Redeterminations, Hedges and Oil & Gas Q415 Outlook

Redeterminations, Hedges and Oil & Gas Q415 Outlook

October will mark the second bi-annual review of the credit lines for many heavily indebted shale players. Unfortunately their options are shrinking since oil prices now hover around $45 per barrel, significantly lower than the April 2015 mark of around $55 to $60 per barrel. While hedged positions staved off an a serious shortage of cash through 2015, and kept lenders from cutting credit lines, those positions are expiring and exposing companies to market prices. Here’s a chart of the debt status of several shale companies.

Image Source

Describing this challenging backdrop was Emanuel Grillo, partner at Baker Bott’s bankruptcy and restructuring practice via Bloomberg Brief in July 2015: “People are coming to realize that the market is not likely to improve. At the end of September companies will know about their bank loan redeterminations and you’ll see a bunch of restructurings. And, as the last of the hedges start to burn off and you can’t buy them for $80 a barrel any longer, then you’re in a tough place. The bottom line is that if oil prices don’t increase, it could very well be that the next six to nine months will be worse than the last six months. Some had an ability to borrow, and you saw other people go out and restructure. But the options are going to become fewer and smaller the longer you wait.”

Viewing this dilemma from the banker’s perspective, Mr. Grillo stated: “They know what pressure they’re facing from a regulatory perspective. At the same time, if they push too far in that direction, toward complying with the regulatory side and getting out, then they’re going to hurt themselves in terms of what their own recovery is going to be. All of the banks have these loans under tight scrutiny right now. They’d all get out tomorrow if they could. That’s the sense they’re giving off to the marketplace, because the numbers are just not supporting what they need to have from a regulatory perspective.”

Companies with midstream assets to sell should have more restructuring possibilities since they have a fairly robust market of potential master limited partnership (MLP) buyers to offer assets. Coupled with non-essential production and acreage position asset sales along with budget cuts survivorship probabilities should be enhanced. Larger sales that may fall into this category are Pioneer-Reliance sale of EFS Midstream for $2.15 billion, Encana’s sale of Haynesville assets for $850 million and Continental’s sale of Hiland Partner’s Bakken pipes for $3 billion.

Options for smaller players are unfortunately much more limited as witnessed by the 2Q additions to Moody’s “probability of default rating” or PDF. Joining that listing were American Energy Woodford, Magnum Hunter Resources, Quicksilver (Bankruptcy 3/16/2015), Sabine Oil & Gas (Bankruptcy 7/14/2015), and Warren Resources.

On a macro basis, Standard and Poor’s Ratings Service in a report this month stated, the oil and gas sector has nearly $242 billion in rated debt scheduled to mature from the second half of this year through 2020. Of the debt scheduled to mature, $124 billion is speculative grade. Companies carrying speculative debt “show weaker credit metrics than those rated investment grade and so, often are subject to a greater degree of refinancing risk, especially when investors become more risk averse and volatility rises or liquidity declines.”

A quote at a recent Barclay’s Capital Energy Conference attributed to Freeport-McMoRan Inc.’s Jim Flores may have summed it up the best, “It’s raining and it’s going to rain for a long time. We’re all going to get wet. A few people are going to drown.”


Natural Gas Intelligence
E & P’s Bracing for Redetermination Redux

Shale Drillers’ Safety Net Vanishing

Zero Hedge
Shale Drillers About to be “Zero Hedged” As Loss Protection Expires
Energy Companies Face “Come-to-Jesus” Point as Bankruptcies Loom

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Natural Gas Exports to Mexico on the Fast Track

Natural Gas Exports to Mexico on the Fast Track

Just as Space X rockets may be taking off from the beaches at Boca Chica near Brownsville, natural gas exports to Mexico look to also sky rocket in the coming years. Due to changes in Mexican law in 2013 opening the electricity market to private investment, billions of dollars in contracts have been let to build power plants, electrical distribution facilities and natural gas pipelines. In turn U.S. pipeline companies and gas producers have moved to capture the lion’s share of that market. Given the fact that Texas and Gulf Coast producers have been rapidly losing their old Northeast and Midwest markets to Marcellus producers this has proven to be a timely and vital new market. The Energy Information Agency (EIA) estimates that natural gas exports to Mexico were 3% of production in April 2015 and are expected to grow to 5% by 2030. While not nearly as important as the domestic power sector to U.S. producers nonetheless it represents a good piece of business.

