PwC: M&A volume slips in first quarter after year-end surge

The number of mergers and acquisitions in the North American oil and gas industry declined in the first quarter of 2013 compared with fourth-quarter 2012, according to a report from PwC US Private equity moved to the sidelines, but foreign buyers and strategic investors took up some of the slack. Both deal volume and deal value increased when compared with first-quarter 2012.

For the three-month period ending March 31, there were 39 oil and gas deals with values greater than $50 million, accounting for $27 billion in deal value, an increase from the 34 deals worth $25.7 billion in the year-ago period. On a sequential basis, however, deal volume in the first quarter dropped 48% from the 75 deals recorded in fourth-quarter 2012, with total deal value in the first three months of the year declining 52%, from $56.2 billion.

“With the acceleration of deal activity in the final three months of 2012 due to the looming fiscal cliff, in addition to the seasonal slowdown of deal-making during the first quarter, we had anticipated this drop-off in M&A activity,” says Rick Roberge, principal in PwC's energy deals practice.

“Foreign buyers, though, are still looking for opportunities to expand in US shale plays and are extremely active in upstream prospects—and they're willing to acquire those assets at a premium. At the same time, while private-equity activity in the oil and gas industry recently hit an all-time high, the increase in asset valuations has caused them to move to the sidelines so far this year. However, we expect private-equity involvement to pick up,” he says.

Foreign buyers announced nine deals in the first quarter that contributed $4.1 billion or 15% of total deal value, versus six deals valued at $5.9 billion during the same period in 2012. On a sequential basis, the number of total deals remained the same as total deal value increased 28.1%.

Private-equity activity ebbed. There were only two private-equity transactions with values greater than $50 million, representing a total deal value of $576 million, compared with seven financial sponsor-backed deals worth $13 billion in first-quarter 2012.

There were 34 strategic deals that contributed $26.4 billion and made up 98% of total deal value in the first three months of 2013.

The 35 asset transactions represented 90% of total deal volume and contributed $17.2 billion—a 30% increase in deal volume from the 27 asset transactions during first-quarter 2012, but a slight decline from the $18.2 billion in total deal value during the year-ago period. There were four corporate transactions totaling $9.8 billion, a dip from the seven corporate deals during first-quarter 2012, although deal value increased from $7.4 billion.

For deals valued at more than $50 million, upstream deals accounted for 23 transactions, representing $12.6 billion or 47% of total first-quarter value. The number of oil deals within the upstream sector was 11, compared with five in upstream gas. Midstream transactions rose sharply, with 11 deals contributing $10 billion, a 120% jump from the five during first-quarter 2012, which totaled $3.2 billion. Three downstream deals during the first quarter added $3.9 billion, while oilfield services contributed two deals worth $465 million.

Shale plays retained their dominant role, with 18 deals with values greater than $50 million related to shale plays in the first quarter of 2013 totaling $16.3 billion, or 60% of total deal value. In the upstream sector, shale deals represented 11 transactions and accounted for $5 billion, or 40% of total upstream deal value.

Included in the shale-related deals were three transactions involving the Marcellus shale, totaling $882 million, and two Utica shale deals that contributed $283 million, versus one Utica transaction, for $112 million, in first-quarter 2012. Compared with the first quarter of 2012, Marcellus deal volume was flat, although total deal value decreased from $3 billion.

“The main story in the first quarter of the year continues to be about shale. We're seeing interest in both the Marcellus and Utica, and we don't expect to see that enthusiasm dissipate anytime soon,” says Steve Haffner, a Pittsburgh-based partner with PwC's energy practice.

“While that interest hasn't translated to a dramatic increase in the volume and value of shale deals in the region, potential buyers are seeking the right opportunities to establish their footprint in the area—or to expand—and that includes both private equity and foreign buyers.”

The most active shale plays for M&A with values greater than $50 million during the first quarter included the Eagle Ford in Texas, with five total transactions representing $5.1 billion, followed by the Marcellus shale, the Utica shale, and the Bakken in North Dakota; the latter posted one deal for $513 million.

“The first quarter saw a divergence in buyer-seller price expectations around gas assets, as natural gas prices bumped up from recent historical low levels,” says Roberge.

