Whiting USA Trust II - FORM 10-Q

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EX-31 - EX-31 - Whiting USA Trust II	d816618dex31.htm
EX-32 - EX-32 - Whiting USA Trust II	d816618dex32.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the quarterly period ended September 30, 2014

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the transition period from to

Commission File Number: 001-35459

WHITING USA TRUST II

(Exact name of registrant as specified in its charter)


Delaware		38-7012326
(State or other jurisdiction of incorporation or organization)		(I.R.S. employer identification no.)

The Bank of New York Mellon Trust Company, N.A., Trustee Global Corporate Trust 919 Congress Avenue Austin, Texas		78701
(Address of principal executive offices)		(Zip code)

(512) 236-6599

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

As of November 7, 2014, 18,400,000 Units of Beneficial Interest in Whiting USA Trust II were outstanding.

TABLE OF CONTENTS


Glossary of Certain Definitions		2

PART I – Financial Information

Item 1.	Financial Statements (Unaudited)	5
	Statements of Assets, Liabilities and Trust Corpus as of September 30, 2014 and December 31, 2013	5
	Statements of Distributable Income for the Three and Nine Months Ended September 30, 2014 and 2013	5
	Statements of Changes in Trust Corpus for the Three and Nine Months Ended September 30, 2014 and 2013	5
	Notes to Modified Cash Basis Financial Statements	6
Item 2.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	10
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	17
Item 4.	Controls and Procedures	18

PART II – Other Information

Item 1A.	Risk Factors	19
Item 6.	Exhibits	19
Signatures		20
Exhibit Index		21

GLOSSARY OF CERTAIN DEFINITIONS

The following are definitions of significant terms used in this report:

“August 2013 distribution” The cash distribution to Trust unitholders of record on August 19, 2013 that was paid on August 29, 2013.

“August 2014 distribution” The cash distribution to Trust unitholders of record on August 19, 2014 that was paid on August 29, 2014.

“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil and other liquid hydrocarbons.

“BOE” One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals one Bbl of natural gas liquids.

“Btu” or “British thermal unit” The quantity of heat required to raise the temperature of one pound of water one degree Fahrenheit.

“completion” The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“COPAS” The Council of Petroleum Accountants Societies, Inc.

“costless collar” An options position where the proceeds from the sale of a call option at its inception fund the purchase of a put option at its inception.

“deterministic method” The method of estimating reserves or resources using a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation.

“FASB ASC” The Financial Accounting Standards Board Accounting Standards Codification.

“February 2013 distribution” The cash distribution to Trust unitholders of record on February 19, 2013 that was paid on March 1, 2013.

“February 2014 distribution” The cash distribution to Trust unitholders of record on February 19, 2014 that was paid on March 3, 2014.

“field” An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.

“GAAP” Generally accepted accounting principles in the United States of America.

“gross wells” The total wells in which a working interest is owned.

“lease operating expense” or “LOE” The expenses of lifting oil or gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

“May 2013 distribution” The cash distribution to Trust unitholders of record on May 20, 2013 that was paid on May 30, 2013.

“May 2014 distribution” The cash distribution to Trust unitholders of record on May 20, 2014 that was paid on May 30, 2014.

“MBbl” One thousand barrels of crude oil or other liquid hydrocarbons.

“MBOE” One thousand BOE.

“Mcf” One thousand standard cubic feet, used in reference to natural gas.

“MMBOE” One million BOE.

“MMBtu” One million Btu.

“net profits interest” or “NPI” A nonoperating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.

“net wells” The sum of the fractional working interests owned in gross wells.

“November 2014 distribution” The cash distribution to Trust unitholders of record on November 19, 2014 which is payable on or before December 1, 2014.

“NYMEX” The New York Mercantile Exchange.

“plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.

“proved reserves” Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

The area of the reservoir considered as proved includes all of the following:

The area identified by drilling and limited by fluid contacts, if any, and

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and

The project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical), engineering and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

“reserves” Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“royalty” The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from crude oil or natural gas produced and sold, unencumbered by expenses relating to the drilling, completing or operating of the affected well.

“SEC” The United States Securities and Exchange Commission.

“working interest” The interest in a crude oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to share in production, subject to all royalties, overriding royalties and other burdens and the obligation to share in all costs of exploration, development and operations and all risks in connection therewith.

“workover” Operations on a producing well to restore or increase production.

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

WHITING USA TRUST II

Statements of Assets, Liabilities and Trust Corpus (Unaudited)

(In thousands, except unit data)


	September 30, 2014		December 31, 2013
ASSETS
Cash and short-term investments	$	245	$	221
Investment in net profits interest, net		126,544		144,990

Total assets	$	126,789	$	145,211

LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses	$	245	$	221
Trust corpus (18,400,000 Trust units issued and outstanding at September 30, 2014 and December 31, 2013)		126,544		144,990

Total liabilities and Trust corpus	$	126,789	$	145,211

Statements of Distributable Income (Unaudited)

(In thousands, except distributable income per unit data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Income from net profits interest	$	15,504		$	13,814		$	40,290		$	37,931
General and administrative expenses		(161	)		(181	)		(676	)		(644	)
Cash reserves withheld for current Trust expenses		(89	)		(19	)		(24	)		(56	)
State income tax withholding		(6	)		(10	)		(14	)		(25	)

Distributable income	$	15,248		$	13,604		$	39,576		$	37,206

Distributable income per unit	$	0.828699		$	0.739362		$	2.150892		$	2.022081

Statements of Changes in Trust Corpus (Unaudited)

(In thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Trust corpus, beginning of period	$	132,569		$	157,953		$	144,990		$	171,355
Distributable income		15,248			13,604			39,576			37,206
Distributions to unitholders		(15,248	)		(13,604	)		(39,576	)		(37,206	)
Amortization of investment in net profits interest		(6,025	)		(6,466	)		(18,446	)		(19,868	)

Trust corpus, end of period	$	126,544		$	151,487		$	126,544		$	151,487

The accompanying notes are an integral part of these modified cash basis financial statements.

