PCC Blog
As much international turmoil as we saw in 2011 in the crude oil markets (Egypt, Libya, Bahrain) and in the financial markets (Euro and the European Union), we do not see any less turmoil for 2012. As is usually true, some considerations will be bullish and some will be bearish for crude oil prices. The trick will be to recognize which considerations have the greatest impact on crude oil buyers and traders at any given time.
As usual, when we make a list of bullish considerations, turmoil in the Middle East is again #1. Iran will continue to agitate in Iraq and will continue to test the international community's limit to gain control of shipping lanes in the Persian Gulf and through the Strait of Hormuz. Iran will also continue to look for ways to destabilize the regime in Saudi Arabia and other Sunni strongholds in the Middle East. Iran's ambition to become a nuclear power and its clear advantage in conventional military power will keep the Middle East at the top of the list for years to come.
On the European front, the major powers within the European Union will wrestle withand with the issue of sovreign debt. Economists and politicians in Europe seem to have forgotten all the lessons of the 1930's and seem determined to use austerity measures to resolve these problems. Economic growth in Europe will be sluggish at best and European economies may well slide into another deep recession this year. Finally, major powers in Europe will work hard to maintain the Euro as a viable currency. Problems in Europe will keep crude oil buyers and traders on edge as a bearish consideration as the risk of economic recession will lead to further declines in demand for refined products.
Domestically, we saw substantial growth in U.S. NGL production as gas producers continued to aggressively expand natural gas production (primarily in Texas, Louisiana, and PA/WV). The year-to-year increases in gas production were 3-4 BCFD but domestic gas demand did not keep pace. The market maintained the supply/demand balance by backing out imports – both waterborne LNG imports and pipeline shipments from Canada. The “low hanging fruit” has been picked and U.S. gas producers will now be faced with increasing competition with each other. Until Q4 2011 weather turned very mild, we had forecast the meltdown in natural gas prices for 2013. We now expect significant bearish pressure to push gas prices in some regional markets below $3.00 per MMBtu for Q2 and Q3 2012.
NO SHORT COVER RALLY
In the October 12th blog post, we expressed concern that heavy short positions pointed to a short cover rally when the first cold weather spooked new short side speculators in the NYMEX natural gas contract. As the gas market developed during November & December, prices continued to fall in the Henry Hub cash market and on the NYMEX. Heating degree days showed temperatures were consistently warmer than the 30 year average (no surprise), warmer than the 10 year average, and were also warmer than in 2010.
Natural gas inventory in working storage posted weekly net injections until the last week of November. Typically, net injections into working storage swing to net withdrawals after the 1st or 2nd week of November. Furthermore, during the first two full weeks of December, net withdrawals were 45% below the 3-year average. Statistics have consistently pointed to a weak rally In the blog post of December 19, we highlighted the forecast for further erosion in natural gas prices and the growing likelihood of a price crash in 2013 and maybe as early as 2012.
Short side speculators were rewarded during November and the first half of December. Even as temperatures grow colder, production growth will persist but marketers already have 4 fewer weeks in which to liquidate inventory. IF Inventory withdrawals remain below average during January, marketers and producers will become acutely aware that 2 TCF may remain in storage at the end of winter. This winter could well be the beginning of the end with no short cover rally in cash market prices during January and a fire sale on natural gas inventory beginning in mid-February.
When historians write about the major developments in petroleum markets of 2011, they will be intrigued by the divergence and convergence of prices for the major crude oil price benchmarks. They will probably marvel at the simplistic explanation for the abrupt divergence of WTI prices versus all other global benchmarks. Various sources laid the basis for ever deeper pricing discounts for WTI at the feet of "surplus supply at Cushing, OK". This answer has to be dismissed as completely unsupportable because WTI pricing discounts were at their widest during August and September but crude oil inventory at Cushing had already declined 12 million barrels or 29% (30 million barrels at the end of September versus 42 million barrels at the end of March) during the previous 6 months.
As abruptly as price divergence emerged, prices began to converge equally abruptly. From a discount of almost $29 per barrel versus dated Brent in mid-September, WTI price discounts were less than $8 per barrel by mid-December. Again, nothing in the current market distribution system actually changed. However, WTI and dated Brent can be viewed as very indicators of the degree of optimism or pessimism for political, economic, and financial system trends in North America and Europe.
During the spring and summer, political gridlock in the U.S. prompted financially oriented traders to take a very pessimistic view of near term trends for the U.S. economy and U.S. financial institutions. Specifically, WTI prices dropped 11.2% in August but dated Brent prices declined only 5.8%. As these fears faded, financially oriented traders became less pessimistic and WTI prices rebounded strongly. Specifically, WTI prices increased 12.4% in November but dated Brent increased only 1.5%.
