Corruption is Delaying Socioeconomic Benefits of Liberian E&P Investments, but Local Supply Chain Development Can Stimulate Foreign Investment and Economic Growth Indirectly

Corruption Index logoAt first glance Liberia doesn’t seem as corrupt as its West African neighbors – it received 41 out of 100 on Transparency International’s Corruption Perception Index (higher is better; 90 was the best score and 8 was the worst). Many African countries with newfound oil reserves received similarly disturbing scores – Chad scored 19; Angola 22; Cameroon 26; Cote d’Ivoire and Equatorial Guinea 29; Mozambique, Mauritania, and Sierra Leone 31; Niger 33; Tanzania 35; and Gabon 38.

Still, Liberia has spent the past year dealing with scandals related to bribery of government officials by its oil company executives who tried, unsuccessfully, to push through a round of oil concessions with limited public consultation. Governance issues are not a unique story in West Africa.Nigeria delayed a 2012 round of oil concessions as foreign investors looked on skeptically, remembering the previous corrupt rounds (2005-2007) and fields that were acquired but left undeveloped. Also, Ghana issued multiple tenders for development of its refining (downstream) sector, but many projects were not approved, not started, or not completed.

While policy reforms can take years to implement, there is another way to attract investment and stimulate jobs and economic growth in the meanwhile: Liberia can build a strong local oil and gas supply capability. By training and developing local suppliers to be competent and capable, and institutionalizing transparent commercial practices, the government can lure investors and make it easier, quicker, and cheaper for NOCAL (the national oil company of Liberia) to do business honestly with efficient suppliers while increasing the difficulty, cost, and consequences of doing business corruptly with its cronies.

Boston Strategies International benchmarks local supply capability in a number of emerging oil, gas and power supply markets. Ask us how you stack up, and how we can help accelerate strategic and economically impactful local content development.

How West African National Oil Companies Can Raise Their Equity Stake in Upcoming Projects from 15% to 50%

shutterstock_80954569Ghana National Petroleum has 15% ownership of the Deepwater Tano Contract Area. The other 85% of the ownership went to Tullow (47%), Kosmos Energy (17%), Anadarko Petroleum (17%), Sabre Oil & Gas Holdings Ltd, a wholly owned subsidiary of Petro SA (4%) (percentages are approximate).

In contrast, Sonangal holds 41% of the Mafumeira Sul project in Angola (Chevron holds 39%, Total holds 10 percent, and ENI holds 10%), and NNPC holds 40% of the Escravos project in Nigeria (Chevron holds 60%).

How can Chad, Côte d’Ivoire, Liberia, Mauritania, Cameroon, Niger, Gabon, Namibia, Sierra Leone, and Equatorial Guinea get a higher percentage ownership of projects in their own backyard? Low equity figures imply that partners are contributing 85% of the value, and by extension that the locals are only remunerated for their natural resource.

These countries can change the game by increasing their local supply chain competence upward toward a target of 50% of the value of the projects – more than the Nigerian and Angolan equity in the aforementioned deals, and just under the minimum target that Nigeria has set for the ensemble of sub-industries in its oil and gas sector (the minimum local content is 54%, on average).

The key to earning more equity is to accelerate the development of local capabilities that are: 1) critical to project execution; 2) that can be incrementally more profitable than the average oil and gas supply industry; and 3) that can meet oil companies’ qualification criteria within a relatively short investment timeframe.

Generally speaking, they can achieve most of these objectives by developing the following six industries:

  • Pressure vessel fabrication
  • Pipe fabricating and installation
  • Compressor manufacture, assembly, and maintenance
  • Well and drilling services
  • Pump and valve assembly and light manufacturing
  • Water treatment equipment and services

Boston Strategies International offers hands-on capabilities to help establish the needed capabilities in oilfield applications of each of these industries. Click here to ask us for our relevant qualifications in:

  • Formation of alliances with leading technology partners
  • Design and construction of facilities
  • Training and development of  local labor force
  • Management and supervision of operations

Note: Image courtesy of AHFRO.

