Caspian production, export, investment outlooks sized up

Aug. 24, 1998
The rise of the Caspian Sea region as a target for international investment was one of the major consequences of the dissolution of the U.S.S.R. for the world oil and gas industry. The relative openness of Azerbaijan, Kazakstan, and even Turkmenistan to foreign participation in upstream operations has stimulated production recoveries in those countries and created prospects that are unique among republics of the former Soviet Union. The area's potential and location has made it hot both in
John D. Grace
Earth Science Associates
Long Beach, Calif.
The rise of the Caspian Sea region as a target for international investment was one of the major consequences of the dissolution of the U.S.S.R. for the world oil and gas industry. The relative openness of Azerbaijan, Kazakstan, and even Turkmenistan to foreign participation in upstream operations has stimulated production recoveries in those countries and created prospects that are unique among republics of the former Soviet Union. The area's potential and location has made it hot both in oil and in political circles. Among participants and observers, expectations vary widely on the course of the region's future. Regarding oil potential, optimistic estimates have Caspian production rising from its 1997 level of 633,000 b/d of oil to as high as 6 million b/d by 2010. From this volume, more than 5 million b/d could be exported. These predictions, however, are short on specifics and almost never deal with how much it will cost to attain forecasted output. In this article, the results of a detailed analysis of the region's production capacity are developed. This provides an outlook for lower Caspian production and a daunting schedule of required investment. A more modest production outlook results in lower demand for export transportation and therefore raises questions about the economic feasibility of some proposed pipelines. Finally, a realistic understanding of production capacity and costs has implications for government policies and company strategies.

The model

To investigate Caspian oil potential, a mathematical model was developed. Its principal purpose was to forecast oil production, consumption, and exports from the Caspian Sea region. Through that analysis, insights were gained on the demand for oil export transportation and the sensitivity of the conclusions on production and exports to changes in assumptions about resources, costs, and investment. The forecast runs from 1998 through 2015. The model has two notable characteristics. It combines a field-level technical model of production and cost within a larger scheme that simulates the industry's response to higher or lower levels of investment. The field-level model incorporates the individual characteristics of known projects. Additionally, it provides a mechanism to build up regional investment requirements. The model is also probabilistic. That is, inputs to the model (e.g., field sizes, decline rates, exploration success ratios, costs) are expressed as probability distributions. In such distributions, the expected value, or mean, is surrounded by alternative values and the probability of their occurrence. The model propagates these variances through to the conclusions (e.g., annual production, consumption, and exports), explicitly representing the uncertainty surrounding them. A similar model for forecasting oil production from the Former Soviet Union through the year 2000 was built in 1992-93.1 From 1993 through 1997, that model's forecasts for the former U.S.S.R. as a whole, and separately for the Russian Federation, have remained on average within 1% of actual annual production. Both that model and the Caspian Sea model were built in Microsoft Excel software and used Decisioneering's Crystal Ball program for Monte Carlo simulation. Separate models were developed for Azerbaijan and the Caspian portions of Turkmenistan, Kazakstan, and Russia ( Fig. 1 [127,243 bytes]).

The Iranian portion of the South Caspian basin was excluded. The structure of each country's model was the same, although the values of the input parameters reflect local conditions (Fig. 2 [47,401 bytes]).

Oil production in each country was divided into three sectors in the model:

Old Production is defined as production from fields online before 1998 and not the subject of investment projects.

New Development includes output from fields discovered before 1998 that are or are expected to be the subjects of investment projects (Table 1 [53,005 bytes]).

Exploration Production is oil that will come from fields discovered between 1998 and 2015. Exploration potential was analyzed on a basin level for each of the three basins in the region (Fig. 1). Exploratory drilling was estimated by country, and forecasted volumes discovered in each basin were allocated to countries by basin area and level of exploration.

The annual contributions of each of these three sectors are aggregated to produce forecasts of total national production.

A simple model of each country's oil consumption produces annual estimates of domestic demand, which, when subtracted from total production, yields exportable production. Finally, each country's volume of exportable production is dispatched over a system of existing and proposed export routes.

This provides an integrated picture of oil supply and export (Fig. 2). As the costs of both exploration and production are captured, the total investment required to achieve the production is forecast. The sensitivity of the forecasts to changes in investment or technical parameters, can also be investigated.

