Let's Make a Deal

The cognoscenti of oil and gas acquisitions and divestitures are waiting for the upstream domestic transaction market to break open sometime before the end of 2012. And when it does, it will reveal whether the A&D sector can sustain upstream domestic transaction levels at $70 billion annually, despite recent headwinds from softer commodity prices.

“We’re seeing all kinds of deals,” says Ener-Vest Ltd. chief executive and president John Walker, always an active buyer. “I think the market will break the record this year in terms of value.”

Four major themes have propelled the domestic upstream A&D market to a triumphant and transformative two-year run. First is the expansion of joint ventures as a mechanism to finance the high cost of unconventional resource development. The combined sum of U.S.-oriented JVs topped $41.5 billion over the past four years with additional candidates readying themselves by year-end.

At press time, Devon Energy Corp. and Sumitomo Corp. announced their $1.4-billion Permian Basin JV providing Sumitomo a one-third interest in 650,000 net acres prospective for the Wolfcamp shale. And, long-time Permian player Pioneer Natural Resources Co. had also assembled 200,000 acres in the Wolfcamp, which it is marketing as a JV.

Second, the A&D market witnessed the return of the majors to North America in their hunt for unconventional reserves, beginning with ExxonMobil’s landmark $41-billion acquisition of XTO Energy in December 2009. Chevron, Hess, Marathon and Shell soon followed, obtaining acreage in the Marcellus, Bakken and Eagle Ford shales.

While joint ventures dominated transactions in 2008-2009, the story changed in 2010-2011 as the majors purchased significant positions in the Marcellus, Bakken, and Eagle Ford shales. Facing page: Crew members operate the slips on Big E Drilling’s Rig No. 3. The rig is employed by EnerVest Ltd., which holds 800,000 acres in the Austin Chalk in central Texas.

Outside of Exxon/XTO, the international oil companies (IOCs) have spent an additional $45 billion on acquisitions during 2010-2012. Transaction values for JVs and the majors’ deals in the U.S. now exceed $122 billion since 2008.

Third, the market saw the rise of upstream master limited partnerships (MLPs) from humble beginnings in 2006 into more than half a dozen firms that include two sizeable players, Linn Energy LLC and EV Energy Partners LP, with enough critical mass on a combined market cap above $10 billion to become asset consolidators in tight formation plays like the Granite Wash, the Barnett shale and Wyoming’s Jonah-Pinedale gas field.

Lastly—and more recently—the oil and gas industry experienced an influx of private equity as the large Wall Street generalist firms sought to expand their roles in energy. Those firms include affiliates of KKR & Co. LP (KKR) and Apollo Global Management, each of whom joined with partners to execute significant upstream deals in the past year. Apollo purchased El Paso Energy’s upstream assets for $7.15 billion in March 2012, while KKR scooped up Tulsa-based Samson Resources for $7.2 billion in November 2011.

These Wall Street firms are joining the private-equity market traditionally led by energy specialists such as EnCap Investments LP, Quantum Energy Partners and Natural Gas Partners (NGP). Private-equity funds focusing on upstream E&P represent an investment pool of $35 billion, which adds to sector deal flow.

Combined, these four themes produced a two-year run of record annual transaction volumes domestically, including $77 billion in 2010 and $70 billion in 2011. When upstream U.S. transaction value fell below $8 billion during second-quarter 2012—and was just $20 billion for the first half of 2012—A&D observers questioned whether weakening commodity prices were negatively impacting the A&D market.

The outlook on 2012

William (Bill) Marko, managing director of Jefferies & Co., took time from a Canadian coastal vacation in late July to reflect on the 2012 A&D market for Oil and Gas Investor. The veteran of more than $50 billion in asset and corporate transactions, including two U.S. JVs between Chesapeake Energy Corp. and CNOOC Ltd., says he has seen fatigue creep into the market.

“Deals are getting harder to do because of a couple of things,” Marko says. “The people who have done deals are digesting the transactions so they may not be in the deal flow and you have fewer buyers. Secondly, with the falling oil price and a weak gas strip, it’s been hard for people to find consensus on how to value deals.

“Prior to the upturn in price in July, buyers didn’t know how far the oil price was going to fall so they didn’t know how to price things. The sellers just saw $100 oil a few months ago and of course they would rather sell for $100 oil. With strengthening oil prices some confidence returned to the market. On the gas side, capitulation by sellers is the theme to improved deal flow. I think you’re starting to see a little more of that since natural gas has come off the bottom.”

