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By Charles Dewhurst
State of the Industry: Low Oil Prices Have Battered, But Not Beaten, the Energy Sector
2015 has been a game-changing year for the oil and gas industry. As the year kicked off, energy executives were cautiously optimistic that faltering oil prices would stabilize relatively quickly—but when the recovery did not materialize, the sector realized it would have to get serious about making some difficult, but necessary, decisions in order to stay afloat until the bust ends and the next boom begins.
While the road ahead remains rocky, there is reason to believe that the new year will bring welcome opportunities to right-size, reorient and prepare for the future. Below, we explore some of the major trends impacting the energy sector as we close the books on 2015 and look ahead to 2016.
Restructuring in Focus, but M&A Market Remains Soft
It is no surprise that many upstream, small to mid-market firms have suffered over the course of the year. According to CNBC, upwards of two dozen companies—mostly smaller players—have negotiated restructuring deals since the collapse in crude prices, but if oversupply persists in pushing prices down, we may expect to see bankruptcies continue into 2016.
At the beginning of 2015, many analysts expected mergers and acquisitions (M&A) to heat up as companies sought to shore up their balance sheets and avoid bankruptcy. According to our 2015 Energy Outlook Survey
from a year ago, 56 percent of energy CFOs expected to see growth in M&A activity in 2015; however, it appears that pervasive gaps between buyer and seller pricing expectations have kept money on the sidelines. With struggling companies holding out for higher valuations, Dealogic reports that only 55 energy industry deals have closed in the U.S. over the course of 2015, compared to 113 transactions completed in 2014.
The winners in this challenging environment have been the larger players who possess the cash and negotiating power for higher-valued assets. For example, Royal Dutch Shell has announced plans to purchase BG Group PLC for $70 billion, and oilfield services giant Schlumberger has pursued a number of acquisitions over the past year, including its purchase of Cameron International Corp. and Fluid Inclusion Technologies.
We may begin to see deal activity pick up somewhat in 2016, but mega-mergers may not be on tap. Our own Clark Sackschewsky recently told Natural Gas Intelligence
that he expects deal flow to be more “focused on assets than actual mergers.” Acquirers may be more interested in purchasing assets that will help diversify their portfolios, or otherwise explore less risky joint ventures. In pursuing smaller-scale deals, purchasers hope to mitigate their exposure to the challenges associated with mergers, including integrating companies, assuming liabilities and managing headcount.
Where is Private Equity?
Contributing to the slowdown in deal flow has been private equity’s pullback from the energy sector. The Wall Street Journal
reports that private equity firms with investments in publicly traded exploration and production (E&P) companies have lost more than $18 billion since oil prices first began to slip. Investments in closely held energy companies have also faltered: According to Reuters, Samson Resource Corp.’s September bankruptcy filing translated to billions in losses for private equity firm KKR, and as of June 30 of this year, annualized returns for Blackstone’s energy fund investors decreased by nearly half from 2014.
But private equity may be poised for a return in the year ahead. Despite a chastening 2015, data provider Preqin estimates that the private equity sector has about $115.6 billion in dry powder for energy deals. As debt financing dries up, private equity funds may step in—particularly while valuations remain depressed.
Oilfield Services Companies Look to Grow Leaner
While the entirety of the energy sector has felt the pain over the past year and a half, oilfield services companies face unique challenges in responding to the new low-price environment. As we noted in our 2015 Global Energy Middle Market Monitor
, oilfield services companies were able to inflate their prices during the boom times, taking advantage of the industry’s voracious appetite for more wells as commodity prices hovered around $100 per barrel.
But as commodity prices have bottomed out, the oilfield services sector has had to reset its pricing structures and make some difficult decisions about how to sustain operations as the money dried up. Like many upstream entities, services companies are cutting their budgets—some by as much as 10 to 15 percent—and shuttering costly, unprofitable operations. Others are seeking efficiencies elsewhere. Halliburton has been exploring new technologies that will help facilitate more work while reducing overhead, and other companies are offering their customers deep discounts in the hopes of maintaining strong ties with drillers that will flourish when prices rebound.
There is a silver lining to this right-sizing, though—those services companies that are able to trim the fat now may emerge from the downturn more nimble than ever and prepared to cope more effectively with the shortening boom-and-bust cycle.
