News Flow

Oil sands to advance on long, winding road

Production of crude from Canadian oil sands will rise by 1 million barrels per day (MMbbl/d) between now and 2025 despite a likely halt in construction of new projects, analytical firm IHS said in a new report.

IHS expects projects begun before oil prices started to collapse in late 2014 to be complete by 2018, with new construction discouraged by market volatility. Growth will be driven until 2020 by the ramp-up of the new facilities.

“We expect oil sands producers to focus future investments in the coming years onto their most economic projects—which we expect to be expansions of existing facilities,” said Kevin Birn, a Calgary-based IHS director who specializes in oil sands. “Expansions of existing facilities are better understood, quicker to first oil and lower cost to construct. It is less risk at a lower cost.”

Lowest-cost oil sands projects can break even at US$50/bbl, IHS estimated in late 2015, but while the price of West Texas Intermediate has flirted with $50 recently, “the pace of future recovery is likely to be more moderate than the preceding six months,” Birn wrote in a blog.

Doubts about future pipeline takeaway capacity add uncertainty to price forecasting in western Canada. The permit denial by the U.S. State Department of TransCanada Corp.’s Keystone XL Pipeline, and substantive delays on that company’s Energy East Pipeline and Kinder Morgan Inc.’s Trans Mountain Pipeline expansion, could slow the crude oil price recovery.

What plays into oil sands producers’ favor is the near-absence of production declines, a unique characteristic. By comparison, a continuous infusion of investment is required in most conventional and unconventional plays just to keep production flat.

“In the oil sands,” Birn wrote, “the absence of production declines means that each investment in new oil production results in growth.” —Joseph Markman

Sabine case ruling ‘not meant to be precedent’

Legal and financial experts agree that the possibility of producer defaults or court invalidations of contracts are a concern for all midstream operators, especially as hydrocarbon prices are expected to stay lower, longer. But they add that the serious peril is probably limited to a few regional gathering and processing firms.

“There is much concern in the midstream sector,” Kraig Grahmann, an associate for the energy practice group at law firm Haynes & Boone’s Houston office, told Hart Energy.

“Previously, they were under the assumption that their covenants ran with the land, so the judge’s ruling in the bankruptcy of Sabine Oil & Gas threw them for a loop. Now they are trying to renegotiate their contracts so that they will be less likely to be rejected by a court. Also, they are trying to redesignate the contracts in terms of real property,” he said.

Those efforts are taking several forms, according to Grahmann. “In some cases, producing companies are reducing their committed volumes, so midstream companies are seeking shortfall payments,” he said. It used to be take-or-pay was the common terminology; now that is shifting to ship-orpay. “Midstream operators are also asking for higher transportation fees.”

Some midstream companies are asking for mortgages on assets or assignment of the leases to the extent that they grant gathering interests. “That creates other problems,” Grahmann explained. “In most cases, the producing firms have bonds or lending agreements that prohibit such pledges. They are usually limited to liens in the ordinary course of business. Also, bank mortgages may disallow conveyance.”

Kenric Kattner, partner at Haynes & Boone, noted that this is still early days, and there are both mitigating and militating indications.

“It is important to note that the judge in the Sabine case made a very narrow ruling. In every case, the matter is very particular to the language of the contract and the applicable state law. Still, the upstream guys in general seem pretty confident that they can get most of the midstream contracts thrown out in court,” Kattner said.

That has knock-on effects beyond the immediate threat to midstream profitability. Bidders for upstream assets don’t want to alienate the gathering operator that will have to get their molecules to market once all is settled. Also, midstream shareholders, lenders and private equity investors are now not so certain of the revenue streams, which their decisions have been based upon. As one attorney asked rhetorically, “how can you underwrite or finance a midstream project now that you know the shipper contracts won’t survive bankruptcy?”

Financial analysts are a bit more sanguine. “The problem at this point is that there is very little case law on how to address these issues,” Andrew Brooks, vice president and senior analyst at Moody’s, told Hart Energy. “For the most part, gathering and processing contracts are executionary that can be affirmed or rejected in bankruptcy. That is an established fact. Carriers can try to redefine their contracts as running with the land, but that then detracts from the estate.”

