“Might As Well Jump”—Will Alaska Jump-Start Gas Exports?

<h1 class="title" id="page-title" style="background-color: white; line-height: 1.2em; margin: 0px auto; padding: 0px;"><span style="line-height: 20.149999618530273px;"><span style="font-family: inherit; font-size: x-small; font-weight: normal;">Housley Carr (RBN Energy)</span></span></h1><h1 class="title" id="page-title" style="background-color: white; line-height: 1.2em; margin: 0px auto; padding: 0px;"><span style="font-weight: normal; line-height: 20.149999618530273px;"><span style="font-family: inherit; font-size: small;"><br /></span></span></h1><h1 class="title" id="page-title" style="background-color: white; line-height: 1.2em; margin: 0px auto; padding: 0px;"><span style="font-family: inherit; font-size: small; font-weight: normal;"><span style="line-height: 20.149999618530273px;">Alaska officials, concerned the state’s once-dominant role in U.S. energy production will continue slipping, are taking a fresh look at helping to jump-start a combined natural gas treatment plant, gas pipeline and LNG export project that would free vast volumes of natural gas now stranded at the state’s North Slope. A new study commissioned by the state found that it could make sense for Alaska to take a 20% or higher equity stake in the project, but that there are significant risks the state would need to mitigate. Today we look at whether the 49</span><sup style="line-height: 20.149999618530273px;">th</sup><span style="line-height: 20.149999618530273px;"> state can make a long-stalled plan by producers to move North Slope gas to market a reality by the mid-2020s.</span></span></h1><div class="content-middle" style="background-color: white; line-height: 20.149999618530273px;"><div class="region region-content"><div class="block block-system" id="block-system-main" style="margin: 0px;"><div class="content"><div about="/might-as-well-jump-will-alaska-jump-start-gas-exports" class="node node-article clearfix" id="node-714" style="border-bottom-color: rgb(187, 187, 187); border-bottom-style: solid; border-bottom-width: 1px; margin: 20px 0px; padding-bottom: 15px;" typeof="sioc:Item foaf:Document"><div class="content clearfix" style="margin: 0.5em 0px;"><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even" property="content:encoded"><div></div><div><span style="font-family: inherit;"><br /></span></div><div><span style="font-family: inherit;">Ask any American about Alaska and one of the first things that will come to mind is oil, and the oil pipeline that was built in the 1970s to move crude south from the North Slope’s Prudhoe Bay. “Alaskan natural gas” doesn’t roll off most tongues. But as we explored a few months ago in “’Some Plans Are Bigger than Others’—Alaska LNG Exports” the North Slope has some of the world’s biggest gas reserves. The Alaska Department of Natural Resources (ADNR) estimates there are 200 Tcf of unproven and 35 Tcf of proven conventional gas reserves onshore and offshore on the North Slope’s Prudhoe Bay and Point Thomson areas and in waters off the north coast of Alaska. Still, despite years of talk about possible gas pipelines, there is still no outlet—no way out--for all that gas. Instead, Prudhoe Bay producers continue to re-inject 8 Bcf/d of gas into oil wells.</span></div><div><span style="font-family: inherit;"><br /></span></div><div><span style="font-family: inherit;">Since the 1970s there has been hope of piping North Slope gas south to the Lower 48, but the last of those plans dried up by 2011-12 after the shale revolution led to the development of major new gas resources in the Barnett, Marcellus, Haynesville and other shale plays much closer to U.S. gas users. That shifted the discussion among Alaska energy giants like ExxonMobil, ConocoPhillips and BP—and TransCanada, which has been working with the state under the Alaska Gas line Inducement Act--to the idea of building about 800 miles of south-bound gas pipeline, a gas treatment plant, and an LNG export terminal in south-central Alaska (see Figure 1).</span></div><div><span style="font-family: inherit;"><br /></span></div><div style="text-align: center;"></div><div style="text-align: center;"><span style="font-family: inherit;">Figure 1</span></div><div class="separator" style="clear: both; text-align: center;"><a href="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEioHf3lrQTp5_vd860Y8TqaMbH14R3JPCMA27uJb1zA4pIkOxKDpF1ON12d_v2IhMHASE0vsyppcfL2D7hhwkNfNkS6oM54tvBCfaAJJfpOJskyfygznmpVc1WLnYrQrN_Ep3Z02X12Enae/s1600/Figure1_0.png" imageanchor="1" style="margin-left: 1em; margin-right: 1em;"><span style="color: black; font-family: inherit;"><img border="0" height="200" src="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEioHf3lrQTp5_vd860Y8TqaMbH14R3JPCMA27uJb1zA4pIkOxKDpF1ON12d_v2IhMHASE0vsyppcfL2D7hhwkNfNkS6oM54tvBCfaAJJfpOJskyfygznmpVc1WLnYrQrN_Ep3Z02X12Enae/s200/Figure1_0.png" width="190" /></span></a></div><div style="text-align: center;"><span style="font-family: inherit;"><br /></span></div><div style="text-align: center;"><span style="font-family: inherit;">Source: Alaska Gas Pipeline Project Office (<a href="http://gasline.alaska.gov/" style="text-decoration: none;">http://gasline.alaska.gov/</a>) </span><br /><span style="font-family: inherit;">Click to Enlarge</span></div><div><span style="font-family: inherit;">The primary market for the resulting LNG would be Asia, which buys about 70% of the LNG produced worldwide and whose LNG demand curve has been rising 8%/year the past five years. The catch is, the capital costs associated with all the required infrastructure are high—even by energy industry standards—and gas/LNG producers from Qatar, Australia, western Canada and the Lower 48 already are racing to reach long-term supply deals with Asia’s largest gas consumers. Time’s a-wasting, as they say, and in recent months there has been a new push to assemble the complex financial package needed to make Alaska’s gas export dreams finally happen.</span></div><div><span style="font-family: inherit;">Just last week (week of November 17), a top executive at ExxonMobil laid out the project’s challenges at the Alaska Resource Development Council Conference, and ADNR released a Black & Veatch study it commissioned on how the state might change its gas royalties or taxes—or even take an equity stake in the treat-pipe-and-export project—to help make the project a “go.” Two primary challenges the project faces, ExxonMobil said, are:</span></div><ul style="list-style-image: url(http://www.rbnenergy.com/sites/all/themes/rbntheme/images/menu-leaf.gif); margin: 0.5em 0px 1em; padding: 0px 0px 0px 1.5em;"><li style="margin: 0.15em 0px 0.15em 0.5em; padding-bottom: 0.1em;"><span style="font-family: inherit;">LNG projects with a capacity equivalent to more than 50 Bcf/d are being planned around the world, but less than 40 Bcf/d of additional LNG capacity is likely to be needed by 2030 to keep pace with expected LNG demand growth.</span></li><li style="margin: 0.15em 0px 0.15em 0.5em; padding-bottom: 0.1em;"><span style="font-family: inherit;">Big LNG customers prefer to enter into supply deals with LNG exporters whose terminals and other infrastructure can be built quickly, because that reduces the risk of entering into a long-term LNG supply deal based on too-high prices. The Alaska project would likely take five years or more to come online from the time of final investment decision (FID). The target FID for the Alaska project is 2017-18, with a commercial operation date of 2023-24, or several years behind the first group of LNG exports terminals planned for the U.S. Gulf Coast, West Coast and western Canada.</span></li></ul><div><span style="font-family: inherit;">Black & Veatch said in its study that the Prudhoe Bay and Thomson Point areas have the gas reserves to supply the project’s total needs, at least into the early 2040s, and by then those reserves could almost certainly be supplemented with new, “yet-to-find” fields nearby (see Figure 2). It also said the international LNG market is “illiquid” and “opaque,” with few participants and based primarily on long-term, 20-year-plus contracts. And, it said, the Alaska project would be costly: $10 billion for the gas treatment plant; $12 billion for a 42-inch diameter pipeline with eight compressor stations; and $23 billion for a three-train, 17.4 Mtpa liquefaction plant and export facility.</span></div><div style="text-align: center;"><a class="colorbox colorbox-insert-image init-colorbox-processed cboxElement" href="http://www.rbnenergy.com/sites/default/files/styles/extra_large/public/field/image/Figure2.png?itok=bW_16s1n" style="text-decoration: none;"><span style="color: black; font-family: inherit;"><img alt="" class="image-large" src="http://www.rbnenergy.com/sites/default/files/styles/large/public/field/image/Figure2.png?itok=eNcaQWrJ" style="border: 0px;" typeof="foaf:Image" /></span></a></div><div style="text-align: center;"><span style="font-family: inherit;">Figure 2</span></div><div style="text-align: center;"><span style="font-family: inherit;">Source: Black & Veatch/ADNR Study (PBU = Prudhoe Bay, YTF = Yet to Find - Click to Enlarge)</span></div><div><span style="font-family: inherit;">A real challenge, the Black and Veatch study said, is that with Alaska’s existing royalty and tax set-up, the $45 billion that producers would owe the State puts the project “out of the money” compared with other worldwide LNG projects under development that would provide sufficient volumes of LNG to meet 2025 demand. Some lower-cost projects may not get built, of course, for a variety of reasons. But even if the Alaska project inched toward being in the money, several other projects would be nipping at its heels, working to undercut it. The bottom line, Black & Veatch told the state, is that the Alaska project has the potential to compete for Asian business, but only if the state of Alaska adjusts its fiscal terms to improve the project’s economics. Like governments elsewhere, Alaska could reduce or even eliminate its royalties to help make the project work. But state officials are concerned that would undermine the Alaska Permanent Fund, whose support comes almost entirely from oil and gas royalties. The study concluded that instead of collecting existing taxes and royalties, a 20 to 30% equity investment in the project by the state could provide the same or better revenue.</span></div><div><span style="font-family: inherit;"><br /></span></div><div><span style="font-family: inherit;">One other thing is worth noting. The study found the state would better protect its interest by taking its royalties “in value”—that is, in cash—rather than taking them “in kind”—that is, by being paid by receiving a portion of the gas being piped south. If the state had to market LNG itself, the reasoning goes, it would need to enter into complex commercial agreements, and would be disadvantaged by its inexperience in LNG negotiation and its lack of an LNG supply portfolio to optimize. Producers, after all, are better than state governments at managing exposure to market risk.</span></div><div><span style="font-family: inherit;"><br /></span></div><div><span style="font-family: inherit;">A full-day hearing at the Alaska House of Representatives’ Natural Resources Committee last Friday (November 22) laid out the range of options the state should consider. What seems likely is that over the next few months, the Alaska DNR, state legislators, and the three North Slope gas producers will try to work out a series of interrelated tweaks to the state’s royalty and tax set-up that would help advance the project—with its treatment plant, pipeline and LNG export terminal--probably resulting in a direct investment in the project by the state. Whether that compromise will be enough remains to be seen. Because with significant amounts of new LNG capacity already under construction elsewhere in the world, and with several other LNG projects poised for construction starts in the U.S. and western Canada, Alaska may need to jump soon or find itself with a lot of still-stranded gas.</span></div></div></div></div></div></div></div></div></div></div>

“Might As Well Jump”—Will Alaska Jump-Start Gas Exports?

