Archive for the ‘BDO USA Industry Publications Feed’ Category

BDO 2017 Energy Outlook

Posted on: January 24th, 2017 by BDO USA Industry Publications Feed


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“American oil & gas companies have demonstrated remarkable resilience amid the continued industry downturn this past year. Spurred by OPEC actions, oil prices are steadily climbing and the sector is regaining a sense of optimism that will hopefully come to fruition in 2017 and beyond.” — Charles Dewhurst, global leader of BDO’s Natural Resources practice.  

Commodity Prices Thaw, Optimism Buds in 2017 

In a market oversaturated with oil, financial success was in short supply for the U.S. oil & gas industry in 2016. But recent OPEC actions have generated renewed confidence, suggesting the sector could be poised for a turnaround. According to BDO’s 2017 Energy Outlook, energy CFOs are anticipating the industry could make strides toward recovery in 2017.  

Oil prices hit the bottom of the barrel in 2016, exerting severe financial stress on U.S. energy companies. In fact, 2016 was the toughest year for survey respondents since the downturn hit in 2014. Fifty-eight percent of energy CFOs report project terminations and delays in 2016, up slightly from 53 percent last year. Low oil prices are the most commonly cited cause of project interruptions, noted by 91 percent of respondents reporting cancellations or delays in the past year. Prices dipped to $26.21 per barrel in February—a 75 percent decline from the market’s 2014 peak at $108 per barrel—and the lowest point since 2003, according to CNN Money. Other factors contributing to project interruptions in 2016 include federal and state environmental regulations (56 percent)—more than double the number reporting such interruptions last year—and lack of capital (49 percent).

On the heels of a difficult year, energy CFOs have a relatively optimistic outlook for 2017. Confidence is up that commodity prices will rise: 57 percent of CFOs predict a price increase for natural gas and 64 percent forecast an increase in oil prices. Sixty-three percent of energy CFOs believe increased oil & gas prices will drive overall industry growth in the year ahead, a slight uptick from last year (60 percent) and a remarkable resurgence from 29 percent in 2015. But what accounts for the returning sense of optimism among energy CFOs?

Global Players Increasingly Influence Market

Signs of cautious market recovery began in late September,[1] when OPEC announced its intent to cut oil production and output for the first time since 2008. Speculation as to whether the 13 member countries could reach an agreement was put to rest on Nov. 30, when OPEC announced a formal deal to reduce output by 1.2 million barrels per day (bpd) to 32.5 million bpd. Perhaps even more significant is that for the first time since 2001, non-member countries—Russia among them—joined OPEC’s initiative and pledged to reduce production by a combined 558,000 bpd.

In the period following OPEC’s decision, the effects on the market have been palpable. In December, Fortune reported prices hit a peak of $57 per barrel—the highest point in 18 months. The industry’s strong reaction is unsurprising; a plurality of energy CFOs (47 percent) identify OPEC actions as the key contributor to price volatility other than supply and demand.


Despite the recent upswing in oil prices and widespread anticipation that they will continue to rise, the industry is not expected to fully recover to highs of $100 per barrel in the near term—a price that was once relatively normal. A majority (62 percent) of energy CFOs cite low oil and gas prices as their greatest financial challenge in 2017, down from 85 percent last year. In addition, fewer CFOs—49 percent this year, compared to 55 percent last year—expect decreasing prices to inhibit growth. While this decline suggests improving sentiment in the industry, it is clear low prices are still a considerable concern.


M&A Accelerates, But Likely to Level in 2017

Upstream oil &  gas M&A activity in 2016 totaled $56.7 billion by mid-November, far outpacing the $26.8 billion raised over the same period last year, according to CNBC. This ramp-up in activity is consistent with the industry’s expectations for 2016, but CFOs generally think deal-making will taper slightly in the year ahead. Two-thirds expect M&A to increase, down from 75 percent last year, while 32 percent expect it to stay consistent with 2016 levels. Unsurprisingly, the bulk of M&A activity in 2016 is largely concentrated in the Permian basin. According to the U.S. Energy Information Administration (EIA), the number of active onshore and offshore oil rigs in the resource-rich area—consisting of parts of West Texas and New Mexico—is nearly equivalent to the rest of the nation’s aggregate total.

Fifty-four percent of CFOs say private equity will be the primary source of capital behind industry transactions in 2017, suggesting that we can expect to see firms continue to leave the sidelines as the financial position of U.S. E&P companies slowly improves. Renewed interest could be a result of the improving exit environment for PE firms. This October, the industry saw Extraction Oil & Gas go public, the first E&P IPO since 2014, and the energy industry’s biggest in 2016.

“Throughout the downturn, private equity interest in the energy industry largely stemmed from firms dedicated to the space. With the uptick in oil prices, however, we expect investments in the energy sector could become a regular asset in private equity portfolios across the board.” — Brad Ross, managing director with BDO Transaction Advisory Services




Labor & Compensation Outlook Brightens 

Throughout the downturn, belt-tightening and cost-cutting initiatives have impacted wages and hiring at every position within energy companies. According to our 2014 Energy Outlook—fielded well before the price crash—61 percent of CFOs expected their labor costs to increase in the coming year. By 2016, that number had declined to a low of 23 percent. However, this year’s survey suggests that things may be looking up for wages, with 29 percent of CFOs saying they expect labor costs to increase in 2017—and only 6 percent expecting a decline (in contrast, 22 percent of CFOs expected labor costs to decrease last year). Headcount reductions are likely to start to subside in 2017, as well, with the proportion of CFOs anticipating hiring additional staff more than doubling, from 10 percent last year to 23 percent this year.

Compensation may also begin to right-size as prices recover. In contrast to last year’s stagnant or decreasing annual bonuses, 12 percent of CFOs anticipate bonuses will increase in fiscal year 2016, compared to just 2 percent the prior year. A plurality of CFOs (44 percent) expect bonuses to be smaller for fiscal year 2016; however, this represents a decrease from 57 percent in our 2016 study.

In terms of their own compensation, energy CFOs are slightly more optimistic than they have been in years past. The downturn has taken a toll on executive compensation in the industry: According to the BDO 600: 2016 Survey of CEO/CFO Compensation Practices, middle market energy CFOs saw their total direct compensation decrease by nearly 6 percent between fiscal years 2014 and 2015. But the 2017 Energy Outlook finds that energy CFOs may be feeling sunnier about their pay packages in the coming year, with more than two-thirds (68 percent) believing their compensation will remain the same. However, 19 percent do expect an increase—nearly double the number anticipating an increase last year. Meanwhile, just 13 percent believe their compensation will decline, down from 20 percent in 2016.

“As commodity prices begin to rise, the outlook for hiring and compensation will likely begin to reflect the industry’s resurgence. Energy companies will need to recruit and retain a strong set of skilled workers to fully capitalize on opportunities in the current market.” — Rick Smith, managing director with BDO’s Global Employer Services 


Changing Regulatory Environment is Top Concern

Concerns surrounding the 2016 general election were high when the survey was fielded,[2]with 42 percent of CFOs identifying it as their top political concern. As expected during a presidential election year, concerns around legislative and regulatory changes ramped up for 2017. The proportion of CFOs citing legislative changes as their greatest financial challenge in the coming year more than tripled—15 percent compared to just 4 percent in 2016. Concerns around industry regulation may have subsided in part following the election results, as President-elect Donald Trump has indicated a preference for policies that may prove friendlier to the energy industry than those passed in prior administrations.

Although a majority of energy CFOs (62 percent) feel better about the U.S. economy, up from just 44 percent last year, fears of a recession and its impact on oil price volatility saw an uptick from 8 percent to 15 percent in 2017. The economy’s overall strength and the direction set by the new presidential administration will be of utmost importance to the energy industry in the coming months.
“A sense of uncertainty was prevalent in 2016 in anticipation of the U.S. general election and in the months following the Brexit vote. That uncertainty is likely to persist in early 2017, as energy companies wait to see how the new administration’s policies will take shape and what impact they will have for the industry.” – Tom Elder, co-leader of BDO’s Natural Resources practice

New Partnership Taxation Rules to Impact Sector

Consistent with prior years, intangible drilling costs and percentage depletion are the top tax issues for the sector, cited by 42 percent and 32 percent of CFOs, respectively. Percentage depletion has become a bigger concern for the industry in 2017, up from just 24 percent last year. This shift could stem from new regulations that the IRS issued in October set to impact companies across all industries that use partnership structures. The regulations address liability allocations under IRC Section 752 and contain guidance on disguised sales under IRC Section 707. In addition to implementing an accelerated filing date of March 15, the new IRS audit regulations add an additional layer of complexity to the already intricate nature of partnership structures in the oil & gas industry. Under the new regulations, if a partnership under IRS audit has an assessment that increases taxable income, the tax assessment may fall to the partnership itself rather than members of the partnership.

“Whenever there is a transition between presidential administrations, the potential for tax reform becomes a larger concern across all industries. Energy companies are particularly attuned to any changes to tax policy that could impact their bottom line. Adjusting to the recent IRS rulings on partnership taxation is one area that CFOs will likely prioritize in 2017.” — Clark Sackschewsky, tax managing principal with BDO’s Natural Resources practice



Industry Keeps a Close Watch on Supply and Demand

With a proliferation of macroeconomic factors impacting the supply and demand of oil and natural gas, the industry is keeping a close eye on global production levels and the level of oil in the market. Overall, CFOs generally expect to see more robust global and domestic demand for oil and gas than in the previous year. CFOs are slightly more bullish on natural gas, with a majority expecting to see both global (56 percent) and domestic (68 percent) demand grow in the coming year. On the oil side, respondents expect demand to remain consistent with 2016 levels. A majority expect the domestic supply of both oil and gas to either increase or remain the same. Perhaps contributing to the expected uptick in supply, more CFOs (36 percent) plan to increase their investment in non-conventional exploration this year, compared to 32 percent in 2016.

More than two-thirds of CFOs (69 percent) believe liquefied natural gas (LNG) and/or crude exports are likely to grow in 2017, which closely aligns with the current pace of production and loosening restrictions on U.S. exports. In November, the United States exported an average of 7.4 billion cubic feet of natural gas per day—becoming a net exporter of natural gas for the first time in nearly 60 years, according to S&P Global Platts and the EIA. The U.S. Energy Department predicts that the country will be the world’s third largest producer of LNG for export by the year 2020.


Addressing Environmental Pressures, Alternative Energy is Top of Mind

In November, the U.S. Environmental Protection Agency (EPA) finalized renewable fuel standard volumes for the upcoming year. Representing a 6 percent increase from 2016, total renewable fuel standard volumes are set at 19.28 billion gallons for 2017. With alternative energy continuing to grow as a global fuel source, oil & gas executives are sizing up the competition. Coal is likely to be most directly impacted by the expanding market for alternative energy. In fact, nearly three-fourths of CFOs (72 percent) identify coal as the energy source that is most at risk due to growing competition from alternative fuels. 

CFOs also appear to be placing renewed focus on addressing environmental regulation in 2017, with 37 percent saying they will focus their risk reduction activities in this area, up from 21 percent last year. Environmentally friendly technologies have become a slightly larger priority in 2017 as well, with 27 percent of CFOs planning to increase their investment, up slightly from 22 percent in 2016. Interestingly, a plurality (31 percent) of CFOs say they will direct the most resources toward water pollution and usage in 2017, and the number of CFOs citing the impact of hydraulic fracturing as an environmental priority decreased to 27 percent. These priorities could shift in the year ahead and might prove more closely aligned, however, after a recent EPA report concluded that fracking could contaminate drinking water in some cases.

After a more than two-year slump, the energy industry could take strides to recover from the extended period of financial hardship in 2017. Driven by global collaboration among OPEC and non-member countries, supply and oil prices are both slowly beginning to stabilize. Energy companies that capitalize on the current market opportunities with an eye toward hedging against unexpected downturns ahead will position themselves for more sustained success and operations in the future. 

Residual Effects of Downturn Persist

A total of 213 North American oil & gas companies filed for bankruptcy between 2015 and November 2016, according to the Houston Chronicle. While the frequency of bankruptcy filings among E&P companies has waned toward the end of 2016, 53 percent of energy CFOs expect bankruptcies to increase in 2017 as companies continue to cope with the fallout of record low oil prices in the past year.

More than half (53 percent) of respondents believe shedding distressed assets will be the primary driver of M&A activity, followed distantly by revenue and profitability (18 percent) and enhancing reserve replacement (16 percent). Perhaps even more telling, 35 percent of CFOs expect their own companies will sell off distressed assets in 2017.

Despite residual effects of the downturn, there are signs of lessening financial stress on energy companies in 2017. Fifty-nine percent of CFOs feel better about their ability to access capital, up slightly from 55 percent last year. The energy industry is eager to streamline operations, with 65 percent likely to seek efficiencies and cut costs to improve profitability, up from 59 percent last year—suggesting the frugal attitude nurtured during the downturn persists even as conditions improve.


“While the climate for the energy industry is looking more positive in the year ahead, most businesses are still contending with the financial strain introduced by the downturn. Whether energy companies have already filed for bankruptcy or plan to in the coming months, balance sheet and operational restructuring will continue to be a key feature of the industry in 2017.”  — Basil Karampelas, managing director in BDO Consulting’s Business Restructuring and Turnaround Services practice


The BDO 2017 Energy Outlook Survey is a national telephone survey conducted by Market Measurement, Inc., an independent market research consulting firm, whose executive interviewers spoke directly to CFOs at 100 U.S. oil & gas exploration and production companies from September through November 4, 2016. The sample comprised companies of all sizes, though was weighted more heavily towards companies with the largest annual revenues.

For more information on BDO USA’s service offerings to this industry, please contact one of the following regional practice leaders: 

Charles Dewhurst


Jim Johnson

Kevin Hubbard
  Rafael Ortiz

Richard Bogatto 
  Clark Sackschewsky


Tom Elder 


Chris Smith
Los Angeles


Vicky Gregorcyk 


Alan Stevens 


Rocky Horvath


Basil Karampelas

Rick Smith


[1] 82 percent of respondents to BDO’s 2017 Energy Outlook were surveyed after OPEC announced its intent to cut output on Sept. 28, 2016.
[2] Survey responses were collected prior to the 2016 election.

Tech Predictions for 2017: A Golden Year Ahead

Posted on: January 19th, 2017 by BDO USA Industry Publications Feed

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BDO Capital Manufacturing & Distribution Newsletter

Posted on: January 16th, 2017 by BDO USA Industry Publications Feed

M&A activity in the Manufacturing & Distribution (M&D) sector was down approximately 15 percent in 2016. A decline was expected after a record 2015, and amplified by the sluggish economy and a brutal election season, which delayed sale decisions. Financial buyers made gains in the sector, backing nearly 40 percent of all closings, including platform and add-on investments, in 2016. This figure is up from 34 percent just two years ago. Election results buoyed M&D investor optimism, given the new administration’s commitment to propelling the U.S. manufacturing industry. Although time will tell if optimism is warranted, our M&D Index beat the S&P 500 by more than 2x in the 3 weeks following Election Day. Read about this and other trends in the industry in BDO Capital’s Manufacturing & Distribution Q1 2017 M&A Review & Outlook


BDO Capital Advisors, LLC, a FINRA/SIPC member firm, is a separate legal entity and is an affiliated company of BDO USA, LLP, a Delaware limited liability partnership and national professional services firm.

