Love makes the world go ‘round but firm transportation makes production flow. It takes plenty of steel to build the takeaway infrastructure to make that happen. Thus, we have the new definition of flow assurance, although we now have to hope President Trump’s steel tariffs don’t block the flow.

Used to be, flow assurance meant making sure oil and gas could move unimpeded through an offshore pipeline without paraffin or hydrate buildup, corrosion or freezing ocean temperatures causing a transportation slowdown. Naturally, high costs are associated with preventing or remediating any flow problems.

Today however, flow assurance has taken on a whole new meaning. In shale basins, particularly in the Marcellus Shale and lately, the Permian, it’s about flow to export terminals—and cash flow. The timeliness of bringing on additional pipeline capacity in these two areas will affect producers’ bottom lines—and has international trade implications.

Increasingly this summer, CEOs are talking about firm transportation. In research notes, analysts mention this issue just as often as they do the usual data points such as wells turned to sales, production guidance, cash flow and so on. Can an E&P assure that its oil and gas will flow?

“On the midstream front, we expect WPX Energy [Inc.] to continue to tout its advantageous position relative to its Permian peers, as a combo of basis hedges/offtake agreements leaves only 5% of crude volumes exposed to Midland spot pricing in 2018,” said a Tudor, Pickering, Holt & Co. research note.

In July, Noble Energy Inc. announced additional firm sales agreements for five years for its Delaware Basin production, beginning July 2018 at 10,000 barrels per day and ramping to 20,000 in October. “This agreement locks down flow assurance for NBL in the Delaware,” said a Simmons & Co. note.

But let’s turn to the Marcellus, where problems with takeaway capacity have been well documented.

Don’t cry for natural gas powerhouse Cabot Oil & Gas Corp. though, which is producing 1.8 billion cubic feet of gas per day (Bcf/d) in northeast Pennsylvania. Despite years of pipeline delays and price differential challenges that plagued the region, “the inflection point for Cabot is coming, and thank goodness,” said Dan Dinges, chairman, president and CEO.

Speaking to the Houston Producers’ Forum recently, he said, “The growth rate in gas supply out of the Northeast is tremendous and will continue, but what we need is more demand.”

The Williams Cos. Inc.’s long-awaited Atlantic Sunrise Pipeline should come online in September, he said, moving Cabot’s gas to a Transco line in southern Pennsylvania. Cabot has 1 Bcf/d of firm transportation on it. “We already have that gas sold on several 15- to 20-year contracts. Our realizations are going to improve.”

Dinges cited some 14 oil and gas pipelines in the Appalachian Basin that have experienced protests and regulatory delays. “Companies produce 8 Bcf/d in a six-county area but the pipelines are not keeping up. We’re trying to break the logjam, but it’s affecting all of us, not just to access demand but to narrow the differentials … and prevent a loss of proceeds.”

Since Cabot started drilling in the Marcellus in 2008 to 2009 (when production in the Barnett Shale was peaking), it has had to wait on takeaway capacity and face legal challenges, water quality issues and fraught community relations.

Even so, from 2012 to 2017, Cabot’s gas production compound annual growth rate has been 22% on a debt-adjusted, per-share basis. Currently the company is operating three rigs and two frack crews.

Cabot’s production now stands at 2.1 Bcf/d, with 561 net producing horizontal wells, but Dinges said he is confident Cabot can grow production above 3.75 Bcf/d by 2020. He’s optimistic based on operating in what he called good rock. The company’s EURs are 4.4 Bcfe per 1,000 feet of lateral in the lower Marcellus and 3.9 Bcfe in the upper Marcellus.

Cabot can sell via new pipelines and directly to some new gas-fired power plants in the basin, with firm transportation arranged. Flow assurance.

In 2017, the company’s all-sources finding and development cost in the Marcellus was a mere 22 cents per Mcf. It has continued to trim its costs and lower its breakeven hurdle. “Our overall all-in operating cost including non-cash expenses like G&A and DD&A is $1.58/Mcf,” he said.

One could say Cabot is sitting pretty. It’s reported eight consecutive quarters of free cash flow. The company has 9.7 Tcfe of proves reserves and 3,000 undrilled locations. “That’s more than 35 years of runway ahead of us,” he said. In addition, debt has been trimmed to 0.5x EBITDA. Moving now to larger drill pads and Gen 5 completion design, which he said he hopes yields even more than the 2.9 Bcfe.

The bottom line is that for every oil and gas producer, flow assurance via firm sales and price protection via basis differential hedging will be the keys. Go with the flow.

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