BB - fig 1 natural gas exports

So just where are these projects crossing the border and linking up to Mexican pipelines? Let’s take a look at recent developments. Last year Kinder Morgan’s (KM) Sierrita gas pipeline went online carrying 1.9 Bcf/day into Mexico. The 36-inch 60-mile line runs from El Paso Natural Gas’s (owned by KM) existing south mainlines near Tucson to Sasabe, AZ before interconnecting to Mexican pipelines at the border. Estimates for gross exports to Mexico are estimated to rise to 4.6 Bcf/d by 2024 and the Sierrita will contribute a fair share of that export capacity. This presentation from Kinder Morgan contains more detailed breakdowns of system capacities.

BB - fig 2 natural gas exports

In addition to the newly constructed Sieritta pipeline, KM also has Texas intrastate facilities. Included in the operations of the KM Tejas system is the Morgan Border Pipeline system. Border Pipeline owns and operates an approximately 97-mile, 24-inch diameter pipeline that extends from a point of interconnection with the pipeline facilities of Pemex Gas Y Petroquimica Basica at the International Border between the United States and Mexico in Hidalgo County, Texas, to a point of interconnection with other intrastate pipeline facilities of KM Tejas located at King Ranch, Kleburg County, Texas. The pipeline has a capacity of approximately 300 million cubic feet of natural gas per day and is capable of importing this volume of Mexican gas into the United States or exporting this volume of gas to Mexico.

Drillinginfo Pipeline Layer Map

BB---fig-3 natural gas exports

The Mier-Monterrey Pipeline, also owned by KM, consists of a 95-mile natural gas pipeline that stretches from the International Border between the United States and Mexico in Starr County, Texas, to Monterrey, Mexico and can transport up to 375 million cubic feet per day. The pipeline connects to a 1,000-megawatt power plant complex and to the PEMEX natural gas transportation system.
BB---fig-4 natural gas exports

Next up are newly announced pipelines, such as Howard Midstream Energy Partners (HEP) June 23, 2015 announcement of the Nueva Era Pipeline, an approximately 200-mile, 30-inch pipeline connecting its existing Webb County Hub to Escobedo, Nuevo Leon, Mexico, and the Mexican National Pipeline System in Monterrey. Expected to be in-service in July 2017, the Nueva Era pipeline, which will be developed in conjunction with HEP’s Mexican partner, will provide seamless transport for up to 600 mcf/day from South Texas producers directly to end-users in Mexico. San Antonio based HEP said it expects Nueva Era transportation service rates from U.S. – Mexico border to Escobedo to be between US $0.13 and US $0.20 per mcf, subject to the shipper’s required term, level of service, and volume commitment, and pursuant to all Mexican legal requirements. HEP CEO Mike Howard made an insightful commit during the press release stating that “…When you look at the state of Texas, we have about 300,000 miles of pipe in Texas, and in all of Mexico they have about 9,000 miles of pipe. I think the prize is that there are going to be large infrastructure requirements in Mexico.”

BB---fig-5 natural gas exports

The biggest proposed natural gas pipeline project in South Texas is the South Texas-Tuxpan Pipeline, a 42-inch diameter line that would run 497.1 miles under the Gulf of Mexico from South Texas to Tuxpan, in the state of Veracruz. The pipeline, valued at $3.1 billion, would have 2.6 Bcf/day of capacity and have interconnections with the Nueces-Brownsville and the Tuxpan-Tula pipelines. This pipeline is among the $9.8 billion in gas transport and power plant projects recently issued requests for proposals from the Federal Electricity Commission (CFE), Mexico’s state-owned electricity utility. The contract has an expected award date of December 2015 with a start date of June 2018.

