Cost savings and activity levels in the UKCS

Enrr~)’ Poh~y, Vol. 23. No. I. pp. ,143, ,995 Elsevier Science Ltd Printed in Great Britain 03014215/95$10.00+0.00

Cost savings and activity levels in the UKCS A positive sum game Alexander G Kemp and Bruce MacDonald Declining production in mature fields, relatively small sizes of new fields, the fall in oil prices and the high tax takes in old fields have combined to squeeze profit margins on petroleum exploitation in the UKCS. Achieved reductions in development and operating costs can help to sustain activity levels over the next two decades. Contractors as well as oil companies and the nation generally will benefit from the substantial number of induced extra field developments achieved from cost savings of 20%. Keywords: Cost savings; Induced investment:

Enhanced production

In the present operating environment it is arguable that the continued healthy development of the UKCS depends to a considerable extent on the achievement of further cost savings. Currently oil prices are relatively low. They are comparable to what they were over 20 years ago in real terms. Production from the early generation of large, prolific fields has long passed plateau levels and operating margins are now relatively low. Effective tax rates on these mature fields are still substantial despite the large reduction in Petroleum Revenue (PRT) in the 1993 Finance Act. Many of the new prospective fields are small with costs per barrel often being relatively high. Some prospective fields, especially gas condensate ones, have very substantial reserves, but the reservoirs often have high high pressure characteristics. Their temperature, development may well require cost reductions as well as technological progress. The authors are with the University of Aberdeen, Edward Wright Building, Dunbar Street, Old Aberdeen, AB9 2TY, UK.

The UK government (Report of the Working Group, 1993; Working Group on UK Competitiveness, 1993) and oil industry leaders (Crine, 1994) have recognized the nature of the problem and have recently launched a cost reduction initiative with the acronym CRINE (Cost Reduction Initiative for the New Era). The emphasis in this initiative is on how investment and operating costs may be reduced. This paper examines some economic aspects of cost reductions. The effects of savings in investment and operating costs on activity levels are assessed. Emphasis is placed on the effects of such savings in enabling more new projects to proceed than would otherwise be the case. The net effect on total new expenditure on field development activity and production levels is highlighted. In the petroleum sector the assessment of projects is generally by discounted cash flow methods. These emphasize the time value of money. It follows that any savings in the cycle time between expenditure on exploration and appraisal (E and A), development expenditures and the related field production increases the net present values (NPVs) and rates of return from

Energy Policy I995 Volume 23 Number I

71

Cost savings and activily in the UKCS: A G Kemp and B MacDonald

the projects. The extent of such possible is also examined in this paper.

improvements

Effects of cost savings on activity in central North Sea (CNS) and northern North Sea (NNS) Methodology and assumptions The effects of achieved cost reductions in CNS and NNS have been examined with respect to all known fields including (i) mature fields which have been producing for many years, (ii) fields currently under development, and (iii) discovered fields which are not yet under development and in some cases have not even been fully appraised. The exercise was undertaken through the use of a large computerized financial model developed at the University of Aberdeen to simulate future activity levels in the UKCS (Kemp and MacDonald, 1991; 1993). Primary inputs into the model include all the publicly available information on currently producing fields relating to their historic and expected production rates, investment costs, operating costs and abandonment costs. From a variety of sources information has also been gathered on all new discoveries which have not yet been developed or even fully appraised in some cases (Wood, Mackenzie, various issues; Nor-oil and Euroil, various issues). Estimates were made of the time periods at which such fields would be ready for development work and production to commence. For these future fields estimates were made of the likely investment costs, operating costs and abandonment costs. In making such calculations some judgements were made regarding the technological progress which will be required, and the cost assumptions have to an extent assumed that such progress will in fact be made. However, in other respects the bank of future fields can be described as conservative as it does not include any new discoveries from further exploration successes. With regard to future field developments the distincbetween probable and possible tion is made developments. Probable developments are defined as those which are currently being appraised or for which reasonably accurate estimates of reserves are available, and development seems likely in the next few years. Possible developments refer to fields where the reserves estimates are not well defined at present, and where some uncertainty exists regarding possible development concept, timing, and production profiles. In these cases a best estimate of recoverable reserves and development expenditure has been employed. Key inputs into the financial model are assumptions

