Oil And Violence In The Niger Delta Isn’t Talked About Much, But It Has A Global Impact

By Terry Hallmark, Visiting Clinical Instructor, Honors College

There have been numerous reports over the last 18 months about terrorist attacks in Europe, the United States and elsewhere. But one long-running hotbed of political violence, Nigeria’s oil-producing Niger Delta, has garnered only a modest amount media attention.

Maybe it’s because the conflict between anti-oil insurgents and the government has gone on for so long, some 20 years, that there’s a bit of “Niger Delta fatigue.” Or perhaps it’s because the Niger Delta militants have no ties to radical Islamic groups like al-Qaeda or ISIS and have shown little or no interest in maiming or murdering the innocent – opting instead to attack targets like drill sites, pipelines, tankers and facilities in order to stifle oil production and cripple the Nigerian government economically.

Or it could be that the conflict hasn’t gotten as much play in the press as it deserves simply because international oil companies working in dangerous places is “old news.”

Because crude oil is such a valuable commodity, international oil companies are practically fearless, impervious to the threats posed by guerrillas, terrorists and insurgents; many of the oil workers are rough and tumble types – “adrenalin junkies” who enjoy the rush of going into such areas to get hydrocarbons out of the ground. But regardless of why the conflict has flown under the radar, what’s gone down in the Niger Delta over the last two decades is worthy of attention – much more so than Boko Haram – for it has a direct impact on the level of oil sector investment and operations in the area, Nigeria’s oil production and economy, and even world oil markets and oil prices.

Peace won’t be easy, but an uneasy détente is possible. Whatever happens will affect not only on oil companies, but consumers, too.

The story, in brief, is as follows: In the late 1980s, several indigenous tribal groups began raising concerns about international oil company operations in the Niger Delta, a region of about 27,000 square miles, larger than the state of West Virginia. The largest and best known of the groups was the Ogoni, an indigenous people of (now) nearly 1 million people. The Ogoni and other ethnic groups – the Ijaws, Itserikis, Urhobos, Isikos, Liages, Ikwerres, Ekpeyes and Ogulaghas – complained that Shell, Mobil and other oil companies were prospering at their expense, as the ethnic groups saw little of the wealth generated by the oil production, while suffering the fallout from widespread environmental degradation caused by exploration and production efforts.

The Ogonis’ response to these perceived wrongs was confined, at least initially, to protests, low-level acts of civil disobedience and minor, occasional acts of sabotage, along with the formation in 1990 of the Movement for the Survival of Ogoni People (MOSOP), led by author and environmental activist Ken Saro-Wiwa. The conflict escalated over the next few years, and in November 1995, SaroWiwa, and eight other activists were hanged by the Nigerian government.

The hangings radicalized the Niger Delta opposition groups, which began to organize and engage in acts of violence and terrorism directed at oil interests.

Environmentalists, Looking For Oil

By Julia Wellner, Assistant Professor, Department of Earth and Atmospheric Sciences

Despite a lingering downturn in the oil industry, which has led to the loss of 100,000 jobs in the United States alone, most of my students are studying geology with an eye towards a career in the industry. This is an understandable choice. Houston is the hub of the world’s petroleum industry.

In Houston, it is likely that the person in front of you at the deli studies the same type of sediment-transport modelling you do, or that your child’s baseball team is entirely made up of families with parents who have all been on the same field trip to the middle of nowhere Utah.

In addition, the jobs also pay well right out of college, with geoscientists in the petroleum industry starting with salaries over $100,000.  Many of the classes offered in my department, included those that I teach, are geared towards the skills specifically needed in the industry, and many of our students are recruited by companies interviewing on campus.

With that said, most of my own training and research is about glacial history and how it relates to climate and sea-level changes. The graduate students I supervise study the sedimentary signature of glacial changes in Antarctica; many of them complete their own field research during travels to the south.

