Today, the U.S. Energy Information Administration (“EIA”) issued its Today in Energy entitled U.S. Crude Oil Production Growth Projected to be Led by Light, Sweet Crude Oil.

We all know that I have a sweet tooth, but we aren’t talking those kinds of sweets today – we are talking light, sweet crude. It is no secret that light, sweet crude oil accounted for the growth in domestic production in recent years – but just how much growth is attributable to lighter crude from tight formations?

According to the EIA’s Today in Energy, “light, sweet crude oil, defined as having an API gravity of 35 or higher and a sulfur content of 0.3% or less” accounted for “nearly 90% of the 3.1 million barrel per day (b/d) growth in production from 2010 to 2017.”

In fact, just last week on April 4, 2018, the EIA issued a Today in Energy entitled U.S. Production of Crude Oil Grew 5% in 2017, Likely Leading to Record 2018 Production. This article discussed the significant increase in domestic crude oil production due to the development of tight rock formations. Specifically, the EIA’s April 4 Today in Energy provides as follows:

“Annual average U.S. crude oil production reached 9.3 million barrels per day (b/d) in 2017, an increase of 464,000 b/d from 2016 levels after declining by 551,000 b/d in 2016.”

“In November 2017, monthly U.S. crude oil production reached 10.07 million b/d, the highest monthly level of crude oil production in U.S. history.”

As I write this, according to Bloomberg Energy, oil prices are pretty steady – WTI Crude Oil is at $63.30 per barrel and Brent Crude is at $68.65 per barrel.

I took this photo while flying into North Dakota a couple of weeks ago – flying high above North Dakota’s Bakken oil play and the mecca of light, sweet crude.

Record Year

The number of producing oil wells in North Dakota just hit a new record…by all accounts, North Dakota could be on track for having a record year.

On Friday, Lynn Helms, Director of Mineral Resources for the North Dakota Industrial Commission, released the Director’s Cut dated 5/12/2017 – which can be found here.

The Director’s Cut outlines oil and gas activity for the State of North Dakota on a monthly basis. The March 2017 Director’s Cut contains some interesting information:

  • New Record: A new all-time high number of producing wells has been reported – The number of wells producing oil, according to the preliminary count in the March 2017 Director’s Cut, is 13,632. This is up over 100 wells since the numbers reported for February 2017.
  • However, Daily Oil Production is Actually Down: According to the March 2017 Director’s Cut preliminary numbers, oil production is down from 1,034,248 barrels/day in February 2017 to 1,025,638 barrels/day for March 2017.
  • Rig Count Up: The rig count as of Friday was reportedly 51, up from 39 in February of 2017.
  • The Comments section of the March 2017 Director’s Cut gives us the insight that “[m]ore than 98% of drilling [in North Dakota] now targets the Bakken and Three Forks formations.”

As of right now, the price of oil is up. According to Bloomberg Energy, WTI Crude is currently at $49.06 per barrel, up 0.43%, and Brent Crude is at $51.98 per barrel, up 0.33%.

Good news for a Monday! Here’s hoping it is a record year…

Spring Takeaways

Spring is in the air here in Denver! Many of us have spring fever and have been looking forward to blooming flowers, sunshine and warm weather.

So you may be curious what is about to bloom in the energy sector… Earlier this week, the US. Energy Information Administration (“EIA”) released its March 2017 Drilling Productivity Report for key tight oil and shale gas regions. A full copy of the report can be found here.

What is the EIA’s Drilling Productivity Report?

According to the EIA, this report provides estimated changes in oil and natural gas production for seven key regions (Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian and Utica) based upon recent data concerning (1) the total number of operating drilling rigs, (2) estimates of drilling productivity and (3) estimated changes in production from existing wells.

These seven regions are said to be the “most prolific” and to have “accounted for 92% of domestic oil production growth and all domestic natural gas production growth during 2011-2014.”

What are the 3 Key Takeaways from the March 2017 Drilling Productivity Report as we head into spring?

  1. Oil production is expected to decrease in the Bakken as of April 2017, while it is expected to increase slightly in the Eagle Ford, Marcellus, Niobrara and Permian for that same time period.
  2. Drilled but uncompleted wells (“DUCs”) increased in the Bakken, Eagle Ford, Haynesville and the Permian from January to February 2017 – with the Permian leading the increase with 95 new DUCs.
  3. New-well oil production is expected to increase the most in the Utica from March to April 2017, while new-well gas production is expected to increase the most in the Marcellus during that same time period. The Bakken is expected to come in second place for new-well oil production, while the Niobrara region is expected to come in second place for new-well gas production.

