insightsENERGY ISSUED JANUARY 2014

Energy Risk ManagementExploring the risk challenges ofa dynamic, changing industry

In this issue:• Pipeline operational risks• Risks of developing renewables• Shale oil and gas production• Floating production, storage and offshore processing• Mining• Risk engineering energy• Energy claims management

2

In this issueBright energy future is powering new risks ........................................ 3

Obtain smarter energy insurance solutions ........................................ 4

Risk management issues in oil and natural gas shale recovery ............ 7

Risks associated with the ownership and operation of pipelines ...... 10

FPSOs helping to open up new frontiers of offshore energy ............ 14

Renewables – bright future, but not without risk ............................. 17

Evolving market challenges impact mining risk management ........... 20

Small risk control lapses can have major consequences .................... 22

Good communication vital to energy claims management ............... 24

3

insig

hts 14

Our energy future is brighter than ever

The energy renaissance in North America and around the globe continues unabated, with new technologies, discoveries and approaches meeting the demands of an energy-hungry world. A burgeoning, US shale gas industry has resulted in growing supplies and decreasing prices. Utilizing the same hydraulic fracturing techniques that are increasing natural gas supplies, oil production in the continental US is on an upward trajectory for the first time since the early 1970s. At the same time, technical advancements and breakthroughs in renewable energy promise increased output and lower costs in the years ahead.

Our energy future appears bright indeed, with some analysts predicting virtual US energy independence in the near term. However, any growing industry brings an expansion of risk. Energy has always faced a variety of inherent risks, but as advanced techniques breathe new life into mature oil fields and previously inaccessible resources, the risks associated with such operations are evolving as well.

In addition, physical and operational risks are not the only challenges facing today’s energy companies. A growing range of regulatory, political and marketplace issues are further complicating the risk management picture. Those charged with managing these risks can benefit greatly from clearer understandings of what they are and how they can be addressed.

In this issue of Insights, we will explore some of the key themes facing today’s energy companies, including, among others, risks associated with:

• Hydraulic fracturing of shale deposits for oil and natural gas

• The promise of renewable energy technologies

• Risks associated with oil and gas pipelines

• Floating Production, Storage and Offloading (FPSO) facilities

Energy is a global and interconnected industry. It would be unrealistic to assert that any one document might address all of the risks faced by all of the various segments of this business. Our objective is to add to discussion about the evolving risks facing today’s dynamic energy industry.

New technologies and approaches driving an energy revolution

Jeanne Jankowski Head of Energy,

Zurich Global Corporate in

North America

4

Obtain smarter energy insurance solutions through good risk understanding and better communication

5

insig

hts 14Effective risk management does not happen in a vacuum. Energy companies – or any other organizations, for that matter – need to understand their own risks and how they interconnect with the risks of a wider, and increasingly volatile, world in order to develop coherent risk management and mitigation strategies

In this process, it is also helpful for risk managers to understand some of the dynamics affecting the insurance industry so they know what to expect from their insurers and what their insurers expect from them.

Within the energy insurance business, there is currently a consensus among industry watchers that significant overcapacity exists in most corners of the segment. Historically, the typical consequence of overcapacity is downward pressure on pricing, or at least a brake on price increases.

However, recent events have placed significant pressure on insurer balance sheets. In 2011, devastating earthquakes in New Zealand and Japan, the Japanese tsunami, floods in Australia and Thailand and other events hammered results. The year 2012 was marked by the arrival of Hurricane Sandy late in the fall. During 2013, the insurance industry responded to massive flooding in Europe and Canada, devastating tornadoes in Oklahoma, spectacular wildfires in the western US, and other events. So, while capacity clearly exists in the energy insurance marketplace, it may not be as readily available in the amounts some operators require for specific risk factors as it has been in the past.

Complicating matters has been a historic lack of reliable risk modeling data. While past models were never as accurate as underwriters would have preferred, recent catastrophe model revisions and updates, specifically RMS 11, may have added uncertainty. Insurers must now consider annual average losses tied to “peak zone” assessments that could result in higher reinsurance requirements, and thus higher rates for primary customers. Some companies may have had to scale back on some business because updated models may suggest greater exposure than previously thought. Some carriers have already reduced limits and capacity they are willing to provide to the energy marketplace, while others have effectively taken themselves out of the market altogether because they don’t believe they can compete effectively.

Finally, historically low interest rates have been a persistent challenge in the aftermath of the global financial crisis. While the global recession was declared over by many economists as long ago as 2009, the industry’s investment portfolios have a long way to go to return to the levels of robust growth celebrated in past years.

Another factor affecting the well-being of corporate balance sheets, is the Western world’s debt crisis. Many international insurance companies hold sovereign bonds in their portfolios. The threat of defaults – especially within the Eurozone – has created huge uncertainties and corresponding falls in the value of bonds held, thus potentially hitting balance sheets hard. Adding to this concern is the fear of a return to recessionary times. This affects everyone, whether through inability to raise funds for development or outright job losses resulting in a reduction in demand for the products produced.

6

Falling demand means reduced income and a potential tightening of capital investment.

What does this mean to the CEO, CFO or risk manager of a large energy company? Simply, at the very time the energy industry is expanding at a record pace, the insurance industry is under significant balance sheet pressure. Hence, the key to achieving the best terms and capacity on casualty and other lines of business will hinge on how well the energy company can differentiate itself in its approach to risk understanding and mitigation

As in so many things, the process begins with asking the right questions:

• How confident are energy C-suite executives and risk managers that they understand their risks and can communicate them effectively to their insurance carrier?

• What practical mitigation strategies does the organization have in place to control its physical and financial risks?

• What compliance and governance mechanisms exist to keep the organization on the right path to effective risk mitigation?

• How effective will an individual facility’s mitigation plans be in helping it get back in business after a loss?

• How seriously does the board of directors take the subject of risk management in general and how is this communicated down the line?

