Edgar Filing: BP PRUDHOE BAY ROYALTY TRUST

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Form 10-Q

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 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 June 30, 2016

¨	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 1-10243

BP PRUDHOE BAY ROYALTY TRUST

(Exact Name of Registrant as Specified in Its Charter)


Delaware		13-6943724
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

The Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Houston, TX		77002
		77002
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s Telephone Number, Including Area Code: (713) 483-6020

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 (17 CFR § 232.405) 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 August 9, 2016, 21,400,000 Units of Beneficial Interest were outstanding.

PART I

FINANCIAL INFORMATION

Item 1.

Financial Statements

BP Prudhoe Bay Royalty Trust

Statements of Assets, Liabilities and Trust Corpus

(Prepared on a modified basis of cash receipts and disbursements)

(In thousands, except unit data)


	June 30,		December 31,
	2016		2015
	(Unaudited)
Assets
Cash and cash equivalents (Note 2)	$	1,002	$	1,002

Total assets	$	1,002	$	1,002

Liabilities and Trust Corpus
Accrued expenses	$	459	$	252
Trust corpus (40,000,000 units of beneficialinterest authorized, 21,400,000 units issuedand outstanding)		543		750

Total liabilities and trust corpus	$	1,002	$	1,002

See accompanying notes to financial statements (unaudited).

BP Prudhoe Bay Royalty Trust

Statements of Cash Earnings and Distributions

(Prepared on a modified basis of cash receipts and disbursements)

(Unaudited)

(In thousands, except unit data)


	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Royalty revenues	$	1,951		$	21,891		$	15,072		$	79,580
Interest income		1			—			1			—
Less: Trust administrative expenses		(410	)		(514	)		(651	)		(671	)

Cash earnings	$	1,542		$	21,377		$	14,422		$	78,909

Cash distributions	$	1,542		$	21,377		$	14,422		$	78,909

Cash distributions per unit	$	0.0721		$	0.9989		$	0.6739		$	3.6873

Units outstanding		21,400,000			21,400,000			21,400,000			21,400,000

See accompanying notes to financial statements (unaudited).

BP Prudhoe Bay Royalty Trust

Statements of Changes in Trust Corpus

(Prepared on a modified basis of cash receipts and disbursements)

(Unaudited)

(In thousands)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Trust corpus at beginning of period	$	584		$	479		$	750		$	833
Cash earnings		1,542			21,377			14,422			78,909
(Increase) decrease in accrued expenses		(41	)		148			(207	)		(206	)
Cash distributions		(1,542	)		(21,377	)		(14,422	)		(78,909	)

Trust corpus at end of period	$	543		$	627		$	543		$	627

See accompanying notes to financial statements (unaudited).

BP Prudhoe Bay Royalty Trust

Notes to Financial Statements (Unaudited)

(Prepared on a modified basis of cash receipts and disbursements)

June 30, 2016

(1) Formation of the Trust and Organization

BP Prudhoe Bay Royalty Trust (the “Trust”), a grantor trust, was created as a Delaware business trust pursuant to a Trust Agreement dated February 28, 1989 (the “Trust Agreement”) among The Standard Oil Company (“Standard Oil”), BP Exploration (Alaska) Inc. (“BP Alaska”), The Bank of New York Mellon, as trustee, and BNY Mellon Trust of Delaware (successor to The Bank of New York (Delaware)), as co-trustee. Standard Oil and BP Alaska are indirect wholly-owned subsidiaries of BP p.l.c. (“BP”). On December 15, 2010, The Bank of New York Mellon resigned as trustee and was replaced by The Bank of New York Mellon Trust Company, N.A., a national banking association, as successor trustee (the “Trustee”).

On February 28, 1989, Standard Oil conveyed an overriding royalty interest (the “Royalty Interest”) to the Trust. The Trust was formed for the sole purpose of owning and administering the Royalty Interest. The Royalty Interest represents the right to receive a per barrel royalty (the “Per Barrel Royalty”) of 16.4246% on the lesser of (a) the first 90,000 barrels of the average actual daily net production of oil and condensate per quarter or (b) the average actual daily net production of oil and condensate per quarter from BP Alaska’s working interests as of February 28, 1989 in the Prudhoe Bay field situated on the North Slope of Alaska (the “1989 Working Interests”). Trust Unit holders are subject to the risk that production will be interrupted or discontinued or fall, on average, below 90,000 barrels per day in any quarter. BP has guaranteed the performance of BP Alaska of its payment obligations with respect to the Royalty Interest.

Effective January 1, 2000, BP Alaska and all other Prudhoe Bay working interest owners cross-assigned interests in the Prudhoe Bay field pursuant to the Prudhoe Bay Unit Alignment Agreement. BP Alaska retained all rights, obligations, and liabilities associated with the Trust.

The trustees of the Trust are The Bank of New York Mellon Trust Company, N.A. and BNY Mellon Trust of Delaware, a Delaware banking corporation. BNY Mellon Trust of Delaware serves as co-trustee in order to satisfy certain requirements of the Delaware Statutory Trust Act. The Bank of New York Mellon Trust Company, N.A. alone is able to exercise the rights and powers granted to the Trustee in the Trust Agreement.

