American Oil and Gas Reporter - May 2016 - 41

ciated production, if a company wishes
to leverage its existing producing properties, it should be able to obtain a traditional oil and gas revolving credit facility,
so long as it has capital support to fund
drilling to hold the acquired acreage with
production. This can provide financial
support for both development drilling
and acquiring acreage.
Borrowing Requirements
For the most part, banks lend on PDP
production, leaving developmental risks
to mezzanine or equity providers. Because
banks want their financing to be used
primarily for development activities,
acreage typically is acquired either through
equity financing or obtained through a
"promote" structure in which working
interest partners are brought in for a
portion of the interests to cover the cost
of developing the acreage. Having the
support of a private equity fund can make
a meaningful impact for both public and
private companies, but access to equity
is severely hampered during periods of
low commodity prices.
There are several advantages associated
with using bank debt, including the fact
that banks are the cheapest source of capital.
Other advantages include interacting with
a financial partner that may provide advice
in many fields to help an oil and gas company operate more efficiently or acquire/divest assets. The disadvantage is that there
are many conditions that need to be met in
order to qualify for bank debt.
The bank must be comfortable with
the management team, the assets (i.e.,
collateral), and the credit metrics of the
borrowing company. An open dialogue is
critical in establishing and fostering a
trusted relationship between the producer
and the bank, including utilizing the banker

as an adviser. A good banking team should
be open to evaluating all opportunities,
and even if a deal is not a right fit, should
be willing to point the operating company's
management in the right direction.
The second and third points are a bit
more challenging. Assuming a transaction
is secured by reserves or assets such as
pipeline systems, the bank will be willing
to advance only a certain rate based on
the secured assets. The borrowing company
must work proactively to understand what
the bank is willing to lend on a targeted
acquisition so that it understands what
level of equity might be involved.
The pre- and post-transaction credit
metrics of the borrower also must be acceptable. Given the latest OCC energy
lending guidelines, banks are looking for
companies with low leverage (less than
3.50 x cash flow leverage), and in most
cases, the capacity to repay the loan
within the half-life of the assets on both
a pre- and post-transaction basis.
Without production, pipelines, storage
facilities and processing plants would
have no purpose, and without midstream
assets, production would have no market.
Given the connection between midstream
assets and producing properties, producers
often join in owning midstream facilities.
Banks understand the value that a midstream asset generates when it is tied to
production, and typically include the midstream asset in a financing package.
However, stand-alone midstream assets
or "speculative" midstream assets not already tied to production would be difficult
to finance without a large equity position
in the asset and/or a strong equity guarantee of the credit facility.
Contrasted to a few years ago when
growing volumes of production made
processing and transportation very prof-

itable, today's lower prices are trimming
margins for midstream facilities through
both lower service rates and decreased
throughputs as producers cut drilling activity. To the extent that upstream A&D
transactions generate additional development and production, the activity should
be good for midstream facilities.
Midstream assets often are included
when the fields they service are sold. As
those package deals transfer ownership,
it may be possible for the midstream
asset to be sold and recapitalized by new
investor groups, which can take advantage
of the tax benefits often available to
owning midstream assets.
❒
Editor's Note: The author acknowledges Mutual of Omaha Bank's energy
team members for their contributions to
the preceding article.
MIKE TURNER is area president
at Mutual of Omaha Bank in Houston,
focused on oil and gas, marine, and
oil field services companies, as well
as companies in other middle-market
commercial and industrial sectors.
With four decades of banking and investment experience, he previously
served in management positions with
Regions Bank, Texas Commerce Bank
(Chase), Team Bank, Bank One, and
Mezzanine Capital. Turner is on the
advisory board of directors for the
University of Texas Health Development
Board, The University of Texas MBA
Investment Fund, LiftFund, and the
Holocaust Museum Fundraising Committee. He holds a B.S. in finance from
Lamar University and a degree from
Southern Methodist University's Southwest Graduate School of Banking.

Hedging Acquisitions Protects Both Parties
Hedging the production on acquired
assets reduces commodity price risk
to both the producer and lender in
good times and bad. The challenge for
producers is to make sure hedging programs protect against the downside of
declining product prices without limiting
the revenue growth upside of increasing
prices.
Because hedging considers the operator's expected production levels,
there must be a reasonable expectation
of production (along with capital spending requirements and funding capabilities), which can be difficult to predict

if a producer is actively buying and selling
producing properties.
Lenders need to consider the type of
hedges entered into by the producer.
Some hedges do not create a true floor
price, which does not give the lender
much protection. Also, care should be
given to selecting the hedge counterparty
to ensure its financial viability, since the
lender will share a collateral position
with that counterparty on the production
subject to the hedge contracts.
Lenders typically prefer at least 50
percent, but not more than to 90 percent,
of expected production to be hedged for

at least 24 months. A period shorter
than 24 months would provide less
than 1.5 years of price protection
relative to the borrowing base value,
since cash flows are rolled forward to
the next semiannual borrowing base
redetermination period. A hedge period
longer than 24 months generally is acceptable to lenders, although it is not
preferred by oil and gas management
teams, which prefer to hold out for
higher future values, rather than locking
in a fixed spread on their profits for a
lengthier period.
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MAY 2016 41

American Oil and Gas Reporter - May 2016

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