As much as I travel, I have been fortunate in the past year and a half not to have had any conflicts during the monthly joint web chat for subscribers of The Energy Strategist (TES) and MLP Profits. On the second Tuesday of each month this chat is conducted by Igor Greenwald, managing editor for TES and chief investment strategist for MLP Profits, and myself. This past week, the Mother’s Day snowstorm in Colorado caused me to break my perfect attendance record. I want to thank Igor for carrying on with the chat, and I apologize to subscribers for missing the chat. I try to avoid any sort of travel that day, but this time it was unfortunately unavoidable.  

Igor addressed over 90 percent of the questions that were asked during the chat. There were a few energy-focused questions remaining at the end. Today I will address them, and elaborate on one question he did answer.

Q: There has been speculation that reduced natural gas storage will support prices (perhaps propel them). So far the opposite is true. Do you have any information of net storage over the summer and fall?

This is one that Igor answered, but I want to elaborate. If I am reading the question correctly, the implication seems to be that natural gas prices are relatively weak or that they are weakening. This isn’t the case. What is important to note is that the summer contracts will trade at a lower price than the winter/spring contracts. So as the spring contracts expire, the new contracts will step down in price. When the May contract becomes the June contract, the price will almost always step down because seasonal demand is falling.

One of the people speculating that reduced natural gas in storage will support prices is yours truly. I have been beating this drum for months. What I have argued is that historically low inventories will lead to higher natural gas prices and higher year-over-year profits for natural gas producers. But we have to compare apples to apples, and compare, for instance, a June 2013 contract to a June 2014 contract. As I write this, the June 2014 contract is trading at $4.37 per million British thermal units (MMBtu), which is $0.50/MMBtu higher than the price a year ago. So indeed, low inventories have driven natural gas prices higher and, as we have been predicting for months, natural gas stocks are rallying in response.

For more details on the natural gas inventory picture, see the Weekly Natural Gas Storage Report from the Energy Information Administration. As I write this natural gas inventories are still nearly 50 percent below normal, and natural gas producers are going to have to work hard to make up the deficit throughout the summer. If history is any guide — and thus far it has been accurate — this will be supportive of higher year-over-year natural gas prices, and subsequently higher profits for natural gas producers. But if you compare the June contract with an April contract you will end up with a distorted picture that won’t tell you anything about the year-over-year earnings boost for natural gas producers.

Q: Which Canadian Energy E&P’s are most interesting? How long before Canada’s building of its own East and West Coast pipelines make Keystone irrelevant?

Many people — myself included — have argued that Keystone XL is already largely irrelevant. As project delays dragged on, oil producers sought other routes to market. And it’s becoming even less relevant to Bakken producers, who had planned on using about 100,000 bpd of Keystone XL’s capacity to alleviate logistical bottlenecks in the Bakken. Late last year Continental Resources (NYSE: CLR) CEO Harold Hamm said in an interview: “They just waited too long. The industry is very innovative, and it finds other ways of doing it and other routes.”

Of course Canada will build its own additional pipelines to the coast. TransCanada (NYSE: TRP) — the company behind Keystone XL — is planning a 4,500-kilometer Energy East pipeline that would carry 1.1-million barrels of crude oil per day from Alberta and Saskatchewan to refineries in Eastern Canada. This project alone would be nearly 50 percent larger than the Keystone XL, and will almost certainly get built. The project involves converting an existing natural gas pipeline to an oil transportation pipeline, constructing new pipelines to link up with the converted pipeline, and then building the associated facilities required to move crude oil from Alberta to Quebec and New Brunswick. This pipeline is expected to be in service to Quebec by 2017 and to New Brunswick by 2018. A recent open season for the project received over 900,000 bpd in shipping commitments for 20 years.

Kinder Morgan’s (NYSE: KMI) Trans Mountain pipeline is the only pipeline currently running from Alberta’s oil sands to Canada’s Pacific coast. Kinder Morgan Energy Partners (NYSE: KMP) has filed an application with Canadian regulators that would nearly triple the current capacity of the 300,000 bpd Trans Mountain to 890,000 bpd, and would terminate in Burnaby, British Columbia. The expansion of the current pipeline would be along an existing right-of-way, simplifying the environmental permitting for the project. To date KMP has obtained 710,000 bpd in new long-term shipping commitments from 13 customers. Construction is scheduled to begin in 2016, with incremental product online in 2017. This project would greatly increase the access of Alberta’s oil sands producers to the growing markets of Asia.