The Per Barrel Royalty in effect for any day is equal to the price of West Texas Intermediate crude oil (the “WTI Price”) for that day less scheduled Chargeable Costs (adjusted for inflation) and Production Taxes (based on statutory rates then in effect).

The Trust is passive, with the Trustee having only such powers as are necessary for the collection and distribution of revenues, the payment of Trust liabilities, and the protection of the Royalty Interest. The Trustee, subject to certain conditions, is obligated to establish cash reserves and borrow funds to pay liabilities of the Trust when they become due. The Trustee

BP Prudhoe Bay Royalty Trust

Notes to Financial Statements (Unaudited)

(Prepared on a modified basis of cash receipts and disbursements)

June 30, 2016

may sell Trust properties only (a) as authorized by a vote of the Trust Unit holders, (b) when necessary to provide for the payment of specific liabilities of the Trust then due (subject to certain conditions) or (c) upon termination of the Trust. Each Trust Unit issued and outstanding represents an equal undivided share of beneficial interest in the Trust. Royalty payments are received by the Trust and distributed to Trust Unit holders, net of Trust expenses, in the month succeeding the end of each calendar quarter. The Trust will terminate (i) upon a vote of holders of not less than 60% of the outstanding Trust Units, or (ii) at such time the net revenues from the Royalty Interest for two successive years are less than $1,000,000 per year (unless the net revenues during such period are materially and adversely affected by certain events).

In order to ensure that the Trust has the ability to pay future expenses, the Trust established a cash reserve account, which the Trustee believes is sufficient to pay approximately one year’s current and expected liabilities and expenses of the Trust.

(2) Basis of Accounting

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

Revenues are recorded when received (generally within 15 days of the end of the preceding quarter) and distributions to Trust Unit holders are recorded when paid.

Trust expenses (which include accounting, engineering, legal, and other professional fees, trustees’ fees, and out-of-pocket expenses) are recorded on an accrual basis.

Cash reserves may be established by the Trustee for certain contingencies that would not be recorded under generally accepted accounting principles.

While these statements differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America, the modified cash basis of reporting revenues and distributions is considered to be the most meaningful because quarterly distributions to the Trust Unit holders are based on net cash receipts. These modified cash basis financial statements are unaudited but, in the opinion of the Trustee, include all adjustments necessary to present fairly the assets, liabilities and corpus of the Trust as of June 30, 2016 and December 31, 2015, and the modified cash basis of earnings and distributions and changes in Trust corpus for the three and six-month periods ended June 30, 2016 and 2015. The adjustments are of a normal recurring nature and are, in the opinion of the Trustee, necessary to fairly present the results of operations.

As of June 30, 2016 and December 31, 2015, cash equivalents which represent the cash reserve consist of a Morgan Stanley ILF Treasury Fund.

BP Prudhoe Bay Royalty Trust

Notes to Financial Statements (Unaudited)

(Prepared on a modified basis of cash receipts and disbursements)

June 30, 2016

Estimates and assumptions are required to be made regarding assets, liabilities and changes in Trust corpus resulting from operations when financial statements are prepared. Changes in the economic environment, financial markets and any other parameters used in determining these estimates could cause actual results to differ, and the differences could be material.

These unaudited financial statements should be read in conjunction with the financial statements and related notes in the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015. The cash earnings and distributions for the interim periods presented are not necessarily indicative of the results to be expected for the full year.

(3) Royalty Interest

At inception in February 1989, the Royalty Interest held by the Trust had a carrying value of $535,000,000. In accordance with generally accepted accounting principles, the Trust amortized the value of the Royalty Interest based on the units of production method. Such amortization was charged directly to the Trust corpus, and did not affect cash earnings. In addition, the Trust periodically evaluated impairment of the Royalty Interest by comparing the undiscounted cash flows expected to be realized from the Royalty Interest to the carrying value, pursuant to the Financial Accounting Standards Board Accounting Standards Codification 360, Property, Plant, and Equipment. If the expected future undiscounted cash flows were less than the carrying value, the Trust recognized impairment losses for the difference between the carrying value and the estimated fair value of the Royalty Interest. By December 31, 2010, the Trust had recognized accumulated amortization of $359,473,000 and aggregate impairment write-downs of $175,527,000 reducing the carrying value of the Royalty Interest to zero.

(4) Income Taxes

The Trust files its federal tax return as a grantor trust subject to the provisions of subpart E of Part I of Subchapter J of the Internal Revenue Code of 1986, as amended, rather than as an association taxable as a corporation. The Trust Unit holders are treated as the owners of Trust income and corpus, and the entire taxable income of the Trust will be reported by the Trust Unit holders on their respective tax returns.

If the Trust were determined to be an association taxable as a corporation, it would be treated as an entity taxable as a corporation on the taxable income from the Royalty Interest, the Trust Unit holders would be treated as shareholders, and distributions to Trust Unit holders would not be deductible in computing the Trust’s tax liability as an association.