WHITING USA TRUST II

NOTES TO MODIFIED CASH BASIS FINANCIAL STATEMENTS

(Unaudited)

1.	ORGANIZATION OF THE TRUST

Formation of the Trust — 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 Corporation (“Whiting Oil and Gas”), as trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (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 was created to acquire and hold a term net profits interest (“NPI”) for the benefit of the Trust unitholders pursuant to a conveyance from Whiting Oil and Gas, a 100%-owned subsidiary of Whiting, to the Trust. The term NPI is an interest in certain of Whiting Oil and Gas’ properties located in the Rocky Mountains, Permian Basin, Gulf Coast and Mid-Continent regions (the “underlying properties”). The NPI is the only asset of the Trust, other than cash reserves held for future Trust expenses. As of December 31, 2013, these oil and gas properties included interests in approximately 1,308 gross (388.5 net) producing oil and gas wells.

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 NPI entitles the Trust to receive 90% of the net proceeds from the sale of production from the underlying properties. The NPI will terminate on 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), and the Trust will soon thereafter wind up its affairs and terminate, after which it will pay no further distributions. As of September 30, 2014 on a cumulative accrual basis, 4.26 MMBOE (40%) of the Trust’s total 10.61 MMBOE have been produced and sold, and the remaining minimum reserve quantities of 6.35 MMBOE (at the 90% NPI) are projected to be produced prior to December 31, 2021, based on the Trust’s reserve report as of December 31, 2013. Since the Trust is not currently expected to contractually terminate until December 31, 2021, additional reserves and production attributable to the NPI may be available for distribution to unitholders (also based on the 2013 year-end reserve report) between the time that the Trust’s minimum 10.61 MMBOE have been produced and sold and the expected December 31, 2021 termination date of the Trust occurs. The Trust’s Annual Report on Form 10-K includes additional information on the Trust’s reserves as of December 31, 2013.

The Trustee can authorize the Trust to borrow money for the purpose of paying 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 that 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 distributable to the Trust.

Initial Issuance of Trust Units and Net Profits Interest Conveyance — On March 21, 2012, the registration statement on Form S-1/S-3 (Registration No. 333-178586) filed by Whiting and the Trust in connection with the initial public offering of the Trust’s units was declared effective by the SEC. On March 28, 2012, the Trust issued 18,400,000 Trust units to Whiting in exchange for the conveyance of the term NPI, which is described above, from Whiting Oil and Gas. Immediately thereafter, Whiting completed an initial public offering of units of beneficial interest in the Trust, selling 18,400,000 Trust units to the public at $20.00 per unit.

2.	BASIS OF ACCOUNTING

Interim Financial Statements — The accompanying unaudited financial information has been prepared by the Trustee in accordance with the instructions to the Quarterly Report on Form 10-Q. The accompanying financial information is prepared on a comprehensive basis of accounting other than GAAP. The Trustee believes that the information furnished reflects all adjustments (consisting of normal and recurring adjustments) which are, in the opinion of the Trustee, necessary for a fair presentation of the results for the interim periods presented. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The Trust’s 2013 Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q.

Term Net Profits Interest — The Trust uses the modified cash basis of accounting to report Trust receipts from the term NPI and payments of expenses incurred. Actual cash distributions to the Trust are made based on the terms of the conveyance that created the

Trust’s NPI. The term NPI entitles the Trust to receive revenues (oil, gas and natural gas liquid sales) less expenses (the amount by which all royalties; lease operating expenses including well workover costs; development costs; production and property taxes; payments made by Whiting to the hedge counterparty upon settlements of hedge contracts; maintenance expenses; producing overhead; and amounts that may be reserved for future development, maintenance or operating expenses, which reserve amounts may not exceed $2.0 million, exceed hedge payments received by Whiting under hedge contracts and other non-production revenue) of the underlying properties multiplied by 90% (term NPI percentage). Actual cash receipts may vary due to timing delays of cash receipts from the property operators or purchasers and due to wellhead and pipeline volume balancing agreements or practices.

Modified Cash Basis of Accounting — The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, liabilities, Trust corpus, earnings and distributions, as follows:

Income from net profits interest is recorded when NPI distributions are received by the Trust;

Distributions to Trust unitholders are recorded when paid by the Trust;

Trust general and administrative expenses (which include the Trustees’ fees as well as accounting, engineering, legal, and other professional fees) are recorded when paid;

Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under GAAP;

Amortization of the investment in net profits interest is calculated based on the units-of-production method. Such amortization is charged directly to Trust corpus and does not affect cash earnings; and

The Trust evaluates impairment of the investment in net profits interest by comparing the undiscounted cash flows expected to be realized from the investment in net profits interest to the NPI carrying value. If the expected future undiscounted cash flows are less than the carrying value, the Trust recognizes an impairment loss for the difference between the carrying value and the estimated fair value of the investment in net profits interest. The determination of whether the NPI is impaired requires a significant amount of judgment by the Trustee and is based on the best information available to the Trustee at the time of the evaluation. If market or oil and natural gas production conditions deteriorate, write-downs could be required in the future.

While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues and distributions is considered to be the most meaningful for the Trust’s activities and results because quarterly distributions to the Trust unitholders are based on net cash receipts. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by FASB ASC Topic 932, Extractive Activities – Oil and Gas: Financial Statements of Royalty Trusts.

Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues are received or expenses are paid. Because the Trust’s financial statements are prepared on the modified cash basis as described above, however, most accounting pronouncements are not applicable to the Trust’s financial statements.

Recent Accounting Pronouncements — There were no accounting pronouncements issued during the nine months ended September 30, 2014 applicable to the Trust or its financial statements.

3.	INVESTMENT IN NET PROFITS INTEREST

Whiting Oil and Gas conveyed the NPI to the Trust in exchange for 18,400,000 Trust units. The investment in net profits interest was recorded at the historical cost basis of Whiting on March 28, 2012, the date of conveyance (except for the derivatives which are reflected at their fair value as of March 31, 2012), and was calculated as follows (in thousands):


Oil and gas properties	$	368,786
Accumulated depletion		(174,626	)

Oil and gas properties, net		194,160
Derivative liability		(128	)

Net predecessor cost of net profits interest conveyed to the Trust	$	194,032

As of September 30, 2014 and December 31, 2013, accumulated amortization of the investment in net profits interest was $67.5 million and $49.0 million, respectively.

4.	INCOME TAXES

The Trust is a grantor trust and therefore is not subject to federal income taxes. Accordingly, no recognition is given to federal income taxes in the Trust’s financial statements. The Trust unitholders are treated as the owners of Trust income and corpus, and the entire taxable income of the Trust is reported by the Trust unitholders on their respective tax returns.

For Montana state income tax purposes, Whiting must withhold from its NPI payments to the Trust, an amount equal to 6% of the net amount payable to the Trust from the sale of oil and gas in Montana. For Arkansas, Colorado, Michigan, Mississippi, New Mexico, North Dakota and Oklahoma, neither the Trust nor Whiting is withholding the income tax due such states on distributions made to an individual resident or nonresident Trust unitholder, as long as the Trust is taxed as a grantor trust under the Internal Revenue Code.

5.	DISTRIBUTION TO UNITHOLDERS

Actual cash distributions to the Trust unitholders depend on the volumes of and prices received for oil, natural gas and natural gas liquids produced from the underlying properties, among other factors. Quarterly cash distributions during the term of the Trust are made by the Trustee no later than 60 days following the end of each quarter (or the next succeeding business day) to the Trust unitholders of record on the 50th day following the end of each quarter. Such amounts equal the excess, if any, of the cash received by the Trust during the quarter, over the expenses of the Trust paid during such quarter, subject to any adjustments for changes made by the Trustee during such quarter in any cash reserves established for future expenses of the Trust.

6.	RELATED PARTY TRANSACTIONS

Plugging and Abandonment — During the three and nine months ended September 30, 2014, Whiting incurred $0.1 million and $1.3 million, respectively, of plugging and abandonment costs on the underlying properties. Pursuant to the terms of the conveyance agreement, plugging and abandonment charges relating to the underlying properties, net of any proceeds received from the salvage of equipment, are funded entirely by Whiting and are not therefore included as a deduction in the calculation of net proceeds or otherwise deducted from Trust unitholders over the term of the Trust.

Operating Overhead — Pursuant to the terms of its applicable joint operating agreements, Whiting deducts from the gross oil and gas sales 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, which is customary practice in the oil and gas industry. Operating overhead activities include various engineering, legal, and administrative functions. 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. The following table presents the Trust’s portion of these overhead charges for the distribution made during the three and nine months ended September 30, 2014 and 2013:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Total overhead charges	$	436,579	$	423,434	$	1,311,630	$	1,236,100
Overhead charge per month per active operated well	$	446	$	432	$	447	$	420

Administrative Services Fee — Under the terms of the administrative services agreement, the Trust is obligated to pay a quarterly administration fee of $50,000 to Whiting 60 days following the end of each calendar quarter. General and administrative expenses in the Trust’s statements of distributable income for the three and nine months ended September 30, 2014 include $50,000 and $150,000, respectively, for quarterly administrative fees paid to Whiting, and general and administrative expenses in the Trust’s statements of distributable income for the three and nine months ended September 30, 2013 also include $50,000 and $150,000, respectively, for quarterly administrative fees paid to Whiting.

Trustee Administrative Fee — Under the terms of the Trust agreement, the Trust pays an annual administrative fee to the Trustee of $175,000, which is paid in four quarterly installments of $43,750 each and is billed in arrears. Starting in 2017, such fee escalates by 2.5% each year. General and administrative expenses in the Trust’s statements of distributable income for the three and nine months ended September 30, 2014 include $43,750 and $131,250, respectively, for quarterly administrative fees paid to the Trustee, and general and administrative expenses in the Trust’s statements of distributable income for the three and nine months ended September 30, 2013 also include $43,750 and $131,250, respectively, for quarterly administrative fees paid to the Trustee.

Letter of Credit — In June 2012, Whiting established a $1.0 million letter of credit for the Trustee in order to provide it with a mechanism to pay the operating expenses of the Trust, in the event that Whiting should fail to lend funds to the Trust if requested to do so by the Trustee. This letter of credit will not be used to fund NPI distributions to unitholders, and Whiting has no obligation to lend funds to the Trust. If the Trustee were to draw on the letter of credit or borrow funds from Whiting or otherwise, no further distributions would be made to unitholders until all such amounts have been repaid by the Trust.