Housley Carr (RBN Energy) Alaska officials, concerned the state’s once-dominant role in U.S. energy production will continue slipping, are t...

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Playing the Natural Gas Revolution with MLPs

<h2 style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 34px; line-height: 36px; margin: 20px 40px; text-rendering: optimizelegibility;"><span style="font-size: 16px; line-height: 21px;">Investors have different strategies and time horizons: While some are seeking stable dividend paying stocks, others enjoy the excitement of growth companies -- or perhaps something in between.</span></h2><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">If you fall in the latter category and are looking for a home-run hitter with a dependable batting average, <strong>Boardwalk Pipeline Partners</strong> (NYSE: BWP) could be a perfect fit. Here is a solid company that offers an outsized, stable distribution with the potential for stock appreciation as well. </div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">As the natural gas production boom continues, Boardwalk, with enough natural gas pipelines to span the United States more than 5 times, is primed to take advantage of transporting the fuel.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">In addition to owning natural gas pipelines in some of the top gas plays in North America, the company also controls underground storage caverns with approximately 201 billion cubic feet of working gas capacity and approximately 18 million barrels of liquids capacity.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;"></div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">The real win for investors is the fact that over 80% of revenues are backed by long-term, fixed-fee contracts with creditworthy customers. This "tollbooth" style of contract (where customers pay regardless of use) protects Boardwalk's cash flows, while sheltering the company from fluctuations in commodity prices.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">Which means investors can sleep soundly and count on receiving regular distributions every quarter. In fact, Boardwalk Pipeline Partners has consistently increased its dividend every year since its IPO.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;"><strong>Why buy into an MLP?</strong></div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">Boardwalk Pipeline Partners is a master limited partnership (MLP) which means the company avoids paying taxes on its profits like a corporation, and instead distributes profits to unitholders who are then taxed on an individual basis. By skipping double taxation, MLPs offer a tax-advantaged income stream and are thus able to lower the cost of capital.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">MLPs are strong investments, especially in low-interest-rate environments, due to the sturdy distribution yields they offer. However, expanding the business either organically or through acquisition is virtually the only way to increase yields. Having a lower cost of capital makes financing expansions possible without cutting distributions. With a suitable 5.5% cost of capital, Boardwalk has never decreased a quarterly distribution and most recently maintained a healthy distribution coverage ratio of 1.2 times.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">Boardwalk's high yield is also insulated by a fortress-like competitive moat since constructing new pipelines is incredibly capital intensive and requires regulatory approval contingent on demand. Equally important, natural gas storage is located in underground caverns and naturally occurring salt domes which limit storage capacity.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;"><strong>Industry tailwinds</strong></div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">Natural gas is a cleaner burning fuel than coal, emitting less than half as much carbon dioxide during combustion per unit of electricity output.  In addition, after natural gas prices reached record lows last spring, natural gas has been rapidly replacing coal-fired power generation. Since 2005, power generation from natural gas has increased more than 60%, supplying over 30% of all power generation in the United States in 2012.</div><div class="separator" style="clear: both; text-align: center;"><span style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px;"><br />In addition to power generation, natural gas usage could further benefit from LNG exportation. With an estimated 6.8 billion cubic feet per day of LNG exports expected in the next decade, Boardwalk, which controls 11% of the nation’s natural gas, stands to benefit. With natural gas expected to be the fastest growing fuel through 2040, investors interested in safe yields should benefit from Boardwalk gaining the upper hand when negotiating long-term, fixed-fee contracts. </span><a href="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEgIjPTpJWUHfuAQII5VhKHXISawKmVm8lvrFy3_dKBGMhIm0xy6Htdstn3K7s_dBJ8E9g9hlACE9ZTXGd-JuN7AYZdubSSyvc_yiCdDVc6JqABslOB0wP20f3bo6PZNo7G_R5-c9zAJhS6c/s1600/us-electricitybyfuel-graph-sfr-3.png" imageanchor="1" style="margin-left: 1em; margin-right: 1em;"><img border="0" height="169" src="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEgIjPTpJWUHfuAQII5VhKHXISawKmVm8lvrFy3_dKBGMhIm0xy6Htdstn3K7s_dBJ8E9g9hlACE9ZTXGd-JuN7AYZdubSSyvc_yiCdDVc6JqABslOB0wP20f3bo6PZNo7G_R5-c9zAJhS6c/s320/us-electricitybyfuel-graph-sfr-3.png" width="320" /></a></div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;"><strong>bottom line</strong></div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">A rare gem in the investing universe, Boardwalk Pipeline Partners offers quality natural gas assets at an incredible price. With the United States gearing up to be a net natural gas exporter, Boardwalk Pipeline Partners is prepared for growth through continued asset add-ons organically as well as through value-adding acquisitions. Also, in an unusually low interest rate environment, investors should be able to collect a steady stream from this 7% yielding natural gas juggernaut.</div>

Playing the Natural Gas Revolution with MLPs

Investors have different strategies and time horizons: While some are seeking stable dividend paying stocks, others enjoy the excitement of ...

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A Different Kind of Oil Investment: CO2 enhanced oil recovery (EOR)

<h2 style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 34px; line-height: 36px; margin: 20px 40px; text-rendering: optimizelegibility;"><span style="font-size: 16px; line-height: 21px;">While headlines are focused on fracking America's top shale plays, another oil industry development is silently profiting in a big way.</span></h2><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">CO2 enhanced oil recovery (EOR) is the third phase of extracting oil from a reservoir after the primary drilling and waterflooding EOR phases. EOR methods are used to pressurize mature wells, increasing the viscosity of the oil and pushing the oil to the wellbore. </div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">Since EOR is used in already proven wells, extracting crude skips the costly exploration expenses incurred by traditional oil E&P companies. Better yet, since the wells are mature, they can be acquired at a fraction of the original cost.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">As far as CO2-EOR -- also known as tertiary recovery-- is concerned, <strong>Denbury Resources</strong> (NYSE: DNR) is the clear leader and the only company you need to follow in the space.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;"><strong>Why Denbury?</strong></div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">Denbury Resources has amassed an excellent portfolio of assets, targeting two areas, the Rocky Mountain and Gulf Coast regions, together comprising just less than 1 billion barrels of oil equivalent in total reserves.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">What really makes these assets unique is Denbury's 1,100 miles of pipeline connecting the company's naturally occurring CO2 deposits to its mature oil fields. Since acquiring CO2 is restrictive, this natural supply gives Denbury a competitive advantage that cannot be replicated.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">Denbury deploys a strategy of staged projects, which staggers the expected oil peaks in the injected fields, giving the company over 20 years of stable growth. If you take a closer look, EOR projects are front-loaded with capital expenditures and take a few years to ramp up. This type of production curve gives Denbury a future inflection point where production increases while capital expenditures decrease, giving investors years of free cash flow. With six operating areas already producing, Denbury anticipates hitting the free cash flow wedge in the next five years.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;"><strong>Years of growth</strong></div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">Since 1999 Denbury has amassed a 29% compounded annual growth rate, mostly on the back of one project that is now in a phase of slow decline. The great news is Denbury still has five plays in the early growth stage and six more promising projects slated for CO2-EOR injections over the next six years.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;"><strong>Margin appreciation</strong></div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">While growing production is great for oil companies, expanding margins is vastly more important for shareholders. Denbury has focused its attention on both lowering its finding and development costs and selling its crude at a premium, with over 93% of oil marketed as Louisiana Light Sweet crude, which commands a higher price than WTI-benchmarked crude.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;"><a href="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEjc0RcNz5cd8V0z-uE1iRG3h1zOC1ILoUtwscfkJRhQkfXnCefwotdBS-VUQVbYBvZTiaHNYABqSemSEnkZhvemEu0xYVeYReL34EVtHDVA4YV91XXD-lvp-E_Or3NJ3WoRA8NOBbC6bxb6/s1600/before-taxrateReturn-sfr-2.png" imageanchor="1" style="clear: left; float: left; margin-bottom: 1em; margin-right: 1em;"><img border="0" height="199" src="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEjc0RcNz5cd8V0z-uE1iRG3h1zOC1ILoUtwscfkJRhQkfXnCefwotdBS-VUQVbYBvZTiaHNYABqSemSEnkZhvemEu0xYVeYReL34EVtHDVA4YV91XXD-lvp-E_Or3NJ3WoRA8NOBbC6bxb6/s320/before-taxrateReturn-sfr-2.png" width="320" /></a>This combination gives Denbury the highest operating margin in its peer group, collecting over $60 per barrel of oil equivalent. The company also stands up to declining oil prices, with breakeven prices significantly lower than those of the most prominent shale plays in the United States.<br /><em style="font-size: 10px;"><br /></em><em style="font-size: 10px;">Source: Denbury Corporate Presentation May 2013</em></div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">The value of an oil company is based on cash flows due to the volatility of oil prices, but over the long term Denbury seems like a screaming value. The company trades 30% over book value, and if it can hit its estimate of a decade of oil-heavy production with a growth rate in the low teens, shareholders should be well-compensated.</div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;"><strong>bottom line</strong></div><div style="background-color: #fcfcfc; color: #333333; font-family: 'Open Sans', Arial, Helvetica, sans-serif; font-size: 16px; line-height: 21px; margin: 20px 40px;">Denbury Resources is a unique company with prized assets and a non-replicable competitive advantage. The maturing of conventional oil fields is ending the age of cheap crude, and Denbury is primed to expand its business and profit from its industry-leading tertiary recovery position. With $100 oil prices the new normal, Denbury is a company all Foolish investors need to consider.</div>

A Different Kind of Oil Investment: CO2 enhanced oil recovery (EOR)

While headlines are focused on fracking America's top shale plays, another oil industry development is silently profiting in a big way. ...

