|To: Ed Ajootian who started this subject||10/6/2003 12:26:39 PM|
|From: Ed Ajootian|
|KCS has done well during the first half and grew proved reserves by 20% over 2002’s year-end number of 196 bcfe. The|
company’s reserve life is now at nine years. The focus of the first half has been on cash-generating development projects.
For the second half, KCS is drilling a number of high-impact exploration wells like the Ray George, 5-Mile Creek and SKA.
If successful, we could see significant reserves addition at year-end 2003.
• In addition to the exploration projects, the company’s low-risk “bread and butter” assets at Elm Grove, Louisiana, and
Sawyer Canyon, Texas, continue to yield additional low-risk, high-return drilling locations. These two assets equate to 44%
of KCS Energy’s proved reserves. We like the fact that KCS could have multiple years of drilling inventory in these
• We think the company is firing on all cylinders. We are confident of our 2003E production estimate of 34 bcfe. If the
drilling program continues to be successful during the second half, we would expect our 2004E volume estimate of 36 bcfe
to increase. We reiterate our Buy recommendation on this gassy story with organic growth. Our 12-month price target is
KCS’s primary focus areas are the Mid-Continent region and onshore Gulf Coast. The company has key operations in the
Anadarko and Arkoma basins, North Louisiana, West Texas and Michigan. Along the Gulf Coast, the focus properties are in
South Texas, Coastal Louisiana and the Mississippi Salt Basin. With the financing of the $61 million Senior Notes completed
in January 2003, KCS has been totally focused on the drill-bit, an effort that resulted in 50 bcfe of proved reserves for the midyear.
The reserves are booked based on $27.00/bbl (WTI) and $5.17/mmbtu (Henry Hub). At a lower gas price assumption of
$4.25/mmbtu, the reserves could swing by 5 bcfe to 6 bcfe. Of the 234 bcfe of proved reserves, 75% are proved developed and
80% are natural gas; KCS operates 80% of the assets. The reserve life is nine years. The geographic mix is 27% Elm Grove;
17% Sawyer Canyon; 25% Gulf Coast and 31% in other Mid-Continent Assets, the Rocky Mountains, Michigan and
By mid-year, the company had drilled 40 wells with a 95% success rate, and each successful well opens up more prospective
locations. We think the company has plenty of running room with this growing prospect inventory. The company increased its
2003 capital budget to $65 million from $55 million during the second quarter. We expect KCS to generate cash flow in
excess of $88 million for 2003, which is sufficient to fund its new spending program and reduce debt. With a robust drilling
inventory and strong commodity prices, we would not be surprised if KCS increased its 2003 spending plan again.
Be on the Lookout for High-Impact Drilling during the Second Half
The company has begun its high-impact exploration program in South Texas. If successful, any of these prospects can make a
meaningful impact on the company’s 2003 year-end reserves:
Ray George: WI 50%, pre-drill target size of 40 bcfe (in progress). The prospect is located 200 to 260 feet updip of an old gas
well, a fault-bounded structure.
5 Mile Creek: WI 30%, pre-drill target size of 20 bcfe (in progress). The prospect is located in the prolific Mission Valley
area. It is a structural trap defined by 3-D seismic data, with amplitudes on the crest.
SKA: WI 30%, pre-drill target size is 30 bcfe (in progress).
Coquat Deep: WI 50%, pre-drill target size is 25 bcfe. This prospect is defined by 3-D seismic. The area is faulted with
multiple pay zones. The main target is the Wilcox, and there are shallower zones supporting additional drilling locations.
Austin Deep: WI 50%, pre-drill target size is 50 bcfe. This prospect is defined by 3-D seismic; the area is faulted with
multiple pay zones. The well will likely be drilled in 2004. There are existing discoveries in shallower zones nearby, which
lowers the risk for the Austin Deep prospect.
Core Areas: Generating More Drilling Locations
As of mid-2003, KCS drilled 40 wells, with 38 successful (95% success rate). During the first half, the company did most of
its drilling in the Elm Grove area of Louisiana and the Sawyer Canyon area in Texas. Combined, these two areas contribute
44% of the company’s proved reserves. We like these plays, as the programs are repeatable, relatively low-risk and have quick
The Elm Grove Field in North Louisiana: (100% WI in 8 sections, 33% in 1 section). KCS drilled 9 wells by mid-year and
expects to drill 9 more before year-end. The company is prospecting for the Hooston interval and the Cotton Valley group.
