A Single Cyber Attack can Cause up to over $60b Loss for the US Economy

Attacks on control systems for critical infrastructure have risen by more than 250% over the past four years in the US, as web linked communication systems have proliferated and nation-states seeking geo-political and economic supremacy added to the incidence of amateur hacking. Of all the critical infrastructures targeted, power grids have become the ripest target because most or all sectors of economy depend on them: cyber attacks on power grids can be exponentially effective by crippling vast swatches of the industrial and commercial sectors. Furthermore, the absence of power paralyzes many national security systems, making physical terrorist attacks much more effective and more likely.

The Crippling Costs and Risks of Cyber Attack in Power Generation, Transmission, and Distribution

The US power grid has recently suffered three major cyber attacks. In 2012 and 2013, Russian hackers were able to successfully send and receive encrypted commands to U.S. power generators. In 2015, unauthorized cyber hackers injected malicious software into the grid operations that allowed spying on U.S. energy companies. And also, in 2015, US law enforcement officials reported a series of cyber attacks that were attempted by ISIS targeting the U.S. power grid. 

The costs of these cyber attacks are massive. A cyber attack targeted at 50-100 generators that supply power to 15 Northeastern United States, including Washington D.C., would leave almost 93m people without electricity and cause $62 billion to $228 billion in economic losses in the first year. Damage to turbine generating power plants and metering systems would cost $1 billion to $2 billion. Loss of electricity revenue would cost the utilities $1 billion to $4 billion. And loss of revenue to electricity consuming customers of the utilities would cost $60 billion to $222 billion. If recovery takes longer than a year, these costs would multiply. This damage assessment is according to a study by the Centre for Risk Studies at the University of Cambridge.

The U.S. power system is more vulnerable than most. It was never designed for network security. Moreover, since U.S. power plants are now connected to the internet as a part of setting up advanced grid and metering infrastructure, a wide range of new attack points are now available to attackers. Finally, the US electrical grid is also a decentralized network owned by numerous local operators, and security standards vary from utility to utility. More permanent damages, such as those inflicted by the Stuxnet virus in Iran’s nuclear program, cannot be ignored.

However, attacks are taking place in other countries, too. On December 23, 2015, three Ukrainian electricity distribution companies suffered power outages due to a massive cyber attack. The attackers used BlackEnergy and Killdesk malware to disable both control and non-control system computers. The attackers simultaneously flooded the utility call centers with automated telephone calls, impacting the utilities’ ability to receive outage reports from customers and decelerating the response effort. Altogether 30 substations were disconnected for more than three hours, causing approximately 225,000 customers to lose power across various areas. BlackEnergy malware had first appeared in the Russian underground for use in distributed denial-of-service attacks. An evolved version of it, BlackEnergy3, is a distinctive tool and has only been used for cyber espionage.

Areas of Particular Vulnerability

All three segments of the power sector supply chain are vulnerable to cyber attacks:

  1. Generation: SCADA systems in power plants are vulnerable through hardcoded passwords, weak authentication solutions, firmware vulnerabilities and ladder logic. Viruses such as ‘Stuxnet’ can be used to exploit these vulnerabilities to execute cyber attack on the computerized control systems in a well-targeted manner. Some of these sophisticated malwares can cover hide its presence until well after the damage is done.
  2. Transmission: Transmission systems have been the most targeted sub-system in the power system value chain..The relays on the transmission sub-system are time sensitive, and delays of even a few milli-seconds can negatively impact the performance of power transmission. The common cyber attacks in this area include Distributed Denial of Service (D-DOS), which can cause the network and communication channels send delayed responses and cause the malfunction of the Smart Grids.
  3. Distribution: Smart meters, which are increasingly common in network infrastructure, connect to the central control or Network Operating Centre (NOC) room of the utility to transmit and receive data. Poor security implementations in the smart meters could make it possible for an unauthorized third-party to intrude the NOC. The consequence can be disastrous if the meter has the “switch off” capability. Given the scale of utilities, which for large utilities could run into millions of smart meters, security vulnerabilities in this area can lead to widespread damage.

The four most vulnerable types of attack to anticipate are: 1) Intrusion in the intelligent electronic devices through false data injection attack, making SCADA send wrong information to the control systems. This can take place at the site of power generation; 2) Attacking power system control centers (PSCC), typically called DoS (denial of service) attack which causes de-synchronization and delay in the PSCC’s ability to take optimization decisions. Power generation and transmission are most prone to these DoS type of attacks; 3) Crippling electronic AC transmission system which controls power transmission capability of the power network. Both transmission and distribution networks are exposed this type of risk. ; and 4) Use of malwares to steal power network data which could be at the generation, transmission, or distribution points, where data is continuously being stored with respectto peak loads, voltage variations etc.

