Category Archives: Producer Articles

The News is So Bad!

I have received a number of calls recently with a common theme; “The News is So Bad!” This statement is usually followed by:

  • “I read that the price of oil/gas will never recover”;
  • “The drilling industry is collapsing”;
  • “I read that the collapse of the oil/gas industry may go on for decades”; or
  • “How can we make money if oil/gas prices don’t recover?”

For value investors, this is as good as the environment gets for making new investments!

The Boom

The boom in oil and gas was driven by several factors. The first was growth in world demand. Despite slowing growth in energy demand in the developed economies (the US, European Union and Japan) primarily due to more efficient use of energy, world demand continued to grow over the last decade. Total energy demand from the emerging economies (China, India and others) is now greater than from the developed economies. The rate of growth in demand by the emerging economies has slowed in the past few years, but world energy demand continues to increase every year.

World Oil Demand

The increase in energy demand resulted in higher prices, which led to the development of unconventional oil and gas development. The method of development is not what is unconventional. Hydraulic fracturing has been used throughout the world since the 1950s. The unconventional part is developing shale formations, which is not economically viable when oil is less than $40 – $50 per barrel. When oil was over $80 per barrel, there was a “gold rush mentality” in the industry, with attempts made to develop almost anything that would produce.

The development was very successful. The majority of the new production developed was in the US. Domestic oil production increased by two-thirds over the last decade, from six million barrels per day to over 10 million barrels per day. Last year, the US was the world’s largest oil producer. But this led to excess deliverable supply and a price collapse.

US Oil Production

Too Much Debt

The boom and subsequent collapse were fueled by a combination of success in drilling and too much debt. The location of the shale formations is well understood and documented, so few dry holes were drilled. This led to the perception that drilling shale wells was not risky, so greater levels of debt were used to capitalize the development than was historically normal.

Oil Price and Unexpected Market Tightness

Debt and Leverage Have Increased Sharply in the Energy Sector

Since interest rates were low, the addition of low interest debt to the capital structure of oil companies became common. The “cost of money” to develop or buy oil properties decreased tremendously.

Historically, good quality proved producing oil properties were valued at a 10% – 15% discount rate. That is, the value of the estimated future income stream is valued at a price that would generate a 10% – 15% net yield over the life of the well.

Low cost debt resulted in the discount rate declining into the 6% – 8% range, increasing the market value of these wells by two to three times or more. And these yields were being calculated on assumed future oil prices continuing at record levels.

Record Prices and Production Volume

Until late 2014, oil was selling for record prices, ranging from $80 – $140 per barrel. The consensus view was that oil would continue to sell for $80 – $100 per barrel. It was assumed it would “spike” above that range during periods of international instability, and that any declines below that range would be short-lived.

By late 2014, world production began to increase to a level greater than world consumption, as demand growth began to slow. Inventories reached historic highs, and prices collapsed. US production has peaked, and is expected to decrease by 700,000 barrels per day this year.

When Do We Buy?

I am often asked “How do we call the bottom?” The answer is, we can not. I have no idea if the bottom was last quarter or if the price of oil will decline again later this year.

However, it is time to buy. We are clearly in the bottom quartile of the cycle. Oil prices are low and discount rates are high. There is “a lot of money on the sidelines,” but most of it is focused on public companies and assets over $100 million.

We believe that over half the oil and gas companies in the US are insolvent. The values of producing properties have decreased by over 80% in the last two years. Many of the transactions will be liquidations of companies. We expect more assets to change hands than in the 1990s.

What’s the Deal?

The answer to the original question is, we will make money by owning income-producing assets. Producing properties are at a value that generates a double digit current yield based on current wellhead prices. Little, if any, value is being paid for future development potential.

We will be using forward sales (“hedges”) to lock in the price of the majority of our production for four years. This ensures that if we are early and prices are lower over the next few years, we will have “locked in” the double digit yield over this period, and be almost certain we have made a profitable investment.

By using hedges, we are giving up the potential to earn superior returns in the short-term. I like this trade. It allows us to accumulate high-quality, long-lived assets, which will earn a very attractive current yield while we wait for an intermediate-term recovery in oil prices which we believe is inevitable.

Good News – Bad News

The US Energy Information Agency (“EIA”) recently announced that production from wells drilled since the start of 2014 made up 48 percent of total US crude oil production in 2015. With the increased use of hydraulically fractured horizontal wells, new production as a percentage of total US production has more than doubled from 22%in 2007, according to the EIA. These are startling facts.

Crude oil production from hydraulically fractured wells now makes up the majority of oil produced in the United States. As of 2015, 51% of crude oil produced in the US came from wells targeting tight oil formations, most significantly the Eagle Ford and Permian Basin in Texas, and the Bakken and Three Forks formations of Montana and North Dakota.

Crude Oil Production

Consider what the combined technologies of hydraulically fracturing and horizontal drilling has meant to our country. Without them, if the average annual rate of US production in 2007 had continued to decline at the same rate it had during the past decade, US average daily production would now be at about 4.3 million barrels of oil per day (“bopd”), rather than 9.4 million as it was in 2015. We would now be importing 75%of our oil supply.

The benefits of increased oil production have been significant. Analysts and politicians agree that decreased reliance on foreign crude in the past few years has allowed the US to be more flexible in its foreign policy and given the US more global heft.

The US is now much less reliant on oil from the Mideast and elsewhere. Think of what that means, not just to our trade-account deficit, but to the reduced necessity of deploying many of our young men and women in the military to protect oil transportation routes.

Literally billions of dollars have poured into the hands of individuals, companies, and state and federal treasuries as a result of new production. Hundreds of thousands of land and mineral owners, many of whom live in areas that previously produced little or no oil or natural gas, now receive monthly royalty checks. That’s the good news.

US Oil Production and Imports

The bad news is that US crude oil production is falling in response to the collapse in oil prices that started in mid-2014. Output is now poised to drop below 9 million bopd—700,000 bopd off its April 2015 peak—and the rate of decline is accelerating, perhaps losing at least another 750,000 bopd by year end, a total drop of 16% in 18 months. That raises all-important questions of how low will US production go, and how much will oil prices need to rise to reverse those declines?

Rig Count by Drilling Direction

Of course, because the decline rate of production from horizontal wells is so high—as much as 90% from year to year—it takes a minimum of about 1,000 active drilling rigs to sustain the current rate of production. However, the total number of active rigs in the United States continues to fall. At the end of March, the number of oil-oriented rigs had fallen to 372, down 15 from the previous week, and down over 1,200 from the recent peak of October 2014. Further reductions are anticipated.

Oil Rigs in Operation

Producers fear they may never again experience the robust oil prices they enjoyed during the 2010-2015 period. The few oil-producing nations with spare production capacities, primarily Saudi Arabia, Iran, Iraq and, to a lesser degree, Russia, have demonstrated that, by maintaining high production levels, they can drive prices lower, and keep them there for extended periods. The effect has been to enable them to maintain their market share, and to make oil from US horizontal drillers non-competitive. For almost all the world’s oil exporters, today’s low prices are unsustainable over the longer term, but today they are successfully damping out aggressive drilling in the US.

At $40 per barrel, and with today’s drilling and completion costs, there are only a few spots in the major US shale plays where it makes economic sense to drill and produce more oil. For there to be a meaningful response from producers, prices must not only be higher than $55 per barrel, but producers must believe that it will stay at that level long enough to recover their investment and make a profit, and hopefully, continue to increase. Even though this is far below the $100 per barrel price of the shale heydays, many producers can make this work, especially if they have undrilled locations on leases held by currently producing wells. Progressively higher prices will bring on additional production. Estimated stable prices of $70 to $80 per barrel are required to put most of the US rig fleet back to work.

The bad news for U.S producers is that shale has so fundamentally changed the oil market that the word “recovery” is no longer relevant. That is because oil prices are now range bound, locked into a bracket which is capped at the high end, and with a floor at the low end. Above $55 per barrel, US production starts to increase, the oil market builds supply, and prices respond by going down. Based on recent experience, a price floor appears to be some number below $35 per barrel.

“Déjà Vu All Over Again” – The Market for Oil and Gas Assets

What a difference a year makes! At this time last year, oil was around $60 per barrel, and we thought we had taken a beating. When oil fell from $85 to $60 per barrel, the present value of the future production fell in half. Little did we know that, in 2015, we would see the wellhead price of oil fall another 50% and the value of producing properties fall even further.

The story was similar for midstream assets (i.e., pipelines). Although most midstream assets are still generating strong earnings, the value of many midstream assets fell by a factor of three or more. The dramatic drop in value occurred as the market began to believe oil prices will not recover significantly and domestic volumes will continue to decline.

We first discussed the likelihood of a decline in oil prices in my article “A Correction in Oil Prices?” in the fourth quarter 2013 issue of The Producer. Due to our concern, we took a defensive position in our investing activity over the last several years. Despite our caution, overall results from investments made during the boom have been disappointing.

The oil and gas industry is in in a devastating down-turn, but our financial condition remains healthy. Five States Energy Capital Fund 1 and Fund 2 have no debt. The managing entities of the various funds are also solvent, and have only operating liabilities. All of our entities remain solvent and have healthy balance sheets.

Our “legacy funds” (Five States Consolidated I, Ltd. Five States Consolidated II, Ltd. and Five States Consolidated III, Ltd. ) generated the majority of the cash distributions investors have been receiving over the last decade. These returns were from investments made primarily in the 1990s, and have already generated over 3:1 returns and an IRR of ~20% over the last 25 years. However, we now need to be cautious and increase the strength of the balance sheets of the legacy funds. We incurred conservative levels of debt over the last cycle to participate in development opportunities on properties owned by those funds. We now believe it is conservative to accelerate paying down our bank lines on these funds. The cash distributions for these funds will be suspended for the next two to four quarters.

