BSI a sponsor of 2nd Mexico Gas Summit 2016 & moderating “Hydrocarbons Infrastructure” panel discussion

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BSI’s President, David Jacoby will be the moderator of the “Hydrocarbons Infrastructure” panel discussion at the 2nd Mexico Gas Summit – The leading natural gas event for Mexico’s onshore E&P, midstream infrastructure, transportation and storage industries on April 13-14, 2016.

The 2nd Mexico Gas Summit is a two day oil and gas event in San Antonio, Texas on April 13 and 14, 2016 that will bring together internationally recognized industry speakers, investors, government officials, and C level executives from the energy, infrastructure, and transportation industries.

The event will cover Mexico as a region with a strong focus on the opportunities associated with US Gulf Coast onshore exploration and production, midstream infrastructure, gas commercialization and the recent opening of the refined fuels market.

For more information about the sponsorship visit this link and view the event agenda visit BSI – Mexico Gas Summit- Agenda.

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For more information about the event please see visit the link BSI sponsoring 2nd Mexico Gas Summit 2016.

BSI to Deliver Keynote Address at China Sourcing Summit

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Boston Strategies International will attend the 6th Conference and Exhibition – China Sourcing Summit On Petroleum & Chemical Equipment (CSSOPE 2016) to be held on 25-26 May, 2016 in Beijing, with a focus on petroleum and chemical equipment sourcing. BSI’s President, David Jacoby will conduct a workshop and deliver a presentation at CSSOPE 2016. For more information about the workshop and presentation outline visit BSI – China Sourcing Summit-outline.

CSSOPE 2016 will also provide a top-level overview and detailed insight into China’s oil and gas equipment supply capacity. It is an essential forum for sourcing managers, sellers, buyers, EPC contractors and venders. It draws great attention from the industry and promotes the China’s communication to the world. For more information about the event please see visit the link CSSOPE 2016.

Future design concept

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Stand out venues

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Technology upgraded

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After Cap & Trade Failure In Europe, USA, and Australia, China’s Next

China is the largest polluter of GHG emissions, credited for nearly 30% of global emissions. It currently emits over 10b tonnes of COequivalent of GHG emissions. No global solution for our climate challenge is possible without China playing a central role.

China’s Plan

In June, China submitted its pledge to the United Nations to peak its greenhouse gas emissions by 2030, a goal laid out in a bilateral agreement in 2014. The pledge also said China plans to reduce its emissions intensity by up to 65%, doubling its current wind and nearly quadrupling its solar power generating capacity by 2020.However, according to a recent study published by London School of Economics, China’s GHG emissions will probably peak in 2025, five years earlier than its stated target in a boost for hopes to curb climate change. Going at the current trends, the world’s biggest carbon emitter will discharge 12.5-14b tonnes of CO2e in 2025, after which emissions will decline.

Following the pledge, China announced its grand Cap & Trade program to achieve emission cut targets more aggressively than ever. It‘s national program, to take effect in 2017, will cover “industry sectors such as iron and steel, power generation, chemicals, building materials, paper-making, and non-ferrous metals.”

Cap-and-trade programs typically give a company the right to emit a certain amount of a given pollutant; if it can cut its emissions beyond what’s expected, it can sell the excess allocation. Conversely, if it needs more credits, it can buy them from another company.The program is meant to complement the Obama administration’s Clean Power Plan, which was finalized in August 2015 and aims to slash carbon emissions from electric power plants by 32% below 2005 levels by 2030.

China began moving toward a national cap-and-trade program in 2011, when it announced the formation of seven regional, pilot emissions trading systems in its 12th Five Year Plan (2011 to 2015). The next step for the 13th Five Year Plan is to scale up pilots to the national level, a draft of which will be unveiled later this year.

The seven pilot ETSs (emission trading systems) were established in the cities of Beijing, Chongqing, Shanghai, Shenzhen, and Tianjin, with two provincial systems in Guangdong and Hubei. The first, in Shenzhen, opened in mid-2013; the last (Chongqing’s) came online in June 2014.