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North American Shale Revolution Has ‘Staying Power’

<h2 style="background-color: white; font-family: Lato; font-size: 27px; line-height: 29px; margin: 0px 0px 3px; padding-bottom: 3px;"><div style="color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; font-weight: normal; line-height: 22px;"><i>The drilling boom continues in the US and Canada, but challenges remain.</i></div><div style="color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; font-weight: normal; line-height: 22px;"><i><br /></i></div><div style="color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; font-weight: normal; line-height: 22px;"><a href="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEhY3F0VRs8FvIcCA2z9Nw8wHV7NjdvbNMPkg9VhX2B8r41kPSn4lXM5hnGagREmVcsc1vSxAJFNdWUAittCLtGIu4EtJ07G8cUGqWsclI3vtdLb91HlDTuoLieJ0oaUJf2uRw3N3j5LmjZy/s1600/images.jpeg" imageanchor="1" style="clear: left; float: left; margin-bottom: 1em; margin-right: 1em;"><img border="0" src="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEhY3F0VRs8FvIcCA2z9Nw8wHV7NjdvbNMPkg9VhX2B8r41kPSn4lXM5hnGagREmVcsc1vSxAJFNdWUAittCLtGIu4EtJ07G8cUGqWsclI3vtdLb91HlDTuoLieJ0oaUJf2uRw3N3j5LmjZy/s1600/images.jpeg" /></a>Shale production has made North America the envy of the world, and the revolution has staying power that will not vanish within the next few years, according to ConocoPhillips CEO Ryan Lance.<br /><br />Speaking during the Deloitte Oil and Gas Conference in Houston on Nov. 19, Lance said shale production in the US and Canada has increased 37% since 2005 and continues to grow.<br /><br />The production surge has led to 33 proposed export terminals in North America, multibillion-dollar projects predicated on low natural gas prices continuing in North America, Lance said, later noting that global demand and competing supplies will, however, restrict the number of projects that are actually built. The global demand is projected to only grow about 850 Mcm/d (30 Bcf/d) by 2025, while the export capacity for the proposed projects is about 1.2 Bcm/d (45 Bcf/d). “Supply and demand is going to play a key role in determining which of these projects move forward,” he said.<br /><br />But the North American drilling boom continues. “Today we’ve gotten back to 10 MMb/d. I think new records are coming,” Lance said. And the payouts have not only impacted the E&P sector; the chemicals industry has witnessed a revival as well. “We are now no longer an importer of LPG. We are an exporter. Even foreign companies are coming back to invest because of the cheap natural gas prices.”<br /><br />There are other sources of growth fueling this energy renaissance. Gulf of Mexico (GoM) deepwater production doubled during the 1990s, flattened out, and is rising again. Production here was about 1 MMb/d in 1996, but that could increase to just less than 2 MMb/d by 2020.<br /><br />“There is a new tranche of production startups that have been announced that are coming on, and new areas are yielding fairly large discoveries whether we’re talking about the Miocene, the Paleogene, the Pliocene, even the Jurassic, or the subsalt that is going on in the GoM,” Lance said.<br /><br />The US has already surpassed other countries in terms of natural gas production, becoming the world’s No. 1 producer at about 1.8 Bcm/d (65 Bcf/d). The US also is on track to pass Russia this year in total oil and gas production and is predicted to pass Saudi Arabia in the next few years, Lance said. The International Energy Agency forecasts US oil production will reach 11.6 MMb/d by 2020.</div><div style="color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; font-weight: normal; line-height: 22px;">“We can export energy to our allies now. We have a greater diplomatic influence in the world today,” Lance said. “With this rising supply in self sufficiency, it weakens some of the more hostile producers that might want to hold us hostage.”<br /><br />But there are some challenges. These, Lance said, include weak demand in North America resulting in low prices, infrastructure permitting delays, import/export issues, public concern about hydraulic fracturing, oil and gas workers approaching retirement age, and costly regulations.<br /><br />Then, there are technology challenges and critical water issues. Lance said the industry has made a lot of progress in this area and continues looking for ways to reduce water usage. Using the Canadian oil sands as an example, he spoke of taking brackish water, instead of potable water, and turning it into steam to help recover oil.<br />Technological opportunities also remain in maximizing recovery and production.<br /><br />“We still don’t really have the optimum completion around these unconventionals. How much of that gross volume are we effectively stimulating? I don’t think the industry really has a good handle on that,” Lance said. “We’ve got a lot of technology that ourselves and others are looking at to try to improve that – how to keep the bit drilling quickly and fast. There is the surface issue.”<br /><br />Added to that are the issues of water management and how to reuse water to make quality fluids and continue stimulating the wellbore, he continued. He predicts a lot of subsurface advances will be forthcoming over the next five to 10 years as the industry works to get the ultimate recovery from investments.<br /><br />“I think we’re in the first inning of this unconventional story,” Lance said.<br /><br /><i>Contact the author, Velda Addison, at <a href="mailto:vaddison@hartenergy.com" style="color: #007ac2; text-decoration: none;">vaddison@hartenergy.com</a>.</i></div></h2>

North American Shale Revolution Has ‘Staying Power’

The drilling boom continues in the US and Canada, but challenges remain. Shale production has made North America the envy of the world, and ...

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Chevron: Rosebank Oil Project Is Uneconomic

<div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;"><a href="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEiUprlaFQrV4H6E3HKgZkxNvEiwB_G9mp7NOyj_WyFpyb-gWO7aGIVA5_X8a40GA0pg_Nb0pueQYx9rQbj2b-LZOXDa3aiG3sS4Ky2RcGV4a4kZ0fTGaoYb_WRDYPZcQ-LFefmAYczNjtns/s1600/Chevron_Rosebank_Map.jpg" imageanchor="1" style="clear: left; float: left; margin-bottom: 1em; margin-right: 1em;"><img border="0" height="245" src="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEiUprlaFQrV4H6E3HKgZkxNvEiwB_G9mp7NOyj_WyFpyb-gWO7aGIVA5_X8a40GA0pg_Nb0pueQYx9rQbj2b-LZOXDa3aiG3sS4Ky2RcGV4a4kZ0fTGaoYb_WRDYPZcQ-LFefmAYczNjtns/s320/Chevron_Rosebank_Map.jpg" width="320" /></a>Chevron Corp., the world’s second- largest non-state energy company by market value, said its Rosebank oil discovery off the coast of Scotland would be unprofitable to bring into production at this time.</div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;"><br /></div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;">Chevron plans to continue evaluating the 240 MMbbl field along with partners OMV AG and Dong Energy A/S for ways to improve the project’s potential returns, the San Ramon, California-based company said in an e-mailed statement Nov. 22. A final decision on whether to proceed will be made next year, according to the statement.</div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;"><br /></div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;">Rosebank’s unprofitability is a blow to UK and Norwegian efforts to halt the slide in North Sea oil output as fields first drilled in the 1970s and 1980s near the end of their productive lifespans. Dropping North Sea supplies are expected to drive a 15% decline in European crude and gas liquids production by 2018, the Organization of Petroleum Exporting Countries said in its annual world outlook on Nov. 7.</div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;">Rosebank “does not currently offer an economic value proposition that justifies proceeding with an investment of this magnitude,” Chevron said in the statement.</div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;">Chevron and its partners hired South Korea’s Hyundai Heavy Industries Co. Ltd. in April to construct a US $1.9 billion platform that could offload crude directly to tankers, Hyundai said in a Nov. 15 slide presentation. The vessel would have capacity to draw 100,000 bbl of oil and 190 MMscd/d of gas from the seafloor.</div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;">Chevron hasn’t disclosed any cost estimates for the total development. Rosebank is located 130 km (80 miles) northwest of the Shetland Islands and 1,130 m (3,700 ft) beneath the sea surface.</div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;">Chevron discovered Rosebank in 2004 and owns a 40% stake. OMV owns 50% and Dong holds a 10% interest.<br />ExxonMobil Corp. is the largest oil company by market value, according to data compiled by Bloomberg.</div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;"><br /></div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;"><br /></div>

Chevron: Rosebank Oil Project Is Uneconomic

Chevron Corp., the world’s second- largest non-state energy company by market value, said its Rosebank oil discovery off the coast of Scotla...

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Tullow’s Agete-1 Well Hits Oil Onshore Kenya

<div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;"><a href="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEj-P0Go0tI4z0k3AlkIgN3S4zv1WB4wSVsyZDBjbOeb_YKz13fNFL95tV2z_Ca00s7m0VKJPZDuFzIKCaHeum6mefYkwBnMRCRoMJpUEWSGPT-fNAIupEtfSvBLX_Es8kh-UjdnoIuacfWD/s1600/download.jpeg" imageanchor="1" style="clear: left; float: left; margin-bottom: 1em; margin-right: 1em;"><img border="0" src="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEj-P0Go0tI4z0k3AlkIgN3S4zv1WB4wSVsyZDBjbOeb_YKz13fNFL95tV2z_Ca00s7m0VKJPZDuFzIKCaHeum6mefYkwBnMRCRoMJpUEWSGPT-fNAIupEtfSvBLX_Es8kh-UjdnoIuacfWD/s1600/download.jpeg" /></a>Tullow Oil Plc announced in a press release that the Agete-1 exploration well in Block 13T, onshore northern Kenya, has discovered and sampled moveable oil with an estimated 100 m (328 ft) of net oil pay in good-quality sandstone reservoirs.</div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;"><br /></div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;">The Agete-1 wildcat well is part of a major exploration campaign and has made the fifth consecutive oil discovery in the first of a chain of multiple rift basins across Tullow’s acreage in the region. This discovery derisks several follow-on prospects located to the north and is on trend with the Twiga South, Ekales, and Ngamia oil discoveries, Tullow said.</div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;"><br /></div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;">The Sakson PR5 rig drilled Agete-1 to a total depth of 1,930 m (6,332 ft). Following completion of logging operations the well will be suspended for future flow testing, which will confirm the net pay count. The rig will then move to drill the Ewoi-1 wildcat in the east of this basin, targeting a rift flank prospect similar to the recent Etuko oil discovery, according to the release.</div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;"><br /></div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;">Tullow operates the Agete-1 well with a 50% interest and Africa Oil (50%) has a nonoperated interest.</div><div style="background-color: white; color: #333333; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px;">Elsewhere in Kenya, exploration and appraisal activities continue to accelerate with the Amosing-1 well in Block 10BB, expected to commence drilling before the end of November with the Weatherford 804 rig. The Etuko-1 well test in Block 10BB also is scheduled to commence this month with the PR Marriott 46 rig, which recently arrived in country, Tullow said. The Ekales-1 well test is scheduled to commence with the new SMP-5 workover unit in early December.</div><br />http://www.epmag.com/Production-Drilling/Tullows-Agete-1-Hits-Oil-Onshore-Kenya_126133

Tullow’s Agete-1 Well Hits Oil Onshore Kenya

Tullow Oil Plc announced in a press release that the Agete-1 exploration well in Block 13T, onshore northern Kenya, has discovered and sampl...