Expected results from Five States Energy Capital Fund 1 have deteriorated with the collapse of oil prices. We have stayed within our targeted risk band, which will allow us to operate through the downturn. We now expect Fund 1 will have full capital recovery with a low single digit return over the life of the investment. If prices stay this low for an extended period, we may incur a small loss.

Such forecasts are materially lower than we were estimating a year ago. The biggest negative was the decline in value in our two pipeline assets. Great Northern Midstream was sold this month. While we made a profit, it was not nearly the result we expected a year ago. The decision to sell was primarily driven by the risk of North Dakota Bakken production, the majority of which is not profitable below $60/barrel. The owners of GNM unanimously agreed it was better to recover our capital than to continue to own this risk. This quarter, we are distributing proceeds from the Great Northern sale. After this quarter, Fund 1 distributions will be materially lower

Many in the industry are faring far worse. More than 250,000 jobs have been lost in the energy sector. Most oil and gas companies that had what was considered conservative debt levels in 2014 are now insolvent. More than 40 oil companies filed for bankruptcy protection in 2015. Some analysts are predicting that half the companies in the industry will fail in 2016.

Five States is well positioned to take advantage of the downturn. We plan to pursue acquisition of producing oil and natural gas working interests through the downturn. More than 65% of the capital committed to Five States Energy Capital Fund 2 has not been deployed. We anticipate opening Five States Energy Capital Fund 3 mid-year, as soon as the majority of Fund 2 has been committed to new investments.

Buy Low

I am often asked why we want to buy oil or natural gas properties now if wellhead prices are low and are not expected to recover in the near term. As value investors, we adhere to the old adage, “buy low, sell high.”

The current situation is much like it was when we started Five States in 1985:

Low Wellhead Prices – wellhead prices of crude oil and natural gas are down two-thirds over the last 18 months. When prices are low, there is less room for them to fall.

In order to continue producing the 92 million barrels humanity is consuming each day, new reserves have to be developed. The marginal replacement cost of oil is in the $60 per barrel range. If the price remains below $60, natural depletion will result in declining production, supply will decrease and prices will increase.

 “But what about the Saudis and Iran?” Saudi Arabia, Iran and others have materially lower production costs than the US, Russia or Venezuela. But Middle Eastern producers do not have the capacity to supply world demand alone. Conventional production has peaked. Without renewed development of the more expensive North American production from sources such as shale, world supply will decline.

Although demand growth has plateaued in the US and Western Europe, world demand is continuing to grow. Consumption has not declined. Only the rate of growth has slowed.

Oil prices will recover. The question is when, and how much. We are assuming in our evaluation of new producing properties that prices remain low for four to five years, average in the $50s in the intermediate term and $60+ in the long-term. Through hedges, we will “lock-in” the oil and gas prices on the majority of our new acquisitions for the first four to five years to minimize income volatility as we recover the majority of our investment from the early current income. Hedging will ensure investor payback and a profit if a price recovery takes longer than we forecast.

High Discount Rates – the Cost of Capital for the oil and gas sector is increasing. We believe the discount rate for valuing producing properties is once again in the 9% – 12% range.

During the recent boom, the market underestimated the systematic risk[1] inherent in owning producing properties. Many incorrectly assumed that because new oil and natural gas production from shale is expensive to develop, wellhead prices would not fall below the cost to develop it. Compounding this error, many lenders failed to recognize the increased risk inherent in the higher operating leverage caused by the much greater drilling costs. They continued to loan money using conventional loan to value metrics, which have proven to be too high. Wellhead prices have fallen materially below the capital cost to profitably drill and complete the new unconventional wells. Looking forward, investors will require an additional risk premium in their cost of capital to compensate for this additional risk.

Junk bonds and inflated stock and MLP valuations provided Five States’ competitors with “cheap currency”, allowing them to pay more for oil and gas assets than Five States would as a cash buyer. Public companies and MLPs financed the drilling boom with “cheap debt” or raised cash at inappropriately high stock prices, allowing public companies and MLPs to spend more than true value to develop new reserves.

We recognize that there are “hundreds of billions of dollars waiting on the sidelines.” But the majority of those dollars are with hedge funds and large institutional investors. Many are recognizing their lack of the skill sets necessary to evaluate individual producing properties. With many of the smaller oil and gas companies insolvent, restructuring is not an option. The opportunity for Five States will be to buy real property interests in producing oil and gas properties, a skill many financial firms lack.

Some ask, “How will you get the good deals?” The reality is, there are no “steals”. This is a very competitive market, and it is always competitive. Buying producing properties was as hard in 1998 when oil was below $10 per barrel as it was during the boom. The reason the 1990s acquisitions look so good in hindsight is that we “bought low”. Today, discount rates are much more normal, so new acquisitions are good value and can generate high cash yields at current prices. We can earn a good current yield from owning the production without needing prices to recover to pre-crash levels. This is an excellent scenario for long-term value investors.

We Buy “Oil in Ground”

The majority of the focus in the media is on the spot price of oil. However, we are not buying barrels of oil to sell in all at once. We are buying producing oil and natural gas properties that we will produce over time. There is an inherent return imbedded in owning these assets.

We Get “Paid to Hold”

Financial theory is based on the assumption that money has “time value”; that a dollar in hand today is worth more than a dollar received in the future. It is similar to investing in income producing real estate. If you buy a house for $100,000, make $10,000 a year for five years then sell it for $100,000, you earn a 10% return without the value of the house or the rent increasing. The same concept applies in buying producing oil and gas properties when discount rates are in the double digits.

Greatest Value Investment Opportunity in Decades

We believe the ongoing collapse of the oil and natural gas industry represents the greatest value investment opportunity we have seen in decades. However, prices for future delivery of oil and natural gas are higher than current wellhead prices, reflecting the market expectation of some recovery over the next few years. The collapse in prices might last longer than we expect, so we will use futures contracts (hedges) to mitigate the price risk during the period when we are recovering our capital, “locking in” the price on much of our production during the payback period. That way the majority of our risk will be the rate of return realized, not whether we will recover our capital from the investment.

The upside potential in buying properties at current prices is huge. A recovery to $60 per barrel could easily double or triple the income from and value of producing properties. As prices rise, not only does the price per barrel increase, but total economically recoverable reserves also increase.

Proved Undeveloped Reserves (PUDs) or the “undeveloped locations” on the majority of domestic properties have little net present value at current prices. But if prices recover into the $50 – $60 range, the value of the undeveloped locations on many properties become profitable to develop, adding material value.

As Yogi Berra said, “It’s like déjà vu all over again!” In many ways, this is a repeat of the late 1980s-90s. We can acquire producing properties at attractive values while prices are low. These new investments will generate an attractive current yield at the prices we can currently “lock-in”. While we are enjoying the attractive yield, we can wait for the appreciation that will come with an inevitable price recovery. With values and yields this attractive, it almost does not matter when the price recovery occurs!


What Happened in 2015?

As the oil industry stumbles into 2016, everyone is asking the same questions:

  • Why did oil and natural gas prices fall so far and so fast in 2015?
  • Did anyone see the collapse coming? Did anyone forecast it?
  • Were OPEC or non-OPEC countries or groups to blame? Were individuals?
  • How long will current conditions last? Will prices recover?
  • Could prices go lower from here? Is there a floor?
  • What will happen to my oil and gas investments? Could I lose all my money?
  • What factors would have to change for prices to rise?
  • What’s the long-term outlook for the industry? Is this the time to be selling petroleum interests, standing pat or loading up?

Of course, no one has answers to all the questions, but in this article we will present the facts as we know them and share thoughts about where the future may take us from here.

The most likely explanation of the recent drop in prices was that oil traders suddenly recognized that the world is awash in oil and is likely to remain so for several years. Cited are full-to-overflowing storage tanks in Cushing, Oklahoma, and oil loaded tanker ships idling on oceans and docked in harbors throughout the world, just waiting to offload millions of barrels to refineries and power plants. Price-bears note that oilfields in Iraq were back to producing almost 4.5 million (MM) barrels of oil per day (“bopd”) in November of 2015, and that Iran has resumed production and announced intentions to increase to 3MM bopd in the near future when sanctions are lifted. On a statistical basis, global inventories built by 2.0 MM bopd in the second and third quarters of 2015. These are the largest inventory builds since the fourth quarter of 2008. The EIA forecast that global inventory builds started to decline in the fourth quarter of 2015 to 1.4 MM bopd and will average only 0.6 MM bopd in 2016.

The possibility of a continuing worldwide oil glut is a concern to producers. In previous times, when oil markets became sated, OPEC, led by oil behemoth Saudi Arabia, acted as the world’s swing producer, cutting back production in order to maintain price stability. This time Saudi is showing no indications of slowing production anytime soon, and in fact is working to produce more. They are attempting to regain their market share at the expense of high cost producers, including US shale drillers. US production appears to have peaked in May of 2015 at 9.4 MM bopd.

Everyone is waiting for the other guy to flinch on production. Until someone does, the price of oil is likely to remain low. Although the Saudi production cost is less than $10 per barrel, social welfare programs take the all-in cost to $100 per barrel. The Saudis are beginning to utilize their cash reserves and have even discussed monetizing a part of Saudi Aramco through a public offering.

A second factor influencing prices is investor perception of future supply and demand. Because there are limited substitutes for oil, a relatively small perceived or actual shortage/surplus in the worldwide balance of supply and demand can cause wide price swings. A relatively small quantity of surplus barrels in the system is interpreted by the public as unlimited supply, and prices fall. A few barrels temporarily unavailable for immediate needs can create panic. Markets react as if the world will soon run out of oil, and prices soar. The tail wags the dog: the price of a few barrels can establish the price of millions. The pendulum can and does swing rapidly and widely in both directions.

Little more than a year ago, US producers were on a roll. Wells were being proposed and drilled in record time, production was increasing, and the US was reducing its unfavorable balance of payments gap. In November 2014, oil closed at $91.16. As US storage capacity disappeared and OPEC stood firm on production quotas, prices fell: to $53.27 in December 2014, and further to $34.66 in December 2015, a collapse of 62% in only 13 months.