Key Challenges

There are many challenges and limitations in way achieving the ambitious targets China has set.

It won’t be an easy to transition to a national cap-and-trade system by 2017. The pilot programs have already revealed some serious issues, such as lack of transparency on emissions and pricing in some of the pilots. Transparency will be vital for keeping track of the actual amount of emissions being released, where the emissions cap is set, and what prices are being charged.

In the end, it is worth noting that China’s announcement of its mega Cap & Trade plan has a silver lining: global emission will indeed be cut if it translates into reality. However, it is imperative that the policymakers must pay heed to the aforementioned challenges.

China needs to heed the lessons learned from Europe’s example. Europe’s emission trading system collapsed partly because recession reduced industrial demand for the permits, and then the European Union gave away too many allowances, leading to immense overcapacity in the carbon market. Prices had already fallen from$30 per tonne in 2011 to $5-7 per tonne in early 2013. China is already experiencing economic fragility, and poorly implemented climate regulation will increase the trouble.

Many economists also believe that a carbon tax regime is far simpler and more efficient. China could simply put a price on each ton of coal, as an MIT-Tsinghua study shows, and fairly quickly see emissions peak with virtually no cost to the economy. But that would take away bureaucratic discretion.

The United States failed to pass a nationwide cap and trade policy, Australia reversed its own carbon market plan, and the UN’s Clean Development Mechanism market collapsed. China’s road to an effective emission reduction regime will not be smooth, but not impossible, provided there is right intent and willingness to learn from previous mistakes.

 

No Business Sense: Caspian Pipelines Will Cost 5 Times Others And Suffer Loss Of 25% Revenue

Caspian Pipelines Picture for Blog 150624 argCentral 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.

Table Watermarked

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.

Graph Watermarked

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).

 

 

Fracking in Mexico: Challenges and Key Success Factors

Fracking in Mexico Blog PicturePemex plans to increase shale activity in the next few years, budgeting over $575m in 2014, highlighting some 200 shale gas opportunities in five geologic provinces in eastern Mexico, and opening up the bidding process for drilling shale fields. It aims to attract as much as $1t in energy investment to exploit Mexico’s shale oil and gas reserves, on the back of the energy sector reform signed by President Enrique Pena Nieto in August 2014.

Based on similarities with Eagle Ford shale in Texas, Mexico’s Eagle Ford shale this is considered to be the country’s top-ranked prospect for shale exploitation. Other basins in Mexico in which drilling has not yet occurred, and where potential is far less certain than the Burgos Basin, include the Sabinas, Tampico, Tuxpan, and Veracruz basins. Pemex (Petróleos Mexicanos), the state-owned oil company, previously identified Tamaulipas, Coahuila and Nuevo Leon, in addition to Chihuahua, as the states where fracking could be used to obtain new energy sources. The other Mexican states officials identified are Puebla, Oaxaca and Veracruz, and Mexico’s technically recoverable shale gas reserves are heavily influenced by the newly discovered Chicuantepec and Burgos.

Shale drilling in Mexico faces many hurdles. Mexico drilled its first shale gas well as recently as 2011, in the Burgos Basin in the North. Drilling was later abandoned by most operators for gas due to low price and high cost. As of February 2013, there were only six productive shale gas and tight oil wells drilled in Mexico (a seventh was abandoned as non-productive). Most of the challenges have to do with infrastructure and technological constraints, and high costs:

  1. Infrastructure constraints: Fracking activities have its own critical pre-requisites and infrastructure is one.  Mexico will need infrastructure such as new roads, rail lines, and rail terminals, and storage units that can hold large amounts of sand, and pipelines that can carry water so that it doesn’t have to be trucked to each site. Each well will require approximately 100 train cars full of sand and 4-5m gallons of water. This is a very large logistical operation.
  2. Technology constraints: Deep-water wells, especially in the Eagle Ford deposits, cut through multiple pancaked layers of oil-soaked rock, and each layer must be fracked to get the most hydrocarbons out, a task that can take a full day to get to the bottom of the well. Halliburton and other oilfield service companies have figured out a way to save time and money by fracking all those layers in one trip down the well, instead of doing each layer separately. This more intense fracking means larger volumes of water, sand, and equipment are needed for greater production. The volumes of inputs needed, especially for these lower tertiary fracks, are huge and the technology required to drill down the multiple layers also need to get more sophisticated. Drilling will not be fruitful without sufficient knowledge of how much sand, water, and chemicals will be required and what will be the best available technology to undertake complex shale drilling to optimize cost.
  3. High cost: “Efficiency is difficult to achieve, quality control is difficult, and corruption increases costs”, explains Garry Ward, expert on oilfield investing.  Drillers pay more than in the US, but do not receive the same quality of chemicals and equipment, which can make all the difference between a good well (profit) and a bad well (loss).  In such a scenario, careless procurement can lead to high cost, poor quality, and losses.

The bottom line is that E&P companies seeking to exploit shale plays in Mexico need expert supply chain strategies to manage their logistics and the cost of purchased materials and services. Boston Strategies International has been in supply chain management for oil and gas, and has supported the planning of every aspect of drilling, completion, production, and transportation, as well as downstream activities.

Fracking: Where Will Latin America Be Without It?

Lat Am Fracking Blog picLatin America, which holds approximately one-fourth of the world’s recoverable shale oil and gas reserves, is poised to reap the benefits of the North American shale revolution between now and 2025.  Ranked by shale reserves, the five largest countries in Latin America are:

  1. Argentina (802 tcf)
  2. Mexico (681 tcf)
  3. Venezuela (167 tcf)
  4. Colombia (55 tcf)
  5. Bolivia (48 tcf)

Argentina has emerged as a potential shale oil superpower as it now has the second-largest shale gas reserves (behind China with 1.1 tcf) and the fourth-largest oil reserves.  It has the shale oil potential of 27b barrels of oil and 802 tcf of recoverable shale gas. The Vaca Muerta formation (located in the Neuquen basin) holds the majority of Argentina’s shale oil reserves with a recoverable 16.2b barrels and 308 tcf of natural gas. Chevron, in partnership with YPF, has begun to exploit the Vaca Muerta formations shale oil reserves and has already invested $3b in the Loma Campana venture, which YPF has described to be the most important shale oil project outside the US. YPF has signed various agreements that will boost fracking activities in Argentina significantly. YPF and Petronas signed an agreement in 2014 to develop shale oil in Argentina’s massive Vaca Muerta formation with over $500m of initial investment. YPF and Petronas plan to use hydraulic fracturing to drill several dozen wells in a pilot phase and as many as 1,000 wells over the coming decade. YPF’s deal with Chevron could lead to about 1,500 wells drilled. In 2013, another deal was signed between YPF and Chevron, which has already turned that area, Loma Campana, into the second-biggest producer of unconventional oil outside North America. Chevron has invested more than $2b till date and is producing more than 25k barrels of shale oil a day at about 245 wells.

The Mexican government’s new energy reform legislation permits the use of fracking, after a majority of senators rejected a clause that would have prohibited the controversial technique. State-owned oil giant Petróleos Mexicanos (Pemex) estimates that Mexico’s shale formation holds the equivalent of 60m barrels of oil, more than the country has pumped out using conventional* means since the turn of the century. Mexico drilled its first shale gas well in 2011, in the Burgos Basin of northern Mexico, in the equivalent of the Eagle Ford Formation of the US. But as of February 2013, there have been only six productive shale gas and tight oil wells drilled in Mexico (a seventh was abandoned as non-productive), all producing from Eagle Ford equivalent. Mexico’s technically recoverable shale gas resource is 545 tcf., the sixth largest in the world.*

