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and depth of technical capabilities flourished, so, too, did the opportunity for specialized field services companies to provide such expertise on an intermittent or as‐needed basis. Similarly, business model adaptations such as nonoperated ventures (NOVs) and joint ventures (JVs) enabled companies to participate in resource development and production activities beyond the reach of their core ownership holdings or core capabilities. These vehicles also facilitated a pooling of financial capital and technical expertise, which were often in short supply, while also syndicating the project risk – which was often considerable.

      As oil and gas became big business, many host countries recognized the opportunity to retain a greater share of their resource sector's bounty and control through the adoption of state‐led national oil companies (NOCs) – another variation in the sector's business models. Consolidation among the largest integrated players (mega‐mergers) facilitated consolidation – affording large economic gains in the downstream refining and retail segments of the industry and a consolidation of conventional upstream business. Many companies adopted corporate shared services models for centralized procurement and other business roles.

      Consolidation of the world's lowest‐cost conventional resources under NOCs and state ownership caused international oil companies (IOCs) and independent operators to venture further afield into new international frontiers and a growing array of resource types – including ultra‐deep‐water, the arctic, shale gas, tight oil, and the Canadian oil sands. These ventures generally represent much higher cost resources and require even more specialized expertise.

      In the aftermath of the collapse in oil and gas prices, efforts to offset the effects of cost inflation and capital constraints have included the sale of many midstream and downstream assets, with many upstream operators exiting these parts of the value chain to focus their efforts (and limited resources) on the needs and opportunities of the upstream. Within the enterprise, this has generally included a migration toward asset team organizations, and investments in key capabilities such as enhanced subsurface capabilities, with improved data processing for 3D seismic, greater use of geomechanical modeling and reservoir engineering, enhanced recovery (EOR), and new applications for digital and big data analytics.

      Despite this evolution – our understanding of the resource base, methods and technologies for its development, ownership and stakeholders, business models – there has been little effort to redesign and transform enterprise operating models beyond incremental accommodations. Unlike industries that have undertaken operating model transformations in response to disruptive industry forces (e.g., retail), the upstream rarely undertakes operating model change on a systematic or enterprisewide basis. The notable exception is post‐merger integration (PMI) programs, where promises of synergies often trigger fundamental reviews of operating models.

      TEN REASONS TO UPDATE YOUR OPERATING MODEL

      Many factors have conspired together to make the case for change – reasons to adopt a low‐cost operating model. A culmination of disruptive forces – including supply gluts in US shale gas and tight oil and growing consensus among world leaders to curb fossil fuel emissions – is reshaping the global energy landscape. Despite several years of relatively high prices, upstream returns had been low, both by historical standards and relative to the cost of capital. And it has been difficult for the majors to maintain, let alone grow, production or replenish reserves. Nor can we rely on high prices. Furthermore, research indicates a major shift in how capital markets value oil and gas companies, with multiyear income, cash flow, and operational measures (including reserves) playing a much more important role in stock prices.10,11

       Evolving Global Resource Base

Enterprise operating models require a much broader set of key capabilities, some new, to accommodate our evolving understanding of the global resource base (see Figure 1.3). Furthermore, the replacement challenge facing the industry is formidable – the world needs ∼60 million barrels per day of new production by 2040 to offset declining fields and net demand growth. This must be sourced from an increasingly diverse, and expensive, resource base amidst choices between enhanced recovery from mature fields, new frontiers, deep‐water and ultra‐deep‐water, unconventional resources such as tight oil, shale gas, oil sands, and coal bed methane, and emerging but largely unproven sources, like the arctic, seabed methane hydrate, and carbonite reservoirs.12 The industry is pursuing higher‐cost resources, more technical/lower quality reservoirs, heavy oil, or harder to commercialize gas, and with more above‐ground risk.

Figure 1.3 World Resource Plays

      Source: IHS Energy

       Disruption from the “Ripple Effect” of Unconventionals

      Rapid growth in US onshore unconventional liquids production and high levels of natural gas production (despite falling rig count and new well spuds) have contributed to keeping liquids, gas, power, and industrial feedstock prices low. This has fueled disruptive change throughout the economy and altered the competitive landscape for refiners, petrochemicals companies, and energy infrastructure. In the upstream, shorter cycle times and very different subsurface risk and cash flow profiles have challenged strategies with disruptive impact along several dimensions:

      • Increased short‐cycle supply, reduced prices, increased price volatility, and challenged the role of OPEC; there was a westward migration in the balance of power and a reorientation of crude and product flows and trade patterns.

      • Shifted capital inflows toward US onshore; private capital dove headfirst into the upstream sector; many exploration and production (E&P) companies created separate organizations for unconventionals investment and/or operation.

      • Provided operational blueprint for developing lower permeability oil and gas reservoirs internationally.

      • Challenges to pricing mechanisms, market liquidity, and competitiveness of global gas/LNG projects.

      • Increased cost‐competitiveness of US petrochemicals; capacity shifted away from foreign naphtha‐based markets toward US ethane‐based conversion capacity and downstream manufacturing.

      • Reduced US carbon footprint and increased cost‐competitiveness of US power‐intensive industry; there was more displacement of coal‐fired (and even some nuclear) power generation.

       Discovery Challenges

The challenges of our evolving resource base are accentuated by a decline in conventional exploration – conventional oil and gas exploration is yielding lower volumes of higher‐cost, lower‐value reservoirs. We are replacing cheaper, high‐quality barrels with high‐cost/lower‐quality barrels (see Figure 1.4). Accounting for the rise of unconventionals – a relatively high‐cost resource – only makes this picture worse.

Figure 1.4 Conventional Oil and Gas Discoveries and Field Growth, by Year

      Source: IHS Energy

      The year 2015 marked the lowest point for conventional oil and gas discovery in many years – the absolute number of wells drilled generally has not been in decline as much as the volumes being discovered – a smaller number of large fields. Nor have there been many billion‐barrel discoveries – the Piri gas field in Tanzania was 1.9 Tcf (i.e., 318 million boe), accounting for 16 percent of total volumes. A growing proportion of discoveries are in the higher‐cost deep‐water (i.e., 1000 to 5000 ft) and ultra‐deep‐water (i.e., >5000 ft); discoveries in shallow water (i.e., <1000 ft) and onshore are in decline. And more gas than oil is being discovered, which are lower economic value resources.

      The rise of unconventionals, plus successful openings in places like Mexico

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