The experience of working in Antarctica has a lifelong impact on most of those lucky enough to have the opportunity. Environmental change does not occur on the scale of a single season.  But students or tourists visiting the region gain an appreciation for the vast areas that appear to be pristine but which research shows to be changing at an accelerating rate.

When they complete their graduate degrees though, most then go to the work in the oil industry. They are, after all, learning the same basic skills as other geologists, and there just aren’t that many jobs for glacial geologists in Houston.

I am often asked if I am disappointed to see my graduate students go to the oil industry.  No!  I am proud of them and, moreover, I believe that more geoscientists with such backgrounds will be good for the industry, and all of us.

The icebreaking ship we work on in the Antarctic burns 6,000 gallons of fuel per day. We all take airplanes to get there. At home, we heat our homes, drive or rely on those who do, and rely on plastics and petrochemical products, at least to some extent. We need the oil industry now and in the future, just like the rest of the population, even though we understand the impact of burning fossil fuels on global climate.

More than just recognizing that all of us need the oil industry, though, I believe the industry needs my students and more like them. With the impact of climate change forefront in their minds, they will automatically balance choices in oil exploration and production with a broad set of concerns.

Maybe they will push to move away from tar sands and towards a more sustainable option.  Maybe they will think about groundwater when a pipeline is being designed, rather than after construction has already begun. And maybe their backgrounds can help build trust with communities worried about fracking in their backyards when they explain that the cleaner-burning gas it will generate is, on the whole, an environmental benefit.

Companies, governments and schools often focus on diversity in hiring and recruiting. That diversity includes race and ethnicity, gender and physical abilities, among others.

Diversity with respect to environmental backgrounds has a role to play in the energy industry of the future.

Wind And Solar Power Seem Cheap Now, But Will The Cost Go Up As We Use More Of It?

By Earl J. Ritchie, Lecturer, Department of Construction Management

Everyone talks about wind and solar power becoming cost competitive, but the cost will rise as its share of generation increases and we have to pay more to integrate it into the electrical system. How much it will rise remains the subject of debate.

The cost of electricity from wind and solar energy, as well as other variable sources, has two components: the cost of generation and the cost of integration into the electrical system. As discussed in an earlier post, integration costs are expected to increase disproportionately as the share of wind and solar increases, potentially offsetting the decreasing cost of generation.

The cost of generation alone is fairly well defined. There is some disagreement about the likely extent of future cost reduction but the ranges are relatively narrow. The Bloomberg New Energy Finance estimates of about $40-$50 per megawatt-hour (MWh) are typical.


Source: Bloomberg 2016

As shown below, except for utility scale solar, the rate of cost reduction has slowed in recent years, so estimates for future reductions in wind power and rooftop solar costs may be optimistic. These are levelized costs, estimates of the actual cost of generation. They do not include integration costs and may differ from reported auction costs, which are affected by market conditions and subsidies.


Source: Lazard 2016

The IPCC estimate

As addressed in Section 7.8.2 of the IPCC’s fifth Assessment Report, there are three components of integration cost: (1) balancing costs (originating from the required flexibility to maintain a balance between supply and demand), (2) capacity adequacy costs (due to the need to ensure operation even at peak times of the residual load), and (3) transmission and distribution costs.

The IPCC does not give specific costs at high penetration levels. Their ranges for levels of 20% to 30% penetration are $1-$7 for balancing, $0-$10 for capacity adequacy, and $0-$15 for transmission and distribution. Total range is $1-32.

Even at these levels the integration costs are significant. At an estimated future generation cost of $45, the middle of the IPCC range of integration costs adds 37%. It is generally recognized that the integration cost of variable renewable energy (VRE) penetration above 30% will be higher but is difficult to estimate.

The complexities of integration

Dealing with intermittency must be managed at a continuum of time scales from milliseconds to years. There are costs associated with all timeframes; however, published analyses focus primarily on the longer intervals of balancing and adequacy.


Source: World Bank 2015

Various measures to manage this variation – storage, source mix, overcapacity, demand management, etc. – have differing costs, advantages and disadvantages which can be traded off. This results in a complex situation in which the optimum solution is typically not obvious.

