In Texas, oil and gas jobs are on a record-setting incline

At NAPE's 2011 summer conference in Houston, John Christmann, Apache's vice president for the Permian region, said, "If anyone's looking for work, we need people in Midland, Texas. It may be tricky finding a house, but we definitely need people. If I could get more folks in Midland it would help us take our rig count up."

However, it's not just the opportunities that have the industry gushing. The current oil and gas employment statistics are record-setting, and that means job prospects have turned into paychecks.

According to the Texas Petro Index (TPI), 224,200 people held exploration and production jobs in the state in June. The employment count eclipsed the October 2008 mark, which was the peak of Texas' last major oil and gas boom. In July, the news was even better as 6,200 Texans joined oil and gas payrolls, according to the TPI. The number of Texans working in upstream businesses now totals 230,400.

The TPI is a rating system that compiles information on indicators such as employment, commodity prices, production volumes and drilling data. A monthly overall score is calculated.

Tom Taylor, chairman of the board of the Texas Alliance of Energy Producers, the nation's largest state association of independent oil and gas producers, said July statistics show that 63% of active rigs in the state are directed at oil prospects. A steady increase in crude exploration, Taylor said, helped propel the TPI to 246.1 in July. By comparison, the TPI was 238.5 in April 2011; 186.6 in December 2009; and 285.4 in September and October 2008, when E&P activity in the state was at high tide.

"Clearly, the crude-driven expansion of the Texas petroleum economy continues, with the TPI for July improving a stout 17% over the July 2010 index," said petroleum economist Karr Ingham, who created the TPI and writes monthly reports. "But the industry already has eclipsed the employment record, and other activity indicators are nearing peak levels.

"As long as prices hold above $80 per barrel, it is unlikely that activity will slow appreciably. It's possible the industry's growth rate could slow down if well-site capabilities begin to reach their limits. Of course, all bets are off if crude oil prices begin to decline further," he added.

Among the leading TPI indicators for July are: crude production of 36.2 million barrels, a 2% increase compared with July 2010; a $3.37 billion value for Texas-produced crude, which is 30.7% more than a year ago; nearly 585.2 billion cubic feet of natural gas production, a year-over-year monthly decline of about 8.1%; and a Baker Hughes rig count of 858, which was 26.9% more than in July 2010 when 676 rigs were active.

Favorable news about oil and gas employment is not limited to Texas. According to data published earlier this year by Economic Modeling Specialists Inc. (EMSI), an organization that tracks labor market trends, regional economics and workforce development, the oil and gas industry dominated job growth in the U.S. from 2009 to 2011. The industry accounted for five of the nation's top 10 job categories, according to EMSI.

Oil and gas employment prospects could be become even brighter if the U.S. adopts policy changes that favor more production, according to a study released by the American Petroleum Institute (API) on Sept. 7. If such changes are adopted, the study suggests that more than 1.4 million new jobs, $800 billion in additional government revenue, and 10 million barrels worth of added daily production by 2030 could be generated. The study was commissioned to Scotland-based Wood Mackenzie Research and Consulting.

"Our industry has kept more than 9 million Americans employed through some of the toughest economic times in America's history, and we created thousands of jobs just last month," API president and CEO Jack Gerard said in a news release. "The study shows we could provide another 1.4 million jobs, with as many as 1 million created in just the next seven years and thousands of shovel-ready jobs available next year. It's time our national energy policy let America take advantage of this opportunity."

The suggested changes include opening non-park federal onshore and offshore areas to development where now prohibited; returning permitting in the Gulf of Mexico to historical levels; approving the Keystone XL and other pipelines; and establishing a regulatory environment that permits full development of the nation's oil and gas resources, including those locked in shale formations.

"The creation of these jobs is within the president's control," Gerard added."The policy changes involve actions he can take unilaterally. They do not require a super committee of Congress and they do not require new legislation," Gerard said.