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Energy Policy 1995 Volume 23 Number I

about future oil and gas prices. The oil prices employed in the simulations are as follows: (i) US$15 per barrel in constant real terms; (ii) US$l7 per barrel in constant real terms; (iii) US$18 per barrel in real terms until 1995, increasing to US$20 in real terms in 1998. This price is maintained in real terms until 2000 after which it increases to US$20.2 in 2003, US$23.3 in 2008, US$24.8 in 2010 and US$29.1 in 2020. The general inflation rate assumed averages 5% per year. There is thus a considerable increase in oil prices in money of the day terms. The price scenarios adopted are not forecasts. They have been deliberately chosen to examine the effects of relatively low oil price situations. They should not be regarded as exhibiting the range of likely possible prices. The financial simulation model operates by calculating the pre-tax and post-tax returns to the projects under the different oil and gas price scenarios. When a posttax real rate of return of at least 10% (15% in MOD terms) is achievable the project is deemed to be acceptable. If this minimum return is not attainable the field’s development is postponed until such time as this return is achievable. The study examines the effects of achieved cost reductions of 20% under the following headings:

0) Field development

(or investment) costs: these costs are split between capital expenditure and development drilling expenditure. For the mature fields only reductions in such costs from 1993 onwards are considered. (ii) Operating costs: again on the mature fields only savings from 1993 onwards are considered. The exercise was conducted under the fiscal terms applicable following the 1993 Finance Act. US$lS price scenario Effects on field development expenditure in CNS and NNS. The results of the exercise are now discussed. The effects of a 20% cost saving in all field development and operating costs from 1993 onwards on the pattern of development expenditure are shown in Figure 1 under the US$15 oil price scenario. The chart shows the net effect on development expenditure. The development cost savings on existing fields and relating to those new ones that would go ahead in any case are shown in the form of negative values. The chart also shows (in the form of positive values) the value of the extra investment expenditure that is incurred as a consequence of new projects going ahead which otherwise would not have been viable. The continuous line shows the net effect. The results show that there is always some new

Cost savings and activity in the UKCS: A G Kemp and B MacDonald

Year

Year -

Figure 1. Development expenditure in CNS and NNS: effect of 20% reduction in development and operating expenditure, real US$15 oil scenario.

coo

f

1

m

Add. fldd

Dwa

0

Cut

M

mvinga

Figure 3. Development expenditure in CNS and NNS: effect of 20% reduction in capital expenditure, real US$15 oil scenario.

e mllllon

@

Change TOW Dmw

---

million

I

I

400 200 0 -200 -400 I

Year

Figure 2. Development expenditure in CNS and NNS: effect of 20% reduction in development expenditure, real US$1.5 oil scenario.

Figure 4. Development expenditure in CNS and NNS: effect of 20% reduction in drilling expenditure. real US$15 oil scenario.

induced development expenditure as a consequence of the cost savings. It is noteworthy that for several years the net amount of development expenditure taking place is higher with the cost savings than without them. There are so many extra developments triggered as a consequence of the cost savings that they more than compensate for the reduced level of development expenditure on projects which were in any case taking place. In Figure 2 the effects of a reduction in development costs by 20% from 1993 onwards are shown under the US$15 oil price and the same assumptions as before. There is again seen to be a worthwhile increase in development expenditure from the achieved savings. The extent of the increase is somewhat less than in the first case, indicating that the cumulative effect of 20% savings in operating costs does contribute significantly to the viability of new projects. Figures 3 and 4 show respectively the effects of 20% savings in capital costs and development drilling costs. The savings in capital costs are clearly the more important, but it is noteworthy that savings in each category can lead to increased numbers of projects going ahead.

In Figure 5 the effects are shown of a 20% saving in operating costs from 1993 onwards on the amount of development expenditure. The finding is that these cost savings also make a significant impact on the amount of extra investment expenditure on new field developments. Effect on field operating expenditure in CNS and NNS. The effects of cost savings on the pattern of operating expenditure is now examined. In Figure 6 the effects of a 20% cut in development and operating costs are shown. From the later 1990s onward it is seen that the extra operating expenditures induced by the cost savings become quite substantial, due principally to new field developments. In Figure 7 the effects of a reduction of 20% in development costs on the pattern of operating costs is shown. The reduced development costs, by triggering off a significant number of field developments, induce significant new operating expenditures. In Figure 8 the effects are shown of a reduction of 20% in all operating costs from 1993 onwards. The cost savings do induce some field developments and prolong field lives, and thus in-

Energy Policy 1995 Volume 23 Number I

73

Cost savings and activity in the UKCS: A G Kemp and B MacDonald

C million

r

800

-6W

J

.

