Demand Change

Source: World Bank for GDP, EIA for Petroleum Demand

 

World Petroleum Demand OECD vs. Non-OECD

World Petroleum Demand OECD vs Non-OECD

Organisation for Economic Co-operation and Development (“OECD”); Source: EIA

 

The Energy Renaissance in the United States has been phenomenally successful. The US is on its way to once again being the largest oil producer in the world. This past summer US production exceeded Saudi Arabia production.

The application of horizontal drilling to develop previously uneconomic shale reservoirs is achieving the more optimistic expectations of a few years ago. Adding to the growth in supply is the recent reversal of strategy by OPEC kingpin Saudi Arabia. Saudi Arabia is now increasing production to defend market share rather than curtailing production to manipulate the world price of crude oil. See Seth Phillips’ article, “OPEC in the Modern Era,” for an overview.

Higher crude oil prices provided the funding for technological advancement, which reversed the trend of declining supply. We now know that there is a lot more oil and natural gas to recover than we thought in the 20th Century, but this supply is only available at a higher cost. See Gary Stone’s article, “Shale Revolution,” in this issue for a detailed discussion.

Demand Growth Slowing

While supply continues to increase, the rate of growth in energy demand is slowing. Technology and conservation have slowed the rate of growth in energy consumption per unit of economic growth. Energy demand is highly correlated to economic growth. The Great Recession further curtailed energy demand growth.

But the industrialization of the emerging economies (primarily China and India) is more than offsetting conservation and efficiency in the industrialized economy. This trend is expected to continue for several more decades.

Growth in Oil Demand, 2014-2040

In recent years, supply has been growing faster than demand. The oil market has been anticipating a future price decline for the last several years. The primary reasons that prices had remained in the $90 – $100 per barrel range were supply disruption in Africa and the Middle East and sanctions on Iran and Russia.

As with any commodity, when supply is growing faster than demand, price declines. But high prices are the cure for high prices, and vice versa. The new US production has a very rapid depletion rate. The development cost is over $50 per barrel in many of these plays, so oil needs to be over $60 per barrel to provide a profit and cover operating costs and taxes.

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.

Conclusions

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.

Conclusions

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.

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

Leverage

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.

Conclusion

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, http://articles.latimes.com/1998/nov/27/news/mn-48263

Five Hundred Million

We reached an interesting milestone at Five States this year. Total distributions from Five States partnerships over our history have now exceeded half a billion dollars. This is about three times the total equity invested1 in the Five States partnerships from 1989 through 2005. About half of this was operating income generated from our producing properties and about half was from the property sales in 2006 and 2007. We completed investing Five States Energy Capital Fund 1 earlier this year, and we expect it to “ramp up” to provide distributable income similar to our earlier partnerships. We consider these results to be a good example of “Value Investing”.

Investment managers are often classified as “Growth Investors” or “Value Investors”. Growth Investors generally have a strategy of seeking investment opportunities where the primary return is expected from growth in the underlying business, translating into growth in investment value. Growth Investors are willing to pay a higher price relative to current earnings because they expect earnings to grow. Returns are achieved primarily from appreciation, so are realized upon sale. Current returns such as dividends are typically low or nonexistent. A good example of a growth investment is Apple stock. The value of the stock is much greater than the current earnings alone justify, and it has historically paid out a low percentage of earnings in dividends.

Value Investors seek investments that are attractively priced based on the existing financial fundamentals; a “what you see is what you get philosophy”. After analyzing revenue, expense and income of their target investments, as well as the component value of the assets and offsetting liabilities, Value Investors calculate what they think the investment is worth based on these fundamentals, typically using a discounted cash flow methodology. A disciplined Value Investor invests only when the target investment can be obtained at or below their calculated value. Utility stocks are an example of a value sector. Most of the valuation is based on the existing income potential of the company. Much of this income is paid in dividends.

We at Five States have always considered ourselves a Value Investor. Our investment decisions are based on analysis of the underlying fundamentals of target assets. We expect to earn the return from owning an asset, relying on the income the asset generates for the majority of our return. We expect to sell an asset only if someone is willing to pay us more than we think it is worth.

A Value Investing approach has a consequence that is sometimes frustrating. There are times when others in the market are willing to pay more for an asset than we are, and we become “priced out of the market”. Periods like late 1997/early 1998 and 2006 to 2009, when we closed few if any transactions, are good examples. In both of these periods we processed plenty of transactions, but someone was usually outbidding us. So we would wait until market values came back in line with our calculated valuation. We do not consider this a contrarian philosophy. We consider ourselves realists.

Fracking

In the 2006 – 2007 period we thought that “peak oil” was going to result in a continually shrinking inventory of domestic assets in the U.S. for us to invest in. New recovery technologies developed in response to higher oil and natural gas prices have reversed that trend. The development of 3-D seismic and horizontal drilling have resulted in the ability to recover economically viable oil and natural gas from formations that would provide insufficient yield with only vertical wells. These technologies have also substantially reduced the “dry hole” risk of new development, often approaching zero.

