Prices Fall on Sixth Consecutive Triple-Digit Injection

Prices Fall on Sixth Consecutive Triple-Digit Injection

Natural gas storage inventories increased 115 Bcf for the week ending June 14, according to the EIA’s weekly report. This injection is well above the market expectation, which was an inventory increase of 104 Bcf.

Working gas storage inventories now sit at 2.203 Tcf, which is 209 Bcf above inventories at the same time last year and 199 Bcf below the five-year average.

At the time of writing, the July 2019 contract was trading at $2.200/MMBtu, dropping $0.076 from yesterday’s close. Prices were up around ~$0.02/MMBtu before the report release, but the bearish release caused prices to quickly fall.

For the sixth consecutive week, the EIA has reported a triple-digit injection. This is the first time this has happened since 2014, when there were seven consecutive weeks of triple-digit injections. With the summer’s peak demand season just around the corner, don’t expect the triple-digit injections to hang around much longer. As power burn ramps up in July and August, some of the gas that is currently being injected into storage will need to be used to meet power burn demand. ICE’s Financial Weekly Index report is currently expecting an injection below 100 Bcf for next week.

See the chart below for projections of the end-of-season storage inventories as of November 1, the end of the injection season.

This Week in Fundamentals

The summary below is based on Bloomberg’s flow data and DI analysis for the week ending June 20, 2019.

Supply:

  • Dry gas production saw an increase of 0.23 Bcf/d. The largest move was in the East region, which showed a 0.22 Bcf/d gain in production. Within the East region, nearly all of the change came from Ohio (+0.20 Bcf/d).
  • Canadian net imports decreased 0.67 Bcf/d. This decrease is mainly due to the complete shutdown of the Alliance pipeline system. This shutdown is for repairs to the pipeline in Iowa and Illinois, and the pipeline is expected to come back online over the weekend.

Demand:

  • Domestic natural gas demand increased 0.51 Bcf/d week over week. Power demand was the driver of the change, gaining 0.74 Bcf/d on the week. This was slightly offset by both Res/Com and Industrial demand, which fell 0.21 Bcf/d and 0.01 Bcf/d, respectively.
  • LNG exports showed an increase of 0.31 Bcf/d on the week, while Mexican exports increased 0.09 Bcf/d.

Total supply is down 0.44 Bcf/d, while total demand increased 0.93 Bcf/d week over week. With the increase in demand and the decrease in supply, expect the EIA to report a weaker injection next week. The ICE Financial Weekly Index report is currently expecting an injection of 95 Bcf. Last year, the same week saw an injection of 66 Bcf; the five-year average is an injection of 66 Bcf.

Rising Above the Fray Series – The Market Taketh and The Market Giveth

Rising Above the Fray Series – The Market Taketh and The Market Giveth

What’s Hot, What’s Not

As Wall Street has slammed the brakes on providing funding via secondary equity offerings and public bond raises, E&Ps are increasingly switching lanes towards other strong market segments as opportune sources of capital. This article provides data and insight on the depth of the Wall Street shutdown (The Market Taketh) as well as some sweet spots for U.S. E&P operators and capital providers to tap into for opportunities (The Market Giveth) including a strong Royalty and Minerals market, a strong Midstream market and other bright spots.

From an industry, capital allocator and investors perspective, the suite of product offerings by Drillinginfo, including its Market Research, Market Intelligence, Mineral and Midstream Research offerings allow for dynamic, single-sourced, integrated quality data sets to stay ahead of the pack and quickly identify profitable opportunities in the one of largest markets in the world (energy) across the entire the energy value chain — be it above ground or below ground, across commodities, in the U.S. or international, or in the public or private markets.

The Market Taketh

Now that we are approaching the mid-year point of 2019, it is remarkable that year-to-date no U.S. operator has raised a single dollar from an equity follow-on issuance.

In fact, the last issuance occurred back on November 19, 2018 when Contango Oil & Gas raised net proceeds of $33 million via issuance of 8.6 million common shares at $4.00/share to support its southern Delaware Basin Bullseye and NE Bullseye development in Pecos County.

This blowback from Wall Street stands in stark contrast to the run and go days for investors backing U.S. public E&P land grabs during 2016 and early 2017.

From Q2 2016 through Q1 2017, equity investors were eager to back acquisitions which totaled $90 billion, of which nearly 60% or $53 billion was for land (aka drilling inventory). In 2016 alone, Wall Street investors wrote $30 billion in equity checks to the acquirors, often overnight. At the time, the open-door policy of Wall Street enabled transformative acquisitions by U.S. operators that set the stage for decades of drilling.

