By Linda Hsieh, assistant managing editor
It’s certainly no secret that US land drillers aren’t having a great year. There are a lot of bad news out there – natural gas prices down to around $3/Mcf, a rig count hovering near the 1,000 mark, and massive layoffs just as green hands were finally trained and employment started to stabilize.
So the question on a lot of people’s minds is: How much worse will this get?
The truth is, nobody can answer that question with any genuine certainty at this point. Some people are forging ahead with a sense of optimism that the absolute worst is behind us, while others look back at the 1980s and ’90s and pray that history won’t repeat itself.
Wm Stacy Locke, president and CEO of Pioneer Drilling, took the optimistic approach, commenting in late March, “I would not be surprised by a faster natural gas price recovery than people may think today. I feel like the rate of decline is beginning to slow week over week, and it suggests we’re nearing a bottom. I’d say the bottom is probably 150-250 rigs away.”
For perspective, the Baker Hughes US rig count for the week ending 27 March was 1,143. Just months earlier, the same count recorded a high of 2,031 active rigs for the week ending 12 September.
“With the rig count having dropped 50% in six or seven months, there will be a material effect on natural gas production,” Mr Locke continued. “We’ll see that start to develop as we move into summer and certainly as we move into fall. I think then you’ll see a more abrupt correction in natural gas prices.”
At Latshaw Drilling, president Trent Latshaw said he also hoped that the bottom is near, yet his outlook was slightly more cautious: “The drop seems to be slowing down some, but just because it’s slowing down on a weekly count doesn’t mean it can’t keep going for a long time. I think we’ve still got some more (rig releases) to go, but hopefully we got the biggest bulk of it behind us now. But who the heck knows?”
It was only in hindsight that we realized how long the ’80s downturn really lasted, Mr Latshaw pointed out. “We thought we hit bottom in ’86 when oil prices did, but then we found out 13 years later in 1999 that the rig count really bottomed out in 1999, at 400-plus rigs. (Now we know) that downturn lasted 17 to 19 years before things really turned around in 2000 and 2001.”
Certainly, he hopes the current slump is “not another two-decade deal.”
“My personal opinion is, it’s going to take at least a couple of years to work through this, both in the economy and the surplus of natural gas,” he said.
Richard Mason, publisher of the Land Rig Newsletter, echoed the ’80s comparison and offered a mix of hope and glumness in his assessment: “This is as tough a market as we’ve seen since 1999 and seems to be angling for sort of a 1986 repeat in terms of severity.”
He contends that the rig count has actually fallen more deeply than is generally understood through public rig counts, adding that his own count was down to 964 as of mid-March.
“We’ve also seen the first rigs go to the auction block, which may be the first rigs auctioned in half a decade or more,” Mr Mason said. “The industry is under a lot of stress.”
On the brighter side, the rig count free-fall just can’t perpetuate itself. Many operators have already gone from a couple dozen rigs to just one or two, so he believes there are just not that many rigs left each company can release – unless they stop drilling altogether. And that is unlikely because companies have to continue drilling to keep their leases, to provide base revenue, to meet debt obligations, etc.
“There’s some level of base drilling out there. We really don’t know what it is, but I think we’re going to find out this year,” Mr Mason said. “We think the rig count is kind of overshot to the down side (now) and will gradually work its way back to the maintenance level activity.”
He also hopes that the Barnett Shale rig releases that took place in the first 60 to 90 days of 2009 – which left that Texas play “virtually shut down” – was the last of the massive releases. In fact, he hopes it might kick-start real reductions in natural gas production. Then the oversupply can start to correct itself.
When the industry first turned, Mr Mason argued, the rigs that got laid down were the ones drilling for marginal gas – but marginal gas wasn’t the problem. “It was this surging production coming out of these shale plays. As long as those rigs continued to work, there was no opportunity for there to be any meaningful impact on production.”
So the fit-for-purpose, advanced technology rigs began to be laid down this year, bringing another signal of the severity and scope of this down cycle. “Operators have been indiscriminate on all types of rigs. The majority of those not under term contracts have been laid down regardless of their specifications or efficiency or age,” Mr Locke said.
Even rigs under term contracts haven’t been immune, with operators making unprecedented decisions to actually pay, in some instances, $15,000 a day not to drill – paying the prorated daily margin for the rig to keep it idle.
Think that’s crazy? Not in this kind of deteriorating economy. Not drilling saves them from having to pay the full dayrate – plus they save on other expenses like drill bits, casing, cement, mud, directional tools, completions, etc.
One producing company even paid close to $60 million to not take delivery of newbuild rigs, Mr Mason said. “That’s how severe the downturn has been.”
One silver lining here – if you want to see it – is that multi-year term contracts have proven their value in this cycle. Drilling contractors had learned from previous downturns how quickly things can go south. So, this time around, most companies built new rigs against multi-year take-or-pay contracts.
