SIPES Event with Arthur Berman
SIPES Next Generation Award
The Andy Peterson Perspective
New Board Member – Godswill Nwankwo
Renewables Biggest Problem, Scaling
Events Calendar
Shale Faces Both Financial & Operational Problems
The Investability of Unconventional Oil and Gas (part 1)
SIPES LinkedIn Page
Shale is Crippled for Life
POP QUIZ! – Professor Steve Walkinshaw
Green CA has the Nation’s Worst Grid
Saudi Refuses to Learn from 2 Failed Price Wars
LNG Outlook Improves
Book Recommendation

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Chapter Officers 2020

Chapter Chair
Mike Jones
(713) 398-3091

Chair Elect
Jeff Allen

Past Chair
Barry Rava
(281) 235-7507

Steve M Smith
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Luis Carvajal
(832) 360-3783

IT Chair
Godswill Nwankwo
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Technical Program Chair
Pete Marshall
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Public Relations Chair
Jeff Lund
(713) 275-1664

Membership Chair
Gene Kubelka
(713) 582-8569

Newsletter Chair
Jeff Allen

Deal Buyers List Chair
Bill Smith
(713) 650-3060

Ryan Price

Sponsor Coordinator
Mark Hazmat
(832) 540-3216

Continuing Education Chair

National Directors
Barry Rava
(713) 621-7282

Jeff Allen
(713) 302-5131

Office Manager
B. K. Buongiorno
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In this issue

Letter From The Editor – Jeff Allen

SIPES Event with Arthur Berman

SIPES Next Generation Award

The Andy Peterson Perspective

New Board Member, Godswill Nwankwo

Renewables Biggest Problem, Scaling

Events Calendar

Shale Faces Both Financial & Operational Problems

The Investability of Unconventional Oil and Gas (part 1)

SIPES LinkedIn Page

Shale is Crippled for Life

POP QUIZ! – Professor Steve Walkinshaw

Green CA has the Nation’s Worst Grid

Saudi Refuses to Learn from 2 Failed Price Wars

LNG Outlook Improves

Book Recommendation


Are you drilling a gas well right now? You should be. If you aren’t ahead of the pack getting ready for a strong gas market you are going to be behind everyone else. Hindsight is 2020. Don’t be that guy at the lunch saying “Oh, if only I had seen this coming…”. At the Deal Buyers Event last month we had some great conversation and opportunities within SIPES. You must become a member of SIPES to start attending special events that focus on investing in this industry.

Each month that goes by proves the point that Arthur Berman has been saying for a decade—Shale is not economic. A great article on page six proves my point, the only success EOG has had is in Trinidad with conventional exploration. You can listen to Mr. Berman on a zoom Fireside chat on September 17th. Details to be sent in an email or sign up on our website.

NAPE was a total disaster this year. In February of 2021 SIPES Houston will be hosting the annual in-person invite only Prospect Forum.

This is not easy. This industry will beat you down. This industry is not safe. Only the bold and stubborn can hack it. That is why if you are in this industry, you should be proud of yourself, strong, and confident. You are one of the few, congratulations.

Stay lean, stay hungry,

Jeff Allen

Jeff Allen


SEPTEMBER 17TH, 2020, 10:30 AM - ZOOM

“Oil and gas markets fascinate me. I am a working petroleum geologist.  I also have a degree in Middle Eastern history. That gives me a completely different perspective than other analysts. I love unraveling the complex factors that drive markets and prices. I look at everything but comparative inventory is the cornerstone of my approach. That’s a real difference from my peers. It’s also why I get oil and gas markets right more often than most. Work with me and I’ll help you make better investment decisions based on realistic price calls” – Arthur Berman

If you don’t know who Arthur Berman is, you need to. He will be joining SIPES Houston for a ZOOM fireside chat to discuss the industry issues, price, and where we go from here.

Mr. Berman has been a consistent and accurate voice for our industry for decades.


Each year SIPES Houston awards one person as the Next Generation Independent. This individual is under the age of 40, an independent deal buyer or seller, member of SIPES, and made big strides in the industry. Jeff Allen of Allen Energy won this year. Jeff, along with Mike Jones, raised money and shot a new 3D when oil was only $23/bbl. This fight embodies the true grit of independents. Aside from drilling successful conventional wells, Jeff also has been a long time supporter of SIPES serving on both the local and National board.