“These higher valuations for

gas assets, combined with continued high valuations in the sweet spots of the liquids-rich shale plays, were a major contributor to private-equity firms largely sitting out this quarter, but it's critically important for private equities and strategics alike to be ready when opportunity surfaces and prices are more favorable, as buyers will be lining up. Making sure they have the right strategies, integration plans and controls in place will make for a better prepared buyer that maximizes the chances for success.”

PwC notes that during the first quarter master limited partnerships (MLPs) were involved in eight transactions, representing more than 20% of total deal activity and continuing the trend of MLP involvement.

PwC's Oil & Gas M&A analysis is a quarterly report of announced US transactions with values greater than $50 million, analyzed by PwC using transaction data from IHS Herold.

—Keefe Borden

For more A&D analysis and data see A-Dcenter.com.

Unconventional petroleum reservoirs call for new approaches

Exploring, appraising and developing unconventional petro leum reservoirs requires a new approach to petroleum geology, said Dick Stoneburner, retired president, North America Shale Production Division, BHP Billiton Petroleum, speaking at Hart Energy's 2013 DUG Permian conference in Fort Worth, Texas.

Stoneburner was previously president and chief operating officer, Petrohawk Energy Corp., and he currently serves as senior advisor for Pine Brook Partners and director for Newfield Exploration Co.

The industry has made remarkable strides in establishing commercial production from many different shale reservoirs in a short period of time, and these learnings have largely come “on the job,” he said. Now comes the task of codifying them and passing them on to the industry at large.

Exploration for unconventional reservoirs is quite different from exploration for conventional accumulations. When prospect generators work with conventional reservoirs, they are generally looking at small, tightly controlled and highly targeted prospects. Stratigraphic support focuses on the facies analysis local to the prospect, and reservoir quality assessment is confined to the prospect area.

Conversely, unconventional prospects require a broad focus: Stratigraphic support focuses on analysis of entire basins, and reservoir quality assessment reaches across broad areas.

The discovery of the Eagle Ford play offers a case study in prospect development. In early 2008, the chief executive officer of Petrohawk Energy charged the company's exploration team with finding another “Haynesville-like play.”

The team became interested in the Eagle Ford shale, a significant regional source rock in the Gulf Coast Basin. The reservoir quality and geochemical attributes of the objective were poorly understood, and the potential trend sprawled across some 10 million acres.

The first conundrum was where to concentrate efforts in this vast area. The Petrohawk explorers initially mapped the Eagle Ford across the entire basin and identified an anomalously thick, porous and highly resistive Eagle Ford section in LaSalle and McMullen counties, Texas. Well control was limited, but the area appeared to be a mini-basin developed between two divergent shelf margins.

There was also seismic support for the prospect—the anomalously thick areas could be identified on 2-D seismic data. The company acquired a grid of 2-D data that allowed it to map the extent of the thickened Eagle Ford section.

While the geochemical properties were unknown, the depth range of 10,000 to 11,500 feet in the selected area suggested relatively mature source rock. A key well on the prospect was drilled in the early 1990s, most likely for the Olmos. The Eagle Ford interval had tested a small amount of gas after a light acid treatment.

The well logs showed more than 250 feet of Eagle Ford shale with greater than 9% density porosity, with the majority greater than 15%. The net-gross ratio was 100%. Resistivities were excellent, and the gamma ray character indicated the lithology was coarse-grained mudstone. The team acquired Eagle Ford cuttings from this well and analyzed such parameters as total organic carbon (TOC) and vitrinite reflectance (Ro).

The prospect's geochemical properties compared favorably to known producing shale plays. The ranges for TOC, Ro, Tmax, transformation ratio and dryness all fell within ranges that the industry had identified as positive for shale reservoirs.

With these encouraging results, the company believed it had found a shale prospect with world-class reservoir potential. Petrohawk acquired 160,000 acres and spudded the initial test. By the fourth quarter of 2008, the discovery well was completed for 7.6 million cubic feet of gas and 251 barrels of condensate per day.

“We were certainly not the only ones working out there at that time, but we happened to come forth with the first commercial discovery,” said Stoneburner. That discovery launched Hawk - ville Field, and the massive Eagle Ford play was off and running.