Bahrain’s LNG Terminal Project: How an Independent Master Supply Chain Plan May Have Saved 29 Months and $138 million

b2ap3_thumbnail_Fast-Track-to-Funding-shutterstock_164841665Bahrain’s National Oil and Gas Authority (NOGA)’s LNG import terminal project seems to be on path for a 7-yearcycle: NOGA initiated partnering steps in 2010, and is forecasting completion for 2017.

  • During a ‘prequalification’ round, NOGA came up with an initial short list of potential EPC firms, then it enlarged the bid list to include a maximum number of responses (21). The bid turned out to be premature, but it did result in two ongoing ‘discussion partners’ (Shell and Vitol).
  • NOGA took several years to iron out governance issues. It had originally considered a joint venture with Independent Terminal Bahrain (ITB), Kuwait’s Independent Petroleum Group (IPG), and Arab Petroleum Investments Corporation (APICORP). In the end, NOGA chose a consultant and engineers to do a pre-FEED and a FEED study. It also decided on issues of ownership between NOGAholding, NOGA, and BAPCO, which it engaged as a technical advisor.
  • It set priorities and interrelationships between related projects, assessing its domestic energy needs (e.g., ALBA), evaluating alternative energy sources and configurations (FLNG, solar, etc.), negotiating the terms of pipelined oil from Saudi Arabia, and tweaking the project’s timing to synchronize anticipated supply and demand.

The introduction and integration of a supply chain ‘master plan’ at the Feasibility Study/Basis of Design stage can shrink the project cycle, improve reliability of the timetable, decrease cost, and synchronize procurement commitments with forecast cash positions, all while meeting target levels of total cost and per-unit cost. A supply chain master plan for an LNG project has three components:

  • Assessment of the cost saving potential of alternative major equipment technologies and choices, such as gas turbines, GT drives, and heat exchanger designs, which on average saves 10-25% on these major items.
  • Determination of the minimal achievable project timeline within inter-related and complex supply chain lead time constraints, especially for major equipment such as compressors. This avoids subsequent project delays and cost overruns. As a proxy, Boston Strategies International sampled 20 major refinery projects between 2005 and 2014 found that 20% of them encountered delays that inflated their schedules by an average of 35% and their cost by an average of 23%. Equivalent factors applied to the roughly $600 million, 7-year terminal project in Bahrain would yield a potential avoidance of 29 months and $138 million.
  • Calibration of the timing of financial and legal/contractual commitment to long lead time equipment, which avoids cash crunches.

Supply chain master plans should be conducted by independent third parties other than the firm that may do or manage the construction. This ensures objectivity of the costs and lead times, which an EPC often has an incentive to misrepresent in order to increase its chances of winning the construction work. By providing a range of cost benchmarks for similar projects, it also dramatically improves the owner/operator’s negotiating position in the bid evaluation phase.

Boston Strategies International developed a supply chain master plan for a major European power producer that helped to save 13% on the baseline cost of a $45 billion project ($5.8 billion).

Pemex Is Buying Jackups and Partnering with Keppel to Build More. Should It Rent The Oil Rigs Instead?

shutterstock_29118568Pemex is investing in offshore oil exploration and production to reverse a 25% drop in oil production levels over the past 10 years, and to secure its claim to domestic offshore oil leases before foreign oil companies gain access to them. Mexican oil industry reform passed in 2012 and 2013 paved the way for more offshore investment, and in 2013 Pemex announced plans to buy 8-12 new jackup rigs – supporting its goal to be the world’s most prolific jackup operator. Pemex is in a hurry to lock in its investment and drilling plans, as new legislation opens up offshore Mexican oil lease auctions to international oil companies as early as 2015. The national oil company wants to hold on to as much acreage as it can, but it needs to prove that it can drill those acres before the upcoming auctions, hence its ambitious plan to secure more jackups.

Pemex announced a Memorandum of Understanding with Keppel Offshore & Marine in October 2013 that covers the development, construction, and operation of a new yard at the Port of Altamira to build and repair offshore rigs. The yard’s first phase will cost $150m, and give Keppel and Pemex the capability to build six new jackups. In addition to the six rigs that Keppel will eventually build at Altamira, it is already building two jackups for Pemex, and Sembcorp is likely to win orders for at least two more jackups this from Pemex this year.