In a twist of irony, soon after the land grab, which by default requires enormous piles of money to drill out the inventory, Wall Street slammed the bank shut and demanded companies develop those inventories through cash flow – significantly slowing the pace of growth. To put numbers around this, at mid-2018 our data indicates that operators publicly disclosed (in their own language) buying net 50,261 drilling locations from January 1, 2016 through June 30, 2018 which would require nearly $350 billion (by Drillinginfo cost estimates) in drilling and completion capital to drill out. That’s a lot to develop out of “cash flow”!

To be sure, the shut down of easy equity has slowed the pace of U.S. resource play inventory development – which is of such scale that going full throttle would certainly have further increased global supply and pressured oil prices more than they already are.

In the past decade, annual bond raises by U.S. operators average around $30 billion. Since January 2015, U.S. operators have issued $107 billion in bonds, compared to $60 billion in equity.

Largely as a result of the equity market shutdown, the bond markets have followed suit as most companies are challenged to raise additional debt without a concomitant increase in equity. The few bonds that are getting through are largely refinances to extend maturities.
Nearing mid-year 2019, U.S. E&P operators have raised a paltry $3.2 billion in bonds thus far this year from just seven companies –

  • Apache, June 5 ($394 MM net, Unsecured Notes due 2049, 5.35% coupon)
  • Apache, June 5 ($596 MM net, Unsecured Notes due 2030, 4.25% coupon)
  • Goodrich, May 31 ($11.8 MM net, Secured Second Lien due 2020, 13.5% coupon)
  • Kosmos, April 4 ($637 MM net, Senior Notes due 2026, 7.125% coupon)
  • CNX Resources, March 14 ($490 MM net, Senior Notes due 2027, 7.25% coupon)
  • Centennial Resource, March 12 ($490 MM net, Senior Unsecured Notes due 2027, 6.875% coupon)
  • Cimarex, March 7 ($497 MM net, Unsecured Notes due 2029, 4.375% coupon)
  • PetroQuest, February 8 ($78 MM net Secured Second Lien due 2021, 10% coupon)

The Market Giveth – What’s Hot

While public investors have gone on strike funding E&P operators, one sector is gaining momentum as an alternative way to play the development of the U.S. resource plays. The mineral and royalty market set a record $3.3 billion in M&A activity in 2018.

Not only is this market active in M&A, the public markets are also pumping fresh capital into this market with the latest example being the IPO of Brigham Minerals (NYSE: MNRL, $1.0 billion market cap) which went public on April 18, 2019 via an upsized offering of 14.5 million shares priced at $18 and currently is trading north of $20. Other pure-play publicly-traded mineral and royalty companies (as of June 17) include –

  • Viper Energy Partners (NASDAQ: VENOM, $3.8B market cap, IPO June 2014)
  • Black Stone Minerals (NYSE: BSM, $3.2 B market cap, IPO April 2015)
  • Kimbell Royalty (NYSE, KRP, $1.1 B market cap, IPO Feb. 2017)
  • Falcon Minerals (NADAQ: FLMN, $0.6 B market cap, formed August 2018)
  • Dorchester Minerals (NASDAQ: DMLP, $0.6 B market cap, formed 2003)

The Grandaddy included in this sector is Texas Pacific Land Trust (NYSE: TPL), an entity created in 1888 via a reorg of the Texas and Pacific Railway that ultimately created the Trust. TPL is now one of the largest landowners in Texas holding 888,333 surface acres and 459,200 acres with a perpetual oil and gas royalty interest, much of which is in the Permian Basin. Prior to the onset of the US shale plays, this stock traded around $30/unit at the beginning of 2010. From January 1, 2010 to April 8, 2019, the stock soared to a recent peak of $901/unit. The units currently trade at ~ $715/unit and the Trust sports a market cap of $5.5 billion.

For U.S. E&P operators, a thriving mineral and royalty markets represent an opportunity to raise capital via the sale of outright minerals or carved-out royalties from high net revenue interest assets. Examples include Range Resources raising $300 million via a 1% ORRI carve out sold to Ontario Retirement Teachers Pension Plan, Continental Resources selling some Oklahoma minerals ($220 million) and forming a JV with Canada’s leading gold-focused royalty company, Franco-Nevada, and of course Diamondback Energy’s dropdowns to its affiliated company, Viper Energy. The attractiveness of this increasingly transparent market also drove Chevron to organize its U.S. minerals into an internal division so that it can take action as needed to realize the full value of these minerals which look to be undervalued under the Chevron company.