Once the discovery had been made and confirmed by a second well, Petrohawk moved into appraisal and development modes.

“There is nothing more critical to the evaluation of a shale resource than the extensive data gathered from whole core analysis,” said Stoneburner. “It all starts with core data.”

Whole-core analysis became the cornerstone of the company's subsequent efforts. It allowed measurement of conventional reservoir attributes such as porosity, water saturation and permeability, and also identification and quantitative measurement of mineralogy.

Of particular interest in shale reservoirs is the prevalence of clay minerals versus coarse-grained constituents.

Additionally, geochemical and geomechanical attributes such as Poisson's Ratio and Young's Modulus were measured. “These latter attributes are rarely worried about in conventional reservoirs,

but are critical in unconventional plays,” said Stoneburner.

“But most importantly, whole core analysis allows you to calibrate core measurements to conventional open-hole log suites.” This greatly expands a company's knowledge for reservoir characterization, formation evaluation and completion designs. The company constructed algorithms that compared whole core data to log data, and the expanded data set was enormously useful. “You really need the detailed information,” he said.

Today, the Eagle Ford has grown into one of the premier resource plays of the world. According to the Texas Railroad Commission, permits for new drilling totaled 4,145 in 2012, a 46% increase over 2011, and production reached an average of 922,000 barrels of oil equivalent (BOE) per day in 2012. Hart Energy Research estimates that Eagle Ford production will surpass 2.5 million BOE per day in the next five years.

Nonetheless, resource plays are still in their infancy and much remains obscure about these reservoirs. Knowledge is advancing from trial-and-error experimentation and guiding principles are being developed both in the field and in the lab. “We need to continue to learn from our experiences and move forward,” said Stoneburner. “We need to collaborate as an industry and collaborate as a team.”

Surely, there are more Eagle Ford-like plays remaining to be discovered around the globe. Oil and gas explorers, armed with new thinking and new techniques, and building on the experiences of those who have gone before, are busily looking.

—Peggy Williams

See UGcenter.com for more news and analysis of unconventional resources.

Fracing support slips, four out of 10 oppose natural gas exports

As the natural gas industry invests billions of dollars for planned export facilities, a University of Texas Energy Poll shows many Americans oppose shipping such resources to other countries.

A March poll by UT at Austin found 39% of respondents think natural gas should stay at home, while 28% support exports.

Hydraulic fracturing also remains a contentious matter, with opinion sharply divided.

The degree to which respondents understand the decades-old technology drives opinion on natural gas exports. The survey found that 37% of participants familiar with hydraulic fracturing were likely to support natural gas exports compared with 20% who are not.

A large percentage of people think domestic natural gas production creates jobs, provides energy security and boosts manufacturing. Those polled ranked natural gas costs least high, followed by electricity, heating oil and gasoline.

The poll also found that hydraulic fracturing support is slipping. About 45% of respondents familiar with hydraulic fracturing support using it for fossil fuel extraction, down from 48% a year ago. The practice is opposed by 41%.

A stark political divide is evident: 22% of Democrats support fracing and 60% oppose it, while 71% of Republicans support fracing and 20% oppose it.

Consumers worry about possible harm to the environment from the use of hydraulic fracturing, with the potential for water contamination topping the list of specific concerns.

“More consumers—43% today versus 38% a year ago—say there should be more regulation of hydraulic fracturing,” said Sheril Kirshenbaum, director of the UT Energy Poll. “Still, we also see steady support for the expansion of domestic natural gas development.”

Other findings cited include:

Trust: The scientific community is perceived to be the most accurate, impartial information on hydraulic fracturing.

Land: The poll found 41% back fracing on public lands and 36% oppose.

Climate: Nearly three quarters of Americans say climate change is occurring, which is consistent with a September 2012 poll.

—Darren Barbee

ConocoPhillips latest to ice plans to drill in Arctic—for now

Quests to tap into potentially lucrative hydrocarbon reservoirs in the Arctic have slowed as companies suspend drilling plans amid ongoing environmental, regulatory and safety concerns.

ConocoPhillips became the latest company to put off plans, postponing its 2014 Alaska Chukchi Sea exploration program. The move, following similar decisions by Shell and Statoil, was made because of “uncertainties of evolving federal regulatory requirements and operational permitting standards,” Conoco Phillips said in a news release announcing the suspension of activity.

