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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

for the quarterly period ended September 30, 20162017

OR

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

for the transition period from                  to                  

Commission File Number: 1-35532

PACIFIC COAST OIL TRUST

(Exact name of registrant as specified in its charter)

1-512-236-6555

(Registrant’s telephone number, including area code)

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

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o  No x As of November 7, 2016,October 30, 2017, 38,583,158 Units of Beneficial Interest in Pacific Coast Oil Trust were outstanding.

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TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “report”) contains “forward-looking statements” about Pacific Coast Oil Trust (the “Trust”) and its sponsor, Pacific Coast Energy Company LP, a privately held Delaware partnership (“PCEC”), that are subject to risks and uncertainties. All statements other than statements of historical fact included in this report, including, without limitation, statements under “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors” are forward-looking statements.  When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify forward-looking statements. The following important factors, in addition to those discussed elsewhere in this report, could affect the future results of the energy industry in general, and PCEC and the Trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:

·                  the effect of changes in commodity prices or alternative fuel prices;

·risks associated with the drilling and operation of oil and natural gas wells;

·                  the amount of future direct operating expenses and development expenses;

·                  the effect of existing and future laws and regulatory actions, including the failure to obtain necessary discretionary permits;

·                  the effect of changes in commodity prices or alternative fuel prices;

·                  conditions in the capital markets;

·                  competition from others in the energy industry;

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

·                  cost inflation.

You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this report. The Trust does not undertake any obligation to release publicly any revisions to the forward-looking statements to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events, unless required by law.

This report describes other important factors that could cause actual results to differ materially from expectations of PCEC and the Trust, including those referred to under “Risk Factors” in Item 1A. of Part II hereof.Trust.  All written and oral forward-looking statements attributable to PCEC or the Trust or persons acting on behalf of PCEC or the Trust are expressly qualified in their entirety by such factors.

GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

In this report the following terms have the meanings specified below.

API—The specific gravity or density of oil expressed in terms of a scale devised by the American Petroleum Institute.

Bbl—One stock tank barrel of 42 U.S. gallons liquid volume, used herein in reference to crude oil and other liquid hydrocarbons.

Bbl/d—Bbl per day.

Boe—One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas.

Boe/dBrent—Boe per day.Global benchmark price used for light sweet crude oil.

Btu—A British Thermal Unit, a common unit of energy measurement.

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

Dry hole—A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Economically producible—A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Field—An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wellsHenry Hub—The total acres or wells, asHenry Hub is a distribution hub on the case may be,natural gas pipeline system in which a Working Interest is owned.Erath, Louisiana. Due to its importance, it lends its name to the pricing point for natural gas futures contracts traded on the NYMEX and the OTC swaps traded on the Intercontinental Exchange.

MBbl—One thousand barrels of crude oil or condensate.

MBoe—One thousand barrels of oil equivalent.

Mcf—One thousand cubic feet of natural gas.

MMBbl—One million barrels of crude oil or condensate.

MMBoe—One million barrels of oil equivalent.

MMBtu—One million British Thermal Units.

MMcf—One million cubic feet of natural gas.

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

NYMEX—New York Mercantile Exchange.

Oil—Crude oil and condensate.

Overriding Royalty Interestroyalty interest —A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale of oil and natural gas, that is limited in duration to the term of an existing lease and that is not subject to the expenses of development, operation or maintenance.

Proved developed reserves—Proved reserves that can be expected to be recovered (i) 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, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate.

Proved reserves—The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically producible in future years from known reservoirs under existing economic and operating conditions and government regulations. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

U.S. GAAP—Proved undeveloped reserves or PUDs Generally accepted accounting principles—Proved 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. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in the United States.Rule 4-10(a)(2-4) of Regulation S-X.

West Texas Intermediate (“WTI”)Recompletion —The completion for production of an existing well bore in another formation from which that well has been previously completed.

Reservoir—Light, sweet crudeA porous and permeable underground formation containing a natural accumulation of producible oil with high API gravityand/or natural gas that is confined by impermeable rock or water barriers and low sulfur content used as the benchmark for U.S. crude oil refiningis individual and trading. WTI is deliverable at Cushing, Oklahoma to fill NYMEX futures contracts for light, sweet crude oil.separate from other reservoirs.

Working Interestinterest—The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The Working Interestworking interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

Workover—Operations on a producing well to restore or increase production.

PART I—FINANCIAL INFORMATION

Item 1.  Financial Statements.

PACIFIC COAST OIL TRUST

Statements of Assets, Liabilities and Trust Corpus

(Unaudited)

The accompanying notes are an integral part of these financial statementsstatements.

PACIFIC COAST OIL TRUST

Statements of Distributable Income

(Unaudited)

The accompanying notes are an integral part of these financial statementsstatements.

PACIFIC COAST OIL TRUST

Statements of Changes in Trust Corpus

(Unaudited)

The accompanying notes are an integral part of these financial statementsstatements.

PACIFIC COAST OIL TRUST

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Note 1.         Organization of the Trust and Basis of Accounting

Formation of the Trust

ThePacific Coast Oil Trust (the “Trust”) is a statutory trust formed in January 2012 under the Delaware Statutory Trust Act pursuant to a Trust Agreement among PCEC,Pacific Coast Energy Company LP (“PCEC”), as trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and Wilmington Trust, National Association, as Delaware Trustee (the “Delaware Trustee”). The Trust Agreement was amended and restated by PCEC, the Trustee and the Delaware Trustee on Maythe inception date (May 8, 2012.2012). References in this report to the “Trust Agreement” are to the Amended and Restated Trust Agreement, dated May 8, 2012, as amended.Agreement.

The Trust was created to acquire and hold Netnet profits interest and royalty interests in certain oil and natural gas properties located in California (the “Conveyed Interests”) for the benefit of the Trust unitholders pursuant to an agreement among PCEC, the Trustee and the Delaware Trustee.Trust Agreement. The Conveyed Interests represent undivided interests in underlying properties consisting of PCEC’s interests in its oil and natural gas properties located onshore in California (the “Underlying Properties”). The Conveyed Interests were conveyed by PCEC to the Trust concurrently with the initial public offering of the Trust’s units of beneficial interest (“Trust Units”) in May 2012.

The Conveyed Interests are passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties. The Conveyed Interests entitle the Trust to receive an 80% Netof the net profits interest from the sale of oil and natural gas production from proved developed reserves on the Underlying Properties as of December 31, 2011 (the “Developed Properties”) and either a 25% Netnet profits interest from the sale of oil and natural gas production from all other development potential on the Underlying Properties (the “Remaining Properties”) or a 7.5% of the proceedsroyalty interest (free of any production or development costs but bearing the proportionate share of production and property taxes and post production costs) attributable topost-production cost) from the sale of oil and natural gas production from the Remaining Properties located on PCEC’s Orcutt and Orcutt Diatomite properties including but not limited to PCEC’s interest in such production (the “Royalty Interest Proceeds”).

The Trust calculates the net profits and royalties for the Developed Properties and Remaining Properties monthly. For any monthly period during which costs for the Remaining Properties exceed gross proceeds, the Trust is entitled to receive the Royalty Interest Proceeds, and the Trust continues to receive such proceeds until the first day of the month following the day on which cumulative gross proceeds for the Remaining Properties exceed the cumulative total excess costs for the Remaining Properties (an “NPI Payout”). Due to significant planned capital expenditures associated with the Remaining Properties for the benefit of the Trust, PCEC expects the Trust to receive payments associated with the Remaining Properties in the form of Royalty Interest Proceeds until the NPI Payout occurs, which PCEC estimates will occur in approximately 2026.

The Trustee can authorize the Trust to borrow money to pay Trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee or PCEC as a lender provided the terms of the loan are fair to the Trust unitholders and similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the Trust at least equals amounts paid by the Trustee on similar deposits, and make other short-term investments with the funds distributed to the Trust. See “Note 6. Funding Commitment and Letter of Credit” for information regarding borrowings by the Trust from PCEC in 2016.