Oil-bears recognize that US oil producers, through horizontal drilling and multi-stage hydraulic fracturing, have unlocked the secrets of obtaining oil and natural gas from the world’s bountiful shale reservoirs. The bears believe now that the genie is out of the bottle, the world’s oil producers will acquire and utilize them, and oil will no longer be a scarce commodity.

A third factor that may lead to disastrous consequences for many companies is the extensive use of borrowed capital. The disadvantage of America’s high-tech shale-play is its high cost. Competition for prospective oil and gas leases has been frenetic. Drilling and completion expenses are high. In their rush to exploit leases before they expire and to “prove up” as much of their potential reserves as possible, aggressive companies have been drilling as fast as they can, typically borrowing as much as banks and private investors would allow.

Collateral to secure the loans has often been producing assets, hedged by futures contracts purchased to assure deliveries at specified prices. Over time, higher price contracts have been expiring and new contracts are at much lower prices. The result is that many bank loans are now in non-performance status and are likely to be called for repayment in 2016. By some estimates, as many as one-half of existing E&P companies, especially the newer, highly leveraged shale drillers, will be out of business by the end of the year.

Prices may be further weakened by increased usage of renewable energy. But despite the growth over the last few years, wind and solar account for only 2 ½% of US energy supply. Further production and efficiency increases are expected, but most authorities do not believe renewables can or will substantially replace oil and natural gas based transportation fuels within the next decade or so.

Facts for the oil-bulls’ case can be equally persuasive as for the bears’. Oil and natural gas are commodities, and at the fundamental core, prices are ultimately determined by supply and demand. Energy is essential to the economies and well-being of all countries. The more energy one has, or can get and use, the stronger, healthier and more viable is its economy. The US, with only 6% of the world’s population, uses almost 22% of the world’s annual energy production, but is able to generate 22% of world’s nominal economic output. We are an immensely successful nation specifically because we have great natural resources, and have learned to use them effectively.

The world requires about 94 MM bopd. Annual demand is increasing about 1.1%, or 1 MM bopd. Worldwide spare capacity is now only about 2 MM bopd above daily production, down from about 8 MM bopd only a decade ago. The International Energy Agency (IEA) projects that by 2020 the world will need another 6 million bopd, outstripping the spare capacity of OPEC. In other words, demand has been increasing while spare capacity has been decreasing. The decreased margin of safety increases price volatility.

With world population continuing to increase, and with the citizenry of developing countries demanding more goods, services, and access to better transportation, the question is whether enough oil and natural gas will continue to be available to meet future demand. Exxon estimates that global population will grow from 7 billion in 2010 to 9 billion by 2040. Even if the per person consumption of energy stayed the same, energy demand would increase by 28%.

US production of shale oil is currently 4 MM bopd. Unlike production from conventional sandstones and limestone reservoirs, which typically have longer lives and slower decline rates, production from shale reservoirs have steep decline rates (up to 90% in the first year) and shorter lives. The result is that production from shale oil fields must be increased or maintained by continued, active drilling programs. If wells are not being drilled, production declines rapidly.

When oil prices began their decline in November 2014, drillers began taking rigs out of service and laying off employees. From a high of 1,931 working rigs in November of 2014, the number has plummeted to fewer than 700. US shale oil production has already declined by more than 500,000 bopd. Projections are that it will have declined by 1 MM bopd by mid-2016. In other words, without drilling as many or more wells than were drilled in 2014, US production will continue to decline rapidly.

Of course, the real wild card in the supply/demand picture is the possibility of turbulent disruptions in any of the world’s major oil producing areas, particularly in the Middle East or the Former Soviet Union. The loss of sustained production in one or another of those hot spots would immediately and dramatically drive prices skyward. The effects of such disruptions are to no country’s best interest, but it is not out of the realm of speculation.

For the present, we at Five States believe that opportunities to acquire quality producing properties may soon be among the best in our careers. A recent article in the Dallas Morning News cited a prediction that half the oil companies now in business would declare bankruptcy and/or go out of business in 2016. Many of their assets and producing properties will be sold at prices much below their value at year-end 2014.

Beyond the Storm, Bright Horizons

Over the last five years, oil production in the US increased by over 4.5 million barrels of oil per day (“bopd”) to almost 10 million bopd.  The US now rivals Saudi Arabia for the position of largest oil producer in the world.  This 4.5 million bopd increase is about a 5% increase in world supply.  Increased world supply combined with slowing demand due to the worldwide economic slowdown resulted in a collapse in the price of oil.

Oil Price and US Production Volume

Crude oil prices have basically fallen in half over the last twelve months.  This translates to a decrease in Operating Cash Profit[1] for most producing properties in the US of 65% to 85%.  If low prices are assumed to continue into the future calculated present value of producing properties have fallen by a comparable magnitude.

Declining Operating Margin Per Barrel

The majority of the new oil production is from shale formations.  Shale production (both for oil and natural gas) differs from conventional production in two ways.  The cost to drill and complete shale wells per barrel of oil or per MMBtu[2] of natural gas recovered is much higher.  The higher capital cost per well requires an oil price of $40 to $60+ per barrel or a natural gas price of $3 to $5 per MMBtu to generate a profit on a new well.

The second difference is that production from shales and very low permeability reservoirs has a different decline profile than production from conventional sand and carbonate reservoirs.  Shale wells produce half the volume they will ever produce in about 18 to 24 months, compared to about five years for more conventional wells.  If shale development ceased, the 4.5 million bopd of new oil production developed in the US in the last five years would fall in half in less than two years.  The extraction/development process must be continuous.  Otherwise, production will rapidly decline.

There is an old adage in the oil industry.  Low prices are the cure for low prices.  Oil selling at +/-$45/bbl and natural gas at +/-$2.50/MMBtu are lower than the average long-term replacement cost.  As new shale production depletes, prices will recover.  We estimate that oil prices must be $65+/bbl and natural gas prices must be $4.00+/MMBtu over the intermediate term to maintain current production levels in the US.

We do not know when prices will begin to recover.  It may be as early as later this year, or it may take two to four years.  Because of the rapid decline rate of the new US production, we do not believe it will take over five years for a recovery in oil prices.  Natural gas could take longer.

The Oil and Gas Industry

The collapse in oil prices has resulted in a material slow-down in drilling and development.  This slow-down is already resulting in a decline in domestic production.  It is also resulting in a dismantling of the infrastructure to develop new production, particularly in the drilling and completion sector.

US Crude Oil Production and Rigs

The decline in Operating Cash Profit is having a devastating impact on the financial condition of many independent producers.  Many companies that had a debt level that was considered “bank prime” this time last year are now insolvent.  Others that have debt but are still solvent are severely constrained in their operating and development activities.

Many companies will require major restructuring.  Some will fail and their assets will be liquidated.  Some companies with a “healthy balance sheet” will sell mature producing assets to free up cash for their higher return development projects.

Transaction activity in the oil and gas industry was at the lowest level in a decade in 2015.  However, we have seen more high quality, long-lived, fully developed conventional producing properties (the type we seek) for sale this year than in a long time.  These have mostly been large packages being sold by public companies.  These assets are mature and have limited additional drilling potential.  When money was easy and cheap, public companies were holding these assets to maintain reserves and earn the spread between their low interest rates and the return from owning production.  But with capital tight, public companies no longer want to hold these long-lived annuities. They want to free up their capital for growth investments.

The tsunami of oil and gas properties we expect to result from the insolvent companies has not yet hit the market.  Earlier in the year, many were hoping things would get better soon.  The expectation was that oil prices would settle at around $60+ per barrel.  At that level the damage was not nearly as severe, and many could have worked their way out through restructuring.

Many producers had hedges that locked in higher prices through 2015.  As we approach the end of 2015 most of these hedges have settled and these companies and their creditors are facing the prospect of $45 per barrel oil in 2016.

Note in the chart above that most properties generate Operating Cash Profit at $45/bbl even though they are insolvent.  Insolvent producers still have cash flow, but are selling their reserves at a price that will not fully repay their debt.

We expected to see a lot more properties for sale in 2015.  But insolvent operators have every reason to delay.  Sale or liquidation today results in nothing to the insolvent operator. If operations continue, everyone still gets another paycheck and hope that things will get better.

Lenders are trying to defer the realization of losses.  Perhaps bonuses are calculated on the year end value of the portfolio.  Or perhaps the objective is to raise a new fund before fully reporting the decline in the old fund.  I suspect some do not yet recognize the degree of damage to their portfolios.  “Word on the street” is that regulators and auditors will be “turning up the heat” at the end of the year.  It is the typical “kick the can” mentality in a real property downturn.

The consensus in the industry is that this is a cyclical downturn.  Prices are expected to correct over time and development of shale reserves is expected to resume.

Five States

Five States is not immune to this downturn.  Our Operating Cash Profit from producing properties is down commensurate with the industry.

We remain in a healthy financial condition.  Our debt level on our legacy funds (Consolidated I, II and III) is very low compared to the industry norm.  The Energy Capital Funds have no debt.  We also have a higher percentage of hedges and our hedges are over a longer period, than most independents.  These two differences have provided us greater financial strength than many to weather this downturn.

The legacy partnerships remain cash flow positive and bank compliant.   We are accelerating the rate of bank principal pay-down for the legacy partnerships in case prices drop further in 2016 or 2017.

Few of the development opportunities for our producing properties are profitable at $45 oil.  We sold what we considered our weakest Bakken properties in Consolidated I last year.  There are a very large number of Bakken development opportunities which we expect will be developed when oil prices warrant.  We were planning to do significant development on the SE Adair in Consolidated III.  We believe that oil prices need to be in the $60/bbl range to support Bakken development and the SE Adair redevelopment.