The average well cost is $1.2 million and the initial production rate is 3 mmcf/d. The reserve potential is 1 bcfe to 3 bcfe. The
company has 50 to 100 additional locations—at 20 wells per year, this could support a 2- to 5-year drilling program. This Elm
Grove area is competitive, but KCS Energy has made long-term agreements with drilling and service companies to keep a lid
on drilling and fracturing costs. These agreements and contracts enhance the economics of the Elm Grove Play.
At the Sawyer Canyon Field, in Sutton County, Texas (90%-100% WI), KCS drilled 14 wells by mid-year, with IP averaging
370 mcf/d per well. The average well cost is $400,000, with reserve per well at 0.4 bcfe/well. The acreage can support 35 to
100 more well locations, and KCS plans to drill 20 wells per year in the Sawyer Canyon field in 2004 and 2005. Spacing is
currently 80 acres; it could be down-spaced to 40-acres at selective locations if commodity prices continue to stay high.
In East Texas at the Joaquin Field: (74%-100% WI), the company drilled 2 wells by mid-year and expects to do three more
by year-end. Average well cost is $1.5 million, with an initial production rate of 1 mmcf/d to 3 mmcf/d. The reserve potential
is 2 bcf to 4 bcf per well; the company has 5 to 10 additional well locations.
At the Talihina Field in Oklahoma (30% to 100% WI), the Weyerhauser 2-22 discovery flowed 4.0 mmcf/d. The
Weyerhauser 3-22 and Blake 11-21 are being completed. The company expects to drill 5 wells by year-end in this Arkoma
Basin play. The well cost is $1.6 million, with an initial production rate of 2 mmcf/d to 4 mmcf/d. The reservoir is the
Jackfork Formation (up to 200 to 400 feet thick). The structures are complex, with steep dips, and reserves per well average 2
bcfe to 6 bcfe. The company has 5 to 15 additional locations. The partners in this play are Chesapeake Energy (CHK/NYSE-
$10.76; Not Rated) and Ward, which is private.
Valuation and Price Target
In valuing our E&P companies, we use a price-to-cash flow multiple. We establish a reasonable range based on historic
averages of a group of broad-based E&P companies, which includes twelve E&P companies with market capitalizations
ranging from $900 million to over $11 billion.
Our 12-month price target of $8.00 is based on approximately 4 times our 2004 cash flow per share estimate of $1.92. We
used a low cash flow multiple to reflect KCS’s high leverage, which is currently about 93%. We are very encouraged by
KCS’s drilling success and believe that, if commodity prices continue to be strong, the company could end 2004 with a debt-tocap
ratio in the low-60% range. We also revised our net asset value (NAV) analysis for KCS using the company’s mid-year
reserves of 234 bcfe. Using our 2004 price forecast of $26.00/bbl for oil and $4.75/mmbtu for gas, we arrived at $10 per share,
net of debt. We reiterate our Buy rating on KCS.
• KCS has a small market capitalization, a relatively thin float and light trading volume, which, under certain circumstances,
could make the stock more volatile.
• The company’s production mix is roughly 80% natural gas: with each $0.10/mmbtu change in Henry Hub natural gas prices,
both 2004E EPS and CFPS could be impacted by $0.05 each. Also, with each $1.00/bbl change in WTI oil price, the 2004E
EPS and CFPS could both be impacted by $0.03.
• In addition, the high debt level makes KCS more sensitive to positive or negative moves in U.S. natural gas prices.
Above is from Sanders Morris Harris report 9-5-03
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|To: Ed Ajootian who wrote (91)||10/6/2003 1:05:10 PM|
|Yes, I'm holding in a big way. I picked up about 80,000 shares below $2.10 a share last year. I have a lot of confidence in management and their acquisition of the Fences I,II,&III properties is beyond amazing. This company is set to fly as far as I can tell. I think we'll all be very pleased with this stock during the next 12 to 24 months. If the first well with CE is a dry hole, the stock may temporarily tank. However, this is much more than a one hole game.|
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|To: Ed Ajootian who started this subject||2/27/2004 6:00:53 AM|
|From: Ed Ajootian|
Prices are based on delivery to National Balancing Point,
within Transco's transmission system.
