Effect of Various European Fiscal Regimes

on Coal Bed Methane Development by

J. Craig Creel & A. John Wright

Cawley, Gillespie & Associates, Inc.

and

Gary Howorth & Martin Smith

Arthur Andersen, Petroleum Services

March 1996

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Abstract As more Coalbed Methane wells are drilled across Europe, it has become apparent that the anticipated

gas and water production has been less than hoped for and, in certain instances, less than sufficient for

sustained commercial development. Despite the inherent differences in the producing characteristics

of wells drilled in each country, the fiscal regimes in certain countries are currently not conducive to

the commercial development of the CBM industry. Using the production estimated to occur from a

typical European well, the effects of various fiscal regimes were evaluated to compare the relative

‘attractiveness’ of likely European countries for CBM development in the U.K, Netherlands, France,

Germany and Poland.

Introduction Coalbed methane (CBM) differs fundamentally from natural gas found in conventional petroleum

reservoirs.1,2

In CBM reservoirs, gas molecules are attached to the carbon atoms in the coal matrix.

As the pressure in the coal seam declines, the gas molecules detach from the carbon atoms and diffuse

through the matrix until they reach a natural fracture called a cleat. The gas molecules then flow

through the natural fracture system to the wellbore. The composition and geological history of a coal

seam will determine whether it is fully charged with gas or whether it exists in some state of

undersaturation. Undersaturated seams are common in the UK and the rest of Europe.3

In an

undersaturated coal seam, only water is produced initially, gas production being delayed until

reservoir pressure has declined to the point of saturation.

Ultimate gas recovery from a CBM well is a function of a complex relationship between permeability,

thickness and well spacing, but the production rates for the first portion of the well’s economic life

are almost solely dependent on the product of coal seam permeability and thickness. Using the

available information from public and private sources, it is possible to construct a forecast of the gas

and water production associated with a typical European CBM well. Using this data, and employing a

finite difference reservoir simulation model, rate forecasts were constructed. This resulted in a single

well forecast with a maximum gas rate of between 100 and 150 mcfd ( 3.4 to 4.0 m3d ). These rates

are similar to US coal developments in the Black Warrior Basin of Alabama.

Although various CBM wells currently planned may have characteristics different from those

assumed, the reservoir parameters used in this paper can be considered as typical. Wells with coal

thicknesses greater than 20 metres would produce at a higher rate. If the permeability is less than 1.5

md the rate would be lower.

CBM is often viewed as a statistical “play”. Companies planning to drill only one well are rare, as the

initial costs are discouraging, also, the gas recovery benefits from multi-well developments are well

documented. Therefore, three plans were postulated for investigation: a single well, a 5 well cluster

and a field development of 100 wells.

As the main aim of this paper is to examine the effects of various European fiscal regimes on CBM

development, the risk associated with well success is ignored, i.e. ALL wells are successful at

producing the rate forecast.

To determine the relative fiscal worth of the three plans for each particular country Arthur Andersen’s

Financial Analysis System was used. Two groups of economic scenarios were modeled;

1. Assuming country specific development and operating costs with the SAME gas price

throughout Europe (15p/th).

2. As 1. but applying specific gas prices to each country.

The countries assessed are the U.K, Netherlands, France, Germany and Poland.

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Drilling and completion costs were varied between the well plans to reflect the fact that drilling costs

would be dramatically reduced with 100 wells. In Poland drilling and operating costs were reduced by

around 35% to reflect cheaper labour and environmental costs.

For the UK in particular, the sensitivity of NPV and IRR to gas price was also investigated

Results are presented as a country comparison of NPV’s, IRR’s and payback periods. This allows

countries to be ranked for both scenarios and indicates some degree of sensitivity of a country’s

suitability for economic CBM development. It should be pointed out that several of the countries

included in the analysis are rumored to be negotiable on the fiscal regime to apply to the currently

fledging industry of CBM drilling and development. However, until negotiations concerning the same

are public information, only the published royalties and tax structures can be used.

