Case Study Document

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IMPORTANT NOTICE This Case Study has been prepared by BG Group solely for its own internal purposes and is confidential. You should not publish or otherwise disclose this Case Study or any information contained herein without the prior written consent of BG Group. Neither BG nor any of its subsidiary companies or their respective officers, employees or agents accept any responsibility or liability whatsoever (including negligence) with respect to the contents of this Case Study. No warranties, representations or conditions of any kind either express or implied are given or made in respect of the contents of this Case Study. Accordingly, if any reader chooses to rely on any aspect of the study they do so entirely at their own risk.


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BG Group Project Academy

Leading Projects 2010

Case Study: Ladder LNG Development


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Case Study Ladder LNG

Table of Contents

Project Overview 5

Phase 1 Directing Programmes and Delivering Value 6 Overview 6 Supporting Materials 7 Questions 7 Phase 1 Epilogue 8

Phase 2 Risk, Complexity and Control 9 Overview 9 Supporting Materials 10 Questions 10 Phase 2 Epilogue 11

Phase 3 Courageous Stakeholder Engagement 12 Overview 12 Supporting Materials 13 Questions 13 Phase 3 Epilogue 15

Reflection: Re-Doing Ladder 16 Overview 16 Questions 16


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Project Overview

When BG Group entered the Ladder LNG project, the successes and challenges that it would encounter over the next few years were unforeseen. Ladder LNG provides BG Group project managers with a powerful example of how complex projects can change over time, and how issues can be resolved with a shared commitment to get the work done, focused stakeholder partnership and influencing, and an innovative approach to solving project issues.

Ladder LNG is a joint venture established to construct and operate a liquid natural gas (LNG) import terminal in Bridgehead, in the country of Westland. BG Groups board sanctioned investment in the project in September 2004 at a cost of 144 million, with projected completion in November 2007.

The project was structured as a joint venture between three shareholders: BG Group, owning a 50% interest in the development, Asiagas owning 30% and Gogas owning 20%. BG Group and Asiagas each contracted for 50% of the capacity in the terminal. The governance of Ladder is provided by a board of five directors two from BG Group and Asiagas and one from Gogas with a BG Group employee as General Manager. The strategic intent of the project was to diversify BG Groups LNG portfolio and secure import capacity for the expected growth in the Westlandic gas market.

The contractor selected for both the front-end engineering and design (FEED) and engineering, procurement and construction (EPC) was a joint venture between Fisher and Teknik (FTJV), led by Fisher in a 70:30 split of responsibility. Fisher was responsible for the overall management of the project with monthly reporting obligations to Ladder LNG. This was a fixed price contract, so the anticipated risk was contained.

The project was completed at a total cost of 224 million in June 2009. Despite the issues encountered, the final construction costs achieved were comparable to the costs of other LNG projects led by competitors1. Moreover, the project had an excellent health and safety record, partially attributable to the Cracked IT programme, in which donations were made to local charities for health and safety performance, thereby creating a culture in which safety was reinforced on the ground.

Over the intervening years, the project encountered a number of difficulties and challenges. These will form the subject of this case study, with opportunities for reflection at each of three phases. The intent is to have participants consider how they would have reacted in each of these phases, as well as to reflect on the overall project and what could have been done differently, or should be retained, for use on

future BG Group projects.

1 Based on the EPC Capital Expenditures on LNG Regasification terminals. Sources include: BG Group, Poten and Partners -, Global Insight & Oil and Gas Journal.


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Phase 1 Directing Programmes and Delivering Value

Overview

When BG Group decided to take part in the Ladder LNG project in 2003, it was already well into the Define phase. Gasplan was the original proponent of the project, as they owned the existing site, had obtained permits, and had undertaken a conceptual technical study by Smith Engineering. At this preliminary stage, BG Group and another partner, Asiagas, agreed an MoU granting options to invest in the opportunity in return for part funding of the development proposal. The option was conditional on BG Group committing to full investment by September 2004. The objective of gas sales into the Westlandic market in the winter of 2007 made this a highly attractive investment opportunity, so there was a great sense of urgency to commit.

Ladder invited competitive EPC proposals from a number of contractors, with scope defined by the conceptual technical work supplemented by further limited work by Ladder after BG Group joined. The contractor selected for front-end engineering and design (FEED) when BG Group entered the project was a joint venture between two firms: Teknik, a major European civil engineering company, took 30% of the JV, while Fisher, owned by the Caledonian company Constructa, had the majority share at 70%. This seemed like a good partnership, as Teknik had extensive experience with building jetties, while Fisher had knowledge of building holding tanks and was backed up by Constructas broader knowledge of project delivery.

