Improving Conditions for Service Sector in 2010

By: Richard Mason
Jan/Feb 2010

 
No matter how 2010 turns out for oil services, rest assured it will be better than 2009. Attractive oil prices promise an improvement in operator cash flow. Toss in low service costs and operators have incentive to get busy again, unlike the withered climate of 2009 when operators vowed to live within rapidly declining cash flow and field activity was frozen in response to the greater economic collapse.

 


Pent up demand from postponed projects will propel 2010 to an early and strong start when it comes to services.

 
Pent up demand from postponed projects will propel 2010 to an early and strong start when it comes to services. A random perusal of operator earnings in the third quarter of 2009 suggests public independents will add 140 drilling rigs in 2010, primarily in hot shale plays such as the Bakken, Haynesville, Marcellus, Eagle Ford or Barnett.
 
Fueling the activity increase is an expected 10 percent jump in operator budgets for 2010, according to Credit Suisse, which says the 60 public oil and gas operators it follows will increase capital expenditures to $63.8 billion, up from $57.9 billion in 2009.
 
While the new shales get the headlines, the largest increase in drilling rig count will occur in the Permian Basin thanks to a confluence of high crude oil prices, low service costs, and an evolution in downhole completion technology. The Permian Basin led the way off the bottom after rig activity troughed in May 2009. Privately held oil and gas independents were the first to return to market in mid-2009 and they did so in oily areas like the Permian Basin or the Midcontinent. Small, privately held oil and gas independents will remain active in 2010, assuming oil prices stay above $65, but will be joined by large public independents. Many public independents are looking to re-balance portfolios to include more oil-directed activity, or to pursue natural gas with high liquids content. This trend will benefit the national well service firms whose utilization in 2009 was at lower levels than that reported by regional well service firms, although regional firms are expected to see business increase as well.
 
The good news is that well site pricing and utilization stabilized in the second half of 2009 and is expected to improve modestly in 2010. Gone are the days where pricing dropped in double-digit percentages month-to-month. In the end, pricing for service rigs bottomed 35 to 40 percent below peak 2008 levels across most regional markets. While pricing is exiting 2009 unchanged, hourly rates will improve in select markets next year, particularly for higher spec rigs.
 
Everything is going to be oil right
Commodity pricing is a mixed bag of expectations with oil faring much better than gas. The Energy Information Administration projects crude oil pricing to hover in the $75 range during the first half of 2010 before ending the year at $82 per barrel. The forecast is predicated on the assumption that U.S. gross domestic product returns to growth in 2010 and rises 1.9 percent, slightly below the forecast 2.6 percent GDP growth internationally. Of note, the EIA expects domestic crude oil production to rise for the first time since 1991, largely as a consequence of production growth from deepwater fields in the Gulf of Mexico. U.S. daily production will average 5.4 Mmbbls/d in 2010, according to the EIA.
 
However, onshore oil production may rise at a greater than expected rate in areas like the Permian Basin where public independents are revitalizing programs in the Spraberry and Wolfberry formations. Similarly, public oil and gas operators were active on property transactions in the second half of 2009, particularly in the Permian Basin where some operators are selling legacy assets to raise funds to underwrite capital programs in unconventional gas resources, or to pay down debt. They are finding willing buyers, indicating that one company’s non-core legacy asset is another company’s potential treasure. One example is Forest Oil’s divestiture of $800 million in Permian Basin legacy assets to SandRidge Energy.


Private operators added rigs at a greater rate in 2009 than public oil and gas companies.

Not so fast on gas
While crude oil price forecasts exhibit a high level of confidence, natural gas is problematic. The EIA projects Henry Hub spot natural gas prices to average $4.62 in 2010, up 17 percent versus 2009. The financial community is all over the map in 2010 with NYMEX gas price forecasts ranging from $5.50 on up to $7.50 per Mcf. The higher prices, which are promoted by sell side firms like Tudor Pickering Holt, are based on an anticipated 5 Bcf/d decline in natural gas production after the devastating 60-percent decline in gas-directed rig count. Firms such as Credit Suisse and Raymond James forecast lower gas prices and contend the rollover in domestic gas production will be shallower and largely offset by increases in shale gas production. Those expectations are similar to the EIA, which anticipates a gas production decline in 2010 of 3 percent versus 2009, which would return gas production to 2008 levels.
 