BB - fig 6 natural gas exports

In March of 2014 Energy Transfer subsidiary Houston Pipe Line Company received FERC approval to build and operate a pipeline to export or import of gas at the international boundary between Hidalgo County in Texas and the city of Reynosa in Tamaulipas state in Mexico. Houston Pipeline will use existing infrastructure and right-of-way to construct a new 24-inch pipeline from near Edinburg, TX to a new international border crossing near McAllen, TX. While the new 23 mile extension will have a design capacity of approximately 140 mcf/day, the 15 year contract with CFE calls for transportation services of 930,000 MMBtu/day.

In January of 2015 Mexico’s CFE selected a consortium of companies that includes Dallas-based Energy Transfer Partners (ETP) to construct two pipelines in West Texas. The Trans Pecos pipeline would run 143 miles from the Waha natural gas hub near the town of Pecos in Reeves County down to the border town of Presidio, where it would connect with a short 1,000 foot cross-border pipeline connecting to another line in the Mexican town of Ojinaga. At 42 inches in diameter, it would be capable of moving 1.4 billion cubic feet of natural gas a day. Local opposition has heated up as local residents learned of the construction and while Energy Transfer has an approved T-4 permit from the Texas Railroad Commission compromise may prove difficult.

The Comanche Trail pipeline will be a 192 mile 42-inch pipeline delivering 1.1 Bcf/day, from the Waha hub to the international border at San Elizario, TX, just south of El Paso. The consortium for this project is comprised of Energy Transfer Partners, MasTec, and Carso Energy (owned by Carlos Slim, Mexico’s richest man).

BB - fig 7 natural gas exports

The Roadrunner Gas Transmission pipeline extends from ONEOK Partners’ Wes Tex pipeline system at Coyanosa, TX west to a new international border-crossing near San Elizario, TX. The first phase of the project for 170 MMcf/d of available capacity is expected to be completed by the first quarter of 2016. The second phase, which will increase the pipeline’s available capacity to 570 MMcf/d, is expected to be completed by the first quarter of 2017. The third and final phase of the project is expected to be completed in 2019 and will increase available capacity to 640 MMcf/d.

BB---fig-8 natural gas exports

That’s three (3) existing pipelines and six (6) proposed pipelines with combined capacity of 6.5 Bcf/d and representing capital budgets in excess of $7 billion. A lot of pipe and money in anybody’s book.

References and image sources:

Vice News, Mexico Wants to Run a Pipeline Through West Texas, Sasha Von Oldershausen, June 22, 2015.
NGI Shale Gas Daily, Texas-Mexico Pipeline Developer Looks Forward to Gathering Mexican Gas, Too, Joe Fisher, June 23, 2015.
RBN Energy, As We Send Gas Through the Streets of Laredo, Housely Carr, June 30, 2015.
High Country News, Natural Gas Exports to Mexico are Surging, Elizabeth Shogren, July 7, 2015.
El Paso Times, Proposed construction of gas pipelines concerns San Elizario residents, Aileen B. Flores, July 12, 2015.

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Gulf Coast LNG is Ready for the World

Gulf Coast LNG is Ready for the World

Even as natural gas overtakes coal as the biggest U. S. electricity source, the U. S. Gulf Coast is set to become a major export hub for the international Liquefied Natural Gas (LNG) business. A quick look at the existing Federal Energy Regulatory Commission (FERC) approved facilities indicates that 6 out of 11 (55%) of them are located on the Gulf Coast. Many of these facilities were originally built as import (re-gasification) terminals, but with the incredible rise in U. S. shale gas reserves and production, they have been re-engineered to export (liquefaction) terminals.

gulf coast lng---fig-1
Existing FERC Jurisdictional LNG Import/Export Terminals (Source

A check of the FERC “approved” facilities shows 9 of 11 (82%) located on the Gulf. More importantly, 4 out of the 9 Gulf sites are currently under construction (Sabine Pass, Hackberry, Freeport, and Corpus Christi).