Mr Latshaw said that two rigs in his fleet each had a year left on three-year contracts for work in the Barnett Shale when the operator decided to stack the rigs and pay the standby rate. “I continue to bill them monthly. They just found it was more economical from their perspective to not drill the wells right now,” he explained.
Which means that drilling contracts and their early termination clauses are working exactly as they should and offering a layer of security, Mr Locke commented. Rigs may still be left idle and revenue may be down, but contractors are mostly left with full drilling margins, he said.
In this market, that has turned into something to be grateful for.
Operator decisions not to drill also underline the size of the oversupply problem in North America, and the game-changing culprit here that many have pointed to is the rapid growth of unconventional shale gas.
“It’s essentially a whole new resource that seven or eight years ago, very few people in the industry thought would have a significant role to play in North American gas supply,” said Simon Mauger, director of the gas services group at Ziff Energy Group. The Houston-based company researches and provides independent analysis and forecasts on gas market fundamentals without taking financial positions.
In the early 2000s, Mr Mauger said, three key factors started coming together that improved the economics of shale gas relative to conventional resources and ultimately made shale gas what it is today. First is the rise in natural gas prices from under $2 to the $7-8 range. The second and third are both technological breakthroughs – in horizontal drilling and multistage fracturing completion technologies.
Innovations in other downhole technologies have helped as well, such as pressure pumping and well stimulation, to harvest more of the original gas in place. In the Barnett Shale, for example, Mr Mason said that the recovery rate has been improved from 9-13% to over 20% now – “with some discussion that we’ll soon move above 30%.”
SO WHAT CHANGES HAS SHALE GAS BROUGHT ABOUT?
For one, Mr Latshaw believes it has significantly reduced the risk in drilling new wells. “If you go back 30 years, the rule of thumb was nine dry holes for every producer,” he recalled. “They call it natural gas farming now because every well you drill, you just drill it horizontally and frac it, and they all produce. It’s like planting seeds out there and watching it grow.”
Another change is in initial production rates, with shale gas wells coming on-line at massive volumes. In the Haynesville, for example, some wells have announced initial production rates of up to 28 MMcf/day. That’s more than 10 times as much as an average Gulf of Mexico shelf well, Mr Mauger said.
But the biggest thing about shale gas is not so much its absolute size today, he continued. Rather, it’s its size relative to five or eight years ago – 5 Bcf/day now versus just over 1 Bcf/day then. “We’ve got nearly a 500% increase in production… Particularly in the last three years, we’ve seen shale gas production really soar, and that has contributed to an oversupply of natural gas in North America.”
Ziff Energy recently released its shale gas production outlook, assessed by different plays across North America. Mr Mauger, the study’s author, believes that by 2020, the 5 Bcf/day we see now will have tripled.
Shales cover an immense area with thick payzones up to 250-ft, compared with payzones in conventional gas wells of 10-30 ft, he said. “We’re quite bullish on the amount of supply that will come from shale gas in the longer term.”
“It’s quite an exciting position from a techie’s viewpoint, seeing what was once considered to be the seal for reservoirs actually be able to produce commercial quantities,” added Mr Mauger, who is a professional geologist.
HOW MUCH IS TOO MUCH?
So how much gas is too much in this market? Estimates range from 2 Bcf/day on the low end to roughly 7 Bcf/day on the high end, according to Mr Mason. “If I draw a line at the mid-point, it’s around 4.5 Bcf a day, and that’s about the Barnett Shale.”
So could eliminating the Barnett Shale put the market back in balance? It would seem so, though that’s obviously not going to happen. Still, it’s an illustration of the size of our oversupply issue.
And, actually, Barnett Shale production is still growing at approximately 100 MMcf a month, Mr Mason said, with approximately 450 wells waiting to be hooked up. “If you take the Barnett Shale average of 1.5 MMcf a day times 450, that gives you an idea of the potential backlog in terms of gas production that’s still out there.”
This begs another question: With so many rigs laid down, how long before natural gas production begins to fall?
“We always thought that if you quit drilling, gas production would roll in six months. I think what we’ll find is that it will take a year or so for gas production to respond to the decrease in drilling,” Mr Mason said.
As Mr Locke of Pioneer said earlier, he’s remaining optimistic and believes that because the rig count has dropped by such a large percentage, “it isn’t going to take a couple of quarters before you start seeing some material reductions.”
However, because this particular cycle is tied to the wider economic recession crossing many industries and sectors, it will likely take a strengthening of the credit markets and the overall economy before the drilling market can come back, he said. “Most probably a recovery will begin in 2010.”
In the meantime, certainly it’s possible for some regions to recover faster than the rest of North America – oil-based plays, for example.