The reduced dry hole risk of developing new fields has been replaced with new risk. The cost of implementing these new technologies is much higher on an individual well basis. Completion risk is also greater. In long horizontal wells it is not uncommon that the cost to complete the well exceeds the cost to drill it. The break even cost to drill and complete oil wells in many of the active domestic plays is $40 to $60 per barrel, and for natural gas is $3.50 to $6.00 per thousand cubic feet (mcf). This adds operating leverage, resulting in increased systematic risk (the impact of oil and gas price volatility). This risk was realized in the natural gas sector at the end of the last decade as the success of horizontal drilling increased domestic supply so much that the price of natural gas declined from over $10/mcf to as low as $2.00/mcf. It has recently recovered back to the $4.00/mcf range.

In 2007 when we expanded our investment tactics to include mezzanine, we did so in recognition of the increased systematic risk. At that time, we did not expect the industry to expand at the rate it has in the last six years, but did see that the systematic risk had increased materially. We needed additional tools to structure new investments appropriately in light of that risk. Ironically, the mezzanine structure was used in only 20% of the FSEC Fund 1 portfolio as it exists today. It would have been over 50% if a very substantial mezzanine commitment known as Coachman had not prepaid.

Increased oil production volume has dampened the consensus expectation that oil prices will increase materially in the near term. Domestic production rates are approaching levels of twenty years ago, and are expected to continue increasing.

NYMEX Futures Curve Comparison

Today, the futures contract price for oil to be delivered one to seven years from now is materially lower than the wellhead price. This is occurring for the first time in decades.

Energy Demand by Region – OECD vs. Non-OECD

Energy Demand by Region - OECDEnergy Demand by Region - Non-OECD

The waning optimism regarding futures prices is actually good for us as a Value Investor. Over the last decade many of our competitors were counting on higher oil and natural gas prices in the near term to support their investments. Now that these competitors are not expecting higher prices in the near term, the assets for which we are competing are more attractively priced.

We believe that this “softening” in oil and natural gas prices is an intermediate term phenomenon. World demand for energy is expected to continue to grow as the world economy expands. The vast majority of this energy demand will be met by oil and natural gas.

The United States is shifting from a net consumer to a net producer. This is already having a material impact on the U.S. economy as our balance of trade deficit shrinks and our economy benefits from the high paying jobs and high return investment of the redevelopment in our domestic energy infrastructure. North America will become hydrocarbon independent, and will likely become an exporter of natural gas.

US Crude Oil Production – Texas and North Dakota

US Crude Oil Production - Texas and North Dakota

This is providing an incredible Value Investing opportunity in an otherwise depressed environment. We believe that this renaissance in the domestic oil and natural gas industry will present Five States investors excellent opportunities and returns for the next decade.


Sunset to Sunrise: Fundamentals & Trends

Industry consensus is that the increase to United States oil production volume in 2012 will exceed growth in world oil demand for the first time in half a century. The increase in the rate of US production is expected to continue for the foreseeable future. The success in development of new natural gas reserves is comparably staggering. The change from the US requiring ever-increasing oil and natural gas imports to possible North America energy self-sufficiency, or even energy exports, is one of the greatest reversals of expectation in industrial history.

North American production of oil and natural gas has increased by 18% in the last five years. This follows decades of constantly declining production rates and reserves. Over the next several decades, proved US crude oil and natural gas liquid reserves are expected to grow five times, from twenty billion barrels to one hundred billion barrels. The US natural gas reserve life is expected to increase from a twelve year supply to a one hundred year supply.

This reversal of fortune is due to the development of new drilling and completion technology that allows for economically viable production of oil and natural gas from shale and low permeability conventional reservoirs. Advances in information technology and materials science that occurred during the oil and gas depression of the 1980s and 1990s have now been applied to the oil and gas industry. These have contributed to the development of three dimensional seismic surveys, horizontal drilling and the ability to perform multi-stage hydraulic fracturing on horizontal wellbores, making this seventy year old stimulation technique exponentially more effective.

These new and improved recovery technologies have increased the cost of drilling and completing new wells. The average well cost in the US has increased three fold, from an average of $1.7 million in 2005 to over $5.7 million today. Recoverable reserves per well have increased proportionately or more. It is estimated that the increased cost of development and expansion of the new opportunities in the US will translate to new capital needs of $35 billion per year for the oil and gas industry. This is over and above the reinvestment of retained earnings and use of the increased borrowing capacity created by the expanding reserve base.