BP Prudhoe Bay Royalty Trust

Notes to Financial Statements (Unaudited)

(Prepared on a modified basis of cash receipts and disbursements)

June 30, 2016

(5) Alaska Oil and Gas Production Tax

The Alaska oil and gas production tax statutes were amended by a bill (the “2006 Amendments”) which became effective in August 2006. The 2006 Amendments replaced an oil production tax levied at the flat rate of 15% of the gross value at the point of production (the “wellhead” or “field” value) of taxable oil produced from a producer’s leases or properties in the State of Alaska. Under the 2006 Amendments, producers were taxed on the “production tax value of taxable oil” (gross value at the point of production for the calendar year less the producer’s direct costs of exploring for, developing, or producing oil or gas deposits located within the producer’s leases or properties in Alaska for the year) at a rate equal to the sum of 22.5% plus a “progressivity” rate determined by the average monthly production tax value of the oil produced. The progressivity rate imposed by the 2006 Amendments was equal to 0.25% times the amount by which the simple average for each calendar month of the daily production tax values per barrel of the oil produced during the month exceeded $40 per barrel.

In December 2007, a bill (popularly titled “Alaska’s Fair and Equitable Share” or “ACES”) took effect which further amended the Alaska oil and gas production tax statutes in certain respects. ACES changed the basic tax rate from 22.5% to 25% and increased the progressivity rate. If the producer’s average monthly production tax value per barrel is greater than $30 but not more than $92.50, the progressivity tax rate is 0.4% times the amount by which the average monthly production tax value exceeds $30 per barrel. If the producer’s average monthly production tax value per barrel is greater than $92.50, the progressivity tax rate is the sum of 25% and the product of 0.1% multiplied by the difference between the average monthly production tax value per barrel and $92.50, except that the sum may not exceed 50%.

The Trustee and BP Alaska entered into a letter agreement in October 2006 and an amendment thereto in January 2008 (the “Letter Agreement”) to resolve issues associated with the 2006 Amendments and ACES. The Letter Agreement modified the calculation of Production Taxes in the daily Per Barrel Royalty calculation effective as of August 20, 2006, in the case of the 2006 Amendments, and effective December 20, 2007, in the case of ACES. It also provides that the retroactivity provisions of the respective tax bills are not applicable to the Per Barrel Royalty calculation for periods prior to the effective dates of the 2006 Amendments and ACES.

On April 14, 2013, Alaska’s legislature passed an oil-tax reform bill aimed at encouraging oil production and investment in Alaska’s oil industry. On May 21, 2013, Alaska Governor Sean Parnell signed the bill into law as chapter 10 of the 2013 Session Laws of Alaska (the “Act”). Among significant changes, the Act eliminated the monthly “progressivity” tax rate implemented by 2006 Amendments and ACES, increased the base rate from 25% to 35% and added a stair-step per-barrel tax credit for oil production. This tax credit is based on the gross value at the point of production per barrel of taxable oil and may not reduce a producer’s tax

BP Prudhoe Bay Royalty Trust

Notes to Financial Statements (Unaudited)

(Prepared on a modified basis of cash receipts and disbursements)

June 30, 2016

liability below the “minimum tax” (which is a percentage, ranging from zero to 4%, of the gross value at the point of production of a producer’s taxable production during the calendar year based on the average price per barrel for Alaska North Slope crude oil for sale on the United States West Coast for the year) under the Production Tax Statutes. These changes became effective on January 1, 2014.

On January 15, 2014, the Trustee executed a letter agreement with BP Alaska dated January 15, 2014 (the “2014 Letter Agreement”) regarding the implementation of the Act with respect to the Trust. Pursuant to the 2014 Letter Agreement, Production Taxes for the Trust’s Royalty Production will equal the tax for the relevant quarter, minus the allowable monthly stair-step per-barrel tax credits for the Royalty Production during that quarter. If there is a “minimum tax”-related limitation on the amount of the stair-step per-barrel tax credits that could otherwise be claimed for any quarter during the year, any difference between that limitation as preliminarily determined on a quarterly basis and the actual limitation for the entire year will be reflected in the payment to the Trust for the first quarter Royalty Production in the following year.

On July 6, 2015, BP Alaska and the Trustee signed a letter agreement (the “2014 Letter Agreement Amendment”) amending the 2014 Letter Agreement to provide that if there is a “minimum tax”-related limitation on the amount of the stair-step per-barrel tax credits that could otherwise be claimed for any quarter during the year, any difference between that limitation as preliminarily determined on a quarterly basis and the actual limitation for the entire year will be reflected in the payment to the Trust for the fourth quarter Royalty Production payment for such year rather than in the payment to the Trust for the first quarter Royalty Production in the following year. The 2014 Letter Agreement Amendment became effective immediately.