Greg Matlock, senior manager for transaction advisory services at Ernst & Young LLP, sees a wide range of oil and gas deals flowing through the accounting firm’s Houston office. He also anticipates the A&D market will heat up as 2012 runs its course.

“We’re still seeing significant interest in inbound acquisition and inbound joint ventures, whether that be in the upstream or the midstream space,” Matlock says. “The first half of 2012 has been a little slow on the publicly disclosed large deals, and you haven’t seen as many as in prior years. But we still expect quite a number of deals to get done in the second half of 2012.”

Foreign firms continue to express interest in domestic transactions of all forms, whether JVs or asset acquisitions, he says.

“Even in deals that aren’t closing, we’re seeing a large amount of interest in North American oil and gas. We’d be more comfortable saying that the market had peaked, if we weren’t continuing to have discussions with new investors or existing parties who already have bought in, are looking to buy more, or looking at different plays to diversify their resource basins.”

One thing on buyers’ and sellers’ minds is the direction of natural gas prices, which has been holding up some deal-making.

Quantum Energy Partners CEO Wil VanLoh expects the transaction market to revitalize in the second half of 2012 as natural gas assets come back into favor. “When gas prices fell in 2009, 2010, 2011, there was a pretty big bid-ask spread between buyers and sellers. A lot of deals never transacted on the gas side.

“But over the last six months, buyer and seller expectations on gas prices have moved closer in alignment. There is still a gap, but a lot of public companies are thinking about selling assets in order to generate cash to reinvest in their oil or liquids-rich programs.”

In fact, the 2012 market is entering the stretch run with several big deals pending, including the widely anticipated sale of Chesapeake Energy Corp.’s Permian Basin acreage (at press time EnerVest supposedly agreed to buy some of that package), an additional Chesapeake JV in the hot Mississippi Lime, EnerVest’s monetization of its Utica shale holdings, and a widely discussed large transaction involving the Gulf of Mexico shelf, to name just a few of the events that will influence 2012 transaction volume.

“The intelligence we get from the A&D firms we talk to is there are quite a few deals coming to market in the second half of the year,” VanLoh says. “I can tell you within our portfolio, for example, the capital gains tax going from 15% up to 28% is absolutely causing a lot of people to think: let’s go ahead and get a deal done by the end of the year.

“I clearly think that changes in the tax code are going to drive some selling.”

EnerVest’s Walker identifies two trends stimulating near-term deal flow. “The market rewards oilier or more liquids-rich companies more than they do dry-gas companies, so the dry-gas entities are trying to change their stripes—and they are trying to do that rapidly, and I think that’s a continuing theme.

“Secondly, I think the guys with high exposure and negative cash flow in the shale plays need currency and their most ready source of currency is to sell cash-cow assets and provide money for their more attractive and cash-demanding assets.”

Are MLPs changing their model?

Longer term, the four transaction themes hint at an evolving U.S. industry model that finds the MLPs expanding share by amassing a growing portfolio of legacy holdings in conventional assets. Additionally, speculation surrounds the question of whether the majors are biding time before the next round of consolidation. Will this involve a partial round-up of large independents with prime positions in resource plays outside the Marcellus and Eagle Ford, where the majors have concentrated so far?

In other words, if both ends of the E&P spectrum grow, as represented by MLPs and the majors, will that growth come at the expense of public independents in the middle?

One of the more intriguing angles in this thesis is whether MLPs are becoming more like growth-oriented C-Corp E&Ps, following recent MLP transactions in unconventional oil and gas in the Granite Wash, Jonah-Pinedale, and the Barnett shale.

Walker fields the MLP question directly. Through EnerVest and EV Energy Partners L.P., he looks at 500 to 600 proposals annually, more deals really than Monte Hall, the legendary maven of television’s “Let’s Make a Deal.”

“If you just look at us, we might be the most extreme MLP out there because we have the Utica,” Walker says. “But the answer, in my opinion, is almost by necessity the MLPs have not changed stripes.

“You really can’t grow an MLP organically over time. The reason for that is when you drill wells, the decline curve escalates higher and higher. If you have negative cash flow and you’re drilling too many wells with a high decline rate, it causes the overall decline rate of the MLP to accelerate. You get on a treadmill and you’re not going to be able to meet your distribution target for investors.”