Brokerage Insights – January 2017

Posted on: January 12th, 2017 by BDO USA Industry Publications Feed

SEC Issues No-Action Letter for Broker-Dealers Under New Lease Accounting Standards
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On November 8, 2016, the U.S. Securities and Exchange Commission’s (SEC) Division of Trading and Markets issued a no-action letter pr…

Same Difference: A Comparison of International Health Systems

Posted on: January 10th, 2017 by BDO USA Industry Publications Feed

Healthcare stories dominate headlines around the world. Recently there has been a focus on increased demand caused by growing and ageing populations, the introduction of new technologies and the need to contain spread of conditions such as obesity …

[Infographic] Middle Market M&A Activity in Q3 2016

Posted on: January 10th, 2017 by BDO USA Industry Publications Feed

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PErspective in Natural Resources – Winter 2016-2017

Posted on: December 22nd, 2016 by BDO USA Industry Publications Feed

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A feature examining the role of private equity in the natural resources sector.
Consolidation is picking up in the midstream oil and gas sector as oil prices slowly rise and several players look to M&A to achieve growth. Ye…

Selections Newsletter – Winter 2016

Posted on: December 21st, 2016 by BDO USA Industry Publications Feed


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Table of Contents

R&D for IPAs: Tax Breaks for Brewpubs
Variable Interest Entities – Guidance on ASU 2015‑02
Nine Questions Brewery Owners Should Ask Their CPAs
Proposed Regulations May Limit Discounts on Family Transfers – Guidance on IRS Section 2704
2016 Year in Review: Tax Planning for Restaurants

R&D for IPAs: Tax Breaks for Brewpubs

By Dirk Ahlbeck, Chris Bard, Chai Hoang

Over the past few years, it has become clear that craft beer is trending in the fast casual scene. While most fast casuals are stocking and selling, brewing their own beer is just around the corner. Owning and operating a brewery can be an expensive business, from the cost of maintenance and ingredients for brewing the beer, to employee compensation and everything in between. But a successful brewpub is well worth the cost: Not only are breweries significant for the restaurant industry, they are also stimulants for the agricultural and tourism industries, so many stand to benefit from their continued prosperity.

What can fast casuals brewing their own beer do to help keep their costs in check and the lights on? One often-overlooked option is taking advantage of the broad array of state, local and federal incentives available to businesses of all sizes for their investments to develop new or improved products and processes. For instance, many business owners may not realize that they needn’t be a high-tech business to qualify for state and federal R&D tax credits. In fact, a wide swath of activities are eligible for these credits, not just groundbreaking discoveries, but also activities to incrementally improve products and processes. Even failed attempts can qualify. In fact, they’re even more likely to qualify.

Picture this: A local watering hole just opened in Far Rockaway, N.Y., and is already loved by New Yorkers old and young. This establishment brews and sells a large craft beer selection on site in addition to quick and tasty bites, allowing customers to enjoy both in-house and at home. The employees are continuously attempting to develop new hopping techniques and fermentation processes and have recently explored the idea of opening a separate bottling facility. As a registered distributor, this restaurant would be entitled to several tax credits and incentives.

At the federal level, helpful resources like the U.S. Small Business Administration (SBA) encourage innovation and healthy businesses. Through the SBA, several incentives for small businesses are funded, including one that is particularly relevant to brewers, the Small Business Innovative Research Grant Program (SBIR). This program helps to fund R&D through contracts and grants, awarding nearly $2.5 billion annually.

Brewers would also be remiss if they didn’t consider the opportunities that came with the passage of the Protecting Americans from Tax Hikes (PATH) Act of 2015. As a part of the PATH Act, many small businesses have a new opportunity to reduce their taxes, namely by offsetting their Alternative Minimum Tax (AMT) with R&D tax credits. In addition, some startup businesses can elect to take up to $250,000 in credits against their portion of payroll taxes (FICA) annually for up to five years. This allows companies to monetize credits where they previously could not due to a lack of federal income tax liability.

Several state and local incentives are available to the brewpub, as well. As a new business in the state, the brewery should consider the START-UP NY program, which offers companies tax incentives for up to 10 years. Tax credits for this program encompass many taxes, including license and maintenance fees, sales and use tax, real estate/real property transfer tax and personal income taxes for New York state, New York City and Yonkers. For some, this program means no taxes at all. In addition, New York State offers exemptions that eliminate sales taxes on purchases of production machinery and equipment, property used for R&D purposes or fuels/utilities used in manufacturing and R&D.

Also available is the alcoholic beverage production credit, which is applicable for tax years beginning on or after Jan. 1, 2016. This credit is equal to 14 cents per gallon for the first 500,000 gallons of beer, cider, wine or liquor produced in New York state in a tax year, plus 4.5 cents per gallon for each additional gallon over 500,000 (up to 15 million additional gallons for beer, cider and wine, and up to 300,000 additional gallons for liquor) produced in New York state in the same tax year.

New York is hardly the only state to make major investments to attract startups and small businesses— states and municipalities nationwide offer a variety of tax credits and incentives to complement those provided at the federal level. Given their ready availability, these incentives should be a critical part of the planning process for anyone thinking about opening a new brewpub, expanding into a new market or adding a brewing component to their existing restaurant. Businesses are encouraged to consult their tax advisor and reach out to their local SBA office or state and local economic development agencies to determine which incentives will yield the greatest benefit.
Dirk Ahlbeck is a tax partner in BDO’s Restaurant practice. He can be reached at

Chris Bard is the practice leader for BDO’s Specialized Tax Services Research and Development practice. He can be reached at

Chai Hoang is a manager in BDO’s Specialized Tax Services Research and Development practice. She can be reached at

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Variable Interest Entities – Guidance on ASU 2015‑02

By Giselle El Biri

The variable interest entity (VIE) rules continue to be a hot topic for restaurants. Many times, a restaurant may set up separate legal entities for various purposes, such as a real estate entity that owns the restaurant facility or a separate entity to operate a commissary. These organizational structures are typically driven by a potential positive tax outcome. However, under the VIE rules, the separate entities may be required to consolidate. These rules address situations in which an entity is structured in such a way that normal voting interest consolidation concepts may be ineffective in determining which party has a controlling financial interest. In other words, there are times when a controlling financial interest is achieved through an arrangement that may not depend on the voting rights of equity holders. 

Once a company has determined that none of the scope exceptions are applicable, analyzing whether an entity must be consolidated under the VIE guidance typically involves answering the following three questions: 

1. Does the company hold a variable interest in the entity?
2. Is the entity a VIE?
3. Is the company the primary beneficiary of the VIE? 

Early last year, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis, revising the VIE guidance, impacting each of the above questions. Over the course of two blog posts, we will explore each of these questions in more detail to illustrate how your restaurant business may be affected.

Does the company hold a variable interest in the entity? 

Some arrangements may obviously constitute variable interests, such as if the reporting entity holds an equity or debt interest in the entity, or if there are any guarantees exposing the reporting entity to risk of loss.  However, other situations may not be as obvious.  For example, licensing or royalty arrangements or management fee contracts may also be considered variable interests.

ASU 2015-02 specifically addresses management and similar fees, providing three criteria to assess in determining whether these types of arrangements have a variable interest:
a) The fees represent compensation for services provided and are commensurate with the level of effort required to provide those services.
b) The decision maker or service provider does not hold other interests in the VIE that individually or collectively would absorb a significant amount of expected losses or residual returns.
c) The service arrangement includes only terms, conditions or amounts that are customarily present in arrangements for similar services negotiated at arm’s length.

If all three criteria are met, then the fee is not a variable interest.  If not, the fee must be included when determining whether the company receiving the fee is the primary beneficiary or not.

Is the entity a VIE? 

Under the VIE guidance, an entity is a variable interest entity if either of the following are true: 1) The entity’s total equity at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support; or 2) As a group, the holders of the equity at risk lack the power to direct the activities of the entity that most significantly impact its economic performance; the obligation to absorb the expected losses of the entity ; and the right to receive the expected residual returns of the entity.

The equity investors as a group also lack power if both:

  1. The voting rights of some equity investors are not proportional to their obligations to absorb the expected losses of the entity or their right to receive the expected residual returns; and
  2. Substantially all of the entity’s activities involve or are conducted on behalf of an investor that has disproportionately few voting rights.

ASU 2015-02 clarified this guidance by providing additional factors to consider when determining whether the equity investors as a group lack power.  Those factors are different depending on whether the entity in question is a limited partnership or not.

