Electric Charge
On April 7 and 8, I attended the annual Energy Information Administration (EIA) conference in Washington, DC. The conference was expanded this year to a celebration of the agency’s 30th year as the statistical arm of the US Dept of Energy.
In reviewing my notes, it quickly became clear that a key topic was the outlook for the global electricity generation industry. More specifically, many of the sessions focused on the growth outlook for coal, nuclear power and natural gas and how to most effectively slake the world’s surging demand for electricity in an efficient, cost-effective manner. The outcomes of these debates have wide-ranging investment implications.
A related matter widely discussed both in the organized sessions and among attendees was the likely effect of proposed environmental and climate change legislation in the US and abroad. Opinions on the existence and urgency of climate change vary, and it’s certainly not my role to comment on that issue.
But as investors, we can’t afford to ignore the implications of the global push toward carbon-dioxide regulations. Furthermore, we can continue to profit from the regulatory changes currently underway.
As resistance from environmental groups increases and uncertainty regarding carbon trading continues, the coal market is shifting to a more international focus. Rapidly growing demand for coal exports from the US market is offsetting any decline in domestic demand. See Coal Goes International.
The UK has been enormously successful in hitting its greenhouse gas reduced emission targets, as laid out in the Kyoto Protocol agreement, by switching from coal- to gas-fired plants. The US is likely to follow. See The UK Example.
LNG has created the opportunity for more gas fields to become viable natural suppliers, thanks to increased transport and storage availabilities. Depleted gas reservoirs in the US are also great storage facilities. See Buying LNG.
I already hold several gas plays in the The Energy Strategist portfolios. However, one has grown too expensive, so I’m replacing it with a new play on unconventional North America drilling. See Playing Gas.
Although natural gas seems the best short-term solution for power supply, nuclear power has gained increasing support. I have exposure to this area through the uranium field bet. See Nuclear Renaissance.
I’m selling one of the Gushers Portfolio holdings because it’s already priced in the best-case scenario regarding takeover rumors. However, several of my recommendations appear to have more room to grow, so I’m raising their buy targets. See Portfolio Update.
I’m recommending or reiterating my recommendation in the following stocks:
One of the speakers at that session was Eugene Grecheck, vice president of nuclear development for Dominion Energy, one of the largest electric utility firms in the US. Dominion has around 2.4 million customers in Virginia and North Carolina, 1.2 million in Ohio and another 1.6 million customers for its unregulated operations. Dominion’s choice of new electric generating capacity offers a reasonable proxy of the choices being made all over the US at this time.
Dominion’s largest single market is Virginia, a state seeing rapid growth in electric power demand. In fact, Virginia’s power grid is already in a deficit; power demand at peak demand periods exceeds Virginia’s total generating capacity, forcing the state to import large amounts of power from neighboring states.
In fact, Virginia is second only to California in terms of electric power imports. Dominion and grid operator PJM estimate that, by 2017, Virginia’s power gap will grow an additional 4,000 megawatts (MW) for a total of more than 5,000 MW.
This isn’t a horrible problem as long as importing power is reasonably cheap and neighboring states on the same grid have power available for export. But with excess generating capacity shrinking, importing electricity is going to continue to get more expensive.
Electricity conservation can certainly help reduce power demand. And as prices rise, the incentives to conserve more also rise. However, the idea that conservation is a complete, long-term solution to Virginia’s energy shortage is absolutely ridiculous.
Consider that much of the growth in the commonwealth’s electricity demand is coming from technology industry growth in Northern Virginia. The Dominion representative pointed out that, in Loudoun County alone, there have been proposals for 20 new data centers.
Data centers are banks of computers and servers requiring reliable baseload power. These data centers require access to power supplies 24 hours a day, seven days a week.
According to Dominion, every data center requires 40 to 80 MW of baseload generating capacity. So the 20 data centers would require baseload capacity equal to one large-scale nuclear power facility.
Given that level of power demand growth, Dominion must build new capacity in Virginia to maintain electric reliability. The only question is: What type of capacity should it build?
Dominion already has plans to add about 4,200 MW of new generating capacity by 2015. Planning new plant construction isn’t a short-term process; projects must be planned years in advance.
There are some issues. First, on a pure price basis, Dominion would probably look to grow its coal plant capacity. After all, natural gas currently trades at more than $10 per million British thermal units (MMBtu), compared to coal at less than $4 per MMBtu. However, building a new coal plant is a tough decision to make in the current environment.
Most utilities believe the US will eventually impose some sort of tax or carbon-trading scheme. But no one can offer any degree of certainty as to what form that cap-and-trade system will take and exactly how much carbon credits will cost.
It’s tough to make the decision to build a new plant, which is designed to last 30 years or more, without being able to make a legitimate economic estimate on the operating cost of that plant. Uncertainty over greenhouse gas (GHG) legislation is making it extraordinarily difficult for US utilities to make decisions on new plant construction.
Dominion has plans to build only one new coal plant, the Virginia City Hybrid Energy Center, located in southwestern Virginia. Dominion made it extraordinarily clear there’s no way it would have decided to build this plant at its current location without the state government’s intervention in the process.
The plant isn’t located near a river; water is typically used to cool power plants, and the lack of nearby water sources is an issue. In addition, the plant is located far away from any major center of consumption.
But this particular coal plant was actually legislated into existence primarily as a means of encouraging economic development in a less-developed part of the state. Virginia has offered economic assistance for the plant. But despite these factors, Dominion has encountered significant resistance from environmental groups regarding the construction of the plant.
Back to In This Issue
Even more important from a demand standpoint is growth in demand for coal across the developing world. China became a net importer of coal in 2007 for the first time in history, and coal imports are only going to grow. Consider that China builds a new large-scale, coal-fired plant once every week and adds generating capacity every year equal in size to the entire electric capacity of the UK.
As you can imagine, rapidly growing demand for coal exports from the US market is offsetting any decline in demand as new US coal-fired plant projects are canceled. According to Arch Coal, US coal net exports should grow from around 59 million tons in 2007 to about 80 million this year. (See the Nov. 7, 2007, issue, Coal and Services, and the Sept. 5, 2007, issue, Australia, Asia and Coal, for more-detailed rundowns on the bullish international story for coal.)
One of the more unfortunate side effects of environmental opposition to new US coal plants is that the plants being blocked are new generation supercritical and ultra-supercritical facilities. Allowing older facilities to be replaced by newer plants would reduce the pollution caused by coal-fired power. However, when new plants are blocked, utilities are forced to try to boost output from existing facilities, which actually increases pollutant emissions.
The efficiency savings from modern facilities isn’t inconsequential. Check out the table below for a closer look.
Source: The Future of Coal: Options for a Carbon-Constrained World, Massachusetts Institute of Technology, 2007.
This chart contains data adapted from a recent MIT study on the future of coal-fired generation. The data compared the efficiency of three types of pulverized coal (PC) plants. The main difference between each type is the temperature and pressure of the steam used to drive turbines in the facility. The table is based on a 500-MW coal plant burning standard Illinois No. 6 coal.
Generating efficiency is a measure of how effectively a plant converts energy in coal to electricity; the higher the number, the more efficient the plant. Note the difference between older-style, subcritical PC plants and the most modern ultra-supercritical plants is large. The efficiency ratio is nearly 10 percentage points higher. That means more modern plants consume far less coal to produce the same amount of energy.
To quantify that even further, note the ultra-supercritical, 500-MW plant consumes 44,000 kilograms (97,000 pounds) less coal per hour than the referenced subcritical plant.
As longtime readers are aware, it’s not my place to comment on the importance, speed or need to regulate carbon-dioxide (CO2) emissions. However, it’s obvious governments the world over are planning to regulate CO2, including the US.
Carbon is also the cause celebre for many environmental groups. Therefore, no matter how you may feel about the concept of global warming, you can’t afford to ignore the investment implications of new carbon regulation.
The most efficient plant in the table above produces nearly 100,000 kilograms (220,000 pounds) less carbon dioxide per hour than an older-style, subcritical plant, with absolutely no use of carbon capture and sequestration (CCS) technologies. Nonetheless, this line of reasoning has little traction with environmental and consumer groups that oppose new plant construction. Therefore, building even the most efficient coal plants is problematic for utilities such as Dominion.
But what’s bad for the environment is a big positive for coal demand. The US will continue to rely on the existing base of coal-fired facilities; the average coal plant is already about 30 years old. These plants burn more coal to produce the same measure of electricity. According to several panelists at the EIA conference, there will likely be increased utilization of the coal-fired industry. That’s a fancy way of saying that utilities will run their existing, older plants harder.
I don’t see the wave of coal plant cancellations as an impediment to further upside in coal prices and stocks of coal mining firms. Rather, growth in coal-fired capacity in the developing world will offset any plant construction delays in the US. And every coal plant that’s canceled or blocked in the US spells more coal burned in older coal-guzzling plants.
Back to In This Issue
One of the really striking points about Dominion’s presentation at the EIA conference is just how much natural gas-fired capacity it’s planning to build. Natural gas plants emit roughly half as much carbon dioxide as coal plants to produce the same amount of energy. And natural gas plant technology is well understood; building new plants is relatively quick and cheap.
With new coal capacity in the US basically off the table, only nuclear and gas are real options for utilities as forms of baseload power. As I detail later in this issue, utilities, including Dominion, are moving with nuclear plant construction projects.
