Replies to This Discussion

Permalink Reply by Jack Straw on August 18, 2014 at 2:18pm

Source: http://www.nasdaq.com/article/us-rig-count-keeps-rising-as-natural-...

U.S. Rig Count Keeps Rising as Natural Gas Drilling Improves - Analyst Blog

By Zacks.com,  August 18, 2014, 01:23:00 PM EDT

In its weekly release, Houston-based oilfield services company Baker Hughes Inc. ( BHI ) reported a rise in the U.S. rig count (number of rigs searching for oil and gas in the country). This can be primarily attributed to an increase in the tally of gas-directed rigs.

The Baker Hughes data, issued since 1944, acts as an important yardstick for energy service providers in gauging the overall business environment of the oil and gas industry.

Analysis of the Data

Weekly Summary: Rigs engaged in exploration and production in the U.S. totaled 1,913 for the week ended Aug 15, 2014. This was up by 5 from the previous week's rig count and indicates the fourth increase in as many weeks.

The current nationwide rig count is more than double the lowest level reached in recent years (876 in the week ended Jun 12, 2009) and is well above the prior-year level of 1,791. It rose to a 22-year high in 2008, peaking at 2,031 in the weeks ending Aug 29 and Sep 12.

Rigs engaged in land operations ascended by 9 to 1,841, inland waters activity was down by 4 to 10 rigs, while offshore drilling remained steady at 62 units.

Natural Gas Rig Count: The natural gas rig count - which in mid-June slumped to its lowest point since May 1993 - increased for the second successive week to 321 (a gain of 5 rigs from the previous week). Despite the weekly growth, the number of gas-directed rigs is down by 60% from its recent peak of 811, achieved in 2012.

In fact, the current natural gas rig count remains 80% below its all-time high of 1,606 reached in late summer 2008. In the year-ago period, there were 388 active natural gas rigs.

(Jack's note: it must be recognized that today's rigs drill more feet of producing formation than was possible in the past ... fewer rigs can 'make more hole'. Long offset horizontal well, multiple wells from a single pad, 'walking' rigs all contribute.)
 
Oil Rig Count: The oil rig count was up by 1 to 1,589. The current tally - the highest since Baker Hughes started breaking up oil and natural gas rig counts in 1987 - is way above the previous year's rig count of 1,397. It has recovered strongly from a low of 179 in June 2009, rising 8.9 times.

Miscellaneous Rig Count: The miscellaneous rig count (primarily drilling for geothermal energy) at 3 was down by 1 from the previous week.

Rig Count by Type: The number of vertical drilling rigs fell by 10 to 368, while the horizontal/directional rig count (encompassing new drilling technology that has the ability to drill and extract gas from dense rock formations, also known as shale formations) was up by 15 to 1,545. However, horizontal rig units increased by 12 from the last week's level to reach an all-time high of 1,329.

Gulf of Mexico (GoM): The GoM rig count remained flat at 60. The number of oil drilling rigs improved by 1 to 44, offset by a unit decrease in gas rigs to 16.

Conclusion

A Key Barometer of Drilling Activity: An increase or decrease in the Baker Hughes rotary rig count heavily weighs on the demand for energy services - drilling, completion, production etc. - provided by companies that include large-cap names like Halliburton Co. ( HAL ) and Schlumberger Ltd. ( SLB ).

Permalink Reply by Jack Straw on August 19, 2014 at 4:22pm

Source: http://www.investingdaily.com/20990/exploding-marcellus-has-more-in...

Exploding Marcellus Has More in the Tank

By Robert Rapier on August 19, 2014

In last week’s Energy Letter, I discussed the one million barrel per day (bpd) milestone for North Dakota oil production, and provided a refresher on the geology and the players in North Dakota’s Williston Basin.

Another energy production milestone was recently announced by the Energy Information Administration (EIA), and it is just as amazing as North Dakota’s rise as a major oil producer. In an Aug. 5 report, the EIA noted that natural gas production in the Marcellus Formation has exceeded 15 billion cubic feet per day (Bcf/d) for the first time. This amounts to nearly 23% of all US natural gas production, and some 40% of all US shale gas production.


