Permian Continues to Test the Limits of America’s Existing Midstream and Downstream Infrastructure

Austin, TX (August 7, 2019) – Drillinginfo, the leading energy SaaS and data analytics company, has released Permian to Gulf Coast Midstream, the latest installment of their FundamentalEdge series, which presents an overview of oil, gas, and natural gas liquids (NGL) infrastructure currently proposed between the Permian basin and Gulf Coast export terminal locations.

Underscoring the lack of adequate takeaway capacity in 2018-2019, plus the expected importance of coastal oil, natural gas, and NGL exports, in this report Drillinginfo highlights the expected impact of upcoming long-haul takeaway capacity projects and the price differentials they’ll create.

“The Permian basin has experienced unprecedented production growth and remains the world’s focus, from producer to private equity, to service and supply companies,” said Bernadette Johnson, Vice President of Strategic Analytics at Drillinginfo. “But the Permian continues to be challenged by existing pipeline constraints and the inability to efficiently and effectively move oil, natural gas, and NGLs to the market. All hydrocarbons are tied at the drill bit and one affects the other. Although many players in the Permian are targeting crude oil primarily, natural gas processing and pipeline bottlenecks can have a negative impact on that crude oil production. However, a light at the end of the tunnel may soon be visible – at least for those that can hang in there through 2020,” said Johnson.

In Permian to Gulf Coast Midstream, Drillinginfo analyzes numerous planned pipeline projects and the bottlenecks they expect will be cleared providing relief to America’s most prolific, but congested basin.

Key Takeaways from the Report:

  • Production growth in the Permian basin is testing the limits of existing midstream and downstream infrastructure, requiring further capital investment in long-haul pipelines, gas processing plants, NGL fractionators, and coastal export terminals.
    • Crude oil production continues to rise in the Permian basin despite economic headwinds resulting from sub-$60/bbl WTI prices. Nevertheless, the pace of growth is at risk of slowing significantly if the low flat-price environment persists. With additional long-haul pipeline capacity coming online in the second half of 2019, noncommitted shippers will likely find themselves squeezed out as spot arbs shut. As volumes are further increased to the Gulf Coast (and away from Cushing), additional export capacity will be required, and there is an acute need for new export facilities capable of fully loading VLCCs. A race to the finish has begun, with numerous onshore and at least seven offshore terminals currently proposed or in development.
    • Although natural gas production is mostly a by-product of drilling for crude in the Permian basin, flaring is just not a long-term option. In DI’s high case scenario, dry gas production could increase by 50% (~5 Bcf/d) over the next five years.
    • Market participants are also facing weak regional pricing, with Waha basis trading at levels more than $1.00/MMBtu under Henry Hub. Hence, at least five projects are currently proposed to alleviate this constraint. All projects will be transporting the gas east toward South Texas and Louisiana to feed LNG exports as well as growing power and industrial demand.
    • NGL production out of the Permian is expected to continue to grow, with most of the production destined for the Gulf Coast. To allow for the extra production, a number of pipeline projects are under construction or in planning to transport the NGLs. As NGLs arrive at the Gulf Coast, they are then fractionated. Fractionation capacity has been running tight since mid-2018, resulting in numerous fractionation projects along the coast. The fractionation bottleneck was relieved slightly in early 2019, when two projects hit the market. However, with most projects scheduled to come online in early 2020 and after, it is possible the bottleneck will reappear in late 2019 and early 2020.

Members of the media can download a shortened preview of the overall 20-page Permian to Gulf Midstream or contact Jon Haubert to schedule an interview with one of Drillinginfo’s expert market analysts.

Drillinginfo Report Highlights Impact on Pricing in Hyper Geopolitical Environment

Austin, TX (July 23, 2019) – Drillinginfo, the leading energy SaaS and data analytics company, has released Pricing in Politics, the 3Q2019 installment of its FundamentalEdge series. This market outlook service presents the company’s current view of the oil, natural gas, and NGL markets, and where they are headed over the next five years.

