The-IHS-EP-Investment-Guide-2013.pdf

The E&P Investment

Guide (2013): A Private Capital Guide

June 2013

Strategic Advisory & Transaction

Support

Kurt Barrow Vice President +1 832 209 4454 [email protected] Bob Fryklund Vice President & Chief E&P Strategist +1 713 369 0317 [email protected] Justin Pettit Vice President +1 212 850 8552 [email protected]

The authors gratefully acknowledge the contributions of Andy Byrne, Darryl Rogers, plus countless others too many to list from across the entire IHS research organization; however, any errors or omissions remain entirely our own. The views expressed herein are solely those of the authors.

mailto:[email protected]



THE E&P INVESTMENT GUIDE (2013): A PRIVATE CAPITAL GUIDE

2

Contents

Executive Summary .........................................................................3

Impact of the Unconventionals Revolution .......................................3

Reshaping of the E&P Landscape .............................................. 3

Trends that Create Investible Discontinuities .............................. 5

Deal Flow: Where the Capital is Going ............................................6

Global Outlook .................................................................................7

World Economy ........................................................................... 7

Fiscal/Regulatory Context ........................................................... 8

Liquids Supply & Demand ........................................................... 8

Global Tight Oil ........................................................................... 8

Global Shale & Coal Bed Methane (CBM) .................................. 9

North America Outlook.....................................................................9

North American Economy ........................................................... 9

Fiscal/Regulatory Context ........................................................... 9

Environment & Water ................................................................ 11

Liquids Supply & Demand ......................................................... 12

North America Infrastructure ..................................................... 13

E&P Companies ............................................................................ 14

Upstream Strategy and E&P “Hotspots” .................................... 14

North American Unconventionals Plays .................................... 15

Technology & Innovation ........................................................... 17

Upstream Spend ....................................................................... 18

Upstream Capital Costs ................................................................. 18

Conclusions ................................................................................... 19

How We Can Help ......................................................................... 19


3

Executive Summary

The energy sector has been one of the few bright spots in the global economy over the past five years, and it has grown so large that it is impossible to ignore – by many measures, we are on the dawn of a N.A. energy renaissance with implications that will carry through the energy supply chain into manufacturing. We acknowledge the many challenges for E&P investment – beyond the traditional sub-surface risks that always present difficulties – including:

A glut of N.A. gas supply, which has created a much lower price environment for N.A. gas,

A shortage of mid-continent liquids take-away capacity, with these bottlenecks leading to relatively weak crude prices, and

A frenzy of investment activity in the sector – both organic and M&A – has led to some relatively high transaction prices

Notwithstanding, the same trends and discontinuities behind these challenges create windows of opportunity – in both public and private markets, and at both the company and project level. Not only is the N.A. upstream still an attractive sector for investment, but also several current trends lead to actionable investment theses. We outline some potential examples in liquids, gas, and the supply chain technology and services. Impact of North American Unconventionals

Unconventionals Revolution is Creating Discontinuities through the World

Source: IHS

Impact of the Unconventionals Revolution Reshaping of the E&P Landscape

The rapid rise in unconventionals is driving a revival in North America’s energy landscape and a renaissance in manufacturing and the U.S. economy. The shale gas/tight oil revolution has spawned a great revival in North America’s domestic E&P sector, with its effects felt throughout the world.

HH

The energy sector has been one of the few bright spots in the global economy and has grown too large to ignore The same trends and discontinuities that create challenges also create windows of opportunity – in both public and private markets, and at both the company and project level


4

In terms of production, North American shale has added 10 bcf/d in the last five years and tight oil reservoirs have added more than 2mmb/d. In terms of domestic reserves, North American tight oil offers the potential for over 45 billion bbl. of commercial oil and Natural Gas Liquids (NGLs) at $90 per barrel. This has greatly reduced U.S. dependence on imports (especially non-Canadian imports) and helped to revive the U.S. economy. Surging N.A. production has the potential to displace foreign imports from Venezuela and the Middle East. The success of unconventionals in natural gas created oversupply and weak gas pricing, which in turn caused many companies to shift toward liquids-rich unconventional plays. The large capital needs have created major shifts in portfolios and capital investment. Many independents have abandoned work offshore or internationally, making them more vulnerable to U.S. policy and politics – import/export, endangered species, and environmental concerns. Historical North American Crude Oil Flows

N.A. Production Could Marginalize Venezuelan & Middle Eastern Imports

Source: IHS

This does not mean that regulatory intervention will kill the renaissance, but the scale and footprint of the growth in unconventionals has created growing pains that have led to an increase in regulatory intervention. A battle over responsibility is taking place between states and the federal government and environmental groups are exploiting this tension. Calls for new regulations have put the industry on defense after a stunning rise – noise and debate continues. Financing this revival has required tremendous internal and external sources of capital – more than $250 billion in foreign investment. Opportunities abound in the more niche plays, as well as in infrastructure, services, technology and compliance, as well as in the downstream refining and petrochemicals industries. The independents once dominated unconventionals – independents drilled 95% of the North American wells and discovered all of the unconventional plays to date. Independents leveraged their entrepreneurial spirit, greater tolerance for risk, and organizational nimbleness, to set the pace for the unconventional revolution. But the majors have entered and consolidation is coming. Three of the industry’s early pioneers have already been acquired (Mitchell, PetroHawk

