Energy Market Changes

How to be the hunter instead of the hunted: by Roberto Healy for Gelber & Associates

“Amazon buys Whole Foods”.  “Grocery’ stocks tumble”.  Can grocery stores, as we’ve known them for the past 20 years, survive?  In today’s new economy, one singular event can produce a sea of change that  very rapidly creates losers and winners.  Ongoing detailed planning and analyses are critical.  Also, an external assessment of the planning is healthy to ensure insightful findings and change driving recommendations going forward. This is true in energy just as it is with grocery stores.

The natural gas market has been in the midst of some radical changes.  The production of gas from shale formations has changed the industry and will continue to do so over the next decades.  These new supplies of shale gas have affected the midstream industry, with major lines reversing flow, loss of demand in major long-haul lines, new pipelines required to move gas to markets, and basis differentials inverting to a changing new normal.  Some transportation companies thrived while others suffered greatly.  The abundance of low-priced natural gas has already produced large investments in production, gathering system, new pipelines and exports.  Most observers would agree that this effect will accelerate in the coming decade. 

Demand for gas in the US alone is expected to grow substantially, by some estimates as much as 50% over the next twenty years.  The expansion of greenfield development of ethylene, methanol and other industrial facilities is well under way. Export pipelines have been sprouting across the border at an unusual pace moving gas to Mexico for power generation and industry.  Mexico alone will represent as much as 10 Bcf/d of gas. LNG export plants are proposed all over the Gulf Coast and the existing import facilities in Atlantic that are being converted to liquefaction.   Exports as LNG could reach over 10 Bcf/d in the next few years.  The abundance of natural gas should propel natural gas as the fuel of choice for electric generation.  The demand for gas for generation could grow by 10 Bcf/d in the next twenty years.

Supply of natural gas has seen a dramatic shift resulting from the shale revolution.  Now, with a new federal executive administration more supportive of oil and gas, and with the stated goal to attain energy dominance through less onerous regulations, it will likely lead to an even greater supply of gas.  Furthermore, other plays like coal-bed methane, tight sands, ultra-deep Gulf, and shallow water will likely see a revival and faster growth.  The size and location of these new supplies will again be at least somewhat disruptive to midstream, even if the likely incremental production in the mid-term would tend to be from those reserves in the proximity of existing infrastructure. Some analysts believe the natural gas industry could double production within 10 years. The recoverable resource base is enormous and growing, technology is improving, risk capital appears abundant and the infrastructure to serve domestic and export markets can be deployed in time, and the fuel is attractive to users.  

Demand growth and new production regions would require an increment of up to 2 Bcf/d per year in pipeline capacity in the coming years.  That very large number of new supplies will exacerbate the current changes in supply options for many buyers and sellers.

The above graphic depiction of the major projects in the Northeast illustrates the major changes headed to this market.   With even more smaller connectors and laterals, the natural gas market will change substantially.  Understanding the risks and rewards product of these changes is critical to all market participants.

These indicators tell a story of growth in all segments of the industry.  Producers, gathering system and treatment facility operators, midstream pipelines, marketers, LDCs, power generators and buyers, industrial, commercial and residential customers, investors and financing entities will all be affected.  In times of rapid and deep changes, there are always players that benefit and others that will be at risk. 

Gelber & Associates has skilled professionals who understand the changes overtaking today’s energy midstream. Rob Healy is an experienced user of the GPCM model, which is a unique tool to evaluate and understand today's rapidly evolving natural gas markets. With GPCM and other sophisticated models, Gelber & Associates prepares regional and national supply, demand, and pipeline delivery models, feasibility studies and analysis. Our scope of operation includes Mexico, the United States, Canada, Latin America, South America, parts of Asia and Europe. Our range of expertise includes natural gas, NGLs, power, transportation and transmission, crude oil and oil products, and LNG.

 

Why Utility Companies Need Natural Gas Hedging

Do Utility Companies Need Natural Gas Hedging? Yes. And how should they think about hedging natural gas

Natural gas hedging is used heavily by two types of utility companies. Natural Gas utilities sell natural gas directly to customers for cooking, heating water, and warming their homes during winter. Power utilities use natural gas as a fuel to make electricity, which they deliver to consumers to power their homes and businesses. Both types of utilities have tremendous natural gas price risk exposure, and both have an obligation to manage their natural gas price risk on behalf of us, the homeowner and ratepayer.

Given this responsibility, what role can an expert advisory firm like Gelber & Associates play in the management of risk for utility companies and consumers?