Andy Peterson hosts an exclusive group to share market perspectives. As a member of SIPES you too get to share in this information. SIPES is about REAL education to help you understand our markets, not only Oil and Gas. Read below for a short excerpt of what his paying members receive on a weekly basis. Andy Peterson is a 32 year old man that has amassed a fortune on being a contrarian investor.  This is from June 28th

Key Market Performance:
Equity markets declined 3% this week with the S&P closing at 3,009 on Friday afternoon, slightly above the important 3,000 price level. Recall that in late February the index hovered around this same level breaking through on a Friday and then gapping down the following Monday on its 3 week slide to 2,200. Year to date the S&P 500 is down 7% while the Nasdaq 100 is up 13%.

Debt: Ten year treasury yields were down 9% on the week to settle at 0.64%. Recall that in my last note ten year treasuries rates had appreciated 40% week over week to settle at 0.90%. We have significantly backtracked on that yield over the course of June. US National debt remains at $26.2 Trillion. I’d wager it continues to go up.

Oil declined 3% this week with the August contract closing Friday at $38.49/bbl. Crude and refined product inventories were relatively calm, however US oil production jumped 500 kbd from 10.5 MMbbl/d to 11.0 MMBbl/d. The behavior of US crude production will be a meaningful driver of oil prices because a popular bull thesis for the commodity is that US shale will decline more rapidly than the market appreciates, and there will be a shortfall of capital available to producers to replace those barrels. 

Weekly Commentary:

It’s Been Awhile: The last time I sent out a note was June 7th and June 8th appears to have marked the top in the S&P 500 for the current month sliding from a peak of 3,232 to just over 3,000 as of a few days ago. One of the items I suggested was that near term earnings results would be given a pass due to the “temporary” nature of covid shutdowns. With Nike reporting a loss of 51c and sliding 7% on Friday this thesis could be off. This is slightly more troubling than other retailers, given that Nike has built a tremendous online presence so their reliance on brick & mortar sales isn’t as significant as other brands. A company to watch is FedEx which reports earnings on Tuesday and should give us some insight into online shopping activity during the shutdowns. 

Another troubling trend is delinquency rates in both residential and commercial real estate. A survey from Apartment List taken in early June showed that 30% of participants made no payment or a partial payment on their rent or mortgage. Now do I give a significant amount of weight to a 4,000 participant survey from Apartment List, no, not really, but I do find it interesting that CMBS 30+ day delinquency rates have tripled for the month of May per research firm Trepp. Housing is a high priority expense for everyone, so not being able to make these payments is even more troubling for parts of the economy that are more discretionary; clothing, airline flights, hotels, restaurants. If you can’t make rent, you’re certainly not going out to eat or take a vacation.
So if things aren’t going well in retail sales (Nike) and large numbers of the population are having trouble making housing payments, then it’s important to ask why have equity prices risen 36% in the last 90 days? Outside of a one off positive job report that was admittedly overstated by the bureau of labor statistics, there hasn’t been a lot of good economic news. What has occurred is the federal reserve has expanded their balance sheet to unprecedented levels and the US treasury has borrowed more money in the last 90 days than any time in history. Debt expansion and money supply expansion are at a breakneck pace and this bazooka of money has translated into higher equity prices. Unfortunately raising capital isn’t enough, that money has to translate into actual production, met with actual demand from a population who has money and the confidence to spend it. I’m struggling to see in the near term where that comes from.


As an engineer, computer scientist, MBA, oilfield veteran, finance manager and deal partner, I work with my team at Prospero Oil and Gas and our affiliates to implement proprietary deal flows and value growth strategies that ensures portfolio companies out-performs their industry comparables while delivering superior returns to investors. These often include:

+ contract (turnkey) drilling which minimizes the risks and uncertainties of time and cost as wells can be planned, drilled, evaluated and completed to our clients’ specifications for a single lump sum price
+ operational, financial and management advisory services with integrated reservoir asset development and management, reservoir economics and valuation (fairness opinion) while driving accretion synergies in mergers, acquisitions and divestitures event
+ implementing robust financial strategies that drive portfolio alpha, smart beta, hedging against exposures etc 

I have more than two (2) decades of international and multi-cultural oil and gas experience working for Schlumberger, Halliburton and Baker Hughes. I have executed oilfield projects overseas and all over the United States – New York, Pennsylvania, Kentucky, Indiana, North Dakota, Montana, Colorado, Wyoming, California, Oklahoma Louisiana, Mississippi, Texas and the Gulf of Mexico.