.

.

-

.

*

2003

’

1

1998

1993

1

7

2w3

2oD6

Year

2003

Year 1 -

Ch~ngeToWDww

1

~Add,fieldDwex

Figure 5. Development expenditure in CNS and NNS: effect of 20% reduction in operating expenditure, real US$15 oil scenario.

Figure 8. Operating expenditure: effect of 20% reduction in operating expenditure only, US$15 real oil price scenario.

lW0

600 0 -600 -1000

,

,

1963

,

,

,

*

1963

I.,

,

2003

,

-1600 2006

1993

1998

Year

-

T&l

0

Costcutrmfings

Change in Opcc

-

Figure 6. Operating expenditure: effect of 20% reductions in development and operating expenditure, real US$15 oil scenario.

Open

2003

2008

Year Chwvg.To@l Expend.

m

Add. fiokl Expand.

1

Figure 9. Total expenditure in CNS and NNS: effect of 20% reduction in development expenditure and operating expenditure, real US$15 oil price scenario.

e mlllke

C ml6bn 1000 606 660 400 206 0 -200 -4w -000 -800

260 200 160 100 60 0 l&a

2Ooa

low‘

2W6

1998

1993

Ye8r -

TOM Chaw

0

Gmtcutwings

in Opac

m

2003

2008

Year 0p.x from wid. fkil

-

ChanwTc&I

a

TOW cut uvinga

Expwd.

m

Add. tbld Expwd.

Figure 7. Operating expenditure: effect of 20% reduction in development expenditure only, US$15 real oil price scenario.

Figure 10. Total expenditure in CNS and NNS: effect of 20% reduction in development expenditure only, real US$15 oil price scenario.

duce some new operating

is such that total induced development and operating expenditures are increased very substantially, reaching around &I billion in 1997 and 1998. In the early years the net effect is a substantial reduction in total expenditure, but in several years the net effect is actually positive. In Figure 10 the effects of a 20% cut in development

expenditures,

but the net effect

is generally to reduce levels of operating expenditure. Effects on total expenditure in CNS and NNS. The effects of cost savings on total expenditure are now examined. In Figure 9 the effects of cost savings of 20% in development and operating costs are shown. The impact

74

Energy Policy 1995 Volume 23 Number I

Cost savings and activity in the UKCS: A G Kemp and B MacDonald

f million

Tot61 no. 01 fieldr

(00 ‘200

I

-aooJ:

1

,

,

,

:

,

,

,

.

:

,

.

,

,

In pmductlon

,,,A

:I I

1998

1932

I0

2003

2ooa

Year

Year ChangaTMal

Gwnd

m Add.field

.

Tc4elcaauvin@

Expnd

1 .

Figure 11. Total expenditure in CNS and NNS: effect of 20% reduction scenario.

in operating expenditure

only, real US$15 oil price

I

Figure 13. Additional field developments in CNS/NNS: effect of 20% reductions in development and operating expenditure, real US$l5 oil scenario.

mboald 0.6

I

1

ev

-.--..-..-~___

26 20 16 10 6 0

1666

1963 C6p. Op & Drill Capax & Drill Carts

IhiiPria

Capax

oprx

Drilkx

reduced by 20% m

617A~rr*l

0

616/bur~l

Figure 12. Impact of cost cuts in CNS and NNS: additional developments

induced by cost cuts to 2018.

are shown. It is again noteworthy that in a considerable number of years between now and 2008 the effect of a 20% cut in development costs is to induce a greater increase in total expenditure. In Figure 11 the effects of a 20% cut in operating costs alone are shown. In most years the induced expenditure is less than the value of the cost savings, but it is noteworthy that in some years the induced expenditure exceeds the cost savings.

expenditure

Additionalfields in production. The effects of cost reductions are to induce the development of new fields. In Figure 12 the numbers of additional fields whose development is made viable by cost savings of 20% in the period 1993-2018 are shown for all three price scenarios. Under the US$15 price scenario 27 extra field developments are induced. This compares with 21 under the US$17 price and only 5 under the higher price. Reductions in capital costs and operating costs are both important in inducing new developments. In Figure 13 the total number of fields in production in the period to 2008 is shown with and without the cost savings under the US$15 price case. The difference in

2002

2006

Year -

Toul than@

0

Prod at.