— Mike Madere, online editor, Midstream Business

NACE: Serious pipeline incidents can create civil fines and criminal penalties

Pipeline companies that experience serious environmental or safety incidents can face both civil fines and criminal penalties, although most incidents do not result in criminal prosecutions, an attorney told a group of pipeline operators.

Chris Paul, an attorney with McAfee & Taft, spoke at the conclusion of the recently held National Association of Corrosion Engineers (NACE) conference, and warned that the notice of a fine does not rule out the possibility of a parallel criminal investigation.

"Whenever oil hits water, it could result in a criminal investigation. Most cases do not," he said. Federal prosecutors have a wide discretion in deciding which incidents to investigate but they generally only pursue the "most egregious cases" by careless operators.

"We are fortunate that most cases get pursued as a civil matter," he said. The decision to pursue a criminal case depends on a number of factors, including whether the organization has a stable record of following up on compliance requests, cooperating with federal and state authorities, maintaining an effective integrity management program and documenting all maintenance and correspondence.

Paul encouraged operators to maintain a rigorous integrity management system and to document all correspondence and replies with federal regulators. Even if pipeline operators avoid criminal prosecution following an incident, they continue to face the risk of civil suits from individuals or companies who claim to be affected by the incidents.

He clarified a number of myths about the defense against civil lawsuits—one of which is that plaintiffs' attorneys must prove intent of harm to win a lawsuit. As a result, pipeline operators cannot merely state they did not intend for the event to occur. "Intent as a defense is effectively dead," he said.

A second ineffective defense against civil lawsuits is the argument that senior management is not responsible for an incident because they were not at the company or in their current positions when key decisions were made. Paul called for managers to be proactive about risks in their system and to document the steps they take to keep the system safe.

Also, he encouraged pipeline operators to have well-established integrity-management systems in place, to document all safety steps taken and to show responses to all correspondence from federal regulators.

Aging infrastructure is an issue in public perception, and more so if an older asset causes an environmental or safety incident. "In the media's view, anything over 40 years old should be retired," he said.

Yet, Paul cited a preliminary study from the Pipeline and Hazardous Materials Safety Administration which concludes that aging infrastructure does not have to be a problem if an active safety and integrity management system is in place.

He encouraged senior managers to respond to all issues brought up in routine safety inspections and to document those responses. Failing to respond creates the impression that a company is negligent about safety.

Managers should be careful about how its employees write inspection and initial assessment reports, a practice which can haunt them if they get involved in litigation. Paul advised pipeline managers to train employees how to write accurate, succinct reports with all relevant facts.

He encouraged operators to be accurate and "stick to the facts" to avoid exaggerating the extent of damage or speculating about the cause of an accident in an initial assessment. "You should avoid statements like 'This was an accident waiting to happen'."

He advised inspectors to describe whatever actions were taken to abate the effects of a spill and to describe who was on the scene immediately after the incident. "What you find after an incident is that a lot of people start pointing fingers," he said.

The explosion of the natural gas distribution line in San Bruno, California, in September 2010, which killed eight people and damaged dozens of homes, caused pipeline operators across the country to upgrade their integrity management systems. "San Bruno has changed everything for everybody," he said.

— Keefe Borden, senior editor, Midstream Business

Wells Fargo: New 2012 forecast predicts propane-to-crude oil price ratio of 59%

Prices for natural gas liquids rose faster than crude prices this summer, according to a study from Wells Fargo's team of master limited partner (MLP) analysts.

The composite price for natural gas liquids (NGL) increased 3.2% in July to $1.46 per gallon from $1.41 per gallon in June. Crude oil prices (WTI) increased by a smaller degree (i.e., 0.9%) in July to $97.05 per barrel (bbl.) from $96.17 per bbl. in June. As a result, the NGL-to-crude ratio increased to 63% in July, up from 62% in June.

The processing margin increased 5.6% in July, to $1.08 per gallon from $1.02 per gallon in June, due to the combination of higher NGL prices and a 3% decrease in the price of natural gas. Wells Fargo's analysts see the propane market to be undersupplied by about 30,000 bbl. per day in 2011, but expect the market to be essentially in balance by 2012. For 2012, Wells Fargo expects total propane supply of 1.299 million bbl. per day, a 2.6% increase from 2011.

