Shale gas has generated a high level of attention over the past few years as by many accounts. Readily accessible shale gas is considered a game

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2 Shale gas has generated a high level of attention over the past few years as by many accounts. Readily accessible shale gas is considered a game changer that will fundamentally alter the global gas industry. I have no intent to challenge a game changer definition of shale. Development of shale gas has had major implications for countries with the LNG export projects. But there are several critical questions regarding shale gas production in the U.S. and around the world that will be addressed in my presentation: Are current prices in the U.S. adequate for sustainable production of shale gas? Will the U.S. market rise to a level that will make LNG deliveries to the U.S. economically attractive again? Will the shale gas impact that has been seen in the U.S. recently expand to other global markets? 2

3 Shale production has been growing exponentially and as of January 2011, the U.S. was producing as much gas as it did at its peak some forty years earlier. As evidenced in the graph, due to the rapid increase in shale production, LNG deliveries to the U.S. have been negligible and have not met the expectations of just a few years ago. What I will try to challenge today is an often cited view that there is a virtually inexhaustible supply of $140 per mcm gas available for the taking. If this view is substantiated it would be highly detrimental to the global LNG industry. In order to investigate this claim, Gazprom Export decided to take a look at the true costs rather than the prevailing market price or selective producer cost claims - of U.S. shale gas development and production. 3

4 One must not look to performance of individual wells, plays, zones and companies to understand what is going on. Gas producers in the U.S. often call good wells hogs while bad well are dubbed dogs. Dogs are usually defined as wells with less than 0.5 mmcf/d in production, while hogs produce at least 4 mmcf/d. The vast majority of the wells drilled are dogs. The US has drilled between 10,000 and 25,000 of these low-productivity wells annually during the last decade, whereas only 1-2,000 wells annually have been high productivity hogs. Although I do not doubt the ability of certain wells and companies to produce gas at a cost of $140 per mcm or lower, it is important to look at the industry averages and the iceberg of costs as a whole. 4

5 The study, which Gazprom Export commissioned the consulting firm Pace Global Energy Services to perform, looked at the quarterly and annual financial statements of ten U.S. oil and gas producers. The study group collectively owns 17% of proved U.S. gas reserves and is tightly focused on shale gas development and production. The study compared total cash costs to total gas production and reserve additions over a six-year period from The graphic below illustrates the study group s reserve and production characteristics. It shows above all that study group production profile was >70% gas weighted. 5

6 The general conclusion of this study is that costs exceed the revenue that natural gas market prices alone have generated in every year for the past five years. That is, shale producer costs cannot be covered by current market prices. The group collectively has been selling gas below their all-in production costs. Even when associated oil and liquids revenues from shale wells are included, costs are still above realized prices. In addition, while nominal prices as well as total industry expenditures peaked in 2008, the cost reductions achieved in 2009 do not point to a trend. It is indicated by total unit costs rebounding 25% in 2010 over 2009 and appearing set to rise again this year as input costs continue to rise. Producers also face the threat of increasing costs of environmental and regulatory compliance. Please note that Pace Global calculates all-in costs through the sum of finding and development ( F&D ) costs and cash operating costs. F&D costs are the costs associated with acquiring, exploring for, and developing new reserves. Unit finding and development costs are estimated by dividing these annual expenditures by the total increase in proved gas reserves year-over-year. Cash operating costs are the costs of producing proved and developed reserves. These include operating expenses such as gathering system expenses, lease operating expenses, production taxes, general and administrative expenses, interest expenses, and current cash income taxes. Cash operating costs are expressed on a unit of annual production volumes. 6

7 One of the key reasons that producers were able to continue shale production despite the low market prices is that they took advantage of higher market prices in past years to lock in hedges on their future gas sales. The study looked at the contribution of price hedging programs on the average unit prices realized by producers in the sample set. Following are the key findings: Realized prices as shown on the chart below, as opposed to market prices, reflect the impact of price hedging programs, which lock in future prices on a portion of a producer s estimated future production. Hedges placed against future production in , when price expectations were very high as demonstrated in the chart in the lower right, provided a substantial portion of 2009 revenue within the sample set. Hedging proceeds were substantially down in 2010, however, and could essentially disappear in 2011 and beyond until gas prices get more volatile. Importantly, realized prices with the benefit of the hedges are still below their all-in costs. Due to the seemingly uneconomic nature of shale production, a key question that arises is, Why do they do it? 7

8 There are several factors that lead shale producers to keep on drilling in a high-cost, low-price environment. One factor relates to the U.S. system of mineral rights ownership and contracting practices. In the U.S., owners of surface properties like farms and house lots also own all the minerals rights on anything buried below the surface. This is a rare practice and in most countries mineral rights belong to the state. U.S. rules force shale gas companies seeking to exploit mineral rights over a broad geographic area to negotiate and acquire minerals leases from all property owners in the area. As each owner wants to be sure his or her property begins to generate income quickly, there is generally a clause in the lease agreement that forces producers to drill for gas within a certain time period, or else lose the rights of the lease. Producers acquired an enormous amount of land requiring near-term development in , and were compelled to spend money on drilling up that land in or lose their drilling rights and with them the future revenue to cover prior expenses. This has lead to large volume of gas coming into the market simply to maintain these leases. Another factor relates international oil majors who responded slowly to the U.S. shale boom and paid a premium price to buy in to active drilling programs by the smaller independents. The international oil majors utilized front-loaded purchase payments and liberal development cost sharing terms from joint venture agreements to effectively subsidize development costs, distorting the economic decision to drill. Additionally, the true motivation of the international oil majors was not to gain access to shale technology, but rather to put reserves on their balance sheets. Purchasing financially distressed shale companies could make a significant addition to their reserve bookings in an environment where they were finding it increasingly difficult to add reserves internationally. ExxonMobil s acquisition of XTO Energy last year accounted for 80% of the reserves it added in 2010, highlighting the difficulty oil companies are having in finding new sources of crude. ExxonMobil s reserve base increased by 3.5bn to 24.8bn oil-equivalent barrels at the end of last year. XTO, a US independent focused on shale gas production, accounted for 2.8bn of the new reserves. 8

9 The key driver to the U.S. gas supply glut has been the boom in shale gas production. However, the persistent and growing gap between U.S. oil and gas prices has actually already begun correcting the U.S. gas oversupply problem. Producers are increasingly directing their capital dollars at oil and liquids-prone drilling targets to benefit from higher prices. As illustrated in the graphs below, as of April 2011, and arguably through most of 2010, more effort was directed at oil and liquids development than dry natural gas development. It is important to note that a significant amount of gas production is associated with these new oil and condensate wells: gas production typically exceeds liquids production by a significant amount in condensate wells. 9

10 The boom in shale gas production has led to increased attention from environmentalists, legislators, and homeowners who have legitimate concerns regarding the risks to fresh water drinking supplies stemming from hydrofracking. These concerns have led to increased regulatory oversight, which produces increasing costs related to compliance and permitting. Without proper regulatory oversight and the use of industry best practices, shale gas production can contaminate fresh water drinking suppliers and endanger homeowners in surrounding areas. Due to the public perception of these risks, federal, state and local regulations are increasing and which will lead to significant costs to shale producers. The following exhibit provides an overview of U.S. regulatory costs facing shale producers. 10

11 Amongst the environmental issues related to shale production, water use and treatment are at the forefront of the discussion. In fact, The New York State Legislature has imposed a temporary ban on shale gas development anywhere in the watershed to New York City, and other states and the federal government are contemplating similar measures. Water issues are so prominent because the demand for water in shale production is so high. In the U.S. there are 35,000 hydrofrac wells drilled per year, each requiring 2-4 million gallons of water per year. The large quantity of water used in hydrofracking necessitates wastewater treatment and waste disposal, and inadequate wastewater management can lead to polluted runoff. To treat and process used frac water costs approximately $0.12 per gallon. Those shale producers that cut corners to limit costs increase the chance to contaminate drinking water and can expect substantial environmental litigation, which is already a real threat and cost to shale producers. Aside from water treatment issues, there are a plethora of other environmental costs related to shale production, including standard clean-up protocols, administrative costs of reporting greenhouse gas emissions, disposing of unforeseen contaminants, compensation for injury and property damage, as well as site reclamation after well closure. Due to all the environmental risks associated with hydrofracking and the practice being in the public spotlight, it is reasonably assured that shale producers will experience tighter regulations surrounding well casings, well permitting, and water treatment from all levels of government in the coming years. Increasing regulatory compliance costs pose a real threat to the economics of shale production and will push all-in costs higher, making drilling for gas less attractive. 11

