1 Copyright 2010. Hart Energy Publishing, LP.

VOLUME 28 ISSUE 49December 30, 2010

In This Week’s Edition of Gas Processors Report

FEATUREIs Historical Natural Gas Volatility Dead?

INSIDE LOOK AT PROCESSING TRENDSGlobal Hunter Securities: How Many Rigs Does It Take to Keep Production Flat?

BLM Leasing, Royalties in Free Fall - Report

Dec. 23, 2010 Box Score: Texas Light NGLs Outperform Heavy NGLs

Dec. 23, 2010 Frac Spread: Margins Improve Despite Mixed NGL Prices

MIDSTREAM NEWSChesapeake Monetizes Haynesville Midstream Assets

Targa Increases Eagle Ford NGL Transportation with Possible Permian Outreach

XTO Scoops Up Petrohawk’s Fayetteville Gas, Midstream Assets

AltaGas’ Harmattan Co-stream Project Approved

FRACTIONATION SPREADFrac Spread Margins Continue to Improve with NGL Prices

BOX SCORENGL Prices Improve on the Back of Colder Weather

PIPELINE NEWSEIA’s 2011 Outlook: Alaska Gas Pipeline Unlikely for Next 20 Years

INTERNATIONAL NEWSSaudi Aramco Moves Wasit Gas Plant Completion Date Up to 2013

Is Historical Natural Gas Volatility Dead?Historically natural gas prices have been subject to vola-tility from heating and cooling demand, as well as due to tightened balances, but over much of the past decade prices have traded in a tighter range due to increased production, among other factors. Given this situation, a recent Natural Gas Weekly Kaleidoscope from Barclays Capital questioned whether pricing volatility was dead.

The report found that since 2007, natural gas prices have hovered between US$3-6 per million Btu (MMBtu) with the ex-ception of 2008. In addition, the average prompt price in 2006, 2004, 2003, 2002, 2001 and 2000 all fell within this range.

“It used to be that a tighter balance between supply/de-mand could cause short-lived price spikes, particularly to-ward the end of winter if inventories did not look sufficient to meet the incremental pull from weather-driven demand. However, end-of-winter storage levels have trended higher over the past 10 years. In fact, in the most recent few years, 2008 is the only example of a low inventory level causing a price rally,” according to the report.

The report further notes that although the average price levels in 2009 and 2010 compare favorably to those earlier in the decade, the price ranges between the high and low prices were among the tightest of the decade.

James Crandell, Biliana Pehlivanova and Michael Zenker, the report’s authors, noted that these tighter prices are due largely to increased production, which they deemed “the

enemy of high volatility” as it has helped to dampen volatil-ity, while also making price spikes less severe.

This effect is increased due to the higher production rates out of the newer unconventional plays. “Moreover, the in-dustry currently operates with more capacity to drill than to complete wells, resulting in uncompleted inventory. These un-completed wells serve as a form of spare capacity in that they can more quickly be turned to production,” the report said.

It was noted that a “major service provider” estimated the amount of uncompleted wells as growing to approximately 2,500-3,000 wells by the end of 2010. This would take a few

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months to complete without new drilling, which is a similar circumstance to what happened last year and helped to limit a price rally when heating demand increased.

In addition, it was noted that demand for natural gas has been stagnant over the last decade with only the electric generation sector increasing its demand significantly, but this demand gen-erally peaks in the summer when inventories are higher.

Increased natural gas storage capacity has increased greatly over the past decade, reaching a peak total capacity of 4.049 trillion cubic feet (Tcf) to 4.364 Tcf in 2010, according to U.S. Energy Information Administration (EIA) data. “The increase in storage capacity has allowed for inventories to build higher each year, and begin the withdrawal season with more gas, even though demand has not increased commensu-rately. Thus, there is less risk that facilities will reach empty and hence, prices are cushioned against this outcome,” the report said.

As storage capacity has increased, so has the associated deliverability with storage deliverability rising 15 billion cubic feet per day (Bcf/d) from 2005 to 2009. In addition, since 2001 there have been more than 20,000 miles of natural gas pipelines added. These have further increased the capa-bility of demand to be met quickly and cheaply and help to stymie price increases even when heating demand is high.

The threat of price spikes has also been hindered due to decreased production out of the Gulf of Mexico, thus limit-ing the effects that hurricanes have on prices. The Barclays Capital analysts stated that the EIA reported production out of the Gulf in January 2005 was 10 Bcf/d while production out of the Lower 48 states was a little more than 55 Bcf/d. By January 2010, production out of the Gulf was down to 6.5 Bcf/d while production out of the Lower 48 states had increased to almost 63 Bcf/d, thus reducing Gulf production to just 10% of all U.S. production.

Prices are further kept in tighter balance due to the com-bined abilities of liquefied natural gas (LNG) and coal-fired power plants. More LNG is imported when natural gas prices

increase, thus helping to push natural gas prices down, and there are more instances of coal being displaced in favor of natural gas in terms of electric generation when prices fall below coal prices, until it increases demand and increases natural gas prices.

In order to reverse this low volatility in the short-term, there would need to be a substantial reduction in natural gas storage levels. Last winter’s extreme cold temperatures ex-perienced throughout much of the country, resulted in stor-age levels coming back into line with their levels from the prior year. “…[O]nly record cold that would draw invento-ries markedly below where they finished last March would excite the market,” the report said.