Trends in daily price changes during September through November (and continuing through mid-December) were remarkable for the speed of reconvergence. Throughout 2011, daily changes in prices were virtually all equal to or less than +/- 2%.
Presidential year election politics will move to the forefront as one of the most important variables for consideration by financially oriented traders. The trick in translating day to day developments on the campaign trail into meaningful indicators for trends in crude oil prices. We evaluate these and many other questions for clients who subscribe to "NGL Markets in North America".
From the simple perspective of Economics 101, when the supply of a good or service increases without an offsetting increase in demand, the price of the good or service will decline. Somehow, the natural gas futures market has suspended belief in the basic principles of economics. The NYMEX forward curve shows natural gas prices were about $3.10 per MMBTU for December 19, 2011 and will be $3.40-3.50 per MMBTU for mid-2012 and $3.80-4.00 per MMBTU by early 2013.
However, U.S. production increased 1.5-3.5 BCFD per year during 2008-2011 but demand increased enough to offset growth in production only during 2010. During 2008, 2009 & 2011, demand in U.S. markets was nearly flat and rising U.S. production reduced imports. Most of the "low hanging fruit" has already been picked and further significant reductions in imports will be more difficult to achieve. Furthermore, with U.S. GDP growth likely to be weaker in 2012, total gas demand is unlikely to increase in 2012 or 2013. Yet, gas exploration companies continued to aggressively increase production -- perhaps by "selling" future production into the NYMEX forward curve.
In Q1 2011, natural gas prices at Henry Hub, the Houston Ship Channel and the Chicago CIty Gate market were $4.20-4.40 per MMBtu. With 3-4 BCFD year/year growth in domestic production but almost no year/year growth in demand , natural gas prices dropped to $3.15-3.40 per MMBTU in November or 20-25% below Q1 price levels.
As natural gas prices fall, gas exploration companies aggressively increased production to maintain constant revenue and meet debt and payroll obligations. So far, the decline in prices has not discouraged gas producers and they have not yet begun to reduce exploration activity to avoid further downward pressures on natural gas prices.
How low will natural gas prices have to fall before gas exploration companies begin to make the necessary but painful reductions in gas exploration activity to avoid an extended period of weak gas prices? We answer these and many other important questions for clients who subscribe to “NGL Markets in North America”.
NOAA versus Farmers Almanac -- which one do you believe?
NOAA has published its forecast for winter 2011/2012. NOAA's #1 criteria for winter weather forecasts for 2011/2012 (temperature and precipitation) is the presence or absence of La Nina. La Nina is the term used to refer to below average sea surface temperatures in the south Pacific. Sea surface temperatures routinely oscillate between average or "normal", above average (El Nino) and below average (La Nina). La Nina conditions are correlated with mild winters and below average precipitation for some areas of North America. To hedge its bets, NOAA also cites the possible "wild card' of the Atlantic Oscillation.
In almost diametrical opposition, Farmers Almanac forecasts a very cold winter for the northern Rocky Moutains, northern Plains, and western Great Lakes. Winter temperatures for the eastern two thirds of the U.S. (excluding New England) will be above average but very wet -- mostly cold rain. Farmers Alamanc does not discuss La Nina effects in its forecast. FA had to go to press a few months ago and La Nina had gone into hibernation but has since resurfaced. Maybe FA forecasts would similar to NOAA if they were real time.
I have listened carefully to many meteorologists discuss forecasts for winter weather for many years. Here is what I know for sure.
- December and January will be colder than September and October -- everywhere exccept maybe southern California and south Florida.
- Cold fronts will be followed by warming trends -- a few days or a week of cold followed by a few days or a week of slightly warmer weather
- Other big picture variable like the Atlantic Oscillaion may or may not override the La Nina effects
- El Nino and La Nina conditions in the Pacific both tend to give North America a warmer than average winter.
- Weather forecasters have difficulty knowing why North America has colder than average winters but sometimes it does.
- Most weather forecasters rely heavily on correlation analysis and probability. No one seems to understand the true fundamentals other than in a very broad sense.
- We seem to care more about how cold the winter will be when natural gas inventory is below average. Since natural gas inventory now looks set to reach an all time record high by mid-November, most likely, most of us don't care how cold the coming winter will be except as it affects our plans for ski trips.
Maybe we ask for too much certainty in what is inherently very dynamic and uncertain. My personal favorite global climate variable is the Pacific Decadal Oscillation.
Managed Money Accounts
Speculative traders in the managed money segment have been consistently net short in the NYMEX natural gas contract for more than 2 years. So why should we concern ourselves about recent trends for this group of traders? We generally view this group of traders to be knowledgeable and rationale because they have sufficient risk to be reportable to the CFTC. During the past 16 weeks, the number of traders (or trading groups) who report short interest positions doubled. Most of the increase in the number of traders occurred duirng August and September.