At this stage, BG Group carried out functional and readiness reviews, and plans were made for execution. The need to commit by September 2004 or lose the opportunity meant that there was not time to perform FEED. The FTJV consortium was the most compliant and attractive, so their tendered proposal was used as the basis for negotiation of a fixed-price FEED/EPC contract. This then defined the execution cost estimate and schedule. BG Groups board sanctioned the 144 million project in 2004.

However, issues quickly waylaid the opportunity. During the contract negotiations, Constructa sold Fisher to an Elboni parent company, the Al Bab Group. This thereby limited the experience of the lead contractor, as Constructas resources were no longer available to the project, and Al Bab was not experienced in this region or area of work. Furthermore, this move complicated the parent company guarantees, as Fisher was now owned by an organisation outside of the EU.

An additional complication was added when Gasplan spun off its investment in LNG into a private equity-backed LNG terminal development company, Gogas. This change resulted in a shift in the interests of the partners; Gogas was a private equity-owned firm, Asiagas was a south asian state-funded entity, while BG Group remained a FTSE 100 company dedicated to maximising shareholder profits. Moreover, Gogas was not involved in contracting for the output of the plant; they had a 20% stake in the development, but no operating interest, while Asiagas had a 30% stake in development and were contracted for 50% of its capacity.

Given BG Groups late entry into the opportunity, its influence over the direction of the program was limited. The contract was awarded as an EPC contract between Ladder LNG as the client and the Fisher-Teknik joint venture (FTJV) as the contractor. BG Groups role in the project was thus as joint client, and BG Group provided the bulk of the staff in the Ladder Project Management Team.


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As the project progressed, further issues continued to arise. One major issue that arose focused on the internal rate of return (IRR) of the project. The IRR is used by BG Group to evaluate the profitability of a project by comparing project costs with projected revenues over a given time period. The original IRR of the Ladder LNG project was estimated at a relatively low IRR for the industry but above the BG Group hurdle. However, it began to drop after several changes to the initial budget were discovered. The initial assumption of the plant being a baseload LNG facility fell through, causing an increase in projected operating expenses from 5.1 to 7.4 million in January 2005 and reducing the IRR further. Projected electricity consumption increased from 7MW to 13.4 MW, and while the cost of electricity had been estimated at 28/MW, actual costs were closer to 48/MW. This had a further negative impact on IRR. These changes, along with an increase in steel prices that had not been hedged, resulted in a significant drop in project profitability.

Supporting Materials

Abridged version of Project Investment Paper of September 2004

Questions

You have been assigned by BG Group as the new Ladder Project Manager for the LNG project.

1. What questions would you ask upon your arrival? 2. How well defined was the project at the outset? What technical,

commercial and project management due diligence and planning should or could have been undertaken before the start of the project?

3. Make a list of the key issues on the project. Which ones can you affect in your role? Which ones do you need to watch out for in the longer term? Which ones do you need others to become involved with, and how will you obtain their support?

4. What impact do you think the different interests of the project stakeholders will have on the project outcomes?

5. What are the key actions that you would suggest at this point of the project? Consider legal, contractual, cultural and risk factors of the project.


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Phase 1 Epilogue

In June 2007, the Ladder LNG team realised that there was an opportunity presented by the refurbishment of the adjacent power station. They negotiated an arrangement whereby the boil-off gas from the Ladder plant could be used by the power station with minor modifications to the plant design. In exchange, the power station would provide Ladder with the electricity it required. This change negated the reduction of IRR caused by the increased electricity requirement and cost.

Furthermore, this change in design enabled the plant to store LNG and operate as a merchant plant rather than a baseload LNG plant, allowing deliveries of LNG only once every 500 days, rather than every 50 days. This change would also allow BG Group to exploit price differentials by attracting spot cargoes and redirection/arbitrage opportunities with other BG Group terminals, enabling the direction of shipments to the most lucrative port, rather than having to supply the Ladder plant on a frequent basis. This change also improved the economics of the project by increasing the IRR.

To fund this change, the project had to dip into the contingency budget of 20 million to cover some of the cost increases. This decision reduced their ability to respond to later project challenges. Additionally, the team was unable to recover the costs of the increased steel price that had not been hedged for by the contractor.