North American shale has added production of 10 bcf/d in the last five years; tight oil has added more than 2mmb/d North American tight oil reserves offer the potential for over 45 billion bbl. of commercial oil and Natural Gas Liquids (NGLs) at $90 per barrel We have already used more than $250 billion of foreign investment to finance this

revival


5

and Henry). The majors and large North American independents have been acquiring positions with hopes of riding the development wave and resource-harvesting phase. They plan to leverage their size, financial strength and project management skills. The big five plays are entering a more mature phase where efficiency, performance and costs dominate. Consolidation and growth in relevant scale have historically been the means to achieve this end. The role of private lands has been an important element in the rise of unconventionals. One of the main reasons for success was the access to land; most of the drilling has been on private land, not federal land, which is more heavily regulated. Considerable discussion still rages over the merits of opening more public land infrastructure – the extensive North American network was undersized for the size and pace of growth. The lack of steady investment to maintain and upgrade pipelines and refineries has impaired the industry’s growth and development. This is further emphasised by the public’s reluctance to support infrastructure development. Trends that Create Investible Discontinuities

The North American energy landscape is in the throes of sweeping change amidst the confluence of several key trends – trends that create investible discontinuities – including the following:

Exploration is very dynamic due to the large number of, and wide range in, unconventional geologic basins in Canada and the Lower-48 states, plus continuously evolving drilling and completion technologies,

This has produced a glut in domestic natural gas supply which supports a chronic North America price discount on an energy equivalent basis,

Weak gas prices have caused the E&P sector to shift toward liquids and liquids-rich plays; this is, in turn, causing rapid growth in Natural Gas Liquids (NGLs) supply,

Weak gas prices plus the need for debt reduction have forced gas-weighted operators to find ways to reduce costs and increase efficiency,

Cash flow is problematic everywhere – capital requirements are well beyond cash flow generation for all but the very largest E&P operators,

Demand for well completions will continue to be strong, including key components such as proppant and completion fluids, well casing, tubing, and drill pipe, etc.,

There is increased scrutiny and regulation of hydraulic fracturing and the unconventionals “footprint” (e.g. water withdrawals, community “boom town impacts”, noise, aesthetics, etc.),

Growing midcontinent liquids supply needs to be connected with demand but take-away capacity is constrained; many debottlenecking projects (new pipeline and pipeline conversions) are in development or underway,

An unbundling in ownership of the previously integrated crude oil and refined products value chain has spawned a new, innovative, independent storage and terminal industry; refined product exports are growing, and

Expanding tight oil and associated NGL production continues to create very attractive feedstocks for refiners and petrochemical producers; a N.A. petrochemical manufacturing renaissance is underway.

Access to private lands has been a key in the rapid exploitation of unconventionals, as well as geology, technology, hydrocarbon prices, ready infrastructure, local expertise, and supply chain availability These trends will re-shape the N.A. energy sector


6

Deal Flow: Where the Capital is Going Many large, established financial sponsors have traditionally avoided the energy sector. But now it is either too large, or too attractive, to avoid. Initial forays into the sector have been generally in segments with no sub-surface risk (i.e. geology) – such as pipelines, barges and other infrastructure, upstream consumables, and maintenance, inspection and testing, or other services. Buyers of U.S. Refinery Capacity (1990-2012) A Surge in Independent Ownership As the Value Chain Unbundles

More independent buyers of refining capacity reveals a sector trend away from integrated value chain ownership. An unbundling of the crude oil and refined product value chain has led to the rise of a more innovative, independent storage and terminalling industry – including considerable participation by financial sponsors – now enjoying greater U.S. refined product export. We are also seeing sponsors move into core areas, which may include sub-surface risk – both at the company and the asset level.

Access to capital for many operators is always challenging and weak gas prices have only made matters worse. The capital requirements for both oil- and gas-weighted portfolios often exceed operating cash flow. This need for capital has helped drive a spike in transaction volume and implied reserve values. Weighted average implied proved reserve (U.S. “1P”) values are roughly $13-$14/boe for both corporate and asset deals. Oil-weighted deals are trading at roughly $15/boe, but gas-weighted deals are closer to $8/boe. Canadian 1P deals tend to trade higher than U.S. deals due to a higher accounting standard for proven reserves, while Canadian 2P (proven + probable) deals will tend to trade slightly lower, due to the expanded definition of reserves. Despite generally high prices, strategic buyers remain focused on liquids-rich plays. Financial sponsors tend to be more interested in “value” than “momentum” and so they are also looking at contrarian gas plays where available. In some cases, the ability to participate in contrarian plays has been limited by deal-flow. In terms of deal structure, new exploration ventures with sub-surface risk are frequently nothing more than a management team backed by a line of equity. However, traditional buyout, growth capital, mezzanine and distressed deals are being done for producing assets, as well as in infrastructure, consumables, services, and the midstream/downstream. Numerous Japanese, Chinese and other Asian investors are aggressively pursuing JVs, stakes, and buy-outs, for entry to the N.A. upstream sector.