Natural Gas Becomes a Long-Term Bright Spot
Natural gas has experienced something of a difficult year, as well, though not to the same extent oil has. At the beginning of the year, natural gas prices averaged about $2.97 per million British thermal units (MMBtu), a steep drop from the $4.10 per MMBtu that prices were trading at in November 2014. Prices remained relatively stable through October, when they suddenly declined 12 percent—from $2.65 per MMBtu in September to just $2.32 per MMBtu. Prices have yet to recover, and have in fact declined further; natural gas futures contracts for both November and December have hovered around $2 per MMBtu.
While the natural gas price decline has not been as dramatic as that of oil, the same contributing factors underlying the oil price rout have been driving gas prices down, as well. Specifically, the United States is currently experiencing a glut of natural gas. According to Platts
data, the U.S. natural gas supply has averaged upwards of 77 billion cubic feet per day this year as a result of increased production, growth in imports and continued roadblocks to exportation. Meanwhile, warmer-than-normal winter temperatures in the North and Midwest have tempered both consumer and industrial demand. It comes as little surprise, then, that the industry expects to see some right-sizing in the natural gas markets in 2016, as well. According to BDO’s 2016 Energy Outlook Survey
, only 40 percent of energy CFOs expect the domestic supply of natural gas to increase in the coming year, a decrease from 64 percent last year.
However, several forces may converge in the coming year to give natural gas a boost. As temperatures continue to cool off, demand may rebound—a view shared by about half of the respondents in our Energy Outlook Survey
. At the same time, natural gas exports are expected to heat up as liquefied natural gas processing gains momentum. Cheniere Energy, the vanguard of LNG processing and exporting in the United States, plans to begin converting natural gas to LNG in December and is slated to export its first shipment in January 2016, according to Reuters. Furthermore, as Michael Levi of the Council on Foreign Relations argues, the pending Trans-Pacific Partnership agreement could open the floodgates for U.S. companies to sidestep the complicated permitting process and begin exporting natural gas to Japan and other signatories to the agreement in the near future. Nevertheless, the primary barrier to LNG exports—the extensive cost of building terminals—remains, suggesting that the industry should continue to treat the growth of exports as a long game, and a not a short-term profitability play.
Continued Challenges Lie Ahead, but the Industry Can Survive
With 2016 looming and prices remaining stubbornly low, the energy industry expects tough times to continue into the new year. In fact, our Energy Outlook Survey
found that more than half of the energy CFOs polled feel pessimistic about the economy and its impact on demand for oil and gas products in 2016—suggesting that companies are now focusing less on growth and more on protecting their assets until prices recover.
But the current difficult circumstances are unlikely to last indefinitely, and the tumultuous market is survivable. Smart companies will take this opportunity to explore every aspect of their business, leaving no stone unturned as they look to do more with less. Whether that means cancelling less profitable projects and focusing more on core business units, carefully assessing their vendors and service providers, or seeking out new investors or partners, oil and gas companies must be creative and nimble in order to ride out the storm.
Charles Dewhurst is partner and leader of BDO’s Natural Resources practice. He can be reached at firstname.lastname@example.org.
How did you become interested in your line of work, especially your work in the natural resources industry?
BDO Spotlight: Q&A with Dan Dickinson, Tax Director, BDO Anchorage
I didn’t follow the most traditional path to becoming a CPA—I actually started my career in the arts. I obtained my CPA certification by taking night classes at the University of Alaska Anchorage, and went on to serve in several state and municipal departments, including seven years as the director of tax for the State of Alaska.
My time in the public sector helped me gain valuable experience and insights into Alaska’s unique position when it comes to not only the natural resources industry, but also taxation. Alaska’s founding premise was that it would “pay its own way” to statehood through tax revenues attained by developing its rich natural resources. But some seven years after it achieved statehood, Prudhoe Bay—the largest oilfield in North America—was discovered in Alaska’s North Slope, which significantly ramped up the state’s development. Along with this increased growth, however, came myriad disputes surrounding oil taxation and royalties that lasted for many years. I was extensively involved in consultation and litigation throughout this time, and from both the public and private sides of the debate. In other words, I became fully immersed in the industry.
I went on to found my own CPA practice focused on Alaska oil and gas production taxes, and later joined BDO.
What do you see as the biggest challenges facing the natural resources industry today?
