GT - Growth strategy: Perspectives from financial executives

The state of the industry— An engine for U.S. growth

GRANT THORNTON LLP SURVEY OF UPSTREAM U.S. ENERGY COMPANIES 2012

Table of contents

3 A view from the top

6 Major findings

8 2011 Economic year in review

10 Prices and spending

11 Enterprise risk management— Risk in the spotlight

13 E&P industry—Key M&A transaction risks

15 Employment

16 Industry issues and opportunities

18 Global use of IFRS—When, not whether

21 Implications

22 Demographics

Grant Thornton LLP Survey of Upstream U.S. Energy Companies 2012 3

We are living in a world of uncertainty, with downward price pressures caused by both the European debt crisis and slower economic growth in non-Organization for Economic Cooperation and Development (OECD) countries being offset by continued unrest and turmoil in the oil-producing regions of the Middle East and North Africa. As Winston Churchill once said, “Without a measureless and perpetual uncertainty, the drama of human life would be destroyed.”

The energy sector is booming and is one of the few areas of job growth. Major oil companies seem to be switching their focus to the United States not only to achieve production growth, but also to position themselves for a longer-term investment in natural gas. Companies with more of an international flavor might see domestic acquisitions of shale players as an entrée into more lucrative overseas opportunities in Eastern Europe, China and India, where higher gas prices can be achieved. J. Paul Getty said that without the element of uncertainty, the bringing off of even the greatest business triumph would be dull, routine and eminently unsatisfying. We are perhaps starting to see the opening moves of a paradigm shift toward natural gas, even though higher gas prices are still a few years away.

The United States is an attractive place for equity investors, especially for Europeans. We have already seen European majors make significant investments in this country. The European debt crisis and its implications for global financial stability have led to nervousness among debt investors. High-yield debt markets were fairly buoyant in the first half of 2011 but have dried up since. Saratoga Resources Inc. was fortunate to raise $127.5 million in a high-yield bond offering in July before the markets tightened.

We also completed two private placements of common stock, bringing in more than $35 million of new equity, some of which has come from Europe. As a result, we have reduced our total debt by $18 million, extended the maturity of our debt facilities to 2016, and substantially strengthened our cash position and shareholders’ equity. Our move to the NYSE Amex has had a tangible positive effect on our company and has opened our universe to many potential investors for whom a listing on a national exchange is a prerequisite.

Across the industry, new issuances of leveraged loans were down drastically in 2011, and deal spreads were higher than in 2010. In contrast, private equity financing appears to be up, mostly targeting capital-intensive shale plays. The end of 2011 saw a move towards new public offerings for energy stocks with up to 20 IPOs being considered.

M&A activity was slow at the beginning of the year but picked up in the latter half. Depressed prices have caused smaller operators to sell to larger companies, although many seem to favor joint ventures as an entry point into key unconventional plays. Obviously most of the industry’s attention has been on unconventional plays during the last several years, and most M&A activity has been concentrated in this sector. But instability in the markets has led to a widening of the gap between buyers’ and sellers’ expectations. Oil is being valued higher than natural gas—but not as markedly as in 2010, and there are a growing number of gas-weighted acquisitions. We are also seeing the start of consolidation in the natural gas sector. There is further consolidation coming among shale players.

A view from the top

Unconventional has become the new conventional, and a handful of companies such as Saratoga are taking advantage of positions in opportunity-rich conventional plays with multiple stacked pays and large held by production (HBP) lease positions, not to mention premium pricing for crude oil. Saratoga has been receiving a $15–30/barrel premium over West Texas Intermediate (WTI) for Light Louisiana Sweet (LLS) and Heavy Louisiana Sweet (HLS) crude since early 2011 although this spread has tightened at year end. We like to say we are pursuing good old-fashioned oil and gas, and we are happy to be receiving close to Brent pricing for crude oil.

Crude oil prices will likely remain volatile. Uncertainty lies in how non-OECD growth will offset OECD stagnation and its effect on oil demand. Domestic crude oil production is likely to increase in 2012 because of renewed activity in liquid-rich shale plays like Bakken and Eagle Ford. Many independents are emphasizing their move to liquids, and clearly project economics are improved by the more liquid-rich portions of the unconventional plays.

Natural gas prices are expected to remain fairly flat and experience downward pressure in 2012, driven by increased supply from unconventionals, coupled with slower growth and lower demand. Henry Hub natural gas spot prices will likely average lower than they did in 2010. The rate of growth in domestic natural gas production is expected to slow in 2012. Gas supply will probably grow because of increased drilling to preserve lease positions.

Saratoga can still make good money below $3/Mcf (thousand cubic feet) gas with respect to our conventional gas assets and do not have lease expiration issues because most of our leases are HBP leases. An important metric that drives rig count, which in turn puts downward pressure on gas pricing, is lease expirations in shale plays. The domestic rig count is up substantially in 2011, despite lower prices and reduced demand, and is expected to grow by 10% in 2012. There are not enough rigs available to drill beyond the initial terms of the leases, so new rigs are under construction.

Some companies are consolidating positions in the shallow-water Gulf of Mexico, while assets are discounted in response to permit delays. There is also a lot of anticipation of McMoRan Exploration Co.’s Davy Jones testing in the shallow Gulf ultra-deep play, where a number of deep and ultra-deep wildcats have been drilled during the year.

Currently, over 60% of our production is weighted toward oil versus gas. We like to say that we are oilier than many of our peers, but we like to maintain a balanced approach to oil and gas, and we are bullish on natural gas for the longer term. Having multiple stacked pay sands and HBP positions with 100% working interest enables us to develop these gas reserves when it makes sense.

Some of the most attractive features of shale plays are the long-lived nature of the reserves, the repeatability, the high probability of success and large lease positions. Saratoga sees the same attributes in its conventional South Louisiana assets. Our Grand Bay Field has never had a dry hole drilled in its confines. The field has had more than 70 years of productive life, with production of over 250 million barrels of oil since 1938 from over 64 stacked pay sands, yet it still offers tremendous potential, both shallow and deep.

We have low decline rates in our wells, not the sharp declines typical of resource plays. We have several wells whose commercial production dates from the 1940s. One well has over 50 years of production from the same sand, and it is still producing at over 20 barrels of oil per day (BOPD) today. We just completed a well in Main Pass 46 with 13 pay sands, only six of which were proved undeveloped reserves (PUDs); completed the well in a sand that was categorized pre-drill as probable; and found six pay sands that were never previously booked. We call that lagniappe and have lots of that in our assets.