Limited partnerships and similar legal entities (LPs)

The provisions of ASU 2015-02 eliminate the presumption that the general partner consolidates an LP.  There is now a two-step process in determining whether the partners of the LP, as a group, have the power to direct its activities.  This test includes analyzing whether there are substantive kick-out rights or significant participating rights.  For example, are the limited partners involved in the daily operations of the company? Is it “majority rules” if the limited partners agree to kick out the general partner?  In addition, in certain instances, liquidation rights may be considered the same as kick-out rights.  If the entity lacks both of these conditions, then the LP is a variable interest entity, and the company must consider the next question—whether it is the primary beneficiary of the LP—by analyzing its power to direct the LP’s activities and economic performance.

Entities other than LPs

Entities other than LPs, such as corporations, are analyzed similarly to LPs.  Do the equity holders collectively have rights to effectively direct activities that most significantly impact economic performance?  Does a single equity holder bear all of the risk or hold kick-out or participating rights over the decision maker?  If the answer to both these questions is no, then the entity is a VIE.

Is the company the primary beneficiary of the VIE?

The primary beneficiary is the entity that has both the power to direct the activities of the VIE that are most significant, and the obligation to absorb losses or the right to receive benefits that could be significant to the VIE.  When assessing whether a company is the primary beneficiary of a VIE, it must also consider the variable interests its related parties hold.

ASU 2015-02 also addresses how to include interests related parties hold when performing the primary beneficiary analysis.  Under this provision, how the reporting entity includes an interest a related party holds is based on whether the two entities are under common control or not. 

If the entities are not under common control, then the indirect interests the related party holds are included on a proportionate basis.  For example, if a company holds a 40 percent interest in another entity, and that second entity holds a 20 percent interest in the VIE, then the company holds an 8 percent indirect interest in the VIE. Conversely, indirect interests held through related parties that are under common control with the decision maker are considered the equivalent of direct interests in their entirety.  In this example, the company would hold the full 20 percent interest in the VIE that its equity method investee holds.

In addition, ASU 2015-02 indicates that if no single entity within a related party group holds both the power and economics related to the VIE, then a related party tie-breaker test should be performed to identify the primary beneficiary. In this instance, the party most closely associated with the VIE will consolidate it.

The effective date of ASU 2015-02 for public entities is for fiscal years beginning after Dec. 15, 2015, while it is effective for fiscal years beginning after Dec. 15, 2016, for all other entities.  Early adoption is permitted. Upon adoption, all existing variable interest relationships must be reassessed, and any changes to consolidation must be applied on either a modified retrospective basis, through a cumulative-effect adjustment or retrospectively to all periods presented. 

Giselle El Biri is an audit director in BDO’s Restaurant Practice. She can be reached at

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Nine Questions Brewery Owners Should Ask Their CPAs

By Dirk Ahlbeck

Do you own a brewery and have a question that you think may be outside of your CPA’s scope of knowledge? Do yourself a favor and just ask! From research and development (R&D) to trademarking advice, your CPA can provide insights into some tricky financial scenarios and help your business improve cash flow while finding savings.

1. Why does inventory matter when I compute my beer ingredient costs, or Cost of Goods Sold (COGS)? What comprises COGS? 
There are a variety of reasons inventory matters when computing beer costs, particularly for your financial reporting. If your inventory is incorrect, it can affect the accuracy of your costs. For example, if you count inventory once per month, your monthly purchases or products used may not be factored in, misrepresenting actual inventory levels and, therefore, cost of sales. At the end of the month, brewers must make an adjustment to the actual physical inventory, which will affect COGS in the income statement. An alternative would be to keep a perpetual inventory system that records the sale or purchase of inventory with immediate reporting of the amount of inventory in stock, and accurately reflect the level of goods on hand.

COGS consists of all costs required to produce your product, including ingredients (malt, barley and hops), freight-in and freight-out for self-distributors, packaging (including keg leasing), excise taxes, labor and supplies. 

2. How can I help offset the cost of my brewery equipment while enhancing the space my brewery occupies?
It’s important to understand which tax laws—federal, state and local—are favorable to your business, in addition to applicable IRS codes. Are you eligible for Section 179, a part of the IRS tax code that allows a business to deduct the full purchase price of financed equipment and off-the-shelf software? Also, have you considered de minimis safe harbor election? Businesses can apply a de minimis safe harbor to amounts paid to acquire equipment in some circumstances.

Other options include bonus depreciation, an additional depreciation allowance, which is currently 50 percent of the cost in addition to regular depreciation and can be taken regardless of income or loss.  You can also carry major losses forward to future years to take advantage of deductions over a longer period of time. Your CPA should be able to assist you with understanding what makes the most sense for your business from a tax planning perspective.

3. How do I generate current cash from past investments?
Breweries, like any other business, are eligible for a variety of tax credits and incentives that could help put cash back in their pockets. Chief among these incentives is the federal research and development (R&D) tax credit, which breweries can apply to myriad activities, including developing new or improved wastewater management techniques, ingredient mixing methodologies and experimenting with product mixtures to create new aromas or flavors, among others.

In addition to the R&D credit, brewers may capitalize on the domestic production activities deduction (DPAD), allowing a deduction from net income based on qualified production activities, and the Federal Insurance Contributions Act (FICA) tip credit. The FICA tip credit allows brewery owners to get a credit for part of the taxes paid on their employees’ gratuity when it exceeds the federal and state minimum wage thresholds. The aim of this tip credit is to incentivize employers to report tipping as accurately as possible, resulting in more revenue from the tax credit once returns are filed. Additionally, on a local level, breweries can take advantage of manufacturing as well as sales and use tax incentives specific to the area in which they are producing craft beers.

Confirm with your CPA the credits (if any) for which you may qualify. Typically, beneficial credits exist for both small and large breweries, and every business should be able to apply some credit computation annually.

4. What is the best structure to save on taxes in the long run and set me up for success in the future?
You have several options for structuring your business for maximum tax benefit. The first is the management company structure, in which owners set up a separate C or S corporation to manage payroll and similar management activities. This structure is ideal for companies operating LLCs with owners subject to self-employment tax.

Another option is a holding company structure, which is simpler and less expensive in terms of accounting and tax costs. This is ideal for having several single-member LLCs and offers deductions for startups and pre-opening expenses.

5. Should I incorporate my brewery as an LLC as opposed to an S Corp or C Corp?
LLCs offer a degree of flexibility that may make them highly attractive to brewery owners. For example, they allow for an unlimited number of members (including non-U.S. residents and citizens), flexibility of distributions, an unlimited number of subsidiaries as well as less paperwork and ease in setting up. However, LLCs do entail some drawbacks, such as more restrictions surrounding transfers of units, the possibility of dissolution if a member leaves the LLC, and differing operating rules from state to state.

Your CPA can help you identify whether an LLC makes sense for your business and, perhaps more importantly, can help you establish an operating agreement and other formalities (that are not mandated by the LLC structure) to help protect your business.

6. How can I expense the cost of the building housing my brewery faster than I am using it?
You have a couple of different options available to you, both of which your CPA can discuss. First, you could purchase the building and perform a cost segregation study, which may allow you to shorten the depreciation time on the asset from the 39 years the IRS typically assigns to non-residential property.
You could also pursue a fixed asset review, which allows you to identify where you have the opportunity to reclassify assets for swifter depreciation.

7. How can I compare my financial numbers to other brewpubs and breweries?
It can be difficult to make an apples-to-apples comparison between yourself and a competitor, as a number of different metrics can be used to measure success. Your CPA can help you split your revenue streams into separate profit centers to help you get a better picture of how your business is performing. You’ll need to understand what portion of your revenues are derived from first- and third-party distribution, retail and restaurant operations. As you’re assessing each unit’s performance, you should use consistent baseline metrics to ensure you can accurately compare results (e.g., you should measure the amount of revenue derived from beer sales across each profit line in the same units—per gallon, per barrel, etc.).

