Investment – Oil + Gas Monitor http://www.oilgasmonitor.com Your Monitor for the Oil & Gas Industry Mon, 15 Aug 2016 06:57:26 +0000 en-US hourly 1 https://wordpress.org/?v=4.6.9 Oil and Gas Debt Crisis: Quick Onset but No Quick Fixes http://www.oilgasmonitor.com/oil-and-gas-debt-crisis-quick-onset-but-no-quick-fixes/ Fri, 20 Feb 2015 12:05:12 +0000 http://www.oilgasmonitor.com/?p=8579 John T. Young, Jr. |Conway Mackenzie While the general population enjoys lower gasoline prices at the pump, the impact to the oil and gas industry in this country, and its implications for our broader economy, is likely much worse than the public realizes.   U.S. oil and gas debt has surpassed the $100 billion mark […]

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February 20, 2015
John T. Young, Jr. |Conway Mackenzie

While the general population enjoys lower gasoline prices at the pump, the impact to the oil and gas industry in this country, and its implications for our broader economy, is likely much worse than the public realizes.
 
U.S. oil and gas debt has surpassed the $100 billion mark and is quickly approaching $200 billion. While many in industry anticipated future impacts from overcapacity and inadequate infrastructure, very few expected this most recent price collapse to happen so soon and to progress so quickly. The fundamentals for industry were very different six weeks ago and now interested parties are scrambling to reposition themselves.

In the U.S., a major factor precipitating this crisis are the steep decline curves typically associated with unconventional plays. A lot of drilling and significant increases in oil production was occurring over a short period of time. This surge in drilling, which is very capital intensive, resulted in massive demand on the service sector. Fleets of equipment were expanded, labor forces ramped up, and unprecedented economic growth was spreading to small towns and corners of America. Low commodity prices, of course, cannot sustain this.

Unfortunately, much of problem lies in our infrastructure so there is no short-term solution.

On the natural gas side, we do not yet have the ability to transport and export the volumes of gas being produced. The relationship between supply and demand are fairly predictable, but once you have reached capacity you see rapid declines in natural gas prices and we currently have a glut.

The same is true of oil; we don’t have the infrastructure to transport and store all the oil coming out of the newly developed shale plays. Nor do we have the legal authority to export much crude.

The manufacturers of field equipment are already taking a bit hit. Service companies are not ordering equipment right now and it will likely come to a halt.

During the second and third quarter of this year, the service companies, which drill and maintain oil fields, will have severe cash flow problems that will become apparent to the rest of the world. The exploration and production companies that utilize their service are requiring 20-30 percent discounts, which will tighten service companies’ working capital. Service companies are getting 30 percent less on pricing; their volumes are declining; and their receivables are likely getting stretched out another 20-40 days. That’s a difficult combination to absorb.

For the upstream companies, the short-term impact largely depends on whether, and by how much, they are hedged. If they are sufficiently hedged, they have some headway. In simplest terms, they will continue to benefit from yesterday’s oil prices for anywhere from six months to a year. Those that are not hedged will not have those protections in place. Those companies already having problems are completely exposed to commodity prices and are going to have a tough time. They may have no choice but to shut in production and may end up losing leases, which creates a difficult situation to restructure.

The most valuable piece of information out there right now is how much of the 2015 production is hedged. When I speak to service companies I tell them one of the most important things when evaluating credit to the exploration companies right now is to determine how much of the production is hedged. That will directly impact the exploration company’s ability to pay its vendors, at least for some period of time.

This is also good advice for debt investors. Debt investors should look at how much a company is hedging before considering purchase.

I would encourage today’s debt investor in the energy space to evaluate these situations as an equity investment and be mindful of operational issues. Many of these situations will actually be taking on equity risk. Service company economics are driven by fleet utilization and firms will not attract investors if they cannot keep their equipment utilized. An investor does not want to put capital into a service company only to see the equipment sitting idle and deteriorating. A debt investor today needs to have a well-thought-out strategy on how they are going to equitize their debt and take the actions needed to make their investments profitable.

In time, we will likely see liquidation and consolidation on a large scale. There is a large amount of capacity in the market right now because so much capital was invested to service a growing demand for drilling. This is now slowing down or coming to a halt. Many equipment companies will need to either liquidate or consolidate. Service companies will need to right size their equipment inventory, as the existing supply of service companies and equipment is far greater than the demand for drilling.

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Despite Cheap Oil, Energy Sector Provides Opportunities http://www.oilgasmonitor.com/despite-cheap-oil-energy-sector-provides-opportunities/ Mon, 09 Feb 2015 14:41:54 +0000 http://www.oilgasmonitor.com/?p=8551 Robert Thummel | Tortoise Capital Management The energy sector has been dominating the headlines due to the dramatic drop in the price of crude oil in the later months of 2014, as global supply currently is exceeding demand. As is often the case in the short term, the market did not necessarily decipher quality, and […]

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February 9, 2015
Robert Thummel | Tortoise Capital Management

The energy sector has been dominating the headlines due to the dramatic drop in the price of crude oil in the later months of 2014, as global supply currently is exceeding demand. As is often the case in the short term, the market did not necessarily decipher quality, and stocks across the energy value chain were affected. As of February, the energy sector is the cheapest sector in the S&P 500.

While the recent volatility within the energy space has been challenging, we believe the current market provides opportunity for long-term investors across the energy value chain. Three ways to play the energy sector in the current oil price environment include:

Upstream: high-quality oil and natural gas producers;
Midstream: energy infrastructure pipeline operators; and
Downstream: refiners and petrochemical companies.

High-quality oil and natural gas producers
Prices notwithstanding, North American crude oil production is expected to grow in 2015, averaging an estimated 9.3 MMbbl/d. However, the pace of that production likely will change. Many oil and gas producers have trimmed their capital expenditure plans for 2015, with the majority planning year-over-year capital expenditure cuts ranging between 20-50 percent, even as they have indicated they still expect production growth year over year resulting from the carryover of aggressive 2014 drilling programs.
We expect drilling activity will be focused on the lower-cost oil basins, such as the Eagle Ford shale and the Permian Basin, where producers likely will focus on the core areas. In the current environment, we believe oil prices should remain high enough to support production in these key basins. Oil producers with low-cost drilling locations, strong balance sheets and experienced management teams are likely to perform better against their peers in the current environment.

Natural gas production also has remained robust, in 2014 setting the highest monthly production average on record, and is expected to grow by an estimated annual rate of 3.1 percent in 2015. The Marcellus is becoming the predominant U.S. basin in this low-price environment. Natural gas producers with core acreage there should continue to benefit as the Marcellus shale continues to increase its market share of total U.S. natural gas production.