The current market downturn is testing and altering relationships and practices throughout the sector. The last time we experienced a price crash of this magnitude was in 2008, when prices plummeted from $100 to $30 a barrel, but managed to rebound within six weeks. But the price correction before that, which began in the mid-’80s, lasted an entire generation. It is likely that the current cycle will fall somewhere between these two extremes, but the exact turnaround time remains to be seen.
The impact of the current downturn is especially pronounced in Alaska. Given the revenue the state accrues from the oil and gas sector, it is particularly sensitive to commodity pricing. During the boom, the state government brought in a lot of money through energy revenues, which it used to establish some aggressive incentive programs in the natural resources sector. Those programs were initially very successful in attracting venture capital dollars. As subsidies grew more attractive and widely known, more traditional players, such as banks, entered the market. But following the price crash, these programs became unsustainable, so we may see investors pulling back out. Given the uncertainty around when prices will bounce back, it’s difficult to predict what the future holds for these incentives.
What’s interesting is that the greatest challenge facing the industry also poses its greatest opportunity. Despite all the negative impacts of the downturn, there are still prospects for growth and development available. Currently, the cheapest way to acquire oil is in purchasing an asset, not in exploration, and strategic buyers are hunting for deals while prices remain low. For those companies that are able to finance favorable deal arrangements, the current pricing situation may turn out to be a boom, rather than a bust.
How is Alaska’s natural resources sector performing in comparison to the broader U.S. industry? What unique opportunities or challenges might oil and gas companies encounter?
Alaska’s natural resources sector is unique in that the role of the state government is so deeply ingrained in the industry. For some entities, the largest positive cash flow consists of the state’s incentive payments. On the other hand, there are many projects where the largest expense is anticipated to be payments to the state—the combined effect of all taxes and royalties. Due to this distinct situation, the government’s strategies in dealing with the price downturn will directly affect oil and gas companies operating in Alaska to an unparalleled degree, though differently positioned companies will face distinct effects. Additionally, Alaska relies on conventional methods of production. The low amount of fracking activity in the state presents its own set of challenges and opportunities. On one hand, Alaska is less susceptible to the boom and bust cycles of fracking activity and is not heavily impacted by new federal fracking regulations. On the other, the lack of fracking activity means that the state is heavily dependent on oil prices and production from conventional plays, and cannot use natural gas activity to counterbalance the current oil bust.
How are Alaskan oil and gas entities responding to today’s down market? What steps should they be taking to protect their businesses?
Companies are taking a wide variety of steps to protect their businesses. The main way many have responded is by spending more time with their bankers, although not necessarily by choice. They are—smartly—looking to shore up their financing, but because investors remain uncertain and risk-averse, companies are turning to non-traditional funding sources. Companies are also closely evaluating various contracts to find any available relief measures to cushion them until prices rebound. Many are meticulously evaluating their quality of work in hopes of qualifying for the few state incentives still available. Lenders are closely evaluating potential loans against anticipated credits. In the political sphere, companies are heavily lobbying government officials to extend or increase exploration, development and/or production incentives, and while these are generally agreed to be positive across the board, the reality is the state currently just can’t afford to make outright payments.
Of course, as producers and financiers contract, this may be a good time to get excellent value from service and support entities, if the cash can be found to support a project.
How have recent developments in Arctic drilling—Shell suspending operations and the Obama administration canceling further lease sales—affected the Alaskan economy? How might they affect the national oil and gas industry?
The impact of recent developments in Arctic drilling is mainly one of perception, creating an air of pessimism and uncertainty surrounding the Alaskan oil and gas sector. Job losses may be an immediate and tangible problem for the state, but the long-term loss of business is ultimately the larger issue. However, given that these developments are mainly impactful at the state level, they do put pressure on the Alaskan government to find a way to pay for incentives that may attract smaller energy players.
While the shockwaves felt in Alaska are fairly self-contained, they do have the potential to ripple out to the national oil and gas sector, as well. These developments also bring into play many larger questions surrounding Arctic policy and involve the state in environmental and governance issues with a number of nations. If the United States limits its economic involvement in the Arctic, there may be political consequences vis-à-vis other economic powerhouses in the region, including Russia, who have a much larger presence and better Arctic production capabilities.
How would you describe the impact of the work you do? How do you create value for clients?
