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Mick & Associates
Oil & Gas Developments
May 22, 2015
We have prepared this newsletter in an effort to keep you informed of developments affecting oil and gas activities, which in turn can impact revenues
and returns of non-traded oil and gas programs.
In this newsletter, we will focus our attention upon drilling activity patterns observed across the U.S., and we will provide you with an update of energy
market developments. We have also provided some commentary about the widespread use of leverage in the oil and gas industry and the importance of monitoring
sponsor leverage as a part of the due diligence process.
In general, drilling activities in most “major” onshore U.S. basins slowed over the past couple of months due to reduced oil prices. For the week ending
May 15, 2015, Baker Hughes reported a total onshore U.S. well count of 850 rigs, which is 54.33% lower than the count of 1,861 rigs reported a year
A table explaining the comparative rig count trends within fourteen major onshore U.S. basins is provided in the following table:
Baker Hughes Rig Count May 15, 2015 – Table Covers 14 Major U.S. Onshore Basins
While drilling activities have slowed in a substantial majority of the onshore U.S. basins, an anomaly to this pattern can be observed in relation to the
Woodford Shale Play situated in Oklahoma. As a collective whole, the three areas that comprise the Woodford Shale Play have collectively experienced
a 33% increase in rig activity year-over-year, with the Cana Woodford region of the play accounting for the increased activity. While the level of
retail sponsor investment activities within the Woodford has been rather limited in recent years, this play has received attention in recent years
from Resource Royalty, LLC and BRG Energy. Our assessment as to why drilling in the Cana Woodford has increased over the past year is due to three
The presence of liquids rich gas reservoirs with improved economics due to cost cutting
The presence of fields with moderate drilling depths and an ability to significantly reduce costs (i.e., drilling and production) with sizeable reserve
potential (with most of the Woodford drilling occurring in the core Tier I acreage positions of the play according to our technical consultants)
Devon, Cimarex, and other rig operators leaving the Eagle Ford to focus more upon the Cana Woodford
We would mention that certain other gas-liquids basins that were down moderately (e.g., 10%) a few months ago are now down 20-40%, such as Utica Shale
(-39%) and Marcellus Shale (-20%), as operators in many areas of these basins may not have been able to reduce costs as much as in the Cana Woodford.
Note that basins with higher breakeven drilling and completion costs or a high presence of dry natural gas are very close to shut down – Barnett Shale
(5 rigs, -80%), Granite Wash (16 rigs, -74%), Mississippian Play (22 rigs, -71%)-with only the best acreage and obligatory wells getting drilled in
Major oil basins such as the Permian (-57%), Williston/Bakken (-57%) and Eagle Ford (-51%) are all down fairly consistently and are trending parallel with
activity patterns observed across the U.S. in general. On a final note, the DJ-Niobrara appears to be a “tweener” in terms of activity at -43% due
to having oil and liquids rich gas, shallow drilling targets, and somewhat better economics. On a comparative note, however, the DJ-Niobrara appears
to be more impacted than the Cana-Woodford because the reserves are smaller in a lot of areas.
Interestingly, the geological coverage of many retail sponsors fall outside of the major onshore U.S. basins, although certain sponsors are more concentrated
within the major basins than others. For purposes of aiding you in your due diligence, a table summarizing the geological basins in which certain sponsors
are invested is provided below:
Status of the Oil & Gas Markets
While it is impossible to know for sure what oil and natural gas prices will be in the future, the Energy Information Administration (“EIA”) provides
a summary of market supply and demand developments as well as a forecast of how those developments will affect prices over a 1-2 year period.
The following information was derived from the EIA’s Short-Term Outlook reported on May 12, 2015:
North Sea Brent crude oil prices averaged $60/barrel in April, a $4/barrel increase from March and the highest monthly average of 2015. Despite increasing
global inventories, several factors contributed to higher prices, including indications of higher global oil demand growth, expectations for declining
U.S. tight oil production in the coming months in the wake of rig reductions, and the growing risk of unplanned supply outages in the Middle East and
North Africa. EIA forecasts that Brent crude oil prices will average $61/barrel in 2015 and $70/barrel in 2016. Average WTI prices in 2015 and 2016
are expected to be $6/barrel and $5/barrel below Brent, respectively. Natural gas working inventories were 1,786 billion cubic feet (“Bcf”) on May
1, which was 71% higher than a year earlier, but 4% lower than the previous five year average. The winter withdrawal season typically ends in March,
and April is typically the beginning of the injection season, which runs through October. The EIA projects natural gas inventories will end October
2015 at 3,890 Bcf, a net injection of 2,420 Bcf. This would be the second-highest injection season on record. Low natural gas prices in recent months
have significantly increased the use of natural gas rather than coal for electricity generation. The EIA expects natural gas generation in April and
May will almost reach the level of coal generation, resulting in the closest convergence in generation shares between the two fuels since April 2012.
The EIA's Henry Hub natural gas price forecast averages $2.93/mcf in 2015 and $3.32/mcf in 2016.
On May 21, 2015, the WTI spot price for oil was $60.43 per barrel. According to statistics provided by the EIA, this price point is roughly 40% lower than
the average oil price observed in May 2014 (i.e., $102 per barrel), but is higher than the monthly average oil price observed in the first three months
of 2015 (i.e., $49 per barrel). On May 21, 2015, the NYMEX futures prices for natural gas deliveries in June was $2.95 per mcf, which is lower than
the prices for natural gas generally observed through much of last year (i.e., $3.50-$4.50 per mcf).