Production Forecast

Geologic Parameters It has been estimated that the world’s resources of coalbed methane ranges between 2.2 and 7 trillion cubic feet (80 and 250 trillion m3 ), of this less than 10 percent is assumed to occur in Western Europe. However, its relative importance is much more than the absolute reserves signify. Due to the industrial revolution most of the major cities of Europe have developed around the significant coal fields (see Figure 1). With Europe being one of the more densely populated areas of the world, the need currently exists for a cheap, clean and Local power source. The analysis of coreholes and CBM wells drilled within Europe has allowed the justification for constructing a typical European well. Permeability, net coal thickness, gas content and degree of saturation, which are the major controllers of magnitude and sensitivity of CBM projects, all drop within the same range of values across Europe (see Table 1). Although some CBM wells planned or recently drilled have characteristics different from those assumed, the reservoir parameters used in this paper can be considered as typical for comparing and assessing the economics of a new project. Table 1 also lists the minimum and maximum values that have been seen. The most critical reservoir parameter for CBM prospects is the coal seam’s permeability, with which the production rate varies proportionally. Hughes and Logan (1990), state that the minimum required permeability in order to recover methane is generally greater than 1 mD. The most likely value of 1.5 mD used was based on the range of values seen in European production tests. The net coal thickness was defined as 20m over a vertical interval of 120m. The combination of these properties yields a gas production rate peaking between 100 and 150 mcfd (3-4 m3d). To achieve such rates the coal must contain sufficient gas. Peak methane generation and storage occur in rank terms, between medium volatile and low volatile bituminous (MvB & LvB respectively). The process is thermogenic with possibly some secondary biogenic production. Carbon dioxide is also generated, but concentrations are usually low. Coal seams that have been targeted for CBM development usually have a rank between HvB and MvB. Coal rank and gas content generally increase with depth, but increased depth has a detrimental effect on permeability. Therefore, there is a trade off between increased gas content and diminishing permeability. European coals that offer a high enough permeability contain between 224 and 385 SCF/T (approx.10 m3/ton) of methane and occur at depths up to 3,800 feet (approx. 1,200 meters).

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Coal gas capacity is reduced by the effect of ash (typically 5 to 30%) and temperature (average 35 deg C ). Ash is an all encompassing term for impurities, the greater the amount of impurities in the coal means fewer attachment sites for the carbon atoms. Increasing coal seam temperature reduces gas capacity in that the carbon molecules have more energy to overcome the weak bonding forces. The actual gas content of many European coal seams have been reduced to 90 to 95 percent of their

indicated gas capacity. This results from post depositional uplifting, faulting and erosion. Uplifting

reduces the coals temperature and increases its gas capacity, hence producing an apparent

undersaturated coal. Faulting and erosion allows gas to escape throughout geologic history and again

leads to an undersaturated coal. In an undersaturated coal seam, only water is produced initially. The

gas production is delayed until the reservoir pressure has declined to the level of saturation.

European coal seam pressure gradients vary from a normal gradient of 0.43 psi/ft to an underpressured value of 0.25 psi/ft. Folding and faulting of sealed reservoir units, which retain their original pressure, is a possible answer to the abnormally low pressure gradients (Creedy 1991 ).

Rate Forecast Two rate forecasts were constructed using the typical geologic parameters and CG&A’s in-house CBM reservoir simulation model. The first forecast represented a single well drilled on a spacing of one sq. km. The second rate forecast assumed three wells per sq. km i.e. an infill drilling scenario. Gas production rate for the infill forecast reaches a peak production level of 140 mcfd per well within 5 years of drilling. The productive life of the well is 23 years to a terminal rate of 25 mcfd. The one well per square kilometer forecast peaks at 120 mcfd within 13 years of drilling and has a life of 41 years. Comparison of the cumulative production after 20 years of life shows the infill forecast producing nearly twice as much gas. Water production is comparable between the two forecasts. For the purposes of preparing the forecasts and estimating the costs, the wells for both rate cases were planned to be completed as cased holes with small scale frac jobs. European experience has indicated that massive hydraulic fracturing does not produce significantly higher production than smaller scale frac procedures. Hence, a small fracture length of 20m was assumed. The well was also assumed to be drilled with a non damaging fluid (water or air). To simulate the gradual start up procedures normally practiced in the field, the simulated flowing bottomhole pressure was reduced over 6 months, at a rate of 50 psi per month, until a terminal pressure of 100 psi was reached. This technique is used in the field to limit the migration and production of coal fines. The remaining production history of the well was assumed to occur at this flowing bottomhole pressure. This would be roughly equivalent to a wellhead producing pressure of 50 to 60 psi.

Well Plans To reproduce a model that mimics likely development plans, three designs were employed. Using the same typical geological parameters, a one well plan, a five well plan and a one hundred well plan were constructed. To avoid additional complexities, it was decided to

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ignore the risks associated with well success during drilling and completion and focus solely on the effects of the fiscal regimes, currently in place within the various European countries. A spacing of one square kilometer ( sq. km. ) was used for the one well plan. The two multi well plans assume a reduced well spacing of 3 wells per sq. km. Unlike conventional gas reservoirs, well spacing within CBM reservoirs, significantly improves recovery efficiency (Ertekin et al 1991). Though ultimate recovery factors are similar, the rate of recovery for the multi-well cases exceeds that of the single well case resulting in a shorter producing life. All three well plans assume a Pilot well is drilled first. This acts as a test bed for both geological and engineering variables, with the remaining wells being drilled 6 months later. For the 1 well plan : The Pilot well is completed and assumed to start producing from day one. For the 5 well plan : After 6 months a program to drill the remaining 4 wells is started, the wells are drilled back to back, assuming one per month. The total time to drill and complete all 5 wells is 10 months. For the 100 well plan : After 6 months three 5 well plans are initially instigated (see above). It is assumed that there are three prospective areas, each being developed simultaneously. Therefore, after 10 months each area will have five wells drilled upon it. The remaining 85 wells are drilled back to back after 12 months (allowing two weeks contingency), assuming one per month per area. Using three rigs, all wells on the three areas will be drilled within 3.5 years. A summary of the drilling programme can be seen in Table 2.

Fiscal Forecast Typical cash flow streams for the three well plans were generated, using Arthur Andersens’s Financial Analysis Service. The production data, gas price, capital and operating costs were input as outlined in Table 2. Application of the various country specific fiscal regimes was made, enabling the countries to be ranked and their relative attractiveness compared.

The analysis assumed first capital expenditure in 1996 with production start in 1997. All

NPV’s are shown at either 10% or 15% nominal post tax rates of returns at 1 Jan 1996. Gas Price In Scenario 1 we have assumed the same gas price of 15p/th (1996) for all countries. This price has been escalated according to Table2. In Scenario 2 Arthur Andersen used their industry knowledge of the individual European markets to assign gas price by country. In the UK, a range of values was used to test for the sensitivity of NPV and IRR to gas price. Table 2 shows the country specific gas prices and the manner in which they are escalated.

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Capital and Operating Costs Capital and operating costs have been assumed to be constant across Western Europe but have been reduced by around 35% for Poland to reflect the cheaper labour and environmental costs. These costs can be seen in Table 2. The values all fall within the anticipated range expected in Europe. Though not specific they allow a simple comparison to be made purely on the ‘attractiveness’ of each fiscal regime. The Pilot well cost is substantially higher than for subsequent wells. Typically a more extensive sampling and testing plan is conducted, with completion requiring more time. Economies of scale and learning curves begin to show benefit as the well count increases. This is reflected in the sliding scale of well costs and operating costs. Capital costs include completion and analysis. Operating costs include workovers, but no abandonment charge. Water disposal costs are assumed to be constant across Europe, with some variance depending on method and quantity. Bulk water disposal incurs similar set up charges to smaller ventures. This value, which can be significant, is spread over many more barrels, hence a reduction in cost per barrel.

Fiscal Regimes The country specific fiscal regimes which were applied to both scenarios are summarized in Table 3.

Results Table 4 shows the NPV’s, IRR’s and payback periods for each country under Scenario 1 (constant gas price) and 2 (country specific gas price). A nominal discount rate of 10% was used for this comparison. This rate does not take into account country specific risk and NPV’s at 15% nominal discount rate are also shown in the table. Figure 3 shows NPV’s IRR’s and payback periods represented graphically for each scenario Figure 4 shows the sensitivity of NPV’s and IRR’s to gas prices in the UK. When the 100 well projects with country specific gas prices are ranked by NPV @10% nominal post tax discount rate, we find that: Most attractive Poland Germany France Netherlands Least attractive UK

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Discussion of Results With its reduced costs and higher gas price, Poland ranks No 1 in both our scenarios. This result should however be treated with caution given Poland’s economic stability and the investment risk What the results show is the high sensitivity of a CBM development to gas price. In the UK for instance with a 12p/th gas price, the 100 well scenario only just breaks even ie it produces a near zero NPV. With 18p/th, however, a NPV of £15 million and IRR of 19% are achievable. With deregulation especially in the UK and potentially in the rest of Europe uncertaintity in gas price, with periods of relatively low gas prices does not bode well for investment in CBM projects in Western Europe. The Polish results are the most encouraging but once this market has been assessed for country specific risk the benefits identified will be reduced. This study has not taken account of reserve risk and this will further reduce the attractiveness of CBM projects. However, we have not included for any additional value associated with add-on projects futher down the gas chain eg investment in turbines to produce power. Comparison between well plans is not what the study is aimed at. The 100 well plan is not a more densely spaced 5 well plan, but an increase in the acreage drained, hence the recovery factors are similar at approximately 22%. The results show that the 1 well and 5 well scenarios should be regarded merely as stepping stones to the 100 well scenario. Infill drilling with this low permeability produces higher returns, this is reflected in the two rate forecasts. However, as there is also an increase in the well count between well plans the affect of well spacing on the net present value is masked. No assumption has been made of the political climate or the availability and cost of licenses, something that is not easily quantified but obviously integral.

