INTRODUCTION
BP Prudhoe Bay Royalty Trust (the Trust) was created as a Delaware business trust by the BP Prudhoe Bay Royalty 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 (formerly named The Bank of New York), as
trustee, and F. James Hutchinson,
co-trustee
(BNY Mellon Trust of Delaware, formerly named The Bank of New York (Delaware), successor
co-trustee).
BP Alaska and Standard
Oil are wholly owned subsidiaries of BP p.l.c. (BP).
Effective as of December 15, 2010, The Bank of New York Mellon
(BNYM) resigned as trustee under the Trust Agreement and BP Alaska appointed The Bank of New York Mellon Trust Company, N.A. (the Trust Company) to succeed BNYM as trustee. The Trust Company accepted its appointment and
assumed all rights, titles, duties, powers and authority formerly held and exercised by BNYM under the Trust Agreement. The corporate trust office of the Trust Company (which we refer to hereafter as the Trustee) at which the affairs of
the Trust are administered is located at 601 Travis Street, Floor 16, Houston, Texas 77002 and its telephone number at that address is (713)
483-6020.
The Trust electronically files annual reports on Form
10-K,
quarterly reports on Form
10-Q
and, when certain events require them, current reports on Form
8-K
with the Securities and Exchange Commission (SEC). The public may read and copy any
materials filed by the Trust with the SEC at the SECs Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330.
The SEC also maintains an Internet site that contains reports, proxy and information statements, and other information
regarding issuers (including the Trust) that file electronically with the SEC. The address of the SECs website is
http://www.sec.gov
.
The Trust does not maintain an Internet website, but certain information concerning the Trust and the Trust Units may be obtained from the
BusinessWire website at the following page location:
http://
bpt.investorhq.businesswire.com
. The Trustee will provide paper or electronic copies of the Trusts reports on Form
10-K,
Form
10-Q
and Form
8-K,
and amendments to those reports, free of charge upon request as soon as reasonably practicable after the Trust files them with the SEC. Requests for copies
of reports may be made by mail to: The Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Floor 16, Houston, TX 77002, Attention: Global Corporate Trust Corporate Finance; by telephone to: (713)
483-6020;
or by
e-mail
to:
elaina.c.rodgers@bnymellon.com
.
The information in this report relating to the Prudhoe Bay Unit, the calculation of royalty payments and certain other matters has been
furnished to the Trustee by BP Alaska.
Forward-Looking Statements
Various sections of this report contain
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.
1
The actual results, performance and prospects of the Trust could differ materially from those
expressed or implied by forward-looking statements. Descriptions of some of the risks that could affect the future performance of the Trust appear in the following Item 1A, RISK FACTORS, and elsewhere in this 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 this report may not occur or may turn out 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.
THE TRUST
Trust Property
The property of the Trust
consists of an overriding royalty interest (the Royalty Interest) and cash and cash equivalents held by the Trustee from time to time. The Royalty Interest entitles the Trust to a royalty on 16.4246% of the lesser of (i) the first
90,000 barrels
1
of the average actual daily net production of crude oil and condensate per quarter from the working interest of BP Alaska as of February 28, 1989 in the Prudhoe Bay oil field
located on the North Slope in Alaska or (ii) the average actual daily net production of crude oil and condensate per quarter from that working interest. The Prudhoe Bay field is one of four contiguous North Slope oil fields that are operated by
BP Alaska and are known collectively as the Prudhoe Bay Unit. The Royalty Interest was conveyed to the Trust by an Overriding Royalty Conveyance dated February 27, 1989 from BP Alaska to Standard Oil and a Trust Conveyance
dated February 28, 1989 from Standard Oil to the Trust. Copies of the Overriding Royalty Conveyance and the Trust Conveyance are filed with the SEC as exhibits to this report. The Overriding Royalty Conveyance and the Trust Conveyance are
referred to collectively in this report as the Conveyance.
The Royalty Interest is a
non-operational
interest in minerals. The Trust does not have the right to take oil and gas in kind, nor does it have any right to take over operations or to share in any operating decision with respect to BP
Alaskas working interest in the Prudhoe Bay field. BP Alaska is not obligated to continue to operate any well or maintain or attempt to maintain in force any portion of its working interest when, in its reasonable and prudent business
judgment, the well or interest ceases to produce or is not capable of producing oil or gas in paying quantities.
Employees
The Trust has no employees. All administrative functions of the Trust are performed by the Trustee.
Duties and Powers of the Trustee
The
duties of the Trustee are specified in the Trust Agreement and the laws of the State of Delaware. BNY Mellon Trust of Delaware has been appointed
co-trustee
in order to satisfy the Delaware Statutory Trust
Acts requirement that the Trust have at least one trustee resident in, or which has its principal place
1
|
The term barrel is a unit of measure of petroleum liquids equal to 42 United States gallons corrected
to 60 degrees Fahrenheit temperature.
|
2
of business in, Delaware. However, 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. A copy of the Trust Agreement is filed with the SEC as an exhibit to this report.
The basic function of the Trustee is to collect income from the Royalty Interest, to pay all expenses, charges and obligations of the Trust
from the Trusts income and assets, and to pay available cash to Unit holders. Because of the passive nature of the Trusts assets and the restrictions on the power of the Trustee to incur obligations, the only liabilities that the Trust
normally incurs in the conduct of its operations are the Trustees fees and routine administrative expenses, including accounting, legal and other professional fees.
The Trust Agreement grants the Trustee only the rights and powers necessary to achieve the purposes of the Trust. The Trust Agreement
prohibits the Trust from engaging in any business or commercial activity or, with certain exceptions, any investment activity and from using any assets of the Trust to acquire any oil and gas lease, royalty or other mineral interest.
The Trustee is entitled to be indemnified out of the assets of the Trust for any liability or loss incurred by it in the performance of its
duties unless the loss results from its negligence, bad faith or fraud or from expenses incurred in carrying out its duties that exceed the compensation and reimbursement to which it is entitled under the Trust Agreement.
Sales of Royalty Interest; Borrowings and Reserves
With certain exceptions, the Trustee may sell all or part of the Royalty Interest or an interest therein only if authorized to do so by vote of
the holders of 60% of the Units outstanding. However, if the sale is made in order to pay specific liabilities of the Trust then due and involves a part, but not all or substantially all, of the Trust properties, the sale only needs to be approved
by the vote of holders of a majority of the Units. Any sale of Trust properties must be for cash unless otherwise authorized by the Unit holders. The Trustee is obligated to distribute the available net proceeds of any such sale to the Unit holders
after establishing reserves for liabilities of the Trust.
The Trustee has the power to borrow on behalf of the Trust or to sell Trust
assets to pay liabilities of the Trust and to establish a reserve for the payment of liabilities without the consent of the Unit holders under the following circumstances:
The Trustee may borrow from a lender not affiliated with the Trustee if cash on hand is not sufficient to pay current
liabilities and the Trustee has determined that it is not practical to pay such liabilities out of funds anticipated to be available in subsequent quarters and that, without such borrowing, the Trust property is subject to the risk of loss or
diminution in value. To secure payment of its borrowings on behalf of the Trust, the Trustee is authorized to encumber the Trusts assets and to carve out and convey production payments. The borrowing must be on terms which (in the opinion of
an investment banking firm or commercial banking firm selected by the Trustee) are commercially reasonable when compared to other available alternatives. No distributions to Unit holders may be made until the borrowings by the Trust have been repaid
in full.
If the Trustee is unable to borrow to pay Trust liabilities, the Trustee may sell Trust assets if it determines
that the failure to pay the liabilities at a later date will be contrary to the best interest of the Unit holders and that it is not practicable to submit the sale to a vote of the Unit holders. The sale must be made for cash at a price which (in
the opinion of an investment banking firm or commercial banking firm selected by the Trustee) is at least equal to the fair market value of the
3
interest sold and is made on commercially reasonable terms when compared to other available alternatives.
The Trustee has the right to establish a cash reserve for the payment of material liabilities of the Trust which may become due
if it determines that it is not practical to pay such liabilities out of funds anticipated to be available in subsequent quarters and that, in the absence of a reserve, the Trust property is subject to the risk of loss or diminution in value or the
Trustee is subject to the risk of personal liability for such liabilities.
In order for the Trustee to borrow, sell assets to pay Trust
liabilities or establish a reserve for Trust liabilities, the Trustee must receive an unqualified written legal opinion that the contemplated action will not adversely affect the classification of the Trust as a grantor trust for federal
income tax purposes or cause the income from the Trust to be treated as unrelated business taxable income for federal income tax purposes. If the Trustee is unable to obtain the required legal opinion, it still may proceed with the borrowing or
sale, or establish the reserve, if it determines that the failure to do so will be materially detrimental to the Unit holders considered as a whole.
The Trustee maintains a $1,000,000 cash reserve to provide liquidity to the Trust during any periods in which the Trust does not receive a
distribution from BP Alaska. See Item 7 in Part II below.
Irrevocability; Amendment of the Trust Agreement
The Trust Agreement and the Trust are irrevocable. No person has the power to terminate, revoke or change the Trust Agreement except as
described in the following paragraph and below under Termination of the Trust.
The Trust Agreement may be amended without a
vote of the Unit holders to cure an ambiguity, to correct or supplement any provision of the Trust Agreement that may be inconsistent with any other provision or to make any other provision with respect to matters arising under the Trust Agreement
that does not adversely affect the Unit holders. The Trust Agreement also may be amended with the approval of holders of a majority of the outstanding Units. However, no such amendment may alter the relative rights of Unit holders unless approved by
the affirmative vote of holders of 100% of the outstanding Units, nor may any amendment reduce or delay the distributions to the Unit holders, alter the voting rights of Unit holders or the number of Units in the Trust, or make certain other
changes, unless approved by the affirmative vote of holders of at least 80% of the outstanding Units and by the Trustee. The Trustee is required to consent to any amendment approved by the requisite vote of Unit holders unless the amendment affects
the Trustees rights, duties and immunities under the Trust Agreement. No amendment will be effective until the Trustee has received a ruling from the Internal Revenue Service or an opinion of counsel to the effect that such modification will
not adversely affect the classification of the Trust as a grantor trust for federal income tax purposes or cause the income from the Trust to be treated as unrelated business taxable income for federal income tax purposes.
Termination of the Trust
The Trust will
terminate if either (a) holders of at least 60% of the outstanding Units vote to terminate the Trust or (b) the net revenues from the Royalty Interest for two successive years are less than $1,000,000 per year (unless the net revenues
during the
two-year
period have been materially and adversely affected by certain extraordinary events).
Upon termination of the Trust, BP Alaska will have an option to purchase the Royalty Interest at a price equal to the greater of (i) the
fair market value of the Trust property as set forth in an opinion of an
4
investment banking firm, commercial banking firm or other entity qualified to give an opinion as to the fair
market value of the assets of the Trust, or (ii) the number of outstanding Units multiplied by (a) the closing price of Units on the day of termination of the Trust on the stock exchange on which the Units are listed, or (b) if the
Units are not listed on any stock exchange but are traded in the
over-the-counter
market, the closing bid price on the day of termination of the Trust as quoted on the
NASDAQ Stock Market. The purchase must be for cash unless holders of 60% of the Units outstanding authorize the sale for
non-cash
consideration and the Trustee has received a ruling from the Internal Revenue
Service or an opinion of counsel to the effect that such
non-cash
sale will not adversely affect the classification of the Trust as a grantor trust for federal income tax purposes or cause the
income from the Trust to be treated as unrelated business taxable income for federal income tax purposes.
