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AARGH Matey! Cap'n Trade Sets Sail in California

 

On January 1st, 2013, California’s cap-and-trade program for Greenhouse Gas emissions (GHG) went live and West Coast energy markets entered a whole new world.  Wholesale electricity prices in California increased 20% as a result and other energy markets have felt the impact.  For example, the new rules pushed up the average cost of refining oil by $0.78/bbl.  For companies subject to the regulations, the bottom line is that if you generate GHG, you pay.  But exactly who pays, how much you pay, and when you pay are all subject to a dizzying array of rules and regulations.  Today we’ll navigate the turbulent and uncharted seas of California cap-and-trade markets.

Check out Kyle Cooper’s weekly view of natural gas markets at http://www.rbnenergy.com/markets/kyle-cooper

The Background

This all started more than six years ago when the California legislature passed the Global Warming Solutions Act of 2006.  The law directed the California Air Resources Board (CARB) to adopt regulations to reduce the state's GHGs to 1990 levels by the year 2020.  More specifically the Act directed CARB to achieve the goal by adopting "market-based compliance mechanisms". That is legalese for setting up a cap-and-trade market.  The cap-and-trade market goes by other names including carbon trading, the carbon market, emissions trading and CO2 trading.

Here’s how it works.   CARB sets an aggregate limit on the metric tons of GHG that can be emitted by covered industries.  That’s the “cap”. CARB then issues a number of allowances to each of the covered companies based on their history of emissions.  Each allowance provides the holder the right to emit one metric ton of GHG.  The total number of allowances issued equals the annual emissions cap (with a couple of adjustments). 

Firms can emit GHG emissions up to the number of allowances they hold, and each firm is required to meticulously measure and track those emissions.  Technically the program requires that a covered company “surrender” allowances to CARB each year sufficient to cover its annual GHG emissions. 

There are three different ways that firms can acquire these distributed allowances: (1) for free through a direct allocation from CARB, (2) by purchasing through a CARB auction, or (3) by purchasing in the bilateral market.  Allowances don’t have to be used to offset a company’s own emissions.  Companies can either use them to offset their own GHGs or they can elect to invest in hardware that will cut their GHGs and then sell any unused allowances in the bilateral market to recover some of the cost of that hardware investment that was used to reduce their emissions output. That’s the “trade” part [1]. Doesn’t sound too bad, right?

But of course, there is a catch.  Each year the cap is reduced. It’s like a game of musical chairs, where some of the chairs are removed each year.  Thus the permitted emissions level declines each year of the program, until it eventually gets the total down to the 1990 emission level goal.  As a company’s permitted emissions levels are reduced, they can make investments to remain under the cap, or they can buy allowances from others who did. 

One of the main goals of cap-and-trade is for the bilateral market to work efficiently, setting the price of allowances based on supply and demand.  Thus when the demand for allowances exceeds the cap, the market price for allowances should reflect the cost (or opportunity cost) of curtailing emissions.  Those with the lowest cost of curtailing emissions do so by making investments and are able to sell their allowances to firms with a higher cost of curtailing emissions, allowing both parties to benefit from the trade.  In many cap-and-trade programs the market is initially over-supplied because regulators tend to set the cap too high.  In that circumstance the price approaches the floor price (the minimum price that someone must pay to obtain an allowance from the regulatory body).

Cap'n Trade Sets Sail

CARB and a cast of thousands have been preparing for the launch of cap-and-trade for years, and it finally set sail on January 1st.  In fact, CARB held its first auction for 2013 allowances in November 2012 when it sold 23 million metric tons of allowances at a clearing price of $10.09 per allowance.  That was slightly above a $10.00 floor price that CARB had set for the auction. 

The maiden voyage of CARB cap-and-trade auctions was not gremlin free.  There was a lot of uncertainty associated with possible legal challenges to the program, and it wasn’t clear what would happen if you purchased an allowance in the auction and the program was delayed or terminated.  Naturally, this dampened demand.  Offsetting that was a mistake on the part of Southern California Edison who accidentally submitted bids for twice as many GHG allowances as available, resulting in the market clearing above the floor.  But ultimately all the issues were worked out, and the system was ready to go for the January launch.  We’ll talk more about the implications of the $10.09 clearing price on California energy markets below.

The next auction is TODAY!  CARB is holding its second auction Tuesday, February 19th.  They will auction 12.9 million metric tons of vintage 2013 allowances with a minimum price of $10.71 (note the floor price is already escalating).  Our company’s view (contributor Tim Belden’s firm is Energy GPS) is that the GHG allowance market is over-supplied for the first few years.  If this is the case, the prevailing wisdom is that prices will clear close to the floor.  What is interesting is that for the past few weeks the bilateral market for Vintage 2013 allowances has traded in the $12 to $16 per metric ton range, with the latest trades coming in around the $14 per metric ton level.  While there are slight differences in product definitions and market rules between the bilateral GHG allowances and the CARB-auctioned allowances, it will be interesting to see whether today’s auction prices clear closer to the floor price or the recent bilateral price.

The Math of Cap-and-Trade: Implications for Power and Refinery markets

During 2013 and 2014 the Cap-and-Trade Program covers electricity generators, electricity importers, refiners, and large industrial customers.  Beginning in 2015, it will encompass all natural gas consumption (e.g., LDCs) and transportation fuels.  We’ll talk more about the significance of the 2015 program expansion in a subsequent edition of this blog series.  But first, we should examine the math of allowances.  Specifically, how the costs of cap-and-trade are translated into energy production costs and thus prices.

Let’s first consider the financial impact of carbon pricing on California’s power generation industry.  You can think of GHG allowances as simply another input into the production process.  The key number to remember is that one MMBtu of natural gas produces 0.05316 tons of carbon when it is burned.  To translate this into power prices we need to know something about California power gen heat rates. (For background on heat rates, see the RBN blog titled Talkin bout My Generation). 