Brooks added, “The Sabine ruling got a lot of attention, but it was not meant to be precedent.” Taking a step back, he observed that “there are a lot of contracts out there that are out of the money. The carriers that are most vulnerable are the ones with gathering systems dedicated to one producer or limited to one basin. That has been the case with Sabine and Southcross, among others. In those cases even acreage dedications are not much help.”

In terms of credit ratings and overall financial health, Brooks reiterated that the serious risk is likely limited to midstream companies with particular vulnerabilities to one region or producer. But even in those cases there is usually plenty of room for negotiation before and even during court proceedings.

“It is no secret that outside of bankruptcy there is a lot of horse trading between producers and midstream companies. Those are generally neutral to net present value. Both sides have leverage. It is a case of mutual assured destruction being a powerful deterrent. Producers can decide not to drill, and gatherers can decide not to connect. So usually they find a way to blend and extend, as the expression goes,” Brooks said. —Gregory DL Morris

Changes loom for LNG market

The LNG market is set to continue to grow substantially as new export terminals are scheduled to come online in the coming years to match considerable natural gas production growth in the U.S. and Australia.

LNG traded globally has quadrupled in the past two decades and is expected to double in the next two decades,according to a recent Deloitte Center for Energy Solutions report, titled “LNG at the crossroads: Identifying key drivers and questions for an industry in flux.” In fact, growth could cause the market to reach critical mass and cause widespread changes in the LNG market.

The report observed seven key factors in helping the market reach its full potential:

--Global economic growth—the LNG market is highly dependent on expansions in Europe and Southeast Asia. Any slowdown in those economies would have major impacts on the sector;

--Energy efficiency—Deloitte also noted the amount of LNG in demand could be impacted as energy efficiency technologies improve;

--Excess capacity—there are also concerns that the market could be oversaturated by the amount of projects coming online out of the U.S. and Australia with as few as one in 20 of announced projects being needed to meet demand through 2035;

--Shipping costs—the widening of the Panama Canal and shortening trading distances may result in lower costs and improved gas price differentials;

--New end users—LNG has typically been used as a power generation fuel, but as its use as a transportation fuel increases, demand will rise, and;

• Market liquidity—the number of changes sweeping the sector has seen several countries building both import and export terminals, which may result in further changes to the industry, including a shift from a contract-dependent market to one focused on flexible spot markets.

These factors will help determine the direction of the global LNG market in the next 20 years, but despite several headwinds, Deloitte predicted that supply growth will continue over the next five years at an average of just under 8% each year to 2020. More supply could come into the market in the years between 2020 and 2035 from Iran, Canada and East Africa.

Demand growth is also expected at a rate that will see supply and demand largely balanced over the next 10 to 20 years. However, Deloitte warned that these forecasts are heavily reliant on strong economic growth in Asia and Europe, and demand could lag.

“While expectations of power generation growth in the developed and developing world differ, natural gas consumption growth will hinge on increasing underlying economic growth. The International Monetary Fund downgraded its 2015 global GDP growth outlook to 3.3% in July, a 0.2% reduction from its January outlook. While growth is expected to accelerate in the near term, downward revisions, notably in several of the BRICs (Brazil, Russia, India, China and South Africa) countries, increase the risk of underperformance. With that said, the strong forecast LNG demand growth may need to be tempered, extending the current glut into the next decade,” the report said.

Even with some murkiness in the nearterm and short-term outlook, Deloitte stated that the long-term prospects for LNG are sound, with growing supply and demand along with reduced costs for both supplies and technology.

The biggest uncertainty is how the market will shift with the possibility of an increased focus on liquefaction and transport at a fixed fee, with returns similar to those found in the utility sector, or a more robust and liquid spot market created by increased supplies and flexible transport options.

“The long-term growth of the LNG industry will be dependent on deepening existing relationships with existing customers and expanding into new sectors, as well as finding more efficient ways to deliver products to wider markets at lower costs, all while attempting to keep supply and demand level,” the report said. —Frank Nieto

Think of oil as ‘the new corn’

Three prominent economists, armed with reams of data and decades of observations, assessed the causes and outlook for crude price volatility before a packed house at the recent KPMG Global Energy Conference.