There are a number of quality Canadian E&P companies that are attractive at current prices. Among my favorites are Baytex Energy (NYSE: BTE, TSE: BTE), Cenovus Energy (NYSE: CVE, TSE: CVE) and Canadian Natural Resources (NYSE: CNQ, TSE: CNQ) I also like Peyto Exploration & Development (TSE: PEY, OTC: PEYUF) for aggressive investors. We have often discussed putting Peyto in one of the portfolios, but I would ideally like it a bit cheaper.

Q: Is there a public source for the offshore drill rates?

Yes. If you want the most current, comprehensive information, you can find that at RigLogix, which is a premium service of RigZone. But Rigzone does publish a free version of Offshore Rig Day Rates. Depending on your needs, you may find it suitable, although you would likely need to keep up with it on a daily basis to see the trends. They have data for floating rigs, jack-up rigs, and several other types of offshore rigs in the following format:

Source: RigZone

On a related note, for comprehensive information on rig count data, see the Baker Hughes Rig Count page. There is an interactive feature, and you can download historical data up to the present that breaks down the rig count by basin, by state, and by the oil and gas split. The same source also has information on the rig counts in Canada. Here is what the US offshore rig count (96 to 100 percent of which is generally Gulf of Mexico rigs) looked like through May 9:

Q: Any opinion on Kodiak Oil & Gas?

We get asked about Kodiak (NYSE: KOG) a lot. It’s one of those that you look back and would like to have owned over the past five years. Kodiak has indeed been a “10-bagger” over the past five years, and the company has risen from relative obscurity to become one of the 10 largest oil producers in the Bakken.

What gives us pause about the company is the degree of leverage, which works very well when oil prices are as strong as they have been. However, we are concerned about a short-term pullback given the strong advances made so far this year among domestic oil and gas producers. When such a correction happened last fall — just after our warning about that possibility — Kodiak shares fell 24 percent. Some of our mainstay picks fared better during that correction and some, like Continental Resources (NYSE: CLR), have outperformed Kodiak over the past year.

I would pass on Kodiak at the current price. It is already down 10 percent over the past month, but if it pulls back another 10 percent then I think your downside from there is limited, and I like the company quite a bit at that price.

(Follow Robert Rapier on Twitter, LinkedIn, or Facebook.)

Portfolio Update

Chesapeake Chasing Cash

A busy stretch for Aggressive Portfolio holding Chesapeake Energy (NYSE: CHK) culminated Friday with the announcement of yet more asset disposals, notably the spinoff of the oil services division to shareholders by the end of June that will delever the parent company’s balance sheet by $1.5 billion.

Another $1.5 billion in debt relief and sales proceeds is expected from the disposals of a mid-continent drilling subsidiary and of non-core acreage in Pennsylvania and Wyoming.

Meanwhile, Chesapeake’s core acreage in the northern Marcellus fueled the strong quarterly results reported by the company earlier in the month, which comfortably exceeded Wall Street’s expectations and let management to boost its annual cash flow forecast by $700 million, or 13 percent.

As polar cold gripped the Northeast for much of the first quarter, Chesapeake sent 30 percent of its northern Marcellus gas production to a wholesale hub supplying Manhattan, where it fetched a premium of 65 percent or so to the quoted NYMEX benchmark price. This generated $210 million in incremental cash flow, underscoring the value of Chesapeake’s reserved capacity on the third-party pipeline to the hub. Similarly, the company’s reserved capacity on the ATEX ethane pipeline linking the Marcellus and the Utica to the the Gulf Coast is responsible, in part, for strong growth in revenue from natural gas liquids.

Crude production is also running above modest growth expectations set earlier in the year, and the company is targeting overall production growth of 9 to 12 percent this year, adjusted for disposals. Put another way, production not adjusted for the disposals should equal last year’s despite the sale of properties accounting for more than 10 percent of last year’s output. In that span, Doug Lawler, the CEO installed last year to save an overextended, debt-laden empire, has ruthlessly cut costs while shifting resources to the much more lucrative liquids production. As a result, first-quarter EBITDA was up 34 percent year-over-year while capital spending declined 50 percent (bad weather played a part) without undermining the longer-term growth outlook.

Chesapeake’s debt load remains stubbornly high, but the latest deleveraging initiatives will help, and the CEO has signaled that further asset sales are likely.

Lawler’s made no secret recently of his ambition to use the proceeds from strong growth in such prime  domestic shale basins as the Eagle Ford to turn Chesapeake into a global shale explorer over the longer term. But for now the dream of international expansion depends on domestic shrinkage.

The stock briefly set a new two-year high following the strong earnings news, then fell back to hover just above our buy limit and the upper end of the base it has built since last summer. We’re still up 39 percent on this recommendation since last May, and expect more to come. Buy CHK on dips below $28.         

— Igor Greenwald