From 2015 through 2018, the U.S. Midstream deal market averaged $113 billion per year as buyers vie to capture the value from the growing midstream buildout to support surging production from the resource plays. In 2018, this activity reached a modern peak at $170 billion with U.S. E&P operators also participating with a record $12 billion of sales into this market.

Recent, notable deals by U.S. E&P operators include the remaining sale of Anadarko’s ownership in Western Gas Partners for $4.0 billion in November 2018. In August 2019, Oxy sold non-core assets to privately held Lotus Midstream and Modus Midstream $2.6 billion. That same month, Apache sold 71% of its Alpine High midstream assets in the Delaware Basin for $2.5 billion. Earlier in the year, Gulfport and EQT sold Ohio gathering assets to EQT Midstream for $1.5 billion. Mid-cap E&Ps like Oasis Petroleum, PDC and Matador have also tapped into this market as avenues to raise additional capital outside of traditional sources.

Not to be discounted, the pivot of private equity into the midstream sector is alive and well. Since 2015, we’ve tallied over $24 billion in PE commitments to midstream companies and projects. 2018 was a record year with $9.2 billion committed (compared to $5.3 billion in the upstream sector) with 2019 thus far tallying over $3.4 billion.

Aside from backing new companies, private equity is directly investing in deals themselves. Since 2015 private equity and financiers bought about 6% of the $600 billion in U.S. midstream deals. However, the role of this sector on the buyside is surging and on a record pace YTD accounting for over 40% of this year’s $29 billion in U.S. midstream deals. Two strong examples include Stonepeak Infrastructure Partners $3.6 billion buy of Oryx Midstream and a Blackstone Infrastructure led group to invest $4.8 billion into a controlling stake in Tallgrass Energy, LP. In announcing the deal, management emphasized that the fund is an open-ended fund that is “very long-tailed” and capable of financing the $4 – $5 billion of capital projects on deck at Tallgrass.

As the public markets tighten their grip on financing upstream activities, we certainly expect E&P companies to look towards selling or forming joint ventures regarding midstream assets as the buyer universe looks to be hungry to expand. A case in point is Noble Energy who in April 2019 disclosed that with the assistance of its advisors, the company is conducting a review of strategic alternatives regarding its effective 45% ownership in Noble Midstream Partners.

Fundamentally, the landscape for private equity investors in the upstream sector is changing. In recent history, there are great success stories of PE sponsors backing talented teams for new private E&Ps with a playbook to go acquire lands early, deploy the latest technology and operational best practices with an objective to de-risk the lands for a sustainable, consistent drill and develop program. The poster child of this model is the Delaware Basin where PE-backed companies deployed risk dollars and were able to exit to a public company seeking to put a solid footprint in the emerging basin. The funding by the buyers was often supported by the public equity markets with funding secured in overnight raises.

As the table below depicts, since 2015 PE-sponsors have committed over $44 billion of which roughly 11% has turned. The Permian is the largest destination representing nearly 50% of those risk dollars. PE investments recently peaked in 2017 at nearly $14 billion.

PE investments dramatically slowed in 2018 to just a little over a third of the prior and in 2019 has only tracked $1.6 billion.

While new upstream commitments have slowed, the landscape of PE investments does offer opportunity on multiple fronts. Traditionally, PE model looks to exit within 3 to 7 years so there is a host of companies that are nearing the exit timeframe and certainly present buying opportunities. It is fair to say currently, the market favors buyers who have many choices of where to deploy acquisition capital.

Also, for those looking to deploy fresh private equity, the aforementioned Wall Street negative sentiment regarding equity and bond issuances sets up alternative models. Instead of the buy, de-risk, sell model, some PE backed companies are looking to build full scale E&P companies and drill out their de-risked positions. At the well level, even in today’s price environment there are attractive IRRs that PE backed companies can achieve – given access to additional drilling and completion capital. This capital may take the form of direct equity or alternative structures including non-op commitments, drillco commitments or joint ventures.

For those who look long term, there is also an opportunity in this market to deploy capital towards PDP production valued at current commodity prices. The lagniappe pie associated with PDP buys is increasing as the public markets continue to change the valuation metrics for public E&Ps.