Supply Chain and Procurement: The Weakest Link

The infrastructure supply chain is particularly vulnerable. Malicious components enter into the supply chain nearly two years before an attack occurs, according to the Cambridge study. Even a slight oversight in procurement could bring the whole system down. Cyber attacks at the supply chain can occur when hardware and software have been counterfeited, tainted, or compromised, resulting in failure of components as designed. Components fitted with rogue malware entering into the supply chain and eventually in the utility, compromising the security mechanisms.

For example, a malicious code could be inserted into software that compromises security or kill-switches/backdoors, enabling attackers to steal data or disable the system. Maintenance and repair activities-software upgrades or equipment services, whether done onsite or remotely, could also allow hackers to corrupt or compromise systems. These compromised components could enter the supply chain from the secondary suppliers or contractors, which are less visible to the utility operators.

Major utility companies are now becoming aware of the risks that cyber attacks pose, and are investing capital to get their systems more secure to attack. Utilities are most vulnerable to cyber threat from a third tier supplier, which has no direct connection to the utility and supplies the equipment through a third party vendor or a distribution channel.  The second tier suppliers also carry the same risk but are more visible and vetted.

What Power Companies Need to Do

Taking into account the above scenarios, the second and third tier suppliers of components and services have to be examined and assessed more strictly.

There are already a number of mandatory standards and requirements for supply chain integrity led by both vendor and government organizations such as NIST, ISO, Common Criteria, and OTTF. While these standards need to become more robust given the growing sophistication of cyber attacks, the least companies can do is to seriously adhere to the existing standards and guidelines.To begin with, the power companies must disclose all features and disable what is not required, limit user capabilities, and block all unauthorized accesses.

As a part of the supply chain cyber security risk mitigation plan of action, the next most important step is to manage procurement risk. This includes joint development of procurement process with representatives from sourcing, legal, technical, and functional subject matter experts.The vendor pre-qualification criteria and all RFPs must clearly specify compliance to vital security standards.

Given the high cyber security risk emanating from second and third tier suppliers, the power companies must make good use of third party certification and accreditation for the vendors, and must also initiate audits as well as scheduled and unannounced inspections for pre-qualified vendors.

Where is the Industrial Gases Mega-merger Trail Heading?

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.

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.

Boston Strategies Targeting Significant Emission Reduction

b2ap3_thumbnail_BSI-Carbon-FootprintBSI has committed to reduce its carbon footprint per revenue dollar for fiscal year 2015 by 63%. This follows a 21% reduction in absolute carbon emission during 2014.

As a consulting firm we do not emit any carbon through manufacturing or conversion itself, which constitutes ‘Scope 1 emissions’ according to the standard guidelines of GHG Protocol for businesses developed jointly by World Resources Institute (WRI) and the World Business Council for Sustainable Development (WBCSD). We do, however, occupy workspace and travel on airplanes (‘Scope 2 emissions’), and commute to work (‘Scope 3 emissions’).

We are reducing our footprint by increasing local staffing, ramping up the use of videoconferencing, and incentivizing low-carbon commuting and home officing. “Multi-local staffing is an initiative we’ve been pursuing for three years. Not only is it environmentally responsible, but it also helps to meet our clients’ local content goals.” explains David Jacoby, President.

“We’ve been working on videoconferencing since 2010, and after several generations of technology we feel that we have achieved a highly effective work mode,” adds Erik Halbert, Principal.  “Telecommuting is opening up flexible options for job candidates, which helps increase the overall caliber of our talent pool,” adds Alok Gupta, Senior Associate.

Our primary goal behind calculating our carbon footprint was to see how we are performing in our efforts towards mitigating the impacts of global warming. Accordingly, we set stricter targets for ourselves to further lower our footprint. Even though our business operations are growing every year, causing an upward pressure on footprint, we still strive to lower emissions by a greater magnitude than ever before.

Our workplace practices categorically focuses on saving energy. Our employees make sure they switch off the laptops, lights, fans, and air-conditioners when not in use. A major chunk of our emissions comes from air-travels, and we give special attention to make sure that we keep our emissions level as low as possible in this area. For this, we make sure that we optimally plan our travel. For conferences and business meets, we try to send employees located closest to the venue.

Although BSI is under no compliance obligation to track or report its carbon footprint, we are doing so entirely voluntarily. Through our practice, we’d like to encourage other firms to take up the exercise of monitoring and managing their carbon footprint. At the end of the day, every drop will make a difference.

About BSI

Boston Strategies International (BSI) is a consultancy firm that compresses the lead time and reduces the investment in major capital programs for oil, gas, and power operators through value chain cost engineering, targeted strategic sourcing, and supply contract negotiation. BSI operates through its offices at multiple global locations including USA, Turkey, India, and Columbia. BSI serves national and international oil companies, power producers and Gas Utilities, Wind and Solar power providers.

BSI carries out its business activities with utmost sensitivity towards environmental concerns, which forms a principle pillar of our business ethics and work culture. We deeply understand the magnitude and criticality of global warming, and want to do our best to contribute to the mitigation efforts.

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