During August and September, we note storage injection rates were above historic averages in every week except one. The surge in storage injection rates averaged 2 BCFD above the historic average. We suspect the surge in storage injection rates attracted many smaller managed money account players into the natural gas contract. With six weeks remaining in the storage injection season, we expect total inventory will, most likely, reach a peak of no more than 3.7 TCF. At this level, inventory in working storage will be 100-150 BCF below 2010 levels.
Weather will turn cold enough to require withdrawals from storage and a seasonal increase in imports from Canada. At this point, bearish supply/demand pressures will disappear and prices will rebound from current levels. How will new short side speculators react when prices are $1.00 per MMBtu higher than they are currently ? We look for short covering to add to bullish seasonal considerations -- probably during the last few trading days before Thanksgiving.
SUMMER HEAT:
The seasonal peak in demand for natural gas by electric power generating plants is one of the most predictable elements of the natural gas supply/demand balance. We need no special weather forecasts to know that July and August will be the hottest months of the year. During these two months, residential consumers will see their electricity consumption reach peak levels due to the extenstive use of air conditioning throughout the southeast, southwest and midwest. Demand in August is usually double demand in April. In the southest, June was as hot as July and August usually are, but EIA data showed demand in the electric power sector this year was 3% less than in 2010. The year-to-year decline in electric power sector demand June was a mild surprise -- especially since net storage injection rates in May and June were 0.4-0.9 BCFD lower than the average for 2008-2010.
OTHER FACTORS:
When the original hypothesis as to why storage injection rates were lower than expected, we naturallly looked at other factors. The year-to-year decline in total imports was the factor that stood out as accounting for the dip in storage injection rates. Total imports were about 0.5 BCFD lower than in 2010 in both May and June. Furthermore, total demand in residential/commercial and industrial markets was 1.5 BCFD higher in May 2011 than in May 2010. In June, total demand for the major market sectors was 0.35 BCFD lower than in 2010 and the increase in inventory was 0.41 BCFD higher than in 2010.
The biggest factor that accounted for total inventory this year persistently lower than in 2010 was the strong year-to-year increase in total demand in April. Demand in April was 4.2 BCFD higher than in April 2010. Consistent with this one-month bump in demand versus 2010, the net increase in inventory was 3.6 BCFD below 2010.
OUTLOOK FOR WINTER 2011/2012:
As a result of the cumulative impact of these factors, inventory at the end of June totaled 2.53 TCF and was 210 billion cubic feet lower than in 2010. Weekly inventory reports showed the year-to-year inventory deficit narrowed 130-150 BCF during July through early September. Nine weeks remain in the storage injection season and we continue to forecast inventory in working storage will reach a seaonal peak of 3.6-3.7 TCF by mid-November. One of the positive factors that supported inventory accumulation during the summer was the absence of major tropical storms or hurricanes in the Gulf of Meixco.
Natural gas prices in the cash market at Henry Hub and in the NYMEX contract are showing the effects of the shift to a more bearish perspective on the part of major buyers and big money speculative traders.
We provide insights into the whys and wherefores of the natural gas market and other important markets in North America in our ongoing consulting service -- NGL Markets in North America.
The trend in diesel fuel and juet fuel demand continue to support our view that economic growth in the U.S. remains on track although growth has been slower than we would all like to see. In Q2 2011, demand for diesel fuel was 50 thousand-bpd higher than in Q2 2010 -- a year-to-year increase of 1.3%. However, within Q2, demand fell 0.5% below 2010 volumes in April but was 3.8% above 2010 levels in June. We expect demand will post an increase of 3.25-3.75% for Q3 2011 but we look for slower growth in Q4.
Similarly, demand for jet fuel posted an increase of 2.4% for Q2 2011 versus 2010. We had concerns when jet fuel demand in Q1 2011 fell 1.5% below 2010 levels. The rebound in demand growth in Q2 is an encouraging sign and reinforces the positive signal from continued albeit slower growth in diesel fuel demand.
As we have highlighted for the past few months, "surplus inventory in Cushing" is probably not the primary factors that caused deep price discounts for WTI relative to virtually all other price benchmarks beginning in December 2010. As supporting evidence, we note EIA statistics in the Petroleum Supply Monthly (PSM) show inventory at Cushing declined 3 million bbl (7%) during April and May. Weekly statistics show inventory at Cushing declined by an additional 6 million bbl (16%) during June and July. Wet barrel crude traders are clearly using all available means of transportation to ship under-priced crude oil at Cushing to the Gulf Coast for resale at full market prices.