Five States Consolidated I, II & III have returned multiples on the money invested in cash distributions, and they still have residual value.  These partnerships contain good quality, long-life producing assets that are profitable at current prices.

Five States Energy Capital Fund 1 is fully invested and has no debt.    The decline in oil and gas Operating Cash Profit has been offset by increased income from its midstream investments.  All of the producing properties are cash flow positive at current prices.  We have profitably “harvested” some of the portfolio.  We recognized major loss reserves against our materially underperforming investments at year-end last year.

The midstream investments (e.g., pipelines) are earning record profits.  We expect volumes to decrease and competition to increase over the next several years.  The range of possible outcomes is much wider than we anticipated a year ago.

Five States Energy Capital Fund 2 has made two investments.  Approximately 70% of the fund capital is undeployed.  We expect to invest the majority of the undeployed capital in production acquisitions and production financing in which the fund will earn a double digit current return and a participation in the assets financed.

Capitalizing on the Downturn

We are seeing more conventional producing properties on the market than we have in a long time.   The economics on which assets are being valued reflect current lower oil and natural gas prices.  The discount rates on which properties are being valued appear to be increasing, returning to historical norms that we consider appropriate valuations.

The investment thesis is:

  • Value production based on these low oil & gas prices
  • Lock in the oil and gas price on the production for 3 to 5 years
  • Use a low level of debt in the acquisition – less than 40% of the purchase price

This structure should generate a good current return from the day the investment is made.  The combination of large hedges and low debt levels result in a high certainty of payback even if prices do not increase.

We cannot call the timing, but the fundamentals are clear.  We are in the buying part of the investment cycle.  Wellhead prices are down, and there is fear in the oil and gas market.  This is very much like the first two decades of Five States.  We believe this is “the best of times” for long term value investors. 


[1] Operating Cash Profit is Net Revenue less Operating Expenses and Property Level Taxes.  It does not include recovery of the capital investment to drill and complete the well.

Riding the Cycles

No one needs to inform west Texas citizens that the oil and natural gas industry is currently in a slump. All one has to do is drive from Midland to Odessa and count the number of drilling rigs standing idle in storage yards, or pick up a copy of Midland’s The Daily Observer to read about oilfield layoffs, diminished company profits, and numerous mergers and acquisitions.

Anyone who has lived in the Permian Basin for more than a decade has experienced the effects of major downturns. Old-timers who can remember the days in the 1950s and 1960s when $3 per barrel oil and 18¢ per MCF natural gas were the norm have lived through five major price collapses. Most of us who have been around the business for any length of time have learned to accept periodic industry retrenchments as normal, and have developed something of a bunker mentality about dealing with them.

Cyclical downturns can actually be the “Best of Times” or the “Worst of Times” for oilmen and their investors. They are created when oil and natural gas prices decline rapidly, usually unexpectedly, and remain low for an extended period. The first major decline since $3 oil started its upward run in 1973 occurred in 1985, when the benchmark price of a barrel of West Texas Intermediate crude oil dropped 62.4%, from $30.81 to $11.57. The resulting jolt was sufficient to create havoc in the oil fields, bankrupt companies, and ultimately contribute to toppling major banks in Dallas, Houston, Oklahoma City, Denver, Chicago and elsewhere that carried large positions of oil and gas debt in their loan portfolios.

Five States was chartered in 1985 in the midst of the wrenching price decline of that year. As prices withered, banks initially began calling in oil loans of borrowers who were in default on debt covenants. Within months, as their debt to asset ratios continued to worsen, the banks began calling in loans from their “good” customers who were still current with scheduled repayments and still compliant on their covenants. Some of these borrowers, unable to raise funds from alternative sources, lost their properties and sometimes their companies in the melee.

Billions of dollars of oil and gas equipment, producing properties, royalties and minerals, oil field service companies and operating companies were thrown on the market, available to anyone who had enough money and courage to bid on them. For some individuals, it was the end of the line. For others it was the beginning.

In such times, the difference between losing a company or starting one is often the availability of or access to capital. Although Five States had only modest assets and a small bank account at the time, we had the experience to recognize that good value properties were on the bargain table. We also had little overhead and no debt. The only missing ingredient was cash. We began knocking on doors as far from the oil patch as possible, hoping to find investors who would listen to our story. A few did, most noteably fee-only financial advisors.  Five States’ upward cycle had begun.

Although oil prices began to recover the following year, it took more than a decade for confidence in the industry to be fully restored, for new banks and capital sources to become well established, the glut of producing properties to finally be settled in new hands.

For most young companies, and those aspiring to grow rapidly through acquisitions and the drill bit, institutional capital and bank debt are essential elements in their development. Serious problems can and do arise when, in the flurry of their activity and achievement, a drop in commodity prices slashes revenue, debt becomes unmanageable, and the companies fail.

In recent years, the commodities futures markets have come to be utilized much more widely and effectively to lock in forward prices, protect collateral and reduce risks of commodity losses. Even so, companies who carry high debt loads, especially over longer periods, always face the possibility of catastrophic losses.

Five States has always been a conservative player. Our focus on investing in long-life legacy oil properties that generate strong operating margins provides us a stable financial foundation.  With excellent financial partners willing to provide capital when needed, a knowledgeable and experienced staff, relatively low debt ratios, an envious track record, and a reputation for competence and integrity, we believe that we are again moving into a new cycle of attractive acquisitions, growth and success.

Change in The Oil Industry and the Impact on Five States

The Oil Market

Over the last five years, oil production in the US increased by over 4.5 million barrels of oil per day (“bopd”) to almost 10 million bopd. The US now rivals Saudi Arabia for the position of largest oil producer in the world.  This 4.5 million bopd increase is about a 5% increase in world supply.  Increased world supply combined with slowing demand due to the worldwide economic slowdown resulted in a collapse in the price of oil.

Crude oil prices have basically fallen in half over the last twelve months. This translates to a decrease in Operating Cash Profit for most producing properties in the US of 65% to 85%.  If low prices are assumed to continue into the future calculated present value of producing properties have fallen by a comparable magnitude. Operating Cash Profit is Net Revenue less Operating Expenses and Property Level Taxes. It does not include recovery of the capital investment to drill and complete the well.

The majority of the new oil production is from shale formations. Shale production (both for oil and natural gas) differs from conventional production in two ways.  The cost to drill and complete shale wells per barrel of oil or per MMBtu of natural gas recovered is much higher.  The higher capital cost per well requires an oil price of $40 to $60+ per barrel or a natural gas price of $3 to $5 per MMBtu to generate a profit on a new well.

The second difference is that production from shales and very low permeability reservoirs has a different decline profile than production from conventional sand and carbonate reservoirs. Shale wells produce half the volume they will ever produce in about 18 to 24 months, compared to about five years for more conventional wells.  If shale development ceased, the 4.5 million bopd of new oil production developed in the US in the last five years would fall in half in less than two years.  The extraction/development process must be continuous.  Otherwise, production will rapidly decline.

There is an old adage in the oil industry. Low prices are the cure for low prices.  Oil selling at +/-$45/bbl and natural gas at +/-$2.50/MMBtu are lower than the average long-term replacement cost. As new shale production depletes, prices will recover.  We estimate that oil prices must be $65+/bbl and natural gas prices must be $4.00+/MMBtu over the intermediate term to maintain current production levels in the US.

We do not know when prices will begin to recover. It may be as early as later this year, or it may take two to four years.  Because of the rapid decline rate of the new US production, we do not believe it will take over five years for a recovery in oil prices.  Natural gas could take longer.

The Oil and Gas Industry

The collapse in oil prices has resulted in a material slow-down in drilling and development. This slow-down is already resulting in a decline in domestic production.  It is also resulting in a dismantling of the infrastructure to develop new production, particularly in the drilling and completion sector.

The decline in Operating Cash Profit is having a devastating impact on the financial condition of many independent producers. Many companies that had a debt level that was considered “bank prime” this time last year are now insolvent.  Others that have debt but are still solvent are severely constrained in their operating and development activities.

Many companies will require major restructuring. Some will fail and their assets will be liquidated.  Some companies with a “healthy balance sheet” will sell mature producing assets to free up cash for their higher return development projects.

Transaction activity in the oil and gas industry was at the lowest level in a decade in 2015. However, we have seen more high quality, long-lived, fully developed conventional producing properties (the type we seek) for sale this year than in a long time. These have mostly been large packages being sold by public companies.  These assets are mature and have limited additional drilling potential.  When money was easy and cheap, public companies were holding these assets to maintain reserves and earn the spread between their low interest rates and the return from owning production.  But with capital tight, public companies no longer want to hold these long-lived annuities. They want to free up their capital for growth investments.

The tsunami of oil and gas properties we expect to result from the insolvent companies has not yet hit the market. Earlier in the year, many were hoping things would get better soon.  The expectation was that oil prices would settle at around $60+ per barrel.  At that level the damage was not nearly as severe, and many could have worked their way out through restructuring.

Many producers had hedges that locked in higher prices through 2015. As we approach the end of 2015 most of these hedges have settled and these companies and their creditors are facing the prospect of $45 per barrel oil in 2016.

Note in the chart above that most properties generate Operating Cash Profit at $45/bbl even though they are insolvent. Insolvent producers still have cash flow, but are selling their reserves at a price that will not fully repay their debt.

We expected to see a lot more properties for sale in 2015. But insolvent operators have every reason to delay.  Sale or liquidation today results in nothing to the insolvent operator. If operations continue, everyone still gets another paycheck and hope that things will get better.

Lenders are trying to defer the realization of losses. Perhaps bonuses are calculated on the year end value of the portfolio.  Or perhaps the objective is to raise a new fund before fully reporting the decline in the old fund.  I suspect some do not yet recognize the degree of damage to their portfolios.  “Word on the street” is that regulators and auditors will be “turning up the heat” at the end of the year.  It is the typical “kick the can” mentality in a real property downturn.