Conclusions The conclusions to be drawn from this paper are: The results show that the 1 well and 5 well scenarios should be regarded merely as

stepping stones to the 100 well scenario.

The 100 well scenario could produce nominal post tax rates of return between 10% and 28% and NPV’s at 10% nominal discount rate of between £0 and £19 million.

It appears that Poland provides the most attractive regime for CBM development. The UK is the least attractive. The primary cause of this is gas price.

The economics of CBM projects are highly sensitive to gas price.

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References

Mechanics of Coalbed Methane production : J.C. Creel and J.B. Rollins, Cawley, Gillespie & Associates, Inc. Potential for Development UK Coalbed methane : J.C. Creel, Cawley, Gillespie & Associates, Inc. Coalbed Methane extraction : Davidson, Sloss and Clarke, IEA Coal Research (Jan 1995) International Unconventional Gas Symposium, Proceedings : Intergas 95, University of Alabama (May 14-20th). Coalbed Methane Utilisation, Proceedings (Volume 1) : Silesian International Conference, Katowice, Poland (October 5-7th, 1994). Coalbed Methane Extraction, an Analysis of UK and European Resources & Potential for Development : IBC Technical Services Ltd., London (January 24-25th 1994). Planning for Profit Coalbed Methane in the UK & Europe : IBC Technical Services Ltd., London (March 30-31st 1995). How to design a coalbed methane well : Petroleum Engineer Int. Hughes and Logan (May1990) An introduction to geologic aspects of methane occurrence and control in British deep coal mines : Quarterly Journal of Engineering Geology Creedy (1991) Structural properties of coal that control coal bed methane production: Geology in Coal resource Utilization Ertekin et al (1991)

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Table 2 - Development Costs and Gas Prices

Drilling Costs Western Europe Poland

Well No 1 £ 700,000 £ 437,500

Well No 2-5 £ 400,000 £ 250,000

Well No 6-100 £ 250,000 £ 156,250

Operating Costs Western Europe Poland

1 Well Scenario £ 2,000 per month per well £ 1,250 per month per well

5 Well Scenario £ 2,000 per month per well £ 1,250 per month per well

100 Well Scenario £ 1,000 per month per well £ 625 per month per well

H2O Disposal All countries

1 Well Scenario £ 0.20 per barrel

5 Well Scenario £ 0.20 per barrel

100 Well Scenario £ 0.10 per barrel

Gas Prices

Country Gas Price in 96/97 Inflated by

UK 12 p/th 50% RPI + 50% Oil Price

Netherlands 15 p/th 25% RPI + 75% Oil Price

France 16 p/th 50% RPI + 50% Oil Price

Germany 18 p/th 10% RPI + 90% Oil Price

Poland (minimum of) 19p/th

23 p/th

100% RPI (Gas price in Zty)

100% Oil (Gas price in $)

Drilling Programme (number of wells drilled)

1996 1997 1998 1999 2000

1 Well Scenario 1

5 Well Scenario 1 4

100 Well Scenario 3 12 36 36 13

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Table 3 - Summary of Fiscal Regimes

Royalty Country

Specific

Hydrocarbon

Taxes

Corporate Taxation

UK 0% none 33%

Netherlands 0% upto 28 bcf/yr PST - 70% 35%

France 0% none 33%

Germany 10% none Municipal 23%

State 27.8%

Poland 6% none 40%

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Table 4a - 15 p/th Gas Prices 1 Well Case