Marcellus gas production has increased from 2 Bcf/d in 2010 to 15 Bcf/d today, and it is now the largest shale gas producing region in North America. In fact, the current 15 Bcf/d is equivalent to Canada’s average rate of production last year, and nearly three times Mexico’s.

So this week in honor of another milestone, let’s take a tour of the Marcellus.

Marcellus Overview

The Marcellus Shale is a black shale formation found largely underneath Pennsylvania, West Virginia, southern New York, eastern Ohio, and extreme western Maryland. Most Marcellus wells are drilled at a depth of 5,000 to 9,000 feet beneath the surface, and are then turned horizontally up to 10,000 feet. The wells are hydraulically fractured to release (primarily) the natural gas from the shale. Much of the Marcellus production to date has taken place in Pennsylvania, where the thickness of the formation ranges from 20 feet in the northwest of the state to more than 250 feet in the northeast.

Just as the Three Forks formation in North Dakota underlies the Bakken, the Utica Shale underlies large parts of the Marcellus, but the Utica also extends further west into Ohio. Above the Marcellus lies the Upper Devonian, and the entire region is part of the Appalachian Basin.

Just to put into perspective what a big deal this shale gas play is (if the explosive growth of Pennsylvania’s gas production is insufficient), the EIA estimated in 2009 that Pennsylvania’s proved shale gas reserves were 88 billion cubic feet (Bcf), which is equivalent to less than a day and a half of US production. At the end of 2012, the EIA had upped that estimate to 32,681 Bcf, a 371-fold increase. Over that same time span, West Virginia saw its own proved shale gas reserves increased from 14 Bcf to 9,408 Bcf.   

Fracking 101

The Marcellus is really ground zero for the controversies surrounding fracking, so let me make a small digression to bring readers up to speed. Hydraulic fracturing, or “fracking” had been around since the late 1940s and has been used for decades to promote higher production rates from oil and gas wells across traditional production regions like Texas and Oklahoma. Fracking has been used to stimulate oil and gas production in more than 1 million wells in the US.

Fracking involves pumping water, chemicals and a proppant down an oil or gas well under high pressure to break open channels (fractures) in the reservoir rock trapping the deposit. Oil and gas do not travel easily through these shale formations, which is why they need to be fractured. The proppant is a granular material designed to hold those channels open, allowing the oil (or natural gas) to flow to the well bore. Some common proppants include sand, ceramics, glass beads — even walnut shells have been utilized, but sand is by far the most common proppant in use.

While fracking has been around for decades, two developments in recent years are responsible for thrusting the technique into the public eye.

The first is the fairly recent development of combining fracking with another common technique used in the oil and gas industry — horizontal drilling. Like fracking, horizontal drilling was invented decades ago, and has been widely used in the oil and gas industry since the 1980s. As its name implies, horizontal drilling involves drilling down to an oil or gas deposit and then turning the drill horizontal to the formation to access a greater fraction of the deposit. These horizontal laterals can be up to 10,000 feet in length, and therefore cover a much greater area below ground than a conventional vertical well.


Source: ProPublica

The second development is that drilling started to push into populated areas unaccustomed to oil and gas development. If fracking was still relegated to the traditional oil and gas producing states, I doubt much of the public would have heard of it. But these populated areas weren’t used to having energy development in their backyard, and as it began to happen many people rebelled against this intrusion into their lives. As someone who believes that fracking is generally safe, I can nevertheless understand the desire by locals to keep it out of their neighborhood. Even ExxonMobil CEO Rex Tillerson joined a lawsuit (which he later dropped out of) against a fracking-related development in his neighborhood.

I don’t want to get into the a long digression on the evidence regarding the environmental implications here. There is enough material there to fill two or three Energy Letters. I will just say that I believe fracking is generally safe, and concerns over water supplies are mostly overblown. (There is generally more than a mile of rock between fracked zones and water supplies).  However, I think there is substantial evidence that reinjecting wastewater from fracking back into the ground is responsible for the enormous increase in earthquakes in my home state of Oklahoma.

Now, back to the Marcellus.

Just Hype?

The shale gas boom has a lot of critics, both from an environmental perspective and from an economic and/or sustainability perspective. One frequent criticism is that shale gas wells deplete rapidly in the first year or so, and therefore more and more wells must be drilled just to make up for what has been depleted. This is absolutely correct, as can be seen in the following graphics from the EIA:

Source: Marcellus Region Drilling Productivity Report

The graphics clearly show that cumulative legacy production falls rapidly (and for individual wells the decline is even steeper), but to date this has been more than offset by production from new wells. This of course can’t go on forever, and when the drilling sites are saturated the region will likely see gas production decline steeply. Most forecasts don’t anticipate a decline setting in for at least a few more years, but it’s something we will be watching closely here.

Companies in the Marcellus

Space constraints don’t allow me to take a deep dive into the Marcellus companies, which are more diverse than the Bakken producers I highlighted last week. Among the major Marcellus producers covered in depth in The Energy Strategist are Cabot Oil and Gas (NYSE: COG), EQT (NYSE: EQT), Range Resources (NYSE: RRC) and Southwestern Energy (NYSE: SWN). However, these companies vary in lot in their production (gas versus liquids) and risk profile. Further, the Marcellus has logistical constraints in some areas for getting the gas to market. This has resulted in significant regional discounts on Marcellus gas at times, but has also created enormous opportunities for pipeline companies and infrastructure providers in the region.

Conclusions

The Marcellus Shale and surrounding Appalachian Basin have a growth story every bit as impressive as that of the Bakken, which I covered in last week’s Energy Strategist. The area has become the most important shale gas producing region in the country, despite challenges from environmentalists. In addition, there are logistical challenges that have prevented this gas from reaching some of the lucrative markets of the northeast. We expect more growth from the Marcellus and like a number of companies operating in the area. Join us at The Energy Strategist for in-depth analysis and profitable recommendations of the companies riding the Marcellus boom.

Permalink Reply by farmgas on August 19, 2014 at 11:11pm

Jack, how do you think the long-term contract Consol CNX Gas has with Dominion to provide gas on a yearly basis for 15 years will affect their development planning for the Central Pa Region?   Will the 30% growth committed by ownership apply to the CPA, too?...Thanks

Permalink Reply by Jack Straw on August 20, 2014 at 8:42am

RE: "how do you think the long-term contract Consol CNX Gas has with Dominion to provide gas on a yearly basis for 15 years will affect their development planning for the Central Pa Region?"

I heard second hand (a CNX Landman related to a friend who passed the information on to me) that CNX had negotiated a substantial guaranteed amount of capacity to be available in the Dominion pipeline that passes through Big Run.

But, I do not know any of the details of such an agreement:

when it commences?,

how much gas has CNX committed to ship (in addition to what CNX are already producing from the (dying) existing shallow wells)?,

is there a penalty - should CNX not be able to provide an agreed minimum (and is that penalty substantial)?

If you happen to know the specific terms of the agreement (or where that information might be found in the public domain), I would appreciate it if you would pass that information along.

If CNX are in a 'ship or pay' situation; they may well need to hustle to avoid ongoing penalty payments; right now, I have witnessed no hustle.

I understand that at one point 18 months-two years ago CNX had indicated that they had planned significant activity for the Big Run area .... drilling, gathering lines, impoundment dams for frac water,  water treatment facilities ..... then, my sources indicated that about 18 months ago all went silent .... there had been a lot of talk, but no meaningful follow up action .... a lot of talk, but little money changing hands .... all flash, no cash; it seemed that CNX wanted to obtain lots of free 'options' from landowners (without any solid commitments from CNX) .... CNX wanted a lot of 'something', guaranteeing nothing tangible in return. 

Without my having knowledge of the specifics of CNX's agreement with Dominion, I am (sadly) in no position to speculate.

JS

  

Permalink Reply by DS on August 20, 2014 at 9:33am

Does this document have any information that is helpful? (I don't have the knowledge base to tell.)
http://www.ferc.gov/CalendarFiles/20110824181619-CP11-39-000.pdf

Permalink Reply by farmgas on August 20, 2014 at 11:28am

Thanks DS...this is exactly the contract agreement.   What do you think about this contract, Jack?   It seems like it would have an impact on their CPA Operation plans.   How would the Beaver Run Reservoir field impact this contract, too?  ....Thanks DS & Jack

Permalink Reply by Jack Straw on August 20, 2014 at 3:32pm

Thank you DS.