Stay tuned for what else is blooming in the energy industry!  Hello Spring!

Director's Cut

Yesterday, Lynn Helms, Director of Mineral Resources for the North Dakota Industrial Commission, Department of Mineral Resources (“NDIC”), issued his monthly Director’s Cut newsletter. The full Director’s Cut can be found here.

To me, reading the monthly Director’s Cut is like sitting down to coffee with Lynn Helms and picking his brain – its like having a conversation with the man in the know in North Dakota. I wish every oil producing Rocky Mountain state put one of these newsletters out every month…

So what are the takeaways from the March Director’s Cut?  Here’s the skinny on North Dakota:

  • Oil Production

January 2017 oil production was up from December 2016: Up roughly 38,000 barrels/day

  • Gas Production

January 2017 gas production was up from December 2016: Up over 550,000 MCF

  • Permitting

Drilling permits spiked from 35 in December 2016 to reportedly 81 in January and 45 in February

  • Rig Count

Holding pretty steady – reportedly 40 in December 2016, 38 in January 2017 and 39 in February 2017

BUT THERE’S MORE…the rig count as of the issuance of the March Director’s Cut on March 8, 2017 was up to 44

The comments to the Director’s Cut state that, “Operators are shifting from running the minimum number of rigs to incremental increases throughout 2017, as long as oil prices remain between $50/barrel and $60/barrel WTI.”

In addition, the comments state that:

  • “The number of well completions decreased significantly from 84 (final) in December to 54 (preliminary) in January.”
  • “Low oil price associated with lifting of sanctions on Iran, a weak world economy, and capital movement to the Permian basin continued to depress drilling rig count.”

And that is the skinny on the March Director’s Cut!

Is the Bakken Fixin' to End

Earlier this week, Forbes published an article entitled, “The Beginning of the End for the Bakken Shale Play,” that likely caused many hearts to sink. In fact, I started writing this blog discussing the article yesterday and I didn’t have the stomach to finish it until this morning…

What is the article’s main prediction?

Basically that the heyday in the Bakken is over…that the decline in the Bakken has signaled “the beginning of the end for the Bakken Shale play.”

It is worth noting that the author of the Forbes article is Art Berman, a petroleum geologist with nearly 40 years of oil and gas experience – his full bio can be found here and additional information about him can be found here.

So is the Bakken fixin’ to end?

Things are not looking great for the Bakken according to the Forbes article, which reports that “[t]he decline in Bakken oil production that started in January 2015 is probably not reversible.”  The article also includes numerous charts and graphs to visually explain its proposition that the Bakken’s heyday is over.

What does the article base this conclusion on?

Here are the following factors that the article cites as the evidence that the Bakken production decline is probably not reversible:

  1. Poorer well performance: New well performance has reportedly deteriorated and estimated ultimate recovery (“EUR”) has reportedly decreased over time for most operators. According to the article, “[t]his suggests that well performance has deteriorated despite improvements in technology and efficiency;”
  2. Less oil: Gas-oil ratios have reportedly increased;
  3. Higher water: Water cuts are reportedly rising; and
  4. Increased efficiencies in drilling technology reportedly increasing depletion.

What is probably most troubling in the article is its conclusion that “[a]vailable evidence suggests that current well density is sufficient to fully drain reservoir volumes.”

In layman’s terms – no new wells are necessary.

According to the article, “[t]hat implies that further drilling will not result in producing new oil volumes but will interfere with and cannibalize production from existing wells.”

A local North Dakota news source addressed the Forbes article this morning by running an article entitled, “Bakken Dispute: What will the Future Hold?” which points out that the Forbes article did not consider the effects of the harsh North Dakota winter when predicting future oil production.

The article concludes that “[i]f observations presented here hold up, there may be nowhere for the Bakken to go but down.”

It is likely that this will be an area that is hotly contested in future months – only time will tell if the heyday in the Bakken is truly over…

To not end the week on a bad note, I am glad to report that as I finished writing this blog this morning, oil prices are up – according to Bloomberg Energy, WTI Crude Oil is at $53.10 per barrel and Brent Crude is at $55.62 per barrel.

