On March 31, 2010, the National Energy Board (NEB) in Canada released a report entitled the “Energy Market Assessment (EMA) Short-term Canadian Natural Gas Deliverability, 2010–2012,” scrutinizing the elements that affect the supply of natural gas in the short term.
Overall natural gas production in Canada is forecasted to decline through 2012 as a result of reduced drilling activity in recent years compared with earlier in the last decade. The National Energy Board expects natural gas deliverability to be down to 13 Bcf/d from 15.1 Bcf/d in 2009.
Capital expenditure on natural gas projects will stabilize and then increase through 2012. Drilling days will replace number of wells as the new labour indicator in the sector. Drilling days will increase about 11% from 45,659 days in 2010 to 50,512 days in 2012. Extracting the tight gas and unconventional gas takes more time to drill so there are more drilling days on each well.
The National Energy Board expects natural gas prices to generally remain within a range of $5.00 to $6.00/MMBtu through 2012 as noteworthy movements outside this range are prohibited by 2 factors. If prices moved much below $5.00/MMBtu, demand for gas to generate power would increase, and cause gas prices to move back up into the range. If prices move above $6.00/MMBtu, then more liquefied natural gas (LNG) imports would likely be attracted to North America to boost supply sufficiently to cause prices to move back down into the range.
Having being afforded the opportunity to interview an expert at the National Energy Board (NEB) in Canada with regards to the report, we jumped at the chance.
Paul Mortensen is Technical Leader of Hydrocarbon Resources at the National Energy Board in Calgary
Biography: Paul Mortensen is Technical Leader of Hydrocarbon Resources at the National Energy Board in Calgary. Paul is responsible for leading the NEB’s program for assessing and monitoring hydrocarbon energy supplies and maintaining the high standards of technical competency within the Board’s community of energy resource specialists. Paul continues to be actively involved in the preparation of the Board’s short and long-term projections of Canadian natural gas supply.
Prior to joining the Board in 2004, Paul spent 10 years at the Canadian Energy Research Institute as Director of Natural Gas Supply. At CERI, Paul directed the Institute’s research program into upstream natural gas issues including assessments of Canadian natural gas deliverability, supply costs, impacts of Sable Island gas and potential for CO2 sequestration.
Paul is a graduate of the University of Saskatchewan with a Masters in Civil Engineering
Q: Given that overall natural gas production is expected to decline through 2012 and despite this, if there will be more than enough supply to meet all our needs, what does this mean for the price of natural gas for consumers and for natural gas producers? On a related note, the Conference board of Canada recently (March 23, 2010) recently released a study stating that they expect profits for the sector to more than double in 2010 due to the continuing economic recovery in the US - do you concur with this view or not?
A: Natural gas prices in Canada are a result of the interaction of supply and demand in the integrated North American market. Our expectation is that the overall market will be somewhat oversupplied in the near term. This has caused prices to move downward since the start of 2010. The reduction in prices lowers the incentive to add supply and encourages demand, and we expect this will lead to more balanced supply and demand conditions in the second half of the year. Our mid-range expectation is that the North American benchmark price (Henry Hub) will average $5.50/mmBTu in 2010, $6.00 in 2011 and $6.75 in 2012.
We do not track industry profitability, so I cannot comment directly on the Conference Board estimate. We note that the price expectations in our outlook and that in the Conference Board study are similar with prices in 2010 about 35 per cent higher than in 2009 and also that industry costs have been reduced somewhat due to lower activity levels. Both of these factors would suggest higher returns than in 2009. A potential increase in returns would be slowed by an expected eight per cent decline in Canadian production volumes in 2010.
Q: The eventual cost and sustainability of shale gas production are open to question. Geologist Arthur Berman has argued that the high decline rates will make shale gas wells far more costly than projected - what might be the implications of high decline rates for shale gas wells to the overall price of natural gas? How large a impact has the discovery of shale gas resources made on the price/supply of natural gas in Canada? Will unconventional sources such as the new Shale and Tight gas plays be enough to offset the decline of higher cost conventional gas?
A: All indications are that the opposite to Berman’s analysis is occurring as shale gas production is continuing to experience lower costs per unit of gas produced and the expected total recovery of gas over a well’s life has continued to increase. This has been accomplished through the addition of hydraulic fracture stages per well to access more of the gas available in the shale. The extent that a high initial decline rate enables a greater proportion of the recoverable volume to occur in the early years that a well is operating allows the initial investment of the well to be paid back sooner. This also tends to lower costs and makes the economics of shale gas development less dependent on the more speculative long-term performance of the well.
It is difficult to separate the impact of rising shale gas development from declines in natural gas demand as a result of the recession. Both have contributed to an oversupply of natural gas in the North American market that has caused prices to move down from the peaks in 2008.
In our outlook, shale and tight gas output in Canada is not expected to be sufficient to offset declines in conventional production over the period through 2012. As a result, Canadian natural gas output is expected to decline by 14 per cent between 2009 and 2012 in the Mid-Price Scenario. The impact of rising tight and shale gas output over the period does cause the rate of decline to slow and suggests that output may begin to stabilize after 2012.
Q: Given that natural gas sells for a fraction of the oil price, is far from market, is in a mature basin, with high operating costs and the high Canadian dollar adversely impacting the revenues of natural gas producers, how can these companies position themselves to maintain their cash flow and keep the drill bits turning? How large a part is hedging for Canadian natural gas producers?
A: We are already seeing producers in Western Canada and the U.S. beginning to shift more of their activities toward oil development to access the higher valuation of oil. In some cases this involves using horizontal drilling and hydraulic fracturing techniques developed to access shale gas being applied to tight oil reservoirs. Other producers will focus on only their best natural gas opportunities rather than pursuing larger scale operations and impose rigid cost discipline to enable them to operate effectively under lower price conditions. Costs of services have declined in response to lower activity and improvements in technology and knowledge further help to enable natural gas development to occur under lower price conditions.
Hedging is a key strategy to enable producers to make their revenues more predictable and thereby reduce the risk of funding their drilling programs. Over the longer term, hedging gains would tend to be offset by hedging losses as prices move down and up. We understand that as much as 40 per cent of North American natural gas production may be hedged in 2010 at an average price of $6.15MMBtu.
Q: With regards to finding and development costs (economics), what is the range in terms of conventional gas and the newer unconventional sources such as the new Shale and Tight gas plays?
A: We have not updated our supply cost work since our analysis of 2007 costs. U.S. shale gas currently under development is occasionally reported to be accessible at costs of $4.00 to $5.00/MMBtu and that conventional gas under development tends to be in the $4.00 to $6.50 range. Of course, higher cost shale gas and conventional deposits exist, but these are not under active development under current pricing conditions.
Q: Lastly, what might be a few ‘black swans’ if you will that might sway the outlook (price, demand, supply) for natural gas dramatically in either a positive or negative direction?
A: Significantly higher levels of LNG imports into North America could cause prices to decline and thereby lead to lower drilling activity and less gas being produced within North America. Greater displacement of coal-fired power by natural gas either due to a price advantage or environmental constraints would tend to increase natural gas demand and thereby natural gas prices. Unpredictable events such as disruption of offshore production due to hurricanes or exceedingly hot or mild summer weather can also influence supply, demand and prices.
Thank you Paul!
Click Here To Read The Entire Report Entitled “The Energy Market Assessment (EMA) Short-term Canadian Natural Gas Deliverability, 2010–2012
{ 1 comments }