Estimates of integration cost at higher levels vary so widely that it is almost impossible to generalize. Local conditions and design choices significantly affect cost. As a study by the Danish Association of Engineers put it “the design of future 100% renewable energy systems is a very complex process.” An almost infinite number of possible combinations of sources is possible depending upon location, anticipated demand, degree of decarbonization and emphasis on economics.

How future costs are estimated

Both optimization and cost forecasting are done with mathematical models. Significant differences may result from the model used. Some characteristics and weaknesses of the three main classes of model are shown below.


Source: Ueckerdt 2015

Limitations of the models mean that not all aspects of the system can be incorporated in any one model. This may result in overestimates or underestimates. In addition, published studies frequently consider only one aspect, such as the addition of wind power alone.

The limitations and possible sources of error in these studies are normally well understood by the authors, and explained in the original articles. Such caveats rarely reach popular articles quoting the results. There is also deliberate or subconscious bias in the choice of parameters due to the prejudices of the authors.

The variation in estimates

The result of these factors is considerable variation in cost estimates, even when similar systems are being analyzed. Two examples demonstrate the range:

The first estimate below is a model of adding wind energy to an existing grid similar to the European grid. It does not consider externalities, such as renewables mandates, but does include a carbon tax of 20 Euros per ton of CO2. The upper dashed line shows short term costs, and the solid black line long term.

The model shows integration cost equal to generation cost at 40% penetration. That is, the cost doubles. It does not consider possible storage or extending the grid to optimize the system.


Source: Ueckerdt, et al. 2013

A 2016 US study by Lantz, et al., showed a mix of about 42% variable renewable energy to have a net present value cost $59 billion higher than an economically optimized scenario. They did not give a per kilowatt-hour cost, but modeled a modest 3% increase in retail electricity cost in 2050. The authors comment that the cost may be understated because of lack of detail in the model.


Source: Modified from Lantz, et al. 2016

Further examples include the widely publicized papers by DeLucchi and Jacobson, which estimate transmission and storage costs as $20/MWh for 100% variable renewables, and the 2012 NREL study, based on somewhat dated costs, which estimates up to $54/MWh over a fossil fuel dominated scenario for 90% renewables (48% wind and solar). Published scenarios are hotly debated.

The headline cost in such studies cannot be taken at face value. In addition to variances due to choice of model, such obvious influences as assumed fossil fuel prices and future cost reductions in generation methods must be weighed in assessing the estimates. As might be expected, proponents of a particular technology will frequently make assumptions favorable to their preferred energy source.

Other renewables and the social cost of carbon

Some issues not discussed in detail here include the other variable renewables, wave and tide; the dispatchable renewables, hydroelectric, geothermal, and biomass; and the social cost of carbon.

Wave and tide are expected to contribute only a small fraction of future electricity generation. They may be complementary to other forms of variable renewable energy.

Hydroelectric and geothermal can be highly desirable as low carbon, low-cost and dispatchable. Very high renewables penetration has already occurred in areas where these resources are abundant. New Zealand is above 80%; Norway and Iceland are over 90%.

Electricity generated from biomass is dispatchable but creates greenhouse gases at the site of generation. The extent to which this is offset by land use changes and carbon storage of the fuel crops depends upon the generation technology, the type of fuel crop and management of the crop. Estimates of offset are controversial but most calculate net reduction in greenhouse gases compared to fossil fuel generation.

The social cost of carbon (SCC) is not the focus of this article, which concentrates on the actual cost of generation. SCC is speculative, with typically quoted numbers from about $5 per ton of CO2 to $100, although extremes can exceed $1,000. The US government’s 5th percentile to 95th percentile range of the cost in 2020 is from zero to about $180. Obviously, the inclusion of any positive SCC will shift economic analysis toward low carbon sources.