We are skeptical about the commerciality of most shale plays, given the current gas prices. This is due to (1) the sharp decline in initial production (IP) rates, (2) outrageously high leasing costs, (3) the high costs to fracture, and (4) the likely need to refracture specific wells to sustain production. Technological breakthroughs in horizontal drilling and hydraulic fracturing have improved shale economics, but uncertainty remains regarding well productivities and recoveries.

Like many of our peer companies, we will fund all capital spending from existing cash flows and cash on the balance sheet. We expect to have additional liquidity through a revolver in the near future. Saratoga is currently focused on development drilling and converting its PUD properties. Some of our development wells have an exploratory tail where we are looking for a little more upside, and our deep prospects have shallower low-risk bailouts, but we are essentially a low-risk development company

4 Grant Thornton LLP Survey of Upstream U.S. Energy Companies 2012

at this stage of our growth, with a serious eye on managed risk exploration in the future. With the addition of liquidity from our improved operating cash flows and equity infusions, we have substantially increased our development budget; we spent $28 million in 2011, up considerably from the last three years, with just over half this amount being devoted to drilling and completion. Our criteria for approving projects are internal rate of return and time to payout. Almost all of our projects have a payout time of less than twelve months. Saratoga’s capital budget for 2012 is expected to be close to $50 million.

We find it a very cooperative regulatory environment in Louisiana, with no permit delays. It is a pleasure working with Gov. Bobby Jindal and Department of Natural Resources Secretary Scott Angelle. We love the operating environment in Southern Louisiana. The state ranks fourth in the United States in crude oil production and fifth if the Gulf of Mexico is included. Saratoga currently ranks 18th in terms of oil producers in the state.

Saratoga has strong institutional and retail participation in its equity and a growing market capitalization. We have attractive conventional assets located in state and parish lands of Louisiana, with an abundance of low-risk development opportunities. We are converting our reserves with an active development drilling program. And we are weighted toward oil in our current production with

LLS/HLS premiums over WTI . In addition, we have tremendous upside—including shallow exploration targets above 5,000 feet with 50 Bcf of potential, plus deep exploration targets with 10 Tcf of potential, all among our large HBP leaseholdings.

We have gained momentum on numerous fronts, achieving several long-standing objectives, and we feel we are now positioned to realize what we believe is the great untapped value of our resource portfolio. In addition to improving our operations, we have made great strides in strengthening our balance sheet. Moving forward, we fully expect our program of recompletions and workovers, together with our infrastructure projects and development drilling program, to increasingly contribute to meaningful production growth as production levels from shut-in and curtailed wells are brought to capacity and new wells are brought online.

Mark Twain said, “We are discreet sheep; we wait to see how the drove is going, and then go with the drove.” Saratoga is not following the drove. We see where they are headed, but in common with a handful of our peers, we like our current pastures.

Andy C. CliffordPresident, Saratoga Resources, Inc.

Upstream U.S. energy companies are no strangers to price volatility, but even the most grizzled industry veterans had to acknowledge that 2011 was a wild ride. Grant Thornton LLP’s 10th Survey of Upstream U.S. Energy Companies revealed a continued broad range of predictions for natural gas and crude oil prices.

Still, our respondents are not letting the uncertainty affect their expansion plans. The survey reveals increasing expectations that employment will pick up in the months ahead, after the sector contributed a significant boost to the U.S. labor market in 2011. Capital spending plans remain relatively unchanged, with a majority still expecting to spend more than they did the year before. More than three-quarters are optimistic that new shale reserves will put the country in a position to address its dependence on foreign oil.

Price expectations• Oursurveyrespondentsexpectthespotpriceof

Henry Hub natural gas to average $3.91 per Mcf in 2012, $4.30 in 2013, and $4.69 in 2014.

• Sixteenpercentpredictthepriceofnaturalgaswill be high enough to support more than a 20% increase in drilling activity in 2012, up from 8% in 2011.

• RespondentsexpectthepriceofWestTexasIntermediate crude oil to average $93.14 per barrel in 2012, $97.09 in 2013, and $101.75 in 2014.

• Forty-onepercentanticipatethepriceofcrudewill be high enough to support more than a 20% increase in drilling activity this year, down from 55% a year ago.

• Expectationsforthespotpriceofnaturalgasin 2014 range from $3 to $8 per Mcf; oil price forecasts for the same period range from $75 to $150 per barrel.

• Uncertainnaturalgasandcrudeoilpricesremainthe industry’s top concern.

Major findings

77%believe new reserves found in shale will play a factor in changing the nation’s dependence on foreign oil.


Capital spending outlook• Sixty-threepercentofrespondentsanticipate

increasing their domestic capital expenditures in 2012, down from 71% in 2011.

• Foreigncapitaloutlaysshouldremainrelativelyunchanged this year, as 82% of respondents anticipate holding the line on such expenditures.

• Themaximumacquisitionpricecompanies are willing to pay for conventional proved reserves is $2.49 MMbtu, down from $2.57 in last year’s survey.

Employment outlook• Seventy-onepercentofrespondentsexpect

employment levels to rise at their companies in 2012, up from 61% in 2011 and 50% in 2010. (Figure A)

• Eighty-sixpercentbelieveemploymentlevels in the oil and gas industry will increase this year, up from 56% in 2011 and 33% in 2010. (Figure A)

• Morethanhalf(55%)anticipatedifficultieshiringand retaining employees in 2012, up from 22% in 2011; availability of technical staff was rated third among the industry’s top concerns.

“ Now, more than ever, today’s oil and gas companies should be focusing on managing risk. Finding and producing oil and gas has always been an inherently risky business, but today there is far less margin for error than there was just a decade ago.”Alan MillisManaging Director, Business Advisory Services, Grant Thornton LLP


Industry issues and opportunities• Seventy-sevenpercentofrespondentsbelieve

new reserves found in the various shale plays in the U.S. shift or change the nation’s dependence on foreign oil.

• While28%ofthosesurveyedbelievetheircompany will qualify as an “end user”, 65% have not begun to implement the documentation and reporting required by the Dodd-Frank Act.