The growth in production is also spurring a boom in required infrastructure. This is referred to as “midstream” in the industry. Midstream includes everything in the “middle of the stream” of the commodity “flow” between the wellhead and the refinery. Production volumes in most parts of the US have outgrown existing infrastructure. In new areas the infrastructure does not exist at all. It is estimated that new investment required to deal with the growing production volumes is about $10 billion per year (including Canada) for natural gas transmission, storage, gathering and processing; oil pipelines; and natural gas liquids pipelines. This is quite a boom in high skill, high wage manufacturing!

The increase in natural gas consumption has had a greater impact on emissions than all of the subsidized investments in renewables combined. Most of the increase in natural gas consumption has been used to generate electricity. Much of the electricity generated with natural gas is replacing the older high emission coal plants. Natural gas emits 45% less carbon per energy unit. CO2 emissions in the US are at the lowest level in twenty years.

Little of this decline in emissions is due to “alternatives.” It is estimated that the shift from coal to natural gas has reduced US emissions by 400-500 megatons of CO2 per year. Wind turbines account for a reduction of about one-tenth of that amount, biofuels 2.5% and solar panels less than 1%. Some experts calculate that the conversion to natural gas has reduced emissions more than required in the Kyoto Protocol.  Further development of natural gas as our core asset, particularly in fueling vehicles, can have additional economically efficient impact on further reducing emissions in an economically productive way.

The risk profile of oil and gas investing has changed with the improvement in development and recovery technology. In the 1985 – 2005 period, our primary risk focus was on individual project (unsystematic) risk. With oil averaging well below replacement cost at $20 per barrel, we were not nearly as concerned with price risk. New technology and the type of reserves being developed have materially reduced the risk of failure of an individual project. For example, we have participated in twenty-two Bakken oil wells in North Dakota in our production partnerships, drilled on acreage positions we own from production purchases made in the 1990s. All of these wells are calculated to be economic successes. Today, with oil over $80 per barrel and replacement cost in the $40 – $50+ range, we are much more focused on oil and gas price (systematic) risk. That is why we continue to lock in current high prices with hedges, and are making some of our new oil investments using mezzanine structures, so that we are in a priority position if oil prices decline in the near term.

Energy imports account for about one half of the US balance of payments deficit. Reducing or eliminating this deficit would have a highly stimulative impact on our national income equation. Much of our military budget is spent in an attempt to maintain stability in the Middle East. If we eliminate the stranglehold of OPEC on the industrialized west, US military expenditures and foreign policy can be greatly modified.

Sunset to Sunrise

My father loved the oil business. He grew up in West Texas during the World War II oil boom and worked his way through college “roughnecking” in the oilfields. Because the derrick crew did the dangerous work out in the weather on the rig floor, my grandfather told Dad to go to college so he could be a “company man” as they did all the “think work” in the trailer. When Dad graduated, he got his dream job as a geologist with Gulf Oil and took part in one of the greatest industrial developments in history. The World War II boom and the domestic oilfield development of the ‘50s and early ‘60s led to a surplus of deliverable supply, which provided the U.S. with low cost oil into the 1970s.

From my childhood, Dad taught me about geology, the oil industry and that oil was a depleting resource. Like most in the industry, he recognized that the abundance of cheap oil was finite and depletion of domestic reserves meant domestic oil was a sunset industry (i.e., an industry believed to be in terminal decline). This low-cost, secure domestic resource contributed to the creation of the modern American middle class during the greatest period of growth in U.S. history. Because domestic production was in rapid decline, we believed an alternative to domestic oil and natural gas would be necessary in my lifetime.

The resource is finite. But the supply is much greater than we believed just five years ago. The creation of recovery methods for developing “unconventional” oil and natural gas resources is a game changer. The U.S. can replace much of its imported oil with domestic oil and generate needed electricity with domestic natural gas rather than with coal. The development of domestic reserves can be a major part of the engine of economic recovery.

The Great Economic Drag

Until recent years, U.S. oil consumption increased in lockstep with the growth of the economy. Domestic production decreased each year and imports increased. It is probably not a coincidence that the deterioration of the U.S. economic condition correlated with the loss of energy independence, increased oil imports and increased deficit in our balance of payments. The cost of maintaining a military presence, fighting multiple wars in unfriendly parts of the world and using our Navy to protect critical shipping lanes has compounded the economic drag.

The U.S. has run a balance of payments deficit for the last 40 years. In essence, we buy more goods and services from foreign countries than we sell to them. This can be beneficial when we purchase goods for less than we can produce them domestically. In relation to oil, such has been the case.

Energy is incredibly important to economic output. Imagine your life without it. What would your day be like without oil and electricity? Tomorrow, turn off your electric meter and avoid cars, buses, planes and trains, and see where you focus your time! No economically competitive substitute for oil as our primary transportation fuel currently exists, even at $100 per barrel. The failures in “alternatives and renewables” illustrate the difficulty of doing without oil. Ethanol as a substitute is a politically driven scam. The failure of other government financed alternative energy companies in the past year illustrates the difficulty of the problem.