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23 Fascinating Facts about 5 Top Bakken Shale Producers from Drillinginfo

<div style="background-color: white; color: #333333; font-family: 'Helvetica Neue', Helvetica, sans-serif; font-size: 14px; line-height: 19.59375px; margin-bottom: 20px; text-align: center;"></div><div class="separator" style="clear: both; text-align: left;">Found on DrillingInfo Blog:  <a href="https://plus.google.com/u/0/100135596995643685976" rel="author" style="-webkit-transition: background-color 0.2s ease, border 0.2s ease, color 0.2s ease; background-color: white; color: #ff6600; font-family: 'Helvetica Neue', Helvetica, sans-serif; font-size: 14px; line-height: 21px; outline: none; text-align: right; text-decoration: none !important; transition: background-color 0.2s ease, border 0.2s ease, color 0.2s ease;">James Hahn II</a><span style="background-color: white; color: #333333; font-family: 'Helvetica Neue', Helvetica, sans-serif; font-size: 14px; line-height: 21px; text-align: right;"> (</span><a href="http://www.drillinginfo.com/" target="_blank">Drillinginfo</a><span style="background-color: white; color: #333333; font-family: 'Helvetica Neue', Helvetica, sans-serif; font-size: 14px; line-height: 19.59375px; text-align: right;"> )</span></div><div class="separator" style="clear: both; text-align: left;"><span style="background-color: white; color: #333333; font-family: 'Helvetica Neue', Helvetica, sans-serif; font-size: 14px; line-height: 19.59375px; text-align: right;"><br /></span></div><div class="separator" style="clear: both; text-align: center;"><a href="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEik8BrmnGYQlPCNV4y8XmMDiOujqbbX-DV47_vSrGaRCgS8wZMaAdGckBzyPeHmTlC3ZzXF7aLKU-vSBUDISu_q1o2LkCJJXJBSSgKihIpnHuI0aDt3mqYzdqauhMN2bMYnGKCtIxn622js/s1600/Oil-Truck.jpg" imageanchor="1" style="margin-left: 1em; margin-right: 1em;"><img border="0" height="138" src="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEik8BrmnGYQlPCNV4y8XmMDiOujqbbX-DV47_vSrGaRCgS8wZMaAdGckBzyPeHmTlC3ZzXF7aLKU-vSBUDISu_q1o2LkCJJXJBSSgKihIpnHuI0aDt3mqYzdqauhMN2bMYnGKCtIxn622js/s400/Oil-Truck.jpg" width="400" /></a></div><div style="background-color: white; color: #333333; font-family: 'Helvetica Neue', Helvetica, sans-serif; font-size: 14px; line-height: 19.59375px; margin-bottom: 20px;">The Bakken Shale just keeps on truckin’.</div><h2 style="background-color: white; color: #003366; font-family: 'Helvetica Neue', Helvetica, sans-serif; font-size: 22px; font-weight: normal; line-height: 22px; margin: 0px 0px 10px; padding: 0px 0px 15px;">23 Fascinating Facts about 5 Top Bakken Shale Producers</h2><div align="center" style="background-color: white; color: #333333; font-family: 'Helvetica Neue', Helvetica, sans-serif; font-size: 14px; line-height: 19.59375px; margin: 0px; padding: 0px;"><iframe allowfullscreen="" frameborder="0" height="356" marginheight="0" marginwidth="0" scrolling="no" src="http://www.slideshare.net/slideshow/embed_code/28201237" style="border-color: rgb(204, 204, 204); border-style: solid; border-width: 1px 1px 0px; margin-bottom: 5px;" width="427"></iframe><br /><div style="margin: 0px 0px 5px; padding: 0px;"><strong><a href="https://www.slideshare.net/drillinginfo/bakken-slideshare-update" style="-webkit-transition: background-color 0.2s ease, border 0.2s ease, color 0.2s ease; color: #ff6600; font-weight: 400; outline: none; text-decoration: none; transition: background-color 0.2s ease, border 0.2s ease, color 0.2s ease;" target="_blank" title="23 Fascinating Facts about 5 Top Bakken Shale Producers">23 Fascinating Facts about 5 Top Bakken Shale Producers</a> </strong>from <strong><a href="http://www.slideshare.net/drillinginfo" style="-webkit-transition: background-color 0.2s ease, border 0.2s ease, color 0.2s ease; color: #ff6600; font-weight: 400; outline: none; text-decoration: none; transition: background-color 0.2s ease, border 0.2s ease, color 0.2s ease;" target="_blank">Drillinginfo</a></strong></div></div>

23 Fascinating Facts about 5 Top Bakken Shale Producers from Drillinginfo

Found on DrillingInfo Blog:   James Hahn II  ( Drillinginfo  ) The Bakken Shale just keeps on truckin’. 23 Fascinating Facts about 5 Top Bak...

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Dodd Frank Revisited

<object classid="clsid:D27CDB6E-AE6D-11cf-96B8-444553540000" codebase="http://download.macromedia.com/pub/shockwave/cabs/flash/swflash.cab#version=9,0,47,0" height="270" id="flashObj" width="480"><param name="movie" value="http://c.brightcove.com/services/viewer/federated_f9?isVid=1&isUI=1" /><param name="bgcolor" value="#FFFFFF" /><param name="flashVars" value="videoId=2842025396001&linkBaseURL=http%3A%2F%2Fwww.plattsenergyweektv.com%2Fvideo%2Fdefault.aspx%3Fbctid%3D2842025396001&playerID=1685956553001&playerKey=AQ~~,AAAABvaL9Hk~,mLC66bU8hPOBGO8BPO1coBAeF5n-gkxo&domain=embed&dynamicStreaming=true" /><param name="base" value="http://admin.brightcove.com" /><param name="seamlesstabbing" value="false" /><param name="allowFullScreen" value="true" /><param name="swLiveConnect" value="true" /><param name="allowScriptAccess" value="always" /><embed src="http://c.brightcove.com/services/viewer/federated_f9?isVid=1&isUI=1" bgcolor="#FFFFFF" flashVars="videoId=2842025396001&linkBaseURL=http%3A%2F%2Fwww.plattsenergyweektv.com%2Fvideo%2Fdefault.aspx%3Fbctid%3D2842025396001&playerID=1685956553001&playerKey=AQ~~,AAAABvaL9Hk~,mLC66bU8hPOBGO8BPO1coBAeF5n-gkxo&domain=embed&dynamicStreaming=true" base="http://admin.brightcove.com" name="flashObj" width="480" height="270" seamlesstabbing="false" type="application/x-shockwave-flash" allowFullScreen="true" allowScriptAccess="always" swLiveConnect="true" pluginspage="http://www.macromedia.com/shockwave/download/index.cgi?P1_Prod_Version=ShockwaveFlash"></embed></object><br /><br /><div class="separator" style="clear: both; text-align: left;"><a href="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEic0uuu9oGSfRbejE4TewauTzf9I2pDhWfdYKPejwgt4OJSgPn5OhSf-cxRycqyLaZQRc71ONzDvH8MNivtFrciQXhgmGM2nbwC6O7IE_RSRzWwg7qCpKCPhmBsZVykyZ76xZRfRfvvaLis/s1600/ext.jpeg" imageanchor="1" style="margin-left: 1em; margin-right: 1em;"><img border="0" src="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEic0uuu9oGSfRbejE4TewauTzf9I2pDhWfdYKPejwgt4OJSgPn5OhSf-cxRycqyLaZQRc71ONzDvH8MNivtFrciQXhgmGM2nbwC6O7IE_RSRzWwg7qCpKCPhmBsZVykyZ76xZRfRfvvaLis/s1600/ext.jpeg" /></a></div><br />Revisiting Dodd-Frank's Impact on Energy Desc: Spencer Abraham, a former U.S. energy secretary, discusses why he thinks it's time to revisit Dodd-Frank's impact on energy industries. <br /><br />* Thanks to Tom Morgan (DrillingInfo) for pointing this video out to us.

Dodd Frank Revisited

Revisiting Dodd-Frank's Impact on Energy Desc: Spencer Abraham, a former U.S. energy secretary, discusses why he thinks it's time to...

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Can Shale Gas Transform the World?