Much has been written regarding the Drillco model. In short, the structure provides for a win/win between a capital provider seeking to invest in low risk wells and an E&P company seeking to accelerate the development of long-dated inventory. An example of the structure is shown to the right.

In simple terms, the operator wins once the capital provider achieves a certain rate of return via a flip of the share of the cash flow generally after the peak production from the well. The capital provider wins by achieving minimum required rates of returns and is rewarded with a tail of cash flow through the life of the well.

Given that many E&P companies have decades worth of de-risked inventory and limited capital sources, Drillco’s are an attractive model to supplement basic capital programs with additional drilling and cash flow.

The types of capital providers reach from typical PE firms to capital firms targeted directly to the Drillco structure.

In the current capital environment, Drillco’s present an excellent opportunity for both private capital and E&P operators (public or private). The key to success for the capital provider is technical due diligence of the geology and economics of a drilling program plus the operator’s ability to perform. For operators, there are choices of capital partners.

Keys to Success

The Drillinginfo platform has grown exponentially over its 20-year history. All the data in this article are sourced solely from our platforms. We provide the industry’s leading dynamic datasets that are easily accessible to both the industry and capital providers to find the best partners or deal opportunities. No longer are players left in the dark. The data talks and the opportunities for wealth creation, particularly in today’s environment, are numerous. If you haven’t checked in lately, we encourage you to call us for a full demo of the power of Drillinginfo.

Also, check out the prior articles I’ve written under this series:

For information regarding Drillinginfo products, click here.

Crude Withdrawal Supports Prices

Crude Withdrawal Supports Prices

US crude oil stocks posted a decrease of 3.1 MMBbl from last week. Gasoline and distillate inventories decreased 1.7 MMBbl and 0.6 MMBbl, respectively. Yesterday afternoon, API reported a crude oil draw of 0.8 MMBbl, alongside a gasoline build of 1.46 MMBbl and a distillate draw of 50 MBbl. Analysts were expecting a larger crude draw of 2.0 MMBbl. The most important number to keep an eye on, total petroleum inventories, posted a decrease of 0.4 MMBbl. For a summary of the crude oil and petroleum product stock movements, see the table below.

US crude oil production decreased 100 MBbl/d last week, per the EIA. Crude oil imports were down 0.1 MMBbl/d last week to an average of 7.5 MMBbl/d. Refinery inputs averaged 17.3 MMBbl/d (200 MBbl/d more than last week’s average), leading to a utilization rate of 93.9%. The bullish report due to higher than expected crude withdrawal is supporting prices. Prompt-month WTI was trading up $0.34/Bbl, at $54.24/Bbl, at the time of writing.

Lingering trade tensions between the US and China, weaker demand growth, and worries over global economic health have been pressuring prices. Expectations that trade officials from the US and China would settle on an agreement on the trade disputes during the June 28-29 G20 meeting in Osaka had been fading away, which was the main catalyst driving the bearish sentiment. Prices took a sharp positive turn yesterday, increasing nearly 4% after US President Donald Trump said he would hold an extensive meeting with Chinese President Xi Jinping at the G20 meeting. Also supporting prices were Saudi Arabia’s reportedly increasing pressure on OPEC members and allies to reach an agreement on extending supply cuts and increasing tensions in the Middle East following last week’s tanker attacks, with the US planning to send more troops to the region.

The attacks last week on two tankers in the coast of Strait of Hormuz, the world’s busiest sea lane for oil shipments, triggered concerns about supply disruptions from the region; however the US –   China trade tensions and gloomy economic and demand outlook had offset the supply risk price movement until President Trump’s statement that a meeting will take place with the Chinese president during the G20 meeting. It is too early to tell what the outcome from the meeting between Trump and his counterparty will be at the end of the month, as the countries have been unable to reach an agreement for months now. IEA’s new monthly report showing a down revision of demand growth by 0.1 MMBbl/d in 2019, as well as a slowing Chinese economy as a result of trade wars, will continue to keep the pressure on prices.

Market will be awaiting the outcome of the G20 meeting on the trade tensions for clarity on the demand side as well as the outcome of the OPEC meeting that will take place around the same time frame as the G20 meeting on the supply side, which will indicate whether OPEC+ will decide to extend the production cut agreement into the second half of the year. Until the results of these meeting materialize, any news on further increasing tensions in the Middle East or demand deteriorating further will be the main driver of any price movement.