But these are long-term projects, and the first new reactors won’t be coming online until 2015 at the absolute earliest. That leaves gas as the only remaining carbon-friendly technology out there that can be put into service quickly. And gas plants are exactly what utilities are building.
But the rush to gas as a carbon-reducing technology is really nothing new. Numerous presenters at the EIA conference made reference to the experience of the UK, one of the clear stars of the Kyoto Protocol agreement. The UK example offers a decent roadmap for what will likely unfold in the US over the next decade as long as the threat of more-stringent carbon regulation remains.
According to the UK Office for National Statistics, total UK GHG emissions were off more than 9 percent between 1990 and 2005, the latest year for which the office provides data. (See the chart “UK Greenhouse Gas Emissions.”)
Source: UK Office for National Statistics
The UK’s official Kyoto target was for a 12.5 percent reduction in GHG emissions from 1990 levels by 2012. According to the most recent estimates, published in a white paper dated February 2008, the UK will likely exceed that target, reducing overall GHG emissions by 25 to 30 percent between 1990 and 2012. In fact, according to some estimates, the UK exceeded its Kyoto Protocol targets before it even signed the deal.
The key to the UK’s Kyoto success hasn’t been the wide-scale implementation of renewable and alternative generation technologies. Nor has the reduction come as a result of decreased emissions from the transportation industry: According to the National Statistics data, GHG emissions from that industry actually rose more than 61 percent between 1990 and 2005.
Instead, the success comes from the simple replacement of coal-fired power plant capacity with natural gas-fired capacity since the late 1980s. Check out the chart “UK Electricity Consumption.”
Source: UK Dept for Business Enterprise & Regulatory Reform (BERR)
UK electricity consumption has risen from about 75 million metric tons of oil equivalent per year in 1989 to just under 87 million tons in 2006, an increase of 12 million tons. Over the same time period, coal consumption dropped by 13 million tons per year.
To meet new electricity demand and offset falling coal-fired output, the UK needed to add about 25 million tons of additional capacity from other sources. It should come as little surprise that the nation added more than 26 million tons of gas-fired capacity over the same time period.
Also helping the UK to reduce GHG emissions has been a reduction in the use of coal in manufacturing operations, replaced largely by natural gas.
According to the British government’s February energy white paper, this trend is projected to continue. By 2020, the UK is projected to need 367 terrawatt-hours of electricity supply, down from around 399 terrawatt-hours in 2006. Of that total, more than 53 percent is expected to come from gas-fired plants, up from 36 percent projected for 2010. Gas is far and away the fastest-growing source of power under the assumptions of this white paper.
As Dominion’s presentation at the EIA conference made abundantly clear, the US is following the UK’s lead on this issue. Increasing natural gas consumption is the only near-term means of reducing GHG emissions while still meeting growing energy needs.
But there’s one difference between the US and UK gas markets: The latter has, until very recently, been energy independent in gas. Check out the chart “UK Gas Production and Consumption” for a closer look.
Source: BP Statistical Review of World Energy
Thanks to Britain’s prolific North Sea natural gas production, it was possible to rapidly ramp up gas capacity in the ’90s without having to worry about imports. But that’s changing fast because the North Sea is now maturing and gas production is falling.
In 2004, the UK became a net importer of natural gas, and by 2006, the nation imported some 10 million metric tons of oil equivalent natural gas. This import demand will continue to increase as North Sea production continues its decline. Several liquefied natural gas (LNG) terminals are already being opened to help satisfy this demand and supplement volumes delivered via pipeline.
The US hasn’t traditionally been energy independent in the gas market; however, taken as a whole, North America has been. Unfortunately, as I explained at some length in the March 19 issue, Gas over Oil, Canadian gas exports to the US are likely to fall in coming years. Canada will use more gas domestically, particularly in oil sands recovery operations. Meanwhile, production in Canada’s traditional fields appears to be declining.
US unconventional reserves (see the Feb. 20 issue, Growing Unconventionally) will grow and help make up for declining production from other regions of the US. However, this growth won’t be enough to offset growing demand.
The bottom line: The US will become more dependent on LNG imports in coming years. (For those unfamiliar with that technology, see the Oct. 24, 2007, issue, Liquid Gold.)
To summarize, LNG is nothing more than a super-cooled version of natural gas. When gas is cooled to around minus 260 degrees Fahrenheit (minus 162 degrees Celsius), it condenses into a liquid.
Better still, as gas cools, it takes up less space; LNG takes up roughly one-six-hundred-and-tenth the volume of gas in its natural gaseous state. To put that into context, a beach ball-sized volume of gas shrinks to the size of a standard pingpong ball when it’s converted to LNG.
The benefit of this is transport. Traditionally, the vast majority of natural gas has been transported in its normal gaseous state by pipeline. So most natural gas consumed in the US was either produced domestically or imported by pipeline from neighboring Canada.
By extension, gas reserves located far from existing pipeline infrastructure had little or no value. Although oil from such fields can be loaded onto tankers and shipped anywhere in the world, gas was considered stranded. Stranded natural gas was routinely burned (flared) or reinjected into the ground as a form of permanent storage.
LNG frees gas from the pipeline grid. If you’re able to turn natural gas into a liquid, it can be loaded onto tankers just like crude oil and transported anywhere in the world. Gas reserves once considered stranded and useless can be exploited using LNG technologies.
Back to In This Issue
The first point worth noting is that the limitation on global LNG trade growth isn’t a lack of LNG tankers or terminals for receiving gas. Rather, the real problem is available liquefaction capacity. Importing countries have sufficient capacity to handle gas imports, but exporting nations simply can’t grow their capacity to produce and liquefy gas fast enough to meet demand.
Most panelists agreed that LNG trade would continue to grow at roughly a 7.5 percent to 8 percent rate through at least 2012-13, after which growth could slow. Note that this growth represents a trend continuation since the early ’90s: Trade in LNG is growing faster than global natural gas demand.
That 2012-13 time frame is roughly the period when major new liquefaction projects underway in the Middle East, Australia and elsewhere are scheduled for completion. Once these projects are complete, the source of new gas supply looks murkier.
Although overall trade in LNG is likely to continue to grow faster than gas demand for the foreseeable future, what’s really interesting is how the nature of LNG contracts is shifting. In the early years of LNG trade, most natural LNG was traded under long-term supply agreements. That meant importing countries would agree to accept a certain quantity of gas delivered on a regular basis at a certain prearranged, fixed price or a price related to some visible index level.
Spot LNG cargoes—basically, one-off shipments on LNG sold at prevailing market prices—were only a tiny portion of the overall market. But the spot market is growing rapidly today.
Consider that, in 1997, short-term LNG trades accounted for only 0.5 million tons per year in LNG trade, roughly half of 1 percent of total LNG trade at the time. In 2002, that figure had grown to 8.4 million tons, 8 percent of total LNG trade for that year. And by 2007, that figure ballooned to 30 million tons per year in short-term trades; that’s about 17 percent of total LNG trade in 2007.
This figure likely underestimates the importance of the short-term LNG trade. Even so-called long-term LNG contracts are becoming shorter in duration, and new contracts have relaxed destination clauses.
This offers more flexibility for cargoes intended for a particular market to be diverted elsewhere. Some countries, such as Algeria, have allowed long-term LNG supply contracts to expire; these nations clearly believe that they can realize more value from their exports by selling and trading the gas on the spot market.
What’s starting to emerge is a far-more-flexible market for LNG cargoes. BG noted in 2007 a large jump in the number of LNG cargoes it had intended to sell in the Atlantic Basin that ended up being diverted to gas-hungry Asian markets. Producers with LNG cargoes have considerable flexibility in diverting cargoes to target whichever markets are most attractive on a price basis.
BG also noted that it’s not yet seeing a large-scale global convergence in LNG prices. Instead, arbitrage opportunities are actually rising. This is great news for BG because it has the flexibility to divert cargoes to far-away markets where the firm is able to sell gas at a premium.
What’s also becoming clear is that the US is, and will remain, a crucial market for LNG. The reason is simply that the US market is large and highly liquid. If a producer can find no other market for its LNG, the US market is a great last resort where prices are highly visible.
Moreover, the US has large gas storage infrastructure. LNG cargoes exported to the US during periods of low gas demand can be stored temporarily for use later when demand is higher.
Storing natural gas typically involves injecting the gas into natural geological formations such as depleted gas reservoirs. The US has a number of such fields available.
But that’s not the case in many parts of Asia. This makes it tough for the region to build out storage capacity even though such storage is in high demand. Therefore, LNG and the US have become sort of gas storage facilities for the world.
Strong growth in LNG capacity and shorter-term trading patterns all adds up to one thing: LNG is becoming a more and more influential factor in the North American natural gas market. LNG cargoes can adjust quickly to changes in price around the world and shift the supply/demand balance quickly.
A perfect example occurred last spring, when a sudden collapse in UK gas prices resulted in a quick shift in cargoes to the US market. According to BG, the whole shift took less than six weeks. The result of the shift was a glut in US gas supplies and a rapid drop in US natural gas prices.
On a shorter-term basis, BG’s comments were even more interesting. The company stated that it believes the EIA’s forecasts for US LNG imports in 2008 are troubled. The representative noted that the BG hadn’t imported a single LNG cargo into the US since Oct. 4. The company also suggested that a planned shipment scheduled for next month was likely to be diverted as long as US prices continue to trade at a discount to prices in Europe and Asia. (See the chart “US and UK Natural Gas Prices.”)