If BP Alaska does not exercise
its option, the Trustee will sell the Trust property on terms and conditions approved by the vote of holders of 60% of the outstanding Units, unless the Trustee determines that it is not practicable to submit the matter to a vote of the Unit holders
and the sale is made at a price at least equal to the fair market value of the Trust property as set forth in the opinion of the investment banking firm, commercial banking firm or other entity mentioned above and on terms and conditions deemed
commercially reasonable by that firm.
The Trustee will distribute all available proceeds to the Unit holders after satisfying all
existing liabilities of the Trust and establishing adequate reserves for the payment of contingent liabilities.
Unit holders do not have
the right under the Trust Agreement to seek or secure any partition or distribution of the Royalty Interest or any other asset of the Trust or any accounting during the term of the Trust or during any period of liquidation and winding up.
Resignation or Removal of Trustee
The
Trustee may resign at any time or be removed with or without cause by vote of the holders of a majority of the outstanding Units at a meeting called and held in accordance with the Trust Agreement. A successor trustee may be appointed by BP Alaska
or, if the Trustee has been removed at a meeting of the Unit holders, the successor trustee may be appointed by the Unit holders at the meeting. Any successor trustee must be a corporation organized, doing business and authorized to exercise trust
powers under the laws of the United States, any state thereof or the District of Columbia, or a national banking association domiciled in the United States, in either case having a combined capital, surplus and undivided profits of at least
$50,000,000 and subject to supervision or examination by federal or state authorities. Unless the Trust already has a trustee that is a resident of or has a principal office in Delaware, any successor trustee must be a resident of Delaware or have a
principal office in Delaware. No resignation or removal of the Trustee will become effective until a successor trustee has accepted appointment.
Voting Rights of Unit Holders
Unit
holders possess certain voting rights, but their voting rights are not comparable to those of shareholders of a corporation. For example, there is no requirement for annual meetings of Unit holders or for periodic reelection of the Trustee.
A meeting of the Unit holders may be called at any time to act with respect to any matter as to which the Trust Agreement authorizes the Unit
holders to act. Any such meeting may be called by the Trustee in its discretion and will be called by the Trustee (i) as soon as practicable after receipt of a written request by BP Alaska or a written request that sets forth in reasonable
detail the action proposed to be taken at the meeting and is signed by holders of at least 25% of the outstanding Units or (ii) when required by applicable laws or regulations or the New York Stock Exchange. The Trustee will give written notice
of
5
any meeting stating the time and place of the meeting and the matters to be acted on not more than 60 days nor fewer than 10 days before the meeting to all Unit holders of record on a date not
more than 60 days before the meeting at their addresses shown on the records of the Trust. All meetings of Unit holders are required to be held in Manhattan, New York City. Unit holders are entitled to cast one vote on all matters coming before a
meeting, in person or by proxy, for each Unit held on the record date for the meeting.
THE ROYALTY INTEREST
The Royalty Interest is a property right under Alaska law which burdens production, but there is no other security interest in the
reserves or production revenues assigned to it. The royalty payable to the Trust for each calendar quarter is the sum of the amounts obtained by multiplying Royalty Production for each day in the calendar quarter by the Per Barrel Royalty for that
day. The payment under the Royalty Interest for any calendar quarter may not be less than zero nor more than the aggregate value of the total production of oil and condensate from BP Alaskas working interest in the Prudhoe Bay Unit for the
quarter, net of the State of Alaska royalty and less the value of any applicable payments made to affiliates of BP Alaska.
Royalty Production
The Royalty Production for each day in a calendar quarter is 16.4246% of the lesser of (i) the first 90,000 barrels of the
actual average daily net production of crude oil and condensate for the quarter from the Prudhoe Bay (Permo-Triassic) Reservoir and saved and allocated to the oil and gas leases owned by BP Alaska in the Prudhoe Bay field as of
February 28, 1989 (the 1989 Working Interests), or (ii) the actual average daily net production of crude oil and condensate for the quarter from the 1989 Working Interests. The Royalty Production is based on oil produced
from the oil rim and condensate produced from the gas cap, but not on gas production or natural gas liquids production. The actual average daily net production of oil and condensate from the 1989 Working Interests for any calendar quarter is the
total production of oil and condensate for the quarter, net of the State of Alaska royalty, divided by the number of days in the quarter.
Per Barrel
Royalty
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.
WTI Price
The WTI Price for any trading day is (i) the price (in dollars per barrel) for West Texas intermediate crude oil of standard
quality having a specific gravity of 40 API degrees for delivery at Cushing, Oklahoma (West Texas Intermediate) quoted for that trading day by whichever of The Wall Street Journal, Reuters, or Platts Oilgram Price Report, in that order,
publishes West Texas Intermediate price quotations for the trading day, or (ii) if the price of West Texas Intermediate is not published by one of those publications, the WTI Price will be the simple average of the daily mean prices (in dollars
per barrel) quoted for West Texas Intermediate by one major oil company, one petroleum broker and one petroleum trading company designated by BP Alaska, in each case unaffiliated with BP and having substantial U.S. operations, until published price
quotations are again available. If prices for West Texas Intermediate are not quoted so as to permit the calculation of the WTI Price, the price of West Texas Intermediate, for the purposes of calculating the WTI Price will be the price
of another light sweet domestic crude oil of standard quality designated by BP Alaska and approved by the Trustee, with appropriate allowance for transportation costs to the Gulf coast (or another appropriate location) to equilibrate its price to
the WTI Price. The WTI Price for any day which is not a trading day is the WTI Price for the preceding trading day.
6
Chargeable Costs
The Chargeable Costs per barrel of Royalty Production for each calendar year are fixed amounts specified in the Conveyance and do
not necessarily represent BP Alaskas actual costs of production. Chargeable Costs per barrel were $16.80 during 2013, $16.90 during 2014, $17.00 during 2015, $17.10 during 2016 and $17.20 during 2017. Chargeable Costs for 2018 and subsequent
years are shown in the following table:
|
|
|
|
|
Calendar
year
|
|
Chargeable Costs
per barrel
|
|
2018
|
|
|
20.00
|
|
2019
|
|
|
23.75
|
|
2020
|
|
|
26.50
|
|
After 2020, Chargeable Costs increase at a uniform rate of $2.75 per barrel per year.
Cost Adjustment Factor
The Cost
Adjustment Factor for a quarter is the ratio of the Consumer Price Index published for the most recently past February, May, August or November to 121.1 (the Consumer Price Index for January 1989). The Consumer Price Index is the
U.S. Consumer Price Index, all items and all urban consumers, U.S. city average
(1982-84
equals 100), as first published, without seasonal adjustment, by the Bureau of Labor Statistics, Department of Labor,
without regard to subsequent revisions or corrections. If the average WTI Price for any calendar quarter falls to $18.00 or less, the Cost Adjustment Factor for that quarter will be the Cost Adjustment Factor for the immediately preceding quarter.
If the average WTI Price returns to more than $18.00 for a later quarter, adjustments to the Cost Adjustment Factor resume, but with an adjustment to the formula that excludes changes in the Consumer Price Index during the period that adjustments to
the Cost Adjustment Factor were suspended.
Production Taxes
Production Taxes are the sum of any severance taxes, excise taxes (including windfall profit tax, if any), sales taxes, value added
taxes or other similar or direct taxes imposed upon the reserves or production, delivery or sale of Royalty Production, computed at defined statutory rates.
On April 14, 2013, Alaskas legislature passed an
oil-tax
reform bill amending Alaskas
oil and gas production tax statutes, AS 43.55.10
et seq.
(the Production Tax Statutes) with the aim of encouraging oil production and investment in Alaskas oil industry. On May 21, 2013, the Governor of Alaska 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 certain amendments to the Production Tax Statutes
in 2006 and 2007, 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 producers tax 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 producers 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.
7
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 Trusts 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. Thus, for 2017 any difference between the limitation as preliminarily determined for the first through third quarters of 2017 and the actual limitation for 2017 will be reflected in the payment to the Trust
for the fourth quarter of 2017, and not in the payment to the Trust for the first quarter of 2018.
Per Barrel Royalty Calculations
The following table shows how the above-described factors interacted during the past five years to produce the average Per Barrel Royalty paid
during the calendar years indicated. 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. Revenues and expenses presented in the
statement of cash earnings and distributions presented in Part II, Item 8 below are recorded on a modified cash basis and, as a result, royalty revenues and distributions shown in such statements for any calendar year are attributable to BP
Alaskas operations during the twelve-month period ended September 30 of that year. Dollar amounts in the table have been rounded to two decimal places for presentation and do not reflect the precision of the actual calculations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
WTI Price
|
|
|
Chargeable
Costs
|
|
|
Cost
Adjustment
Factor
|
|
|
Adjusted
Chargeable
Costs
|
|
|
Production
Taxes
|
|
|
Average Per
Barrel
Royalty
|
|
Calendar 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
th
Qtr 2012
|
|
$
|
88.15
|
|
|
$
|
16.70
|
|
|
|
1.773
|
|
|
$
|
29.60
|
|
|
$
|
21.37
|
|
|
$
|
37.18
|
|
1
st
Qtr 2013
|
|
|
94.40
|
|
|
|
16.80
|
|
|
|
1.788
|
|
|
|
30.03
|
|
|
|
24.98
|
|
|
|
39.38
|
|
2
nd
Qtr 2013
|
|
|
94.14
|
|
|
|
16.80
|
|
|
|
1.794
|
|
|
|
30.13
|
|
|
|
24.76
|
|
|
|
39.25
|
|
3
rd
Qtr 2013
|
|
|
105.94
|
|
|
|
16.80
|
|
|
|
1.801
|
|
|
|
30.25
|
|
|
|
32.79
|
|
|
|
42.89
|
|
|
|
|
|
|
|
|
Calendar 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
th
Qtr 2013
|
|
$
|
97.40
|
|
|
$
|
16.80
|
|
|
|
1.795
|
|
|
$
|
30.15
|
|
|
$
|
26.88
|
|
|
$
|
40.33
|
|
1
st
Qtr 2014
|
|
|
98.58
|
|
|
|
16.90
|
|
|
|
1.808
|
|
|
|
30.55
|
|
|
|
17.50
|
|
|
|
50.52
|
|
2
nd
Qtr 2014
|
|
|
103.07
|
|
|
|
16.90
|
|
|
|
1.832
|
|
|
|
30.96
|
|
|
|
19.28
|
|
|
|
52.83
|
|
3
rd
Qtr 2014
|
|
|
97.31
|
|
|
|
16.90
|
|
|
|
1.831
|
|
|
|
30.95
|
|
|
|
16.60
|
|
|
|
49.75
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
WTI Price
|
|
|
Chargeable
Costs
|
|
|
Cost
Adjustment
Factor
|
|
|
Adjusted
Chargeable
Costs
|
|
|
Production
Taxes
|
|
|
Average Per
Barrel
Royalty
|
|
|
|
|
|
|
|
|
Calendar 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
th
Qtr 2014
|
|
$
|
73.02
|
|
|
$
|
16.90
|
|
|
|
1.818
|
|
|
$
|
30.75
|
|
|
$
|
6.88
|
|
|
$
|
35.41
|
|
1
st
Qtr 2015
|
|
|
48.80
|
|
|
|
17.00
|
|
|
|
1.807
|
|
|
|
30.72
|
|
|
|
1.67
|
|
|
|
16.41
|
|
2
nd
Qtr 2015
|
|
|
57.80
|
|
|
|
17.00
|
|
|
|
1.831
|
|
|
|
31.13
|
|
|
|
2.02
|
|
|
|
24.65
|
|
3
rd
Qtr 2015
|
|
|
46.70
|
|
|
|
17.00
|
|
|
|
1.835
|
|
|
|
31.20
|
|
|
|
1.58
|
|
|
|
13.92
|
|
|
|
|
|
|
|
|
Calendar 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
th
Qtr 2015
|
|
$
|
42.15
|
|
|
$
|
17.00
|
|
|
|
1.827
|
|
|
$
|
31.07
|
|
|
$
|
1.40
|
|
|
$
|
9.68
|
|
1
st
Qtr 2016
|
|
|
33.73
|
|
|
|
17.10
|
|
|
|
1.826
|
|
|
|
31.22
|
|
|
|
1.06
|
|
|
|
1.45
|
|
2
nd
Qtr 2016
|
|
|
45.56
|
|
|
|
17.10
|
|
|
|
1.850
|
|
|
|
31.63
|
|
|
|
1.53
|
|
|
|
12.38
|
|
3
rd
Qtr 2016
|
|
|
44.99
|
|
|
|
17.10
|
|
|
|
1.855
|
|
|
|
31.71
|
|
|
|
1.51
|
|
|
|
11.81
|
|
|
|
|
|
|
|
|
Calendar 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
th
Qtr 2016
|
|
$
|
49.24
|
|
|
$
|
17.10
|
|
|
|
1.858
|
|
|
$
|
31.78
|
|
|
$
|
1.68
|
|
|
$
|
15.79
|
|
1
st
Qtr 2017
|
|
|
51.94
|
|
|
|
17.20
|
|
|
|
1.876
|
|
|
|
32.26
|
|
|
|
1.78
|
|
|
|
17.90
|
|
2
nd
Qtr 2017
|
|
|
48.32
|
|
|
|
17.20
|
|
|
|
1.884
|
|
|
|
32.41
|
|
|
|
1.63
|
|
|
|
14.27
|
|
3
rd
Qtr 2017
|
|
|
48.12
|
|
|
|
17.20
|
|
|
|
1.890
|
|
|
|
32.52
|
|
|
|
1.63
|
|
|
|
14.00
|
|
THE UNITS
Units
Each Unit represents an equal
undivided share of beneficial interest in the Trust. The Units do not represent an interest in or an obligation of BP Alaska, Standard Oil or any of their respective affiliates. Units are evidenced by transferable certificates issued by the Trustee.
