Boston Strategies International’s President Mr. David Jacoby spoke on the Comparative Economics of Combined Cycle, Solar, Wind, Hydro, and Geothermal Power at the University of Calgary’s Haskayne School of Business (HSB) in Calgary, Alberta, Canada on October 19, 2017.
Renewable energy transformation is fashionable everywhere, but in most geographies, combined cycle power plants fueled by coal and natural gas will continue to dominate for a long time. Solar, wind, hydropower, and geothermal fired plants will compete for their shares of power generation, as coal and even oil recede and biomass fails to reach economic scale.
In the image (Left to Right): Dr. Jaydeep Balakrishnan (Professor, Operations and Supply Chain Management), Mr. David Jacoby (President, Boston Strategies International), and Ms. Bea Ewanchuk, Associate Director-HSB Development
The EU has issued clean energy mandates, Asia has established leadership in low-cost supply of equipment, and Latin America is following the guidance of the Paris accord. Nearly everybody agrees that green is a desirable direction, and solar and onshore wind have lower capital costs than conventional power generation plants, but gas-fired combined cycle plants can in many cases deliver a lower Levelized Cost of Electricity and generate more jobs than solar and wind. The battle for lowest cost production has yet to be played out. Fossil fueled power costs can be driven lower still through smart midstream technology such as UAVs, Radar/LIDAR, Infrared Imaging, and Smart Pigging. The political and economic battle for the best energy sources will ultimately also need to consider economic impact and energy independence.
This keynote speech provided a perspective as to the comparative economics of combined cycle, solar, wind, hydro, and geothermal power generation alternatives, and put the comparison into Canadian perspective, using actual project examples and case studies.
Click on the image for an executive summary of the INECC analysis.
To access full 43 page slide deck “Combined Cycle, Solar, Wind, Hydro, and Geothermal Power” featuring 25 graphs and tables, 9 descriptive figures and diagrams, and full text analysis, click on the link below.
The global Industrial Gases industry has been dominated by about 5 major players controlling more than 70% of the market.Recently, strategic business alliances have begun to augment the already heavily consolidated market towards further market consolidation. In early 2016, the number of players shrunk to four when Air Liquide acquired Airgas. Now, Praxair and Linde are exploring possibilities to merge. If this merger is accomplished, it will further reduce the number of major players to three.
With talks of a merger in its early stages, the Praxair and Linde deal would result in a global market share of about 40% and annual sales of close to $28 billion, making it by far the world’s largest gases firm.
The resulting high market concentration from the Praxair and Linde merger could have an adverse impact on the price of industrial gases at a time when major buyers, especially in the oil & gas industry, are struggling to recover from the oil price crisis. Any further increase in market concentration will certainly have antitrust authorities scrutinizing the merger even more strictly.
While the market may exhibit distorting trends in the form of oligopoly, merger and acquisition deals are a win-win for the deal-makers. The last mega-deal was closed in May 2016, when Air Liquide acquired Airgas for $13 billion. It is estimated that the combined businesses will generate annual sales of more than $22 billion, employ approximately 68 thousand people around the world, and serve well over 3 million customers. The acquisition allows Air Liquide to expand in the U.S., the largest global market for industrial gases, and extends its customer base by more than one million. It will also benefit from the most advanced multi-channel distribution network in the U.S., including e-commerce and telesales capabilities. Air Liquide is projected to become the leader in North America, after having already clinched that spot in Europe, Middle East and Africa, and Asia-Pacific.
Regulators have already had a tough time with the Air Liquide-Airgas deal and it is likely that antitrust agencies will make decision a similar decision with respect to the possible Praxair-Linde merger. The deal, which will create the world’s largest industrial gas company with a market value of more than $60 billion, may witness some kind of divestitures.
According to the current market distribution, Air Liquide has 29% of the U.S. industrial gas market, Praxair has 21%, Linde has 15%, and Air Products has 14%. A merger of Praxair and Linde would give the combined company 36% of the U.S. market share. In Europe, Air Liquide has 32% of the market, Linde has 30%, Air Products has 13% and Praxair has 7%.
In future, it will be interesting to observe the changes to the industrial gases market. Next in line, after the big players, are tier 2 suppliers such as the BASF, Messer Group, Matheson Trigas, GruppoSapio, and SIAD. These suppliers will need to fight harder to survive alongside the emerging giants of the industrial gases supply space and may also, in the medium to long run, build a strong regional base of customers via strategic moves such as price undercutting. This will counteract the recent market concentration, resulting in the top 5 players controlling about 55% of the market over the next three years. Implication for strategic buyers: engage second tier suppliers in competition to stimulate and accelerate the return to more balanced market conditions.