Energy infrastructure pipeline operators
Energy infrastructure companies, specifically pipeline operators, typically are good investment opportunities in volatile commodity price environments. These midstream companies are attractive to investors because they typically provide current income plus growth to the investor. They generally earn a fee to transport oil and natural gas from the producer to the end user. Therefore, their cash flows tend to be less volatile, as they are not directly tied to an underlying commodity price. Should low oil prices persist, volumes may eventually decrease, which could affect crude oil pipelines. However, refined products pipelines stand to benefit from lower prices, due to increased consumer demand driven by lower prices at the pump. The new sources of crude oil and natural gas in the U.S. have created opportunities for energy infrastructure companies to build additional pipelines to transport rising volumes. Despite lower oil prices, the project backlog continues to be robust, with an estimated approximate $135 billion in projects through 2017. The visible growth from these projects underway provides clarity to cash flows and potential in 2015 and 2016. We believe new natural gas projects will continue at a fairly constant pace, but new crude oil-related projects will continue at a slower clip if prices remain low.

Refiners and petrochemical companies
The crude oil and natural gas production outlined earlier has benefited some companies within the downstream, and for some, lower commodity prices can be beneficial. Petrochemical companies should benefit from low-cost feedstocks and the ability to export, as demand for their consumer products increases as a result of growing gross domestic product. Low oil prices often spur economic growth around the world. In addition, refiners should benefit from increasing refined product (gasoline and diesel) demand. Data from the Energy Information Administration suggest demand for gasoline and diesel was higher in January of this year compared to the same period last year. As we move into the traditional summer driving season, we expect demand to continue to grow for U.S. producers of gasoline and diesel, which should boost U.S. refiners.

Despite recent volatility, North America remains a major, relevant, global energy player, enabling the U.S. to better control its national security, with significant production potential for generations to come. The overarching reality is that although currently there is a global oil supply/demand imbalance, the laws of economics ultimately should prevail. Lower prices may discourage short-term production growth but may also spur demand. We anticipate this will drive prices in the other direction, and the cycle will continue. We think that over the long term, prices will return to a range that is economical for production to continue broadly.

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Beyond Commodity Prices – The Story on Midstream Oil & Gas Opportunities in 2015 http://www.oilgasmonitor.com/beyond-commodity-prices-the-story-on-midstream-oil-gas-opportunities-in-2015/ Thu, 22 Jan 2015 17:11:34 +0000 http://www.oilgasmonitor.com/?p=8483 John Hritcko | TRC Companies, Inc. The latest news covering the oil and gas market for 2015 focuses almost entirely on the detrimental effects of low prices on exploration and production, making it easy to miss the bigger picture. Just as the fluctuations of the stock market do not reflect the entire state of the […]

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January 22, 2015
John Hritcko | TRC Companies, Inc.

The latest news covering the oil and gas market for 2015 focuses almost entirely on the detrimental effects of low prices on exploration and production, making it easy to miss the bigger picture. Just as the fluctuations of the stock market do not reflect the entire state of the US economy, commodity oil and natural gas prices do not tell the whole story of our industry. Even in the face of a 50% drop in the price of a barrel of oil, and a reduction in natural gas prices, opportunities still abound for investment, especially in the midstream segment.
 
Since 2007, previously non-productive shale reserves have come online to unlock a wealth of new oil and gas supplies. However, the resulting surge of shale-related production revealed deficiencies in both the quantity and condition of our existing infrastructure used to bring these products to market.

Production holds steady, may rise in 2015
Even in light of the plunge in oil prices and cuts in upstream investments, oil and gas production continues to hold steady and may potentially rise in 2015. Recent US Energy Information Administration (“EIA”) forecasts of US crude oil production from shale and tight oil plays project production rising from an average of 8.6 million bbl per day in 2014 to a projected 9.3 million bbl per day in 2015.

While many exploration and production companies have begun implementing budgets cuts, rig stacking, and layoffs, they are expected to maintain their investments in certain core tight oil plays including the Bakken, Eagle Ford, Niobrara, and Permian basins.

Likewise, according to EIA’s, Natural Gas Annual, gross production from shale gas wells increased from 5 Bcf per day in 2007 to 33 Bcf per day in 2014, equivalent to 40% of total US natural gas production, and exceeding production from all non-shale natural gas wells. The Pennsylvania Marcellus play became the second largest gas producing region in the country with 8 Bcf per day of production in 2013. The Marcellus formation is likely to exceed the entire projected gas demand in New England and Mid-Atlantic regions by 2016, growing from 1.9 Tcf per year in 2012 to an anticipated 5 Tcf per year in 2022.

Despite the current pullback in exploration and production, these massive volumes of oil and gas are driving the continued need for investment in downstream links of the production value chain. As usual, investments in the midstream sector are lagging the upstream production spending by two to three years. This has resulted in bottlenecks within the transportation systems and price volatility for both the producers and buyers.

In order for the producers to monetize their reserves, the production must be moved to market.

Designing, permitting, and constructing these facilities is challenging and the ability to deliver the planned projects safely, on time, and on budget, is a key requirement. The demand for service providers catering to the needs of the infrastructure developers is ongoing. Speed to market for these gathering, processing, and pipeline companies is essential.

Significant staying power
A December 2013 report on oil and gas transportation and storage infrastructure by IHS Global for the American Petroleum Institute (“API”) found significant staying power in the level of capital expenditures needed throughout the 2014 to 2025 forecast period. So strong is the need to ensure the growth of midstream infrastructure that API has just set up a new department to focus on issues related to infrastructure and transportation of oil and natural gas.

Supporting this view, there has been little real world indication by midstream companies that investment is being curtailed over the next 12 to 18 months. In fact, some of the largest players have positioned themselves during the past year for growth in 2015 and beyond.

For example, some companies consolidated their holdings into a corporate structure to lower the cost of equity capital and make it easier and more profitable to proceed with facility expansions and targeted acquisitions. Others have restructured their midstream pipeline assets into tax advantaged MLP structures. Yet others have taken advantage of the existing low interest rates to refinance their outstanding debt. None of these moves signal a retrenchment in the midstream sector of the market.

Location influences opportunities

In addition to the financial considerations driving the investment in new gathering, processing, and pipeline infrastructure, the location of the booming shale production also influences these investment opportunities.

Traditionally, the majority of US oil and gas production flowed from the Gulf Coast and Mid-continental regions of the country to the Northeast, Midwest, and West. The vast majority of gas treatment and processing infrastructure is co-located in these production regions. Also, the center of gravity of the US chemical and refining industry consuming this oil and gas is situated along the Gulf Coast.

With the increased Marcellus and Utica shale gas production servicing the major markets in the Northeast, the need for pipeline capacity from the southwest decreases. As a result, pipeline operators are investing in significant new capacity and system modifications to move the Northeast gas supplies bi-directionally, i.e., both north and south.

