The natural gas market “is severely out of balance,” and participants can expect to see prices during injection season near “the top end of a $5.00-8.00/MMBtu range,” according to Lehman Brothers equity research.
In a report on large cap oil and gas E&P companies released last Wednesday, Lehman analyst Thomas Driscoll lowered his view on the sector from “positive” to “neutral” and also lowered his recommendation on Apache Corp., EnCana Corp. and Newfield Exploration.
“Although we believe that the E&Ps represent a solid long-term value we believe that the near-term natural gas price movements could lead to further [stock] price weakness over the next seven to eight months,” Driscoll wrote.
Lehman lowered its 2006 forecast for gas prices to $7.75/MMBtu from $9/MMBtu and cut its oil price outlook to $60/bbl from $65/bbl. For the time being, Driscoll and company favor the stocks of producers focused on oil, such as Canadian Natural Resources, Talisman Energy and Occidental Petroleum. Other favorites, because of their “positive momentum,” are Noble Energy and, especially Kerr-McGee Corp.
“Our long-term bullish view on [the] group is underpinned by our view that current higher costs demand natural gas prices in the $8-10 range — the bear case is that customers will be unwilling/unable to pay the higher prices. The current natural gas demand weakness should give long-term bulls pause.”
While producer costs “have risen at an alarming rate the past few years,” Driscoll wrote that Lehman and others have concluded that extra costs would be passed on to and picked up by consumers. That is no longer a foregone conclusion. The current lack of demand “could be an enormous threat to the bull case for E&P stocks.”
Or maybe not. Had natural gas lost market share in step with weak weather-adjusted storage withdrawal rates, one could conclude customers will resist covering producers’ all-in costs. The trouble is, early winter price spikes and the high level of publicity they attracted, along with recent warm weather all serve to confuse the issue, Driscoll wrote. But the bearish signs are there for anyone to see.
“The storage overhang versus the five-year average is presently at a record high level of 691 Bcf. We believe that the gas market has several problems to deal with.”
One is that in order to end the upcoming injection season at historical levels, up to 8 Bcf/d of additional demand needs to materialize, Driscoll wrote. This includes about 3 Bcf/d of ongoing demand weakness and 3 Bcf/d of storage overhang. Add to that an expected half a Bcf of supply expected to be restored in the Gulf of Mexico and a summer liquefied natural gas surge of 1.0-1.5 Bcf/d above early 2006 import rates due to lower European demand.
At the end of this month, storage is likely to be 650-700 Bcf more than the five-year average for the end of February, according to Driscoll. That puts the industry on track to end withdrawal season (March 31) with storage about 200 Bcf above record levels. The Energy Information Administration reported last Thursday that 123 Bcf was removed from storage for the week ending Feb. 17. Last week storage stood at 2,143 Bcf, a record high for the date.
Over the next six months residual fuel oil may set the ceiling for gas prices, and coal may set the floor at about $5.50/MMBtu, according to Driscoll. “We believe that Nymex gas is likely [to] trade between $5.50-$7.00/MMBtu for several months unless crude oil prices move.”
In a Feb. 20 “Energy Insight” note, the Gerdes Group asked, “is fuel switching to natural gas in vogue again?” Since 2003, gas has generally been priced higher than residual fuel, Gerdes said, with the last period of sustained price inversion being in 2002. The group said that industrial demand for gas declined 1 Bcf/d during 2003 “in a markedly higher gas price environment” and attributed no more than half of that decline to fuel switching. “Overall, industrial/power generation fuel switching probably equates to 0.5-1.5 Bcf/d, or 1-2% of U.S. natural gas demand.
“Notably, a 1 Bcf/d increase in natural gas demand related to residual fuel switching would equate to roughly a 15% loss in U.S. residual demand,” the Gerdes note says. “A loss in residual demand that material is likely [to] have a meaningful negative impact on residual fuel prices, implying the likelihood of an iterative, or ‘soft,’ floor for natural gas prices attributable to fuel switching.”
While Driscoll conceded in his note that factors cited and their attached numbers “seriously overstates the supply-demand imbalance,” a demand deficit of even half of the potential 8 Bcf/d (about 16%) “is likely to have serious consequences for near term natural gas prices this summer.”
And others have noted softness on the demand side.
While the price spikes of late 2005 are gone they are not forgotten. “Several weeks of sub-$10 gas have eliminated most ‘price spike’ demand destruction but newly embedded conservation is now evident,” wrote analyst Stephen Smith, Stephen Smith Energy Associates, in a Feb. 20 report.
Smith also noted some other bearish signals in his report.
Hydro generation for the Columbia River Basin for the week of Feb. 16 was up 11% year over year and 8% sequentially. “For the first time in several years, the NWS [National Weather Service] is projecting an above-average water flow for January-to-July in the Columbia River Basin.”
Also for the week of Feb. 16, nuclear plant availability was up 0.2% year over year, but it was down 2.7% sequentially.
Smith was projecting a gas storage surplus of 804 Bcf as of Feb. 17, representing an increase of 605 Bcf over the past eight weeks. Blamed for this are heating degree days that were 22% lower than normal for the period as well as “slowing but still significant” net demand destruction effects, meaning that the demand destruction effects exceeded supplies shut in due to Hurricanes Katrina and Rita.
But colder weather is expected, and if Mother Nature delivers, “the surplus should decline by about 60 Bcf over the next two weeks (ending March 3) if this projected weather occurs as forecast.”
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