At this point, the nature of the contract meant the project was still operating with limited visibility by Ladder and BG Group into the activities of FTJV. As will be seen in the next phase, the lack of action in this area caused serious implications for the subsequent project delivery.


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Phase 2 Risk, Complexity and Control

Overview

Following the business model change and co-generation agreement with the Bridgehead Energy power station, the project continued according to the revised plan. However, the relationship with FTJV continued to deteriorate. In fact, the FTJV appeared set on limiting Ladders involvement; when concerns were raised over the confrontational relationship between the Fisher Project Manager and the Ladder Project Manager, the Ladder directors were told that it was not their concern. Moreover, Fisher would only report progress on a monthly basis, and only at a high level, with the schedule provided in a PDF format that could not be analysed by the Ladder team. Ladder was therefore unable to track the storm that was brewing within Fisher. However, the fixed price contract seemed to be secure. BG Group was protected from the risk of delays or increased costs because of the contract or was it?

In May 2006, the situation reached crisis point. Fisher requested an increase of 8 million to cover additional costs, which was approved by Ladders board. Shortly after the additional cash was received however, they requested a further 20 million, then more, until the total variation reached over 60 million. Ladder was unsure of what to do with the evolution of the business model, and the additional costs, Ladders board agreed to 20 million in May 2007 plus two months to settle all claims, with 14.5 million conditional on achieving milestones. Unfortunately, this proved to be too little too late and did not solve the problem. By August 2007, Fisher asked for more money, claiming that they were running out of cash.

To make matters worse, the Fisher Project Manager left the project at this point, with little evidence of progress towards achieving the goals set out the previous May. The sub-contractors claimed they were not being paid and the project seemed to be heading for failure. With limited visibility into the project financials, Ladder and the shareholders were unable to get a good understanding of the projects position.

At this point, the Ladder LNG shareholders ordered a review of the project, and identified several key issues that had delayed the progress of the construction:

Although Fisher had relevant experience, they lacked the overall project management expertise necessary to complete the construction

Poor management of sub-contractors and the construction programme had led to extremely low productivity on site, with progress in some areas at 14% of industry standards (1 inch of welding was being achieved per day where the industry expectation is 7 inches)

Inflationary cost pressures in the construction industry and poor management of funds impacted the project budget and resulted in a cash flow crisis. Later, materials were found that had been ordered and stored without record, and subsequently re-ordered

Labour issues resulting from the location of the work in a remote area of Westland and ineffective construction management and supervision resulted in high staff turnover and difficult industrial relations


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With the original project deadline three months away and progress moving painfully slowly, Ladder and the shareholders knew that changes were needed. They decided to negotiate a completion agreement with the other partners and FTJV.

Supporting materials

Abridged version of Project Reinvestment Approval paper of July 2008.

Questions

You have been assigned by BG Group as the Project Manager on Ladder LNG, and your brief is to get the project back on track.

1. How would you structure the completion agreement? What would you include?

2. How would you mitigate the risks on the register at this point in the project? What are the key risks that are missing from the register?

3. What do you think could be done to improve the productivity of the sub-contractors? What do you think are the main causes of the poor productivity and poor industrial relations?

4. What risks does a modification to a fixed price EPC contract introduce into a project? What risks does it eliminate?


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Phase 2 Epilogue

Ladder made several changes at this point in the project. Firstly, Teknik replaced Fisher in the management of the project, and agreed to provide detailed weekly reports. These weekly reports significantly improved Ladders ability to monitor the project and to ensure that it would be completed to the revised timeline.

Secondly, a completion agreement was structured between the partners to address the shortfall and the resources needed to complete the project. Given the revised scope and cost of the project, it was re-sanctioned by the BG Group board in July 2008 to authorise additional project management and contractor costs. The revised budget for the re-sanctioned project was as follows:

These costs originated in the following areas:

The additional contractor costs (45m plus 18m capital at risk) related to BG Groups 50% share plus Gogas 20% share of the cost of the Completion Agreement (rescue) plan, which was approved in March 2008

Additional Ladder project management costs arose as a result of a significant under-estimate of these costs at sanction in 2004, combined with additional costs associated with the delay in project completion

BG Group project costs were not included at all in the original sanction.