Quotes for specific dates are settlement prices.
Week's High/Low reflects intra-day trading.
Above are UK gas futures, wrt ATPG.
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|To: Ed Ajootian who wrote (94)||3/4/2004 12:12:53 AM|
|Hi Ed: Thanks for the feedback. FXEN has dropped back but I view it as a healthy correction. I'm in this one for 3-5 years and believe that under Hartman's competent guidance, this company will do phenomenally well. Time will tell.|
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|From: Ed Ajootian||3/21/2007 4:58:09 AM|
|Alcan May Buy Gas From Rift Oil for Australian Plant |
By Angela Macdonald-Smith
March 21 (Bloomberg) -- Alcan Inc. signed an initial accord with Rift Oil Plc that may result in the world's second-biggest aluminum producer buying natural gas from a field in Papua New Guinea for an alumina refinery in the far north of Australia.
The company needs 40 billion cubic feet a year of gas for 20 years for the Gove plant and London-based Rift still needs to prove the Douglas field is big enough, Stefano Bertolli, an Alcan spokesman in Brisbane, said today. Rift's Douglas field is one of several potential supply options being considered, he said.
An agreement Alcan had earlier to buy gas for Gove from Exxon Mobil Corp.'s proposed $5.5 billion project to pipe gas from Papua New Guinea to eastern Australia lapsed late last year after the group that was to build the line decided the project was uneconomic. That prompted Alcan to study alternative options, including coal-seam methane and liquefied natural gas.
``We signed a non-binding MOU with Rift and they're going to explore to see if there are enough reserves there, and if there are then we're going to have to see how it moves forward,'' Bertolli said in a telephone interview. ``There are many options on the table and this is one of them.''
Last October Alcan agreed to start studying a gas-to-liquids project with Arrow Energy NL that would use coal seam gas from Brisbane-based Arrow's fields in Queensland. The study was to study gas-to-liquids against other options available for energy supply to Alcan's Australian operations.
Arrow said earlier this month the initial studies showed a plant costing about A$1 billion ($802 million) and producing about 20,000 barrels a day of diesel, naphtha and liquefied petroleum gas may be economic.
Should a final agreement be reached with Rift, it would require the construction of a $1 billion pipeline to take gas from the Douglas field in Papua New Guinea's Western Province to Gove in the Northern Territory, the Australian said today, citing Ian Gowrie-Smith, chairman of Rift Oil. The pipeline would be shorter and cheaper than Exxon's proposed line as it may only supply Gove, the newspaper said.
Alcan, based in Montreal, isn't considering investing in the pipeline at this stage, Bertolli said. The company is spending $2.3 billion on expanding the Gove refinery and wants to switch fuel supply at the site to gas from fuel oil because it's more economic.
Rift will explore at Douglas over the next 12 months to see if there are enough reserves and the companies will then decide whether to seek a final gas sales agreement, with the possibility of gas deliveries starting in 2010 or 2011, Bertolli said.
Rift's Foreland Oil Ltd. unit owns 65 percent of the PPL 235 exploration permit in Papua New Guinea, which holds the Douglas-1 and Langia-1 gas discoveries, which may also contain condensates, Rift said in a March 20 statement on the initial accord with Alcan. New Zealand's Austral Pacific Energy Ltd. owns the rest of the permit.
Planned work in the permit ``is expected to be completed by mid-2008 and aims to provide sufficient information for the parties to proceed to a binding agreement to supply natural gas to Gove,'' Rift said in the Regulatory News Service statement.
Wellington-based Austral said in July the Douglas field may hold ``several hundred billion cubic feet'' of gas across an area of 40 square kilometers.
Rift and Austral are also equal partners in an adjacent permit, PPL 261, which lies within about 100 kilometers (62 miles) of the Juha and Hides gas fields and the Moran, Mananda and Kutubu oil fields.
To contact the reporter on this story: Angela Macdonald-Smith in Sydney at email@example.com .
Last Updated: March 21, 2007 01:48 EDT
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|From: Ed Ajootian||1/4/2008 12:07:11 PM|
|UK energy prices rise in 2007, drive retail tariff rise |
Wholesale gas and power prices in the UK have risen steadily during the
12 months since the round of retail price cuts in early 2007, an analysis of
Platts' data shows. UK utilities have pointed to rising wholesale prices as
the basis for a new round of retail price tariff hikes.
