What's new in production

As much as I used to love to ride roller coasters, after more than four decades in the upstream business, experiencing the inevitable oil price roller coaster, I’m no longer a fan! Companies need to make tough decisions to survive—decisions that ultimately may diminish their ability to capture opportunities when oil prices go up again, as they inevitably do. The oil price cycle is a given; the wavelength and amplitudes are the unknowns.

Corporate survival actions all come down to the economics of individual development prospects or fields. If you’re on a Producing Team (Production Superintendent or Production Engineer), assigned to a producing field, you should always be prepared for the inevitable downturn.

How does a Producing Team prepare for industry downturns? I can think of three ways.

First, understand each well’s performance. This is no great epiphany to most of you. It’s one of the basic duties of a Production Engineer. However, I submit to you that this effort should not be based solely on past well performance, but also on all the parameters that influence flow potential. Benchmark against physics! Evaluate a well’s theoretical performance. Should a well’s actual performance deviate from its theoretical performance, diagnose the problem and propose a solution. Investigate ways to bring a well up to its full potential; increase the Productivity Index; optimize artificial lift; optimize the entire production system using nodal analysis.

Second, understand each well’s economics. It is not uncommon to give a team responsibility for production levels and expense at the field level—these are the only parameters that can be controlled by the field. Because they cannot control product price, they are not held accountable for revenue or field profitability. That responsibility rests higher in the organization.

The Production Superintendent does control operating expenses to ensure they are appropriate. Sometimes, these expenses are broken down to field or lease level—seldom to well level. The producing team should know which wells are “bad actors” in terms of profitability; frequent well work, high utility usage, high water disposal costs, high downtime.

Producing teams routinely handle problems, such as a well going off production, or an unexpected increase in a well’s water/oil ratio, where the water disposal cost makes that well uneconomic to produce.

Third, when “really bad things” happen, like the drastic oil price drop that we’ve experienced recently, being prepared is a must. In such cases, a producing team should look outside its usual toolbox for solutions. Here’s one.

Understand (and optimize) how your field and wells contribute to corporate financial performance, well beyond the usual cash flow model reflected in the Field Production and Controllable Expense Report. Understand how the assets (wells) you operate add value to the corporation beyond cash flow. Understand how each well contributes to the corporation’s financial performance—income and earnings per share. This may sound like overkill, but I’ve seen this approach be extremely helpful.

Appreciating depreciation. Depreciation of assets is a “corporate accounting” thing that producing teams usually don’t worry about, as it is not controllable by producing teams—or is it?

In theory, a financial statement for a well would look something like this:

Revenue = Production x Product Price

Profit = Revenue – Direct Production Expenses

Income = Profit – Depreciation

Income → Earnings Per Share → Stock Price

Producing teams typically look only at revenue and expenses. However, understanding each well’s depreciation status may yield some opportunities.

Accounting standards (not for income tax calculations) dictate that the capital expenses incurred in developing reserves are to be depreciated on a Unit of Production (UOP) basis. For example, if your company spends $10 million of capital developing 1 MMbbl of recoverable oil, then there is a $10/bbl UOP burden on your production. For every barrel produced, the corporation must deduct $10 from revenue to calculate corporate Income. This UOP is how the corporation “pays back” the $10 million it spent developing those reserves. NOTE: This is different from reserves depletion.

When you lower a well’s operating expense, its economic production limit decreases. That means that as a well’s output naturally declines, it can stay on production longer—beyond the time used to estimate recoverable reserves. The reserves recovered during that extra time, when booked, change the UOP depreciation calculation. If, for example, the extra production due to the lower economic limit is 100,000 bbl of oil, and you have already depreciated half of the $10 million, the new UOP for the remaining $5 million will be based on 600,000 bbl, rather than 500,000 bbl, or $8.33—a savings of $1.67/bbl. Of course, you’ll have some additional operating expense.

Similarly, if a producing team can increase a well’s producing rate and, therefore, its Estimated Ultimate Recovery, then UOP can be decreased.

The idea is to think past cash flow into the realm of corporate accounting practices. When a Producing Team can increase a well’s production rate or decrease operating expense, there are three potential, positive outcomes: 1) increase cash flow; 2) increase reserves; and 3) increase income by decreasing UOP.

Producing Teams should take the initiative to engage their financial folks to expand their thinking beyond conventional cash flow models into the realm of corporate financial performance. You might find the effort rewarding.