But the economic cost of imported oil is high. In 2010, the United States spent about $265 billion on net oil imports. Moreover, a tremendous amount of the U.S. military budget is allocated to security of oil producing nations. Economic forecasters estimate that every $10 per barrel increase in the price of oil reduces U.S. economic growth by 0.2% due to the impact of oil imports. The money that we send abroad provides little stimulus to our economy. It has no “velocity”.

Velocity of Money

Economists talk about money spent or invested as having “velocity”. High velocity is good for economic growth. Low velocity is less so. The problem today with much of the government stimulus is that it has no velocity. If the government provides capital to a bank and the bank buys U.S. Treasury securities, the funds do not do much good. The government is providing the money to the bank for less than the bank is lending it back to the government by buying U.S. Treasury securities. Other than the earnings accrued to the bank in this cycle, there is no economic stimulus. This money has no economic velocity; it is merely cycling in a non-productive treadmill. The government is effectively giving money to the banks.

If the bank takes the same money and lends it to a company to build a factory, there is a lot of velocity. The company hires contractors who provide wages and consume products from subcontractors, and so forth. When finished, the factory provides jobs and produces a product (hopefully at a profit). Employees from these companies spend their wages on goods and services, stimulating other businesses to hire more employees, and the cycle continues. Those dollars loaned had a lot of velocity and contributed to a lot of economic activity.

Money spent on imported oil has limited velocity for the U.S. It is much like the first example. But we now have the opportunity to replace low velocity money spent on foreign oil with domestic production. Developing domestic resources is highly stimulative to the U.S. economy. Money invested in developing domestic production is high velocity money, creating high paying jobs and consuming goods and services that stimulate other businesses.

The 21st Century Domestic Energy Boom

The current boom in domestic energy production was inconceivable ten years ago. Since the ‘60s, each year more oil and natural gas was imported to meet our country’s energy needs. In the ‘80s Mitchell Energy began to attempt to produce natural gas from the Barnett Shale. Up to that time it was widely believed shale formations were too “tight” to recover the natural gas trapped in the rock. It took years of experimentation and millions of dollars before Mitchell Energy began to have commercial success. As natural gas prices rose in the early 2000s other companies were drawn to the Barnett play and new techniques and technologies quickly evolved. The most significant of these were the widespread use of horizontal drilling and improved hydraulic fracing methods. Today almost all new unconventional (and many conventional) wells include horizontally drilled lateral “legs”, and all require hydraulic fracing to increase the permeability of the reservoir rock.

The technology and techniques developed in the Barnett Shale were applied in other natural gas shale plays across the country. The Fayetteville in Arkansas, the Haynesville in Western Louisiana and Eastern Texas, and the Marcellus in Pennsylvania all became significant natural gas plays. The speed at which the reserves in these plays were being developed was astonishing. The number of rigs drilling for natural gas went from approximately 500 in the mid ‘90s to over 1600 by ‘08. The pace of drilling combined with the high initial production from these shale plays flooded the market with natural gas.

Sunset to Sunrise

Similar exploration and production began taking place in oil plays. Engineers and geologists began to revisit formations previously thought to be uneconomic. As natural gas prices fell in 2009 natural gas focused operators began directing more of their capital budgets to more lucrative oil plays. These companies, armed with the knowledge they acquired drilling for shale gas, soon began to develop new oil fields throughout the country. The Bakken formation in North Dakota and Montana, the Permian Basin in Texas and New Mexico, and the Eagle Ford Shale play in south Texas have led the way in this revitalization of domestic oil production.

The results have been astonishing! The Bakken shale has elevated North Dakota to the 2nd largest oil producing state in the U.S. Today North Dakota produces over 600,000 barrels of oil per day. The development of the Eagle Ford shale and the reemergence of the Permian Basin have pushed oil production in Texas to over 1.7 million barrels a day, the highest level in twenty years. Today our country produces more oil than it has in over ten years, and the rate is still increasing.

Booms Lead to Busts

My grandfather was a drilling contractor in the World War II boom and during the following two decades. He started as a roughneck and worked his way up to foreman, saving enough money to start his own company and make a down payment on a drilling rig, which was the primary asset of his company over the next 20 years. He never went to college, but over my 30 years in the industry, his counsel has proven to be some of the most salient I ever received. As the boom of the ‘70s peaked, he warned me that every boom sows the seed of its own end.

The record production in natural gas outpaced record demand and resulted in the current price collapse. Fear of such a collapse was a primary factor in our decision to sell our natural gas assets in 2007. Current prices are below replacement cost, making natural gas attractive on a fundamental basis. We believe there will be wonderful new investment opportunities in natural gas in this lower price environment over the next three to five years.