Quantum’s VanLoh sees evidence of change in the largest MLPs, though the magnitude is hard to quantify. Quantum, which has $6.5 billion in capital under management, played a major role in birthing the upstream E&P MLP model in mid-decade. The private-equity firm brought Linn Energy to market in January 2006, provided an investment midwife’s role in the January 2007 IPO of Legacy Reserves LP in the Permian Basin, and more recently, launched QR Energy Partners LP in December 2010 as an MLP focused on acquiring mature assets throughout North America from related Quantum entities as well as from third-party sellers.

“A lot of people told us back in 2004 when we were trying to first do this that E&P MLPs can’t be done,” VanLoh recalls. “There were MLPs in the oil and gas business back in the 1980s and for the most part they all went out of business. But they went out of business because they were exploration oriented; they weren’t buying mature producing properties. When we started Linn Energy, we were intent on making sure we had a sustainable model that could deliver the results we were promising investors, which was stable distributions, growth in distributions,” he says.

The standard model is that investors reward C-Corp companies for growth in production and reserves. Consequently, these companies re-invest a majority of their capital to generate growth. Conversely, MLPs package low-risk, mostly producing or legacy properties as a yield vehicle.

“We said there are a lot of assets out there where you can re-invest 20% or 30% of your cash flow and just maintain production,” Van-Loh says. “If you can do that and hedge so you can remove the volatility of commodity price fluctuations, you can deliver a long-term, stable distribution to the unit holders of the MLP. That was the original premise.”

VanLoh suggests that some of the larger MLPs can now grow production by investing more of their cash flow into assets rather than just running the clock out on the long tail of terminal decline, replenishing the portfolio with proved developed producing properties (PDPs), and ultimately serving as the oil and gas version of assisted living centers for legacy assets.

But is the MLP structure itself evolving, given recent acquisitions in formerly higher-risk tight-oil and gas plays?

Ernst & Young’s Matlock sees a growing appetite among asset holders to explore a variety of options for monetization of oil and gas properties, including MLPs, JVs, or other business structures that allow the seller to capture value in existing properties in a tax-efficient manner.

Matlock identifies alternatives to upstream MLPs, to include the resurgence in the U.S. royalty trust structure as evidenced by SandRidge Mississippian Trust I and II, Energy Corp. of America’s ECA Marcellus Trust I, and the Chesapeake Granite Wash Trust.

“…we don’t think there is going to be a huge shift in the overall make-up of the MLP profile,” Matlock says. “But in a smaller subset of upstream MLPs, you are starting to see a little more investment in non-traditional types of properties.

“What we have seen lately…is a newer concept , variable pay or variable distribution. What that means is that outside of the cash the MLP is going to reserve or retain, it will distribute what it has on hand to its unit holders. If it’s a great quarter, the MLP will distribute more cash out to unit holders. If it’s a bad quarter the MLP distributes what it has on hand, whether that is equal to or less than what the MLP distributed in previous quarters.”

One analog of how the variable distribution MLP works can be found at KKR, the New York-based global investment firm. While historically viewed solely as a private-equity firm, KKR is a full service investment firm providing an array of investment vehicles to clientele. Over the past decade, KKR allocated a growing volume of investments towards the energy and power sectors.

It has created newer vehicles for investment, depending on an investor’s appetite for risk. An example is the KKR Natural Resources Fund established in February 2010, which provided the capital to buy the Barnett shale assets of ConocoPhillips for $148 million in January 2010, and in April 2012, the Barnett shale assets of both WPX Energy Inc. for $306 million, and Carrizo Oil & Gas Inc. for $104 million.

Jonathan Smidt, senior leader of the energy team at KKR Natural Resources, says it’s almost like a private MLP.

“We don’t have a stated quarterly distribution, so we can be a bit more flexible in respect to how much we re-invest in the assets versus how much we pay out. We are buying the assets for the cash flow. Our investors like it because it gets them exposure to the commodity and it gets them current income or yield.” Technology as an equalizer

Ultimately, appearances may be deceiving on the perceived evolution of the MLP model into a more aggressive, higher-risk entity. In fact, the move by MLPs, or MLP-like entities, into the Barnett, Jonah-Pinedale and Granite Wash, may actually reflect technology improvements available to the industry as a whole, rather than a greater appetite for risk on the part of MLPs.