7.	SUBSEQUENT EVENT

On November 6, 2014, the Trustee announced the Trust distribution of net profits for the third quarterly payment period in 2014. Unitholders of record on November 19, 2014 are expected to receive a distribution of $0.642014 per Trust unit, which is payable on or before December 1, 2014. This aggregate distribution to all Trust unitholders is expected to consist of net cash proceeds of $12.1 million paid by Whiting to the Trust, less a provision of $250,000 for estimated Trust expenses and $8,811 for Montana state income tax withholdings. There were no realized gains or losses on hedge settlements during the third quarterly payment period of 2014.

Item 2. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations

References to the “Trust” in this document refer to Whiting USA Trust II. References to “Whiting” in this document refer to Whiting Petroleum Corporation and its subsidiaries. References to “Whiting Oil and Gas” in this document refer to Whiting Oil and Gas Corporation, a 100%-owned subsidiary of Whiting Petroleum Corporation.

The following review of the Trust’s financial condition and results of operations should be read in conjunction with the financial statements and notes thereto, as well as the Trustee’s discussion and analysis contained in the Trust’s 2013 Annual Report on Form 10-K. The Trust’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports are available on the SEC’s website www.sec.gov.

Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Quarterly Report on Form 10-Q, including without limitation the statements under “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” are forward-looking statements. No assurance can be given that such expectations will prove to have been correct. When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q, could affect the future results of the energy industry in general, and Whiting and the Trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:

•

the effect of changes in commodity prices and conditions in the capital markets;

•

uncertainty of estimates of oil and natural gas reserves and production;

•

risks incident to the operation and drilling of oil and natural gas wells;

•

future production and development costs;

•

the inability to access oil and natural gas markets due to market conditions or operational impediments;

•

failure of the underlying properties to yield oil or natural gas in commercially viable quantities;

•

the effect of existing and future laws and regulatory actions;

•

competition from others in the energy industry;

•

risks arising out of the hedge contracts;

•

inflation or deflation; and

•

other risks described under the caption “Risk Factors” in the Trust’s 2013 Annual Report on Form 10-K.

All subsequent written and oral forward-looking statements attributable to Whiting or the Trust or persons acting on behalf of Whiting or the Trust are expressly qualified in their entirety by these factors. The Trustee assumes no obligation, and disclaims any duty, to update these forward-looking statements.

Overview and Trust Termination

The Trust does not conduct any operations or activities. The Trust’s purpose is, in general, to hold the NPI, to distribute to unitholders cash that the Trust receives pursuant to the NPI, and to perform certain administrative functions with respect to the NPI and the Trust units. The Trust derives substantially all of its income and cash flows from the NPI, which is in turn subject to commodity hedge contracts through December 31, 2014. The NPI entitles the Trust to receive 90% of the net proceeds from the sale of production from the underlying properties.

Oil and gas prices historically have been volatile and may fluctuate widely in the future. The table below highlights these price trends by listing quarterly average NYMEX crude oil and natural gas prices for the periods indicated through September 30, 2014. The August 2014 distribution in the third quarter of 2014 was mainly affected, however, by April 2014 through June 2014 oil prices and March 2014 through May 2014 natural gas prices.


	2012								2013								2014
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3
Crude Oil (per Bbl)	$	102.94	$	93.51	$	92.19	$	88.20	$	94.34	$	94.23	$	105.82	$	97.50	$	98.62	$	102.98	$	97.21
Natural Gas (per MMBtu)	$	2.72	$	2.21	$	2.81	$	3.41	$	3.34	$	4.10	$	3.58	$	3.60	$	4.93	$	4.68	$	4.07

In recent months, oil prices have begun to decline since reaching highs of over $105.00 per Bbl in June 2014, dropping below $80.00 per Bbl in October 2014. Lower oil and gas prices on production from the underlying properties could cause the following: (i) a reduction in the amount of net proceeds to which the Trust is entitled; and (ii) a reduction in the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties causing an extension of the length of time required to produce 11.79 MMBOE (10.61 MMBOE at the 90% NPI). Alternatively, higher oil and natural gas prices may potentially result in the following: (i) an increase in the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties, and (ii) cash settlement losses on commodity derivatives.

Trust Termination. The NPI will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE (10.61 MMBOE at the 90% NPI) have been produced from the underlying properties and sold, and the Trust will soon thereafter wind up its affairs and terminate, after which it will pay no further distributions. Since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the Trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment or yield. As a result, the market price of the Trust units will decline to zero at termination of the Trust. As of September 30, 2014 on a cumulative accrual basis, 4.26 MMBOE (40%) of the Trust’s total 10.61 MMBOE have been produced and sold (of which proceeds from the sale of 342 MBOE, which is 90% of 380 MBOE, will be distributed to the unitholders in the Trust’s forthcoming November 2014 distribution). The remaining minimum reserve quantities are projected to be produced prior to December 31, 2021, based on the Trust’s reserve report as of December 31, 2013. Since the Trust is not currently expected to contractually terminate until December 31, 2021, however, additional reserves and production attributable to the NPI may be available for distribution to unitholders (also based on the 2013 year-end reserve report) between the time that the Trust’s minimum 10.61 MMBOE have been produced and sold and the expected December 31, 2021 termination date of the Trust occurs. Accordingly, the Trust’s remaining reserves attributable to the 90% NPI were estimated to be 8.15 MMBOE as of December 31, 2013, which is more than the minimum, but there is no assurance that the Trust will receive more than the minimum amount of reserves. The Trust’s Annual Report on Form 10-K includes additional information on the Trust’s reserves as of December 31, 2013.