Pricing in Politics explores energy trends and pricing in a market highly affected by geopolitics and the continued impacts of sanctions and tariffs. “The story for 2019,” the report reads, “has been one of dashed hopes for those bullish market participants that believed a redoubling of efforts by OPEC+ would solve the oversupply conditions.”

“The trade tensions between the U.S. and China are creating a global economic activity slowdown and we’re continuing to see the effects politics has in crude oil pricing,” said Bernadette Johnson, Vice President of Strategic Analytics at Drillinginfo. “Even if OPEC keeps production constant and the U.S. and China agree to no further escalation in tariffs, non-OPEC production growth will remain in excess of global incremental demand.”

“While the price crash at the end of 2018 caused a drop in U.S. rig count in America’s shale plays, prices have recovered and the new mantra of free cash flow, return to shareholders, and ‘do more with less’ has caused operators to rethink their drilling and completion schedules and strategies,” said Johnson.

“With more than 1,000 wells drilled, but sitting uncompleted in the Permian, means there is a lot of crude oil production that could come on line quickly, but is not currently accounted for in the storage numbers or balances. U.S. basins continue to prove they hold great economics that result in continued growth expectations for production,” said Johnson.

Key Takeaways from the Report:

  • Efforts by OPEC+ and declines from Venezuela and Iran have eased excess supply; however, escalating trade tensions between China and the U.S. and their effects on global economic health and demand growth have been keeping a lid on prices. Heightened geopolitical tensions between Iran and the U.S. provide some support for prices, but ultimately demand needs to increase for fundamentals to support a balanced market and prices. The OPEC meeting and news around U.S.–China trade tensions will set the tune for next quarter.
  • Natural gas prices for Henry Hub have plummeted recently, trading under $2.30/MMBtu. Only a month ago, prices were above $2.60/MMBtu, and during the first quarter of the year, prices reached $3.00/MMBtu. Despite record-high LNG export levels, underwhelming early summer power demand along with strong production growth have pushed inventory levels up. Looking ahead, natural gas prices of $2.60-$2.75/MMBtu will balance the market, allowing production to increase at a rate to meet the expected demand growth.
  • NGL prices have taken a downturn in the first half of 2019. Production and stocks are at or near record levels for propane and butanes, causing downward pressure on prices. Additionally, prices have been impacted by slowing global economic demand as well as the trade war between the U.S. and China, as LPG exports to China have become nonexistent.
  • The E&P mantra remains focused on capital efficiency, living within cash flow, and returning cash to shareholders. These themes are here to stay. Q1’19 earnings reports show little change to E&P guidance for 2019. Chevron and Occidental spiced up the earnings season with the bidding war on Anadarko. Despite that, Q1 yielded 10-year lows in the upstream deal market. Expect Q2’19 reports to continue to explore how operators are handling price volatility and discussions on efficiencies, Permian gas bottlenecks, and M&A.

Members of the media can download the 19-page preview of Pricing in Politics or contact Jon Haubert to schedule an interview with one of Drillinginfo’s market analysts.

Wall Street Funding Slowdown for Energy Continues with Q2 Capital Raised Via Public Equity & Debt Issues Off 36% YOY

Austin, TX (July 17, 2019) – Drillinginfo, the energy industry’s leading SaaS and data analytics company, released its Q2 2019 Capital Markets review revealing $16.9 billion in aggregate funds raised via energy industry public equity and debt offerings. The amount is down 36 percent from the same quarter a year ago, and down 23 percent from funds raised in Q1 2019.

“These numbers understate how weak capital markets were for parts of the industry,” said Drillinginfo analyst Andrew Dittmar. “In a particularly poor showing, the upstream and oilfield service sectors combined to raise only $300 million from fresh equity, and $2.5 billion from bond issuances,” said Dittmar.

On a bright note, the industry supported two initial public offerings that raised a combined $1.025 billion in Q2, almost double Q1’s $505 million. However, a once-probable IPO issue in midstream’s dynamic water management sub-sector was taken off the table when the Permian Basin-focused candidate withdrew its registration statement during the quarter, opting instead to fund privately with banks and an overseas sovereign fund.