The consensus in the industry is that this is a cyclical downturn. Prices are expected to correct over time and development of shale reserves is expected to resume.

Five States

Five States is not immune to this downturn. Our Operating Cash Profit from producing properties is down commensurate with the industry.

We remain in a healthy financial condition. Our debt level on our legacy funds (Consolidated I, II and III) is very low compared to the industry norm.  The Energy Capital Funds have no debt.  We also have a higher percentage of hedges and our hedges are over a longer period, than most independents.  These two differences have provided us greater financial strength than many to weather this downturn.

The legacy partnerships remain cash flow positive and bank compliant.   We are accelerating the rate of bank principal pay-down for the legacy partnerships in case prices drop further in 2016 or 2017.

Few of the development opportunities for our producing properties are profitable at $45 oil. We sold what we considered our weakest Bakken properties in Consolidated I last year.  There are a very large number of Bakken development opportunities which we expect will be developed when oil prices warrant.  We were planning to do significant development on the SE Adair in Consolidated III.  We believe that oil prices need to be in the $60/bbl range to support Bakken development and the SE Adair redevelopment.

Five States Consolidated I, II & III have returned multiples on the money invested in cash distributions, and they still have residual value. These partnerships contain good quality, long-life producing assets that are profitable at current prices. Five States Energy Capital Fund 1 is fully invested and has no debt.   The decline in oil and gas Operating Cash Profit has been offset by increased income from its midstream investments.  All of the producing properties are cash flow positive at current prices.  We have profitably “harvested” some of the portfolio.  We recognized major loss reserves against our materially underperforming investments at year-end last year.

The midstream investments (e.g., pipelines) are earning record profits. We expect volumes to decrease and competition to increase over the next several years.  The range of possible outcomes is much wider than we anticipated a year ago.

Five States Energy Capital Fund 2 has made two investments. Approximately 70% of the fund capital is undeployed.  We expect to invest the majority of the undeployed capital in production acquisitions and production financing in which the fund will earn a double digit current return and a participation in the assets financed.

Capitalizing on the Downturn

We are seeing more conventional producing properties on the market than we have in a long time.   The economics on which assets are being valued reflect current lower oil and natural gas prices.  The discount rates on which properties are being valued appear to be increasing, returning to historical norms that we consider appropriate valuations.

The investment thesis is:

  • Value production based on these low oil & gas prices
  • Lock in the oil and gas price on the production for 3 to 5 years
  • Use a low level of debt in the acquisition – less than 40% of the purchase price

This structure should generate a good current return from the day the investment is made. The combination of large hedges and low debt levels result in a high certainty of payback even if prices do not increase.

We cannot call the timing, but the fundamentals are clear. We are in the buying part of the investment cycle.  Wellhead prices are down, and there is fear in the oil and gas market.  This is very much like the first two decades of Five States.  We believe this is “the best of times” for long term value investors.

How Do We Know?

Our most frequently asked question the last several months can be summarized as “How Do We Know?” Some specific questions are, “How do we know:

  • When oil prices have bottomed?
  • When it is time to buy?
  • When the banks will force their non-compliant or insolvent borrowers to sell?
  • When it is time to “back up the truck” and buy “everything”?

We do not know the answers to these questions . . . we never do. We depend on the market to tell us when to close on individual transactions. As value investors, we know it is time to close on an individual transaction when it is priced at a level that we believe will generate our targeted rate of return.

I often state that we are “Benjamin Graham investors in oil and gas.” Graham is considered by many to be the “father of value investing”[1]. Graham’s thesis was that by performing fundamental analysis of the financial condition and financial performance of companies you can determine their true value. He believed that fundamental analysis differentiates investing from speculation. He posed that through fundamental analysis one can calculate the true value of a stock, and should only buy a stock at that calculated price or a lower price. Conversely, when a stock trades above its true value, one should sell.

As value investors in oil and gas assets, we perform a fundamental valuation of every asset we consider, using a process similar to that described by Graham. However, we use additional metrics that are unique to the oil and gas industry.

When buying producing oil and gas properties, we start with a list of what type of properties we want to own. This eliminates the need to perform superfluous work analyzing assets we do not want as part of our portfolio. We primarily target properties that have:

  • Long-lived reserves,
  • A high Proved Developed Producing (“PDP”) component in the valuation. We want the Proved Developed already Producing to be large compared to the potential production from additional development,
  • On-shore production,
  • Permian/Delaware Basin & Midcontinent production. This includes almost everything between the Rockies and the Mississippi River,
  • Solution-gas drive reservoirs,
  • Low lifting costs, and
  • Locations in the United States (no Canadian or Mexican assets).

We avoid projects with a high debt component in the capital structure. We are investing in a high operating leverage industry. It does not lend itself to high financial leverage.

In our analysis, we attempt to forecast the range of earnings an oil or gas property can generate in the future, much like a fundamental analyst tries to forecast the future earnings of a company. We also attempt to calculate likely outcomes under a range of scenarios and the probability of those outcomes. Scenarios include lower oil and gas prices, varying production levels and other variables discussed in this article. We calculate the price we are willing to pay based on our target rate of return applied to the forecast income. We avoid investments in which our analysis calculates that, in the low case, we can lose the majority or all of our invested capital.

Valuation Process

Future Production Volumes

The valuation of a producing property begins with a forecast of future production volumes. This forecast is based on historical rates of production which decline over time. Other data such as producing rate versus cumulative production help estimate the remaining reserves, as do measurements of bottom hole pressure and comparisons to nearby analogous well histories. The following is an example of the production curve of a property. The “squiggly” part of the graph is the actual production from the past. The smooth line on the right is the forecast future production.

Olivia Marie 32-5H

Revenue

We use the forecast future production to calculate estimates of future revenue. We typically use the New York Mercantile Exchange (“NYMEX”) futures prices for West Texas Intermediate (“WTI”) crude oil to calculate the estimated revenue for oil produced each month in the future. For example, on July 27, 2015 the price for a barrel of oil sold in Cushing, OK in September 2015 was $47.39. The price for a barrel of oil to be sold in August 2016 was $53.17, and so on. We typically use the 48th month’s price as the estimated price for all months after the 48th month.

Crude Oil Futures

Differentials

The term “differential” refers to the difference between the reference price (i.e., WTI) and a regional price (e.g., Williston, Midland, etc.). Bottlenecks in the transportation system and differences in quality account for the variance between prices. The Bakken has historically experienced a wide differential due to the lack of infrastructure and high production volume.

Revenue forecasts are adjusted for the impact of field differentials. Differentials change over time, so understanding the impact of this potential volatility is another variable in our valuation equation. We receive a “field price” for our production at the wellhead that may be higher or lower than WTI. This results in basis differential risk that we are usually unable to control or mitigate.

Differentials Map

Source: Coquest Daily Report 7/28/2015

Hedging

Using the NYMEX contracts described above, when we buy a producing property we hedge a portion of the production for the next three to five years. The hedge is an actual physical forward sales contract for delivery of 1,000 barrels of WTI delivered to Cushing, OK on the expiration date. Using hedges reduce the price volatility risk in new investments.

Operating Expenses

Producing properties have several categories of operating expenses. Fixed costs include lease overhead and pumpers (i.e., field employees). Variable costs include electricity/fuel, subsurface maintenance and repair, surface equipment and repair, wastewater disposal, and production taxes. In the single well example below, fixed annual operating costs total $36,000 per year. Variable costs total $30 per barrel. These costs as well as severance and ad valorem taxes are subtracted from revenue to give us the property level cash flow. As illustrated below, the economic limit of the property is the point where property level cash flow is negative. At this point, the well should be shut in and possibly plugged and abandoned.

Economic limit of a property

Value

We calculate the value of a producing property by applying an appropriate discount rate to the expected cash flow to calculate. This is the net present value of the projected future production. At this point we have estimated value of the PDP portion of the property.

In many cases, there are believed to be proved undeveloped reserves[2] on the property (i.e., PUD or Proved Undeveloped). Depending on the risk in developing this potential, we may attribute some value to these undeveloped reserves. We estimate the timing and capital costs to develop the new reserves. Then, we calculate the expected cash flow and net present value as we did with the PDP reserves. But these reserves are less certain, so we then “risk” the calculated present value by reducing it by as little as 20% or as much as 90%. We then add the risk adjusted valuation of the undeveloped reserves to the valuation of the PDP to calculate the value of the property.  If we believe we can buy the property at this price, we should achieve our risk adjusted return if the base case scenario proves to be reality. This is how the market tells us when to buy.

Contract Closing

If we are successful in identifying an asset that meets our valuation parameters we will attempt to get it under contract. We will structure our investments in direct purchases, preferred or “mezzanine” investments or high interest rate loans on any of these types of assets.

We then enter into the closing process. This includes review of the leases (title review), review of all existing contracts and operating agreements, physical inspections and any other documentation related to the structure of the deal.

Various Oil & Gas Segments

The previous example was for the purchase of producing properties. We actively pursue investments in four basic subsets of the oil and gas industry:

  • Oil Properties– properties that primarily produce crude oil
  • Gas Properties – properties that primarily produce natural gas
  • Midstream – assets such as pipelines, storage, and processing facilities
  • Service – well workover and maintenance, waste disposal & transportation other than pipeline

We invest in direct purchases, preferred or “mezzanine” investments or high interest rate loans on any of these types of assets. Investments in assets other than producing properties are based on underlying production fundamentals. We perform a valuation analysis on midstream and service assets similar to what we do on producing properties. The economic life in midstream and service assets is a function of the economic life of the underlying production they service, so much of the skill set required to perform this analysis overlaps with production assets. The legal and contract work is also related.

