American Oil and Gas Reporter - September 2020 - 51

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SpecialReport: Permian Powerhouse

Getting Back To Work

TOM JORDEN
CEO
Cimarex Energy

Q:

In your second-quarter conference call you stated,
"Although we are not out of the woods yet, we are

sufficiently confident in the stability of the commodity
markets to get back to work." You have already added a
couple rigs in the Permian. What are your near-term Permian
drilling plans and when will you start calling frac spreads
back into action? What projects are at the top of the list for
drilling/completion through year's end?
JORDEN: By the end of September, we plan to have four
drillings rigs and two completion crews working in the Delaware
Basin (increasing from one rig and no completion crews at the
start of summer). There is no "picking up where we left off"
before the OPEC+ price war and COVID-19 pandemic. We
have seen a reset in costs, well design and capital planning. In
particular, the price shocks from the price war/pandemic have
caused us to take a fresh look at our long-term plan in light of
our interests in generating free cash flow and strengthening our
balance sheet.
As always, return on capital is our primary criteria for prioritization. Consistent with this, we plan on drawing down a
portion of our drilled but uncompleted well inventory as we
look ahead. We don't have a large DUC inventory. We strategically
use DUCs to ensure operational flexibility when running multiple
rigs and frac crews, but we never "bank" DUCs. Our mindset is
that we do not want to store opportunity. Once a well is drilled,
our goal is to get cash flow started, assuming we can prudently
build facilities and market the production. We will exit 2021
with fewer DUCs, but our DUC inventory is not expected to be
higher than 40 at any point.

Q:

Give us a sense of how your plans for the back end
of 2020 position Cimarex for success going forward.

You have noted that Cimarex is basing its plans for 2021 and
beyond on $35/bbl oil and $2.50/Mcf gas prices. What are
the keys to maintaining your production base and generating
cash flow at $35 oil? How do you anticipate higher gas
prices "sweetening" well economics in Delaware Basin wells?

JORDEN: The $35 oil and $2.50 gas prices are the base case
for planning. Under these price assumptions, we can maintain
an active capital program, grow our dividend and generate
excess free cash flow. Fortunately, we think we will be able to
generate single-digit oil production growth at this level. The
key elements are successful execution, ongoing cost control,
improving well performance and fiscal discipline.
The $2.50 gas price is a NYMEX index price. As we all
know, realized prices were horrible during the first half of
2020, occasionally going negative. As we look ahead into 2021,
at current strip prices, our realized Permian price should be
north of $2.00/Mcf. We produce a lot of gas, so increased gas
prices are significant to cash flow generation. At the wellhead,
the gas stream includes gas and natural gas liquids, so you can't
talk about gas without considering NGLs.
In recent years. oil has accounted for 60%-70% of our total
cash flow, even though it was a much smaller percentage of our
total production volume (Cimarex produced 185,700 barrels of
oil equivalent a day in the Permian in the second quarter, with
oil volumes averaging 68,800 bbl/d). With higher prices, gas
and NGLs would become a greater percentage of cash flow.
Higher gas prices would also make our Anadarko Basin assets
more attractive, but not necessarily in contrast to the Delaware
Basin. A rising tide lifts all boats in our portfolio.

Q:

Cimarex shut in 20% of its production volumes last
spring after analyzing reservoir performance and

concluding that the majority of your wells could be shut in
without damaging productivity. All those wells are now back
on production. How are they performing? Did you gain any
insights about your reservoirs and completion designs through
the shut-in/restart processes?
JORDEN: Our technical teams studied our reservoirs prior
to our shut-in decisions and concluded that, with few exceptions,
we could shut in or curtail production without exposing ourselves
to any long-term reservoir damage. This was an important
finding, for it meant that we could make shut-in and curtailment
decisions solely based on economic and lease considerations.
As we have brought our wells back on line, we have not
observed any significant performance degradation owing to the
shut ins and curtailments.
With the goal of having positive cash flow for each well, we
spent a lot of time looking at the total cost structure of our wells
and identifying how much of that cost was fixed versus variable.
We made shut-in decisions based on variable costs because that
SEPTEMBER 2020 51



American Oil and Gas Reporter - September 2020

Table of Contents for the Digital Edition of American Oil and Gas Reporter - September 2020

Contents
American Oil and Gas Reporter - September 2020 - Intro
American Oil and Gas Reporter - September 2020 - 1
American Oil and Gas Reporter - September 2020 - 2
American Oil and Gas Reporter - September 2020 - 3
American Oil and Gas Reporter - September 2020 - 4
American Oil and Gas Reporter - September 2020 - Contents
American Oil and Gas Reporter - September 2020 - 6
American Oil and Gas Reporter - September 2020 - 7
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