From there, you can begin to look at how your performance stacks up against the competition. This will allow you to understand how your retail sales, for instance, may compare to that of a microbrewery without brewpub operations, or your restaurant operations to a gastropub that doesn’t brew its own beer.

8. What pitfalls might I encounter as I create federal, state and city excise tax returns?
The most important point to keep in mind when filing excise tax returns are that each jurisdiction has different filing requirements. For example, some jurisdictions may require paper filings rather than digital, which could impact your overall timeline. In addition, some filing areas may be more burdensome and time consuming than others. For example, if you’re filing in Illinois, its RL-26-R requires that you report every resale customer and how much you sold, as well as that customer’s state and account number. Failing to collect all of this information from the start can cause delays in reporting and missed deadlines. An experienced CPA can help you get all of your ducks in a row well in advance, helping to ensure compliance and avoid penalties.

9. Is trademarking my name and brand worth the expense, even if my brewery is small?
Yes! Doing so will make you distinguishable from other craft brewers, especially if you cover your brewery name, logo and core brands. While you will want to consult with a qualified legal expert to develop your trademark, your CPA can help you identify opportunities to write off expenses related to the trademark depending on the circumstances, making this a valuable conversation in which to include your CPA.

Dirk Ahlbeck is a tax partner in BDO’s Restaurant practice. He can be reached at

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Proposed Regulations May Limit Discounts on Family Transfers – Guidance on IRS Section 2704

By Dr. Tami Bolder

Time may be running out for restaurant owners to take discounts on transfers to family members. On Aug. 2, 2016, the Department of the Treasury issued proposed regulations under IRC Section 2704 in response to perceived abuses in the use of valuation discounts. Currently, owners transferring non-controlling interests in privately held companies are able to consider discounts for lack of control and discounts for lack of marketability. Discounts for lack of control relate to the inability of non-controlling interest holders to impact the strategic direction of the entity. Discounts for lack of marketability account for the lack of a ready market to sell privately held interests.

The provisions of the IRS 2704 proposed regulations that may have the most impact on restaurant owners seeking to transfer wealth to family members include:

Transfers Within Three Years of Death

Under Section 2704(a) of the proposed regulations, if a transfer resulting in a restriction or elimination of a liquidation right occurs within three years of the transferor’s death, the transfer is treated as if it occurred at death. The effect of this three-year rule is that the transferred interest would be included in the transferor’s gross estate at liquidation value.

Applicable Restrictions

Applicable restrictions will not be considered when valuing interests transferred to family members under Section 2704-2 of the proposed regulations unless certain requirements are met. Section 2704-2 defines an applicable restriction as “a restriction that limits the ability to liquidate the entity if the limitation lapses or the liquidation right may be removed by the transferor or the transferor’s family.”  Applicable restrictions include restrictions on withdrawal rights and other restrictions on liquidation rights imposed under the terms of the entity’s governing documents and under local laws. Exceptions include:

  • Commercially reasonable restrictions on liquidation rights considered compulsory by an unrelated person providing capital to the entity.
  • Restrictions imposed by federal or state law (but only under certain conditions).
  • Each holder of an interest must hold a “put right,” which allows them to receive cash or property (not including notes unless certain conditions are met) at “Minimum Value” (defined as the interest’s share of the net value of the entity on the date of liquidation or redemption) within six months of the notice of the intent to withdraw.

Disregarded Restrictions

Under Section 2704-3 of the proposed regulations, when valuing transferred interests to a family member where the transferor’s family controlled the entity (meaning holding at least 50 percent of either the capital or profits interests) immediately before the transfer, applicable restrictions limiting the ability to liquidate the transferred interest will not be considered in the value of the transferred interest. Section 2704-3 states that, “disregarded restrictions includes one that (a) limits the ability of the holder of the interest to liquidate the interest; (b) limits the liquidation proceeds to an amount that is less than a minimum value; (c) defers the payment of the liquidation proceeds for more than six months; or (d) permits the payment of the liquidation proceeds in any manner other than in cash or other property, other than certain notes.”

While transferring ownership to a nonfamily member may seem like a viable option to avoid the control provision, the proposed regulations stipulate that interests transferred to non-family members are to be disregarded unless certain stringent requirements (including a holding period of at least three years prior to the transfer) are met as outlined in Section 2704-3.

If an applicable restriction is disregarded, the inability to liquidate and, thus, a discount for lack of marketability, is not considered in valuing the transferred interest, resulting in a higher value.

The IRS has a public hearing scheduled for Dec. 1, 2016, to discuss the proposed regulations.  If the regulations become final on or shortly after Dec. 1, 2016, the effective date would be 30 days after being finalized. Given this timing, the limits on taking valuation discounts for owners transferring wealth to family members may be in place shortly after the end of the year. Restaurant owners considering transferring an interest to a family member may want to act as soon as possible before the law changes.

Dr. Tami Bolder is a senior manager in BDO Consulting’s Valuation and Business Analytics practice. She can be reached at

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2016 Year in Review: Tax Planning for Restaurants

By Phil Hofmann and Julie Komnick

As 2016 comes to an end, taxpayers need to be proactive in year-end tax planning. The Protecting Americans from Tax Hikes Act of 2015 (PATH Act), was signed into law in December 2015 and made many changes that are effective with 2016 tax returns. Restaurants, in particular, should be aware of the following items in this Act:

Certain accelerated filing deadlines: For the 2016 tax year, the due dates for filing W-2 and W-3 Forms, as well as certain 1099-MISC Forms, are now due by Jan. 31, 2017. Additionally, penalties have increased for late information return filings.

Changes to due dates for C-corp and partnership tax returns: Starting with 2016 tax returns, the due date has been moved back a month to the 15th day of the fourth month for the calendar year, with a five-month extension available. 2016 calendar partnership tax returns are due a month earlier, on March 15, 2017, with a six-month extension available.

Code Sec. 179 expensing: The PATH Act permanently set Code Section 179 expensing of qualified property at $500,000 with a $2 million investment limit prior to phaseout. These amounts are indexed annually for inflation. The 2016 amounts are $500,000 and $2.01 million. The $250,000 cap on qualified real property is no longer in effect, starting with 2016 tax returns. Keep in mind that the property does not have to be new to qualify for Sec. 179. Air conditioning and heating units are now eligible for expensing starting in 2016.

Bonus Depreciation: A 50 percent bonus depreciation is available for 2016 tax returns. A new category of property, “qualified improvement property” (QIP), applies in 2016 and permits the 50 percent bonus on certain 39-year property, among other things. QIP removes the third-party lease requirement and the three-year building age rule. Also, an election is permitted for corporations to forgo bonus depreciation and, instead, increase the amount of unused alternative minimum tax credits.

Research Credit: The PATH Act made the research credit permanent and more useful to small businesses. Recently, the IRS final regulations were issued with additional potential opportunities.

Work Opportunity Tax Credit: This credit was modified starting in 2016 to include hires of qualified, long-term individuals unemployed for 27 or more weeks.

Repair Regulations: Ensure the policies are being followed if you have filed accounting method changes, such as making annual elections as required and reviewing the de minimis capitalization thresholds for compliance. Taxpayers taking advantage of the de minimis thresholds should have a written capitalization policy in effect. Effective in 2016, the de minimis safe harbor limit was increased to $2,500 for taxpayers without an applicable financial statement. It remains at $5,000 for those with applicable financial statements. As a reminder, an applicable financial statement is defined as a certified audited financial statement.

Remodel-Refresh Safe Harbor: Restaurants should consider filing an accounting method change to treat 75 percent of qualified remodel-refresh costs as currently deductible repair expenses. Once an accounting method change is filed, future remodels in the same trade or business would be subject to the safe harbor provisions. An applicable financial statement is required to use the safe harbor method.

Shorter Recovery periods for certain property: The 15-year life for qualified leasehold improvements (QLIP), qualified restaurant buildings and improvements (QRP), and qualified retail improvements (QRIP) is now permanent.

FICA Tip Tax Credit: This is a credit against federal tax for payroll taxes employers pay on certain reported tips. Make sure you claim the credit if your operation has tipped employees.