The expected increase in propane supply in 2012 is primarily due to higher anticipated propane production from natural gas processing, which is a direct result of the incremental fractionation capacity currently being constructed in Mont Belvieu, Texas.

On the demand side, Wells Fargo forecasts total propane consumption of 1.3 million bbl. per day in 2012, which represents a modest 0.8% increase over the 2011 level. The slight increase in estimated propane demand in 2012 is primarily due to higher forecasted export-related demand, which more than offsets the impact of lower assumed residential heating demand for propane.

"Net-net, we forecast the propane market to be relatively balanced from a supply and demand perspective in 2012. However, propane prices in 2012 could decline below 2011 levels (on a percentage of crude oil basis), as propane markets have been especially tight this year due to strong export activity. For 2012, we forecast a propane-to-crude oil price ratio of 59%, which compares with our 2011 estimate of 62%," Wells Fargo stated.

During the past heating season, propane distribution companies had to manage the impact of record propane prices, a sluggish economy that encouraged customer conservation, and weather that was warmer than normal in key regions, which reduced the number of gallons sold, according to the analysts. During that time, propane MLPs focused on improving profitability and strengthening their balance sheets.

Throughout most of fiscal year 2011, propane prices have mirrored crude oil prices, which have challenged margin expansion. Notwithstanding, margin per gallon remains firm (i.e., a fiscal year 2011 estimated average of $1per gallon versus $0.98 per gallon in fiscal year 2010). However, the affects of a lackluster economic environment, fewer acquisitions, and customer conservation (estimated at 2% to 3%) have resulted in a decline in volume for propane MLPs.

Meanwhile, Wells Fargo anticipates that U.S. residential demand for propane could decline by 4% in 2012. "Our forecast is predicated on the NOAA's preliminary degree day expectations for the 2012 winter heating season. Although weather in 2012 is estimated to be roughly unchanged from 2011 (on a calendar year basis), we anticipate that overall residential demand could decline by 4% due to the continued impact of conservation and fuel switching," they report.

For propane MLPs, the impact of weaker demand could be offset by incremental volume from acquisitions. On the margin side, Wells Fargo estimates a 2% improvement in fiscal year 2012. "Given our expectation that propane prices could head lower in 2012, residential and retail margins could improve," the report states.

— Frank Nieto, editor, Midstream Moniter

Deloitte: Energy deals and values down compared to first-half 2010

The quantity of mergers and acquisitions (M&A) deals during the first half of 2011 rose and subsided with the price of a barrel of oil. That's the conclusion that Deloitte Center for Energy Solutions came to when compiling their "Oil & Gas Mergers and Acquisitions Report" for midyear 2011.

With commodity prices falling, Deloitte & Touche LLP's M&A transaction services practice partner Jim Dillavou says the volatile economy also has been causing the drop in both the number of M&A deals and their values.

"We think most of the decline can be attributed to the up-and-down process of deal-making," says Dillavou. "It also probably reflects the movement of oil prices, which ran up to near record highs and have now receded. The high prices likely caused some people to pause and reassess transaction values, but now that prices have softened, deal activity may return to trend-line levels."

The total upstream deal count for the first half of 2011 was 149, down from 164 in the first six months of 2010. Upstream M&A deal values dropped from $80.5 billion during the first half of 2010 to $53.6 billion during the same period in 2011, a 33.4% drop. The fall-off in value was due to several large international assets and corporate deals that occurred in 2010, according to Deloitte.

Deal activity so far in 2011 has remained concentrated in North America. Deloitte Tax LLP partner Jason Spann says, "U.S. shale plays are still attracting lots of deal activity and interest."

Meanwhile, prolonged weakness in natural gas prices is a significant factor driving the domestic E&P transaction market. The depressed prices are causing difficulties for small and midsized producers, providing incentives to sell off their assets. This, in turn, creates opportunities for majors with deep pockets and long-term time horizons, reports Deloitte.