I possess a Bachelor’s degree in Mechanical Engineering with specialization in Computational Fluid Dynamics (CFD) and a Master of Science (MSc) degree in Computer Science with specialization in Cognitive Artificial Intelligence. I also have a Master’s in Business Administration (MBA) in Finance with specialization in Private Equity and Energy Investments.

I serve in various roles with several non-profits and board positions including Co-Chair and Board for University of Houston CT Bauer College Alumni Association.


Energy Tribune, Robert Bryce

It’s summer. It’s hot. And once again, we are hearing from the usual suspects that we must change our entire way of living. Repent, they say. Carbon dioxide emissions are killing Mother Earth. Give up hydrocarbons and embrace renewable energy.

Doing so, we’re assured, will result in a gentler climate and myriad other benefits, including scads of “green” jobs. Sounds easy, no?

Alas, no matter how much they may wish it to be so, the proponents of alternatives — and better yet, “clean” energy — cannot overcome the problem of scale. A simple bit of math shows that even with the rapid expansion that solar and wind-energy capacity have had in the past few years, those two sources cannot even meet incremental global demand for electricity, much less make a dent in the world’s insatiable thirst for coal, oil, and natural gas. Indeed, had any of the myriad advocates for renewable energy bothered to use a simple calculator, they would see that their favored sources simply cannot provide the vast scale of energy needed by the world’s 7 billion inhabitants, at a price that can be afforded.

Consider this: between 1985 and 2011, global electricity generation increased by about450 terawatt-hours per year. That’s the equivalent of adding about one Brazil (which used 485 terawatt-hours of electricity in 2010) to the electricity sector every year. And the International Energy Agency expects global electricity use to continue growing by about one Brazil per year through 2035.

How much solar would be needed to produce 450 terawatt-hours per year? Well, Germany has more installed solar-energy capacity that any other country, with some25,000 megawatts of installed photovoltaic panels. In 2011, those panels produced 18 terawatt-hours of electricity. Thus, just to keep pace with the growth in global electricity demand, the world would have to install about 25 times as much photovoltaic capacity as Germany’s total installed base, and it would have to do so every year.

Let me repeat that: just to meet the world’s increasing demand for electricity — while not displacing any existing electricity-production facilities — the world would have to install about 25 times as much photovoltaic capacity as what now exists in Germany. And it would have to achieve that daunting task every year.

The scale problem is equally obvious when it comes to wind. In fact, wind-energy’s scale problems are even more thorny because wind energy requires so much land.

At the end of 2011, the U.S. had 47,000 megawatts of installed wind-energy capacity. (Only China, with 62,000 megawatts, had more capacity.) In 2011, all of the wind turbines in the U.S. produced about 120 terawatt-hours of electricity. Thus, just to keep pace with the growth in global electricity demand by using wind energy, we would have to install about 3.75 times the current installed wind capacity in the U.S. every year. That means that global wind-energy capacity would have to increase by about 176,000 megawatts each and every year.

That would be an enormous challenge given that between 2010 and 2011, global wind-energy capacity increased by just 41,000 megawatts. That’s a record increase, and one that advocates of renewable energy are quick to laud. But those same advocates refuse to acknowledge the energy sprawl inherent in wind energy nor will they admit the growing backlash against the wind industry. Read the full article on the link


Shale Faces Both Financial & Operational Problems

The Fuse, Nick Cunningham

Crude oil prices have firmed up, setting new four-month highs in the past two weeks. Brent has climbed to $45 per barrel and WTI above $42, although both benchmarks remain range-bound. The oil market is close to rebalancing, at least in terms of supply and demand flows, and one big factor has been the steep decline in U.S. shale production. Below $50 per barrel, very few unconventional producers are making money. But the maturing industry is also facing some drilling challenges that could prevent a substantial rebound in production.