in prod

m

Prod from add. fiald

field life

1

Figure 14. Additional production from CNS/NNS: effect of 20% reduction in development expenditure and operating expenditure, real US$15 oil scenario. the number of fields becomes significant from the mid1990s onwards. The effects of the prolongation of field lives are included as well as new developments. It is seen that in 2002 no less than 110 fields could be producing with overall cost savings of 20% but only 82 fields with no cost savings. Additional production. The effects of the cost savings on production are now considered. In Figure 14 the additional production from (i) extra field developments and (ii) prolongation of field lives are shown from reductions in total costs of 20%. The total annual extra production rises substantially in the later 1990s and for around seven years is in the range of 0.4-0.5 million b/d oil equivalent. By far the greatest contribution to the extra production comes from extra field developments. The effects of a 20% saving in development costs alone are shown in Figure 15. The extra production rises to a peak of around 0.25 million b/d oil equivalent at the beginning of next century. The contribution of 20% savings in operating costs alone to extra production is shown in Figure 16. The extra production rises substan-

Energy Policy 1995 Volume 23 Number I

75

Cost savings and activity in the UKCS: A G Kemp and B MacDonald

number of field abandonments effect is substantial.

mboold

are postponed

the former

US$17 price scenario

1208

1993

2003

2003

Year -

Total change in prod

0

Prod ext. hid

1

iSlY Prod from add. firld

lib

Figure 15. Additional production from CNS/NNS: effect of 20% reduction scenario.

in development

expenditure,

real US$15 oil

mboeld

...... ............. ... ......... . .............

_

.................

Year -

Total change in prod

0

Prod ext. field lib

l!?Sl Prod from add. field

Figure 16. Additional production from CNS/NNS: effect of 20% reduction in operating expenditure, real US$15 oil scenario.

2 milllon ““I

,

-eooJ:

I

r

t

,

1993

,

:

,

,

,

1923

,

: 2003

a 1 ,

0 :’ 2003

Year

Figure 17. Development effect of 20% reduction operating expenditure,

expenditure in CNS and NNS: in development expenditure and real US$17 oil scenario.

tially in the later 1990s and reaches a peak of 0.25 million b/d oil equivalent in the early years of next century. Extensions to field lives are generally much less important than new developments, but occasionally when a

76

Energy Policy 1995 Volume 23 Number 1

Effects on field development expenditure. Under the US$17 oil price scenario the effects of a 20% saving in development and operating costs are shown in Figure 17. There is still a substantial amount of induced investment in new field developments, though it is less than under the US$15 price scenario (see Figure 1). Nevertheless for a number of years the induced new investment is greater than the value of the savings in development costs. In Figure 18 the effects of cost savings of 20% in development costs alone are shown. While there is again substantial new investment it is generally less than the value of the cost savings. Often there is not much difference in the magnitudes. In Figure 19 the effects are shown of 20% savings in operating costs on induced investment. The extra investment is significant for a number of years from the later 1990s though the induced effect is again not so strong as under the US$15 price scenario. Effects on field operating expenditures in CNS and NNS. In Figure 20 the effects of savings of 20% in development costs in inducing extra operating costs via new field developments are shown. The extra operating expenditures are seen to rise to over f250 million per year in the early years of next century. In Figure 21 the effects of cost savings of 20% of operating costs are shown. In this case the value of the cost savings are considerably in excess of the extra expenditure from the development of new fields. In Figure 22 the effects of cost savings of 20% in all investment and operating costs are shown. The value of the cost savings is always greater than the extra operating expenditures. Effects on total expenditure in CNS and NNS. The effects of the cost savings on total expenditure in CNS and NNS are now examined. In Figure 23 the results of a 20% reduction in development and operating costs are shown. The total cost savings always exceed the extra induced expenditure, but it is noteworthy that the difference is frequently quite small. This is especially the case in the period from 1998 to 2008. In that period the annual

total

extra

induced

expenditure

is never

below

&500 million and reaches a peak of f750 million. In Figure 24 the total effects on expenditure of a 20% cut in development costs alone are shown. In this case the induced total expenditure exceeds the savings in development costs from the period 1998-2008, sometimes by a substantial margin. Savings in development costs to the extent shown are thus quite potent in

Cost savings and activiry in the UKCS: A G Kemp and B MacDonald

-woo :

-ewJ: I

I

1

1663

:

I

I

lo66

:

I

I

2003

f

I

tiw

Ta*

Dwrx

RFJ Add. IbId bva

r

,

:

,

,

0

cat

,

I

lsQ6

:,

,

;I

,

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2006

Year

2006

Year -

r

lDO3

:

cut wings

-

Toul Ch4m

0

cmttiswing#

in Opa

m

opw from &d.

fide I

Figure 18. Development effect of 20% reduction US$17 oil scenario.

expenditure in CNS and NNS: in development expenditure, real

Figure 21. Operating expenditure:

effect of 20% reduction in only, real US$17 oil scenario.

operating expenditure

e milllon

Op*x 4W 200

.