(6) Royalty Revenue Adjustments

Certain of the royalty payments received by the Trust in 2016 and 2015 were adjusted by BP Alaska to compensate for underpayments or overpayment of the royalties due with respect to the quarters ended prior to the dates of such payments. Average net production of crude oil and condensate from the proved reserves allocated to the Trust was less than 90,000 barrels per day during certain quarters. Royalty payments by BP Alaska with respect to those quarters were based on estimates by BP Alaska of production levels because actual data was not available by the date on which payments were required to be made to the Trust. Subsequent recalculation by BP Alaska of the royalty payments due based on actual production data resulted in the payment adjustments shown in the table below (in thousands). In addition, the payment received in January 2015 included an adjustment of the royalty payment due with respect to the quarters ended June 30, 2014 and September 30, 2014. The underpayment was a result of the BP Operating unit reaching the cumulative condensate limit of 1,175,000,000 barrels as of June 8, 2014. Once the cumulative condensate limit had been reached the production associated with condensate was subject to the Oil Rim Initial

BP Prudhoe Bay Royalty Trust

Notes to Financial Statements (Unaudited)

(Prepared on a modified basis of cash receipts and disbursements)

June 30, 2016

Participating Area royalty interest of 50.6848339% instead of the Gas Cap Participating Area Royalty Interest of 13.8398950%. This allocation of the condensate production to the Oil Rim Initial Participating Interest remains in effect.


	Payments Received (In Thousands)
	Jan. 2016			Apr. 2015		Jan. 2015
Royalty payment as calculated	$	13,168		$	21,832	$	48,150
Adjustment for previous quarter’s underpayment (overpayment), plus accrued interest		(47	)		59		9,539

Total payment received	$	13,121		$	21,891	$	57,689

(7) Subsequent Event

In July 2016 the Trust received a payment of $15,110,437 from BP Alaska, representing the royalty payment due with respect to the Trust’s Royalty Interest for the quarter ended June 30, 2016. On July 20, 2016, after deducting Trust administrative expenses, the Trustee distributed $14,659,918 to Unit holders of record on July 16, 2016.

Item 2.

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

Cautionary Statement

This report contains forward looking statements (that is, statements anticipating future events or conditions and not statements of historical fact). Words such as “anticipate,” “expect,” “believe,” “intend,” “plan” or “project,” and “should,” “would,” “could,” “potentially,” “possibly” or “may,” and other words that convey uncertainty of future events or outcomes are intended to identify forward-looking statements. Forward-looking statements in this report are subject to a number of risks and uncertainties beyond the control of the Trustee. These risks and uncertainties include such matters as future changes in oil prices, oil production levels, economic activity, domestic and international political events and developments, legislation and regulation, and certain changes in expenses of the Trust.

The actual results, performance and prospects of the Trust could differ materially from those expressed or implied by forward-looking statements. Descriptions of material risks known to the Trustee that could affect the future performance of the Trust appear in Item 1A, “Risk Factors,” of the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015 (the “2015 Annual Report”). There may be additional risks of which the Trustee is unaware or which are currently deemed immaterial.

In the light of these risks, uncertainties and assumptions, you should not rely unduly on any forward-looking statements. Forward-looking events and outcomes discussed in the 2015 Annual Report and in this report may not occur or may transpire differently. The Trustee undertakes no obligation to update forward-looking statements after the date of this report, except as required by law, and all such forward-looking statements in this report are qualified in their entirety by the preceding cautionary statements.

Liquidity and Capital Resources

The Trust is a passive entity. The Trustee’s activities are limited to collecting and distributing the revenues from the Royalty Interest and paying liabilities and expenses of the Trust. Generally, the Trust has no source of liquidity and no capital resources other than the revenue attributable to the Royalty Interest that it receives from time to time. (See the discussion under “THE ROYALTY INTEREST” in Part I, Item 1 of the 2015 Annual Report for a description of the calculation of the Per Barrel Royalty, and the discussion under “THE PRUDHOE BAY UNIT AND FIELD – Reserve Estimates” in Part I, Item 1 of the 2015 Annual Report for information concerning the estimated future net revenues of the Trust.) However, the Trustee has a limited power to borrow, establish a cash reserve, or dispose of all or part of the Trust Estate, under limited circumstances pursuant to the terms of the Trust Agreement. See the discussion under “THE TRUST” in Part I, Item 1 of the 2015 Annual Report.

Since 1999, the Trustee has maintained a $1,000,000 cash reserve to provide liquidity to the Trust during any future periods in which the Trust does not receive a distribution. The Trustee will draw funds from the cash reserve account during any quarter in which the quarterly distribution received by the Trust does not exceed the liabilities and expenses of the Trust, and will replenish the reserve from future quarterly distributions, if any. The Trustee anticipates that it will keep this cash reserve program in place until termination of the Trust.

Amounts set aside for the cash reserve are invested by the Trustee in U.S. government or agency securities secured by the full faith and credit of the United States, or mutual funds investing in such securities. Interest income received by the Trust from the investment of the reserve fund is added to the distributions received from BP Alaska and paid to the holders of Units with each quarterly distribution.