Between 1990 and 2008, natural gas was the most volatile commodity trading on a regulated futures exchange. Natural gas, during this 18-year time period, traded at roughly 3 times the volatility of the Dow Jones Industrial Average, a large amount by any measure. Prices in the natural gas market have been falling, pretty much unyieldingly, since the onset of the shale revolution in 2008. In this regard, 2008 was arguably the height of a natural gas bull market. Since this time, a large supply of gas from shale has hit the market and caused prices to decline into March of 2016. Presumably, after prices bottomed out in spring of 2016, a bear market for natural gas came to an end. During the period of rising natural gas prices and volatility after 1990, hedging to mitigate risk exposure was commonplace, but the lower prices and reduced volatility in recent years has led utility companies into complacency.

Some industry experts like Gelber & Associates (www.gelbercorp.com) believe that a new bull market for natural gas is nascent but underway. By the year 2020, Gelber believes that a bull market will be in full swing. Presuming this opinion is accurate, how should utility companies manage their natural gas price risk? What should utilities do to adjust their behavior in a downward natural gas market compared to an upward natural gas market? How do they know the difference? How speculative are utility hedging decisions when they are viewed by the Public Utility Commission in the rear-view mirror? Similarly, what should the Public Utility Commission do when reviewing the huge hedge losses that utility companies have taken at the expense of ratepayers since the market began its downward price cycle in 2008?

  • Four Florida utilities have reported lost $6.5 billion in natural gas related hedging losses since 2002
  • Regulators have invoked an order will halt hedging programs through 2017 while the parties investigate how they can be improved
  • Parties will come together in one or more workshops to consider thier alternatives including a halt to all hedging activities

Most importantly, what will utility companies do if higher prices and volatility return to the market? In response to these losses, some states are engaged in efforts to improve the hedging performance of their respective utilities, while others have halted hedging practices completely.

Gelber & Associates’ position is this: halting hedging practices in today’s market is analogous to cancelling flood insurance at the end of a drought period as a tropical storm is developing in the area adjacent to your home. Natural gas price and volatility are both low; this is when creating a hedging strategy can yield the greatest benefit.

Recently, the State of Colorado Public Utility Commission has recognized Gelber & Associates for its skill in handling the hedging on behalf of utilities in their state. We have been successful at “risk adjusting” our utility hedging programs during a variety of market conditions without taking undo speculative risks. On August 17th, the Colorado Utility Commissioners are holding a Commissioners’ Information Meeting in Denver and have asked Gelber & Associates to present on the topic of utility hedging and participate in the subsequent round table. The meeting will be a webcast and is open to the public. More information about the Colorado Public Utilities Commission can be found on their website:

https://www.colorado.gov/pacific/dora/puc

Recently the State of Washington has voted on and passed a policy statement and interpretive statement (Dockey UG-132019) instructing the Sate's natural gas utilities to review, revamp and submit a Comprehensive Hedging Plan. More on this in another article.

What Utilities Need to Know to Survive Obama's Clean Power Plan

Below is a LinkedIn preview of Gelber & Associates’ White Paper. The paper focuses on the risks and market opportunities resulting from federal initiatives to manage Carbon Dioxide (CO2) emissions from stationary sources. If you are interested in receiving a full version of the offering please follow this linkhttp://goo.gl/forms/HT4Hf8WfxR to provide some quick contact details and a version of the White Paper will be sent to the email provided. This post follows up on a prior LinkedIn post we published in August 2015.

What Utilities Need to Know to Survive the Clean Power Plan

By Gary Scoggin and Arthur Gelber, Gelber & Associates

Executive Summary:

On August 3, 2015 President Obama and the EPA announced the Clean Power Plan (CPP). Gelber believes that this, along with other Federal efforts to reduce CO2 emissions, will create a lasting impact from the Obama administration. This paper does not take a position on the merits, burdens, or necessity of the CPP. Instead, this paper examines the likely outcomes from CPP in the creation of state regulated carbon markets and how these markets will impact the utilities that operate within these markets. One result of CPP is that coal burning states, such as Missouri, will be market short CO2 credits while low-coal burning states such as New York will be market long CO2 credits. The CO2 market structures and rules will be designed by the state regulatory bodies but the required compliance action will be the burden of power plant owners and operators. At this time, Gelber believes that the probability of mandated CO2 reductions is high enough to warrant action for state regulations and utilities. State regulators need to develop a plan or risk a heavier handed approach from the Federal Government. Power generators especially need to organize and engage with their state commissions, industry peers, and internal decision-makers so that market rules and structures are designed in a manner to best achieve cost-effective compliance.

