Ite
m 1.
Business
General
Whiting USA Trust II (the “Trust”) is a statutory trust formed on December 5, 2011 under the Delaware Statutory Trust Act, pursuant to a trust agreement (the “Trust agreement”) among Whiting Oil and Gas Corporati
on (“Whiting Oil and Gas”), as T
rustor, The Bank of New York Mellon Trust Company, N.A., as
T
rustee (the “Trustee”)
,
and Wilmington Trust, National Association, as Delaware Trustee (the “Delaware Trustee”). The initial capitalization of the Trust estate was funded by Whiting Petroleum Corporation (“Whiting”) on December 8, 2011.
The Trust maintains its offices at the office of the Trustee, at
601 Travis Street, 16
th
Floor
,
Houston
, Texas 7
7002
. The telephone number of the Trustee is
512-236-6599
.
The Trust makes copies of its reports under the Exchange Act
available at
http://
w
hiting
whz
.investorhq.businesswire.com
. The Trust’s filings under the
Exchange Act are also available electronically from the website maintained by the
SEC
at
http://www.sec.gov
.
In addition, t
he Trust will provide electronic and paper copies of its recent filings free of charge upon request to the Trustee.
As of December 31, 20
11
, the Trust had no assets other than a de
minimis
cash balance from
its
initial capitalization and had conducted no operations other than organizational activities.
I
n
March
20
12
, the Trust issued
18,400,000
units of beneficial interest in the Trust (“Trust units”) to Whiting in exchange for the conveyance of
the
NPI
by Whiting Oil and Gas
.
The NPI represents the right
for the Trust
to receive 90% of the net
proceeds from Whiting’s interests in certain existing oil, natural gas and natural gas liquid producing properties which
are
refe
r
r
e
d
to as “the underlying properties”. The underlying properties are located in the Permian Basin
,
Rocky Mountains,
Gulf Coast and Mid-Continent
regions
of the United States
. The underlying properties include interests in
1,312
gross (
376.7
net) producing oil and gas wells
as of
December 31, 2017
. Whiting completed an initial public offering of Trust units selling
all of its
18,400,000
units
on March 2
8
, 2012.
The Trust units are
currently traded
on the OTC, operated by OTC Markets Group, under the trading symbol “WHZT”
, but the Trust can provide no assurance that any trading market for the Trust units will exist on the OTC in the future or that current trading levels will be sustained or will not diminish.
The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date
,
which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI),
or (b) the sale of the net profits interest. The Trust is required to sell the NPI and
liquidate
if cash proceeds to the Trust from the net profits interest are less than $2.0 million for each of any two consecutive years. During the year
s
ended December 31, 201
7 and 2016
, the Trust received cash proceeds of
$6.7 million and
$1.9 million
, respectively,
from the net profits interest.
After the termination of the Trust, it will pay no further distributions.
As of
December 31, 2017
,
on a
cumulative
accrual basis
7.95
MMBOE
(
75%
)
of the
10.61
MMBOE
attributable to the NPI
have been produced
and sold
or divested.
Further detail on the reserves is provided herein under
the section titled “Properties—
Description of the Underlying Properties—Reserves”, and such reserve information is based upon a reserve report prepared by independent reserve engineers Cawley, Gillespie & Associates, Inc.
for the underlying properties as of
December 31, 2017
, which
is
referred
to as the “reserve report.” According to the reserve report, the portion of the
11.79
MMBOE (
10.61
MMBOE
at the 90% NPI
) reserve quantities attributable to the NPI not yet produced
and
sold
or divested
as of
December 31, 2017
is
projected to be produced from the underlying properties
prior to December 31, 2021
,
which
reserve report is based
on
NYMEX oil and gas prices of $
51.34
per Bbl and $
2.98
per MMBtu
, respectively,
pursuant to current SEC and FASB guidelines and
the
other
assumptions included therein.
T
he
average
NYMEX oil and gas prices
for the month of January 201
8
were $
63.66
per Bbl and $
3.
5
8
per MMBtu, respectively
.
Refer to
“Risk Factors”
in Item 1A of this Annual Report on Form 10-K
for additional discussion. Production from the underlying properties for the year ended
December 31, 2017
was approximately
83%
oil and approximately
17%
natural gas.
Whiting entered into certain costless collar hedge contracts and in turn conveyed to the Trust the rights and obligations to hedge payments under such contracts. All such contracts terminated as of December 31, 2014 (which hedging effects extended through the quarterly payment period covered by the February 2015 distribution
to unitholders), and no additional hedges are allowed to be placed on the Trust assets. Thus, there
are
no further cash settlements on commodity hedges, and the Trust therefore has increased exposure to oil and natural gas price volatility
.
Net proceeds payable to the Trust depend upon production quantities
;
sales prices of oil, natural gas and natural gas liquids
;
costs to develop and produce the oil and gas
;
and realized cash settlements from commodity derivative
contracts. In calculating net proceeds, Whiting deducts from gross oil and natural gas s
ales proceeds, lease operating expenses (including costs of workovers), production
and property taxes,
development costs,
hedge payments made by Whiting to the hedge contract counterparty, maintenance expenses, producing overhead
(all such costs, “production and development costs”)
and amounts that may be reserved for future development, maintenance or operating expenses (which reserve may not exceed $2.0 million at any time)
as
calculated o
n an aggregate basis for all the
se properties
. If at any time
production and development
costs should exceed gross proceeds, neither the Trust nor the Trust unitholders would be liable for the excess costs
.
T
he Trust
,
however, would not receive any net proceeds until future net proceeds exceed the total of those excess costs, plus interest at the
prevailing money market
rate. For more information on the net proceeds calculation,
refer to
“Computation of Net Proceeds”
later in this section
.
The Trust makes quarterly cash distributions of substantially all of its quarterly cash receipts,
if any,
after the deduction of fees and expenses for the administration of the Trust, to holders of its Trust units. Because payments to the Trust are generated by depleting assets and the Trust has a finite life
due to
the production from the underlying properties diminishing over time, a portion of each distribution represents a return of the original investment in the Trust units
, with the remainder being considered as a return on investment. As a result, the market price of the Trust units will decline to zero at termination of the Trust.
T
he Trustee can authorize the Trust to borrow money to pay Trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee, Whiting or the Delaware Trustee as a lender, provided the terms of the loan are similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself
, which may be a non-interest bearing account,
and make other short-term investments with the funds
distributed to the Trust
.
The Trust was created to acquire and hold the NPI for the benefit of the Trust unitholders
pursuant to
the
conveyance to the Trust from Whiting Oil and Gas
.
The NPI is the only asset of the Trust, other than cash
reserves
held for
future
Trust expenses.
The NPI is passive in nature, and the Trustee has no management control over and no responsibility relating to the operation of the underlying properties. The business and affairs of the Trust are
administered
by the Trust
e
e.
Whiting and its affiliates have no ability to manage or influence the operations of the Trust. The oil and gas properties comprising the underlying properties for which Whiting is designated the operator are currently operated by Whiting and its subsidiaries on a contract operator basis. Whiting, as a matter of course, does not make public projections as to future sales, earnings or other results relating to the underlying properties.
Marketing and
Major Customers
Pursuant to the terms of the conveyance creating the NPI, Whiting has the responsibility to market, or cause to be marketed, the oil, natural gas and natural gas liquid production attributable to the underlying properties. The terms of the conveyance creating the NPI do not permit Whiting to charge any marketing fee, other than fees for marketing paid to non-affiliates, when determining the net proceeds upon which the NPI is calculated. As a result, the net proceeds to the Trust from the sales of oil, natural gas and natural gas liquid production from the underlying properties are determined based on the same price that Whiting receives for oil, natural gas and natural gas liquid production attributable to Whiting’s remaining interest in the underlying properties.
Whiting principally sells its oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities. Whiting’s marketing of oil and natural gas can be affected by factors beyond its control, the effects of which cannot be accurately predicted. The table below presents percentages by purchaser that accounted for 10% or more of the oil, NGL and natural gas sales
attributable to the NPI
for the years ended
December 31, 2017
,
2016
and
2015
.
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2017
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2016
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2015
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Plains Marketing, LP
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17%
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16%
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15%
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Chevron USA
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15%
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15%
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15%
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Merit Management Partners I, LP (previously Marathon Oil Corporation)
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14%
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9%
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14%
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Phillips 66 Company
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11%
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11%
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11%
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Whiting does not believe that the potential loss of any of these purchasers presents a material risk because there is significant competition among purchasers of crude oil and natural gas in the areas of the underlying properties, and if the underlying properties were to lose any of their largest purchasers, several entities could reasonably be expected to purchase crude oil and natural gas produced from the underlying properties with little or no interruption to their sales.
Competition and Markets
The oil and natural gas industry is highly competitive. Whiting competes with major oil and gas companies and independent oil and gas companies for oil and natural gas, equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than Whiting, but even financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt to maintain cash
flow. The Trust is subject to the same competitive conditions as Whiting and other companies in the oil and natural gas industry.
Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. Future price fluctuations for oil, natural gas and natural gas liquids will directly impact Trust distributions, estimates of reserves attributable to the
NPI
and estimated and actual future net revenues to the Trust.
In light of the many uncertainties that affect the supply and demand for oil and natural gas, neither the Trust nor Whiting can make reliable predictions of future oil and natural gas supply and demand, future product prices or the effect of future product prices on the Trust.
Description of Trust Units
Each Trust unit is a unit of beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis.
E
ach Trust unitholder has the same rights regarding
each of
his or her Trust units as every other Trust unitholder has regarding his or her units. The Trust units are in book-entry form only and are not represented by certificates.
Periodic Reports
The Trustee file
s
all required Trust federal and state income tax and information returns. The Trustee prepare
s
and
makes available
to Trust unitholders annual reports that Trust unitholders need to correctly report their share of the
Trust’s
income and deductions. The Trustee also cause
s
to be prepared and filed reports required under the Exchange Act and by the rules of any securities exchange or quotation system on which the Trust units are listed or admitted to trading, and
is responsible for causing
the Trust to comply with all of the provisions of the Sarbanes-Oxley Act
of 2002
, including but not limited to, establishing, evaluating and maintaining a system of internal controls over financial reporting in compliance with the requirements of Section 404 thereof.
Each Trust unitholder and his or her representatives may examine, for any proper purpose, during reasonable business hours, the records of the Trust and the Trustee.
Liability of Trust Unitholders
Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General
Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware w
ould
give effect to such limitation.
Voting Rights of Trust Unitholders
The Trustee or Trust unitholders owning at least 10% of the outstanding Trust units may call meetings of Trust unitholders. The Trust is responsible for all costs associated with calling a meeting of Trust unitholders
,
unless such meeting is called by the Trust unitholders
,
in which case the Trust unitholders are responsible for all costs associated with calling such meeting. Meetings must be held in such location as is designated by the Trustee in the notice of such meeting. The Trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the Trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of Trust units outstanding must be present or represented to have a quorum. Each Trust unitholder is entitled to one vote for each Trust unit owned.