In southern California year-to-date (YTD), the marginal generating unit averaged a 9.8 heat rate [2].  That means that it takes that power generator 9.8 MMBtus of natural gas to produce one MWh of electricity.  Multiplying its heat rate of 9.8 (MMBtu per MWh) times the carbon constant of .05316 (tons per MMBtu) gives you 0.521 tons of carbon per MWh.  Since one allowance enables you to emit one ton of carbon, that marginal generating unit needs about half of an allowance per MWh.  The spot price of allowances YTD has been $14.67 ($ per ton).  Multiply the 0.521 (tons per MWh) times the $14.67 ($ per ton) and you get  $7.65 per MWh.  The YTD on peak power price in Southern California has averaged $45.80 per MWh which means that without carbon pricing it would have been $38.15 per MWh. Consequently the carbon regulations have increased power prices in Southern California by 20%.  It’s just math.

The same thing happens in the refinery sector.  Here we’ll base the math on the relationship between emissions and crude oil throughput.  In 2011 the refinery sector emitted 33.4 million metric tons of carbon (more details on emissions history for all the industries covered in subsequent editions of this blog series).  During 2011 California refined 1.6 MMb/d of crude oil, or 586 MMBbl for the year. That means on average, a refiner emits 0.06 tons of carbon per barrel of oil refined.  To turn that into $ per barrel, you simply take the 0.06 tons per barrel and multiply it by the YTD carbon price of $14.67 per ton and you get $0.84 per barrel of throughput.  That’s a cost that refiners in other parts of the country don’t have to pay.

Is that really true?  The refineries got their first tranche of allowances for free, so that $.84 per barrel is not a real cost yet, right?  Wrong.  The refineries can either use their allowances or sell them.  If they sell them, they keep the money.  So it’s an opportunity cost.  Any crude throughput they don’t run produces an allowance they can sell.  Among other implications, that fact would suggest that it doesn’t make sense to produce gasoline at California refineries for export out of state.  Fortunately that’s a fact we can check.  Our friends at the California Energy Commission prepare the Weekly Fuels Watch Report that tracks that statistic.   If you go to the site and run the most recent week’s data, you’ll see that refinery production of non-California gasoline has dropped by 38% YTD.  We don’t think that’s a coincidence.

This is a Big Deal for Energy Markets – Even Those Outside of California’s Borders

So far we’ve just given you a taste for the market implications of cap-and-trade.  The impact will go much further.  It will impact regional natural gas demand and basis.  Companies will shift the locations where crude oil is processed.  Power imports into the California market from the Pacific Northwest will soar.  Factors like weather and hydroelectric production will influence the price of allowances, which will launch a domino effect across all sorts of energy markets and energy intensive industries.  In the next edition of this blog series on cap-and-trade we will look at these impacts, assess the various industries covered by cap-and-trade (both now and in 2015 when the program coverage more than doubles), and examine a forecast for allowance prices for the 2013 calendar year.  We’ll also review the trading in today’s auction to see what clues it gives us to the future value of allowances.

Avast, me hearties.  There’s a lot of booty out there if you are willing to master the ways of Cap'n Trade. 

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[1] Cap and Trade is not a new idea. US power generators have participated in a successful cap and trade market for “acid rain” sulfur dioxide and nitrogen oxide emissions (aka “sox” and “nox”) since the late 1990’s. The European Union launched a carbon cap and trade market in 2005 known as the Emissions Trading System (ETS).

2] In the California power market (and most other regional power markets) generating units are dispatched in order of variable cost. The marginal generating unit is the highest cost unit needed to meet load – thus the heat rate for that unit sets the price for all power in the market.

Note: Annual Talk-like-a-Pirate day is September 19th.  We’ll be doing a special Cap’n Trade roundup on that day, for sure.

 

Each business day RBN Energy releases the Daily Energy Post covering some aspect of energy market dynamics. Receive the morning RBN Energy email by signing up for the RBN Energy Network.

 

Comments

It appears to me that it is having an impact of the western coal markets. California imports @25% of its electricity demand. As a result AZ, UT, CO, MT, WY are all net power exporters and generate a lot of their power from coal. The Cap and Trade law covers power marketers as well.  The YoY comps for coal production are much worse in these states 30%+ in most cases even though the cheapest coal.  First the PNW Hydropwer production in the last 3 months was better than last this could be a reason.  But I believe the drop in the coal production is more due to CA cap and trade.  

The increased califronia power demand and price has not resulted in increased production in CA. The power marketers who import power generated from coal plants are affected the most.  It would make sense for them to 1. switch to NG sources 2. buy credits from the CA utilities for the rest of the coal production. I believe this imoposed switching along with the permanent retirement coal plants net 5GW and new NG 7GW has resulted in sustained EIA drawdowns that are above what the rescom numbers indicate. 

It appears Cap and Trade + the permanent changes in powergen mix are resulting in 2+bcfd consumption in NG and this will be the case even if the NG prices go up.  As the new NG plants are @60% efficient much higher than the 44% number used in this article.  And cap and trade raises coal price more than NG, 2.5 x NG increase. 

If my observation are true it makes sense that the CA utilities are not increasing production.  Their increase is penalized but not their status quo. So they sold their credits. So cap and trade has increased the price by increasing the cost for the power importers.  Its reflected in the data, the prices have not gone up as they do in your math it close to 1/2 that in Socal and not changed in Norcal.  Socal is hurting because of SONGS so they have to buy incremental NG/Coal power.  

If this turns out to be true, cap and trade is doing what it's meant to do.  I'll look for evidnece in the next Electricity report.    

Do you see evidence of this switching in the CA periphery states?