Little effect in the short run

Wind and solar intermittency are not likely to be very costly in the near-term, say to 2030, because most scenarios do not have them reaching high penetration levels by that time. For example, wind and solar are 15% of electricity generation in the Reference Case of the EIA’s 2016 Annual Energy Outlook.

Even the highly publicized German Energiewende (Energy Transformation) has wind and solar currently at 21%, below the level of potential significant cost increase. Intermittency is still being handled by fossil fuels, dispatchable renewables, and exports. Germany’s target for 2030 is 33%.


Source: Burger 2017

Local areas with more ambitious goals will be an interesting test. California has a goal of 50% of retail electricity sales from renewables by 2030. A 2014 analysis by the consulting firm E3 modeled reaching this goal with 43% wind and solar. The report said “This is a much higher penetration of wind and solar energy than has ever been achieved anywhere in the world.” Capital costs under various scenarios ranged from $89 billion to $128 billion in 2012 dollars, with electricity rates increasing between 15% and 30% solely due to the renewables standard. An additional 40% would be due to infrastructure replacement and other factors. The report further says “overgeneration and other integration challenges have a substantial impact of (sic) the total costs for the 50% RPS scenarios.”

Will intermittency costs limit high penetration?

It is clear that there is a cost to managing intermittency and this cost will likely be greater than the decrease in generation cost itself. Actual experience suggests that this cost will be higher than is envisioned in the more optimistic scenarios.

However, cost is not the only consideration. High cost generation may have value where the cost of alternative sources is higher or the match to demand is good. Carbon taxes and renewables mandates will increase the share of renewables, regardless of the underlying economics.

Predictions of whether costs associated with increasing share of variable renewables will outweigh future cost reductions depend upon expectations of both, as well as future costs of storage and other means of dealing with intermittency, all of which are speculative. Storage costs are a topic for another day.

When Flaring Natural Gas Becomes Political — Needless Regulation Or Good Conservation?

By  Bret Wells, George Butler Research Professor of Law and Tracy Hester, Lecturer at the University of Houston Law Center

One of us pointed out in a prior blog post that the oil and gas industry downturn represented the perfect time for the Texas Railroad Commission to change its regulations on flaring associated gas. The current rules – known as Rule 32 – allow drillers to burn off natural gas produced along with more profitable crude oil if there isn’t an immediately available pipeline or other marketing facility to take it. That’s been sweepingly interpreted to allow the burning of gas that could have been captured and sold.

In a subsequent post, the same co-author argued that the flaring of potentially profitable and economically valuable natural gas may give rise to common law claims for royalty owners. Under Texas law, the operator is held to an implied covenant to act as a reasonably prudent operator.  As part of this implied duty, an operator must reasonably and prudently administer the leasehold estate in a nonwasteful manner.  So that previous post argued that flaring commercially profitable natural gas may violate this implied covenant standard and thus subject the operator to damage claims by impacted landowners.

But recent events have made flaring a political issue. The Bureau of Land Management, which oversees the development of federally owned lands, proposed regulations last February to curtail methane emissions from public lands. As the Bureau of Land Management noted in its regulations, methane is the primary component of natural gas, and the venting or flaring of natural gas causes methane to be released into the atmosphere. Moreover, the Bureau of Land Management estimated that methane has a climate change impact 25 times greater than that of CO2.

Whether or not one accepts the climate change concerns raised by these methane emissions, the fact remains that the Bureau of Land Management has a vital interest in ensuring that natural gas obtained from federally owned lands is put to a productive use. Thus, the Bureau of Land Management issued regulations that sought to curtail the amount of flaring that could occur on federally owned lands, and one of the rationales was to prevent the needless waste of an economically valuable and scarce natural resource.

Last week, it was reported that Congress and the President would seek to overturn needless regulations that inhibit business activity, and news reports identified the Bureau of Land Management’s recent regulations as targets for elimination.

Flaring degrades the nation’s air quality, adds to global climate change impacts and also wastes a valuable natural resource that could have had a productive use. The public should expect the Bureau of Land Management would ensure that federally owned lands would be developed in a way that minimizes the waste of natural gas. To that end, it is appropriate for the Bureau of Land Management to require businesses to use best practices in its oil and gas development activities conducted on federal lands.