The answers to these questions are particularly important because the energy risk environment is changing as rapidly as all other aspects of the business. Insurers are now seeing operational risks they have never been exposed to before. Companies are drilling farther offshore and in deeper waters, sometimes at extraordinary depths. They are deploying prototypical exploration and production assets that did not even exist a few years ago. The time and expense required to replace that equipment is potentially much greater than would be the case with older, more established technologies.

In this changing environment, the key to achieving the best mix of capacity and terms is a clear and open dialogue between the insurance carrier, the broker and the customer based on a thorough understanding of risk exposures. The process can be helped along greatly when the customer provides as much information as possible regarding critical supply chains, spare capacity and other issues that will help the insurer better understand what it is getting into and what the anticipated outcome of a loss might be.

Keep in mind that an experienced energy insurer can be an enormous help in this process. Insurers often have an array of tools that can aid in benchmarking against competitors, assess individual locations against a consistent, risk management standard and generally rate the competence and readiness of the organization to deal with the contingencies it may face in a changing energy world.

7

insig

hts 14

7

Since the 1970s, geologists have predicted that significant petroleum and natural gas reserves existed in massive oil shale deposits. In recent years, rising global energy demand, new technologies and improved recovery techniques for extracting petroleum and natural gas from deep shale deposits have put shale back on the national energy agenda in the U.S. and Canada in a major way, with shale exploration and production on the rise in other regions of the world as well.

Risk management issues in oil andnatural gas shale recovery

The U.S. Department of Energy notes that unconventional natural gas supplies (including shale gas) now account for 46% of total U.S. production, and could rise to more than 60% by 2020. Shale gas opportunities are located throughout the West, the South and the Northeast’s Appalachian Basin. The Barnett field in Texas spans 5,000 square miles and provides 6% of the U.S. natural gas supply. The Marcellus area in the Northeast U.S. covers 10 times the square miles of the Barnett formation, leading some experts to believe it could be the second largest gas field in the world. The net result may be that the U.S., once a net importer of natural gas and liquefied natural gas (LNG), may soon become a net exporter of LNG to Europe and Asia.

8

According to a recent article in The Economist, Europe has almost as much technically recoverable shale gas as the U.S. – 639 trillion cubic feet compared with America’s 862 trillion. However, European firms face challenges American shale gas operators do not. For one thing, European shale formations tend to be deeper and harder to reach. For another, there are fewer contractors with shale experience in Europe simply because there has been less exploration and production employing the hydraulic fracturing – “fracking” – techniques widely used in the U.S. Many European regulators remain uncertain about the benefits versus risks of fracking, especially with regard to the safety of subsurface aquifers and even the theoretical potential to trigger earth movements. This has resulted in more restrictive permitting requirements, more frequent denials and thus greater hesitancy on the part of operators to allocate investment to fracking techniques.

However, based upon America’s unprecedented success in increasing recoverable natural gas reserves through shale discoveries, and prompted by new discoveries on the European Continent, including a formation under Austria that some suggest might supply the country’s needs for 30 years or more, some EU governments are giving more serious consideration to the potential benefits of fracking recovery. In addition, the natural gas price and supply shocks experienced by Western Europe as a result of the recent disputes between Russia and the Ukraine are still very much on the minds of many European consumers and regulators. Between the prospect of the U.S. becoming a major, new source of supply and recent shale discoveries in Europe, the

potential for greater energy independence, lower consumer cost and greater reliability of supply appears positive. The desire to drive these benefits could make EU regulators more accepting of fracking, the caveat being that any operations must be done in adherence with stringent environmental requirements.

Reaching ‘hard-to-get’ energy resourcesFracking is indeed the most effective way to extract shale oil and gas from rock formations with low permeability. An initial, vertical well is drilled far below the level of local, underground aquifers to reach deep shale deposits. Once the well reaches the target depth, the drill and pipe casing curve horizontally to follow the resource-laden rock strata. Then, a water-sand mixture is injected into the underground rock under high pressure, creating tiny fissures into which the sand will lodge. This keeps the fissures open and allows petroleum or gas to escape into the well for recovery at the surface.

Technical risksEven for experienced subcontractors, a number of potential risks may emerge during shale oil and natural gas fracking operations. These include:

• Bending of the steel pipe – The pipe needs to fit into a small diameter hole and then curve into the horizontal leg. Although improvements have been introduced to the steering tools used in placing the pipe in horizontal wells, the bend is the one area that is susceptible to failure under high pressure if not installed to the highest standards.

• Integrity of pipe and casings – Given the accelerated pace of fracking in the U.S., shortages in milled pipe have led some contractors to buy foreign-made supplies that may not be fabricated or rolled to all the required industry standards and specifications. In addition, in some cases sections of casing may be obtained from multiple fabricators, which can also increase the risk of breaches. Similar concerns will affect European operators as fracking operations

According to a recent article in The Economist, Europe has almost as much technically recoverable shale gas as the U.S. – 639 trillion cubic feet compared with America’s 862 trillion.

9

insig

hts 14

increase on the Continent. Hence, it is important for operators everywhere to review their casing programs to determine what specific pressures can be applied and to limit squeeze pressures to levels below the pipe’s design specifications.

• Perforation of steel casing – However well pipes are fabricated, cyclical stress on well casings can cause perforations even when manufactured to the appropriate industry standards. Repeated high pressures of anywhere from 8,000 to 12,000 PSI can exert tremendous stress on casing integrity, potentially perforating the pipe and exposing the interior to the exterior rock formation.

• Fracturing pressure intermediate casing – Intermediate casings used in the drilling process usually have a lesser internal yield or burst pressure, which makes it unsafe to attempt fracking through these types of casings.

• Surface valve failure – The integrity of surface high-pressure values in the fracking process is critical. As a result, it is necessary to engineer redundancy into the fracking valve systems at the surface in order to have a backup if a valve becomes inoperable.

Operational risksIdeally, shale fracking operations are performed by subcontractors with years of experience in high-pressure, deep-well drilling. But current high demand is putting pressure on crews to keep up with workloads. It is critical that oil and gas companies contracting these services require subcontractors to carry appropriate coverage and limits that dovetail with master service agreements and indemnities.