Yet another issue that will yield opportunities for midstream investments is the quality of the Marcellus Shale natural gas production. More gas production has driven the need for more gas treatment and processing in the Marcellus region. The Marcellus gas must conform to the gas quality specifications of the pipelines and local utilities. This also includes the immediate problem of the removal of large amounts of excess ethane.

Across the industry, expansions to existing gas processing plants are being proposed as shale gas production grows. While the timing of these projects may be affected by the current commodity prices, they remain strong midstream investment opportunities.

Speed to Market

Once again, a driving factor for these investment is, “speed to market,” allowing the product to be delivered to market quicker and more economically. Companies with the experience and know how to develop and implement strategies for delivering these projects, from inception, permitting, and construction, will be in demand.

As we move through 2015, much of what is needed to spur these midstream oil and gas infrastructure investments is in place, but the pathways to success are far from certain. Success depends upon many factors including commodity prices and continued overall US economic health. However, equally important is the ability of companies to understand the environmental, engineering, and regulatory challenges inherent with these large capital investment opportunities and how to address them.

Whether it’s knowing how to traverse a wetland, culturally significant geography, remediating existing brownfields, or employing the best sustainable development practices for the project, employing firms with the proper knowledge and technical capabilities needed to deliver under difficult conditions is essential. We don’t lack for oil and gas sector investment opportunities, and success will follow those companies who can muster the understanding, skill, and experience needed to capitalize on these challenges.

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Cold Winter Temperatures Give Rise to a Hot M&A Market for the Canadian Oil and Gas Sector http://www.oilgasmonitor.com/cold-winter-temperatures-give-rise-hot-ma-market-canadian-oil-gas-sector/ Mon, 18 Aug 2014 17:00:13 +0000 http://www.oilgasmonitor.com/?p=7641 Lorraine L. Walker

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August 18, 2014
Lorraine L. Walker | BDO

It was the biggest deal of 2012: Chinese state-owned firm CNOOC Limited’s takeover of Calgary oil and gas producer Nexen Inc. Although there were a total of 260 deals closed over the course of the year, it was CNOOC Limited’s CDN$14.95 billion transaction and another megadeal — PETRONAS’ CDN$5.5 billion acquisition of Progress Energy — that helped lift 2012 transaction values to approximately CDN$49.5 billion.

Analysts suggested that transaction deals and values in 2013 would build on the successes of 2012. However, that was before the CNOOC Limited – Nexen and PETRONAS deals attracted attention from the media, regulators, policy makers and the public at large that changed the trajectory of deal-making in the Canadian oil and gas sector.

Following the CNOOC Limited-Nexen deal, the federal government solicited feedback from a broad spectrum of stakeholders, the results of which prompted the government to amend the Investment Canada Act for Industry Canada’s State Owned Entity (SOE) guidelines. These guidelines restricted the amount of investment allowed by SOEs in Canadian companies by broadening the definition of an SOE and clarifying certain other aspects of definitions of control. These changes, enacted in June 2013, cast a pall over the sector for potential Asian investors. From CDN$27.3 billion in 2012, Asian investment in the Canadian oil industry fell to CDN$1.2 billion in 2013.

Although Asian investment explains part of the decline, uncertainty surrounding pipeline approvals to expand Canada’s ability to export oil to foreign markets exacerbated what amounted to an 80% drop in deal values in 2013.

So where does this leave us in 2014?

SOE guidelines are still in place and the pipeline uncertainty continues. Yet, both equity financing and merger activity are on the rise. To date, the merger activity in the Canadian oil and gas sector has already reached CDN$15 billion, exceeding the CDN $13 billion in activity for all of 2013.

Canada’s cold winter has helped to heat up the transaction landscape as plummeting temperatures gave rise to gas demands. After years of depressed prices based on an oversupply of natural gas, extreme cold weather in Eastern Canada and parts of the U.S. caused by the polar vortex pushed down storage levels and increased prices to as much as CDN$38 a gigajoule in early February, 2014. Add volatility in the Middle East and a lower Canadian dollar to the mix and all of a sudden shale gas has become the new transaction darling. Major deals to date include Canadian Natural Resources Ltd.’s purchase of a significant portion of Devon Energy Corp’s natural gas assets valued at CDN$3.13 billion and Encana Corp’s sale of Western Canadian exploration property to a private equity (PE) suitor.

Just as rising natural gas prices may have sparked interest in shale gas assets, the increasing use of rail to resolve the oil sands transportation woes has boosted oil prices and by extension investor confidence. This, in turn, is attracting M&A activity and now private equity (PE) investment with more PE players seeking to set up shop in Calgary.

Some funds, including giant Kohlberg Kravis Robert, have seen opportunity in the difficult capital markets of the past few years. They have looked for opportunities to provide capital, where the public markets have not been available. The same fundamentals and geo-political considerations are driving other PEs to turn their interest toward North American oil and gas opportunities. These PEs are looking for service companies with unique features and value-add products and services. With low interest rates, PEs are able to raise funds from their limited partners and are seeing higher levels of leverage from lenders. This enables the PEs to aggressively pursue high quality assets.

Also hot are Canadian exploration and production (E&P) companies with high-quality unconventional and light-oil assets. According to global market information and analytics company IHS Inc. (IHS), there have been eight E&P transactions worth more than CDN$10.9 million each, with the market on pace to reach 15 corporate acquisitions valued at approximately CDN $7.63 billion by year’s end. A majority of these buyers will be Canadian E&Ps. However, despite SOE guidelines, the Chinese and others are showing interest.

Where foreign investors are beginning to show interest in E&P, U.S. companies have shown renewed interest in Canada after years of selling their investments amid softening oil and gas prices. The draw? Liquefied natural gas (LNG). Yet, although there are as many as 16 LNG gas plants proposed in British Columbia, the number that will come to fruition will depend on finding suitors willing to accept the significant capital costs, seek the required regulatory approvals, and forge alliances with First Nations and other parties that would be crucial to a project’s success.

With five months still to go before year’s end, Canadian oil and gas companies are well-positioned to acquire and be acquired. Whether it’s shale gas, LNG or E&P, companies from all segments of the oil and gas sector will continue to attract investors, far surpassing both deal numbers and deal values set in 2013. Moreover, as Canadian companies receive regulatory approval to ship product through pipelines to the U.S. and offshore, the Canadian industry will only become more attractive to investment for the foreseeable future.

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U.S. Energy Policies are Affecting Investment Decisions http://www.oilgasmonitor.com/u-s-energy-policies-affecting-investment-decisions/ Sat, 26 Jul 2014 10:57:17 +0000 http://www.oilgasmonitor.com/?p=7522 Andrew Bateman

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July 26, 2014
Andrew Bateman | SunGard’s Energy Business
The recent announcement by the Environmental Protection Agency (EPA) that the U.S. will reduce CO2 emissions from coal generation by 30% from 2005 levels by the year 2030 is the latest in a number of policy and regulatory decisions that have and will continue to affect the energy supply and demand balance in the U.S.