Country Gas Price NPV at 1 Jan 96 NPV at 1 Jan 96 IRR Payback Year at 10%

@10% nom disc @15% nom disc Project Start =1996

p/therm £ ,000 £ ,000

UK 15 (422) (513) 2.7% 2016

Netherlands 15 (359) (470) 3.9% na

Germany 15 (390) (444) 0.9% na

Poland 15 (229) (306) 4.2% 2013

France 15 (441) (521) 2.0% 2004

5 Well Case

Country Gas Price NPV at 1 Jan 96 NPV at 1 Jan 96 IRR Payback Year at 10%

@10% nom disc @15% nom disc Project Start =1996

p/therm £ ,000 £ ,000

UK 15 (913) (1,163) 1.7% 2009

Netherlands 15 (751) (1,026) 3.3% na

Germany 15 (811) (1,051) 1.6% na

Poland 15 (306) (563) 6.4% 2006

France 15 (933) (1,269) 1.6% 2018

100 Well Case

Country Gas Price NPV at 1 Jan 96 NPV at 1 Jan 96 IRR Payback Year at 10%

@10% nom disc @15% nom disc Project Start =1996

p/therm £ ,000 £ ,000

UK 15 7,406 (83) 14.9% 2004

Netherlands 15 2,594 (2,350) 12.2% 2010

Germany 15 3,707 (2,292) 12.7% 2010

Poland 15 10,720 3,921 20.4% 2003

France 15 5,406 (1,048) 13.9% 2004

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Table 4b - Country Specific Gas Prices 1 Well Case

Country Gas Price NPV at 1 Jan 96 NPV at 1 Jan 96 IRR Payback Year at 10%

@10% nom disc @15% nom disc Project Start =1996

p/therm £ ,000 £ ,000

UK 12 (536) (587) na 2024

Netherlands 15 (359) (470) 3.9% na

Germany 18 (285) (377) 3.9% na

Poland 19 (120) (235) 7.2% 2009

France 16 (409) (499) 2.7% 2016

5 Well Case

Country Gas Price NPV at 1 Jan 96 NPV at 1 Jan 96 IRR Payback Year at 10%

@10% nom disc @15% nom disc Project Start =1996

p/therm £ ,000 £ ,000

UK 12 (1,418) (1,521) na na

Netherlands 15 (751) (1,026) 3.3% na

Germany 18 (544) (810) 5.0% na

Poland 19 151 (232) 11.7% 2003

France 16 (799) (1,070) 3.0% 2008

100 Well Case

Country Gas Price NPV at 1 Jan 96 NPV at 1 Jan 96 IRR Payback Year at 10%

@10% nom disc @15% nom disc Project Start =1996

p/therm £ ,000 £ ,000

UK 12 (3) (5,087) 10.0% 2006

Netherlands 15 2,594 (2,350) 12.2% 2010

Germany 18 9,280 1,313 16.3% 2008

Poland 19 18,779 9354 27.5% 2002

France 16 7,572 430 15.4% 2004

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Figure 3a - 100 Well Scenario NPV, IRR and

Project Payback with 15p/th gas prices

0

5

10

15

20

£ m

illi

on

s

NP

V

UK Netherlands Germany Poland France

NPV @ 10% nominal with 15p/th gas price

0

5

10

15

20

25

30

IRR

%

UK Netherlands Germany Poland France

Nominal IRR with 15p/th Gas Price

1996 1998 2000 2002 2004 2006 2008 2010 2012

UK

Netherlands

Germany

Poland

France

Payback @10% nom disc

with 15p/th gas price

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Figure 3b - 100 Well Scenario NPV, IRR and Project

Payback with country specific gas prices

0

5

10

15

20

15

18

19

16

£ m

illi

on

s

NP

V

UK Netherlands Germany Poland France

NPV @ 10% nominal with likely gas price

0

5

10

15

20

25

30

12

15

18

19

16IRR

%

UK Netherlands Germany Poland France

Nominal IRR with likely Gas Price

1996 1998 2000 2002 2004 2006 2008 2010 2012

12

15

18

19

16

UK

Netherlands

Germany

Poland

France

Payback @10% nom disc

with likely gas price in p/th

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Figure 4 - Sensitivity to Gas Price in the UK 100 Well Scenario

Gas Price

p/th

NPV at 1 Jan 96

@10% nom disc

£ ,000

IRR

8.4 (9,177) 2.8%

9.6 (6,015) 5.4%

10.8 (2,925) 7.8%

12.0 114 10.0%

13.2 3,116 12.0%

14.4 6,104 14.0%

15.6 9,060 15.8%

16.8 12,017 17.6%

18.0 14,948 19.4%

6 8 10 12 14 16 18 20-15

-10

-5

0

5

10

15

20

Gas Price p/th

NP

V £

mil

lion

s

UK CBM Sensitivity to Gas Price

NPV @ 10% Nom Disc

6 8 10 12 14 16 18 200

5

10

15

20

Gas Price p/th

IRR

%

UK CBM Sensitivity to Gas Price

Internal Rate of Return