Equipment values associated with the specialized equipment deployed onsite during the fracking process also present significant risk management challenges. Well operators may periodically have third-party contractors on location with anywhere from USD 30-40 million worth of specialized equipment. This will include a fleet of trucks rigged to carry fracking solutions and high-pressure pumping equipment for injecting those solutions into the

shale formation. Finally, the personnel demand of a dramatic increase in fracking operations around the US has greatly stressed the available talent pool of heavy trucking professionals. Driver fatigue has become a significant risk for many operators, opening up the potential for increased risk due to the legal liability implications of drivers’ long hours and alertness.

Old wells, hidden risksFracking can restore productivity to older fields that have experienced production falloffs. However, a hidden risk in such fields may be what regulators sometimes refer to as “orphan wells.” The retired, capped wells may have been out of production for so long a time that they are no longer included in written records and may have been essentially forgotten. If not properly plugged and abandoned, or in the event of a poor cement job, any attempt to produce hydrocarbons from a deeper formation in an existing field could result in the operator finding an unexpected charged zone that could result in a well control event in their own well and perhaps the orphan well. As a result, a high degree of due diligence (field research) must be undertaken prior to attempts to employ fracking techniques to extract hydrocarbons in known fields, including thorough site inspections and research into all available records.

10

Risk management issues associated with the ownership and operation of oil and natural gas pipelines

The utilization of pipelines literally reaches back to antiquity. The Romans used lead pipes to distribute water as early as 500 B.C., while the Chinese were reputed to have used bamboo pipelines to light their capital with natural gas in 400 B.C. The movement of petroleum through fixed pipelines arose simultaneously in the United States and in Europe in the late 1870s.

11

insig

hts 14

To this day, pipelines remain the most economical and efficient means of moving large quantities of oil, natural gas and other product from wellhead to point of processing and ultimate distribution. The U.S. alone currently possesses more than 250,000 mile of pipeline networks, with more under construction. In Europe, the pipelines of the municipal gasworks date back to the 19th century in large cities like London or Paris etc. These operations set similar and different challenges to those responsible for the risk management / HSE and the liability insurance underwriter.

In recent times, pipeline projects have generated controversy due to concerns about perceived safety and environmental hazards. However, despite the massive presence of oil and natural gas pipeline networks across North America, Europe and other parts of the globe, loss events have been of relatively low frequency. While much the worlds’ pipeline infrastructure is aging, with adequate inspection and maintenance these systems can provide reliable, cost-efficient service for many years.

There are many types of pipelines currently in widespread operation:

• Flowlines and gathering lines are short-distance conduits used to move a variety of products to and from processing facilities. They are generally of low pressure and diameters.

• Feeder lines move oil and gas from initial processing and storage facilities to main transmission lines.

• Transmission lines are the largest, longest-distance conduits for the movement of oil and gas. They may be of large diameter and generally use high pressure to move product over long distances.

• Product lines transport refined petroleum products from refineries and other processing facilities to distributions points.

• Distribution lines allow for local, low-pressure distribution from the transmission line system to downstream facilities and households.

All pipelines may be subject to failure due to corrosion, undetected cracks and weaknesses, and the actions of third parties. The pipeline operator, owner must show that the risk management organization is able to ensure a safe and responsible operation which fulfills not just technology, process and organization standards but also the legal standards set by law and by contract.

A frequent cause of pipeline failure is external damage, such as mishaps involving the use of heavy equipment during construction, excavations undertaken without adequate advance planning, accidents during pipeline maintenance and similar situations.

12

Major risk factorsThe remoteness of long stretches of pipeline or the difficulty to reach it remain a major risk factor in the event of a break or leak. For example, a number of liquid and gas pipelines extend across very long stretches of prairie or taiga forests. The distances, the terrain and the remoteness make all risk management operations such as surveillance, maintenance, repair and incidence response more complicated, costly and requires dedicated resources and skills.

A frequent cause of pipeline failure is external damage, such as mishaps involving the use of heavy equipment during construction, excavations undertaken without adequate advance planning, accidents during pipeline maintenance and similar situations. For all pipeline operators, especially those with lines running through

high-density industrial parks or residential areas, making sure work done in proximity to pipelines strictly conforms to all codes, notification procedures and monitoring is an absolute necessity.

Restarts following a pipeline shutdown also require careful monitoring and procedural controls. In one case of a minor break near a waterway in North America, pipeline telemetry and safeguards performed as designed. However, they were overrode by operators and the pipeline restarted several times before it was determined that there was in fact a break in the line. The company has now installed a procedure that prohibits operators from overriding shutdown procedures without consulting the risk management function and other controls higher up the chain of command.

3. Intersections / Crossings with other pipelines (onshore or offshore) Many pipelines will intersect other pipes owned either by the same company or by others. Such crossings are agreed to and regulated by contract “crossing agreements”. All issues, including the relevant technical data of all the pipelines involved and the neighborhood information at each location, should be included. When analyzing the contract the underwriter must understand the particular nature of knock-for-knock agreements particularly in the offshore area. A special challenge might be an industrial park, a marine or non-marine terminal area.

1. “High Consequence Areas” When applying for a permit to construct and operate a pipeline the authorities are looking also for a declaration of the “High Consequence Areas” (HCA) or “High Impact Area” or similar terminology, depending on the country. This term defines an area with a “high” concentration of residential and commercial development where an accident might cause large bodily injury and/ or property damage.

2. Crossings Risk is elevated whenever pipelines intersect rivers, lakes, roads, highways, railways and other natural and/or artificial features. Whenever possible, pipelines should follow rights of way that steer as clear as possible of such complicating factors. These crossings are agreed to and regulated by contract or permit, be it with legal entities constituted under civil law or by public authorities. All the issues including the liabilities of the contract parties are or should be determined in these contracts or permits.