Central Asia is fast becoming a region of strategic importance because of large reserves of natural gas being discovered here and prospects of vital pipelines catering to the needs of both western and oriental worlds. To be more precise, the country which drives this importance is Turkmenistan with its fourth largest reserves of natural gas (an estimated 24,700 bcm of gas reserves, according to the 2014 Statistical Review of World Energy published by BP), ranked only behind Russia, Iran, and Qatar. In spite of such reserves, Turkmenistan has hardly exploited it, with only 76 bcm of gas produced in 2014. While it exports to only China and Russia presently, Europe and South Asia are hungry for Turkmen natural gas, which is leading to rise in production levels.
It is obvious that the rise in demand for natural gas and its rising production are leading to new pipeline projects in the region which are extremely high on capital expenditure (cap-ex). To diversify its exports and satiate the growing demand for its natural gas, huge investment is required to build midstream infrastructure for countries like Turkmenistan. Even now $15 billion worth of two major pipeline projects TAPI (Turkmenistan-Afghanistan-Pakistan-India Pipeline) and Trans Caspian (TCP) pipelines are on radar. Other projects such as TANAP (Trans-Anatolian Natural Gas Pipeline), originating from Turkey, will play a critical role in transporting gas to Europe, has cap-ex worth $10b (up from $7.5 billion).
Are these high cap-ex projects appropriately budgeted? Are they financially viable? Is there any possibility to reduce the cost? If yes, then by how much? It is important answer these key question while talking about such large investments to find out if the project is viable and sustainable before once can find solution, in case they are not.
Based on BSI’s benchmarking of natural gas pipelines, the average cost of transporting natural gas thorough pipelines falls in the range $150k-$300k per km per bcm. For example, Tucson-Guaymas Connection Pipeline in Mexico (currently under construction) of comparable dimensions is costing $220k per km per bcm to transport natural gas. Another one in Mexico, Sonora-Sinaloa Pipeline cost $150k per km per bcm. Among examples from Africa, the West African Gas Pipeline (WAGP) costs about $270k per km per bcm. Even a subsea pipeline called the Blue Stream Pipeline, which is a trans-Black Sea gas pipeline that carries natural gas from Russia into Turkey, cost $165k per km per bcm. However, it seems like the Trans Caspian Pipeline project is demanding way higher capex of $5 billion for the pipeline of length 300 km to carry 30 bcm of natural gas per year. In this case, it will cost $550k per km per bcm to transport natural gas, much higher than the aforementioned examples. The high cost may result from a multitude of factors including high material procurement cost and labor cost (management, engineering, and construction labor), each of which forms up to 40% of total pipeline construction cost.
At currently budgeted costs, the pipelines including TAPI, TCP, TANAP, and Turkmen East West Pipeline will cost more than others per unit of length. All the pipelines studied were commissioned in or after 2013 to ensure that they are recent and comparable. Of 35 comparable pipeline projects, the average cost of 26 pipelines is $1.47 million per km, with $0.6 million per km (MMBPL Pipeline Extension) being the lower and $2.3 million per km (Rakhine-China Pipeline), being the upper limit of the set. As compared to this, the four pipeline in the Caspian Sea region considered in the study cost $7.26 million per km on an average, nearly five time higher than the rest. The lowest of these is $2.61 million per km (Turkmenistan EWP) which is already near completion. Trans Caspian Pipeline Capex, on the other hand, is exorbitant at $16.67 million per km.
Source: Boston Strategies International analysis
The other major issue that the pipelines in the Caspian region face is that their potential returns are significantly reduced due to fall in natural gas price. Therefore, if we look at the revenue generated by the aforementioned four projects at the current natural gas price, it will be 36% and 25% less than what they could have been earned in 2014 and 2013, respectively. This is a big blow to the margins on top of high costs.
The cost of each of these pipelines needs to be driven down through value chain cost engineering, astute procurement strategy, and supply contract negotiations. The major cost components of such pipeline projects include construction material such as concrete, equipment for earthmoving, lifting, and welding, besides large number of valves and pumps to be installed along the pipeline and at the pump stations. Labor cost is another major cost component which includes management & engineering labor and construction & support Labor. Other factors that shape the cost of pipeline projects include pipe diameter, wall thickness, terrain and soil type, and pipe mill location.
While I could elaborate on the factors that would normally drive price variations in pipeline construction costs, such as terrain type, pipe diameter, wall thickness, and material sourcing, the order of magnitude of the ‘price gap’ makes this discussion premature.
The projected cost of proposed pipelines such as the Trans Caspian pipeline and the Trans Afghanistan Pipeline are at least twice as expensive per km as the nearest other data point and warrants an objective audit from an independent specialist such as Boston Strategies International (BSI).