As discussed under “CERTAIN TAX CONSIDERATIONS” in Part I, Item 1 of the 2015 Annual Report, amounts received by the Trust as quarterly distributions are income to the holders of the Units (as are any earnings on investment of the cash reserve) and must be reported by the holders of the Units, even if such amounts are used by the Trustee to repay borrowings or replenish the cash reserve and are not received by the holders of the Units.

Results of Operations

Relatively modest changes in oil prices significantly affect the Trust’s revenues and results of operations. Crude oil prices are subject to significant changes in response to fluctuations in domestic and world supply and demand and other market conditions as well as the world political situation as it affects the members of OPEC and other producing countries. The effect of changing economic and political conditions on the demand for and supply of energy throughout the world and future prices of oil cannot be accurately projected.

Under the terms of the Conveyance of the Royalty Interest to the Trust, the Per Barrel Royalty for any day is the WTI Price for the day less the sum of (i) Chargeable Costs multiplied by the Cost Adjustment Factor and (ii) Production Taxes. The narrative under the captions “THE TRUST – Trust Property” and “THE ROYALTY INTEREST” in the 2015 Annual Report explains the meanings of the terms “Conveyance,” “Royalty Interest,” “Per Barrel Royalty,” “WTI Price, “Chargeable Costs” and “Cost Adjustment Factor” and should be read in conjunction with this report.

Royalty revenues are generally received on the fifteenth day of the month following the end of the calendar quarter in which the related Royalty Production occurred (the “Quarterly Record Date”). The Trustee, to the extent possible, pays all accrued expenses of the Trust on each Quarterly Record Date from the royalty payment received. Revenues and Trust expenses presented in the statement of cash earnings and distributions are recorded on a modified cash basis and, as a result, royalty revenues and distributions shown in such statements for the three-month and six-month periods ended June 30, 2016 and 2015, respectively, are attributable to BP Alaska’s operations during the three and six-month periods ended March 31, 2016 and 2015, respectively.

The following table summarizes the factors which determined the Per Barrel Royalties used to calculate the payments received by the Trust in January and April 2016 and 2015 (see Note 1 of Notes to Financial Statements (Unaudited) in Part I, Item 1). The information in the table has been furnished by BP Alaska.


			Data for Quarter
Royalty Payment in Month	Is Based on Data for Quarter Ended		Average WTI Price		Chargeable Costs		Cost Adjustment Factor		Adjusted Chargeable Costs		Average Production Taxes		Average Per Barrel Royalty		Average Net Production (mb/d)
Apr 2016 Jan 2016		03/31/2016 12/31/2015	$ $	33.73 42.15	$ $	17.10 17.00		1.826 1.827	$ $	31.22 31.07	$ $	1.06 1.40	$ $	1.45 9.68		95.1 96.7
Apr 2015 Jan 2015		03/31/2015 12/31/2014	$ $	48.80 73.02	$ $	17.00 16.90		1.807 1.818	$ $	30.72 30.73	$ $	1.67 6.88	$ $	16.41 35.41		92.8 96.3

“Royalty Production” for each day in a calendar quarter is 16.4246% of the first 90,000 barrels of the actual average daily net production of oil and condensate for the quarter from the proved reserves allocated to the Trust. During periods when BP Alaska’s average daily net production from those reserves exceeds 90,000 barrels, the principal factors affecting the Trust’s revenues and distributions to Unit holders are changes in WTI Prices, scheduled annual increases in Chargeable Costs, changes in the Consumer Price Index and changes in Production Taxes. Since 2006, BP Alaska has undertaken a program of field wide infrastructure renewal, pipeline replacement and well mechanical improvements. As a consequence of these activities and the required downtime, and the natural production declines from the Prudhoe Bay field, Royalty Production from the proved reserves of oil and condensate allocated to the Trust was less than 90,000 barrels per day on an annual basis in 2013, 2014 and 2015. BP Alaska anticipates that its average net production of oil and condensate from those reserves will be below 90,000 barrels per day on an annual basis in most future years.

BP Alaska estimates Royalty Production from the reserves allocated to the Trust for purposes of calculating quarterly royalty payments to the Trust because complete actual field production data for the preceding calendar quarter generally is not available by the Quarterly Record Date. To the extent that average net production from those reserves is below 90,000 barrels per day in any quarter, recalculation by BP Alaska of actual Royalty Production data may result in revisions of prior Royalty Production estimates. Revisions by BP Alaska of its Royalty Production calculations cause BP Alaska to adjust its quarterly royalty payments to the Trust to compensate for overpayments or underpayments of royalties with respect to prior quarters. Such adjustments, if material, may adversely affect certain Unit holders who buy or sell Units between the Quarterly Record Dates for the Quarterly Distributions affected.

Three Months Ended June 30, 2016 Compared to

Three Months Ended June 30, 2015

Trust royalty revenues received during the second quarter of the fiscal year are based on Royalty Production during the first quarter of the fiscal year. The first of the following two tables shows the changes from the first quarter of 2015 to the first quarter of 2016 in the factors which determined the Per Barrel Royalties used to calculate the royalty payments received during the second quarters of 2015 and 2016. The second of the two tables shows the resulting changes in the Trust’s revenues and distributions and the changes in the Trust’s expenses from the second quarter of 2015 to the second quarter of 2016.