 

“ Dominion executed a long-term, binding precedent agreement with CONSOL Gas Company for firm transportation service totaling 200,000 dekatherms per day (Dth/d), which represents 100 percent of the proposed capacity of this project.”

 

1 dekatherms = 999,761.29 btu = let’s do a tiny bit of rounding it off and call it 1million btu.

The average gross heating value of natural gas is approximately 1,020 British thermal units per standard cubic foot (btu/scf).

 

1 dekatherms = 1,020 cubic feet = 1 mcf  

200,000 dekatherms per day (Dth/d) = 204,000 mcf/d

 

Source: http://www.ogj.com/articles/uogr/print/volume-2/issue-2/range-resources-boosts-marcellus-shale-production-above-1-bcfd.html

 

“Range also is optimizing drilling and completion in the dry gas area of its southwest Pennsylvania leasehold. Plans call for increasing the average lateral length of wells drilled in this area to 5,200 ft and utilizing 26 stage completions in 2014, an increase from 2,950 ft laterals with 14 stages in 2013. This is expected to result in an average EUR of 13.4 bcf/well.”

 

1 bcf = 1,000,000 mcf

One ‘average’ Marcellus well (per Range’s prediction) would require 66 days worth of Consol’s full contracted capacity … during the productive lifetime of that well.

We know that the production of a Marcellus well is very front-loaded …. I’ll take a wild guess and say that an ‘average’ Marcellus well will produce half its ultimate EUR in the first six years of production (actually probably less than six years).

66 days/2 (for half production) = 33 days.  

33 days/6 years = 5.5 days/well.

 

For one year … 365 days/year / 5.5 days/well = 66 wells

The drilling of 66 wells would (over their first six years of production) fulfill Consol’s commitment to Dominion.

With six wells/drilling pad = 11 drilling pads.

 

Let’s say that each horizontal is 5200’ and wells are spaced 1000’ apart.

Each well occupies 5,200,000 square feet.

43,560 square feet/acre … 120 acres per well … 720 acres per six well pad

11 drilling pads = 7920 acres = 12 .4 square miles.

 

Area of Jefferson County = 655 square miles.

Area of Indiana County = 834 square miles.

Area of Clearfield County = 1,154  square miles.

Total 2634 square miles.

 

12 .4 square miles = 0.47% of the land area of the three above counties.

 

Let’s say that I was overly optimistic (by a factor of two) in the potential well results …. and pessimistic about any future improvements in technology and Consol need to drill (over a six year period) a full 1% of the land area of the combined three above Counties for Consol to fulfil their commitment to Dominion.

 

Now, unless there is something very seriously wrong with my very rough ‘back-of-the- envelope’ calculations; Consol will not have to do an extraordinary amount of drilling in order to fulfil their contracted commitment.

 

Unless there is something very seriously wrong with my very rough ‘back-of-the- envelope’ calculations; there will be a lot of drilling, and a lot of pipeline expansion …. and it will take many years to drill up these three Counties.

 

All IMHO,

                    JS

Permalink Reply by farmgas on August 20, 2014 at 4:33pm

Thanks JS....so, are you saying this contract isn`t too difficult for Consol to fulfill in CPA?   Currently, they only have 4 producing wells at the Bower well pad.   The Marchand well hasn`t been turned in yet.  The many shallow wells in the area would be adding gas, too, maybe the most right now.   Without additional drilling it would seem to me they are not meeting the contract amount of gas per day.   Would you agree?  The wells at Beaver Run Reservoir could be contributing significant gas to the system.  

Permalink Reply by Jack Straw on August 20, 2014 at 4:13pm

Source: http://www.xconomy.com/san-francisco/2014/08/20/siluria-bags-30m-fr...

Siluria Bags $30M from Saudi Aramco for Natural-Gas-to-Gasoline Tech

Martin LaMonica8/20/14

Many startups are seeking to take advantage of cheap and abundant natural gas to make chemicals and fuels, but Siluria Technologies is one of the few moving to large-scale production.