Figure A: Projected increases in employment levels (%)

Company

Oil and gasindustry

0 20 40 60 80 100

201020112012

201020112012

506171

335686

A number of events and developments directly affected the energy industry during 2011. Following are some of the highlights:• Geopolitical unrest in Libya, Egypt, Tunisia,

and other Middle Eastern and North African countries. The civil war in Libya has resulted in approximately 1.8 million barrels per day of oil production no longer being available; however the larger implications of this conflict will be playing out for some time. And recently, a joint exploration program proposed by the autonomous Kurdish region and ExxonMobil has raised the ire of the Iraqi central government over jurisdiction.

• Sharper scrutiny of hydraulic fracturing. Various federal, state and local authorities are looking to regulate or restrict hydraulic fracturing, and more studies are being conducted. A recent earthquake near Youngstown, Ohio, that is being attributed to the injection of wastewater from hydraulic fracturing into a disposal well will likely intensify the review of fracking processes and their byproducts.

• Nuclear and alternative energy sources falling from favor. Before the March 11, 2011, disaster at the Fukushima plant, nuclear power was beginning to be reconsidered in a positive light, but the incident soured public opinion. As heavily subsidized manufacturers from China and elsewhere flooded the world markets with low-cost solar panels, U.S. companies Solyndra and Evergreen Power filed for bankruptcy; these filings led to a steep decline in public support for government funding of alternative energy development. The wind power production tax credit, the ethanol tax credit and related import tariffs all expired at the end of 2011.

• The beginnings of a rebound in Gulf of Mexico drilling. While deep well permits are nowhere near 2008–2009 levels, regulators approved 38 such permits in 2011 (versus four during 2010 after April), 31 of which came in the last six months of the year. Rig utilization and day rates have also improved. The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) recently completed Oil and Gas Lease Sale 218, which was the first Gulf of Mexico lease sale since the Deepwater Horizon incident. The winning bids totaled more than $337 million from 20 companies, including BP.

2011 Economic year in reviewLoretta Cross, Managing Partner, Energy Advisory Services and Partner, Corporate Advisory & Restructuring Services, Grant Thornton LLPRob Moore, Director, Corporate Advisory & Restructuring Services, Grant Thornton LLP


“ Mergers and acquisitions were numerous in the energy industry during the year, with announced transactions reaching almost three times their 2010 total.”

• The issuance of new regulations. In December 2011, the Environmental Protection Agency (EPA) issued final regulations limiting emissions of mercury and other pollutants from fossil-fired power plants. Compliance by the industry is required within three years and is expected to cost $10 billion annually, and many utilities are worried that older coal-fired plants might have to shut down. Congress may move to modify the rule or extend the timeline for compliance, and utilities are likely to initiate litigation against the enactment of the regulations.

Last year, we believed that 2011 would allow industry players to pursue growth opportunities, and this supposition has been shown to be correct. Mergers and acquisitions were numerous in the energy industry during the year, with announced transactions reaching almost three times their 2010 total. In addition, transaction sizes increased during 2011. The three largest transactions announced—Kinder Morgan’s purchase of El Paso, Duke Energy’s acquisition of Progress Energy, and BHP Billiton’s purchase of Petrohawk Energy—represented aggregate consideration of more than $87 billion; this amount is greater than the combined consideration for the 11 largest acquisitions announced in 2010. Aggregate consideration for all transactions in 2011 whose values were reported totaled more than $312 billion, as compared with $216 billion in 2010.

Joint ventures, which are primarily used to acquire interests in natural gas shale acreage, again contributed sizable amounts of capital to the industry in 2011. As in prior years, the majority of joint venture transactions involved foreign partners whose investment objectives also included making their energy supply secure and gaining access to technological and production knowledge. Some of the most notable joint ventures are listed below:• ConsolEnergy/NobleEnergy—$3.4billion• DevonEnergy/Sinopec—$2.5billion• ChesapeakeEnergy/Total—$2.32billion• ConsolEnergy/HessCorp.—$600million

More equity capital was also made available during 2011. In the public markets, IPOs for companies in exploration and production as well as energy services raised almost $2.4 billion during 2011—nearly $1 billion, or 70%, more than they did in 2010. And public equity offerings in 2011 totaled in excess of $9.5 billion, up by more than 17% from $8.1 billion in 2010.

2012 capital budgets that have already been announced indicate optimism, with most of them exceeding 2011 levels by an average of 15–30%.

As we enter 2012, the industry faces a variety of ongoing challenges—the critical need for safety in its operations; environmental concerns, including issues regarding hydraulic fracturing; increasingly expensive technological requirements; and political instability in many areas of the world. Many industry analysts are bullish on oil, with most predicting that prices will materially exceed $100 per barrel during the year. Analysts are generally bearish on natural gas given the struggles in the market to balance supply with demand; most analysts are reducing their price expectations for the year to under $4/thousand cubic feet.

In summary, 2011 brought significant growth to the industry. Those participants that are positioned to manage the challenges discussed above are likely to experience another attractive year in 2012.


Volatility in natural gas and crude oil prices is making it exceedingly difficult to forecast where they are heading in the near future. Estimates for the spot price of Henry Hub natural gas this year differ by as much as $2.10 per Mcf at the extremes, while the spread between the highest and lowest forecasts for the price of West Texas intermediate crude oil is $40 per barrel. The majority of respondents believe neither will approach the price levels needed to support an increase in drilling activity of 20% or more. As a group, they are more optimistic about their capital spending plans.

Average price projections Our respondents predict that natural gas prices will recover this year, with the average expectation for the spot price of Henry Hub natural gas exceeding $4 per Mcf by 2013. They anticipate the price of West Texas intermediate crude oil hovering near the $100 level over the next several years. (Figure B)

Even so, the responses vary widely. For example, individual estimates for the average price of natural gas range from a low of $3 per Mcf in 2012 to a high of $5.10. Crude oil prices were no easier to pin down, with 2012 estimates ranging from $75 to $115 per barrel.

Respondents believe the average price of natural gas must be $5.29 per MMbtu to justify a 20% increase in U.S. drilling activity, down from $5.69 a year ago. Sixteen percent of respondents expect that natural gas prices will reach that threshold, compared to 8% in 2011. Eighty-eight percent said they would curtail production if prices were less than $4 per MMbtu in 2012.