0

500

1,000

1,500

2,000

2,500

3,000

19

90

19

92

19

94

19

96

19

98

20

00

20

02

20

04

20

06

20

08

20

10

20

12

Buyers of U.S. Refinery Capacity

Private Equity

Emerging

MNC

NOC

Regional Player

Small/Specialty

Thousand Barrels per Day

Source: IHS

Financial sponsors traditionally avoided the sector, but now it is either too large, or too attractive, to avoid Weak gas prices have made cash flow an issue, but capital requirements for both oil- and gas-weighted portfolios often exceed operating cash flow


7

Global Outlook World Economy

The global economy is stabilizing and growth is returning, although we expect Western Europe and Japan to remain sluggish and even China has shown signs of slowing. After a two-year slowdown, global growth is settling near 2.5% (see below). The stage is set—through monetary stimulus and de-leveraging—for a modest acceleration in the world economy through 2014. Although global economic growth is stabilizing near 2.5% annually, this is an average – effectively “one hand in the fire and one hand in the freezer” – with advanced economy growth closer to 1% (near zero for Western Europe and Japan) and growth in emerging markets closer to 5%. World Real GDP Outlook

World GDP Slowly Rebounding from Negative Growth in 2009

Source: IHS

Stagnation in the Eurozone and Japan will impair U.S. export growth. The Eurozone will struggle with weak growth and sovereign-debt problems. Market reforms and closer integration will be the steps toward a permanent solution. Growth will depend increasingly on domestic demand rather than exports – global economic recovery will be powered by underlying growth in the emerging economies. Latin America and Africa will do well by historical standards but Asia (excl. Japan) will lead global growth. BRIC country GDP growth continues to lead investment and consumption. We project China (China is slowing but has averted a hard landing) and India annual growth at 5-10%, and Brazil and Russia just below 5%. Their combination of size and high rates of growth continue to make these countries important growth drivers for the world economy. Moreover, not only will they drive world GDP growth, but also they will become an increasingly larger part of the global economy. China and India will account for more than 21% of the world’s fixed capital expenditure in 2013-17. The greatest risk to our economic outlook is any deterioration in EMEA-based risks – geopolitics and policy mistakes will be the main sources of risk, especially with regard to the Middle East, Africa and North Korea.

The stage is set—through monetary stimulus and de-leveraging—for a modest acceleration in the world economy through 2014 Growth will depend increasingly on domestic demand rather than exports – global growth will be powered by the emerging economies


8

Fiscal/Regulatory Context

Host governments will need to rethink fiscal terms against the world map of opportunity in order to remain competitive – especially with new sources of unconventional oil and gas. There are signs of loosening terms for some assets in established areas such as Algeria, Trinidad and Tobago and Russia (oil only), while in emerging provinces host governments are seeking appropriate governance arrangements, fiscal structures, and local content terms. For investors, this implies a wider set of choices to make when deciding where to play. Investment delays are a likely consequence of regulatory reviews (e.g. Nigeria) to the benefit of provinces where regulatory terms have been finalized. Governments in emerging frontiers are increasingly demanding greater local content within the sector – through NOC participation, local sourcing, and local employment. This carries cost, quality and timing implications for investors as well as an emerging source of competition for service companies. Liquids Supply & Demand

On the supply side, world oil markets will grow at more than 1 million b/d annually with OPEC having a slightly smaller, but important, role. Increases in North American tight oil, Caspian production, and other non-OPEC traditional production, will cause an increase in OPEC spare capacity – most of which resides in Saudi Arabia. Regardless of America’s growing independence, we do expect OPEC cohesion (and influence) to increase should prices fall significantly – as we have seen in the past. World Liquids Production Growth Growth in World Liquids Production (2008-2012)

Source: IHS

After recession-led demand destruction in 2008-2009, global demand rebounded but slowed again with economic uncertainty in 2011-2012. Our outlook is for moderately higher growth in the next few years as the global economy accelerates. Longer-term, we expect demand growth of 1-1.5% annually, largely based on the emerging markets and the transportation sector. Global Tight Oil

Global technically recoverable tight oil resources could be hundreds of billions of barrels. There are many hurdles to commercial development outside North America and it is early days to predict full commercial potential. However, with

Host governments will need to rethink fiscal terms to remain competitive against world opportunity World oil markets will grow at more than 1 million b/d annually with OPEC having a slightly smaller, but important, role; non-OPEC growth will increase OPEC spare capacity in the Kingdom


9

the right mix of government policy, fiscal terms and regulatory measures, tight oil could become a tremendous element of energy supply in many parts of the world. Our studies found some 150 prospective tight oil areas outside North America. Initial screening suggests promising areas that include Argentina, Western Europe, North Africa, Middle East, Russia, China and Indonesia. Nevertheless, the geology is different from North America, and will require considerable effort to understand fully. Thus, it is likely that development in these other parts of the world will be many years behind North America due to appraisal timelines, a significantly less mature infrastructure and supply chain, and uncertainty in the political, fiscal and regulatory regimes. Global Shale & Coal Bed Methane (CBM)

Based on our study of 440 global shale gas and CBM plays outside North America, we estimate these areas alone contain about 1,300 Tcf to contribute to production, on a risked technical/commercial basis. Our study shows production from shale and CBM could build during the 2020s and peak in the 2030s. Potential supplies from shale and CBM just in the areas studied are projected to reach some 80 Bcf/d (800 Bcm/yr.) by the 2030s. Our study included plays in Europe, China, Indonesia, South America, India and Australia. Further major contributions are possible from other geographies – including Russia and North Africa – as well as from tight gas. Some of the countries that need new gas supplies the most do have large shale potential (China is a good example); however, others such as India, do not. Outside of North America, exploitation of shale gas and CBM is still in its infancy. Our “shale gale” was enabled by an ideal set of aboveground conditions (not just technology), that are rarely all present globally. Successful growth of shale and CBM globally will require close management of above ground issues, and not just the transfer of technical expertise. Critical above ground factors governing the pace and scale of growth include land access, regulations, supply chain capability, and infrastructure.