The data was compiled by Drillinginfo’s Capitalize platform, which tracks securities and credit activity of energy companies that file with the U.S. Securities and Exchange Commission, as well as private investment activity.

Equity Markets Up Sequentially, Down YOY

↑ The industry raised $3.4 billion from public stock offerings during Q2, up 189% sequentially but off 19% YOY.

↓ Upstream sold $261 million in public equity in Q2 through a sole offering, the IPO of Brigham Minerals, and was down by half sequentially and 75% YOY. It was upstream’s second-worst equity raising quarter since 2010.

↑ The midstream sector issued $1.6 billion of equity, up 400% from Q1 and 17% YOY. IPO Rattler Midstream Partners’ $765 million raise accounted for almost half the total.

↓ There were no public equity offerings in the oilfield services sector in Q2, a first since 4Q15. The sector had raised $312 million in Q1 and $1.7 billion in 2Q18. Additionally, downstream had no fresh public equity offerings.

“Wall Street emphatically closed the door on fresh external capital for upstream companies, especially from equity raises. That is consistent with calls for E&Ps to live within cash flow,” added Dittmar. “The sole equity success story was Brigham’s IPO and its business of owning minerals and collecting royalties isn’t exactly representative of the broader industry. Similarly, it was tough sledding for oilfield service companies, which are being crimped by cutbacks in upstream spending,” he said.

“The only continued momentum for capital raises came from midstream companies and integrated utilities, which combined to account for 95 percent of energy sector stock issuances and 85 percent of bond sales, including the spinout of Rattler by Diamondback. Unsurprisingly, midstream asset sales are also where E&P companies are looking to raise capital,” added Dittmar.

Capitalize tracked a total $3.4 billion in industry-wide equity issuances through six offerings in Q2. This compares with $4.2 billion in 18 equity offerings in 2Q18 and $1.16 billion across five offerings in Q1, which marked the industry’s lowest output of total equity deals this decade.

Private equity groups also continued their affinity for midstream deals in Q2, making nine new commitments with a disclosed total of $6 billion. Upstream came in second on commitment count with six during the quarter, Capitalize reported. The Permian is unsurprisingly the main target for upstream private capital while midstream investments are geographically diverse.

Bond Issues Fell 39 Percent YOY and 36 Percent from Q1

Capitalize tracked the issuance of $13.5 billion principal amount across 24 bond floats industry wide in Q2, compared with $21 billion through 30 deals in Q1 and $22 billion through 34 deals YOY. Average principal amount in Q2 of $561 million was off 19 percent sequentially and 13 percent YOY. Investment-grade issuers accounted for two-thirds of the debt floated during Q2, down from 75 percent in the previous quarter. Generally, the trend over the last year has been a focus on a better credit quality of issuer for underwritten bond offers. Midstream represented 57 percent of debt raised and 50 percent of activity.

Bond Floats by Sector

↓ Upstream issuers sold $1.96 billion in notes through five floats, off 57 percent from the $4.58 billion raised via six deals in the previous quarter and 66 percent down from the $5.71 billion in debt raised across 12 issuances YOY.

↓ Midstream raised $7.7 billion in debt across 12 deals, 22 percent below Q1’s $9.9 billion through 13 issuance and 38 percent lower than $12.48 billion in debt raised via 17 deals in 2Q18.

↓ Oilfield services raised $0.53 billion in debt through one offering in Q2 compared with $0.61 billion from five bonds in Q1 and $1.6 billion sold via two offerings in 2Q18.

↑ Integrated companies (in this case integrated utilities) issued $3.8 billion in bonds during Q2 compared with $4.0 billion in Q1 and $3.0 billion in 2Q18.

Full copies of the report are available upon request.

Anchored by Occidental’s Record $57 Billion Deal, Oil & Gas M&A Shows Muted Rebound in Q2 2019

Austin, Texas (July 2, 2019) – Drillinginfo, the leading energy SaaS and data analytics company, published a list of the Top 10 U.S. upstream M&A deals in the second quarter of 2019 and summary of activity. While deals rebounded off historic lows in Q1 to reach $65 billion, analysts caution the value was overwhelmingly driven by Occidental’s $57 billion acquisition of Anadarko, which is the fourth-largest oil and gas upstream deal ever. That single acquisition contributed 88 percent of total deal value in Q2.