Each Unit entitles its holder to the same rights as the holder of any other Unit. The Trust has no other authorized or outstanding class of securities.
Distributions of Income
BP Alaska makes
quarterly payments to the Trust of the amounts due with respect to the Trusts Royalty Interest on the fifteenth day following the end of each calendar quarter or, if the fifteenth is not a business day, on the next succeeding business day (the
Quarterly Record Date). The Trustee pays all expenses of the Trust for each quarter on the Quarterly Record Date to the extent possible, then distributes the excess, if any, of the cash received by the Trust over the Trusts
expenses, net of any additions to or subtractions from the cash reserve established for the payment of estimated liabilities (the Quarterly Distribution), to the persons in whose names the Units were registered at the close of business
on the Quarterly Record Date.
The Trust Agreement requires the Trustee to pay the Quarterly Distribution to Unit holders on the fifth day
after the Trustees receipt of the amount paid by BP Alaska. Cash balances held by the Trustee for distribution to Unit holders are required to be invested in United States government or agency obligations secured by the full faith and credit
of the United States (Government Obligations) or, if Government Obligations that mature on the date of the distribution to Unit holders are not available, in
9
repurchase agreements secured by Government Obligations with banks having capital, surplus and undivided profits
of $100,000,000 or more (which may include The Bank of New York Mellon). If time does not permit the Trustee to invest collected funds in Government Obligations or repurchase agreements, the Trustee may invest funds overnight in a time deposit with
a bank meeting the foregoing capital requirement (including The Bank of New York Mellon).
Reports to Unit Holders
After the end of each calendar year, the Trustee mails a report to the persons who held Units of record during the year containing information
to enable them to make the calculations necessary for federal and Alaska income tax purposes, including the calculation of any depletion or other deduction which may be available to them for the calendar year. In addition, after the end of each
calendar year the Trustee mails Unit holders an annual report containing a copy of this Form
10-K
and certain other information required by the Trust Agreement.
Limited Liability of Unit Holders
The
Trust Agreement provides that the Unit holders are, to the full extent permitted by Delaware law, entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under Delaware law.
Possible Divestiture of Units
The Trust
Agreement imposes no restrictions on nationality or other status of the persons eligible to hold Units. However, it provides that if at any time the Trust or the Trustee is named a party in any judicial or administrative proceeding seeking the
cancellation or forfeiture of any property in which the Trust has an interest because of the nationality, or any other status, of any one or more Unit holders, the Trustee may require each holder whose nationality or other status is an issue in the
proceeding to dispose of his Units to a party not of the nationality or other status at issue in the proceeding. If any holder fails to dispose of his Units within 30 days after receipt of notice from the Trustee to do so, the Trustee will redeem
any Units not so transferred within 90 days after the end of the
30-day
period specified in the notice for a cash price equal to the fair market value of the Units. Units redeemed by the Trustee will be
cancelled.
The Trustee may cause the Trust to borrow any amount required to redeem the Units. If the purchase of Units from an ineligible
holder by the Trustee would result in a
non-exempt
prohibited transaction under the Employee Retirement Income Security Act of 1970, or under the Internal Revenue Code of 1986, the Units subject to
the Trustees right of redemption will be purchased by BP Alaska or a designee of BP Alaska.
Issuance of Additional Units
The Trust Agreement provides that BP Alaska or an affiliate from time to time may assign to the Trust additional royalty interests meeting
certain conditions and, upon satisfaction of various other conditions, the Trust may issue up to an additional 18,600,000 Units. BP Alaska has not conveyed any additional royalty interests to the Trust, and the Trust has not issued any additional
Units.
THE BP SUPPORT AGREEMENT
BP agreed to provide financial support to BP Alaska in meeting its payment obligations to the Trust in a Support Agreement dated
February 28, 1989 among BP, BP Alaska, Standard Oil and the Trust (the
10
Support Agreement). Within 30 days after BP receives notice from the Trustee that the royalty payable
with respect to the Royalty Interest or any other amount payable by BP Alaska or Standard Oil has not been paid to the Trustee, BP will cause BP Alaska and Standard Oil to satisfy their respective payment obligations to the Trust and the Trustee
under the Trust Agreement and the Conveyance, including contributing to BP Alaska the funds necessary to make such payments. BP is required to make available to BP Alaska and Standard Oil such financial support as BP Alaska, Standard Oil or the
Trustee may request in writing. Any Unit holder has the unconditional right to institute suit against BP to enforce BPs obligations under the Support Agreement.
Neither BP nor BP Alaska may transfer or assign its rights or obligations under the Support Agreement without the prior written consent of the
Trustee, except that BP can arrange for its obligations to be performed by any of its affiliates so long as BP remains responsible for ensuring that its obligations are performed in a timely manner.
BP Alaska may sell or transfer all or part of its working interest in the Prudhoe Bay Unit, although such a transfer will not relieve BP of
its responsibility to ensure that BP Alaskas payment obligations with respect to the Royalty Interest and under the Trust Agreement and the Conveyance are performed.
BP will be released from its obligation under the Support Agreement upon the sale or transfer of all or substantially all of BP Alaskas
working interest in the Prudhoe Bay Unit if the transferee agrees in writing to assume and be bound by BPs obligation under the Support Agreement. The transferees agreement to assume BPs obligations must be reasonably satisfactory
to the Trustee and the transferee must be an entity having a rating of its unsecured, unsupported long-term debt of at least A3 from Moodys Investors Service, Inc., a rating of at least
A-
from
Standard & Poors, or an equivalent rating from at least one nationally-recognized statistical rating organization (after giving effect to the sale or transfer and the assumption of all of BP Alaskas obligations under the
Conveyance and all of BPs obligations under the Support Agreement).
THE PRUDHOE BAY UNIT AND FIELD
Prudhoe Bay Unit Operation and Ownership
Since several oil companies besides BP Alaska hold acreage within the Prudhoe Bay field, as well as several contiguous oil fields, the Prudhoe
Bay Unit was established to optimize field development. Other owners of these fields include affiliates of Exxon Mobil Corporation, ConocoPhillips and Chevron Corporation. The Trusts Royalty Interest pertains only to production from the 1989
Working Interests in the Prudhoe Bay field and does not include production from the other oil fields included in the Prudhoe Bay Unit.
The operations of BP Alaska and the other working interest owners in the Prudhoe Bay Unit are governed by an agreement dated April 1,
1977 among the State of Alaska and the working interest owners establishing the Prudhoe Bay Unit (the Prudhoe Bay Unit Agreement) and an agreement dated April 1, 1977 among the working interest owners governing Prudhoe Bay Unit
operations (the Prudhoe Bay Unit Operating Agreement).
The Prudhoe Bay Unit Operating Agreement specifies the allocation of
production and costs to the working interest owners. It also defines operator responsibilities and voting requirements and is unusual in its establishment of separate participating areas for the gas cap and oil rim. Since July 1, 2000, BP
Alaska has been the sole operator of the Prudhoe Bay Unit.
11
The ownership of the Prudhoe Bay Unit by participating area as of December 31, 2017 is shown
in the following table:
|
|
|
|
|
|
|
|
|
|
|
Oil rim
|
|
|
Gas
cap
|
|
BP Alaska
|
|
|
26.36
|
%(a)
|
|
|
26.36
|
%(b)
|
Exxon Mobil
|
|
|
36.40
|
|
|
|
36.40
|
|
ConocoPhillips
|
|
|
36.08
|
|
|
|
36.08
|
|
Chevron
|
|
|
1.16
|
|
|
|
1.16
|
|
Total
|
|
|
100.00
|
%
|
|
|
100.00
|
%
|
(a)
|
The Trusts share of oil production and condensate is computed based on BP Alaskas ownership interest in the oil rim participating area of 50.68% as of February 28, 1989. Subsequent decreases in BP
Alaskas participation in oil rim ownership do not affect calculation of Royalty Production from the 1989 Working Interests and have not decreased the Trusts Royalty Interest.
|
(b)
|
The Trusts share of condensate production is computed based on BP Alaskas ownership interest in the gas cap participating area of 13.84% as of February 28, 1989. Subsequent increases in BP Alaskas
gas cap ownership do not affect calculation of Royalty Production from the 1989 Working Interests and have not increased the Trusts Royalty Interest. Under the terms of an Issues Resolution Agreement entered into by the Prudhoe Bay Unit owners
in October 1990, produced condensate (defined as the Original Condensate Reserve in the agreement) from the gas cap participating area was allocated to that participating area until a cumulative limit of 1,175 million barrels was reached. This
cumulative limit was reached in June 2014, and beginning at that time and continuing thereafter, the condensate is allocated to the oil rim participating area.
|
If BP Alaska fails to pay any costs and expenses chargeable to BP Alaska under the Prudhoe Bay Unit Operating Agreement and the production of
oil and condensate is insufficient to pay such costs and expenses, the Royalty Interest is chargeable with a pro rata portion of such costs and expenses and is subject to the enforcement against it of liens granted to the operators of the Prudhoe
Bay Unit. However, in the Conveyance BP Alaska agreed to pay all costs and expenses chargeable to it and to ensure that no such costs and expenses will be chargeable against the Royalty Interest. The Trust is not liable for any loss or liability
incurred by BP Alaska or others attributable to BP Alaskas working interest in the Prudhoe Bay Unit or to the oil produced from it and BP Alaska has agreed to indemnify the Trust and hold it harmless against any such impositions.
