Canadian drilling activity is flagging due not only to the recessionary impact on oil and gas demand, but also due to weak producers' cash flows and restricted access to investment capital to help fund new exploration and development programs. The traditional seasonal downturn at breakup this year was worse than at any time since before 2000. The Canadian land drilling rig count, as measured by Baker Hughes at June 26th, stands at 147 active rigs. This represents somewhere around 18% of the available rig fleet.
We have plotted the 2008 and 2009 rig counts along with the weekly high and low counts for the entire period of 2000-2009. So far, virtually all the weekly rig counts for 2009 have set decade lows, which is not surprising given the industry environment. As a result, when you look at the decade-low line on the chart you should note that the blue line going forward only reflects low rig counts through 2008, but given where drilling activity is centered at the moment, it is likely that many more weekly low counts will be established in coming months.
Last year, the Alberta government moved to alter its oil and gas royalty scheme with the aim of improving the attractiveness for exploring in the province. This new plan marks the fifth change in taxation of energy companies since 2007. Because of prior royalty changes, Alberta had seen its attractiveness as the prime location for oil and gas activity decline. The plan changes put in place last year were designed to stimulate Alberta's drilling activity, but no one expected the industry and economic changes that later unfolded. The Alberta government is now moving to extend its altered royalty scheme for a second year hoping to bolster industry activity and government revenues.
The Alberta royalty program consists of two programs - one for drilling and the second for production. The Drilling Royalty Credit provides a $200/meter royalty credit for new wells drilled based on total measured depth from April 1, 2009, through March 31, 2011. The new program extends the life of the royalty by one year from 2010 to 2011. The royalty is designed to assist small producers as it is determined on a sliding scale for each producer based on its 2008 oil and gas production in Alberta. The second program, the New Well Incentive Program, provides up to a maximum of a 5% royalty rate during the first year of production up to a maximum total production of 50,000 barrels of oil or 500 million cubic feet of gas.
While these programs are welcome, they will probably have only a marginal impact on oilfield activity for the balance of the summer. The new royalties should help the shallow natural gas market and smaller producers. The extension of the plan may help producers and service companies by providing operators more time to plan for drilling programs in seasonally restricted or winter access only areas. This means that wells that might have not been drilled because they couldn't be completed within the prior March 2010 deadline will now be drilled. This will be especially true for winter wells next year.
An additional aspect of the New Well Incentive Program is that the royalty increases linearly with rising gas prices, although at the present time prices seem to be struggling to sustain current levels. Should we see a rally in natural gas prices as the second half of 2009 unfolds, that would make it more attractive for producers to commence drilling under the new royalty scheme.
The newly extended incentives are designed to help producers recoup a percentage of their capital spending and the Drilling Royalty Credit helps. Producers, however, have to spend money in order to save money under the Alberta's royalty program. If producers were unconstrained by cash flow limitations or had ready access to capital financing or were enjoying high energy prices, these royalty programs would likely have a greater impact. Unfortunately, producers are finding their cash flow constrained, they have great difficulty securing outside capital and natural gas prices are low. To see how well these incentive programs are working, one only needs to understand that they have been in place for three months, yet drilling remains at decade lows suggesting that capital and cash flow challenges are overwhelming the government's improved incentives. Since Alberta gets 55% of its revenue from natural gas production taxes, low gas prices and high oilfield service costs are taking a serious toll on industry activity and government revenues.
The Alberta provincial government needs to re-examine its overall competitive position, a program that is underway and is targeted to be completed this fall. The province probably needs a simpler royalty scheme. There needs to be greater transparency and visibility in the province's incentive program. Without these characteristics, Alberta's ability to compete long-term for access to investment capital will be restricted. So far, the province appears to have been too focused on short-term stimulus efforts possibly driven by its budget revenue shortfall, currently estimated at $4.7 billion for 2009-2010.
Understanding that the oil and gas industry is a capital-intensive, long-term focused business that welcomes, and needs, stable government policies both on taxation and incentives is an important recognition. The Alberta Energy Department is performing its competitiveness review of conventional oil and gas, comparing the province's regulations, land practices and royalty schemes with others. This is a joint government-industry effort. Its results cannot come too soon as the recently released Fraser Institute Global Petroleum Survey ranks Alberta 130 out of 143 jurisdictions for its fiscal terms. Alberta continues to rank highly in terms of geopolitical security. With huge shale-gas and oil sands deposits in Alberta, the province needs to repair its economic incentives in order to attract the necessary capital to develop these resources.
G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.
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