In fact, oil may be the only bright spot in an otherwise gloomy market, having risen closer to $50/bbl from dips into the $30s. “Oil seems to have come off its lows, and ultimately oil does have an impact on our land drilling market, even though we always assume it’s a gas-directed market,” Mr Mason said.
For example, oil prices impact activity in the Permian Basin, California and parts of the Mid-continent. Healthy oil prices can bring in many of the small, privately held operators, he continued, and on occasion they can account for up to 40% of rig counts. They also often hire sub-1,000-hp rigs, a market devastated by the downturn. “So an improvement in oil pricing is potentially some good news in an otherwise bleak outlook for 2009.”
EVERYTHING IN TIME
Whether it takes six months or a year or longer, industry experts agree that everything will fix itself in time.
In the process, Mr Mauger predicts that the industry will see huge volatility in gas prices and producers will take a cautious approach to increasing capital investments. “Anything they can do quickly and easily to capture those rising prices, they will do. But they would probably hold back on longer-term investments.”
In today’s dollars, he added, natural gas prices would have to rise above $6, and closer to $7 or $8 in the long term, for operators to put rigs back to work. Then, when the industry approaches fleet capacity, inflation will come into play again, and “that will sort of escalate the price that’s needed.”
But let’s not get ahead of ourselves. There are still hurdles that must be crossed before the industry can be healthy again.
First, natural gas demand has to rise, and that is completely out of the industry’s control. It will depend on the overall economy, not just in the US but worldwide, Mr Mason said.
One good news here is that Ziff Energy believes demand will remain fairly stable, said Bill Gwozd, vice president of gas services. “Demand is not going to change significantly one way or another in the immediate short term while energy prices are fluctuating significantly,” he said. His analysis is based on five sectors: residential, commercial, industrial, gas for power generation and pipeline fuel.
Second, how will the industry ramp up again? Depending on how long rigs are stacked, time will have to be spent on maintenance, inspections, clean-up, etc, to bring them up again. “I don’t know that the industry has ever added more than three rigs a day, even in the best of times. It’s going to be very difficult for us to ramp up, and we can’t do it at nearly the same rate we laid equipment down,” Mr Mason said.
Not to mention that massive layoffs have taken place across drilling markets, sending away many of the new workers that the industry had been hiring and training for the last few years.
Pioneer, for example, has reduced its workforce by about 40% – which doesn’t seem so bad when Mr Mason cites another company as having gone from 218 employees to seven in a matter of months. Overall, Mr Mason estimates that the industry has lost about 20,000 jobs in this downturn.
“These are good-paying jobs, primarily in rural areas. Oftentimes, these are the best-paying jobs in those rural communities, so there’s a big ripple effect on the economy, not just for the contract drillers but for the communities in which they operate,” he added.
Mr Locke commented that the layoffs have been absolutely one of the worst aspects of the downturn, if simply because it’s undermining all the personnel and safety efforts that the industry has made in recent years. “We had just finally had stable employment in the industry and trained people to be good and safe workers. We achieved our highest safety standards in 2008 and now we’ve had to reduce our workforce by 40% or more… And the longer you don’t have a rig operate, the less likely it is you’ll get your trained people back.”
Still, regardless of how tough layoffs are, many companies are finding them necessary evils in this market. And Mr Latshaw said he’s viewing this cycle as an opportunity to improve the overall quality of his workforce.
“We are doing with our rig crews just like what our customers are doing with their rig fleets. Our customers are cherry-picking their best rigs and laying down their worst performers. That’s what we’re doing with our rig crews,” he said.
COST, NOW AND FUTURE
One of the toughest challenges that drilling companies face now is how to manage cost. “Because we have nothing but bad news for the next three or four quarters as we’re rolling off our term contracts. Your profitability per quarter will continue to decline throughout this year because the spot dayrates are quite a bit lower,” Mr Locke said.
And he hopes that drilling contractors have learned their lessons from previous cycles: “Leverage is not a good thing for a pure land contract driller. You have to stay conservatively financed, and you have to be able to rapidly downsize your organization from a cost perspective.”
Even for companies that manage to make their way through this downturn, experts say the industry may have to adapt to a new cost structure going forward.
Mr Mason noted that current market pricing – sub-$50 oil and sub-$4 gas – takes the industry back to 2004 revenue flow levels. “I would argue that going forward, the industry is going to have to live within that revenue model.”
The picture changes even further when you factor in LNG, which still remains a total wild card for the global gas market.
LNG capacity is slated to increase significantly in 2009 even as the global recession tempers demand. Europe and Asia could absorb some of the supply, but after that, it’s on the world market. “Ultimately the LNG has nowhere to go, and it’s going to flow towards the US because we have the underground storage… I think that’s the 800-pound gorilla that no one wants to talk about,” Mr Mason said.