-600 -ewJ:

1

I

I1

: lo66

1963

I

C~MMJ, Tall

Dw.x

m

Add. Md

I1 2003

I

I

1 2006

Devat

Figure 19. Development expenditure in CNS and NNS: effeet of 20% reduction in operating expenditure, real US$17 oil scenario.

op*x

I1

Year

Year -

I

Figure 22. Operating expenditure: operating scenario.

0 nIllIon

and

development

effect of 20% reduction in expenditure, real US$17 oil

C million -1””

600 _.

0

_. -600

- 1000 -1SOOl 1663

l666

2003

2006

:

r

,

1963

I

:

I

1 I

I

1666

I

1

t

2003

Year

I

I

!’ 2006

Year -

Chw-tg.Tc&l

0

T&l

Expnd

K%! Add. fi4ld Expwtd.

cat swing* 1

Figure 20. Operating expenditure: effect of 20% reduction in development expenditure only, real US$17 oil scenario.

Figure 23. Total expenditure

increasing activity levels and total expenditure in the North Sea. In Figure 25 the effects of a 20% reduction in operating costs on total expenditure are shown, It is seen that the cost savings generally exceed the induced expenditure. Nevertheless the difference is often not large and

on occasions savings.

20% reduction in development US$l7 oil scenario.

the induced

on CNS and NNS: effect of and operating expenditure, real

expenditure

exceeds the cost

Additional field developments

in CNS and NNS. The cost reductions induce a number of new field developments. In Figure 26 the results of a reduction in

Energy Policy 1995 Volume 23 Number I

77

Cost savings and activity in the UKCS: A G Kemp and B MacDonald

la99

Year

2002

Year -7GGGG-j -dwg*inno.offida

Figure 24. Total expenditure 20% reduction in development oil scenario.

on CNS and NNS: effect of expenditure only, real US$l7

e million

Ohvm*xt.fieldlih

Figure 27. Additional field developments in CNS and NNS: effect of 20% reduction in development and operating expenditure, real US$17 oil scenario.

10,

600-l

~fromadd.pmjeo

Change

in iha no. of pmdueing

field6

400 200 0 -2W -400 -600

._ _ ._

-800 1903

1223

2003

2003

1903

Year

1993

2005

2008

Year

-

ChangeTotal Expwl.

0

Total cost swings

m

Add. fiald Expend. -

Figure 25. Total expenditure on CNS and NNS: effect of 20% reduction in operating expenditure only, real US$l7 oil scenario.

Chmme In the no. of oroduclna

fltldr

chanw

in no. of fida

EBIl from add. pmjeaa

0

Figure 28. Additional field developments in CNS and NNS: effect of 20% reduction in operating expenditure only, real US$l7 oil scenario.

Total no. of fielda In nmductlon

2003 1993

1228

horn at. Wld life -II

2008

2003

2003

Year

Year -

d’w&win no. of fide

m

from aid. pmieUs

0

from at.

field lifa

Figure 26. Additional field developments in CNS and NNS: effect of 20% reduction in development only, real US$17 oil scenario.

Figure 29. Additional field developments in CNS and NNS: effect of 20% reductions in operating and development expenditure, real US$l7 oil scenario.

investment costs by 20% are shown. The results show the increase in the number of new fields in production. They rise to reach a cumulative extra total of 14 fields by 2005. The exercise was repeated for a reduction of 20% in both development and operating expenditures.

The latter can cause an extension to the lives of fields. In Figure 27 it is seen that the cumulative extra number of fields in production reaches 19 by 2007. The results also show that extensions to field lives occur in a significant number of cases. In Figure 28 the effects of a 20% re-

78

Energy Policy 1995 Volume 23 Numher I

Cost savings and activity in the UKCS: A G Kemp and B MacDonald

In Figure 29 the contribution of all the various forms of cost cuts to additional field developments and field life extensions is summarized for the period to 2008. The effects are clearly significant by the end of the 1990s.

mbo./d

-

ToulChUWpiflpWd

0

Prod aat Md

w

Pfodfrom8dd.li9ld

lib

Figure 30. Additional production from CNS and NNS: effect of 20% reduction in development and operating expenditure, real US$l7 oil scenario.

