Keyera Corp. and SemCAMS Midstream, two major midstream players in Western Canada, in mid-May announced they are proceeding with the construction of their joint-venture project — a new NGL and condensate pipeline system out of the liquids-rich Montney and Duvernay plays of Alberta. The planned Key Access Pipeline System would provide the first direct competition for the transportation of NGLs and condensate out of these producing regions, currently dominated by Pembina Pipeline Co. Any and all transportation options for the movement of condensate and other NGLs out of the Montney and surrounding plays will likely be welcomed by Western Canadian natural gas producers, who are looking to capitalize on oil-sands producers’ growing demand for homegrown sources of condensate for use as diluent in bitumen transportation. Today, we provide key details about the project and how it fits into the region’s existing condensate/NGLs market.
As Western Canadian natural gas production has been recovering off lows from a few years ago and pushing higher, one of the by-products of this recovery has been steadily rising production of natural gasoline, an NGL “purity product’ also known as plant condensate. Condensate production has been growing so much that Pembina Pipeline Corp. — a leading transporter of natural gasoline in the region — has been undertaking another round of expansions to its Peace Pipeline system to move more of the product to the Alberta oil sands. There, condensate is used as a diluent to allow the transportation of viscous bitumen to far-away markets via pipelines or rail. Today, we take a closer look at Pembina’s effort to expand the Peace Pipeline.
Through the first half of the 2010s, U.S. production of field condensate — the ultra-light liquid hydrocarbon that bridges the gap between superlight crude oil and heavier natural gas liquids like natural gasoline — more than doubled, peaking at about 640 Mb/d in early 2015. As condensate production ramped up in the Eagle Ford and other plays, conde prices were discounted to move the product, markets were developed to absorb the barrels, and infrastructure was built to move the conde to those markets. Then, in a dramatic turnaround that continued into 2017, condensate production fell by more than one-third, the new markets — splitters and exports — were starved for product, and conde prices flipped from discounts to premiums. But the market is shifting yet again. Conde production is once more on the rise, with the Eagle Ford rebounding and production rising in the star of the show in crude oil markets: the Permian. Today, we discuss highlights from RBN’s new Drill Down Report on the condensate market roller-coaster.
Record high production with prices still rangebound! As of year-end 2017, Lower-48 natural gas production was at an all-time high — 77 Bcf/d and rising. NGL production from gas processing was at 3.7 MMb/d, the highest since EIA started recording the numbers. And U.S. crude oil output stood at 9.8 MMb/d, within spitting distance of the 10 MMb/d record set back in October/November 1970. All this with the price of WTI crude oil no more than 9% higher than it was this time last year, and natural gas prices 20% below year-end 2016. Yup, the dogs are out. Productivity is the culprit: longer laterals, super-intense completions, manufacturing-process pad drilling — the list goes on. Clearly the U.S. can’t absorb all this production growth, so the export market must be the answer. Or is it? Are we really that confident that world markets will make room for still more U.S. hydrocarbons? If not, what does it mean for prices? And ultimately, how will these prices impact U.S. producers? These are big questions, and with this much turmoil in the market it is impossible to know what will happen. Impossible? Nah. No mere market turmoil will dissuade RBN from sticking our collective necks out to peer into our crystal ball one more time to see what 2018 holds.
The combination of rising condensate demand as new splitter capacity came online and falling conde supply resulted in just what you’d expect — higher conde prices. Worse yet for the companies that made throughput commitments for those new splitters, the once-favorable price differentials between conde and light-crude benchmarks West Texas Intermediate (WTI) and Louisiana Light Sweet (LLS) have been turned on their heads, and a number of splitters are operating at far less than capacity. Today, we continue our look at the roller-coaster world of conde, this time focusing on conde prices and differentials, and on the forces that may change the conde market once again.
The sharp decline in U.S. condensate production since early 2015 and the end to the ban on U.S. crude oil exports a few months later were a one-two punch for the companies that made throughput commitments to condensate splitters and made other conde-related infrastructure investments. In what seemed like a flash, conde supply plummeted and the steep price discount to WTI and other light crude that made conde so attractive for splitting and exporting was gone. Holders of splitter capacity were paying top-dollar for what conde they could corral, and operators were forced to run their brand-new facilities at far less than capacity. And, when the general ban on crude exports was lifted in December 2015, the special status that conde had enjoyed since exports of lightly processed conde were permitted in June 2014 was a thing of the past. Today, we continue our review of a conde world in upheaval, this time with a focus on splitters and exports.
Back in 2015, U.S. production of superlight crude oil and condensate had been on the rise for five years, driven primarily by boom times in the Eagle Ford shale play in South Texas. Condensate was selling for several bucks-a-barrel less than light-crude benchmark West Texas Intermediate (WTI), the U.S. government had recently approved the export of minimally processed condensate, and new condensate splitters were being built to allow refineries to use more high-API-gravity liquids. Fast forward to now, though, and production of superlight crude and conde is off by one-third — the lighter the material, the steeper the decline — a barrel of conde is selling for several dollars more than WTI and a lot of those new splitters are running at far less than full capacity. As for exports of neat conde, they’ve dropped to almost zero, and whatever superlight crude and conde that is being exported goes out as part of blended crude. But things could be about to change again, possibly in a big way. Today, we begin a new blog series on the chaotic U.S. conde and superlight crude market.