The schedule delays increased the risk that the EPC contractor might once again run out of funds

The capital at risk resulted from the refusal of Gogas to contribute its share of the cost overrun negotiated in the Completion Agreement, on the grounds that it should be covered as part of the operating expenses rather than the capital cost of the project. BG Group and Asiagas agreed to share the cost of Gogass portion of the over-share in a 70:30 ratio, pending expert determination that they were confident would be won. This dispute was later resolved in BG Groups favour.

The major risk, which was not included on the risk register, came from the false security provided by the fixed price contract with FTJV. As can be seen, the fixed price contract continued to tie Ladders hands in terms of demanding accountability from FTJV, who supposedly held the risk in the contract, and resulted in a drastic increase in the project cost.

BG Group share million

Original sanction 144

Additional contractor costs (resulting from Completion Agreement)

45

Capital at risk as a result of the partner dispute 18

Additional Ladder project management costs 9

BG GROUP project costs 5

Potential additional contractor fees 3

Total 224


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Phase 3 Courageous Stakeholder Engagement

Overview

One of the major complexities of Ladder LNG was the number of stakeholders, both internal and external, that were involved in the project. From BG Groups point of view, it was particularly challenging to manage the complex internal relationships that characterise the matrix structure of the company. These included not only managing the relationship between BG Group staff representing Ladders interests and BG Group staff focused on BG Groups interests, but also the interaction between the Project Team, the Asset to which it reports, and the Region that manages the asset, as well as working in parallel with BG Advance. BG Groups structure was both a help and a hindrance to the project; while a number of critical skills were brought to bear, it added further issues to a volatile stakeholder environment.

As a result of the Completion Agreement, Teknik assumed the management of the project with a new scope, schedule and cost estimates. At first, it seemed like this move could get the project back on track, but unfortunately, this did not rectify the situation and the project continued to experience poor co-ordination of activities and management of materials.

To deal with the recurring issues, BG Group and Asiagas deployed full time specialists to work with and monitor the FTJV. The BG Group/Asiagas focus was on identifying and resolving shortcomings in the organisation, management practices and site coordination. Furthermore, operations were integrated into the project to ensure that the work was completed as required, with extra emphasis on inspection.

Eventually, it became clear that Teknik was not able to lead the project. Although their work was technically competent, they too lacked the experience to manage the complex relationships between the partners, the joint venture with Fisher, and the sub-contractors. After almost four years, Ladder took the difficult decision to terminate the contract. The potential complexities in managing this termination were part of the reason that Ladder had continued to fund the FTJV contract despite repeated issues throughout the project timeline. However, the time had come to terminate this agreement.

At the same time, Ladder brought in a new project management firm to complete the contract. ECON, a company that focuses on high-value consultancy, engineering and project management services for the oil and gas industry, was contracted to assess and define the required activities to complete the project. Additionally, Ladder took over the 105 sub-contractor agreements directly, to ensure accountability for their performance.

At this time Ladder also began to actively direct the project. A commissioning manager was appointed and established an on-site presence within the ECON project management office to supervise day-to-day completion work. ECON reported progress on a weekly basis and allowed detailed analysis of their plans by Ladder staff.

The project achieved a step change improvement under the new organisation, and achieved first gas in June 2009 at a total cost of 224 million. Ladder LNG is now operating as a merchant plant, providing BG Group with arbitrage opportunities around the world. Following completion of the project, BG Group decided to do a detailed lessons learned investigation to ensure that the issues that had transpired on the project would not happen again, and to retain the successes of the project for further projects.



Authority Request for EPC Contract Termination Deed

Briefing Note on Completion of LNG Import Terminal (22 Nov 08)

Questions

You are the Manager on this project in charge of the lessons learned investigation.

1. How would you compile the key lessons learned from Ladder LNG? 2. What points from Ladder should be used in other projects? 3. Who would you include in the lessons learned session? 4. Who were the key stakeholders for this project? How could they have

been managed differently to achieve a different outcome? 5. What drivers do you think influenced the behaviour of the different

stakeholders on the project?


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Phase 3 Epilogue

Ladder completed a lessons learned session on the project in late 2009. Among other things, there was a realisation that the fixed price nature of the contract had affected Ladders ability and willingness to intervene in the project.

Ultimately, the fixed price contract did not protect BG Group from risk; in fact, it introduced more risk because it prevented BG Group from obtaining good quality information on the project progress. Further, the imbalance of partners interests in both the development and operation of the plant resulted in a number of conflicts. It was necessary to resort to the contract in disputes with partners, which created relationship difficulties that made it difficult for the people to work together during the challenges that the project team encountered.