Source: Bloomberg
This commentary adds to my conviction that 2008 will be a big year for gas prices. Currently, the EIA is forecasting that the US will import 680 billion cubic feet (bcf) of gas this year in the form of LNG, down just 12 percent from last year’s record levels. But BG has suggested that this estimate is overly optimistic, especially given global gas price trends; US supply will be tighter without those LNG imports.
Back to In This Issue
I’ve highlighted several plays on rising natural gas prices in recent issues of TES. In particular, I prefer producers with growing production potential and access to promising unconventional reserves, such as EOG Resources and XTO Energy—both holdings in the Wildcatters Portfolio. I covered both firms at length in the Feb. 20 issue.
Since that time, both firms have performed well. I’m looking to hear more positive news from EOG when it reports earnings in early May. In particular, there’s considerable excitement surrounding the potential for the company’s newly discovered gas reserve in British Columbia.
The play is similar geologically to the Barnett Shale gas play of Texas and, according to EOG, could contain upward of 6 trillion cubic feet in reserves. British Columbia recently reported record sales of oil and gas leases in the province, nearly doubling the previous annual record set in 2003-04.
I also expect to hear more about EOG’s strong oil production growth from its Bakken Shale reserves in the US.
XTO Energy has also been busy. Most recently, the company announced the purchase of Marcellus Shale acreage from fellow Wildcatters Portfolio recommendation Linn Energy for $600 million. As noted in two flash alerts last week, I see this as a positive deal for both companies.
XTO has the capacity to spend heavily on drilling in the region to exploit this promising play. Meanwhile, Linn received a large amount of cash that gives it firepower for future acquisitions of mature reserves elsewhere that fit better with its overall strategy.
As noted above, BG Group remains the premier pure play on exploding growth in LNG trade and the scope for arbitrage in gas prices. In addition, as I noted in the March 5 issue, The Final Frontier, BG holds a 25 percent stake in Brazil’s exciting Tupi field, one of the largest deepwater fields ever discovered.
And Brazil recently announced another exciting discovery—the Carioca oil field in the Santos Basin. Santos is the same basin where the Tupi field was discovered.
Initial reserve estimates leaked by Brazil’s National Petroleum Agency were up to 33 billion barrels of oil in the field. Since that time, Petrobras and others have sought to control enthusiasm, stating that more drill tests would be necessary to confirm those reserves.
However, it’s clear this is a major discovery, perhaps even larger than Tupi. And BG has a 30 percent stake in this oilfield. I’m boosting my buy targets slightly for both BG Group and XTO Energy to 130 and 68, respectively.
I’m making one more change to my gas play recommendations this issue: Sell Gusher Portfolio holding Quicksilver Resources for a profit of more than 115 percent since my initial recommendation last summer.
Quicksilver’s reserves in the Barnett Shale remain highly attractive; however, the stock has gotten too expensive relative to its peer group, trading at 24 times cash flow, compared to 11.8 times for EOG and 9.1 times for XTO. Based on 2008 earnings estimates, Quicksilver also looks expensive, trading on 37 times estimates against 18 times for EOG and 18.5 times for XTO.
I’m adding Canadian exploration and production (E&P) firm Talisman Energy to the Gushers Portfolio this issue as a replacement for Quicksilver. Talisman isn’t a pure play on natural gas or the North American market. However, the company is making the shift from a conventional oil and gas producer to targeting fast-growing unconventional plays.
Under a new CEO, I expect Talisman to see a significant uptick in production growth over the next few years. This will propel the stock.
For 2007, roughly 42 percent of Talisman’s production came from North America, with another 33 percent from the North Sea. North American production is weighted in favor of natural gas, which accounted for more than three-quarters of 2007 production. In contrast, North Sea production is close to 90 percent crude oil, mainly the most valuable light crude oil.
In North America, Talisman has traditionally focused its attention on the Western Canada Sedimentary Basin (WCSB), the prime conventional natural gas play in Canada. As I explained the Feb. 20 issue, conventional gas production in North America is declining, and such reserves generally simply don’t offer the growth potential of unconventional plays.
Unconventional oil and gas plays are simply reservoirs that can’t be produced using traditional technologies. Through a combination of horizontal drilling techniques and fracturing, these reserves are prolific. Because of the company’s less-than-stellar production growth and relatively high costs, Talisman has lagged most of its peer group focused on unconventional North American plays.
Last September, Talisman hired new CEO John Manzoni and is in the middle of a strategic review of its acreage. We should hear more concerning the outcome of that strategic review at the upcoming earnings release at the end of this month and an in-depth analyst meeting scheduled for May 21-23.
Most likely, the company will announce its plans to develop several unconventional plays it owns but hasn’t fully exploited. The list of plays includes about 800,000 acres of land in the Appalachian Basin of the US. This region includes an area known as the Marcellus Shale.
Readers will recognize that XTO purchased acreage in this exact same region from Linn Energy last week. So far, only a few producers have drilled wells in the region. But early results are positive, and the area also benefits from close to consuming markets such as New York. Talisman already has plans to drill six test wells in the region for 2008, but that development plan could easily be accelerated.
I’ve highlighted the potential of the Bakken Shale oil play before in TES. This shale play is primarily in the US; however, part of the play extends into southeastern Saskatchewan. Talisman has about 100,000 acres in this area. Oil production growth from Bakken has been impressive for other producers in the region.
The Montney gas field in Alberta and British Columbia, the Utica Shale of Quebec, and the Outer Foothills of British Columbia and Alberta are three more promising gas plays where Talisman owns significant acreage and likely plans significant drilling activity.
And there’s another catalyst for Talisman in Canada near term: The producer owns significant acreage in an Alberta deep gas play. Producers are drilling wells as long as 6,000 meters (18,000 feet) to produce this gas effectively.
Although this is a highly promising reserve, Talisman, along with other producers, cut back capital spending plans sharply in the region after the Alberta government made changes to its royalty regime. These changes hiked the royalty rates producers were required to pay on deep gas fields, rendering production from such fields uneconomic.
But on April 11, Alberta backtracked on those planned changes, set to go into effect Jan. 1, 2009. The government announced it was making changes to the new royalty framework to offset unintended consequences. Basically, drilling activity dropped off so quickly in Alberta the regional government realized higher royalty rates meant lower royalties for their coffers.
Deep gas plays such as those owned by Talisman where a specific area in which the government is altering its royalty structure to encourage development and capital spending. I suspect that, in light of these changes, Talisman will boost its capital spending plans in the region. This would be a positive move for the stock.
And although North American unconventional reserves are perhaps Talisman’s most exciting prospects, don’t ignore international growth potential. The firm has $2 billion in capital spending planned for the North Sea, about $1.14 billion for the UK and the remainder for Norway.
The list of projects includes some exploration spending, redevelopments of older fields, and appraisals and tests for wells Talisman has already identified. Five projects came online in 2007, and Talisman has plans for six more in 2008 and 2009.
Talisman believes that fields in the region remain underdeveloped. The company has the opportunity to re-enter existing fields and increase production. And because there’s significant oil and gas processing, storage and pipeline capacity in the region, expenses are relatively low. Overall, Talisman is looking for 45 percent production growth between 2007 and 2009.
And the company is increasing its capital spending in Southeast Asia to $765 million from $585 million last year. Exciting, high-growth potential projects are underway in Vietnam, Malaysia and Indonesia. Buy Talisman Energy under 24.
Back to In This Issue
By and large, comments at the EIA conference were supportive of nuclear. On the second day of the conference, I expected Sen. Pete Domenici (R-NM) to make comments broadly in support of nuclear power in the US; after all, Domenici authored an outstanding book on nuclear power’s potential, entitled “A Brighter Tomorrow: Fulfilling the Promise of Nuclear Energy.”
I was also pleased to hear Sen. John Dingell (D-MI) come out strongly in support of nuclear power during his keynote address. Dingell stated that the future is dark without such power. These comments suggest that nuclear is getting some support from both sides of the proverbial aisle.
On a more practical front, while gas has been the favored near-term solution to power capacity needs, nuclear has received some serious attention. For example, Dominion noted that, back in 2001-02, most utilities weren’t even seriously considering new nuclear capacity additions. In fact, they were so concerned that investors would punish their shares for even considering nuclear that most formed industry consortiums to investigate the technology without appearing outwardly interested. However, a series of changes to the process and procedures for licensing new plants and some new incentives have encouraged a second look at nuclear power.
Dominion was also careful to point out that no new reactors have been built since the ’70s, and the permitting process is still unproven. Moreover, the upfront capital costs for building new plants are huge even for the nation’s largest, most-experienced utilities. Therefore, nuclear loan guarantees will likely be necessary to encourage the construction of first few plants.
Nonetheless, Dominion looks to be among the first utilities that will actually build a new reactor in the US at its existing North Anna site. The company stated, however, that on a best-case scenario this new reactor would unlikely be put into service before 2015.
Because nuclear power plants produce no air pollution of any sort, they’re an ideal longer-term solution to satisfy global power needs and meet environmental regulations. Natural gas will be the bridge between the present and a time when the world can start constructing a new generation of nuclear plants.