The San Francisco-based company today said that Saudi Aramco Energy Ventures has invested $30 million of a planned $50 million Series D round expected to close this year. It’s the first time that Siluria has taken on a strategic investor, rather than financial investors, a move that could lead to Saudi Aramco using Siluria’s natural gas-to-chemicals process.

The money will be used to complete construction of a demonstration plant in La Porte, TX and continue research into using Siluria’s technology in other areas. Siluria expects to be operating two commercial-scale plants in 2017: one for producing the chemical ethylene and one for making gasoline from natural gas, says Rahul Iyer, the company’s vice president of corporate development.

Siluria’s technology uses catalysts to synthesize methane into more complex—and valuable—molecules, a fundamentally different approach to making the chemicals and fuels used in the petrochemical industry.

The traditional method of making ethylene, a common chemical used in various industries, is to use steam to “crack” long-chain hydrocarbons, such as naptha, into a two-carbon compound. Gasoline is similarly refined from crude oil using high temperatures and pressures.

Siluria’s chemical approach is less expensive and less polluting because less energy is needed during the processing, Iyer says. Natural gas enters a tube-shaped reactor in which secret catalysts trigger a chemical reaction between the natural gas and oxygen in the air to produce ethylene. In a similar method, it can combine ethylene molecules into gasoline.

Siluria is a good example of the innovation happening in fossil fuels and how the abundance of natural gas—particularly in the U.S., thanks to fracking—is dramatically changing the energy and chemicals industries. At current prices, making gasoline from natural gas with Siluria’s technology costs about $1 per gallon, Iyer says.

The low price of natural gas has even attracted some companies that had first planned to make fuels from plants. Primus Green Energy and Calysta both scrapped plans to make fuels from biomass and switched to natural gas as a feedstock.

Siluria also demonstrates the hefty capital requirements for commercializing energy technologies. The company has now raised nearly $100 million since 2008 to develop its approach, which grew from the lab of MIT materials scientist Angela Belcher.

The investment from Saudi Aramco, the world’s largest energy company, is expected to lead to business for Siluria, Iyer says. Saudi Aramco is already a large producer of industrial chemicals, and Siluria’s natural gas-based method will allow it to produce ethylene at low cost while giving it a hedge from the volatile prices of conventional feedstocks.

Martin LaMonica is a national correspondent for Xconomy covering energy and technology. You can reach him at mlamonica@xconomy.com or @mlamonica.

Permalink Reply by Tim Tarr on August 21, 2014 at 2:40am

http://www.sfgate.com/business/article/Natural-gas-to-1-gasoline-57...

$1 gallon at current prices to convert Natural Gas to Gasoline. WOW !! I'm sure that doesn't include capital cost for plant. Rather than going from Natural gas (CH4) to Gasoline (C8H18), Why not Propane (C3H8) or even better Butane (C4H10). Butane is a liquid at ~+30 degrees F at Sea Level. Butane has 23% more energy than Ethanol or ~80.59% GGE (gallon of Gasoline equivalent). No need for a heavy steel tank. Just strap a BIG Bic lighter on the truck and there you go. 

Permalink Reply by Jack Straw on August 21, 2014 at 11:41am

Source: http://in.reuters.com/article/2014/08/21/asia-lpg-idINL4N0QI1OF2014...

Banking on U.S. shale gas boom, Asia petrochemical firms switch to LPG

Fri Aug 22, 2014 2:30am IST

By Seng Li Peng

SINGAPORE, Aug 22 (Reuters) - Asia petrochemicals firms are building tanks and retooling plants to store and process liquefied petroleum gas imported from the United States, counting on a flood of supply from the shale boom to replace costlier naphtha as a raw material.

Samsung Total Petrochemical, LG Chem and Royal Vopak are among a number of companies in Asia expanding import terminals or retrofitting plants over the next one to two years as they buy more LPG. The gas is used by petrochemicals firms to make a broad range of consumer and industrial plastics.

Asian petrochemicals firms have traditionally used naphtha as a raw material. They are now switching to LPG because rising U.S. supplies have pushed prices below those of both naphtha and LPG from their main supplier, the Middle East. A looming rise in tanker supply from next year will also help cut U.S.-Asia freight costs.