The boom in unconventional oil, combined with the worldwide recession, may result in a decline in oil prices. Many argue that without the political instability in the Middle East prices of oil would be much lower today. Although we do not believe that a downturn would last as long as in natural gas, management of price volatility is critical in these investments. That is why we continue to maintain an active hedging strategy, locking in future prices to reduce the volatility of our expected results.

Conclusion

I sometimes think of investing in oil and gas as riding a roller coaster blindfolded. You can have a great time as long as you don’t get thrown out of the car! Hedging smooths the peaks and valleys, in this case making the ride much more enjoyable.

Reversal of Fortune

In the last decade, we have experienced a complete reversal of expectations regarding the future of our domestic energy supply. Today we have the potential to materially improve both our geopolitical and economic situation.

In the 1970s it was widely believed that U.S. oil and natural gas reserves had been depleted to the point that we had no choice but to rely on imported foreign oil. Many also concluded that the U.S. needed to import natural gas. The actual experience of the last 10 years has proven key parts of these assumptions wrong.

Regulation of oil and natural gas prices during most of the early 20th century was the root cause of the errors. Oil and natural gas prices were highly regulated during most this period, primarily to keep prices low. As low cost reserves were depleted, the incentive for producers to develop more expensive new reserves was less than it would have been if prices had been allowed to gradually rise. This distortion amplified the apparent decline rate in reserves, leading to misguided energy policy which exaggerated the already volatile oil and natural gas markets.

Oil and natural gas prices were deregulated in the 1960s to 1980s. The deregulation of oil prices was fait accompli as the U.S. became a major importer of oil and could no longer control prices through manipulation of domestic production. As prices rose through the 1970s, the ensuing drilling boom developed an overhang of supply of oil and natural gas, which lasted for almost two decades, resulting in the low energy prices we experienced throughout the 1980s and 1990s. Over the last decade, as the supply overhang was depleted, we saw energy prices increase substantially.

The two decades of excess deliverable supply and low prices were also a period of limited investment in energy research and development. The energy industry was in a prolonged depression. Despite the fact that the long term outlook was problematic, politicians were not concerned because gasoline and natural gas prices were low, therefore constituents were not complaining.

By the end of the 20th century, the bonanza from the 1970s boom had been consumed. Oil and natural gas prices began to rise. As prices rose, capital investment in research and development accelerated. The results have been phenomenal!

Oil and Gas Prices Decouple

The U.S. economy is once again in a period where high oil prices are negatively impacting our economy. Oil products are our primary transportation fuels. Our oil supply remains dependent on politically unstable areas of the world.

Higher oil and natural gas prices have stimulated tremendous success in developing new supplies. The development boom in natural gas has been so successful that prices have fallen to levels that, five years ago, we thought we would never see again. As a consequence, the historic price correlation between crude oil and natural gas has decoupled. The chart below shows this dramatic change.

Oil-and-Natural-Gas-Prices

 

The difference in price per unit of energy between oil and natural gas is incredible. Natural gas is currently trading at approximately $2.00 per MMBTU (MM = million, BTU = British Thermal Units, a measure of energy content). The equivalent for oil is about $18.00 per MMBTU. At current market prices oil costs 8.9 times as much per unit of energy as natural gas.

The development of horizontal drilling technology combined with hydraulic fracturing technology has resulted in a tremendous increase in natural gas production in the U.S. This increased supply has resulted in a collapse in domestic natural gas prices. Natural gas prices are 80% below the high of five years ago. Prices are 80% lower in the U.S. than in Europe and Asia, providing our nation with a huge competitive advantage.

Increasing Consumption of Natural Gas

 

Shale-Production-of-Natural-Gas

In the early days of the oil industry natural gas was something of a nuisance. The gas was found in association with crude oil or dissolved in the oil when under pressure in the formation. As the oil was produced, the gas was also produced or came out of solution as the oil reached the surface. To dispose of it, the gas was often flared. Over time, pipeline systems were developed to distribute gas for industrial and residential consumption.

U.S.-Consumption-of-Natural-Gas-Trends-BCF

Typically the price of a commodity rises when consumption increases. But the increase in the deliverable supply of natural gas in the U.S. has been so successful that natural gas prices have collapsed while consumption increased. The increased consumption is primarily due to the use of natural gas as electrical generation fuel.

2011-U.S.-Consumption-of-Natural-Gas-by-End-Use

Lower Emission Electrical Supply

Many of the new electrical generating facilities in the U.S. are natural gas powered. Electrical generation is one of the easiest applications for the additional use of natural gas. An advanced distribution infrastructure exists for both the natural gas consumed and the electricity produced. Capital cost to build natural gas powered generating capacity is low relative to alternatives such as coal, nuclear and renewables. In addition to superior economics, there is a big bonus in that most of the generation being powered by natural gas, with significantly lower emissions, is in lieu of coal fired power plants.