Over the long term, prices are likely to trade in a wider price range, the analysts said, due to a variety of factors, including the shutting down of coal plants, the adoption of natural gas vehicles and the exporting of LNG on the demand side.

The report stated that questions still remain about the long-term viability of shale gas to remain a low-cost resource as it is unknown how long drilling and production costs can remain low and what the decline rates will be over the long haul.

Furthermore, the company noted that there has been even more pressure placed on longer-term volatility by produc-ers seeking to earn a premium to apply to more traditional hedges by operating as sellers. While this is occurring, one of the largest buyers of volatility – hedge funds – have been less active in the market.

“Although we recognize that most of the recent devel-opments have tended to make the market less volatile, we do think that volatility is cyclical in nature. In a sense, the market has projected forward today’s oversupply condition out the forward curve, and then added in additional pressure from producer selling. Therefore, while fundamentals sug-gest volatility will stay contained in the front of the curve, we would be buyers rather than sellers of longer-term volatility,” the report said. – Frank Nieto

INSIDE LOOK AT PROCESSING TRENDS

Global Hunter Securities: How Many Rigs Does It Take to Keep Production Flat?“There is little question that a picture is worth a 1,000 words. And for natural gas producers, those words may include some of George Carlin’s “7 Dirty Words,” Michael Bodino, director of energy research at Global Hunter Securities LLC, jokes in a Dec. 22 research report.

On a serious note, the firm has continued the ongoing dis-cussion, “How many rigs does it take to keep production flat domestically?” with a look at certain historical highs and lows in both domestic rig counts and production.

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“We started thinking about enhancements in productivity and the proliferation of horizontal drilling and completion technology that has led to rapid production growth and the need for fewer overall rigs to generate growth,” Bodino said.

Louisiana is one of the best examples of this, according to the research director. Until May 2008, the state had an aver-age of 156 total gas rigs running, including just one or two horizontal gas rigs. Production remained flat at just under 3.7 billion cubic feet per day (Bcf/d). “Then along came the Haynesville, and while the overall rig count during the past two years has averaged 145 rigs, horizontal rigs represented an average of around 100 rigs,” Bodino said.

Currently, horizontal rigs comprise more than 80% of the overall rig count, and “superior” productivity of the hori-zontally drilled wells has driven production to more than 6.5 Bcf/d. Meanwhile, the difficulty lies in how to determine the number of rigs needed to keep production flat.

Looking at more mature areas in Texas for the key to a balanced rig count may be telling, however, according to Bodino. Because of the Barnett shale, the horizontal rig count steadily rose from 2005 through third-quarter 2008. And, with 400 vertical rigs targeting primarily the Cotton Valley and 100 horizontal rigs increasing to 300 rigs, Barnett production soared from 14.5 Bcf/d to nearly 20.5 Bcf/d.

“Then the music stopped,” Bodino said, pointing to a col-lapse in the Texas gas rig count from 700 to under 300, in-cluding a drop in the horizontal rig count from just under 300 to around 120. Production subsequently declined 10%.

Although the horizontal rig count has returned to its highs, the vertical rig count has never recovered as many of the targeted reservoirs remain economically challenged, Bodino continued. “Still, the current count of around 400 total gas rigs, about 75% of which are horizontal rigs, appears to have been enough to stabilize production in Texas,” he noted.

Similar to Texas, the rig count in Oklahoma ramped up from 2005 to 2008, with much of the horizontal rig count di-

rected toward the Arkoma Woodford shale. Then, when gas prices fell, production took a hit. But as the total rig count moved back toward 115 rigs (90 horizontal), production began to stabilize. However, much of the rebound in rigs has been directed toward western Oklahoma, Bodino maintains.

“In Louisiana, Texas and Oklahoma, there has been a clear trend toward horizontal drilling and less vertical rigs running as a percentage. However, some states have yet to have an abundance of horizontal drilling opportunities,” Bodino said. “Looking below at New Mexico and Wyoming shows the lack of impact on production as the rig count has fallen.”

During the last five years, the gas rig count has had a steady decline in New Mexico from around 70 rigs to less than 15, and gas production has fallen from 4.5 Bcf/d to 3.5 Bcf/d, according to the research director. In the past few months, however, gas production appears to have flattened and is now holding its own on a lower rig count, Bodino noted.

In Wyoming, the story is a bit different, Bodino added. Due to infrastructure bringing stranded gas to market, a reason-able flat rig count between 2005 and 2008 aided in production growth from less than 4.5 Bcf/d to more than 6.5 Bcf/d. “Re-cently, however, production (from around 35 rigs) appears to have rolled over and is starting to decline,” he said.

Bodino said Global Hunter concurs on two points: there is little question that the supply shift in the U.S. has created some regional supply and price changes; and horizontal drilling has transformed supply dynamics, particularly in the shales.

“As we sit today, the Haynesville and the Marcellus are still ramping, but the Barnett, Fayetteville and Woodford have begun to roll over,” he reflects. “And regardless of rig count, production will ultimately find its level and flatten.” In the meantime, “there are too many or too few rigs running in many of these states,” Bodino contended.

As for the industry’s resolution in the new year? “For the gas producers, we hope for fewer Haynesville horizontal rigs and an erosion of the number of wells waiting on completion.”