Unless otherwise required by the Trust agreement, a matter may be approved or disapproved by the vote of a majority of the Trust units held by the Trust unitholders at a meeting where there is a quorum. This is true
,
even if a majority o
f the total Trust units did not
approve it. The affirmative vote of the holders of a majority of the outstanding Trust units is required to:
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remove the Trustee or the Delaware Trustee;
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amend the Trust agreement (except with respect to certain matters that do not adversely affect the rights of Trust unitholders in any material respect);
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merge or consolidate the Trust with or into another entity;
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approve the sale of assets of the Trust unless the sale involves the release of less than or equal to 0.25% of the total production from the underlying properties for the last twelve months and the aggregate asset sales do not have a fair market value in excess of $
1.0 million
for the last twelve months; or
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agree to amend or terminate the conveyance.
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In addition, certain amendments to the Trust agreement, conveyance
and
administrative services agreement may be made by the Trustee without approval of the Trust unitholders.
Termination of the Trust; Sale of the Net Profits Interest
The
Trust
will
wind up its affairs and
terminate
shortly after the earlier
of
(a) the NPI termination date, which is the later to occur of
(
1
) December 31, 2021, or (
2
) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which
amount
is the equivalent of 10.
61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI),
or (b) the sale of the net profits interest.
After
the
termination of the
Trust, it will pay no further distributions
and the market price of Trust
units
will have declined to zero
.
The remaining reserve quantities are projected to be produced
prior to
December 31, 2021
, based on the Trust’s reserve report as of
December 31, 2017
.
As a result, the Trust is not currently expected to contractually terminate until December 31, 2021, and additional reserves and production attributable to the NPI may be available for
distribution to unitholders between the time that the Trust’s minimum 10.61 MMBOE have been produced and sold and the Trust’s expected termination. However, there is no assurance that this will occur.
The Trust will dissolve prior to the termination of the NPI if:
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the Trust sells the NPI;
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annual
cash
procee
ds to the Trust attributable to the NPI are less than $
2.0 million
for each of
any
two consecutive years;
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the holders of a majority of the outstanding Trust units vote in favor of dissolution; or
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the
Trust
is judicially dissolved
.
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The Trustee would then sell all of the Trust’s assets, either by private sale or public auction, and distribute the net proceeds of the sale to the Trust unitholders.
During the years ended December 31, 2017 and 2016, the Trust received cash proceeds of $6.7 million and $1.9 million, respectively, from the net profits interest
.
Computation of Net Proceeds
The provisions of the conveyance governing the computation of net proceeds are detailed and extensive. The following information summarizes the material information contained in the conveyance related to the computation of net proceeds. For more detailed provisions concerning the NPI, we make reference to the conveyance agreement, which is
filed
as an exhibit to this
Annual Report on
Form 10-K.
Net Profits Interest
The NPI was conveyed to the Trust by Whiting Oil and Gas
o
n
March
28,
2012
by means of a conveyance instrument that has been recorded in the appropriate real property records in each county where the underlying properties are located. The NPI burdens the interests owned by Whiting in the underlying properties.
The conveyance creating the NPI provides that the Trust is entitled to receive an amount of cash for each quarter equal to 90% of the net proceeds (calculated as described below) from the sale of oil, natural gas and natural gas liquid production attributable to the underlying properties.
The amounts paid to the Trust for the NPI are based on the definitions of “gross proceeds” and “net proceeds” contained in the conveyance and described below. Under the conveyance, net proceeds are computed quarterly, and 90% of the aggregate net proceeds
, if any,
attributable to a computation period are paid to the Trust no later than 60 days following the end of the computation period (or the next succeeding business day). Whiting does not pay to the Trust any interest on the net proceeds held by Whiting prior to payment to the Trust. The Trustee makes distributions
to Trust unitholders quarterly when the NPI generates
distributable income
.
“Gross proceeds” means the aggregate amount received by Whiting from sales of oil, natural gas and natural gas liquids produced from the underlying properties (other than amounts received for certain future non-consent operations). Gross proceeds does not include any amount for oil, natural gas or natural gas liquids lost in production or marketing or used by Whiting in drilling, production
and plant operations. Gross proceeds includes “take-or-pay” or “ratable take” payments for future production in the event that they are not subject to repayment due to insufficient subsequent production or purchases.
“Net proceeds” means gross proceeds less Whiting’s share of the following:
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an
y taxes paid by the owner of an underlying property to the extent not deducted in calculating gross proceeds, including estimated and accrued general property (ad valorem), prod
uction, severance, sales, excise and other taxes;
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the aggregate amounts paid by Whiting upon settlement of the hedge contracts on a quarterly basis, as specified in the hedge contracts
, which all terminated as of December 31, 2014
;
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any extraordinary taxes or windfall profits taxes that may be assessed in the future that are based on profits realized or prices received for production from the underlying properties;
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all
other
costs and expenses, development costs
and
liabilities of testing, drilling, completing, recompleting, workovers, equipping, plugging back, operating and producing oil, natural gas and natural gas liquids, including allocated expenses such as labor, vehicle and travel costs and materials other than costs and expenses for certain future non-constant operations;
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costs or charges associated with gathering, treating and processing oil, natural gas and natural gas liquids
(provided, however that any proceeds attributable to treatment or processing will offset such costs or charges, if any)
;
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costs
paid
pursuant to
existing operating agreements
, including producing overhead charges
;
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to the extent Whiting is the operator of an underlying property and there is no operating agreement covering such underlying property, the overhead charges allocated by Whiting to such underlying property calculated in the same manner Whiting allocates overhead to other similarly owned property;
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amounts previously included in gross proceeds but subsequently paid as a refund, interest or penalty; and
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amounts reserved at the option of Whiting for development expenditure projects, including well drilling, recompletion and workover costs, maintenance or operating expenses, which amounts will at no time exceed $
2.0 million
in the aggregate, and will be subject to the limitations described below (provided that such costs shall not be debited from gross proceeds when actually incurred)
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All of the hedge payments received by Whiting from the counterparty upon settlements of hedge contracts and certain other non-production revenues, as detailed in the conveyance,
offset the
production and development costs
outlined above
(such production and development costs excluding the last bullet point above)
in calculating the net proceeds.
Plugging and abandonment liabilities relating to the underlying properties will not be deducted from the gross proceeds in determining net proceeds.
If certain other non-production revenues exceed the operating expenses during a quarterly period, the
use of
such excess amounts to offset operating expenses may be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period when such amounts
, together with other offsets to costs for the applicable quarter,
are less than such expenses. If any excess amounts have not been used to offset costs at the time when the NPI terminate
s
or is sold
, then unitholders will not be entitled to receive the benefit of such excess amounts.
The capital expenditures included in the net proceeds attributable to the underlying properties
are
subject to an annual limitation
that became effective January 1, 2018
.
As a result,
the sum of the capital expenditures and amounts reserved for approved capital expenditure projects for
each
year
beginning in 2018
may not exceed the average annual capital expenditure amount.
The “average annual capital expenditure amount” means the quotient of (x) the sum of the capital expenditures and amounts reserved for approved capital expenditure projects with respect to the three
years
end
ed
December 31, 2017
, divided by (y) three
,
which
amount
equals $3.9 million and
will be increased
annually
by 2.5% to account for expected increased costs due to inflation
beginning December 31, 2017
.
Therefore, the capital expenditures included in the net proceeds attributable to the underlying properties cannot exceed $
4.0
million during the year ending December 31, 2018.
Pursuant to the terms of
its
applicable
joint
operating agreements, Whiting deducts from gross proceeds an overhead fee to operate those underlying properties for which Whiting has been designated as the operator. Additionally,
with respect to
those underlying properties for which Whiting is the operator but
where
there is no operating agreement
in place
, Whiting deducts from the gross proceeds an overhead fee calculated in the same manner
that
Whiting allocates overhead to other similarly owned properties
,
as
is customary in the oil and gas industry
.
O
perating overhead activities include various engineering, legal and administrative functions.
T
he Trust’s portion of the monthly charge averaged
$
372
per month
per active operated well, which totaled
$1.4
million
for the
four
distributions made during the year ended
December 31, 2017
. The fee is adjusted annually pursuant to COPAS guidelines and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers.
In the event that the net proceeds for any computation period is a negative amount, the Trust will receive no payment for that period, and any such negative amount plus accrued interest at the prevailing money market
rate will be deducted from gross proceeds in the following computation period for purposes of determining the net proceeds for that following computation period.
Gross proceeds and net proceeds are calculated on a cas
h basis, except that certain costs, primarily ad valorem taxes and expenditures of a material amount, may be determined on an accrual basis.
Commodity Hedge Contracts
Whiting entered into certain costless collar hedge contracts
to reduce the exposure to volatility in the underlying properties’ oil revenues due to fluctuations in crude oil prices, and to achieve more predictable cash flows
.
Whiting in turn conveyed the rights
and obligations
of
such costless collar hedge contracts
to the Trust
.
A
ll
costless collar hedge
contracts terminated as of December 31, 2014
,
which hedging effects extend
ed
through the February 2015 distribution to unitholders and cease
d
thereafter.
Accordingly, there were no
hedge contracts in place during
any period
presented in this Annual Report on Form 10-K
.
No additional hedges are allowed to be placed on Trust assets
,
and
the
Trust
cannot therefore
enter into derivative contracts for speculative
or trading
purposes.
Consequently, there
are
no
future
cash settlement gains or losses on commodity derivatives, and the Trust therefore has increased exposure to oil and natural gas price volatility.
Additional Provisions
If a controversy arises as to the sales price of any production, then for purposes of determining gross proceeds:
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a
mounts withheld or placed in escrow by a purchaser are not con
sidered to be received by Whiting until actually collected;
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amounts received by Whiting and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to Whiting by the escrow agent; and
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amounts received by Whiting and not deposited with an escrow agent will be considered to have been received.
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The Trustee is not obligated to return any cash received from the NPI. Any overpayments made to the Trust by Whiting due to adjustments to prior calculations of net proceeds or otherwise will reduce future amounts payable to the Trust until Whiting recovers the overpayments plus interest at the prevailing money market
rate. Whiting may make such adjustments to prior calculations of net proceeds without the consent of the Trust unitholders or the Trustee
,
but is required to provide the Trustee with notice of such adjustments and supporting data.
In addition, Whiting may, without the consent of the
T
rust unitholders, require the Trust to sell the net profits interest associated with any well or lease that accounts for less than or equal to 0.25% of the total production from the underlying properties in the prior 12 months, provided that the net profits interest covered by such releases cannot exceed, during any 12-month
period, an aggregate fair market value to the Trust of $
1.0 million
. These releases will be made only in connection with a sale by Whiting of the relevant underlying properties and are conditioned upon the
T
rust receiving an amount equal to the fair value to the Trust of such
portion of the
NPI
. Any net sales proceeds paid to the
T
rust are distributable to
T
rust unitholders
in
the quarter in which they are received.
In 2016 and 2015, Whiting completed divestitures of certain producing and shut-in wells for sales proceeds attributable to the Trust’s interest of $
58,500
and $0.3 million, respectively, which properties had proved reserves of 16.32 MBOE with respect to the Trust’s 90% net profits interest. For further information on these divestitures refer to “Abandonment, Sale and Farm-out of Underlying Properties” in Item 2 of this Annual Report on Form 10-K.
For the underlying properties for which
Whiting
is the
designated operator
,
it
may enter into farm-out, operating, participation and other similar agreements
with respect
to the property. Whiting may enter into any of these agreements without the consent or approval of the Trustee or any Trust unitholder.
Whiting entered into three farm-out agreements with a third-party
partner
for certain underlying properties within the (i)
Keystone South
f
ield located in Winkler County, Texas
in April 2016, (ii)
Signal Peak field located in Howard County, Texas
in February 2017 and (iii) Flying W, SE field located in Winkler County, Texas in March 2017
. Refer to “Abandonment, Sale and Farm-out of Underlying Properties” in Item 2 of this Annual Report on Form 10-K for additional information related to these farm-out agreements.
Whiting
or any other operator
has the right to abandon any well or property if it reasonably believes the well or property ceases to produce or is not capable of producing in commercially paying quantities. In making such decisions, Whiting is required under the applicable conveyance to operate
, or to use commercially reasonable efforts to cause the operators of the underlying properties to operate,
the underlying properties as a reasonably prudent operator in the same manner it would if these properties were not burdened by the NPI. Upon termination of the lease, the portion of the NPI relating to the abandoned property will be extinguished.
Whiting must maintain books and records sufficient to determine the amounts payable under the NPI to the Trust. Quarterly and annually, Whiting must deliver to the Trustee a statement of the computation of net proceeds for each computation period. The Trustee has the right to inspect and copy the books and records maintained by Whiting during normal business hours and upon reasonable notice.
Federal Income Tax Matters
The following is a summary of certain U.S. federal income tax
matters
that may be relevant to the Trust unitholders. This summary is based upon current provisions of the Internal Revenue C
ode of 1986, as amended, which is
refer
red
to as the “Code,” existing
(
and
to the extent
proposed
)
Treasury regulations thereunder
,
and current administrative rulings and court decisions, all of which are subject to change
or different interpretation at any time, possibly with
retroactive
effect
. No attempt has been made in the following summary to comment on all U.S. federal income tax matters affecting the Trust or the Trust unitholders.
The summary is limited to Trust unitholders who are individual citizens or residents of the United States. Accordingly, the following summary has limited application to domestic corporations and persons subject to specialized federal income tax treatment such as, without limitation, tax-exempt organizations, regulated investment companies, insurance companies, and foreign persons or entities.
Each Trust unitholder should consult hi
s
own tax advisor with respect to his particular circumstances.
Classification and Taxation of the Trust
Tax counsel to the Trust advised the Trust at the time of formation that, for
U.S.
federal income tax purposes, in its opinion
,
the Trust would be treated as a grantor trust and not as an unincorporated business entity. No ruling has been or will be requested from the
IRS or another taxing authority. The remainder of the discussion below is based on tax counsel’s opinion, at the time of formation, that the Trust will be classified as a grantor trust for U.S. federal income tax purposes.
As a grantor trust, the Trust is not subject to
U.S.
federal income tax at the Trust level. Rather, each Trust unitholder is considered for federal income tax purposes to own
and receive
its proportionate share of the Trust’s assets directly as though no Trust were in existence.
The income of the Trust is deemed to be received or accrued by the Trust unitholder at the time such income is received or accrued by the Trust, rather than when distributed by the Trust. Each
Trust unitholder is subject to tax on its proportionate share of the income and gain attributable to the assets of the Trust and is entitled to
claim its proportionate share of the deductions and expenses attributable to the assets of the Trust, subject to applicable limitations, in accordance with the Trust unitholder’s tax method of accounting and taxable year without regard to the taxable year or accounting method employed by the Trust.
On the basis of that advice, the Trust will file annual information returns, reporting to the Trust unitholders all items of income, gain, loss, deduction and credit. The Trust will allocate items of income, gain, loss, deductions and credits to Trust unitholders based on record ownership at each quarterly record date. It is possible that the IRS or another tax authority could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily, prorated or other basis, which could require adjustments to the tax returns of the Trust unitholders affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.
Classification of the Net Profits Interest
Tax counsel to the Trust also advised the Trust at the time of formation that, for
U.S.
federal income tax purposes, based upon representations made by Whiting regarding the expected economic life of the underlying properties and the expected duration of the NPI, in its opinion the NPI should be treated as a “production payment” under Section 636 of the Code,
or otherwise as a debt instrument. On the basis of that advice, the Trust treats the NPI as indebtedness subject to
Treasury
regulations applicable to contingent payment debt instruments, and by purchasing Trust units, a Trust unitholder agrees to be bound by the Trust’s application of those regulations, including the Trust’s determination of the rate at which interest will be deemed to accrue on the NPI. No assurance can be given that the IRS
or another tax authority
will not assert that the NPI should be treated differently. Any such different treatment could affect the timing and character of income, gain or loss in respect of an investment in Trust units and could require a Trust unitholder to accrue income at a rate different than that determined by the Trust.
Reporting Requirements for Widely-Held Fixed Investment Trusts
Some Trust units are held by middlemen, as such term is broadly defined in the Treasury regulations (and includes custodians, nominees, certain joint owners and brokers holding an interest for a custodian street name, collectively referred to herein as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely
held fixed investment trust
(“WHFIT”) for U.S. federal income tax purposes
.
The Bank of New York Mellon Trust Company, N.A.,
601 Travis Street, 16
th
Floor, Houston
, Texas
7
7002
, telephone number
512-236-6599
, is the representative of the Trust that will provide the tax information in accordance with applicable Treasury regulations governing the information reporting requirements of the Trust as a WHFIT. Notwithstanding the foregoing, the middlemen holding Trust units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury regulations with respect to such Trust units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose Tr
ust units are held by middlemen
should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust units.
Any generic tax information provided by the Trustee of the Trust is intended to be used only to assist Trust unitholders in the preparation of their federal and state income tax returns.
Available Trust Tax Information
In compliance with the Treasury
r
egulation
s
reporting
requirements for
non-mortgage
widely-held fixed investment trusts and the dissemination of Trust tax reporting information, the Trustee provides a generic tax information reporting booklet which is intended to be used only to assist Trust unitholders in the preparation of their
2017
federal and state income tax returns. The projected payment schedule for the NPI is included with the tax information booklet. This tax information booklet can be obtained at
http://
w
hiting
whz
.investorhq.businesswire.com
.
On December 22, 2017, Congress passed the Tax Cuts and Jobs Act (the “TCJA”). The new legislation significantly changes the U.S. corporate tax law by, among other things, lowering the highest marginal U.S. federal income tax rate applicable to corporations from 35% to 21% beginning in January 2018 which rate applies to both ordinary income and capital gains. Additionally, the TCJA lowers the highest marginal U.S federal income tax rate applicable to ordinary income of individuals from 39% to 37%. The highest marginal U.S federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and also applicable to qualified dividends of individuals is 20%.
Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income generally will include a Trust unitholder’s allocable share of the Trust’s interest income plus the gain recognized from a sale of Trust units. In the case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such individual’s federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (x) undistributed net investment income, or (y) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.
Environmental Matters and Regulation
The operations of the
underlying
properties are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the
release,
discharge
or emission
of materials into the environment
;
the handling of hazardous materials
;
or otherwise relating to environmental protection
. These laws and regulations may, among other things:
|
·
|
|
require the acquisition of a permit for drilling and other regulated ac
tivities;
|
|
·
|
|
require
the
proper manage
ment
and dispos
al
of waste and
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production activities;
|
|
·
|
|
limit or prohibit drilling activities
in sensitive areas, such as wilderness areas, we
tlands, streams
or areas that may contain endangered or threatened species and their habitats
;
|
|
·
|
|
require
investigatory
or
remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits
,
plug
and
abandon wells and
restore properties upon which wells are drilled;
|
|
·
|
|
apply
specific
health and safety criteria addressing worker protection; and
|
|
·
|
|
enjoin some or all of the operations of the underlying properties deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.
|
Failure to comply with these laws and regulations
may result in the assessment
of
significant
administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental statu
t
es impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, these laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly
well construction, drilling, water
management or completion activities or
waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on the operating costs of the properties comprising the underlying properties.
President Trump has indicated that he would work to ease regulatory burdens on industry and on the oil and gas sector, including environmental regulations. However, any executive orders the President may issue or any new legislation Congress may pass with the goal of reducing environmental statutory or regulatory requirements may be challenged in court. In addition, various state laws and regulations (and permits issued thereunder) will be unaffected by federal changes unless and until the state laws and corresponding permits are similarly changed, and any judicial review is completed.
The following is a summary of the
more significant
existing laws, rules and regulations to which the operations of the
underlying
properties are subject that are material to the operation of the underlying properties.
Waste Handling
.
The Resource Conservation and Recovery Act
, as amended
(“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage
and
disposal of hazardous and non-hazardous wastes. Under
delegations of authority from
the
U.S.
Environmental Protection Agency (“
EPA
”)
the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. In its operations at the underlying properties, Whiting generates solid and hazardous wastes that are subject to RCRA and comparable state laws.
Drilling fluids, produced water
and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. In September 2010, the Natural Resources Defense Council filed a petition with the EPA, requesting them to reconsider the RCRA exemption for exploration, production and development wastes
. In May 2016, several environmental groups sued the EPA for failing to update its rules for management of oil and gas drilling waste under RCRA. The petitioners requested that the EPA revise its regulations for waste materials generated as a result of oil and gas exploration and production activities. The petitioners claimed that the EPA has not reviewed or revised its regulations for management of wastes from oil and gas exploration and production operations since 1988, even though the statute requires the EPA to review and, if necessary, revise the regulations every three years. In December 2016, the court entered a Consent Decree resolving the litigation. Under the Consent Decree, the EPA has agreed to propose no later than March 15, 2019 a rulemaking for revision of the regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. In the event that the EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021.
Any such change in the current RCRA exemption and comparable state laws, could result in an increase in the costs to manage and dispose of wastes, which could have a material adverse effect on the cash distributions to the Trust unitholders.
Comprehensive Environmental Response, Compensation and Liability Act.
The Comprehensive Environmental Response, Compensation and Liability Act of 1980
, as amended
(“CERCLA”)
, also known as the Superfund law
and comparable state laws impose
strict joint and several
liability, without regard to fault or legality of conduct, on classes of persons
who are considered to be responsible for
the release of a
“
hazardous substance
”
into the environment. These persons include the owner or operator of
the
site where
the
release occurred
,
and
anyone who
disposed
of
or arranged for the disposal of the hazardous substance
released
at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.
While Whiting generates materials in the course of its operations of the underlying properties that may be regulated as hazardous substances, Whiting has not been notified that it has been named as a potentially responsible part
y
at or with r
espect to any Superfund sites.
In addition, i
t is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the
release of
hazardous substances
, hydrocarbons, waste products or other chemicals
into the environment.
The underlying properties of the Trust may have been used for oil and natural gas exploration and production for many years
. Although
Whiting believes that it has
utilized
operating and
waste
disposal practices that were standard in the industry at the time,
hazardous substances, wastes, or hydrocarbons
may have been released on
or
under the properties
,
or on
or
under
other locations
, including off-site locations,
where
such substances
have been taken for
recycling or
disposal. In addition,
the underlying properties of the Trust may
have been operated by third parties
or by previous owners or operators
whose
treatment
and disposal of
hazardous substances, wastes or
hydrocarbons and materials w
as
not under
Whiting’s
control.
These properties and the substances disposed or released on them may
give rise to
potential liabilities
for Whiting pursuant to
CERCLA, RCRA and analogous state laws. Under such laws, Whiting could be required to remove previously disposed substances and wastes, remediate contaminated property, perform remedial plugging or pit closure operations to prevent future contamination or to pay some or all of
the costs of any such action.
Water Discharges.
The Federal Water Pollution Control Act, or the Clean Water Act
, as amended
(the “CWA”)
, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other
substances, into state waters or
other
waters of the United States. The discharge of pollutants into
regulated
waters is prohibited, except in accordance with the terms of a permit issued by the EPA
, the Army Corps of Engineers (the “Corps”)
or an analogous state
or tribal
agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of
navigable
waters
in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the
CWA
and analogous state laws require individual permits or
coverage
under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the
CWA
and analogous state laws and regulations.
The EPA issued a final rule in May 2015 to clarify the federal jurisdictional reach over waters of the United States. This rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals while courts consider whether the federal district or appellate courts had jurisdiction over challenges to the May 2015 rulemaking, In January 2017, the U.S. Supreme Court accepted review of the 2015 rule to determine whether jurisdiction rested with the federal district or appellate courts and in January 2018 the U.S. Supreme Court held that the federal district courts retained jurisdiction. This ruling effectively lifted the U.S. Sixth Circuit Court of Appeals nationwide stay of the rule. In June 2017, following the issuance of a presidential executive order to review the rule, the EPA and the Corps proposed a rulemaking to repeal the 2015 rule. The EPA and the Corps also announced their intent to issue a new rule defining the CWA’s jurisdiction. In January 2018 the EPA and Corps collectively released a final rule extending the effective date of the 2015 rule to 2020 while the agencies consider the issuance of a new rule. As a result, future implementation of the 2015 rule is uncertain at this time.
Hydraulic Fracturing.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight
rock
formations.
The process involves the injection of
mainly water and sand plus a de minimis amount of
chemicals under pressure into formations to fracture the surrounding rock and stimulate production.
Hydraulic fracturing has been utilized
to
complet
e
wells drilled
on
the underlying properties
,
and
Whiting
expects it will
also be used in the future. The process is typically regulated by state oil and gas commissions. However, the EPA
also
issued
guidance
in 2014
for permitting authorities and the industry regarding the process for obtaining a permit for hydrauli
c fracturing involving diesel.
In
December 2016
, the EPA released a
final report on
the potential impacts of oil and gas fracturing activities on the quality and quantity of drinking water resources in the United States. In addition,
in
June 2016
, the EPA issued a
final rule promulgating pretreatment standards
for the oil and gas extraction category which would address discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works
.
Unconventional oil and gas extraction facilities can send wastewater to a private wastewater treatment facility that can either discharge treated water or send it to a publicly-owned treatment works.
The EPA is also conducting a study of private wastewater treatment facilities accepting oil and gas extraction wastewater.
The
EPA is collecting data and information regarding the extent to which these facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of the facilities, the environmental impacts of discharges and other information.
Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy, the U.S. Government Accountability Office and the White House Council for Environmental Quality. In March 2015, the U.S. Department of the Interior released a final rule addressing (i) hydraulic fracturing on federal and Indian oil and natural gas leases to require validation of well integrity and strong cement barriers between the wellbore and water zones through which the wellbore passes, (ii) disclosure of chemicals used in hydraulic fracturing to the Bureau of Land Management, (iii) higher standards for interim storage of recovered waste fluids from hydraulic fracturing and (iv) measures to lower the risk of cross-well contamination with chemicals and fluids used in fracturing operations. In addition, legislation has been introduced in Congress from time to time to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.
Also, some states have adopted, and other states are considering adopting, regulations that could
ban,
restrict or impose additional requirements
on activities
relating to hydraulic fracturing in certain circumstances.
For example, in June
2011, Texas enacted a law that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production
in Texas
) and the public. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater.
This rule was challenged in federal court and in June 2016, the Wyoming District Court hearing the case ruled that the Department of the Interior had exceeded its authority in issuing the rule
.
In March 2017, Justice Department lawyers representing the Bureau of Land Management asked the Court of Appeals for the Tenth Circuit to stay the government’s previously filed appeal as the Trump Administration was planning to rescind the rules; and in July 2017, the Department of the Interior announced its proposal to rescind the rules, with the public comment
period on the proposal closing in September 2017
.
On December 29, 2017, the Department of the Interior issued a final rule rescinding the 2015 rule.
In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permit
ting
requirements or operational restrictions and also to associated permitting delays
, litigation risk
and potential increases in costs.
Further, local governments may seek to adopt, and some have adopted, ordinances within their jurisdictions restricting the use of or regulating the time, place and manner of drilling or hydraulic fracturing.
No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the underlying properties are located.
If new laws
,
regulations
or ordinances
that significantly restrict
or otherwise impact
hydraulic fracturing are
passed by Congress or
adopted
in
the
states or local municipalities where the underlying properties are located
, such legal requirements could
prohibit or
make it more difficult or costly for
Whiting
to
perform
hydraulic fracturing activities
on the underlying properties and thereby could affect the determination of whether a well is commercially viable
.
In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that Whiting is ultimately able to produce in commercially paying quantities f
ro
m the underlying properties
and could reduce cash distributions by the Trust and the value of Trust units
.
In addition, in July
2014, a major university and U.S. Geological Survey researchers published a study purporting to find a causal connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma since 2008.
This study, as well as subsequent
studies
and reports,
may trigger new legislation or regulations that would limit or ban the disposal of hydraulic fracturing wastewater in deep injection wells. If such new laws or rules are adopted, operations on the underlying properties may be curtailed while alternative treatment and disposal methods are developed and approved
,
or the costs of operations
on the underlying properties may increase
, which could reduce cash distributions by the Trust and the value of Trust units.
Global Warming and Climate
Change
.
I
n D
ecember
2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHG
s
”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. Based on these findings, the EPA has adopt
ed
and implemented
regulations that restrict emissions of GHG
s
under existing provisions of the
federal Clean Air Act
, as amended
(the “
CAA
”)
, including
rules that limit
emissions of GHG
s
from motor vehicles beginning with the 2012 model year.
The EPA has asserted that these final motor vehicle GHGs emission standards trigger the CAA construction and operating permit requirements for stationary sources, commencing when the motor
vehicle standards took effect in January
2011.
In June
2010, the EPA
also
published
its final rule
to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (
the
“PSD”) and Title V permitting programs.
This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first
becoming subject to permitting.
Further, facilities required to obtain PSD permits for their GHG emissions are required to reduce those emissions consistent with guidance for determining “best available control technology” standards for GHG, which guidance was published by the EPA in November 2010. Also in November 2010, the EPA expanded its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis.
Whiting believes that it is in compliance with all substantial applicable emissions requirements.
In June 2014, the Supreme Court upheld most of the EPA’s GHGs permitting requirements, allowing the agency to regulate the emission of GHGs from stationary sources already subject to the
PSD and Title V requirements.
Certain of Whiting’s equipment and installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, may also be subject to the installatio
n of controls to capture GHGs.
For any equipment or installation so subject,
Whiting
may have to incur increased compliance costs to capture related GHGs emissions, which could reduce cash distributions by the Trust and the value of Trust units.
In October 2016, the EPA proposed revisions to the rule applicable to GHGs for PSD and Ti
tle V permitting requirements.
On November 18, 2016, the EPA extended the public comment period for the rulemaking to December 16, 2016.
The proposed rule
, which would not expand federal GHG air permitting requirements,
has not
yet
been finalized.
In accordance with President Obama’s Climate Action Plan,
in
August 2015
, the EPA
issued a rule
to reduce carbon emissions f
rom electric generating units.
The
rule
, commonly called the “Clean Power Plan,” requires states to develop plans to reduce carbon emissions from fossil fuel-fired generating units commencing in 202
2
, with the reductions
to be fully phased in by 2030.
Each state is given a different carbon reduction target, but the EPA expects that, in the aggregate, the overall proposal will reduce carbon emissions from electric generating
units by 3
2
% from 2005 levels.
S
tates are given substantial flexibility in meeting their emission reduction targets and can generally choose to lower carbon emissions by replacing higher carbon generation, such as coal or natural gas, with lower carbon generation, such as efficient natural gas units or
renewable energy alternatives.
Several industry groups and states have challenged the Clean Power Plan in the Court of Appeals for the D
.C. Circuit, and in February
2016, the U.S. Supreme Court stayed
the implementation of the Clean Power Plan while it is being challenged in court.
The Court of Appeals for the D.C. Circuit heard oral arguments on the Clean Power Plan in September 2016, but has not yet issued a decision.
On March 28, 2017, the Trump Administration issued an executive order directing the EPA to review the Clean Power Plan
.
On the same day, the EPA filed a motion in the U.S. Court of Appeals for the D.C. Circuit requesting that the court hold the case in abeyance while the EPA conducts its review of the Clean Power Plan
.
On October 16, 2017, the EPA published a proposed rule that would repeal the Clean Power Plan
.
The EPA also stated in the proposed rule that the agency has not determined the scope of any rule to regulate GHG emissions from existing electric generating units, but intends to issue an Advance Notice of Proposed Rulemaking “in the near future.” Several states have already announced their intention to challenge any repeal of the Clean Power Plan
.
It is not yet clear what changes, if any, will result from the EPA’s proposal, whether or how the courts will rule on the legality of the Clean Power Plan, the EPA’s repeal of the rules, or any future replacement
.
In addition, both houses of Congress have
actively
considered legislation to reduce emissions of GHG
s
, and many states have already taken legal measures to reduce emissions of GHG
s
, primarily through the development of GHG inventories,
GHG
permitting and/or regional GHG cap
-
and
-
trade programs. Most of these cap
-
and
-
trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.
In the absence of new legislation, the EPA is issuing new regulations that limit emissions of GHG
s
associated with
the
operations
of the underlying properties
,
which will require
Whiting
to incur costs to inventory and reduce emissions of GHG
s
associated with
the
operations
of the underlying properties
and
that
could adversely affect demand for the oil
, natural gas liquids
and natural gas produce
d
. Finally, it should be noted that
many
scientists have concluded that increasing concentrations of GHG
s
in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events
.
Air Emissions.
The
CAA
and comparable state laws regulate emissions of various air pollutants from various industrial sources through air emissions permitting programs and also impose other monitoring and reporting requirements. Operators of the underlying properties
, including Whiting,
may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining
pre-construction and
operating permits and approvals for air emissions. In addition,
the
EPA has developed, and continues to develop, stringent regulati
ons governing emissions of
air pollutants at specified sources.
For example,
in
2012
, the EPA
finalized
rules establish
ing
new air emission controls for oil and natural gas production operations. Specifically, the EPA’s rule includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. Among other things, these standards require the application of reduced emission completion techniques
associated with the
completion of newly drilled and fractured wells in addition to existing wells that are refractured. The rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment.
These rules could require a number of modifications to operations at the underlying properties including the installation of new equipment.
Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs
, which may adversely impact
cash distributions to unitholders
.
Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the
CAA
and associated state laws and regulations.
The EPA announced in 2015 that it would directly regulate methane emissions from oil and natural gas wells for the first time as part of President Obama’s Climate Action Plan.
As part of this strategy, in May 2016, the EPA issued three final rules. The EPA issued a final rule that updated the New Source Performance Standards to add requirements that the oil and gas industry reduce emissions of greenhouse gases and to cover additional equipment and activities in the oil and gas production chain. The final rule sets emissions limits for methane, which is the principal greenhouse gas emitted by equipment and processes in the oil and gas sector. This rule applies to new, reconstructed and modified processes and equipment. This rule also expands the volatile organic compound emissions limits to hydraulically fractured oil wells and equipment used across the industry that was not regulated in the 2012 rules. The rule also requires owners and operators to find and repair leaks, also known as “fugitive emissions.” The EPA also issued a final rule known as the Source Determination Rule, which is intended to clarify when multiple pieces of equipment and activities in the oil and gas industry must be deemed a single source when determining whether major source permitting programs apply under the prevention of significant deterioration, nonattainment new source review preconstruction and operation permit programs under Title V of the CAA (“Title V”). The final rule defines the term “adjacent” to clarify that equipment and activities in the oil and gas sector that are under common control will be considered part of the same source if they are located near each other – specifically, if they are located on the same site, or on sites that share equipment and are within one quarter of a mile of each other. This rule applies to equipment and activities used for onshore oil and natural gas production, and for natural gas processing.
Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact cash distributions to unitholders. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.
OSHA and Other Laws and Regulation.
Whiting is subject to the requirements of the federal Occupational Safety and Health Act,
as amended
(“
OSHA
”)
and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that Whiting organize and/or disclose information about hazardous materials used or produced in its operations. Whiting believes that it is in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.
Endangered
S
pecies
C
onsiderations.
The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats. If endangered species are located in areas of the underlying properties where Whiting or the other underlying property operators wish to conduct seismic surveys, development activities or abandonment operations, the work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for
the District of Columbia in September
2011, the U.S. Fish and Wildlife Service
is required to
make a determination on
listing more than 250 species as endangered
or threatened
under the
ESA
over the next several years
. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause operators of those underlying properties, including Whiting, to incur increased costs arising from species protection measures or could result in limitations on their exploration and production activities that could have an adverse impact on their ability to develop and produce reserves.
Consideration of
E
nvironmental
I
ssues in
C
onnection with
G
overnmental
A
pprovals.
Whiting’s
operations frequently require licenses, permits and/or
other governmental approvals.
Several federal statutes, including the Outer Continental Shelf Lands Act (“OCSLA”)
and
the National Environmental Policy Act (“NEPA”) require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taki
ng other major agency actions.
OCSLA, for instance, requires the U.S. Department of Interior to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or huma
n environment.
Similarly, NEPA requires the Department of Interior and other federal agencies to evaluate major agency actions having the potential to signifi
cantly impact the environment.
In the course of such evaluations, an agency would have to prepare an environmental assessment and, potentially, an environmental impact statement.
This process has the potential to delay the development of oil and natural gas projects.
Whiting believes that it is in
compliance
in all material respects
with all existing environmental laws and regulations applicable to the current operations of the underlying properties and that its continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the Trust unitholders. For instance, Whiting did not incur any material capital expenditures for remediation or pollution control activities for the
year
ended
December 31, 2017
with respect to these properties.
Additionally, Whiting has informed the Trust that Whiting is not aware of any environmental issues or claims that will require material capital expenditures during
2018
with respect to these properties.
However, there is no assurance that the passage of more stringent laws or implementing regulations in the future will not have
a negative impact on the operations of these properties and the cash distributions to the Trust unitholders.
I
tem 1A.
Risk Factors
The amounts of cash distributions by the Trust are subject to fluctuation as a result of changes in oil, natural gas and natural gas
liquids
prices.
The reserves attributable to the underlying properties and the quarterly cash distributions of the Trust are highly dependent upon the prices realized from the sale of oil, natural gas and natural gas liquids. Prices of oil, natural gas and natural gas liquids applicable to the underlying properties can fluctuate widely on a quarter-to-quarter basis in response to a variety of factors that are beyond the control of the Trust and Whiting, including, but not limited to, the following:
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changes in regional, domestic and global supply and demand for oil and natural gas;
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the level of global oil and natural gas inventories;
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the actions of the Organization of Petroleum Exporting Countries;
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the price and quantity of imports of foreign oil and natural gas;
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political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity, such as recent conflicts in the Middle East;
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the level of global oil and natural gas exploration and production activity;
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the effects of global credit, financial and economic issues;
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developments of Unit
ed States energy infrastructure;
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technological advances affecting energy consumption;
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current and anticipated changes to domestic and foreign governmental regulations, including those
that may arise in response to the policies of the Trump Administration
;
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proximity and capacity of oil and natural gas pipelines and other transportation facilities;
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the price and availability of competitors’ supplies of oil and gas in captive market areas;
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the price and availability of alternative fuels; and
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Moreover, government regulations, such as regulation of oil and natural gas gathering and transportation, can adversely affect commodity prices in the long term.
These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements. Also, prices for crude oil and prices for natural gas do not necessarily move in tandem. Declines in oil or natural gas prices would not only reduce revenue, but could also reduce the amount of oil and natural gas that can be economically produced from the underlying properties.
Whiting entered into hedge contracts, which were structured as costless collar arrangements and were conveyed to the Trust to reduce the exposure to volatility in the underlying properties’ oil and gas revenues due to fluctuations in crude oil and natural gas prices, and to achieve more predictable cash flows. However, all such costless collar hedge contracts terminated as of December 31, 2014 (which hedging effects extended through the February 2015 distribution to unitholders), and no additional hedges are allowed to be placed on the Trust assets. As a result, the amounts of the cash distributions may fluctuate significantly as a result of changes in commodity prices because there are no hedge contracts in place to reduce the Trust’s exposure to oil and natural gas price volatility.
Substantial and extended declines in oil, natural gas and natural gas liquids prices have resulted and may continue to result in reduced net proceeds to which the Trust is entitled and may ultimately reduce the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties. As a result, the operator of any of the underlying properties could determine during periods of low commodity prices to shut in or curtail production from the underlying properties. In addition, the operator of these properties could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Because these properties are mature, decreases in commodity prices could have a more significant effect on the economic viability of these properties as compared to more recently discovered properties. The commodity price sensitivity of these mature wells is due to a culmination of factors that vary from well to well, including the additional costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, the volatility of commodity prices may cause the amount of future cash distributions to Trust unitholders to fluctuate, and a substantial decline in the price, or sustained periods of low prices, of oil, natural gas or natural gas liquids, will likely materially reduce, or completely eliminate, the amount of cash available for distribution to Trust unitholders.
The Trust units have been delisted from the New York Stock Exchange. It will likely be more difficult for unit holders to sell the Trust units or to obtain accurate quotations of the Trust units.
The Trust units ceased trading on the NYSE on January 6, 2016. The Trust units transitioned to OTC, operated by OTC Markets Group, effective with the opening of trading on January 7, 2016 under the trading symbol “WHZT.” The Trust can provide no assurance that any trading market for the Trust units will exist on OTC or that current trading levels will be sustained or not diminish. Securities traded on the over-the-counter markets are typically less liquid than stocks that trade on the NYSE. Trading on the over-the-counter market may negatively affect the trading price and liquidity of the Trust units and could result in larger spreads in the bid and ask prices for Trust units. Unit holders may find it difficult to resell their Trust units due to the delisting.
The reserves attributable to the underlying properties are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and natural gas properties or NPI to replace the depleting assets and production.
The net proceeds payable to the Trust from the NPI are derived from the sale of oil, natural gas and natural gas liquids produced from the underlying properties. The reserves attributable to the underlying properties are depleting assets,
which means that such reserves will decline over time. Based on the reserve report, overall production for both oil and gas attributable to the underlying properties
is expected to decline at an average year-over-year rate of approximately
13.3%
for oil and
25.9%
for gas between
2018
and 202
1
, assuming the level of developmental drilling and investments on the underlying properties as assumed in the year-end reserve report. However, cash distributions to unitholders may decline at a faster rate than the rate of production due to fixed and semi-variable costs attributable to the underlying properties or if expected future development is delayed, reduced or cancelled. Also, the anticipated rate of decline is an estimate and actual decline rates will likely vary from those estimated. As
of
December 31, 2017
,
the percentage of remaining reserves expected to be produced during the term of the NPI was
43.4%
.
The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), or (b) the sale of the net profits interest.
Future maintenance projects on the underlying properties beyond those which are currently estimated may affect the quantity of proved reserves that can be economically produced from the underlying properties. The timing and size of these projects will depend on, among other factors, the market prices of oil, natural gas and natural gas liquids. If operators of the underlying properties do not implement required maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by Whiting or estimated in the reserve report. Additionally, although Whiting retained a 10% interest in the net proceeds from the sale of oil, natural gas and natural gas liquids from the underlying properties, Whiting does not own any Trust units, which could reduce its economic incentive to operate the underlying properties in an efficient and cost-effective manner.
The Trust agreement provides that the Trust’s business activities are limited to owning the NPI and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyance related to the NPI. As a result, the Trust is not permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets or production attributable to the NPI, nor is the Trust permitted to enter into any new hedging arrangements.
Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the portion of the distributions to unitholders attributable to depletion should be considered a return of capital as opposed to a return on investment. Eventually, the NPI may cease to produce in commercial quantities and the Trust may, therefore, cease to receive any distributions of net proceeds therefrom. Further, distributions will cease upon termination of the Trust.
Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust units.
The value of the Trust units and the amount of future cash distributions
, if any,
to the Trust unitholders depends upon, among other things, the accuracy of the production and reserves estimated to be attributable to the underlying properties and the NPI. Estimating production and reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates, and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating production and reserves. Those factors and assumptions include:
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historical production from the area compared with production rates from other producing areas;
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the assumed effect of governmental regulation; and
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assumptions about future prices of oil, natural gas and natural gas liquids, including differentials, production and development costs, gathering and transportation costs, severance and excise taxes and capital expenditures.
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Changes in these assumptions may materially alter production and reserve estimates. The estimated proved reserves attributable to the NPI and the “standardized measure” value attributable to the NPI are based on estimates of reserve quantities and revenues for the underlying properties. The quantities of reserves attributable to the underlying properties and the NPI may decrease in the future as a result of future decreases in the price of oil, natural gas or natural gas liquids.
For example, the reserve estimates in the reserve report have been derived from NYMEX oil and gas prices of $
51.34
per Bbl and $2.
98
per MMBtu, respectively, which are calculated using an average of the first-day-of-the month price for each month within the 12 months ended
December 31, 2017
, pursuant to current SEC and FASB guidelines.
Financial returns to purchasers of Trust units will vary in part based on how quickly 11.79 MMBOE are produced from the underlying properties and sold, and it is not known when that will occur.
The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold, or (b) the sale of the net profits interest.
The reserve report currently projects that 11.79 MMBOE will have been produced from the underlying properties
prior to December 31, 2021
.
As basis for comparison,
the estimated date when such amount would
have
be
en produced according to
t
he 201
6
year-end reserve report was
July 31
, 202
3
. However, the exact rate of production cannot be predicted with certainty and such amount may be produced before or after that date. If production attributable to the underlying properties is slower than estimated, then financial returns to purchasers of Trust units will be lower (assuming constant prices) because cash distributions attributable to such production will occur at a later date.
There will be no distribution to unitholders when the amount of any costs, expenses and reserves related to the underlying properties, other costs and expenses incurred by the Trust and prior period net losses and applicable accrued interest, exceeds or equals the gross proceeds generated by the NPI, as occurred for the February 2016 net loss, May 2016 net loss and August 2016 distribution.
The NPI bears its share of all production and development costs and expenses related to the underlying properties, such as lease operating expenses, production and property taxes and development costs, which reduces or potentially eliminates the amount of cash received by the Trust and thereafter distributable to Trust unitholders. Additionally, if production and development costs on the underlying properties exceed the proceeds from production, as occurred for the February 2016 and May 2016 net losses when the NPI generated an aggregate $1.3 million net loss attributable to the Trust’s interest, the Trust will not receive net proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. Also, amounts may be reserved by Whiting for future development, maintenance or operating expenses (which reserve amounts may not exceed $2.0 million), which also reduces the amount of cash received by the Trust and thereafter be distributable to Trust unitholders.
Accordingly, higher production and development costs and expenses related to the underlying properties directly decreases the amount of cash received by the Trust in respect of its NPI. In addition, cash available for distribution by the Trust is further reduced by the Trust’s general and administrative expenses. If the Trust does not receive net proceeds pursuant to the NPI, or if such net proceeds are reduced, the Trust will not be able to distribute cash to the Trust unitholders, or such cash distributions will be reduced, respectively.
Risks associated with the production, gathering, transportation and sale of oil, natural gas and natural gas liquids could adversely affect cash distributions by the Trust and the value of the Trust units.
The revenues of the Trust, the value of the Trust units and the amount of cash distributions to the Trust unitholders depends upon, among other things, oil, natural gas and natural gas liquids production and the prices received and the costs incurred to exploit oil and natural gas reserves attributable to the underlying properties. Drilling, production or transportation accidents that temporarily or permanently halt the production and sale of oil, natural gas and natural gas liquids at any of the underlying properties reduces Trust distributions by reducing the amount of net proceeds available for distribution. For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any costs incurred in connection with any such accidents that are not insured against will have the effect of reducing the net proceeds available for distribution to the Trust. Also, Whiting does not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations.
Refer to the risk factor entitled
“Federal, state and local legislative and regulatory initiatives rel
ating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affecti
ng Whiting’s and other operator
s
’
services.
” for a discussion of the uncertainty involved in the regulation of hydraulic fracturing. Also, Whiting’s oil, natural gas liquids and natural gas production depends in large part on the proximity and capacity of
pipeline systems and transportation facilities which are mostly owned by third parties. The lack of availability or the lack of capacity on these systems and facilities could result in the curtailment of production or the delay or discontinuance of drilling plans. Similarly, curtailments or damage to pipelines and other transportation facilities used to transport oil, natural gas and natural gas liquids production to markets for sale could reduce the amount of net proceeds available for distribution. Any such curtailment or damage to the gathering systems could also require finding alternative means to transport the oil, natural gas and natural gas liquids production from the underlying properties, which alternative means could result in additional costs that will have the effect of reducing net proceeds available for distribution.
Also, in response to recent accidents involving rail cars carrying Bakken crude oil, the U.S. Department of Transportation (the “DOT”) issued an emergency order on February 25, 2014 that requires rail shippers to test the makeup of such crude oil before transporting it. This move follows the safety alert the DOT issued in January 2014 that Bakken formation crude oil is more flammable than other types of crude oil and has been followed by additional emergency orders and safety advisories and alerts. An accident involving rail cars could result in significant personal injuries and property and environmental damage. In May 2015, the Pipeline and Hazardous Material Safety Administration issued new rules applicable to “high-hazard flammable trains”, which could increase transportation expenses. Similarly, regulatory responses to the October 2015 failure at a Southern California underground natural gas storage facility could also lead to increased expenses for underground storage.
In addition, drilling, production and transportation of hydrocarbons bear the inherent risk of loss of containment. Potential consequences include loss of reserves, loss of production, loss of economic value associated with the affected wellbore, contamination of air, soil, ground water, and surface water, as well as potential fines, penalties or damages associated with any of the foregoing consequences.
The market price for the Trust units may not reflect the value of the NPI held by the Trust and, in addition, over time will decline to zero around or shortly after the NPI termination date, which is currently estimated to be
December
31, 202
1
.
The trading price for publicly traded securities similar to the Trust units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the Trust will vary in response to numerous factors outside the control of the Trust, including prevailing sales prices of oil, natural gas and natural gas liquids production attributable to the underlying properties. Further, the market price of Trust units may be affected by factors other than the anticipated future Trust distributions. Consequently, the market price for the Trust units may not necessarily be indicative of the value that the Trust would realize if it sold the NPI to a third-party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid
, if any,
on the Trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the unitholder, and over time the market price of the Trust units will decline to zero
around or
shortly after the NPI termination date, which is currently estimated to be
December 31, 2021
based on the reserve report as of December 31, 201
7
.
Whiting has limited control over activities on the underlying properties that Whiting does not operate, which could reduce production from the underlying properties, increase capital expenditures and reduce cash available for distribution to Trust unitholders.
Whiting is currently designated as the operator of
65%
of the underlying properties based on the standardized measure of discounted future net cash flows at
December 31, 2017
. However, for
the
35%
of the underlying properties that it does not operate, Whiting does not have control over normal operating procedures, expenditures or future development relating to such properties. The failure of an operator to adequately perform operations or an operator’s breach of the applicable agreements could reduce production from the underlying properties and the cash available for distribution to Trust unitholders. The success and timing of operational activities on properties operated by others therefore depends upon a number of factors outside of Whiting’s control, including the operator’s decisions with respect to the timing and amount of capital expenditures, the period of time over which the operator seeks to generate a return on capital expenditures, the inclusion of other participants in drilling wells, and the use of technology, as well as the operator’s expertise and financial resources and the operator’s relative interest in the underlying field. Operators may also opt to decrease operational activities following a significant decline in oil or natural gas prices. Because Whiting does not have a majority interest in most of the non-operated properties comprising the underlying properties, Whiting may not be in a position to remove the operator in the event of poor performance. Accordingly, while Whiting has agreed to use commercially reasonable efforts to cause the operator to act as a reasonably prudent operator, it is limited in its ability to do so.
The processes of drilling and completing wells are high risk activities.
The processes of drilling and completing wells are subject to numerous risks beyond the Trust’s and Whiting’s control, including risks that could delay the current drilling schedule of Whiting or any other operator of an underlying property and the risk that drilling will not result in commercially viable production. Neither Whiting nor any other operator is obligated to undertake any development activities, so any drilling and completion activities are subject to their discretion. Further, Whiting’s or any other operator’s future business, financial condition, results of operations, liquidity or ability to finance its share of planned development expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including the following:
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substantial or extended declines in oil, NGL and natural gas prices;
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delays imposed by or resulting from compliance with regulatory requirements;
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delays in or limits on the issuance of drilling permits on federal leases, including as a result of government shutdowns;
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pressure or irregularities in geological formations;
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shortages of or delays in obtaining qualified personnel or equipme
nt, including drilling rigs, completion services and CO
2
;
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equipment failures or accidents;
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adverse weather conditions, such as freezing temperatures, hurricanes and storms;
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pipeline takeaway and refining and processing capacity; and
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In the event that development activities are delayed or cancelled, or development wells have lower than anticipated production, due to one or more of the factors above or for any other reason, estimated future distributions to unitholders may be reduced.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affecting Whiting’s
and other operator
s
’
services.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. Hydraulic fracturing has been utilized during the completion of wells drilled on the underlying properties, and Whiting expects it will also be used in the future. The process involves the injection of mainly water and sand plus a de minimis amount of chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has also issued guidance in 2014 for permitting authorities and the industry regarding the process for obtaining a permit for hydraulic fracturing involving diesel.
In December 2016, the EPA released a final report on the potential impacts of oil and gas fracturing activities on the quality and quantity of drinking water resources in the United States.
In addition
,
in June
2016
the EPA issued a final
rule promulgating pretreatment standards for the oil and gas extraction category which addresses discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works.
Unconventional oil and gas extraction facilities can send wastewater to a private wastewater treatment facility that can either discharge treated water or send it to a publicly-owned treatment works.
The EPA is also conducting a study of private wastewater treatment facilities accepting oil and gas extraction wastewater. The EPA is collecting data and information regarding the extent to which these facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of the facilities, the environmental impacts of discharges and other information.
Other federal agencies are also examining hydraulic fracturing, including the U.S. Department of Energy, the U.S. Government Accountability Office and the White House Council for Environmental Quality. In March 2015, the U.S. Department of the Interior released a final rule addressing (i) hydraulic fracturing on federal and Indian oil and natural gas leases to require validation of well integrity and strong cement barriers between the wellbore and water zones through which the wellbore passes, (ii) disclosure of chemicals used in hydraulic fracturing to the Bureau of Land Management, (iii) higher standards for interim storage of recovered waste fluids from hydraulic fracturing and (iv) measures to lower the risk of cross-well contamination with chemicals and fluids used in fracturing operations.