An increase in shale gas production will also offset declining Canadian imports and LNG, which averaged 1.4 Bcf/d in December 2009. Additional global LNG capacity will come online in 2010, though much of that is destined for higher priced markets in Asia and Europe and should not be a meaningful threat to oversupplied gas markets in the U.S.
 
Winter natural gas storage reached a record 3.837 Tcf during the last week of November 2009, exceeding the previous high by 292 Bcf. Storage remained 513 Bcf above the five-year average in December. This becomes critical in the face of an El Nino winter, which is projected to be slightly warmer than normal in major gas consuming regions, and a slow economy. Combined, those events will reduce U.S. gas demand to 61.9 Bcf/d in 2010, according to the EIA, down from 63.8 Bcf/d in 2008.
 
Increased well productivity, greater efficiencies and an intensification of downhole services are edging initial production (IP) and, theoretically, estimated ultimate recovery (EUR) ever higher as operators redeploy a dividend from lower service costs into longer lateral lengths and more frac stages. The end result is well IPs that routinely top 10 Mmcfed in many plays, and have exceeded 30 Mmcfed in a few instances.
 
Operators are beginning to work through a backlog of drilled, but not completed wells, particularly in unconventional gas plays and that promises an uptick in activity for pressure pumping, fluid hauling, well stimulation and completion rigs. Expectations are that the increase in work on uncompleted wells will significantly reduce the 2009 backlog during the first six months of 2010.
 
Heading to the chapel and we’re going to get married
The industry may be entering a new cycle of mergers, acquisitions and consolidation on both the operator and service side. The $5.5 billion Baker Hughes/BJ Services merger potentially alters the global pressure pumping space, though deals of this size in the oil services sector may be rare going forward with consolidation more likely to involve national service companies acquiring assets or market presence from distressed regional firms.
 
In contrast, the $41 billion ExxonMobil/XTO purchase may point to a new trend on the operator side as the majors look for growth domestically. The majors have been frozen out of global markets since national oil companies already control those assets. That leaves deepwater and the U.S. domestic space as the remaining two areas for meaningful growth. Several majors have abundant cash on hand and can add to their portfolios by writing a check to acquire key domestic independents, essentially buying their way into the unconventional space.
 
It appears public independents are ripe candidates as companies sell assets and reorganize. The Devon restructuring in which the company will sell offshore and international assets to focus on North American gas is one example, though the irony may be that Devon is restructuring itself into an attractive acquisition target.
 
But it doesn’t have to be big name deals. The $4.5 billion merger between Dallas-based Denbury Resources and Encore Acquisitions brought together two firms who were expanding CO2 tertiary recovery projects on the Texas/Louisiana Gulf Coast and in the northern Rockies. The merger will create America’s largest independent oil producer when the deal closes in early 2010. It is of note that the deal focus is on oil, signaling that while gas shales generate headlines, attractive crude oil prices generate profit.
 
Other arguments supporting an increase in 2010 field activity are found in the behavior of oil and gas operators. Several have hedged 2010 production at prices above $6 per Mcf, which is well above deflating threshold economics in gas plays. A recent Credit Suisse study found that 44 percent of public operators in its coverage universe hedged for 2010, up from 40 percent in 2009.
 
Gas-directed rig count would have fallen as much as 300 units lower in 2009 had it not been for hedging, which supported drilling despite the collapse in commodity prices and is an important factor in why domestic gas production has not rolled over to the extent expected.
 
Additionally, operators have been able to raise money for capital spending through equity issuances earlier in 2009 while several executed successful joint ventures, trading acreage or well participation in shale plays for drilling cost carries. More recently, operators have completed, or are announcing, sales programs to monetize assets in non-core areas in order to redeploy cash into expensive growth projects, primarily in shale plays.
 
All those signs suggest the service industry will enter 2010 with a slight tail wind at its back, certainly a long-awaited improvement over a challenging 2009.