The Trust is not subject to any pre-set termination provisions based on maximum volume of oil or natural gas to be produced or the passage of time.  The Trust will dissolve upon the earliest to occur of the following: (1) the Trust, upon approval of the holders of at least 75% of the outstanding Trust Units, sells the Conveyed Interests, (2) the annual cash proceeds received by the Trust attributable to the Conveyed Interests, in the aggregate, is less than $2.0 million for each of any two consecutive years, (3) the holders of at least 75% of the outstanding Trust Units vote in favor of dissolution or (4) the Trust is judicially dissolved.

Conveyance of Net Profits Interest and Overriding Royalty Interest and Initial Public Offering

On May 8, 2012, the Trust and PCEC entered into a Conveyance of Net Profits Interest and Overriding Royalty Interest (the “Conveyance”), pursuant to which PCEC conveyed to the Trust the Conveyed Interests. The Conveyed Interests entitle the Trust to receive 80% of the net profits from the sale of oil and natural gas production from the proved developed reserves as of December 31, 2011 on the Developed Properties and either 25% of the net profits from the sale of oil and natural gas production from all Remaining Properties or the Royalty Interest Proceeds.

Concurrent with the Conveyance, PCEC sold 18,500,000 Trust Units to the public in an initial public offering.  Upon completion of the offering, there were 38,583,158 Trust Units issued and outstanding, of which PCEC owned 20,083,158 Trust Units, or 52% of the issued and outstanding Trust Units.  On September 19, 2013, PCEC and other persons or entities (the “Other Selling Unitholders”) sold 13,500,000 Trust Units at a price of $17.10 per Trust Unit ($16.416 per Trust unit, net of underwriting discounts and commissions). On September 23, 2013, PCEC distributed 11,216,661 Trust Units to the Other Selling Unitholders.  Immediately following the distribution, the Other Selling Unitholders sold 8,500,000 Trust Units, and PCEC sold an additional 5,000,000 Trust Units, for a total sale of 13,500,000 Trust Units. PCEC retained 3,866,497 Trust Units, or 10% of the issued and outstanding Trust Units.  The Trust received no proceeds from either sale of these Trust Units.

On June 9, 2014, PCEC distributed 3,866,497 Trust Units, or the remaining 10% of the issued and outstanding Trust Units it owned to PCEC’s management and owners. Certain holders of the Trust Units affiliated with PCEC sold an aggregate of 2,654,436 Trust Units pursuant to an underwritten secondary public offering at a price of $13.00 per Trust Unit ($12.70 per Trust Unit, net of underwriting discounts and commissions). None of the Trust, PCEC or PCEC’s management sold any Trust Units in the secondary offering nor received any proceeds from the offering. The Trust Units were sold pursuant to a prospectus supplement and an accompanying prospectus as part of an effective shelf registration statement filed by the Trust with the Securities and Exchange Commission (the “SEC”).

Note 2.Trust Significant Accounting Policies

Basis of Accounting

The accompanying Statement of Assets and Trust Corpus as of December 31, 2015,2016, which has been derived from audited financial statements, and the unaudited interim financial statements as of September 30, 20162017 and for the three months and nine months ended September 30, 20162017 and 20152016 have been prepared pursuant to the rules and regulations of the SEC. Accordingly, certain information and disclosures normally included in annual financial statements have been condensed or omitted pursuant to those rules and regulations. Therefore, these financial statements should be read in conjunction with the financial statements and notes thereto included in the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed on March 4, 2016(“20152016 (“2016 Annual Report”).

In the opinion of the Trustee, the accompanying unaudited financial statements reflect all adjustments that are necessary for a fair statement of the interim period presented and include all the disclosures necessary to make the information presented not misleading. Certain prior-period amounts have been reclassified to conform to current-period presentation.

The preparation of financial statements requires the Trust to make estimates and assumptions that affect reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Although the Trustee believes that these estimates are reasonable, actual results could differ from those estimates.

The Trust uses the modified cash basis of accounting to report Trust receipts of the Conveyed Interests and payments of expenses incurred. The Net profits interest represents the right to receive revenues (oil and natural gas sales), less direct operating expenses (lease operating expenses and production and property taxes) and development expenses of the Underlying Properties plus certain offsets. The Royalty Interest represents the right to receive revenues (oil and natural gas sales), less production and operating taxes and post-production costs. Cash distributions of the Trust will be made based on the amount of cash received by the Trust pursuant to terms of the Conveyance creating the Conveyed Interests.

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

·  Income from the Conveyed Interests is recorded when distributions are received by the Trust;

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

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

·  PCEC’s operating and services fee is recorded when paid; and

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

The Conveyance of the Conveyed Interests to the Trust was accounted for as a transfer of properties under common control and recorded at PCEC’s historical net book value of the Conveyed Interests on May 8, 2012, the date of transfer to the Trust, except for the commodity derivatives which were reflected at their fair value as of May 8, 2012.

Amortization of the investment in the Conveyed Interests is calculated on a unit-of-production basis and is charged directly to the Trust corpus balance. The production and net reserves used in the amortization calculation are determined using the economic interest method, where the sum of the net profits payments are divided by the effective price per barrel of oil equivalent resulting in the volume of production and reserves used in the calculation. For the three months ended September 30, 2016 and 2015, amortization expense was $184,705 and $2,686,921, respectively.  For the nine months ended September 30, 2016 and 2015, amortization expense was $958,338 and $5,799,229, respectively. Such amortization does not affect cash earnings of the Trust.  Accumulated amortization as of September 30, 2016 and December 31, 2015 was $56,406,480 and $55,448,142, respectively.

Investment in the Conveyed Interests is periodically assessed to determine whether its aggregate value has been impaired below its total capitalized cost based on the Underlying Properties.  If an impairment loss is indicated by the carrying amount of the assets exceeding the sum of the undiscounted expected future net cash flows, then an impairment loss is recognized for the amount by which the carrying amount of the asset exceeds its estimated fair value. Fair value is generally determined from estimated discounted cash flows. There was no impairment as of September 30, 2016 or December 31, 2015.

While these statements differ from financial statements prepared in accordance with U.S. GAAP, the modified cash basis of reporting revenues, expenses, and distributions is considered to be the most meaningful because monthly distributions to the Trust unitholders are based on net cash receipts.  This comprehensive non-GAAP basis of accounting corresponds to the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

Note 3.Income Taxes

Federal Income Taxes

Tax counsel to the Trust advised the Trust at the time of formation that for U.S. federal income tax purposes, the Trust will be treated as a grantor trust and therefore is not subject to tax at the trust level. Trust unitholders are treated as owning a direct interest in the assets of the Trust, and each Trust unitholder is taxed directly on his or her pro rata share of the income and gain attributable to the assets of the Trust and entitled to claim his or her pro rata share of the deductions and expenses attributable to the assets of the Trust. The income of the Trust is deemed to have been received or accrued by each unitholder at the time such income is received or accrued by the Trust rather than when distributed by the Trust.

The deductions of the Trust consist primarily of administrative expenses.  In addition, each unitholder is entitled to depletion deductions because the Net profits interest constitutes “economic interests” in oil and gas properties for federal income tax purposes.  Each unitholder is entitled to amortize the cost of the Trust Units through cost depletion over the life of the Net profits interest or, if greater, through percentage depletion.  Unlike cost depletion, percentage depletion is not limited to a unitholder’s depletable tax basis in the Trust Units.  Rather, a unitholder is entitled to percentage depletion as long as the applicable Underlying Properties generate gross income.

Some Trust Units are held by a middleman, as such term is broadly defined in U.S. Treasury Regulations (and 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 non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 919 Congress Avenue, Austin, Texas 78701, telephone number (512) 236-6545, 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.  Notwithstanding the foregoing, the middlemen holding units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such units, including the issuance of IRS Forms 1099 and certain written tax statements.  Unitholders whose units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.