Food Inventory Charitable Contributions: Several changes for 2016 were made to Sec. 170(e)(3), which allows an enhanced deduction for food contributions. A taxpayer-friendly change was made in the determination of the fair market value of food contributions. Restaurants should consider setting up a program to use this tax benefit.

Empowerment Zone Credit: This is a credit against federal tax for salary paid to employees who both live and work in designated zones. Be sure to check for new locations to determine if they are within a designated zone.

Tenant Improvement Allowances: Money received from a landlord can be excluded from taxable income in certain instances under Sec. 110. Be sure to follow the requirements in the code and regulations, including having the proper lease language.

Phil Hofmann is a tax senior director in BDO’s Restaurant Practice. He can be reached at

Julie Komnick is a tax senior manager in BDO’s Restaurant Practice. She can be reached at

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For more information on BDO USA’s service offerings to the restaurant industry, please contact:

Adam Berebitsky
Tax Partner and Co-Leader of the Restaurant Practice
   Dustin Minton
Assurance Partner and Co-Leader of the Restaurant Practice

Dana Zukofsky

Natural Resources Record Newsletter – Winter 2016-2017

Posted on: December 21st, 2016 by BDO USA Industry Publications Feed


Download PDF Version

Table of Contents

Changes to Partnership Taxation: Implications for Oil and Gas Businesses
OPEC’s Deal to Cut Production: Global Short and Long-Term Effects
Top Takeaways from the 2016 Oil & Gas Council North America Assembly
Q&A with Steve Franckhauser, HBK Energy
PErspective in Natural Resources


Changes to Partnership Taxation: Implications for Oil and Gas Businesses

By Shuja Akram

It has now been more than a year since President Obama signed the Bipartisan Budget Act (BBA) of 2015 into law, promising major changes to partnership audit and taxation in 2016. With the IRS’s October 2016 release of final and temporary regulations related to liability allocations under IRC Section 752 and disguised sales under IRC Section 707, among others, that promise has been fulfilled—with significant ramifications for oil and gas companies that often rely on partnership structures.

The Basics                     

The regulations introduce several key tax changes for partnerships, with some of those most affecting the natural resources sector including:

  • Tax return due dates move up. Partnership tax returns are now due a month earlier on March 15, as opposed to April 15.
  • New IRS examination rules shift the burden of responsibility for taxes due. If, following an audit, a member of a partnership is found to owe additional taxes, the partnership must pay the amount due. This is effective for the 2018 tax year.
  • Partners may not be considered employees of the partnership via disregarded entity. The IRS has long held that partners cannot be treated as employees of a given partnership and are subject to self-employment tax, effectively increasing the partner’s tax burden and limiting their access to employee benefits. In an effort to work around these downsides, many partnerships have employed their partners through the creation of a “disregarded entity”—typically, a single-member limited liability company the partnership wholly owns. The IRS’s newest guidance aims to crack down on this practice.
  • Debt-financed distributions to partners will now be allocated based on profit allocation ratios to members who have received cash distributions. Under the temporary regulations related to IRC Sections 707 and 752, a partner’s share of any partnership liability for disguised sale purposes is the same percentage used to determine the partner’s share of the partnership’s excess nonrecourse liabilities. This rule applies regardless of whether the liability is recourse or nonrecourse. For purposes of the disguised sale rules, a partner’s share of partnership excess nonrecourse liabilities will be based on the partner’s share of partnership profits. The temporary regulations also provide that, for disguised sale purposes, if another partner bears economic risk of loss with respect to a liability, then no portion of that liability can be allocated to the contributing partner.
  • Partners may no longer compute preformation capital expenditures on an aggregate basis. Also pertaining to disguised sales under IRC Sections 707 and 752, in general, transfers of money or other consideration from a partnership to reimburse a partner for certain capital expenditures and costs incurred by the partner are not treated as part of a disguised sale of property. There is, however, an exception for preformation capital expenditures that typically applies only to the extent that the reimbursed capital expenditures do not exceed 20 percent of the fair market value of the property transferred by the partner to the partnership (the 20-percent limitation). The 20-percent limitation does not apply if the fair market value of the transferred property does not exceed 120 percent of the partner’s adjusted basis in the property at the time of the transfer (the 120-percent test). Under the new guidance, the preformation expenditure exception applies on a property-by-property basis—partners may not use an aggregate value and tax basis—which may limit their ability to take advantage of this exception.

The final and temporary regulations include a number of other provisions with broad applicability to partnerships, ranging from anti-abuse rules and deficit restoration obligations to qualified liability exclusions. And though the timeline for implementation of the new regulations remains in question, partnerships must begin planning now to ensure they understand the impact of these rules on their tax returns—and their partners.

Implications for the Oil and Gas Industry

All partnerships, regardless of sector, are likely to feel some reverberations from these new regulations, as will their tax advisors and preparers. However, the natural resources industry and the oil and gas sector in particular will face some unique challenges—some that may simply create more work for the partnership, and others that will remain major sticking points as the industry works to comply with the new regulations.
The adjustment to the examination process—specifically, the rules requiring underpayments to be calculated at the partnership level—may prove particularly problematic for the oil and gas industry. In general, oil and gas partnerships calculate taxes at the partner level, which in and of itself makes it difficult to adjust for underpayment at the partnership level. However, this is further complicated by the patchwork of tax deductions available to partners in the oil and gas industry, such as depletion expense and the intangible drilling deduction—which the partnership does not compute.

In the case of depletion expenses, tax rules allow partners to use one of two methods (cost or percentage) to compute their deduction for expenses spent on a given oil or gas leasehold, taking whichever results in a higher reduction in taxes owed. The cost method is straightforward and similar to depreciation in that the partner can simply expense the amount of money spent on a given leasehold. The percentage method, however, is far more complicated, and requires the partner to determine how much revenue he or she is receiving from selling the produced oil and gas, and then take 15 percent of the total as the deduction. Unlike the cost method, this restricts the deduction to the partner’s taxable income and does not allow him or her to take a loss on the asset. Similarly, in order to claim a deduction for intangible drilling costs, a partner can choose to either capitalize or expense the costs associated with a leasehold, with implications for the ultimate amount of individual income tax owed.

Partnerships, then, have limited insight into the individual tax position of each partner. If an individual is a partner in multiple ventures, it is difficult for each partnership to assess which computation method that partner is using for his or her deductions, and virtually impossible for a partnership to know the total amount of that individual’s taxable income. Thus, if an IRS audit finds that a partnership owes taxes, the partnership may struggle to identify how to allocate the underpayment.

The accelerated filing date will also place a major burden on oil and gas partnerships. In addition to simply having less time to prepare a tax return, the new timeline does not make much allowance for the complex nature of oil and gas industry partnerships. In the case of exploration and production companies, partnerships generally rely on outside contractors to actually drill and produce oil and gas assets—and it can take time to access essential information from these contractors to facilitate tax preparation.  Some of the same limitations partnerships face when assessing tax liabilities at the partner level—a lack of visibility into taxable income and the way deductions are calculated—apply here as well. Partnerships in the oil and gas industry can also consist of multiple tiers (e.g., if a private equity fund invests in the partnership) that add layers of complexity to the tax preparation process. In other words, partnerships have even less time—just two-and-a-half months from year-end—to gather information from these disparate parties and file their returns.

Exacerbating the new timeline are the latest rules surrounding disguised sales—in particular, the guidance that preformation capital expenditure reimbursements must be calculated on an asset-by-asset basis. For example, prior to the new rules, a $52 million disguised sale of multiple oil and gas assets might yield $10.4 million in reimbursable expenditures (that is, 20 percent of the $52 million). However, under the new guidance, the sale price and reimbursable expenditure of each asset sold must be calculated separately, which creates additional burden for the tax preparer while reducing the reimbursement—perhaps to as little as $2 million, depending on the individual fair market value of each asset.