BLM Leasing, Royalties in Free Fall - ReportThe Bureau of Land Management (BLM) has overseen a 79% drop in leases issued over five years in Colorado, Mon-tana, New Mexico, North Dakota, Utah, and Wyoming, ac-cording to new report comprising government data related to oil and gas development on western public lands by Western Energy Alliance.

The report, “Western Oil and Natural Gas Dashboard,” shows a continued decrease in the productive use of public lands for domestic oil and gas development, and a significant

corresponding decline in revenue to federal and state govern-ments. Leasing revenue dropped 46% over the same period, and overall onshore royalties have declined 33% over two years, according to Western Energy Alliance.

“Western Energy Alliance remains dedicated to provid-ing timely and credible data to enable policymakers to make informed decisions on how to best manage our public lands,” said Spencer Kimball, manager, government affairs. “Our (report) reveals a clear trend toward decreased access of the

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American people to oil and natural gas on public lands. This trend, if continued, will result in a decline in energy devel-opment with a resulting loss of jobs, and less revenue for federal and state treasuries at a time when Americans are very concerned about out-of-control deficits and spending.”

Notable Trends:Employment• Employees of the oil and natural gas industry in the West

typically earn 86% more than the state average and 67% more than the U.S. average.

• The oil and natural gas industry supports 488,000 jobs in the West (8.1% of total regional employment).

• Western oil and natural gas employees receive more than US$27 billion in annual labor income (10.3% of total regional labor income).

Tax and Royalty Revenues• Revenue from onshore federal royalties, rents, and bo-

nuses declined from $4.2 billion to $2.8 billion between 2008 and 2010, a 33% decrease.

• Every dollar appropriated for BLM’s Onshore Oil & Gas Management Program generates over $40 in royalty, rent, and bonus revenue for the federal treasury.

• In 2009, oil and natural gas development in the West provided $6.6 billion in direct government revenue, which is used for impacted communities, schools, con-servation funds, and other public benefits.

Production and Reserves• The West produces 27% of total U.S. natural gas and

14% of total U.S. oil. • In 2009, 42% of western oil and natural gas was pro-

duced on federal lands.

Land Use• Actual surface disturbance from oil and natural gas de-

velopment is just 0.07% of total public lands in the West. • Of the 700 million acres of BLM-managed mineral estate,

just 6.4% is leased for oil and natural gas development.

Leasing• BLM offices in the West issued 531 leases in fiscal year

(FY) 2010, a 79% drop from the 2,499 leases issued in FY2005.

• Since FY2005, BLM has offered 60% fewer parcels and 70% fewer acres.

• Leasing revenue dropped 46% from $189.6 million in FY2005 to $101.6 million in FY2010.

• Since 1984, total leases in effect in the West declined 52% and acreage declined 61%.

• BLM sold 75% fewer acres and issued 84% fewer acres in FY2010 than it did in FY2005.

• In the first two years of the Obama administration, BLM issued 76% fewer acres than the first two years of the Clinton administration, and 71% fewer acres than the first two years of the Bush administration.

Leasing by StateColorado• Colorado BLM issued 34 leases in FY2010, an 88% drop

from the 272 leases issued in FY2005. • Leasing revenue dropped 85% from $18.4 million in

FY2005 to $2.7 million in FY2010. • Since FY2005, 87% of offered parcels have been protested.

Montana/Dakotas• Montana BLM issued 70 leases in FY2010, a 77% drop

from the 306 leases issued in FY2005. • Since1984, total leases in effect in Montana declined

66% and the total number of acres declined 74%. • North Dakota BLM issued 23 leases in FY2010, a 90%

drop from the 229 leases issued in FY2005

New Mexico• Leasing revenue dropped 56%, from $54.3 million in

FY2005 to $23.9 million in FY2010. • New Mexico BLM issued 30,660 acres in FY2010, an

84% drop from the 184,786 acres issued in FY2005.

Utah• Utah BLM issued 21 leases in FY2010, a 97% drop from

the 617 leases issued in FY2005.• Leasing revenue dropped 96% from $33.8 million in

FY2005 to $1.4 million in FY2010. • Since 1984, total leases in effect in Utah have declined

71%, and the total number of acres has declined 75%.

Wyoming• Wyoming BLM issued 314 leases in FY 2010, a 61%

drop from the 797 leases issued in FY2005. • Since FY2008, 90% of offered parcels have been protested.

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(Note: This is not this week’s Box Score)Lighter natural gas liquids (NGL) prices fared better than their heavy counterparts the week of December 23. This was espe-cially true at Mont Belvieu where ethane and propane’s price increases helped the theoretical NGL barrel price improve de-spite the heavy NGLs falling in value.

Propane had the biggest gains at both Mont Belvieu and Conway during the week, as it rose 2% at both hubs. The Texas price of US$1.31 was the highest at the hub since it was $1.36 the week of February 3 while the Kansas price of $1.25 was its highest since the week of Febru-ary 10 when it was $1.29. This uptick in propane prices was due to a 31% increase in implied demand for propane according to the U.S. Energy Information Adminis-tration because of heating demand out of the Midwest and Northeast. En*Vantage reported that despite this increase, propane demand is still lagging behind the same time period last year.

Mont Belvieu ethane was up 1% to 64¢, its highest price at the hub since it was 65¢ the week of November 3. Meanwhile Con-way ethane was down 1% to 51¢. This was still the third-highest price at the hub since early March.