			Increase (decrease)
	3 Months Ended 3/31/2016		Amount			Percent			3 Months Ended 3/31/2015
Average WTI Price	$	33.73	($	15.07	)		(30.9	)	$	48.80
Adjusted Chargeable Costs	$	31.22	$	0.50			1.6		$	30.72
Average Production Taxes	$	1.06	($	0.61	)		(36.5	)	$	1.67
Average Per Barrel Royalty	$	1.45	($	14.96	)		(91.2	)	$	16.41
Average net production (mb/d)		95.1		2.3			2.5			92.8

The decline in WTI price that began early in the third quarter of 2014 reached a low of $26.21 per barrel in February 2016. Despite finishing the first quarter of 2016 at a $38.34 per barrel, the average WTI price for the quarter was more than 30 percent lower than the average WTI price for the first quarter of 2015. Although the dollar amount of the decline in the average Per Barrel Royalty between the two periods was virtually identical to the dollar amount of the decline in the WTI price, the percentage decline of the average Per Barrel Royalty from the prior period was over 60% more than the percentage decline in the average WTI price compared to the first quarter of 2015. This resulted from the fact that Adjusted Chargeable Costs, which along with average Production Taxes are subtracted from the average WTI price to determine the average Per Barrel Royalty, represented a much larger percentage of the WTI price for the first quarter of 2016 (93%) compared to prior period (63%). The percentage decrease in the average Per Barrel Royalty for the period includes a deduction for Production Taxes. See Note 5 of Notes to Financial Statements (Unaudited) in Item 1 above.

The increase in Adjusted Chargeable Costs shown in the table above resulted from the scheduled increase in Chargeable Costs from $17.00 in 2015 to $17.10 in 2016 and the slight increase in the Cost Adjustment Factor between the two periods.

The increase in the average net production from the 1989 Working Interest for the two reporting periods was due to fewer days impacted by planned and unplanned downtime during the two reporting periods.

The following table shows the changes to the Trust’s revenues received and distributions paid during the second quarters of 2015 and 2016 resulting from the factors in the table above, as well as changes for the Trust’s administrative expenses.


			Increase (decrease)
	3 Months Ended 6/30/2015		Amount			Percent			3 Months Ended 6/30/2015
	(Dollar amounts in thousands)
Royalty revenues	$	1,951	($	19,940	)		(91.1	)	$	21,891
Cash earnings	$	1,542	($	19,835	)		(92.8	)	$	21,377
Cash distributions	$	1,542	($	19,835	)		(92.8	)	$	21,377
Administrative expenses	$	410	($	104	)		(20.2	)	$	514

The period-to-period decreases in royalty revenues, cash earnings and cash distributions are due to the significantly lower average WTI Prices that prevailed in the first quarter of 2016 compared

to the first quarter of 2015. The decreases in royalty revenues, cash earnings and cash distributions were offset somewhat by the increase in royalty interest received by the Trust as a result of the decrease in Production Taxes. The decrease in administrative expenses reflects timing differences in accruals of expenses.

Six Months Ended June 30, 2016 Compared to

Six Months Ended June 30, 2015

Trust royalty revenues received during the first six months of the fiscal year are based on Royalty Production during the first quarter of the fiscal year and the fourth quarter of the preceding fiscal year. The first of the following two tables shows the changes from the six months ended March 31, 2015 to the six months ended March 31, 2016 in the factors which determined the Per Barrel Royalties used to calculate the royalty payments received during the six months ended June 30 of the respective years. The second of the two tables shows the resulting changes in the Trust’s revenues and distributions and the changes in the Trust’s expenses from the first six months of 2015 to the first six months of 2016.


			Increase (decrease)
	6 Months Ended 3/31/2016		Amount			Percent			6 Months Ended 3/31/2015
Average WTI Price	$	37.94	($	22.97	)		(37.7	)	$	60.91
Adjusted Chargeable Costs	$	31.15	$	0.42			1.4		$	30.73
Average Production Taxes	$	1.23	($	3.05	)		(71.3	)	$	4.28
Average Per Barrel Royalty	$	5.54	($	20.37	)		(78.6	)	$	25.91
Average net production (mb/d)		95.9		1.3			1.4			94.6

The decrease in the average Per Barrel Royalty for the period resulted primarily from the decline in WTI prices. This decline was partially offset by the decline in Production Taxes. The decline in WTI prices resulted in Production Taxes for the fourth quarter of 2015 and the first quarter of 2016 being calculated on the basis of the minimum tax under the Act and the 2014 Letter Agreement, compared to only the first quarter of 2015 being calculated on the basis of the minimum tax. See Note 5 of Notes to Financial Statements (Unaudited) in Item 1 above.

Fewer days impacted by planned and unplanned downtime during the two reporting periods contributed to the increase in average net production.