Spann says, "We continue to see lots of consolidation in the E&P segment, particularly in U.S. oil and gas. The major companies have been active buyers, making significant multi-billion-dollar investments in shale plays."

Also, Eagle Ford and Marcellus shale plays have been big drivers of M&A deals, Deloitte Consulting LLP principal Trevear Thomas says. The majors are taking advantage of the lower gas prices to buy up sound properties now to develop them when prices reach a more sustainable level.

The real area to keep an eye on is offshore U.S. Thomas says the regulatory situation in the Gulf of Mexico has improved and permits are being issued again, bringing back an upward trend in drilling.

"Deepwater is the next E&P frontier," says Thomas. "We will continue to see transaction activity in this area in the form of joint ventures and partnerships."

Dillavou says the recent increase in joint ventures is a reflection of current interest rates and the hard time many companies have finding an investor. "For someone who owns reserves, it's a cheap way to get financing," he says.

Not that professional capital providers have remained quiet. Private-equity players remain active buyers of unconventional resources, Deloitte reports. "Financial buyers are putting expansion and development dollars into both existing producing properties and undeveloped properties," says Spann.

Deloitte Financial Advisory Services LLP principal Jed Shreve adds, "While small independents may struggle in this environment of low gas prices, private-equity firms are active, doing smaller transactions, bundling assets and pulling management teams together to build attractive businesses position for growth."

— Stephen Payne, online editor, Oil and Gas Investor

Toreador merges with ZaZa Energy

Toreador Resources Corp., a publicly traded French energy company, and ZaZa Energy LLC, a privately-held U.S. company with holdings in South Texas, announced a corporate merger to form an upstream oil and gas company.

"We are creating a resource-focused E&P company," Toreador president and chief executive officer Craig McKenzie told attendees at Enercom Inc.'s annual Denver event, The Oil & Gas Conference. "We are bringing two pure plays together, without losing focus," he said.

The new company, which will be called ZaZa Energy Corp., will be public and will trade on the NASDAQ exchange under the ticker ZAZA. Combined, it will have 423,000 net acres in two of the world's leading resource plays. The deal is slated to close before the end of October, and the new entity's headquarters will be in Houston.

Interestingly, the two combining firms are involved in separate joint ventures with Hess Corp. ZaZa has a joint venture with Hess in the Eagle Ford, and Toreador has one with Hess in the Paris Basin. "The joint ventures provide a significant amount of capital carry and other financial provisions that are focused on exploration and development activity," said McKenzie. "So the coming years of funding are largely sourced out of the joint venture. It's a great synergy having this transaction include the two separate partnerships with Hess."

Toreador's assets include two producing concessions in the Paris Basin, which make some 880 barrels of oil per day and hold proved reserves of 5.5 million barrels. The independent has identified 15 conventional exploration prospects on its acreage that carry potential of 40 million barrels.

More significantly, Toreador also has 1 million gross acres, awarded and pending, in one of the world's most attractive resource plays, the Paris Basin Liassic shale. Toreador's partnership with Hess is focused on the Liassic play, but Hess can also participate in the conventional prospects if it chooses. The deal is valued at up to $265 million.

ZaZa, for its part, holds 123,000 gross acres in the Eagle Ford play. To date it has drilled 14 wells, six of which are producing. Its joint venture with Hess includes funds to make more than $500 million in acreage acquisitions and drill more than 200 wells. The value of the JV could be well over $1.5 billion, said McKenzie. Additionally, ZaZa has 70,000 net acres in the eastern expansion of the Eagle Ford, in a play it calls the Eaglebine. Active leasing is ongoing, and ZaZa expects to add significant leasehold there as well.

"These are impressive land positions in two very promising basins," said McKenzie. "The shared programs dovetail and provide stockholders with continuous drilling programs across multiple assets."