A June report from Deloitte declared that the U.S. shale boom “peaked without making money for the industry in aggregate.” The firm estimated that the industry collectively posted $300 billion in net negative cash flow over the past decade and a half.

Through the losses, the industry produced extraordinary amounts of oil and gas. But the pandemic-induced market collapse finally killed off the boom. Many market watchers have speculated when and if drilling would return. The recent stabilization of oil prices seemingly offers a new opportunity to drill. In a prior era, drillers would recapitalize and get back to work. However, there is no sign that this is occurring. The rig count continues to decline, with the Permian accounting for the most recent week’s losses.

Meanwhile, the U.S. shale industry has a raft of other problems. While the financial trouble is increasingly well-known, particularly with oil prices stuck below $50 per barrel, drillers face numerous obstacles in the field as well. A recent report from investment bank Raymond James looks at the increasing likelihood that drillers have largely maxed out their productivity gains. In fact, the bank warned a year ago that drillers were approaching their productivity limits; recent data suggest that this trend is bearing out.

For years, shale drillers squeezed more oil and gas out of wells by drilling longer laterals, using more proppant and water, packing wells closer together, and drilling more wells per well pad. This is the “bigger hammer” approach, as Raymond James calls it. Last year, for example, companies increased production on average by increasing the lateral length of their wells. But on a per-foot basis, productivity only increased by 2 percent in 2019, according to Raymond James. That is down a 4 percent increase in 2018 and a 12 percent increase in 2017. In the Permian, productivity increased by less than 1 percent, while productivity actually decreased in the Eagle Ford.

All of these trends point to a broader problem – the ever-increasing intensification of drilling has reached its logical limit. “The quest to maximize IP30s was futile as the overstimulated reservoir resulted in not only expedited pressure depletion/sink in the target wellbore, but also increased wellbore interference/fracture migration issues in subsequent adjacent wells,” Raymond James said. “To put it simply, an overaggressive completion lowered the longer-term productivity of the current well along with future child wells.”

Speaking of his company’s spending cuts in the Permian, Chevron CFO Pierre Breber told analysts: “The capital will come back when the world needs energy.”

The Investability of Unconventional Oil & Gas (part 1)

Allen Gilmer, Forbes

ShaleCo. The word has become an epithet. To be called a ShaleCo is to be called a fraud, a destroyer of Other People’s Money. It is bandied about with more emotion than seemingly any other term in that dark, murky and largely anonymous world of social media. If a publicly traded oil company committed the mortal sin of taking on debt to the extent it would be problematic paying off should commodity prices fall 50% or more, and stay there, AND if their assets were comprised principally of unconventional reservoirs, the primary asset that actually created investment “gravity” at an increasingly manic pace from roughly 2007 to late 2014, then it has been tainted with Original Sin. Of course, some companies made it particularly easy for the haters to hate… executive salaries, perks, and bonus packages that belied the very idea of effective corporate governance.

Why are these companies SO gut shot? The myriad of issues that contribute are 1) the resource base itself and its impact on global market price,  2) no clear guidance from investors (or ShaleCos) as to what metrics constitute “success”, 3) short or medium term viability of hydrocarbons in competition with “green” alternatives, 4) fundamental well economics, 5) larger pad economics, 6) reserves in all of their forms, 7) confidence or lack thereof in reserve audits, 8) corporate governance, and 9) the unhealthy politicization of energy.

The purpose of this series of articles is to examine each of these to determine if unconventional reservoirs are fundamentally uneconomic and to be avoided at all costs or if there are emerging opportunities to successfully invest in this type of resource.

Hydrocarbons are the fuel that undergirds roughly 60% of the planet’s energy as well as providing myriad other incidental uses.  The strategic security consequences of depending upon either Saudi Arabian or Russian oil and gas, the two other “swing” exporters, is written hugely in 20th Century history. But investors don’t care about strategic security, they care about returns. Strategic security is invoked only to secure political support for downside risk abatement to those investment dollars. 