North America Outlook North American Economy

We expect the U.S. economic recovery to advance slowly but reach 3% annual GDP growth by 2015. We see the U.S. economic recovery slowing somewhat in 2013, due to fiscal tightening, but housing starts and vehicle sales will remain strong. The U.S. economic recovery is also buoyed by a renaissance of the domestic energy sector, due to rising oil production. Surging sources of domestic supply are creating ripple effects of spend and investment throughout our economy. Canada’s economic growth slipped below 2% in 2012, due to weakness in U.S. and European export markets. Canada ranks fourth in the world in terms of expected real gross output growth (oil & gas) for 2013-17. Fiscal/Regulatory Context

U.S. onshore development is pressing ahead but within an evolving regulatory context. Certainly, Canada and the U.S. offer two of the most favorable investment climates in terms of country risk, but politics, policy and regulatory forces have not been favorable under the current U.S. Administration. For example, beyond the obvious example of the delayed Keystone XL pipeline, the U.S. government has turned to the Endangered Species Act (ESA) as

Our studies found 150 prospective tight oil areas outside N.A., including Argentina, W. Europe, N. Africa, Middle East, Russia, China and Indonesia; development time will be many years behind N.A. U.S. economic recovery is buoyed by rising oil production and a renaissance of the domestic energy/ petrochemical sector


10

another lever to invoke a “green agenda” with more than 17 new species added to the list. Many of these new species, such as the lesser sage grouse and the prairie chicken, will put entire plays off limits. While the industry has thus far been able to work within these constraints, by working with states and landowners, these efforts are costly and image damaging. Private mineral rights are a unique and critical element in the U.S. and provide the right conditions for deals regarding land access – from pre-exploration seismic work right through to field development, drilling and enhanced recovery. Mineral rights holders are frequently the surface right owners in the U.S., so landowners have both the incentive and the authority to grant access – for exploration and production. In jurisdictions with state-held mineral rights, land access is a difficult political decision for a footprint that will include a multi acre-drilling pad, flaring of gas, new roads, and significant traffic. Privately held rights help to ensure some level of stakeholder support for development – this support has not happened on a large scale in Europe – and development has stalled. The federal onshore project “take” is 12.5%, while the offshore development take ranges from 12.5% to 16.67%. There is consideration underway to raising the royalty rate on onshore drilling on federal lands to 18.75%, in an effort to boost federal revenues, to offset reduced rental fees and declining federal land production. Despite changes in the royalty regime, there has been no evidence to suggest an adverse impact on leasing acreage. However, some have speculated that any reduction in fiscal incentives could adversely affect U.S. unconventional projects. Meanwhile the Alaska state government has twice enacted increases in its royalty rate – most recently in 2007 – to 25%. Alaskan production has been in decline and there has been little new activity due to low gas prices and the pressure of environmental groups on federal lands. A revamp of the U.S. Tax Code was promised after the 2012 election and could get underway in 2013. There is speculation that changes will include the removal of the deduction for intangible drilling costs (costs currently include hydraulic fracturing in shale gas projects) along with other benefits such as percentage depletion for oil and gas wells and availability of the domestic manufacturing credit to oil companies. Natural Resources Canada is responsible for policy at the federal level and uses this charge to advance a strong, centrally coordinated, vision for the entire energy sector in Canada. The ministry is responsible for creating environmental policy and managing natural resources, including forests and wildlife, for the social and the economic well-being of Canadians. This mandate creates a strong commercial interest and relatively business-savvy environment. A new Canadian Environmental Assessment Act was created in 2012 (replacing an Act of the same name from 1992), with the aim of simplifying the federal assessment procedure. The National Energy Board (NEB) regulates the construction and operation of inter- provincial and international oil and gas pipelines, exportation and importation of oil and gas, and frontier oil activities. The relevant provincial authority is responsible for awarding oil and gas leases. Royalty rates and contractually granted exploration periods vary widely from province to province and between different types of licenses and fuel types. Alberta had approved an increase in royalty rates for oil, natural gas and oil sands production, but the economic downturn caused it to delay full implementation of this royalty increase. In addition to royalties, energy companies are also subject to federal and provincial income tax on profits from production. The general corporate tax rate is 38% but companies are also

Private mineral rights are a unique and critical element in the U.S. and provide the right conditions for deals regarding land access – from pre-exploration seismic work right through to field development, drilling and enhanced recovery Natural Resources Canada advances a centrally coordinated vision for the entire energy sector; their mandate creates a strong commercial interest and business-savvy environment


11

subject to provincial income taxes – the rates of provincial corporate tax vary from province to province. Exploration and operating expenditure is expensed for federal and provincial income tax across the provinces and other deductions are available. The provincial government of British Columbia proposed the idea of a major new tax on the impending export of natural gas – if imposed it would affect cost projections and render some projects unviable. Environment & Water

The dramatic surge in activity related to on-shore unconventional oil and gas production in in North America has led to increased scrutiny regarding the operational impact on local environments, water resources, and communities. Well Construct Multiple Layers of Casing, and Great Distance, Separate Aquifer & Production

There are many legal and regulatory issues associated with production from unconventional resources, including the impact of hydraulic fracturing on drinking water, the development of fracturing waste standards, permitting guidance on underground injection, disclosure of chemicals used, and regulations for fracturing on public lands. Hydraulic fracturing has become a popular news item and we have witnessed public debate on fracturing fluids allegedly contaminating aquifers. Current well construction requirements consist of installing multiple layers of protective steel casing and cement designed to protect fresh water aquifers. Water contamination is also unlikely given the great distance between the producing zone and most aquifers. Unrelated to fracking, cement or casing issues near the aquifer could lead to problems; however, hydraulic fracturing remains the subject of controversy with graphic images of flaming tap water the centerpiece of protest. The Environmental Protection Agency (EPA) has issued guidance stating that no company may frack with diesel in the mixture, without a permit. The EPA plans to propose a rulemaking for Shale Gas Extraction in 2014. Operators have begun to test drinking water wells prior to fracking to provide a baseline and have warned that onerous regulation will limit development. However, tighter regulation is expected. New York State suspended hydraulic fracturing, pending further study, placing a considerable portion of the Marcellus off limits.