Future production

In the base or Reference Case of the study, regional oil production expands at an average rate of 14%/year for the next 10 years. After that point, growth slows, peaking in 2011 with a mean production of 3.6 million b/d ( Fig. 3 [43,602 bytes]). From then through 2015, output decreases slightly. The 10% and 90% probability percentiles on production in 2011 are 2.5 and 5.0 million b/d, respectively, surrounding the 3.6 million b/d mean. Four important details emerge from the Reference Case scenario on production:
  • For the next 10 years, the New Development projects, most importantly, the region's two mega-projects, will dominate production.
  • Without active, early, and successful exploration, regional oil production will peak at a level significantly lower than the Reference Case in 10 to 12 years and then decline.
  • Caspian production is capital-constrained, not resource-constrained. The region's resource base could support aggressive exploration sufficient to substantially raise and extend the regional peak production, depending on the level of investment.
  • The country with the largest current and future productive potential is Kazakstan.
Over the next decade, two giant New Development projects, onshore Tengiz field in Kazakstan and the offshore Azeri-Guneshli-Chirag complex in Azerbaijan, will provide one out of three barrels of new production in the Caspian Sea region. Both fields are already on line and will grow in output from 215,000 b/d and 100,000 b/d, respectively, in 1998 to a combined 1.3 million b/d by 2010.



The output of Old Production plus the 23 New Development projects listed in Table 1 will contribute two-thirds of the region's output between 1998 and 2015. Their production will peak in about nine years at 2.1 million b/d (Fig. 3). This is earlier than the anticipated peaks of Tengiz and Azeri-Guneshli-Chirag because beyond the half-dozen very largest projects, most are small in terms of peak production. They will contribute only modestly and fairly early to regional output.

If regional production is to rise beyond the 2.1-million b/d level, very active exploration must begin immediately. Specifically, attaining the Reference Case peak of 3.6 million b/d in 2011 depends on increasing exploration from the present levels of testing less than a handful of new prospects annually, to testing two to three dozen per year regionwide. Ultimately, if the Reference Case production profile is to hold, one out of three barrels must come from fields that are presently undiscovered (Fig. 3).

Political uncertainties, transportation and economic risk, as well as lack of modern infrastructure in the region have retarded exploration so far. Long lead times for the oil discoveries that are made, dry holes, and gas discoveries will collectively ensure that the present low level effort will pay off far too slowly to support long-run growth.

This problem, however, is a capital constraint, not a resource constraint. The three basins of the Caspian Sea region are expected to yield oil discoveries as large as several billion barrels. It is not even that capital is unavailable in the industry on a worldwide basis (though presently low prices are not helping). It is that expected return under the current conditions is often failing to make the grade in absolute terms and relative to alternative investments.

Host countries could stimulate exploration with streamlined, more transparent licensing, the resolution of boundary disputes, and deciding transportation issues. If exploration does languish, and with it long-run production growth, it will be because of politics and economics, not geology.

Over the forecast period, Kazakstan will lead the region in production. In the short run, it has the largest discovered resource base. This includes old fields on decline as well as New Development projects. Beyond Tengiz, Kazak New Development projects include several very large fields with long lives. Kazak assets also include an inventory of onshore discoveries that have not yet been developed.

In the long run, Kazakstan has the richest exploration potential in the Caspian Sea region. The Kazaks have nearly the entire unexplored offshore area of the North Caspian basin (Fig. 1). They also sit on the geologically better half of the Middle Caspian. Assuming vigorous exploration, these two provinces should provide the country with a very solid foundation for production from future discoveries.

Oddly enough, the wild card of Caspian production is Russia. Output from the Russian part of the Caspian Sea region was 110,000 b/d in 1992. The general collapse of the Russian oil industry and the war in Chechnya eliminated all but 21,000 b/d by 1995. In 1997, output was still only 33,000 b/d. While not all of the lost Russian capacity may be economic under present price and cost conditions, restoration projects could make a significant contribution.

Russian exploration, when it begins, could go either way.

On the positive side, the Russian Middle Caspian offshore is expected to yield discoveries that could top 1 billion bbl, even though extension of Russian onshore plays offshore yields smaller average sizes than on the Kazak side. On the down side, Russia has only a very small part of the unexplored offshore North Caspian basin, and its share is expected to be gas-prone (although high in condensate content).

Other than investment, two factors could significantly raise the potential production profile from the Caspian Sea region. First, the largest New Development projects, most importantly Tengiz and Azeri-Guneshli-Chirag, could prove to be much richer than current estimates. If the reserves of these fields, particularly Tengiz, grow during their development, regional peak production could be higher and come later than indicated here.

The second factor is luck. While the "expected" results of exploration are incorporated in the Reference Case, an extraordinary discovery (something over 4 billion bbl of economically recoverable reserves) in the next few years would materially change the outlook toward the end of the forecast period. However, to count on this unlikely event before it happens, no matter how alluring the undrilled structures of the North Caspian offshore, would be folly.