Lynn Helms, Director of the North Dakota Industrial Commission Department of Mineral Resources, released his monthly “Director’s Cut” today showing North Dakota’s oil and gas stats. The full Director’s Cut can be found here.

North Dakota’s rig count as of today is 29 – representing the lowest number of rigs since October of 2005.  The all-time high was reportedly 218 rigs in May of 2012.  The statewide rig count is down 87% according to the Director’s Cut.

The Director reportedly opines that “Operators are committed to running the minimum number of rigs while oil prices remain at current low levels.”

However, while production is also decreasing, the numbers do not reflect significant decline.

The Director’s Cut reports January, 2016 oil production at 34,796,333 barrels = 1,122,462 barrels/day and February, 2016 oil production at 32,431,669 barrels = 1,118,333 barrels/day.

The Wall Street Journal noted today that “[s]lumping oil prices are starting to affect output in U.S. shale fields, including the prolific Bakken formation in North Dakota.”

That is a great way to put it – prices are starting to affect output.

In reality, a slight decline in production has occurred, but it is not really notable in light of the rig count in January being nearly double today’s count.  In January the rig count stood at 52…

According to the Wall Street Journal article, “North Dakota crude oil production fell for the third month in a row, ticking down 0.4% in February and hitting its lowest level in 18 months.  The slightly lower production in February follows a 2.6% drop in January and a 2.5% slide in December, data from the department show.”

With the relatively drastic decline in the rig count, one would expect to see a more significant decline in production.

Yesterday, Lynn Helms, the director of the NDIC Department of Mineral Resources, released his “Director’s Cut” providing production figures and analysis for the month of October 2015.  Some of the numbers he presented are pretty startling.

Though we all have heard about rig count declines in North Dakota and elsewhere, October oil production showed an INCREASE over the prior month of around 6,000 barrels per day.  Similarly, though (as with oil) not at all-time highs, natural gas production climbed in October by more than 46,000 MCF per day over September production.

Moreover, the number of producing wells in the state increased to a total of 13,174 representing an all-time high in the state.  Of these, 80% were unconventional Bakken or Three Forks wells.  Finally, it was reported that as of the end of October, there were 975 wells drilled but waiting to be completed.

The report noted that drilling permit activity “fell sharply in November as operators continued to position themselves for low 2016 price scenarios.”  The problematic part, from a production/pricing standpoint is the further comment that “[o]perators have a significant permit inventory should a return to the drilling price point occur in the next 12 months.”

What does this mean overall?  We see nothing in these production figures to provide any optimism that domestic supply will decrease materially any time soon.  To the extent commodity prices are driven by the supply coming from American shale, as opposed to just OPEC, that keeps us (unfortunately) generally pessimistic on prices for the foreseeable future.

Democratic presidential candidate Bernie Sanders became the first presidential candidate to announce opposition to the proposed Bakken oil pipeline, which, the Des Moines Register reports, “would transport up to 570,000 barrels of crude oil daily through 18 Iowa counties.”

According to the report, Senator Sanders, who also opposed the Keystone XL pipeline, stated: “I’m opposed to the construction of the Bakken crude oil pipeline because as a nation our job is to break our addiction to fossil fuels, not to increase our dependence on oil, coal, and other carbon pollution sources.”

While we are not climate change deniers, we fail to see how preventing the delivery of crude oil will help achieve Senator Sanders’ goal.  The fact of the matter is that, at least in the “near” term, this nation is dependent on crude oil.  As but one example, the American Petroleum Institute notes that “[p]etroleum products power virtually all motor vehicles, aircraft, marine vessels, and trains around the globe.  In total, products derived from oil, such as motor gasoline, jet fuel, and heating oil, supply 33% of all the energy consumed by households, businesses, and manufacturers worldwide.  By comparison, natural gas and coal supply 22% and 28%, respectively, of the world’s energy needs.”  American Petroleum Institute, “Understanding Crude Oil and Product Markets” 2014.

Furthermore, the growth in oil production over the last few years (which remains an increase over historical figures even with recent price-driven production declines) has been met with relatively minimal increases in pipeline capacities and minimal development of new pipelines.  This means more crude is being transported by barge, rail, and truck.  Each of these modes of transportation has its own environmental issues – not even to mention carbon footprints apparently ignored by Senator Sanders.