IF EIA weekly statistics are directionally correct and reasonably accurate, Cushing inventory levels are now as low as they were in October 2010 -- 3 months before WTI prices disconnected from other pricing benchmarks. We continue to suspect short selling by big money traders was the factor that sparked the WTI price disconnect.
If inventory liquidation at Cushing continues at the rates of the past 4 months, there will be no crude oil left by the end of Q1 2012.
Based on data published by the PA Department of Environmental Protection, natural gas production from Marcellus averaged 1.48 BCFD during July through December 2010. The PA DEP report provides production data for 36 counties. Production was concentrated in two areas. In northeast PA, production from Bradford, Susquehanna, and Tioga counties averaged 0.89 BCFD. In southwest PA, production from Greene and Washington averaged 0.37 BCFD.
As is true with other shale plays (and exploration in general), the trick is to find the sweet spots. PCC expects gas exploration companies to maintain a strong focus on these 5 counties for the next few years. However, increasing concern about the impact of fracturing operations on water quality and the potential for soil contamination will most likely slow the pace of growth in exploration activity and production.
WINTER WEATHER:
Heading degree days are the best measure of the severity of winter weather on a regional basis. Regional analysis is very important because demand in the residential/commercial market is concentrated in the Upper Midwest & Northeast. The Upper Midwest experienced about 4.7% more heating degree days during core months (Nov, Dec, Jan & Feb) of the winter of 2010/2011 and the Northeast experienced about 7.4% more heating degree days for the same core winter months.
RESIDENTIAL/COMMERCIAL DEMAND:
According to data published by EIA, residential/commerical demand in Nov averaged 25.1 BCFD and increased to 46.6 BCFD in Dec. PCC estimates demand averaged 47.5-48.0 BCFD in Jan and 45.5-46.5 BCFD in Feb -- based on heating degree days. Demand averaged 27.1 in Q4 2010 (10.5% higher than year-earlier volumes). PCC estimates demand averaged 42.1 BCFD (1% higher than year-earlier volumes) in Q1 2011. Based on total volume, demand during Q4 2010 and Q1 2011 was 270-275 billion cubic feet more than during Q4 2009 & Q1 2010. Based on the year-year increase in residential/commerrical demand alone, total withdrawals of natural gas from storage would likely be 0.20-0.25 TCF above average.
INDUSTRIAL/ELECTRIC POWER DEMAND:
Demand in the industrial sector is marginally seasonal & demand in the electric power sector is generally contra-seasonal. According to data published by EIA, industrial demand & electric power demand averaged 38.8 BCFD in Q42009 // Q!2010 and was 40.2 BCFD in Q42010 // Q1 2011. Total demand in winter 2010/2011 was 254 BCF higher than in the previous winter.
NATURAL GAS INVENTORY IN WORKING STORAGE:
According to EIA weekly survey data, Inventory in working storage reached a peak of 3.843 TCF in mid-November. During a typical winter, inventory withdrawals of 2 TCF supplement production and imports to meet peak winter demand. During the winter 2010/2011, demand was 0.53 TCF higher than during the previous winter heating season. The year-year increase in demand would normally be expected to total 2.5-2.55 TCF -- a significantly larger cumulative withdrawal of natural gas from working storage versus recent years. During this winter, however, withdrawals totaled 2.23 TCF. Furthermore, inventory in the producing region reached its seasonal low in mid-February and began to increase thereafter. PCC expects total injections to storage to be average or above average during April 1 through Nov 15 and forecasts inventory in working storage to increase to 3.80-3.85 TCF or equal to the record high volume of 2010. PCC also expects domestic natural gas production to continue to increase during 2011.
NATURAL GAS INVENTORY IN WORKING STORAGE:
Well head natural gas prices varied from a minimum of $3.64 per MMBtu to a maximum of $4.42 per MMBtu in Jan but prices declined to $4.23 in Feb. The min/max variance of $0.78 per MMBtu compares with a variance of $2.67 per MMBtu for the previous winter. Will natural gas prices decline during Apr/May/Jun? How will the hurricane season impact natural gas production in the Gulf of Mexico? How much will natural gas prices increase during Aug/Sep if the eastern Gulf of Mexico has tropical storms and hurricanes? PCC answers these and many other important questions in NGL Markets in North America,
We present this brief review of pricing history to document the timing of the shift in pricing relationships between WTI crude oil and various other pricing benchmarks. Various information sources attribute these pricing divergences to completion of Keystone Phase II. Keystone Pipeline is a TransCanada crude oil pipeline project that originates at Hardisty in northern Alberta and will ultimately extend to Port Arthur, TX. Keystone will enable delivery of bitumen/diluent blend from Alberta's oil sands to refineries in the Gulf Coast. Keystone Phase II is the segment of the Keystone Project the extends the system from Steele City, NB to Cushing, OK.