Excluding Occidental-Anadarko, Q2 M&A largely matched Drillinginfo analyst expectations with a modest rebound to $7.6 billion. While nearly a four-fold increase over the $2.0 billion low in Q1 M&A, $7.6 billion is less than half of the average quarterly total of the $19 billion seen 2017-2018.

“Occidental dominated headlines this quarter with assertive maneuvering to beat out much larger rival Chevron and secure a deal with Anadarko,” said Drillinginfo M&A analyst Andrew Dittmar. “While Anadarko’s assets span the globe, the deal is largely a play on U.S. shale —particularly in the juggernaut Permian which continues to power U.S. production growth.”

Moving past that deal, the largest Q2 deals focused on the Haynesville, Gulf of Mexico, and onshore U.S. conventional assets.

Comstock Resources picked up the second-largest deal of Q2 when it acquired private equity-backed Covey Park for $2.2 billion to expand its Haynesville operations. The acquisition relied on the willingness of Dallas Cowboys owner and Comstock controlling shareholder Jerry Jones to open his checkbook and increase his total commitment by $475 million to $1.1 billion.

The support by Jones permitted Comstock to avoid one of the key impediments to acquisitions by public companies — a near complete lack of Wall Street financial support. Halfway through 2019, there has been little-to-no growth capital provided via follow-on equity raises to U.S. public operators. Following suit, bond issuances are on track for a decade low. Public E&Ps are tightly focused on efficiently drilling existing inventory, which they appear to be doing effectively as U.S. production continues to grow despite Drillinginfo analysts observing an expected 20 percent average capex cut for 50+ E&Ps in 2019.

“Wall Street, consistent with the message for E&Ps to live within cash flow, has cut off new investment dollars from public markets,” continued Dittmar. “Smaller E&Ps, many of which were focused on growth and counting on continued funding have been particularly impacted. Some of these smaller companies could evaluate whether they would be better off private.”

Private capital is still being deployed, albeit potentially with a different model from past years. “Private money is finding targeted opportunities,” said John Spears Director of Market Research at Drillinginfo. “Companies like Sabinal (Kayne Anderson sponsored) are buying production-heavy assets as public companies trim their portfolios. The investment timeline may have lengthened from past years, but these companies still see opportunity to generate cash flow.” Other private moves include the merger of Gastar (Ares) with Chisholm (Apollo) and talks between Elliott Management and QEP for a go-private deal.

What didn’t emerge in Q2 was a spate of public company consolidation in the wake of Oxy/Anadarko. Commentary from market participants including management at the majors indicates the wide expectations in price between buyers and sellers makes deals challenging. What could take place are further “mergers of equals” like the Midstates/Amplify deal in May and the recent oilfield services combination of Keane Group and C&J Energy, with both deals leading to a 50-50 ownership structure between existing shareholders in the new companies.

Top Takeaways from Q2 2019:
• $65 billion total in 2Q19 upstream deal activity, but $57 billion is attributable to one deal
• Occidental’s acquisition of Anadarko is a historic bet on shale, particularly the Permian
• Otherwise, deal value bounces off extreme Q1 low to a modest $7.6 billion
• Brigham Minerals joins the ranks of public royalty companies with $300 million IPO
• Gulf of Mexico sees some activity as companies look at cash flow generating assets
• E&Ps look to midstream asset sales and joint ventures as additional capital sources

Outlook for Q3 2019:
• Deal activity likely to remain slow but steady as private capital is put to work
• Some smaller public E&Ps with high-quality assets may get offers to go private
• Companies will evaluate merger of equal deals as one option for gaining efficiencies
• E&Ps will continue to pursue alternative financing (drillcos) with tight capital markets
• Royalty market will keep gaining momentum with more buyers growing their portfolios
• Majors want to grow shale exposure, but may still be some time out from making a move

 

Top 10 Deals in Q2 2019

Members of the media can download an 6-page preview of oil and gas M&A Review & Outlook or contact Jon Haubert to schedule an interview with one of Drillinginfo’s market analysts.