A liability insurer very much wants to look at the following factors to determine the risk and loss profile, which in turn can influence the attraction to accept the risk of an individual pipeline:

13

insig

hts 14

4. Onshore and offshore earth movements, land slides and flooding hazards Flooding poses another serious

(onshore) risk. The hydraulic pressure of moving waters can easily undermine above-ground pipeline supports and expose subsurface lines, with predictable results. Immersion of valve couplings and control equipment can result in a range of mechanical failures. Pipelines submerged in flood waters can even become vulnerable to strikes by boat hulls or other floating debris.

5. Particular hazards to which offshore pipelines are exposed Apart from the hazards described earlier there are those linked to the operation of watercraft. These are the use of nets by fishing vessels or anchor dropping operations and the lowering, unloading or loading of heavy equipment. This paper does not address the issues of offshore or onshore oil and gas production activities. These activities might impact pipeline operations. However, the underwriter is able to control or avoid the most important hazards due the standard exclusion language which applies the hazards caused by wells.

Ground movement, landslides, deformation and liquefaction of subsurface soils due to earthquakes are common hazards in earthquake-prone regions. The most obvious consequences are fractures and compressions in lines resulting in loss of contents, interruption of service, explosions, fires with potential for bodily injury and property damage (pollution). Such displacements are not uncommon during major quakes.

14

FPSOs helping to open up new frontiersof offshore energy productionAs oil drilling operations move farther offshore and into deeper waters, and/or into territories in remote, less developed parts of the world, one of the biggest challenges they face is the availability of infrastructure needed for collection of product so that it can be efficiently recovered, processed, stored and moved to onshore processing facilities.

The answer in many cases has been the deployment of Floating Production Storage and Offloading (FPSO) systems – moveable platforms that can serve undersea oil fields in parts of the world where there is no available infrastructure to transport the hydrocarbons to shore.

Old ships, new risksMany FPSOs are converted tankers with a large percentage being leased from specialist FPSO operators. FPSOs converted from ships often offer the shortest and the cheapest routes to production. Their main limitations include a lack of ability to operate dry tree and technical feasibility of mooring in very deep water in harsh environments, although purpose-built FPSOs may be more versatile for use in very deep water and harsh environments.

There are numerous management systems, such as management of change, permit-to-work, contractor controls, for fixed platform and onshore operations which are transferable to FPSO facilities. The owners/operators of FPSOs should be constantly reviewing these segments for best practices.

The industry standard is to design the hull to a classifications society’s Floating Offshore Installation Rules. Occasionally owners will include the topsides within the classification envelope, when the requirements also embrace the classification society’s Floating

Production Installation Rules. However, the majority of FPSOs class the hull and not the topsides. The topside structures are checked within the hull classification envelope as are the basic marine systems that are relevant to the hull and topsides. There is no requirement for FPSOs to be classed by law, however, most prudent FPSO owners choose to build and operate their vessels to classification society standards, and some choose to maintain class in service for insurance, mortgage and marketing purposes.

It is industry standard that classed FPSOs are designed for the initial environmental conditions that will be present at the field location. The design of environmental loads for hull, topsides and moorings should be such that it considers the most severe loading conditions. In some locations, the values of these extremes are not universally agreed and quite often can differ significantly. Underestimates of current have caused issues with early failures.

In general, FPSO units pose different risks in different parts of the world:

• Large currents in the deep water zones of the Gulf of Mexico

• Challenges of getting off and back onto a well location following a hurricane

• High seas and strong currents in the North Atlantic

insig

hts 14

15

• Long period swells in West Africa

• Shorter, higher seas in the North Sea and temptation by operators to employ cheaper FPSOs less capable of 360-degree rotation since the major storms often (but not always) come from one direction

• Generally more frequent bad weather in the North Sea leading to fatigue issues for hull and for moorings

• The need to disconnect for icebergs offshore Eastern Canada.

As exploration and production has progressed to deeper and deeper waters, there has been a move toward dynamically positioned FPSOs. These units are kept in place with the aid of computer controls, Global Positioning Systems and similar technologies. To achieve optimal safety and performance, all hardware and software components must work as an integrated system. This includes the position reference systems and sensors, DP computer system, the power plant including the power management system (PMS), the thruster remote control systems, and the local thruster control systems as well as the auxiliary systems needed for electric, mechanical and hydraulic power, lubrication, cooling, ventilation and fuel. How software is maintained after delivery and installation is a key safety and performance issue. Often, the amount of involvement of the original software designer will be uncertain. The primary cause of failures is said to have been when the equipment is under manual control and not under the control of the software. The lack of information on lessons learned in DP system failures is a significant issue

for the industry as it is difficult to obtain statistical information of drive-off, blackouts and drift-off, etc.

For conversions of older vessels, certainly those over 30 years, it is important to ensure an extensive drydock inspection prior to conversion. Such inspections are highly specialized undertakings and must be performed by experienced inspection professionals. Quite often there is a time crunch after the FPSO project is awarded and the

16

vessel is selected by the contractor. As a result the conversion may not have been inspected in sufficient detail during the bidding process to confirm its definitive suitability, leading to more repairs or changes than originally anticipated. It is also important for the designer of the conversion to ascertain the previous trading life of the vessel in order to evaluate the approximate fatigue life left in the hull.

Trading ships are analyzed using the North Atlantic spectrum of waves to determine fatigue of the hull. However, if the vessel has been used elsewhere its residual fatigue life may be more or less depending on its trade routes. If it were to have had a life trading in the North Sea it would have a far worse fatigue life than the normal North Atlantic spectrum. Likewise, if the vessel served most of its time in South East Asia it may still have most of its fatigue life left after many years of service.

Since most of the rules and standards are revised from time to time, it is important to know the changes over the years. Under class rules, there is grandfathering based on the date of contract or date of keel laying. Older concepts such as centrally moored turret FPSOs and those with drag chain systems pose a greater risk to physical change. Likewise, if DP systems software has not been upgraded in some years, it may pose a higher risk. Mooring failures do frequently occur and careful examination of the moorings on a regular basis is important.

Industry standards and rules are written to reflect past design practice that have proven successful and usually don’t cover the new or novel structures. Some new FPSO

designs now incorporate drilling operations which can present significant additional risk. Drilling is a risky business in itself, but when done in an environment where production of hydrocarbons is also taking place, the risk may be elevated considerably. Best practices may include restricting drilling operations while offloading product to tankers in order to reduce the possibility of a loss event.

FPSOs designed to disconnect from moorings to avoid cyclones, hurricanes or icebergs should have their propulsion systems tested on a regular basis so that the systems are available at the critical time. The propulsion system may have been idle for years until it suddenly needs to be pressed into service to move a unit out of danger. Contingency plans for the use of tugboats should be in place in the event propulsion systems fail at this critical moment.

At other times, the movement of an FPSO may be undertaken to redeploy it to another field. Risk issues in the movement of the vessel include the age of the vessel, the types of hull steel used in the construction of the FPSO, which will determine remaining hull-fatigue life in the new environment, historical maintenance of the unit and other factors. Confirmation is required to ensure that the FPSO has been re-evaluated for the new environmental loadings.

Because an FPSO may be on location for years, there may be a tendency to reduce and eliminate the marine crew necessary for the operation and management of the unit. However, since ballast systems and other marine components are required to maintain stability, it is very important to have qualified marine-rated crew on board at all times to handle unexpected or complex situations. In addition, FPSO operators should observe the need for practice drills and refresher training for crew members similar to those performed on fixed platforms and onshore facilities.

Drilling is a risky business in itself, but when done in an environment where production of hydrocarbons is also taking place, the risk may be elevated considerably.

insig

hts 14

17

Questions remain about ultimate commercial viability and scalability of alternative technologies. Will renewables be viable in sufficient scale to make realistic contributions to the total energy equation? Will those contributions be delivered with the consistency and reliability consumers expect when they flick on a light switch? Widespread acceptance of renewable and alternative energy will only be assured by the promise of consistent reliability regardless of external environmental conditions. Given that some alternative technologies are still in early stages of deployment, track records regarding reliability, “performance risk” and related liability exposures remain sketchy.

SolarIt must be noted that the term “solar power” covers a variety of applications. The first images that enter the public mind in discussions of solar power are the large, black photovoltaic panels mounted on rooftops or in ground-level “farms” directly converting the sun’s energy into electricity. Solar thermal panels and devices are used to heat water for residential and commercial heating and other purposes. Perhaps the most ambitious and systematic harnessing of the sun’s energy is represented by “heliostat” power plants employing tall, central towers surrounded by arrangements of aimed mirrors. The mirrors concentrate the sun’s energy upward toward a structure

Renewables –Bright future but not without risk

With increasing global demand on fossil fuels combined with growing concern about climate change, worldwide interest in the renewable energy sector has grown exponentially. The renewable energy future appears bright, but it is not without potential risk and obstacles to growth, both technical and political.

18

high on the central tower where water or some other fluid medium, such as liquid sodium salts, is heated to very high temperatures and used to drive power generating turbines. These units are particularly effective in deserts and other regions with reliable sunshine. However, heliostats have come under some criticism from environmental groups over claims of intrusiveness in sensitive desert environments as well as the ongoing need for water for steam drawn from scarce water supplies in desert regions.

Rare earth metals are critical to the manufacture of photovoltaic components. Unfortunately, many of these metals are sourced from a relatively small number of countries, some located in less politically stable parts of the world. As a result, political risk and supply chain risk are key concerns, both of which can be addressed by insurance solutions presently available. Further, the relatively small number of dedicated manufacturers means that business interruptions and supply chain risk due to a manufacturer being “down” are ever-present concerns.

BiofuelsLiquid biofuels for transportation and biomass electric power generation depend on the availability of agricultural feedstock and waste products. This may present operators with supply chain risk as well as environmental issues that may require specialized liability insurance solutions. If a company is manufacturing biofuels in a dedicated refinery, it will require coverages able to respond to the same pollution and transportation risks faced by traditional fuel refinery operators.

Product liability insurance covering the fuel products being manufactured may also be needed. It should be noted that biofuel manufacturers have come under increasing criticism, and some lawsuits, from environmental organizations claiming that the byproducts and processes of biofuel production are causing damage to aquatic systems, either by utilizing too much water or returning waste products to water systems. As a result, securing relevant pollution liability coverage is a necessity.

WindWind turbine farms have become an increasingly familiar presence on hilltops, plains and coastal waters of North America and Europe. Wind turbines and related hardware are costly, requiring adequate property insurance. Wind power operators may also want warranty coverage from manufacturers, completed operations coverage from the installer, as well as machinery breakdown and property coverages. In addition, wind energy power generators should carry adequate liability insurance covers in the event that the mechanical failure of a tower causes direct physical damage or loss to a third party.

There is presently a major push for offshore wind turbines in Europe and also in some coastal regions of the U.S., driven in part by government subsidies and incentives. However, offshore turbine farm construction presents a number of additional construction and operational challenges, from the offshore construction liability challenges of siting a wind farm in coastal waters to weather extremes and threats of collision from shipping

19

insig

hts 14

traffic. Offshore turbine facilities are also criticized as being intrusive and a hazard to marine life and migrating bird species.

Manufacturers of wind generation equipment should recognize that they may be exposed to claims by customers who may need to purchase carbon offsets or credits in order to access power generated by more carbon-intense sources due to the lack of performance of their wind-powered generating equipment.

GeothermalPerhaps the most efficient, cheapest and least controversial form of renewable energy is the heat generated by the planet itself. A growing number of geothermal plants around the world use steam generated by the earth to drive turbines generating electricity. It is clean, non-polluting, inexpensive and always “on.” However, it is practical only in areas where geological conditions are right, i.e. where the natural confluence of underground water and heat generate steam and geyser activity that can be harnessed by turbines.

According to the Geothermal Energy Association (GEA), as of August 2013 a total of 11,765 megawatts of geothermal power were operational around the world, with an additional several hundred megawatts in the final stages of construction. By the end of 2013, the global geothermal market is expected to reach more than 12,000 megawatts of generating capacity. GEA has counted over 674 developing geothermal power projects globally, from prospects to projects in the late stages of development.