The conclusion: “Oil has become the new corn."

Not what you were expecting? Hey, the Saudis don’t care for it either, but the data provide strong support.

“Oil is going to be much more like an agricultural product, meaning when there are disruptions to supply like the fires in Alberta, or the MEND [Movement for the Emancipation of the Niger Delta] attacks in Nigeria, supplies will get cut, prices will go up,” said Philip K. Verleger Jr., who served in the Ford and Carter administrations and later played a key role in creating oil futures markets. “But then there will be periods when there are huge crops, and you’ll see prices go down.”

If that appears to contradict what has long been accepted about the economic fundamentals of the oil business, that’s because it does.

The mindset was defined by Harold Hotelling, an economist whose paper, “The Economics of Exhaustible Resources,” was published by the University of Chicago Press in 1931. Hotelling’s theory was that producers of nonrenewable resources like oil will only produce a limited supply of their product if it generates more profit than bonds or interest-bearing financial instruments.

Therefore, long-term prices will rise year after year at the prevailing interest rate—in theory.

But two years ago, the leaders of Saudi Arabia found themselves in an existential crisis. They looked at the steps being taken to combat global warming. They saw the success of unconventional techniques in the U.S. like horizontal drilling and hydraulic fracturing, and concluded that, long term, their oil was going to be left in the ground, Verleger said.

“What this does for those of us who study resources was essentially turning Hotelling upside down,” he said.

So much for “peak oil.”

In this situation, oil as a natural resource is no longer finite, and it put the Saudis in a race with other producers, particularly Venezuela, to pump as much as possible for as long as possible until the market disappeared.

Twenty years ago, Venezuela had the upper hand and sought to push Saudi Arabia out of the market. Times have changed, and now the Saudis are trying to return the favor. “They are pushing for maximum production,” Verleger said. “I think they’ll probably try to go for 13 million or 14 million barrels per day, and I don’t think that they will ease off.”

But it’s not just Saudi production fueling glum times. Global energy companies have issued about $400 billion a year of debt since 2014, despite falling prices.

“One thing we know from economics is that when you have oversupply of something, and you have leverage on the back end that is linked to that oversupply, your trough tends to be longer,” said Constance Hunter, KPMG’s chief U.S. economist. “It’s a situation where it’s possible—now, of course oil prices are notoriously difficult to predict—it’s possible that this downturn could be a little lower and a little longer than a lot of people have anticipated. And yet, for non-economists looking at this, look at the open interest in the oil contracts. It still remains pretty high.

“The most dangerous assumption in economics is when people come to believe this time is different,” said Mustafa Mohatarem, chief economist for General Motors Co. “It isn’t. So it’s a question of, where will the new demand come from that absorbs the new capacity that we’ve brought to the market?”

Mohatarem acknowledged how the current relatively high prices may distort this view, but he noted that in previous eras, oil price stability was maintained first by the Texas Railroad Commission, beginning in the 1930s, and later by OPEC, in the 1970s.

“Absent the cartel, absent the price regulation, you will always have a price crash coming,” he said. “The problem is, that in itself sets in motion the process of people seeking new resources or new technologies and that again bring the price down.” —Joseph Markman

U.S. poised to become major energy exporter

Despite the lull in commodity prices over the last 18 months, the future remains bright for the U.S. oil and gas industry, with the country set to become a major exporter of hydrocarbons in the coming decade, according to Carmine Difiglio, deputy director for energy security at the U.S. Department of Energy (DOE).

“We expect the U.S. to become one of the biggest LNG exporters by 2022, second only to Qatar,” he said while speaking at Hart Energy’s recent DUG East Conference & Exhibition.

According to Difiglio, U.S. gas exports— via LNG and pipeline—will total 10 billion cubic feet per day (Bcf/d) by 2022, and will increase to 20 Bcf/d by 2040. This is quite the increase from the 4.88 Bcf/d the country exported in 2015.

“The Marcellus and Utica shales continue to be the most productive for natural gas, and especially impressive is the increase between last July and now,” he continued.

