Benchmarking Report QUE$TOR · QUE$TOR 2016 Q1 Benchmarking IHS May 2016 Page 1 Introduction We are...

Benchmarking Report

QUE$TOR

2016 Q1 Release

May 2016 QUE$TOR is a registered trademark of IHS.

Contents

Introduction 1

Technical Benchmarking 3

Onshore 4

Offshore 5

Cost Benchmarking 7

Onshore 9

Offshore 10

Release Benchmarking 11

Software Support Contacts 13

Sales and Commercial Contacts 14

Appendix 15

Onshore components 15

Offshore components 18

QUE$TOR 2016 Q1 Benchmarking

IHS May 2016 Page 1

Introduction We are pleased to announce the release of IHS QUE$TOR 2016 Q1. As with previous updates, this version contains both product enhancements and cost updates. This benchmarking report has been prepared to provide an understanding of the effect of the changes between QUE$TOR 2016 Q1 and the previous version, QUE$TOR 2015 Q3. This report provides an overview of the results that are likely to be seen with capital costs estimations when a QUE$TOR project is updated. The method of analysis is to run projects using three versions of QUE$TOR. Projects are run in the previous version (QUE$TOR 2015 Q3), the updated version (QUE$TOR 2016 Q1), and an intermediate version that only incorporates the technical changes and feature additions made to the latest release of the software. The difference between the previous and the updated version quantifies the combined cost and technical changes. The change in results from the previous to the intermediate version describes technical changes and the difference between the results of the intermediate build and those of the updated version reveals the change in costs that stem from market movements. To make the analysis as meaningful and realistic as possible a large sample of projects (approximately 450) are used which are based on real assets and potential developments around the world. The projects have been selected to give a diverse international portfolio (Figure 1).

Figure 1: Breakdown of benchmarking portfolio by region and project type

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Page 2 May 2016 IHS

The portfolio of projects to be analyzed is roughly split into 250 offshore and 200 onshore developments. Every region contains both project types, although the overall portfolio is not intended to include all possible projects but to be a representative sample. As a result some projects or regions may be more or less represented than others. The objective of this analysis is to check whether the expectations of capital cost estimations are consistent with the changes as described in the Release Notes. The process highlights how technical changes to the application have been included and their potential to mask other cost changes that occur in the application. The analysis also provides a comparison of cost change effects by region, type and cost category. The analysis in this report is meant to supplement the market changes discussions found in the Release Notes.


IHS May 2016 Page 3

Technical Benchmarking The technical benchmarking distinguishes between the effects of new technical definitions on project costs in QUE$TOR and the effects of cost database changes. This provides an understanding for the reasons behind the changes and helps validate QUE$TOR as new features are developed. Technical benchmarking is a process that allows the comparison of the costs of developments run in different builds of QUE$TOR that use the same cost databases, thus isolating the effects of the new technical specifications. The technical changes to QUE$TOR (detailed in the Release Notes that accompany the update) are summarized below:

Expansion of offshore pipeline installation form and inclusion of supply vessel durations

New high grade steel options for offshore pipelines, along with an update of the wall thickness calculation

Improvements to tanker turret sizing

Dry oil tanks have been added to oil export in topsides

Ability to select tubing material in offshore drilling

Update of turbine powers and addition of two high output units

Ability to add a user comment to a locked value

Charting of the pressure profile in the onshore pipeline schematic

New defaults for offshore and onshore Russian procurement strategies

New metrics for topsides and subsea components These changes have had an impact on project costs both onshore and offshore, as can be seen in Figure 2. The effects on project costs are analyzed more closely in the following subsections.

Figure 2: Distribution of cost changes due to new technical definitions in QUE$TOR 2016 Q1

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Onshore

It is clear from Figure 2 that the new technical definitions in QUE$TOR have had a limited impact on onshore project costs. Over 95% of onshore projects changed by less than 1%, with the remaining five percent forming a small left tail that ends at -6%. Analyzing the project cost changes by component, we find that production facility costs are driving these differences. Figure 3 shows the distribution of production facility cost changes within the portfolio; note how closely it resembles the onshore plot in Figure 2.

