First of all, IPAA has some phenomenal statistics available for free. I had previously relied on the Energy Information Administration's data but the IPAA data sets are excellent companion pieces. IPAA also advocates maintaining tax breaks for oil and gas exploration on its Energy Tax Facts site. I'd prefer to eliminate any and all tax breaks for energy exploration because the market needs to price the all-in cost of energy production. I would also eliminate breaks for renewable energy because its costs have pretty much reached grid parity. Eliminating both severance taxes and depletion allowances would make the non-renewable energy sector's project economics more transparent.
Let's talk about hedging for a moment. Lots of hydrocarbon producers like to hedge the price of oil with futures contracts. Exploration and production (E&P) companies in the upstream sector hedge against declines in the price of West Texas Intermediate (WTI) crude because a price drop will hurt their revenue. I can see how operators who have committed free cash flow to a capex program would not want to see their drilling interrupted by commodity price swings. Hedging makes a bit less sense for operators who have committed to a perpetually rising common stock dividend. That kind of corporate policy can hamstring management and set investors up for disappointment if the hedging strategy cannot sufficiently protect earnings. Most E&Ps hedge most of their projected production. Swaps seem to be the most popular instrument but some companies use costless collars. That's my anecdotal impression, anyway.
Energy REITs and MLPs also hedge prices (again, to support their expected dividend) and some of them even hedge interest rates because they borrow to acquire new producing properties. They hedge prices to make their payouts more predictable. Investors have to live with that predilection, but it makes less sense to me than producers who hedge prices. Do E&Ps hedge interest rates as well as prices? They certainly borrow for capex.
I'm agnostic on whether North American oil producers should hedge their production against WTI prices or Brent prices. It may depend on where the companies market their crude. Crude shipments to the Americas are often priced in WTI quotes while production in Asia and the Middle East is priced in Brent. The Brent-WTI spread matters to investment banks, hedge funds, and energy traders whose arbitrageurs play the price differential. Bloomberg has a decent rundown of common energy prices; arbitrage away, hedgies. The CME Group has the most transparent energy derivative prices I could find, including contracts for both WTI and Brent. Futures and other derivatives have enormous risks and I've never used them in my own portfolio. I would rather leave them to energy supermajors who have complex value chains to hedge.
MLPs have it easier than E&Ps. Older wells with long, slow decline curves fit MLPs very well because they need little additional capex other than basic maintenance. That's why MLPs use debt to acquire existing wells rather than putting in capex. I agree with the common MLP claim that low barrel per day (bpd) producing wells are ideal for their structures. I've heard some MLPs describe their avoidance of incentive distribution rights (IDRs) as a selling point to the investing public. I really think MLPs will have a field day buying low-producing shale wells at cheap prices once the Bakken boom fades away.
Some E&P companies tout their natural gas liquids (NGL) production. Investors need to remember that NGLs are more difficult to hedge because they require longer futures contracts (about 12-18 months). A web search for "NGL derivatives" did not reveal any central exchange for them that I could find, but some energy trading firms specialize in constructing private swaps for NGLs. The lack of liquidity for these financial derivatives means NGL swap prices can easily affect real-world NGL prices.
Energy MLPs do have to worry about Unrelated Business Income Tax (UBTI) and they report this on the K-1 form they send to their investors. I had previously thought that holding a high-yielding MLP in a tax-advantaged retirement account would be a smart move until I realized that UBTI may trigger a tax liability. Index funds and ETFs that invest in MLPs do not have this UBTI drawback for an IRA. An MLP that produces zero or negative UBTI poses no apparent problem for an IRA. It pays to know the rules in IRS Pub 598 and it pays to read an MLP's documents. I am not a tax advisor, so don't ask me what to do.
If you're sick of hearing about fracking and horizontal drilling, there's a new drilling technique called "down spacing" coming along. Drillers down space by decreasing the space between wells in an area, which is slightly different from the "pad drilling" concept that erects more than one well on a given land plot. These two approaches fly in the face of one of shale gas's selling points, namely that one drill rig per pad enables the minimum possible surface disturbance. Increasing the rig count on a project also accelerates a field's decline rate. Shale producers need to think hard about how much they can spend on additional engineering to expand recoverable deposits before they go hog wild into down spacing and pad drilling. We're all going to hear a lot more about enhanced oil recovery (EOR) techniques and ways to minimize sub-surface non-productive time (NPT) as more shale plays hit their very steep decline curves.
I don't worry about whether producers have drill-to-earn, produce-to-earn, or shoot-to-earn clauses in their farm-out agreements. Either they produce or they don't. I'm interested in bottom-line results. I don't worry about land value capture because the financing of infrastructure servicing oil/gas fields is less important than whether said fields are economically recoverable. Held by production clauses are good to have if the producer doesn't know how long it will take to bring a greenfield project to maturity.
I'm agnostic as to whether a producer owns a working interest or the entire property; their job is to spend capex on production and someone has to pay the costs of owning wells. I do care about MLPs that focus on royalty interests (especially overriding ones) because that limits their lifetime capex commitment.
Geologists analyze a project's porosity, resistivity, lithology, total organic carbon (TOC), permeability, and isopach subsurface data. I don't look at those things because I'm not a geologist. I'm a finance guy and I need to see financial data. All of the eyewash on soil engineering that energy companies put into their investor relations pitches means nothing if they don't have a budget to turn exploration into production. Geological characteristics will determine the amount of stock tank original oil in place (STOOIP) and its estimated ultimate recovery (EUR).
The EUR of a project deserves a special.discussion. EUR is a mix of oil, gas, and NGLs that is always measured in BOE. Proven reserves includes several engineering terms that do not necessarily comport with financial terms allowed by US securities regulators. Progressing from 1P (proven) to 2P (probable) to 3P (possible) reserves may impress some investors but it does not impress regulators. The SEC has very definite rules for what can and cannot be included in reserves reported in financial statements. This is why producers break down their 1P reserves into proved developed producing (PDP), proved developed non-producing (PDNP), and proved undeveloped (PUD). Using estimates of proven reserves only is the most conservative way to calculate a project's valuation. That's why I read the 43-101 reports of junior resource companies that are registered in Canada. The 43-101 regime allows for "proven and probable" (2P) reserves that I can use to find a valuation.
It's good to know the Baker Hughes US rig count to track the energy sector's health. Producers need to know the day rates of rigs in their region. Analysts track the recycle ratio of an energy company, which the companies themselves often quote as the netback. I have not yet used a recycle ratio in my analysis of energy companies but I will try to apply it in the future. It may even apply to renewable energy companies if it can be measured in kilowatt hours.
I shake my head at shale oil producers who allow their natural gas production to flare off instead of trying to capture it. That is literally money going up in smoke. Producers who care about maximizing ROI on their projects should be willing to spend the capex needed to install temporary pipelines and storage systems that will enable them to capture gas that would otherwise flare off. Orphan gas gets plenty of attention in the midstream sector. Too many shale producers have their eye on the steeply declining production curve and want to get a cash return as quickly as possible. They need to to think more about how capturing extra gas production from a shale play will increase a project's long-term value when it's ready to be sold to an MLP. Don't ask me to figure the difference between wet gas and dry gas; that's a problem for petroleum engineers.
The great thing about reading my blog is that all of the knowledge I gain at conferences and investment seminars is here for free. You people should be entertained by my discussions. I'll take my bow, thank you very much. The next set of IPAA events will give me more opportunities to show off my knowledge.