Coal is currently used to generate 45% of the electricity in the U.S. Natural gas fuels 24% of U.S. electric generation.

2010-Electricity-Net-Generation-by-Sector

A recent Congressional Research Service report concluded that “if natural gas powered combined cycle plants utilization were to be doubled from 42% capacity factor to 85%, then the amount of power generated would displace 19% of the carbon dioxide (CO2) emissions attributed to coal-fired electricity generation.” According to a GE Report, CO2 emissions could fall by 150 million tons per year by year 2020 if natural gas powered combined cycle plants replace coal. This is in addition to the material reduction in air pollutants such as carbon monoxide, non-methane organic gas and nitrogen oxides as well as ash waste.

Natural gas is a much more economical option for power plants to mitigate CO2 than carbon capture and storage (CCS). For the first time in history, natural gas is cost competitive with coal.

Substitution of natural gas in lieu of coal is taking place in the domestic power generation sector. The Energy Information Administration reports that, in February and March 2011, coal-fired generators had the largest year-over-year decline, down 6.9%. Natural gas prices are even lower today than last year, so this trend is likely accelerating.

Growth Potential for Natural Gas

In some applications, natural gas can be substituted for oil products (for example, as a boiler fuel or heating fuel instead of fuel oil). Because the price differential has made natural gas so much more attractive, most of the “easy” substitution that makes sense has occurred.

Because it is a gas at ambient temperature and pressure, natural gas is not easy to store or transport by vehicle. Natural gas is almost always delivered by pipeline (not to be confused with natural gas liquids such as propane, which are used as fuel in remote areas where pipelines are not cost effective). This is why we have traditionally considered it a “domestic fuel” with our imports coming by pipeline from Canada.

LNG – Import to Export

Liquefied Natural Gas (LNG) is natural gas temporarily converted to liquid form by cooling. LNG takes up about 1/600th the volume of natural gas in the gaseous state. In liquid form, it is possible to transport natural gas by ship in cryogenic containers.

Five years ago some companies were developing facilities to import LNG into the U.S. With the lower prices today, this development has reversed and companies are now working on LNG facilities to export U.S. natural gas.

Natural Gas as a Transportation Fuel – Compressed Natural Gas

Compressed Natural Gas (CNG) is being adopted by many government agencies and companies as a fleet fuel. The lower cost compared to petroleum, combined with the reduced emissions, makes this a very attractive fuel. However, the lower energy density of CNG compared to gasoline and diesel limits the attractiveness of this option. In addition, wider spread adoption of natural gas as a vehicle fuel would require major infrastructure development in compression and pipeline systems.

Gas-to-Liquids (GTL)

Major advances have been achieved in gas-to-liquid (GTL) technology. GTL overcomes the two major disadvantages of CNG. The liquid fuels produced using this process have comparable energy density to traditional liquid fuels refined from crude oil, and can be mixed with conventional liquid fuels and distributed through the existing systems that we use to distribute liquid fuels today.

Shell is a leader in this area. Shell developed its first Pearl GTL plant in a joint venture with the state of Qatar. This facility produces 260,000 barrels of oil equivalent per day of cleaner-burning diesel and aviation fuel, oil for lubricants, and ingredients for plastics and detergents from natural gas. The first shipment of refined products from this facility occurred in June 2011. Shell recently announced plans for a Pearl GTL plant in Louisiana.

Improvement to the National Income Equation

The current economic and political discourse revolves around decreasing spending and increasing taxes. These are painful choices, but the discourse is leaving out a key component: net exports (actually imports).

In elementary economics, the National Income Equation is defined as:

National Income = C + G + I + NX + net foreign factor income – indirect taxes – depreciation where:
C = Consumption
G = Government Spending
I = Investments
NX = net exports (exports minus imports)

Decreased Government Spending decreases Consumption. Increased taxes decrease Consumption and Investments. These options reduce National Income, shrinking the economy. This is the dilemma facing policy makers.

An improvement in Net Exports (a decrease in imports; reduction of the balance of payments deficit) would increase National Income. For decades we have run a trade deficit, primarily due to energy imports. Increased domestic energy production can materially reduce imports, increasing our National Income. This would be very constructive toward growing our way out of our current fiscal dilemma.

The potential also exists to break OPEC’s stranglehold on world oil prices. Replacing 10% to 20% of U.S. oil imports with domestic oil and natural gas has the potential to materially effect on world prices. Our goal should not be energy independence. It should be to develop sufficient energy supplies both domestically and internationally that no nation or cartel can manipulate world prices.

Conclusion

The decrease in natural gas prices over the last five years once again provides indisputable proof that free market forces control the price of oil and natural gas. Massive capital investment has produced new supplies, collapsing the domestic price of natural gas at the expense of the companies that made the investments.