Reviewing the “proposed” FERC facilities, 16 out of 24 (67%) find their home on the southern coastline.

gulf coast lng---fig-2
Sources and

All told, 25 projects (some facilities will have multiple liquefaction and purification trains) are planned, representing approximately 36 Bcf/day of export capacity and exceeding $50 billion in potential capital commitments. A look at the Department of Energy’s (DOE) applications for export lists 51 applications, 42 of which are for the Gulf Coast.

Many of these projects are far from being built and many still await approvals from FERC and the DOE. That said, the abundance of shale gas in the U. S. and the ability to tie the long term gas contracts to Henry Hub pricing make these facilities some of the most competitive in the world market. Interest from Asian and European buyers is very high and can be seen in the commitments being made to these facilities by BG (British Gas, now in merger with Shell), Osaka Gas (Japan), Chubu Electric (Japan), Pertamina (Indonesia), Endesa (Spain), Iberdrola (Spain), Gas Natural Fenosa (Spain), Woodside (Australia), Petronet (India), Mitsubishi (Japan), Mitsui & Co. (Japan), GDF Suez (France), EDF (UK), and EDP (Portugal).

There are currently 34 LNG liquifaction plants internationally with 16 under construction. With the addition of the potential U.S. and Canadian facilities that number could almost double in 10 – 20 years. While much risk and uncertainty surrounds these projects they are yet another offspring of the shale revolution.

gulf coast lng---fig-3

Based on demand, LNG production is expected to double in the next 20 years.

gulf coast lng - fig 5

Japan and South Korea accounted for 75% of 2014 demand but China, India, and other Asian economies (Thailand, Singapore, the Philippines, Vietnam) are expected to have greater growth in the years ahead. Asia will remain the primary demand center as exemplified by their 2014 imports of 180 MTPA (23 Bcf/d) which is 6 times greater than the nearest competitor, Europe.

LNG accounts for only 10% of Europe gas demand due Russia’s Gazsprom which pipes in 14.3 Bcf/d (> one-third of the market). However, Western European countries that were not part of the old Soviet bloc, imported more gas from Norway in the 1Q 2015 for only the 2nd time in recent history (think Ukraine conflict). Since European gas production, primarily from Norway and the Netherlands, is forecast to decline significantly in the next 20 years LNG demand is expected to double by 2025 and triple by 2035. That fact bodes well for U. S. exporters (with contracts tied to Henry Hub) who will be able to compete more effectively in the more liquid European spot market.

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Heater-Treaters on the rise in North Dakota?

Heater-Treaters on the rise in North Dakota?

Responding to pressure to reduce the volatility of North Dakota crude oil after the train disaster in Lac-Megantic, Quebec in 2013 which killed 47 people and another derailment and fire in North Dakota that same year, the North Dakota Industrial Commission (NDIC) passed standards on December 9, 2014 to require oil-conditioning equipment at the well head to separate production fluids into their gas and liquid components, thereby reducing the volatility of the crude.

The standard requires producers to heat crude oil to at least 110 degrees F. at a pressure of 50 psi., effective April 1, 2015. The standard device commonly used to accomplish this is known in the industry as a “heater-treater. See image below.

Image Source:

The order requires a Reid Vapor Pressure (RVP) of 13.7 psi. “RVP” is a measure of gasoline volatility indicated in pounds per square inch, the higher the RVP the more quickly it evaporates, RVP at normal atmospheric pressure is 14.7 psi. Just how many heater-treaters may be required is a heated subject of debate between the State regulators and the industry.