The tax consequences to a unitholder of ownership of Trust Units will depend in part on the unitholder’s tax circumstances. Unitholders should consult their tax advisors about the federal tax consequences relating to owning the Trust Units.

State Taxes

The Trust’s revenues are from sources in the state of California. Because it distributes all of its net income to unitholders, the Trust is not taxed at the trust level. California presently taxes income of nonresidents from real property located within the state.  California taxes nonresidents on royalty income from the royalties located in that state and also imposes a corporate income tax which may apply to unitholders organized as corporations.

Each unitholder should consult his or her own tax advisor regarding state tax requirements applicable to such person’s ownership of Trust Units.

Note 4.2.         Distributions to Unitholders

Each month, the Trustee determines the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the Conveyed Interests and other sources from that month (such as interest earned on any amounts reserved by the Trustee), over the Trust’s liabilities for that month, subject to adjustments for changes made by the Trustee during the month in any cash reserves established for future liabilities of the Trust.  Distributions are made to the holders of Trust unitholdersunits as of the applicable record date (generally within five business days after the last business day of each calendar month) and are payable on or before the 10th business day after the record date. Due to the decline in commodity prices, the Trust has not made distributions since January 2016.

The following table illustrates information regarding the Trust’s distributions paid during the nine months ended September 30, 20162017 and 2015.2016.

Nine Months Ended September 30, 2017

Nine Months Ended September 30, 2016

Nine Months Ended September 30, 2015

Note 5.3.         Related Party Transactions

Trustee Administrative Fee.  Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $200,000 to the Trustee and $2,000 to the Delaware Trustee.  During the three-month and nine-month periods ended September 30, 2016,2017, the

Trust paid $50,000 and $150,000, respectively, to the Trustee. During each of the three-month and nine-month periods ended September 30,201630, 2017, the Trust paid zero$0 and $2,000, respectively, to the Delaware Trustee. During the three-month and nine-month periods ended September 30, 2015,2016, the Trust paid $50,000 and $150,000, respectively, to the Trustee. During each of the three-month and nine-month periods ended September 30, 2015,2016, the Trust paid zero$0 and $2,000, respectively, to the Delaware Trustee.

PCEC Operating and Services Fee.  Under the terms of theThe Trust and PCEC are parties to an Operating and Services Agreement dated as of May 8, 2012, by and between PCEC and the Trust (the “Operating and Services Agreement”), pursuant to which PCEC provides the Trust with certain operating and informational services relating to the Conveyed Interests in exchange for a monthly fee which is revised annually based on changes to the Consumer Price Index.  The monthly operating and services fee was $86,330$87,330 during the first quarter of 20152016 and was $87,730 from April 1, 2015$87,834 through the end of the first quarter of 2016. On2017. As of April 1, 2016,2017, the monthly operating and services fee changed to $87,834.$88,942. The Operating and Services Agreement will terminate upon the termination of the Conveyed Interests unless earlier terminated by mutual agreement of the Trustee and PCEC.  During the three monthsthree-month and nine-month periods ended September 30, 2016 and 2015,2017, PCEC charged the Trust $263,502$266,827 and $263,190,$794,940, respectively, for the operating and services fee. During the nine monthsthree-month and nine-month periods ended September 30, 2016, and 2015, PCEC charged the Trust $789,987$263,502 and $782,568,$789,987, respectively, for the operating and services fee. The Trust paid the operating and services fee in full for each month during the first nine months of 2017. The Trust paid the operating and services fee in full for the month of January 2016. However, because the Trust did not have enoughsufficient cash to pay the operating and services fee in full for the months of February 2016 and March 2016, the Trust made partial payments of $55,977 for February and $26,392 for March. For the months of April, May, June, July, August and September 2016, it was necessary for the Trust borrowed funds underto execute a promissory note payable toand borrow funds from PCEC dated February 25, 2016, and subsequently amended and restated on September 29, 2016 (as amended, the “Promissory Note”)discussed in orderNote 4 below) to make payments of $87,730, $87,730, $87,834, $87,834, $87,834 ,andand $87,834, respectively. All operating and services fees have beenwere completely paid through September 30, 2016 as a part of the borrowings under the Promissory Note.Note (as discussed in Note 4 below).

Note 6.4.         Funding Commitment and Letter of Credit

On February 25, 2016, the Trust entered into the Promissory Notea promissory note with PCEC (as amended, the “Promissory Note”) and borrowed $232,000 to pay general and administrative expenses, as the Trust did not otherwise have sufficient cash to pay its ordinary course administrative expenses as they became due. Under the initial terms of the Promissory Note, the Trust agreed to pay interest on the outstanding principal amount at a rate of 8.5% per annum from February 25, 2016 until maturity.Thematurity. The Promissory Note, as amended and restated bearson August 10, 2016, bore interest at (1) 8.5% per annum from February 25, 2016 to August 9, 2016, and (2) 4.0% per annum from August 10, 2016 until maturity.maturity (March 31, 2018). Subsequent borrowings and repayments, including interest thereon, added an additional $900,450 to the original $232,000 amount, resulting in an outstanding note balance as of December 31, 2016 of $1,132,450 owed to PCEC. The Trust repaid the entire amount of the Promissory Note will mature on March 31, 2018.  Forin the nine months ended September 30, 2016, the Trust borrowed an additional $805,463 under the Promissory Note. Asfirst quarter of 2017, and no amount remains outstanding as of September 30, 2016, the Trust had $1,037,464 of borrowings outstanding under the Promissory Note, reflecting net increases in the principal and interest amounts, as permitted thereunder, since the execution of the Promissory Note.2017. Interest expense on the outstanding borrowings will bewas recorded as it iswas paid to PCEC. For the three monthsthree-month and nine monthsnine-month periods ended September 30, 2016,2017, the Trust incurred a total of $17,495interest totaling $0 and $26,717$10,141, respectively, in interest, which has beenwas included in the borrowings under the Promissory Note. No further distributions will be made toFor the three-month and nine-month periods ended September 30, 2016, the Trust unitholders until the amounts borrowed, includingincurred interest thereon, are repaid. The Trust may prepay the Promissory Note in whole or in part without being required to pay any penalty or premium.totaling $17,495 and $26,717, respectively.

PCEC has also provided the Trust with a $1.0 million letter of credit to be used by the Trust in the event thatif its cash on hand (including available cash reserves) is not sufficient to pay ordinary course general and administrative expenses as they become due. Any funds provided under the letter of credit or loaned by PCEC may only be used for the payment of current accounts or other obligations to trade creditors in connection with obtaining goods or services or for the payment of other accrued current liabilities arising in the ordinary course of the Trust’s business, and may not be used to satisfy Trust indebtedness. No distributions will be made to Trust unitholders (except in respect of any previously determined monthly cash distribution amount) until allsuch amounts drawn on the letter of credit, or borrowed under the Promissory Note,from PCEC or any other source, including interest thereon, are repaid. PCEC has agreed to loan funds to the Trust necessary to pay such expenses through the Promissory Note(evidenced by written promissory notes) as stipulated by the Trust Agreement. As of September 30, 2017, the letter of credit remains unused.

Note 7.5.         Commitments and Contingencies

Legal Proceedings. The Trust has been named as a defendant in a putative class action as described below.

On July 1, 2014, Thomas Welch, individually and on behalf of all others similarly situated, filed a putative class action complaint in the Superior Court of California, County of Los Angeles, against the Trust, PCEC, PCEC (GP) LLC, Pacific Coast Energy Holdings LLC, certain executive officers of PCEC (GP) LLC and others.