Venezuela has 167 tcf of shale gas and 13.4b barrels of oil reserves.* Much of these reserves are found in the state of Zulia which borders Colombia. The low oil prices have made it very difficult for Venezuela to explore and produce shale oil gas due to the high production costs. Venezuela is planning to begin its first shale gas exploration in western Lake Maracaibo in a joint venture with Brazil’s state-run Petrobras. The joint venture company is called Petrowayu, in which the state run oil company PDVSA has 60% stake, Petrobras has 36% and US based Williams has the remaining 4%.  PDVSA has already run initial tests for shale gas at La Guajira, also in western Zulia state, in the hope of discovering significant reserves of unconventional resources.

In Colombia, shale potential is mainly present in three of its 23 basins: the Middle Magdalena Valley (MMVB), Llanos, and Catatumbo basins, amounting to a total shale gas reserve of 55 tcf. Potential shale formations are also thought to exist in the Caguan-Putamayo, Cesar-Rancheria and Eastern Cordillera basin. So far, shale exploration has been predominantly focused on the MMVB. The primary source rock in the MMVB is the La Luna formation, which is considered to be of high quality, and can be compared to those of the Eagle Ford shale formation in the US. The MMVB is estimated to have 18 tcf TRR shale gas, roughly a quarter of that being wet gas. In addition, it contains significant oil deposits estimated at 4.8b bbl. In the latest round of oil and gas concession auctions carried out by the Colombian government, 19 of the 98 bids went to fracking sites, where foreign and national investors will attempt to exploit the deposits of shale oil and gas, most of which lie somewhere to the north of the centre of the country.

Bolivia is very keen to exploit its 48 tcf of shale gas as it fears running out of its conventional gas reserves by 2026. Back in 2013, the country’s state-owned Yacimientos Petroliferos Fiscales Bolivianos (YPFB) announced it would begin studies to identify shale gas deposits. At this point, however, there is no law that regulates hydraulic fracturing activities in Bolivia, but a hydrocarbons bill is underway which addresses the exploitation of unconventional gas.

In Peru, shale gas was found in the Devonian shale beneath the Santa Rosa 1X well in 2009, which was drilled by Maple Energy. Shale gas has not been previously developed in Peru, and Maple Energy is currently seeking investment partners for development at Santa Rosa.

In other smaller Latin American countries like Ecuador, Cuba, Trinidad and Tobago, and El Salvador fracking potential is meager, almost nil. Even if there is any little reserve, lack of investments and protests from environmental groups make it impossible for shale drilling to commence.

While shale gas prospects seem promising in Latin America, some fundamental challenges exist with respect to its viability. Financial viability of these projects is a question in most parts, especially Mexico and Colombia, where shale gas drilling is a costly affair.  Efficiency and quality control are difficult to achieve as shale drilling is still at a nascent stage, pushing cost up, more so in the absence of economies of scale of operations.  Choice of drilling equipment, stimulation technologies, and well spacing are some of the critical decisions that need to be taken. Large volumes of sand, water, and chemicals need to be transported to the drilling site, which can get logistically complicated. The right procurement, logistic, and supply chain strategies will ensure better quality and cost control. Therefore, E&P companies eying shale gas drilling in Latin America must depend on expert supply chain strategies to manage their logistics and the cost of purchased materials and services.

* According to the US Energy Information Administration (EIA)

Fracking Fever in Colombia

Fracking Potential in Colombia Blog Picture

In Colombia, shale potential is mainly present in three of its 23 basins: the Middle Magdalena Valley (MMVB), Llanos, and Catatumbo basins, amounting to a total shale gas reserve of 55 tcf. Potential shale formations are also believed to exist in the Caguan-Putamayo, Cesar-Rancheria, and Eastern Cordillera basin. So far, shale exploration has been predominantly focused on the MMVB region. The primary source rock in the MMVB is the high quality La Luna formation, which can be compared to those of the Eagle Ford shale formation in the US. This region is estimated to have 18 tcf TRR shale gas, roughly a quarter of that being wet gas. In addition, it contains significant oil deposits estimated at 4.8b bbl.