Before September 2010, prices for WTI at Cushing, OK were at their typical premiums of $0.50-2.00 per barrel vs. dated Brent. From early September through the end of December, WTI prices were persistently discounted by $0.50-2.50 per barrel - a swing of $1.00-4.50 per barrel from typical price relationships. Although WTI/dated Brent pricing differentials diverged from their historically normal range during Q4 2010, pricing differentials between WTI and other domestic and international benchmarks remained within their historic ranges. However, the discount for WTI versus dated Brent widened to $5-7 per barrel during January 2011 and then jumped to $12-14 per barrel during February 2011. During this period, pricing relationships between WTI and nearly all other domestic and international benchmarks also diverged.
During Q4 2010, the relationship between WTI, dated Brent prices diverged well before crude oil began to flow through Keystone Phase II. To evaluate the veracity of conclusions that pricing differentials diverged entirely or primarily due to pumping crude oil into Keystone Phase II for line fill purposes, we have to evaluate trends in Canadian crude oil exports, crude oil inventory in Cushing and the Mid-Continent, refinery crude runs in the Mid-Continent and the overall crude oil supply/demand balance in the Mid-Continent.
First, Canada exports 1.8-2.0 million-bpd of crude oil into the U.S. each and every day. However, NEB statistics indicate most Canadian crude oil exports move into the Mid-Continent but 200-400 thousand-bpd of Canadian crude moves to refineries in the northeast and Pacific Northwest. According to EIA statistics from the Petroleum Supply Monthly Canadian crude oil shipments into the Mid-Continent averaged 1.23 million-bpd during Q4 2010 and were 28 thousand-bpd less than in Q4 2009.
EIA weekly statistics showed total imports into the Mid-Continent increased to 1.32 million-bpd in January and 1.34 million-bpd in February (based on three weeks of data for Feb). The cumulative increase in imports (based on weekly statistics) was 4.92 million barrels. However, EIA statistics for inventory at Cushing showed a net decline of 53 thousand barrels. Effectively, none of the increase in Canadian imports into PADD II increased crude oil inventory in storage at Cushing.
Finally, a review of Mid-Continent crude oil supply/demand balances also reveals interesting trends. First, refinery crude oil inputs averaged 3.3-3.4 million-bpd during December through February versus 3.15 million-bpd during October and November. Demand for crude oil was 185 thousand-bpd higher during the period when WTI prices diverged from global crude oil prices. Furthermore, after accounting for domestic production in the Mid-Continent at 735 thousand-bpd, the Mid-Continent crude oil supply shortfall averaged about 1.1 million-bpd. All of the Mid-Continent crude oil supply shortfall has to be imported into the Gulf Coast from international sources.
With prices for 1 million-bpd of international supply at a price premium of $11-14 per barrel, the flow of supply into the Mid-Continent from the Gulf Coast should decline during the next few months and crude oil inventory in the Mid-Continent should decline significantly.
Why would anyone sell crude oil worth $110 per barrel into a market where prices are $95 per barrel? More importantly, why would refinery crude oil buyers in the Mid-Continent pay $110 per barrel when they can buy up inventory in the Mid-Continent for $95 per barrel?
We routinely evaluate these and other topics of interest in NGL Markets in North America.
The big boys (Goldman Sachs, Morgan Stanley, Deutche Bank, etc.) called for WTI prices to reach $100 per bbl in 2011 in February 2010. Even though crude oil prices were well below levels that would encourage a view this bullish, we have to pay attention when serious money talks.
After the financial crisis in Greece, crude oil prices fell sharply during May 2010 and we didn't hear the steady beat of bullish drums until late in the year. Instead, during May through August 2010, crude oil prices were range bound in the $70-80 per bbl range. Prices broke out of this established trading range in September and we've seen what the bullish view is capable of doing. We note that WTI prices reached $90 per bbl despite bearish trends in U.S. crude inventory, seasonally bearish trends in U.S. refinery crude runs and nominally bearish seasonal trends in gasoline supply/demand balances. Despite all these "bearish" factors, big money private traders in the NYMEX became unrelentingly bullish. They hardly paused to have Thanksgiving dinner with their families and must have hired personal shoppers to do Christmas shopping.
We note that China experienced significant shortages of diesel fuel in 2010 (perhaps beginning in Aug/Sep). U.S. refining companies began to aggressively export distillate fuel oil in the second half of 2010. Although EIA weekly statistics provide a reasonable view of trends in domestic supply/demand balances for crude oil and the major refined products, EIA does not, as yet, publish any detailed break-out of U.S. exports of refined products. From an analytical perspective in the current environment, we need weekly details on exports of distillate fuel oil in particular. U.S. refineries in the Gulf Coast and West Coast will become much more internationally focused during the coming years and a 2 month lag in export statistics is no longer acceptable.