1. Background: The Clean Power Plan

The Clean Power Plan is a cornerstone of the Obama Administration’s approach to reduce CO2 emissions. The plan was published in the Federal Register on October 23, 2015 and is an integral part of the US climate change commitments made at the recently concluded UN Climate Conference held in Paris.

The plan functions by creating limits on CO2 emissions at the state level. States are required to meet certain targets beginning in 2022 with final compliance by 2030. The state targets can be expressed on either a rate basis (measured in tons-CO2/MW-generating capacity) or on a mass basis (tons-CO2). Each state must submit a compliance plan to EPA by November of 2016, although a two-year extension is available. The EPA has also proposed a model federal plan that can be used as the basis for a state plan or in lieu of state plan should one not be developed.

A feature of the Clean Power Plan is language that enables CO2 emissions trading as a compliance tool. The CPP allows the creation of cap and trade markets (without calling them that) that can be formed within a state or across multiple states. Part of Gelber & Associates’ job is to read the tea leaves. We currently believe that the CO2 management initiatives will go forward and that, with few exceptions, compliance will be achieved through trading-based systems because they generally offer the most cost-effective solutions.

To read Gelber's White Paper in its entirety visit:  http://goo.gl/forms/HT4Hf8WfxR

3. Trading Mechanisms in the CPP

The Clean Power Plan, as well as the model federal plan, contains numerous features to enable CO2 emissions trading. As mentioned earlier, the CPP federal plan includes trading under either a rate-based program or a mass-based program. Under the mass-based program, the state would then initially distribute allowances under those state budgets to affected power plants based on historical generation (See Insert Calculation: The Math Behind Calculating the Emissions Allocation Gap for a description of how this could work and how we have calculated the resulting allowance gaps). In creating a market designed in this fashion, EPA is drawing on its experience in other emissions abatement structures such as the Acid Rain Program under Title III of the Clean Air Act.

Calculation Insert - CPP

 

To see #4-9 visit http://goo.gl/forms/HT4Hf8WfxR to receive your complimentary White Paper. 

10. Economic Factors in CO2 Pricing

Carbon markets in general tend to follow the overall economy. Figure 2 below illustrates how this is true for the EU.

Cost projections for carbon emissions under the CPP vary. If each state is taken in isolation, there will likely be substantial state-to-state differences for the value of emission allowances. One study projects market costs to vary widely between states. From as low as zero to as high as $26.00 per ton. The Texas grid operator ERCOT predicts that carbon prices in its interconnect to be around 22.50 per ton [1]. These state to state differences provide a driver for interstate trading arrangements.

The US Chamber of Commerce estimates that the cost to the economy of the CPP (not necessarily the market price of carbon) will be around $50 per ton in 2030 after peaking at $317 per ton in 2021.

In contrast, the EPA, in its Regulatory Impact Analysis of the proposed CPP rule, forecasted 2030 carbon compliance costs of $28 per short ton (ranging from zero to $106 per ton depending on the state).

The EPA also looked at regional compliance approaches where states could work cooperatively to reduce costs. The regional approach raised prices for some states and dramatically reduced costs for others; it forecasted average costs of $29 per short ton in 2030. Gelber & Associates will look at and forecast CO2 market pricing in more detail on a client by client basis and in a future white paper.

Figure 2: The relationship of carbon prices and economic growth

12. Trading as an Ingredient in Long-Term Planning

States and operators should seriously consider the essential role of emissions trading, when developing a plan for meeting CO2 reductions. Emission markets can be designed and implemented in a large variety of ways, some of these to the detriment of some operators. The creation of the California power markets around the year 2000 caused unintended harmful outcomes to numerous operators due to faults in the design.

There are two things that operating companies should be doing at this point:

  • Participate in the design of state or regional emissions market architecture. This includes interacting with state regulators, peer groups, and interested parties overseeing the features of CPP market design. Be an advocate to educate state officials and help them avoid detrimental market design features.
  • Brief the company’s internal resource planners, environmental staff, management, and executives on the CPP market design and forward looking pricing expectations.

The ability to recover capital and operating costs will be a major component in shaping a particular company’s CPP compliance strategy. We plan to write more about the rate-base issue in a later paper. In the meantime, Gelber & Associates would be happy to discuss this on a customized basis.

Gelber’s trading and design understanding, along with our intimate knowledge of the utility business and the regulators who have oversight of it, prepares us to assist operators with these tasks.

13. Conclusion

The Clean Power Plan (CPP) is an integral part of the US climate change commitments. It creates a challenge for all electric utility operators and will lead to the restructuring of many businesses and the closure of many assets. Fortunately, the plan as written includes the opportunity for market-based compliance mechanisms. Experiences in other emissions markets show that through proper design and efficient use of these mechanisms, utility operators can reduce their compliance costs and create a valuable potential profit center.