Prices and spending


Figure B: Average price expectations

Year Natural gas Crude Oil

2012 $3.91 per Mcf $93.14 per barrel



“ Natural gas production continues to outpace demand, resulting in a few notable companies electing to curtail gas production in 2012. Although uncertain and volatile prices are inherent in the industry, it is difficult to be optimistic about a significant and sustained run up in gas prices in the near future.”Brandon SearLeader, National Energy Practice, Grant Thornton LLP

Now, more than ever, today’s oil and gas companies should be focusing on managing risk. Finding and producing oil and gas has always been an inherently risky business, but today there is far less margin for error than there was just a decade ago. The explosion of social media has sparked a new wave of social activism and increased pressure on politicians and regulators to thoroughly scrutinize the business practices of E&P companies.

As a result, leading E&P companies are implementing or enhancing an enterprise risk management (ERM) program to more confidently manage major risks that naturally occur in the E&P business. Optimally designed, an ERM program produces a standardized and comprehensive risk inventory that arms board members, company executives and department managers with the information they need to identify the risks that are most important to the company’s strategy.

Discussions with many of our E&P clients found that they are placing more emphasis than before on addressing operational risks, specifically:• Environmental—The inherent potential for

release of pollutants or spills which cause ground, air or water contamination; companies are focused on honing their ability to quickly and effectively respond to such a crisis.

• Regulatory—Greater challenges in complying with evolving regulatory requirements and inconsistent enforcement of rules in jurisdictions, particularly in emerging resource plays where regulators have limited experience with oil and gas operations.

• Public relations—The proliferation of social media is significantly increasing the velocity with which company news is disseminated to the public, prompting companies to devise new strategies for shaping news coverage and opinions.

• Contractors—An insufficient supply of adequately trained well site contractors in the newer resource plays.

• Water management—State and local restrictions or lack of proximity to an adequate water supply in certain geographic areas is making it more difficult to obtain sufficient water for fracturing wells.

• Security—Increasingly sophisticated “cyber-terrorists” are an emerging threat to production control (measurement/flow) systems.

Of course, it’s one thing to identify risks and quite another to manage them in a cost-effective way. That’s why a risk inventory is just the first step in implementing an ERM program. Once a company has accomplished this, it should evaluate each risk in terms of 1) potential financial impact to the business, 2) likelihood or probability of occurrence, and 3) the speed at which risk events can have an impact on the business.

ERM is much more than a process for tracking risks. According to a recent study by the American Productivity and Quality Center, organizations with mature ERM programs in place “reach beyond process design and mechanics… and aim to influence culture, people and mental models.” In this regard, a mature ERM function engenders a high degree of change management, necessitating the active involvement of senior leaders. We recommend that our clients follow a “top-down” approach where executives engage each functional leader in the organization, particularly in operational areas, to continuously build knowledge and expertise throughout the organization about key business risks and related risk mitigation strategies.

Given the increasing complexity of risks facing E&P companies and the speed with which missteps are disseminated, oil and gas business executives may be tempted to err on the side of caution and shoot down new opportunities that could put them in a position to expand the business. A well-managed ERM program positions business leaders to resist this temptation and pursue each new potential venture with the confidence that they’re prepared for whatever might come.

Enterprise risk management—Risk in the spotlightAlan Millis, Managing Director, Business Advisory Services, Grant Thornton LLP


When asked the same question for crude oil prices, respondents set the average price floor at $99.37, an $11.44 increase from last year. Forty-one percent believe crude oil prices will be high enough to support a 20% increase in drilling activity this year, down from 55% a year ago. Sixty-six percent indicate that oil production would be cut if prices were less than $70 per barrel, though none of our respondents expect prices to dip that low this year.

Our respondents said they would pay a maximum of $2.49 per MMbtu for conventional proved natural gas reserves, and $52.16 per barrel of crude oil.

Capital spending outlookWhile a lesser percentage of respondents than last year anticipate increasing their domestic spending, they are still in the solid majority (63%). Eighteen percent plan to spend more in overseas markets in the coming year, with the remaining 82% predicting they will hold steady with last year. (Figure C)


Of course, those plans hinge on where prices head this year, as forecasted natural gas and crude oil prices rank in our survey as the most important factors in capital spending decisions. Other factors, ranked by order of significance, include: availability of attractive drilling prospects, capital availability, projected demand for natural gas and crude oil, drilling rig availability, availability of skilled personnel, regulatory requirements or constraints, and tax considerations.

Figure C: Plans for capital spending in 2012 compared to 2011 for U.S. and foreign expenditures (%)

0 26 52 78 104 130

Increase significantly (more than 20%)

Increase somewhat(up to 20%)

No change

Decrease

218

4110

2782

110

U.S. expenditures

Foreign expenditures

It might surprise some that Houston ranked second only to New York City for M&A deal value during the first nine months of 2011.* To be sure, this was a notable achievement, considering that U.S. metropolitan areas such as Chicago and Boston have a significantly higher presence of venture capitalists, private equity firms and hedge funds whose business models essentially consist of buying and selling companies.

But to those in exploration and production (E&P), Houston’s emergence as a hotbed for M&A activity was far from unexpected. Since their primary assets (i.e., reserves) are a dwindling resource with a finite value, E&P companies are under constant pressure to acquire and exploit reserves or buy other E&P companies when they can’t replace reserves organically. Fortunately, their historically strong balance sheets and cash positions allowed them to make deals last year, even as many other industries and locales were forced to retrench.

The real surprise is how often E&P executives ask the same question when considering an M&A transaction: “Since our reserves—and their values—are under the ground, why should we perform financial due diligence?” My response is always the same: “How can a dynamic E&P company afford not to?”

I’ve had the opportunity to work on more than 200 transactions during my career—as a private equity professional, a director of corporate development in industry, and an M&A transaction adviser. Through this experience, I’ve learned that understanding key transaction risks—and negotiating and structuring the transaction to mitigate them—are critical to a successful deal. After all, a single

M&A transaction can alter a company’s future significantly. The challenge is that most companies are operationally focused and typically do not have sufficient M&A experience at the executive level or the infrastructure needed to acquire and integrate companies effectively. With so many E&P company earnings and reserve restatements stemming from acquisitions in recent years, it’s clear that the industry is not immune to this challenge.