Despite the severe price downturn in 2015, production continued to grow on the back of shale plays, which reached a record level of production. The top-producing states were Pennsylvania, Ohio and West Virginia.

These three states, which make up the bulk of the Appalachian Basin, were among the few that saw production growth in 2015. The continued strength of the Marcellus and Utica shales will remain a driving force behind the production growth that will fuel much of these exports.

Further production records can be expected to be set in the coming years, as Difiglio anticipates demand returning soon, with domestic gas production expected to surpass 80 Bcf/d by the end of next year as supply and demand continue catching up to each other.

Despite the LNG market becoming more competitive with more volumes available through new capacity, the U.S. should remain a strong player. The U.S. has about 50% of global capacity under construction. In addition, U.S. projects have advantages over their rivals, according to Difiglio.

“U.S. LNG projects are brownfield projects and already have pipeline connections to gas supplies. They also have marine terminals and have a relatively efficient transition from regasification to liquefaction,” he said.

By comparison, Australian LNG projects are much more expensive, as they require more infrastructure to be built because the industry is relatively young in that country. Companies must build all new construction, including pipelines. These greenfield projects will add costs that help to keep U.S. LNG economical even as Henry Hub prices improve.

The sheer size of U.S. reserves is also an advantage, as domestic producers can send more volumes out to market based on demand while not diverting volumes away from consumers. “If gas prices rise, production increases; so as we export more LNG, the gas to supply LNG terminals is coming from new production. It’s not taking away from new consumption,” he said.

Another advantage for domestic producers is that U.S. LNG contracts are more favorable to consumers than those found in other parts of the world.

Difiglio noted that U.S. contracts only require buyers to pay tolling fees with no penalties for gas not purchased, and that gas purchased under contract is based on Henry Hub spot prices plus markup. U.S. contracts are also typically more liquid since they don’t have destination clauses.

The U.S. is also set to increase its role as a major NGL exporter. The country is exporting a significant amount of LPG, and Sunoco Logistics recently began exporting ethane from its Marcus Hook facility outside of Philadelphia. Enterprise Products Partners LP is planning an ethane export terminal along the Gulf Coast. As more ethane crackers are built in the Northeast, Marcus Hook will be able to export the increased volumes coming out of the Marcellus and Utica.

Though the U.S. ban on crude exports was lifted at the end of 2015, Difiglio said this market won’t show much strength going in the short term with an unbalanced market leading to more volatility. On a long-term basis, the situation is more positive, with demand increasing worldwide and non-OPEC supply growth declining.

“As supply stalls, demand increases; and if we experience more oil supply outages, we could again see high prices,” Difiglio said. —Frank Nieto

IEA: Oil balanced for the second half

Stronger than expected oil demand growth, unexpected supply outages and modest growth from OPEC members mean the oil market is on course to balance in second- half 2016, according to the International Energy Agency (IEA).

That is assuming there are no surprises, the IEA said in its June oil report.

“At halfway in 2016, the oil market looks to be balancing; but we must not forget that there are large volumes of shut-in production, mainly in Nigeria and Libya, that could return to the market, and the strong start for oil demand growth seen this year might not be maintained,” the IEA said.

“In any event, following three consecutive years of stock build at an average rate close to 1 MMbbl/d there is an enormous inventory overhang to clear. This is likely to dampen prospects of a signifi cant increase in oil prices.”

The report was released as oil companies continued to feel the pain of lower commodity prices, the outcome of a supply-demand imbalance brought on by an abundance of oil and reluctance by some of the world’s biggest producers to cut production. Global output fell by 590,000 bbl/d year-on-year to 95.4 MMbbl/d.

Output in the U.S. has fallen as companies produce less and leave wells uncompleted until prices rebound further. Plus, outages caused by events such as raging wildfi res in Canada have contributed to the global oil supply falling by nearly 800,000 bbl/d in May, according to the IEA.

The IEA estimates production from non-OPEC countries will fall by 900,000 bbl/d in 2016. U.S. shale output is also expected to tumble by 500,000 bbl/d. However, the IEA expects non-OPEC supply growth will return in 2017, rising by a “modest” 200,000 bbl/d.

Supply disruptions have not been limited to non-OPEC countries.

The IEA pointed out that OPEC crude output saw its fi rst signifi cant production since early 2013—dropping by 110,000 bbl/d in May to 32.61 MMbbl/d. Contributing to the fall were losses in Nigeria, where militants have attacked oil facilities and pipelines in the Niger Delta to draw attention to their demand for more oil wealth in certain parts of the region.

Militant action has forced production to 30-year lows in Nigeria, the IEA said, later adding troubles in Nigeria and Libya— where production “remains a long way from signifi cantly increasing”—appear to be longstanding.

“This current list of shut-ins might soon be augmented by Venezuela where the deteriorating situation could affect the operations of the oil industry,” the IEA said. “In addition to the unplanned shut-ins, our forecast of production falls due to lower oil prices remains intact.”

But Iran has emerged as OPEC’s fastest source of supply growth in 2016. The country, which was freed in January from economy-crippling sanctions related to development of nuclear capabilities, is expected to add 700,000 bbl/d.

“On the planning assumption that OPEC oil production grows modestly in 2017, we expect to see global oil stocks build slightly in fi rst-half 2017 before falling slightly more in second-half 2017,” the IEA said. “For the year as a whole there will be a very small stock draw of 0.1 MMbbl/d. We must stress that this is our fi rst look at 2017, and the huge number of moving parts will see us amend our numbers accordingly … the direction of travel seems to be clear.”

Meanwhile, global demand is picking up. Calling oil demand growth “significantly stronger” than expected, the IEA revised up global oil demand growth for 2016 to 1.3 MMbbl/d.

“In 2017 we will see the same rate of growth and global demand will reach 97.4 MMbbl/d,” the IEA said. “Non-OECD nations will provide most of the expected gains in both years. The growth rate is slightly above the previous trend, mostly due to relatively low crude oil prices.” —Velda Addison

EPA’s ‘Quad Oa’ to take effect

The U.S. Environmental Protection Agency’s (EPA) new rules targeting methane and volatile organic compound (VOC) emissions from new, modifi ed and reconstructed natural gas processing plants and compressor stations were set to take effect at the fi rst of August. This rule, known as “Subpart OOOOa” or “Quad Oa,” builds on existing regulations that EPA previously released for gas plants and natural gas wells. It places a number of new requirements on midstream owners and operators, and could create headaches for businesses caught unprepared.

For the midstream industry, the new rule has two primary requirements:

A mandate that control devices or practices be used to reduce methane and VOC emissions from certain equipment by 95%; and

• A requirement of fugitive emission leak detection and repair (LDAR) for compressor stations.

One of the most diffi cult near-term tasks for midstream businesses will be determining whether these requirements apply to their facilities. In addition, companies will have to carefully monitor any future changes to their facilities not currently subject to the new rule to know if those actions have suddenly “triggered” Quad Oa compliance obligations.

EPA’s new rules only apply to specifi c types of equipment, compressor stations and gas processing plants that are new or have undergone certain changes since Sept. 18, 2015. Natural gas processing plants built, modifi ed or reconstructed before Sept. 18, 2015, may be subject to other regulations under Quad Oa.

Dete rmining whether a facility qualifies as new, modifi ed or reconstructed can be particularly tricky because the analysis must be done for each piece of equipment or compressor station that could potentially be subject to the rule, and the defi nition of “modifi cation” is different depending on the piece of equipment or facility in question. For example, a particular pneumatic controller at a compressor station can be “modifi ed,” and thus be required to reduce emissions, when certain physical or operational changes are made to that specifi c controller.

In contrast, the entire compressor station will only be considered “modifi ed” for purposes of the LDAR requirements when one or more additional compressors is installed at a compressor station, or when one or more compressors at a compressor station is replaced by one or more compressors of greater total horsepower than the compressor(s) being replaced. As a result, companies will need to undertake a careful analysis of their facilities and institute internal protocols to ensure that future changes at compressor stations and gas processing plants are fl agged when those changes could result in additional compliance requirements. —Larry W. Nettles and Corinne V. Snow