The question of subsidiesBoth in the U.S. and in Europe, the development of renewable energy sources has been encouraged by large government subsidies and tax breaks. The goal has been to kick start development of renewables, and the “green” jobs they can produce, while meeting ambitious goals for energy generated by alternative sources. The net result has been to help make the cost of new installations economical enough to spur widespread adoption and to moderate the cost of electric power generated by renewable sources. A recent Bloomberg BusinessWeek report noted that solar capacity in the UK saw a 10-fold increase during 2011, following on similar increases in Germany, Italy and other regions.

However, during a time of fiscal austerity and concern over sovereign debt, subsidies for renewables are under stress around the globe. In the US, a framework of tax credits and subsidies enacted in 2009 is slated to expire in phases over the next several years. The U.S. federal tax credit for wind power was due to expire at the end of 2012, but was extended through 2013 during an 11th hour budget deal. Credits for biomass and geothermal are set to expire at the end of 2013, with tax credits for solar expiring at the end of 2016.

Whether renewable energy sources will remain commercially viable under a scenario in which all subsidies are scaled back or eliminated is an open question, however such an extreme scenario is unlikely. As the global economy recovers and debt concerns ease, economic activity will increase not only in the developed world but also in the emerging market powerhouses of Asia and Latin America. This will place additional pressure on available supplies and costs of conventional fossil fuels. Additionally, many countries, and even 29 individual, American states, have a variety of renewable portfolio standards and carbon-mitigation goals that can only be met by a commitment to the expansion of renewables.

Widespread acceptance of renewable and alternative energy will only be assured by the promise of consistent reliability regardless of external environmental conditions.

20

Reduced demand, regulatory challengesimpact mining risk management strategies In recent years, mining and commodities firms experienced dramatic growth driven by strong demand

in the developed world as well as fast-growing, emerging markets such as China and India.

But reduced demand due to economic uncertainty, coupled with overcapacity and increasing regulatory challenges in some segments of the industry, most notably coal, has had impacts on all aspects of mining. Indeed, falling commodity prices combined with reduced demand and business activity has prompted a growing number of mining industry risk managers to take a closer look at current risk mitigation strategies and to question whether the coverages and limits currently in place are appropriate for an industry in a state of flux.

Until recently, commodity prices appeared locked into a steady upward trajectory. Mining and metals operators spent millions to open new mines, to expand existing facilities and to acquire and upgrade equipment to achieve significant increases in production. Predictably, this response to spiraling marketplace demand ultimately resulted in overcapacity once demand cooled, beginning with a significant slowdown in China’s resource-hungry steel and construction industries. Profits for the world’s 40 largest mining firms fell 49 percent in 2012, effectively erasing the previous six years of profit growth.*

Historically, China’s growth rate has been in the range of 15-16 percent, but more recently has slowed to 7-8 percent. While for any country this rate would still represent significant growth, it is insufficient to support the output of a global metals and mining industry geared to providing for twice that rate of growth. As recently as the first quarter of 2013, strong steel production in China had driven iron ore prices as high as $160 per ton, only to fall to less than $115 a ton by mid-June**, due in large part to China’s policy tightening in construction. Lower prices for copper and aluminum resources, again due to construction slowdowns in emerging markets, are affecting the results of producers in those segments as well.

21

insig

hts 14

While iron ore and other metals are dealing with a cyclical softening in demand, the US domestic coal industry is in the midst of a more structural dilemma fueled by a confluence of factors. A key factor affecting the market for US thermal coal is the unprecedented increase in natural gas domestic supplies made possible by greatly improved hydraulic fracturing techniques and huge, new discoveries in the lower 48 states. Natural gas continues to gain market share in the power generation sector, with prices continuing to decline as supplies increase. Some analysts have raised the possibility of the US becoming literally energy independent thanks to the

natural gas sector, perhaps even becoming a major exporter down the road. With operations that tend to be more capital intensive to mine, process and distribute than the natural gas industry, US thermal coal remains at a significant pricing disadvantage. Some analysts believe that as natural gas inevitably becomes less competitive as supplies are drawn down, its price advantage related to coal may narrow, once again making coal an attractive alternative. However, in the interim, perceived negatives in the use of thermal coal for power generation and continued progress in renewables may mean that coal will remain a less attractive alternative in the long term.

Further, the impact of current Environmental Protection Agency (EPA) regulations regarding carbon emissions produced by coal usage, and the likelihood of even tougher regulations being promulgated in the near term, will likely further disadvantage thermal coal against natural gas and other energy alternatives.

Natural gas continues to gain market share in the power generation sector, with prices continuing to decline as supplies increase.

Historically, when commodity prices in the mining and materials segment have fallen, insurable exposures such as business income will fall with them. Consequently, mining industry risk managers, especially those engaged in segments most heavily affected by cyclical and regulatory factors, need to take a closer look at the structures of their risk management programs. Is the firm carrying the right limits and types of insurance for its facilities, machinery, equipment and business income exposures at a time when a production slowdowns are resulting in lower average Estimated Maximum Losses (EMLs). In advancing effective risk assessment and profiling reviews, operators will be well served by collaborating closely with their brokers, carriers and reliable, external risk engineering experts to arrive at a realistic picture of what coverages are needed, where and how much. Periodic reviews are beneficial in any industry segment at virtually any time, but they are essential at a time when the economics are in a state of flux due to changing market conditions.

As a basic industry supplying the needs of many others, it is not surprising that the mining and metals segment is particularly susceptible to periods of economic slowdown and reduced demand. However, players with a diverse customer base, strategic diversification in the global import/export marketplace, and strong, vibrant business plans will survive and thrive in the years ahead. Economic growth driven by emerging markets and a rising, global middle class inexorably increases the need for raw materials and metals used in everything from bridge building to tablet computer components. And as business activity and production increase, individual operators in the mining and metals segment will once again need to revisit their evolving exposures and risk transfer strategies.

* Business Spectator, “Global Mining Outlook Falls Sharply,” June 2013.