Additional production in CNS and NNS. The additional production which may be obtained from the reductions in development and operating costs combined are shown in Figure 30. The annual total is between 0.3 and 0.4 million b/d oil equivalent for eight years starting at the beginning of next century. In Figure 31 the extra production induced by a 20% reduction in development costs alone is shown. The extra annual output grows to over 0.2 million b/d oil equivalent by 2003. In Figure 32 the effects of cuts of 20% in operating costs are shown. Production from extra field developments reaches a peak of 0.2 million b/d oil equivalent by 2004. Extensions to field life add significant amounts as well. Higher price scenario

1995

lQQ@

2005

2000

Year -

lotalchwpinprod

I=

Pmd*xt.fi&llif9

&al

Prodfromadd.Md

Figure 31. Additional production from CNS/NNS: effect of 20% reduction in development expenditure, real US$17 oil scenario.

Effects on field development expenditure in CNS and NNS. The effects of cost savings on activity levels are not so pronounced under the higher oil price scenario. In Figure 33 the effects of a 20% cut in development costs are shown. The cost savings greatly exceed the induced investment for most of the period to 2008. Effects on operating expenditures in CNS and NNS. In Figure 34 the effects of a 20% cut in development costs on induced operating costs are shown. The effect is generally positive throughout the period but the magnitudes involved are relatively small. The relatively small effects are a consequence of far fewer additional field developments being induced under the higher price scenario. Additional field developments in CNS and NNS. In Figure 35 the effects of cost savings of different categories on the number of fields in production are shown. The extra fields and life of field extensions are very much less than under the lower oil price scenario.

lms

lQQ@

2005

2008

Year

Figure 32. Additional production from CNS/NNS: effect of 20% reduction in operating expenditure, real US$17 oil scenario.

duction in operating costs are shown. Cost reductions induce a cumulative total of 10 extra fields by 2008 as well as ensuring a considerable number of field life extensions.

Additional production in CNS and NNS. The effects of a 20% cut in development and operating costs on induced production are shown in Figure 36. The extra output from induced field developments is much less than under the lower price scenarios. It is noticeable that the output from extended field lives is often relatively significant in the total extra production. In Figure 37 the effects of a 20% cut in development costs are shown and in Figure 38 the impact of a 20% cut in operating costs. It is noteworthy that in a number of years the impact of savings in operating cuts is greater than from reduced investment cuts. This is generally in contrast to the situation under the lower oil price scenarios.

Energy Policy 1995 Volume 23 Number I

79

Cost savings and activity in the UKCS: A G Kemp and B MacDonald

2 mlllion 400 I

0.06

mboold ,

Year

Figure 33. Development expenditure in CNS and NNS: effect of 20% reduction in development expenditure, high oil price scenario.

-

TOW chmw

0

Prod ?? xt

5l

in prod

Prodfromadd.6ald

I

RLIIi&

Figure 36. Additional production from CNS/NNS: effect of 20% reduction in development and operating expenditure, high oil price scenario.

Ooex C million

mboold 0.06 I

2003

lo06

Year -

Total Change in Opax

0

cm1 cut *wings

&SKI opmt from add. fide

Figure 34. Operating expenditure: effect of 20% reduction in development expenditure, high oil price scenario.

Total nb. of Wldr

2006

Year

in productIon

I

n

-

Totalchw~~inprod

0

Prod at

m

Prod from add. f&Id

I

field lifr

Figure 37. Additional production from CNS/NNS: effect of 20% reduction in development expenditure, high oil price scenario.

mboeld

0.08,

,

90 70 60 2003

1603

2006

lo66

Year km Dw.xcutzOX FW Dewx

200s.

Year I

& OPX cut 26%

-

Total change in prod

0

Prod wt. field lib

m

Prod from add. IkId

Figure 35. Additional field developments in CNS/NNS: effeet of 20% reduction in development and operating expenditure, high oil price scenario.

Figure 38. Additional production from CNS/NNS: effect of 20% reduction in operating expenditure, high oil price scenario.