The United States is blessed with natural resources, but they should not be wasted.  We should applaud regulations that minimize the amount of hydrocarbons immediately burned up in flares. These regulations support greater energy independence for the United States by ensuring that our natural resources are put to a productive use.

Thus, we hope that the current administration and Congress will defend these regulations as a reasonable effort to minimize the waste of our finite natural resources.

The Cost Of Wind And Solar Intermittency

By Earl J. Ritchie, Lecturer, Department of Construction Management

Until relatively recently, generation of electricity with wind and solar has not been cost competitive. Growth has largely been due to subsidies and renewable energy mandates. Due to decreasing cost, wind and solar are now cost competitive with fossil fuels in favorable locations.

The continuing decrease in wind and solar costs is a very positive development. However, this trend may reverse as the percentage of variable renewable energy (VRE) energy that isn’t available on-demand but only at specific times, such as when the wind is blowingreaches high levels. Countries such as Germany that have integrated significant amounts of wind and solar have already seen price increases.

The levelized cost of electricity

Comparisons of electrical generation cost are usually based on the so-called levelized cost of energy (LCOE), an estimate of the total cost of generation expressed in dollars per megawatt hour ($/WMh). The calculation includes capital costs, operating and maintenance costs and fuel cost. It is affected by assumed utilization rate and interest rates.

The most widely cited levelized cost estimates are those of the U.S. Energy Information Agency (EIA) and the investment firm Lazard. Although these estimates are useful for comparison, they exclude such costs as network upgrades, integration and transmission, which can become significant as renewables penetration increases. As the International Energy Agency (IEA) put it in the context of integrating variable renewable energy, “comparison based on LCOE is no longer sufficient and can be misleading.”

Levelized cost estimates are based on a large number of assumptions, not least of which is the future cost of fossil fuels. There are some differences in these estimates, with Lazard showing unsubsidized utility scale solar and onshore wind as competitive with natural gas and the EIA not.

The table shows national averages. For wind and solar, location is very important; they are in places locally cheaper than natural gas combined cycle. For the purposes of this discussion, these differences are not significant. The more important point is the added cost of factors not included in the levelized cost.

The sources of integration costs

As described by Mark Delucchi and Mark Jacobson, “any electricity system must be able to respond to changes in demand over seconds, minutes, hours, seasons and years, and must be able to accommodate unanticipated changes in the availability of generation.” Traditionally, this is handled by base load and peak load plants, which handle the minimum load and increases above that level, respectively. This is an oversimplification, since supply is managed by the minute using a variety of sources with different response times.

Wind and solar are non-dispatchable, meaning that they are not under the control of the operator. They only generate electricity when the wind blows or the sun shines. This adds integration costs, shown conceptually below.

Source: Ueckerdt, 2015

 When variable sources are a small fraction of electricity supply, the cost of integration is low. The current level of deployment is below thresholds where the cost of dealing with intermittency becomes significant.

There are numerous possible solutions to intermittency. These include diversification, redundancy, storage and demand shifting. That redundancy and storage add cost is obvious. Diversification also adds cost in control equipment and transmission capability between geographically separated sources.

Demand shifting can theoretically lower cost by reducing the peak capacity needed. It is often discussed jointly with efficiency improvement under the term demand-side management.

One issue in demand management is illustrated in this graph of daily load for a location in Australia. Solar is only available when the sun shines and peaks around midday. As solar generation increases, the average load on the remainder of the system decreases, but the peak is barely affected. Dispatchable sources must make up the difference between the midday low and the evening and morning peaks. This relationship is called the “duck curve.”

Source: Ledwich 2015

Measures to shift usage from peak periods include education, jawboning, differential pricing and control of end use by the utility through the smart grid. Education, jawboning and even differential pricing have had limited success to date. Time of day pricing and end-use control require a smart grid, with attendant cost.