Overall, there was recognition that BG Group cant just hand over control to deliver this there has to be more oversight and participation. However, the final build quality is good and is achieving BG Groups strategic goals.


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Reflection: Re-doing Ladder

Overview

Ladder LNG can provide both useful lessons and suggestions for how to manage similar projects. In retrospect, how would you have managed the Ladder LNG project? What would you do differently if you encountered the same situation at the beginning of the project? In the middle of the project? At the end of the project?

Take time to reflect on the case study and consider how different actions could have produced an improved project management experience.

Supporting Materials

Lessons Learned Report

Questions

1. What would you do as a Projects Director? 2. What went well on Ladder? What does this show about BG Group? 3. How do value changes (such as merchant plant) get reflected in the

project? 4. How do you think the value delivery of the project could be modified? 5. What have you learned about managing legal and commercial risk? 6. How do you think project risk could have been managed differently? 7. What impact does the project complexity and control have on the

project outcomes? What can be done to mitigate these impacts? 8. What courageous conversations would you have had and when? 9. How could stakeholders have been engaged differently? 10. How did Ladder integrate continuous delivery and improvement

behaviours on the project? What else could have been done? 11. Did Ladder team members show a concern for others on the project?

How can this be used on other projects? 12. What opportunities did Ladder have to connect and collaborate within

the team? How could more opportunities have been created? 13. How could challenging on the project have been more effective? 14. How did Ladders actions in anticipating and innovating solutions to the

extra energy costs improve the project? How could this be done on other projects?

15. How did Ladder team members use impact and influence to achieve the project goals?

16. Did the Ladder team inspire a shared commitment in the project? Why or why not?

17. What aspects of the environment did the Ladder team need to understand to be successful?


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BG Group Project Academy

Leading Projects 2010

Case Study: Albustan Gas Development


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Case Study: Albustan Gas Development

Table of Contents

Project Overview 19

Phase 1 Directing Programmes and Delivering Value 20 Supporting materials 21 Questions 21 Phase 1 epilogue 22

Phase 2 Risk, Complexity and Control 23/22 Supporting materials 25 Questions 25 Phase 2 epilogue 26

Phase 3 Courageous Stakeholder Engagement 27 Supporting materials 28 Questions 28 Phase 3 epilogue 29

Reflection: Re-Doing Albustan 30 Overview 30 Questions 30


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Project Overview

This case outlines the key events of the Albustan project, located in Elbonia and the largest offshore installation ever built and installed in the Gulf of Elbonia. The case highlights the importance of risk management, contracting strategy, and stakeholder management, with regards to both contractors and partners.

The Albustan project was part of the third phase of the West Coast Development (WC 3c) conducted by BG Group, together with their partners.

The first two phases of the WC Development were completed in 2003 with seven wells drilled from the Addar platform. In April 2005, BG Group and their partners decided to proceed with the further development of the WC acreage. Phase 3 of the development was initiated at this time; the project was split into three parts, phase 3a was the drilling of a sub-sea well tied back to Addar and phase 3b involved the drilling of three more subsea wells also tied back to Addar. Phase 3c, which is referred to here as the Albustan project, involved several integrated components:

Installation of a new platform at the Albustan field

Drilling of four new platform wells

Drilling and tieback of a single subsea well

Tieback of the new platform to the existing Addar platform via a 20 pipeline Modifications to the existing Addar Platform to accommodate Albustan Gas as it

passed into the export pipeline.

The project entered front-end engineering and design (FEED) in September 2005. Once completed, the board sanctioned the project in July 2006, with full partner approval in April 2007, at an estimated total cost of USD875 million. Project completion was targeted for the end of Quarter 4 of 2008.

A consortium of The Halide Company Inc (HCO) and Marine Construction Inc. (MCO), both based in the US, completed the detailed engineering, procurement, installation and commissioning (EPIC). HCO also subcontracted a local company Elbonia Fabricators PL (EFCO) to build the topsides, the largest ever to be built in the country. The project was completed on 14 January 2009 at a total cost of less than USD875 million. At the time of writing, all four platform drilled wells have been completed together with two additional wells (under a separate phase, WC Phase 3d) under budget and ahead of time and have been handed over to operations.