Source: IHS

The dramatic surge in activity related to on-shore unconventional oil and gas production has led to increased scrutiny regarding the operational impact on local environments, water resources, and communities Most new rules and regulations are simply codifying industry best practices and are not expected to present a significant hurdle to continuing future development


12

Across the U.S., new rules and regulations governing development have been emerging. Most new rules seem to be codifying industry best practices, and are not expected to present a significant hurdle to continuing future development. E&P companies are taking a more proactive and integrated approach to environmental and stakeholder management, engaging local communities early and often, embracing transparency, and taking a life cycle approach to minimizing and mitigating impacts. However, the industry remains vulnerable to operators with low standards and the risk that this could bring burdensome or over-prescriptive regulation. The oil sands present Canadian politicians with a conflict of interest – on one hand the oil sands boost declining conventional production, and on the other hand, the oil sands create major concerns over GHG emissions. Canada’s historic withdrawal from the Kyoto Protocol suggests that the balance is in favour of economic development, but this in turn affects producers’ environmental reputation and may cast the industry in a negative light. Liquids Supply & Demand

North American Crude Oil Balance U.S. Production Reaches 8 mmb/d by 2019

Source: IHS

Our study of N.A. unconventionals identified the potential for over 90 billion bbls of commercially recoverable liquids (oil and NGL) at break-evens of less than $90 per bbl. This could grow through the addition of reservoirs in existing plays and has potential to yield some five mmb/d of tight oil by the early 2020s. Local crude oil and NGL production will displace imported sources, though the scale of demand means that complete independence is unlikely. Nevertheless, the historical North American crude oil import pattern will shift as growing domestic production marginalizes imports from Venezuela and the Middle East. While refiners scrabble to process the changing crude quality resulting from the tight oil boom, crude price discounts (relative to international) and low cost gas for fuel and hydrogen production is creating a competitive advantage for U.S. refiners. One example of this is the rise of Gulf Coast refined product exports that now totals more than 1 million B/D.

The industry remains vulnerable to operators with low standards and the risk that this could bring burdensome or over-prescriptive regulation Our study of N.A. unconventionals identified potential for over 90 billion bbls of commercially recoverable liquids (oil and NGL) at break-evens of less than $90/bbl. Shale resources are almost doubling the U.S. natural gas resource base, which had not

changed in years


13

Shale resources are almost doubling the U.S. natural gas resource base, which had not changed in years. The cost basis for this unconventional natural gas resource brings tremendous supply on-stream at $4-6 per Mcf, which will keep prices bound in that range. Surplus gas production from the “shale gale” has already precipitated a N.A. gas price collapse but production was slow to fall due to increases in well productivity and the production growth of associated gas. Associated gas is could grow to 30 Bcf/d over the next decade. North American liquefaction is one way to exploit the natural gas price arbitrage (versus rest of world). Within a few years, projects to export LNG into Asian markets will come online. The U.S. has long been a prime destination for Canadian oil and gas exports. U.S. unconventional production boom will over time result in a reduction of gas from Canada and new markets will be required. Another route to exploit the natural gas price arbitrage (versus other fuels on an energy equivalent basis) is through the continued displacement of coal in power generation, and through new applications in transportation, such as a substitute for bunker fuel in marine shipping, or diesel in rail and long haul trucking. North America Infrastructure

Domestic production overflow of light, sweet crude into high-cost transportation modes (e.g. barge, rail) has created a bottleneck in take-away capacity and led to significant price discounts beyond WTI Cushing. North American Crude Oil Pipeline Projects

Seventeen New Pipeline Projects plus Three Conversions

Source: IHS

The Keystone XL pipeline (connecting Alberta to the Gulf refining hub) – postponed until late summer 2013 – is not the only project. We have identified at least 20 new crude oil pipeline projects, including at least 3 conversions and 17 new pipelines, with capacity of more than six million barrels per day and length of 9,500 miles. In the near- to mid-term, these infrastructure bottlenecks and price differentials will ameliorate as the pipeline landscape evolves.

Infrastructure bottlenecks and price differentials will ameliorate. The Keystone XL is important, but not the only pipeline project. We track more than 20 new crude pipeline projects – including 3 conversions and 17 new pipelines – with capacity of more than six million barrels per day, and length of 9,500 miles


14

The outlook for Canada hinges on improved take-away capacity to the West, South and East. Canadian oil sands production has the potential to double in the next few years, but take away capacity must grow. If Canada diversifies its into Asian markets this will ease bottlenecks but there will be competition from Australia and the Middle East. Our pipeline infrastructure is dated and capital investment is needed both to upgrade and to grow installed throughput. We anticipate pricing for light sweet crude will evolve to pipeline netbacks in the near to medium term, as new pipeline projects push the bottleneck increasingly Northward. Debottlenecking between Cushing and the Gulf Coast will affect all crudes moving through the midcontinent corridor, price-linked to the WTI.