“All over the country, if you hold acreage in good places, sometimes the source rock below you turns out to be a shale that you are able to exploit,” says EnerVest’s Walker. “A prime example of that is the Utica.”

Beginning in 2003, EnerVest’s institutional partnerships entered Ohio to exploit the Clinton and Knox formations. The company added to its position through large acquisitions of Belden & Blake in 2005, some Exco Resources Inc. assets in 2009, and some Range Resources’ assets in 2010. EV Energy Partners, as an MLP, has an interest in the Exco and Range deals. The 2011 discovery of the underlying Utica shale altered the picture and EnerVest subsequently entered a JV with Chesapeake Energy Corp. to delineate and develop the nascent Utica.

But high-stakes shale-play exploration and development does not suit the MLP model. EnerVest Ltd., which deploys investment dollars from institutional investors in a three- to five-year program involving an acquire-exploit-sell strategy, and EV Energy Partners, its affiliated MLP, focused on predictable yield from legacy oil and gas properties, plan to divest Utica operated and non-operated interests as EV Energy Partners realigns its holdings to reflect the sweet spot for MLPs, which are built around a portfolio that is comprised of 80% to 90% proved developed properties (PDPs).

The divestment is one of four deals that EnerVest and EV Energy Partners are readying for market by year-end.

“Secondly,” Walker says, “when you marry two 60-year-old technologies—horizontal drilling with multistage hydraulic fracturing—you can do some things that you just couldn’t do before and that’s true within ultra-tight formations like shales, where you are dealing with nano spaces.

“But this is also true in places like the Permian, where you are really dealing with a conventional formation, you’re just using those same types of unconventional tools, or the Austin Chalk, where we have drilled into the least fractured part of the chalk and used those same techniques to get oil and gas molecules out of tight spaces in the chalk.”

The presence of MLPs in formerly higher-risk plays illustrates how technology has reduced risk and expanded the range of properties available to buyers, even within the framework of the steady yield, lower-risk MLP model. Using technology, larger MLPs are allocating capital to developmental efforts and essentially expanding their own portfolio of PDPs.

A growing pie

While the meek, in the form of MLPs, may inherit the earth (at least that portion of the earth that is 85% PDP), what about the opposite end of the spectrum? Will the majors expand their role in unconventional plays by consolidating the public independents? Not necessarily, says Jefferies’ Marko.

“I doubt the majors will roll those guys up. I think the food chain is pretty well positioned where XOM has its place, Shell has its place, and so do Anadarko and Apache—and Linn and EnerVest. That’s sort of the three parts of the lifecycle,” he says.

Marko questions whether the majors are going to roll up independents any time soon. “The key with all of these acquisitions is that once you buy it you have to run it,” he says. “I don’t think the majors can just start chewing up $2-billion, and $5-billion, and $10-billion companies, then effectively integrate them and manage them. The fields that those independents own really don’t suit what the majors are good at, which is big development, high technology, large capital spending—kind of all the things you need in the early stage of the shales.”

An alternative scenario argues that the energy pie will grow large enough in the future to accommodate an expanded role for the majors, the MLPs and public independents. Private equity will be one factor financing that growth by underwriting or recapitalizing experienced management teams, particularly in a world where resource plays demand such significant capital.

“As I see the future, there are certain projects and certain developments that are ideally suited for much larger companies because they have enormous capital needs or are more risky,” says Kenneth A. Hersh, chief executive officer of NGP Energy Capital Management, an Irving, Texas-based firm that has been providing private equity to oil and gas management teams since 1988.

“At the same time, there is a role for smaller companies that are able to put the time and attention into very mature assets that otherwise wouldn’t get that time and attention,” he says. “I don’t predict the future of any one segment of the industry because those dynamics cycle as well. The majors will be around in the future, absolutely; they have been around in the past. But there has always been a role for good, entrepreneurial quality management teams who know how to take assets and enhance the value, and I’ll hang my hat on that every day of the week.”

The buck starts here

The stellar run in upstream energy over the past decade has made it attractive for outside investors, particularly as alternative sectors fared indifferently in a challenging global economic environment. That upstream performance is attracting the mega-firm Wall Street generalists that bring a sizeable arsenal of capital to the E&P sector. Why upstream energy?