The complaint asserts federal securities law claims against the Trust and other defendants and states that the claims are made on behalf of a class of investors who purchased or otherwise acquired Trust securities pursuant or traceable to the registration statement

that became effective on May 2, 2012 and the prospectuses issued thereto and the registration statement that became effective purportedly on September 19, 2013 and the prospectuses issued thereto. The complaint states that the plaintiff is pursuing negligence and strict liability claims under the Securities Act of 1933 and alleges that both such registration statements contained numerous untrue statements of material facts and omitted material facts. The plaintiff seeks class certification, unspecified compensatory damages, rescission on certain of plaintiff’s claims, pre-judgment and post-judgment interest, attorneys’ fees and costs and any other relief the Court may deem just and proper.

On October 16, 2014, Ralph Berliner, individually and on behalf of all others similarly situated, filed a second putative class action complaint in the Superior Court of California, County of Los Angeles, against the Trust, PCEC, PCEC (GP) LLC, Pacific Coast Energy Holdings LLC, certain executive officers of PCEC (GP) LLC and others. The Berliner complaint asserts the same claims and makes the same allegations, against the same defendants, as are made in the Welch complaint. In November 2014, the Welch and Berliner actions were consolidated into a single action.

On December 8, 2015, the above referenced parties agreed in principle to settle the consolidation action, andconsolidated action. On June 12, 2017, the Court entered an order granting preliminary approval ofa final judgment in the action approving the settlement on September 14, 2016. Ain the amount of $7.6 million.  The Court set a hearing to determine whether to grant final approval offor February 28, 2018 regarding compliance with the settlement and enter final judgement in this action is set for March 2, 2017.approved settlement. The Trust believes that it is fully indemnified by PCEC against any liability or expense it might incur in connection with the consolidationconsolidated action. The approved settlement does not require any payment from the Trust.

On July 7, 2016, PCEC received a letter from the California Department of Conservation, Division of Oil, Gas & Geothermal Resources (“DOGGR”) revising regulations on injection operations, impacting West Pico’s three active water injection wells.  Included inDuring the revised regulation is a limit onsecond half of 2016 all three injectors were successfully reworked to optimize their injection capacity while remaining below the new maximum injection pressures allowable to a level approximately 60% below current injection pressures.  PCEC is currently notallowable.  All three injectors were inspected by DOGGR and signed off as in compliance with the guidelinesrevised regulations.  The result has been a reduction in water injection capacity by approximately 30% and approximately 75 Bbl/d of reduced oil production (60 Bbl/d net to the Trust’s 80% interest).  PCEC is working with DOGGRexploring opportunities to develop a work plan to address the new guidelines.  PCEC expects that complianceincrease injection capacity which may require additional capital expenditures and reduce production.expenditures.

AsPCEC previously disclosed in the Trust’s 2015 Annual Report, PCEC currently hashad submitted permit applications pendingrelating to allow the drilling of an additional 96 steam injection wells on certain oil and natural gas properties located onshore in California in the Diatomite zone at Orcutt (the “Orcutt Hill Resource Enhancement Plan” or “OHREP”).  At a hearing on June 29, 2016, the Santa Barbara County Planning Commission (the “Planning Commission”) instructed its staff to prepare Findings for Denial, which the Planning Commission adopted by a 3-2 vote on July 13, 2016. On July 21, 2016, PCEC filed an appeal to the Santa Barbara County Board of Supervisors. On November 1, 2016, the Santa Barbara County Board of Supervisors heard PCEC’s appeal and voted 3-2 to deny the project, with the exception of approving permanent permits for the installation of seep cans on the Company’s Orcutt Hill property.  As a result of the Board of Supervisors’ decision, future cash flows associated with new permits for drilling in the Diatomite Zone at Orcutt, all of which would be attributable to Remaining Properties, is uncertain.  AtAs of the date of this time,report, PCEC has not filed any additional permits for drilling in the Diatomite Zone at Orcutt and is not able to provide an estimate for when or if additionalPCEC will submit such permits will be submitted to Santa Barbara County for drillingCounty. If submitted in the Diatomite Zone at Orcutt.future, there can be no assurance that Santa Barbara County will approve such permits or that PCEC will be able to generate additional cash flows as a result.

Note 8.6.   Property Tax Settlement

On March 23, 2016, PCEC reached a settlement agreement with the Santa Barbara County Assessor’s Office on supplemental property tax bills related to the tax years covering the periods July 1, 2011 through June 30, 2016. The supplemental tax bills relate to the settlement of disputed property values for Orcutt and Orcutt Diatomite field locations for these periods. Amounts attributable to the periods from April 1, 2012 through June 30, 2016 total $2,121,621 for the Developed Properties and $1,280,275 for the Remaining Properties and arewere chargeable in part to the Trust in the March 2016 production month calculation of the net profits. The property tax adjustment amounts attributable to the Trust increased the cumulative Net profits interestProfits Interest deficits of the Developed Properties and the Remaining Properties by $1,394,937 million and $245,394, respectively, and will be subtracted from any future net profits untilin the second quarter of 2016. As of the October 2016 production month calculation, the Developed Properties cumulative Net profits interest deficits haveProfits Interest deficit had been reduced to zero.

Note 9.Subsequent Events

On October 28, 2016, the Trust issued a press release announcing there will be no cash distribution in November 2016 to the holders of its Trust Units.

Due to a temporary maintenance shutdown on the export line that transports natural gas out of West Pico, West Pico has had to temporarily shut in select wells to limit the amount of associated gas produced from oil production.  West Pico net production attributable to the Developed Properties prior to the maintenance shutdown was approximately 530 Boe/d (approximately 420 Boe/d net to the Trust).  During the shutdown months, which began in August and are expected to last through early November 2016, production is down by approximately 33%-50%.  During the shutdown months, West Pico is able to reduce certain operating expenses associated with the production from the shut in wells.  Following the return to service of the gas export line, West Pico is expected to return production to levels similar to those prior to the shutdown months.

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

The following review of the Trust’s financial condition and results of operations should be read in conjunction with the financial statements and notes thereto, as well as “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” contained in Part II, Item 7 of the 2015Trust’s 2016 Annual Report.  The following review should also be read in conjunction with “Forward-Looking Statements” in this report and with “Part I — I—Item 1A — 1A—Risk Factors” in the 2015Trust’s 2016 Annual Report and “Part II – Item 1A – Risk Factors” in our Quarterly Reports on Form 10-Q for the first and second quarters of 2016.Report.

Overview

The Trust is a statutory trust formed in January 2012 under the Delaware Statutory Trust Act. The business and affairs of the Trust are administered by the Trustee. The Trust’s purpose is to hold the Conveyed Interests (described below), to distribute to the Trust unitholders cash that the Trust receives in respect of the Conveyed Interests and to perform certain administrative functions in respect of the Conveyed Interests and the Trust Units. The Trust does not conduct any operations or activities. The Trustee has no authority over or responsibility for, and no involvement with, any aspect of the oil and natural gas operations or other activities on the Underlying Properties. The Delaware Trustee, has only minimal rights and duties as are necessary to satisfy the requirements of the Delaware Statutory Trust Act.  The Trust derives all or substantially all of its income and cash flow from the Conveyed Interests, subject to the effects of the commodity derivative contracts. The Trust is treated as a grantor trust for U.S. federal income tax purposes.

The Trust was created to acquire and hold Netnet profits interests and royalty interests in certain oil and natural gas properties located in California.  The Conveyed Interests represent undivided interests in the Underlying Properties.underlying properties consisting of PCEC’s interests in its oil and natural gas properties located onshore in California (the “Underlying Properties”).

Concurrently with the Trust’s initial public offering in May 2012, the Trust and PCEC effectedentered into a Conveyance of Net Profits Interests and Overriding Royalty Interest (the “Conveyance”), pursuant to which PCEC conveyed to the Conveyance.Trust net profits interest and an overriding royalty interest (the “Conveyed Interests”) in the Underlying Properties. The Conveyed Interests entitle the Trust to receive 80% of the net profits from the sale of oil and natural gas production from the Developedproved developed reserves as of December 31, 2011 on the Underlying Properties (the “Developed Properties”) and either 25% of the net profits from the sale of oil and natural gas production from all other development potential on the Underlying Properties (the “Remaining Properties”) or a 7.5% royalty interest from the Royaltysale of oil and natural gas production from the Remaining Properties located in PCEC’s Orcutt properties (the “Royalty Interest Proceeds.Proceeds”).