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Phase 1 Directing Programmes and Delivering Value

At the end of the Select phase a fixed platform with four platform drilled wells was selected because of the ability to add additional tie-ins at later dates, versus a subsea installation that would be slightly cheaper but would pose greater operational risk. The availability of a suitable drilling rig to meet the schedule was an important consideration, so the selection of a fixed platform concept was made in collaboration with the BG Group drilling department. At the end of the Select phase of the project, and after much deliberation, the readiness review committee supported the recommended simple, unmanned fixed platform facility.

For BG Group, it was important to achieve a balance between getting the right people with the right skills to conduct the complex project, while maximising local Elbonian content to satisfy government expectations and thus maintain good support for future license rounds. However, a history of poor project delivery performance in Elbonia at that time was a concern.

The contracting strategy for the project was another consideration. The urgency around the need for completing the project as early as possible was at a time when activity in the oil and gas market was at its most buoyant for decades. Resources were scarce as order books for many contractors, together with material and equipment suppliers, were tight. As such, there was a need to make early decisions in order to mitigate risks to delivery of the project. For example, the heavy lift and pipe lay vessels necessary for the installation of the project had to be committed quickly. This needed to be reflected in the planning and contracting strategy. Additionally, the project required a new platform with a bespoke design, rather than merely a copy of the previously installed Addar sister platform. The added complexity required a high level of expertise from contractors. It was decided to invite EPIC proposals from consortia led by three recognised industry leaders; evaluation criteria would include installation equipment availability, engineering quality, local content and schedule.

In addition, Stakeholder relations were not as they should have been, with partners complaining that they had not had their views heard in the decision making process.

With the design decision made and urgent contracting decisions impending, the project was at a critical point. The skills of both the BG Group project team and contractors were being questioned, and a number of major risks were on the horizon. The future of Albustan hinged on how these decisions and risks were implemented and managed.


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Contract Strategy June 2006

Phase 3c Project Objectives June 2006

Questions

You are in charge of the BG Group Albustan Define phase team and are preparing for confirmation of the fixed topside platform design by the readiness review committee.

1. How would you manage the transition from the Define to the Execute phase of the project given that key members of the project team have little or no experience of fixed platform projects?

2. What would you do to alleviate any remaining Partner concerns over the design?

3. How would you manage the stakeholders on the project? 4. What contracting strategy would you advise for the project? 5. What are the critical factors to consider in order to make this

strategy work? 6. What would you consider when developing a contracting strategy to

manage risk?


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Phase 1 Epilogue

The FEED was completed in July 2006, by HCO, working out of their local office in Elbonia. The end of FEED coincided with a significant turnover in project leadership, which was attributable to the lack of experience in managing offshore platform projects.

This change could have had significant impacts for the project. Managers in several critical positions were replaced, including the Project Manager who was a subsea engineer rather than topside expert and the Engineering Manager who had downstream, rather than upstream experience. This provided the project team with appropriate skills going forward giving the project a far better chance of success.

Negotiations took place with three consortia in competition. The intent of these negotiations was to reveal profit, overhead and Heavy Lift Vessel availability from the competing entities. The element of competition was retained for as long as possible. Eventually a combination of local content and global experience was achieved through the selection of a consortium of HCO and MCO based in Houston, with a nominated subcontractor for fabricating the topsides being EFCO. As part of the agreement, HCO immediately began the detailed design of the topsides whilst MCO commenced the detailed design for the jacket. EFCO would fabricate the topsides locally. This strategy satisfied expectations for local content, while at the same time providing some surety of project success. In addition, MCO would be responsible for the transportation and installation risks, thereby addressing a significant concern in the project timeline. Of the two other consortia considered, both were unable to commit to the installation equipment required and insisted on a four month FEED verification period.

Partner relationships had broken down by such an extent by that an offer was made by the new project team to conduct an independent design review using a contractor of the partners choice. The partners selected SBB (a subsidiary of CFN). This independent review gave partners the reassurance that their concerns were being heard and that the design concept was indeed optimal. This alleviated the concerns of the partners, and allowed the project to move forward to sanction.