Since the ban on exports of U.S. crude oil was lifted in December 2015, export volumes have soared, and for the week ending October 27, 2017, they surpassed 2 million barrels/day (MMb/d) for the first time ever, according to Energy Information Administration (EIA) statistics. And while exports slowed last week, it is clear that there’s more to come. But the pace of export growth depends on many things, including the ability of Gulf Coast infrastructure to receive and store increasing volumes of West Texas Intermediate (WTI), SCOOP/STACK, Bakken and other crudes and load it onto ships — the bigger the ship the better. Fortunately, coastal Texas and Louisiana already had extensive crude-related infrastructure in place when the export ban ended just under two years ago, and elements of that have been repurposed to handle exports. Will it be enough? Today, we begin a new blog series on existing and planned storage facilities and marine terminals targeted to support rising U.S. crude oil exports.
Term charter rates for medium-range Jones Act tankers have fallen by two-thirds since they peaked at $120,000/day in mid-2014, to only $38,000/day done in September 2016, which is good news for producers but a punch in the stomach for ship owners. A sharp rise in the number of vessels being added to the Jones Act fleet has surely contributed to the charter-rate collapse. Less obvious are the degrees to which the rate drop may have been influenced by the decline in superlight Eagle Ford crude oil production, or by the lifting of the ban on U.S. crude oil exports. Today, we examine the evidence.
More than four years after the Utica and the “wet” part of the Marcellus became a hot spot for drillers, the field condensate and natural gasoline produced there are still moved to market by barge, rail and truck. A three-part, $500 million plan by MPLX LP and the midstream master limited partnership’s (MLP’s) subsidiaries, now well under way, will enable more efficient pipeline transport of these important hydrocarbons to Midwest refineries, Western Canadian diluent pipelines and other end-users. To hold down costs, the effort involves a creative mix of new and existing pipelines. Today we continue our review of MPLX’s plan with a look at its “Utica Build-Out Projects.”
Two new 50-Mb/d, Kinder Morgan-owned and -operated condensate splitters came online during the first seven months of 2015, backed by a 10-year BP commitment to process a total of 84 Mb/d through the units. Located in the Houston Ship Channel’s refinery row, the splitters were expected to provide a profitable outlet to process growing volumes of the ultra-light crude oil known as condensate. Instead, average plant throughput through July 2016 has been only 71% of capacity, well below the 90% average operating level of neighboring refineries. The relatively low level at which these units have been operating reflects sagging condensate processing margins. Today, we detail how Kinder Morgan’s new splitters have been run during their first year or so of operation.
MPLX LP and the midstream limited partnership’s subsidiaries (collectively referred to as “MPLX”) are stepping up to address a lingering hydrocarbon-delivery issue in the Utica and “wet” Marcellus plays, namely, how to more efficiently transport the field condensate and natural gasoline produced there to refineries, Western Canadian heavy-crude shippers and other end-users. Currently, condensate and natural gasoline are moved within and out of production areas in eastern Ohio, northern West Virginia and western Pennsylvania via truck, rail or barge. MPLX’s three-part, $500-million plan, the first elements of which are nearing completion, is mostly about pipelines—a mix of new ones and creatively repurposed existing ones. It looks like a win-win for condensate and natural gasoline producers and buyers. Today we begin a series on improving the flow of these two close relatives in the hydrocarbon family to buyers in the Midwest and beyond.
Way back when—before 2012—few outside a small cadre of oil producers and marketers paid any attention to condensates, or even knew they existed. Then two events shook the condensate world. First came rapid growth in the Eagle Ford, where crude oil production turned out to be almost half condensates. Then the Department of Commerce started allowing condensate exports while maintaining the ban on international sales of mainstream crude oil. Suddenly condensates were the star of the show. But like the careers of one-hit rock & roll wonders, the stardom didn’t last long. The crude oil price crash hit Eagle Ford hard, resulting in a disproportionate decline in condensate production. Congress then sent condensates further back into obscurity by removing the export ban for all crude oil in December 2015, eliminating any special status for the product. That was the end of the road for the condensate story, right? Wrong. Because during condensate’s day in the sun, billions were spent on pipelines, stabilizers, splitters, export facilities and refinery modifications, all focused on providing new markets for condensates. Oops. Today we consider how the next chapter of the condensate saga will play out.
The STACK shale play west/northwest of Oklahoma City has quickly emerged as one of the hottest hot spots, and two “sweet-spot” counties in the heart of the play rank near the top nationwide in drilling activity. For now, the primary focus of the small group of producers active in STACK (for “Sooner Trend Anadarko Canadian Kingfisher”) isn’t on production, it’s on gaining a more complete understanding of the play’s complex geology, which offers (as acronym luck would have it) a bona fide stack of hydrocarbon production layers (including the particularly promising Meramec) that together may offer off-the-chart volumes. Today, we consider a play that can provide some producers a 75% rate of return at $45/bbl oil and $2.25/MMBtu natural gas—that is, at prices 11% to 13% lower than they are today.
The race to load the first freely exported U.S. crude cargo was won by NuStar’s Corpus Christi terminal, edging out Enterprise’s Houston terminal, as the Theo T set sail for Italy on New Year’s Eve with Eagle Ford crude and condensate on board. Midstream companies are now set to fiercely compete, not just for bragging rights but for terminal fees, as more U.S. crude heads overseas. But where exactly will that crude go? With oil prices tracking below $40/Bbl and narrow differentials prevailing between U.S. and overseas crudes, breaking into new markets will be tough. Today we outline which markets are most likely to absorb U.S. crude supply.