BP Alaska has the right to amend or terminate the Prudhoe Bay Unit Agreement, the Prudhoe Bay Unit Operating Agreement and any leases or
conveyances with respect to the 1989 Working Interests in the exercise of its reasonable and prudent business judgment without liability to the Trust. BP Alaska also has the right to sell or assign all or any part of the 1989 Working Interests, so
long as the sale or assignment is expressly made subject to the Royalty Interest and the terms and provisions of the Conveyance.
The Prudhoe Bay Field
The Prudhoe Bay field is located on the North Slope of Alaska, 250 miles north of the Arctic Circle and 650 miles north of Anchorage.
The Prudhoe Bay field extends approximately 12 miles by 27 miles and contains nearly 150,000 gross productive acres. Approximately 45% of the acreage within the field is subject to the Royalty Interest granted to the Trust by the Conveyance. The
Prudhoe Bay field, which was discovered in 1968 by BP and others, has been in production since 1977 and is the largest producing oil field in North America. As of December 31, 2017, approximately 11.81 billion barrels of oil and condensate
had been produced from the Prudhoe Bay field.
12
Field Geology
The principal hydrocarbon accumulations at Prudhoe Bay are in the Ivishak sandstone of the Sadlerochit Group at a depth of approximately 8,700
feet below sea level. The Ivishak is overlain by four minor reservoirs of varying extent which are designated the Put River, Eileen, Sag River and Shublik (PESS) formations. Underlying the Sadlerochit Group are the
oil-bearing
Lisburne and Endicott formations. The net production allocated to the Royalty Interest pertains only to the Ivishak and PESS formations, collectively known as the Prudhoe Bay (Permo-Triassic) Reservoir,
and does not pertain to the Lisburne and Endicott formations.
The Ivishak sandstone was deposited, commencing some 250 million years
ago, during the Permian and Triassic geologic periods. The sediments in the Ivishak are composed of sandstone, conglomerate and shale which were deposited by a massive braided river and delta system that flowed from an ancient mountain system to the
north. Oil was trapped in the Ivishak by a combination of structural and stratigraphic trapping mechanisms.
Gross reservoir thickness is
550 feet, with a maximum oil column thickness of 425 feet. The original oil column is bounded on the top by a
gas-oil
contact, originally at 8,575 feet below sea level across the main field, and on the bottom
by an
oil-water
contact at approximately 9,000 feet below sea level. A layer of heavy oil and tar overlays the
oil-water
contact in the main field and has an average
thickness of around 40 feet.
Oil Characteristics
The oil produced from the Prudhoe Bay (Permo-Triassic) Reservoir is a medium grade, low sulfur crude with an average specific gravity of 27 API
degrees. The gas cap composition is such that, upon surfacing, a liquid hydrocarbon phase, known as condensate, is formed.
The Royalty
Interest is based upon oil produced from the oil rim and condensate produced from the gas cap, but not upon gas production (which is currently uneconomic on a large scale) or natural gas liquids production stripped from gas produced.
Historical Production
Production from
the Prudhoe Bay field began on June 19, 1977, with the completion of the Trans-Alaska Pipeline System (TAPS). As of December 31, 2017 there were 1046 active producing oil wells, 31 gas reinjection wells, 184 water injection
wells and water and miscible gas injection wells in the Prudhoe Bay field. Production wells drilled in the field during the three years ended December 31, 2017 were: 56 in 2015, 33 in 2016 and 23 in 2017. These include new sidetrack completions
in existing wells. No exploratory drilling activities were conducted in the field during the three-year period. Production from the Prudhoe Bay field reached a peak in 1988 and has declined steadily since then. The average well production rate was
about 188 barrels per day in 2013, 177 barrels per day in 2014, 170 barrels per day in 2015, 171 barrels per day in 2016 and 178 barrels per day in 2017.
BP Alaskas share of the hydrocarbon liquids production from the Prudhoe Bay field includes oil, condensate and natural gas liquids.
Using the production allocation procedures from the Prudhoe Bay Unit Operating Agreement, the Prudhoe Bay fields total production and the net share of oil and condensate (net of State of Alaska royalty) allocated to the 1989 Working Interests
have been as follows during the past five years:
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calendar
year
|
|
Oil
|
|
|
Condensate
|
|
|
Total field
|
|
|
Net to 1989
Working
Interests
|
|
|
Total field
|
|
|
Net to 1989
Working
Interests
|
|
|
|
(thousand barrels per day)
|
|
2013
|
|
|
173.4
|
|
|
|
77.7
|
|
|
|
44.6
|
|
|
|
5.4
|
|
2014
|
|
|
184.4
|
|
|
|
81.8
|
|
|
|
19.4
|
|
|
|
2.3
|
|
2015
|
|
|
196.4
|
|
|
|
87.1
|
|
|
|
0.0
|
(a)
|
|
|
0.0
|
|
2016
|
|
|
197.9
|
|
|
|
87.8
|
|
|
|
0.0
|
(a)
|
|
|
0.0
|
|
2017
|
|
|
188.0
|
|
|
|
83.4
|
|
|
|
0.0
|
(a)
|
|
|
0.0
|
|
(a)
|
Having reached the cumulative condensate limit in June 2014, pursuant to the Issues Resolution Agreement all condensate produced from the Initial Participating Area (IPA) is now allocated to the Oil Rim IPA for
accounting purposes.
|
Collection and Transportation of Prudhoe Bay Oil
Raw crude oil produced from individual production wells located at well pads is diverted to flowlines (pipelines). The flowlines transport the
raw crude oil to one of six separation facilities (three on the western side of the Prudhoe Bay Unit and three on the eastern side) where the water and natural gas mixed with the raw crude are removed. The stabilized crude is then sent from the
separation facilities through two
34-inch
diameter transit lines, one from each half of the Prudhoe Bay Unit, to Pump Station 1, the starting point for TAPS.
At Pump Station 1, Alyeska Pipeline Service Company, the operator of TAPS, meters the oil and pumps it in the
48-inch
diameter pipeline to Valdez, almost 800 miles (1,288 km) to the south, where it is either loaded onto marine tankers or stored temporarily. It currently takes the oil about 16 days to make the trip
from the Prudhoe Bay Unit to Valdez, due to declining flows of oil from the North Slope. TAPS has a maximum daily average throughput of approximately 1.14 million barrels of oil; recently, however, the pipeline has been moving an average of
approximately 527 thousand barrels per day.
Following a partial shutdown of the eastern side of the Prudhoe Bay Unit which lasted
from August 7 until September 22, 2006, BP Alaska replaced approximately 16 miles of oil transit lines and has implemented new integrity management and corrosion monitoring practices that supplement or replace the practices that existed in
2006. BP Alaska states that its integrity management practices meet the requirements of 49 CFR 195.452 for pipeline integrity management in high consequence areas.
Reservoir Management
The Prudhoe Bay
field is a complex, combination-drive reservoir, with widely varying reservoir properties. Reservoir management involves directing field activities and projects to maximize the economic value of reserves.
Several different oil recovery mechanisms are currently active in the Prudhoe Bay field, including pressure depletion, gravity drainage/gas
cap expansion, water flooding and miscible gas flooding.
14
Separate yet integrated reservoir management strategies have been developed for the areas affected by each of these recovery processes.
Reserve Estimates
Proved oil reserves
attributable to the 1989 Working Interests at December 31, 2017 are those quantities of oil which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from 2018 forward from
known reservoirs and under existing economic conditions, operating methods and government regulations. Estimates of proved reserves are inherently imprecise and subjective and are revised over time as additional data becomes available. Such
revisions often may be substantial. BP Alaskas reserve estimates and production assumptions and projections are predicated upon a reasonable estimate of the allocation of hydrocarbon liquids between oil and condensate according to the
procedures of the Prudhoe Bay Unit Operating Agreement. Oil and condensate are physically produced in a commingled stream of hydrocarbon liquids. The allocation of hydrocarbon liquids between the oil and condensate from the Prudhoe Bay field is a
theoretical calculation performed in accordance with procedures specified in the Prudhoe Bay Unit Operating Agreement. Under the terms of an Issues Resolution Agreement entered into by the Prudhoe Bay Unit owners in October 1990 (the Issuers
Resolution Agreement), the allocation procedures were adjusted to generally allocate condensate in a manner which approximates the anticipated decline in the production of oil until an agreed original condensate reserve of 1,175 million
barrels has been allocated to the working interest owners.
By letter dated December 19, 2014, BP Alaska advised the Trustee that the
portion of the hydrocarbon liquids produced from the initial participating areas of the Prudhoe Bay Unit being allocated as condensate from the gas cap participating area was found to have reached on June 8, 2014 the agreed original condensate
reserve of 1,175 million barrels allocated to the working interest owners. As a result, the portion of hydrocarbon liquids previously allocated as condensate to the gas cap participating area will be allocated to the oil rim participating area.
This event has had the effect of changing the calculation of the volume of Royalty Production subject to the Royalty Interest because 50.68% of hydrocarbon liquids allocated to the oil rim participating area
2
are counted for the purpose of calculating such volume, but only 13.84% of the hydrocarbon liquids are allocated to the gas cap participating area for such purpose.
3
The end of the allocation to the gas cap participating area on June 8, 2014 meant that volumes of hydrocarbon liquids subject to the Royalty Interest for the second and third quarters of 2014
were greater than the volumes of Royalty Production initially reported by BP Alaska. The correction to the volumes of Royalty Production and the Royalty payments with respect to the Royalty Interest for such quarters were made in conjunction with
the scheduled Royalty payment in January 2015 for the quarter ended December 31, 2014. See Note 6 of Notes to Financial Statements below.
There is no precise method of forecasting the allocation of reserve volumes to the Trust. The Royalty Interest is not a working interest and
the Trust is not entitled to receive any specific volume of reserves from the 1989 Working Interests. The reserve volumes attributable to the 1989 Working Interests are estimated using an allocation of reserve volumes based on estimated future
production and the average WTI Price, and assume no future movement in the Consumer Price Index and no changes to the procedure
2
|
See note (a) to the table of ownership of the Prudhoe Bay Unit by participating area as of December 31, 2015 above under the caption THE PRUDHOE BAY UNIT and FIELD Prudhoe Bay Unit Operation and
Ownership.
|
3
|
See note (b) to the table of ownership of the Prudhoe Bay Unit by participating area as of December 31, 2016 above under the caption THE PRUDHOE BAY UNIT and FIELD Prudhoe Bay Unit Operation and
Ownership.
|
15
for calculating Production Taxes. The estimated reserve volumes attributable to the Trust will vary if different
estimates of production, prices and other factors are used. Even if expected reservoir performance does not change, the estimated reserves, economic life, and future revenues attributable to the Trust may change significantly in the future. This may
result from changes in the WTI Price or from changes in other prescribed variables utilized in calculations defined by the Overriding Royalty Conveyance.