Colombia jumped onto the fracking bandwagon after its Mining and Energy Ministry gave the green signal to this practice in 2014. The government established a regulatory framework, so as to minimise the risks associated with fracking. In the latest round of oil and gas concession auctions carried out by the Colombian government, 19 of the 98 bids went to fracking sites, where foreign and national investors are now attempting to exploit the deposits of shale oil and gas. Shell, Ecopetrol (Colombia’s state-run oil company), Exxon Mobil, and Nexen Petroleum are a few who have purchased the rights to develop these sights. In this regard, the government specified that the bidders for unconventional blocks must have financial standing of at least $200m (compared with $6m required for onshore conventional blocks). This reflects the high costs of shale exploration in entering Colombian market and suggests that smaller players would need to join bigger companies if they intend to ride high on the wave of shale boom.

The government had initially hoped that commercial production of shale oil and gas could begin sometime in 2015. However, the drop in crude oil prices proved to be a dampener in Colombia’s hopes of developing shale deposits as a way of countering depleting conventional oil reserves. Global drillers including Exxon Mobil are deferring shale exploration plans as crude oil price plummeted. Colombian drillers including Ecopetrol and Pacific Rubiales Energy lowered exploration spending in 2015 as they focused mainly on production. Ecopetrol’s budget for unconventional reserves was $40m this year, compared with $240m in 2014. Royal Dutch Shell and ConocoPhillips have also deferred shale exploration spending in Colombia.

Despite Colombia’s competitive environment, exploration has until recently mainly focused on conventional methods. Concerned with dwindling natural gas reserves (currently 7 tcf of proved reserves) from existing conventional fields and the prospect of becoming a net importer within a few years, Agencia Nacional de Hidrocarburos (ANH), the state regulatory body on hydrocarbons, has introduced several policies in recent years to encourage shale drilling. For example, they introduced a 40% discount on royalties to make the exploration and production of unconventional resources even more attractive. In addition, natural gas producers in Colombia now have the right to export without prior Government approval, as long as total gas reserves meet at least eight years of domestic demand.

ANH conducted Colombia’s first shale block auction in 2012. It had high hopes for the second unconventional auction through Ronda Colombia 2014. However, shale plays auctions raised only about $1.4b, significantly less than the $2.6b expected originally. Despite this, Ecopetrol continues to control the majority of the market, managing about one third of the oil and gas licenses in Colombia. Shale exploration has become a critical component of Ecopetrol’s business plan, and the company plans to drill for unconventional hydrocarbons this year in the Middle Magdalena and Catatumbo areas, including nine stratigraphic wells, three exploratory wells and three productivity and study pilots.

As its current reserves will only last for about six years, the commercialization of Colombia’s proven shale reserve is essential to the country future energy prospects. However, commercial success will depend on the cost of exploitation. Fracking is a relatively expensive proposition if it is done correctly, due to quality, environmental, and efficiency concerns, which is why the major firms like Halliburton, Schlumberger and Baker Hughes are well-positioned to execute it. Choice of drilling equipment, stimulation technologies, and well spacing will determine the productivity of a field. Reservoir response should be carefully monitored over the life of a project to make necessary adjustments to the operational model. The drop in oil prices put on hold the beginning of shale exploration that was planned for the start of this year.  Fracking at $45-50/barrel makes it extremely difficult for smaller, independent and/or local E&P companies to get started. Shell and Exxon’s have already delayed the shale drilling decision due to current price level.

The companies getting into shale gas production in Colombia today will need to streamline their procurement costs and invest in productivity, technological, and operational excellence. Operational efficiency, a skilled workforce, effectiveness in supply chain management and monitoring of costs will be critical.