<div class="separator" style="clear: both; text-align: center;"></div><h1 class="xlHeader" style="background-color: white; border: 0px; color: #222222; font-family: Arial, Helvetica, sans-serif; font-size: 32px; letter-spacing: -1px; line-height: 36px; margin: 0px 0px 5px; padding: 0px;"><span class="vcard byline" style="border: 0px; color: #666666; font-family: inherit; font-size: 12px; font-style: inherit; font-weight: inherit; line-height: 1.3em; margin: 0px; padding: 0px;"><br /></span></h1><h1 class="xlHeader" style="background-color: white; border: 0px; color: #222222; font-family: Arial, Helvetica, sans-serif; font-size: 32px; letter-spacing: -1px; line-height: 36px; margin: 0px 0px 5px; padding: 0px;"><span class="vcard byline" style="border: 0px; color: #666666; font-family: inherit; font-size: 12px; font-style: inherit; font-weight: inherit; line-height: 1.3em; margin: 0px; padding: 0px;">Post by  <a class="qsAdd qs-source-iapsitlnk0000002" href="http://my.fool.com/profile/reubengbrewer/info.aspx?source=iapsitlnk0000002" style="border: 0px; color: #339933; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;"><span content="Reuben Brewer" itemprop="author" style="border: 0px; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;">Reuben Brewer</span></a> (Motley Fool)</span></h1><div class="entry-content" style="background-color: white; border: 0px; color: #222222; font-family: Arial, Helvetica, sans-serif; font-size: 14px; line-height: 22px; margin: 0px; padding: 0px;"><div style="border: 0px; font-style: inherit; font-weight: inherit; margin-bottom: 11px; margin-top: 11px; padding: 0px;">There are hundreds of shale wells being drilled outside of the United States using fracking and horizontal drilling -- the transformational techniques that pushed natural gas prices to historic lows in the domestic market. If the U.S. experience is any indication, the world could soon be awash in oil and cheap natural gas. Beware the hyperbole!</div><div style="border: 0px; font-style: inherit; font-weight: inherit; margin-bottom: 11px; margin-top: 11px; padding: 0px;"><strong style="border: 0px; font-family: inherit; font-style: inherit; margin: 0px; padding: 0px;">Everyone in</strong>The shale gas boom was huge in the United States, leading industry giants like <strong style="border: 0px; font-family: inherit; font-style: inherit; margin: 0px; padding: 0px;">ExxonMobil</strong>(<span class="ticker" style="border: 0px; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;">NYSE: <a class="qsAdd qs-source-isssitthv0000001" data-id="206209" href="http://caps.fool.com/Ticker/XOM.aspx?source=isssitthv0000001" style="border: 0px; color: #339933; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;">XOM</a></span> <a class="addToWatchListIcon qsAdd qs-source-iwlsitbut0000010" href="http://my.fool.com/watchlist/add?ticker=XOM&source=iwlsitbut0000010" style="background-image: url(http://g.foolcdn.com/common/img/buttons/BtnAdd.gif); background-position: 0px 0px; background-repeat: no-repeat no-repeat; border: 0px; color: #339933; display: inline-block; font-family: inherit; font-style: inherit; font-weight: inherit; height: 16px; margin: 0px; padding: 0px; vertical-align: middle; width: 16px;" title="Add XOM to My Watchlist"> </a>) and <strong style="border: 0px; font-family: inherit; font-style: inherit; margin: 0px; padding: 0px;">Royal Dutch</strong> <strong style="border: 0px; font-family: inherit; font-style: inherit; margin: 0px; padding: 0px;">Shell</strong> (<span class="ticker" style="border: 0px; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;">NYSE: <a class="qsAdd qs-source-isssitthv0000001" data-id="209622" href="http://caps.fool.com/Ticker/RDS-B.aspx?source=isssitthv0000001" style="border: 0px; color: #339933; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;">RDS-B</a></span> <a class="addToWatchListIcon qsAdd qs-source-iwlsitbut0000010" href="http://my.fool.com/watchlist/add?ticker=RDS-B&source=iwlsitbut0000010" style="background-image: url(http://g.foolcdn.com/common/img/buttons/BtnAdd.gif); background-position: 0px 0px; background-repeat: no-repeat no-repeat; border: 0px; color: #339933; display: inline-block; font-family: inherit; font-style: inherit; font-weight: inherit; height: 16px; margin: 0px; padding: 0px; vertical-align: middle; width: 16px;" title="Add RDS-B to My Watchlist"> </a>) to spend heavily for a seat at the table. Smaller players like <strong style="border: 0px; font-family: inherit; font-style: inherit; margin: 0px; padding: 0px;">Chesapeake Energy</strong> (<span class="ticker" style="border: 0px; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;">NYSE: <a class="qsAdd qs-source-isssitthv0000001" data-id="203108" href="http://caps.fool.com/Ticker/CHK.aspx?source=isssitthv0000001" style="border: 0px; color: #339933; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;">CHK</a></span> <a class="addToWatchListIcon qsAdd qs-source-iwlsitbut0000010" href="http://my.fool.com/watchlist/add?ticker=CHK&source=iwlsitbut0000010" style="background-image: url(http://g.foolcdn.com/common/img/buttons/BtnAdd.gif); background-position: 0px 0px; background-repeat: no-repeat no-repeat; border: 0px; color: #339933; display: inline-block; font-family: inherit; font-style: inherit; font-weight: inherit; height: 16px; margin: 0px; padding: 0px; vertical-align: middle; width: 16px;" title="Add CHK to My Watchlist"> </a>) became market darlings because of their property acquisitions.</div><div style="border: 0px; font-style: inherit; font-weight: inherit; margin-bottom: 11px; margin-top: 11px; padding: 0px;">Although the gas revolution is real, the land grab hurt investors more than it helped them. For example, Exxon admits that the $40 billion it paid for gas specialist XTO Energy was too much, suggesting that it was years early with the purchase. Shell, meanwhile, is selling off shale land and taking big write-offs.</div><div style="border: 0px; font-style: inherit; font-weight: inherit; margin-bottom: 11px; margin-top: 11px; padding: 0px;">The poster child of shale excess, however, is probably Chesapeake. The company's shares plummeted as investors started to realize that the debt it took on to buy land would be hard to pay off with natural-gas prices at historic lows. That led to a public battle with Carl Icahn that ousted the company's co-founder. With a new CEO, the company has shifted gears and is starting to focus on working its own properties -- a process that's included land sales.</div><div style="border: 0px; font-style: inherit; font-weight: inherit; margin-bottom: 11px; margin-top: 11px; padding: 0px;"><strong style="border: 0px; font-family: inherit; font-style: inherit; margin: 0px; padding: 0px;">Beware the hype</strong>So, even though the U.S. shale potential is material, many investors have gotten hurt. That's why you need to be wary about headlines that suggest the world is on the verge of a U.S. type shale boom. In fact, Maria van der Hoeven, executive director of the International Energy Agency, <a href="http://www.bloomberg.com/news/2013-11-15/shale-revolution-spreads-with-record-wells-outside-u-s-energy.html" style="border: 0px; color: #339933; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;" target="_blank">told</a> Bloomberg "...you just can't copy the U.S. experience."</div><div style="border: 0px; font-style: inherit; font-weight: inherit; margin-bottom: 11px; margin-top: 11px; padding: 0px;">Shell's CEO provided a key warning, <a href="http://business.financialpost.com/2013/10/18/u-s-has-overfracked-and-overdrilled-shell-director-says/?__lsa=67d6-0746" style="border: 0px; color: #339933; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;" target="_blank">telling</a> an audience that "...it is very dangerous when we hype things, because it sets expectation which perhaps can't be fulfilled..." He points to Poland as an example of a country where drillers went in with high hopes that didn't pan out. "We never talk about the basins that have not worked," he noted.</div><div style="border: 0px; font-style: inherit; font-weight: inherit; margin-bottom: 11px; margin-top: 11px; padding: 0px;"><strong style="border: 0px; font-family: inherit; font-style: inherit; margin: 0px; padding: 0px;">Real opportunity</strong>That said, the global opportunity is real. "But not everywhere at the same time," as the IEA's van der Hoeven notes. Although it would be nice to believe that a relatively small country like Poland could transform itself overnight, that's just not likely and is far more risky than the potential of countries with larger land masses -- like China and Russia.</div><div style="border: 0px; font-style: inherit; font-weight: inherit; margin-bottom: 11px; margin-top: 11px; padding: 0px;">That's where big, international oil and gas giants come into play. For example, Shell is working with China National Petroleum to explore for natural gas and oil in China. That gives Shell a foothold in the country with the largest shale-gas reserves and the third largest shale-oil reserves in the world. Add in Shell's experience in the liquified natural gas space, and this out-of-favor giant looks like it is making the right moves for long-term success.</div><div class="image small" style="border: 0px; font-style: inherit; font-weight: inherit; margin: 0px 0px 5px; padding: 0px;"><div class="separator" style="clear: both; text-align: center;"><a href="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEjJVP5T-tVNz0sv6jqvQvOL_suhyc8BvOSGQPPcBvdcOZcgzHrQCHtMGzlud3CRyixj_bpqMSbnDKQv_raAif48ijyVmvFvtPiMBexZ1tIQ3Pnpl48JXlxi6ZYQ-MuwmAelAj7QLgd3IZDt/s1600/13_11_18-shale-gas-and-oil-reseves-table-eia_large.png" imageanchor="1" style="margin-left: 1em; margin-right: 1em;"><img border="0" height="177" src="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEjJVP5T-tVNz0sv6jqvQvOL_suhyc8BvOSGQPPcBvdcOZcgzHrQCHtMGzlud3CRyixj_bpqMSbnDKQv_raAif48ijyVmvFvtPiMBexZ1tIQ3Pnpl48JXlxi6ZYQ-MuwmAelAj7QLgd3IZDt/s320/13_11_18-shale-gas-and-oil-reseves-table-eia_large.png" width="320" /></a></div><br /></div><div style="border: 0px; font-style: inherit; font-weight: inherit; margin-bottom: 11px; margin-top: 11px; padding: 0px;"><strong style="border: 0px; font-family: inherit; font-style: inherit; margin: 0px; padding: 0px;">BP </strong>(ADR) (<span class="ticker" style="border: 0px; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;">NYSE: <a class="qsAdd qs-source-isssitthv0000001" data-id="202988" href="http://caps.fool.com/Ticker/BP.aspx?source=isssitthv0000001" style="border: 0px; color: #339933; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;">BP</a></span> <a class="addToWatchListIcon qsAdd qs-source-iwlsitbut0000010" href="http://my.fool.com/watchlist/add?ticker=BP&source=iwlsitbut0000010" style="background-image: url(http://g.foolcdn.com/common/img/buttons/BtnAdd.gif); background-position: 0px 0px; background-repeat: no-repeat no-repeat; border: 0px; color: #339933; display: inline-block; font-family: inherit; font-style: inherit; font-weight: inherit; height: 16px; margin: 0px; padding: 0px; vertical-align: middle; width: 16px;" title="Add BP to My Watchlist"> </a>) , meanwhile, has been working with Russia's Rosneft, recently inking key deals for oil and refined products. BP is Rosneft's second largest shareholder. Although Russia is only ranked ninth for shale-gas reserves, it's No. 1 for shale oil.</div><div style="border: 0px; font-style: inherit; font-weight: inherit; margin-bottom: 11px; margin-top: 11px; padding: 0px;">Of course BP and Shell have very different risk profiles. Although Shell has struggled amid difficulty in finding new reserves, BP's out-of-favor stock stems from the Deepwater Horizon oil spill; the impact of which is still an overhang on the shares. While the worst may be over for BP, the legal and political fallout certainly isn't. So, despite similar yields in the 5% area, Shell is probably the safer of the two options.</div><div style="border: 0px; font-style: inherit; font-weight: inherit; margin-bottom: 11px; margin-top: 11px; padding: 0px;"><strong style="border: 0px; font-family: inherit; font-style: inherit; margin: 0px; padding: 0px;">Don't get burned</strong>There will be money made in foreign shale. However, the hype that hurt investors in the U.S. market could easily take the same toll elsewhere. There is a long-term opportunity, but it's probably best to stick with big players like Exxon, Shell, and BP so you don't get caught when the next Chesapeake flames out.</div><div style="border: 0px; font-style: inherit; font-weight: inherit; margin-bottom: 11px; margin-top: 11px; padding: 0px;"><strong style="border: 0px; font-family: inherit; font-style: inherit; margin: 0px; padding: 0px;">Don't miss out on the U.S. shale boom in its prime</strong></div><div class="sfr" id="pitch" style="border: 0px; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;"><div style="border: 0px; font-style: inherit; font-weight: inherit; margin-bottom: 11px; padding: 0px;">Record oil and natural gas production is revolutionizing the United States' energy position. Finding the right plays while historic amounts of capital expenditures are flooding the industry will pad your investment nest egg. For this reason, the Motley Fool is offering a comprehensive look at three energy companies set to soar during this transformation in the energy industry. To find out which three companies are spreading their wings, check out the special free report, "<a href="http://www.fool.com/fool/free-report/18/sa-nextenergyboom-sfr-display-333164.aspx?aid=6597&source=isaeditxt0900038" style="border: 0px; color: #339933; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;">3 Stocks for the American Energy Bonanza</a>." Don't miss out on this timely opportunity; <a href="http://www.fool.com/fool/free-report/18/sa-nextenergyboom-sfr-display-333164.aspx?aid=6597&source=isaeditxt0900038" style="border: 0px; color: #339933; font-family: inherit; font-style: inherit; font-weight: inherit; margin: 0px; padding: 0px;">click here</a> to access your report -- it's absolutely free. </div></div></div>

Can Shale Gas Transform the World?

Post by   Reuben Brewer  (Motley Fool) There are hundreds of shale wells being drilled outside of the United States using fracking and horiz...

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Behind The Margins – Will Lower Gasoline Prices Threaten the Gulf Coast Refining Party?

<div class="separator" style="clear: both; text-align: left;"><span style="font-size: x-small;"><span rel="sioc:has_creator" style="background-color: white; font-family: Arial, Helvetica, sans-serif; line-height: 20.15625px;">Sandy Fielden (RBN Energy)</span><span style="background-color: white; font-family: Arial, Helvetica, sans-serif; line-height: 20.15625px;"> </span></span></div><div class="content clearfix" style="background-color: white; font-family: Arial, Helvetica, sans-serif; line-height: 20.15625px; margin: 0.5em 0px;"><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even" property="content:encoded">Recent third quarter earnings reports from US refiners have reflected lower refining margins squeezed by higher feedstock prices for inland crudes like West Texas Intermediate (WTI) rising to the same level as coastal crudes like Light Louisiana Sweet (LLS) while product prices stood still. In the past two weeks domestic crude prices have fallen below $100/Bbl in the face of a Gulf Coast supply glut. But despite lower crude costs, refinery margins have continued to weaken. The primary culprit has been sharply falling gasoline prices. Today we review what Gulf Coast refiners could do to improve margins.<br /><div style="font-size: 13px;"><br /></div><div style="font-size: 13px;">RBN Energy analysis of refining margins uses a simplified approach known as “crack spreads” to identify overall trends in refinery performance rather than getting into more complex refinery economics. Recall that the term “crack” does not refer to something a wayward crude trader might ingest in the bathroom but rather to breaking down or “cracking” crude oil. The term “spread” means the difference between the sales price of the refined products and the raw material cost of crude i.e. the refining margin. A 3-2-1 Crack spread for example approximates a refinery that produces two barrels of gasoline and one barrel of diesel for every three barrels of crude input. In other words the refinery yield is two-thirds gasoline, one-third diesel. </div><div style="font-size: 13px;"><br /></div><div style="font-size: 13px;">Back at the start of August we looked at how the NYMEX 3-2-1 crack spread (based on NYMEX futures contracts) cratered 56 percent between March and August this year (2013) after the NYMEX benchmark West Texas Intermediate (WTI) crude discount to Brent narrowed close to parity in July 2013. WTI prices had previously been discounted to Brent for almost three years as a result of crude supply disruption in the Midwest. The 3-2-1 crack spread was squeezed when rising WTI crude prices this year were not matched by refined product prices that stayed more or less static. As a result refiners paid more for their crude but didn’t get higher revenues from refined product sales - reducing their margins.</div><div style="font-size: 13px;"><br /></div><div style="font-size: 13px;">Two months ago in September we looked at the impact of the Syrian crisis on refining margins at the US Gulf Coast . Back then the threat of war caused international crude prices to increase temporarily, pulling US crude prices along with them but leaving product prices behind. That put further downward pressure on refinery margins – showing how refiners are frequently impacted by events beyond their control.</div><div style="font-size: 13px;"><br /></div><div style="font-size: 13px;">Any time that crude and refined product prices get out of whack – and it happens quite often - refiners experience volatile margins. Sometimes it works out in refiners’ favor. Over the past three years the WTI discount to Brent crude meant that refiners with access to lower priced “advantaged” crude (for example refineries in the Midwest) were able to enjoy very favorable margins, because generally speaking, product prices continued to be set higher by international markets even as crude feedstock prices for these refiners were discounted.</div><div style="font-size: 13px;"><br /></div><div style="font-size: 13px;">Back to the present and - as we discussed a couple of weeks ago, crude prices have come under pressure at the Gulf Coast as more supplies reach refineries there from US and Canadian producers and seasonal refinery maintenance reduces demand for feedstocks . But even as crude prices are falling, refinery margins are not responding positively. That is because refined product prices – particularly gasoline are falling faster than crude. And as we shall see, the resulting margin squeeze encourages those refiners that have the flexibility, to cut down their gasoline output and increase their diesel production.</div><div style="font-size: 13px;"><br /></div><div style="font-size: 13px;">Taking a look first at crude prices, the chart below shows WTI (green line) Gulf Coast benchmark Light Louisiana Sweet (LLS – red line) and international benchmark Brent (blue line) since the start of July 2013.  After increasing to over $110/Bbl in early September under the influence of international tensions in the Middle East, crude prices have fallen back below $100/Bbl. As we noted a moment ago an increasing surplus of light sweet crude supplies at the Gulf Coast has caused WTI and LLS prices to fall. Meanwhile Brent prices have become detached from the Gulf Coast market because supplies of imported light and medium sweet crude that use Brent based pricing are not currently needed to meet refinery needs. The two black dotted arrows on the chart show the divergence between Brent and WTI/LLS prices. The current supply surplus has caused crude inventories in the Gulf Coast region to increase by over 17 MMBbl from mid September to the beginning of November. LLS prices have fallen 13 percent from $110.63/Bbl on September 13, 2013 to $97.89/Bbl on November 8, 2013. WTI prices fell 13.6 percent over the same period from $108.21/Bbl on September 13 to $94.6/Bbl on November 8.</div><div style="font-size: 13px; text-align: center;"><div class="separator" style="clear: both; text-align: center;"><a href="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEh8q3S97Or8ZAZ4xXPP-2RVdX_fSQVZLI4HQgriz9jbFmH-dM7BIUH0PLLPe9zLuA-8rclFVOfP0XyTW0Yc67Bwm2QcPiTFlSIfuoMGPDmNyLMMm9vDa6rfRCuQ3WD0GAZRJSY8HmRQwP_q/s1600/chart1_54.png" imageanchor="1" style="margin-left: 1em; margin-right: 1em;"><img border="0" src="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEh8q3S97Or8ZAZ4xXPP-2RVdX_fSQVZLI4HQgriz9jbFmH-dM7BIUH0PLLPe9zLuA-8rclFVOfP0XyTW0Yc67Bwm2QcPiTFlSIfuoMGPDmNyLMMm9vDa6rfRCuQ3WD0GAZRJSY8HmRQwP_q/s1600/chart1_54.png" /></a></div><br /></div><div style="font-size: 13px; text-align: center;">Source: CME data from <a href="http://www.morningstarcommodity.com//" style="color: #005a8c; text-decoration: none;">Morningstar</a> (Click to Enlarge)</div><div style="font-size: 13px;">Next take a look at refined product prices for gasoline and diesel at the Gulf Coast. The chart below shows ultra low sulfur diesel (ULSD - green line) and reformulated gasoline (orange line) priced at the Gulf Coast since the start of July 2013. You can see that the price of diesel has remained relatively stable since the start of September while gasoline has fallen sharply (blue dotted circle). The strength of diesel prices results from continued strong demand for exports from the Gulf Coast, to Latin American and European markets. Also demand for heating oil (used primarily in the Northeast during the winter) is high at this time of year in the run up to winter. Because New York State now requires the use of lower sulfur spec heating oil, the demand for low sulfur diesel from Gulf Coast refineries is higher –underpinning ULSD prices.</div><div style="font-size: 13px;"><br /></div><div style="font-size: 13px;">In contrast gasoline prices are falling because of continued weak domestic demand. Gasoline demand in the US fell by 3 percent between the end of August and mid October according to data from the Energy Information Administration (EIA). We have previously discussed falling US gasoline demand. Increased ethanol blending in gasoline to meet Renewable Fuel Standards and more efficient engines under CAFÉ regulations have reduced US consumption since 2005. Gasoline demand is traditionally weaker at the end of the summer driving season and Gulf Coast gasoline inventories remained high this fall. Early October inventories were essentially the same as those in late July because summer demand did not soak up supplies (source EIA). As a result gasoline prices at the Gulf Coast fell 22 percent from $2.96/gal on September 2^nd 2013 to $2.32/gal on November 1, 2013 although in the past week falling gas prices at the pump have encouraged increased demand and a slight uptick in prices that you see at the end of the chart.</div><div style="font-size: 13px; text-align: center;"><a class="colorbox colorbox-insert-image init-colorbox-processed cboxElement" href="http://www.rbnenergy.com/sites/default/files/styles/extra_large/public/field/image/chart2_39.png?itok=XoWWtCqy" style="color: #005a8c; text-decoration: none;"><img alt="" class="image-large" src="http://www.rbnenergy.com/sites/default/files/styles/large/public/field/image/chart2_39.png?itok=IsMjI0Uc" style="border: 0px;" typeof="foaf:Image" /></a></div><div style="font-size: 13px; text-align: center;">Source: CME data from <a href="http://www.morningstarcommodity.com//" style="color: #005a8c; text-decoration: none;">Morningstar</a> (Click to Enlarge)</div><div style="font-size: 13px;">In this situation where crude prices are down 13 percent and gasoline prices fell 22 percent, refining margins are once again under pressure. However, stronger diesel prices afford some hope that refiners can bolster their margins by increasing their output of diesel and reducing their output of gasoline. We can see how this works by looking at two crack spread calculations that reflect different gasoline output volumes. The chart below shows two Gulf Coast crack spreads calculated since July 2013 . The blue line on the chart is a 3-2-1 crack spread – modeling a refinery that processes 3 barrels of LLS crude to produce 2 barrels of gasoline and 1 barrel of diesel. That 3-2-1 crack spread represents a traditional US Gulf Coast complex refinery configuration designed to produce twice as much gasoline as diesel. The red line on the chart is a 2-1-1 crack spread modeling a refinery that processes 2 barrels of crude to produce one barrel of gasoline and one barrel of diesel. The 2-1-1 configuration matches gasoline and diesel output at 50 percent each. You can see that in the period since the start of September the 2-1-1 crack spread with less gasoline has been more profitable than the 3-2-1 with more gasoline (green circle). In fact between September 2 and November 1, 2013 the 2-1-1 crack spread averaged $3/Bbl higher than the 3-2-1. In other words reducing gasoline output at the expense of diesel increases the potential margin by $3/Bbl.</div><div style="font-size: 13px;"><br /></div><div style="font-size: 13px; text-align: center;"><a class="colorbox colorbox-insert-image init-colorbox-processed cboxElement" href="http://www.rbnenergy.com/sites/default/files/styles/extra_large/public/field/image/chart3_14.png?itok=Y3yB4J0P" style="color: #005a8c; text-decoration: none;"><img alt="" class="image-large" src="http://www.rbnenergy.com/sites/default/files/styles/large/public/field/image/chart3_14.png?itok=x7BcJaCq" style="border: 0px;" typeof="foaf:Image" /></a></div><div style="font-size: 13px; text-align: center;">Source: CME data from <a href="http://www.morningstarcommodity.com//" style="color: #005a8c; text-decoration: none;">Morningstar</a> (Click to Enlarge)</div><div style="font-size: 13px; text-align: center;"><br /></div><div style="font-size: 13px;">Easy enough to do that with our crack spread models but is it something that refiners are able to accomplish in practice?  The answer to that question is not so simple because refineries are complex operations that cannot be reconfigured overnight. Most complex Gulf Coast refineries that process light sweet crude were designed to meet market needs 10 years ago when US gasoline demand was growing and domestic demand for diesel was weaker. These refineries still produce more gasoline than diesel. Not surprisingly, when diesel demand and prices are stronger than gasoline - which is the situation today – those refinery configurations produce lower margins. And if those refiners produce more diesel then they get more unwanted gasoline along with it – adding to the downward pressure on gasoline prices.</div><div style="font-size: 13px;"><br /></div><div style="font-size: 13px;">But refiners are not blind to these economics and they are responding by investing in processing units that produce more diesel. Back in July we covered investments by Valero and Marathon in hydrocracker units designed to bring their refinery production closer to a 50/50 gasoline/diesel output like a 2-1-1 crack. Expect to see more investments along these lines among Gulf Coast refiners with an eye to the strong diesel export market.</div><div style="font-size: 13px;"><br /></div><div style="font-size: 13px;">However, as we have frequently detailed, the flood of new shale crude showing up at Gulf Coast refineries are very light – meaning that they contain a lot of gasoline components. These crudes do not have so many middle distillate components that are needed to produce diesel. So whatever refiners do to adjust their configuration to produce more diesel, they are still going to be left with a lot of gasoline range material. Since the US market demand for gasoline is static or falling, that material will likely have to be exported. If international and domestic demand for gasoline are both weak then gasoline prices will fall. Good news for US motorists but bad news for refiners. </div><div style="font-size: 13px;"><br /></div><div style="font-size: 13px;">Summing up, as Gulf Coast refiners get ready for the flood of new crude coming their way, the downward pressure on crude prices offers the prospect of improved refinery margins through lower feedstock costs. But that is not guaranteed because refining margins also depend on product prices staying higher as well. So far healthy demand at home and abroad for diesel has made that product quite profitable for Gulf Coast refiners. Gasoline margins are less robust and could threaten to spoil the refining party.</div></div></div></div></div>

Behind The Margins – Will Lower Gasoline Prices Threaten the Gulf Coast Refining Party?

Sandy Fielden (RBN Energy)   Recent third quarter earnings reports from US refiners have reflected lower refining margins squeezed by higher...

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Higher and Higher – A Better Forecast of Drilling Rig Productivity

<div class="separator" style="clear: both; text-align: center;"></div><div class="separator" style="clear: both; text-align: left;"><span style="background-color: white; color: #999999; font-family: Arial, Helvetica, sans-serif; font-size: xx-small; line-height: 20.15625px;">Sandy Fielden (RBN  Energy) </span></div><div class="separator" style="clear: both; text-align: left;"><span style="background-color: white; color: #999999; font-family: Arial, Helvetica, sans-serif; font-size: xx-small; line-height: 20.15625px;"><br /></span></div><h1 class="title" id="page-title" style="background-color: white; font-family: Arial, Helvetica, sans-serif; line-height: 1.2em; margin: 0px auto; padding: 0px;"><span style="font-size: 13px; font-weight: normal; line-height: 20.15625px;">Last month the Energy Information Administration (EIA) debuted a new monthly report detailing oil and gas drilling productivity in six of the largest US production basins. Rather than just being an “after the fact” report telling us what happened in the past, the new report provides a forecast of oil and gas production for the current and next month out in each of the six basins. The initial report indicates that oil production will increase by roughly 60 Mb/d in these basins during November with gas production increasing by 0.4 Bcf/d. The report also highlights continued improvement in rig productivity. Today we begin a series interpreting the new drilling rig productivity data.</span></h1><div class="content-middle" style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13px; line-height: 20.15625px;"><div class="region region-content"><div class="block block-system" id="block-system-main" style="margin: 0px;"><div class="content"><div about="/higher-and-higher-a-better-forecast-of-drilling-rig-productivity" class="node node-article clearfix" id="node-691" style="border-bottom-color: rgb(187, 187, 187); border-bottom-style: solid; border-bottom-width: 1px; margin: 20px 0px; padding-bottom: 15px;" typeof="sioc:Item foaf:Document"><div class="content clearfix" style="margin: 0.5em 0px;"><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even" property="content:encoded">We have previously described rapidly increasing US natural gas production from shale as well as oil production from shale and other tight resources. Recent U.S. crude and gas growth has centered largely in a few key regions and has been driven by advances in the application of horizontal drilling and hydraulic fracturing technologies. The growth in production has been accompanied by improvements in drilling productivity - described in our six part series on drilling economics. In fact drilling productivity is driving domestic production to such an extent that the EIA has developed a new approach to measuring it.<br />The EIA Drilling Productivity Report (DPR) provides region-specific insights into rig efficiency, new well productivity, decline rates at previously existing wells, and overall production trends. The report covers six regions (see map below). In 2011-12, these six regions accounted for 90 percent of domestic oil production growth and virtually all domestic natural gas production growth.<br /><div class="separator" style="clear: both; text-align: center;"><a href="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEgZrJORPC_7WprB1v5lmne6ZZWsHpOh6kvHitcK2C0paru9fItc_e-4owrvGCmxJZjyEYFwMVMUO1CS57RQlaqAVebdM1PO5SO1CHBft8qrB7N3hsc334SO1hyphenhyphenk_H0rO9-5C1kBdvfZj5wS/s1600/map_17.png" imageanchor="1" style="margin-left: 1em; margin-right: 1em;"><img border="0" height="196" src="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEgZrJORPC_7WprB1v5lmne6ZZWsHpOh6kvHitcK2C0paru9fItc_e-4owrvGCmxJZjyEYFwMVMUO1CS57RQlaqAVebdM1PO5SO1CHBft8qrB7N3hsc334SO1hyphenhyphenk_H0rO9-5C1kBdvfZj5wS/s320/map_17.png" width="320" /></a></div><br /><div style="text-align: center;"></div><div style="text-align: center;">Source: EIA (Click to Enlarge)</div>The DPR estimates the current rate of growth or decline in production in each of these basins based on a number of indicators. These include the active rig count, drilling efficiency as well as the productivity of new wells, and production and depletion trends for previously producing wells. The data is intended to be more informative than traditional indicators such as simple oil and gas rig counts. The report also estimates rig productivity - a new measure that EIA has developed to better reflect continuing improvements in drilling rig efficiency. The rig productivity measure starts with an estimate of crude and natural gas output from new wells in a region during their first month in production. The rig productivity (calculated separately for oil and for gas) is the new well output divided by the number of drilling rigs in the region.<br /><br />We will look at some of the regional data in the report in future episodes in this series but this time we have compiled two tables that summarize the production and rig productivity data provided in the report.<br />Table #1 below shows a summary of the production forecast data in the initial report for October 2013. The table is divided into two parts – the top half is for oil and the bottom half is for gas. Taking the oil data first, there are 8 column headings – one each for the production basins, a total column (orange box) and a monthly change column (light blue box). For each basin the table has three months worth of data extracted from the DPR. The data shows estimated monthly oil production in Mb/d for each basin that the EIA forecast. The forecast is based on prior month well data published by State agencies, current and prior month well drilling counts and average production from new and existing wells. Because production data reported by states can be significantly lagged, DPR uses rig count data along with trends in drilling productivity to make estimates of oil and gas production where data are not yet available. Since existing EIA monthly production reports have a three month lag the information in the DPR is more current than previously available – although likely subject to adjustment. The DPR provides history back to 2007.<br /><div style="text-align: center;"><a class="colorbox colorbox-insert-image init-colorbox-processed cboxElement" href="http://www.rbnenergy.com/sites/default/files/styles/extra_large/public/field/image/table1_30.png?itok=kXB20XnY" style="color: #005a8c; text-decoration: none;"><img alt="" class="image-large" src="http://www.rbnenergy.com/sites/default/files/styles/large/public/field/image/table1_30.png?itok=2gAve1Eh" style="border: 0px;" typeof="foaf:Image" /></a></div><div style="text-align: center;">Source: EIA and RBN Energy (Click to Enlarge)</div>The oil data shows that production in the Eagle Ford basin (red box) is expanding at a rate of over 25 Mb/d per month from 1045 Mb/d in September 2013 to 1093 Mb/d in November with Bakken production (brown box) expanding at similar rates, while the Permian basin is expanding more slowly (2 Mb/d per month – green box). The overall six-basin production estimate for November 2013 is 3.7 MMb/d (Total Oil column in the table) representing more than 50 percent of the latest published EIA total US crude production of ~7.5 MMb/d (July 2013). In the final column of the table we show the forecast monthly change in total production for all six basins, which is around 60 Mb/d for the latest three months in the DPR.<br /><br />The bottom half of Table #1 shows the identical summary for natural gas production in the six basins in MMcf/d. The total gas production in the six basins is expected to reach 34.2 Bcf/d in November – up 0.4 Bcf/d from October (Total Gas column). The two largest gas basins are the Marcellus (purple box) and the Haynesville (light green box) – with the former expected to produce 12.6 Bcf/d in November 2013 – just under double the Haynesville estimate of 6.6 Bcf/d (note the data in the table is in MMcf/d). Natural gas production in the Permian and Eagle Ford basins is higher than the Bakken because the former have more infrastructure to deliver associated gas from oil production to market .<br /><div style="text-align: center;"><a class="colorbox colorbox-insert-image init-colorbox-processed cboxElement" href="http://www.rbnenergy.com/sites/default/files/styles/extra_large/public/field/image/table2_10.png?itok=cHn1_RU6" style="color: #005a8c; text-decoration: none;"><img alt="" class="image-large" src="http://www.rbnenergy.com/sites/default/files/styles/large/public/field/image/table2_10.png?itok=iZIZgsiC" style="border: 0px;" typeof="foaf:Image" /></a></div><div style="text-align: center;">Source: EIA and RBN Energy (Click to Enlarge)</div>Table #2 above is a summary of drilling rig productivity data for each of the six basins. The data is an estimate of new well production (during the first month of production) divided by the rig count. The layout of the table is similar to Table #1 with three months of data for each basin – oil at the top and gas at the bottom. The data shows that oil rig productivity is improving in all the basins except the Permian (dark green box) that is basically flat. Estimated Bakken rig productivity (brown box) jumped 23 Mb/d between October and November, but the average of all basins increased by only 7 Mb/d (blue shaded monthly change column). Estimated gas rig productivity increases in every basin except the Niobrara (pink box) in November. Marcellus rig productivity was up by 160 Mcf/d in November over October compared to the average for all 6 basins of 29 Bcf/d (purple box).<br />The new DPR report provides a compelling gauge of US oil and gas drilling productivity in a more timely form than we have previously had access to. The data shows production continues to increase in the main shale and tight oil basins. Much of the improvement is due to drilling efficiency and new well productivity, rather than an increase in the number of active rigs. In the next episode in this series we will look more closely at the data provided for specific basins as well as the impact of older declining production on the overall trends. </div></div></div></div></div></div></div></div></div>