A cutback in naphtha use will hit key regional suppliers of the fuel such as India's Oil & Natural Gas Corp (ONGC) and Kuwait Petroleum, who are already being forced to cut the premiums they charge on naphtha sales.

The LPG buying will, however, help the United States trim an expected surplus of the gas and give the shipping industry more business at a time when global trade is still recovering from the aftermath of the financial crisis.

Petrochemicals firms in South Korea, Japan, Taiwan and Thailand have bumped up their use of LPG since June as the gas has cost at least $50 a tonne less than naphtha, said traders who track the Asian fuel market closely.

"The Far East has been using 350,000 to 400,000 tonnes of LPG a month since June," said a trader who tracks naphtha and LPG, compared with at most 250,000 to 300,000 tonnes a month in the past.

Rising supplies of LPG - a compressed mix of propane and butane, also used for heating and transport - have widened the price gap between LPG and naphtha. In June, the average price of the gas was $916 a tonne versus naphtha's $972, a spread of $56. In the same month of last year gas was $17 cheaper than naphtha, data from Ginga Petroleum showed.

Both naphtha and LPG are produced by refining crude. A barrel of crude typically has a 3 percent LPG yield while for naphtha it is more than 10 percent. LPG is also obtained in the process of extracting natural gas.

The design of petrochemical plants in Asia, though, constrains how much LPG can replace naphtha. Typically, up to 15 percent of naphtha can be replaced. Even within that limit, plants in Asia have room to raise LPG use, which may mean more imports of the gas.

U.S. LPG SURPLUS

The shale boom is expected to spur U.S. LPG production. By 2019, the nation's surplus of the gas will double to 550,000 barrels per day (bpd) from 270,000 bpd in 2014, said U.S.-based consultancy firm ESAI.

Asia now accounts for more than a quarter of all U.S. LPG exports and that is set to rise steadily this decade. Exports to Asia could rise to 230,000 bpd by 2019 from 70,000-90,000 bpd this year, said Vivek Mathur, senior analyst at ESAI.

Supplies from the Middle East will also grow but exports may not rise as much as U.S. shipments. And Asia is eager to get its hands on U.S. LPG.

Chinese energy giant CNOOC Group's $8 billion petrochemical complex in Huizhou city aims to use U.S. LPG, a senior executive of the project's contractor said this week.

Samsung Total will build a 40,000-tonnes LPG tank to ride on the shale boom, a spokesman said, without giving a construction timeline.

South Korea's LG Chem will raise the LPG volume used by its crackers by half to 66,000 tonnes a month after October maintenance at its Yeosu complex.

And in Singapore, Royal Vopak will build an LPG storage facility with an initial capacity of 80,000 cubic meters to give petrochemical makers an alternative to naphtha.

Naphtha sellers are feeling the pressure. ONGC sold a September cargo at premiums to Middle East quotes of about $14.50 a tonne, its lowest in over two years.

The situation will worsen for them when new tankers are ready and the Panama canal expansion is completed by end-2015. Some 36 new LPG tankers are scheduled for delivery in 2015 and another 38 in 2016 versus five this year, said a Southeast Asia-based LPG trader, potentially helping lower freight rates.

U.S. LPG is available now for loading below $600 a tonne compared to the $760-$780 for the gas from the Middle East. Even with current freight rates from America to the Far East higher compared to rates from Middle East to Asia, U.S. LPG works out a cheaper option for Asian users.

"LPG prices should be more competitive versus naphtha due to the amount of supplies available," said another LPG trader. (Additional reporting by Meeyoung Cho in SEOUL; Editing by Muralikumar Anantharaman)

Permalink Reply by Jack Straw on August 26, 2014 at 4:55am

Source: http://finance.yahoo.com/news/williams-announces-open-season-transco-123000879.html

 

Williams Announces Open Season for Transco Pipeline’s Diamond East Project

To Provide Additional 1 billion cubic feet per day of Marcellus natural gas to Northeast Market

TULSA, Okla.--(BUSINESS WIRE)--

Williams (WMB) today announced that it is initiating an open season from August 26 to September 23, 2014 for the Diamond East Project, an expansion of the Transco interstate pipeline to provide firm natural gas transportation capacity to markets in the northeastern United States by mid-2018. Transco is a wholly owned subsidiary of Williams Partners, L.P. (WPZ), of which Williams owns controlling interests and is the general partner.