Capital Expenditure Activities

The primary goal of the planned capital expenditures relative to the underlying properties is to mitigate a portion of the natural decline in production from producing properties. The underlying properties have a capital expenditure budget per the December 31, 2013 reserve report of $31.5 million estimated to be spent over eight years. No assurance can be given, however, that any such expenditures will result in the production of commercially paying amounts, if any, or that the characteristics of any newly developed well will match the characteristics of existing wells on the underlying properties or the operator’s historical drilling success rate. In addition, no assurance can be given that Whiting’s actual level of capital expenditures on the underlying properties will meet this $31.5 million amount of budgeted capital expenditures over the next eight years. With respect to fields for which Whiting is not the operator, Whiting will have limited control over the timing and amount of capital expenditures relative to such fields. Please read the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013, Item 1A. Risk Factors “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.”

During each twelve-month period beginning on the later to occur of (1) December 31, 2017 and (2) the time when 8.24 MMBOE have been produced from the underlying properties and sold (which is the equivalent of 7.41 MMBOE attributable to the 90% NPI) (in either case, the “capital expenditure limitation date”), the sum of the capital expenditures and amounts reserved for approved capital expenditure projects for such twelve-month period 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 twelve-month periods ending on the capital expenditure limitation date, divided by (y) three. Commencing on the capital expenditure limitation date, and each anniversary of the capital expenditure limitation date thereafter, the average annual capital expenditure amount will be increased by 2.5% to account for expected increased costs due to inflation.

The following table presents the underlying properties’ aggregate capital expenditures attributable to the February 2014, May 2014 and August 2014 distributions (in thousands):


Region	2014 Capital Expenditures
Rocky Mountains	$	3,416
Permian Basin		2,927
Gulf Coast		660
Mid-Continent		3

Total	$	7,006

Results of Trust Operations

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

The following is a summary of income from net profits interest and distributable income received by the Trust for the nine months ended September 30, 2014 and 2013, consisting of the February, May and August distributions for each respective period (dollars in thousands, except per Bbl, per Mcf and per BOE amounts):


	Nine Months Ended September 30,
	2014			2013
Sales volumes:
Oil from underlying properties (Bbl)^(a)		918,298	^(c)		971,634	^(e)
Natural gas from underlying properties (Mcf)		1,727,718	^(c)		1,791,713	^(e)

Total production (BOE)		1,206,251			1,270,253
Average sales prices:
Oil (per Bbl)^(a)	$	87.36		$	81.36
Natural gas (per Mcf)	$	5.58	^(d)	$	4.72	^(d)
Costs (per BOE):
Lease operating expenses	$	27.68		$	25.90
Production taxes	$	3.90		$	3.53
Revenues:
Oil sales^(a)	$	80,222	^(c)	$	79,049	^(e)
Natural gas sales		9,647	^(c)		8,454	^(e)

Total revenues	$	89,869		$	87,503

Costs:
Lease operating expenses	$	33,391		$	32,897
Production taxes		4,705			4,484
Development costs		7,006			7,976
Cash settlements on commodity derivatives^(b)		—			—

Total costs	$	45,102		$	45,357


Net proceeds	$	44,767		$	42,146
Net profits percentage		90	%		90	%


Income from net profits interest	$	40,290		$	37,931

Provision for estimated Trust expenses		(700	)		(700	)
Montana state income tax withheld		(14	)		(25	)

Distributable income	$	39,576		$	37,206

(a)	Oil includes natural gas liquids.

(b)

As discussed in Item 3. Quantitative and Qualitative Disclosures About Market Risk in this Quarterly Report on Form 10-Q, all costless collar hedge contracts terminate as of December 31, 2014, and no additional hedges are allowed to be placed on Trust assets. Consequently, for all distributions after the February 2015 distribution, there will be no further cash settlements on commodity hedges, and the Trust will then have increased exposure to oil and natural gas price volatility.

(c)

Oil and gas sales volumes and related revenues for the nine months ended September 30, 2014 (consisting of Whiting’s February 2014, May 2014 and August 2014 distributions to the Trust) generally represent crude oil production from October 2013 through June 2014 and natural gas production from September 2013 through May 2014.

(d)	The average sales price of natural gas for the gas production months within the distribution period exceeded the average NYMEX gas prices for those same months within the period due to the “liquids rich” content of a portion of the natural gas volumes produced by the underlying properties.

(e)

Oil and gas sales volumes and related revenues for the nine months ended September 30, 2013 (consisting of Whiting’s February 2013, May 2013 and August 2013 distributions to the Trust) generally represent crude oil production from October 2012 through June 2013 and natural gas production from September 2012 through May 2013.