If you are interested in receiving help with this complex and opaque arena or simply wish to read the White Paper in its entirety, Gelber is happy to provide insight. Feel free to contact us through our website or give us a call at (713)-655-7000. A full copy of the white paper can be found here.

[1] The ERCOT analysis also included the impacts of coal-fired plant closures due to other concurrent environmental regulations.

The State of Houston: Go East Young Man

Go East Young Man

Houston economy adjusts as economic growth shifts from the upstream heavy west side to the downstream driven east side

Economics of Houston

    For the past decade, high oil prices and the explosion of domestic drilling (mostly shale) have led to high times for the Energy Corridor of West Houston. Profits and employment levels boomed as oil prices consistently stayed far above what they are today. But with oil prices collapsing recently, this prosperity has contracted. As stated in a prior blog, and to much dismay of upstream producers, oil prices won’t be recovering anytime soon. Concrete and glass buildings, filled during the boom, will soon lose their glimmer as vacancies rise. But hope lies in the east, the old grimy Houston ship channel is starting to look more beautiful as downstream activities continue full steam ahead. Below, we'll see a comparison of West Houston & East Houston Companies.

 West Houston Contenders

Both BP and ConocoPhillips have significant operations in the West Houston Energy Corridor. As seen above their stocks prices have significantly decreased as oil has dropped to under $50 a barrel. But if we head to the east-side of the energy capital of the world, we find where the current prosperity lays. 

East Houston Contenders

 

As seen above, Valero and Phillips 66, both players in the downstream refining markets of the Houston Ship Channel, are seeing significant share increases. Compared to state of the energy markets as a whole (as seen below), the East Houston Ship Channel is booming. 

Market

 

In a pound-for-pound boxing match the ship channel of East Houston is in full-boom mode as crude, refined products, and chemicals are brought in and shipped out. Here refiners and chemical plants continue to see strong profits and growth. The shale revolution has given the Gulf Coast downstream sector significant advantages over their international counterparts.

Space City's downstream refining profits are not rocket science. It boils down to two simple things:

1 | Cheap WTI Crude Oil

Cheap WTI crude has given US refiners a distinct competitive edge by decreasing the primary feedstock cost of refineries. International refiners are having a hard time competing with low prices here in the US.

2 | Cheap US Natural Gas

Cheap domestic natural gas prices lowers both the feedstock and fuel cost for chemical plants and refineries alike. In addition, cheap gas has kicked off the construction of billion dollar LNG plants. Natural gas is headed to large exports as this dip in prices continues.  

Conclusion

     Tough times have hit some in Houston as production companies are laying off employees. But hope is far from lost as refining companies are seeing prosperous times ahead. To those looking for prosperity in Houston:

Go East.

 

- Kent Bayazitoglu

The Bear is in the Room

WTI Crude Oil continues to fall as traders lose confidence due to a multitude of reasons. The rise in U.S. production and bearish prospects of Iran's increased production and export capability have made the corporate fears of oversupply and cheap prices a reality. In the near term, this two-headed monster will continue to drive the price of WTI Crude Oil even lower. 

The Case for Oversupply 

     People have longed feared that oil supply will rapidly diminish within the next decade or so, but this has proven to be a myth by the reality of the current state of crude. Proven oil reserves continue to grow, from 1,400 billion barrels in 2004 to 1,700 billion barrels at the end of 2014. The idea that economic growth and oil prices are almost perfectly correlated is being heavily tested by this year's inverse relationship between economic growth and the price of oil. 

    We are still very (let me repeat that, very) far away from the threat of oil scarcity in the world. Disruptive petroleum technology, natural gas and other fuel alternatives, production (Iran & other emerging markets) have provided the market with more oil than it can handle. As mentioned earlier, prices continue to plummet. This dip is a testament to the sustainability of oil reserves in the world. 

Effect on the Market

     In the near term, energy companies are taking a hit:

     As we can see above, energy companies shares have been steadily falling for the past 30 days. Although they made a slight rebound at the beginning of the month, Iranian fears stopped the pop and continued the negative trend throughout the energy sector. 

     

     Halliburton (HAL) has been a best of class performer lately by metric of damage mitigation. HAL's performance has seen a slight rebound over the past few days that has been fueled by their latest earnings reports. These report's showed that HAL has effectively cut costs. 

     The bear is in the room for oil companies. They will need to get lean and re-think their business models during these times of low prices if they want to lead the energy sector.