Despite a technology-driven revolution that has allowed massive increases in oil and gas production from shale and tight sand formations, a continuing stream of new or changed regulations from federal and state authorities has created an almost decade-long atmosphere of uncertainty and concern among energy producers, utilities, traders and consumers.

In the modern era of energy regulation, U.S. energy policy has been a mixed bag of stimulus and punitive measures, intended to create an outcome that meets economic, environmental or political goals. Since the early 2000s, much of that energy policy has been focused on addressing environmental issues – reducing pollution and carbon emissions. The environmental-centric energy policies have been wide-ranging, designed on one hand to encourage development of renewable energies (primarily wind, solar and ethanol), while on the other encouraging or even forcing improvements in energy efficiency.

The federal agencies involved in implementing or enforcing regulations affecting energy companies reads like a laundry list of acronyms: DOE, EPA, FERC, NERC, NRC, CFTC, BLM, BOEM, BSEE, and even the State Department and Coast Guard. The list of tools for enacting or enforcing U.S. energy regulatory policy is equally long, including tax policy, environmental law, rule-making on federally owned or Native American lands, regulation of interstate and international commerce, financial subsidization including federal loan guarantees, and financial markets regulation. The wielding of these tools has in the past resulted in wide-ranging and, many times, controversial changes to the functioning of the energy markets that has affected energy production, transmission/transportation, distribution, trading and consumption.

In almost every case where the tools of energy policy have been used, friction has increased in the market and has had an impact on either the supply or demand (an ultimately the price) of an energy product.

While the actual effects of the Obama administration’s plans remain unclear and the economic costs and impacts will not be fully realized for a number of years, should the new rules survive the legal challenges that will surely come and be implemented as proposed, the changes would force an accelerated restructuring of the U.S .energy supply portfolio, increasing the use of natural gas and renewables (particularly wind and solar) for power generation. Such a restructuring could increase power costs as the capital investments required to develop the replacement capacity will be high and the increased reliance on natural gas will push prices beyond where they would be otherwise be. While there will be winners under the new regulations, such as some natural gas producers and those utilities whose fleets are primarily comprised of nuclear and renewable facilities, the impacts on the power and coal industries will likely be difficult to absorb.

Achieving a 30% reduction in coal-fired CO2 emissions will force the early retirement of costly generation assets and result in the shuttering of some coal mines. It’s likely that a few coal-heavy utilities will need to seek out mergers with more diversified companies or find themselves heading toward bankruptcy. However, as the U.S. generators have already reduced coal usage by more than 200 million tons per year from 2005 to 2012, setting the baseline of reductions to the 2005 level does mean that much of the necessary changes have already occurred. According to the EIA, utilities burned some 826 million tons of coal for power generation in 2012, leaving a little more than 100 million tons to be cut by 2030.

For U.S. power utilities and other affected energy companies, the future remains murky. Despite the EPA’s recent announcement, it will be a year or more before these companies will truly be able to measure with certainty the impacts on their businesses, leading to a continuing deferment of investment and limiting growth in the interim. Nonetheless, as most coal-centric companies, including generators, have been living under the threat of punitive regulations for years, at least the new rules do start to lay out a timeline for achieving some future clarity.

Until the new carbon dioxide emission rules are finalized and the pace of new regulations slows, many utilities will continue to operate in an environment of uncertainty. Given the increasing regulatory burdens and exposures this segment is faced with, utilities are often left without a clear commercial path and are unwilling to invest in new facilities or new markets without a reasonable assurance that those investments will provide a return. Without such an assurance, these companies, though many flush with cash, have continued to stand back, limiting investments in new plants and facilities to replace those that are nearing the end of their useful lives, or making investments in new markets or regions that in a more “normal” market could offer significant commercial upside.

Instead of looking outward for opportunity, it does appear that utilities are increasingly focused internally, concentrating on core capabilities and making investments to improve operational efficiencies – reducing costs and risk. These investments, from improving equipment maintenance procedures to upgrading telemetry and IT systems, are targeted at optimizing operations and ensuring compliance with existing regulatory mandates, such as the North American Electric Corporation’s (NERC) Critical Infrastructure Protection (CIP) Standards.

In the area of commercial IT systems, utilities are seeking to shave costs and reduce risks via consolidation of systems. In the not too distant past, it was common for utilities and energy traders to seek out solutions for specific operational units (such as gas or fuel supply, power scheduling, gas scheduling, real-time trading, etc.). However, in today’s environment, utilities are increasingly looking to partner with one or two technology vendors that can meet their needs across multiple operational or business units and commodities to help decrease costs and support overhead associated with dealing with multiple vendors, and the integration infrastructure required to tie together those multiple systems.

While a shifting U.S. energy policy can create uncertainty, for many in the utility space, the end of the regulatory turmoil of the last several years may actually be in sight. However, until the new EPA rules are either fully implemented or struck down through legal challenge, most of these companies will continue to focus on “run and maintain,” not on growing their commercial operations. For them, the real opportunity exists in improving operations — providing a positive return to shareholders through reduction of costs and limiting the operational and financial risks associated with old systems and processes.

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What You Need to Know About Oil & Gas Hedging http://www.oilgasmonitor.com/need-know-oil-gas-hedging/ Mon, 14 Apr 2014 12:51:56 +0000 http://www.oilgasmonitor.com/?p=6992 Ray Asif | Schneider Electric To Hedge or Not to Hedge While some may see hedging as a complicated and advanced investing strategy, the principles behind hedging are in reality very simple. Hedging commodities allows investors to ensure predictable financial results by protecting against future price movements. By purchasing futures contracts, investors can lock in […]

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April 14, 2014
Ray Asif | Schneider Electric
To Hedge or Not to Hedge
While some may see hedging as a complicated and advanced investing strategy, the principles behind hedging are in reality very simple. Hedging commodities allows investors to ensure predictable financial results by protecting against future price movements. By purchasing futures contracts, investors can lock in prices that are favorable to an organization to continue realizing profits over time. While limiting exposure to financial losses also limits the potential for gains, it does help protect investors during periods of market volatility.

Benefits of Hedging
Hedging is particularly valuable in oil and gas commodities to help investors achieve predictable financial results. Depending on the size and nature of an organization, a well-defined hedging program could help encourage growth and profitably even during periods of relatively flat prices. While larger conglomerates may not need to rely on hedging to ensure profitability, giving that its investment activities can help drive the market, a smaller company can see great advantages from hedging as usually its long or short position has minimal or practically no impact on the market prices.