KKR’s Smidt outlines the thinking. “We are in a transformational period with the advent of the shales and the unconventional. This is a capital-intensive industry in the best of times. It’s an industry that monetizes a portion of its assets every single year as it produces out its reserves, so it has to reinvest to replace reserves and production. This constant need for reinvestment in the industry is interesting for financial investors.”

Smidt lists several upstream areas that have a voracious appetite for capital: large-scale leasing programs, drilling to define and capture a resource, and the need to build infrastructure to get the resource to market.

“Operators can’t fund this from internally generated cash flow for a couple of reasons,” Smidt says. “First, commodity prices have come down. Many operators positioned their portfolios, acquired acreage, and took on debt to develop gas resources, expecting gas prices to be higher. With gas prices having come down, a lot of operators have been shifting to the trend of the day, liquids. What that means is they already have a balance sheet that has been overextended. As they position themselves for liquids, they don’t have the capacity on their balance sheet to take on meaningful debt while the cash flow from their current assets has come down.”

This situation offers multiple opportunities for large-scale Wall Street firms, which can provide capital directly to operators, as KKR did with East Resources in the Marcellus shale in 2009 and Hilcorp Energy in the Eagle Ford shale in 2010.

“That’s straight private equity,” Smidt says. “We make an investment into the business alongside existing shareholders to provide them capital.”

In 2009, KKR invested $336 million in East Resources for a 35% stake in the firm, which held 650,000 net acres in the Marcellus. East sold a year later to Royal Dutch Shell for $4.7 billion. Then, KKR entered a JV on Hilcorp’s Eagle Ford assets for $320 million in June 2010 and invested alongside management to develop 141,000 net acres and acquire incremental acreage. Hilcorp sold its Eagle Ford acreage to Marathon for $3.5 billion in June 2011.

When the owners at East and Hilcorp each identified attractive opportunities to sell early in a rapidly evolving marketplace, KKR experienced unexpectedly rapid success. It netted $2.44 billion from $656 million in private-equity investment in two deals over two years.

“For East and Hilcorp, we were ahead of the curve,” Smidt says. “For better or worse, people pay a lot of attention to what we do. If we are able to do something successfully, you can be sure our competitors are focused on trying to replicate what we did. It’s more difficult to do today. Acreage values imply de-risking that is greater than has actually occurred in some of these plays, so it’s more difficult to do. But we’re coming back now to a period where a lot people have accumulated large acreage positions who don’t have the capital to develop them. I think we will see more opportunities to provide capital in the way we did for East and Hilcorp.”

A more recent example is the KKR-led consortium that bought Tulsa-based Samson Resources for $7.2 billion in November 2011.

“Samson historically had a very gas-rich portfolio,” Smidt says. “Eighty percent of its reserves and production were natural gas at the time we acquired the company. But Samson also has 1.3 million development acres in 15 different plays. If you look at the opportunity set, about 65% of that is liquids, or oil. In the case of Samson, we are thinking of this business as a long-term investment.

“The thesis is to take cash flows from existing reserves and production and reinvest that in the large acreage position they’ve assembled in some of the most attractive plays in North America, creating a more balanced portfolio between oil and gas, and hopefully take the company public.”

KKR also invests directly in existing PDP reserves via its Natural Resources Fund, an MLP-style vehicle. The process assists deal flow in the industry by generating options for sellers and opportunity for investors. For example, WPX Energy’s sale of non-core Barnett shale assets to KKR in April 2012 provided capital that WPX could redeploy on higher-return assets elsewhere.

“You’ve seen a lot of companies sell off conventional assets, or sell off more mature assets, which frees up management time and attention, and frees up capital,” Smidt says. “We use our Natural Resources Fund to do that. Those low-risk PDP properties can then be packaged into a yield vehicle that may provide a lower return than high-profile exploration, but the return is in line with lower risk.”

Smidt also identifies the ability to provide drilling capital as a third way the firm invests in upstream energy. “We provide drilling capital to companies that have opportunities to develop existing resources. We take a direct working interest ownership in those assets.”

KKR’s August 2012 investment in Comstock Resources’ Eagle Ford holdings is an example. It will carry a portion of Comstock’s well costs in the next 100 wells Comstock drills on 28,000 net acres in Atascosa, Frio, Karnes, LaSalle, McMullen and Wilson counties in South Texas. KKR has the right to participate for a one-third interest plus a drilling carry in wells drilled on Comstock’s acreage. Assuming KKR participates in the full development, the investment nets it a one-third stake in Comstock’s Eagle Ford holdings for roughly $233 million, or $25,000 per acre.

The private-equity cycle

Private equity is expanding its role in upstream energy. Even as large Wall Street firms are providing billions to recapitalize existing E&P firms under existing management, a cadre of private-equity firms specializing in energy constantly moves the industry forward by backing experienced management teams who serve as creative agents in applying new technology, or new geological understanding, to broaden the scope of oil and gas activity.

These savvy management teams demonstrate the viability of a play or concept in the field, then package the project for sale to larger public independents or majors, for full development.

After the sale, those management teams get restocked with fresh equity to start new endeavors in a cycle that runs from three to five years. It is estimated some 200 to 230 private E&P companies are now operating backed by private-equity firms.

NGP’s Hersh has spent 24 years witnessing this cycle. NGP closed its $3.58-billion NGP Natural Resources X LP fund in July 2012, bringing to $13 billion the amount raised since its inception.

“Given that we invented the business of doing equity-backstop of management-team platform companies back in 1988, I take some satisfaction that it has become an established way of growing companies now,” Hersh says.

“When we first started NGP, we did a lot of educating people who were employed by very, very large companies who didn’t understand that they could really be entrepreneurs. By creating the equity-backed start-up model, we were able to unlock the entrepreneurial instinct of this industry and now, 24 years later, there are dozens and dozens of companies that are doing this all over the country. The good news is there is between$2- and $3 trillion dollars worth of oil and gas assets in North America. There is plenty to go around.

“I view this as a very, very deep pool of opportunities and I’m really satisfied there is a deep pool of talent to go after it.”

The energy-focused private-equity world continues to evolve as resource plays occupy center stage. EnCap Investments LP partner E. Murphy Markham IV outlines how. Since 1988, Dallas-based EnCap has amassed more than $13 billion in investment capital for energy. Markham notes the private-equity model incorporates a variety of approaches to investment.

The Wall Street mega-firms earn a position in oil and gas by providing capital to existing companies through recapitalization. Energy specialty private-equity firms back experienced management teams through start-ups. Those start-ups nurture new plays, or expand existing concepts both inside a basin and across basins.

EnCap’s investment opportunities have evolved over the past decade. Previously, most investment-capital-backed management teams that acquired producing properties from the majors, used technology to exploit the assets and grow production, then sold the package to public independents.

“That’s changed to where 80% of our capital today is buying acreage in repeatable resource plays and drilling,” Markham says. “The risk/return is so much better than the acquire-and-exploit strategy. Our experience over the last four funds is that over 50% of the capital we are investing involves repeat management teams, which we think is the best investment opportunity out there.”

Those management teams are sometimes quick movers into a play following a discovery, or possess significant geological and engineering capabilities to identify areas where good rock exists, quickly lease acreage, and delineate and optimize a resource play. Once the play is established, they sell.

Resource plays

The advent of resource plays has impacted that buyer universe. Buyers used to be midcaps and public E&Ps looking for growth prospects. These days, the mix of buyers is much larger.

“The people who go through our data rooms today are the majors and international oil companies,” Markham says. “They don’t really want our management team. They just take the assets and field hands. So we’ll have an opportunity to re-back the management team. That team may go back to where they were successful, but a lot of times success has driven prices up. As a result they are going on to a new resource play.”

One additional change involves the size of typical upstream private-equity investment. A decade ago, EnCap was investing around $25-to $50 million per deal in acquire-and-exploit strategies. Today it invests $200- to $300 million to underwrite experienced management teams in a lease-and-drill strategy targeting resource plays, which require significant capital to develop.

These investments ultimately generate many of the deals that keep the domestic A&D market vibrant on an annual basis.

And that leads back to where the upstream A&D market sits in the final months of 2012. Trends converging on the deal-making scene include an expanding role for private equity and the majors, more JVs, and greater technological prowess for the MLPs—as well as across the whole upstream sector. These trends are aligning with stabilizing commodity prices. Expectations of change in tax policy at the national level will combine with these themes to generate a strong finish in the 2012 upstream transaction market.