Lower 48 Oil Production

Today's EIA Weekly Petroleum Report shows an unsurprising continuation of the upward production trend that suggests we will keep rising for some time, perhaps breaking 10 million barrels per day by year's end.

Nuclear Power Output Stabilizes, Near 2016 Levels

As we move through refueling and maintenance season, nuclear power output levels should continue to drop, but the outages have not outpaced 2016 by much so far.  April should see larger year-on-year differentials, at least that's what is expected.

High Gas Prices Take Toll on Power Burn Market Share in MISO

The most recent two days (March 25 and 26) are in RED below.  Not only are total gas demand levels quite low, they reflect a loss of market share to coal of about 10 points vs last year:

Nuclear Refueling Begins: Large Drop in US Nuclear Capacity Factor Over the Weekend

Nuclear power output capacity factor dropped from 88% to 82% over the weekend, as units came offline.  That improves the power burn potential for natural gas, and a full gas replacement of the lost nuclear output would see about 1BCFD more gas being burned today than on this day last year.  This imbalance is projected to persist for some time.

MISO Coal to Gas Switching Snapshot: March 2016 vs 2017

Load-adjusted, gas is averaging about 5 points of thermal marketshare below last year in March.

The slope is also different, with market-share varying more directly with overall thermal load size.  With lower demand anticipated as weather moderates in the back half of March, the market share loss should be more pronounced, since thermal demand in the 8-10 BCFE range is showing a gas share around 37%, vs last year at 43%.

Compounding this loss for natural gas is the higher wind output experienced in MISO.  Average daily wind output is 185 GWH this month, vs 135 last March.  That's a MASSIVE difference, displacing something on the order of 400 MMCF per day.  (The increased wind output isn't just in MISO either, it is big in SPP and ERCOT)

Solar Power: Small Beginnings that Matter Quickly

Texas is late to the utility-scale solar power game, but keep one eye on these small beginnings.

It takes perhaps 120 GWH per day to displace a BCF of natural gas, so a tiny number like 6 GWH seems insignificant.  But capacity will grow quickly against a backdrop of low/no load growth, and say 20 GWHD still adds up to 60 BCF per year in gas offset.  With summer sun, and more capacity, coming quickly in the ERCOT region, this graph may take on an interesting slope soon....

MISO Natural Gas Market Share Continues To Steal From Coal

High loads have helped, but in general natural gas is regaining market share from coal since mid-February.  It is not just a few percentage points below 2016 levels, despite a higher market price.  This should help keep a floor under gas prices so long as weather doesn't abandon north america completely this summer:

Winter Heating Requirements Weak Despite Cold Spell

This winter is barely keeping pace with last year's anemic performance.

Through the 3/20 forecast period, we are just 67 HDD's ahead of last year (OCT-MAR), and a full 504 HDD's behind the 20 year average:

Western Canada Natural Gas Storage Surplus Eliminated

A combination of colder weather, higher exports, and lower production have more than eliminated the 40 BCF surplus that western Canada started the year with.  It is now a growing deficit, though weather is moderating quickly from here on out and the big daily storage draws should be history by mid-week.

Coal-to-Gas-to-Coal Switching in the Midwest (MISO) Region

We saw clear and prompt evidence of a switch from gas to coal as power generation feedstock in MISO when gas prices began their sharp rise in late NOV 16.  Then again when prices fell in FEB 17.

Now, with strip prices back above $3 (but HH Spot lagging at the moment), will we see a reversal back to coal domination?

Not yet.

Here are two angles on the question.  The first is the demand adjusted scatter plot, which is indicating that gas is within about 5% of the thermal power market share it held last March, when gas prices were below $2.

The second shows the daily market share of thermal power generation since last November.  Gas was at a 40% market share vs coal back in early November, and then dropped as low as 25% around New Year's Day.  It started rising steadily at the beginning of February, and was near last year's levels, around 40%, by March.  It's been maintaining a high 30's share, clocking 38.4% yesterday.

As higher strip prices translating into the spot market, shouldn't we see gas lose marketshare?

ERCOT Reports February Generation Fuel Mix

ERCOT released their Demand and Energy Report for February 2017 today, and the results are both expected and alarming.  Total generation was off about 2.6% from last Feb, likely due to weather.

My focus was on two things:

Wind power generation....capacity is up from 2016, and the capacity factor seems to be up even more (next gen windmills, better siting?).  In any case, wind generation was up 19.4% over last Feb, from about 6.7 GW average, to 8 GW.  The difference is even larger in March to date.

Market share of thermal output.....it was 60.9% this Feb, vs 64.4% last Feb...down on lower total load and losses to wind.

Natural gas market share of thermal output.....it was 50.7% this Feb vs 67.1% last Feb.  Gas was much more expensive this year.  Falling prices in March should improve this a bit, but last March, gas took a whopping 79.3% of the thermal power market.

Nuclear Power Refueling and Maintenance Season Begins. More Downtime than '16 Expected

A large number of reactors are going down for Spring refueling this year.  Currently the difference between 2016 and 2017 outages isn't significant, but we should see it grow quite a bit over the next 90 days:

Alberta Gas Production Level at 11.2 BCFD, Storage Withdrawals Strong

Field receipts on the TC Nova system in Alberta have been near 11.2 BCFD for the last 12 days, which is around 1/4 BCF below last year's average for the same period.  

Meanwhile, year to date withdrawals from storage total 58 BCF, far exceeding last year's 17 BCF.  This brings western Canadian storage to about even with last year, as a 40 BCF surplus at Jan 1 has been worked off.  Cold weather should be moderating in the province this week, so likely the storage withdrawals will ease back and we may see the beginning of injection season, since gas demand south of the border will also be very low after this weekend.

Henry Hub Spot Price Comparisons

As shoulder season approaches and gas prepares to battle with coal for power generation market share, here is the current scenario:

Gas has been taking back significant market share from coal since prices began dropping two weeks ago.  But contango still reigns, and the summer is priced a little too high for gas to seize the massive market share it took from coal last spring/summer.  

Gas production remains subdued relative to last year, and to expectations.  That will be very supportive if the trend continues, but 1Q reports by E&P's suggest it will not, at least in Q3+.  

If production begins to bound forward, prices will likely come under downward pressure because:

• Hydro surpluses will destroy 1BCFD or more of gas demand all summer
• Renewable energy (solar and wind) will grow by about that same amount again, displacing around 1 BCFD of gas demand.
• Weather was warmer than normal last year (see previous post), which will drop NG demand if we experience a normal summer, perhaps by more than 1 BCFD.  

Obviously this is all against a backdrop of positive variables as well, such as LNG exports and pipeline exports to Mexico, which are all up significantly.  And of course some coal plant retirements.  The economy could also generate some incremental demand due to GDP growth stemming from either a recovery or stimulus.  Lastly, we should see steady small upticks in industrial demand due to long lead time projects coming into service.

Also note how year-on-year pricing improves beginning in June.

A Mighty Wind

Wind power is growing and will grow above trend in 2017.  Electricity demand is not growing.  If wind steals an additional 1% of market share in '17, what feedstock will pay the price?  Hint:  not nuclear, hydro, solar, or even coal.

From the EIA Electric Power Monthly:

Cooling Requirements for Upcoming Summer

As gas demand is modeled for 2017 summer, note that there were about 200 more cooling degree days than normal last year, back-loaded after a cooler than normal start in April-May: