Sales abroad of crude oil, natural gas and petroleum products have reached more than 7 million barrels of oil equivalent per day (MMboe/d), representing a new industry for the U.S., according to Harold Hamm, who heads one of the nation’s largest independent oil and gas producers as chairman and CEO of Continental Resources Inc.

Crude oil exports alone may increase to 4 MMbbl/d by 2022, according to recent remarks by Enterprise Products Partners LP, as the world demands more light sweet crude. China has gone from taking just one cargo of under 1 MMbbl in the first eight months of 2016 to buying about 115,000 bbl/d from the U.S. so far this year, according to Reuters.

The problem is, the nation simply is not equipped to handle the potential outflow after a 40-year federal law that prohibited most crude sales abroad. The nation’s excellent midstream infrastructure was directed to bringing in and distributing oil supplies—not sending them out.

The shale revolution changed that. The U.S. has re-emerged as a major crude oil and natural gas trader on the world’s energy stage.

New infrastructure must go in place to transport and/or liquefy the gas and load tankers—many of which are so large they can’t enter U.S. ports—if the U.S. expects to reach its potential. Since Hamm has been a strong proponent of energy exports, the editors of Oil and Gas Investor and Midstream Business met with him at his Oklahoma City headquarters recently to discuss the potential and challenges he sees in fulfilling that promise.

Harold Hamm is closely watching how U.S. crude exports affect production and oil prices. And he questions the EIA’s forecasts related to that.

In addition, he explained why his team takes issue with the U.S. Energy Information Administration’s (EIA) data and projections, upon which so many securities analysts, and the industry itself, rely. He thinks the EIA’s errors are causing a lot of misperceptions about the global oil glut and charges that it’s caused by U.S. producers.

Investor: Why are crude exports so important to U.S. producers?

Hamm: We can’t control the market, so, through contractual arrangements or otherwise, oil and gas companies are quickly changing what they do and how they do it. We’ve brought in people to do that and we’re not the only ones. Thirty percent of U.S. oil production could be going to foreign countries soon. It would be “game over” if the U.S. couldn’t sell that oil, that’s the name of the game.

The current amount of exports is important; over 6 million barrels per day of crude and petroleum products are now being exported. This is new and additional business for the midstream and, as I’ve said, it’s a new industry for America. We said it would spawn a whole new industry and it has; a lot of new companies have sprung up. It’s a little bit hard on our infrastructure because this is going all around the world.

The first product shipments were going to South America, but there are a lot of shipments of crude and products now going all over. China is a big market: They have a lot of these small—I call them “teapot”—refineries, but some of them run 160,000 barrels per day, which is not that small. They were required to use domestic crude supply, but now they can deal directly with anybody and buy supply from anywhere—and they want to diversify their supply. The Chinese are coming here to talk.

They (China) need our light sweet crude. A lot of foreign refineries were built—and are operated—on the cheap. They are not complex and can’t run heavy and sour crudes. We’ve found there are a lot of refineries that want light shale oil; there’s a good market for it.

Enterprise Products (Partners LP) and my friend (Enterprise CEO) Jim Teague and other midstream operators have done very well with (crude oil) exports. One of the first shipments—in January 2016—was done by Enterprise.

Investor: You recently projected that U.S. LNG exports will roughly triple in the long term and take around 40% of domestic gas production. Given increasing LNG output by Australia and other suppliers, is there a sufficient worldwide market for such large volumes?

Hamm: There is. The short answer is there are a lot of LNG markets and not always where you expect. There is a lot of interest even in the Middle East, in Dubai, for example, in U.S.-produced LNG. The Mideast producers have drilled for gas, thinking there would be a lot produced, but really not much has been found. And what they found has been sour natural gas, so they haven’t had much success with it. It’s tremendously sour.

We’ve seen LNG exports rise to between 2.5- and 3 billion cubic feet (Bcf) per day and it could grow to 10 or 11 Bcf per day by 2019. We’re off to an awfully good start. There are 143 to 147 receiving points around the world and there will be more, so it’s a big market. It’s a lot easier to build receiving terminals than liquefaction plants. It is absolutely a good growth industry for us.

And can we compete with Australia and Qatar? Yes, I absolutely think we can. We have the infrastructure and we can be the low-cost producer.

Investor: What about Mexico? Will the U.S. continue to increase its exported gas volumes across the border in the foreseeable future?

Hamm: Mexico has been a very good market; let’s face it, natural gas is cheap and very accessible to them. People thought it would be about a 5-Bcf-per-day market, but it’s going way past that. Some people have forecasted that it will go higher. A lot of times, forecasts and predictions are wrong.

Investor: How have crude exports affected Continental?

Hamm: It, obviously, ultimately impacts us, but we leave the sales to the midstream players—to Koch (Industries Inc.), Enterprise Products and others. But it benefits us in a lot of ways: Instead of worrying about outlets for our crude, we’re working at capacity and we’re not going to be at the mercy of U.S. refiners—I never want to be in that position again. We’re not going to do that anymore.

The balance has shifted. We did have something of an adverse relationship with refiners before the export ban was lifted. Some of them actually fought to keep it, but the big refiners—like ExxonMobil,, Chevron and Phillips (66)—were supportive. Others want to keep domestic producers as their milk cow and we do not want to do that.

It’s important to remember that a large share of U.S. refining capacity—about 30%—is owned by foreign crude producers, who bought plants and modified them to run their specific crudes. They aren’t interested in U.S. crude production being exported.

Investor: Has the export market for U.S. crude grown as rapidly as you expected, following the lifting of the export ban at the end of 2015?

Hamm: It has. Lifting the ban had two effects. First, within 11 hours, the differential between West Texas Intermediate and Brent went to zero, but it (Brent) has gone back up. Two, the market has grown since then to about all the exports we can handle with the infrastructure that we have. We really need to be able to load those very large ships. A couple of things have helped. One was expansion of the Panama Canal. The other is the expansion of our ability to load tankers for export at our ports.

Investor: Have you heard from overseas crude customers that buy U.S. oil? What are their thoughts?

Hamm: We have had early contacts with some of them. We talk with South Korea all the time. They were buying oil from Iran and some other people they really didn’t want to deal with. They wanted to change that permanently and quickly. They want deals that are dependable; they’re following the lead of China.

Investor: Can the U.S. gain markets by proving itself a dependable source—in comparison with Venezuela and other politically unstable countries?

Hamm: I’ve said all along that the United States can be the producer of choice. We are dependable, and we have the banks, the rule of law and the courts; contracts matter, if there are questions. It’s quick and easy to do business with us. We knew we’d become the market of choice and we’re seeing that play out.

Investor: How does the midstream need to change to support swelling exports? Do you feel it is responding adequately?

Hamm: I believe the midstream is responding, but it will take a little while to get moving. Take a look at Corpus Christi, Texas. I read that there will be $30 billion invested to make that port ready to handle growing exports. Corpus is a very important port and it’s important to be there, yet Corpus can’t handle the really big ships—the VLCCs (very large crude carriers)—but that will change going forward. That’s a lot of money; we’re talking about what it would cost to build a large refinery. But this type of infrastructure is huge and it will have to be there—given the magnitude of this business.

Also, the LOOP (Louisiana Offshore Oil Port) is an example of infrastructure that needs to be changed. It can already handle incoming VLCCs that want to unload. (Editor’s note: The facility recently announced plans to make upgrades that will allow it to load, as well as unload, tankers starting in early 2018.)

Investor: What impact has the Dakota Access Pipeline (DAPL) had on Continental and other Bakken producers?

Hamm: Things have improved recently since DAPL has gone into service. You can’t blame the midstream if they couldn’t get it done—with all of the opposition.

Actually, it’s had a large impact on transportation costs as the differential for Bakken crude has gone down below $2.50 per barrel compared to WTI. It has taken Bakken oil off the tracks, which was very expensive. We needed the infrastructure and now we have it. We had to use rail for some time and that added as much as $12 per barrel in transportation costs.

Investor: What about your Oklahoma production? Where is it going and is any of it exported?

Hamm: We are so close to the Cushing, Okla., terminal that most of it goes there. Some of it goes to the CVR Refining (LP) plant at Wynnewood, Okla. It is not a complex refinery and the light, sweet crude we produce fits it well.

Investor: You recently said that, overall, domestic producers need crude prices at $50 or higher to be consistently profitable. Will exports help meet that goal?

Hamm: They will, but there’s quite a bit of variance. The impact of exports can be great. There may be a lot of supply now, but that’s not sustainable worldwide at lower prices. Producers are incapable of sustaining production without adequate capex and the EBITDA to support it and we have to have that to generate a return for our investors. There’s one inescapable fact: The lower the price is, the less revenue you have and the less capex you have, and then you can’t meet the world demand.

Investor: What kind of price does Continental need to break even in the Bakken and Oklahoma’s Scoop and Stack plays?

Hamm: Well, first, let’s talk about the Bakken. This is the best pure oil play in America. We needed the infrastructure and now we have it. We also needed the technology, such as multistage completions, and now we have that. For most of us in the core of the play, we need at least $40 per barrel to break even with some kind of decent margin. It’s good that Continental is the low-cost producer with lower lifting costs up there. We’ve had to drive out about $3.50 per barrel in costs to remain competitive.

For the Scoop and Stack, these are awfully good plays. We can make money below $50 per barrel—maybe less than $40—but that results in low capex. The existing infrastructure makes a lot of difference for sure. Prices below $50 are unsustainable.

Investor: You announced a joint venture with South Korea’s SK E&S Co. Ltd. in 2014 for some of your Cana Woodford acreage in the Midcontinent. Is your partner taking that gas as LNG? Do you expect the relationship to grow?

Hamm: They made a large investment in the play but SK has not taken any LNG up to this point—but they could. It has been a good business relationship for us.

Investor: You told the Financial Times that Continental is “an opportunistic entity: We’re not devoted only to oil.” Do you plan to increase your production of gas, relative to oil?

Hamm: We produce a lot of oil—about 60% of our production. In the second quarter, it was 56% and I expect it to be 60% or greater for the balance of this year, given about where we run right now on the oil cut. We produce a lot of gas when you look at Scoop and Stack wells that produce 1,000 to 1,500 barrels of oil equivalent per day.

PHANTOM U.S. DATA

Continental Resources Inc. chairman and CEO Harold Hamm has championed the vast oil potential of the Bakken Shale, the Scoop/Stack in Oklahoma, and the U.S. independent producer for many years. To that end, he’s also founder and chair of the Domestic Energy Producers Alliance (DEPA), a nationwide collaboration of 25 coalition associations whose companies and individual producer members make up about 67% of total U.S. output. It also speaks for 10 million royalty owners.

When the U.S. oil renaissance kicked into high gear, DEPA and Hamm fought for exports to be allowed. That success has led to the latest data—that the U.S. is exporting more than 1 million barrels per day (MMbbl/d). Now, DEPA and Hamm are fighting on a new front: They believe data provided by the Energy Information Administration (EIA) are distorting the market and affecting the price of West Texas Intermediate (WTI) by as much as 20% because of inflated production numbers.

Like most oilmen, Hamm keeps his finger on the pulse by digesting reports from the EIA; dozens of Wall Street analysts also cite it. The general consensus of the EIA—and, thus, of those analysts—is that there is a crude oil glut holding down WTI prices relative to the Brent benchmark, and that American shale producers are to blame.

But Hamm has called a time out. “Things aren’t adding up at the EIA,” he said in a September interview with Investor. “Everybody said, ‘There is no stopping U.S. producers,’ but most producers are living within cash flow.”

The domestic rig count and well completions started flattening out in the summer, after the oil price fell by $6/bbl from April to June, partly due to increased production from Libya and Nigeria that offset cuts by OPEC members and Russia. Projections from the EIA on 2017 exit rates didn’t move as a result.

Hamm and DEPA president Mike McDonald have been meeting with the EIA for five years. This July, they started researching the problem further because the EIA missed the U.S. production move on the way up during the shale surge, and, now, it is missing it once again on the way down. They analyzed the numbers on U.S. and OPEC production, U.S. exports, the effect of the U.S. dollar and more.

DEPA now projects muted U.S. output growth in the second half of 2017. When it downloaded production guidance from a number of E&Ps, it found that 13 companies cut capex in the second quarter, 25 had no change and only three raised their capex. Total U.S. production for this group declined 0.78% or by 139,500 boe/d in the second quarter.

“We [and DEPA] have had conversations with producers all over this nation—in West Texas, Louisiana, you name it. We saw production backing away and so this EIA data wasn’t adding up,” Hamm said.

“It’s real troublesome, because everybody hangs their hat on this government data. EIA’s phantom production forecast needs huge growth by the E&P companies to catch up to its faulty projections. When we looked at their projections and adjusted for actuals, we knew it was impossible for oil production to pick up that much.”

Market perceptions are indeed colored by EIA data, and that, in turn, affects decisions on crude price, hedging and capital allocation across the industry. Hamm said during the week of Sept. 18, more than 190 analysts mentioned data from EIA’s Short-Term Energy Outlook (the so-called STEO) report, released the prior week.

“EIA drives market perception, but they are so far off—they are slow and don’t understand the dynamics of this market,” Hamm said. A 400,000-bbl/d error in EIA numbers has led to a 20% correction in price, he said, so the market should be in for a large correction to the upside on oil price—by as much as 20%.

“There’s this growing realization that this oil is not there and we are not glutting the market. Producers have less to invest with since their cash flow is down, and most are investing within cash flow.”

Hamm and DEPA went to Washington to see the EIA and were given every courtesy in a cordial meeting. Hamm’s takeaway: “They are really short-handed and have an acting director. This is under [Energy Secretary] Rick Perry’s purview now and I think he’s a great leader, but the point is, they can do a lot better. They have such an impact, it affects all our companies.

“Our own team at Continental has to make budget and production forecasts, and we get within 3% correct, even on all our outside-operated properties,” Hamm said.

“We asked them ‘What are you using?’ They are getting their data from one source that very few in the industry use today. They need better tools and more people, if anybody in the industry is going to believe them going forward.”

DEPA’s McDonald said, “The point is, by the time the EIA revises its 914-form production data, it’s old and too late for us. Producers have already sold their oil by that time and sold it based on ‘false’ EIA data that affect the oil price.”

Hamm said this error has gone on for a long time, causing several problems. He believes analysts should do their own work and not rely so heavily on the EIA.

Web Extra

To hear Continental Resources Inc. senior vice president Blu Hulsey discuss the EIA’s U.S. production forecast and its effects on oil prices, visit this link.

Comments