The market internals maintain a consolidating trade within the new range. Last week’s trade softened the oversold conditions, as the market closed in the middle of the range on rising volume, while open interest declined. The last two weeks traded to highs of $54.63/Bbl and $54.84/Bbl, respectively, and those levels should find sellers this week. A break above those levels this week will likely challenge the area where prices broke down: between $56.00/Bbl and $57.33/Bbl. Should prices reach this range, selling should accelerate. Declines back to the lows of the past two weeks, at $50.60/Bbl to $50.72/Bbl, will find buyers just like last week. The recent range should hold without significant expansion of the conflict with Iran.

Petroleum Stocks Chart

Forecasting this Summer’s Gas and Power Supply and Demand

Forecasting this Summer’s Gas and Power Supply and Demand

The first official day of summer is Friday, June 21. That means packing up your winter clothes unless you live in Northern California where May’s record-setting snowfall will keep ski resorts open into August! As the snowpacks melt (or don’t), the weather warms, and El Niño lingers for a second year in a row, Drillinginfo’s expert analysts have begun developing their hydro, wind, and natural gas production and demand forecasts.

Rob Allerman, Senior Director of Power Analytics and Rob McBride, Senior Director of Market Intelligence, recently co-hosted a webinar to deliver Drillinginfo’s predictions for the West Coast Hydro outlook, how the long-term load and wind forecast can help provide deeper insights to traders and analysts, and explore the U.S. natural gas balance.

The replay of the webinar – “Summer 2019 Gas and Power Fundamentals” – is available here. Let’s take a look at some highlights.

Hydro Generation

Rob Allerman began with his hydro-generation forecast for the Columbia Basin, which is expected to be below average due primarily to the fact that the remaining snowpack is far below average for this time of year. Most of the snow melted early, particularly in the northern basins, and that will have a significant impact on hydro generation in July and August.

 

 

The forecast for California hydro generation is a 180 degree turn. It’s been a very wet year, especially in Northern California, and a cool spring has slowed the pace of snowpack melt. After years of suffering through droughts, the area will generate extremely high hydro flows and reservoir storage levels will be high throughout the summer.

 

 

North American Wind and Load Summer Forecast

For the second straight year the country will be affected by El Niño conditions – a rarity. Before this year, you could count on one hand the number of times it had occurred: 1957-1958, 1968-1969, 1976-1977, 1986-1987, and 2014-2015.

History shows the second El Niño year usually brings a summer with cool temperatures across the Great Plains and Midwest, but warmer temperatures on the coasts. We expect that will be the case this summer, and will be one of the factors in below average load and lower than average wind generation over the middle of the country.

 

After Allerman concluded his presentation with the PRT/Drillinginfo ISO Load and ISO Wind forecasts, it was Rob McBride’s turn to deliver our U.S. gas balance forecasts.

Natural Gas Demand

We’re moving out of the cooler winter and early spring months, and that signals the coming shift of natural gas demand away from the residential heating load to gas burning by electricity generators.

 

Following the 2014 oil price crash, both production and demand for natural gas has grown steadily each year. Production is being driven by the shale boom and improving drilling economics and efficiencies, and demand is being driven by low-cost gas and the retirement of several coal and nuclear power plants.

Production in 2019 has started off strong, even compared to the incredible year that was 2018. As you can see below, that gap is starting to narrow.

O&G producing companies want to live within their cash flows, and that means lowering their capital expenditure budgets. We expect to see production growth through the summer as companies introduce new efficiencies and get better at drilling – just not the same explosion of growth as last year.

 

 

McBride also provided an outlook for net exports of natural gas and what will be left over in the U.S., and explained the myriad of factors that could affect power demand and the end of summer storage inventory.

Follow this link to view the webcast replay. If you want to do a deeper dive, you’ll find all the details in our latest FundamentalEdge Market Outlook report, available as part of our Drillinginfo MarketView Fundamentals product suite.

If you have any questions, please connect with us on Twitter and Facebook.