The lone heavy NGL to experience a price increase at either hub was Conway iso-butane, which improved very slightly to $1.72, its highest price at the hub since it was $1.74 the week of February 3. While Kansas iso-butane im-proved by 1¢, its Texas counterpart was down 1¢ to $1.77. However, iso-butane remains strong as the Mont Belvieu price was the second highest at the hub since the first week of January.

Butane fell 1% at both hubs as it was down to $1.70 at Mont Belvieu and Conway. This was the first time that the

price of butane was roughly the same price at both hubs since the week of September 15 when both prices were $1.44.

Pentanes-plus (C5+) was down very slightly to $2.06 at Con-way, which was still the second-highest price at the hub since it was $2.07 the week of September 10, 2008. The Mont Belvieu price fell 1% to $2.09, which was the hub’s third-highest price since it was $2.11 the week of September 24, 2008.

– Frank Nieto

Dec. 23, 2010 Box Score: Texas Light NGLs Outperform Heavy NGLs

Data Provided by Intercontinental Exchange. Individual product prices in cents per gallon. NGL barrel in $/42 gallons

Box ScoreMont Belvieu Eth Pro Norm Iso Pen+ NGL Bbl

Dec. 15 - 21, '10 64.01 131.20 169.92 177.36 208.45 $53.27

Dec. 8 - 14, '10 62.85 127.08 172.34 178.82 209.95 $52.87

Dec. 1 - 7, '10 63.49 125.02 170.66 176.96 208.82 $52.51

Nov. 24 - 30 '10 63.37 126.13 165.43 173.33 198.80 $51.57

November '10 62.88 125.42 161.66 166.63 197.78 $50.96

October '10 54.21 123.20 154.62 160.26 192.08 $48.44

3rd Qtr '10 44.99 106.98 138.23 143.25 171.45 $42.37

2nd Qtr '10 50.97 108.43 145.01 157.23 178.04 $44.64

1st Qtr '10 70.80 123.84 151.72 165.09 183.29 $50.45

4th Qtr '09 63.50 109.05 137.54 148.17 163.79 $45.04

Dec. 16 - 22, '09 65.73 117.50 145.56 155.73 167.08 $47.24

Conway, Group 140 Eth Pro Norm Iso Pen+ NGL Bbl

Dec. 15 - 21, '10 51.14 125.40 169.57 171.90 205.90 $50.77

Dec. 8 - 14, '10 51.93 121.66 170.70 171.00 206.50 $50.53

Dec. 1 - 7, '10 52.15 120.64 167.22 169.10 199.55 $49.74

Nov. 24 - 30 '10 48.83 120.07 157.70 166.40 190.73 $47.96

November '10 48.20 119.49 154.72 158.68 189.78 $47.36

October '10 41.59 118.37 150.62 158.08 184.00 $45.52

3rd Qtr '10 31.16 101.46 132.39 141.93 163.91 $39.04

2nd Qtr '10 31.56 103.03 130.96 145.20 172.55 $39.90

1st Qtr '10 59.82 123.81 143.58 160.70 181.55 $48.69

4th Qtr '09 52.71 109.26 140.03 145.23 169.77 $44.39

Dec. 16 - 22, '09 58.50 126.30 151.86 154.68 178.65 $48.84

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Dec. 23, 2010 Frac Spread: Margins Improve Despite Mixed NGL Prices(Note: This is not this week’s Frac Spread)

Frac spread margins for the week of December 23 improved across the board despite an up-and-down week for natural gas liquids (NGL) prices as natural gas feedstock prices ex-perienced significant decreases at both Mont Belvieu and Conway. Gas prices at Texas were down 9% to US$4.05 per million Btu (/MMBtu) while Kansas gas prices fell 10% to $3.97/MMBtu.

Light NGLs had the greatest improvements in margin at both hubs due to their overall stronger price performance this week with ethane margins improving by 9% at Conway and 11% at Mont Belvieu and propane margins rising 9% at Conway and Mont Belvieu.

The smallest gain in margin posted at Conway was for C5+, which had a 3% improvement, while butane had the smallest gain in margin at Mont Belvieu at 1%.

The theoretical NGL barrel price improved 1% at both hubs with the Conway price rising to $50.77 per barrel (/bbl) with a 5% improvement in margin to $36.27/bbl while the Mont Belvieu theoretical barrel price improved to $53.27/bbl with a 5% margin improvement to $38.47/bbl.

The most profitable NGL to make at both hubs was C5+ at $1.64 per gallon (/gal) at Mont Belvieu and $1.62/gal at Con-way. This was followed, in order, by iso-butane at $1.37/gal at Mont Belvieu and $1.32/gal at Conway; butane at $1.28/gal at both Mont Belvieu and Conway; propane at 94¢/gal at Mont Belvieu and 89¢/gal at Conway; and ethane at 37¢/gal at Mont Belvieu and 25¢/gal at Conway. – Frank Nieto

Current Frac Spread (Cents/Gal)December 23, 2010

ConwayChange from Last Week

Mont Belvieu

Last Week

Ethane 51.14 64.01

Shrink 26.32 26.85

Margin 24.82 8.74% 37.16 10.99%

Propane 125.40 131.20

Shrink 36.37 37.10

Margin 89.03 9.32% 94.10 8.79%

Normal Butane 169.57 169.92

Shrink 41.17 42.00

Margin 128.40 2.58% 127.92 1.20%

Iso-Butane 171.90 177.36

Shrink 39.54 40.34

Margin 132.36 3.99% 137.02 1.73%

Pentane+ 205.90 208.45

Shrink 44.03 44.91

Margin 161.87 2.57% 163.54 1.69%

NGL $/Bbl 50.77 0.47% 53.27 0.76%

Shrink 14.50 14.79

Margin 36.27 5.14% 38.47 4.88%

Gas ($/mmBtu) 3.97 -9.57% 4.05 -8.58%

Gross Bbl Margin (in cents/gal)