Current natural gas prices below $2 per MMBTU are not sustainable. The cost to develop new natural gas supplies are in the $4 – $6 MMBTU range. But at a $4 – $6 MMBTU level, natural gas would still be about one-fourth the current world price of oil on an energy equivalent basis.

Natural gas is an excellent transition fuel for breaking the stranglehold of foreign suppliers and allowing the transition time period for the development of economically viable renewable energy. Natural gas should continue to take market share from coal for electric generation. The development of export systems and systems for expanding the use of natural gas into the transportation market will further expand supply.

Most renewables being implemented today are based on 20th century technology. Current investment should be in research and development of economically viable new technology, not installing cost ineffective alternatives which reduce our national economic output. Natural gas is cost effective, produces lower emissions and is readily available in the U.S. Gas can provide an economically viable energy supply while we develop alternative energy technology.

Natural gas can be a major contributor to reducing our balance of payments deficit by reducing oil imports, and possibly oil prices. This can play a major part in easing the difficult spending/tax choices we currently face in the government sector.

Cycles

The universe functions in cycles. Stars are born and die, providing the material for the birth of new stars and planets. Galaxies and solar systems revolve in their cosmic dance. Current theory holds that the universe began with a massive explosion of energy, and will continue to expand for millions of eons, at which point it will begin to collapse on itself in the ultimate cycle of existence as we understand it.

Here on earth, we live in a world of cycles. Night follows day. We rise, are active, tire and then sleep. Spring follows winter. Each generation is born, lives and dies, begetting another generation to follow the same cycle. Cycles of temperate and harsh weather are recorded throughout history. Periods of famine and periods of plenty have been the norm throughout human existence, documented as far back as Joseph’s prophecy to Pharaoh of “seven years of plenty followed by seven years of famine.” Archaeological records throughout the history of man show that this cycle was often the key driver of the birth and death of civilizations.

Many cycles that exist in nature and in human activity are long in comparison to the human life span. Currently geological theory believes that we live in an Ice Age, and that we are now in the Third Interglacial stage. Yet few of us are stocking up for the end of this interglacial stage and the resumption of the Ice Age. The longer the cycles, the more we perceive them as changes from “normal”. If we grew up under a certain set of circumstances, we consider them the norm and any change from that to be the exception. We thought my grandmother, who was a Depression orphan, was peculiar in her hoarding habits, always having two freezers full of food (in addition to the kitchen refrigerator, a cellar full of home-canned food and a garden) and saving used aluminum foil and jelly jars. But the Depression was her “norm”, and our time of plenty was an anomaly.

In our modern times, we have shielded ourselves from many of the impacts of natural cycles. We produce and store so much food that in industrial societies we no longer face the specter of famine. In many areas, we no longer even “suffer” the inconvenience of the seasonality of our favorite foods, shipping them half-way across the world so we can have fresh berries on our cereal every day. But the natural cycles are still functioning in the background, applying their pressure to various portions of the economy.

Financial cycles mirror natural cycles in many ways. In early civilization, agriculture was the primary industry. Times of plenty resulted in low prices of goods and higher standards of living. Hard times resulted in periods of economic contraction. As we all learned in school, the Great Depression was initially ignited by overexpansion of the agricultural sector followed by a great drought.

Financial cycles continue. The information technology boom of the last thirty years has apparently eliminated the inventory cycle, which was the most regular cause of business expansion and contraction. However, it did not eliminate the financial cycle, as we have so painfully learned over the last five years.

The current financial cycle began in 1981, when Paul Volcker, then Chairman of the Federal Reserve, decided to break the inflation cycle of the 1970s by raising interest rates. Treasury yields peaked at over 21%. President Reagan introduced a series of new policies targeted at cutting government spending offset by lower marginal tax rates to counter the contractive effect of reduced government spending. The higher interest rates squelched the inflation, and the lower marginal tax rates stimulated the economy, but the spending cuts were never achieved. The decline in inflation translated into declining interest rates, which set off a price/earnings expansion cycle in both financial assets and real property values that lasted 25 years.

Declining interest rates resulted in a rise in the value of all income producing assets. If one could no longer get 20% interest on their government bonds, then they would consider paying more for stocks, bonds or real estate, thus driving up the price of those assets and driving down the yields. With the Federal Reserve continually lowering interest rates, the economy grew and we were able to ignore the time bomb we had created in the actually unsound social entitlements that Congress continued to expand. We now hear some pundits speak of the current situation as “the end of . . .” (fill in the blank depending on the political leaning of the speaker), requiring drastic measures (personally, I think a little pragmatic reassessment of our expectations would go a long way to resolving these issues). Asset values escalated beyond sustainable fundamentals. The sub-prime collapse is often credited with causing the boom, but in reality it was the inevitable end of a 25 year expansion that had been manipulated to last beyond all reason. Asset values were materially overinflated. A correction was past due.