After a big run-up in the first half of 2007, my nuclear field bet picks—mostly pure-play uranium mining firms—have been broadly weak over the past nine months. The main driver of that weakness has been a slump in the uranium spot price from more than $130 per pound in June 2007 to its current level of less than $70 per pound.
But remember that the spot market isn’t particularly important in uranium; most contracts are negotiated as longer-term, multi-year supply deals. Temporary increases in spot supply or drops in demand can have an outsized effect on spot prices that doesn’t reflect positive underlying fundamentals.
In this case, the main driver of weakness in spot prices has been the retreat of speculative hedge and investment funds from the uranium spot market. Speculative activity likely softened when the credit crunch began to hit last July. In addition, most utilities are well covered in terms of short-term supplies and have no need to enter the spot market right now.
But longer term, supplies look shaky. Mine production in 2007 was again far lower than global demand; this situation will only get worse as new plants come online and look for fuel.
Meanwhile, although a number of new uranium production projects have been announced, several have been delayed or have encountered real difficulties in ramping up to full capacity. I’m not convinced that global supply growth is assured.
Although we may still not be at an absolute bottom, I firmly believe that uranium prices will remain elevated in coming years and that new plant construction will overwhelm mined supply. Now is a good time to buy up a position in my uranium field bet recommendations.
However, remember my field bet concept. Uranium mining is a risky business. Production delays, unforeseen project cost, and simple labor and raw materials inflation can all have important effects on the economics of a particular mining project. And production costs vary wildly depending on the grade of ore mined and how large overall reserves are.
Riskier still is exploration. Uranium explorers buy acreage and drill holes, taking core samples to evaluate reserve size and ore grades.
Sometimes even the most-promising reserves just don’t pan out and can never reach economic production. It’s impossible to know this for sure until you’ve spent considerable sums on exploration; only once uranium is produced can we really know for sure the full costs and viability of a project.
To account for this higher level of risk, I’m recommending that risk-tolerant investors take a more diversified approach to playing the junior uranium E&P companies. Remember, no matter how careful your selection criteria, some promising uranium exploration stories will never work out.
Fortunately, there are high rewards to be found in this sector as well. Famed mutual fund manger Peter Lynch used to look for what he called ten-baggers—companies with the potential to earn investors 1,000 percent or more on their investment. Obviously, you don’t need many ten-baggers to make a solid return and make up for the inevitable losing plays.
If my bullish thesis on uranium prices and nuclear power is even half correct, I suspect there will be many ten-baggers among the uranium juniors during the next few years.
For the best chance at big returns, I recommend casting a wide net. Instead of just buying one or two high-risk names, I recommend placing a smaller amount in five to 10 such companies. Keep in mind that this is designed as a multi-year play; you should keep position sizes small.
Back to In This Issue
Peabody Energy (NYSE: BTU)—This Wildcatter has seen a nice run-up over the past several weeks and hit a new high earlier this week after the company reported first quarter earnings. It broadly beat analysts’ expectations for the quarter, but the more important aspect of the report was its raised forecast for full-year 2008 earnings to $2.20 to $3 per share; that compares favorably to analysts’ estimates for $1.99 per share.
Peabody is actually the second coal miner to report blowout earnings. Arch Coal reported better-than-expected results and raised its guidance one day before Peabody.
As I noted earlier, the international market remains key to Peabody’s growth. The company noted it’s signed more deals to export coal in the first three months of 2008 than it had in the prior two years combined. The company also pointed out that global coal inventories remain low and there’s an accelerating build-out of coal-fired capacity globally, necessitating higher US exports.
Clearly, Peabody is taking steps to ensure it can profit from rising demand for export coal. Earlier this week, the miner announced it’s increasing its ownership stake in the Dominion Terminal Association coal export terminal in Newport News, Va. This move will allow Peabody to export more coal from the US East Coast.
But that’s not to say that Peabody isn’t benefiting from higher prices in the US as well. As coal exports pick up, US utilities have to offer higher prices to secure supplies. As a result, Peabody announced it’s been contracting coal at prices 37 percent higher than last year from its core Powder River Basin (PRB) mines.
Although Peabody is currently trading slightly above my buy target, the firm remains my favorite play on a tightening global coal market. Buy Peabody Energy on any dip below 65.
MacArthur Coal (Australia: MCC)—First recommended in the Sept. 5, 2007, issue MacArthur Coal is now up 128 percent from that recommendation. The firm makes a form of pulverized coal used in steel production. The most recent catalyst for a rally is swirling speculation that the firm will be taken over; the company confirmed it’s been approached recently.
Founder Ken Talbot owns 24 percent of the company and has stated publicly he’d be willing to sell his stake at a substantial premium. China-based investment group Citic owns a near 20 percent stake and is also rumored to be interested in a full takeover, most likely as part of a partnership with a Chinese coal miner. Mining giants Anglo American and Xstrata are also rumored suitors.
A series of small Australian miners has been taken over in recent years, and MacArthur would be a valuable prize because it controls a third of the market for pulverized coal injection (PCI) coal used in steelmaking. This commodity is in high demand across Asia.
MacArthur may have more upside in a takeover bid; however, the recent surge in the stock has priced in a good measure of upside potential. As a result, I’m selling MacArthur Coal from of the Gushers Portfolio for a 128 percent profit.
Hercules Offshore (NYSE: HERO)—Hercules is a shallow-water contract driller heavily exposed to the Gulf of Mexico natural gas drilling market. (For a full explanation of my rationale behind this pick, see the Feb. 6 issue, Earnings on Tap.)
The driller’s recent rig status reports indicate that the day-rates for Gulf of Mexico jackups are stabilizing. This is likely because of rising gas prices have triggered renewed interest in drilling activity. Hercules reports earnings on May 1; I expect management to make some bullish comments about rig demand and day-rates. I’m raising my buy target for Hercules Offshore to a buy under 30.
Schlumberger (NYSE: SLB)—This oil services company is currently not in the TES portfolios, although it rates a buy in the How They Rate Table. Longtime readers know I see Schlumberger as an outstanding indicator on the health of the energy industry and, therefore, eagerly await its quarterly earnings releases. (I last analyzed the stock in the Feb. 6 issue.)
I’ll offer a more detailed update of the firm’s most recent quarterly report in the upcoming issue of TES. For now, the tone of this quarter’s call was significantly more bullish and upbeat than for the company’s third and fourth quarter 2007 calls. The company seemed to reaffirm continued strong growth outside the US. Even better, Schlumberger indicated that margins and growth in the long weak North American business are turning for the better.
My favorite play in oil services remains Weatherford International (NYSE: WFT), a stock that’s handily outpaced the other services names in recent months. I’m raising my buy under target on Weatherford International to 85.
Acergy (NSDQ: ACGY)—I offered a detailed rationale for this Wildcatters Portfolio holding in the March 5 issue. The company remains my favorite play on the deepwater boom.
Acergy’s recent earnings release suggests the firm is continuing to build a solid backlog of projects in core regions such as West Africa and Brazil. Acergy is now a buy under 27.50.
Back to In This Issue
In reviewing my notes, it quickly became clear that a key topic was the outlook for the global electricity generation industry. More specifically, many of the sessions focused on the growth outlook for coal, nuclear power and natural gas and how to most effectively slake the world’s surging demand for electricity in an efficient, cost-effective manner. The outcomes of these debates have wide-ranging investment implications.
A related matter widely discussed both in the organized sessions and among attendees was the likely effect of proposed environmental and climate change legislation in the US and abroad. Opinions on the existence and urgency of climate change vary, and it’s certainly not my role to comment on that issue.
But as investors, we can’t afford to ignore the implications of the global push toward carbon-dioxide regulations. Furthermore, we can continue to profit from the regulatory changes currently underway.
In This Issue
Dominion Energy is seeing a large increase in baseload electricity demand, in large part because of the growing technology industry in Northern Virginia. In order to maintain reliability, it needs to build additional capacity. See New Baseload Electric Capacity.As resistance from environmental groups increases and uncertainty regarding carbon trading continues, the coal market is shifting to a more international focus. Rapidly growing demand for coal exports from the US market is offsetting any decline in domestic demand. See Coal Goes International.
The UK has been enormously successful in hitting its greenhouse gas reduced emission targets, as laid out in the Kyoto Protocol agreement, by switching from coal- to gas-fired plants. The US is likely to follow. See The UK Example.
LNG has created the opportunity for more gas fields to become viable natural suppliers, thanks to increased transport and storage availabilities. Depleted gas reservoirs in the US are also great storage facilities. See Buying LNG.
I already hold several gas plays in the The Energy Strategist portfolios. However, one has grown too expensive, so I’m replacing it with a new play on unconventional North America drilling. See Playing Gas.
Although natural gas seems the best short-term solution for power supply, nuclear power has gained increasing support. I have exposure to this area through the uranium field bet. See Nuclear Renaissance.
I’m selling one of the Gushers Portfolio holdings because it’s already priced in the best-case scenario regarding takeover rumors. However, several of my recommendations appear to have more room to grow, so I’m raising their buy targets. See Portfolio Update.