Two recent State announcements attempt to provide some indication of where things might stand. The North Dakota Department of Mineral Resources has indicated that 80% of Bakken crude has an average RVP of 11.8 psi, less than the requirement and therefore in compliance. State inspectors recently reported that 55% (165) of the roughly 300 existing heater-treaters operated within the guidelines, 33% (99) were operating at lower temperatures and 12% (36) applied no heat to crude oil. The 12% is believed to represent smaller operators who could be severely impacted by the new rules.

The 800 pound gorilla in the room with these statistics though is what percentage of the existing wells have no heater-treaters, potentially a lot more than 300 given the thousands of wells in North Dakota. A search of the DI database for existing directional wells in North Dakota reveals 12,994 directional wells. Accepting the State’s 80% rule and taking only 20% of the 12,994 wells leaves 2599 wells without equipment. To be conservative we will assume as many as 6 wells could be treated with one heater-treater (the number will actually vary depending upon production and equipment capacity) the additional units would total 133 (2599/6 – 300 = 133). If labor and equipment were to run $100,000 per installation costs would be in the neighborhood $13,300,000 to reach compliance.
Due to the uncertainty of making accurate predictions of total wells in North Dakota, I chose to use only newer horizontal wells in this example. However a conservative estimate of the total number of active wells in North Dakota would be upwards of 25,000 wells. In which case, the projections herein could easily double. Not to mention the likelihood of wildly varying installation costs, all assumed to be occurring over 90 days in the dead of winter. Alas, as most field disputes in remote areas of the oil patch one can see that this controversy is just beginning. Given the 60% decrease in the price of crude oil in January alone, the only certainty appears to be a bad April Fool’s joke for a lot of operators. As always DI Analytics will be watching the data to sort out fact from fiction as the information becomes available.

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What Exactly is Condensate and Why is its Export Prohibited?

What Exactly is Condensate and Why is its Export Prohibited?

Condensate is a very light hydrocarbon with an American Petroleum Institute (API) specific gravity of greater than 50 degrees and less than 80 degrees. In underground formations condensate can exist separately from the crude oil or dissolved in the crude oil.

Plant and Field Condensate

When produced at the wellhead and run through a stabilizer it is known as “field” or “lease” condensate. In dry gas or condensate wells, condensate remains suspended in the gas stream until separated at gas processing facility, thus earning the name “plant” condensate or “natural gasoline”. FYI, for reporting purposes, the U.S. Energy Information Administration defines lease condensate as crude oil and plant condensate as a natural gas liquid (NGL). The beaker on the left below is plant condensate.


With the current explosion in unconventional shale development vastly increasing the quantity of condensate being produced, the domestic market has been overwhelmed. Traditionally field condensate was a preferred source of feedstock for petrochemical refineries. However with the decline in the 1970’s of the lighter grades of crude, domestic refiners switched to refining heavier grades of crude and now have less of a need for lighter feedstock without costly conversions of their facilities.

Plant condensate on the other hand was a preferred diluent for blending with heavier Canadian crudes to improve pipeline flow. With these traditional markets now oversupplied, pressure has been growing for the export of condensate to foreign petrochemical users. Unfortunately condensate historically had been considered crude oil and its export had been prohibited since the 1973 Arab oil embargo.

In June 2014 Pioneer Natural Resources and Enterprise Products Partners received approval from the Department of Commerce Bureau of Industry and Security to export a limited amount of Eagle Ford condensate which was ruled a “product” and therefore exportable, since it had been processed through a field stabilization unit. See the type of facility below.

Image Source:

Field units of his type are rapidly being installed throughout the condensate rich areas of the Eagle Ford highlighted in this map from DI Analytics.

EF_API_Grav_With_Scale_Bar (1)

Recently BHP Billiton announced their intention to export Eagle Ford condensate without the government’s explicit authorization. No doubt Anadarko, Conoco Phillips and other large Eagle Ford condensate producers cannot be far behind, score one for our balance of trade.

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