Conclusion

I often joke that investing in oil and gas is like riding a roller coaster blindfolded. You cannot really see where you are going, but you know there will be big highs and lows, and as long as you do not get thrown out of the car you will have a great ride. The inherent returns in oil and gas are high, due to a large part because of the volatility. Over the last thirty years we have “had a great ride” being well compensated for accepting volatility of the ride. We avoid “getting thrown out of the car” by managing our risks. We use our fundamental analysis to determine the appropriate levels of debt and non-producing exposure as we make new investments. As long as we avoid too much debt and too much exposure to non-producing assets we can structure our portfolio to generate positive cash flow through the inevitable downturns, and be positioned to profit in the upturns.

We are also asked what area we like today: oil, natural gas or midstream? Right now I like gas. But that tends to have little to do with what we will actually buy. Opinion is not the driver. By sticking to our disciplined fundamental analysis, the market tells us which sector is being priced the most attractively on a risk/reward basis. The market will also tell us when not to buy.

Some are surprised that we have not made many new investments since the price crash at the end of last year. It takes time for those incurring huge losses to process changes of this magnitude, something akin to the five stages of grief.[3] Late last year the mentality was denial and anger, with the consensus that “this cannot be happening and it cannot last.” By the late first quarter we saw many bargaining for the terms and pricing they believed were available before the crash, hoping that they could somehow turn back the clock. We are now beginning to see depression and acceptance, which is translating into acceptance by sellers and others seeking capital of the new reality.

We believe this is an excellent time for making new investments in oil and gas. We are in the low end of the cycle, and long-term upside potential exists. This is probably the best oil and gas investment market we have seen in over a decade. Downturns are always the best investing environment for value investors like Five States.

As discussed in my Producer article last quarter, pretty much every independent in the industry that was using 50% debt in their capital structure is in a difficult position. Debt levels in the oil and gas industry reached all-time highs before the crash.  The need for capital to restructure the excessive debt will be great over the next few years. We are well positioned to provide that capital to private independents. We do not know when the bottom will occur, or which segments will be the best. But by sticking to our disciplined value investing methodology, we expect to continue to make solid investments during the current trough of our industry’s roller coaster ride that will justly reward our investors for the risks taken.


[1] “Benjamin Graham.” Wikipedia: The Free Encyclopedia. Wikimedia Foundation, Inc. 27 June 2015. Web. 5 August 2015. https://en.wikipedia.org/wiki/Benjamin_Graham.

[2] Proved Non-Producing (‘PDNP”) or Proved Undeveloped (“PUD”) reserves.

30-Year Anniversary Events

Five States is celebrating our 30th year in business! We gratefully acknowledge the confidence and support of the many financial advisors, investors, business associates, employees, and friends who have been a part of our success and growth through the years.

Many of the company’s current activities are “business as usual”: reviewing investment submittals, analyzing and evaluating prospective projects, making lease inspections, and visiting construction and development sites. This year we are making special efforts to initiate new industry contacts, strengthen existing relationships with current investors and advisors, increase our visibility by sponsoring more industry events, and provide opportunities for staff members to be featured speakers at professional and trade association meetings.

To that end, Five States recently hosted a three-day investor field trip to Midland. Fourteen individuals attended, including five from Five States and nine guests representing seven investment groups from around the country.

A brief reception at the Doubletree Hilton kicked off the first evening, followed by dinner at the nearby Wall Street Café. On the morning of the second day, an orientation at the Permian Basin Petroleum Museum introduced the group to the Permian Basin’s geology and oil industry history. Everyone had the opportunity for up-close inspections of a drilling rig, pumping units, and other types of production equipment.

Following lunch, the group visited facilities of the Advantage Pipeline System, an 87-mile pipeline from Pecos to Crane, Texas, in which Five States’ Fund 1 has a substantial investment. The facility includes oil truck off-loading facilities, storage tanks, and pipeline pump stations. The Advantage Pipeline System currently gathers and transports more than 70,000 barrels of oil per day, delivering them into the Longhorn System that moves oil from West Texas to refineries on the Texas Gulf coast.

That evening, Five States hosted a celebratory anniversary reception at the Petroleum Club of Midland for our guests, as well as many of Midland’s independent oil men and women. Investors had a great opportunity to meet with and ask questions of knowledgeable and experienced professionals.

After breakfast on the third day, we visited a rail terminal which handles tank cars transporting oil produced nearby, as well as open-top rail cars that bring in frac sand used in wells to hydraulically fracture dense, oil-bearing rock formations. Guests expressed appreciation for the visit and said that they had learned much about field operations during their brief time in Midland.

Five States will continue to work throughout this year to expand our network of business associates and to uncover opportunities that can provide lucrative results to our investors in the months and years ahead.

Capital Rationing

Last quarter my article in The Producer focused on Cost of Capital. This quarter I will address the impact of Capital Rationing on the market for direct oil and gas investments. Capital Rationing is a reflection of limited capital in an industry segment. Following the collapse in crude oil prices, capital in the oil and gas sector is now more disciplined, providing a greatly improved investment environment for Five States.

Cost of Capital is the price, expressed as a percentage that a company must pay for capital. Think of it as a weighted-average of the cost of debt and equity. For example, if debt costs 4% and equity 10%, and the optimal mix was 60% debt and 40% equity, then the Cost of Capital would be 6.4% (i.e., 4% * 60% + 10% * 40% = 6.4%).

This percentage is then used to value new investments. Financial theory assumes that a company will undertake any investment that will generate a risk-adjusted return greater than its Cost of Capital. Capital Market Theory assumes that companies that follow this discipline can raise unlimited capital (one of several unrealistic assumptions).

Most of the time though, there are limits on the capital available to a company. Capital Rationing is a term used to describe when companies are subject to this limiting factor. Capital Rationing is defined as “the act of placing restrictions on the amount of new investments or projects undertaken by a company . . . by imposing a higher cost of capital for investment consideration or by setting a ceiling on the specific sections of the budget.”1

Capital Rationing in the Oil and Gas Industry

Oil and gas companies have historically been subject to Capital Rationing. The oil and gas industry is extremely capital intensive. Most companies invest more capital on an ongoing basis than they generate from operations. This also applies to the industry as a whole. Most years the industry consumes more capital for new development than it generates in oil and gas income.

The additional funding is made up by the capital markets through bank loans, bond sales, stock sales or by direct investments in individual projects. Rarely does the industry have access to enough capital to fund all of the possible exploration and development projects. Companies have to prioritize, resulting in the less attractive projects not getting done.

Since the “Great Recession,” Capital Rationing has not been the norm for the oil and gas industry. The lust for income-producing assets, combined with the notion that the oil and gas business was no longer risky due to the statistical certainty of success in most shale plays, led to a huge increase in capital available to the industry.

Over the last eight years, total debt in the oil and gas sector has increased materially. Since 2002, total corporate bonds outstanding has increased over fourfold.

Debt and Leverage Increase in Energy Sector

 Debt and Leverage in Energy Sector

There has also been significant growth in bank loans to oil companies with $1.6 trillion in syndicated loans as of 2014, up from $600 billion in 2006. (BIS Quarterly Review, March 2015). Total capital raised by the major oil and gas private equity funds has increased over tenfold, from $3 billion in 2001 to over $30 billion in 2014.

 Energy Private Equity Fund Growth: 2001-2004

Energy Private Equity Fund Growth

Source:  Sage Road Capital presentation to IPAA Private Capital Conference, January 2015

In addition to the growth in debt outstanding and private equity capital growth is record stock issuance by upstream producers in Q1 2015 amounting to $10.8 billion.

 Upstream Equity Issuances by Quarter
($ in billions)

Upstream Equity Issuances by Quarter

 

Source: Tudor Pickering Holt & Co. presentation at DUG Bakken/Niobrara, April 2015

The confidence during the recent investment frenzy was fueled by the belief by many that oil prices could not fall below a certain level. The rationale of some was that the Middle Eastern sheiks needed a certain wellhead price to support their populace. Others reasoned that since the new North American oil plays were so expensive, prices had to stay at a level that made those projects profitable. But none of this has proven correct. Only two factors determine the daily wellhead price of oil: supply and demand. The oil supply increased and oil demand growth slowed.

Higher prices over the last decade stimulated the development of new oil supply. During this same period, worldwide economic expansion slowed. The difference between a tight oil supply, which results in high prices, and a surplus, which causes prices to tumble, is only a few percentage points.

Many companies are now in a debt or liquidity squeeze. Debt levels that just a year ago looked conservative are now proving to be too much. The following is an example of the “meltdown” of the financial condition of a hypothetical oil company.

Prior to the decline in oil prices, the hypothetical company on the following page looked healthy:

Operating Statement
Revenue (net of differentials & Severance Taxes) $85 100%
Lease Operating Expenses & Overhead 29 34%
Operating Profit     $56 66%
Interest Expense assuming line fully drawn 4% 7 9%
Cash Flow from Operations minus Interest Expense $49 57%
   
Operating Profit Margin (Operating Profit/Revenue) 66%
Interest Coverage 7.6 x
Value as multiple of Operating Profit 5.5 x $308  
         
Senior Borrowing Base        
Max Loan Amount based on an Advance Rate of 60% $185  
Capital Structure
Senior Debt $185 60%
  Mezz Needed      0    0%
  Total Debt $185 60%
Equity     $123 40%
Total Assets $308 100%

Operating profit was 66% of revenue and debt was 60% of Total Asset Value. This resulted in strong coverage ratios. But over the last year, the decline in oil prices resulted in the following changes:

  • Oil Price declined from $85 to $55, a decline of 35%. So Revenue declined 35%.
  • Lease Operating Expenses and Overhead remained constant at $29.
    • Therefore, Operating Profit declined 54%. The decline in Operating Profit is 50% greater than the decline in oil prices and revenue.
  • Asset Value is estimated at 5.5 times Operating Profit. Asset Value decreased by 54%, the same as the decline in Operating Profit.
  • Borrowing Base remains 60% of Asset Value. But since Operating Profit and Asset Value decreased by 54%, the Borrowing Base will decline by 54%.

