Читать книгу The Final Frontier: E&P's Low-Cost Operating Model - Pettit Justin - Страница 10

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 and Iran, bring great promise but do not address all of our replacement needs. Nor will growth in renewables. The global resource potential remains enormous but appraisal and development is costly and technologically complex. Many new plays still require economically viable fiscal terms, operating structures, and costs. We must replace “cheap barrels” in the context of an evolving and increasingly expensive resource base, disappointing conventional exploration results, project delays, and rising costs and capital intensity.

One bright spot has been the offsetting effect of “field growth” – upward adjustments made to the volumetric resource estimates of prior year discoveries – which now often exceeds new discoveries. Roughly 2000 conventional fields have their technical resources revised upward every year based on factors such as more/better data, de‐risking milestones, and enhanced interpretation. Therefore, some companies might opt to focus on existing basins and fields over traditional frontier exploration in order to reduce costs and mitigate declining exploration success rates. Others might opt to focus on unconventionals, which carry a very different subsurface risk (and cost) profile than conventional frontier exploration.

Fading Production

Upstream operating cash flow is both inadequate and in decline. Despite a period of high prices, returns in the upstream oil and gas sector were already down (i.e., both relative to historical returns on capital and relative to the cost of capital) well before the 2014 collapse in oil prices. Moreover, as illustrated in Figure 1.5, major producers struggled to grow their production (and to replenish reserves). Production is fading, operating margins have shrunk, the supply chain of services companies has telegraphed that its prices must rise, and the amount of invested capital has soared.

Figure 1.5 Worldwide Oil and Gas Production by Majors (MM boe)

Source: IHS Energy

Many large NOCs, such as Mexico's PEMEX and Venezuela's PDVSA, also face fading production. Over the past 10 years PEMEX's total annual production of gas and liquids declined 35 percent, from 1580 million barrels of oil equivalent (MM boe) in 2006 to only 1159 million boe in 2015. Host governments and state‐owned national oil companies had grown reliant in their expectations for high returns and a steady stream of cash flow from royalties or dividends to fund public programs and other state initiatives. The oil and gas sector had become the proverbial cash cow.

But with fading production and massive investment requirements, host governments and national oil companies must take action. For example, liquids production from PDVSA has gone from 3.3 million barrels per day in 2008 (the year before the nationalization of its oil service companies) to only 2.7 million barrels per day (bpd) in 2015, an 18 percent decline. Venezuela's Maracaibo‐Falcon basin declined 35 percent from producing 1 million bpd in 2008 to 0.7 million bpd in 2015. Production from the enormous El Furrial field declined an extraordinary 51 percent in seven years from 408,000 bpd in 2008 to just 198,000 bpd in 2015. While production does typically decline in mature fields, this rate of decline is unusually severe.

Costs and Capital Efficiency

Most of the world's conventional fields are “mature” and the operational complexities of mature fields grow over time – this puts pressure on costs. We also see cost escalation driven by a rising tide of local content requirements, falling yard productivity (e.g., more rework), and in some cases, other factors such as regulatory requirements and higher complexity.

The case of UK offshore operators is not unusual – they experienced more than a threefold increase in development costs on a per barrel of oil equivalent (boe) over 10 years, while unit operating costs rose nearly fourfold. Meanwhile, production efficiency – how much is actually produced from production facilities compared to what would be produced if they operate without problems – has dropped over the same period from around 80 percent to less than 70 percent.13 The industry was able to withstand this decline in productivity and escalation in costs because oil prices nearly tripled over the same period. But now the economics of North Sea production are very challenging, with negative free cash flow in some fields, and often reliant on the benefits of a large installed base of infrastructure.

Project delays and overruns have damaged IOC reputations for operational excellence, and much of this comes from the way IOCs have managed uncertainty as projects have become more complex. The real project cost baselines and their uncertainties and risks are neither well estimated nor well managed. In the United Kingdom, five large projects accounted for about 30 percent of total spend, while smaller fields accounted for the rest. As field sizes become smaller, unit costs rise. Oil & Gas UK cited the average unit development cost for fields under consideration at £13.50/boe ($21.75), up from £4.00/boe ($6.44) on an inflation‐adjusted basis from 10 years earlier; the average unit operating cost year was £17.00/boe ($27.39), up from £4.50/boe ($7.25) 10 years earlier.14 As the unit cost rises, the economic life of many fields is shortened; more reserves are stranded as infrastructure is decommissioned earlier.

Technology and Expertise

Enterprise operating models now require a much wider set of critical capabilities to accommodate the growth and evolution of the industry's requisite capabilities – combinations of assets, technology, and expertise. For example, recent industry‐changing innovations include deep‐water and ultra‐deep‐water technologies, production technologies in the oil sands, 3D seismic acquisition and data processing, rotary steerable drilling, geo‐steering with logging‐while‐drilling, horizontal drilling coupled with multistage hydraulic fracturing, and a host of completions techniques for unconventionals involving greater use of water, proppant, and pressure (aka superfrac), longer laterals and more stages, sequencing variations (e.g., zipper frac), different proppants (e.g., ceramic), and more. Greater capabilities are required to enhance primary and tertiary recovery in shale gas and tight oil. Artificial lift for horizontal wells is an evolving science, and recovery is also managed through reservoir contact, in‐fill drilling, trade‐offs between lateral length frac height, stage spacing, and downspacing, and opportunities for refracturing.

Supply Chain and Services

Enterprise operating models also might be reoptimized to acknowledge the massive growth and evolution of the upstream supply chain for outsourced services – its size, potential roles, and available capabilities. The upstream supply chain has transformed the industry through functional and geographical unbundling. One fundamental trade‐off in this fractionalization is between the gains of capabilities specialization (and their utilization), versus the costs of coordination and oversight. Growth in the externalization of services has enabled greater utilization of specialized capabilities – combinations of assets, technology, and expertise – in novel ways. The future of the supply chain will be influenced by: (1) improvements in coordination technology that lower the cost of functional and geographical unbundling, (2) improvements in production technology that affect the benefits of specialization, (3) narrowing of wage gaps that reduces the benefit of offshoring, and (4) the price of oil.15

Fiscal and Regulatory Terms

We have seen a significant evolution in the structure, calibration, and fluidity of host government fiscal and regulatory regimes for natural resources, with immediate implications for enterprise operating models. Government receipts may include royalties, local and state taxes, corporate and special taxes, and direct participation or participation through an NOC. One result of all the competing objectives for fiscal and regulatory terms is that this has become an increasingly complex and specialized area, demanding specialized expertise both to navigate strategic choices and also to influence the competitive landscape.