In the Eagle Ford play, the new company expects to be running as many as 12 rigs by the end of 2013, up from three at present. It also plans to have one rig running in the Eaglebine play by the end of first-quarter 2012. By the end of this year, it anticipates having 30 wells drilled, and it plans 100 in 2012 and 150 in 2013.

Activity in the Paris Basin's Liassic play has been slow to kick off, due to regulatory issues in France over shale development, but the company will start a six-well drilling program by the end of 2011. It will also have a rig at work on its conventional prospects by year-end, and it currently has a workover program under way.

"In the Paris Basin, we can shortly begin to drill vertical wells and horizontal wells, but obviously, none of our activity will involve fracturing," said McKenzie.

The merger is a cashless transaction. Toreador stockholders will own 25% of the new company, and ZaZa equity holders will own 75%. Toreador stockholders will receive 25.4 million shares in the new entity and ZaZa equity holders will receive 76.2 million shares and a $50-million promissory note that may be exchanged for cash.

"When we put the two together, it's a win-win," said McKenzie. "And that is where great deals and great companies come from."

— Peggy Williams, director of unconventional resources, Hart Energy

Deal strategy: Closing buyer-seller gap key to claiming value

Bridging the gap between buyer and seller and understanding market signals are keys to a good deal, industry executives said at Hart Energy's 10th Annual A&D Strategies and Opportunities conference in Dallas recently. They offered insight and analysis on various aspects of the oil and gas market from the deal level to commodity pricing.

Ken Olive, chairman and chief executive of The Oil and Gas Asset Clearinghouse, addressed the negotiation process, and how that divide between buyer and seller can be bridged.

"The fact that we have seen quite a number of transaction closings in the last seven months or so is indicative that the value gap is not that great at the present time." The valuation gap happens when expectations of price diverge from what is believed to be fair.

Current market conditions generally place a ceiling on value at two-times proved-developed-producing assets, unless the buyer sees the asset as a strategic fit for their company. Buyers should look at the fit of an asset to consider how they can enhance production or reduce cost, and not use what is reported in the data room.

"I've had people hang up when they were 10% away from a deal," said Olive. He has proposed to clients that an acquisition that is a poor fit is still a poor fit even at a 10% lower asking price. Knowing if the asset in question fits the company is more important.

Also, the market may have begun to embrace dry gas as a smart play, according to Sylvia Barnes, managing director and head of energy banking for Madison Williams and Co.

"In July 2008, the forward curve for Henry Hub was more than $13 per Mcf. In actuality, prices plunged to as low as $1.88 per Mcf. However, the drop in oil was sharper, after a steep incline, showing a large gap between expectation and reality," she said. "Ironically, August 29 we closed around $87 (per barrel), which is pretty much where we thought we would be back in 2008." She asked the audience to consider if gas was at a cyclical low, and if downside might be limited, and presented some interesting data points.

In the first half of 2008, gas was being valued slightly higher than oil on a barrel-of-oil-equivalent basis. The following year, oil began to be favored over gas, which grew more dramatic, such that in 2010, the difference was more than $6 per barrel of oil equivalent. That difference is $3.80 now, she said. Barnes asked what might be behind that, and suggested that because the majors have few attractive alternatives globally for production growth, they are logically driven onshore North America. She emphasized that four of the biggest recent transactions were gas deals.

"Petrohawk's reserves are 92% gas, although the headlines said, 'BHP buys oil company,'" Barnes pointed out, adding that "growth is the story," and there is no better place for that than North American gas. From February of this year to August, publicly traded oil companies that had performed well across 2010 have traded down, compared to gas-oriented companies.

Barnes said her firm has confidence there is room for growth-oriented gassy transactions. As she displayed the current forward curves she asked, "How wrong will the strip be this time?"

Many leases from 2008 are starting to expire, including acreage from major rounds in the Bakken and the Eagle Ford shales. Opportunities thus occur where leases are expiring, but where wells have not been permitted or drilled yet for the rest of this year and 2012, said Ramona Hovey, senior vice president of analysis and consulting with DrillingInfo Inc. She discussed rig count, lease expirations, and the implications for opportunity. Breaking down gas rig count versus gas price, most activity has been focused on holding acreage in the major plays, she concludes.