The unconventional boom identified and largely unlocked a vast accessible resource base, primarily in North America.  Turning resource into reserves has always been a bit tricky. The USGS assessment of oil and gas reserves, historically one of the most conservative assessors of future reserves (for instance, the United States has historically produced it’s “known reserve base” every ten to 12 years, and has been “running out oil” since WWI),

Using FCF to reinvest and grow a company makes sense, IF there is a decent return of that invested cash. A demand that the FCF be dividended back doesn’t make sense if the money can be reinvested profitably. Clearly, companies MUST have a transparent method to show that they can both achieve FCF AND reinvest that FCF profitably.

A valuation based solely on free cash flow dividended out is the domain of those who’ve given up. Companies that dividend every bit of cash flow aren’t growing and can’t reinvest; it’s a signal they have no place to put their money. Rather, FCF should be viewed as a tool that expands value… more money to invest in low risk profitable growth using methods that the companies are proficient providing



Seeking Alpha

US shale isn’t dead. And in the realm of analyzing US shale oil production growth, the analyst community falls into two extreme categories. A group led by Rystad Energy estimating that US shale could reach ~16.2 million b/d by the end of 2030 at $65/bbl WTI and another group that thinks US shale is going to structurally decline sub ~9 mb/d by 2021. The truth is somewhere in between. US shale isn’t dead and the EIA 914 report for July (released at the end of Sept) and August (released at the end of Oct) will prove this.

The reason is that July US oil production rebounded back to ~11.3 mb/d following a near-complete return of shut-in production. August saw a similar recovery, but the monthly average will be impacted by the storm shut-ins.

After August, however, the rebound is over. US oil production is expected to keep rolling over with no sign of a rebound until the second half of 2021 if oil prices are well above $50/bbl WTI by then. As you can see in the chart above, EIA has US oil production flattening around ~11 mb/d for the rest of 2020 and the first half of 2021. But our data suggests EIA is vastly underestimating the current recovery but also the subsequent decline rates.

At $40/bbl WTI, US shale oil production will fall below ~10 mb/d by second half 2021. There’s no improvement in well productivity that’s going to reverse that. The only way for US shale to reverse the incoming decline is if oil prices shoot up. Even at ~$70/bbl WTI, we estimate that given the new capex guidance policies of targeting ~50% to ~70% of OCF to capex, US shale oil production will grow at a measly ~35k b/d to ~75k b/d per month (growth rate is based off the average targeting of capex to OCF).

As a result, the glory days of US shale of growing at ~200k b/d are long gone.

The significance of this could be tied back to the era of cheap capital between 2010-2016. The Fed’s policy of quantitative easing and the investor’s appetite to chase yield led US shale to borrow extremely cheaply to finance drilling. Cash flow outspend was enormous, to say the least, and if capex was kept in-line with cash flow, US oil production would have been flat.

This fundamental change in how credit is going to be provided to US shale will be a night and day difference in how US shale grows in the future. And given credit availability is extremely tight and only available to the fortunate large producers, the growth engine that propelled the US to become the largest oil producer is no longer there.

US shale isn’t dead but it’s crippled for life. The key source of funding for most E&Ps, the reserve-based lending facility, is all but extinct by the end of 2021. Without this source of cheap capital from the banks, energy producers will be forced to spend within cash flow. Larger producers like Pioneer already have guided to new capex policies of spending only ~50% to ~70% of OCF on capex. This material change in capex spending will dramatically alter the future of the US oil production trajectory.

As a result, people are seriously underestimating just how significant the recent decline in US oil production really is. While we would say that US shale is far from dead, it’s truly crippled this time around.

POP QUIZ! - Professor Steve Walkinshaw

The images highlight one of the five largest gas fields in this country, with recoverable reserves approaching 40 TCF.

This field is noteworthy in that this ~40 TCF resource is trapped within a productive area that is less than 85 square miles in aerial extent.

Virtually all of the stacked reservoirs in the principal producing interval have low (<10%) porosity and micro-darcy permeability. It wasn’t until an operator employed modern multi-stage fracture stimulation at a nearby (also large) gas field that the commerciality of these tight reservoirs became apparent. Today, this field produces ~1.5 BCF/day from over 2,200 wells.