The reserves attributable to the 1989 Working Interests constitute only a part of the overall reserves in the Prudhoe Bay Unit. BP Alaska has
estimated that the proved reserves allocated to the Trust as of December 31, 2017 were 9.070
million barrels of oil and condensate, of which 9.047 million barrels are proved developed reserves
4
and 0.023 million barrels are proved undeveloped reserves
5
. Proved reserves attributable to the Trust were increased by approximately
4.4 million barrels during 2017 as a result of the increase in the West Texas Intermediate price, forecast revisions and capital activities including drilling and well treatments. Additional information regarding changes in estimated quantities
of proved oil and condensate, proved developed reserves and proved undeveloped reserves is found below in Supplemental Reserve Information and Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Reserves
(Unaudited) following the Notes to Financial Statements.
In all cases, the volumes are being progressed as a part of an adopted
development plan that calls for drilling of wells over an extended period of time given the magnitude of the development. BP has a historical record of completing comparable projects. There were no contributions to proved undeveloped reserves from
extensions or discoveries during 2017.
Based on the 2017 twelve-month average WTI Price
6
of $51.34 per barrel, other economic
parameters prescribed by the Conveyance, and utilizing procedures specified in Financial Accounting Standards Board Accounting Standards Codification (FASB ASC) 932,
Extractive Activities Oil and Gas
, BP Alaska calculated
that as of December 31, 2017 production of oil and condensate from the proved reserves allocated to the 1989 Working Interests will result in undiscounted estimated future cash flow to the Trust of $73.823 million, with a net present value
of estimated future cash flows at 10% discount of $68.676 million.
The internal controls applicable to the foregoing estimates of
the reserves allocated to the Trust are those employed by BP, which provides the information to the Trustee. BP Alaska has advised the Trustee that BPs vice president of segment reserves is the petroleum engineer primarily responsible for
overseeing the preparation of the reserves estimate. He has 30 years of diversified industry experience managing the governance and compliance of BPs reserves estimation since 2005. He is a past member of the Society of Petroleum Engineers Oil
and Gas Reserves Committee, a sitting member of the American Association of Petroleum Geologists Committee on Resource Evaluation and current chair of the bureau of the United Nations Economic Commission for Europe Expert Group on Resource
Classification. The Trust employs Miller and Lents, Ltd., an international oil and gas consulting firm, to conduct an annual review of BP Alaskas estimates of the proved reserves allocated to the Trust, estimated future net revenues to the
Trust, and the remaining period of economic production from the Prudhoe Bay field attributable to the Trust. All Miller and Lents, Ltd. staff members assigned to the BP Prudhoe Bay Royalty Trust are licensed professional engineers. Work was
supervised by a licensed professional
4
|
Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor
compared to the cost of a new well.
|
5
|
Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
|
6
|
The unweighted arithmetic average of the WTI Price on the first day of each month during the year.
|
16
engineer with more than 15 years of experience with the Trust. A
copy of the February 15, 2018 report
of Miller and Lents, Ltd.
is filed as Exhibit 99 to this report.
BP Alaska has undertaken a program of field-wide infrastructure
renewal, pipeline replacement, and mechanical improvements to wells. As a consequence of these activities and their required downtime, and the natural production declines discussed above under Historical Production, BP Alaskas net
production of oil and condensate allocated to the Trust from proved reserves 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 allocated to the
Trust from proved reserves will be below 90,000 barrels per day on an annual average basis most future years. The occurrence of major gas sales could accelerate the decline in net production, due to the consequent decline in reservoir pressure. See
Item 1A, RISK FACTORS.
Based on the 2017 twelve-month average WTI Price of $51.34 per barrel, current Production Taxes, and
the Chargeable Costs adjusted as prescribed by the Overriding Royalty Conveyance, it is estimated that royalty payments to the Trust will continue through the year 2019, and would be zero in the following year. Therefore, no proved reserves are
currently attributed to the BP Prudhoe Bay Royalty Trust after that date. Even if expected reservoir performance does not change, the estimated reserves, economic life and future net revenues attributable to the Trust may change significantly in the
future. This may result from sustained periods of change in the WTI Price, the Production Tax or from changes in other prescribed variables utilized in calculations as defined by the Overriding Royalty Conveyance.
BP Alaska is under no obligation to make investments in development projects which would add additional
non-proved
resources to proved reserves and cannot make such investments without the concurrence of the Prudhoe Bay Unit working interest owners. The Prudhoe Bay Unit working interest owners regularly assess
the technical and economic attractiveness of implementing projects to increase Prudhoe Bay Unit proved reserves. See Item 1A, RISK FACTORS, below.
In the event of changes in BP Alaskas current assumptions, oil and condensate recoveries may be reduced from the current estimates,
unless recovery projects other than those included in the current estimates are implemented.
INDUSTRY
CONDITIONS AND REGULATIONS
The production of oil and gas in Alaska is affected by many state and federal regulations with respect to
allowable rates of production, marketing, environmental matters and pricing. Future regulations could change allowable rates of production or the manner in which oil and gas operations may be lawfully conducted.
In general, BP Alaskas oil and gas activities are subject to existing federal, state and local laws and regulations relating to health,
safety, environmental quality and pollution control. BP Alaska believes that the equipment and facilities currently being used in its operations generally comply with the applicable legislation and regulations. During the past few years, numerous
environmental laws and regulations have taken effect at the federal, state and local levels. Oil and gas operations are subject to extensive federal and state regulation and to interruption or termination by governmental authorities due to
ecological and other considerations and in certain circumstances impose absolute liability upon lessees for the cost of cleaning up pollutants and for pollution damages resulting from their operations. Although BP Alaska has advised that the
existence of legislation and regulation has had no material adverse effect on BP Alaskas current method of operations, the effect of future legislation and regulations cannot be predicted.
17
Since the end of 2006, the corrosion monitoring and mitigation practices for the oil transit
lines in the Prudhoe Bay Unit have been monitored and reviewed by the U.S. Department of Transportation. The construction, testing, and commissioning of the new replacement oil transit lines have been inspected by DOT inspectors. The replacement
lines have been constructed and are operated and maintained in accordance with the requirements of the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (the PIPES Act). The applicable requirements of the subsequent
regulations of the PIPES Act began to be phased in in 2012. See THE PRUDHOE BAY UNIT AND FIELD Collection and Transportation of Prudhoe Bay Oil above.
CERTAIN TAX CONSIDERATIONS
The following is a summary of the principal tax consequences to Unit holders resulting from the ownership and disposition of Units. The laws
and regulations affecting these matters are complex, and are subject to change by future legislation or regulations or new interpretations by the Internal Revenue Service, state taxing authorities or the courts. In addition, there may be differences
of opinion as to the applicability or interpretation of present tax laws and regulations. BP Alaska and the Trust have not requested any rulings from the Internal Revenue Service with respect to the tax treatment of the Units, and no assurance can
be given that the Internal Revenue Service would concur with the statements below.
Unit holders are urged to consult their tax advisors
regarding the effects on their specific tax situations of owning and disposing of Units.
Federal Income Tax
Classification of the Trust
The following discussion assumes that the Trust is properly classified as a grantor trust under current law and is not an association taxable
as a corporation.
General Features of Grantor Trust Taxation
A grantor trust is not subject to tax, and its beneficiaries (the Unit holders in the case of the Trust) are considered for tax purposes to own
the assets of the trust directly. The Trust pays no federal income tax but files an information return reporting all items of income or deduction. If a court were to hold that the Trust is an association taxable as a corporation, the Trust would
incur substantial income tax liabilities in addition to its other expenses.
Taxation of Unit Holders
In computing his federal income tax liability, each Unit holder is required to take into account his share of all items of Trust income, gain,
loss, deduction, credit and tax preference, based on the Unit holders method of accounting. Consequently, it is possible that in any year a Unit holders share of the taxable income of the Trust may exceed the cash actually distributed to
him in that year. For example, if the Trustee should add to the reserve for the payment of Trust liabilities or repay money borrowed to satisfy debts of the Trust, the money used to replenish the reserve or to repay the loan is income to and must be
reported by the Unit holder, even though the money was not distributed to the Unit holder.
The Trust makes quarterly distributions to the
persons who held Units of record on each Quarterly Record Date. The terms of the Trust Agreement seek to assure to the extent practicable that income, expenses and deductions attributable to each distribution are reportable by the Unit holder who
receives the distribution.
18
The Trust allocates income and deductions to Unit holders based on record ownership at Quarterly
Record Dates. It is not known whether the Internal Revenue Service will accept the allocation based on this method.
Depletion
Deductions
The owner of an economic interest in producing oil and gas properties is entitled to deduct an allowance for the
greater of cost depletion or (if otherwise allowable) percentage depletion on each such property. A Unit holders deduction for cost depletion in any year is calculated by multiplying the holders adjusted tax basis in his Units (generally
his cost less prior depletion deductions) by Royalty Production during the year and dividing that product by the sum of Royalty Production during the year and estimated remaining Royalty Production as of the end of the year. The allowance for
percentage depletion generally does not apply to interests in proven oil and gas properties that were transferred after December 31, 1974 and prior to October 12, 1990. The Omnibus Budget Reconciliation Act of 1990 repealed this rule for
transfers occurring on or after October 12, 1990. Unit holders who acquired their Units on or after that date may be permitted to deduct an allowance for percentage depletion if such deduction would otherwise exceed the allowable deduction for
cost depletion. In order to take percentage depletion, a Unit holder must qualify for the independent producer exemption contained in section 613A(c) of the Internal Revenue Code of 1986. Percentage depletion is based on the Unit
holders gross income from the Trust rather than on his adjusted basis in his Units. Any deduction for cost depletion or percentage depletion allowable to a Unit holder reduces his adjusted basis in his Units for purposes of computing
subsequent depletion or gain or loss on any subsequent disposition of Units.
Unit holders must maintain records of their adjusted basis
in their Units, make adjustments for depletion deductions to such basis, and use the adjusted basis for the computation of gain or loss on the disposition of the Units.
Taxation of Foreign Unit Holders
Generally, a holder of Units who is a nonresident alien individual or which is a foreign corporation (a Foreign Taxpayer) is
subject to tax on the gross income produced by the Royalty Interest at a rate equal to 30% (or at a lower treaty rate, if applicable). This tax is withheld by the Trustee and remitted directly to the United States Treasury. A Foreign Taxpayer may
elect to treat the income from the Royalty Interest as effectively connected with the conduct of a United States trade or business under Internal Revenue Code section 871 or section 882, or pursuant to any similar provisions of applicable treaties.
If a Foreign Taxpayer makes this election, it is entitled to claim all deductions with respect to such income, but a United States federal income tax return must be filed to claim such deductions. This election once made is irrevocable unless an
applicable treaty provides otherwise or unless the Secretary of the Treasury consents to a revocation.
Section 897 of the Internal
Revenue Code and the Treasury Regulations thereunder treat the Trust as if it were a United States real property holding corporation. Foreign holders owning more than five percent of the outstanding Units are subject to United States federal income
tax on the gain on the disposition of their Units. Foreign Unit holders owning less than five percent of the outstanding Units are not subject to United States federal income tax on the gain on the disposition of their Units, unless they have
elected under Internal Revenue Code section 871 or section 882 to treat the income from the Royalty Interest as effectively connected with the conduct of a United States trade or business.
If a Foreign Taxpayer is a corporation which made an election under Internal Revenue Code section 882(d), the corporation would also be
subject to a 30% tax under Internal Revenue Code section 884. This tax is imposed on U.S. branch profits of a foreign corporation that are not reinvested in the U.S. trade or business. This tax is in addition to the tax on effectively connected
income. The branch profits tax may be either reduced or eliminated by treaty.