The Trust calculates the net profits and royalties for the Developed Properties and Remaining Properties monthly.  For any monthly period during which costs for the Remaining Properties exceed gross proceeds, if any, the Trust is entitled to receive the Royalty Interest Proceeds, if any, and the Trust will continue to receive such proceeds until NPI Payout.the first day of the month following the day on which cumulative gross proceeds for the Remaining Properties exceed the cumulative total excess costs for the Remaining Properties (such occurrence being herein called a “NPI Payout”).  Due to significant planned expenditures associated with the Remaining Properties for the benefit of the Trust, PCEC expects the Trust to receive payments associated with the Remaining Properties in the form of Royalty Interest Proceeds until the NPI Payout occurs which PCEC estimates will occur in approximately 2026.2020. The estimated date on which the NPI Payout is expected to occur is an estimate based on the annual reserve report and changes from time to time.  In any monthly period following an NPI Payout, the Trust is entitled to receive Royalty Interest Proceeds if costs for the Remaining Properties exceed gross proceeds.

The Trust is exposed to fluctuation in energy prices in the normal course of business due to the Net profits interest in the Underlying Properties. The revenues derived from the Underlying Properties depend substantially on prevailing crude oil prices and, to a lesser extent, natural gas prices. As a result, commodity prices affect the amount of cash flow available for distribution to the Trust unitholders. For example, since February 2016, because of a decline in average realized prices, no cash distributions have been made as Trust expenses exceeded the proceeds received from the Conveyed Interests. Lower prices may also reduce the amount of oil and natural gas that PCEC and its third party operators can economically produce.  In addition, no further distribution will be made to Trust unitholders until amounts borrowed by the Trust under the Promissory Note, including interest thereon, have been repaid in full and the cumulative Net profits interest deficit for the Developed Properties has been reduced to zero.

If the amounts paid to the Trust enable the Trust to repay its debt and resume distributions, the Trust would makemakes monthly cash distributions of all of its monthly cash receipts, after deduction of fees and expenses for the administration of the Trust, to holders of Trust Units as of the applicable record date (generally within five business days after the last business day of each calendar month) on or before the 10th business day after the record date.  Actual cash distributions to the Trust unitholders will fluctuate monthly based upon the quantity of oil and natural gas produced from the Underlying Properties, the prices received for oil and natural gas production, costs to develop and produce the oil and natural gas and other factors. Because payments to the Trust are generated by depleting assets with the production from the Underlying Properties diminishing over time, a portion of each distribution represents, in effect, a return of a unitholder’s original investment. Oil and natural gas production from proved reserves attributable to the Underlying Properties will continue to decline over time.

The Trust is exposed to fluctuation in energy prices in the normal course of business due to the Net Profits Interest in the Underlying Properties. The revenues derived from the Underlying Properties depend substantially on prevailing crude oil prices and, to a substantially lesser extent, natural gas prices. As a result, commodity prices affect the amount of cash flow available for distribution to the Trust unitholders. For example, from February 2016 through January 2017, primarily because of a decline in average realized prices, no cash distributions were made as Trust expenses exceeded the proceeds received from the Conveyed Interests. Lower prices may also reduce the amount of oil and natural gas that PCEC and its third party operators can economically produce.  Pursuant to the Trust Agreement, no distributions are permitted to be made to Trust unitholders until amounts borrowed by the Trust under the Promissory Note described in Note 4 to the financial statements, including interest thereon, or otherwise borrowed, have been paid in full.

Commodity Prices

In the third quarter of 2016,2017, the WTIBrent crude oil spot price averaged approximately $44.85$52.10 per Bbl, compared to approximately $46.51with $45.80 per Bbl in the third quarter of 2015. The WTI crude oil spot price decreased from a high of $61.36 per Bbl in  2015 to a low of $26.19 per Bbl in February 2016. Lower crude oil prices may not only decrease the Trust’s distributable income, but may also reduce the amount of crude oil that PCEC can produce economically and therefore potentially lower PCEC’smay decrease the Trust’s crude oil reserves.  In the third quarter of 2016,2017, approximately 99%98% of production from the Developed Properties consisted of oil and 100% of production from the Remaining Properties consisted of oil.

Prices for natural gas in many markets are aligned both with supply and demand conditions in their respective regional markets and with the overall U.S. market. Natural gas prices are also typically higher during the winter period when demand for heating is greatest in the U.S.  In the third quarter of 2016,2017, the Henry Hub price averaged approximately $2.88$2.94 per MMBtu, compared with approximately $2.76$2.88 per MMBtu in the third quarter of 2015. The Henry Hub spot price decreased from a high of $3.32 per MMBtu in January 2015 to a low of $1.49 per MMBtu in March 2016.

AThe significant decline or increase in oil and natural gas prices since 2014 increases the uncertainty as to the impact of commodity prices on our estimated proved reserves.oil and gas reserves attributable to the Trust. We are unable to predict future commodity prices with any greater precision than the futures market.prices. A prolonged period of depressed commodity prices couldmay have a significant impact on the volumetric quantities of PCEC’sour proved reserve portfolio.

Distributable Cash to Fluctuations in commodity prices impact the Trust

The Trustee must sell the Conveyed Interestsvalue of proved oil and dissolve the Trust if the annual cash proceeds received by the Trustgas reserves attributable to the Conveyed Interests, in the aggregate, are less than $2.0 million for each of any two consecutive years. Through September 30, 2016, the Trust received approximately $0.6 million in proceeds attributable to the Conveyed Interests. As a result, aggregate proceeds attributable to the Conveyed Interests received by the Trust are not expected to reach $2.0 million in 2016, and unless commodity prices increase or operating expenses decrease in the near term, such proceeds are unlikely to reach that threshold in 2017.  If income from the Conveyed Interests in 2017 does not improve significantly, the Trustee will be required to sell the Conveyed Interests and dissolve the Trust.

20162017 Capital Program Summary

As previously disclosed, PCEC’s 2016PCEC informed the Trustee at the beginning of 2017 that its 2017 capital program is expected to total approximately $3.4$4.5 million, and would be focused onconsisting of $2.7 million of mandatory facility upgrades at Orcutt Field, and$1.0 million of capital expenditures for non-operated properties, $0.5 million for Orcutt Diatomite rate-generating projects and Orcutt Diatomite permitting fees.$0.3 million for West Pico mandatory facility upgrades.  This total includes expected investments of approximately $2.0$4.2 million ($1.63.3 million net to the Trust’s interest) in the Developed Properties and approximately $1.4$0.3 million expected to be spent on the Remaining Properties ($350,0000.1 million net to the Trust’s interest).

Properties

The Underlying Properties consist of the Developed Properties and the Remaining Properties. Production from the Developed Properties that will be attributable to the Trust is produced from wells that, because they have already been drilled, require limited additional capital expenditures.expenditures associated with new drilling but may require capital expenditures associated with regulatory capital expenditures or drilling capital expenditures associated with utilizing the existing wellbores. Production from the Remaining Properties that will be attributable to the Trust will require capital expenditures for the drilling of wells and installation of infrastructure. PCEC will supply required capital on behalf of the Trust during this period; however, because the costs initially incurred will exceed gross proceeds, the Remaining Properties will have negative net profits during the drilling and development period. During this period of negative net profits, instead of being paid net profits, the Trust will be paid a 7.5% overriding royalty on the Royalty Interest Proceeds.portion of the Remaining Properties located on PCEC’s Orcutt properties. Once revenues from the Remaining Properties have been used to repayrepaid PCEC for the cumulative costs it has advanced on behalf of the Trust, including the net profitsaggregate amount of the 7.5% overriding royalty, the Net Profits Interests on the Remaining Properties will be paid out in place of the Royalty Interest Proceeds, as described below. The Conveyed Interests entitle the Trust to receive the following:

Developed Properties

·          80% of the net profits from the sale of oil and natural gas production from the Developed Properties.