I’m recommending or reiterating my recommendation in the following stocks:
- Acergy (NSDQ: ACGY, Norway: ACY)
- BG Group (OTC: BRGYY)
- EOG Resources (NYSE: EOG)
- Hercules Offshore (NYSE: HERO)
- Paladin Resources (Australia: PDN, TSX: PDN, OTC: PALAF)
- Peabody Energy (NYSE: BTU)
- Pitchstone Exp. (TSX V: PXP, OTC: PEXPF)
- Talisman Energy (NYSE: TLM, TSX: TLM)
- UEX Corp (TSX: UEX)
- UNOR (TSX V: UNI, OTC: ONOFF)
- Uranium One (TSX: UUU, OTC: SXRZF)
- Uranium Participation Corp (TSX: U, OTC: URPTF)
- Uranium Resources (NSDQ: URRE)
- Weatherford International (NYSE: WFT)
- XTO Energy (NYSE: XTO)
- MacArthur Coal (Australia: MCC; OTC: MACDF)
- Quicksilver Resources (NYSE: KWK)
New Baseload Electric Capacity
One of the lectures I attended at the 2008 EIA conference in early April was titled “New Baseload Generation: Coal or Nuclear?” But judging from the presentations at the meeting, the short-term choice in new power plant construction appears to be between natural gas and nuclear, rather than coal and nuclear.One of the speakers at that session was Eugene Grecheck, vice president of nuclear development for Dominion Energy, one of the largest electric utility firms in the US. Dominion has around 2.4 million customers in Virginia and North Carolina, 1.2 million in Ohio and another 1.6 million customers for its unregulated operations. Dominion’s choice of new electric generating capacity offers a reasonable proxy of the choices being made all over the US at this time.
Dominion’s largest single market is Virginia, a state seeing rapid growth in electric power demand. In fact, Virginia’s power grid is already in a deficit; power demand at peak demand periods exceeds Virginia’s total generating capacity, forcing the state to import large amounts of power from neighboring states.
In fact, Virginia is second only to California in terms of electric power imports. Dominion and grid operator PJM estimate that, by 2017, Virginia’s power gap will grow an additional 4,000 megawatts (MW) for a total of more than 5,000 MW.
This isn’t a horrible problem as long as importing power is reasonably cheap and neighboring states on the same grid have power available for export. But with excess generating capacity shrinking, importing electricity is going to continue to get more expensive.
Electricity conservation can certainly help reduce power demand. And as prices rise, the incentives to conserve more also rise. However, the idea that conservation is a complete, long-term solution to Virginia’s energy shortage is absolutely ridiculous.
Consider that much of the growth in the commonwealth’s electricity demand is coming from technology industry growth in Northern Virginia. The Dominion representative pointed out that, in Loudoun County alone, there have been proposals for 20 new data centers.
Data centers are banks of computers and servers requiring reliable baseload power. These data centers require access to power supplies 24 hours a day, seven days a week.
According to Dominion, every data center requires 40 to 80 MW of baseload generating capacity. So the 20 data centers would require baseload capacity equal to one large-scale nuclear power facility.
Given that level of power demand growth, Dominion must build new capacity in Virginia to maintain electric reliability. The only question is: What type of capacity should it build?
Dominion already has plans to add about 4,200 MW of new generating capacity by 2015. Planning new plant construction isn’t a short-term process; projects must be planned years in advance.
There are some issues. First, on a pure price basis, Dominion would probably look to grow its coal plant capacity. After all, natural gas currently trades at more than $10 per million British thermal units (MMBtu), compared to coal at less than $4 per MMBtu. However, building a new coal plant is a tough decision to make in the current environment.
Most utilities believe the US will eventually impose some sort of tax or carbon-trading scheme. But no one can offer any degree of certainty as to what form that cap-and-trade system will take and exactly how much carbon credits will cost.
It’s tough to make the decision to build a new plant, which is designed to last 30 years or more, without being able to make a legitimate economic estimate on the operating cost of that plant. Uncertainty over greenhouse gas (GHG) legislation is making it extraordinarily difficult for US utilities to make decisions on new plant construction.
Dominion has plans to build only one new coal plant, the Virginia City Hybrid Energy Center, located in southwestern Virginia. Dominion made it extraordinarily clear there’s no way it would have decided to build this plant at its current location without the state government’s intervention in the process.
The plant isn’t located near a river; water is typically used to cool power plants, and the lack of nearby water sources is an issue. In addition, the plant is located far away from any major center of consumption.
But this particular coal plant was actually legislated into existence primarily as a means of encouraging economic development in a less-developed part of the state. Virginia has offered economic assistance for the plant. But despite these factors, Dominion has encountered significant resistance from environmental groups regarding the construction of the plant.
Back to In This Issue
Coal Goes International
In addition to environmental resistance and uncertainty about carbon taxes, there are other shifting factors in the coal market. One, as noted on multiple occasions in TES, is that coal is shifting from a domestic-focused market to an internationally driven story. Although it may be problematic to build new coal plants in the US, there are still a few under construction. And America’s vast fleet of existing plants still needs reliable fuel sources.Even more important from a demand standpoint is growth in demand for coal across the developing world. China became a net importer of coal in 2007 for the first time in history, and coal imports are only going to grow. Consider that China builds a new large-scale, coal-fired plant once every week and adds generating capacity every year equal in size to the entire electric capacity of the UK.
As you can imagine, rapidly growing demand for coal exports from the US market is offsetting any decline in demand as new US coal-fired plant projects are canceled. According to Arch Coal, US coal net exports should grow from around 59 million tons in 2007 to about 80 million this year. (See the Nov. 7, 2007, issue, Coal and Services, and the Sept. 5, 2007, issue, Australia, Asia and Coal, for more-detailed rundowns on the bullish international story for coal.)
One of the more unfortunate side effects of environmental opposition to new US coal plants is that the plants being blocked are new generation supercritical and ultra-supercritical facilities. Allowing older facilities to be replaced by newer plants would reduce the pollution caused by coal-fired power. However, when new plants are blocked, utilities are forced to try to boost output from existing facilities, which actually increases pollutant emissions.
The efficiency savings from modern facilities isn’t inconsequential. Check out the table below for a closer look.
|
Old versus New
|
|||
|
Subcritical PC
|
Supercritical PC
|
Ultra-Supercritical PC
|
|
| Generating Efficiency (HHV) | 34.3 | 38.5 | 43.3 |
| Coal Feed (Kg/Hr) | 208,000 | 185,000 | 164,000 |
| Carbon Dioxide Emitted (Kg/Hr) | 466,000 | 415,000 | 369,000 |
| Total Plant Cost (USD/KW) | 1,280 | 1,330 | 1,360 |
This chart contains data adapted from a recent MIT study on the future of coal-fired generation. The data compared the efficiency of three types of pulverized coal (PC) plants. The main difference between each type is the temperature and pressure of the steam used to drive turbines in the facility. The table is based on a 500-MW coal plant burning standard Illinois No. 6 coal.
Generating efficiency is a measure of how effectively a plant converts energy in coal to electricity; the higher the number, the more efficient the plant. Note the difference between older-style, subcritical PC plants and the most modern ultra-supercritical plants is large. The efficiency ratio is nearly 10 percentage points higher. That means more modern plants consume far less coal to produce the same amount of energy.
To quantify that even further, note the ultra-supercritical, 500-MW plant consumes 44,000 kilograms (97,000 pounds) less coal per hour than the referenced subcritical plant.
As longtime readers are aware, it’s not my place to comment on the importance, speed or need to regulate carbon-dioxide (CO2) emissions. However, it’s obvious governments the world over are planning to regulate CO2, including the US.
Carbon is also the cause celebre for many environmental groups. Therefore, no matter how you may feel about the concept of global warming, you can’t afford to ignore the investment implications of new carbon regulation.
The most efficient plant in the table above produces nearly 100,000 kilograms (220,000 pounds) less carbon dioxide per hour than an older-style, subcritical plant, with absolutely no use of carbon capture and sequestration (CCS) technologies. Nonetheless, this line of reasoning has little traction with environmental and consumer groups that oppose new plant construction. Therefore, building even the most efficient coal plants is problematic for utilities such as Dominion.
But what’s bad for the environment is a big positive for coal demand. The US will continue to rely on the existing base of coal-fired facilities; the average coal plant is already about 30 years old. These plants burn more coal to produce the same measure of electricity. According to several panelists at the EIA conference, there will likely be increased utilization of the coal-fired industry. That’s a fancy way of saying that utilities will run their existing, older plants harder.
I don’t see the wave of coal plant cancellations as an impediment to further upside in coal prices and stocks of coal mining firms. Rather, growth in coal-fired capacity in the developing world will offset any plant construction delays in the US. And every coal plant that’s canceled or blocked in the US spells more coal burned in older coal-guzzling plants.
Back to In This Issue
The UK Example
But the problems inherent in siting and constructing new coal facilities in the US have an even more important implication: Natural gas demand is set to rise sharply in most developed countries for the foreseeable future. In fact, I suspect gas demand will rise faster in the US and European Union (EU) than the EIA projects.One of the really striking points about Dominion’s presentation at the EIA conference is just how much natural gas-fired capacity it’s planning to build. Natural gas plants emit roughly half as much carbon dioxide as coal plants to produce the same amount of energy. And natural gas plant technology is well understood; building new plants is relatively quick and cheap.
With new coal capacity in the US basically off the table, only nuclear and gas are real options for utilities as forms of baseload power. As I detail later in this issue, utilities, including Dominion, are moving with nuclear plant construction projects.
But these are long-term projects, and the first new reactors won’t be coming online until 2015 at the absolute earliest. That leaves gas as the only remaining carbon-friendly technology out there that can be put into service quickly. And gas plants are exactly what utilities are building.