The spotlight on recent events in the Middle East, while understandably focused on ISIS and the coalition battling it, has overshadowed the potential emergence of a Kurdish state, which would dramatically change the energy landscape in Iraq, Turkey, and, by extension, Europe.
Some have observed that ISIS may control oil production. In fact, ISIS’s current oil production capacity is only around 25,000-40,000 barrels per day and it would be difficult to foresee that the group would be allowed any future control over any oil production facility.
The more interesting potential outcome of these events is suggested by the image above, in the gray area labeled “Kurdistan,” which outlines the potential area of influence or domination by the Kurds. So far, the Kurdish forces have been the most active among the ground troops in the war waged against ISIS. There is no doubt that their quick and intense involvement is linked with their longstanding dream of establishing an independent state, which they have partially achieved through the current Kurdistan government. A Kurdish state with a geographic spread that currently spans four countries would immediately transform the Kurds into a significant regional energy player, not only because of the oil production capacity that the state would have, but also because of its strategic location.
Kurdish desire for the means to control their own economic destiny and the potential benefits to other countries of stabilizing governmental control in the region lend support to the rise of a Kurdish state. The Kurdistan Regional Government plans to reach a production capacity of 1 million barrels per day (bpd) by 2016. This would generate revenues of around $35 billion per year at current oil prices, but with the developments taking place in the region and should the Kurds take control of the Kirkuk Oil field they will have achieved their target much earlier than their forecast. Furthermore this would immediately pave the way to the Kirkuk-Cayhem pipeline, which could potentially transport 1.6 billion barrels per day to energy-hungry Turkey. While the Turkish Government opposes the creation of an independent Kurdistan, a stronger government in the oil-rich region would support Turkey’s ambition to become an energy corridor to Europe.
Such prospects create new opportunities, and risks, for energy companies, and their effects will be felt by end-users of gas and oil. Boston Strategies International is helping its clients identify new partners and maximize the value of potential opportunities during this window of opportunity.
In their book “Ecological Economics” Daly and Farley wrote: “We almost certainly will never exhaust fossil fuel stocks in physical terms, because there will always remain some stocks that are too energy-intensive or too expensive to recover.”
Technological advances have enabled us to continuously readjust our fossil fuel reserve forecasts, but they will eventually have their limits. It is a scientific fact that it takes 9.8 joules of energy to lift 1 kg one meter and there is no techonological advance that can change that fact. Additionally, a fossil fuel is recoverable only if the net energy gain from extraction is positive (it needs to take less than a barrel of oil to extract a barrel of oil), and increased energy is being consumed to recover the remaining supplies. Therefore the energy return on investment is declining: in 2012 the top 50 American oil operators invested 20% more than in 2011 to develop new oil fields, and yet their combined production grew only 13% while after-tax profits declined 58%.
While the EIA increased its forecast of global recoverable shale gas by 10% in 2013 to 7,299 trillion cf, another 2013 survey of 35 leading companies in shale exploration revealed that their average capex spending reached $50 per barrel with average revenue per barrel of $51.5. Exploration and Production (E&P) companies will need to identify the sweet spots within this landscape if they are to reap their target ROI on E&P spending.
In addition, the countries with the most years of oil left include many of the less politically stable ones, which will provide incentive for a global political convergence. With extensive experience in the Middle East and Latin America, Boston Strategies International is helping its global client base to establish win-win joint ventures and partnerships to take advantage of this opportunity.
Budgeting and controlling investment costs for Latin American oil & gas projects can be particularly tricky. If investors and owners don’t use reliable information in negotiating with EPCs and equipment suppliers, their projects may suffer from a proliferation of risk buffers and safety margins that cumulatively make them unviable. Or, even worse, they may proceed with the projects and then suffer financially disastrous cost overruns.
Costs vary widely across Latin America, and between Latin America and other regions. Labor costs, third country national participation, and local employee benefit adders are particular to each country. Local productivity differentials, local content requirements, and union regulations together can double or even triple project costs. Steel costs vary widely due to volatile demand and limited supply. Fuel costs are subsidized in some countries and not in others. Finally, high payment risks, the chance of expropriation, hyperinflation, and economic volatility affect terms and conditions of contracting.
Projects like Sea Lion, a joint venture of Premier Oil (60%) and Rockhopper (40%), in Argentina, exemplify the need for supplementary and more methodical cost benchmarking, value chain engineering, tender design, and supplier negotiation. The total capital estimate ($5 billion) is making it hard to fund this project. In addition, Sea Lion’s project budget is fluid and has wide variances: the pre-FEED study on the FPSO plan suggested a required investment of approximately $7b, while new estimates come closer to $5.2 billion.
In order to assure project viability investors in Latin American oil and gas ventures need to access equivalency costs for similar investments in other regions, tapping into specialized expertise if necessary to accurately forecast and mitigate financial and strategic supply chain risks.