With Coal in Rear View Mirror, Renewables Look to Battle Natural Gas Next for Market Share

Austin, TX (June 11, 2019) – Drillinginfo, the leading energy SaaS and data analytics company, has released Gas Power Burn, an update on fuels used to power America’s domestic electric market. This is an interim report covering the dynamics of the natural gas power demand market in the U.S.

“While no one can predict the future – or the weather – our modeling is projecting a glimpse of how renewables will affect power burn in the U.S.,” said Rob McBride, Senior Director of Market Intelligence at Drillinginfo. “From forecasting out a year in advance, to next-day load forecasts, we’re finding utility operators, power marketers, and other power buyers are tapping machine learning technology to obtain accurate, actionable information. When it comes to load forecasting, accuracy matters,” said McBride.

The report draws from historical data related to time of year, weather, and traditional power use. For example, during the summer months, natural gas demand from the electric power sector makes up a larger share of total domestic gas demand compared to winter. Last summer, power burn represented 49 percent of the total gas demand consumed in the U.S. While winter heating demand from the residential and commercial sectors is very price inelastic due to a lack of substitutes, summer cooling demand from the power sector is price sensitive. Grid operators have the flexibility to respond to changes in the pricing of input fuels by substituting coal and gas for each other. The share of total power generation attributed to gas has been growing over the past several years due to changes in infrastructure, most specifically additions to power plant fleets fueled with gas and added gas transport capacity.

As the report indicates, that could change as a number of wind and solar projects are slated to come online over the next five years. From 2019 to 2020, if all wind and solar projects come online as expected, and run at 100 percent capacity, wind and solar power generation will displace 1.42 Bcf/d of gas demand for power burn.

Regional Power Outlooks:
Retail sales of power differ by region, with some sales being above or below total generation. If retail sales are above total generation, the region needs to import power to meet demand. If retail sales are below total generation, the region has excess power generation and needs to export the excess. Gas Power Burn highlights two prominent regions in the U.S.

Northeast — The grid in the Northeast region is dominated by gas and nuclear. Although some switching capacity remains, coal is mostly gone from the region. Nuclear plants continue to face pressure from low power prices caused by cheap gas and a lack of demand growth. The Pilgrim (MA) nuclear plant is set to retire by June 1, 2019. Following Pilgrim is Indian Point (NY), which may retire unit 2 by May 2020 and unit 3 by May 2021. These three units represent 30 percent of the nuclear capacity in the region. As these units retire and nuclear generation decreases, wind is expected to pick up the generation capacity.

PJM-East — The PJM-East region remains very coal-heavy despite decreasing coal generation and retirements over the past several years. Local coal production makes the fuel more competitive compared to other regions. Over the next 5 years, 43% (14.5 GW) of new gas-fired capacity in the US is expected to be in the PJM-East region. If all announcements come online, this region will add 3.6 GW (or 4%) over the next year, compared to 8.8 GW over the past year. In the next 5 years, it would add 14.5 GW (or a 17% increase from today), compared to 25.3 GW over the past 5 years. With nuclear generation holding steady over the past few years and very little generation from other sources, gas is set to take market share from coal as new plants come online.

Key Takeaways from the Report:

  • The share of total power generation attributed to natural gas has been growing over the past several years due to changes in infrastructure, most specifically additions to power plant fleets fueled with gas and added gas transport capacity.
  • Power burn represents almost 50% of the total gas demand consumed in the U.S. during the summer months.
  • In 2019, demand for power during May-August is expected to average 35.2 Bcf/d. Warmer weather, similar to the summer of 2011, will cause gas demand for power burn to exceed 2018 and reach 36.5 Bcf/d. However, having a cooler summer similar to 2014 will cause weak power burn demand, taking power burn down to 34.0 Bcf/d.
  • End of injection season storage inventories will be greatly impacted by summer weather. Warmer temperatures will cause higher power demand and less gas going into storage, while cooler temperatures will do the opposite. Drillinginfo analysts expect storage inventories to end the injection season between 3.6 Tcf and 3.7 Tcf.
  • Renewables and natural gas continue to increase their shares on the supply stack for electricity generation as coal and nuclear decline. However, some coal-to-gas switching capacity remains, but it is more limited.
  • For natural gas, the battle is now with renewables. With a number of wind and solar projects slated to come online over the next couple of years, natural gas demand could decline by 1.2-1.4 Bcf/d, should all projects come online as expected.