But the rush to gas as a carbon-reducing technology is really nothing new. Numerous presenters at the EIA conference made reference to the experience of the UK, one of the clear stars of the Kyoto Protocol agreement. The UK example offers a decent roadmap for what will likely unfold in the US over the next decade as long as the threat of more-stringent carbon regulation remains.
According to the UK Office for National Statistics, total UK GHG emissions were off more than 9 percent between 1990 and 2005, the latest year for which the office provides data. (See the chart “UK Greenhouse Gas Emissions.”)
Source: UK Office for National Statistics
The UK’s official Kyoto target was for a 12.5 percent reduction in GHG emissions from 1990 levels by 2012. According to the most recent estimates, published in a white paper dated February 2008, the UK will likely exceed that target, reducing overall GHG emissions by 25 to 30 percent between 1990 and 2012. In fact, according to some estimates, the UK exceeded its Kyoto Protocol targets before it even signed the deal.
The key to the UK’s Kyoto success hasn’t been the wide-scale implementation of renewable and alternative generation technologies. Nor has the reduction come as a result of decreased emissions from the transportation industry: According to the National Statistics data, GHG emissions from that industry actually rose more than 61 percent between 1990 and 2005.
Instead, the success comes from the simple replacement of coal-fired power plant capacity with natural gas-fired capacity since the late 1980s. Check out the chart “UK Electricity Consumption.”
Source: UK Dept for Business Enterprise & Regulatory Reform (BERR)
UK electricity consumption has risen from about 75 million metric tons of oil equivalent per year in 1989 to just under 87 million tons in 2006, an increase of 12 million tons. Over the same time period, coal consumption dropped by 13 million tons per year.
To meet new electricity demand and offset falling coal-fired output, the UK needed to add about 25 million tons of additional capacity from other sources. It should come as little surprise that the nation added more than 26 million tons of gas-fired capacity over the same time period.
Also helping the UK to reduce GHG emissions has been a reduction in the use of coal in manufacturing operations, replaced largely by natural gas.
According to the British government’s February energy white paper, this trend is projected to continue. By 2020, the UK is projected to need 367 terrawatt-hours of electricity supply, down from around 399 terrawatt-hours in 2006. Of that total, more than 53 percent is expected to come from gas-fired plants, up from 36 percent projected for 2010. Gas is far and away the fastest-growing source of power under the assumptions of this white paper.
As Dominion’s presentation at the EIA conference made abundantly clear, the US is following the UK’s lead on this issue. Increasing natural gas consumption is the only near-term means of reducing GHG emissions while still meeting growing energy needs.
But there’s one difference between the US and UK gas markets: The latter has, until very recently, been energy independent in gas. Check out the chart “UK Gas Production and Consumption” for a closer look.
Source: BP Statistical Review of World Energy
Thanks to Britain’s prolific North Sea natural gas production, it was possible to rapidly ramp up gas capacity in the ’90s without having to worry about imports. But that’s changing fast because the North Sea is now maturing and gas production is falling.
In 2004, the UK became a net importer of natural gas, and by 2006, the nation imported some 10 million metric tons of oil equivalent natural gas. This import demand will continue to increase as North Sea production continues its decline. Several liquefied natural gas (LNG) terminals are already being opened to help satisfy this demand and supplement volumes delivered via pipeline.
The US hasn’t traditionally been energy independent in the gas market; however, taken as a whole, North America has been. Unfortunately, as I explained at some length in the March 19 issue, Gas over Oil, Canadian gas exports to the US are likely to fall in coming years. Canada will use more gas domestically, particularly in oil sands recovery operations. Meanwhile, production in Canada’s traditional fields appears to be declining.
US unconventional reserves (see the Feb. 20 issue, Growing Unconventionally) will grow and help make up for declining production from other regions of the US. However, this growth won’t be enough to offset growing demand.
The bottom line: The US will become more dependent on LNG imports in coming years. (For those unfamiliar with that technology, see the Oct. 24, 2007, issue, Liquid Gold.)
To summarize, LNG is nothing more than a super-cooled version of natural gas. When gas is cooled to around minus 260 degrees Fahrenheit (minus 162 degrees Celsius), it condenses into a liquid.
Better still, as gas cools, it takes up less space; LNG takes up roughly one-six-hundred-and-tenth the volume of gas in its natural gaseous state. To put that into context, a beach ball-sized volume of gas shrinks to the size of a standard pingpong ball when it’s converted to LNG.
The benefit of this is transport. Traditionally, the vast majority of natural gas has been transported in its normal gaseous state by pipeline. So most natural gas consumed in the US was either produced domestically or imported by pipeline from neighboring Canada.
By extension, gas reserves located far from existing pipeline infrastructure had little or no value. Although oil from such fields can be loaded onto tankers and shipped anywhere in the world, gas was considered stranded. Stranded natural gas was routinely burned (flared) or reinjected into the ground as a form of permanent storage.
LNG frees gas from the pipeline grid. If you’re able to turn natural gas into a liquid, it can be loaded onto tankers just like crude oil and transported anywhere in the world. Gas reserves once considered stranded and useless can be exploited using LNG technologies.
Back to In This Issue
Buying LNG
It’s worth outlining a few additional points about LNG, one of the most talked-about subjects at this year’s EIA conference. One session centered on LNG included a representative from longtime Wildcatters Portfolio recommendation BG Group, a firm fast becoming the dominant player in the Atlantic Basin LNG trade. According to the company, it accounted for just less than 60 percent of all LNG trade with the US for 2007.The first point worth noting is that the limitation on global LNG trade growth isn’t a lack of LNG tankers or terminals for receiving gas. Rather, the real problem is available liquefaction capacity. Importing countries have sufficient capacity to handle gas imports, but exporting nations simply can’t grow their capacity to produce and liquefy gas fast enough to meet demand.
Most panelists agreed that LNG trade would continue to grow at roughly a 7.5 percent to 8 percent rate through at least 2012-13, after which growth could slow. Note that this growth represents a trend continuation since the early ’90s: Trade in LNG is growing faster than global natural gas demand.
That 2012-13 time frame is roughly the period when major new liquefaction projects underway in the Middle East, Australia and elsewhere are scheduled for completion. Once these projects are complete, the source of new gas supply looks murkier.
Although overall trade in LNG is likely to continue to grow faster than gas demand for the foreseeable future, what’s really interesting is how the nature of LNG contracts is shifting. In the early years of LNG trade, most natural LNG was traded under long-term supply agreements. That meant importing countries would agree to accept a certain quantity of gas delivered on a regular basis at a certain prearranged, fixed price or a price related to some visible index level.
Spot LNG cargoes—basically, one-off shipments on LNG sold at prevailing market prices—were only a tiny portion of the overall market. But the spot market is growing rapidly today.
Consider that, in 1997, short-term LNG trades accounted for only 0.5 million tons per year in LNG trade, roughly half of 1 percent of total LNG trade at the time. In 2002, that figure had grown to 8.4 million tons, 8 percent of total LNG trade for that year. And by 2007, that figure ballooned to 30 million tons per year in short-term trades; that’s about 17 percent of total LNG trade in 2007.
This figure likely underestimates the importance of the short-term LNG trade. Even so-called long-term LNG contracts are becoming shorter in duration, and new contracts have relaxed destination clauses.
This offers more flexibility for cargoes intended for a particular market to be diverted elsewhere. Some countries, such as Algeria, have allowed long-term LNG supply contracts to expire; these nations clearly believe that they can realize more value from their exports by selling and trading the gas on the spot market.
What’s starting to emerge is a far-more-flexible market for LNG cargoes. BG noted in 2007 a large jump in the number of LNG cargoes it had intended to sell in the Atlantic Basin that ended up being diverted to gas-hungry Asian markets. Producers with LNG cargoes have considerable flexibility in diverting cargoes to target whichever markets are most attractive on a price basis.
BG also noted that it’s not yet seeing a large-scale global convergence in LNG prices. Instead, arbitrage opportunities are actually rising. This is great news for BG because it has the flexibility to divert cargoes to far-away markets where the firm is able to sell gas at a premium.
What’s also becoming clear is that the US is, and will remain, a crucial market for LNG. The reason is simply that the US market is large and highly liquid. If a producer can find no other market for its LNG, the US market is a great last resort where prices are highly visible.
Moreover, the US has large gas storage infrastructure. LNG cargoes exported to the US during periods of low gas demand can be stored temporarily for use later when demand is higher.
Storing natural gas typically involves injecting the gas into natural geological formations such as depleted gas reservoirs. The US has a number of such fields available.
But that’s not the case in many parts of Asia. This makes it tough for the region to build out storage capacity even though such storage is in high demand. Therefore, LNG and the US have become sort of gas storage facilities for the world.
Strong growth in LNG capacity and shorter-term trading patterns all adds up to one thing: LNG is becoming a more and more influential factor in the North American natural gas market. LNG cargoes can adjust quickly to changes in price around the world and shift the supply/demand balance quickly.
A perfect example occurred last spring, when a sudden collapse in UK gas prices resulted in a quick shift in cargoes to the US market. According to BG, the whole shift took less than six weeks. The result of the shift was a glut in US gas supplies and a rapid drop in US natural gas prices.
