North American natural gas prices will limp into 2010 but end the year "strong" because of supply declines, but "quantifying the magnitude of the domestic supply decline is becoming more opaque," EOG Resources Inc. CEO Mark Papa said Friday.
As he is known to do during quarterly conference calls, Papa gave financial analysts his view of the macro gas markets in North America. He admitted that trying to get a handle on how much drilling across the continent is under way and how much is planned for 2010 is difficult to ascertain.
The Energy Information Administration (EIA), Papa noted, "recently revised downward their estimate of 2008 gross production by about a half a Bcf a day but did not adjust their 2009 data." Given these revisions, he said EOG's supply model can match the EIA 2008 volumes, but not the 2009 numbers.
"I really come down to the point that drilling has slowed dramatically, and we believe that production will fall. And if you look at the Canadian production situation, the Canadian production kind of levitated for six months, maybe nine months longer, and stayed at relatively stable levels before it started to fall.
"In other words, there was a longer lag time between when the drilling really slowed down and when production slowed down," said Papa. "And that may well be just due to unconnected wells. What we believe is...that there was a backlog of unconnected wells and that we've probably worked our way through that. I know at EOG we have pretty well worked our way through that..."
The number of onshore gas wells awaiting completion "is a big conundrum," said the CEO. "The other ancillary part to that is, if you add up all the public companies as to what they are alleging they are doing to grow gas volumes in the U.S. next year, it is a bigger number than is consistent with the production declines that we would project."
EOG doesn't have the numbers on other companies' backlogs, said the CEO. "We know our backlog is really relatively modest in terms of wells uncompleted, and our belief is that it will probably be about three or four months from now when you get EIA data that has not got a lot of noise in it.
"But we believe it is just inevitable that production is going to decline in 2010 and [we] believe it will be in the range of about 4 Bcf/d for the full year. But we have to say that we have some questions as to when...We can't pound the table and say it is going to be exactly 4 [Bcf/d] because there is a lot of opaqueness out there right now."
Assuming a year-end 2009 gas rig count of 740, EOG's macro view of the gas markets is that production will be down 3.2 Bcf/d by December and 5 Bcf/d by June 2010 relative to December 2008.
Combining the estimated 0.8 Bcf/d year/year decline that is occurring in Canada, offset by a 1-2 Bcf/d increase in 2010 liquefied natural gas imports, "we expect the gas market to tighten by mid-2010," Papa said. "We are already seeing evidence of this tightening. Storage injections since mid-June have been running about 2 Bcf/d less than last year and half a Bcf a day less than the five-year average."
EOG has 44% of its 4Q2009 North American natural gas hedged at $9.43/Mcf "and then we are likely hedged for the first half of 2010," he told analysts. "Our oil view continues to be that the 2010 through 2012 Nymex [New York Mercantile Exchange] is reasonably reflective of what oil prices will likely be. We are long-term bullish regarding oil and have no oil hedges."
EOG turned toward more oil production this year because of low gas prices, and that trend will continue, said Papa. "With our arsenal of gas sets assets, we can easily organically grow our gas at a 15% annual rate for multiple years, so we are continuing to moderate our gas drilling activity."
Most of EOG's gas growth will come from the Haynesville Shale, he said. Less promising in the short-term is the Marcellus Shale, where only "modest activity" is planned in 2010.
"Up until a couple weeks ago, we had zero sales from the Marcellus simply because of just delays on pipeline connects, and just over the last few weeks, we got our first wells actually flowing to sales," said Papa. "As we have related multiple times, we think this is an infrastructure-challenged area...Two rigs will get us probably about 45 wells next year."
It took EOG "at least a year" to get its first Marcellus wells on production. "I really think that, in the macro view for North American gas, it is going to be 2013 or so before the Marcellus plays any significant role."
About half of the company's total liquids growth in 2010 will come from the Barnett Shale, as well as the Bakken and Waskada horizontal plays. The company hasn't finalized its 2010 capital expenditure budget, but "at least 60% of our North American budget will be allocated to oil," said Papa.
EOG's North American liquids production is growing enough to lift total estimated 2009 output by 6% from 2008. The Houston-based producer now expects to build total organic production in 2010 by 13%, which includes a forecast for liquids output to jump by 50%.
Based on recent oily well results from EOG's Bakken and Barnett wells, the company increased its liquids production growth estimate for 2009 to 27% from 25%. EOG also increased its holdings in the Barnett Shale by adding 7,800 net acres in Montague and Cooke counties in Texas.
In addition, EOG upped its acreage position in the Texas portion of the Haynesville Shale by 37,000 net acres based on initial production (IP) rates of some of its wells that "equal the better wells drilled to date in the Louisiana core area," Papa said. In Nacogdoches County, TX, the Hill #1, Pop Pop Gas Unit #1 and Hassell Gas Unit #1, which were drilled early in 3Q2009, had IP rates "in excess of 15 MMcf/d of natural gas," the company said. EOG has 42% working interest in the wells. The company said it now has 153,000 net acres in the Haynesville Shale.
In the Horn River Basin of British Columbia (BC), EOG's summer program concentrated on the completion of seven natural gas wells drilled the previous winter. The wells, said EOG, had IP rates ranging from 16 MMcf/d to 23 MMcf/d. In addition, EOG reached agreement with the BC government on royalty incentives for a significant portion of the company's acreage.
EOG reported net income in 3Q2009 of $4.2 million (2 cents/share), which included a $20.9 million gain on mark-to-market hedges. In 3Q2008 EOG earned $1.56 billion ($6.20).
Natural gas volumes in the United States in the quarter fell slightly from a year earlier to 1,128 MMcf/d from 1,196 MMcf/d. Canadian gas volumes also fell in the period to 268 MMcf/d from 224 MMcf/d in the year-ago period. However, natural gas equivalent volumes rose slightly in 3Q2009 to 1,577 MMcfe/d from 3Q2008's 1,525 MMcfe/d. EOG's average gas price in the latest quarter averaged $3.27/Mcf, compared with $8.99 in 3Q2008.
In his closing comments Papa said he wanted to make an "editorial comment regarding industry year-end reserve bookings" for proved undeveloped (PUD) reserves. The Securities and Exchange Commission (SEC) has required producers to use the closing price for oil and natural gas on Dec. 31 of a given year to calculate proved reserves. However, the SEC rules were revised and the changes take effect next year (see related story).
"It is our belief that the new PUD booking rules provide a much larger amount of flexibility than previously was permitted," said Papa. "Hence, you can expect to see big variations in PUD bookings across companies, making it difficult for analysts to make comparisons between companies regarding proved reserve replacement rates and finding costs.
"This is not code for EOG signaling a reserve or finding cost problem, but I felt that at least one industry executive should alert shareholders that you will have one less comparative tool to measure industry results."
Papa wouldn't comment on where EOG may be regarding "potential write-downs or write-ups" on its PUDs. However, "particularly early in the year, when everybody says, 'well, what is your finding cost relative to peer companies, what is your reserve replacement relative to peer companies?'
"And in my humble opinion, you have just lost the tool of having that be a useful metric because I expect, with variants that is afforded companies on PUD booking, that those that elect to book liberally...will show up with extremely low finding costs. And those that book conservatively for PUDs could have higher finding costs. As far as trying to evaluate across companies, in my opinion, it is just going to be invalid from this point forward."
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