Effects of shortening cycle times on returns to investors

(NPVs) and internal rates of return. These emphasize the time value of money. Accordingly, it follows that if cycle times are shortened, NPVs can be improved even when the costs are not reduced in absolute terms. In this part of the study the elements of the cycle time which are examined concentrate on the period from first significant

Methodology and assumptions In the petroleum industry the acceptability of projects is generally assessed by estimating net present values

80

Energy Policy 1995 Volume 23 Number I

Cost savings and activity 06

64

06

66

67

66

66

00

01

06

03

04

in the

UKCS:A G Kemp and B MacDonald

06

zoo

Total RNPV 010% (6 million) .

160

....

100 60 0 -60

Figure 39. Phasing used in shortening cycle times: example of 100 mmbbls project (fast cycle time scenarios).

Figure 41. Impact of shortened cycle times on real NPVs of

100 mmbbl projects (US$15 real/barrel).” “Total E and A costs remain US$37.5 million. *Development shortened by one year.

8 nilllm Total RNPV .lOS

,

Dev. co8t per barrel

-40 64

66

86

$7

Figure 40. Impact of shortened cycle times on real NPVs of

100 mmbls project (US$l8 real/barrel).a aTotal E and A costs remain US$37.5 million. *Development shortenedby one year.

Figure 42. Impact of shortened cycle times on real NPVs of 50 mmbbl projects (US$15 real/barreQa

“Total E and A costs remain US$37.5 million. *Developmentshortened by one year.

expenditure on exploration to first production. The length of the exploration and appraisal (E and A) period is subject to very considerable variation in practice, often depending on the extent of the need for appraisal. This is the first period considered. The second period is between the end of appraisal and first development expenditure. The third period considered is the length of the development period before first oil is obtained. The variations in the phasing of the activities considered are shown in Figure 39. The base case considered has fast cycle time. The E and A period is only three years. There is a three year development period, but first production is attained early in the third year. The variations from this base examined here are as follows:

The effects of the variation in the cycle times were examined on a suite of hypothetical fields. In the results shown here emphasis is placed on fields of 100 million and 50 million barrels. The exercise was undertaken for a wide range of cost conditions and these are displayed here. Realistic development cost conditions in the UK North Sea are currently USW-7 per barrel. The exercise was conducted for oil prices of US$15, US$18 and US$23 in constant real terms. The returns to investors shown are after tax. They assume that corporation tax is being paid at the time of the investments. Returns are measured in terms of NPVs at 15% in MOD terms (10% in real terms). Results

(i) (ii) (iii) (iv)

E and A period extended to five years; the development period shortened by one year; development delayed by one year; E and A extended to five years plus development delayed by one year.

In all cases the E and A costs plus the development costs are kept at the same levels in real terms. The only variations are in the phasing of the expenditures.

100 million barrels field. A summary of the absolute returns to investors under the five cases examined is given in Figure 40 for the US$l8 price scenario and in Figure 41 for the US$15 price scenario. It is seen from Figure 40 that the projects have positive NPVs under all cost and cycle conditions. The size of the NPVs varies enormously according to development cost conditions. (Operating costs are a fixed proportion of

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Cost savings and activity inthe UKCS: A G Kemp and B MacDonald

development costs and so they increase as the latter increases.) With development costs of US$7 per barrel the size of the positive NPVs is relatively small. In a situation of capital rationing there could, be doubts regarding the viability of the projects. Thus variations due to changes in cycle times could be very important in decision making. Under the base case the NPV is US$39 million. A reduction in the development period by one year increases it to US$55 million. An increase in the E and A period to five years reduces the NPV to US$30 million. A delay of one year in the commencement of development results in an NPV of US$27 million while a five-year E and A period plus a one year delay before development results in an NPV of US$24 million. Figure 40 also illustrates how sensitive are the returns to the projects to variations in exploitation costs. In Figure 41 the results of the analysis are shown under the US$15 price. All projects are non-viable with development costs of US$7 per barrel. Under the US$6 development cost case the NPVs are all modestly positive. Again, under a capital rationing situation doubts must arise regarding their acceptability. Under the base case the NPV is US$18 million. A reduction of one year in the development period increases the NPV to US$33 million. A five-year E and A period results in an NPV to US$14 million. A one-year delay before development leads to an NPV of US$lO million. If this is combined with a five-year E and A period the results is an NPV of US$12 million. 50 million barrelfreld. The exercise was repeated for the 50 million barrel field. In Figure 42 the NPVs under the US$15 price scenario are shown for all the combinations of cycle times. It is seen that the NPVs are generally positive except where development costs are US$7 per barrel. The size of the NPVs are often very small, however, and thus improvements in cycle times could play a significant role in determining the acceptability of projects. Marginally acceptable projects are those under the US$6 development cost case. Under the base case the NPV is US$16 million. A one-year reduction in the development period leads to an NPV of US$27 million. An extension of the E and A period to five years entails an NPV of US$12 million. A one-year delay before development activity leads to an NPV of US$13 million and this combined with a five-year E and A period results in an NPV of US$lO million.