The Week Ahead For Crude Oil, Gas and NGLs Markets – June 17, 2019

The Week Ahead For Crude Oil, Gas and NGLs Markets – June 17, 2019

CRUDE OIL

  • US crude oil inventories posted an increase of 2.2 MMBbl last week, according to the weekly EIA report. Gasoline inventories increased 0.8 MMBbl, and distillate inventories decreased 1.0 MMBbl. The total petroleum inventories showed another substantial increase of 9.3 MMBbl. US crude oil production decreased 100 MBbl/d last week per EIA. Crude oil imports were down 0.3 MMBbl/d to an average of 7.6 MMBbl/d versus the week prior.
  • Prices confirmed the recent trend of weak global demand outpacing the production cuts and geopolitical unrest to drive trader interests. Rarely in WTI trade does the price of crude fail to maintain most of its gains after bullish events, like the two tankers attacked in the Gulf of Oman on Thursday. This type of geopolitical unrest, targeting the shipping lanes, should send prices up at a strong clip. While the action was met with gains immediately, by the end of the week prices had settled back into the middle of a recent range ($50-$55), closing the week at $52.51/Bbl.
  • Early in the trade last week, prices were supported based on Saudi Arabian energy minister Khalid al-Falih’s comments about extending the oil production cuts, with an agreement on the horizon. He went on to say that the only oil exporter undecided on the need to extend the cuts was Russia. Russian energy minister Alexander Novak provided little insight as to where the country stands on the deal, only citing the risk that if oil producers pump out too much oil, prices could drop to $30.00/Bbl.
  • After positive bias early in the week, which set the week’s highs, prices were punished when the inventory report was released. This bearish report, similar to other recent reports, showed US petroleum inventories growing significantly. IEA’s latest oil market report, lowering demand 0.1 MMBbl/d, brought additional negativity to the market.
  • Data points from world markets and equities confirm that both global economic growth and demand for crude are under attack, and market sentiment in WTI is not immune to these factors. Trade tensions between the US and China, which are subduing global economic growth, may be addressed at the upcoming G20 meetings later in June, but neither side has publicly shown a strong interest in resolving the issues. This lack of interest has placed a cloud of uncertainty over the markets, as traders continue to trade out of risk assets that are linked to economic growth (crude, commodities in general, and some equities) and into safety trades like the US Treasury (10-year).
  • The CFTC report (positions as of June 11) brought forth additional selling from the bulls as the Managed Money long component liquidated 24,136 contracts, while the short position added 27,839 contracts. The short speculative sector seems to add to positions on price runs to the high side of the recent range ($50-$55). With the continued gains in the short position of late, uncertainty regarding any solution to the trade issues is directing the positions of traders.
  • The market internals maintain a consolidating trade within the new range. Last week’s trade softened the oversold conditions, as the market closed in the middle of the range on rising volume, while open interest declined. With the strength of prices on Friday, follow-through gains going into this week should be expected. The last two weeks traded to highs of $54.63/Bbl and $54.84/Bbl, respectively, and those levels should find sellers this week. A break above those levels this week will likely challenge the area where prices broke down: between $56.00/Bbl and $57.33/Bbl. Should prices reach this range, selling should accelerate. Declines back to the lows of the past two weeks, at $50.60/Bbl to $50.72/Bbl, will find buyers just like last week. The recent range should hold without significant expansion of the conflict with Iran.

NATURAL GAS

  • Natural gas dry production showed an increase of 0.32 Bcf/d, while Canadian imports decreased by 0.42 Bcf/d.
  • Res/com demand gained 0.09 Bcf/d, while power demand declined 0.98 Bcf/d. Industrial demand dropped 0.03 Bcf/d. LNG exports rose 0.02 Bcf/d, while Mexican exports increased 0.04 Bcf/d. These events left the total supply for the week dropping 0.10 Bcf/d while total demand decreased by 0.87 Bcf/d.
  • The storage report last week showed the injections for the previous week at 102 Bcf. Total inventories are now 189 Bcf higher than last year and 230 Bcf below the five-year average. With the drop in demand being greater than the drop in supply, expect the EIA to report a stronger injection this week.
  • Weather models are showing that summer-like temperatures will be arriving in the southeast and south central regions in the coming two weeks. This will provide the market a good period to evaluate the power demand requirements over the summer months.
  • The CFTC report (as of June 11) showed the Managed Money long sector decreasing positions by 1,751 contracts, while the short position took another aggressive position by adding 40,771 contracts. The chart below shows the position of the speculative short trade position.