12 The net effect of declining pressures to drill for gas and gas demand growth stimulated by both price and ample long-term supply will be declining gas production until prices respond sufficiently to justify further investment. There are several factors that will increase demand for gas in the U.S. in the near- to mid-term, including: The expected recovery of industrial natural gas demand, Aging coal and nuclear power plants to be replaced by natural gas plants, Gas-for-oil substitution in more applications increasing demand, and Natural gas slowly beginning to displace diesel fuel for industrial vehicles and commercial fleets. 12

13 Additionally, cost pressures are rising due to labor and material cost increases and responses to environmental and water treatment regulations. With U.S. shale gas development and production costs now over $200 per mcme and rising, U.S. gas prices will need, at a minimum, to be significantly above $200 per mcme to generate sufficient revenue to justify the technical and financial risks. We believe that natural gas prices in the U.S. will eventually begin to converge with those of the rest of the world because many shale gas producers have negative cashflows from their operations. They are able to drill thanks to hedges, investor and lender money and support of JV partners. But there is an end to any miracle. Trees do not grow to the sky. 13

14 At current reserve replacement cost levels, the present $140 per mcme North American gas market does not appear to be sustainable. Given the high costs of production and expected increase in demand for U.S. gas, we do expect gas prices eventually increasing to a range of $200-$280 per mcme. While current import terminal capacity can accommodate a significant increase in the U.S. LNG imports, the issue is whether the expected price increase will be sufficient to make LNG exports to the U.S. an attractive proposition. LNG exporters may not be able to secure big margins in North America, but market prices will be high enough to generate an acceptable profit for most LNG producers, and the the U.S. market is open to anyone who is willing to match the market price. The U.S. market should start to absorb an ever growing share of LNG as prices rise to better reflect the true costs of production. 14

15 Even with a positive outlook for LNG exports into the U.S., one must still consider the large amounts of technically recoverable shale gas in Europe, Asia and around the world. U.S. shale success has led to a rush of activity around the world to determine the size, extent and production potential of shale basins in other markets. While many shale basins are yet to be evaluated, the U.S. Energy Information Administration released a study in April of this year stating that, of the basins studied thus far, there are an estimated 188 Tcm of technically recoverable natural gas resources. Please note that in the following map the basins evaluated for resource size in the study are shown in red and those shaded yellow remain unevaluated. Importantly, technically recoverable does not mean proven and producible. Unlike conventional gas extraction, in which the gas flows to the wellbore unaided, shale gas production in commercial quantities requires literally pulverizing in place a portion of the shale rock formation, and total gas recovery expectations from a single well lie in the range of only MMcm. At that rate, it would take approximately two million gas wells to recover the 188 Tcm of technically recoverable gas. Due to a variety of technical and economic reasons, the majority of that 188 Tcm of gas resources will never flow to market. 15

16 Fortunately for LNG exporters, European shale gas development faces numerous economic, regulatory and political barriers before there are significant amounts of shale gas production, no sooner than in ten or more years. For example, the lack of essential specialized equipment and field services outside the U.S. will retard the rate of commercial shale development in Europe and Asia. Also, preliminary assessments of Chinese shale development opportunities indicate generally lower-quality prospects coupled with water deficit in productive areas. Commensurately higher unit costs will be offsetting cheaper labor costs. Essentially, higher development costs in Europe and Asia will require a higher market-clearing price for economic shale gas development. The redistribution of, and increase in, available gas resources represented by shale gas development creates new difficulties for any party trying to extract scarcity rents from gas importers by virtue of controlling gas reserves. This development does not, however, imply an era of ubiquitous and cheap natural gas supplies globally. Unconventional resources remained undeveloped until high market prices justified the investment. They will only continue to be developed if gas prices remain strong. LNG exporters, with their large reserves of inexpensive gas, have a long-term role in the global supply mix at prices that will not place past and future LNG investments in jeopardy. 16

17 Given this extended time horizon for a significant commercial threat to emerge in Europe and Asia, the high development cost of this admittedly abundant shale resource, and the expected global gas demand growth stimulated by its abundance and environmental benefits, there is every reason to believe that today s LNG industry can secure a profitable role in the emerging global gas economy, including in the U.S. In conclusion, U.S. market prices will rise to reflect the true costs of production. Also, there will not be significant exports of shale gas from the U.S. markets to other global markets. The high production costs plus the cost of liquefaction and shipping makes it impossible compete with other gas sources over the long run. Finally, the development of shale gas in other global markets will be significantly slower, smaller and at even higher cost than we have seen recently in the U.S. 17

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