Based on our current analysis of global crude oil production and demand, we see three important trends. First and probably most important, the key crude oil exporting countries in the Middle East (Saudi Arabia, Kuwait, and U.A.E ) continue to maintain reasonable strict production discipline. Second, the rate of decline in North Sea production has seemingly accelerated and supported very strong premiums for date Brent vs. WTI since September 2010. Finally, based on reports of demand growth in China, China by itself has the capability to increase global demand by 1 million bpd -- unless declining demand in North America and Europe is enough to offset -- and the nascent economic recovery make this unlikely during 2011-2012.
Finally, in the detailed CFTC statistics on the NYMEX crude contract, we see further reason to remain bullish for WTI prices for the first half of 2011. Swap dealers, who represent pension fund money, were historically and consistently net long. This class of NYMEX traders, however, shifted into net short positions during Q4 2010. Perhaps, pension fund money will remain on the sidelines due to the risk of significant declines in prices if/when large private money traders decide to liquidate long postions and take profits.
We forecast WTI NYMEX prices to reach a $100 per barrel average by April or May 2011.
EIA weekly statistics showed natural gas inventory in working storage reached a peak of 3.84 TCF in mid-Nov. While we recognize final EIA statistics sometimes vary from weekly statistics by as much a 100-200 BCF, weekly statistics were in close agreement with final statistics for end of Aug and Sep. While this volume was a new record high for mid-Nov, inventory levels in 2009 did not peak until the last week of Nov and also totaled 3.84 TCF.
Since 2000, withdrawals from working storage totaled a low of 1.5 TCF and a high of 2.32 TCF with a median of 2 TCF. For winter 2010/2011, based on a cumulative withdrawal of 2 TCF, inventory remaining in working storage on March 31 will total 1.5-1.8 TCF. The record high volume of natural gas remaining in storage on March 31 was 1.69 TCF (March 2006) and inventory remaining in storage was 1.66 TCF for March 2009 and March 2010. Unless winter 2010/2011 is significantly colder than last year, we expect a new record high volume on March 31 -- our most likely case is 1.75 TCF.
The plentiful supply of natural gas in storage will tend to keep natural gas prices in check in most regional markets except the northeast city gate markets. We look for natural gas prices at Henry Hub to succumb to significant bearish pressures as early as mid-Feb and we definitely expect to see falling prices before the end of March. There is some chance prices could begin to fall before the end of Jan.
Finally, bearish pressures on wellhead prices and market prices in the Houston Ship Channel, Henry Hub, NYC city gate will be more intense during Q2 2011 than during Q2 2010. For more information on our consulting services and details on the outlook for trends in natural gas markets and prices, contact Daniel Lippe, principal consultant, at 713.977.0114.
Another thought occurred to me -- if diesel fuel demand tell us interesting things about the domestic economy, should we consider jet fuel demand as a similar economic indicator. Diesel fuel demand, after all, represents only the hard goods component of the U.S. economy. The U.S. economy is now substantially driven by services and other soft goods elements. Jet fuel demand trends reflect both business and leisure travel and both forms of travel reflect real world trends in the soft components of the U.S. economy. As is true with diesel fuel demand, we can track trends in jet fuel demand in almost real time with little concern for the constant revisions that occur in federal government statistics on financial measurements of total GDP.
What did historic trends in jet fuel demand tell us ? First, jet fuel demand trends showed signs of softening as early as the second half of 2005. Demand dropped four consecutive months (Aug through Nov) in 2005 vs. 2004. In 2006, demand was lower vs. 2005 for three of four quarters and was 0.4% lower for the year overall. Demand in 2007 was nearly flat -- but as was true with diesel fuel demand, demand was significantly lower in 2008 in every single month and the year-to-year decline in demand averaged 5.7% in Q3 2008 and 12.5% in Q4 2008. Demand continued to decline at 10-12% on a year over year basis for the first half of 2009 but the rate of decline slowed to only 5% in Q3 2009 and 4% in Q4 2009. Jet fuel demand did not show any sustained recovery until early in 2010. In Q2 2010, demand was 3.8% higher than in 2009 but remained 185 thousand-bpd or 11% lower than in 2007. The sluggish recovery in jet fuel demand tends to confirm other indications that economic recovery is weak and sluggish.
We routinely address these and other issues of importance to producers, midstream companies and petrochemical companies in NGL Markets in North America.
We have an endless flow of economic news but the best indicator comes from petroleum industry statistics published by EIA -- diesel fuel demand. When goods have to be shipped from manufacturer to consumer, the trucking industry does its job and consumes diesel fuel in the process. Consistent with the slide into economic recession, diesel fuel demand began to flatten out during the 2nd half of 2007. In January 2008, demand went into a deep and sustained decline. Year over year, diesel fuel demand declined for 23 consecutive months (Jan 2008 through Nov 2009).