The natural gas market is a great example of where hedging has helped companies continue to realize profits in periods of recent price volatility. For example, the polar vortex of 2013-2014 saw volatility in a market that had long been flat. Natural gas futures contracts on the NYMEX had been trading under $4/mmBtu since January of 2012. However, February 2014 saw prices close to $6/mmBtu, from a low in January of $3.10. The eastern United States saw some local supplies surging as much as eightfold as demand for heating soared during periods of extreme cold. In these types of market movements, a well defined and an active hedging program can ensure maximum value is captured for investors.

Some Common Tools Used for Hedging
Various tools are used to manage hedging programs, depending on their complexity.

Futures/Forward Contracts

Futures are a standardized agreement to purchase a specified asset of standardized quantity, on a specific date at a specific price. Futures contracts are exchange traded and are guaranteed by a clearinghouse, which minimizes the risk of counterparty default.
Forward contracts are private agreements between two parties and are not as rigid terms and conditions as a futures contract, and there is a chance that the other counterparty might default on its commitment.

Options

Options are a more flexible hedging tool. A company or investor can purchase a ‘call’ option, which is the right to buy an asset at a particular price, or a ‘put’ option, to sell at a particular price at a future date. Unlike futures, the option owner is not required to follow through with the transaction if the market price is more advantageous than the option price.

Should You Be Hedging?

The appetite and willingness for market risk is the biggest factor in deciding whether or not to embark on a hedging program. Smaller companies looking to protect themselves from wild market fluctuations and volatility would be well served by at least investigating what a well-defined hedging program could bring to the business. However, market participants of all sizes need the ability to smooth the ups and downs of future financial results, as businesses can’t grow on unpredictable financial results and a well-defined hedging program is still better than hoping that the market moves in your favor.

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New Paradigm in E&P Finance http://www.oilgasmonitor.com/new-paradigm-ep-finance/ Thu, 06 Mar 2014 17:18:00 +0000 http://www.oilgasmonitor.com/?p=6792 Bernard F. Clark and | Jeff Nichols Haynes and Boone, LLP Domestic exploration, production and development have been transformed by technological advances leading to an explosion of unconventional and conventional production of oil, natural gas and natural gas liquids. The first stage of this recent transformation was the land grab and lease maintenance drilling in […]

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March 6, 2014
Bernard F. Clark and | Jeff Nichols Haynes and Boone, LLP

Domestic exploration, production and development have been transformed by technological advances leading to an explosion of unconventional and conventional production of oil, natural gas and natural gas liquids. The first stage of this recent transformation was the land grab and lease maintenance drilling in the early part of the decade. Now, the second stage has begun, which is the rationalization of acreage portfolios and more deliberate exploitation of reserves. Ultimately this stage will require billions of dollars of capital expenditures to fully develop the possible and probable reserves unlocked by this new technology. Oil and gas companies will spend about $723-billion on exploration and production in 2014, an increase of 6.1 percent over 2013, Barclays Bank said in a recent report. Where will the money come from?

The old paradigm for the last 40 years has been that a producer borrowed from his bank against a percentage of the PV10 value of his PDP reserves (the “borrowing base”) and used the proceeds under a revolving-based loan to further develop existing acreage. Under this “conforming” borrowing base loan structure, lenders were generally able to keep pace with the capital needs of the producer’s drill bit. In large part this was because, prior to recent technological advances, wells were simpler – single vertical wells, no multistage fracs. Accordingly, drilling costs were (relatively) cheaper than today. The borrowing base revolver structure worked well to serve the producer’s capital needs where every six months the lender would reevaluate the producer’s reserves (including new production) and increase the borrowing base to fund further development drilling and the occasional producing property acquisition.

Today’s technological drilling and completion improvements, however, come with a steep upfront price. Leasehold acquisition costs have risen ten-fold or more. Horizontal wells with multistage frac completions have significantly increased capital expenditures and, with development pad drilling of up to six wells simultaneously drilled and completed prior to commencement of production, a producer’s capital budget is significantly strained before the wells are turned on to production. While drilling multiple well completions saves time and money, it doesn’t fit well within a semi-annual borrowing base revolver capital structure. Where before a producer might have received some PDP credit from his banker for the first one or two vertical wells drilled in a six-well package by the time of the next borrowing base increase, in order to realize cost savings of a multipad drilling program, today’s producers may be required to finance up to six horizontal wells prior to seeing initial production from a location. Even drilling and completing a horizontal well on a single well program can require a capital outlay of up to $10 million per well (although costs continue to come down with improved drilling techniques). Any way you slice it, however, even though efficiencies and initial production rates justify implementation of the new technology, producers today need access to ready capital much more than their grandfathers or fathers could have expected.

Bankers and new capital market entrants are adjusting to meet the changing needs of the industry. Some banks, especially banks with in-house mezzanine or “stretch” lending groups, are able to offer a one-stop first lien-second lien facility. The first lien being the familiar conforming borrowing base revolver with a second tranche of capital (typically a fully funded term loan) at a higher interest coupon secured with a lien junior to the first lien that can be used to prime the pump for a more aggressive multipad development drilling program.

Banks that lack the in-house capacity to fund both the first- and second-lien facilities can either pair up with a mezzanine capital provider or try to stretch its borrowing base underwriting algorithms in an effort to meet its borrower’s cash needs. A good example of this stretching exercise is where traditionally banks loaned predominantly against PDP reserves, some are now willing to increase the percentage of PDNP and PUD value of the borrower’s reserves under the borrowing base. Historically, banks have advanced around 60 to 65 percent against PDP with additional value attributed to a lesser percentage of PDNP and PUD, not to exceed 20 to 25 percent of the total borrowing base. For more established borrowers some commercial lenders may now be willing to advance up to 70 percent against PDP values, and increase the value attributable to PDNP and PUDs up to 40 percent. Some major lenders have even included a component of ‘leasehold’ value where the borrower’s acreage position is located in a particularly competitive area (e.g. the ‘oily Eagleford’). For management teams backed by substantial private equity sponsors, advance rates can approach 90 to 100 percent of PDPs in stretch- or second-lien facilities. Some stretch facilities go beyond 100 percent of PDPs on a temporary basis, with interest rates and fees that reflect the increased risk.

Borrowers who lack track record or private equity backing may have to look beyond the traditional commercial energy bank for needed capital. Those borrowers without any assets or track record – sometimes known as the “Two-Guys-and-Truck” business model—are typically looking at equity capital. Equity capital comes in all shapes and sizes, the two principal areas being either “friends and family’ money, or if a producer has identified a good prospect or has a compelling investment thesis, perhaps private equity capital. Either way, if funding is available, it will be expensive (multiples of the cost of debt financing) and on a short fuse (i.e. private equity will be looking for monetization of its investment within three to seven years).