For example, Eagle Ford lease expirations are most concentrated in the oil and condensate windows. Expirations in the Haynesville are fairly scattered, but there is acreage expiring in core areas. Niobrara expiries are mostly in the D-J Basin area, and Permian Basin Wolfcamp lease expirations are also very scattered. Barnett shale expiring acreage is in core areas, but there has not been a rush to pick up the slack, Hovey said.

"Can we drill the acreage set to expire with the rigs we have?" she asked. The answer leads to opportunities, and depends on well spacing. More than a million acres will expire in the Bakken between now and 2012, but at 640-acre spacing, operators would need 89 weeks with 70 rigs in the play, (if averaging three weeks per well) to drill everything before leases expire.

"The reality is, we are seeing a lot of 1,280-acre units there," said Hovey, which means less opportunity.

The Eagle Ford has in excess of a million acres expiring soon, with 200 rigs in the play. At 640-acre spacing--typical in the gas areas--it would be no problem to drill in 32 weeks. At denser spacing like 160 acres, as is found in the condensate or oily areas, it would take 127 weeks. That is a lot less doable, and could mean opportunity for companies that control rigs to partner with those that have acreage, she says.

"The other component that always has to be addressed is who has the rigs," Hovey said. Big players have leases expiring and perhaps too few rigs available. EOG Resources Corp., for instance, has 145,000 acres set to expire between now and 2012, yet has only 20 rigs, which could create a challenge.

— Brian K. Tully, senior editor, Oil and Gas Investor

Risky business: Buying and selling natural gas according to Dr. Jim Duncan

At the recently held 23rd annual Midcontinent LDC gas forum in Chicago, Illinois, at the Chicago Marriott Downtown Magnificent Mile hotel, talk of natural gas became heated, as analysts urged fellow colleagues to be aware of shifting and fluctuating energy markets and manage risks accordingly.

Dr. Jim Duncan, director of market research at ConocoPhillips Co., stressed especially how global drivers are impacting a hitherto quiet market, and that managing the risk of market drivers has become more critical in a volatile marketplace.

Demand, according to Duncan, is brisk and keeping price temporarily stable, while long-term technical signals suggest that the price of natural gas may even receive a bounce in price. Thanks to recent record-setting cold and hot weather patterns in the U.S., natural gas has enjoyed an unforeseen uplift.

Meanwhile, long-term growth in natural gas demand, should be robust due to abundance, affordability and environmental benefits, according to Duncan. Supply of natural gas has come in overwhelming amounts from onshore shale plays, and has granted natural gas a low price in the current market.

In fact, in 2010, thanks to onshore production of the shale plays, the U.S. managed an upset by placing first in overall global natural gas production, leaving second-place for Russia. Thanks to the abundance, Duncan believes that this will allow a sustained period where U.S. gas prices are disconnected from the rest of the world.

Some new sources of demand for natural gas will include liquefied natural gas (LNG) exports (650 to 1,000 MMcf per day), LNG trucks (0.002 MMcf per day), CNG fleet vehicles (0.0005 Bcf per year) and ethylene plants (60 MMcf per day).

Power plants choosing to switch from coal-fueled to gas-fueled power generation will also provide a healthy source of demand. However, Duncan cautioned that the health of the demand scenarios will depend heavily upon the concerted effort to inform and educate consumers about the benefits of natural gas.

Public policy can and has been affected by misinformation and mistrust of the general public, he says, and warns that managing risk has become more important than ever, as unforeseen drivers will have the ability to dramatically change the state of the market.

He stresses that managing the risk of buying and selling natural gas requires a healthy respect and knowledge of the agents of change in the marketplace, which include the rush for NGLs and the switch to NGL drilling, South American and other global development of shale plays and the drive for new policy. These risks require better and more efficient risk-management strategies for those in the buying and marketing business.

—Meredith Freeman, associate editor, Midstream Business