When expressed in dollars rather than percentages, the negative impact of the financial leverage is devastating. (See table below). The Borrowing Base has declined from $185 to $86, a decrease of $99. The value of Total Assets has declined from $308 to $143, a decrease of $165. The outstanding debt of $185 is now greater than the revised Value of $143. This hypothetical company is now bankrupt.

Before the decline in Oil Prices Redetermination after the decline in Oil Prices % Change
New Price Change
Operating Statement
Revenue (net of differentials & Severance Taxes) $85 $55 ($30) -35%
Lease Operating Expenses & Overhead 29 29    
Operating Profit     $56 $26 ($30) -54%
Interest Expense assuming line fully drawn 4% 7 7  
Cash Flow from Operations minus Interest Expense $49 $19 ($30) -62%
     
Operating Profit Margin (Operating Profit/Revenue) 66% 47% -28%
Interest Coverage 7.6 x 3.5 x -54%
Value as multiple of Operating Profit 5.5 x $308 $143 ($165) -54%
             
Senior Borrowing Base            
Max Loan Amount based on an Advance Rate of 60% $185 $86 ($99) -54%
Capital Structure
Senior Debt $185 $185
Equity (Deficit)     $123 ($42) ($165) -134%
Total Assets $308 $143 ($165) -54%

 

If the company has hedges, the hedges might keep the company afloat for a year or two. But the impact is clear. If prices remain at this level, companies that had debt levels considered normal a year ago will have problems. Those that are not bankrupt become non-conforming or non-complying with their loan covenants, resulting in a primary source of their funding “drying up”.

Most independents had sold their production forward (hedged), locking in higher prices. But, most only sold forward for a year or so. Without a major correction in oil prices, a growing group of companies that are out of compliance with their borrowing covenants will become insolvent. We have seen companies where hedges were 25% or more of the tangible net worth. As those hedges roll off and the profit is used, that translates to shrinking total assets.

Even some large public companies are being impacted. For example, this month we saw two packages of properties totaling $1 billion in value for sale by a public company that is financially solid. Clearly management is taking capital rationing seriously.

During the boom both public and private companies were keeping assets that they traditionally would have sold. Public companies were keeping non-core and non-operated properties. Many of these properties were “mature annuities” with little or no development prospect. Because their cost of capital was low, they could hold these assets to try and slow the rate of decline in their reported reserves (total “barrels in the ground”).

Compounding this move to divestiture, many companies are reducing staff, so they no longer have the resources to administer these assets. There will likely be a move to selling off midstream assets such as gathering systems (pipelines) and storage facilities to free up capital for their core investments.

During the boom the industry had access to what appeared to be “unlimited” cheap capital. Now capital is limited and more expensive. This creates improved opportunity for Five States. We like “boring, no-growth” annuities.

In addition to the increase in public offerings, our business development team is hearing a different story from commercial banks and private companies than they did this time last year. Borrowing bases are eroding, and banks are beginning to put pressure on borrowers to take the necessary steps to bring their loans back into compliance. Some lenders are looking for ways to “play kick the can” by softening covenants and inflating forecast price decks. But these “tricks” only delay the inevitable. Without a material increase in oil prices, a major restructuring of the oil and gas sector will be necessary. This is about as good as it gets for making new investments in oil and gas!

The Oil Glut

Global oil prices are now near five-year lows. US producers are feeling the pain; they are not alone. Low oil and natural gas prices are causing companies and governments throughout the world to reexamine their budgets, rethink their priorities and, in some cases, make major policy decisions based on the possibility that significantly higher prices may be a long time coming, if ever.

In July of last year, oil was trading above $100 per barrel. Since January of 2015, the average price has been less than $50. The new technology of horizontal drilling combined with multiple stage hydraulic fracturing has unlocked literally billions of barrels of oil from tight reservoir rocks. Since 2005, US oil production has been increasing at an astonishing rate. The US is now the second largest producer in the world, close behind Saudi Arabia. “This is a historic turning point,” historian Daniel Yergin said. “The defining force now in world oil is the growth of US production.”

The result has been the development of a worldwide oil glut that has hammered commodity prices. Here in the US, lower prices have idled half the fleet of drilling rigs, necessitated the layoffs of thousands of workers, and are wreaking havoc among the independent oil and gas operators who depend on operating cash flow to fund their businesses. Around the world, the glut is creating some significant geo-political ripples.

As was recently pointed out in a talk by Ken Hersh, chairman of Natural Gas Partners, the world is suddenly shifting from one of energy scarcity to one of energy abundance. “It’s a world in which the economics of scarcity, whose rules are determined by producers, are being replaced by those of consumers, who are benefitting from lower prices,” Hersh said.

For American motorists, the price-drop is providing a windfall. The average price of a gallon of gas is more than a dollar lower than it was a year ago, a huge savings to consumers who are putting much of it straight back into the economy, buying clothes, electronics, restaurant meals and other items they might not otherwise splurge on.

Worldwide, lower prices could imperil the economies of petro-states such as Venezuela, Iran and Russia. Analysts believe OPEC, whose 12 members account for around one-third of the world’s oil supply, is trying to drive some US shale producers out of business. Saudi Arabia, which effectively leads the cartel, has so much wealth it can handle significant losses, but for countries whose economies rely heavily on high oil prices, the outlook is much bleaker.

The West now has more leverage over rogue petro-states. Until the US made the accommodative agreement with Iran over Iran’s nuclear program, Iran could no longer rely on high oil prices to soften the impact of economic sanctions. For a time, the US had an opportunity to make a favorable deal. Similarly, Russia now has more reason to pull back on its aggression toward its neighbors, and even to make sales of natural gas to China, which it might not have previously considered. Whether Mr. Putin ultimately accedes to the pressure to lessen his belligerency toward Ukraine is still to be determined.

Venezuela is in even worse financial straits. Inflation is a staggering 60%, and currency controls have generated scarcity of basic needs. In the past, President Nicolas Maduro, and his predecessor, Hugo Chavez, hid the perilous state of Venezuela’s finances behind populist policies funded by vast oil revenues. Now political upheaval is a real possibility.

The US benefits in other ways by its new largess. Oil imports are, and have historically been, the largest component of our foreign trade deficit. Every barrel produced domestically replaces one otherwise imported. Since 2005, when production of shale oil began coming on the market in significant volumes, the US has reduced its dependence on oil imports from 72% to 16%, an amazing accomplishment.

The US has spent billions of dollars in military support to protect oil transport ships in hazardous areas, and to provide military equipment and personnel to those countries considered critical to a continued secure supply. With less dependence on imports, the need for a continued high level of support might be reduced.

Further, with increasing supplies, the US dollar becomes stronger, and our government’s hand is strengthened in negotiations with foreign governments. We have the opportunity to regain our reputation as a stable and reliable partner to our friends and allies, and to be less required to deal with unfriendly regimes merely because we need to purchase their oil.

2015 Energy Issues Outlook

Each year, JP Morgan writes a “deep dive” piece on energy. The report is a well-researched analysis that covers several specific topics. We find the report to be informative and useful as a basis for understanding current issues and forming opinions pertinent to our industry. This year’s topics include the history of energy development and the eventual transition to renewable energy, the impact of US shale oil on US energy independence and the latest trends in nuclear, wind, solar and energy/electricity storage. In this issue of The Producer, I offer a much condensed summary of the topics discussed in the JP Morgan report.

While the world has become twice as energy efficient over the last 50 years, global consumption of primary energy is three times higher than in 1965. The finite nature of fossil fuels, the increasing cost of extracting them and their environmental impacts are prompting the US and other countries to plan for greater reliance on renewable energy. What is on the horizon, and what factors will determine our energy future?

1. US energy independence in light of increasing domestic oil and gas production.

Rising US shale oil production makes US energy independence feasible by 2025. It has brought down the marginal cost of oil, and coincided with slowing oil demand for both cyclical and structural reasons.

Since 2006, the US has reduced its net oil imports from 60% of our supply to less than 30%, providing enormous savings to our nation’s economy and citizens. However, the ability of US producers to continue to ramp up production at the pace of the last decade will depend on several factors: robust industrial growth in the US and other countries, oil prices that provide adequate profit margins to producers, relaxing the ban on oil exports, and increasing light-oil refining capacity.

2. The rising cost of nuclear power.

Once thought of as a long-term bridge between fossil fuels and renewable energy, rapidly rising costs have slowed capacity additions outside of Asia. An analysis from France shows rapidly increasing capital and operational costs over the last decade. A prior assessment using data from the year 2000 estimated overall costs at $35 per megawatt-hour (MWh). The French audit report set out in 2012 to reassess historical costs of the fleet. The updated audit costs per MWh are 2.5x the original number.

In 1945, physicists predicted that nuclear breeders would be man’s ultimate energy source. A decade later, the chairman of the US Atomic Energy Commission predicted that energy produced by atomic reactors would be “too cheap to meter.” Today the picture is clear: the days of nuclear energy being a cheap way to add base load power are likely a thing of the past.

3. Wind power and the issue of questionable continued government subsidies.

US wind capacity was growing rapidly, and was ahead of the DOE’s “20% by 2030” plan until new capacity additions collapsed in 2013. A variety of factors make the next decade more uncertain for wind than the prior one.

Every year, Lawrence Berkeley National Laboratory publishes an annual wind study on the US, which gets 4% of its electricity from wind. There are factors which favor increased deployment of wind turbines: declining upfront capital costs, declining instances of involuntary wind power curtailment, and increasing transmission line deployment. However, those issues obscure the “elephant in the room”: continued reliance on subsidies to maintain capacity growth. Subsidies have been in place almost continuously since 1994. Whenever subsidy extension was unclear, capacity additions fell in the following year by 79%-90%. Without subsidies, it would probably be difficult to mobilize private sector capital for wind projects without cash grants, production tax credits, or investment tax credits.