Those borrowers who are in search of development dollars and who have a strategic position in an attractive basin, preferably with some initial production, have another option: mezzanine finance. The cost of mezzanine capital by definition lies between bank pricing on conforming loans but typically well below the cost of equity capital. The number of mezzanine capital providers to the upstream business has fluctuated over the years since first becoming popular in the late 1980s. Today however, we are seeing a new crop of experienced capital providers exploring mezzanine financing for the upstream industry. There are multiple reasons for this renewed cyclical interest in mezzanine financing, not the least of which being the competition of too many dollars chasing too few deals. Bulge bracket lenders with capital market departments have made the conforming borrowing base market practically a ‘loss leader’ in order to sell other bank products and services, not the least, underwriting a producer’s public debt and equity offerings. This downward pressure on commercial financing has financiers looking for other pastures in which to put their dollars to work.

Lenders in this category can use structures to accommodate the particular risk-and-reward profile for the company. For example, some mezzanine lenders can also make an equity investment or can require “penny warrants” as a way for a cash constrained company to provide the lender with a piece of the upside. Some mezzanine lenders will take an interest in the oil and gas properties such as a convertible royalty interest or a net profits interest.

Other companies who want to reduce their commodity risk as part of a financing may turn to commodity-linked financing structures. One of the most basic and popular of these is a structure that can have many variations but is generally referred to as a “prepaid” transaction. A basic prepaid transaction would involve a cash advance to a company in exchange for the company’s promise to pay back the market value of a set quantity of a commodity. For example the company could receive $1,000,000 in exchange for the promise to pay the dollar value of 200 barrels of oil per month for five years. If the price of oil is $100 the monthly payment would be $20,000. If the price of oil is $50 the monthly payment would be $10,000. The company’s commodity risk is reduced because its payments rise and fall along with commodity prices. This is, in fact, similar to a loan with hedges. But prepaids can be preferred because they offer higher advance rates (the company can borrow more than under a traditional loan). The firms that offer prepaids have a different cost of capital than the firms that offer loans, and the commodity prices used to extend the credit tend to be keyed off of the NYMEX prices, which tend to be higher than the price decks used by banks in their borrowing-base models. A volumetric production payment, or “VPP” is similar in that the amount advanced is repaid from the dollar value of a specific volume of future production. A VPP and a prepaid transaction differ greatly in terms of the physical assets that support the transaction. A VPP conveys an interest in specific producing properties, whereas a prepaid may be secured with a lien on a wide group of producing and non-producing properties. There are other important legal distinctions which are beyond the scope of this article. These structured transactions are legally intensive and can carry a higher transaction cost and up-front legal fees than a more common loan, but with a higher advance rate they may offer a better solution that justifies the expense.

Understanding the many options and knowing the different players in the capital markets is almost as important as knowing the latest technologies and techniques for finding and producing hydrocarbons. Anyone with more than a few years experience in the oil patch knows that today’s trends and cycles will become yesterday’s news. Staying ahead of technological advances has been and remains a constant key to success in our industry. Innovations in capital markets make it important that today’s producer, even more than his father or grandfather, also stay informed in the new paradigms that will transform how capital can be accessed and employed.

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The A&D Outlook for the Oil & Gas Industry http://www.oilgasmonitor.com/ad-outlook-oil-gas-industry-2/ Fri, 28 Feb 2014 13:14:39 +0000 http://www.oilgasmonitor.com/?p=6759 Rodney Moore | Weil, Gotshal & Manges LLP M&A activity in the upstream and midstream industries in the United States has been incredibly robust over the past 10 years. Although the frenzy to get a piece of the shale action has slowed, the interest in shale plays and enhanced drilling programs, together with shifting market […]

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February 28, 2014
Rodney Moore | Weil, Gotshal & Manges LLP

M&A activity in the upstream and midstream industries in the United States has been incredibly robust over the past 10 years. Although the frenzy to get a piece of the shale action has slowed, the interest in shale plays and enhanced drilling programs, together with shifting market focus from diversification to focus on core areas, continues to drive significant transaction activity in these sectors.

With this activity, capital needs skyrocketed to fund drilling activities (created both by increased drilling activity and the increased cost to drill horizontal wells) and infrastructure needs. With the debt markets tight after the economic downturn in 2008, companies began looking for more creative means to gain capital. This created an opportunity for more private equity funding, and the high-value return potential created by the shale plays and enhanced horizontal drilling techniques provided a catalyst for more sponsors to focus on the industry and for private equity funds to become more readily available to the industry.

Foreign investors, looking to gain knowledge to export to enhance their own development efforts, also became more active in investing in the industry. This led to more creative and complex financing structures and joint development arrangements.

But now, as development has provided more data, some of those high stakes deals are not providing the results as anticipated and public market dynamics are telling companies that focusing on core areas is valued more than diversification, resulting in some shifting dynamics in the industry.

E&P companies that five years ago were focused on diversification are shedding non-core assets to create capital to develop or increase their holdings in their core area(s). Private equity-backed companies that are looking to monetize after a relatively brief development period are seeing a shift in the mix of potential buyers and, depending on the nature of their asset mix, the process to effect monetization.

In the past, private equity firms could have a high degree of confidence that if they acquired the acreage and drilled enough wells to build up reserves and provide data on a play, there would be plenty of competition for the assets. Now, while there are still opportunities to monetize, as buyers focus more on their own core areas and the public market valuations are syncing up with the M&A valuations, the pool of potential buyers for different assets has shifted and sellers are considering public markets more as an alternative monetization event. The variation in initial expectations and actual results from drilling efforts also has contributed to a reshuffling of asset configurations by companies and restructuring of some of the creative financing arrangements that marked the deal landscape over the last several years.

Another strategy that has recently gained favor is acquiring small non-operated working interests in areas where mature production has held the acreage and mineral ownership has been divided up over time. The holders of small mineral interests in these areas are seeing renewed drilling activity, such as in the Bakken Shale, and either may not have, or don’t want to commit, the capital to participate in the new drilling activities. Their option is to go non-consent on these new wells and effectively give up participation or sell their fractional interests to someone who has the capital and is willing to participate. This strategy has been favored by private equity firms looking for additional ways to put money to work in the E&P industry.

The increased drilling activity resulting from the upstream explosion has created a significant need for more midstream infrastructure. The cash needs of traditional upstream companies to develop upstream assets, and the reluctance or inability of master limited partnerships (MLPs) to divert funds from dividends to construction projects, coupled with the reduced availability of traditional debt financing, created more opportunity for private equity to invest in the midstream sector as well. The result was an influx of private equity-backed companies engaging in midstream projects with an eye towards a quick monetization flip.