Wind power typically will generate throughout the day, but it has its own limitations. It is less predictable, more variable over short periods than solar, may be seasonal and may need to be shut down when the wind is too strong.

The graph below shows generation for one day on the island of Crete. Renewables penetration reaches a peak of 60%, accommodated by curtailment of diesel and gas generation. Even so, average annual renewable share is only 20%, and some difficulties were encountered during peak renewables generation periods.

The Crete example is typical of existing systems in that balancing is done with fossil fuels. Balancing may also be done by dispatchable renewable energy, primarily hydroelectric and biomass, and with storage.

What’s the best generation mix?

Due to the wide variety of generating sources and unique local circumstances, there is considerable flexibility in the design of generating systems. The trade-offs in cost and environmental benefit are complex.

Hundreds of studies which address increasing the share of renewables have been published. These vary greatly in scope and sophistication. Some do not include cost analysis or ignore integration costs. Adequate analysis of high levels of variable generation requires that balancing demand within short time frames be included.

The sample of published scenarios below illustrates the wide range of possible combinations. Wind and solar range from less than 20% to over 80%. The mix is influenced by availability of other sources, and by ideology.

Source: Modified from Cochran 2014

Big differences result from design choices, such as whether expansion or retention of some fossil fuels are included. Accepting periods of inadequate capacity is also a factor.

Most scenarios with high percentages of renewables rely on substantial reduction in growth of electricity demand. It’s questionable how realistic this is, particularly if strong growth in electric automobiles is anticipated.

What is the integration threshold?

There is no threshold, per se. The cost of managing intermittency is nonlinear and depends upon the mix and location of dispatchable and non-dispatchable sources, the match of local demand patterns with variable source pattern, and various other factors.

Based on model studies of Germany and Indiana, Falko Ueckerdt found integration costs began to become significant at 20%. As of 2015, only four countries have variable renewable energy over 20%.

Hawaii Electric recently approached 50% renewables; however, the share of wind and solar was only about 15%. Even so, they have requested a 6.9% rate increase based partly on the cost of renewables integration, and estimate the cost of grid upgrades necessary to reach 100% renewables as $8 billion.

Champions of wind and solar have characterized integration cost estimates as ploys to discourage renewable energy, but integration costs are real.

Isn’t it being done already?

The poster child for variable renewable energy is Denmark, reported to be over 50% in 2015. Denmark’s success is often used to illustrate that high levels are readily achievable. This is misleading in that Denmark is a small country tied into the European grid. Variable wind power is balanced with hydroelectric and other sources in adjacent countries. De facto share for the system is lower. Denmark’s installed wind capacity ranks ninth among EU countries and represents less than 4% of EU.

Source: EIA 2016

Germany’s combined wind and solar has the largest capacity in Europe and is second highest per capita. Despite Germany’s progress, the share of variable renewable energy for electrical generation is less than 25% and has been achieved at significant cost. The renewable energy surcharge is 22% of household electricity price.

Even at relatively low levels of renewables share, there is a clear correlation between the share of variable renewable energy and the retail price of electricity. This is largely due to feed-in tariffs and net metering, which transfer renewable subsidies costs to the retail customer.

 The range of published integration cost estimates at higher shares of wind and solar is very broad and dependent upon both parameter assumptions and model structure. I will discuss these in a later post.

Earl J. Ritchie is a retired energy executive and teaches a course on the oil and gas industry at the University of Houston. He has 35 years’ experience in the industry. He started as a geophysicist with Mobil Oil and subsequently worked in a variety of management and technical positions with several independent exploration and production companies. Ritchie retired as Vice President and General Manager of the offshore division of EOG Resources in 2007. Prior to his experience in the oil industry, he served at the US Air Force Special Weapons Center, providing geologic and geophysical support to nuclear research activities.