The increase in adjusted Chargeable Costs resulted principally from the scheduled annual increase in Chargeable Costs from $17.00 in 2015 and to $17.10 in 2016. The Cost Adjustment Factor increased marginally between the two periods due to low inflation.

The following table shows the changes to the Trust’s revenues received and distributions paid during the first and second quarters of 2015 and 2016 resulting from the factors in the table above, as well as changes for the Trust’s administrative expenses.


			Increase (decrease)
	6 Months Ended 6/30/2016		Amount			Percent			6 Months Ended 6/30/2015
	(Dollar amounts in thousands)
Royalty revenues	$	15,072	($	64,508	)		(81.1	)	$	79,580
Cash earnings	$	14,422	($	64,487	)		(81.7	)	$	78,909
Cash distributions	$	14,422	($	64,487	)		(81.7	)	$	78,909
Administrative expenses	$	651	($	20	)		(3.0	)	$	671

The period-to-period decreases in royalty revenues, cash earnings and cash distributions are due to the significantly lower average WTI Prices that prevailed in the fourth quarter of 2015 and the first quarter of 2016 compared to the fourth and first quarters of 2014 and 2015, respectively. The decreases in royalty revenues, cash earnings and cash distributions were offset somewhat by the increase in royalty interest received by the Trust as a result of the cumulative condensate limit being reached at the end of the second quarter of 2014 and the decrease in Production Taxes. The decreases in royalty revenues, cash earnings and cash distributions for the period also reflect the $9.5 million true-up adjustment that was included in the royalty payment for the fourth quarter of 2014. This adjustment represented the amount of an underpayment by BP Alaska, including interest on the underpayment, of the royalty payment due with respect to the quarters ended June 30, 2014 and September 30, 2014, associated with the reaching of the cumulative condensate limit in June 2014 described above. The decrease in administrative expenses reflects the increased overall costs of supplies and services offset by timing differences in accruals of expenses.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk.

The Trust is a passive entity and except for the Trust’s ability to borrow money as necessary to pay liabilities of the Trust that cannot be paid out of cash on hand, the Trust is prohibited from engaging in borrowing transactions. The Trust periodically holds short-term investments acquired with funds held by the Trust pending distribution to Unit holders and funds held in reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of these investments and limitations on the types of investments which may be held by the Trust, the Trust is not subject to any material interest rate risk. The Trust does not engage in transactions in foreign currencies which could expose the Trust or Unit holders to any foreign currency related market risk or invest in derivative financial instruments. It has no foreign operations and holds no long-term debt instruments.

Item 4.

Controls and Procedures.

Disclosure Controls and Procedures

The Trustee has disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Exchange Act) that are 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 (the “Exchange Act”) is recorded, processed, summarized and reported, within

the time periods specified in the SEC’s rules and forms. These controls and procedures include but are not limited to 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 Exchange Act is accumulated and communicated to the responsible trust officers of the Trustee to allow timely decisions regarding required disclosure.

Under the terms of the Trust Agreement and the Conveyance, BP Alaska has significant disclosure and reporting obligations to the Trust. BP Alaska is required to provide the Trust such information concerning the Royalty Interest as the Trustee may need and to which BP Alaska has access to permit the Trust to comply with any reporting or disclosure obligations of the Trust pursuant to applicable law and the requirements of any stock exchange on which the Units are listed. These reporting obligations include furnishing the Trust a report by February 28 of each year containing all information of a nature, of a standard and in a form consistent with the requirements of the SEC respecting the inclusion of reserve and reserve valuation information in filings under the Exchange Act and with applicable accounting rules. The report is required to set forth, among other things, BP Alaska’s estimates of future net cash flows from proved reserves attributable to the Royalty Interest, the discounted present value of such proved reserves and the assumptions utilized in arriving at the estimates contained in the report.

In addition, the Conveyance gives the Trust certain rights to inspect the books and records of BP Alaska and discuss the affairs, finances and accounts of BP Alaska relating to the 1989 Working Interests with representatives of BP Alaska; it also requires BP Alaska to provide the Trust with such other information as the Trustee may reasonably request from time to time and to which BP Alaska has access.

The Trustee’s disclosure controls and procedures include ensuring that the Trust receives the information and reports that BP Alaska is required to furnish to the Trust on a timely basis, that the appropriate responsible personnel of the Trustee examine such information and reports, and that information requested from and provided by BP Alaska is included in the reports that the Trust files or submits under the Exchange Act.

As of the end of the period covered by this report, the trust officers of the Trustee responsible for the administration of the Trust conducted an evaluation of the Trust’s disclosure controls and procedures. Their evaluation considered, among other things, that the Trust Agreement and the Conveyance impose enforceable legal obligations on BP Alaska, and that BP Alaska has provided the information required by those agreements and other information requested by the Trustee from time to time on a timely basis. The trust officers concluded the Trust’s disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

There has not been any change in the Trust’s internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rule 13a-15 or Rule 15d-15 under the Exchange Act that occurred during the Trust’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

PART II

OTHER INFORMATION

Item 1.

Legal Proceedings.

None.

Item 1A.