The BG Group board sanctioned the project in July 2006, with full partner approval in April 2007, at an estimated total cost of USD875 million:

Summary of Budgeted Costs $ million

Base Cost 613

Development Drilling 151

Pre sanction Costs 21

Total Base Cost 786

Project Contingency 63

Drilling Contingency 25

Total Project Cost 875


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Phase 2 Risk, Complexity and Control

With the introduction of a new Project Manager with both surface installation experience and a prior knowledge of the contractor MCO, the project proceeded to issue a limited letter of award of up to $25 million for the HCO MCO Consortium to commence the detail engineering and procurement. This allowed the Heavy Lift Vessel to be booked (taken off the market for the installation time frame required) and also allowed sufficient detailed engineering to take place to allow placement of orders for the Long Lead Items. Due to the extremely active contractor market, there was a concern that contractor prices could be inflated. The project team therefore introduced an open-book pricing approach for the EPIC phase of the project. Over the next six months as each order was placed, price and delivery risk was eliminated from the risk monies contained within the consortium pricing structure. By December 2006 85% of the LLIs had been placed eliminating the necessity of risk monies associated with these items.

This approach, however, was not without risk. The consortium contractors, HCO and MCO, usually acted in competition with one another. An independent auditor was therefore appointed to ensure the accuracy of disclosed cost information whilst at the same time keeping proprietary cost information confidential from each party and to verify the financial details of all project participants. The implementation of open-book accounting was achieved after six months of negotiation from August 2006 until January 2007. As part of the agreement, BG Group had the option of terminating the contract after six months, should acceptable costing not be achieved through the open-book process. Whilst transferring the remaining engineering and procurement to another entity would not have been without its problems, this strategy protected the overall project schedule in either eventuality. This provided additional incentive to the contractors to achieve an optimal cost solution.

The decision to award the contract to the HCO-MCO consortium also alleviated other risks within the project. Firstly, HCOs existing strategic relationships with a number of suppliers helped to reduce the costs that were being levied by many vendors in the buoyant oil and gas market. Additionally, HCOs experience in working with local contractor EFCO on smaller projects reduced the risk involved in employing a local contractor. Similarly, MCOs ability to lock-in bulk steel orders with their own strategic steel providers proved to be invaluable for cost control, as did MCOs ownership of a the Heavy Lift Vessel required to complete the installation. This also reduced the risk to BG Group, as MCO was responsible both for ensuring that the vessels were available and for covering any costs for late arrival of the vessels. Another main risk mitigant was the fact that EFCO was 50% owned by Chet Atkins, who owned two fabrication yards in Texas. If EFCO got into real trouble in fabricating the topsides in Elbonia, support would have been available at one or other of these yards. However, none of this proved necessary as EFCO performed well.

Despite these positive risk mitigations, using EFCO was seen as a significant risk to the project in terms of ensuring safety in working practices, maintaining adequate productivity and quality, and avoiding industrial disputes. However, BG Groups commitment to investing in local content in Elbonia made the risks a necessary component of the project.


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Furthermore, the budget still had to account for major weather risks that were projected. Weather risk was particularly significant for the project, due to the monsoon. The known difficulties of working in the regions strong currents created a significant risk of delay that had been realised on previous projects in Elbonia. The need to coordinate with a complicated pipeline installation, the jacket construction in the UAE and the tow to Elbonia, meant that weather was critically important.

Given these challenges, the new project team had their work cut out for them in managing the risk and complexity of Albustan within an aggressive timeline.


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Phase 3c - RR5 Readiness Review Report June 2006

Phase 3c - Project Execution Plan

Phase 3c Cost Estimate Summary

Questions

1. What are the risks involved in the contracting arrangement? 2. Which are the most serious risks to the project at this point and

how can they be mitigated? 3. Who should be responsible for the risks? 4. Assess the benefits and challenges of implementing open book

accounting on a generic project. Design a plan to implement open book accounting how could this be achieved?


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Phase 2 Epilogue

The open book accounting approach was successful and an independent benchmarking review conducted at the end of the first six months of the Execute phase concluded that the EPIC costs were within an acceptable range, especially considering the market environment at the time. The open-book accounting approach created a high level of trust between the project stakeholders. The use of open book accounting further permitted BG Group to eliminate unnecessary risk premiums by contractors. For example, MCO had estimated the weather risk at USD20 million, which they then increased to $40 million for risk pricing purposes. However, BG Group decided to accept the risk relating to weather themselves and place $20 million within the provisional sums section of the contract to be used only if a weather event occurred (in the event, despite the weather risks occurring, less than $12 million was paid with the remainder retained by BG Group).

To address the risks inherent in EFCOs selection, BG Group worked closely with the organisation to ensure that good safety practices were in place. Further, BG Group encouraged EFCO to invest in welding schools that could develop local skills within the community, which could subsequently be deployed on the fabrication effort.

The risk of industrial dispute could not be avoided. The weather and labour relations risks did occur, which ultimately threatened the project delivery date. These and other delivery challenges will be discussed in the next phase.