The Diamond East Project is being designed to provide up to one billion cubic feet per day of new natural gas transportation capacity from receipt points along its Leidy Line in Lycoming County, Pennsylvania and Luzerne County, Pennsylvania to its Market Pool at Station 210 in Mercer County, New Jersey where it can provide supply diversity to Transco's northeast market, including existing Pennsylvania, New Jersey and New York local distribution companies and power generators.

Diamond East will consist of additional compression and selected pipeline loop segments along the existing Transco pipeline corridor. Although the final capacity, scope and cost of the project will be determined by the results of the open season, it is anticipated that the project will include approximately 50 miles of pipeline looping and horsepower additions at existing Transco compressor facilities. The capital investment for Diamond East is estimated to be between $500 million to $800 million, depending on customer participation and volume commitments.

"Diamond East is another example of Williams' commitment to add critical infrastructure that will connect growing Transco markets to abundant, economically-priced Marcellus production," said Rory Miller, senior vice president of Williams' Atlantic-Gulf Operating Area. "Unlike competing projects designed to serve the New Jersey Market Pool, Diamond East is a cost-effective expansion along an existing Transco corridor.”

The proposed project will be subject to approval by the Federal Energy Regulatory Commission and other agencies. For customer inquiries, contact Jamie Taft at (713) 215-2404.

Diamond East is in addition to the $3.3 billion in capital expenditures planned through 2017 on Transco growth projects designed to serve markets in the Northeast. Transco is the nation’s largest and fastest-growing interstate natural gas transmission pipeline system. It delivers natural gas to customers through its 10,200-mile pipeline network whose mainline extends nearly 1,800 miles between South Texas and New York City. The system is a major provider of cost-effective natural gas services that reach U.S. markets in 12 Southeast and Atlantic Seaboard states, including major metropolitan areas in New York, New Jersey and Pennsylvania.

About Williams (WMB)

Williams, headquartered in Tulsa, Okla., is one of the leading energy infrastructure companies in North America. It owns controlling interests in both Williams Partners L.P. and Access Midstream Partners, L.P. (ACMP) through its ownership of 100 percent of the general partner of each partnership. Additionally, Williams owns approximately 66 percent and 50 percent of the limited partner units of Williams Partners L.P. and Access Midstream Partners, L.P., respectively.

Williams Partners L.P. owns and operates both on-shore and offshore assets of approximately 15,000 miles of natural gas gathering and transmission pipelines, 1,800 miles of NGL transportation pipelines, an additional 11,000 miles of oil and gas gathering pipelines and numerous other energy infrastructure assets. The partnership's facilities have daily gas processing capacity of 6.6 billion cubic feet of natural gas, NGL production of more than 200,000 barrels per day and domestic olefins production capacity of 1.35 billion pounds of ethylene and 90 million pounds of propylene per year.

Access Midstream Partners, L.P. owns, operates, develops and acquires natural gas gathering systems and other midstream energy assets. Headquartered in Oklahoma City, the partnership's operations are focused on the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara and Utica Shales and the Mid-Continent region of the U.S.

For more information about Williams, Williams Partners and Access Midstream Partners, visit www.williams.com, www.williamslp.com and www.accessmidstream.com.

Portions of this document may constitute “forward-looking statements” as defined by federal law. Although the company believes any such statements are based on reasonable assumptions, there is no assurance that actual outcomes will not be materially different. Any such statements are made in reliance on the “safe harbor” protections provided under the Private Securities Reform Act of 1995. Additional information about issues that could lead to material changes in performance is contained in the company’s annual reports filed with the Securities and Exchange Commission.

Contact:

Williams
Media Contact:
Tom Droege, 918-573-4034
or
Investor Contacts:
John Porter, 918-573-0797
or
Sharna Reingold, 918-573-2078

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