Higher and Higher – A Better Forecast of Drilling Rig Productivity

Sandy Fielden (RBN  Energy)  Last month the Energy Information Administration (EIA) debuted a new monthly report detailing oil and gas drill...

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Under Pressure – Natural Gas Prices Held in Check By Abundant Supplies

<div class="separator" style="clear: both; text-align: left;"><span style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px;">Sandy Fielden RBN 2013</span></div><div class="separator" style="clear: both; text-align: left;"><span style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px;">The CME natural gas futures market has been trading in a narrow 40 cent range between $3.40/MMBtu and $3.80/MMBtu since the end of the summer. The onset of winter and the first storage withdrawals last week (according to EIA) have done little to jump start prices. The prompt Henry Hub futures market closed at $3.702 yesterday (November 21, 2013). The dominating story remains increased supply from new production. Today we look at how supplies are weighing on spot prices and futures market speculation.</span></div><span style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px;"><br /></span><br /><div style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px;">This year has been a pretty unexciting one for the natural gas market so far. CME NYMEX Henry Hub futures prices reached $4.40/MMBtu in April, which turned out to be their high of 2013 so far, after a colder than normal start to the year, before falling to a low of $3.25/MMBtu in August when summer temperatures did not increase demand significantly. Prices recovered to $3.82/MMBtu in October during an early cold spell but fell back to $3.44/MMBtu in November as milder weather returned – recovering to $3.70/MMBtu in the past week on colder forecast temperatures. But we have not seen the record low prices of 2012 when gas dipped close to $2/MMBtu and there has not been a sustained recovery above $4/MMBtu as many market analysts expected. Since the end of the summer prices have been stuck in a 40-cent range between $3.40/MMBtu and $3.80/MMBtu.<br /><br /></div><div style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px; text-align: center;"><a class="colorbox colorbox-insert-image init-colorbox-processed cboxElement" href="http://www.rbnenergy.com/sites/default/files/styles/extra_large/public/field/image/table1_32.png?itok=fmnqW5af" style="color: #005a8c; text-decoration: none;"><img alt="" class="image-large" src="http://www.rbnenergy.com/sites/default/files/styles/large/public/field/image/table1_32.png?itok=U5c3gJP1" style="border: 0px;" typeof="foaf:Image" /></a></div><div style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px; text-align: center;">Source: Bentek (Click to Enlarge)</div><div style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px;">Looking at monthly supply/demand data from our friends at Bentek we can see that the dominant theme in the market remains growing supplies. The table above shows the month and year to date US supply/demand balance. Dry gas production in the US continues to increase – up by 1.2 Bcf/d to 65 Bcf/d in the year to October (dark blue circle) and another 2 Bcf/d so far in November to 67 Bcf/d (orange circle). As domestic production continues to grow – especially in the Northeast Marcellus basin, the natural gas distribution network is being rearranged to match new supplies to demand. In the national supply picture those changes show up in the 6.3 percent decline in Canadian imports versus 2012 (red circle) and the 37 percent reduction versus 2012 in LNG imports (dark green circle – “sendout” meaning sent inland from an import terminal). On the demand side, natural gas prices remained high enough relative to coal to discourage generators from large scale switching to natural gas . That coupled with a mild summer led to a 12 percent reduction in power burn versus 2012 (light blue circle). Nearly all of that reduced power burn demand this year (3 Bcf/d) was replaced by a 14.2 percent increase in residential and commercial demand in 2013 over 2012 (magenta circle). Despite much discussion of new industrial demand to suck up lower priced natural gas, the majority of these projects are still a few years away so industrial demand has been flat this year. Helping to soak up increased supplies have been exports across the border to Mexico, which continue to increase – up 11.9 percent this year over last and 15.1 percent so far in November 2013 (brown circle).<br /><br /></div><div style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px;">The buoyant supply picture has kept the lid on the market’s price expectations. The futures market has also seen lower price expectations this year than in the recent past. The chart below shows CME natural gas futures data over the past four years. The blue line is a monthly average CME Henry Hub futures market close price from December 2010 to present. Shooting off from that underlying line are four forward curves for dates around November 19 in 2010 (brown line), 2011 (green line), 2012 (red line) and 2013 (orange line). Recall that forward curves represent current futures market sentiment about the value of forward deliveries – they are not a price forecast. Looking at the right hand end of the top and bottom curves, you can see that the high price on the November 2010 curve is $7.36/MMBtu (for December 2022 delivery) and the November 2013 high price is $1.42/MMBtu lower at $5.94 (for December 2025 delivery). These highest prices on the forward curve – usually the furthest point out into the future, have been getting lower every year for the past four years and they fell faster in 2013 than prior years (black dotted arrows on the chart). This means market sentiment that natural gas prices will increase in the future has become less bullish every year for the past four years – a trend that accelerated this year.<br /><br /></div><div style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px; text-align: center;"><div class="separator" style="clear: both; text-align: center;"><a href="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEgrIzF2qR27dyPR8wgDBfagzZ3ollItD2hPqUL2rLUzmFuP3Y6nZqGOQH9v6khn4ikxHzltefVDu0qM3twMsl0sy8Y3skd-pNsHCycZYJn-vBZDb4bOSu3z_8B5_zvEkXLBtYOhUsczwkfs/s1600/chart1_55.png" imageanchor="1" style="margin-left: 1em; margin-right: 1em;"><img border="0" height="202" src="https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEgrIzF2qR27dyPR8wgDBfagzZ3ollItD2hPqUL2rLUzmFuP3Y6nZqGOQH9v6khn4ikxHzltefVDu0qM3twMsl0sy8Y3skd-pNsHCycZYJn-vBZDb4bOSu3z_8B5_zvEkXLBtYOhUsczwkfs/s320/chart1_55.png" width="320" /></a></div><br /></div><div style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px; text-align: center;">Source: CME Data from <a href="http://www.morningstarcommodity.com//" style="color: #005a8c; text-decoration: none;">Morningstar</a> (Click to Enlarge)</div><div style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px;">With spot and futures prices dampened by the rosy supply picture the natural gas futures market is losing its following among speculators. That follows a trend over the past few years where lower price volatility has discouraged physical trading. Low price volatility is also impacting futures transactions because speculators in financial markets are attracted to commodities with big price swings. With forward prices weaker and increased supply keeping the lid on volatility, opportunities for speculators to profit from sharp price moves are drying up. The chart below shows CME NYMEX prices (red line) and total open interest (blue shaded area) so far this year. Open interest is a measure of  “open” futures contracts i.e. contracts held for future sale or exercise. High open interest generally indicates increased speculation by financial players – hoping to profit from price volatility by holding open positions longer. The chart shows that between February and April 2013 there was a run up of open interest from 1.2 MM contracts to 1.6 MM contracts as speculators piled into the market expecting a strong recovery in gas prices this year. However, once prices began to fall and did not recover in the summer the open interest began to fall as speculators headed for the exits. Continued decline in open interest suggests that speculators do not have high hopes for a winter natural gas price spike this year.<br /><br /></div><div style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px; text-align: center;"><a class="colorbox colorbox-insert-image init-colorbox-processed cboxElement" href="http://www.rbnenergy.com/sites/default/files/styles/extra_large/public/field/image/chart2_40.png?itok=jV8YLUyU" style="color: #005a8c; text-decoration: none;"><img alt="" class="image-large" src="http://www.rbnenergy.com/sites/default/files/styles/large/public/field/image/chart2_40.png?itok=pk-LZizh" style="border: 0px;" typeof="foaf:Image" /></a></div><div style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px; text-align: center;">Source: CME Data from <a href="http://www.morningstarcommodity.com//" style="color: #005a8c; text-decoration: none;">Morningstar</a> (Click to Enlarge)<br /><br /></div><div style="background-color: white; font-family: Arial, Helvetica, sans-serif; font-size: 13.600000381469727px; line-height: 20.149999618530273px;">So far 2013 has not proven comforting for natural gas producers because prices stayed below $4/MMBtu for the most part. Increased production has kept the lid on prices. Power burn was down this year versus last and industrial consumption has yet to pick up significantly. Exports to Mexico remain the bright spot for demand. Supplies from Canada and LNG imports are being pushed out by increased domestic production. Lower price sentiment appears to be set in and the lower expectations of future prices as well as falling open interest suggest that financial markets do not expect a strong recovery in gas prices any time soon. That is good news for consumers of course and for those industrial project planners keeping their fingers crossed for continued low gas prices.</div>

Under Pressure – Natural Gas Prices Held in Check By Abundant Supplies

Sandy Fielden RBN 2013 The CME natural gas futures market has been trading in a narrow 40 cent range between $3.40/MMBtu and $3.80/MMBtu sin...

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