19
Sale of Units
Generally, a Unit holder will realize gain or loss on the sale or exchange of his Units measured by the difference between the amount realized
on the sale or exchange and his adjusted basis for such Units. Gain on the sale of Units by a holder that is not a dealer with respect to such Units will generally be treated as capital gain. However, pursuant to Internal Revenue Code section 1254,
certain depletion deductions claimed with respect to the Units must be recaptured as ordinary income upon sale or disposition of such interest.
Backup
Withholding
A payor must withhold 28% of any reportable payment if the payee fails to furnish his taxpayer identification number
(TIN) to the payor in the required manner or if the Secretary of the Treasury notifies the payor that the TIN furnished by the payee is incorrect. Unit holders will avoid backup withholding by furnishing their correct TINs to the Trustee
in the form required by law.
Widely Held Fixed Investment Trusts
The Trustee assumes that some Trust Units are held by a middleman, as such term is broadly defined in the U.S. Treasury Regulations (which
includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee considers the Trust to be a widely held fixed investment trust (WHFIT) for U.S. Federal income
tax purposes. The Bank of New York Mellon Trust Company, N.A. is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust
as a WHFIT. For information contact The Bank of New York Mellon Trust Company, N.A., Global Corporate Trust Corporate Finance, 601 Travis Street, Floor 16, Houston, TX 77002, telephone number (713)
483-6020.
State Income Taxes
Unit holders may be required to report their share of income from the Trust to their state of residence or commercial domicile. However, only
corporate Unit holders will need to report their share of income to the State of Alaska. Alaska does not impose an income tax on individuals or estates and trusts. All Trust income is Alaska source income to corporate Unit holders and should be
reported accordingly.
Foreign Account Tax Compliance Act
Pursuant to the Foreign Account Tax Compliance Act (commonly referred to as FATCA), distributions from the Trust to foreign
financial institutions and certain other
non-financial
foreign entities may be subject to U.S. withholding taxes. Specifically, certain withholdable payments (including certain
royalties, interest and other gains or income from U.S. sources) made to a foreign financial institution or
non-financial
foreign entity will generally be subject to the withholding tax unless the foreign
financial institution or
non-financial
foreign entity complies with certain information reporting, withholding, identification, certification and related requirements imposed by FATCA. Foreign financial
institutions and
non-financial
foreign entities located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules. Foreign Unit holders
are encouraged to consult their own tax advisors regarding the possible implications of these withholding provisions on their investment in Trust Units.
20
Owners of Units are exposed to risks and uncertainties that are particular
to their investment.
|
|
|
Royalty Production from the Prudhoe Bay field is projected to decline and will eventually cease.
|
The Prudhoe Bay field has been in production since 1977. Development of the field is largely completed and proved reserves are being depleted.
Production of oil and condensate from the field has been declining during recent years and the decline is expected to continue. As discussed above under the caption THE PRUDHOE BAY UNIT and FIELD Reserve Estimates, Royalty
payments to the Trust, based on calculations using a 2017 WTI Price of $51.34 per barrel, among other prescribed variables, are projected to cease after 2019.
Production estimates included in this report are based on economic conditions and production forecasts as of the end of 2017, and also depend
on various assumptions, projections and estimates which are continually revised and updated by BP Alaska. These revisions could result in material changes to the projected declines in production. It is possible that economic production from the
reserves allocated to the 1989 Working Interests could decline more quickly and end sooner than is currently projected.
|
|
|
Royalty payments by BP Alaska to the Trust are unpredictable, because they depend on Cushing, Oklahoma WTI spot prices, which are subject to volatility, and on the volume of production from the 1989 Working
Interests, which may vary from quarter to quarter in the future.
|
WTI Prices, like prices in the global crude oil
market generally, are subject to periodic fluctuations and significant volatility. This was dramatically demonstrated by the steep decline in WTI Prices from more than $100 per barrel in June 2014 to around $27 dollars per barrel in early 2016.
Recent price changes also provide evidence of this volatility. WTI prices increased $5.43 per barrel from January 2 to February 1, 2018. From a price of $65.80 per barrel on February 1, 2018, WTI prices fell below $60 dollars per
barrel on February 9, 2018 as world stock markets fell sharply.
Even before the 2014 plunge in oil price, the general trend of WTI
price increases had moderated as a result of increasing volumes of crude oil production from Canada and the Bakken shale formation, situated in the northwest portion of North Dakota (and extending into Montana and portions of Canada), moving into
the U.S. Midwest market. Oil production in the United States also surged owing, in part, to a dramatic increase in horizontal drilling and hydraulic fracturing, or fracking, and other technological advances in oil detection and extraction. This
great increase in output from the U.S. helped lead to an oversupply in the global crude market. While the global crude oil market became oversupplied, global demand was declining, with the result that global oil prices dropped more than 70% from
June 2014 through the middle of February 2016. As a result of this imbalance, U.S. production declined by over one million barrels per day by
mid-2016
from a peak of 9.6 million barrels per day in June
2015 as U.S. oil companies discontinued most exploration and drilling operations.
The decline in global oil prices was halted in the
first quarter of 2016 as the falling U.S. production and increased global demand led to generally increasing oil prices following the lows reached in early 2016. In June 2016, oil prices settled over $50 per barrel for the first time in almost a
year on higher than expected draws on U.S. crude oil stockpiles and concerns about global supply shortfalls. Oil prices
21
received additional support later in 2016 when OPEC and eleven
non-OPEC
countries, including Russia, agreed to curtail production for the first six months of 2017 in an attempt to remove supply from the global market.
As a result of these events, it was widely anticipated at the beginning of 2017 that oil prices would remain relatively stable in 2017 and
trade in a range of $50 to $55 per barrel. However, there were several large price swings during the first half of 2017 as U.S. output increased and doubts grew over the ability of OPEC to decrease production sufficiently to have a significant
effect on the oil market. Extended spring maintenance at refineries within and outside of the U.S. also reduced the amount of crude oil being refined, which contributed to an unexpected
build-up
of crude oil
stocks and exerted further downward pressure on oil prices. Once this maintenance ended and draws on crude oil supplies resumed, prices began to rise again. The price rise also reflected growing expectations that, as a result of the fluctuations in
crude oil stocks during the first half of the year, OPEC would agree to not only extend but increase its agreed-upon production cuts at its
mid-year
meeting. However, prices fell again when OPEC announced its
decision to maintain production volumes at current levels and to extend its production agreement only through March 2018. In addition, reports that a number of U.S shale operators had significantly increased spending gave rise to fears of increasing
global supply. These factors contributed renewed downward pressure on oil prices, which declined into the low $40s in June 2017.
Despite
these concerns during the first half of the year, data in the summer of 2017 indicated that global demand for oil was strong and that refineries were increasing runs following the period of maintenance earlier in the year. As a result, global levels
of crude oil stocks began to decline. This, together with other factors, such as evidence that the OPEC deal was being effectively implemented, supported global expectations of rising crude oil prices. Other unanticipated
events also bolstered oil prices during the second half of 2017, such as Hurricane Harvey, which interrupted a significant portion of refining capacity and offshore crude production in the region of the U.S. Gulf Coast, and the temporary shutdown of
the Keystone pipeline following a leak of approximately 210,000 gallons of oil in South Dakota in November 2017. In addition, OPEC announced at its annual November meeting that the cartel and the other
non-OPEC
producers had agreed to extend the 2016 production agreement through the end of 2018. Following this announcement, crude oil prices rose to their highest levels of the year up to that point. Brent crude
received additional price support in December due to the closure of the North Seas Forties crude oil pipeline system, which is one of the primary distribution networks for Brent crude oil delivery in the North Sea, because of a hairline crack
found in an onshore portion of the pipeline. Also in December, news of an explosion at a Libyan crude oil pipeline that carries crude oil to Libyas largest oil export terminal added to expectations of a reduction in oil supplies.
This rise in crude oil prices in the second half of 2017 occurred despite robust increases in U.S. crude oil production. This production
increase was led by strong onshore production (especially in the Permian basin area largely contained in the western part of Texas and the southeastern part of New Mexico) with an estimated increase of nearly 330,000 barrels per day from 2016 to
2017. The U.S. Energy Information Administration (EIA) also estimated in its February 2018 Short-Term Energy Outlook (the February STEO) that total U.S. crude oil production averaged 9.3 million barrels per day in 2017.
Despite this production increase, EIA estimated in the February STEO that global petroleum and other liquid fuels inventories fell by an average of 0.5 million barrels per day in 2017. This was the first year of annual average drawdown of
global inventories since 2013. As a result of these factors, WTI prices finished 2017 averaging more than $51 per barrel, which was $7 per barrel higher than in 2016. Strong global demand for crude oil in 2017 also supported prices, with global oil
consumption rising more than the historical average, according to the International Energy Agency (IEA).
22
With respect to 2018, EIA forecasts that total U.S. crude oil production will average
10.6 million barrels per day in 2018, which would eclipse the previous record for the highest annual average U.S. production of 9.6 million barrels per day in 1970. The IEA also announced that it expects U.S. crude oil production in 2018
to surpass that of Saudi Arabia. Although forecasts of continuing global economic growth suggest that there will be continued strong demand for crude oil and petroleum products in the near term, EIA expects that global oil inventories will rise by
0.2 million barrels per day in 2018 and 2019. EIA forecasts that this anticipated
build-up
of inventory in 2018 and 2019 will result in crude oil prices averaging $60 per barrel during the first quarter
of 2018. EIA then expects oil prices to remain relatively flat through 2019.
Although crude oil prices rose generally in 2017, WTI prices
averaged $6 per barrel less in the fourth quarter of 2017 than Brent crude - the other main crude oil benchmark - after previously trading at a difference of between $2 and $3 for most of the preceding 18 months. EIA forecasts that WTI
crude oil prices will be $4 per barrel lower than Brent prices in 2018 and in 2019, which would be a narrowing of the $6 per barrel average price difference seen in the fourth quarter of 2017. EIA bases this forecast on the assumption that certain
limitations on the capacity to transport crude oil from the Cushing, Oklahoma storage hub to the Gulf Coast will be alleviated. In prior periods, Cushing has occasionally become oversupplied due to new oil flows from Canada and the United States.
Historically, this market had been reliant on high-cost rail and trucks to ship both crude oil stored at Cushing and production from Canada and the Bakken shale formation to the Gulf Coast. These constraints on transportation of crude oil out of the
U.S. Midwest market, together with the great increase in production in North America and the decades-long U.S. ban on crude oil exports, had helped to weigh down WTI spot prices for several years and kept the price of WTI crude oil at a historic
discount to globally traded waterborne crudes such as Brent. Prior to that period, WTI, which is generally a sweeter and lighter crude oil than Brent, had been more likely to trade at a premium to Brent.
After diverging in 2011 to a high of around $30 per barrel, with Brent the more expensive oil, the spread between WTI and Brent gradually
decreased as these transportation problems were largely resolved. For example, the direction of the Seaway crude oil pipeline was reversed in 2012 and pump station additions and modifications were subsequently made. In 2014 the Seaway
Twin pipeline running parallel to the reversed Seaway pipeline was opened. Also in 2014, the Cushing MarketLink phase of the Keystone pipeline went into operation. This portion of the Keystone pipeline starts at Cushing, where
American-produced oil is added to the pipelines Canadian oil. The pipeline then runs south to terminals in Nederland, Texas near refineries located in the Port Arthur, Texas area. The Houston Lateral pipeline also began operating in 2017. This
is a
47-mile
pipeline transporting crude oil from the MarketLink pipeline in Liberty County, Texas, to refineries and terminals in the Houston area. However, closures of the Seaway pipelines due to spills in
October 2016 and early 2017 highlight the risk that prolonged shutdowns of these or other pipeline projects out of Cushing could contribute to rising inventory levels, particularly if such shutdowns should coincide with increased volumes of crude
oil flowing into Cushing.