As recently as a year ago, MLPs and other midstream companies looking to compile an asset base to support an initial public offering (IPO) were willing to pay for assets based on projections for unfilled midstream capacity. We are now seeing M&A valuations in the midstream sector more heavily based on existing production committed to the midstream asset, resulting in the M&A and capital markets valuations being more in synch (if not higher in the capital market sector).

So what does this mean for upstream and midstream transactions in the near future?

E&P companies, which spent 2013 in a relative transaction trough, will be active in M&A transactions as companies shed non-core assets and accumulate core assets. Private equity, with a tremendous amount of money to put to work, will continue to be active in providing capital to develop upstream assets through acquisitions, joint ventures and other creative financing transactions. In addition, if commodity prices soften, some of the larger E&P companies may acquire a mid-size or another large independent E&P company if the asset mix can be accretive to market value.

In the midstream sector, private equity will continue to be active in filling the capital needs to fund development of midstream assets, in many cases through partnering with other private equity money or an E&P company. The M&A activity will remain strong because as these facilities are built and capacity contracted for, smaller companies will be looking to consolidate or acquire add-on assets to facilitate a public MLP, and public MLPs will continue to pursue opportunities to add cash flow through acquisitions.

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Shale Gas is Creating a Tsunami of Change for the Industry http://www.oilgasmonitor.com/shale-gas-creating-tsunami-change-industry/ Mon, 17 Feb 2014 20:39:19 +0000 http://www.oilgasmonitor.com/?p=6684 Andrew Bateman
Trending: Gas Trading, Markets and Operations

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February 17, 2014
Andrew Bateman | SunGard’s Energy Business
It’s been theorized that should a sizable meteorite or asteroid strike the earth mid-ocean, it could create a pressure wave in the water that would travel in all directions, ultimately rising up into a tsunami wherever the sea met land. The resultant wave would permanently reshape land forms along the coasts and would force itself into rivers, streams and tributaries, displacing the flow of fresh water that had traveled hundreds or thousands of miles from the interior of the continent…

It’s a frightening scenario and one that has seen its fair share of play in Hollywood blockbusters. It’s also a useful, though imperfect, analogy of what’s currently happening in the North American natural gas markets as new production from shale formations continues its dramatic increase.

The asteroid in our analogy is the technical innovation (i.e. relatively cheap and reliable horizontal drilling techniques and hydraulic fracturing) that has opened up huge deposits of hydrocarbons that were previously tightly locked in shale deposits; the ocean is the reserves of natural gas held in the shale; the wave is ever-increasing natural gas production; the land is the energy markets; and the rivers and other waterways are the natural gas gathering systems and pipelines that service the industry. Where the analogy falters is that while a tsunami may continue to press inland for minutes or hours, the tsunami of natural gas from shale will continue to flow across the continent for many years.

State Natural Gas Gross WithdrawalsFor the industry, ground zero in our tsunami analogy is the Marcellus Shale formation that spans a large portion of the Northeastern states, including much of West Virginia, Ohio, Pennsylvania, Maryland and New York. While other large shale deposits have contributed to the increasing production of gas in the US, none has rivaled the Marcellus in terms of impact on the industry.

US Natural Gas WIthdrawalsAs shown in Figure 1, the “traditional” gas producing states and federal waters have seen either declining production or relatively modest gains (in the case of Texas) while the “other states” have been responsible for virtually all the approximately 15 Bcf/day increase in total U.S. gas production since mid-year 2009 (Figure 2).

Marcellus Natural Gas ProductionLooking specifically at Marcellus production (Figure 3), one begins to appreciate the tsunami analogy even more. Its seven-fold increase in production in less than four years has overwhelmed a large swath of the natural gas market, and the production and transportation infrastructure that supports it. Extending from its epicenter in the Northeast region, the impact of the wave of new production is being felt to the south from Florida to the gulf coast of Texas, west to the Rockies and north to the Canadian border.

As Marcellus production increases, and new wells are connected to the northern sections of the various interstate pipeline systems that had been constructed primarily to carry Gulf of Mexico, Texas and Louisiana production to the markets of the Northeast, the gas traveling from the south is being displaced and/or devalued given the much shorter distance to market for the new supply. As a result, basis differentials between the Northeast and Gulf Coast have narrowed and producers along the Gulf are having increasing difficulty selling their gas into the lucrative Northeast and New England markets. The increasing surplus of supply in the south is spurring pipeline operators to explore development of new routes in order to reach underserved or growing markets throughout the region, including planned pipeline construction to increase gas delivery as far south as Miami.

To the west of the Marcellus, the Rockies Express Pipeline (REX) was constructed just a few years ago in order to bring an oversupply of midcontinent gas to the Northeast. Soon after entering service, the pipe’s eastern leg began suffering flows well below designed capacity as gas buyers turned to sources much closer to their facilities in the Northeast. Given the underutilization of the eastern leg of REX, the pipeline has requested, and received, permission from the FERC to reverse the flow of that section of pipe, giving Marcellus producers access to the growing Midwestern markets that had been previously served almost exclusively by producers in the Mid-continent and the western Gulf Coast regions.

To the north, Western Canadian natural gas flowing south to service the market around New York has also been displaced by the Marcellus wave, and in late 2012, flows at the Niagara interconnect between Trans-Canada and Tennessee Gas Pipeline reversed as Marcellus natural gas began to flow into Canada.

For gas producers, traders, utilities and industrial consumers, the Marcellus tsunami creates both challenges and opportunities. The challenges arise in remaining abreast of, and planning for, an evolving market in which a new facility or pipeline coming on-line can almost immediately impact local or regional energy prices and can send once profitable deals or transportation agreements into a tailspin of losses virtually overnight. As the build-out, expansion and re-engineering of the gas transmission system continues, identifying optimal transportation routes and avoiding emerging constraints becomes increasingly difficult.

Despite these difficulties, there are opportunities. For utilities operating in the Northeast corridor, new pipeline construction and expansion of existing pipes is helping to alleviate historical constraints and choke-points throughout the region. Additionally, with a massive new source of supply much closer to their generation facilities and/or gas customers, fuel prices should come down over the next several years and reliability should improve. As existing transportation, storage or supply agreements expire, opportunities to reduce costs and further improve reliability of supply will likely emerge.

For traders, the ongoing short to mid-term regional imbalances offer opportunities in what is otherwise a somewhat unexciting market, one that has been enduring relatively low and stable prices for the last couple of years (setting aside the price spikes caused by the extreme cold of the winter of 2013/14). However, in order to take advantage of the opportunities offered by these short lived imbalances, it is important to have a complete and broad view of the market, one that’s informed by improved data visibility, market intelligence and analytics.