The company has 98 lease blocks spanning about 558,000 acres in the Chukchi Sea. It had planned to begin exploration drilling in 2014.

The April 10 announcement came just more than a month after the US Department of Interior (DOI) issued a report on Shell's 2012 offshore oil and gas exploration program, which was rife with problems. The Kulluk drilling rig chartered by Shell ran aground the southeast Alaskan coast after separating from its towing vessels. Other setbacks included a damaged containment dome for the containment barge needed to gain certification for permits and air emissions permits violations

Shell addressed its Arctic operations in its 2012 sustainability report released April 11. Apologizing for the Kulluk drill-ship running aground and admitting the year's events fell short of goals, Marvin Odum—upstream Americas director for Shell—said the company can manage the risks of operating in Arctic waters.

“We must not forget that the industry has been conducting safe operations in the Arctic for decades—proof that the industry can manage the risks,” Odum said. “Effective risk management is about improving safety by analyzing what could go wrong, minimizing the possibility of it occurring, and reducing the potential consequences. At Shell we have embedded this approach within our management system, and work continuously to enhance safety.

Safe well operations demand highly competent people, strict safety procedures, and rigorous design, construction and maintenance standards for all equipment.”

The company will use the lessons learned in 2012 to improve future operations, Odum said. Plans for the Arctic are being reviewed as Shell works with the US Coast Guard and the DOI.

The DOI said Shell entered the drilling season not fully prepared. Although the report mentioned areas in which Shell succeeded—drilling tophole sections for two wells, implementing weather forecasting and ice management systems that enabled quick response to changing sea ice conditions, and coordinating well with Alaskan communities—the mishaps indicated serious deficiencies.

The federal government has identified principles and prerequisites for safe offshore drilling in the Alaskan Arctic. These include mandates for operators to understand and plan for Alaskan conditions, maintain management and oversight of contractors, and establish plans with clear objectives in advance of the drilling season. The DOI also has encouraged the industry to work with the government to create an Arctic-specific model for offshore exploration, including drilling and maritime safety as well as emergency response equipment and systems.

“We welcome the opportunity to work with the federal government and other leaseholders to further define and clarify the requirements for drilling offshore Alaska,” Trond-Erik Johansen, president, ConocoPhillips Alaska, said in a prepared statement. “Once those requirements are understood, we will reevaluate our Chukchi Sea drilling plans. We believe this is a reasonable and responsible approach given the

huge investments required to operate offshore in the Arctic.”

The Alaskan Arctic region holds the largest amount of undiscovered Arctic oil deposits, about 30 billion barrels, according to estimates from the US Energy Information Administration.

The US Geological Survey estimates about 90 billion barrels of oil, 1,669 trillion cubic feet of natural gas, and 44 billion barrels of natural gas liquids (NGLs) may remain undiscovered in the Arctic. The figures represent about 22% of the world's undiscovered conventional oil and natural gas resource base; about 30% of its undiscovered natural gas resources; about 13% of the undiscovered oil resources; and 20% of the world's NGL resources. Most of the natural gas and NGLs are located among the Eurasian continents' part of the Arctic, while the North American territory is believed to have more oil.

Given the region's fragile environment in addition to increased scrutiny post-Macondo, companies with Arctic exploration plans are being watched closely. Companies are forming partnerships to study the Arctic and its challenges in hopes of finding solutions and gaining expertise. Statoil and DNV, for example, created the Arctic Competence Escalator program in March 2013 to do just that.

“The stakes are high in the Arctic,” the DOI said in its report. “The oil and gas resources in the Alaskan Arctic are potentially world class, and exploring for them requires years of planning and enormous up-front capital expenditures.

“The risks are substantial and unique as well. As Shell's experience last year makes clear, the waters off Alaska present myriad challenges and dangers during every phase of an offshore operation. A significant accident or spill in the remote and inhospitable Alaskan Arctic could have catastrophic consequences on fragile ecosystems and the people who depend on the ocean for subsistence.”