America Still Uses A Lot Of Nonrenewable Energy: The Pros And Cons

By Debora Rodrigues, Associate Professor of Civil and Environmental Engineering

There is a lot of talk about the rapid growth of renewable energy, including wind and solar. It can be easy to forget that at least for now, we still rely heavily on nonrenewable energy sources, such as oil, natural gas, coal and uranium.

Today, it’s hard to imagine the western standard of living without fossil fuels and nuclear energy, and many developing nations still struggle to be able to generate enough power to serve their populations. Nonrenewable energy – especially coal – enabled the industrial revolution and has traditionally been the cheapest way to improve standards of living for people in far flung corners of the earth.

These old-school sources of energy each have their pros and cons, but I think the transformation to renewables will come more quickly than many people think. With a new fossil fuel-friendly presidential administration and growing global concern over climate change, the issue of what forms of energy we should use, and for how long, may be the subject of a hot debate.

I’ve outlined the basics of what people need to know about nonrenewable energy to adapt to a changing energy future:


Hydrocarbons – oil, natural gas and coal – have been produced over millions of years, transforming the buried remains of ancient plants and animals into the products we use to power modern life. Uranium is a naturally occurring element.


Trump, Tillerson, NAFTA, Mexico And Oil Companies

By Julián Cárdenas García, Research Professor, University of Houston Law Center

On December 5, 2016, several U.S. oil companies were among the winners of petroleum contracts awarded by the Mexican Hydrocarbon Commission to develop deep water projects in the Gulf of Mexico. From a legal standpoint, an initial assumption could be that the North American Free Trade Agreement (NAFTA) became more relevant to these “American” companies entering into the Mexican oil market. Indeed, the legal regime provided by NAFTA Chapter 11, which was designed to protect property rights in long-term investments, could be essential to ventures involving operations that might last for over two decades.

Later, President-elect Donald Trump announced Rex Tillerson as his nominee for Secretary of State. Until 2016, Tillerson was the CEO of Exxon Mobil, one of the U.S. oil companies investing in the new projects in Mexico.

During the first year in office, Trump and Tillerson, assuming Tillerson is confirmed by the Senate, will navigate national and international politics to grapple with issues arising from promises made during Trump’s presidential campaign. Among these promises was Trump’s pledge to renegotiate or to terminate NAFTA.

Yet now that U.S. oil corporations plan to heavily invest in multi-billion dollar projects in Mexican territory, Tillerson should be aware that U.S. oil companies might prefer to keep NAFTA, in contrast with the anti-NAFTA rhetoric and nationalist positions expressed by some Trump supporters. Nevertheless, both views require a closer look to identify the benefits of the agreement, since protecting U.S. oil investments in Mexico under NAFTA is far from a question with a unique and straightforward answer.

As a matter of fact, U.S. oil companies will initially face two NAFTA caveats. First, the conflicting interpretations of the agreement concerning the application of NAFTA Chapter 11. This is caused by the divided opinion of the legal community on the validity of the Mexican reservation to NAFTA that blocks protection of investment in the energy sector. For some, this reservation was implicitly waived after the approval of the Mexican energy reforms, whilst for others, the reservation remains and limits the application of some sections of the agreement.

Second, if one decides to ignore this debate and considers that NAFTA Chapter 11 applies, then they should bear in mind that, as Professor Gus Van Harten from York University has highlighted, NAFTA has no “survival clause.” A survival clause is a provision typically included in treaties for the protection of investments, which provides the continuing protection of the agreement for existing investments for periods of 10 to 15 years, even after the treaty has been unilaterally terminated. Without this clause, a NAFTA party can terminate the agreement on six months’ notice and could deprive foreign investors of the protection of international law and international arbitration.  Hence, the framework, currently a subject of a public and politicized debate, seems far from providing the certainty of the rule of law required for these investments.

Then, why expose multi-billion-dollar projects to this degree of uncertainty? In recent years, U.S. investors have been able to place investments through subsidiaries incorporated in other countries to acquire the protection of an investment treaty. Indeed, in a time when oil majors operate around the world, corporation nationality has turned into a malleable concept.