In terms of gas prices, please note that different pricing considerations apply currently to the Marcellus Shale Play in comparison to the rest of the
U.S. While the Marcellus has held its own in terms of drilling activities over the past year (as reported in our first newsletter), the greatest operational
challenge to this play right now is the discounts that apply to natural gas prices in the Marcellus in comparison to general market prices, as the
rapid growth of production within the play in the face of pipeline constraints has affected basis differentials in the Marcellus region. While Appalachia
producers used to enjoy a premium to Gulf Coast pricing, the premium disappeared in late 2013. The price premium to the Henry Hub Index steadily declined
since peaking at 110.1% in February 2009, so much that the average of the gas prices began trading at a discount to Henry Hub through much of 2014
(with 20-25% negative pricing differentials reported through much of 2014). Through much of last year and into 2015, the negative pricing differentials
within the western region of the Pennsylvania Marcellus Play have varied from $0.50 per mcf to as high as $1.50 per mcf.
Notwithstanding these pricing challenges, there is another 3.3 bcf/day of pipeline capacity out of the Marcellus that has been announced or under construction.
The factors that will eventually determine whether the additional takeaway capacity will be enough to improve basis differentials in the Marcellus
include the continued pace of drilling in the Marcellus itself, competing supply from the nearby Utica Shale, and the ability of Eastern Canada to
take more supply from the U.S. On a better note, and from a long-term investment perspective, the potential for the Marcellus to become a base supplier
of natural gas worldwide could also potentially bode well for better future gas prices and upside over a longer term investment horizon if natural
gas exporting begins in earnest over the next 3-5 years.
Use of Leverage
What Does it Mean for Sponsors Going Forward
The leveraged nature of the U.S. upstream oil and gas industry is well established. The debt advanced to drillers in recent years is estimated to
be in the neighborhood of $500 billion — some $300 billion in leveraged primary loans and another $200 billion in high yield debt. That’s about
16% of the U.S. high yield debt market, or four times its share a decade ago.
Oil producers' debt since 2010 has also reportedly increased by more than 55%, but revenues have slowed, rising only 36% compared to the 2010 levels according
to the Wall Street Journal. The growing use of leverage in the oil patch was “well accepted” over the past five years in the wake of seemingly stable
oil prices. In the wake of a $50-$60 per barrel pricing pattern since January 2015 and the fact that many U.S. basins require $60 per barrel just to
break even, Monday morning quarterbacking of credit underwriting practices has become rampant in the U.S. media.
From our engagements this year, we have seen early signs of energy lenders taking precautionary steps to reduce their energy loan exposures. In
one case, a redetermination of the sponsor’s producing reserves required a borrowing base reduction of 30% and an immediate cash repayment of about
$6 million. In another case, a fairly significant pre-payment of a low eight figure amount was helpful in keeping the sponsor’s debt within the borrowing
base limit. While these instances resulted in no harm to the sponsors due to their significant capitalizations, what is evident from these developments is that energy lenders take financial covenants and borrowing base determinations very seriously (and in one case noted above, the net worth requirement called for in the loan agreement was increased four-fold as an ongoing condition of keeping the credit line). In cases of smaller sponsors with limited capital reserves, the outcomes might not bode as well for such sponsors and their drilling project investors.
At our energy symposium, two of many due diligence themes we stressed in various education panels included: (i) the importance of careful economic
underwriting of projects using current oil/gas prices, and (ii) the ongoing monitoring of a sponsor’s financial condition. On the positive side, we’ve
seen drilling cost reductions in a number of areas that have helped to improve the economic return potential of the programs reviewed so far. Of equal
importance, however, sponsor financial monitoring should not be taken lightly as the ability to stay in business and execute the drilling/investment plan is likewise a critical part of the review process. Some helpful financial ratios that we often review in this regard are explained below:
Debt to EBITDA. This leverage ratio measures a company's ability to pay off its incurred debt. Since oil and gas companies typically have
a lot of debt on their balance sheets, this ratio is useful in determining how many years of EBITDA would be necessary in order to pay back all the
debt. In terms of following U.S. companies, it can be alarming if the ratio exceeds three or more (and many energy lenders, in fact, impose a three-to-one
ratio as a financial covenant requirement). In Canada, where leverage is scrutinized cautiously, ratios of 2.0 or greater have been known to be viewed
with a jaundiced eye in terms of equity market acceptance.
Interest Coverage Ratio. The interest coverage ratio is used by oil and gas analysts to determine a firm's ability to pay interest on outstanding
debt. The greater the multiple, the less risk to the lender and typically, if the company has a multiple higher than one, it is considered to have
enough capital to pay off its interest expenses. An oil and gas company should cover its interest and fixed charges by at factor of two, or even more
ideally, three to one. If not, its ability to meet interest payments may be questionable.
Debt to Asset Ratio. This ratio is a measurement of a company's financial leverage and is arguably one of the more meaningful ratios because
it focuses on the relationship of the total liabilities as a component of a company's total capital base. Debt includes all short term and long term
obligations. Both current and long term assets are also considered in the analysis. The ratio is used to evaluate a firm's financial structure and
how it's financing operations. Typically, if a company has a high debt-tocapital ratio amongst its peers, then it may have an increased default risk
due to the effect the debt has on its operations. In the public eye, the oil industry seems to have about a 40% debt-to-asset threshold. In the private
arena, we tend to be concerned in cases where the total debt is 70% of a company’s assets.
We hope that you have found this newsletter to be informative. In view of the status of oil/gas markets, we will provide ongoing newsletters periodically
in an effort to inform you of what is happening in the oil and gas industry in 2015. If there are certain topics you would like for us to address in
upcoming newsletters, please let us know.
Bryan Mick, JD, MBA
Bradford Updike, LLM, JD