Part 1: What country am I referring to?
Part 2: What is the name of the field?
Part 3: What is the name of the adjoining field, where fracture stimulation of such reservoirs was first applied?
Part 4: What company drilled and abandoned the first well on this structure after deeming its reservoirs non-commercial?
Part 5: What basin is this field located in?
Part 6: What is the name of the principal producing reservoir?


Part 7: What is the name of the Cenomanian unit annotated on the 2D line image?
Part 8: What is the age of the youngest producing formation in this field?
Part 9: What’s the smallest unit spacing?

Green CA has the Nation’s Worst Grid

Washington Examiner. Steve Goreham

More than a million Californians suffered power blackouts last Friday evening. When high temperatures caused customer demand to exceed the power available, California electrical utilities used rotating outages to force a reduction in demand. The California grid is the worst in the nation, with green energy policies pursued by the state likely furthering reduced grid reliability.

At 6:30 p.m. on Friday, Pacific Gas and Electric, California’s biggest utility, began shutting off power in rolling outages to force a reduction in demand. Southern California Edison also denied power to homes, beginning just before 7 p.m. Shutoffs impacted a rotating group of up to 2 million customers until 11 p.m. The California Independent System Operator declared a Stage Three Electrical Emergency, the first such emergency since 2001. Spot electricity prices soared to more than $1,000 per megawatt-hour, more than 10 times the usual price.

In 2018, 19% of California’s electricity came from rooftop and utility-scale solar installations, the highest percentage in the nation. But by 6:30 p.m. each day, that solar output approaches zero. The state lacks enough reliable electricity generation capacity to run everyone’s air conditioner during hot summer evenings. California has the least reliable electrical power system in the United States. It isn’t even close. According to data by Eaton Corporation, the Golden State leads the U.S. in power outages every year, with more than twice as many as any other state over the last decade.

The causes of power outages can be divided into four major groups. In order of importance, these are weather or downed trees, faulty equipment or human errors, unknowns, and vehicle accidents. California suffered the largest number of outages in each category in each year for 2014 through 2017. The problem of California’s poor electric reliability will likely get worse. On Sept. 10, 2018, then-Gov. Jerry Brown signed Senate Bill 100, committing California to obtain 100% of its electricity from “clean energy sources” by 2045. Replacement of coal, nuclear, and natural gas generators with wind and solar will continue to erode grid reliability. As part of global warming efforts, officials want all citizens to switch their natural gas stoves and furnaces to electric models. More than 30 California cities have enacted bans on gas appliances, including the major cities of San Francisco and San Jose. Almost 10% of the state population now lives in an area covered by restrictions against gas appliances in new residential construction.

California also wants residents to transition from gasoline- and diesel-powered cars and trucks to plug-in electric models. So, when those blackouts occur in the future, not only will your lights and air conditioners fail, but you won’t be able to cook your food or drive your car either. California sacrificed reliable electrical power on the altar of the fight against global warming. There is no evidence that state efforts will have the slightest effect on global temperatures, but they will be great for candle and flashlight sales.


These are three SIPES Houston members that have had discoveries in the last few months. To be a member of SIPES means you get to see their prospects first and learn from them. We all want to surround ourselves with other like-minded people. No better place than SIPES.

Barry Rava

Ray Blackhall

Bill Smith


Mike Jones and Jeff Allen are about to spud a well starting their goals of taking advantage of the coming strong gas market. Ryan Price of POCO, LLC is the operator.

Mike Jones
Charger Exploration

Ryan Price

Jeff Allen
Allen Energy, LLC

Club Guidelines and Reservations

RESERVATIONS OPEN for the Bayou Bengal Bar Today at 1:00 PM 

OPENING TUESDAY, JUNE 16TH- Bayou Bengal Bar Evening Service
Tuesday – Thursday evenings
Two Time Slots Available
Time Slot #1 – 4:00 pm -7:00 pm 
Time Slot #2 – 7:30 pm -12:00 am

Reservations REQUIRED (Based upon the Governor’s occupancy restrictions, walk-ins will not be allowed, reservations will be required.)

In order to accommodate as many members as possible we are asking you to follow the Bayou Bengal Bar reservation guidelines accordingly.