Alaska’s situation is truly unique, and the work I do allows both lenders and producers to benefit from BDO Anchorage’s knowledge and experience in the area. We have an extensive history and depth of understanding of Alaska’s various incentives program, and we seek to serve as a link between the state credit system and E&P companies.
At the end of the day, we look to help create good outcomes for our clients. As the opportunity space changes—and it’s changing rapidly—the ways we can add value change, as well. Everyone has the same amount of spray paint covering his or her crystal ball. Having experienced advisors to assist with working through issues can help refine the client’s vision and arrive at the path most likely to lead to that good outcome.
By Daniel Fuller
Renewable Energy: A Spotlight on Clean Energy Incentives
Tax incentives for energy conservation first appeared in the same legislation that established the modern income tax in 1913. Although income tax is a congressional constant, green energy incentives ebb and flow with political and economic tides. The mood on Capitol Hill may be murky, but thanks to the December 2015 extension of renewable energy tax incentives, there are still paths to greener tax pastures for renewable energy companies and investors.
Section 45 Renewable Electricity Production Tax Credit (PTC)
In December 2014, the Tax Increase Prevention Act of 2014
extended the expiration date for this tax credit to Dec. 31, 2014. Projects that were not under construction prior to Jan. 1, 2015, are ineligible for this credit. In March 2015, IRS Notice 2015-25 extended the Continuous Construction Test and Continuous Efforts Test (used to determine if a project commencing construction before the end of 2014 is eligible for the PTC) by one year to Jan. 1, 2017. This credit is applicable for electricity production facilities utilizing biomass, geothermal, hydropower, marine and hydrokinetic, municipal solid waste, small irrigation or wind power. This credit is based on a fixed amount per-kilowatt-hour of electricity produced—2.2 cents for wind, geothermal or closed-loop biomass and 1.1 cent for other eligible technologies. Taxpayers can take the credit for a 10-year period beginning on the date the facility is placed in service (this time frame is reduced to five years for geothermal energy, small irrigation and municipal solid waste facilities.)
Section 48 Business Energy Investment Tax Credit (ITC)
An alternative to the PTC is the Section 48 Business Energy Investment Tax Credit (ITC), which is a credit based on the tax basis of the energy property placed into service by Dec. 31, 2016: 30 percent for Solar Water Heat, Solar Space Heat, Solar Thermal Electric, Solar Thermal Process Heat, Solar Photovoltaics, Wind (All), Municipal Solid Waste, Fuel Cells using Non-Renewable Fuels, Tidal, Wind (Small) and Fuel Cells using Renewable Fuels; 10 percent for equipment producing or distributing geothermal energy, equipment that uses the ground or groundwater to heat or cool a structure, qualified micro-turbines, or combined heat and power systems. In an attempt to provide more certainty around subsidies for PTC-qualified energy facilities, legislation was passed in 2009 allowing certain PTC facilities to opt instead to take ITC.
Monetization Strategies for Energy Credits
The primary strategy used by developers and tax equity investors to own and operate renewable energy projects eligible for the PTCs and ITCs is the “partnership flip” structure (see the illustration below). Under this structure, the entity that directly owns the renewable energy property is required to be taxable as a partnership for federal income tax purposes because current federal tax law mandates that federal income tax credits and depreciation tax deductions cannot be sold. Therefore, instead of buying federal income tax benefits, a federal tax credit investor would literally invest cash, in the form of a contribution to the partnership, in exchange for a capital and profits interest in the partnership. As a result, each partner/owner of the underlying partnership property is allocated his or her respective share of partnership tax benefits, which can include income, gain, deductions, loss and tax credits. With an ITC and the partnership structure, the partner receiving the investment tax credit benefits must be a partner in the project entity prior to the project being placed in service for federal income tax purposes.
In the flip structure there is either a General Partner (GP) or Managing Member who is typically the project sponsor and manager, and one or more separate Limited Partners (LP) or “Investor” Members who are primarily motivated to obtain state tax credits (if any exist). In most cases, there will also be a separate “federal investor” who is primarily motivated to obtain federal tax benefits. Investors often evaluate their level of investment in terms of a target yield. That yield is then compared to other investments that investors might make or to the percentage of project cost that is expected to be covered by their tax equity investment.