With that in mind, it’s a good idea for E&P executives to examine key transaction considerations that are unique to their companies and have the potential to negatively impact capital deployment and/or cash flows if not properly measured and factored in. Grant Thornton’s Energy Transaction Advisory Services group helps companies assess E&P transaction risks in five overarching categories: (1) reserve and production characteristics, (2) reinvestment, (3) operating and capital efficiency, (4) tax exposures, and (5) non-E&P operations. Executives should consider a number of essential items within these categories when conducting due diligence:

Reserve and production characteristics• Theimpactofhistoricalversusprojected

production volumes and volatility on cash flows. • Concentrationanddiversificationamonggeologic

basins (e.g., percentage of oil versus gas, onshore versus offshore, and number of wells).

• Thedurationthatprovedundevelopedreserves(PUDs) have been on the books, the related drilling program to develop these PUDs, and whether there were significant changes to the drilling program.

E&P industry—Key M&A transaction risksBrandon Cradeur, Managing Director, Transaction Advisory Services, Grant Thornton LLP

* Houston Chronicle, Dec. 19, 2011.


• Thereservereport,whichisacriticalreportrelied upon during E&P transactions, presents many risks and estimates that are important to consider, including (1) risks related to whether the report was prepared internally or externally, (2) projection sensitivities based on production and forecasted capital expenditures (CAPEX), and (3) estimates generated by comparing the current NYMEX strip with the price deck used.

• Historicalassetimpairmenttestingand related analyses.

Reinvestment• Thereservelifeindex—calculatedbydividing

proved developed producing (PDP) reserves by annual production—indicates the potential pressure of capital deployment.

• Comparisonoftheannualreservereplacementindex, which indicates a company’s ability to replace its annual production, with indexes calculated by companies of similar sizes.

• Evaluatingacompany’sabilitytoeconomicallyreplace reserves; this evaluation involves looking at historical finding and development (F&D) costs based on dollar-per-barrel equivalent (boe).

• Calculatinganundevelopedleaseexpirationwaterfall, which identifies potential acreage and reserves at risk of being lost.

• DrillingandCAPEXassumptionsusedindeveloping PUD projections.

• Thereserveacquisitionpriceperboeversushistorical F&D costs.

• Theexistenceofcommitmentsrelatedtoseismicacquisition, CAPEX, drilling, or long-term take-or-pay contracts with commodity price caps or floors.

Operating and capital efficiency• Operatingefficiencyasmeasuredbythefull-cycle

cost and expressed as $/boe. The full-cycle cost is the average cash cost to produce each boe and the capital necessary to replace it—in other words, the sum of lease operating expenses (LOE) plus general and administrative (G&A) burden plus F&D costs.

• Management’sabilitytomaintainastrongliquidity position as measured by the ratio of capital spending to cash flows.


“…it’s a good idea for E&P executives to examine key transaction considerations that are unique to their companies and have the potential to negatively impact capital deployment and/or cash flows if not properly measured and factored in.”

Tax exposures• Federal,stateandlocalincometaxexposures.• Salesandusetax,propertytax,employmenttax,

escheat, or other applicable tax exposures. • Deferredtaxassets/liabilities,netoperatingloss

(NOL) carryforwards, the depletion deduction allowance, like-kind exchanges, and tax basis verification.

Non-E&P operations• Thepotentialforsignificantliabilitiesrelatedto

other businesses (e.g., midstream, distribution or refining/marketing) with different risk profiles, such as an out-of-the-money trading book from aggressive marketing/trading activity or environmental liabilities from refineries and chemical plants.

In addition to looking at these items while conducting their due diligence, E&P companies should consider factors that fall outside these broader categories. Following are some of the questions we encourage our clients to answer: Does the asset base, as currently leveraged, generate adequate return on capital invested? If not, what are the scenarios to optimize investment? What are the strategic synergies that can be created by the transaction under consideration, and how are they expected to impact the overall value chain? Are hedging programs in place to protect against commodity price exposures? Are there any joint venture or royalty issues, counterparty risks, or off-balance sheet financing contingencies?

The challenge, of course, is finding the best way to perform financial and operational due diligence in today’s environment of limited or stretched corporate development budgets. Companies can build out their corporate development departments, engage experienced transaction advisory professionals to leverage their internal team, or elect to do both. Whatever approach a company takes with respect to due diligence, the rewards for conducting it will be clear: The company will not only make more informed decisions, but also perform its fiduciary duties for its investors and lenders in an optimal way.

After four straight years of low expectations for hiring, we saw a marked increase in the percentage of respondents looking for the industry’s overall level of employment to rise in the coming months. Many seem to believe that these hiring plans will exacerbate the war for talent, as a majority now believes their companies will have difficulty hiring and retaining employees. Given that higher salaries, larger cash bonuses and equity awards are widely used to attract new workers, companies may have to differentiate themselves in other ways to bring on necessary talent.

Employment levelsRespondents predict that hiring will pick up in 2012 at their companies and in the industry overall. Seventy-one percent expect their company’s employment level to increase in the coming year, compared with 61% in last year’s survey. That figure swelled to 86% when considering the industry’s overall employment; that was a marked increase from the 56% of respondents who expected the industry to add workers last year. (Figure A)

Hiring and retaining talentA majority of respondents (55%) expect to encounter difficulties hiring and retaining employees in the coming year, up from just 22% a year ago. (Figure D) They indicate that higher salaries will likely be the most popular mechanism they use to attract skilled workers, with larger cash bonuses, equity awards and other enhanced benefits all drawing at least 50%. Fifty-seven percent predict increasing compensation for geologists, engineers and other professionals by at least 10% this year, up from 21% of respondents in last year’s survey. (Figure E)

Employment


86%expect the industry’s overall employment level to increase over the next year.

“ The energy sector is booming and is one of the few areas of job growth. Major oil companies seem to be switching their focus to the United States not only to achieve production growth, but also to position themselves for a longer-term investment in natural gas.” Andy CliffordPresident, Saratoga Resources, Inc.

Figure D: Respondents expecting difficulties hiring and retaining employees in the coming year (%)

20112012

2255

0 10 20 30 40 50 60

Figure E: Respondents planning to increase professional salaries by at least 10 percent (%)

20112012

2157

0 10 20 30 40 50 60

Not surprisingly, respondents list uncertain natural gas and oil prices as the greatest threat to their business. As such, they are increasingly turning to hedging instruments to address that risk, but they also agree that additional government incentives to increase drilling would be the most effective way to keep consumer energy prices in check. Those surveyed are more concerned than in recent years about finding skilled workers, and they expressed uncertainty about how to handle rapidly changing regulatory and tax requirements.