Income from Net Profits Interest. Income from net profits interest is recorded on a cash basis when NPI proceeds are received by the Trust from Whiting. NPI proceeds that Whiting remits to the Trust are based on the oil and gas production Whiting has received payment for within one month following the end of the most recent fiscal quarter. Whiting receives payment for its crude oil sales generally within 30 days following the month in which it is produced, and Whiting receives payment for its natural gas sales generally within 60 days following the month in which it is produced. Income from net profits interest is generally a function of oil and gas revenues, lease operating expenses, production taxes and development costs as follows:

Revenues. Oil and natural gas revenues were $2.4 million (or 3%) higher for the nine months ended September 30, 2014 as compared to the same 2013 period. Sales revenue is a function of average commodity prices realized and oil and gas volumes sold. The increase in revenue between periods was due to higher realized oil and natural gas prices, which were partially offset by a decrease in oil and natural gas production volumes. The average sales prices realized increased for crude oil by 7% and for natural gas by 18% between periods. Oil production volumes decreased by 53 MBbls (or 5%) when comparing the first nine months of 2014 to the same period in 2013 primarily due to i) normal field production decline, ii) four wells that were shut-in for a portion of the 2014 period and iii) one well that was temporarily abandoned at the end of 2013. The decline in oil production between periods was partially offset, however, by three newly drilled wells and two workover wells that came online during the last twelve months and differences in timing associated with revenues received from non-operated properties. Gas production volumes decreased by 64 MMcf (or 4%) between periods primarily due to normal field production decline and four wells that were shut-in for a portion of the 2014 period. The decline in gas production was partially offset, however, by i) two recompleted wells and two newly drilled wells that came online during the last twelve months and ii) differences in timing associated with revenues received from non-operated properties. Based on the December 31, 2013 reserve report, overall production attributable to the underlying properties is expected to decline at an average year-over-year rate of approximately 8.4% from 2014 through the estimated December 31, 2021 Trust termination date.

Lease Operating Expenses. Lease operating expenses (“LOE”) increased $0.5 million (or 2%) during the first nine months of 2014 compared to the same 2013 period primarily due to higher workover and electricity costs of $0.8 million and $0.4 million, respectively. These increases were partially offset by a decrease in ad valorem taxes of $0.5 million between periods. The higher overall LOE coupled with the decline in overall production volumes resulted in an increase in LOE on a per BOE basis of 7% between periods, from $25.90 during the first nine months of 2013 to $27.68 for the same period in 2014.

Production Taxes. Production taxes are typically calculated as a percentage of oil and gas revenues, and production taxes as a percent of revenues remained relatively consistent for the nine months ended September 30, 2014 and 2013 at 5.2% and 5.1%, respectively. Overall production taxes for the first nine months of 2014, however, increased $0.2 million (or 5%) as compared to the same period in 2013, primarily due to higher oil and natural gas sales revenue between periods.

Development Costs. Development costs for the nine months ended September 30, 2014 were $1.0 million (or 12%) lower as compared to the same 2013 period. This decrease was primarily related to i) reduced drilling activity in the Sandtank Bone Springs field of $0.9 million, ii) reduced drilling and facility expansion costs in the Rangely Weber field of $0.7 million and iii) fewer recompletions in the Keystone South field of $0.3 million. These development cost decreases were partially offset, however, by a well recompletion in the Deb field of $1.2 million during the nine months ended September 30, 2014.

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

The following is a summary of income from net profits interest and distributable income received by the Trust for the three months ended September 30, 2014 and 2013, consisting of the August distributions for each respective period (dollars in thousands, except per Bbl, per Mcf and per BOE amounts):


	Three Months Ended September 30,
	2014			2013
Sales volumes:
Oil from underlying properties (Bbl)^(a)		299,440	^(c)		314,344	^(e)
Natural gas from underlying properties (Mcf)		567,303	^(c)		594,295	^(e)

Total production (BOE)		393,991			413,393
Average sales prices:
Oil (per Bbl)^(a)	$	90.55		$	85.19
Natural gas (per Mcf)	$	5.67	^(d)	$	4.89	^(d)
Costs (per BOE):
Lease operating expenses	$	25.62		$	26.39
Production taxes	$	3.94		$	3.65
Revenues:
Oil sales^(a)	$	27,113	^(c)	$	26,780	^(e)
Natural gas sales		3,214	^(c)		2,907	^(e)

Total revenues	$	30,327		$	29,687

Costs:
Lease operating expenses	$	10,095		$	10,910
Production taxes		1,551			1,509
Development costs		1,454			1,919
Cash settlements on commodity derivatives^(b)		—			—

Total costs	$	13,100		$	14,338


Net proceeds	$	17,227		$	15,349
Net profits percentage		90	%		90	%


Income from net profits interest	$	15,504		$	13,814

Provision for estimated Trust expenses		(250	)		(200	)
Montana state income tax withheld		(6	)		(10	)

Distributable income	$	15,248		$	13,604

(a)	Oil includes natural gas liquids.

(b)

(c)	Oil and gas sales volumes and related revenues for the three months ended September, 2014 (consisting of Whiting’s August 2014 distribution to the Trust) generally represent crude oil production from April 2014 through June 2014 and natural gas production from March 2014 through May 2014.

(d)	The average sales price of natural gas for the gas production months within the distribution period exceeded the average NYMEX gas prices for those same months within the period due to the “liquids rich” content of a portion of the natural gas volumes produced by the underlying properties.

(e)	Oil and gas sales volumes and related revenues for the three months ended September 30, 2013 (consisting of the August 2013 distribution) generally represent crude oil production from April 2013 through June 2013 and natural gas production from March 2013 through May 2013.