—Velda Addison

Halcón: Returns on newly producing Eagle Ford wells 'awesome'

A backdrop of plunging commodity prices meant few speakers were spared seeing their stocks tumble as they participated in Day 1 of the OGIS New York meeting of the Independent Petroleum Association of America (IPAA) held in New York in mid-April. The tragic deaths and injuries of those felled in the Boston Marathon bombing added another level of pain.

Halcón Resources Corp.'s chief executive officer, Floyd Wilson, unveiled a new play to a standing-room-only breakout session at OGIS, only to see the company's stock retreat 15.9% by day's end. Color he provided on the new play, called El Halcón, included “a few wells” achieving 30-day initial production (IP) rates of nearly 800 barrels per day, as well as some that had lesser IP's. The company's press release gave an average 30-day IP of 694 barrels per day for the seven wells producing in the play.

Wilson described the returns anticipated for the new East Texas Eagle Ford play as “awesome.” The estimated ultimate recovery (EUR) per well was 350,000 to 400,000 barrels of oil equivalent (BOE), with costs projected to come down to under $7 million (versus an estimated $7- to $8 million in the release). Average spud to total depth for the wells was 17 days, with one well down in 13 days. Wilson indicated that Halcón would this year drill more than the 15 to 20 wells stated in the release.

While upbeat about all of the company's four major plays (El Halcón, the Woodbine, the Utica/Point Pleasant and the Bakken/Three Forks), Wilson held out the possibility of trimming one if another play's risk/reward ended up being dramatically better.

Wilson anticipated the best returns would come from the Utica, but said the play carried more risk.

Halcón's completion methodology in the Utica was in line with Gulfport Energy's and included a 60-day resting period. Early indications were positive and—with eight wells either in flowback, resting, completion or drilling—Halcón expected to have a well coming on production every two to three weeks.

In the Tuscaloosa Marine shale, Halcón had “great shows” during drilling and completion phases, but suffered a casing collapse while drilling out the plugs. Halcón will probably re-drill the well at nearby locations, Wilson said.

—Chris Sheehan

Advice for producers: Know liability risks, especially for fracs

Insurance rates are bound to rise, and with the expansion of hydraulic-fracturing equipment on location, the liability risks for most producers have risen as well. In many cases, the frac provider or other oilfield service provider has shifted the risk onto the producer. But there are things producers can do to mitigate these risks.

“You need to understand your risk and explain to your insurance broker the loss prevention things you and your contractor are doing. Maybe have one of your engineers accompany you when you meet with your broker.”

Sound advice from one who knows: Richard M. Blades, vice chairman of John L. Wortham & Son LP, one of the 10 largest privately owned insurance brokers in the US Wortham has been based in Houston for 98 years.

Speaking to the Houston Energy Finance Group recently about trends in oil and gas industry insurance, Blades advised producers to carefully review their policies with regard to liability during frac jobs.

“You're going to have multiple wells drilled on these pads, so having a blowout would obviously be worse. The authorization for expenditure (AFE) on these wells is higher than for a vertical well, so look at your limits. When you frac, you have a lot more equipment out there on location. We are selling more of this type of coverage.”

At present, underwriters are trying to raise insurance rates because they are not getting enough return on their investments, due to low interest rates. What's more, five of the top 14 most expensive catastrophic losses occurred in the past three years. In 2012, catastrophic losses were above average. Hurricane Sandy alone was a loss of an estimated $33 billion, Blades said, and the severe nationwide drought was another $25 billion.

“Insurance is just like any other market in that it is cyclical. Capital comes into the market and rates get soft … then something happens [such as Hurricane Sandy] and the market contracts and rates start going up.”

For 2013, Blades predicts that offshore insurance rates are going down slightly (perhaps by 10%).

However, onshore operators' extra expense (commonly called blowout insurance) rates are going to be flat. All other forms of insurance are going up: excess liability, onshore property, and directors and officers (D&O) insurance.

One thing that has frustrated insurers and operators is that it is taking longer than before to write policies for midstream and downstream clients. The reason is rapid growth. There is a lot of construction going on in these two segments today, and replacement values are higher.

—Leslie Haines

Yergin: North American LNG exports raise hopes, what-ifs

In January 1959, a converted World War II liberty freighter named The Methane Pioneer set sail from a Louisiana port to the United Kingdom loaded with liquefied natural gas (LNG).