Required investment

Few public analyses of Caspian potential link oil production with the level of investment required to attain it. Yet it is investment that will ultimately determine output, as the region is not resource-constrained. To obtain the Reference Case mean production of 16.6 billion bbl between 1998 and 2015, $158 billion in constant 1997 dollars will be required. This includes only exploration and production costs. Demand for regional upstream investment was developed in the model in three stages. First is determining the annual funding requirements of the 23 New Development projects (Table 1). Capital and operating costs were estimated using project-specific data and regional averages where details were lacking. It was assumed that companies would fully fund existing projects before investing in exploration. Second was the budget for exploration, which was based on a scenario for annual new field wildcat drilling. That scenario reflected known plans, presently and prospectively available offshore mobile drilling units, onshore exploration history, and activity in analogous regions. Average costs of testing onshore and offshore prospects times the number of prospects tested yields annual exploration expenditures. A discovery process model was used to estimate the average number and sizes of the new discoveries generated by the scenario of new field wildcat drilling. In this final stage, the same algorithm used to estimate the production and cost of New Development projects was employed to estimate how much it would cost to develop newly found fields. The annual budgets for New Development projects, exploratory drilling, and the cost of developing new discoveries sum to the annual investment required to meet the production forecast ( Fig. 4 [43,586 bytes]). Constructed from the project level up, details of the investment requirements for Caspian production highlight economic strengths and weaknesses. Perhaps the greatest economic strength of the region arises from the geologic endowment of the three basins and their relative immaturity offshore.

As a result, exploration success is expected to be relatively high and discovery sizes large, driving exploration costs down to less than $2/bbl.

Large field sizes also bode well for lower development costs. However, lack of infrastructure, distance, logistics of supply, and an offshore setting for most projects counteract some of these advantages. Oil quality in the northeastern Middle Caspian and hydrogen sulfide, reservoir depth, temperature, pressure, and heterogeneity in the North Caspian subsalt plays also confront producers, driving up costs.

The net effect: Opportunities that are quite attractive even if they are not on a par with technical and economic characteristics of the Arabian Peninsula. If, however, transportation uncertainties, opaque licensing, and an erratic business environment are not resolved soon, the joint effect may be strong enough to drive enough investment elsewhere, seriously undercutting the Reference Case production profile in Fig. 3.

On the positive side, Azerbaijan and Kazakstan were fast off the block in originally fostering an investment environment that attracted tens of billions of dollars in "commitments." Turkmenistan may now be turning that corner. If these initiatives are extended, investment could exceed the Reference Case. An example is the estimated impact produced by a 50% increase over the Reference Case in annual investment between 1998 and 2015, shown in the top "slices" of Figs. 3 and 4. The flow of investments would reach a peak of nearly $17 billion annually in 12 years (Fig. 4). As a result, mean peak production would rise to 4.9 million b/d in 2011 (Fig. 3). This incremental investment, modeled as an increase in exploration, would also substantially boost proved reserves as of 2015.

Caspian exports

More attention has been paid to transporting Caspian crude than any other aspect of the region's development. Nearly a dozen different pipeline plans to export Caspian oil have been proposed leading to destinations as disparate as the Indian Ocean, Persian Gulf, Mediterranean Sea, Black Sea, and China. Because of the countries these corridors intersect, the routing decision is highly charged politically. In this study, based on the Reference Case mean production in 2011 of 3.6 million b/d and regional domestic consumption (not including the Caspian portion of Russia) of about 650,000 b/d, almost 3 million b/d will be available for export. Approximately two-thirds of that volume will come from east of the Caspian Sea (mainly from Kazakstan). This scenario has two major implications for export pipelines. First is the central role of a trans-Caspian oil pipeline. Azerbaijan's production is expected to peak in 2011 at around 1 million b/d, with a quarter of that volume consumed domestically. If a trans-Caspian pipeline is not built, expansion of the existing line from Baku to Novorossiisk, Russia, and the Baku to Supsa, Georgia, line presently under construction (both terminating on the Black Sea) could probably service Azeri exports. What could not be accommodated could pass through Iran. This obviates the need for a major (up to 1 million b/d) line from Baku through Turkey to the Mediterranean Sea. Azerbaijan would remain highly reliant on Russian cooperation for exports; it must hope for stability in Chechnya and Dagestan, and it does not alleviate the future potential bottleneck of tanker traffic through the Bosperous Straits. On the other hand, part of the capacity already exists; the solution is cheap and can be expanded incrementally as demand arises.



Without a pipeline across the Caspian Sea, most Kazak oil not shipped through the Caspian Pipeline Consortium system via Russia (if, and when it is completed) would probably flow south along the east coast of the Caspian Sea. It would join Turkmen exports before connecting to the Iranian pipeline system. These volumes would ultimately find their way to market directly, or through swaps for Iranian crude loaded at Kharg Island on the Persian Gulf.