Demand began to recover in March 2010. Year over year growth averaged 6.45% for Q2 2010 and 6.4% for Q3 2010. For Q4 2010, we expect demand to increase 3-4% vs. 2009.
The most important advantage for using diesel fuel demand as an economic indicator is its timeliness. We use EIA weekly statistics to determine monthly demand in near real time. In contrast, most other economic statistics from the federal government are not as timely and are subject to revisions.
WTI prices averaged $75.14 per barrel for September vs. $76.61 per barrel for August. In August, for 22 trading days, prices increased only 7 days (32%) and declined 15 days (68%). The daily increases averaged 1.68% and the daily declines averaged 1.38%. Bearish and bullish influences very nearly offset each other during August but the slight bullish edge yielded an increase in the monthly average price for the third consecutive month.
In September, however, for 23 trading days, prices increased 12 days (52%) and declined 11 days (48%). The daily increases averaged 1.64% and the daily declines averaged 0.98%. From this perspective, price trends in September were, on balance, more bullish than in August but the monthly average price for September was $75.15 per barrel or $1.46 per barrel (1.9%) below the average for August.We note that the bullish trend of July continued into the first two trading days of August and pushed prices to a 3 month high of $82.59 per barrel. The "on balance" bearish trend during August pushed prices to a low of $71.71 per barrel on the last trading day of the month.
From a purely domestic perspective, considering bearish fundamentals and the established trading zone ($70-80 per barrel), WTI prices were near the upper end of the trading range and seem poised to fall by $8-10 per barrel during October/November. We note, however, that dated Brent prices jumped to an average premium of $2.70 per barrel for September. Furthermore, spot Dubai/Oman prices recovered to near parity versus WTI in September after being consistently priced at discounts of $1.50-3.75 per barrel for the previous 3 months. We have to recognize, however, that the purely domestic perspective is no longer the only perspective that influences near term trends in WTI Prices. Specifically, from a global perspective, fundamentals are less bearish and other considerations (e.g., trends in the Euro/USD) are more bullish for WTI prices. Finally, in the immediate term for Q4, geopolitics are perhaps more of an enigma than during the past 90 to 120 days.
Have crude oil prices finally turned the corner and are they poised to break out of the established trading range ?
We answer these and many other questions about crude oil and refined products for clients who subscribe to NGL Markets in North America.
The mere mention of the phrase -- Bakken shale -- conjures and facinates oil and gas exploration companies and exasperates shale skeptics. In 2005, for 7 counties in Bakken shale country in ND, crude oil production averaged 33 thousand-bpd. In Q2 2010, according to ND Industrial Commission's oil and gas division, oil production in these same 7 counties averaged about 210 thousand-bpd. The seven-fold increase in oil production in this area is the tip of the iceberg for continued increases in crude oil production from the Bakken formation in the Williston Basin -- but only IF exploration into expanded areas of the Bakken formation is as successful as we have seen during the past 5 years.
On another note, many midstream companies have joined the shale gas frenzy. The oil & gas exploration industry's foray into shale exploration is still in its infancy and exploration may encounter obstacles and challenges in extracting the anticipated very large volumes of very rich gas from the array of shale formations in North America. Nature does not give up her bounty so easily. For example, while crude oil production from the 7 county region in ND continues to increase, natural gas production from these same 7 counties was 12-14% lower in Apr and May 2010 versus year-earlier volumes. However, we are cautious to become pessimistic on rich gas production in ND because the most current data points tend to be revised upwards as producers submit revised and corrected production data to the regulatory agency in ND.
Finally, 5 years of exploration activity yielded 181 thousand-bpd of additional crude oil production and 148 MM Cfd of additional gas production in the 7 country region. Major midstream infrastructure commitments have been made that are premised on gas production reaching levels that 10 to 20 times current production levels within the next 5 years. As an industry, we may need to temper our enthusiasm with a moderate dose of caution.
We submitted our current composite wellhead gas price forecasts to the Natural Gas Week Price Forecast Scoreboard. The Scoreboard for Q3 will be published in the July 26th issue:
Q3 2010: $4.80 per MMBtu
Q4 2010: $4.30 per MMBtu
FY 2010: $4.60 per MMBtu
FY 2011: $4.50 per MMBtu
Commentary: Gas prices for Aug/Sep are forecast to move to $5.00-5.50 per MMBtu based on expected tropical storm and hurricane activity in the Gulf of Mexico. However, with onshore production continuing to grow, the impact of storms in the Gulf of Mexico will have less impact than in 2005 and 2008. Furthermore, inventory accumulation so far has bee in line with expectations and peak inventory in working storage is on track to peak at 3.8 TCF. We note that EIA's final inventory number for the end of April was 2.01 TCF and was almost 100 BCF higher than April 2009 -- itself a record high for the end of April. Further, demand in the electric power generation sector during March/April was below expectations and March was almost 10% below year-earlier volumes. Temperatures in the Gulf Coast were moderate during the first half of July and power generation demand is likely to be below bullish expectations for the peak demand months of Jul/Aug.