83.11 5.59% 89.70 5.24%

NGL Value in $/mmBtu

Ethane 2.82 -1.52% 3.52 1.85%

Propane 4.35 3.07% 4.55 3.24%

Normal Butane 1.83 -0.66% 1.84 -1.40%

Iso-Butane 1.07 0.53% 1.10 -0.82%

Pentane+ 2.65 -0.29% 2.69 -0.71%

Total Barrel Value in $/mmbtu

12.73 0.57% 13.71 1.12%

Margin 8.76 5.95% 9.66 5.83%

Price, Shrink of 42-gal NGL barrel based on following: Ethane, 36.5%; Propane, 31.8%; Normal Butane, 11.2%; Isobutane, 6.2%; Pentane+, 14.3%, Fuel, frac, transport costs not included. Conway gas based on NGPL Midcontinent zone, Mont Belvieu based on Houston Ship Channel.

Shrink is defined as Btus that are removed from natural gas through the gathering and processing operation.

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MIDSTREAM NEWS

Chesapeake Monetizes Haynesville Midstream AssetsChesapeake Midstream Partners LP plans to acquire the Springridge natural gas gathering system and related facili-ties in the Haynesville shale from Chesapeake Midstream Development LP, a subsidiary of Chesapeake Energy Corp. for US$500 million in cash.

The assets include Chesapeake’s 100% ownership inter-est in the Springridge system, which consists of 220 miles of gathering pipeline in Caddo and De Soto parishes, Louisi-ana. The average throughput on the system during the 2010 third quarter was approximately 400 million cubic feet per day, with significant future exposure to third-party volume. The acquisition allows Chesapeake Midstream Partners to broaden its operating footprint and provides access to the Haynesville Shale, which is one of the largest and lowest cost natural gas fields in the United States.

Pro forma, Chesapeake Midstream Partners will simul-taneously enter a 10-year, 100% fixed-fee gas-gathering agreement with Chesapeake, which includes a significant acreage dedication, annual fee redetermination and a mini-mum volume commitment. The combination of basin di-

versification, increased footprint, access to third-party volumes, low risk contractual terms and anticipated growth prospects makes the acquisition an attractive addition to the Partnership’s portfolio.

The acquisition will be financed with a draw on the part-nership’s revolving credit facility of approximately $250 million plus $250 million of cash on hand. Following the transaction, the partnership will have approximately $500 million of additional borrowing capacity on its credit facility.

Chesapeake Midstream Partners chief executive J. Mike Stice said, “We are pleased to deliver an attractive drop-down within six months of our IPO. We expect the acquisi-tion to be immediately accretive to distributable cash flow and believe these assets, located in one of the premier cost-advantaged unconventional plays, have significant potential for organic growth. This transaction is consistent with our best-in-class business model which is based on long-term contractual arrangements.”

The deal is expected to close before Dec. 31.

Targa Increases Eagle Ford NGL Transportation with Possible Permian OutreachTarga Resources Partners LP has entered into an exclu-sive non-binding Memorandum of Understanding (MOU) with TexStar Midstream Services LP and TEAK Midstream LLC for the development of a new pipeline to transport natural gas liquids from processing facilities in the Eagle Ford shale to Mont Belvieu, Texas. This agreement includes a plan for a new fractionation train at the Targa Resources Partners operated Cedar Bayou fractionation facility (CBF). CBF is owned by Cedar Bayou Fractionators LP, a joint ven-ture that is 88% owned by Targa Resources Partners.

When the transaction is finalized, Targa Resources Part-ners expects to become an owner in the new pipeline that will provide transportation services from natural gas processing plants in the Eagle Ford shale area, including a TEAK gas plant and a TexStar gas plant, into Mont Belvieu, Texas. The new pipeline will be designed to provide additional capacity to customers in the Eagle Ford shale area. Additionally, the pipeline will be designed to accommodate a future extension into the Permian Basin area of West Texas to provide trans-portation services to that growth region.

CBF will expand by 100,000 barrels per day (b/d), with commencement of operations expected in late 2012. The 100,000 b/d expansion will be an addition to the current 78,000 b/d expansion at CBF, which is expected to be op-erational in the second quarter of 2011. Upon the completion of both expansions, the fractionation capacity of CBF will be about 353,000 b/d.

TEAK will install and operate a new cryogenic natural gas processing plant with about 200 million cubic feet per day (MMcf/d) of processing capacity, and TexStar is expected to also install and operate a new cryogenic natural gas process-ing plant with about 300 MMcf/d of processing capacity. TEAK and TexStar will expand existing gas gathering sys-tems that supply the new natural gas processing plants. Both plants are expected to produce about 50,000 b/d. Combined, the two processing plants and the gathering systems behind them will serve 12 counties in the liquids-rich Eagle Ford shale of South Texas.