This rule was challenged in federal court and in June 2016, the Wyoming District Court hearing the case ruled that the Department of the Interior had exceeded its authority in issuing the rule
.
In March 2017, Justice Department lawyers representing the Bureau of Land Management asked the Court of Appeals for the Tenth Circuit to stay the government’s previously filed appeal as the Trump Administration was planning to rescind the rules; and in July 2017, the Department of the Interior announced its proposal to rescind the rules, with the public comment period on the proposal closing in September 2017
.
On December 29, 2017, the Department of the Interior issued a final rule rescinding the 2015 rule.
In addition, legislation has been introduced in Congress from time to time to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.
Also, some states have adopted, and other states are considering adopting, regulations that could ban, restrict or impose additional requirements on activities relating to hydraulic fracturing in certain circumstances. For example,
in June
2011, Texas enacted a law that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas (the entity that regulates oil and natural gas production in Texas) and the public. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting requirements or operational restrictions and also to associated permitting delays, litigation risk and potential increases in costs. Further, local governments may seek to adopt, and some have adopted, ordinances within their jurisdictions restricting the use of or regulating the time, place and manner of drilling or hydraulic fracturing. No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the underlying properties are located. If new laws, regulations or ordinances that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in the states or local municipalities where the underlying properties are located, such legal requirements could prohibit or make it more difficult or costly for Whiting to perform hydraulic fracturing activities on the underlying properties and thereby could affect the determination of whether a well is commercially viable. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that Whiting is ultimately able to produce in commercially paying quantities from the underlying properties and could reduce cash distributions by the Trust and the value of Trust units.
In addition, in July
2014, a major university and U.S. Geological Survey researchers published a study purporting to find a causal connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma since 2008. This study, as well as subsequent studies and reports may trigger new legislation or regulations that would limit or ban the disposal of hydraulic fracturing wastewater in deep injection wells. If such new laws or rules are adopted, operations on the underlying properties may be curtailed while alternative treatment and disposal methods are developed and approved, or the costs of operations on the underlying properties may increase, which could reduce cash distributions by the Trust and the value of Trust units.
The Trust and the Trust unitholders have no voting or managerial rights with respect to the underlying properties. As a result, neither the Trust nor the Trust unitholders have any ability to influence the operation of the underlying properties.
Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners of oil and natural gas properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the Trustee nor the Trust unitholders have any contractual ability to influence or control the field operations of, and sale of oil and natural gas from, the underlying properties, including underlying properties where Whiting is the operator. Also, the Trust unitholders have no voting rights with respect to the operators of these properties and, therefore, have no managerial, contractual or other ability to influence the activities of the operators of these properties.
The Trust’s NPI may be characterized as an executory contract in bankruptcy, which could be rejected in bankruptcy, thus relieving Whiting from its obligations to make payments to the Trust with respect to the NPI.
Whiting has recorded the conveyance of the NPI in the states where the underlying properties are located in the real property records in each county where these properties are located. The NPI is a non-operating, non-possessory interest carved out of the oil and natural gas leasehold estate, but certain states have not directly determined whether a NPI is a real or a personal property interest. Whiting believes that the delivery and recording of the conveyance should create a fully conveyed and vested property interest under the applicable state’s laws, but certain states have not directly determined whether this would be the result. If in a bankruptcy proceeding in which Whiting becomes involved as a debtor a determination were made that the conveyance constitutes an executory contract and the NPI is not a fully conveyed property interest under the laws of the applicable state, and if such contract were not to be assumed in a bankruptcy proceeding involving Whiting, the Trust would be treated as an unsecured creditor of Whiting with respect to
the
NPI in the pending bankruptcy proceeding.
Whiting or other operators may abandon individual wells or properties that it or they reasonably believe to be uneconomic.
Whiting or other operators may abandon any well if it or they reasonably believe that the well can no longer produce oil or natural gas in commercially economic quantities. This could result in termination of the NPI relating to the abandoned well.
An increase in the differential or decrease in the premium between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price received could reduce cash distributions by the Trust and the value of Trust units.
Oil and natural gas production from the underlying properties generally trades at a discount, but sometimes at a premium, to the relevant benchmark prices, such as NYMEX. A negative difference between the benchmark price and the price received is called a differential and a positive difference is called a premium. The differential and premium may vary significantly due to market conditions, the quality and location of production and other risk factors. Whiting cannot accurately predict oil and natural gas differentials or premiums. Increases in the differential and decreases in the premiums between the benchmark price for oil and natural gas and the wellhead price received could reduce cash distributions by the Trust and the value of the Trust units.
The Trust units may lose value as a result of title deficiencies with respect to the underlying properties.
The existence of a material title deficiency with respect to the underlying properties could reduce the value of a property or render it worthless, thus adversely affecting the NPI and distributions to Trust unitholders. Whiting does not obtain title insurance covering mineral leaseholds, and Whiting’s failure to cure any title defects may cause Whiting to lose its rights to production from the underlying properties. In the event of any such material title problem, proceeds available for distribution to Trust unitholders and the value of the Trust units may be reduced.
Conflicts of interest could arise between Whiting and the Trust unitholders.
The interests of Whiting and the interests of the Trust and the Trust unitholders with respect to the underlying properties could at times differ. For example:
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Whiting’s interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of certain wells on the underlying properties for which Whiting acts as the operator. Whiting may also make decisions with respect to development costs that adversely affect the underlying properties. These decisions include reducing development costs on properties for which Whiting acts as the operator, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future. Additionally, Whiting’s broad discretion over the timing and amount of development, maintenance, operating expenditures and activities could result in higher costs being attributed to the NPI.
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In the event the Trust is required to se
ll the NPI because
(i)
annual cash
proceeds
to the Trust from
the
net profits interest
are less than $2.0 million for each of any two consecutive years or
(ii)
Trust unitholders vote to sell the NPI, Whiting may seek to purc
hase the NPI from the Trust.
Although the Trust
ee
has certain obligations to unitholders in connection with the sale of the NPI, there is likely a limited universe of potential buyers given the terms of the
net profits interest
and Whiting’s residual interest
in the underlying properties.
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Whiting has the right, subject to significant limitations as described herein, to cause the Trust to release a portion of the NPI in connection with a sale of a portion of the oil and natural gas properties comprising the
underlying properties to which the
NPI relates. In such an event, the Trust is entitled to receive its proportionate share of the proceeds from the sale attributable to the NPI released.
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The Trust has no employees and is reliant on Whiting’s employees to operate those underlying properties for which Whiting is designated as the operator. Whiting’s employees are also responsible for the operation of other oil and gas properties Whiting owns, which may require a significant portion or all of their time and resources.
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The documents governing the Trust generally do not provide a mechanism for resolving these conflicting interests.
The Trust is managed by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.
The business and affairs of the Trust are administered by the Trustee. The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust agreement provides that the Trustee may only be removed and
replaced by a vote of the holders of a majority of the outstanding Trust units at a special meeting of Trust unitholders called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. As a result, it may be difficult to remove or replace the Trustee.
Trust unitholders have limited ability to enforce provisions of the NPI.
The Trust agreement permits the Trustee to sue Whiting on behalf of the Trust to enforce the terms of the conveyance creating the NPI. If the Trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of a Trust unitholder would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The Trust agreement expressly limits the Trust unitholders’ ability to directly sue Whiting or any other third party other than the Trustee. As a result, the unitholders are not able to sue Whiting to enforce these rights.
Under certain circumstances, the Trust provides that the Trustee may be required to sell the NPI and dissolve the Trust prior to the expected termination of the Trust. As a result, Trust unitholders may not recover their investment.
The Trust is required to sell the NPI and liquidate if cash proceeds to the Trust from the net profits interest are less than $2.0 million for each of any two consecutive years. During the year
s
ended December 31, 2017 and 2016, the Trust received cash proceeds of $6.7 million and $1.9 million, respectively, from the net profits interest. Additionally, the Trustee must sell the NPI if the holders of a majority of the Trust units approve the sale or vote to dissolve the Trust. The sale of the NPI will result in the dissolution of the Trust and the net proceeds of any such sale will be distributed to the Trust unitholders.
The Trust will wind up its affairs and terminate shortly after the earlier of (a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), or (b) the sale of the net profits interest. The Trust unitholders will not be entitled to receive any net proceeds from the sale of production from the underlying properties following the termination of the NPI. Therefore, the market price of the Trust units will approach and eventually reach zero shortly after the end of the NPI term because cash distributions from the Trust will cease following the termination of the NPI, and the Trust will have no right to any additional production from the underlying properties after the term of the NPI.
Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.
Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations under the General Corporation Law of the State of Delaware. Courts in jurisdictions outside of Delaware, however, may not give effect to such limitation.
The operations of the underlying properties may result in significant costs and liabilities with respect to environmental and operational safety matters, which could reduce the amount of cash available for distribution to Trust unitholders.
Significant costs and liabilities can be incurred as a result of environmental and safety requirements applicable to the oil and natural gas exploration, development and production activities of the underlying properties. These costs and liabilities could arise under a wide range of federal, regional, state and local environmental and safety laws, regulations, and enforcement policies, which legal requirements have tended to become increasingly strict over time. Numerous governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts on the operations of the underlying properties.
Although President Trump has indicated that he would work to ease regulatory burdens on industry and on the oil and gas sector, including environmental regulations, any executive orders the President may issue or any new legislation Congress may pass with the goal of reducing environmental statutory or regulatory requirements may be challenged in court. In addition, various state laws and regulations (and permits issued thereunder) will be unaffected by federal changes unless and until the state laws and corresponding permits are similarly changed, and any judicial review is completed.
Strict, joint and several liability may be imposed under certain environmental laws and regulations, which could result in liability being imposed on Whiting with respect to its portion of the underlying properties due to the conduct of others or from Whiting’s
actions even if such actions were in compliance with all applicable laws at the time those actions were taken. Private parties, including the surface estate owners of the real properties at which the underlying properties are located and the owners of facilities where petroleum hydrocarbons or wastes resulting from operations at the underlying properties are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damages. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If it were not possible to recover the resulting costs for such liabilities or non-compliance through insurance or increased revenues, then these costs could have a material adverse effect on the cash distributions to the Trust unitholders.
The Trust bears indirectly 90% of all costs and expenses paid by Whiting, including those related to environmental compliance and liabilities associated with the underlying properties. In addition, as a result of the increased cost of compliance, the operators of the underlying properties may decide to discontinue drilling.
The operations of the underlying properties are subject to complex federal, state, local and other laws and regulations that could adversely affect cash distributions to the Trust unitholders.