Enhancing company valueSuccessful exploitation and exploration of resources top our respondents’ list of factors with the greatest potential for enhancing company value. Those factors rank ahead of (in order): operating efficiencies, mergers and acquisitions, retaining and attracting people, better use of technology, price risk management (e.g. hedging), capital infusion and asset sales.

Threats to company valueRespondents list uncertain natural gas and oil prices as the greatest challenge facing the industry today. Availability of technical staff moved up two spots compared to last year’s survey; the issue now ranks as their third biggest concern. Rounding out the list are regulatory requirements, legislative initiatives, obtaining capital, environmental considerations, lack of good exploration prospects, competition with larger companies, and litigation concerns.

HedgingThe survey found that 59% of respondents increased the use of hedging instruments over the past year to effectively manage price risk. More than three-quarters (77%) said that hedging instruments were required by lenders.

Industry issues and opportunities

“ In the public markets, IPOs for companies in exploration and production as well as energy services raised almost $2.4 billion during 2011—nearly $1 billion, or 70%, more than they did in 2010.”Loretta Cross, Managing Partner, Energy Advisory Services and Partner, Corporate Advisory & Restructuring Services, Grant Thornton LLP and Rob Moore, Director, Corporate Advisory & Restructuring Services, Grant Thornton LLP


The role of governmentThose we surveyed said government incentives to increase U.S. drilling for oil and gas is the most effective mechanism for reducing energy prices for the U.S. consumer. Increased U.S. refining and processing capacity and increased efficiency through technology are also viewed as significant contributors.

Asked to identify priority areas for the federal government to focus its support of the industry, respondents said opening onshore federal lands for drilling should be its biggest focus in the short term. Clean coal was the top vote-getter for alternative fuel policies in the short term, coming in well ahead of other options such as biofuel, geothermal and wind energy. Carbon emission credits are seen as a near-term priority by less than a third of respondents. (Figure F)

The shale gas boomSeventy-seven percent of respondents believe new reserves found in the various shale plays in the U.S. will shift or change the nation’s dependence on foreign oil.

The Dodd-Frank ActOnly 28% of respondents believe they will qualify as an “end user” and therefore be exempted from complying with the Dodd-Frank Act. Even so, nearly two-thirds (65%) have not begun to implement the documentation and reporting required by the law.


“ Some of the most attractive features of shale plays are the long-lived nature of the reserves, the repeatability, the high probability of success and large lease positions.”Andy Clifford, President, Saratoga Resources. Inc.

Open areas for drilling Short term Long termEast Coast 34 66West Coast 33 67Eastern Gulf Coast 60 40Arctic 51 49Onshore Federal 61 39

Drilling Incentives 51 49

Alternative FuelsNuclear 25 75Solar 15 85Wind 26 74Geothermal 28 72Biomass 25 75Clean Coal 53 47Biofuel 33 67

Environmental safeguards 41 59

Carbon emission credits 29 71

R&D CreditsGrants 43 57Tax credits 50 50

Figure F: Preferred areas of government focus (%)

0 20 40 60 80 100

0 20 40 60 80 100

0 20 40 60 80 100

A flock of nearly 2,000 public accountants and industry professionals converged on the nation’s capital in December for the 2011 AICPA National Conference on Current SEC and PCAOB Developments. What drove us all to D.C.? A common viewpoint was that we would finally hear how and when International Financial Reporting Standards (IFRS) would be incorporated into the U.S. financial reporting system. The anticipated announcement was expected to reflect thoughts initially publicized in a May 26, 2011, Staff Paper, Work Plan for the Consideration of Incorporating International Financial Reporting Standards into the Financial Reporting System for U.S. Issuers: Exploring a Possible Method of Incorporation. At the end of the three-day conference, however, the flock flew the coop with no decision rendered.

SEC Chief Accountant James Kroeker did acknowledge that while a decision had been expected by the end of 2011, a final determination would not be forthcoming for a few months. His reasoning was that the staff paper was not yet complete, nor were several major convergence projects that needed to be finalized prior to a decision. The SEC indicated that it has completed the majority of its fieldwork and is finalizing a staff paper that will ensure a strong and lasting framework for standard setting. According to Kroeker, key requirements for a successful incorporation of IFRS include (1) providing clear U.S. authority over standard setting in U.S. capital markets, (2) mandating and facilitating a strong U.S. voice in establishing global accounting standards, and (3) responding to the economic and other impacts of change.

For its part, the International Accounting Standards Board (IASB) has indicated that it may be time to discontinue convergence efforts with the Financial Accounting Standards Board (FASB), as suggested in recent speeches by IASB Chairman Hans Hoogervorst. At the AICPA conference in Washington, he stated that the convergence efforts have been “extremely useful in getting us to a point where IFRS and U.S. GAAP are much improved and closer together” but may be most beneficial when directed toward other countries pursuing convergence paths. His comments were generally indicative of the best method of adoption, incorporating the approach outlined in the staff paper, but he seemed cautious about any plan that did not include a clear timeline and a transparent, very high threshold for declining to endorse a standard. The IASB’s expectation is that deviations from international standards will be “extremely rare”. The IASB continues to recommend that U.S. companies be allowed to voluntarily adopt IFRS in the very near future.

Worldwide momentum In the meantime, the rest of the world is flying toward the use of IFRS as a common global standard for financial reporting. The only question remaining for most countries is when, not whether, to move to IFRS. For these countries, a single common set of standards has several clear benefits. First, it would allow for greater transparency and comparability of financial statements across an industry. As financial reporting gained greater transparency, investor confidence in it would inevitably grow. Second, global standards would allow for more efficient

Global use of IFRS— When, not whetherApril D. Little, Partner, Transaction and Risk Advisory Services and Practice Leader, IFRS Tax, Grant Thornton LLP


capital markets. Investors would be able to compare transactions and the allocation of capital based on common accounting methods. Finally, with the issue of convergence settled, rulemakers would be able to focus their attention on improving one new set of global standards.

Among those regions currently moving to IFRS, Europe is furthest along. Countries from Albania to the United Kingdom have been successfully using IFRS since 2005. The only remaining country on the European continent to prohibit the use of IFRS is Belarus, which has no common exchange, yet even Belarus is currently planning for convergence. Latin America has begun the transition, with Brazil and Venezuela requiring IFRS for many companies in 2011; Argentina and Colombia are mandating IFRS in 2012. In Asia, India and Indonesia are the most recent countries requiring the use of IFRS for many of their listed companies. Africa is not far behind, with Nigeria planning for transition using a phased-in approach from 2012 to 2015.