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XTO Scoops Up Petrohawk’s Fayetteville Gas, Midstream AssetsXTO Energy Inc., a subsidiary of ExxonMobil Corp., has purchased the Fayetteville shale gas assets of Petrohawk En-ergy Corp. for about US$575 million.

The Fayetteville shale gas assets are primarily in Cleburne and Van Buren counties, Arkansas.

Petrohawk had estimated proved reserves in the Fayette-ville shale of about 299 billion cubic feet of gas (Bcf) as of year-end 2009. Current production is about 98 million cubic feet of gas equivalent per day.

Additionally, Petrohawk has agreed to sell XTO Energy its midstream assets in the Fayetteville shale for $75 million. Combined, the two deals are worth $650 million.

ExxonMobil acquired XTO Energy earlier this year to become one of the leading operators in U.S. unconventional plays. XTO currently holds some 380,000 net acres in the Fayetteville shale. Petrohawk first entered the Fayetteville through its merger with KCS Energy Inc. in 2006. The sale is part of a capital raise to fund company capex in the Eagle Ford shale.

The portion of the deal involving the midstream assets is expected to close in early 2011. The effective date is Oct. 1.

Bank of America Merrill Lynch is financial advisor to Petrohawk.

Michael Hall, senior analyst at Wells Fargo Securities LLC, said that although the deal value was “somewhat below our expectations of more than $700 million,” the firm still views the sale as positive.

Hall estimates the deal metrics for the combined sale, con-sisting of 299 billion cubic feet equivalent proved and 98 million cubic feet equivalent per day flowing, at $2.17 per thousand cubic feet equivalent (Mcfe) and $6,633 per Mcfe per day, respectively.

“(The deal) finalizes an important funding catalyst for Petrohawk’s 2011 program,” Hall said in a Dec. 23 research report. “Net of these sales, we put the 2011 capex program at around $550 million above cash flow on our deck, or some $580 million on the strip—both very manageable numbers by our view.”

Raymond James analyst J. Marshall Adkins equates the deal to $1.92 per thousand cubic feet or around $5,900 per flowing thousand cubic feet, slightly below its early 2010 divestitures, “but a fair price considering today’s gas prices,” he conceded.

AltaGas’ Harmattan Co-stream Project ApprovedCalgary-based AltaGas Ltd received approval from the Al-berta Energy Resources Conservation Board on its Harmat-tan Co-stream Project.

AltaGas entered into a Memorandum of Understanding (MOU) with Nova Chemicals in 2009. The MOU provides that the definitive agreements would be for an initial term of 20 years and would have AltaGas deliver all liquids or co-stream gas products on a full cost-of-service basis to NOVA Chemicals. The agreement provides that all capital expendi-tures and operating costs related to the proposed project will be fully recovered through fees under normal operations.

The Co-stream Project will allow 250 million cubic feet per day (MMcf/d) of rich, sweet natural gas sourced from the NGTL Western Alberta System to be processed using spare capacity at the Harmattan Complex to recover ethane and natural gas liquids (NGLs).

It will expand the availability of valuable feedstock for Alberta’s petrochemical industry and retain extraction rev-enues and value in Alberta in an economical manner. The current throughput at the Harmattan Complex is about 150 MMcf/d, or 30% of the licensed plant capacity.

The Co-stream Project involves constructing and operat-ing two new large-diameter high pressure sweet natural gas pipelines and one small-diameter high vapor pressure prod-uct pipeline, as well as modifying existing equipment for processing gas at the Complex. Construction of the project will take approximately 14 months to complete. The proj-ect is expected to begin contributing to operating income in early 2012. The capital cost estimate for the Co-stream Proj-ect is C$100-120 million (US$99.3-119.2 million).

9

December 30, 2010

www.worldfuels.com/GPRHart Energy Publishing

Frac spread margins continued to show improvements this week as natural gas liquids (NGL) prices rose while natural gas feedstock prices continued to fall. Once again the largest gains were posted by lighter NGLs due to stronger heating demand and tighter ethane balances.

The biggest margin improvements were for Conway eth-ane, which rose 6% from last week, and Conway propane, which rose 3% from the previous week. The largest improve-ments in margin at Mont Belvieu were for propane and C5+, which both rose 3% from last week.

The lone NGL to drop in margin this week was butane, which was down 2% at both hubs. Iso-butane had the small-est gain in margin at both hubs this week, as the Conway margin was up 2% from last week while the Mont Belvieu margin saw a 1% improvement from last week.

Pricing for the theoretical NGL barrel only rose 1% from last week at both hubs with the Mont Belvieu price improv-ing to $53.80 per barrel (/bbl) with a frac spread margin improvement of 2% to $39.11/bbl. The Conway theoretical barrel price rose to $51.39/bbl with a frac spread margin im-provement of 2% at $36.92/bbl.

The most profitable NGL to make at both hubs remained C5+ at $1.68 per gallon (/gal) at Mont Belvieu and $1.64/gal at Conway. This was followed, in order, by iso-butane at $1.39/gal at Mont Belvieu and $1.35/gal at Conway; butane at $1.26/gal at Mont Belvieu and Conway; propane at 97¢/gal at Mont Belvieu and 92¢/gal at Conway; and ethane at 38¢/gal at Mont Belvieu and 26¢/gal at Conway.