In the Ziff Energy forecast, LNG is certainly a threat to US land drillers. Mr Mauger and Mr Gwozd asserted that, in the coming years, North American land drillers will have to further lower costs and increase efficiency in order to survive. In fact, they have to start thinking of the North American natural gas market as a global natural gas market – and they must be competitive on a cost basis not with their fellow North American drillers but with natural gas drillers around the world.
To explain, Mr Gwozd used an analogy of foreign-made shirts – shirts made in countries like Vietnam, Trinidad and China and imported to the US. “They can ship a fully finished shirt to North American consumers cheaper than we can manufacture a shirt in North America. LNG can be delivered to consumers in North America cheaper than producers can manufacture gas here… We suggest to the producers and service companies that their competitors are not the other producers or service companies (in North America). Their competitors are actually the other people in the world who can do their jobs cheaper than they can do it themselves today… Global competition will crush those that fail to recognize competition,” Mr Gwozd said.
He also cautioned that companies have to benchmark the cost of their products – whether it’s a shirt or natural gas – so they know how they compare against the best-in-class. “Everybody should be striving for the top-quartile cost position, be the lowest-cost operator,” he urged.
LNG imports averaged between 1 to 2 Bcf/day over the last five years – a small fraction of overall supply. But Ziff Energy research shows that by 2020, there will be a much more tangible 10 Bcf/day of LNG here. In other words, LNG is cheap shirts, and US land drillers simply have to make their natural gas more cost-competitive.
Certainly, it won’t be easy to drive drilling costs down. In fact, the cost structure in North America has risen significantly in recent years.
Five to 10 years ago, if drilling contractors had been told that commodity prices would double – to $50 oil and $4 gas, they’d probably have been happy with that, Mr Gwozd said. Yet when it actually happened, all of a sudden those prices weren’t enough anymore.
First, he explained, the size of the resource base is shrinking. Second, the cost structure (steel, labor, etc) went up much more rapidly than people expected. In other words, we’re now spending more and getting less.
And with inflation in the double digits in the last five to six years industrywide, Mr Mauger said, “what we need to be profitable today is significantly more than it was six or seven years ago.”
Overall, the North American market is simply overcapitalized for the resources we’re getting, Mr Gwozd said. “We’re spending way too much money on drilling activity to extract the resource, i.e., we’re drilling wells that are feet apart as opposed to tens of miles apart. Nothing wrong with it… but you reach a point where no more wells are required. Whereas in other countries, wells might be miles apart so they haven’t overcapitalized and therefore they get higher productivity and better economics for their wells.”
JUST TOO MANY RIGS?
One interesting question that seems to be emerging, amid discussions of oversupply and prolific shale gas wells, is: How many rigs do we really need drilling for natural gas on US land? Could it be that, with this decade’s downhole technological breakthroughs, maybe we just don’t need as many rigs working anymore?
“The natural gas farming of the shale plays would lead a person to think there’s probably not going to be as many rigs needed in the future,” Mr Latshaw acknowledged. “Does this mean we only need 1,500 rigs going forward? I have no earthly idea.”
Mr Mauger believes that to keep production flat, we actually only need somewhere on the order of 1,000 rigs in the US. And certainly the industry is dealing with a much larger fleet than that, having refurbished, built new and imported in the last few years.
It’s possible that some old rigs won’t come back from this downturn, depending on how long it lasts. But Mr Mason isn’t convinced. People often assume that a significant number of very old, out-of-date rigs are just waiting to be scrapped, but actual attrition numbers have been very low in recent years. “My experience over the last 12 years has been that when dayrates get high enough, all those old rigs come back… It may be premature to write the obituary on some of those old rigs.”
So what about the excess rigs? One possible solution Mr Gwozd offers is for drilling companies to move outside North America and expand their drilling portfolio. There are many places around the world where natural gas is drilled, such as Trinidad, Australia and Indonesia, and that means new opportunities.
“You can take the know-how, the equipment and the people, move them to those locations,” he suggested.
‘LIKE A ROCKET’
Despite the bad news going around the land drilling industry, for the most part, people appear to be staying relatively hopeful. In a survey conducted in April on www.DrillingContractor.org, an overwhelming 83% believed either that a strong recovery is likely in late 2009 or early 2010 or a recovery could begin by 2010.
Mr Mauger commented, “This one is going to be a pretty severe (downturn), but we will come out of it like a rocket.”
And Mr Mason said he’s “hopeful without having any rational reason that we’re getting close (to bottom).” When that does happen, though, “we can establish a psychological bottom and turn our focus to how best to manage through this. The industry, unfortunately, has had a lot of experience being able to work in these types of business conditions.
“There are a lot of experienced people out there, and ultimately they are going to find a way to make all this work.”