On a shorter-term basis, BG’s comments were even more interesting. The company stated that it believes the EIA’s forecasts for US LNG imports in 2008 are troubled. The representative noted that the BG hadn’t imported a single LNG cargo into the US since Oct. 4. The company also suggested that a planned shipment scheduled for next month was likely to be diverted as long as US prices continue to trade at a discount to prices in Europe and Asia. (See the chart “US and UK Natural Gas Prices.”)
Source: Bloomberg
This commentary adds to my conviction that 2008 will be a big year for gas prices. Currently, the EIA is forecasting that the US will import 680 billion cubic feet (bcf) of gas this year in the form of LNG, down just 12 percent from last year’s record levels. But BG has suggested that this estimate is overly optimistic, especially given global gas price trends; US supply will be tighter without those LNG imports.
Back to In This Issue
Playing Gas
The bottom line: Longer-term realities of carbon legislation favor rising gas demand for use in power plants. Meanwhile, the increasing importance of LNG trade to gas fundamentals favors higher North American gas prices this year; the current LNG import dynamics are almost a mirror image of the case last spring.I’ve highlighted several plays on rising natural gas prices in recent issues of TES. In particular, I prefer producers with growing production potential and access to promising unconventional reserves, such as EOG Resources and XTO Energy—both holdings in the Wildcatters Portfolio. I covered both firms at length in the Feb. 20 issue.
Since that time, both firms have performed well. I’m looking to hear more positive news from EOG when it reports earnings in early May. In particular, there’s considerable excitement surrounding the potential for the company’s newly discovered gas reserve in British Columbia.
The play is similar geologically to the Barnett Shale gas play of Texas and, according to EOG, could contain upward of 6 trillion cubic feet in reserves. British Columbia recently reported record sales of oil and gas leases in the province, nearly doubling the previous annual record set in 2003-04.
I also expect to hear more about EOG’s strong oil production growth from its Bakken Shale reserves in the US.
XTO Energy has also been busy. Most recently, the company announced the purchase of Marcellus Shale acreage from fellow Wildcatters Portfolio recommendation Linn Energy for $600 million. As noted in two flash alerts last week, I see this as a positive deal for both companies.
XTO has the capacity to spend heavily on drilling in the region to exploit this promising play. Meanwhile, Linn received a large amount of cash that gives it firepower for future acquisitions of mature reserves elsewhere that fit better with its overall strategy.
As noted above, BG Group remains the premier pure play on exploding growth in LNG trade and the scope for arbitrage in gas prices. In addition, as I noted in the March 5 issue, The Final Frontier, BG holds a 25 percent stake in Brazil’s exciting Tupi field, one of the largest deepwater fields ever discovered.
And Brazil recently announced another exciting discovery—the Carioca oil field in the Santos Basin. Santos is the same basin where the Tupi field was discovered.
Initial reserve estimates leaked by Brazil’s National Petroleum Agency were up to 33 billion barrels of oil in the field. Since that time, Petrobras and others have sought to control enthusiasm, stating that more drill tests would be necessary to confirm those reserves.
However, it’s clear this is a major discovery, perhaps even larger than Tupi. And BG has a 30 percent stake in this oilfield. I’m boosting my buy targets slightly for both BG Group and XTO Energy to 130 and 68, respectively.
I’m making one more change to my gas play recommendations this issue: Sell Gusher Portfolio holding Quicksilver Resources for a profit of more than 115 percent since my initial recommendation last summer.
Quicksilver’s reserves in the Barnett Shale remain highly attractive; however, the stock has gotten too expensive relative to its peer group, trading at 24 times cash flow, compared to 11.8 times for EOG and 9.1 times for XTO. Based on 2008 earnings estimates, Quicksilver also looks expensive, trading on 37 times estimates against 18 times for EOG and 18.5 times for XTO.
I’m adding Canadian exploration and production (E&P) firm Talisman Energy to the Gushers Portfolio this issue as a replacement for Quicksilver. Talisman isn’t a pure play on natural gas or the North American market. However, the company is making the shift from a conventional oil and gas producer to targeting fast-growing unconventional plays.
Under a new CEO, I expect Talisman to see a significant uptick in production growth over the next few years. This will propel the stock.
For 2007, roughly 42 percent of Talisman’s production came from North America, with another 33 percent from the North Sea. North American production is weighted in favor of natural gas, which accounted for more than three-quarters of 2007 production. In contrast, North Sea production is close to 90 percent crude oil, mainly the most valuable light crude oil.
In North America, Talisman has traditionally focused its attention on the Western Canada Sedimentary Basin (WCSB), the prime conventional natural gas play in Canada. As I explained the Feb. 20 issue, conventional gas production in North America is declining, and such reserves generally simply don’t offer the growth potential of unconventional plays.
Unconventional oil and gas plays are simply reservoirs that can’t be produced using traditional technologies. Through a combination of horizontal drilling techniques and fracturing, these reserves are prolific. Because of the company’s less-than-stellar production growth and relatively high costs, Talisman has lagged most of its peer group focused on unconventional North American plays.
Last September, Talisman hired new CEO John Manzoni and is in the middle of a strategic review of its acreage. We should hear more concerning the outcome of that strategic review at the upcoming earnings release at the end of this month and an in-depth analyst meeting scheduled for May 21-23.
Most likely, the company will announce its plans to develop several unconventional plays it owns but hasn’t fully exploited. The list of plays includes about 800,000 acres of land in the Appalachian Basin of the US. This region includes an area known as the Marcellus Shale.
Readers will recognize that XTO purchased acreage in this exact same region from Linn Energy last week. So far, only a few producers have drilled wells in the region. But early results are positive, and the area also benefits from close to consuming markets such as New York. Talisman already has plans to drill six test wells in the region for 2008, but that development plan could easily be accelerated.
I’ve highlighted the potential of the Bakken Shale oil play before in TES. This shale play is primarily in the US; however, part of the play extends into southeastern Saskatchewan. Talisman has about 100,000 acres in this area. Oil production growth from Bakken has been impressive for other producers in the region.
The Montney gas field in Alberta and British Columbia, the Utica Shale of Quebec, and the Outer Foothills of British Columbia and Alberta are three more promising gas plays where Talisman owns significant acreage and likely plans significant drilling activity.
And there’s another catalyst for Talisman in Canada near term: The producer owns significant acreage in an Alberta deep gas play. Producers are drilling wells as long as 6,000 meters (18,000 feet) to produce this gas effectively.
Although this is a highly promising reserve, Talisman, along with other producers, cut back capital spending plans sharply in the region after the Alberta government made changes to its royalty regime. These changes hiked the royalty rates producers were required to pay on deep gas fields, rendering production from such fields uneconomic.
But on April 11, Alberta backtracked on those planned changes, set to go into effect Jan. 1, 2009. The government announced it was making changes to the new royalty framework to offset unintended consequences. Basically, drilling activity dropped off so quickly in Alberta the regional government realized higher royalty rates meant lower royalties for their coffers.
Deep gas plays such as those owned by Talisman where a specific area in which the government is altering its royalty structure to encourage development and capital spending. I suspect that, in light of these changes, Talisman will boost its capital spending plans in the region. This would be a positive move for the stock.
And although North American unconventional reserves are perhaps Talisman’s most exciting prospects, don’t ignore international growth potential. The firm has $2 billion in capital spending planned for the North Sea, about $1.14 billion for the UK and the remainder for Norway.
The list of projects includes some exploration spending, redevelopments of older fields, and appraisals and tests for wells Talisman has already identified. Five projects came online in 2007, and Talisman has plans for six more in 2008 and 2009.
Talisman believes that fields in the region remain underdeveloped. The company has the opportunity to re-enter existing fields and increase production. And because there’s significant oil and gas processing, storage and pipeline capacity in the region, expenses are relatively low. Overall, Talisman is looking for 45 percent production growth between 2007 and 2009.
And the company is increasing its capital spending in Southeast Asia to $765 million from $585 million last year. Exciting, high-growth potential projects are underway in Vietnam, Malaysia and Indonesia. Buy Talisman Energy under 24.
Back to In This Issue
Nuclear Renaissance
All this talk about gas doesn’t mean the nuclear story is dead. Rather, nuclear power plant build-outs continue in the developing world: China has plans for about 40 plants, India for 15 and Russia for as many as 40 in the next 20 to 25 years. The developed world is also likely to see a jump in nuclear plant capacity.By and large, comments at the EIA conference were supportive of nuclear. On the second day of the conference, I expected Sen. Pete Domenici (R-NM) to make comments broadly in support of nuclear power in the US; after all, Domenici authored an outstanding book on nuclear power’s potential, entitled “A Brighter Tomorrow: Fulfilling the Promise of Nuclear Energy.”
I was also pleased to hear Sen. John Dingell (D-MI) come out strongly in support of nuclear power during his keynote address. Dingell stated that the future is dark without such power. These comments suggest that nuclear is getting some support from both sides of the proverbial aisle.
On a more practical front, while gas has been the favored near-term solution to power capacity needs, nuclear has received some serious attention. For example, Dominion noted that, back in 2001-02, most utilities weren’t even seriously considering new nuclear capacity additions. In fact, they were so concerned that investors would punish their shares for even considering nuclear that most formed industry consortiums to investigate the technology without appearing outwardly interested. However, a series of changes to the process and procedures for licensing new plants and some new incentives have encouraged a second look at nuclear power.