Natural gas in storage for the week of December 17, the most recent data available from the U.S. Energy Information Administration, was down 184 billion cubic feet to 3.368 trillion cubic feet (Tcf) from the 3.552 Tcf storage level re-corded the previous week. This was 2% below the 3.424 Tcf storage figure recorded last year at the same time and 9% above the five-year average of 3.104 Tcf.

The U.S. National Weather Service’s forecast for the coming week is calling for the recent cold spell to continue throughout the entire Southern United States. The areas ex-pected to experience the most out-of-normal cold weather are the Southeast and Southwest. However, this cold weather is not expected to affect the New England and Tri-State regions as they are expected to experience normal winter weather.

– Frank Nieto

Current Frac Spread (Cents/Gal)December 30, 2010

ConwayChange from Last Week

Mont Belvieu

Last Week

Ethane 52.53 64.63

Shrink 26.25 26.65

Margin 26.28 5.87% 37.98 2.20%

Propane 128.05 133.45

Shrink 36.27 36.82

Margin 91.78 3.08% 96.63 2.68%

Normal Butane 166.8 167.65

Shrink 41.07 41.69

Margin 125.73 -2.08% 125.96 -1.53%

Iso-Butane 174 178.5

Shrink 39.44 40.04

Margin 134.56 1.66% 138.46 1.05%

Pentane+ 208.33 212.15

Shrink 43.92 44.58

Margin 164.41 1.57% 167.57 2.47%

NGL $/Bbl 51.39 1.22% 53.8 0.99%

Shrink 14.47 14.69

Margin 36.92 1.81% 39.11 1.65%

Gas ($/mmBtu) 3.96 -0.25% 4.02 -0.74%

Gross Bbl Margin (in cents/gal)

84.71 1.93% 91.24 1.73%

NGL Value in $/mmBtu

Ethane 2.89 2.72% 3.56 0.97%

Propane 4.45 2.11% 4.63 1.71%

Normal Butane 1.80 -0.02 1.81 -1.34%

Iso-Butane 1.08 1.22% 1.11 0.64%

Pentane+ 2.69 1.18% 2.74 1.78%

Total Barrel Value in $/mmbtu

12.91 1.44% 13.85 1.04%

Margin 8.95 2.20% 9.83 1.79%

Price, Shrink of 42-gal NGL barrel based on following: Ethane, 36.5%; Propane, 31.8%; Normal Butane, 11.2%; Isobutane, 6.2%; Pentane+, 14.3%, Fuel, frac, transport costs not included. Conway gas based on NGPL Midcontinent zone, Mont Belvieu based on Houston Ship Channel.

Shrink is defined as Btus that are removed from natural gas through the gathering and processing operation.

FRACTIONATION SPREAD

Frac Spread Margins Continue to Improve with NGL Prices

10

December 30, 2010

www.worldfuels.com/GPRHart Energy Publishing

This week natural gas liquids (NGL) prices improved in all but one case from last week as the holiday season and colder weather increased demand in most cases at both Mont Belvieu and Conway.

The biggest increase from last week was for light NGLs at Conway, as both ethane and propane prices improved by 2%. Con-way ethane rose to 53¢, its highest price since it was 57¢ the week of March 3. The hub’s price of US$1.28 for propane was the highest it has been since it was $1.29 the week of February 10.

Mont Belvieu ethane and propane rose 1% each with ethane’s price of 65¢ being the hub’s highest price since November 3 when it was also 65¢. The propane price of $1.34 was the highest price at the hub since it was $1.36 the week of February 3.

Propane’s price increases were due to increased heating demand as the winter season continued its belated arrival in the Northeast and Midwest while ethane de-mand keeps growing as ethane inventories continue to tighten.

Iso-butane rose 1% at both hubs, as it was up to $1.79 at Mont Belvieu and $1.74 at Conway. The Mont Belvieu price was the second-highest at the hub since it was $1.82 the week of September 3, 2008. The Conway price was the highest since the week of February 3 when it was also $1.74. Iso-butane prices continue to benefit from strong demand for winter-grade gasoline.

Pentanes-plus (C5+) continues to benefit from improved crude prices, as both the Mont Belvieu and Conway prices rose 1% this week. The Mont Belvieu price of $2.12 was the highest at the hub since it was also $2.12 the week of

September 10, 2008. The Conway price of $2.08 was that hub’s highest price since it was $2.26 the week of Septem-ber 24, 2008.

The lone NGL to drop in value this week was butane, which fell 1% at both Mont Belvieu and Conway. The Mont Belvieu price of $1.68 and the Conway price of $1.67 were the lowest prices in a month at their respective hubs.

– Frank Nieto

NGL Prices Improve on the Back of Colder WeatherBOX SCORE

Data Provided by Intercontinental Exchange. Individual product prices in cents per gallon. NGL barrel in $/42 gallons