We believe that increased production of crude oil from domestic reserves, coupled with decreased overall reliance on foreign oil, is a good thing for the country – but that increased production will mean nothing if it cannot be transported in an efficient, cost-effective and environmentally sound manner.

Senator Sanders’ categorical rejection of the Bakken and Keystone XL pipeline projects strikes us as both short-sighted and imprudent.

A few weeks back, we discussed the pressing issues surrounding drilled but not yet completed wells in North Dakota.  Under the then-applicable rules, a well was required to be completed within one year of the date of issuance of the applicable drilling permit.  At the time, we noted there were in excess of 900 drilled but not completed wells in the state, many of which were approaching that one year deadline.  As we predicted, last week the North Dakota Industrial Commission adopted new policies which should allow producers to keep drilled wells uncompleted for a longer period of time, thus avoiding the requirement to complete wells at times of continued depressed commodity prices.  We can’t help wondering, however, if the likely increasing backlog of wells to be completed might not have unintended consequences with respect to future commodity prices.

North Dakota flag
Copyright: chelovek / 123RF Stock Photo

As reported by Amy Dalrymple in The Dickinson Press, the NDIC “adopted a new policy” allowing operators to have wells drilled but not completed for a year after the date of the well permit to be placed “on temporary abandoned status, giving them another year to store the oil in the ground.  Royalty owners, land owners and non-operating interest owners would have the opportunity to object.”  According to an email from the North Dakota Petroleum Council to its members, technically speaking the NDIC merely clarified the process to temporarily abandon a well and did not formally change any policy.

The paper further noted that Lynn Helms, Director of the Department of Mineral Resources, said he expects about 500 wells will be designated as temporarily abandoned and that he expects those designations to “prompt a gradual decline in oil production from 1.19 million barrels per day to 1.1 barrels per day at the end of the biennium in June 2017.”

Then comes the kicker:  “Most experts anticipate that oil prices will recover in 2017, Helms said.”  And now we have questions.

We accept the premise that reduced production could have a positive impact on prices.  But when the wells that were put on temporarily abandoned status are completed, won’t production increase?  To the extent the decrease in commodity prices was triggered (in whole or in part) by supply – demand issues, couldn’t increase production from the year-long delayed wells, send supply back ahead of demand, triggering another round of downward price adjustments?

This morning, an article on notes that the number of rigs running in North Dakota held steady for the third straight week, and quotes Mr. Helms for the proposition that “the state-wide rig count [is] about a dozen less than it would be if oil was priced at $65 per barrel.”  Again, that suggests to us that with improved pricing will come more active rigs which will lead to more production.  Will this increased production upset the delicate supply-demand balance and precipitate another downturn in prices?  How much of an impact will foreign nations and conditions have on WTI pricing before and during this expected expansion in production?

Frankly, we don’t know the answer to these questions.  Further, we speculate with a fair amount of confidence that we could find several experts to opine both for and against any premise we would set forth.  What we are convinced of, though, is that the price recovery we all are expecting (at some point) is likely to be susceptible to many influences making both its timing and form far from certain.

An interesting report from this morning notes that during the first quarter of the year oil and gas producers earned around $3.7 billion from hedges.   Significantly, “[p]ayments from hedges accounted for at least 15 percent of first-quarter revenue at 30 of the 62 oil and gas companies in the Bloomberg Intelligence North America Exploration and Production Index.” 

The problem:  “Now that safety net is going away.”

As Bloomberg reports, last year, companies could secure hedges in the $85-$90 per barrel range.  Today, similar hedges only see prices in the low $60s.  And many companies are seeing those higher priced hedges start to expire.  As an example, according to Bloomberg:

Oasis Petroleum Inc., one of the most active drillers in North Dakota’s Bakken shale, received almost $91/barrel for 19,000 barrels/day. That accounts for more than 40 percent of its daily production and is the biggest piece of its hedging program. At the end of June, the guaranteed price drops to $77, company records show. By January, the company will have just 2,000 barrels/day hedged at $65/barrel.

At the same time, though, the hedges have allowed producers to cut costs and increase efficiencies. 

The day of reckoning may be coming for some companies as banks and other lenders often evaluate their credit lines in October.  How will those reevaluations go if the debtor’s hedges have expired? 

Was the cash crunch resulting from the drop in commodity prices only delayed?