Revenues. Oil and natural gas revenues were $0.6 million (or 2%) higher for the three months ended September 30, 2014 as compared to the same 2013 period. Sales revenue is a function of average commodity prices realized and oil and gas volumes sold. The increase in revenue between periods was due to higher realized oil and natural gas prices, which were partially offset by a decrease in oil and natural gas production volumes. The average sales prices realized increased for crude oil by 6% and for natural gas by 16% between periods. Oil production volumes decreased by 15 MBbls (or 5%) when comparing the third quarter of 2014 to the same period in 2013 primarily due to i) normal field production decline, ii) two wells that were shut-in for a portion of the 2014 period and iii) one well that was temporarily abandoned at the end of 2013. The decline in oil production was partially offset, however, by one newly drilled well and one workover well that came online during the last twelve months and differences in timing associated with revenues received from non-operated parties. Gas production volumes decreased by 27 MMcf (or 5%) between periods primarily due to normal field production decline. The decline in gas production between periods was partially offset, however, by i) two newly drilled wells and one recompleted well that came online during the last twelve months and ii) differences in timing associated with revenues received from non-operated properties. Based on the December 31, 2013 reserve report, overall production attributable to the underlying properties is expected to decline at an average year-over-year rate of approximately 8.4% from 2014 through the estimated December 31, 2021 Trust termination date.

Lease Operating Expenses. Lease operating expenses (“LOE”) decreased $0.8 million (or 7%) during the third quarter of 2014 compared to the same 2013 period primarily due to lower costs of oilfield goods and services and ad valorem taxes of $0.5 million and $0.3 million, respectively. LOE on a per BOE basis declined 3% between periods, from $26.39 during the third quarter of 2013 to $25.62 for the same period in 2014 primarily due to lower overall LOE, partially offset by the decrease in overall production volumes, during the third quarter of 2014 versus the third quarter of 2013.

Production Taxes. Production taxes are typically calculated as a percentage of oil and gas revenues, and production taxes as a percent of revenues remained consistent for the three months ended September 30, 2014 and 2013 at 5.1%. Overall production taxes during the three months ended September 30, 2014 and 2013 were also consistent at $1.6 million and $1.5 million, respectively.

Development Costs. Development costs for the three months ended September 30, 2014 were $0.5 million (or 24%) lower as compared to 2013 development costs for the same period. This decrease was primarily related to reduced drilling and facility expansion costs in the Rangely Weber field of $0.6 million.

Liquidity and Capital Resources

The Trust has no source of liquidity or capital resources other than cash flows from the NPI. Other than Trust administrative expenses, including any reserves established by the Trustee for future liabilities, the Trust’s only use of cash is for distributions to Trust unitholders. Administrative expenses include payments to the Trustee and the Delaware Trustee, a quarterly fee paid to Whiting pursuant to an administrative services agreement, and expenses in connection with the discharge of the Trustee’s duties, including third party engineering, audit, accounting and legal fees. Each quarter, the Trustee determines the amount of funds available for distribution to unitholders. Available funds are the excess cash, if any, received by the Trust from the NPI and other sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the Trust’s expenses for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities. The Trustee may borrow funds required to pay liabilities if the Trustee determines that the cash on hand and the cash to be received are insufficient to cover the Trust’s liabilities. If the Trustee borrows funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid.

Income to the Trust from the NPI is based on the calculation and definitions of “gross proceeds” and “net proceeds” contained in the conveyance agreement, which is filed as an exhibit to this report, and reference is hereby made to such conveyance agreement for the actual definitions of “gross proceeds” and “net proceeds”.

Whiting may reserve from the gross proceeds amounts up to a total of $2.0 million at any time for future development, maintenance or operating expenses. However, Whiting has not funded such a reserve since the inception of the Trust, including during the three and nine months ended September 30, 2014 and 2013. Instead, Whiting deducted from the gross proceeds only actual costs paid for development, maintenance and operating expenses.

Plugging and abandonment costs related to the underlying properties, net of any proceeds received from the salvage of equipment, cannot be included as a deduction in the calculation of net proceeds pursuant to the terms of the conveyance agreement. During the three and nine months ended September 30, 2014, Whiting incurred $0.1 million and $1.3 million, respectively, of plugging and abandonment charges on the underlying properties that were not charged to the unitholders of the Trust.

In June 2012, Whiting established a letter of credit in the amount of $1.0 million in favor of the Trustee to provide a mechanism for the Trustee to pay the operating expenses of the Trust, in the event that Whiting should fail to lend funds to the Trust if requested to do so by the Trustee. This letter of credit will not be used to fund NPI distributions to unitholders, and Whiting has no obligation to lend funds to the Trust. If the Trustee were to draw on the letter of credit or borrow funds from Whiting or otherwise, no further distributions would be made to unitholders until all such amounts have been repaid by the Trust.

The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources.

Future Trust Distributions to Unitholders

New Accounting Pronouncements

There were no accounting pronouncements issued during the nine months ended September 30, 2014 applicable to the Trust or its financial statements.

Critical Accounting Policies and Estimates

A disclosure of critical accounting policies and the more significant judgments and estimates used in the preparation of the Trust’s financial statements is included in Item 7 of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2013. There have been no significant changes to the critical accounting policies during the nine months ended September 30, 2014.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Hedge Contracts

The primary asset of and source of income to the Trust is the term NPI, which generally entitles the Trust to receive 90% of the net proceeds from oil and gas production from the underlying properties. Consequently, the Trust is exposed to market risk from fluctuations in oil and gas prices. Through 2014, however, the NPI is subject to commodity hedge contracts in the form of costless collars entered into by Whiting, which are intended to reduce, but not eliminate, the NPI’s exposure to crude oil price volatility. 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.

The revenues derived from the underlying properties depend substantially on prevailing crude oil, natural gas and natural gas liquids prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil, natural gas and natural gas liquids that Whiting can economically produce. Whiting sells the oil, natural gas and natural gas liquid production from the underlying properties under floating market price contracts each month. Whiting entered into certain hedge contracts through December 31, 2014 to manage the exposure to crude oil price volatility associated with revenues generated from the underlying properties, and to achieve more predictable cash flows. However, these contracts also limit the amount of cash available for distribution if prices increase above the fixed ceilings of the hedges. The hedge contracts consist of costless collar arrangements placed with a single trading counterparty, JPMorgan Chase Bank National Association. Whiting cannot provide assurance that this trading counterparty will not become a credit risk in the future.