Remaining Properties

·          25% of the net profits from the sale of oil and natural gas production from all of the Remaining Properties, or

·          7.5% of the Royaltyproceeds (free of any production or development costs but bearing the proportionate share of production and property taxes and post-production costs) attributable to the sale of all oil and natural gas production from the Remaining Properties located on PCEC’s Orcutt properties, including but not limited to PCEC’s interest in such production (the “Royalty Interest ProceedsProceeds”).

The Trust calculates the net profits and royalties for the Developed Properties and the Remaining Properties separately. Any excess costs for either the Developed Properties or the Remaining Properties will not reduce net profits calculated for the other; however theother. The amount of Royalty Interest Proceeds paid will be taken into accountis deducted in the net profits calculation of the Net Profits Interest for the Remaining Properties.Properties, and PCEC will be repaid the aggregate amount of the Royalty Interest Proceeds prior to payment of the 25% Net Profits Interest to unitholders. If at any time cumulative costs for the Developed Properties on the one hand, or the Remaining Properties on the other hand, exceed cumulative gross proceeds associated with each, thensuch properties, neither the Trust nor the Trust unitholders would be liable for the excess costs, but the Trust would not receive any net profits from the Developed Properties or the Remaining Properties, as the case may be, until future cumulative net profits for the Developed Properties or the Remaining Properties (as applicable)such properties exceed the cumulative total excess costs for the Developed Properties or the Remaining Properties (as applicable).such properties.

The Trust is not subject to any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time. The Trust will dissolve upon the earliest to occur of the following: (1) the Trust, upon approval of the holders of at least 75% of the outstanding Trust Units, sells all of the Conveyed Interests and any assets constituting the Trust estate, (2) the annual cash proceeds received by the Trust attributable to the Conveyed Interests, in the aggregate, are less than $2 million for each of any two consecutive calendar years (the “Revenue Termination Provision”), (3) the holders of at least 75% of the outstanding Trust Units vote in favor of dissolution or (4) the Trust is judicially dissolved. For additional information, see “Risk Factors—Distributable CashThe cumulative proceeds received by the Trust attributable to the Trust”Conveyed Interests from production months November 2016 through July 2017 (related to Trust fiscal months January through September 2017) was $5.9 million. Therefore, because the Trust has received more than $2 million of proceeds attributable to the Conveyed Interests in Part II, Item 1A2017, the Trust will not be at risk of this report.termination at the end of 2017 as a result of the Revenue Termination Provision.

On April 6, 2015, PCEC received a letter from the California Department of Conservation, Division of Oil, Gas & Geothermal Resources (“DOGGR”) mandating the suspension of cyclic steaming operations in PODS 2 and 4 at Orcutt Diatomite, citing concern over surface expressions related to two wells occurring late in 2014 and the potential for landslides on the property.  This resulted in the suspension of steaming to 22 wells and curtailed production by approximately 300 barrels of oil per day. PCEC undertook significant testing and has installed monitoring equipment pursuant to direction from DOGGR. In May 2016, following approximately 12 months of slope monitoring showing no significant ground movement, DOGGR granted permission to PCEC continues to cooperate withresume cyclic steaming operations at POD 4.  In December 2016, two wells at POD 2 were also granted permission to resume cyclic steaming operations.  In May 2017, DOGGR conditionally approved PCEC’s request to develop and implement a work plan that addresses DOGGR’s concerns. This resulted in a letter from DOGGR, received April 25, 2016, giving approval to recommenceresume cyclic steaming operations on five additional wells at PODS 2 and 4, conditional upon further well testing.POD 2. PCEC has carried outsince complied with the required well testing oncondition of approval and commenced cyclic steaming operations in early July 2017. Two wells at POD 4 and recommenced steaming on 11 POD 4 wells in May 2016.2 will remain permanently shut in.

During 2015, DOGGR discussed with PCEC the modification of existing well permits for approximately 25 water injection wells located at the Orcutt Field, which could require certain changes to operating procedures or well modifications. In a letter dated September 30, 2015, PCEC proposed, and has since implemented, a schedule to modify one of the affected injection wells each quarter until all have been modified.  The first threefour such modifications were successfully completed in the first half of 20162016. PCEC has completed two such modifications to date in 2017, and PCEC’s capital budget for 20162017 includes onetwo additional modification during the fourth quarter of 2016.modifications.  If DOGGR were to order the modifications to be carried out more rapidly, PCEC’s capital costs could significantly increase.  Alternatively, PCEC could choose or be required financially to shut in all or a portion of the affected injection wells, which would result in a loss of production.

On July 7, 2016, PCEC received a letter from DOGGR revising regulations on injection operations, impacting West Pico’s three active water injection wells.  Included in the revised regulation is a limit on the maximum injection pressures allowable to a level approximately 60% below current injection pressures.  PCEC is currently not in compliance with the guidelines, but has received a waiver through the end of 2016, and is working with DOGGR to develop a work plan to address the new guidelines.  PCEC expects that compliance may require additional capital expenditures and reduce production.

Diatomite Zone Drilling Permits Denial

As previously disclosed in the 2015 Annual Report, PCEC currently hashad submitted permit applications pendingrelating to allow the drilling of an additional 96 steam injection wells on certain oil and natural gas properties located onshore in California in the Diatomite zone at Orcutt (the “Orcutt Hill Resource Enhancement Plan” or “OHREP”). At a hearing on June 29, 2016, the Santa Barbara County Planning Commission (the “Planning Commission”) instructed its staff to prepare Findings for Denial, which the Planning Commission adopted by a 3-2 vote on July 13, 2016. On July 21, 2016, PCEC filed an appeal to the Santa Barbara County Board of Supervisors. On November 1, 2016, the Santa Barbara County Board of Supervisors heard PCEC’s appeal and voted 3-2 to deny the project, with the exception of approving permanent permits for the installation of seep cans on the Company’s Orcutt Hill property. As a result of the Board of Supervisors’ decision, future cash flows associated with new permits for drilling in the Diatomite Zone at Orcutt, all of which wouldand any associated future cash flows attributable to the Remaining Properties, isare uncertain. AtAs of the date of this time,report, PCEC has not filed any additional permits for drilling in the Diatomite Zone at Orcutt and is not able to provide an estimate for when or if additionalPCEC will submit such permits will be submitted to Santa Barbara County for drillingCounty. If submitted in the Diatomite Zone at Orcutt.

West Pico Temporary Limited Shutdown

Due to a temporary maintenance shutdown on the export linefuture, there can be no assurance that transports natural gas out of West Pico, West Pico has had to temporarily shut in select wells to limit the amount of associated gas produced from oil production.  West Pico net production attributable to the Developed Properties prior to the maintenance shutdown was approximately 530 Boe/d (approximately 420 Boe/d net to the Trust).  During the shutdown months, which began in August and are expected to last through early November 2016, production is down by approximately 33%-50%.  During the shutdown months, West Pico is able to reduce certain operating expenses associated with the production from the shut in wells.  Following the return to service of the gas export line, West Pico is expected to return production to levels similar to those prior to the shutdown months.

Property Taxes

On March 23, 2016, PCEC reached a settlement agreement with the Santa Barbara County Assessor’s Office on supplemental property tax bills related to the tax years covering the periods July 1, 2011 through June 30, 2016. The supplemental tax bills relate to the settlement of disputed property values for Orcutt and Orcutt Diatomite field locations for these periods. Amounts attributable to the periods from April 1, 2012 through June 30, 2016 total approximately $2,121,621 for the Developed Properties and $1,280,275 for the Remaining Properties and are chargeable in part to the Trust in the March 2016 production month calculation of the net profits. The property tax adjustment amounts attributable to the Trust will increase the cumulative Net profits interest deficits of the Developed Properties and the Remaining properties by $1,394,937 and $245,394, respectively, andapprove such permits or that PCEC will be subtracted from any future net profits until the cumulative Net profits interest deficits have been reducedable to zero.generate additional cash flows as a result.