Since the last decade, international arbitration tribunals have recognized “treaty shopping” as a legitimate practice to gain access to the protection of an investment treaty. For instance, oil companies like Exxon and Chevron (both among the winners of the Mexican deep water bidding round) have circumvented the lack of investment protection in countries like Venezuela, investing through Dutch or Danish subsidiaries that provide access to treaty protection. Consequently, we would expect that oil companies could use the Mexican network of several investment treaties to gain the protection provided by international law.

Moreover, this is not a one-sided legal agreement. NAFTA is not only relevant to U.S. corporations, but it has also become important to Mexican investments in the U.S. Mexican investments, such as those conducted by Carlos Slim, have invested in the U.S. real estate market; in the media sector through his ownership of 17% of the New York Times; and even in the oil and gas sector through the company Wellaware. Furthermore, Mexican investors have not ignored the investment treaty system. In fact, Slim’s companies have recently profited from it and filed an arbitration claim against Colombia before the International Centre for Settlement of Investment Disputes at the World Bank. We may never know whether NAFTA was a topic during the recent meeting between the Mexican multi-billionaire and Donald Trump. However, what we certainly know from Trump’s Twitter account is that after the meeting he called Slim a “great guy,” and that Trump’s relationship with the New York Times is far from being “great.”

Based on the uncertainty created around NAFTA, the practice of “treaty shopping” reveals that NAFTA is one of a variety of options available to transnational corporations acting as foreign investors.

Does this make NAFTA a useless treaty? Of course not. NAFTA not only governs the protection of foreign investments. It has been the main legal framework that incentivized cross-border trade growth and investment relations between Mexico, the U.S. and Canada. Even Tillerson has publicly recognized the value of NAFTA in a conference before the Council on Foreign Relations in 2012. Despite Trump’s position blaming NAFTA as the cause of all evils suffered by American workers, some scholars, such as Harvard Professor Ricardo Hausmann, have recently highlighted the benefits of NAFTA to the economies of the United States and Mexico, increasing trade and expanding markets.

Therefore, blaming international treaties for economic mismanagement seems like a misleading approach. Of course, treaties, investment protection and trade can always be improved. Moreover, States have the sovereign power to do so and the renegotiation of treaties could open the door for improvements. However, by focusing on the withdrawal from one or two trade agreements, neither the Republicans nor the Democrats will solve the biggest problem of global competition or undue globalization.

Mexican and U.S. investors should take a closer look at this situation. On the U.S. side, the final decision regarding whether to renegotiate or withdraw from NAFTA might also consist of a lengthy decision-making process that would require the agreement of Mexico and Canada, and the support of the U.S. Congress. In the case of NAFTA withdrawal, there are still legal uncertainties since there is not a definitive answer on whether the U.S. president has the power to withdraw the U.S. from NAFTA by an executive action, without consulting Congress. Nonetheless, if Trump decides to dispatch a notice of termination to NAFTA parties without the Congress’ support, not only would this action spark a national debate, it would also be sufficient to terminate the agreement as a matter of international law.

Hence, the NAFTA case during the first year in office will show how the new administration will deal with national debates and the role of the U.S. finding new ways of leading in international trade and investment.

Julián Cárdenas García is a Venezuelan attorney and Doctoral Fellow at the Research Center on Investment and International Trade Law (CREDIMI) at the University of Bourgogne, Dijon, France. Prior to this position, he served as career diplomat at the Venezuelan Ministry of Foreign Affairs working multilateral affairs with the Organization of the American States (OAS) and the United Nations (U.N.) and bilateral affairs on sovereign boundary issues. Currently, he is a Research Professor of Law at the Environment, Energy and Natural Resources Center of the University of Houston Law Center where he teaches Transnational Petroleum Law, Diplomacy and Geopolitics of Oil and Gas and Transnational Investment Law and Arbitration.

UH Energy is the University of Houston’s hub for energy education, research and technology incubation, working to shape the energy future and forge new business approaches in the energy industry.