ExxonMobil Corp., Chevron Corp., BP plc and super independent ConocoPhillips are expected to lead all other exploration and production (E&P) spenders in the United States this year, with capital expenditures (capex) on average about 5% higher than in 2012, according to a survey by Barclays Capital. Last year’s No. 2 spender, Chesapeake Energy Corp., dropped to No. 5 after cutting its exploration plans.
The majors, and big operators like ConocoPhillips (a former major) continue to have a “positive impact” on the U.S. E&P market, formerly dominated by independents.
Barclays last December published initial findings from its annual global E&P outlook after surveying more than 300 operators about spending intentions (see Shale Daily, Dec. 10, 2012). Over the past month, analyst James West and his colleagues revisited their forecasts to see if anything had changed and discovered that E&Ps are more optimistic than they were in December and even more positive about growth in the coming years.
North America is not getting the bulk of E&P spending by any means, but it’s seeing some “modest” growth, said West. Overall, global E&P spending is set to hit a record $678 billion in 2013, 10% higher than in 2012 and up more than 300 basis points from projections six months ago, with a lot of new spending directed to the Eastern Hemisphere. Overall, it’s good news for operators, he said during a conference call to discuss the findings.
“We believe the results of our spending outlook, especially the continued growth internationally and offshore, and rebounding activity in North America, support our constructive view on the group,” West said. “The industry remains in what we believe are the early days of a long and powerful global up-cycle, valuations remain at attractive levels, and fundamentals continue to improve.”
The “outlook for next year is starting to take hold, and we anticipate further substantial gains internationally, more oil-related activity and the start of a natgas cycle in North America. Only 6% of the companies we surveyed anticipate a decline in 2014 E&P spending.
“We expect spending in North America to increase roughly 2% in 2013, with positive growth in the U.S. somewhat offset by a year/year decline in Canada,” he said. U.S. E&P capex is forecast to increase 3.4% to $146 billion, versus year-ago spending of $141 billion. Canadian capex is predicted to decline slightly to C$42 billion from C$43 billion.
“Despite a slower start to the year than some expected, we think activity levels in the U.S. are improving and, given the conservative commodity price assumptions currently driving spending, we think North American E&Ps could be in position to outspend their budgets by the end of the year,” West said.
Spending patterns among the large and mid-sized independents, which make up the bulk of the U.S. market, are mixed because of the geographic disposition across various basins, said West. Company-specific initiatives appear to be driving current plans.
For instance, two of the largest independent spenders in the United States, Anadarko Petroleum Corp. and Apache Corp., plan to increase spending relative to last year, while another traditional power, Occidental Petroleum Corp., is forecast to decrease its allocation to U.S. operations.
Continental Resources Inc., the largest operator in the Bakken Shale, is planning to ramp up spending, with 10% more wells than a year ago. It also is targeting an increased presence in the Woodford Shale, said West. “Also of note, Antero Resources, the leading E&P in the Marcellus, has increased its 2013 drilling budget by over 60% compared to last year and plans to spend over $1 billion in Appalachia this year.”
Natural gas prices “have been particularly strong since the start of 2Q2013, averaging over $4.10,” West said. Barclays currently is forecasting $4.00/MMBtu gas prices for 3Q2013 and $4.10 for 4Q2013. “We think these levels are supportive of an uptick in activity in low-cost gas basins,” including the Marcellus, Cana Woodford, and portions of the Barnett and Utica shales.
A material increase in activity in major U.S. gas basins “would likely require sustained prices above the $5.00 level, an outcome we think is unlikely to materialize this year,” said West. An exception, he said, is Encana Corp., which has increased its rig count in the Haynesville Shale (see Shale Daily, Feb. 19).
“However, with gas prices expected to surpass E&P forecasts the remainder of the year, we expect a number of operators will direct excess cash flows from the gas plays to oil plays. We continue to be bullish on activity levels in the Bakken, Eagle Ford, Permian, Mississippian Lime and the Gulf of Mexico, where deepwater activity is surging.”
North American operators benchmarking capital budgets off West Texas Intermediate (WTI) have increased their 2013 price assumptions since the December survey, “but not materially,” said West. “Operators are currently budgeting for an average 2013 WTI price of $86.50/bbl, compared to a forecast average of $84.50/bbl in early December. Both levels are well below year-to-date actual prices for WTI, which have averaged roughly $94 since the start of the year.”
One worry is a concern that production may be beginning to plateau in the Bakken Shale, West said.
“The major independent forecasting agencies are calling for a significant increase in North American production, which would reduce the call on OPEC and has dampened increased expectations about oil prices. Much of this growth relies on the Bakken; if production growth in the Bakken is slowing or plateauing, there could be significant adjustments to the call on OPEC crude and, as a result, increased prices for oil.”
West said that since January 2008, Bakken output has grown from 36,150 b/d to nearly 718,791 b/d this year.
“Over the same time period, monthly production has decreased sequentially only seven times. However, sequential production has declined twice in the last six months. Average monthly sequential production increases have fallen to roughly 4,600 b/d in 2013 after reaching nearly 19,600 b/d in 2012 and 16,400 b/d in 2011.
“The rig count in the region has typically grown steadily with production over the past few years, but it had fallen significantly relative to production in recent months. While lower costs and improved drilling efficiencies have reduced the need for new rigs, the recent decline in overall production indicates a plateau that could require an influx of new rigs to regain production growth.”
However, some of the key operators in the Bakken are planning density pilot programs in several of the sweet spots, West said. If those are successful, they could “lead to several hundred new drilling locations and likely require a significant number of new rigs in the region.”
All of the positives for E&Ps lend support for an upswing in the U.S. land market and oilfield services in general.
“Following a severe curtailment of activity to end 2012, drilling operations in the U.S. land market got off to a relatively slow start in 1Q2013,” said West. “The monthly average for active rigs troughed in January and has risen slowly but steadily in the subsequent months. We expect the increases to continue, and also note that widespread drilling efficiencies being achieved by much of the active fleet are having a positive impact on the service companies, particularly the large caps.”
However, the positive effect of the faster cycle times for high-spec land rigs, touted by the service providers during 1Q2013 conference calls, “is obscured by a lack of timely completion data, and a continued reliance by many investors on rig count as a proxy for activity. but is evidenced, in our opinion, by the strong performance of the large cap service companies to start the year.
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