Figure 3: Changes in production facility costs due to new technical definitions in QUE$TOR 2016 Q1

The review and update of turbine powers and specifications is the change responsible for the differences in production facility costs. While the vast majority of projects did not see any change in the costs of production facilities, around 16% did, of which only one project saw costs increase. The updated turbine specs sometimes lead to the selection of smaller units, which not only reduces the equipment costs, but also the associated weights and materials required. At times the smaller turbine selection has a knock-on effect on infrastructure costs, reducing the number of men required leading to smaller construction and operations camps.

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IHS May 2016 Page 5

Offshore

Referring back to Figure 2 once again, offshore projects have experienced more changes in costs due to the new technical definitions than onshore projects. With over 80% of the offshore projects in the portfolio changing by less than 1%, it cannot be said that the changes were severe, but some components did have some substantial differences. The offshore projects that changed the most during the technical benchmarking were the ones with high pressure or high temperature (HPHT) drilling conditions. In fact, all projects that changed by more than 5% belonged to this set. Figure 4 shows the breakdown of the cost changes by cost centre. On average, the cost of drilling in HPHT conditions has increased by around 9%, driven in large part by new tubing material options (Alloy 625, Alloy 825, and Titanium Alloy). Increased design and installation times also played a part, as did the adjusted flowline thickness calculations.

Figure 4: Cost changes in offshore drilling component in HPHT conditions due to technical changes in QUE$TOR 2016 Q1

Another contributor to the increase in project costs offshore has been the reworking of turret sizing algorithms and the inclusion of electric and utilities swivels in the estimation of tanker costs. The new model was prompted by user feedback and should represent a significant improvement in tanker cost estimation. The portfolio only contains 20 projects with FPSOs and of those 13 have turrets. Figure 5 shows the changes in tanker costs for these projects. Including HPHT projects, these 13 projects account for almost all offshore project cost increases exceeding 3%.

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Figure 5: Change in turret-moored tanker costs due to new sizing model Offshore pipelines were the final component to experience a notable change in costs due to the new technical definitions. The addition of higher-grade steel material options led to a revision of wall thickness calculations based on the external pressure criterion which had an impact on most pipelines and increased costs by an average of 6%. Figure 6 shows the distribution of these changes.

Figure 6: Change in offshore pipeline costs due to new technical definitions

In conclusion, only users with HPHT projects or ones with turret-moored FPSOs should expect significant changes stemming from the new technical definitions in the updated version of QUE$TOR.

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IHS May 2016 Page 7

Cost Benchmarking Following the technical benchmarking, the portfolio projects were run through the release version of QUE$TOR 2016 Q1, and the results analyzed. The analysis method to get the cost changes compares the new build version with the results generated by the intermediate build in order to focus solely on cost changes stemming from new market conditions. The distribution of project cost changes for all projects in the assembled portfolio can be seen in Figure 7.

Figure 7: Distribution of cost changes due to market movements in QUE$TOR 2016 Q1

Over 95% of onshore projects decreased between 2-6%, with an average of -4%. Offshore projects saw steeper declines in costs and a much wider range of variation; they averaged a fall of around 8%. Figure 8 shows the regional breakdown of onshore and offshore project cost changes, revealing that while costs have decreased somewhat uniformly onshore, offshore project costs have fallen further in some regions than in others.

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Figure 8: Regional breakdown of cost changes Figure 9 shows the change in project costs by cost category. In this graph, prefabrication and fabrication were averaged together. Installation is both the most variable cost category and the most severely impacted by the enduring lack of activity, explaining the differences between onshore and offshore costs observed in Figure 7. A thorough investigation into these changes is presented in the following subsections.

Figure 9: Breakdown of project cost changes by category

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IHS May 2016 Page 9

Onshore

Onshore cost changes have been driven by falling material prices and increased competition from suppliers over the limited amount of activity in the upstream market. Onshore markets tend to be local or regional, making exchange rates an important factor in determining cost estimates. This has caused less economically stable regions to experience sharper declines than others. Figure 10 shows the average change in onshore component costs for each region, as well as the overall averages for the portfolio. The average component cost changes are very similar, declining between 3-6%. Components with a larger portion of material and labour costs have fallen further than those with higher equipment and engineering costs.

Figure 10: Onshore cost changes by component Also of note are the regional rankings. Latin America and Africa are consistently the regions to exhibit the most change, largely due to the negative economic climates in the countries that comprise them. European onshore projects are largely from the Commonwealth of Independent States (C.I.S.), another region that has experienced exchange rate volatility. Local expenditures in these regions (primarily labour costs) drop sharply when estimated in USD terms. Infrastructure costs illustrate the point as a large proportion of the component cost is labour related. By contrast, costs in the Middle East, Far East, and Australasia have been more stable. Detailed breakdowns of the component cost changes are available in the Appendix. Discussions of each market can be found in the Release Notes.

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Page 10 May 2016 IHS

Offshore

Development costs have fallen further offshore than they have onshore, as shown in Figure 7. Analyzing the changes by cost category (Figure 9) shows that the change in installation costs are the dominant factor, as this has declined almost twice as much as other categories. While installation costs are a part of every offshore component, they make up a relatively small portion of the total costs of topsides and the various floaters in QUE$TOR, limiting cost movements in those components. Figure 11 shows the average cost change in each offshore component. Offshore drilling, pipelines, and jackets all require significant installation expenditure, making them the most affected components. The decrease in drilling came mainly from lower rig and vessel dayrates. The chart shows conspicuous variability in rig dayrates by region during this update, leading the drilling component to have the widest range of cost changes. This variability stems from the difference in upstream activity between regions, with the most active ones being more stable.

Figure 11: Offshore cost changes by component Jackets are dominated by installation and material costs, both of which have decreased strongly this update. Offshore pipelines were similarly affected as linepipe costs have fallen sharply over the past six months, as have lay vessel dayrates in most regions. Other components experienced less severe changes, still mainly driven by installation and material costs. As with onshore costs, detailed breakdowns of the cost changes by component in each project are available in the Appendix. Discussions of the various upstream markets can be found in the Release Notes.

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IHS May 2016 Page 11

Release Benchmarking In this section technical and cost changes are brought together to give an idea of how users will likely experience cost changes when updating from QUE$TOR 2015 Q3 to QUE$TOR 2016 Q1. The total capital cost change for onshore components is shown in Figure 12.

Figure 12: Overall cost changes of onshore components in QUE$TOR 2016 Q1 As noted in the onshore technical benchmarking section, only production facilities saw any cost changes due to the feature updates in QUE$TOR. Occasionally these changes influenced infrastructure costs, which can be seen in Figure 12. More offshore components experienced cost changes due to the new technical definitions, as shown in Figure 13.

Figure 13: Overall cost changes of offshore components in QUE$TOR 2016 Q1

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Though all offshore components experienced some change in costs due to technical changes in QUE$TOR, the three most prominent ones were the ones discussed in the offshore technical benchmarking section. New pipeline wall thickness calculations, material types, and changes to installation times all played a part in increasing costs, almost nullifying the market changes experienced in this component. The increase in floaters all stems from the new turret sizing model; spars, TLPs, and offshore loading units did not experience any significant changes. Finally, the cost increase in offshore drilling seems minor in this graph, but that is only because of the limited number of HPHT developments in the offshore portfolio. Of the 250 projects only 15 can be classified as HPHT, and including the changes experienced by those with the rest of the portfolio brings down the average. A histogram of cost changes of the portfolio projects is shown in Figure 14. The distribution looks very similar to the one depicting only the cost changes stemming from market movements (Figure 7), only shifted slightly to the right. This is the figure that represents most closely what changes users can expect in their project costs.