Crude oil costless collar arrangements settle based on the average of the closing settlement price for each commodity business day in the contract period. In a collar arrangement, the counterparty is required to make a payment to Whiting for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. Whiting is required to make a payment to the hedge counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price.

In connection with Whiting’s conveyance on March 28, 2012 of the term NPI to the Trust, the rights to any future hedge payments Whiting makes or receives on certain of its derivative contracts (representing 119 MBbl of crude oil from October through December 2014) were also conveyed to the Trust. As a result, such hedge payments, if any, will be included in the Trust’s calculation of net proceeds, and Trust unitholders thereby would receive 90% of the future economic results of such hedges.

The table below summarizes all of the outstanding costless collars that Whiting entered into and then in turn conveyed, as described in the preceding paragraph, to the Trust (of which Trust unitholders receive 90% of the future economic results). This quantity of hedged oil volumes represents approximately 36% of the underlying properties’ projected oil production from October through December 2014, based on the estimated production of proved reserves in the Trust’s December 31, 2013 reserve report.


	Crude Oil Collars
	Volumes (Bbl)		Price (per Bbl) Floor / Ceiling
Three months ending December 31, 2014		119,100	$	80.00/$122.50

The collared hedges shown above have the effect of providing a protective floor while allowing Trust unitholders to share in upward price movements up to the ceiling. Consequently, while these hedges are designed to decrease exposure to price decreases, they also have the effect of limiting the benefit of price increases beyond the ceiling. For the crude oil contracts listed above, a hypothetical $10.00 change in the NYMEX price above the ceiling price or below the floor price applied to the notional amounts would cause an aggregate change in the estimated future cash settlements on all oil commodity derivatives of $1.2 million to Whiting, of which 90% would be transferred to the Trust. These hypothetical cash settlements would be recognized as contracts expire in the future periods through the remainder of 2014.

Any cash amounts received by Whiting from the counterparty upon settlements of these hedge contracts will reduce the production and development costs related to the underlying properties when calculating net proceeds. However, if the hedge payments received by Whiting under the hedge contracts and other non-production revenue exceed production and development costs during a quarterly period, the ability to use such excess amounts to offset such costs may be deferred, with interest accruing on such amounts at the prevailing money market rate, until the next quarterly period where the hedge payments and the other non-production revenue are less than such costs. In addition, the aggregate amounts paid by Whiting on settlement of the hedge contracts will reduce the amount of net proceeds paid to the Trust.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by Whiting to The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, the Trustee carried out an evaluation of the Trustee’s disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.

Due to the contractual arrangements of (i) the Trust agreement and (ii) the conveyance of the NPI, the Trustee relies on (A) information provided by Whiting, including historical operating data, plans for future operating and capital expenditures, reserve information and information relating to projected production, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers. For a description of certain risks relating to these arrangements and risks relating to the Trustee’s reliance on information reported by Whiting and included in the Trust’s results of operations, see the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013, Item 1A. Risk Factors “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.”

Changes in Internal Control over Financial Reporting. During the quarter ended September 30, 2014, there has been no change in the Trustee’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trustee’s internal control over financial reporting relating to the Trust. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of Whiting.

PART II – OTHER INFORMATION

Item 1A. Risk Factors

Risk factors relating to the Trust are contained in Item 1A of the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013. No material change to such risk factors has occurred during the nine months ended September 30, 2014.

Item 6. Exhibits

The exhibits listed in the accompanying exhibit index are filed as part of this Quarterly Report on Form 10-Q.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


WHITING USA TRUST II

By:	THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.

	By:	/s/ MIKE ULRICH
		Mike Ulrich
		Vice President

November 7, 2014

The Registrant, Whiting USA Trust II, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available, and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that such function exists pursuant to the terms of the Trust agreement under which it serves.

EXHIBIT INDEX


Exhibit Number		Description
3.1*		Certificate of Trust of Whiting USA Trust II [Incorporated herein by reference to Exhibit 3.3 to the Registration Statement on Form S-1 (Registration No. 333-178586)].

3.2*		Amended and Restated Trust Agreement, dated March 28, 2012, by and among Whiting Oil and Gas Corporation, The Bank of New York Mellon Trust Company, N.A. as Trustee and Wilmington Trust, National Association, as Delaware Trustee [Incorporated herein by reference to Exhibit 3.1 to the Trust’s Current Report on Form 8-K filed on March 28, 2012 (File No. 001-35459)].

10.1*		Conveyance and Assignment, dated March 28, 2012, from Whiting Oil and Gas Corporation to The Bank of New York Mellon Trust Company, N.A. as Trustee of Whiting USA Trust II [Incorporated herein by reference to Exhibit 10.1 to the Trust’s Current Report on Form 8-K filed on March 28, 2012 (File No. 001-35459)].

10.2*		Administrative Services Agreement, dated March 28, 2012, by and between Whiting Oil and Gas Corporation and Whiting USA Trust II [Incorporated herein by reference to Exhibit 10.2 to the Trust’s Current Report on Form 8-K filed on March 28, 2012 (File No. 001-35459)].

31		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(*	Asterisk indicates exhibit previously filed with the SEC and incorporated herein by reference.)

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