  • The level of shorts is now challenging the bearish period of January 2018, but remains 120,000 contracts below the multiyear lows of early 2016. It should also be noted that the Managed Money long position has dipped down to the low levels from early 2016. The market positions of the speculative community show a lack of panic from the longs, while the shorts are adding aggressively to their positions. This situation has the potential for a short covering rally that could catch trade off guard.
  • Market internals continue to show a bearish bias; total volume has increased week over week, while total open interest remained flat (according to preliminary data from the CMS). The quieter trade last week took the momentum indicators out of the extremely oversold levels.
  • The fundamental indicators continue to show strong production, but the market will likely taste summer demand in the coming weeks. Prices look to seek additional declines but have found buyers when they have headed toward $2.30 over the past seven trade days. This area around $2.30 might be the low side of a potential trading range for prices during the July prompt contract until the market fully understands the potential impact of summer power demand. Any rally in prices will run into selling at $2.475 up to $2.573. Should the support area fail to hold declines, probes lower will likely challenge a zone from May 2016, between $2.151 and $2.288.

NATURAL GAS LIQUIDS

  • NGL prices mostly dropped week over week. Ethane fell $0.035 to $0.167, propane was down $0.033 to $0.412, normal butane dropped $0.004 to $0.468, and isobutane was down $0.002 to $0.499. Natural gasoline was the only product to increase, gaining $0.021 to reach $1.019.
  • US propane stocks increased ~2.9 MMBbl during the week ending June 7. Stocks now sit at 71.1 MMBbl, roughly 20.3 MMBbl and 18.4 MMBbl higher than the same weeks in 2018 and 2017, respectively.

SHIPPING

  • US waterborne imports of crude oil fell for the week ending June 14, according to DrillingInfo’s analysis of manifests from US Customs & Border Patrol. The decrease was driven mostly by a drop in imports to PADD 1 and PADD 5. As of June 17, the data showed that PADD 1 imports stood at nearly 590 MBbl/d for the week, while PADD 5 imports were at nearly 1.05 MMBbl/d. PADD 1 imports fell by more than 650 MBbl/d from the prior week. PADD 3 imports rose from the prior week and are at nearly 1.75 MMBbl/d.

  • Total US crude imports from Russia were at their highest level since at least 2017 at nearly 330 MBbl/d. PADD 1 received nearly 90 MBbl/d, PADD 3 received more than 45 MBbl/d, and PADD 5 received nearly 195 MBbl/d. The biggest recipient of Russian barrels was Par’s refinery on Oahu, which imported nearly 150 MBbl/d of Sakhalin Blend and Sokol crude oil originating from facilities in South Korea and Japan.

Triple-Digit Injection for Fifth Consecutive Week Meets Expectations

Triple-Digit Injection for Fifth Consecutive Week Meets Expectations

Natural gas storage inventories increased 102 Bcf for the week ending June 7, according to the EIA’s weekly report. This injection is nearly spot on with the market expectation, which was an inventory increase of 101 Bcf.

Working gas storage inventories now sit at 2.088 Tcf, which is 189 Bcf above inventories at the same time last year and 230 Bcf below the five-year average.

At the time of writing, the July 2019 contract was trading at $2.350/MMBtu, dropping $0.035 from yesterday’s close. However, most of this decline came before the release of the storage report.

This week, the prompt month contract has traded in a narrow $0.049 range. The main driver of prices as we near peak summer will be weather. Should weather forecasts show significant heat, expect price gains. However, should the peak summer season be mild and inventories continue to gain on the five-year average, expect prices to fall.

See the chart below for projections of the end-of-season storage inventories as of November 1, the end of the injection season.

This Week in Fundamentals

The summary below is based on Bloomberg’s flow data and DI analysis for the week ending June 13, 2019.

Supply:

  • Dry gas production increased 0.04 Bcf/d. The largest move was in the East region, which showed a 0.21 Bcf/d gain in production, while all other regions decreased less than 0.10 Bcf/d.
  • Canadian net imports decreased 0.29 Bcf/d.

Demand:

  • Domestic natural gas demand was flat week over week. Power demand fell 0.14 Bcf/d, while the offset came from Res/Com, which increased 0.17 Bcf/d. Industrial demand decreased slightly on the week, falling 0.04 Bcf/d.
  • LNG exports showed an increase of 0.03 Bcf/d on the week, while Mexican exports were relatively flat.

Total supply is down 0.25 Bcf/d, while total demand increased 0.04 Bcf/d week over week. With the increase in demand and the decrease in supply, expect the EIA to report a weaker injection next week. The ICE Financial Weekly Index report is currently expecting an injection of 99 Bcf. Last year, the same week saw an injection of 95 Bcf; the five-year average is an injection of 81 Bcf.