The following article is part one in a three part series discussing upstream operating models.
A culmination of disruptive forces have conspired together to make the case for change in the upstream oil and gas industry – reasons to adopt a new, low-cost E&P operating model.
1. 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. The world needs ~60 million barrels per day of new production by 2040 and this must be sourced from an increasingly diverse, and expensive, resource base. There are choices between enhanced recovery from mature fields, new frontiers, deep-water and ultra-deep-water, unconventionals, and emerging but largely unproven sources, like the arctic, seabed methane hydrate, and carbonite reservoirs. The industry is pursuing higher cost, more technical/lower quality reservoirs, of heavy oil or harder to commercialize gas, and with more above-ground risk.
2. Disruption from the “Ripple Effect” of Unconventionals
Rapid growth in US onshore unconventional liquids production and high levels of natural gas production 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 many dimensions.
3. 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 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 2,000 conventional fields have their technical resources revised upward every year based more/better data, de-risking milestones, enhanced interpretation, etc. 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.
4. 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, 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. Many large NOCs, such as Mexico’s PEMEX and Venezuela’s PDVSA, also face fading production.
5. Costs & 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.
For example, UK offshore operators experienced a three-fold increase in development costs on a per barrel of oil equivalent (boe) over ten years, and unit operating costs rose even more. Production efficiency dropped over the same period from around 80 percent to less than 70 percent. As unit cost rises the economic life of fields is shortened; more reserves are stranded as infrastructure is decommissioned earlier.
6. New Technology and Expertise
Company operating models must be revised to accommodate the evolution of requisite capabilities – the combinations of assets, technology and expertise. For example, industry-changing innovation includes subsea-to-shore technologies, oil sands production, 3-D seismic acquisition and data processing, rotary steerable drilling, geo-steering with logging-while-drilling, horizontal drilling coupled with multi-stage hydraulic fracturing, and a host of completions techniques for unconventionals. 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 and downspacing, and exploring prospects for refracturing.
7. Supply Chain & Services
Company operating models must also be re-optimized to acknowledge the massive growth and evolution of the upstream supply chain for outsourced services – its size, potential roles, and available capabilities. The supply chain has transformed the industry through functional and geographical unbundling. One 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 will be influenced by: 1) improvements in coordination technology that lowers the cost of functional and geographical unbundling, 2) improvements in production technology that affects the benefits of specialization, 3) narrowing of wage gaps that reduces the benefit offshoring, and 4) the price of oil.
8. Fiscal & Regulatory Terms
E&P companies have seen major change in one of their biggest costs – the structure, calibration, and fluidity, of host government fiscal and regulatory regimes for natural resources, with immediate implications for their 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 expertise both to navigate strategic choices and to influence the competitive landscape.
Neither R/T nor PSC regimes necessarily dictate a high or low government take, but PSCs tend to be more “progressive” and progressive terms are especially important in a low price environment – progressive structures are those which vary with prices or profits, such as taxes and profit sharing. Regressive structures are those that are fixed and not linked to prices or profitability, such as royalties, export duties, and domestic market obligations (DMOs). Fiscal regimes (and resource bid rounds) seek to strike a balance between encouraging direct investment and the need for an attractive and politically saleable government take, and a growing interest in methods to promote local economic development. Similarly, regulatory frameworks seek to increase innovation and competition, while also ensuring safety and environmental concerns, but must avoid becoming overly burdensome or expensive.
9. Social License & Environmental Costs
E&P companies need a much greater capability to support and promote their social license to operate than ever before. Regardless of one’s views on climate change and the host of other environmental issues and concerns that can affect the industry, the inarguable truth is that environmental issues have grown to become an extraordinary force for the E&P sector, manifesting in an extremely wide range of business costs and challenges. These include increased capital expenditures and higher operating costs to meet the rise of regulatory requirements, project delays, and lower wellhead prices due to constraints in take-away capacity, restricted access to Federal lands and waters, and bans on hydraulic fracturing or working in certain areas. One study by the Fraser Institute estimates that delays in pipeline projects cost several billion dollars per year.
10. Weak Oil & Gas Prices
Under even the most optimistic outlook for oil and gas prices over the next several years, upstream oil and gas companies need a new operating model now more than ever. North American natural gas prices had been low since 2009, under surging supply from the boom in domestic shale gas production. But now we see the same story playing out in global liquids.
Conclusions – What Now?
The E&P context has changed and while on their own any one of these changes might be quite manageable, in aggregate it demands a bold new approach and a low-cost E&P operating model. However, beyond incremental changes, there have been few efforts to re-design and transform operating models on a systematic or enterprise-wide basis, other than post-merger integrations.
The upstream oil and gas sector has been focused on cost and productivity for several years and has made significant gains, but operating cash flows remain insufficient to cover costs, let alone the needs of the future, or to provide an adequate return on the capital employed. And many of the gains thus far will not be sustainable over a full cycle – the “low-hanging fruit” was taken but there is much more work to do.
Now is the time to “cut costs while growing stronger” – by investing in a company’s most important organizational capabilities and leveraging the capabilities of others where it makes sense to do so.
Read more insightful analysis from Justin here