UK utility RWE Npower said Friday it would announce retail price rises
later in the day, and its fellow utility Centrica said in its trading update
in December that rising wholesale prices had squeezed margins. If high
wholesale prices continued, they would "create a more difficult environment"
in 2008, Centrica said, adding: "We will continue to monitor this with regard
to future pricing policy."
The last round of domestic price changes from UK utilities began at the
end of 2006, when Centrica announced the first price cut after several years
of price rises. Scottish and Southern followed in January, with other
utilities promising price matching or special cheaper tariffs.
Last winter UK gas and power prices had been falling steadily for several
months, partly because of two new major pipelines bringing gas from Norway and
the Netherlands. In addition to the extra supply, the UK experienced an
extremely mild winter season, lowering demand and hence price.
At the start of 2006 prompt gas prices had spiked in response to supply
problems, with day-ahead reaching as high as 187.5 pence/therm in March 2006,
and the front month contract above 100 p/th at points during the winter.
But with the new supplies online at the end of 2006, and low demand, gas
prices plummeted. Day-ahead traded below 30 p/th for almost the whole of
the first quarter of 2007. Similarly, the month-ahead contract fell steadily
from above 50 p/th at the start of winter 2006 to under 30 p/th in January
2007, usually a peak period.
UK power prices tend to track UK gas prices because the marginal power
generation supply in the country is largely gas-fired. So with gas prices
fairly low, power prices followed. And that improved utilities' margins
significantly, creating a strong rationale for price cuts.
During the course of 2007, however, the bearish wholesale trend reversed.
To some extent this was due to a rising oil price. At the start of 2007 the
dated Brent crude oil contract was at just above $50/barrel. But by July it
was up to $77/b, and on the first trading day of 2008 it hit $100/b for the
first time ever.
Gas contracts on the Continent tend to be indexed to oil products, with a
six-month delay. So the steady rise in the oil price caused a steady rise in
European gas prices over the course of the year from July onwards. With
European gas prices rising, producers could choose to send gas to the
continent in preference to the UK, so UK gas prices also rose.
Compounding matters, there were several incidents of North Sea
infrastructure problems, including the extended outage at BP's CATS pipeline.
The weather was also an important factor with the UK experiencing a fairly
mild summer and then a rash of colder-than-normal weeks towards the end of the
year, raising demand.
In July, the UK gas day-ahead price stuck close to the 30 p/th mark, up
from the sub-20 p/th level seen in April despite the summer's traditionally
lower demand. As the year wore on and the market entered the higher demand
winter period, prompt prices rose further and day-ahead traded above 50 p/th
for much of November and December, almost double the level seen in early 2007.
By the start of 2008, infrastructure problems, higher demand than
expected and the rising oil price had combined to raise market expectations of
future prices. The winter 07 contract had closed in September at 43.75 p/th.
But January 3, the winter 08 gas contract was 50% higher than this, at 61.6
On the power side, as well as the rising gas price pushing up power
prices, nuclear plant problems added extra bullish spice. Four of British
Energy's nuclear power units, two at Hartlepool and two at its Heysham-1
plant, have been out of action since October 22 after the generator found a
wiring problem at Hartlepool-1. All the units have a similar design, and
therefore the three other units have been kept offline for further checks.
The four units together generate 2,360 MW of power and they are usually
run on a constant baseload shape, since marginal costs are relatively low
compared to gas and coal plants.
Traders said the nuclear outages brought up prompt power prices as well
as forward prices for November and December 2007, a period when demand
increases due to the colder winter weather. The average daily baseload power
price in November 2007 was GBP44/MWh, 57% higher than November 2006. In
December 2007, day-ahead power was 39% more expensive year-on-year, at an
average of GBP51/MWh.
Finally, in addition to other factors, the start of 2008 saw the onset of
the second phase of the EU's Emissions Trading Scheme. Phase 1 was
oversupplied with carbon certificates, leading to an EUA price of under 10
euro cent equivalent to 1 mt of CO2. But Phase 2 is widely expected to be
short and the current December 2008 EUA price is Eur23.50/mt CO2e. That makes
generating power using fossil fuels such as coal and gas more expensive, hence
raising power prices further.
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