As we move out of hurricane season and inventories continue to build to a new record high, we see the bullish camp pulling up stumps and the bearish camp taking control of price trends during late Sep through early Dec. Even if winter 2010-11 is as cold as 2009-10, inventories will again most likely become a major bearish consideration for Q1 2011.
Prices for all major global benchmark crudes rose gradually but steadily during late January through the end of April. The bullish trend pushed WTI prices to a weekly average of $84.10 per barrel during the week of April 26. The bullish trend ended abruptly in early May and prices fell almost $15.00 per barrel (about 18%) during the first three weeks of May. We note that fundamental considerations became increasingly bearish during the 3 month bullish trend but the market clearly ignored bearish fundamentals. Crude traders with a financial/currency orientation generally have a bullish view of WTI prices when the Euro strengthens against the USD. This trend in the currency markets came to an abrupt end when the Greek financial crisis threatened to push the European Union into crisis. During the first half of May Euro values dropped relative to the USD. During this period, prices for WTI as well as other major benchmarks fell sharply.
The bearish correction ran its course within three weeks and a modest recovery boosted WTI prices to almost $80.00 per barrel before the end of June. Fundamentals for all global benchmarks, however, became increasingly bearish. Control of price trends is likely to swing between financially oriented traders and fundamental traders for the next six to twelve months. We expect to see a bearish bias in crude oil price trends for the remainder of 2010.
Prices for all major global benchmark crudes rose gradually but steadily during late January through the end of April. The bullish trend pushed WTI prices to a weekly average of $84.10 per barrel during the week of April 26. The bullish trend ended abruptly in early May and prices fell almost $15.00 per barrel (about 18%) during the first three weeks of May. We note that fundamental considerations became increasingly bearish (rising inventories in the U.S. and at Cushing, OK and rising U.S. crude oil production) during the 3 month bullish trend but the market clearly ignored bearish fundamentals until early May. Our evaluation led us to conclude that other factors tipped crude oil prices into a bearish trend.
Crude traders with a financial/currency trading orientation generally have a bullish view of WTI prices when the Euro strengthens against the USD. This trend in the currency markets came to an abrupt end when the Greek financial crisis threatened to push the European Union into crisis. During the first half of May Euro values dropped relative to the USD. During this period, prices for WTI as well as other major benchmarks fell sharply.The bearish correction ran its course within three weeks and a modest recovery boosted WTI prices to almost $80.00 per barrel before the end of June. Fundamentals for all global benchmarks, however, became increasingly bearish. Control of price trends is likely to swing between financially oriented traders and fundamental traders for the next six to twelve months.
Will the bearish bias continue to dominate trends in crude oil price trends for the remainder of 2010?
We answer these and many other questions about crude oil and refined products for clients who subscribe to NGL Markets in North America.
Before Q4 2007, demand for ethane in the ethylene feedstock market in the U.S. Gulf Coast was limited by supply. Ethane prices routinely yielded variable ethylene production costs that were 1-3 ¢ per lb premiums to costs based on light paraffinic naphtha. During 2007, midstream companies constructed 4 large gas plants in Wyoming and Colorado. These plants were based on state of the art processing technology and were deep cut ethane recovery plants. When these plants started up, gas plant ethane recovery in Wyoming and Colorado began a period of sustained growth that persisted through the present day.
The increase in ethane recovery flowed via NGL pipeline grid into Mont Belvieu. Since Q4 2007, ethane markets in Mont Belvieu and the Gulf Coast at large were no longer supply limited but were demand limited. The swing from a supply limited market had the predictable bearish impact on prices. Since Q4 2007, variable ethylene production costs based on ethane were consistently lower than costs based on propane and light paraffinic naphthas.
This fundamental change in the ethane supply/demand balance caused buyers and sellers to adjust their day to day behavior. In today's ethane market, no one wants to accumulate ethane inventory.
Sellers want to sell every gallon of ethane production every day. Buyers now purchase only what they need this month -- secure in the knowledge that ethane supply will remain plentiful next month and the month after ....
As with all markets in transition, plentiful ethane supply at attractive prices prompted knowledgeable ethylene producers to retrofit naphtha plants with substantial ethane cracking capability .. the pendulum will eventually swing the other way .. the key question is when ...
We answer these and many other questions about ethane, other natural gas liquids, and petrochemicals for clients who subscribe to NGL Markets in North America.
