Tag Archives: Arthur N. Budge, Jr.

A Shakeout at $100 Oil?

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

The Case for a Shakeout

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

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

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

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

Increased Differential Risk

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

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

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

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

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


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

Increased Operating Costs

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

Increased Capital Cost

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

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

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

Operating Leverage

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

Example 1

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


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

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

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

Example 2

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

Increased Financial Leverage

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

Example 3

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

The Impact on Five States Energy Capital Funds

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

The Impact on Five States Legacy Funds

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

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

Concluding Thoughts

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

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

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