Consultants at Freedman Billings Ramsey (FBR) in Northern Virginia see only a slight increase in drilling and gas production as a result of the proposal released last week by the Minerals Management Service (MMS) to reduce royalties on deep shelf Gulf of Mexico gas production (see Daily GPI, March 27).

The goal was to stimulate drilling activity in this high-risk province, but the results may be relatively insignificant, the consultants said after interviews with producers on well economics, risk levels and available service equipment.

“We believe that higher commodity prices and the royalty relief stimulus will cause exploration and production companies to drill roughly 10 to 15 more wells per year, adding approximately 200 MMcf/d of natural gas production to current, estimated base production of 47 Bcf/day.” FBR consultants said in their study. “[Currently], companies are allocating approximately 5%-10% of capital spending towards deep shelf exploration. Until technology improves to reduce the risk, most producers believe this potential royalty benefit will not affect their activity levels.

“The legacy oil and gas producers that focus on deep shelf…are the main beneficiaries, while some drilling contractors and small-cap oil service companies…could see marginal revenue increases,” the consultants said. “The royalty relief proposal will likely be a long-term positive for the industry since it improves incremental rates of return and essentially removes some cyclicality from the business; however, we do not expect significant incremental activity based on the proposal alone.”

The MMS plan would provide royalty suspension incentives for nearly 2,400 existing leases if producers are willing to drill for new and deeper prospects that are more than 15,000 feet total vertical depth (TVD). The program would provide a royalty suspension on the first 15 Bcf produced from a well drilled and completed between 15,000 feet and 18,000 feet, or on the first 25 Bcf from a well drilled and completed 18,000 feet TVD or deeper. Production must begin within five years of the release of the new royalty suspension rules and realized gas prices cannot be higher than $5/MMBtu.

MMS estimates that the incentives would save about $280 million a year over the next 15 years. Production from deep wells on existing leases in the shallow water of the GOM may yield up to 20 Tcf of yet undiscovered reserves, according to the agency.

Although natural gas from the Outer Continental Shelf currently provides about 25% of domestic production, the contribution from the shallow water area has been declining precipitously over the past five years. Shallow waters of the GOM have been actively explored, but relatively few wells have penetrated depths below 15,000 feet because of the high cost and risk associated with such wells. Because infrastructure is already in place, in terms of platforms and pipelines, MMS anticipates that production could come on line relatively quickly.

MMS also is offering dry hole incentives that would allow a royalty suspension supplement of 5 Bcf applied to future production of gas or oil from any drilling depth on a lease for an unsuccessful well drilled to a target reservoir 18,000 feet or deeper. The dry hole incentive would help offset the high risk associated with deep drilling. Two royalty suspension supplements are available per lease prior to production from a deep well.

MMS has included a deep gas royalty incentive for new leases since March 2001, and proposes to allow lessees to exercise an option to replace their existing deep gas royalty terms on leases acquired from sales held after Jan. 1, 2001, with the terms in the final rule on this initiative. The rule currently is in a 60-day comment period.

“We value the deep shelf royalty relief proposal at about $12.5 million per successful well, or 65% of the initial well cost but only 25% of the total drilling and completion cost,” the FBR consultants said. “In comparison, deepwater GOM royalty relief can be as much as 87.5 MMboes in around 2,500 feet of water, equating to $160 million, or roughly 545% of the initial well cost and about 33% of total project development costs.”

The consultants said surveyed producers assumed the probability of drilling success in this area would be between 10% and 50%. Several producers said the minimum economic target size is 50 Bcf. “In our opinion, the deep shelf proposal slightly augments success-case economics but does little to improve the risk tolerance for deep gas exploration,” the consultants said.

Although 5,000 wells have been drilled in the Gulf of Mexico, only 7% and 2% were drilled below 15,000 and 18,000 feet, respectively, according to the MMS. Over the past three years, the industry has drilled about 87 deep shelf wells per year defined as below 15,000 feet TVD.

FBR consultants estimate that drilling contractors Rowan and Ensco will be the primary beneficiaries of increased deep shelf drilling activity. The two companies own most of the 30 rigs capable of efficiently drilling deep gas wells. Other small-cap, mid-cap and large cap oilfield services companies also could benefit.

The type of rigs required to do the drilling currently are being utilized at about 90%, in contrast to the overall Gulf rig market (67% utilization). However, FBR said these “high-spec” rigs are being used to drill less-challenging wells due to the weak market. “As demand for high-spec rigs increases, those rigs will begin to drill more challenging wells, potentially causing capacity constraints in the high-spec rig market.” But FBR consultants don’t see that happening in the near term. “In our opinion…, the current number of high-spec rigs in the Gulf is sufficient to handle near-term demand.”

“We believe that deep shelf activity will increase in 2003, based on increased lease sale activity and the potential for royalty relief, but even a substantial 15%-20% increase would lead to only 10-15 additional wells. With average drilling times of three to four months, 15 additional wells would only put an extra four rigs to work each year, not a meaningful increase in terms of rig count,” the consultants said. “We would expect this level of increase to generate an incremental $300 million to $400 million in annual spending, representing about a 1% increase in U.S. E&P expenditures. This figure assumes about $20 million in drilling cost per well, a 20% success rate, and $20 million to $30 million per well completion costs.”

The FBR consultants, however, also noted there still are some risks potentially standing in the way of royalty suspension:

For more details from the study, contact David Khani at (703) 469-1179 or Robert Mackenzie at (703) 312-1891.

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