What’s Next

Several questions about the new regulations remain unanswered, with the final versions of some of these rules still pending and implementation dates unclear. It is also uncertain whether companies will be permitted to adopt these rules ahead of their effective date. Regardless of the lingering questions, however, oil and gas businesses should consult with a tax professional to begin planning—whether that means exploring alternative business structures, or otherwise adjusting their tax preparation procedures to ensure compliance.
In October, BDO’s National Tax Office issued three alerts related to the new partnership regulations. For an in-depth discussion of these regulations and their applicability, refer to our alert addressing disguised sales under IRCS Section 707, our alert relating to the determination of recourse liabilities under Section 752, and our alert discussing the re‑proposed regulations.

Shuja Akram is a tax managing director with BDO USA. He can be reached at
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OPEC’s Deal to Cut Production: Global Short and Long-Term Effects

By Charles Dewhurst

OPEC, the 13-member cartel responsible for producing nearly a third of the world’s oil supply, announced a deal to cut oil production on November 30—a landmark decision designed to reverse the two-plus year downward spiral in oil prices. Involving several key players, including oil giants Saudi Arabia and Iran, the deal urged OPEC countries to reduce output by 1.2 million barrels per day (BPD) to 32.5 million BPD.[1]Saudi Arabia will lead the charge and take the highest cut at 486,000 BPD, followed by Iraq and United Arab Emirates. [2]Non-OPEC countries were additionally encouraged to cut 600,000 BPD.

A High-level Monitoring Committee consisting of OPEC oil ministers and assisted by the OPEC Secretariat is charged with ensuring that members carry out the deal’s obligations. The cuts will take effect January 1 and last for six months, with the possibility of another six-month extension.

If anything, the deal signals the desperation the cartel feels after its decision to allow production output to run freely in 2014 backfired, leading to a market oversupply of up to nearly two million barrels a day. [3] Crude oil prices took a hit as a result, falling by more than 70 percent from June 2014 levels at its lowest point over the past two years. [4] OPEC’s deal, then, is long overdue and will have several short-term and long-term effects on the oil and gas industry.

The Short-Term

The short-term effects of the deal are apparent. Hours after the announcement, the industry witnessed a spike in oil prices, an increase in U.S. energy group shares and a general renewed optimism. CNN Money reported a nearly 9 percent increase in crude prices to $49.20 per barrel on the same day. In the days to follow, crude prices topped $50 per barrel for the first time in several months, and industry observers continue to hope that prices will increase to $55-$60 per barrel in early 2017.

Renewed optimism has also sent the shares of U.S. energy groups soaring, with both major onshore producers and smaller energy groups benefiting. Bloomberg Markets reported investors pushing several energy companies into the top 18 spots on the Standard & Poor’s 500 index, increasing the U.S. oil industry’s market value by $81.3 billion in one day. Banks also displayed renewed confidence in energy companies’ ability to repay loans by beginning to release protection reserves set aside earlier this year.

The Long-Term

The longer-term effects of OPEC’s deal remain to be seen. Nevertheless, experts expect an overall increase in oil production from non-OPEC countries looking to capitalize on rising prices and increased demand. The International Energy Agency predicts Brazil, Canada and Kazakhstan will pump more oil in 2017, which could increase total non-OPEC output to 500,000 BPD next year. [5] China, one of the world’s biggest oil importers and a major producer, may also boost its own oil production as it reduces reliance on Saudi oil. The U.S. shale industry—ironically, the industry that OPEC is looking to drive out of business—may also see an uptick in production now that crude oil can be pumped almost as inexpensively in the U.S. as in several OPEC countries. The Permian Basin in Texas and New Mexico is particularly attractive in this regard.

For OPEC, an increase in non-OPEC oil production could have the opposite effect of the deal’s original intent: a loss of global market share and a stem in increasing prices. Thus, while a decreased oil supply may lead to increased prices over the next couple of months, the industry may also see an eventual leveling out of prices, or even potential decreases, as non-OPEC members rush to fill the gap. Goldman Sachs, for example, predicts that crude prices will spike in the first half of 2017 but moderate in the second half, while JP Morgan sees prices rising slowly but steadily quarter after quarter. The overarching question of whether the cuts are even significant enough to offer the boost to oil prices that OPEC needs to be profitable also remains.

Looking Ahead

Many uncertainties surrounding the deal’s success persist, including speculation as to whether OPEC members will even uphold the agreement. Regardless, OPEC’s deal is significant in many ways. For many oil-producing countries, it could be the catalyst needed to re-invigorate domestic oil production, boost industry morale and stem the downward spiral of bankruptcy and loss. For oil-dependent industries, such as the airline industry, it could mean preparing for potential fluctuations in crude oil prices over the next few months. As for OPEC itself, the deal may either be the saving grace the cartel needs to get itself back on its feet—or its downfall, encouraging the rise of the non-OPEC oil producers it has tried so hard to compete against in the first place.

Charles Dewhurst is partner and co-leader of the Natural Resources practice at BDO. He can be reached at
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Top Takeaways from the 2016 Oil & Gas Council North America Assembly

By Jason Taibel

Along with several of my colleagues, I recently attended the 2016 Oil & Gas Council North America Assembly in Houston. The conference, which brought together oil and gas executives across the continent to discuss prominent industry trends and developments, coincided with big news for the oil and gas industry. For the first time in over two years, an exploration and production (E&P) company went public in October. On the heels of an extremely successful IPO, the conference focused on opportunities and challenges for the industry in the year ahead.

Human capital is a valuable—and increasingly scarce—resource in the industry.
As the Baby Boomer generation reaches retirement age, many industries are facing a succession challenge, and the energy industry is no exception. As this demographic ages, the number of skilled workers, such as petroleum engineers, exiting the workforce outweighs the new talent entering. Given the greater concerns around pricing, a human capital deficit is not the top concern in the immediate term. Many companies have emphasized cost-cutting to combat the ripple effects of the downturn. Looking toward the future, however, a deficit of skilled workers could prove challenging. When the market turns around, will there be enough talent to support continued industry growth and expansion?

Innovation and automation is an emerging force in the sector.
While skilled workers will always be vital to the industry’s success, many oil and gas companies are embracing technological advancements to automate, optimize and streamline processes. BP, for example, recently launched an initiative to increase its digital capabilities and gather real-time data from offshore production platforms through cloud and analytics software. Companies that actively leverage new technology and automation capabilities will be able to operate with fewer workers, making them less susceptible to the negative effects of a decreased labor supply.

For M&A deals, executives value areas with growth potential.
Expansion-minded industry executives are focusing on key geographic areas that offer opportunities for profitable mergers and acquisitions. Beyond the areas that are already active deal sites, oil and gas executives are increasingly seeking to identify growth assets, or areas that demonstrate potential for growth when commodity prices resurge. In recent years, there has been an uptick in deal flow as oil prices get closer to $50 per barrel. In the third quarter of 2016, there were 93 deals in the oil and gas industry, totaling $16.6 billion, according to the U.S. Energy Information Administration. At present, the majority of the deals in the energy sector are funded by equity, with energy-focused private equity firms being a key driver of deals, while generalist firms have largely remained on the sidelines.

A few of the major areas in play at the start of 2017 include:

  • The Permian and Delaware Basins continue to be extremely active regions. Throughout the year, there has been a heavy cadence of transactions with high multiples in these two key regions. In fact, it has been difficult to sell conventional assets outside of the Permian and Delaware Basins or Eagle Ford.
  • Environmental factors have led to downturns in deal activity in major onshore regions. Oklahoma, for example, has seen decreased deal activity because of increasing concerns around earthquake exposure. Colorado is also facing a slow deal-making environment as fracking concerns persist in the region. 
  • For companies not already engaged in the U.S. Gulf of Mexico, there are no incentives to enter this highly-regulated region.
  • With respect to Mexico, in the immediate future, oil and gas executives are interested in how US-Mexico relations will evolve with the new presidential administration.

Financial and capital structure concerns continue to disrupt the industry.
It’s no secret that the energy industry has had a difficult few years financially. Since December 2014, about 150 companies have restructured or filed for bankruptcy. Looking toward the future, as U.S. bank regulators continue to limit the amount of credit that U.S banks will have available for reserve based loans, future borrowing base redeterminations may spur more restructuring as liquidity decreases. Companies that initially did some light restructuring in anticipation of a quicker spike in prices may need to restructure again or file bankruptcy.