If an oil pipeline is built across the Caspian Sea, Azerbaijan will require not only the capacity to export its own crude, but would trans-ship another 500,000 to 1 million b/d of Kazak and Turkmen oil. This would warrant capacity exceeding even potential expansions of the Baku-Novorossiisk and Baku-Supsa routes. While a new line could run south to Iran, present U.S. political pressure bodes for a route through Turkey to the Mediterranean Sea.

The second transportation implication of the Reference Case production forecast is that there will not be enough oil to fill all of the pipelines proposed for the region. The most economically tenuous of the plans involves shipping Kazak (and potentially Turkmen) oil east to China, or in the most extreme case, southeast across Central Asia to the Indian Ocean.

The economic justification of a pipeline to China is not presently apparent. The project might be undertaken in support of Chinese foreign policy or in the event of China decontrolling the price of domestic oil. However, while China's commitment to major upstream investments in Kazakstan puts it in a position to catalyze such a project, it does not make it economic under foreseen conditions.

Filling a 500,000 to 1 million b/d oil pipeline to the Indian Ocean, given the regional production scenario developed here, would require addition of large volumes of West Siberian crude. It is by no means certain that competitive netbacks in West Siberia would be available from a 3,500+ mile haul to the Indian Ocean. The route seems even more unlikely if the Russian pipeline system can be transformed within the next decade into a reliable common carrier.

Policy crossroads

Not since the Iranian revolution of 1979 has oil drawn the political focus directed on the Caspian Sea region. Host governments, regional powers and distant states all see Caspian oil as a vehicle for gamesmanship. In this match, investing companies are both pawns and players-boxed by the moves of kings and rooks but holding the power to take the game elsewhere. At this point, conclusions are apparent on two levels. In Azerbaijan and Kazakstan, which were quick starters, the early initiative is flagging at just the wrong time. Nearly all of the "get-in-early money" has arrived. If those already in do not generate local profits soon, funding from headquarters will dwindle. This will spark a downward spiral in which host governments raise government takes to fill hollow revenue forecasts, profitability will be further squeezed, and production growth will wane. Now is also a critical time to anchor long run foreign investment. The Caspian is hot, in part, because it is not presently competing with Iraq, Iran, or Mexico for upstream investment. These and other lower-cost regions will not jeopardize online Caspian projects as they open in the future. They will, however, vie for funds at the margin, particularly for exploration, which is so important to the Caspian's future production and will heavily influence pipeline decisions. Nothing will fasten long-term capital to the region more tightly than a large base of producing fields.

Yet wrangling for short-term gain and indecision continue to slow the development of productive capacity far below its potential. It is the iron of platforms and wells, not the paper of agreements and "commitments," that will bind Caspian investment in the next century. If host governments lose sight of this, they jeopardize short and long run success.

The larger context surrounding host government-company dealings is formed by the polarized positions by the U.S., Russia, and Iran. This environment makes the problems of Azerbaijan, Kazakstan, and Turkmenistan less soluble, exacerbates delays, and ultimately makes Caspian projects less attractive to investors. In Russia's case, this may well be the goal. Iran may also be smiling at the thought of weak northern neighbors. However, it is the conflicted policy objectives of the U.S. that perhaps create the most perplexing straits for the Caspian nations and companies trying to operate there.

Since dissolution of the U.S.S.R. in 1991, the U.S. has stridently fostered the independence and development of the newly independent states of the Former Soviet southern flank. Liberation of the region from its economic dependence on Russia has been a cornerstone in that pursuit. In terms of oil and gas development, this approach should support the widest possible diversity of partners, suppliers, contractors, and transportation routes for Caspian oil and gas.

Yet U.S. opposition thwarts the potentially positive role of Iran in balancing Russia's squeeze on transportation and in providing local and experienced partners in upstream projects. The U.S.-Iranian stalemate is withering. However, the time it will take may well be enough put the Caspian region on a much lower production profile than described in the Reference Case and will probably deny the region the benefits of accelerated investment and development.

Conclusions

Without extraordinary luck, the expected case for Caspian production is not the wild-eyed 6 million b/d by 2010. There are steep investment requirements, and even the Reference Case production goals will not be met without extensive and immediate exploration. Recognition of realistic stakes may temper the game and in so doing drive the players to more pragmatic goals that can be attained quickly, if not forsaken in pursuit of petro-fantisies. Fundamentally, delay only restricts the region's potential and narrows the attainable production profile to lower and lower paths.

Reference

1. Study finds FSU oil flow slide easing, OGJ, Nov. 8, 1993, pp. 30-32.

The Author

John D. Grace is president of Earth Science Associates, Long Beach, Calif., a firm specializing in resource assessment and analysis of hydrocarbon supply, and a partner in Troika Energy Services, which provides consulting services on the countries of the Former Soviet Union. From 1985-91 he held positions in geologic research, corporate planning, and management at ARCO. He received a PhD in economics from Louisiana State University. E-mail: [email protected]

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