The development and production operations of the underlying properties are subject to complex and stringent laws and regulations. In order to conduct the operations of the underlying properties in compliance with these laws and regulations, Whiting and the other operators must obtain and maintain numerous permits, approvals and certificates from various federal, state, local and governmental authorities. Whiting and the other operators may incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations, which could decrease the cash distributions to the Trust unitholders. In addition, the costs of compliance may increase or the operations of the underlying properties may be otherwise adversely affected if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to such operations. Such costs could have a material adverse effect on the cash distributions to the Trust unitholders.
The operations of the underlying properties are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on the cash distributions to the Trust unitholders.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for oil and gas which could reduce the amount of cash available for distribution to Trust unitholders.
In December
2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. Based on these findings, the EPA has adopted and implemented regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, as amended (the “CAA”), including rules that limit emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger the CAA construction and operating permit requirements for stationary sources, commencing when the motor
vehicle standards took effect in January 2011. I
n
June
2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (the “PSD”) and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Further, facilities required to obtain PSD permits for their GHG emissions are required to reduce those emissions consistent with guidance for determining “best available control technology” standards for GHG, which guidance was published by the EPA in November 2010. Also in November 2010, the EPA expanded its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis.
In June 2014, the Supreme Court upheld most of the EPA’s GHGs permitting requirements, allowing the agency to regulate the emission of GHGs from stationary sources already subject to the PSD and Title V requirements. Certain of Whiting’s equipment and installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, may also be subject to the installation of controls to capture GHGs. For any equipment or installation so subject, Whiting may have to incur increased compliance costs to capture related GHGs emissions, which could reduce cash distributions by the Trust and the value of Trust units.
I
n October 2016, EPA proposed revisions to the rule applicable to GHGs for PSD and Title V permitting requirements.
On November 18, 2016, the EPA extended the public comment period for the rulemaking to December 16, 2016.
The proposed rule
, which would not expand federal GHG permitting requirements,
has not
yet
been finalized.
The EPA announced in 2015 that it would directly regulate methane emissions from oil and natural gas wells for the first time as part of President Obama’s Climate Action Plan. As part of this strategy, in May 2016, the EPA issued a final rule that updated the New Source Performance Standards to add requirements that the oil and gas industry reduce emissions of greenhouse gases and to cover additional equipment and activities in the oil and gas production chain. The final rule sets emissions limits for methane, which is the principal greenhouse gas emitted by equipment and processes in the oil and gas sector. This rule applies to new, reconstructed and modified processes and equipment.
In accordance with President Obama’s Climate Act
ion Plan, in August
2015, the EPA issued a rule to reduce carbon emissions from electric generating units. The rule, commonly called the “Clean Power Plan,” requires states to develop plans to reduce carbon emissions from fossil fuel-fired generating units commencing in 2022, with the reductions to be fully phased in by 2030. Each state is given a different carbon reduction target, but the EPA expects that, in the aggregate, the overall proposal will reduce carbon emissions from electric generating units by 32% from 2005 levels. States are given substantial flexibility in meeting their emission reduction targets and can generally choose to lower carbon emissions by replacing higher carbon generation, such as coal or natural gas, with lower carbon generation, such as efficient natural gas units or renewable energy alternatives. Several industry groups and states have challenged the Clean Power Plan in the Court of App
eals for the D.C. Circuit, and in February
2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan while it
is being challenged in court.
The Court of Appeals for the D.C. Circuit heard oral arguments on the Clean Power Plan in September 2016, but has not yet issued a decision.
On March 28, 2017, the Trump Administration issued an executive order directing the EPA to review the Clean Power Plan
.
On the same day, the EPA filed a motion in the U.S. Court of Appeals for the D.C. Circuit requesting that the court hold the case in abeyance while the EPA conducts its review of the Clean Power Plan
.
On October 16, 2017, the EPA published a proposed rule that would repeal the Clean Power Plan
.
The EPA also stated in the proposed rule that the agency has not determined the scope of any rule to regulate GHG emissions from existing electric generating units, but intends to issue an Advance Notice of Proposed Rulemaking “in the near future.” Several states have already announced their intention to challenge any repeal of the Clean Power Plan
.
It is not yet clear what changes, if any, will result from the EPA’s proposal, whether or how the courts will rule on the legality of the Clean Power Plan, the EPA’s repeal of the rules, or any future replacement
.
In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and many states have already taken legal measures to reduce emissions of GHGs, primarily through the development of GHG inventories, GHG permitting and/or regional GHG cap-and-trade programs. Most of these cap-and-trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. In the absence of new legislation, the EPA is issuing new regulations that limit emissions of GHGs associated with the operations of the underlying properties, which will require Whiting to incur costs to inventory and reduce emissions of GHGs associated with the operations of the underlying properties and that could adversely affect demand for oil, natural gas liquids and natural gas produced. Finally, it should be noted that many scientists have concluded that increasing concentrations of GHGs in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on the Trust’s assets and the amount of cash available for distribution to the Trust unitholders.
Shortages or increases in costs of oil field equipment, services, qualified personnel and supply materials could delay production, thereby reducing the amount of cash available for distribution.
The demand for qualified and experienced field personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs, completion cre
w
s and other oil
field equipment as demand for these items has increased along with the number of wells being drilled and completed. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs and other oil
field goods and services.
Additionally, operations on the underlying properties in some instances require supply materials such as CO
2
for production which could become subject to shortage and increasing costs.
Shortages of field personnel, drilling rigs, completion crews, equipment, supplies or personnel or price increases could delay or adversely affect the amount of cash available for distribution to the Trust unitholders, or restrict operations on the underlying properties.
If the financial position of Whiting degrades in the future, Whiting may not be able to satisfy its obligations to the Trust.
Whiting operates approximately
65%
of the underlying properties based on the standardized measure of discounted future net cash flows at
December 31, 2017
. The conveyance provides that Whiting will be obligated to market, or cause to be marketed, the production related to underlying properties for which it operates.
Whiting’s ability to perform its obligations related to the operation of the underlying properties and its obligations to the Trust will depend on Whiting’s future financial condition and economic performance, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and upon financial, business and other factors, many of which are beyond the control of Whiting. Whiting cannot provide any assurance that its financial condition and economic performance will not deteriorate in the future. A substantial or extended decline in oil or natural gas prices may materially and adversely affect Whiting’s future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
The financial results of the Trust may differ from the financial results of Whiting USA Trust I.
Whiting previously participated in the formation and initial public offering of Whiting USA Trust I (“Trust I”) on April 30, 2008 and Trust I terminated its NPI effective January 28, 2015 as a result of the contractual volumes being produced and sold from Trust I’s underlying properties. Given the differences in assets comprising the underlying properties, commodity prices, production and development costs, development schedule, operators of the underlying properties and regulatory environment, among other things, the historical results of operations of Whiting USA Trust I should not be relied on as an indicator of how Whiting USA Trust II will perform.
Under certain circumstances, the Trust provides that the Trustee may be required to reconvey to Whiting a portion of the NPI, which may impact how quickly 11.79 MMBOE are produced from the underlying properties for purposes of the NPI.
If Whiting is notified by a person with whom Whiting is a party to a contract containing a prior reversionary interest that Whiting is required to convey any of the underlying properties to such person or cease production from any well, then Whiting may provide such conveyance with respect to such underlying property or permanently cease production from such well. Such a reversionary interest typically results from the provisions of a joint operating agreement that governs the drilling of wells on jointly owned property and financial arrangements for instances where all owners may not want to make the capital expenditure necessary to drill a new well. The reversionary interest is created because an owner that does not consent to capital expenditures will not have to pay its share of the capital expenditure, but instead will relinquish its share of proceeds from the well until the consenting owners receive payout (or a multiple of payout) of their capital expenditures. In such case, Whiting may request the Trustee to reconvey to Whiting the NPI with respect to any such underlying property or well. The Trust will not receive consideration for any such reconveyance of a portion of the NPI and, any such reconveyance of a portion of the NPI may extend the time it takes 11.79 MMBOE (10.61 MMBOE at the 90% NPI) to be produced from the underlying properties for purposes of the NPI.
The Trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the Trust units. If the IRS were to determine (and be sustained in that determination) that the Trust is not a “grantor trust” for federal income tax purposes, or that the NPI is not properly treated as a production payment (and thus could fail to qualify as a debt instrument) for federal income tax purposes, the Trust unitholders may receive different and potentially less advantageous tax treatment than they anticipated.
If the Trust were not treated as a grantor trust for federal income tax purposes, the Trust should be treated as a partnership for such purposes. Although the Trust would not become subject to federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the Trust unitholders, the Trust’s tax reporting requirements would be more complex and costly to implement and maintain, and its distributions to unitholders could be reduced as a result.
If the NPI were not treated as a debt instrument, any deductions allowed to an individual Trust unitholder in their recovery of basis in the NPI may be itemized deductions, the deductibility of which would be subject to limitations that may or may not apply depending upon the unitholder’s circumstances.
Neither Whiting nor the Trustee has requested a ruling from the IRS regarding these tax questions, and neither Whiting nor the Trust can assure that such a ruling would be granted if requested or that the IRS will not challenge this position on audit.
Thus, no assurance can be provided that the opinions and statements set forth in the discussion of U.S. federal income tax consequences would be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the Trust units and the prices at which Trust units trade. In addition, the costs of any contest with the IRS (whether or not such challenge is successful), principally legal, accounting and related fees, will result in a reduction in cash available for distribution to the Trust unitholders, and thus will be borne indirectly by the Trust unitholders.
Trust unitholders should be aware of the possible state tax implications of owning Trust units, and should consult their own tax advisors for advice regarding the state as well as federal tax implications of owning Trust units.
The Trust allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date, instead of on the basis of the date a particular Trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.
The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date, instead of on the basis of the date a particular Trust unit is transferred. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily, prorated or other basis, which could require adjustments to the tax returns of the Trust unitholders affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.
The tax treatment of an investment in Trust units could be affected by future legislative, judicial or administrative changes and differing opinions, possibly on a retroactive basis.
The U.S. federal income tax treatment of an investment in the Trust may be modified by administrative or legislative changes, or by judicial interpretation, at any time, possibly on a retroactive basis.
Trust unitholders will be required to pay taxes on their share of the Trust’s income even if they do not receive any cash distributions from the Trust.
For income tax purposes, Trust unitholders are treated as if they own the Trust’s taxable asset (which for tax purposes, is a loan receivable owed to the Trust from Whiting) and they receive the Trust’s income and are directly taxable thereon as if no trust were in existence. The Trust unitholders generally do not receive cash distributions from the Trust equal to their share of the Trust’s taxable income or even equal to the actual tax liability that results from that income. Because the Trust typically generates taxable income that is different in amount than the cash the Trust distributes, the Trust unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of the Trust’s taxable income even if they receive no cash distributions from the Trust.