  • Onereservation per member, per day, per time slot. 
  • If you plan to dine with other members, please list your guests/members name in the dedicated area online. This way you can all sit together, split checks and not over crowd the reservation bookings.
  • No more than 6 ppl per Table
  • Kindly respect the booking time frame that you reserve. 
  • Social Distancing Tables Required (6ft between tables)
  • No Seating and/or standing at the Bar will be Available
  • Limited A La Carte Dinner/Bar Bites Menu Available
  • NEW Cocktail Menu!!!!

Thank you in advance for understanding.

Don’t Forget – we are also open for lunch!

Noble Energy Grill
Monday – Friday
11:30 am – 2:00 pm
Reservations Required
Social Distancing Tables Required (6ft between tables)
A La Carte Menus Available (no buffet at this time)

Bayou Bengal Bar
Monday – Friday
11:30 am – 2:00 pm
Reservations Required
Social Distancing Tables Required (6ft between tables)
A La Carte Menus Available (no buffet at this time)
Maximum Capacity of 25 ppl
No more than 6 ppl per Table

What to Expect When Arriving!


Valet services will not be available at this time; however limited self parking is available at hourly and daily rates.  The surface lot entrance is the same entrance as the valet entrance, please see the parking map located on our website, under Directions to the Club.


Masks in the Club are not required for members, but for your safety, we encourage you to wear a face covering from your vehicle to the Club level.

Saudi Refuses to Learn from 2 Failed Price Wars

Having failed to achieve the slightest semblance of success in the two oil price wars that it started – the first running from 2014 to 2016, and the second running from the beginning of March to effectively the end of April this year – it might be assumed that key lessons might have been learned by the Saudis on the perils of engaging in such wars again. Judging from various statements last week, though, Saudi Arabia has learned nothing and may well launch exactly the same type of oil price war in exactly the same way as it has done twice before, inevitably losing again with exactly the same catastrophic effects on it and its fellow OPEC members. At the very heart of Saudi Arabia’s problem is the collective self-delusion of those at the top of its government regarding the Kingdom’s key figures relating to its oil industry that underpins the entire regime. These delusions are apparently not discouraged by any of the senior foreign advisers who make enormous fees and trading profits for their banks from Saudi Arabia’s various follies, most notably oil price wars. It is, in the truest sense of the phrase, a perfect example of ‘The Emperor’s New Clothes’, although in this case, it does not just pertain to Crown Prince Mohammed bin Salman (MbS) but to all of the senior figures connected to Saudi Arabia’s oil sector. One of the most obvious examples of this is the chief executive officer of Saudi Arabia’s flagship hydrocarbons company, Saudi Aramco (Aramco), Amin Nasser, who said last week – bewilderingly for those who know even a modicum about the global oil markets – that Aramco is to go ahead with plans to increase its maximum sustained capacity (MSC) to 13 million barrels per day (bpd) from 12.1 million bpd.

Quite aside from the sheer pointlessness of this posturing in a world already awash in oil as a result of the negative demand effect of the COVID-19 pandemic and the output overhang from the oil price war just ended, this comment from Saudi Arabia’s third-ranking oil man (after MbS, albeit by the loosest possible definition, and Energy Minister, Abdulaziz bin Salman al Saud), is extremely misleading. As such, it feeds into the oil market’s collective understanding since the 2014-2016 oil price war that anything that Saudi Arabia says about its oil industry is not to be taken as true, without a lot of additional fact-checking. Regarding the ‘maximum sustained capacity’ statement, to begin with, this term is one that has been repeatedly used by Saudi Arabia since the first oil price war disaster to cover for two other long-running delusions relating to the real level of its crude oil reserves and to the real level of its spare capacity.

Before the 2014-2016 oil price war, Saudi had stated for decades that it had a spare capacity of between 2.0-2.5 million bpd. This implied – given the widely-accepted (but also wrong) belief that Saudi Arabia had pumped an average of around 10 million bpd for many years (it actually pumped an average of just over 8.162 million bpd from 1973 until 2020) – that it had the ability to ramp up its production to about 12.5 million bpd when required. However, even as the 2014-2016 oil price war dragged on and wreaked new heights of economic devastation on Saudi Arabia and its OPEC colleagues, the Kingdom could produce on average no more than just about 10 million bpd. Crucially here, the Energy Information Administration (EIA) defines spare capacity specifically as production that can be brought online within 30 days and sustained for at least 90 days, whilst even Saudi Arabia has said that it would need at least 90 days to move rigs to drill new wells and raise production by an additional 2.0-2.5 million bpd.