Risk Factors

There have been no material changes in risk factors disclosed in the 2015 Annual Report that are known to the Trustee.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3.

Defaults Upon Senior Securities.

None.

Item 4.

Mine Safety Disclosures.

Not applicable

Item 5.

Other Information.

(a) Reference is made to Note 7 of Notes to Financial Statements (Unaudited) in Part I, Item 1 (Form 8-K, Item 8.01).

(b) Not applicable.

Item 6.

Exhibits.



4.1		BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among The Standard Oil Company, BP Exploration (Alaska) Inc., The Bank of New York, Trustee, and F. James Hutchinson, Co-Trustee.

4.2		Overriding Royalty Conveyance dated February 27, 1989 between BP Exploration (Alaska) Inc. and The Standard Oil Company.

4.3		Trust Conveyance dated February 28, 1989 between The Standard Oil Company and BP Prudhoe Bay Royalty Trust.

4.4		Support Agreement dated as of February 28, 1989 among The British Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The Standard Oil Company and BP Prudhoe Bay Royalty Trust.

4.5		Letter agreement executed October 13, 2006 between BP Exploration (Alaska) Inc. and The Bank of New York, as Trustee.



4.6		Letter agreement executed January 11, 2008 between BP Exploration (Alaska) Inc. and The Bank of New York, as Trustee.

10.1		Settlement Agreement, dated May 8, 2009, among BP Exploration (Alaska) Inc., The Bank of New York Mellon, as Trustee, and BNY Mellon Trust Company of Delaware, as Co-Trustee.

10.2		Agreement of Resignation, Appointment and Acceptance dated as of December 15, 2010 among BP Exploration (Alaska) Inc., The Bank of New York Mellon and The Bank of New York Mellon Trust Company, N.A.

31		Rule 13a-14(a)/15d-14(a) Certifications.

32		Section 1350 Certification.

99		Report of Miller and Lents, Ltd., dated February 12, 2016.

101		Explanatory note: An Interactive Data File is not submitted with this filing pursuant to Item 601(101) of Regulation S-K, because the Trust does not prepare its financial statements in accordance with generally accepted accounting principles as used in the United States. See Note 2 of Notes to Financial Statements (Unaudited) in Part I, Item 1.

SIGNATURE

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.


BP PRUDHOE BAY ROYALTY TRUST

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

By:		/s/ Elaina Conley
		Elaina Conley
		Vice President

Date: August 9, 2016

The registrant is a trust and has no officers or persons performing similar functions. No additional signatures are available and none have been provided.

INDEX TO EXHIBITS


Exhibit No.		Exhibit Description
Exhibit No.		Exhibit Description

4.1		BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989 among The Standard Oil Company, BP Exploration (Alaska) Inc., The Bank of New York, Trustee, and F. James Hutchinson, Co-Trustee. Incorporated by reference to the correspondingly numbered exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006 (File No. 1-10243).

4.2		Overriding Royalty Conveyance dated February 27, 1989 between BP Exploration (Alaska) Inc. and The Standard Oil Company. Incorporated by reference to the correspondingly numbered exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006 (File No. 1-10243).

4.3		Trust Conveyance dated February 28, 1989 between The Standard Oil Company and BP Prudhoe Bay Royalty Trust. Incorporated by reference to the correspondingly numbered exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006 (File No. 1-10243).

4.4		Support Agreement dated as of February 28, 1989 among The British Petroleum Company p.l.c., BP Exploration (Alaska) Inc., The Standard Oil Company and BP Prudhoe Bay Royalty Trust. Incorporated by reference to the correspondingly numbered exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006 (File No. 1-10243).

4.5		Letter agreement executed October 13, 2006 between BP Exploration (Alaska) Inc. and The Bank of New York, as Trustee. Incorporated by reference to the correspondingly numbered exhibit to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 1-10243).

4.6		Letter agreement executed January 11, 2008 between BP Exploration (Alaska) Inc. and The Bank of New York, as Trustee. Incorporated by reference to the correspondingly numbered exhibit to the Registrant’s Current Report on Form 8-K dated January 11, 2008 (File No. 1-10243).

10.1		Settlement Agreement, dated May 8, 2009, among BP Exploration (Alaska) Inc., The Bank of New York Mellon, as Trustee, and BNY Mellon Trust Company of Delaware, as Co-Trustee. Incorporated by reference to the correspondingly numbered exhibit to the Registrant’s Current Report on Form 8-K dated May 8, 2009 (File No. 1-10243).

10.2		Agreement of Resignation, appointment and Acceptance dated as of December 15, 2010 among BP Exploration (Alaska) Inc., The Bank of New York Mellon and The Bank of New York Mellon Trust Company, N.A. Incorporated by reference to the correspondingly numbered exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010 (File No. 1-10243).

31*		Rule 13a-14(a)/15d-14(a) certifications.

32*		Section 1350 certification.

99		Report of Miller and Lents, Ltd., dated February 12, 2016. Incorporated by reference to the correspondingly numbered exhibit to the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015 (File No. 1-10243).

*	Filed herewith.