Dominion was also careful to point out that no new reactors have been built since the ’70s, and the permitting process is still unproven. Moreover, the upfront capital costs for building new plants are huge even for the nation’s largest, most-experienced utilities. Therefore, nuclear loan guarantees will likely be necessary to encourage the construction of first few plants.
Nonetheless, Dominion looks to be among the first utilities that will actually build a new reactor in the US at its existing North Anna site. The company stated, however, that on a best-case scenario this new reactor would unlikely be put into service before 2015.
Because nuclear power plants produce no air pollution of any sort, they’re an ideal longer-term solution to satisfy global power needs and meet environmental regulations. Natural gas will be the bridge between the present and a time when the world can start constructing a new generation of nuclear plants.
After a big run-up in the first half of 2007, my nuclear field bet picks—mostly pure-play uranium mining firms—have been broadly weak over the past nine months. The main driver of that weakness has been a slump in the uranium spot price from more than $130 per pound in June 2007 to its current level of less than $70 per pound.
But remember that the spot market isn’t particularly important in uranium; most contracts are negotiated as longer-term, multi-year supply deals. Temporary increases in spot supply or drops in demand can have an outsized effect on spot prices that doesn’t reflect positive underlying fundamentals.
In this case, the main driver of weakness in spot prices has been the retreat of speculative hedge and investment funds from the uranium spot market. Speculative activity likely softened when the credit crunch began to hit last July. In addition, most utilities are well covered in terms of short-term supplies and have no need to enter the spot market right now.
But longer term, supplies look shaky. Mine production in 2007 was again far lower than global demand; this situation will only get worse as new plants come online and look for fuel.
Meanwhile, although a number of new uranium production projects have been announced, several have been delayed or have encountered real difficulties in ramping up to full capacity. I’m not convinced that global supply growth is assured.
Although we may still not be at an absolute bottom, I firmly believe that uranium prices will remain elevated in coming years and that new plant construction will overwhelm mined supply. Now is a good time to buy up a position in my uranium field bet recommendations.
However, remember my field bet concept. Uranium mining is a risky business. Production delays, unforeseen project cost, and simple labor and raw materials inflation can all have important effects on the economics of a particular mining project. And production costs vary wildly depending on the grade of ore mined and how large overall reserves are.
Riskier still is exploration. Uranium explorers buy acreage and drill holes, taking core samples to evaluate reserve size and ore grades.
Sometimes even the most-promising reserves just don’t pan out and can never reach economic production. It’s impossible to know this for sure until you’ve spent considerable sums on exploration; only once uranium is produced can we really know for sure the full costs and viability of a project.
To account for this higher level of risk, I’m recommending that risk-tolerant investors take a more diversified approach to playing the junior uranium E&P companies. Remember, no matter how careful your selection criteria, some promising uranium exploration stories will never work out.
Fortunately, there are high rewards to be found in this sector as well. Famed mutual fund manger Peter Lynch used to look for what he called ten-baggers—companies with the potential to earn investors 1,000 percent or more on their investment. Obviously, you don’t need many ten-baggers to make a solid return and make up for the inevitable losing plays.
If my bullish thesis on uranium prices and nuclear power is even half correct, I suspect there will be many ten-baggers among the uranium juniors during the next few years.
For the best chance at big returns, I recommend casting a wide net. Instead of just buying one or two high-risk names, I recommend placing a smaller amount in five to 10 such companies. Keep in mind that this is designed as a multi-year play; you should keep position sizes small.
|
Uranium Field Bet
|
||||
|
Company Name (Exchange: Symbol)
|
Entry Price (USD)
|
Total Return From 07/26/06 (%)
|
Total Return for 2008 (%)
|
Advice
|
| Paladin Resources (Australia: PDN, TSX: PDN, OTC: PALAF) | 3.28 | 26.5 | -29.2 | Buy |
| Pitchstone Exp. (TSX V: PXP, OTC: PEXPF) | 1.42 | -9.9 | -39.0 | Buy |
| UEX Corp (TSX: UEX) | 3.23 | 24.9 | -39.0 | Buy |
| UNOR (TSX V: UNI, OTC: ONOFF) | 0.47 | -62.1 | -25.0 | Buy |
| Uranium One (TSX: UUU, OTC: SXRZF) | 8.22 | -40.2 | -45.0 | Buy |
| Uranium Participation Corp (TSX: U, OTC: URPTF) | 7.38 | 9.6 | -23.0 | Buy |
| Uranium Resources (NSDQ: URRE) | 4.95 | 48.2 | -45.0 | Buy |
Back to In This Issue
Portfolio Update
In each issue of TES, I offer brief news updates on a handful of portfolio recommendations. Here’s the update for this issue:Peabody Energy (NYSE: BTU)—This Wildcatter has seen a nice run-up over the past several weeks and hit a new high earlier this week after the company reported first quarter earnings. It broadly beat analysts’ expectations for the quarter, but the more important aspect of the report was its raised forecast for full-year 2008 earnings to $2.20 to $3 per share; that compares favorably to analysts’ estimates for $1.99 per share.
Peabody is actually the second coal miner to report blowout earnings. Arch Coal reported better-than-expected results and raised its guidance one day before Peabody.
As I noted earlier, the international market remains key to Peabody’s growth. The company noted it’s signed more deals to export coal in the first three months of 2008 than it had in the prior two years combined. The company also pointed out that global coal inventories remain low and there’s an accelerating build-out of coal-fired capacity globally, necessitating higher US exports.
Clearly, Peabody is taking steps to ensure it can profit from rising demand for export coal. Earlier this week, the miner announced it’s increasing its ownership stake in the Dominion Terminal Association coal export terminal in Newport News, Va. This move will allow Peabody to export more coal from the US East Coast.
But that’s not to say that Peabody isn’t benefiting from higher prices in the US as well. As coal exports pick up, US utilities have to offer higher prices to secure supplies. As a result, Peabody announced it’s been contracting coal at prices 37 percent higher than last year from its core Powder River Basin (PRB) mines.
Although Peabody is currently trading slightly above my buy target, the firm remains my favorite play on a tightening global coal market. Buy Peabody Energy on any dip below 65.
MacArthur Coal (Australia: MCC)—First recommended in the Sept. 5, 2007, issue MacArthur Coal is now up 128 percent from that recommendation. The firm makes a form of pulverized coal used in steel production. The most recent catalyst for a rally is swirling speculation that the firm will be taken over; the company confirmed it’s been approached recently.
Founder Ken Talbot owns 24 percent of the company and has stated publicly he’d be willing to sell his stake at a substantial premium. China-based investment group Citic owns a near 20 percent stake and is also rumored to be interested in a full takeover, most likely as part of a partnership with a Chinese coal miner. Mining giants Anglo American and Xstrata are also rumored suitors.
A series of small Australian miners has been taken over in recent years, and MacArthur would be a valuable prize because it controls a third of the market for pulverized coal injection (PCI) coal used in steelmaking. This commodity is in high demand across Asia.
MacArthur may have more upside in a takeover bid; however, the recent surge in the stock has priced in a good measure of upside potential. As a result, I’m selling MacArthur Coal from of the Gushers Portfolio for a 128 percent profit.
Hercules Offshore (NYSE: HERO)—Hercules is a shallow-water contract driller heavily exposed to the Gulf of Mexico natural gas drilling market. (For a full explanation of my rationale behind this pick, see the Feb. 6 issue, Earnings on Tap.)
The driller’s recent rig status reports indicate that the day-rates for Gulf of Mexico jackups are stabilizing. This is likely because of rising gas prices have triggered renewed interest in drilling activity. Hercules reports earnings on May 1; I expect management to make some bullish comments about rig demand and day-rates. I’m raising my buy target for Hercules Offshore to a buy under 30.
Schlumberger (NYSE: SLB)—This oil services company is currently not in the TES portfolios, although it rates a buy in the How They Rate Table. Longtime readers know I see Schlumberger as an outstanding indicator on the health of the energy industry and, therefore, eagerly await its quarterly earnings releases. (I last analyzed the stock in the Feb. 6 issue.)
I’ll offer a more detailed update of the firm’s most recent quarterly report in the upcoming issue of TES. For now, the tone of this quarter’s call was significantly more bullish and upbeat than for the company’s third and fourth quarter 2007 calls. The company seemed to reaffirm continued strong growth outside the US. Even better, Schlumberger indicated that margins and growth in the long weak North American business are turning for the better.
My favorite play in oil services remains Weatherford International (NYSE: WFT), a stock that’s handily outpaced the other services names in recent months. I’m raising my buy under target on Weatherford International to 85.
Acergy (NSDQ: ACGY)—I offered a detailed rationale for this Wildcatters Portfolio holding in the March 5 issue. The company remains my favorite play on the deepwater boom.
Acergy’s recent earnings release suggests the firm is continuing to build a solid backlog of projects in core regions such as West Africa and Brazil. Acergy is now a buy under 27.50.
Back to In This Issue
Speaking Engagements
It’s time: Vegas, baby! Neil, Roger and I will head to the desert paradise May 12-15, 2008, for the Las Vegas Money Show at Mandalay Bay. Go to http://www.lasvegasmoneyshow.com/ or call 800-970-4355 and refer to priority code 010671 to do the “what happens here stays here” thing as my guest.
Stock Talk
Add New Comments
You must be logged in to post to Stock Talk OR create an account