Why is Pemex is buying rigs instead of renting them? To avoid ever-increasing day rates and ensure availability. True, it is contracting rigs as well, having already closed six-year contracts on four Seadrill jackups (and it will soon close a similar deal on a fifth), but those are only a temporary measure until its own rigs can enter operation. Average jackup day rates rose 11% in 2013, from $120k to more than $130k. A tight market for jackup capacity can push day rates into the $300-400k range for some jackups. Part of Pemex’s goal is to plan its spending as accurately as possible, a goal not satisfied by climbing day rates for rigs. In addition, when fleet utilization rates are high, the wait for available rigs can stretch to years, which could delay Pemex’s long-term drilling goals. Its status as a National Oil Company (NOC), ultimately controlled by the Mexican Government, gives Pemex the flexibility to embark on such an ambitious buying program. In contrast, most Independent Oil Companies (IOCs) prefer not to tie up resources in such capital-intensive assets, contracting rigs wherever possible to insulate themselves from the boom-bust cycle of oil prices.

How does an oil company know whether to buy or lease rigs? A correct decision should compare a forecast of day rates to a properly negotiated purchase contract. The easy way to do this is to forecast straight-line day rates and use 2-3 recently publicized rig contracts as a basis for a comparison. Unfortunately, the actual line is often sloping or curved, and the publicized contracts are not the best price that can be had. Inaccuracies can yield a wrong decision – lease instead of buy, or buy instead of lease. Boston Strategies International recently developed a detailed rig procurement cost analysis for a major NOC that is helping it to assure future drilling capacity while saving approximately 20% on the purchase cost of the rigs – in Pemex’s case this could save approximately $400m on 10 jackups.

Supply Chain Planning Critical to Latin American Oil & Gas Capital Project Profitability

b2ap3_thumbnail_Carnaval1Budgeting and controlling investment costs for Latin American oil & gas projects can be particularly tricky. If investors and owners don’t use reliable information in negotiating with EPCs and equipment suppliers, their projects may suffer from a proliferation of risk buffers and safety margins that cumulatively make them unviable. Or, even worse, they may proceed with the projects and then suffer financially disastrous cost overruns.

Costs vary widely across Latin America, and between Latin America and other regions. Labor costs, third country national participation, and local employee benefit adders are particular to each country. Local productivity differentials, local content requirements, and union regulations together can double or even triple project costs. Steel costs vary widely due to volatile demand and limited supply. Fuel costs are subsidized in some countries and not in others. Finally, high payment risks, the chance of expropriation, hyperinflation, and economic volatility affect terms and conditions of contracting.

Projects like Sea Lion, a joint venture of Premier Oil (60%) and Rockhopper (40%), in Argentina, exemplify the need for supplementary and more methodical cost benchmarking, value chain engineering, tender design, and supplier negotiation. The total capital estimate ($5 billion) is making it hard to fund this project. In addition, Sea Lion’s project budget is fluid and has wide variances: the pre-FEED study on the FPSO plan suggested a required investment of approximately $7b, while new estimates come closer to $5.2 billion.

In order to assure project viability investors in Latin American oil and gas ventures need to access equivalency costs for similar investments in other regions, tapping into specialized expertise if necessary to accurately forecast and mitigate financial and strategic supply chain risks.

Making the Case for Floating Renewable Energy Nodes (FRENs)

442904-ea99f99a-ee0d-11e4-a82d-68ff75e6542cMost people assume that the economics of one energy technology will prevail over the others for extended stretches of time. Sure, large oil companies such as Chevron and Saudi Aramco fund small research and development projects aimed at leveraging possible interaction between the technologies, for example offshore wind powering oil and gas rigs, or solar-powered field offices, with many of the more futuristic projects being proposed and executed under academic research grants. However, less developed energy technologies get relatively little attention. In the current paradigm, wind, waves and sun are often perceived mostly as nuisances that complicate offshore installation and equipment operation and maintenance.