Such increases could occur as U.S. production continues to increase in response to the upward direction of
crude oil prices in 2017 and early 2018. Also, even greater amounts of crude oil are expected to be arriving at Cushing following the approval by the Trump administration in January 2017 of a permit allowing TransCanada to build the Keystone XL
pipeline and the approval by the Nebraska Public Service Commission of a new route for the pipeline in November 2017. Nebraska was the only state that had not yet approved the route of the pipeline.
TransCanada expects construction of Keystone XL to begin in 2019 and forecasts that Keystone XL will eventually carry up to 830,000 barrels of
oil per day. This could significantly increase the total
23
amount of crude oil flowing into Cushing. The first part of the Keystone pipeline system, which runs through
North and South Dakota, Nebraska and Missouri, went into operation in 2010 and connects Hardisty, Alberta to U.S. refineries in Illinois. The pipeline has a nominal capacity of 435,000 barrels per day. The second part of the Keystone system is a 291
mile-long pipeline connection running from Steele City, Nebraska south to Cushing, Oklahoma. This Keystone-Cushing pipeline, which opened in 2011, transports 100,000 barrels of crude oil per day to Cushing. The Keystone XL pipeline would enter the
U.S. through Montana, where American-produced oil would be added to the pipeline, and would then connect with the existing Keystone pipeline at Steele City, Nebraska. This would increase the amount of oil in the Keystone system flowing east to
Illinois refineries and south to Cushing.
While insufficient outgoing pipeline capacity capable of transporting the crude oil entering
Cushing could depress WTI prices, pipeline capacity out of Cushing was increased in December 2017, when the Plains All American and Valero Diamond Pipeline went into operation. This pipeline, with a capacity of 200,000 barrel per day, connects
Cushing to Valeros refinery in Memphis, Tennessee. According to the EIA, the increase of volumes flowing through the Diamond Pipeline was the main reason for the sharp decline in crude oil stocks at Cushing reported in January 2018, which were
down 40 percent compared to a year earlier.
The spread between the Brent price and the price of U.S. domestic production could also
be affected by the lifting of the U.S. ban on crude oil exports introduced in the 1970s. This ban was lifted in December 2015. The removal of the ban could contribute to wider use of WTI as a global benchmark. Although the U.S. continues to be
a net importer of oil (due, among other reasons, to U.S. refineries having been designed to process much heavier crudes), weekly U.S. crude oil exports reached a record level of 2.13 million barrels per day in the week ended October 27,
2017. Also in 2017, China passed the U.S. as the worlds largest importer of crude oil.
If OPEC and
non-OPEC
nations continue to adhere to the production cuts agreed to in November 2017, U.S. producers may have an opportunity to gain access to additional international markets. Although the IEA has reported
that OPECs compliance with the production cuts averaged 95% throughout 2017, the possibility of losing market share to the U.S. could jeopardize compliance with the agreed-upon production levels by OPEC and the other producing countries.
|
|
|
The amount and value of reserves attributable to the Trust, the estimated life of the Trust, estimates of future net revenues and estimates of the present value of future net revenues fluctuate based on the WTI
Price, among other factors. WTI Prices may be below the break-even point for daily royalty calculations.
|
As discussed above under THE ROYALTY INTEREST in Item 1, revenues to the Trust are calculated daily by BP Alaska using the WTI
price, production tax, and other variables as prescribed by the Conveyance applicable on that specific day. On January 1, 2018 the break-even WTI price (at which all taxes and prescribed deductions are equal to the WTI price) was
$39.26.
7
The quarterly royalty payment by BP Alaska to the Trust is the sum of the individual revenues calculated each day during the quarter. In the event that one or more daily calculations
results in a negative amount, the total of such daily negative amounts during that calendar quarter would be subtracted from total daily positive amounts during such quarter to determine the royalty payment for such quarter, provided, that in no
event will any quarterly royalty payment be less than zero.
7
|
The fixed Chargeable Cost increases specified in the Conveyance will impact the break-even price in future years.
|
24
The estimated future net revenues and present value of estimated future net revenues reported
herein are calculated based on a single average WTI price, that being the average of 12 WTI values, each value representing the WTI price in effect on the first calendar day of the month for the 12 months prior to January 1, 2018. As a result,
any single calculation of a calendar day will not reflect the value of the dividend paid to the Trust for any quarter, nor will it reflect the estimated future value of the Trust or the estimation of how long royalty payments to the Trust will
continue.
Based on the 2017 twelve-month average WTI Price of $51.34 per barrel, current Production Taxes, and the Chargeable Costs
adjusted as prescribed by the Overriding Royalty Conveyance, it is estimated that royalty payments to the Trust will continue through the year 2019, and would be zero in the following year. Therefore, no proved reserves are currently attributed to
the BP Prudhoe Bay Royalty Trust after that date. Even if expected reservoir performance does not change, the estimated reserves, economic life and future net revenues attributable to the Trust may change significantly in the future as a result of
sustained periods of change in the WTI Price, the Production Tax or from changes in other prescribed variables utilized in calculations as defined by the Overriding Royalty Conveyance. Such changes could result in the termination of royalty payments
prior to 2019.
While energy price forecasts are highly uncertain,
EIA forecasts that Brent and WTI crude oil spot prices will average approximately $62 and $58 per barrel, respectively, in 2018 and 2019. As discussed under THE PRUDHOE BAY UNIT AND FIELD Reserve Estimates, the amount and value of
reserves attributable to the Trust and the estimated life of the Trust fluctuate based on changes to certain prescribed factors, including the WTI price. WTI prices at the level forecast by EIA should, subject to the effect of the other
prescribed variables, result in positive royalty payments to the Trust, if such prices actually constitute the 2018 twelve-month average WTI Price (that is, the unweighted arithmetic average of the WTI price on the first day of each month during the
year). If such WTI Prices are in fact lower than the 2017 twelve-month average WTI Price of $51.34, this could result, subject to the effect of the other prescribed variables, in substantial decreases in the value and the estimated life of the Trust
as calculated for such periods compared to the 2017 calculations set forth under THE PRUDHOE BAY UNIT AND FIELD Reserve Estimates.
However, future domestic and international events and conditions may produce wide swings in crude oil prices over relatively short periods of
time. Recent moves in crude oil prices have been affected by many factors. These include changes in demand due to variations in economic activity, increased efficiency, increased demand for other types of fuel, strong production growth, new supplies
from tight and shale resources, whether OPEC and other oil producing nations have been willing to intervene to stabilize oversupplied crude oil markets by cutting production or to take other measures in order to preserve or expand market share,
shifts in inventory management strategies by international oil companies, conservation measures by consumers, increasing effects of the oil futures market and other unpredictable political, geopolitical, psychological and economic factors, such as
developments with respect to political unrest in Iran and the Iran nuclear deal, the continuing collapse of Venezuelas oil industry, tensions between North Korea and South Korea and the U.S., the strength or weakness of the U.S. dollar (the
currency in which crude oil is quoted, with crude oil prices, like prices of other commodities priced in dollars, generally moving inversely to the value of the dollar), how the policies of the U.S. administration may influence oil production and
markets, expectations for global economic growth, political turmoil in North Africa and the Middle East and ongoing tensions in other regions of the world and turmoil and volatility in global stock markets.
For additional information, see the history of WTI Prices since 1986 published by the U.S. Energy Information Administration at
http://tonto.eia.doe.gov.
25
It is increasingly likely that the Trusts revenues in future periods also will be affected
by decreases in production from the 1989 Working Interests. BP Alaskas average net production of oil and condensate allocated to the Trust from proved reserves was less than 90,000 barrels per day on an annual basis during 2015, 2016 and 2017,
and the Trustee has been advised that BP Alaska expects that average net production allocated to the Trust from the proved reserves will be less than 90,000 barrels a day on an annual basis in future years. Unit holders thus are subject to the risk
that cash distributions with respect to their Units may vary widely from quarter to quarter.
|
|
|
Prudhoe Bay field oil production could be shut in partially or entirely from time to time as a result of damage to or failures of field pipelines or equipment.
|
In August 2006, BP Alaska shut down the eastern side of the Prudhoe Bay Unit following the discovery of unexpectedly severe corrosion and a
small spill from the oil transit line on that side of the Unit. Earlier, in March of 2006, BP had to temporarily shut down and commence the replacement of a three-mile segment of transit line on the western side of the Prudhoe Bay Unit following
discovery of a large oil spill.
BP Alaska completely replaced approximately 16 miles of transit lines on the eastern and western sides of
the Prudhoe Bay Unit and has implemented federally-required corrosion monitoring practices. However, the discovery of additional defects in Prudhoe Bay Unit oil flowlines and transit lines, and damage to or failures of separation facilities or other
critical equipment, could result in future shutdowns of oil production from all or portions of the Prudhoe Bay Unit and have an adverse effect on future royalty payments.
|
|
|
Oil production from the Prudhoe Bay Unit could be interrupted by damage to the Trans-Alaska Pipeline System from natural causes, accidents, deliberate attacks or declining oil flows.
|
The Trans-Alaska Pipeline System connects the North Slope oil fields to the southern port of Valdez, almost 800 miles away. It is the only way
that oil can be transported from the North Slope to market. The pipeline system crosses three mountain ranges, many rivers and streams and thaw-sensitive permafrost. It is susceptible along its length to damage from earthquakes, forest fires and
other natural disasters. The pipeline system also is vulnerable to failures of pipeline segments and pumping equipment, accidental damage and deliberate attacks. Recently, the pipeline has become susceptible to damage resulting from declining flows
of oil from the North Slope. Slower flows cause the temperature of the oil in the pipeline to cool faster, increasing the rate of deposit of wax, which coats pipe walls, hides corrosion and clogs sensors on smart pigs sent through the pipeline to
detect it. Even lower flow rates projected in the future may lead to internal damage caused by ice formation within the pipe and external damage from frost heaves under buried segments. Major upgrades to the pipeline may be required to counteract
the effects of cooler oil temperature. If the pipeline or its pumping stations should suffer major damage from natural or
man-made
causes, production from the Prudhoe Bay Unit could be shut in until the
pipeline system can be repaired and restarted. Royalty payments to the Trust could be halted or reduced by a material amount as a result of interruption to production from the Prudhoe Bay Unit.
In January 2011, TAPS was shut down over two periods of several days each as a result of the discovery of a leak of crude oil in the basement
of a booster pump building at Pump Station No. 1. See THE PRUDHOE BAY UNIT AND FIELD Collection and Transportation of Prudhoe Bay Oil in Item 1 for additional information.