E&P Companies Upstream companies are repositioning their portfolios in response to the new map of oil and gas opportunities. New portfolio choices have arisen from the wave of shale gas and tight oil opportunities in North America, plus the opening of new oil & gas frontiers in East Africa, the Eastern Mediterranean and the Arctic. While some U.S. companies are returning home, others remain in international frontiers facing new challenges, risks and requisite capabilities. Upstream Strategy and E&P “Hotspots”

Our research reveals a wide diversity of upstream opportunity types even in mature provinces. Certain themes – such as vertical integration – appear common in many areas. For example, monetization of heavy oil in Colombia could be enhanced if disparate reserves could be aggregated (unitization) and their development integrated with the new processing facilities (particularly diluents), and infrastructure. Another example is Myanmar (aka Burma), where participation in the full value chain from offshore production through to power generation or export is an emerging possibility. While S.E. Asia is one of the older oil and gas regions, there remains a rich diversity of opportunity types, from mature oil to high-risk frontier gas. These opportunities appear suited to small or midsized payers, as well as the existing majors. For example, in Indonesia there is growing gas demand but declining production. However, new frontier and shale gas potential creates opportunity for exploitation and repurposing existing export-oriented LNG plants, to serve markets within the archipelago. International Frontiers Seismic Acquisition Activity (2012-2013 excl. N.A.)

E&P hotspots do not arise at random – we have identified the leading indicators of future hotspots. These include rethinking the geology, spotting analogues, and identifying potential changes in the political, security or fiscal environment, as well as technology advances. The chart (see left) highlights recent international seismic Source: IHS EDIN Database

Light sweet crude oil prices will evolve to pipeline netbacks in the near to medium term, as pipeline projects push the bottleneck Northward. Debottlenecking between the Gulf Coast and Cushing will affect all crudes that move through the midcontinent corridor E&P hotspots arise from rethinking the geology, spotting analogues, and identifying potential changes in the political, security or fiscal environment, as well as technology

advances


15

acquisition activity. While deep water has been a focus for exploration in recent years, our top five projected future E&P hot spots are all in onshore or shallow water areas. The key regions for future upstream activity include Central and Northern Africa, Eastern Latin America, and the Caribbean. For example, we outline potential future hotspots below. International E&P Hotspots

Anticipated Future E&P Hotspots & their Drivers

Region Drivers U.S. (GOM)

Opening of offshore acreage, though GOM data indicates shallow waters are gassy

Guyana/Suriname Basin ranked by the U.S. Geological Survey as second most attractive under-explored basin, some in shallow water. Deep water is driven by the 800MMBO Zaedyus discovery

Brazil (onshore)

Offering 289 blocks in 11 basins, 68K sq. km onshore and 87K sq. km offshore

Bolivia (onshore)

Tax credits and developing marginal fields increased steady activity levels

Peru (onshore)

Infrastructure development in remote areas and upcoming 27 onshore blocks; mid-sized heavy oil discoveries in the jungle (Buena Vista, Raya, and Delfin) to develop after Block 67

Libya (onshore)

Driven by changes to fiscal contract terms and newer technology

Kenya/East Africa Kenya/East Africa is driven by analogues from Mozambique and Tanzania gas plays

Angola (Kwanza pre-salt)

Onshore and shallow water is driven by analogues from Brazil pre-salt; pre-salt onshore acreage license blocks to be released in late 2013; offshore Kwanza-Benguela and Namibe basins contain pre-salt blocks in the shelf areas

Myanmar/ Burma

Driven by both a re-thinking of the geology and political change

Source: IHS

A country’s resource endowment, stage of resource exploitation maturity, and petroleum sector governance model, shape the most effective commercial tactics for accessing its resources. Successful access tactics will enable further growth efforts that match the host country needs. Oil company business developers construct commercial approaches that align with country needs, not only to compete for entry, but also to establish a core area beyond the initial assets. Joint ventures between IOCs and NOCs are becoming ever more popular growth vehicles. Recent major joint ventures in Russia and China are good examples of how IOCs can access new, large-scale growth opportunities. E&P companies’ success in tapping these markets depends increasingly on having the span of capabilities and depth of expertise that convince host governments to select the company as a joint venture partner. North American Unconventionals Plays

Although initially on the sidelines, major oil companies are now very active in the key shale gas and tight oil plays. We outline some of the key positions in the major plays in the table below. Investment will continue at high levels in order to

Joint ventures (often between IOCs and NOCs) are becoming ever more popular vehicles for growth and access

Although initially on the sidelines, major oil companies are now very active in the key shale gas

and tight oil plays


16

develop these resources. EOG is a key player in the Eagle Ford Shale and will drill 400 net wells in the play this year. At this rate of drilling, EOG has a 12-year Eagle Ford drilling inventory. Range Resources is a leader in the Marcellus – the play will consume 80% of this year’s $1.3 billion CAPEX budget. With 6,750 Marcellus locations in South Western PA alone, we estimate the company’s drilling inventory at over 30 years. Pioneer Natural Resources has 40,000 drilling locations identified on its Permian acreage. In the Southern Wolfcamp, for example, they have 5,600 locations identified, or over 40 years of drilling (after already entering a JV). Unconventional Play Holdings by Major

The Majors Have Entered the Fray

Source: IHS

However, access to capital is still challenging. Weak gas prices have made cash flow an issue for many, as gas-weighted operators continue to look for ways to reduce costs and increase performance. This situation has been exacerbated as their forward gas price hedges roll off. Moreover, for both oil and gas portfolios, the capital requirements of all but the largest operators, exceed operating cash flow by a wide margin. In addition, even leading players in the best plays could benefit from more capital to accelerate drilling and increase well inventory NPV. Finally, many operators also need to reduce debt. This need for capital has spurred deal flow and caused transaction prices and implied reserve values to spike in the North Central and Gulf Coast regions – the top plays are commanding top dollar. The most recent prices paid for deals in the top three tight liquids plays are averaging about $24,000 per acre. Acreage prices for these plays (Eagle Ford $33,456/acre, Permian $20,500/acre, Bakken $17,900/acre) are at or near all-time highs, and running 200-300% of their 3-year average. The Eagle Ford and Bakken are mature plays that are relatively de-risked, and therefore relatively expensive. However, Permian well results have been more variable and are not as de-risked. The Granite Wash and Utica are large, wet gas plays ($10,000/acre) attracting interest.