The GP or project sponsor could be the project developer as well. The sponsor may or may not have the right to earn a developer fee for his or her efforts as both the project sponsor and business manager of the project. The lender, if any, is typically an unrelated third-party financial institution.
Project capital costs are covered, therefore, by a combination of sponsored equity, tax investors (the “tax equity”), equity raised from state tax credit investors, state or local grants, rebates, subsidies, etc.; and sales (including pre-sales) of renewable energy certificates, carbon offsets, heat or power. The balance of construction sources are typically made up with debt.
The ITC also contains recapture provisions that apply to an underlying energy property that is disposed of or otherwise ceases to be energy property with respect to the taxpayer before the end of its five-year recapture period (starting from the year the property was placed in service). The ITC vests at 20 percent per year over the five-year recapture period.
A variety of actions may result in recapture. First, the sale of a partnership interest or shifting allocations may be dispositions subject to recapture. Moreover, the interest reduction rule states that recapture is required if a partner’s interest in the partnership is reduced by a sale to less than two-thirds of what it was when the ITC was claimed. The two-thirds reduction rule stays in effect during the five-year recapture period and a proportionate amount of the credit is subject to the recapture calculation. Recapture may also occur if there is a reduction in the taxpayer’s amount at risk or if there is an increase in non-recourse financing during the five-year period.
Companies should consult their tax advisor regarding these transactions, as partnership allocations must have substantial economic effect. The IRS has also issued Revenue Procedure 2007-65, which is specific to wind and sets a safe harbor for taxpayers. Although the ruling only applies to wind power, most participants are comfortable applying its principles in the solar context.
The other common strategy is a sale-leaseback in which the lessor obtains tax-invested capital (see the illustration below). In this structure, the tax investor is the owner/lessor and, as such, is entitled to the credits and depreciation. The tax investor further benefits by being able to mitigate operations risks by locking in purchase price and stream of rental payments. The developer is able to receive up-front proceeds from the sale of property while transferring full ownership of the property, however, the transaction must occur within 90 days of the original placed-in-service date.
One of the advantages of a sale-leaseback structure is that it largely insulates the investors from operations risks by placing a barrier between the project ownership and the project operations. On the other hand, it costs more for the developer to get the project back. After the lease ends, the developer can only continue using the project by purchasing it from the investor at fair market value.
Tax incentives are essential to the deployment of solar energy in the U.S., and the recent extension of clean energy tax credits offers myriad opportunities for renewable energy companies. As developers prepare to introduce clean and renewable energy projects, they will also want to combine novel technology, stable returns and secured financing through tax equity investments, traditional financing, or a combination of the two. Developers will be able to position themselves for success if they implement a solid business plan and ensure they have a firm understanding of the available tax equity options for additional certainty in their business’ future.
Daniel Fuller is a tax partner in BDO’s Grand Rapids office. He can be reached at email@example.com.
Did you know...
The Energy Information Administration
predicts U.S. crude oil production will decrease to 8.8 million barrels per day in 2016.
According to BDO’s 2016 Energy Outlook Survey
, 60 percent of energy chief financial officers (CFOs) expect changes in oil & gas prices to be the single most important factor dictating whether the industry recovers in the coming year.
In its Oil Market Report, the International Energy Agency
forecasts that global demand will slow to 1.2 million barrels per day in 2016.
In September, Goldman Sachs
cut its 2016 Brent price predictions to $49.50, a significant decline from its prior forecast of $62.
The BDO 600 2015 Survey of Board Compensation
found that directors of middle market energy companies experienced a 14 percent increase in compensation between 2013 and 2014, the largest increase seen among the industries analyzed.
According to MarketWatch
, oil prices declined to about $37 per barrel on Dec. 7—the lowest level seen since 2009.
PErspective in Natural Resources is a feature examining the role of private equity in the natural resources sector.
PErspective in Natural Resources
Low oil prices continue to cause pain in the oilfield services sector. As the current supply glut leads big oil producers to slow production, services companies are left competing for a shrinking number of oil projects. Since 2015, oil producers have pulled back more than $200 billion in spending, reducing the number of projects available to a quarter or even a fifth of usual levels, The Wall Street Journal reports. Facing intense pressure over pricing, falling stock prices and heavy quarterly losses, services firms have been forced to slash costs wherever possible, from mass layoffs down to changing the color of the paint on underwater equipment. Many firms are paring down their operations and exiting certain markets.
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