Results of Operations for the Three Months Ended September 30, 20162017 and 20152016

For the three months ended September 30, 2016,2017, income from Conveyed Interests received by the Trust amounted to $110,323$2.0 million compared with 4,446,380$0.1 million for the three months ended September 30, 2015.2016.  The increase in income was primarily due to higher oil prices, lower production and other taxes and lower development expenses, partially offset by lower production volumes and higher lease operating expenses. The net profits calculatedincome received by the Trust during the three months ended September 30, 2016 were2017 was associated with net profits for oil and natural gas production from the Developed Properties during the months of May, June and July 2016,2017, and with the Royalty Interest Proceeds relating to production during those same months. The net profits income received by the Trust during the three months ended September 30, 2016 was associated with the Royalty Interest Proceeds relating to production during the months of May, June and July 2016. However, there were nothe Trust did not receive any net profits received by the Trustincome for oil and natural gas production from the Developed Properties during the months of May, through SeptemberJune and July 2016, as operating expenses and capital expenditures exceeded revenues. The net profits received by the Trust during the three months ended September 30, 2015 were associated with net profits for oil and natural gas production during the months of May, June, and July 2015.

Oil and natural gas sales volumes are allocated to the Netnet profits interestinterests based upon a formula that considers oil and natural gas prices and the total amount of production expense and development costs.  As oil and natural gas prices change, the Trust’s share of the production volumes is impacted as the quantity of production to cover expenses and development costs in reaching the Netnet profits interest break-even level changes inversely with price.  Accordingly, the Underlying Property production volumes do not correlate with the Trust’s net profitprofits share of those volumes in any given period.  Therefore, the comparative discussion of oil and natural gas volumes is based on the Underlying Properties as stated in the table below.

The following table displays PCEC’s underlying sales volumes and average realized prices for the Underlying Properties, representing the amounts included in the Netnet profits interest calculation during the three months ended September 30, 20162017 and 2015.2016.

(a)  Crude oil sales represented 99%98% and 96%99% of sales volumes from the Developed Properties for the three months ended September 30, 20162017 and 2015,2016, respectively.

(b) Production costs include lease operating expenses and production and other taxes.

(c)  Crude oil sales represented 100% and 100% of total sales volumes from the Remaining Properties for each of the three-month periodsthree months ended September 30, 2017 and 2016, and 2015.respectively.

Computation of Net Profits and Royalty Income Received by the Trust

The Trust’s net profits and royalty income consist of monthly net profits and royalty income attributable to the Conveyed Interests.  Net profits and royalty income for the three months ended September 30, 20162017 and 20152016 was determined as shown in the following table:

(1) Income from 80% Net profits interest in the third quarter of 2016 represents three months of net profits from the Conveyed Interests during the production months of May, June, and July 2016 as discussed in Note 1, Organization of the Trust, in the Notes to Financial Statements.

(2) There were no net profits for the first six months of 2016 as operating expenses and capital expenditures exceeded revenues. Net profits from the third quarter of 2016 recouped the entire net profits interest deficit from the first six months of 2016. Net profits for the three months ended September 30, 2016 equalled $2,101.

(3) There were no net profits for the third quarter of 2016 as operating expenses and capital expenditures exceeded revenues. The excess of operating expenses and capital expenditures over revenues added to the cumulative deficit balance.

Three Months Ended September 30, 20162017 and 20152016

Developed Properties — For the three months ended September 30, 2016,2017, revenues exceeded direct operating expenses and development expenses from the Developed Properties by $2,153,607. For the three months ended September 30, 2015, revenues exceeded direct operating expenses and development expenses by $5,256,547.$2.3 million. For the three months ended September 30, 2016, revenues were $2.2 million more than direct operating expenses and development expenses.  The decrease$0.1 million period-over-period increase is primarily attributable principally to lowerhigher oil prices, lower production and other taxes and lower development expenses, partially offset by lower production and higher lease operating expenses in the three months ended September 30, 20162017 compared to the three months ended September 30, 2015.2016. Average realized prices decreasedincreased by $10.86$3.79 per Bbl,Boe, or 21%10%, and sales volumes decreased 4118 MBoe, or 15%8%. Orcutt,The decrease in production period over period is primarily due to a decline in the steam flow between wells in the Orcutt Diatomite andarea, increased regulatory requirements in West Pico all had decreased volumesand natural production declines. Total lease operating expenses included in the net profits calculation were $6.7 million for the three months ended September 30, 2016 versus the three months ended September 30, 2015. Total lease operating expenses included in the Net profits interest calculation during the quarter were $6,068,4822017 compared to $6.1 million for the three months ended September 30, 2016 compared2016. The overall increase period over period is mainly related to $7,805,474the non-operated properties. Total production and other taxes included in the net profits calculation during the quarter were $0.5 million for the three months ended September 30, 2015. The decrease is primarily attributable2017 compared to lower operating expenses and workover expenditures at Orcutt Field, Orcutt Diatomite, Sawtelle and West Pico, which resulted from lower fuel and utilities, chemicals, company labor, and workover expenditures. Total capital expenditures were approximately $507,361$0.8 million for the three months ended September 30, 2016 compared2016. Ad valorem taxes decreased in 2017 due to $317,647decreased assessed values on the county property tax rolls associated with lower commodity prices. Total capital expenditures were approximately $0.2 million for the three months ended September 30, 2015.  The increase is primarily due2017 compared to DOGGR mandated injection casing repairs which began in 2016, as well as increased well work in the non-operated properties. Production and other taxes were approximately $839,947$0.5 million for the three months ended September 30, 2016 compared to $889,332 for the three months ended September 30, 2015. Income from 80% Net profits interest for the three months ended September 30, 2016 was $1,722,886 compared to $4,205,238 of income for the three months ended September 30, 2015.  Since a Net profits interest deficit existed as a result of the lack of net profits on the Developed Properties from the Conveyed Interests during the production months of February through April, 2016, the Trust did not receive any net profits generated in the production

months of May through July 2016 and will not receive any Net profits interest until the previous cumulative Net profits interest deficit and borrowings under the Promissory Note is recovered in full.  The cumulative Net profits interest deficit on the Developed Properties was $0 at September 30, 2016, however the balance due under the Promissory Note prohibited the distribution of any Net profits interest as of September 30, 2016.

Remaining Properties — DirectFor the three months ended September 30, 2017, revenues from the Remaining Properties exceeded direct operating expenses and development expenses fromby $0.4 million. For the Remaining Properties exceededthree months ended September 30, 2016, revenues were  approximately equivalent to direct operating expenses and development expenses. The approximately $0.5 million period-over-period increase is attributable principally to higher oil prices, lower production and other taxes and lower development expenses, partially offset by $30,307higher lease operating expenses in the three months ended September 30, 2017, compared to the three months ended September 30, 2016. Average realized prices increased by $1.93 per Boe, or 5%, and sales volumes increased 2 MBoe, or 4%. Total lease operating expenses included in the net profits calculation during the quarter were $1.2 million for the three months ended September 30, 20162017 compared to revenues exceeding the direct operating expenses and development expenses from the Remaining Properties by $1,386,010$1.0 million for the three months ended September 30, 2015. Average realized prices decreased by $9.74 per Bbl, or 20%,2016. Total production and sales volumes decreased 29 MBoe, or 39%, both contributing to a decreaseother taxes included in 2016 distributable income compared to 2015. Orcutt and Orcutt Diatomite had decreased volumesthe net profits calculation were $0.1 million for the three months ended September 30, 2016 versus the three months ended September 30, 2015. Capital expenditures were $414,0462017 compared to $0.3 million for the three months ended September 30, 20162016. Ad valorem taxes decreased in 2017 due to decreased assessed values on the county property tax rolls associated with lower commodity prices. Capital expenditures were less than $0.1 million for the three months ended June 30, 2017 compared to $604,932$0.4 million for the three months ended September 30, 2015. The decrease in capital expenditures was primarily due to lower expenditures for the Remaining Properties in the Orcutt Field and Orcutt Diatomite properties.2016. Since a cumulative deficit existed on the 25% Netnet profits interest, the Trust received approximately $108,222 and $241,141$0.1 million during the three months ended September 30, 20162017 and 2015,2016, respectively, from the Royalty Interest Proceeds.7.5% overriding royalty interest attributable to the sale of all production from the Remaining Properties located on PCEC’s Orcutt Field and Orcutt Diatomite properties.  The cumulative Net profits interest deficit of the Netnet profits interest on the Remaining Properties, including Royalty Interest Proceeds, waspayments to the Trust pursuant to the 7.5% overriding royalty interest, decreased to approximately $2,176,413$1.8 million at September 30, 20162017 compared to $1,577,708$2.2 million at September 30, 2015.2016.