** Nasdaq.com; “Mining-Ferrous & Non Ferrous Stock Outlook, Sept. 2013, Industry Outlook.

22

The fundamentals of good risk engineering and loss prevention are much the same no matter what the commercial or industrial exposures may be. Identifying potential hazards based upon knowledge, experience and insight, and then taking steps to mitigate them, are essential to the protection of life, property and profits.

In few industries are the stakes as high as they often are in the energy industry, which routinely involves extremely high-value facilities managing volatile, flammable and potentially dangerous materials. In addition, business interruptions for energy producers and power suppliers can have significant consequences not only for the firm affected, but also for its customers and society at large.

It may be cliché to say that ‘little things mean a lot,’ but in the field of energy industry risk management it is too often true that small mishaps can rapidly lead to huge loss events. Illustrating this simple, fundamental principle, Zurich Risk Engineers/ Risk Specialists continue to report real-world cases in which small or uncorrected deficiencies could have resulted in costly, even devastating, losses.

Case studies – Small fixes can avoid major threatsUpon a visit to a petrochemical facility, a risk engineer with extensive energy-industry experience discovered a shut and locked sectional control valve regulating the water supply to a fractionation unit. The valve was part of a grid loop system that would carry the water to the unit and its vicinity in the event of a fire. A remote pump house separated from the processing and storage areas would supply the water, while a grid of pipelines would deliver the water to where it would be needed in the event of a mishap. The shut and locked valve would have meant no water available to quell a fire in or around the fractionation unit. The result could have been a potentially catastrophic event.

Small risk control lapses can have major consequences

23

insig

hts 14

The best course of action is simply to make a conscious effort to focus on the fundamentals of common-sense risk reduction at all times and continually ask “what if?”

In a similar case, an oil refinery employed a number of emergency shutdown values that would activate in the event of a pipeline break or fire. The intent was to isolate the section of pipe involved in a fire to contain its spread. Upon close evaluation, no improperly closed main emergency shutdown valves were discovered. However, the facility’s engineers had greatly underestimated the importance of a small sectional valve attached to the system. In the event of a fire, isolation of the affected section might have been compromised, causing the fire to worsen significantly. In addition, many of the emergency shutdown valves were operated by hydraulic oil, which is itself a fire hazard. As a result, the flammable hydraulic oil was replaced with a less hazardous substitute. Again, a small change delivered significant loss mitigation benefits.

Another case involved something as simple as the lengths of the bolts holding two sections of pipe together. Sections of pipe are often joined by connecting the flanges at the opposite ends of the sections. Industry practice is to use bolts just long enough to hold the sections together. When the bolt is too long, the length extending beyond the flange will cause the bolt to heat up more rapidly during a fire and possibly fail, losing containment and making a bad situation worse. This is something that an experienced risk engineer will notice immediately, and fortunately it was. No loss had yet occurred, and once the situation was brought to the attention of the customer a substantial hazard was reduced at a very nominal cost.

Focus on fundamentalsThere are many similar near-miss examples known to Zurich’s Risk Engineers/Risk Specialists actively serving the energy industry. It should be remembered, however, that when a problem is identified it is not an admission that the customer’s engineering or maintenance team is somehow lacking in expertise or diligence. Often the local team is simply too close to a potential hazard to readily recognize it given the demands and complexity of their everyday jobs.

The best course of action is simply to make a conscious effort to focus on the fundamentals of common-sense risk reduction at all times and continually ask “what if?” Keep in mind that no matter how large, complex and state-of-the-art a facility may be, something small and fundamental can bring it down. If the operation is an energy company, the stakes can be high indeed.

It is important for energy customers to remember that it is not unheard of for the business interruption costs to account for the major portion of the total loss, considering that a large turbine or process vessel can take up to two years to manufacture, install and bring online.

It is also important for customers, whether in the energy industry or some other line of business, to recognize that most of the risk improvement protocols and recommendations they receive from risk engineering professionals are often based on previous losses. In other words, some facility has experienced a very similar loss that your risk engineer is attempting to help you prevent. Keep in mind that the only difference between a preventive action and a corrective one is that prevention means learning from somebody else’s mistake, while correction is learning from your own. Given the alternative, prevention is a far more cost-effective way to go.

24

Good communication vital toeffective energy claims resolutionOne of the most critical components in the effective management of any type of industrial or commercial claim event, no matter what the business or industry segment may be, is effective communication. Comprehensive, consistent information sharing will greatly reduce opportunities for misunderstandings, help prevent delays and disagreements over values and financial issues, and enable more rapid disbursement of funds necessary to effect repairs and get the customer back into operation.

The value of good communication is especially important in the management of complex, multifaceted and high-value claims experienced by energy industry customers. Due to the values and complex risks represented by oil refineries and terminals, natural gas plants, power stations and other energy facilities, most energy claims are “market losses” requiring the coordination of anywhere from five to 25 different insurance carriers. As a result, the typical energy claim will be handled by a highly experienced independent adjuster with dedicated energy experience, usually appointed by the “Leading Insurer”. Once on the case, the independent adjuster will become the representative for the entire panel of insurers, working in consultation with their respective claims operations and keeping them informed regarding developments related to the claim. This arrangement provides both customers and insurers with a single point of contact for all questions or claims issues, which in theory should help drive more effective communication.

Unfortunately, it is not uncommon for the independent adjuster to be excluded from some of the customer’s earliest, post-loss decision-making meetings, usually due to an understandably perceived need for expedience and the internal focus often experienced by risk managers dealing with a catastrophic event. The first impulse of the

team will often be to “pull out the stops” to get back up and operating as quickly as possible, and worry about insurance issues later.