Choked by killer fogs from the burning of coal, Britain hoped that “one way to deal with it was to import natural gas,” said Daniel Yergin, a Pulitzer-prize winning author who serves on the US Secretary of Energy Advisory Board.

“That was the beginning of the trade of LNG,” Yergin said at LNG 17. Decades later, the US seemed destined to be the recipient of LNG, as natural gas production declined.

Today is a different story. “Things have turned around,” Yergin said. The US and Canada are expected to be players in the LNG market and, perhaps, to dominate it.

But LNG exports are a puzzle with each piece in motion. In the coming years, the US will export billions of cubic feet of natural gas, and LNG prices will rise and stabilize at up to three times their price while hampered by the escalating costs of skilled labor.

Today, “everyone has the expectation that the US will play an important role as an LNG exporter,” Yergin said. “Of course the debate is how big of a role and how soon that will occur, and how much.”

Yergin, vice chairman of IHS, said he's struck by how often the unexpected has hit the energy industry.

What would happen if North American exports turn out to be much larger than projected? “That would change the balance in price formation and ... create question marks for other projects in other parts of the world.”

And what if gas export results in an excess surplus? Or if so much LNG comes into the market and traditional pricing relationships break down? Yergin said the US should set a new competitive price benchmark for gas around the world for perhaps $12 per million British thermal units (MMBtu). US LNG exports to Japan averaged $14.44 in 2012, according to the Energy Information Administration.

“Obviously that doesn't mean everyone by any means will adopt that pricing system,” he said. “But it will be possible in some cases to deliver gas from the US to almost any global coastal port.”

Yergin said there are about 30 applications to build facilities. Only a fraction will be built, he said. Such facilities are painfully expensive to build—$10 billion or more.

In January, 20 US firms had submitted applications for US LNG exports. Of those, 16 were approved for countries with free trade agreements (FTA) with the US, such as Canada, Mexico, Chile and South Korea.

For the overall natural gas market, “we are optimistic. We expect global natural gas demand to double by 2040 from where it is today,” Yergin said.

“For those that think in oil terms, that would be equivalent to 100 million barrels a day of oil equivalent, which is larger than today's world oil market,” he said.

Natural gas is already encroaching on coal's territory. Five years ago, natural gas was about 21% of power generation; today it's more than 30%.

By the 2030s, fuel sources will be in a horse race with natural gas, coal and oil neck and neck, making up 75% of total energy mix, Yergin said. North American exports could be 8 billion cubic feet per day by 2030.

“We would expect in 2040, maybe a little before that, natural gas will edge out ahead of oil and coal and become the world's dominant fuel,” Yergin said.

—Darren Barbee

Topeka: San Juan play could best Wattenberg Field

The emerging Gallop (Niobrara)/Mancos play in the San Juan Basin is already showing its teeth, according to a recent report by Topeka Capital Markets.

The report focuses on Encana Corp., which recently announced its last five Gallup (Niobrara)/ Mancos wells in the San Juan Basin have had initial 30-day rates of 150 to 700 barrels of oil equivalent (BOE) per day, 80% of which is oil.

“More importantly, these well costs came in at $5- to $6 million, presenting viable economics for the play,” say the report's authors. They note Encana is currently running two rigs and may add another by the end of the year.Further, Encana is targeting estimated ultimate recovery on a 5,000-foot lateral well of 550,000 barrels of oil equivalent, for costs of $4- to $5 million per well.

“Based on our estimates of the company's targets, in a long-term $90-per-barrel WTI crude oil and $4.50-per-MMBtu natural gas environment, the play could generate economics north of 75% internal rates of return, greater than the core Wattenberg Niobrara,” the report notes.

The capital market provider adds that the Encana announcement is an incremental positive for Energen Corp., which has more than 80,000 net acres in the oil phase in the San Juan Basin.

Additionally, Energen has 58,500 net acres that are in the dry-gas window of the play and have been de-risked by early wells from WPX Energy Inc. and Black Hills Corp.

—Caroline Evans

ERRATA

In the May issue, a photo on p.87 was incorrectly labeled as Juan Espinosa, chief executive officer of Futura Royalties. The photo should have been identified as Lee Caple, president of Caple Royalty Services. We regret the error.