PCEC Operating and& Services FeesFee — PCEC charged the Trust approximately $263,502$0.3 million for operating and services fees for each of the three monthsthree-month periods ended September 30, 2016 compared2017 and 2016. The Trust paid the operating and services fee with respect to $263,190 for the three months ended September 30, 2015. Since2017 period in full in the third quarter of 2017. The Trust did not have enough cash to pay its expenses with respect to the 2016 period and entered into the Promissory Note with PCEC (see Note 4 to the accompanying financial statements). The Trust borrowed funds under the Promissory Note to pay all operating and services fees due during the three months ended September 30, 2016.

Trust Administrative Expenses — The Trustee paid general and administrative expenses of $76,267$0.1 million for each of the three monthsthree-month periods ended September 30, 2017 and 2016, compared to $162,233 for the three months ended September 30, 2015.  The decrease in general and administrative expenses for the three months ended September 30, 2016, was primarily due to the timing of payments related to auditing fees and the NYSE listing fee. The auditing fees and the NYSE listing fee were paid during the three months ended June 30, 2016 compared to the prior year payments of these items in the three months ended September 30, 2015.respectively. Since the Trust did not have enough cash to pay its expenses in the third quarter of 2016, it borrowed $290,675$0.3 million from PCEC from June 30, 2016 to September 30, 2016 (see “Liquidity and Capital Resources” below).2016.

Distributable Income — The total cash received by the Trust from PCEC through income from conveyed interests, net of PCEC operating and service fees and principal repayments, for the three months ended September 30, 2017 was $1.7 million. The Trust general and administrative expenses and cash reserves used for expenses were $0.2 million for the three-month period ended September 30, 2017, primarily consisting of Trustee, audit and legal fees, resulting in distributable income of $1.5 million. The total cash received by the Trust from PCEC for the three months ended September 30, 2016 was $0. There was no cash transferred to the Trustee from distributable income for the months of July, August, and September 2016 as income from the Conveyed Interests was not sufficient to recoup the cumulative deficit generated during the first six months of 2016 and repay the borrowings under the Promissory Note. The total cash received by the Trust from PCECDistributable income was also $0 for the three months ended September 30, 2015 was approximately $4,183,188, which represents the cash received for the months of  July, August and September  2015, as income from the Conveyed Interests exceeded administrative expenses. Distributable income was $4,018,190 for the three months ended September 30, 2015.2016.

Results of Operations for the Nine Months Ended September 30, 20162017 and 20152016

For the nine months ended September 30, 2016,2017, income from Conveyed Interests received by the Trust amounted to $588,104$5.9 million compared with $10,673,212$0.6 million for the nine months ended September 30, 2015.2016.  The increase in income was primarily due to higher oil prices and lower production and other taxes, partially offset by lower production volumes and higher lease operating expenses and development expenses. The net profits income received by the Trust during the nine months ended September 30, 2017 was associated with net profits for oil and natural gas production from the Developed Properties during the months of November and December 2016 and January through July 2017, and with the Royalty Interest Proceeds relating to production during these same months. The net profits received by the Trust during the nine months ended September 30, 2016 werewas associated with Netnet profits interest for oil and natural gas production from the Developed Properties during the months of November and December 2015, and May, June  and July 2016, andwith the Royalty Interest Proceeds for oilrelating to production from the Remaining Properties located in PCEC’s Orcutt Field and Orcutt Diatomite properties during the months of November and December 2015 and January February, April, May, June andthrough July 2016. However, there were noThe Trust did not receive any net profits income for oil and natural gas production from the Developed Properties during the months of January February, March and Aprilthrough July 2016, as operating expenses and capital expenditures exceeded revenues. The

Oil and natural gas sales volumes are allocated to the net profits received by the Trust during the nine months ended September 30, 2015 was associated with net profits forinterests based upon a formula that considers oil and natural gas prices and the total amount of production duringexpense and development costs.  As oil and natural gas prices change, the monthsTrust’s share of Novemberthe production volumes is impacted as the quantity of production to cover expenses and December 2014development costs in reaching the net profits break-even level changes inversely with price.  Accordingly, the Underlying Property production volumes do not correlate with the Trust’s net profits share of those volumes in any given period.  Therefore, the comparative discussion of oil and January, February, March, April, May, June and July 2015.natural gas volumes is based on the Underlying Properties as stated in the table below.

The following table displays PCEC’s underlying sales volumes and average realized prices for the Underlying Properties, representing the amounts included in the Netnet profits interest calculation during the nine months ended September 30, 20162017 and 2015.2016.

(a)  Crude oil sales represented 96%98% and 99%96% of sales volumes from the Developed Properties for the nine months ended September 30, 20162017 and 2015,2016, respectively.

(b) Production costs include lease operating expenses and production and other taxes.

(c)  Crude oil sales represented 100% of total sales volumes from the Remaining Properties for each of the nine-month periodsnine months ended September 30, 2017 and 2016, and 2015.respectively.

Computation of Net Profits and Royalty Income Received by the Trust

The Trust’s net profits and royalty income consist of monthly net profits and royalty income attributable to the Conveyed Interests.  Net profits and royalty income for the nine months ended September 30, 20162017 and 20152016 was determined as shown in the following table:

(4) Increase in Production and other taxes:

On March 23, 2016, PCEC reached a settlement agreement with the Santa Barbara County Assessor’s Office on supplemental property tax bills related to the tax years covering the periods July 1, 2011 through June 30, 2016. The supplemental tax bills relate to the settlement of disputed property values for Orcutt and Orcutt Diatomite field locations for these periods. Amounts attributable to the periods from April 1, 2012 through June 30, 2016 total approximately $2.1 million for the Developed Properties and $1.3 million for the Remaining Properties and are chargeable in part to the Trust in the March 2016 production month calculation of the net profits.

(1) Property tax adjustment amounts related to PCEC not applicable to the Trust based on partial ownership of the Trust by PCEC from May 8, 2012 through June 9, 2014.

(2) There were no net profits for the first nine months of 2016 as operating expenses and capital expenditures exceeded revenues. The excess of operating expenses and capital expenditures over revenues added to the cumulative deficit balance.

(3) Property tax adjustment amounts related to PCEC not applicable to the Trust based on partial ownership of the Trust by PCEC from May 8, 2012 through June 9, 2014.

(4) Production and other taxes in the nine months ended September 30,second quarter of 2016 include supplemental property tax bills from the Santa Barbara County Assessor’s Office related to the tax years covering the periods July 1, 2011 through June 30, 2016. The supplemental property tax billsAmounts attributable to the periods from April 1, 2012 through June 30, 2016 total approximately $2,121,621$2.1 million for the Developed Properties and $1,394,937$1.3 million for the Remaining Properties.