Conclusions In this paper the effects of two separate aspects of cost saving in the UKCS have been examined. The first part

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of the study has analysed the consequences of cost savings for activity levels. It was found that under US$15 and US$17 per barrel real oil price scenarios cost savings of 20% could result in a significant number of extra new field developments being triggered. Between 1993 and 2018 under the US$15 real price scenario no less than 27 extra new field developments in CNS and NNS could be made viable as a consequence of overall cost savings of 20%. This means capital costs, development drilling costs and operating costs. Under the US$17 real oil price scenario 21 extra field developments could be triggered by such cost savings. If development costs alone were cut by 20% the number of extra field developments could be 16 under the US$15 price scenario and 12 under the US$17 price scenario. Savings in operating costs of 20% would be capable of triggering off the development of 11 extra fields under both price scenarios. Under a scenario of moderate real price increases the number of new field developments triggered by cost savings of 20% is very considerably less. It follows from the above that there are significant induced increases in development and operating expenditures emanating from cost savings. It is noteworthy that under the low oil price scenarios the extra induced expenditure can be as high as the value of the cost savings. Under the US$15 price scenario the total new induced expenditure, while often less than the value of cost savings, does sometimes exceed these savings. It is likely that when investment and operating costs are reduced by 20% the value of the extra development expenditure will often exceed the value of the savings in development costs. The extra production emanating from (i) further field developments and (ii) extensions to field life could be very substantial. Under the US$15 price scenario the extra production from both sources could be in the 0.4-0.5 million b/d oil equivalent for a number of years starting at the beginning of the next century. The second part of the study examined the consequences of variations in cycle times (with costs held constant in real terms) for the returns to investors. This exercise was conducted on a suite of model fields. Attempts have been made, and are continuing, to reduce the cycle times from exploration to first production. In the study the effects of variations in (i) the E and A period, (ii) the time between E and A and first development expenditure, (iii) total development period, and (iv) period between first development and production were examined. Generally, moderate variations in all the above elements of the cycle time had significant effects on NPVs to investors. The variation in NPVs was greater the higher the oil price scenario employed reflecting the prime importance in the results of the value

Cost savings and activity

of the revenues in present value terms. A moderate shortening of the overall development period was found to have a substantial effect on NPVs. In general the improvement in NPVs from improved cycle times could be of major importance when projects are of only marginal profitability. All measures which can improve cycle times are of great importance in today’s operating environment of major capital rationing. This study has concentrated on the effects of achieved cost savings on activity levels. It should be noted that other benefits will accrue to the industry and the nation. Achieved cost savings of 20% or so will substantially improve industry cash flow. This will reduce the capital rationing constraint on new developments. It will also enable the industry to engage in more exploration work. This activity is generally financed from net cash flows. The government will also gain from increased tax revenues resulting from the increased profitability of projects which will in any case go ahead plus the tax share of the fruits of extra, induced projects. Cost

in the UKCS: A G Kemp and B MacDonald

savings in the UKCS constitute considerable magnitude.

a positive

sum game of

References (Cost Reduction Initiative for the New Era) Report (1994) Institute of Petroleum for United Kingdom Offshore Operators Association. Kemp, A G and MacDonald, B (1991) ‘Economic aspects of cost savings in the UKCS’ Paper No OTC 7434, Proceedings of the Offshore Technology Conference, Houston, TX, Society of Petroleum Engineers, May, 125-140. Kemp, A G and MacDonald, B (1993) Economic Aspects of Cost Savings in the UKCS, North Sea Study Occasional Paper No 45, Department of Economics, University of Aberdeen. Noroil and &roil (various issues). CRINE

Report

of the

Working

Group

on

CJKCS Competitiveness

(1993)

Presented to the President of the Board of Trade and to the Minister for Energy, DTI, February. The Working Group on UKCS Competitiveness (1993) Progress Report to the Ministers for Energy, DTI. Wood, Mackenzie, Stockbrokers, Edinburgh (various issues) North Sea Report.

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