Certain midstream companies may be the next market segment to restructure, since many of their contracts, which were established during periods of high prices, are set to expire.

The worst is likely behind us.
Barring any catastrophic events, it is unlikely that oil prices will drop to less than $30 per barrel again. Prices are expected to recover, but no one expects a full resurgence to peaks of $100 per barrel. In all likelihood, prices will level off around $55-$60 per barrel. 

The oil and gas industry is still in the mires of a downturn, but there is reason for optimism in the year ahead. Companies that embrace innovation and take strategic measures to consolidate and cut costs will be well-positioned when the market recovers.

Jason Taibel is a partner in BDO’s Houston office, and can be reached at
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Q&A with Steve Franckhauser, HBK Energy

Established in 1949, Hill, Barth & King (HBK) CPAs & Consultants offers tax, accounting, assurance and consulting services to a variety of clients in Ohio, New Jersey, Pennsylvania and Florida, and has been a BDO Alliance firm for 14 years, joining more than 400 independent firms in the world’s fifth largest accounting and consulting network.

We recently sat down with Steve Franckhauser, Director of HBK Energy (an affiliated HBK entity), to discuss Steve’s work in the sector and his predictions for industry trends. With over two decades of experience in the energy space, Steve has been with HBK Energy since 2011, assisting natural resources owners, shale businesses, lenders and government entities, developers and others maximize their financial opportunities and investments.

How did you come to specialize in the oil & gas industry?
I was born and reared in the Appalachia region, specifically eastern Ohio. In the mid-1990s, I had the good fortune to cut my teeth in the energy industry as a young lawyer representing a dairy farmer in a lawsuit against a large public utility. Through practicing law in similar cases, I realized I had a true passion for working with privately held companies. Because energy is an essential part of our daily life, it’s something I view more as a vocation than a job.

As I realized where my professional interests lie, I also witnessed what was happening in the region where I was born and raised—the dramatic and painful decline of steel and other material industries. When the shale industry started to take hold in Pennsylvania in the mid-2000s, I saw that as an opportunity for the region to restore itself to prosperity and become an important player in the nation again. At the same time, I was looking for an opportunity to combine my legal and financial experience with my passion for helping private businesses, and HBK proved to be the perfect place to do just that.

Tell us a bit more about your company HBK Energy (HBKE) and the type of work you do, and how that ties into your relationship with BDO USA. 
HBK is a total financial services firm with a wide variety of tax, accounting, assurance and business specialty services. Our footprint is growing beyond the historical base in Appalachia, eastern Pennsylvania, New Jersey and both Florida coasts—and given our service offerings and our regional identity, working with energy and shale clients is a clear opportunity for our firm to support the sector. Our goal is help clients apply their limited resources within the framework of their operations. Our multidisciplinary resources are enhanced by BDO’s expertise and support. We’ve had a relationship with BDO for many years, and our partners are active at seminars, webinars and conferences. We have found this partnership to be mutually beneficial, particularly for our natural resources work.

How would you characterize the current state of the energy industry in the United States, and what do you think lies ahead in the coming year?
When it comes to the domestic energy sector, I prefer the term “evolution” to “revolution.” Most of the country is dedicated to weaning itself off imported oil and coal, but perceptions about this shift vary widely along generational and regional lines.

Despite the obvious shifts and contrary to some of the chatter littering airwaves both in the industry and in the general media, most of what is happening in the energy sector is positive. The energy industry learns from each new challenge. While the presidential election was contentious, energy was not a major point of division. Remarkably, the U.S. is still playing a huge role in the advancement of the global energy industry, and I expect that will continue for years to come.

Looking forward to 2017, I think the sector will continue to evolve. We’ll move towards using cleaner forms of energy, such as natural gas, to power our electrical grid, but figuring out how to maximize the use of our domestic energy supply will prove to be a significant hurdle. While the desire to move away from coal is substantial, the infrastructure needed to support this shift, including refineries, pipelines and generators, is still developing.             

How do you think regulatory action, at the federal and state levels, affects the performance of the industry overall?
There are 51 different regulatory jurisdictions governing the industry—federal and state. In some instances, the differences between these regulations have made certain states more attractive to energy players than others. For example, many of the energy assets in Pennsylvania shifted to Ohio, partially due to Pennsylvania’s proposed severance tax on top of its existing impact “fee.” Conversely, Ohio has not increased its extraction tax rate in recent years—making it a prime target for relocation.

Despite these differences, regulatory changes have been incremental in the Appalachian Basin and cooperation and healthy competition exists. Energy companies seek fair and predictable regulations they can work into their strategic planning. A new chief executive in Washington is the “X” factor. Time will tell if electoral rhetoric will match policy initiatives. At a minimum, HBKE expects a less hands on approach from the new administration.

Are there any areas of the U.S. you expect will play a large role in U.S. energy production next year? 
Texas has long been a good home for energy companies, and the state manages to contribute to the industry’s growth without too much burden on the local landscape. Louisiana also has a large petrochemical presence along the Gulf of Mexico, which is a major source of employment in the state. When it comes to my home Appalachia region, the story has not been written yet. As I had mentioned, Pennsylvania’s impact tax and diverse constituencies have caused many companies to flee to nearby states with less stringent requirements. West Virginia might be poised for a bit of a boom if it proves attractive to Pennsylvania-based companies. Ohio has made major strides toward welcoming the industry, addressing most problems quickly and efficiently, while positioning itself as a regional industry powerhouse. We anticipate the Upper Ohio Valley to spawn a petrochemical industry along the banks of the Ohio River. The gestation period is critical for this industry and much hinges on the subsequent development to the Shell ethane cracker in Pennsylvania and potential other ethane crackers further south in Ohio and West Virginia.

Is there anything else you would like to add?
U.S. energy is growing beyond coal and oil—natural gas, renewable and sustainable energy sources will gain prominence in the energy mix. What happens in the future ultimately comes down to a two-pronged question— what will the consumer demand, and how will the industry work to meet those demands?

When we established HBK Energy, our goal was to include all energy forms within our sphere of influence. Thus, we purposively chose the word “energy” because we did not want to restrict our efforts to oil and gas alone. We sought a much larger seat at the table and included coal, solar, wind and hydro options, among several others, that will be a much larger part of the conversation years from now—simply because the consumer is demanding it and the technology is evolving. To use a sports analogy, you throw the football where the receiver will be, not where he is when you throw the ball. We have a rich history, but our eyes are on the energy industry of the future.

For more information on HBK Energy, visit their website:

Steve Franckhauser can be reached at

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PErspective in Natural Resources

A feature examining the role of private equity in the natural resources sector.

Consolidation is picking up in the midstream oil and gas sector as oil prices slowly rise and several players look to M&A to achieve growth. Year-over-year, M&A activity has remained much the same, but there has been a significant uptick in dealmaking in the third quarter, driven in part by crude’s price topping $50 a barrel for several consecutive weeks, according to energy newsletter Rigzone.

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Alan Stevens 


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Jim Willis 


[1] OPEC 171st Meeting concludes. (2016, November 30). Retrieved from
[2] Hjelmgaard, K., & Bomey, N. (2016, November 30). OPEC agrees to oil production cuts. Retrieved from
[3] DiChristopher, T. (2016, November 30). The OPEC deal is done. Here’s what to expect from oil markets next. Retrieved from
[4] Krauss, C. (2016, December 1). Oil Prices: What’s Behind the Volatility? Simple Economics. The New York Times. Retrieved from
[5] DiChristopher, T. (2016, November 30).

HITRUST CSF Assurance Program

Posted on: December 21st, 2016 by BDO USA Industry Publications Feed

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Cyber-attacks are on the rise, and healthcare has the bullseye on its back—the industry was the most attacked in 2015, surpassing financial services, information and communication, manufacturing, retail and wholesale, …