Members of the media can download an 11-page preview of Gas Power Burn or contact Jon Haubert to schedule an interview with one of Drillinginfo’s market analysts.

Drillinginfo: Infrastructure and Exports Will Drive or Hinder the Future of Energy in America

Austin, TX (May 8, 2019) – Drillinginfo, the leading energy SaaS and data analytics company, has released an update on exports as a part of their FundamentalEdge series. The report points to continued production growth of crude oil, natural gas, and NGLs, that outpaces domestic demand, with the supply surplus heading overseas.

“The story on the future of oil and gas in America is becoming clearer. Every incremental barrel of production since the middle of 2016 has been exported. As U.S. crude oil production grows, all incremental barrels are (and will continue to be) exported,” said Bernadette Johnson, Vice President of Market Intelligence at Drillinginfo. “To facilitate this rapid increase in exports, additional infrastructure will be critical. Without it, operators will be stuck with a valuable product, but limited options of how to send it to market,” said Johnson

The report highlights that most of this infrastructure will be built in Houston and Corpus Christi, Texas. Corpus Christi is expected to be the leading point of export moving forward, due to its proximity to the Permian and Eagle Ford basins and being a less congested port. As natural gas production continues to grow faster than domestic demand, more gas is finding a home outside of the U.S. In early 2017, the U.S. became a net exporter of natural gas for the first time. During 2018, net exports reached an average of 2.5 Bcf/d. Over the next five years, Canadian imports and Mexican exports will each represent 5 Bcf/d, netting zero imports/exports. Therefore, the amount of LNG exports will equal the total net exports in the U.S. By 2024, the U.S is expected to net export ~10 Bcf/d of natural gas.

“This will be a busy year, and very telling for the future of the LNG export market,” continued Johnson. Three new facilities are expected to come online — Elba Island, Cameron LNG, and Freeport LNG. Additionally, currently operating terminals will be increasing their capacity with added trains in Sabine Pass and Corpus Christi. Beyond that, there are four projects already approved but not under construction, and many others have been announced. “If recent history has shown us anything, it’s that infrastructure doesn’t always come online as expected, and everyone, both the industry and investors alike, should expect some price volatility while the market balances itself,” she said.

Key Takeaways from the Report:

  • Crude oil exports have been growing since 2017 as U.S. production reached historic levels thanks to growth from prolific shale basins, which in large part produces lighter crude that is better suited for refinery fleets in Asia and Europe. Exports to Asia are finding new destinations as China’s imports have declined to virtually zero. Iranian sanctions by the U.S., the situation in Venezuela, and U.S.-China trade wars will play a big role in U.S. exports moving forward. The U.S. supply growth is likely to be exported rather than displacing currently imported volumes.
  • The LNG liquefaction market is the key player for natural gas exports. By the end of 2019, the U.S. will have six operating terminals and nearly 10 Bcf/d of capacity. Additionally, more than 40 Bcf/d and 20 terminals have been proposed in the U.S. However, Drillinginfo analysts expect U.S. LNG exports to reach 10 Bcf/d in 2023, as growth from non-U.S. LNG export facilities drives global LNG prices down.
  • For NGLs, strong production growth is expected to continue. Export markets will continue to grow, as supply will outpace domestic demand. As additional infrastructure hits the market, ethane, propane, and butanes will grow export volumes. Pentanes plus domestic demand is expected to grow in the short term, due to bottleneck issues and production cuts in Canada.

 

 

 

Members of the media can download a 20-page preview of Growing Exports or contact Jon Haubert to schedule an interview with one of Drillinginfo’s market analysts.