Instead, from that point onwards, Saudi Arabia began to attempt to obfuscate this spare capacity lie by semantic trickery. Senior Saudis spoke of ‘capacity’ and of ‘supply to the market’ rather than of ‘output’ or ‘production’ and these two groups of terminology mean very different things. ‘Capacity’ (or its synonym, as far as the Saudis are concerned, ‘supply to the market’) relate to the utilization of crude oil supplies held in storage at any given time in the Kingdom plus the supplies that can be withheld from contracts and re-directed into those stored supplies. It can also mean oil clandestinely bought in from other suppliers (notably Iraq in the last oil price war) through brokers in the spot market and then passed off as its own oil supplies (or ‘capacity’). ‘

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LNG Outlook Improves

Global LNG exporters have faced significant, though transient, headwinds going back to the end of last year, as a warm winter, demand weakness as a result of COVID-19 lockdowns, and mounting inventories in Europe and Asia have contributed to weak prices (read more). According to the US Energy Information Administration (EIA), daily natural gas deliveries to US facilities fell by about 60% from a high of 9.8 billion cubic feet per day (Bcf/d) in late March to less than 4.0 Bcf/d in mid-June. Similarly, daily US LNG exports dropped from a record high of 8.0 Bcf/d in January 2020 to an estimated average of 3.1 Bcf/d in July. These volume reductions reflected cargo cancellations for US LNG exporters, with some customers opting to pay fees instead of taking delivery.

Recently, however, prices have been boosted by recovering demand with coronavirus lockdowns slowly easing, US LNG cargo cancellations helping to tighten the supply-demand balance, and warm summer weather in the US and Europe supporting energy demand. In late May, global price benchmarks hit historic lows in Europe, as represented by the UK National Balancing Point (NBP) and Dutch Title Transfer Facility (TTF) benchmarks, and in Asia, as represented by the Japan Korea Marker (JKM), as shown in the chart below. After bottoming at $2.00 per million British thermal unit (MMBtu) on May 27, the JKM price has more than doubled to $4.11/MMBtu through August 26. Prices have recovered considerably in Europe as well. The UK NBP price was $3.32/MMBtu as of August 26, more than triple its low from May 28, while the Dutch TTF price increased from $1.14 to $3.17/MMBtu. Though prices in Europe and Asia are now above pre-COVID levels and just below levels seen in August 2019, they remain low relative to history. As we approach winter, there is potential for continued seasonal price improvement that could benefit LNG exporters as reflected in forward prices below. Cheniere Energy (NYSEMKT:LNG) Chief Commercial Officer Anatol Feygin recently commented that in the short term, the continuing recovery in demand in Asia is expected to help drive regional price spreads that are supportive of US exports, with growth over the longer term likely driven by China.

Recent price improvements and the modest widening in differentials between US and foreign LNG prices are welcome developments for US exporters, who have seen customers opt to cancel dozens of cargoes over recent months due to uneconomic conditions. For cargoes scheduled for loading from June through August, 141 US cargoes are estimated to have been canceled (see chart below). Notably, however, cargo cancellations are expected to be much lower at an estimated 26 cargoes for September and only 10 for October as demand has begun to recover. Cheniere Chief Financial Officer Zach Davis said the company expected continued improvement in market conditions and did not expect cancellations of contracted volumes this winter, further supporting the idea that the worst of the cargo cancellations are over.

LNG market conditions have been challenging for much of 2020, but improving prices and fewer cargo cancellations are signs that the worst is likely behind US exporters. The medium and long-term thesis for LNG remains intact given the expectations for growth in Asia, with the competitive landscape potentially becoming more enticing for some exporters given several liquefaction projects have been delayed or canceled this year. While some challenges remain for US LNG exporters, temporary headwinds seem to be subsiding.


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