The need for capital has spurred deal flow and caused transaction prices and implied reserve values to spike in the North Central and Gulf Coast regions – the top plays are commanding top dollar Acreage remains considerably less expensive for the emerging U.S. and top Canadian liquids plays because they have not been as de-risked as the more mature plays, in terms of well data regarding sub-

surface risk


17

Acreage remains considerably less expensive for the emerging U.S. liquids plays and top Canadian liquids plays because they have not been as de-risked as the more mature plays, in terms of well data regarding sub-surface risk. Emerging U.S. tight liquids like the Mississippian and Tuscaloosa Marine are oily plays that are less de-risked and have more sub-surface risk – more exploration and experimentation is still underway. Acreage in the Mississippian is averaging $2,400/acre while the Tuscaloosa is averaging only $225/acre. The Tuscaloosa is LA light sweet crude quality, but initial wells were not successful. But recent efforts by EnCana are promising. Nevertheless, it is much deeper than the Eagle Ford, and therefore, it will be more expensive to produce. Canadian tight liquids plays are relatively inexpensive on an acreage basis because they are wet gas plays – akin to the Granite Wash. Based on our research, project economics and “size of the prize” make the Duvernay one of our top picks in North America. And of course, given our outlook for gas prices, deal flow and price are down dramatically for gas-weighted deals. Shale gas acreage has plummeted. Recent prices paid for deals in the top shale gas plays are averaging $6,500 per acre and are well off their record highs (Woodford $9,845/acre, Marcellus $8,430 acre, Barnett $1,460/acre). The Marcellus and Barnett are at roughly 50% of their highs, while the Woodford is 28% of its high. Technology & Innovation

Technology leadership really matters. We examined the impact of technology on Finding & Development (F&D) costs for the case of the U.S. Gulf of Mexico (GOM), as a unique but important illustration. Over a 16-year period, several key technologies enabled a decline in F&D costs per boe while input costs rose, even as E&P companies moved into more challenging plays in deeper water. Technology and innovation can also enable reserve growth to outpace exploration finds. Past research showed that when exploration added about 10 billion barrels per year, reserves growth almost doubled this. A wide range of technologies spanning digital, imaging, EOR, drilling / multi-stage fracking and engineering collectively have considerable potential to extend this trend. Oil companies are now seeking to better align their research and technology strategies with their overall business strategies. They are also bringing corporate development into this mix – they are diversifying their innovation portfolios to include open innovation initiatives and venture funding. And they are raising organic spend rates in an attempt to develop proprietary technologies that will help to establish a sustainable competitive advantage. With ever-larger projects and a growing emphasis on safety and efficiency, the need for integration across functional groups and segments of the value chain is growing. Our research demonstrates that such integration can be achieved through new field development and operating practices that tie together real-time data, virtually co-located personnel, more advanced analytical tools and models - a concept that we refer to as the digital oil field of the future. Upstream innovation and technology development is shifting away from traditional centers, in a trend toward globalization of innovation. Local content requirements and local technical demands are taking firmer hold in regions such as Brazil, China, and the Former Soviet Union. This has implications for oil companies attempting to maintain any competitive advantage through proprietary technology, as well as for service companies attempting to expand their roles.

Natural gas prices have rebounded with the 12-month strip (HH) up 20% from its 52-week low. While prices will remain low, many sources are economic at these levels and producers continue to drive down operating costs; gas assets remain oversold, and we also see opportunity via growth in demand – recovering industrial production, petrochemical feedstock, and new markets like transportation Global upstream spending is up 10-15% in 2013, from $1.2tn, because oil prices averaged well above 100 dollars per barrel for the last two years. OPEX is expected to see steady gains as new fields are

brought online


18

Upstream Spend

Global upstream spending is up 10-15% in 2013, from $1.2tn, because oil prices averaged well above 100 dollars per barrel for the last two years. OPEX is expected to see steady gains as new fields are brought online and as global costs per unit of oil and gas produced rise. While E&P investment opportunities abound globally, oil and gas companies are disciplined about capital investment. They attempt to maintain strong balance sheets by containing capital outflows and shareholder distributions in order to preserve their position in case of lower commodity prices. This also allows them to be opportunistic, for example, with gas-weighted or cash-strapped companies. We expect continued growth in E&P spend in the near-term, based on sanctioned and planned operator projects (opex tends to follow capex, albeit with some time lag). Contractor backlogs remain at record levels and it is challenging for operators to find capacity for projects in several markets. We outline our global expectations for E&P capital expenditures for the next five years on a regional basis below. Latin America and Asia are recording the highest levels of growth, but the year 2013 represents the peak for growth in several markets. Upstream Regional CAPEX Growth Rates (2012-2017) Growth in Upstream Capital Spend has Peaked in Several Regions

Source: IHS

Due to the slow demand in other industry sectors, contractors have been largely able to secure the resources required to expand E&P-related capacity; however, securing experienced engineers and skilled laborers remains a challenge, and new capacity takes time to come online. Capacity will remain tight among contractors for next 1-2 years. We expect a continued shift in negotiating power toward contractors for several more years in most market segments, leading to rising costs and potential delays. Markets will be more balanced by 2017, as growth softens and new contractor capacity comes online.