As noted above, without more crude oil to be transported by TAPS, slower flows and freezing temperatures could eventually force the closure of
the pipeline, making it impossible to transport oil from the North Slope to market. However, for the second year in a row, there was an increase in the amount
26
of oil transported by TAPS. Alyeska Pipeline Service Company, the operator of TAPS, announced that the
pipelines average throughput increased by approximately 10,000 barrels per day in 2017 compared to 2016, which amounted to a 1.5 percent increase. Before the 2016 increase, the last increase in pipeline throughput was in 2002, when the
pipeline carried over one million barrels per day. The recent increases have been attributed to a combination of factors, such as better than expected performance from newer oil fields west of Prudhoe Bay, such as ConocoPhillips
CD-5
development on the North Slope in the Colville River Unit (part of the Alpine Field and the first commercial oil development on Alaska Native lands within the boundaries of the National Petroleum Reserve-Alaska
(NPRA) as discussed below) and the ability of oil companies to produce oil from mature fields like Prudhoe Bay more efficiently.
Although there was an increase in volume in TAPS in 2017 compared to 2016, throughput, as noted above, averaged 527,000 barrels per day.
The pipeline was designed to carry much higher volumes of oil. In 2011, a study by Alyeska raised questions as to whether TAPS could continue in operation below a throughput level of approximately 300,000 barrels per day. The EIA, which has forecast
continued declining production from the North Slope, has also noted that considerable investment could be required to keep TAPS operational if throughput goes below 350,000 barrels per day.
However, in potentially significant developments for Alaska and TAPS, within the past year and a half, three companies announced oil
discoveries capable of producing up to or in excess of 100,000 barrels of oil per day. Caelus Energy LLC, a small energy exploration company, announced in October 2016 that it had discovered oil in Smith Bay on Alaskas northern coast. The
company reported that the field could hold as much as 6 billion barrels of oil and that it expects to be able to recover between 1.8 to 2.4 billion barrels. However, due to the complexity and expense of the project and the length of the
regulatory process, oil from the discovery is not expected to flow to TAPS until 2022. In March of 2017, a partnership between Spanish oil company Repsol and its U.S. partner, Armstrong Energy, announced a significant oil discovery in the Nanushuk
formation located across the central and western portion of the North Slope. The partnership predicted that production could begin as soon as 2021 and could produce as much as 120,000 barrels of oil per day. According to the partnership, the
discovery, located in a well known as Horseshoe, is 20 miles south of where Repsol-Armstrong had already found oil in 2014 and 2015 in a project known as the Pikka Unit. The Pikka project is already in early development and it is anticipated that
first production will begin in 2021, with a possible production of nearly 120,000 barrels of oil per day. Also in January 2017, ConocoPhillips announced a new oil discovery, known as Willow, located in the Greater Mooses Tooth Unit on
ConocoPhillips leases in the northeastern portion of NPRA. According to ConocoPhillips, Willow could produce up to 100,000 barrels of oil per day. Production at Willow is expected to begin in 2023. Conoco also recently began producing oil at a
field known as
CD-5,
which is the first oil producing field within the NPRA. Production at
CD-5
reached 20,000 barrels of oil per day in 2017 and
is expected to reach 30,000 barrels of oil per day. The Horseshoe, Willow and Smith Bay discoveries are all located in the Nanushuk formation or the related Torok formation.
Another potential source of crude oil in Alaska lies in the 19 million acres of the Arctic National Wildlife Refuge
(ANWR). It is estimated that a
1.5-million-acre
part of the coastal plain of ANWR known as the 1002 area contains 11.8 billion barrels of potentially
recoverable crude oil. A
40-year-old
ban on energy development in the ANWR was removed when the Tax Cuts and Jobs Act (the TCJA) was enacted in December
2017. The TCJA includes a provision that permits oil exploration and drilling in the 1002 area. In addition, the Trump administration announced in January 2018 that it would allow new offshore oil and gas drilling in nearly all United States coastal
waters, including the Arctic Ocean.
Production from the 1989 Working Interests may be interrupted or discontinued by BP Alaska.
27
BP Alaska has no obligation to continue production from the 1989 Working Interests or to maintain
production at any level and may interrupt or discontinue production at any time. The Trust does not have the right to take over operation of the 1989 Working Interests or share in any operating decisions by BP Alaska concerning the Prudhoe Bay Unit.
The operation of the Prudhoe Bay Unit is subject to normal operating hazards incident to the production and transportation of oil in Alaska. In the event of damage to the infrastructure, facilities and equipment in the Prudhoe Bay field which is
covered by insurance, BP Alaska has no obligation to use insurance proceeds to repair such damage and may elect to retain such proceeds and close damaged areas to production.
Construction of a gas pipeline from the North Slope of Alaska could accelerate the decline in Royalty Production from the Prudhoe Bay
field.
The construction of a natural gas pipeline to bring natural gas from the North Slope could make it economical to extract
natural gas from the Prudhoe Bay field and transport it to market. Currently, natural gas released by pumping oil is reinjected into the ground, which helps to maintain reservoir pressure and facilitates extraction of oil from the field. Extraction
of natural gas from the Prudhoe Bay field would lower reservoir pressure, although carbon dioxide stripped out of the gas could be reinjected and other methods could be employed to mitigate the reduction. The lowering of the reservoir pressure could
accelerate the decline in production from the 1989 Working Interests and the time at which royalty payments to the Trust would cease. Since the Trust is not entitled to any royalty payments with respect to natural gas production from the 1989
Working Interests, the Unit holders would not realize any offsetting benefit from natural gas production from the Prudhoe Bay field.
Without a pipeline, extraction of natural gas from the Prudhoe Bay field on a large scale would not be economical. In October 2012,
ExxonMobil, ConocoPhillips, BP and Calgary-based TransCanada Corporation (TransCanada) notified the Alaska Governor that they had agreed on a plan to combine what were once two competing natural gas pipeline projects destined for the
continental U.S. into one project focused on export markets. This project contemplated building an
800-mile
natural gas pipeline from the North Slope to a port on the southern coast of Alaska from which
liquified natural gas (LNG) would be exported to Asia. It was contemplated that the project would also include natural gas processing facilities and a
natural-gas
export terminal.
In January 2014, it was announced that the state of Alaska would pursue becoming an equity partner in the Alaska natural gas pipeline project
and that ExxonMobil, BP, ConocoPhillips, TransCanada, Alaska Gasline Development Corporation (AGDC), and Alaskas commissioners of natural resources and revenue had signed a heads of agreement (HOA) for the Alaska LNG
Project. This established the commercial framework for the development of the natural gas pipeline from the North Slope to the south-central Alaska coast. The Nikiski area of the Kenai Peninsula was selected as the leading site for the LNG plant. In
September 2014, an application was filed with the Federal Energy Regulatory Commission (FERC) to begin a
pre-filing
process to begin preparatory work for an environmental impact statement for the
project. Earlier in 2014 an application was submitted to the U.S. Department of Energy for a license to export LNG.
Pre-Front
End Engineering and Design work, or
pre-FEED,
also commenced in the summer of 2014. In November 2015, AGDC purchased TransCanadas 25% interest in the project.
In August 2016, ExxonMobil, BP and ConocoPhilips indicated that they did not currently wish to make further investments in the Alaska LNG
project. This decision followed a report, commissioned by ExxonMobil, BP and AGDC, by an energy consultancy firm stating the projects competitiveness ranks poorly under current market conditions. At the end of 2016, it was
announced that AGDC had concluded agreements with ExxonMobil, BP and ConocoPhillips to take over the leadership position in the Alaska LNG project.
28
In November 2017, Alaska state officials announced that AGDC, which is currently the sole owner
of the Alaska LNG project, had signed a joint development agreement with Sinopec, one of the worlds largest oil and gas companies, China Investment Corp., the worlds third-largest sovereign wealth fund, and the state-owned commercial
bank, Bank of China, to pursue the project. This development followed the announcement in June 2017 that AGDC had signed an agreement with the Korea Gas Corp. establishing a cooperative framework for the development of Alaskas natural gas
infrastructure. Construction of the project may begin in 2019 with a goal of transporting natural gas by 2024 or 2025.
|
|
|
The effect of any changes to the Alaska Production Tax Statutes on Per Barrel Royalty and Royalty Production from the Prudhoe Bay field is unpredictable.
|
As noted (see THE ROYALTY INTEREST Production Taxes in Item 1 above), Alaskas Production Tax Statutes affect the
calculation of the Per Barrel Royalty. Among other changes to the Production Tax Statutes, the 2013 amendments added a stair-step
per-barrel
tax credit for oil production, provided that a producers tax
liability may not be reduced below the minimum tax. Since going into effect on January 1, 2014, the 2013 amendments had the effect of reducing Production Taxes imposed on Royalty Production. Moreover, as a result of the low oil
price environment that began in
mid-2014,
Royalty Production has been subject to the minimum tax under the Production Tax Statutes since the first quarter of 2015. The reduction in Production Taxes has in part
offset the reduction in royalty payments that resulted from declining WTI prices.
Any changes to the Production Tax Statutes in the
future may also impact the amount of Production Taxes and, in turn, the amount of royalty payments. Whether or when any such changes may occur and the effect any such changes may have on the Per Barrel Royalty is unpredictable.
The Production Tax Statutes can also have an impact on Royalty Production from the Prudhoe Bay field. For example, the 2007 amendments to the
Production Tax Statutes (see THE ROYALTY INTEREST Production Taxes in Item 1 above) may have accelerated the decline in production of oil and condensate from the Prudhoe Bay field to the extent that it caused BP Alaska and the
other owners of working interests in the Prudhoe Bay Unit to reduce or defer investment in oil production infrastructure renewal, well development and implementation of new technology due to uncompetitive returns on investment in Alaska. The 2007
amendments, in addition to increasing the basic oil production tax rate and the progressivity factor, also eliminated or reduced many deductions and credits permitted under the 2006 amendments to the Production Tax Statutes. Due in part to the 2007
amendments, BP Alaskas spending on production adding activity, adjusted for inflation, was flat to declining from 2008 through 2012. As noted under THE ROYALTY INTEREST Production Taxes in Item 1 above, the 2013 amendments
to the Production Tax Statutes were intended to encourage oil production and investment in Alaskas oil industry by eliminating the monthly progressivity tax rate implemented by 2006 and 2007 amendments and adding a stair-step
per-barrel
tax credit for oil production. Due to the low oil price environment that has prevailed for much of the time since the 2013 amendments went into effect, and since the Prudhoe Bay field is a mature field,
the impact of the 2013 amendments in terms of encouraging oil production and investment with respect to the Prudhoe Bay field is uncertain. However, it has been suggested that the 2013 amendments to the Production Tax Statutes provided the impetus
for the series of recent Alaska oil discoveries discussed above.
29
|
|
|
There are potential conflicts of interest between BP Alaska and the Trust
that could affect the royalties paid to Unit holders.
|
The interests of BP Alaska and the Trust with respect to the Prudhoe Bay Unit could at times be different. The Per Barrel Royalty that BP
Alaska pays to the Trust is based on the WTI Price, Chargeable Costs and Production Taxes, all of which are amounts contractually defined in the Conveyance. The WTI Price does not necessarily correspond to the actual price realized by BP Alaska for
crude oil produced from the 1989 Working Interests, and Chargeable Costs and Production Taxes may not bear any relation to BP Alaskas actual costs of production and tax expenses. The actual per barrel profit realized by BP Alaska on the
Royalty Production may differ materially from the Per Barrel Royalty that it is required to pay to the Trust. It is possible under certain circumstances that the relationship between BP Alaskas actual per barrel revenues and costs could be
such that BP Alaska might determine to interrupt or discontinue production in whole or in part from the 1989 Working Interests even though a Per Barrel Royalty might otherwise be payable to the Trust under the Conveyance.