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Phase 3 Courageous Stakeholder Engagement

As the project progressed to the installation phase, a number of significant issues arose, including the realisation of many of the risks that the project had considered.

In April 2008, a 21-day industrial dispute at EFCO delayed progress on the project, but did not result in any significant changes to the budget.

Although not part of the HCO - MCO EPIC contract, the pipe-lay contractor also ran into installation difficulties due to weather. Despite the use of one of the top pipe-lay vessels in the world, the currents in the Arabian Sea proved challenging and the vessel struggled to hold station. Pipe lay activities took 23 days rather than the 15 days planned, with an extra cost for the 8 days at $800,000 per day equal to $6.4 million. However, the pipe-lay scope was subject to a separate contract with Pipco who covered this cost, having accepted the weather risk as part of their pipe lay scope.

The weather risk relating to towing the jacket across the Arabian Sea was also realized. The two tugs towing the transportation barge ran into difficult weather in the Arabian Sea and encountered three storms. During a sudden squall at one point, the jacket transportation barge had to be cut loose to avoid the potential of sinking the tugs. The jacket was quickly recovered after the storm, but this could have had significant consequences.

Despite these challenges, the upfront investment of time in building trust and relationships with the contractors through the open book accounting process, and in managing the project in a fair and transparent manner, were beneficial. Issues were managed in a cooperative and collaborative manner, with input from all parties. Additionally, the contracting decisions that BG Group made at the beginning of the project ensured that the delays were covered by those best able to manage the risk rather than solely by the project. The risks therefore lay with the contractors towards the end of the project, versus at the beginning where BG Group and its partners held much of the risk.

From a team perspective, a regular all-team status meeting was held every two weeks, with weekly meetings focused on interfaces. The Consortium sponsors held monthly meetings with representatives from each of the contracting entities including EFCO. The project stakeholders felt included in the process throughout. The independent reviews allowed a degree of external confirmation of the approach and associated costs, and that provided a useful focus for the partners and the contractors.


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Monthly Report no. 50, period ending 25 Jan 09

Questions

You are the Manager on this project in charge of the lessons learned review:

1. What do you think are the key lessons learned from Albustan? 2. What points from Albustan should be used in other projects? 3. Who would you include in the lessons learned session? 4. What drivers do you think influenced the behaviour of the different

stakeholders on the project?


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Phase 3 Epilogue

The overall implementation was completed on 14 January 2009, despite the realisation of major risks. In fact, the industrial dispute coincided with delays in the transportation of the jacket and thus allowed extra time to finish the topsides. In the final analysis, despite the realisation of many of the risks anticipated, the platform was ready to start-up on 24 December 2008 and was only held back by the Deepdive III performing the final pipeline tie-ins as the vessel struggled with heavy currents and poor sea conditions.

However, the deliberate decisions to contract strategically and to pursue the difficult option of open book accounting allowed the project to proceed through difficult times. Challenges from partners were addressed with external support, and the commitment to aspects like local content contributed to positive relationships with government stakeholders.

Although it can be seen that the Albustan project was not without challenges, it has been equally recognised with a number of awards. Contractors MCO and HCO both rewarded the project with internal awards, and BG Group won the Association of Project Management (APM) 2009 Overseas Project of the Year award and Elbonias Energy Chamber Award. It is also worth noting that the success of this project compared to earlier projects in this region improved the overall perception of BG Groups project delivery capability in the area and of the capacity of local contractors. EFCO especially has benefited from follow-on work due to their experience on Albustan, which has had a positive impact on the local economy.


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Reflection: Re-doing Albustan

Overview

The Albustan project can provide both useful lessons and suggestions for how to manage similar projects. In retrospect, how would you have managed the Albustan project? What would you do differently if you encountered the same situation at the beginning of the project? In the middle of the project? At the end of the project?

Take this time to reflect on the case study and consider how different actions could have produced an improved project management experience.

Supporting Material

Shared Learnings Report.

Questions

18. What would you do as a Projects Director? 19. How do you think the value delivery of the project could be modified? 20. What have you learned about managing legal and commercial risk? 21. How do you think project risk could have been managed differently? 22. What impact does the project complexity and control have on the

project outcomes? What can be done to mitigate these impacts? 23. What courageous conversations would you have had and when? 24. How do you think the stakeholders could have been engaged?

Case Study Document

Documents

Transcript of Case Study Document