What if we took a more holistic approach and developed Floating Renewable Energy Nodes (FRENs) that could simultaneously harness the power of the wind, the waves, and the sun while drilling for, and producing, oil and gas? The idea is not borne out of environmental sentimentalism, but out of hard financial benefits. The following economic synergies would need to be validated for any specific project:


1. Could the ancillary units could hook onto the primary structure at a minor incremental cost, directly increasing the project ROI of the primary project through additional revenue streams or reduced costs?

2. Could the ancillary units connect to the same electrical system as the primary unit, either providing motive power (e.g., solar energy powering pumps) or delivering incremental electricity output (e.g., wave energy connecting to the Wind Turbine Generator) with a shared electrical infrastructure?

3. Could harvesting the various forms of energy around the tower or platform dampen the stress load on the primary structure, thereby reducing its complexity and cost? For example, could harvesting the energy of the wind and waves before they crash against the foundation enable a lighter foundation?

4. Could floating structures economically support multiple forms of energy generation? Floaters (semi-submersibles, drillships, drilling barges, FPSOs, TLPs, SPARS, etc.) have become the norm for the offshore oil and gas industry.

Oceanlinx has designed and built a range of floating wave energy capture units (called Oscillating Water Columns), one of which (ogWAVE) is designed to integrate with oil and gas platforms, supplying 500 KW of power as a microturbine might. This example is intriguing, and could pave the way for other integrated designs.

Eventually, these could form a sea of floating energy nodes, tying to common cabling systems that link them to shore.

Thoughts and comments are welcome…

Note: Image (unartfully) adapted and modified by Boston Strategies International from various images, including, which was originally sourced to


DONG-Siemens Collaboration a Model for Long-Term, Sustainable Supply Chain Partnerships

b2ap3_thumbnail_Bride-and-groom-ss_164851256The DONG-Siemens offshore wind collaboration, a long-term relationship that began in 1991 and has involved over 930 turbines used across more than 13 windfarm projects, is a model of sustainable and long-term supply chain organization for strategic partnerships in offshore wind. The way the relationship has played out  leverages economies of scale of the WTG, and takes advantage of reductions in cost over time due to learning curve effects, without sacrificing commercial independence. Many companies in the industry are seeking the optimal form of interaction with customer and suppliers of key components and services (preferred supplier, partnership, direct investment, etc. – my book “Optimal Supply Chain Management in Oil, Gas & Power Generation” provides a roadmap for building industry partnerships, which articulates and classifies different levels of partnerships). The mode of commercial organization that DONG and Siemens have created provides a model for many other players to study and emulate.

Mainstream Renewable Power Locks in High Cost Structure at Neart Na Gaoithe Windfarm

b2ap3_thumbnail_Fat-shutterstock_125676140In contrast to other windfarm owners and developers that have established supply chains that achieve economies of scale through standardization, and replication of proven, reliable, and cost-efficient technologies and processes, Mainstream Renewable Power (MRP) has locked in a high-cost supply chain for its Neart Na Gaoithe windfarm. This could explain why the Department of Energy and Climate Change’s Final Investment Decision Enabling for Renewables (FIDeR) regime classified the windfarm as “unaffordable.”

In what way is the supply chain configuration expensive?

  • The group appointed an exclusive preferred supplier (Siemens), apparently before deciding on the technology platform or negotiating price or terms. Although this is done sometimes in the oil and gas business, this approach should be reserved for risky and/or remote projects where a single source is the only or clearly the best option. It is not a “best practice.” My book “Optimal Supply Chain Management in Oil, Gas and Power Generation” has a flowchart that shows when to single source, and the chart shows that there are relatively few circumstance in which you want to specify the source before choosing the model or negotiating a price. MRP just wrote Siemens a blank check. There is no doubt that Siemens is a great supplier; it’s just that this approach is not the most cost-efficient way to manage a project that is struggling for financial viability.
  • MRP has decided to outsource project management from soup to nuts. It will outsource Engineering, Procurement, Construction and Installation, rather than just E or EP or EPC. For sure, EPCI firms get the job done, but they charge a premium for it and usually have an incentive to increase the cost of the project rather than reduce the cost (since they frequently get reimbursed as a percent of the cost). If you have the capabilities in-house (and perhaps MRP does not), you can reduce the cost of the project by managing it yourself, as other major windfarm owners/operators have done.
  • It enlisted two EPCI partners rather than one, which is bound to be even more costly than having one EPCI partner, as each one will need to be compensated. As a 25% shareholder in MRP, the choice of Marubeni is obvious, but the rationale for tacking Technip on too is less obvious.