Implications for the U.S. energy sectorHere in North America, our neighbors to both the north (Canada) and the south (Mexico) have charted a path to mandatory use of IFRS. While the United States remains the lone holdout, the staff paper details a method for incorporating IFRS into the U.S. accounting system.

The staff paper described an endorsement approach whereby existing standards would be reviewed and grouped into several tiers: (1) completed Memorandum of Understanding (MOU) projects, (2) IASB agenda projects, and (3) projects with no current revisions planned. Under the proposal, convergence would be determined separately for each group. The SEC was clear that it is considering comments and refinements or alternate approaches and expects to make a decision in the coming months. That decision is likely to be highly dependent on current key convergence projects regarding topics of significant importance to the energy industry: leasing, revenue recognition and financial instruments.

The proposed leasing standard, which will be applicable to leases of oil and gas properties, would put the majority of leases on companies’ balance sheets and effectively front-load expense for lessees and income for lessors. The revised leasing standard is currently being re-exposed and is not expected to be finalized until at least mid-2012.

The proposed revenue recognition standard simplifies guidance for revenue recognition in a significant way, moving from more than 220 existing revenue recognition models under U.S. GAAP to a single revenue recognition model. The most common criticism of the proposed standard is its lack of detailed guidance. The proposal was re-exposed in November 2011, with final issuance expected in the first quarter of 2012.

In the current international standards, there is very little specific industry guidance for extractive activities. IFRS 6, Exploration for and Evaluation of Mineral Resources, gives stopgap guidance for accounting for exploration and evaluation costs; this guidance is intended to help companies transitioning to IFRS from local GAAP. In the interim, a discussion paper, Extractive Activities, was issued in April 2010. In October 2010, the research project was paused to allow the IASB to conclude deliberations on its future workplan. The Board’s next step will be to determine, based on the completed research project, whether to add a proposed project for extractive activities guidance to its future agenda. For now, energy companies will have to rely on only limited industry-specific guidance.

Some of the other standards that will impact energy companies include IAS 36, Impairment of Assets, and IAS 16, Property, Plant and Equipment. The transition to international standards in these two areas may involve a substantial amount of work, since both standards generally require consideration of a much more precise unit of account. Fixed assets, for example, are capitalized based on replaceable components. Goodwill and other intangible assets, similarly, are evaluated for impairment at the level of the cash-generating unit that is used to aggregate and analyze financial data. This will compel companies to maintain records and evaluate transactions at a much more detailed level than they are accustomed to under U.S. GAAP.

Why the time to act is nowWith U.S. standard setters not yet charting a path toward the use of IFRS, why should U.S. companies be concerned about international standards? Much as they were during the evolution of Sarbanes-Oxley (SOX) Section 404 and FASB Interpretation No. 48 (FIN 48), companies in the United States are in wait-and-see mode until the SEC announces a formal plan for the use of international standards. Lacking any substantive guidance for energy and extractive



activities, many U.S. companies will postpone planning for transition to IFRS for the foreseeable future.

For many, however, this tactic may result in a competitive disadvantage. Awareness of IFRS and the basic differences between it and U.S. GAAP is increasingly important for companies requiring access to global capital markets. Most global creditors, vendors and even regulators of state-owned natural resources arrange contractual obligations using metrics tied to global reporting standards as their domestic markets transition to IFRS. Some of the common areas causing differences are discussed above. Other classification differences impacting the balance sheet can also influence key financial metrics dramatically. For example, a company’s current ratio may be affected by reclassifying all deferred taxes to noncurrent for IFRS purposes. Or a company may find that while it cured a debt covenant violation prior to finalizing the financial statements, the entire obligation must be classified as current based on a purely technical violation as of the year-end. Some statements of financial position will be highly volatile, particularly in the year of conversion, as a result of the optional use of fair value measurements for intangible and fixed assets.

Additionally, many players in the global M&A market are using IFRS as a common basis for evaluating transactions across the industry. With IFRS conformity increasing on a global scale, a U.S. GAAP metric becomes difficult to compare with existing benchmarks. Companies may find that capital markets are interested in common measurement metrics under IFRS rather than U.S. GAAP. For example, one company I’m familiar with translates all U.S. GAAP reporting information to IFRS solely for the purpose of entering the global private equity market because, as one company executive says, “the game is played globally, so we have to react globally.” Acquirers see common global accounting methods as a time and cost efficiency, while acquired companies find that interest in an investment increases as it grows competitive under common measurement standards. Companies that aren’t prepared risk turning off investors that might otherwise spend the resources needed to improve technology systems, catalog and coordinate accounting methods, or create duplicative reporting systems for U.S. GAAP.

From the investor perspective, common accounting standards decrease the number of financial reporting languages a user must master. True, dialect differences remain, but these can be caused by a variety of factors: • Differencesininterpretationduetocommon

practices carried over from a country’s prior reporting standards

• Differencesintransitionalguidancethatmayprohibit or require certain accounting treatments

• Lackofdetailedapplicationguidance• Flexibilityinchoosingalternativeaccounting

policies (keeping in mind that different standards do not always mean different outcomes)

Finally, as the United States moves closer to IFRS, companies with an awareness of the new standards will be in the best position to manage upcoming changes to U.S. GAAP and minimize their impact on operations. Indeed, these companies will be most capable of adopting IFRS in the next 18 to 24 months, based on a typical timeline (Figure G). This timeline assumes that a company will evaluate common accounting policies across consolidated groups and make changes to IT systems, hiring and compensation policies, and contract negotiations. In other words, these companies will have a competitive advantage when the United States ultimately taps into the global accounting pipeline.

Figure G: A typical timeline for IFRS adoptionExample: 2012 IFRS reporting timetable for a March 31 year-end company

IFRStrasitiondate

2010/11 2011/12

IFRSreportingdate

Q1 Q2 Q3 Q4

April 1, 2010IFRS openingstatementof position

March 31,2011Last localGAAP financialstatements

June 20, 2011First quarterlyreport underIFRS

March 31, 2012First IFRSfinancialstatements

First effective year under IFRSComparative year under IFRS

Q1 Q2 Q3 Q4

The issues identified as concerns in this year’s survey—price volatility, finding and retaining talent, the need to operate more efficiently—are not likely to go away in the coming months. Leading energy companies are managing this uncertain environment through a variety of means, all coordinated from the top of the house in a strategic and holistic way.• Risk management—Employing ERM

programs to make better strategic decisions and redeploy capital effectively, and incorporate risk management in financial reporting and the corporate culture.