In the background to this drama, and influencing the boom and the bust, was the evolution of the energy market. Prior to 1970, the world oil market was effectively controlled by the United States (history students will recall that the Japanese attack on Pearl Harbor was in retaliation for the Roosevelt Administration’s blockade of Japan’s oil supply in Indonesia). During that period, the Texas Railroad Commission was successfully manipulating the deliverable oil supply to maintain a constant oil price. In the early 1970s, the leaders of the OPEC countries (Saudi Arabia, et. al.) realized that the United States no longer had the production capacity to control world oil prices, but that OPEC functioning as a cartel could. With the Arab Oil Embargo of 1971, OPEC set off the resumption of the boom/bust energy cycle that began in the early years of the industrial revolution, which was only briefly interrupted by the success of the United States in manipulating the world market in the early 20th century.

Energy cycles are long. The last two have been particularly extreme. The 1970s/early 1980s boom resulted in the development of excess deliverable supply, resulting in a fifteen year bust that lasted from the early 1980s through the 1990s, when oil and natural gas sold at prices below replacement cost. As the excess deliverable supply was consumed, the current growth cycle in the energy industry began. The consensus of many pundits was that “this is the end, we are running out and oil and natural gas prices can only go to the moon.”

The length of the bust impacted investor and government behavior during that portion of the cycle. The low energy prices contributed materially to the economic stimulation of declining interest rates during the 1990s. Little money was invested in energy conservation. Despite the lessons of the oil embargoes, gas guzzlers once again became the vehicle of choice. Little capital was invested in new oil and gas exploration and recovery technology. The trend was one of rising demand in the face of falling supply.

By the early part of the last decade, the excess deliverable supply was used up, as the existing producing properties followed their natural decline and consumption continued to increase. As expectations of higher oil and gas prices resumed, capital returned to the energy sector. Focus on conservation returned. Research and development into ways to consume energy more efficiently once again came into focus. New technology developed over the last two decades was applied to exploration and recovery. The results have been stunning.

Natural gas closed below $2.50/mmbtu last week – a price level not seen on a sustained basis since 2002. Natural gas prices peaked at over $10 in 2008. The current collapse is due to the success of the development of shale reservoirs, which has turned expectations for the U.S. natural gas supply on its head. It is now estimated that the U.S. have as much as 100 years of reserves based on current projections of future demand. Five years ago projects were under way to import liquefied natural gas into the U.S. Now the cycle has reversed and several projects are underway with the goal of exporting U.S. and Canadian natural gas.

The same technologies that are used to develop shale gas formations are also being successfully applied to shale oil formations. Ten years ago, Five States scoffed at a U.S. Geological Survey estimate that the Bakken Shale formation in North Dakota, Montana and southern Canada might be the largest oil field in North America. [sentence omitted from original article]

This is a paradoxical time for us in our planning. Oil and natural gas markets are moving in opposite directions for the first time. Oil is booming while natural gas is crashing. We are grateful that we sold our gas properties in 2007 and are in a position to once again accumulate natural gas properties when the market presents opportunities. We continue to actively solicit natural gas acquisition opportunities. Depressed markets are often the best environment for making great value acquisitions. However, failure of regulators to enforce traditional discipline on over-extended banks continues to allow them to keep non-conforming producing natural gas off the market, “waiting for the market to recover”.

As Jim discussed in his article “The Froth is on the Punkin’,” it feels like boom times in the oil business. There is an atmosphere of frenzy around several of the major oil plays. Articles are being published rationalizing why it is different, and why oil prices cannot fall. We are bullish on oil over the intermediate to long term. But one concern is that the pace of development could result in short-term periods of excess deliverable oil supply resulting in unforeseen corrections in oil prices. The investment structure of Five States Energy Capital, LLC allows us to continue to participate in high quality acquisition and development projects, but to do so in a preferred position. With the customer (the producer/borrower) in the “first loss” position, and our crude oil production hedging program limiting short-term price exposure, Five States can remain active in the oil sector without exposing investor capital to the risk of material loss in the event of a short-term price collapse.

Our biggest concern is the continued efforts of government to thwart the cycles. Some steps taken in the Troubled Asset Relief Program (TARP), signed into law by President Bush, stopped the collapse. But the shoring up of overinflated markets left excessive loans on the books of many financial institutions, resulting in the “investment bubble” in real estate and in other sectors never fully correcting. The financial reform bills passed by the Democratic controlled House from 2008 to 2010 avoided key issues, and left those most responsible unaccountable and further entrenched “too big to fail”. The current Republican controlled House has done nothing to address these issues and there has been no leadership in this area from the White House. The excesses that led to the debacle are as bad as ever. Not only do we have gridlock in Washington, but we have gridlock in several key sectors of the financial system. We do not believe this is sustainable. It is a scary time.