There may be reasoning behind these agreements that makes them cost-efficient supply chain maneuvers, which MRP is keeping close to the vest. Let’s hope that there is some hidden supply chain wisdom in play.

Savvy Supply Chain Planning the Key to North Sea Offshore Wind farm Profitability

b2ap3_thumbnail_wind-turbine-73158643The last 12 months have seen the unraveling of many Round 3 offshore UK windfarm plans. Both Vattenfall and RWE, although they are still committed to some major successful projects, have decided to curtail their future spending on renewables (mostly wind) by nearly half. RWE pulled out of the Atlantic Array. Others have scaled back the size and/or number of planned projects in light of a sluggish political / consenting process and strong opposition from environmentalists. Even the enticement of huge subsidies (for example, from the European Investment Bank, or EIB) can only tie up capital and business plans for so long.

The success or failure of these offshore wind projects hinges on savvy supply chain planning and management, which can reduce investment cost by 13% without trying hard, and by more than 20% when push comes to shove. The “supply chain” delta can be the difference between a loss-making project and a profitable one. Siemens understands this well. It has developed a well-crafted modularization program that can extend from the owner through the WTG supplier through to component and maintenance suppliers. But an optimal supply chain strategy involves more than modularization. Supply chain thinking should have already entered into the decision to invest in the project in the first place, since the costs, benefits, and risks of supply chain decisions are integral to the program’s cost and financial results. Strategic supply chain planning should dictate how many phases there should be and how large each one should be; how to stage and organize the engineering, construction, and procurement of key equipment in each stage and across all the stages; how to choose key suppliers and how and when to align with them; whether to bundle procurement together into large modules or split it up into small chunks; whether to insource or outsource various facets of operation and maintenance; and when to commit to contracts and incur financial milestones.

While it may be too late for projects that already been cancelled, E.on, Forewind (Dogger Bank), EDF/Eneco (Navitus Bay), SSE, Scottish Power, and Blackstone (Nordlicher Grund) may want to get an outside expert’s opinion on how much can be saved by optimizing the supply chains of projects that are currently being downsized or are at risk of being cancelled in the future.

Can Extra Long Monopiles Really Replace Jacket Foundations for Offshore Wind Turbines?

b2ap3_thumbnail_Offshore-wind-turbines-43932955Siemens Project Ventures GmbH has apparently not decided which type of wind turbine foundation to use for its 600 MW Hornsea One project (Heron Wind) in the North Sea, despite having chosen Siemens’ own SWT-6.0-154 wind turbines for the project (a joint venture with Mainstream Renewable Power and DONG). Five years ago, monopiles would have been out of the question in that water depth (25-40 meters), and the prospect of using gravity base foundations would have raised many engineering questions, leaving jackets as the default choice. Today, due to the advent of extra-long monopiles, there is a renewed debate on the subject of foundations. Still, the challenges of monopiles supporting the weight of a 6+ MW turbine 200 meters from the ocean floor and rotating a 154-meter diameter blade on a single pole would seem to be a major concern – bending and buckling in heavy waves and wind, not to mention shipping and installing a monopile of that length.

The offshore wind industry often takes its engineering, procurement, and construction cues from the offshore oil and gas industry. Of course the weight and physics of offshore oil rigs and production platforms are totally different than wind turbines, and the wind and wave conditions are engineered for every farm, but in general it is a lot easier to make offshore windfarms cost-effective if they are based on proven technologies such as jacket foundations (manufacturing, shipping, installation, operation, maintenance, and decommissioning) repeated in high volume with significant economies of scale, at least in the early stages.

Informed responses would be appreciated. Please comment.