BPT BP Prudhoe Bay Royalty Trust

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, 2017 (the “2017 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 2017 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 2017 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 2017 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 2017 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.

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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 2017 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 2017 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- and nine-month periods ended September 30, 2018 and 2017, respectively, are attributable to BP Alaska’s operations during the three and nine-month periods ended June 30, 2018 and 2017, respectively.

The following table summarizes the factors which determined the Per Barrel Royalties used to calculate the payments received by the Trust in January, April and July 2018 and 2017 (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.

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“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 2015, 2016 and 2017. 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 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 September 30, 2018 Compared to

Three Months Ended September 30, 2017

Trust royalty revenues received during the third quarter of the fiscal year are based on Royalty Production during the second quarter of the fiscal year. The first of the following two tables shows the changes from the second quarter of 2017 to the second quarter of 2018 in the factors which determined the Per Barrel Royalties used to calculate the royalty payments received during the third quarters of 2017 and 2018. 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 third quarter of 2017 to the third quarter of 2018.

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The rebound in the WTI price that began early in 2016 generally continued throughout 2017 and through the first two quarters of 2018. This resulted in an average WTI price for the second quarter of 2018 that was 40.4 percent higher than the average WTI price for the second quarter of 2017. This increase in WTI price for the quarter resulted in an 87.1 percent increase in the average Per Barrel Royalty between the two periods. The percentage increase in the average Per Barrel Royalty for the period was offset somewhat by the increase in Production Taxes for the second quarter of 2018. Although the 47.9 percent increase in Production Taxes for the quarter reflects the increase in WTI price between the two periods, Production Taxes remained historically low for the second quarter of 2018 because, as with each quarter since the second quarter of 2015, Production Taxes were calculated on the basis of the minimum tax under the Act and the 2014 Letter Agreement. 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 $17.20 in 2017 to $20.00 in 2018 and the increase in the Cost Adjustment Factor between the two periods.

The decline in the average net production from the 1989 Working Interest was due to the naturally declining production rate from the Prudhoe Bay field and variance in the impacts of 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 third quarters of 2017 and 2018 resulting from the factors in the table above, as well as changes for the Trust’s administrative expenses.

The period-to-period increases in royalty revenues, cash earnings and cash distributions are due to the higher average WTI Prices that prevailed in the second quarter of 2018 compared to the second quarter of 2017. The decrease in administrative expenses reflects lower overall costs of supplies and services and timing differences in accruals of expenses.

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Nine Months Ended September 30, 2018 Compared to

Nine Months Ended September 30, 2017

Trust royalty revenues received during the first nine months of the fiscal year are based on Royalty Production during the first and second 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 nine months ended June 30, 2017 to the nine months ended June 30, 2018 in the factors which determined the Per Barrel Royalties used to calculate the royalty payments received during the nine months ended September 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 nine months of 2017 to the first nine months of 2018.

The increase in the average Per Barrel Royalty for the period resulted primarily from the increase in WTI prices compared to the nine months ended June 30, 2017. This increase was limited by the increases in adjusted Chargeable Costs and Production Taxes.

The decline in the average net production from the 1989 Working Interest was due to the naturally declining production rate from the Prudhoe Bay field and variance in the impacts of planned and unplanned downtime during the two reporting periods.

The increase in adjusted Chargeable Costs resulted principally from the scheduled annual increase in Chargeable Costs from $17.20 in 2017 to $20.00 in 2018. 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 nine months ended September 30, 2017 and 2018 resulting from the factors in the table above, as well as changes for the Trust’s administrative expenses.

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The period-to-period increases in royalty revenues, cash earnings and cash distributions are due to the higher average WTI Prices that prevailed in the nine month period ended June 30, 2018 compared to the nine month period ended June 30, 2017. The decrease in administrative expenses reflects timing differences in accruals of expenses.

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.

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