• Transactions—Turning to acquisitions and joint ventures to share risk, increase capital and expand access to new technologies.

• Accounting standards—Getting ahead of IFRS requirements to open more doors to sovereign wealth funds and other global investors that may be interested in investing in high-risk energy ventures but demand consistency in reporting.

• Talent—Benchmarking and tailoring benefits and compensation programs to remain competitive and take advantage of the information now available through newly enhanced compensation disclosure requirements in the U.S.

• Operating efficiency—Focusing on improved cash management and working capital strategies, assessing changes to IT management and opportunities provided by cloud computing, and improving the tax function to capitalize on all available incentives and structure the overall tax organization for optimal tax advantage.

Implications


About the surveyThis is the 10th Survey of Upstream U.S. Energy Companies commissioned by Grant Thornton. The survey was conducted via mail and Internet from November 2011 through January 2012, with more than 100 responses from senior executives of independent oil and gas exploration and service companies. Survey topics included price and employment forecasts, capital spending plans, regulatory and legislative developments, and new areas of opportunity. Issues explored by the Grant Thornton Survey of Upstream U.S. Energy Companies were identified by seasoned professionals in Grant Thornton’s Energy Practice. The figure below indicates the demographics of the companies that responded to the survey questionnaire.

About Grant ThorntonGrant Thornton LLP is the U.S. member firm of Grant Thornton International, one of the six global accounting, tax and business advisory organizations. Through member firms in more than 100 countries, including 49 offices in the U.S., the partners of Grant Thornton member firms provide personalized attention and the highest quality service to public and private clients around the globe.

National Energy PracticeGrant Thornton’s National Energy Practice is dedicated to serving the accounting, tax and business advisory needs of public and privately owned energy companies. Headquartered in Houston, Grant Thornton’s Energy Practice group has experience in all segments of the industry with a focus on exploration and production, drilling and energy services, pipeline and distribution, and refining and marketing. Grant Thornton’s experienced team of energy professionals provides the following industry-specific services:• audit• governanceriskandcompliance• federaltax• internationaltaxconsulting• stateandlocaltaxconsulting• forensics,investigationsandlitigation• informationtechnology• performanceimprovement• businessstrategy• restructuringandturnaround• transactionadvisoryservices• valuation

Demographics


Demographics

Exploration and production companies 75%Gathering and transportation companies 8%Service companies 13%Other companies 4%

Average total assets at the end of fiscal 2011 $1.63 billionAverage projected revenues for fiscal 2011 $544 million

Public 27%Private - C Corp 15%Private - S Corp/Partnership 38%MLP 20%

Contact information

Energy practice key contactsClevelandRick Gross, Audit PartnerT 216.858.3627

Patrick Gable, Audit PartnerT 216.858.3537

DallasKenneth Clay, Audit PartnerT 214.561.2290

DenverBruce Johnson, Audit Senior ManagerT 303.813.4000

HoustonBrandon Sear, National Energy Practice LeaderT 832.476.5048

Loretta Cross, CARS Managing PartnerT 832.476.3630

Susan Floyd-Toups, Tax Executive DirectorT 832.476.3631

Kansas CityGreg Payne, Audit PartnerT 816.412.2400

Oklahoma CityKevin Schroeder, Audit PartnerT 405.218.2800

TulsaJohn Meinders, Audit PartnerT 918.877.0800

Tim Ogden, Tax Practice LeaderT 918.877.0812

WichitaBrad Heerey, Audit PartnerT 316.265.3231

Office locationsNational Office175 W. Jackson Blvd., 20th FloorChicago, IL 60604-2687312.856.0200

Washington National Tax Office1250 Connecticut Ave. NW, Suite 400Washington, DC 20036-3531202.296.7800

AlaskaAnchorage 907.264.6620

ArizonaPhoenix 602.474.3400

CaliforniaIrvine 949.553.1600Los Angeles 213.627.1717Sacramento 916.449.3991San Diego 858.704.8000San Francisco 415.986.3900San Jose 408.275.9000Woodland Hills 818.936.5100

ColoradoDenver 303.813.4000

ConnecticutGlastonbury 860.781.6700

FloridaFort Lauderdale 954.768.9900Miami 305.341.8040Orlando 407.481.5100Tampa 813.229.7201

GeorgiaAtlanta 404.330.2000

IllinoisChicago 312.856.0200Oakbrook Terrace 630.873.2500Schaumburg 847.884.0123

KansasWichita 316.265.3231MarylandBaltimore 410.685.4000

MassachusettsBoston—N Station 617.723.7900Boston—Fin Distr. 617.226.7000Westborough 508.926.2200

MichiganDetroit 248.262.1950

MinnesotaMinneapolis 612.332.0001

MissouriKansas City 816.412.2400St. Louis 314.735.2200

NevadaReno 775.786.1520

New JerseyEdison 732.516.5500

New YorkAlbany 518.427.5197Long Island 631.249.6001Downtown 212.422.1000Midtown 212.599.0100

North CarolinaCharlotte 704.632.3500Raleigh 919.881.2700

OhioCincinnati 513.762.5000Cleveland 216.771.1400

OklahomaOklahoma City 405.218.2800Tulsa 918.877.0800

OregonPortland 503.222.3562

PennsylvaniaHarrisburg 717.265.8600Philadelphia 215.561.4200

Rhode IslandProvidence 401.274.1200

South CarolinaColumbia 803.231.3100

TexasAustin 512.391.6821Dallas 214.561.2300Houston 832.476.3600San Antonio 210.881.1800

UtahSalt Lake City 801.415.1000

VirginiaAlexandria 703.837.4400McLean 703.847.7500

WashingtonSeattle 206.623.1121

Washington, D.C.Washington, D.C. 202.296.7800

WisconsinAppleton 920.968.6700Madison 608.257.6761Milwaukee 414.289.8200

© Grant Thornton LLPAll rights reservedU.S. member firm of Grant Thornton International Ltd

Content in this publication is not intended to answer specific questions or suggest suitability of action in a particular case. For additional information on the issues discussed, consult a Grant Thornton client service partner.

GT - Growth strategy: Perspectives from financial executives

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