In this environment, relying on outdated technologies and historical views of a market that is constantly being reshaped would seem a sure way to be overrun by the relentless tsunami of shale gas and the changes to the market landscape that it continues to bring.

Written By Insider ANDREW BATEMAN


Andrew BatemanAndrew Bateman is president of SunGard’s energy business, which helps energy companies, corporate hedgers, hedge funds and financial services firms to compete efficiently in global energy and commodities markets.

Mr. Bateman has spent more than 15 years at SunGard, helping the company expand globally with new solutions and new markets. Previous roles include executive vice president of global accounts, chief operating officer of international distribution, and managing director of AvantGard EMEA.

Before joining SunGard, Mr. Bateman worked at KPMG Information Solutions/GIS and Rolls-Royce. He holds a bachelor’s degree in physics from the University of Nottingham.

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Challenging and Expanding the Innovation Paradigm http://www.oilgasmonitor.com/challenging-expanding-innovation-paradigm/ Mon, 04 Nov 2013 09:24:18 +0000 http://www.oilgasmonitor.com/?p=6139 Gregg LeStage | Kotter International The word “innovation” is commonplace in the oil and gas industry. It’s the element in the alchemy that can turn stiff competition, high risk, volatility, and capital intensity into rewards. But are we limiting ourselves by defining and pursuing it under current assumptions and practices?   Innovation is an upstream […]

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November 4, 2013
Gregg LeStage | Kotter International
The word “innovation” is commonplace in the oil and gas industry. It’s the element in the alchemy that can turn stiff competition, high risk, volatility, and capital intensity into rewards. But are we limiting ourselves by defining and pursuing it under current assumptions and practices?
 
Innovation is an upstream imperative for scientists and engineers. It is not surprising that the units that make up this sector are the provinces of innovation culture; the professionals that inhabit it are its keepers, and with good reason: Higher oil prices over the past decade and a half have shifted the onus of value creation upstream. In addition, the sheer rate of change has put great pressure on the pace of innovation.

Thijs Jurgens, a vice president at Shell’s Dutch Innovation Lab, observes in a recent issue of Wired magazine that “[t]he world is changing faster and faster, and disruptive innovations are changing the way we work, live, organize ourselves and communicate.” Shell has invested millions to generate big ideas to keep up with or set the pace of change. Among them are the use of solar power to assist oil recovery, deploying space robots on earth, and creating the world’s biggest floating structure – a liquification plant for natural gas.

Cost concerns – in terms of labor, time and money – are dead center in this innovation paradigm, and so are efforts to contain them. Failing cheaply and quickly is a rare exception to the cost rule; it follows that success is expensive and slow. Joe Powell, a research leader in the industry, commented in a recent article in WorldExpro that the oil and gas industry’s upstream “focus on capital-intensive, strategic innovation demands an extremely rigorous approach to innovation.” Capital-intensive means costly: Innovation budgets are disproportionately high. Rigor means process. Stage-gating – or the development approach – ensures persistent rigor from idea to development steps, metrics and milestones. The result, when it works, is a game-changing technology. It produced fracking in the recent past; among likely future innovations will be biofuels.

So, to challenge the assumptions behind innovation today is less about questioning focus areas, cost and rigor. The case for current investment levels and practices is generally sound – and strengthening. What we should be asking is: Where else can we create structures, processes and energy for innovation? Where are the untapped reservoirs of innovation capacity and capability?

Don’t look outside; look inside

The prevailing tendency in oil and gas, as in all industries, is to assign innovation to special task forces, roles, or functions – like Shell’s Innovation Lab – whose main purpose is to innovate. As with strategy, it is also common to associate innovation responsibility with senior leadership or with consultants hired for their outside-in perspectives and ideas. Each of these approaches is an outsourced one. Sometimes temporarily, sometimes permanently, companies select or hire small, elite groups to generate actionable ideas. One can understand why survey results often reveal that the large majority of a company’s employee population sees innovation as “someone else’s job.”

Increasingly, evidence shows that “insourcing” innovation through the disciplined application of specific strategies and tactics is a powerful way for a company to transform itself. Insourcing is a disciplined, multi-step process of engaging a broad representation of an employee population, in large numbers, on a volunteer basis, and over a long period of time. By tapping the vast repository of its own latent expertise, a company can build and sustain a “volunteer army” of innovators to help it grow or transform. The employee experts who do the real work day in and day out actually drive the innovation. This is not idea anarchy, however. Strategic guidance is essential.

Senior leaders from the corporate, business unit, division or function level must align around a “big opportunity” of which they want to take advantage. Among myriad others, it can be an opportunity to reduce costs by creating a more efficient supply chain; or to take market share with a more effective sales force; or to achieve growth through a merger or acquisition. Once identified and articulated, the single most important effort is to make 50 percent of the employee population across all roles, ranks and functions feel urgent – that is, excited and energized – about fulfilling the opportunity. When hundreds or thousands of employees volunteer, they then self-organize into strategic initiative teams tied to the big opportunity. Senior leaders provide direction and support, as well as remove barriers, to ensure the success of the strategic initiatives. As wins are generated and communicated, tangible business results take shape.

To engage a diagonal slice of the organization in a large-scale transformation or innovation effort means to include those who are typically marginalized in such engagements. This includes control and support functions, like HR, Legal, Regulatory, IT and Finance. It also includes individual contributors, first-line managers, and emerging leaders, in addition to long-tenured executives. This is where passion, motivation and energy to innovate and transform reside.

Don’t look up; look down

Where can innovation have impact quickly and significantly in the current environment? Perhaps where it is most necessary. Due to the rising price of oil, low and negative margins compounded by stiffening competition continue to affect broad swathes of midstream and downstream companies and sectors. Identifying big opportunities and amassing and leading volunteer armies downstream could help redress these setbacks.

For example, a company or one of its divisions can unleash an army to create new competitive advantages in refining, such as cracking the complexity code of feedstock and output flexibility, or finding ways to strengthen the trading function by maximizing feedstock/product arbitrage, routing and placement. Customer loyalty, an area of critical importance to both retailing and lubricants, is particularly responsive to initiatives executed on a large scale by employees who have been given guidance, support and permission to innovate.

Without doubt, the energy resource – employees in great numbers – costs almost nothing to discover, extract, convert, and distribute to the reaches of an organization. In the form of coordinated and networked innovation, it can transform a company from slow and constrained to fast and agile.

Few industries are as effective at implementing processes as oil and gas. The potential, therefore, for successfully deploying one like that described above is high, especially when the industry’s hallmark rigor is applied. The challenge is to broaden the definition of innovation concerning where it happens, who contributes, how little it can cost, and the scale on which it occurs. The opportunity for oil and gas is not to shift the paradigm, but to expand it by instituting a process that encourages and enables innovation to be part of everyone’s job.

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