Box ScoreMont Belvieu Eth Pro Norm Iso Pen+ NGL Bbl

Dec. 22 - 28, '10 64.63 133.45 167.65 178.50 212.15 $53.80

Dec. 15 - 21, '10 64.01 131.20 169.92 177.36 208.45 $53.27

Dec. 8 - 14, '10 62.85 127.08 172.34 178.82 209.95 $52.87

Dec. 1 - 7, '10 63.49 125.02 170.66 176.96 208.82 $52.51

November '10 62.88 125.42 161.66 166.63 197.78 $50.96

October '10 54.21 123.20 154.62 160.26 192.08 $48.44

3rd Qtr '10 44.99 106.98 138.23 143.25 171.45 $42.37

2nd Qtr '10 50.97 108.43 145.01 157.23 178.04 $44.64

1st Qtr '10 70.80 123.84 151.72 165.09 183.29 $50.45

4th Qtr '09 63.50 109.05 137.54 148.17 163.79 $45.04

Dec. 23 - 29, '09 73.38 128.05 154.25 167.60 170.20 $50.66

Conway, Group 140 Eth Pro Norm Iso Pen+ NGL Bbl

Dec. 22 - 28, '10 52.53 128.05 166.80 174.00 208.33 $51.39

Dec. 15 - 21, '10 51.14 125.40 169.57 171.90 205.90 $50.77

Dec. 8 - 14, '10 51.93 121.66 170.70 171.00 206.50 $50.53

Dec. 1 - 7, '10 52.15 120.64 167.22 169.10 199.55 $49.74

November '10 48.20 119.49 154.72 158.68 189.78 $47.36

October '10 41.59 118.37 150.62 158.08 184.00 $45.52

3rd Qtr '10 31.16 101.46 132.39 141.93 163.91 $39.04

2nd Qtr '10 31.56 103.03 130.96 145.20 172.55 $39.90

1st Qtr '10 59.82 123.81 143.58 160.70 181.55 $48.69

4th Qtr '09 52.71 109.26 140.03 145.23 169.77 $44.39

Dec. 23 - 29, '09 61.25 133.28 165.33 167.33 178.83 $51.18

11

December 30, 2010

www.worldfuels.com/GPRHart Energy Publishing

PIPELINE NEWS

EIA’s 2011 Outlook: Alaska Gas Pipeline Unlikely for Next 20 YearsAccording to the recent 2011 Annual Energy Outlook (AEO) issued by the U.S. Energy Information Administration (EIA), it is unlikely that either of two proposed pipelines, Denali – the Alaska Gas Pipeline or the Alaska Highway Pipeline coming out of Alaska’s North Slope into the Lower 48 states will be built in the next 20 years because of higher construc-tion costs and lower natural gas prices.

EIA’s 25-year outlook for the domestic energy market does not include a natural gas pipeline from Alaska into the Lower 48 states during this time period because of the prolif-eration of shale gas plays. However, the report does note that it is likely that the economics hindering the project will result in project delays rather than outright cancellations.

The previous AEO included an Alaska gas pipeline being online by 2023, but this new AEO stated that the elimina-tion of such a pipeline was a result of “increased capital cost assumptions and lower natural gas wellhead prices, which make it uneconomical to proceed with the project over the projection period.”

Before this new AEO there had already been increased speculation that these two projects were likely to be pushed back from their current timetables due to poor economics despite both projects recently holding open seasons.

The US$35 billion Denali pipeline, which is a joint ven-ture between BP and ConocoPhillips that includes a natural gas processing plant in addition to the proposed 1,700-mile pipeline, was not included on ConocoPhillips’ list of projects in its most recent round of analyst presentations.

The $41 billion Alaska Pipeline Project/Alaska High-way Pipeline is being jointly developed by TransCanada

and ExxonMobil and would stretch roughly the same length as the Denali pipeline, but would also include ac-cess to liquefied natural gas (LNG) terminals as well as perceived shipper commitments from ExxonMobil, the largest holder of North Slope natural gas reserves (see Gas Processors Report 06/17/09).

The project also has a $500 million commitment from the State of Alaska’s Alaska Gasline Inducement Act (AGIA), which was created in 2007 to encourage de-velopment of a natural gas pipeline in the state (see Gas Processors Report 01/16/08).

However, since completing its open season in July, there hasn’t been much noise out of the project, which has caused some to question if it may move its timetable back. It should be noted that the heads of both projects continue to express strong public support of the two projects.

In addition, Philip Budzik, an EIA analyst, stated that the organization’s outlook is not set in stone and is primarily based on its internal price outlooks for natural gas. If gas prices remain below $6.18 per thousand cubic feet in 2009 dollars, then the project (the outlook is of the impression of many analysts that only one project will actually see fruition) does not get included in the EIA outlook because it is judged that the project is not economically feasible.

“The reference case isn’t the future. It’s just our best rep-resentation of the future based on what we know today. What tomorrow will bring, I do not know,” Budzik said.

– Frank Nieto

INTERNATIONAL NEWS

Saudi Aramco Moves Wasit Gas Plant Completion Date Up to 2013Saudi Aramco moved up the completion date for its Wasit natural gas processing plant up by one year to December 2013 in order to meet increased domestic demand for natural gas, which is increasing at an average of 5-6% annually.

At 2.5 billion cubic feet per day (Bcf/d) of processing ca-pacity, the Wasit plant will be the largest in Saudi Arabia when it comes online in February 2014 and help the country achieve its goal of processing approximately 15.5 Bcf/d by 2015, up from the current level of 10.2 Bcf/d.

Saudi Aramco is also in the midst of developing its US$5-6 billion Shaybah natural gas liquids (NGL) project, which would process up to 2.4 Bcf/d of low-sulphur sweet gas and extract 264,000 barrels of NGLs that will ship to the company’s Juaymah gas plant for further extraction (see Gas Processors Report 10/07/10).

The company is in the midst of accepting construction bids for the Wasit plant and anticipates beginning the bid-ding process for the Shaybah project in 2011.

– Frank Nieto

12

December 30, 2010

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