Figure 14: Distribution of cost changes when updating from QUE$TOR 2015 Q3 to QUE$TOR 2016 Q1

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Software Support Contacts If you have any problems or questions relating to any of the QUE$TOR suite applications, please contact the Software and Engineering Support Desk. Support e-mail address: [email protected] (Note: ‘s’ rather than ‘$’) Licensing support e-mail: [email protected] Support telephone and fax: North & Central America Tel: (+1) 713 840 8282

Fax: (+1) 713 995 8593

South America Tel: (+55) 21 3299 0440

Europe, Africa, Middle East Tel: (+44) 20 3159 3300

Fax: (+44) 20 3159 3299

S.E. Asia & Australia Tel: (+91) 124 454 2699

China Tel: (+86) 10 5633 4567

Fax: (+86) 10 5633 4500

The IHS software support team key contacts are: North, Central & South America Thais Hamilko, Jonathan Stephens, Abhishek Verma, Zayd Wahab e-mail: [email protected], [email protected],

[email protected], [email protected] Europe, Africa, Middle East Rita Antonelli, Matthew Butcher, John Helliwell, Greville Williams e-mail: [email protected], [email protected],

[email protected], [email protected] S.E. Asia & Australia Sanjay Sinha e-mail: [email protected] China Yaxing Wang e-mail: [email protected]



Sales and Commercial Contacts If you have any questions or would like any further information regarding IHS software or services please contact your Account Manager or your local IHS sales office. Beijing Tel: (+86) 10 5633 4567

Fax: (+86) 10 5633 4500

Geneva Tel: (+41) 22 721 1717

Fax: (+41) 22 721 1919

Houston Tel: (+1) 713 840 8282

Fax: (+1) 713 559 9101

London Tel: (+44) 20 3159 3300

Fax: (+44) 20 3159 3299

Moscow Tel: (+7) 495 937 77 24

Fax: (+7) 495 937 77 25

Rio de Janeiro Tel: (+55) 21 3299 0440

Singapore Tel: (+65) 6439 6000

Fax: (+65) 6439 6001

Tetbury Tel: (+44) 1666 501 200

Fax: (+44) 1666 504 704

Tokyo Tel: (+81) 3 5791 9530

Fax: (+81) 3 5791 9662



Appendix

Onshore components

Figure 15: Onshore drilling

Expenditures on materials and labour differentiated regional drilling costs.

Figure 16: Wellpad groups

Africa, Europe (in this context, the C.I.S.), and Latin America all experienced large falls in their labour costs, driving the changes seen in this component. Middle Eastern costs fell due to lower material costs in the region.

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Figure 17: Production facilities

The changes on the extreme left and right come from projects that experienced a change in turbine selection due to the revision mentioned in the technical benchmarking section.

Figure 18: Terminals

Regions with more pronounced labour cost declines showed the greatest drop in component costs. This component had the narrowest range of cost changes.

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Figure 19: Onshore pipelines

Linepipe costs have fallen globally. The largest decrease was seen in regions where labour rates and exchange rate changes contributed to the fall.

Figure 20: Infrastructure

This is the component in which labour costs play the biggest part. It is clear that Latin American costs have decreased the most because of this, followed by European and African costs.

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Offshore components

Figure 21: Offshore drilling

Drilling costs are dominated by installation expenditures. Australasian and European rigs and vessels decreased the most, making those regions the ones to experience the biggest declines. Middle Eastern rigs were the least affected as activity has not fallen in that region as far as in others.

Figure 22: Subsea

Cost changes in this component were broadly similar across regions. The wide range can be attributed to the diversity in subsea layouts.

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Figure 23: Topsides

Cost changes in this component were driven by installation costs as other cost categories did not change much by comparison. Consequently the range of cost changes is relatively narrow for an offshore component.

Figure 24: Jackets

Only European cost changes spanned the entire range of this component due to differences in regional currencies led to diverse results. Other regions changed in narrower bands depending on the sourcing of labour and material for each project. Installation also played a large role in determining regional costs.

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Figure 25: Offshore pipelines

This component was the one most affected by technical revisions this update; very few projects were left unaltered by the new changes. The four rightmost columns are due to changes in line sizes necessitating the use of higher specification lay vessels, considerably increasing installation costs.

Figure 26: Floaters

Turret moored tankers represent the majority of the rightmost columns, as the new sizing model increased costs for those projects. Other floaters all decreased in costs.

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