4. Solar power in the US: An early look.

Analysts at Lawrence Berkeley National Laboratory now have enough critical mass to look at solar costs, capacity factors and growth potential. While costs have declined sharply, photovoltaic solar energy is starting from a very low base and relies heavily on continued subsidies and the continuing decline in module process costs.

Although sunlight has the highest theoretical potential of the earth’s renewable energy sources, its real-world limitations and costs have made its adoption slower than wind. The US gets just 0.2% of its energy from utility-scale and large commercial solar installations. Capacity forecasts from the Energy Information Administration and the Solar Energy Industries Association imply that solar’s contribution will rise only to 0.6%-0.9% of US electricity generation by 2016, which would still leave solar behind biomass.

5. Electricity storage.

Renewable energy intermittency can be mitigated by increased interconnectedness of electricity grids, or through advances in energy storage. The latest update from Sandia National Laboratories indicates that the going has been slow thus far, but there has been some progress in the lab.

Most electricity is used when generated and not stored. Storage facilities are equal to just 2% of installed global generating capacity, and most can only store minutes to a few hours of supply. The most common approach is pumped storage: pump water uphill into a naturally-occurring or man-made reservoir at night when electricity prices and demand are lower, and discharge the water downhill to spin a turbine during the day when prices and demand are higher. According to the Electric Power Research Institute, pumped storage accounts for 99% of all electricity stored around the world.

Other methods of energy storage include compressed air, thermal storage, batteries, hydrogen storage, and flywheels. All may have potential use in specific instances, but large scale storage is still more of a concept than reality.

Crude Oil: A Market Perspective

The decline in crude oil prices over the last six months has been dramatic. Since early summer, the spot price for crude oil traded on the New York Mercantile Exchange (“NYMEX”) has dropped from the $90 – $100 per barrel range, where it has been trading for the last several years, to about $70 per barrel at the end of November. Last week the posted price in the US was below $50 per barrel for Williston Basin (Bakken, North Dakota).

NYMEX Crude Oil Futures Prices
(January 2015) 

Graphic courtesy of INO.com

Two factors are causing the price of crude oil to fall. World supply is increasing due to the US oil boom, and world demand growth is slowing. It is classic economics. See my article, “Oil Fundamentals: Supply and Demand,” for a more detailed discussion of world supply and demand.

Regional Wellhead Price Differentials

The price decline in crude oil is further impacted in regions of the US where production volume has increased materially by what is referred to as price differential. Price differentials are the difference between a reference price, such as NYMEX, and the actual price paid at a field location or at the wellhead. Areas with off-take constraints or limited delivery infrastructure, such as the Bakken in North Dakota, can experience wellhead differential expansion (the price falling relative to the reference price) during periods of rapidly increasing production volume, infrastructure disruption or demand decline. See Tom Barnes’ article, “Price Differentials,” for a more detailed discussion of differentials.

Self-Correcting

Now for the $64 questions: “How Low Will Crude Prices Go and How Long Will the Correction Last?” The answers to these two questions are inversely related.

The decline in crude prices is a self-correcting situation. The lower the price of oil, the more oil is consumed. The lower the price, the slower the pace of new drilling, which accelerates the decline in deliverable supply. The faster the decline in deliverable supply, the sooner demand will outpace supply, resulting in higher prices. “The cure for low prices is low prices.”

In the short term, the “floor” for oil prices is very low. When midstream facilities are glutted, what happens to additional production? If every tank battery and pipeline is full, there is a physical constraint. In the short term, crude prices could fall below $60/barrel.

Unwinding of financial trades around the physical market can exacerbate a price decline. In 2008, we saw the price of oil drop below $40/barrel, falling $100 in 100 days. Paper traders exacerbate extremes when a trend reverses or breaks technical barriers. See Tom Costantino’s article, “Forward Curves, Markets & Trading Strategies,” for a detailed discussion.

Corrections of the magnitude experienced in 2008 are unsustainable. In a severe correction, “supply destruction” is almost immediate. The production from shale wells declines much more rapidly than conventional wells. Over 50% of the production from a shale well will be produced in the first two years after each well is completed. If drilling slows or stops, it will not take long for the new production developed in the past three years to decline materially.

When oil is in the $90+/barrel range development activity accelerates, ultimately increasing supply and depressing prices. When oil is below this level ($70s & below) development will slow, the rate of depletion will accelerate since new production is not being added, and demand will outpace supply, resulting in a price recovery. We expect the current correction and decline in new development will take six to twenty-four months to reverse.

In the intermediate and long term, we believe that the sustainable price of oil is in the $80 per barrel range. This covers the cost to continue shale development with an appropriate rate of return on capital. Without shale development, the oil market reverts to the late 20th Century position of dependence on OPEC. In our plans, we expect a trading range of $65 – $105. We do not expect to see long term oil prices above this range until the resumption of more normal worldwide economic growth.

Crude Oil Annual Trading Range 

West Texas Intermediate Spot Price, Cushing, Oklahoma Note: 2014 numbers are through Nov. 24, 2014 (Source: EIA)

West Texas Intermediate Spot Price, Cushing, Oklahoma
Note: 2014 numbers are through Nov. 24, 2014 (Source: EIA)

Near Term Impact on Five States Distributions

We have hedges in place on 88% of our proved producing properties at $90 per barrel for 2015. Hedges are in place on 42% at $87 per barrel for 2016. Having prices “locked in” will reduce the impact of lower prices over the next two years.

Our low leverage philosophy is defensive. Our properties have low production costs and we do not have a lot of debt. Low operating and financial leverage results in less downside volatility during periods of declining prices.

Midstream assets are not as sensitive to short-term price volatility. Revenue is in units of oil transported, not the price per barrel produced. Our midstream projects will still continue to operate, moving production that has already been developed even when drilling slows. Our pipelines and rail facility are the lowest cost transportation option currently available. We believe it would take a long-term drop below $70 to impact long-term economics of our pipelines.

We estimate net cash flow for Five States Consolidated I, II & III would decline by approximately 15% for 2015 compared to 2014 if NYMEX crude averages $70 per barrel. Net cash flow for 2016 could decrease an additional 25% in 2016 if NYMEX crude averages $70 per barrel.

Lower prices will decrease operating cash flows from the production components of the portfolio in FSEC Fund 1. However, the hedges in place will mitigate much of the negative impact over the next couple of years. Prolonged lower prices could slow the pace of further drilling on our development projects. This could affect the development schedules for the OSR-Halliday, as well as the Waggoner Ranch. Lower oil revenues could also impact our mezzanine loan with Diversified Resources and their ability to stay current on the 12% coupon.

The two largest investments in Fund 1, Great Northern Midstream and Advantage Pipeline, should continue to perform at or above current levels in 2015. Advantage Pipeline is still projected to begin making cash distributions in early 2015. We expect larger distributions from Great Northern Midstream in 2015. The increased distributions from our midstream assets, along with our hedges, should offset much of the negative impact from the decline in oil prices.

Five State Investment Strategy

We have made only one investment for FSEC Fund 2 to date. This is the Tenawa natural gas processing plant. Falling crude oil prices have impacted this project. The decline in crude prices has reduced the value of the extracted natural gas liquids, particularly propane, and while still a profitable project, we have reduced our projected profit on this project by roughly 50% – 60%. Going into the winter it is difficult to estimate the demand pull on propane and hence the extent of any upward pressure on price. We still have 80% of the capital of Fund 2 uncommitted, so we have plenty of capital available to take advantage of new opportunities.

In the 20th Century, the greatest risk in oil and gas investing was unsystematic risk. The primary risk was drilling a dry hole. Today, the primary risk is systematic, or market risk. Shale development projects are almost always productive. Wellhead price volatility is now the greatest risk. The NYMEX price must remain over $60 per barrel for many of the shale projects to be profitable and encourage additional drilling.

As we have stated over the past few years, we are cautious about new oil investments based at $90 per barrel, typically investing in a mezzanine or preferred structure. We believe $70 – $85 per barrel is the “fair value” for the NYMEX reference price. When the price for crude oil is below $80 per barrel, we become more aggressive seekers of producing properties.

New Opportunities

We are excited about developing opportunities. We believe lower prices will renew acquisition opportunities, which remain part of our investment strategy. If good assets are revalued based on current prices, they can be acquired at lower prices and performance on new investments will be more attractive.

Eroding bank borrowing bases of independents should create demand for equity. As oil prices fall, the collateral value of producing properties declines, reducing the amount banks will advance. The last few years we have seen some banks underwriting loans very aggressively. This trend should reverse, reducing the amount of bank capital and providing more opportunities for private equity.

Independent producers that need more capital to continue development will look either to mezzanine investors like Five States or sell assets. This may take time to develop. Collateral revaluations typically take place twice a year. Much of the reduction in bank collateral value is not because assets are bad. In many cases lenders loaned too much on good assets because they were assuming higher prices.

Our business development team is actively approaching community and regional banks, updating them on our interest in providing capital to their customers who no longer have sufficient borrowing capacity under their primary banking lines. Lower oil prices should also put pressure on banks and investors holding underperforming natural gas assets to sell some of these assets.

Another primary reason for the increase in producing property prices over the last five years was an overall industry “land rush” during the shale boom. Many acquirers of producing properties were trying to gain control of the potential shale acreage, paying an inflated price for the existing production in order to acquire the shale drilling rights. This type of competition will no longer be bidding up producing properties.

We will continue to actively solicit midstream investments. The energy renaissance is still in its early stages, and it will probably take twenty years to develop the new infrastructure needed.

Conclusion

We like new oil investments at $80 per barrel or lower. Lower prices should result in lower development costs, improving the long-term economics of the redevelopment underway on our legacy holdings.

We are in a defensive position on oil prices with respect to our legacy portfolios. But the price drop is not without negatives. If prices remain at this level, we will realize lower income for the production not hedged. We have been using prices in the $80s in our forecasts and valuations for 2017 and beyond for the last three years.

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.