However, leaving the independent adjuster out of the loop in the early stages is a mistake. An experienced independent adjuster often will have connections that can help a customer find immediate and creative solutions to help reduce the length of a business interruption. The typical profile of an independent adjuster focused on the energy business is one of deep, long-term experience in assessing and assisting with complex, high-stakes energy claims. Large claim events affecting energy customers are relatively rare, but when they do occur they can be of significant severity. A seasoned independent adjuster experienced in handling of energy industry claims is virtually certain to have contacts a risk manager will not have. These contacts can be vitally important when, for instance, trying to locate a vital but rare piece of equipment needed to get a generator, turbine or some other piece of equipment back in operation. In addition, the adjuster may see further opportunities to reduce the business interruption period by advising the insured to incur ‘expediting expenses’ in the procurement phase i.e. incentivizing a manufacturer to produce a piece of equipment more expeditiously than they normally would such that the lead time is reduced and interruption period shortened.

25

insig

hts 14

25

Setting appropriate reservesEqually important is the role the independent adjuster will play in gathering information sufficient to help the panel of insurers accurately set reserves. With simple property claims, such as an office exposure, an adjuster can calculate the number of square feet, obtain a list of damaged items and then readily develop an estimate projecting property and business interruption values. However, the situation can be much more complex with an energy customer. What’s the lead time for a major refinery repair or critical replacement part? How readily available are the components for a vital piece of equipment, such as a new distillation tower? Some of these components are literally “one-offs” manufactured on an as-needed basis, with the possibility of long lead times and significant delays in final delivery. Consequently, even the most seasoned independent adjuster may need some degree of onsite briefing about a particular customer’s situation and processes, information that will be crucial for the effective setting of reserves.

For example, the independent adjuster may have the resources and contacts to help a refinery’s engineering team develop an accurate assessment of the cost and availability of a distillation tower, a challenging process. However, without full technical information about the particular facility’s installations, the adjuster may not know that a large amount of control cabling running underneath the tower will result in significant additional repair and business interruption costs. As a consequence, six months later the panel of insurers may be shocked by loss estimates well in excess of the original reserve figures due to the amount of additional work and components required in addition to the new tower.

The underlying principle is that “bad news doesn’t get better with age”. A realistic, post-loss assessment developed in collaboration with the risk manager, the insured’s engineering team and the independent adjuster is the most effective way to set accurate reserves. Once done, all reasonable mitigation steps can be taken to help to reduce the ultimate cost of the claim, but establishing accurate reserves from the beginning means less chance of disputes six or 12 months later when final repair costs are tallied.

Build relationships in advanceIt’s also a good idea for the risk manager to reach out through the Leading Carrier to attempt to build a relationship with any independent adjuster likely to be assigned in the event of a loss. Establishing a personal rapport with the adjuster in advance of a loss, and familiarizing the adjuster with key members of the company’s management team and vice versa, can help to build a foundation of trust more likely to make the adjuster an accepted member of the response team from the beginning of a claim.

Thankfully, significant energy losses tend to be low- frequency events. However, when they do occur, they can be costly, time-consuming and disruptive to processes and profits. Building relationships in advance of a claim, and then making sure that all parties are at the table as early in the process as possible, can help drive the swift, effective resolution of a major energy claim and head off disagreements and disputes that can slow the process and result in dissatisfaction for all parties involved.

A realistic, post-loss assessment developed in collaboration with the risk manager, the insured’s engineering team and the independent adjuster is the most effective way to set accurate reserves.

26

Contributors

Marion Abston Underwriting Manager, Onshore Property, Zurich Global Corporate in North America

James Aloway Underwriting Manager, Onshore Property, Zurich Global Corporate in North America

Leo Dixon Global Head, Energy Claims,Zurich Global Corporate

Nathan Espe Head of Construction, Zurich Global Corporate in Europe

Scott Fuqua Underwriting Manager, Exploration & Production, Zurich Global Corporate in North America

Jeanne Jankowski Head of Energy, Zurich Global Corporate in North America

Jose Mogartoff Director of Energy Claims - The Americas, Zurich North America

Hanspeter Reitinger Underwriting Manager, Energy Casualty Europe

Frank Streidl Head of Offshore Energy, Zurich Global Corporate

Darrin Tasker Head of Energy Casualty, Zurich Global Corporate UK

27

insig

hts 14

27

A

1-20

184-

B (

10/1

3) 1

1200

2120

The information in this publication was compiled from sources believed to be reliable and is provided for informational purposes only. All sample policies and procedures herein may serve as a guideline, which you can use to create your own policies and procedures. We trust that you will customize these samples to reflect your own operations and believe that these samples may serve as a helpful platform for this endeavor. Any and all information contained herein is not intended to constitute legal advice and accordingly, you should consult with your own counsel when developing policies and procedures. We do not guarantee the accuracy of this information or any results and further assume no liability in connection with this publication and the sample policies and procedures, including any information, methods or safety suggestions, contained herein. Moreover, Zurich reminds you that this cannot be assumed to contain every acceptable safety and compliance procedure or that additional procedures might not be appropriate under the circumstances. This is also intended as a general description of certain types of insurance and services available to qualified customers through the companies of the Zurich Financial Services Group, including, in the united States, Zurich American Insurance Company, 1400 American Lane, Schaumburg, Illinois 60196; in Canada, Zurich Insurance Company Ltd, Canadian Branch, 400 university Avenue, Toronto, Ontario M5G 1S7; and outside the U.S.A. and Canada, Zurich Insurance Plc, Ballsbridge Park, Dublin 4, Ireland; Zurich Insurance Company Ltd, Mythenquai 2, 8002 Zurich, Switzerland; Zurich Australian Insurance Limited, 5 Blue Street, north Sydney, nSW 2060, Australia and other legal entities, as may be required by local law. Your policy is the contract that specifically and fully describes your coverage. The description of the policy provisions contained herein gives a broad overview of coverages and does not revise or amend the policy.

Certain coverages are not available in all jurisdictions. You are in the best position to understand your business and your organization and to take steps to minimize risk, and we wish to assist you by providing the information and tools to help you assess your changing risk environment. In the United States, risk engineering services are provided by The Zurich Services Corporation.

www.zurichna.com

For more information about Zurich’s products and services for the energy industry, visit zurichna.com

For additional Zurich solutions, services and risk insights, visit the Zurich Virtual Literature Rack at zurichvlr.com or download it to your iPad from the App Store.