Upstream Capital Costs We expect annual growth in our Upstream Capital Cost Index of 4.8% with some regions experiencing higher escalation, such as Brazil and the North Sea, due to

The year 2013 represents the peak for growth in several markets We expect annual growth in the Upstream Capital Cost Index of 4.8% with some regions experiencing higher escalation, such as Brazil and the North Sea, due to the rapid development of deep-water projects


19

the rapid development of deep-water projects. Markets that will remain most active and show the largest increases will be offshore rigs, subsea and personal. New build vessel (FPSOs, floaters, FLNGs) supply markets will remain tight, as only the South Korean yards have proven their credibility in executing these complex projects. Fast tracking of project is impossible. However, a brief window of opportunity will open in 2013 to secure capacity before it is taken up. Project complexity rather than full capacity will be the main reason for project delays and cost overruns. The latter will merely exacerbate the problem. Engineering and project management (EPM) labor costs and backlogs are at historically high levels compared to any previous year. Demand and utilization for offshore rigs remains high, pushing rates higher. Skilled workers, such as drillers and deep-sea personnel, will continue to demand a premium. Unskilled and support personnel costs will be dictated by local supply and demand issues. Geographic “hot spots” like Australia, Brazil, Canada, U.S. Bakken, and China, will continue to demand higher wages. Service companies with a record of reliability, on-time delivery, and no cost over-runs, command a price premium.

Conclusions We remain very bullish on the health of and prospects for the North American energy sector, as well as its current opportunity for investment. There are still many attractive opportunities to participate in the great revival of the sector. North American shales added more than 10 bcf/d of natural gas in the last five years and tight oil reservoirs added more than 2mmb/d of liquids. The “Shale Gas/Tight Oil Revolution” is driving a revival in North America’s energy landscape and a renaissance in manufacturing and the U.S. economy. Growing pains have led to an increase in political and regulatory intervention, but this will not kill the renaissance. Opportunities abound in niche plays, supply chain technology, infrastructure and the midstream/downstream industries. The same trends and discontinuities that are creating the sector’s greatest challenges are also creating windows of opportunity. Although the success in natural gas created an oversupply and price correction, persistent low gas price created many new opportunities in NGLs, gas processing, and liquids-rich plays. While bottlenecks in take-away capacity have created mid-continent price differentials, these differentials have in turn funded many, large-scale capital projects that will reduce these differentials. Large capital needs will create opportunity for investors – financing this capital-intensive revival has already required more than $250 billion of foreign investment.

How We Can Help IHS is perhaps best known for its comprehensive industry research subscription services; however, we also leverage the breadth and depth of our capabilities and expertise to provide a full range of advisory to operating companies, financial sponsors and sovereign wealth funds. Our Strategic Advisory & Transaction Support provides consulting related to both new deals and existing operations or portfolio companies, from investment strategy and target screening, right through to due diligence, strategic choices, major capital decisions and performance improvement.

We remain bullish on the N.A. energy sector; the same trends and discontinuities that create challenges also create windows of opportunity We advise on both new deals and existing portfolio businesses – from investment strategy and target screening to due diligence, strategic choices and performance

improvement


20

IHS Inc. (NYSE: IHS) is a leading information company,

that helps the world’s top businesses, governments, and

organizations to make their most important capital

decisions every day.

IHS also provides consulting services, including

strategic advisory and transaction support. Today, with

more than 1,000 professionals in 150 countries around

the world, we bring information, insight, and expertise

to major business decisions.

Visit www.ihs.com/products/consulting for free access

to our white papers and webinar replays.

Houston Kurt Barrow Vice President +1 832 209 4454 [email protected] Bob Fryklund Vice President & Chief E&P Strategist +1 713 369 0317 [email protected] New York Justin Pettit Vice President +1 212.850.8552 [email protected]

Contact Information

About the Authors

Kurt Barrow is a Vice President with twenty years of experience in downstream refining and petroleum markets. Kurt leads the Houston downstream consulting practice focusing on midstream/downstream-strategic assessments, crude oil and refined products market analysis, merger and acquisitions and technical reviews. Kurt has been the author of two successful Purvin & Gertz subscription services: the Global Petroleum Market Outlook Prices & Margins and the Residual Fuel Market Outlook. Bob Fryklund is a Vice President and our Chief E&P Strategist. He brings more than 30 years of experience in the upstream oil and gas industry as an explorer, international executive leading businesses in Africa and South America, and a recognized industry thought-leader speaking at the World Economic Forum and CERA Week. Bob is a member of the Houston Geological Society (HGS), IPAA and the American Association of Petroleum Geologists (AAPG). Justin Pettit is a Vice President with more than twenty years of advisory experience, as an oil company executive, management consultant and bulge-bracket investment banker, to corporate Boards and executives, financial sponsors, and sovereign wealth funds, on matters of strategy, M&A and major capital decisions. He is the author of two books, Merge Ahead (McGraw Hill 2009) and Strategic Corporate Finance: Applications in Valuation & Capital Structure (Wiley 2007).

http://www.ihs.com/products/consulting




The-IHS-EP-Investment-Guide-2013.pdf

Documents

Transcript of The-IHS-EP-Investment-Guide-2013.pdf