Pacific Coast Oil Trust - FORM 10-Q

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EX-32 - EX-32 - Pacific Coast Oil Trust	a14-14144_1ex32.htm
EX-31 - EX-31 - Pacific Coast Oil Trust	a14-14144_1ex31.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

for the quarterly period ended June 30, 2014


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)



Delaware		80-6216242
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)



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

1-800-852-1422

(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. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer o		Accelerated filer x

Non-accelerated filer o		Smaller reporting company o
(Do not check if a smaller reporting company)

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 August 7, 2014, 38,583,158 Units of Beneficial Interest in Pacific Coast Oil Trust were outstanding.

TABLE OF CONTENTS



Forward-Looking Statements	3
Glossary of Certain Oil and Natural Gas Terms	4
PART I — Financial Information
Item 1. Financial Statements (Unaudited)	7
Statements of Assets and Trust Corpus as of June 30, 2014 and December 31, 2013	7
Statements of Distributable Income for the three and six months ended June 30, 2014 and 2013	8
Statements of Changes in Trust Corpus for the three and six months ended June 30, 2014 and 2013	9
Notes to Financial Statements	10
Item 2. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3. Quantitative and Qualitative Disclosures About Market Risk	24
Item 4. Controls and Procedures	24
PART II — Other Information
Item 1A. Risk Factors	25
Item 6. Exhibits	25
Signatures	27
Exhibit Index	28

FORWARD-LOOKING STATEMENTS

This Form 10-Q 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 Form 10-Q, 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 Form 10-Q, 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:


·	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;


·	the impact of any commodity derivative contracts;


·	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 Form 10-Q. 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 Form 10-Q or to reflect the occurrence of unanticipated events, unless required by law.

This Form 10-Q 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 Section 1A of Part II hereof. 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/d—Boe per day.

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.

Development Well—A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential—The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil price, and the wellhead price received.

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

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

Exploratory well—A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is not a development well.

Estimated future net revenues—Also referred to as “estimated future net cash flows.” The result of applying current prices of oil and natural gas to estimated future production from oil and natural gas proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.

FASB—Financial Accounting Standards Board.

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 wells—The total acres or wells, as the case may be, in which a working interest is owned.

ICE—-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 acres or net wells—The sum of the fractional working interests owned in gross acres or wells, as the case may be.

NGLs— The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

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

Net revenue interest—An interest in all oil and natural gas produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, net profits interests, carried interests, reversionary interests and any other burdens to which the person’s interest is subject.

NYMEX—New York Mercantile Exchange.

Oil—Crude oil and condensate.

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

Overriding royalty interest—A fractional, undivided interest or right of participation in the oil or gas, or in the proceeds from the sale of oil and 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.

Plugging and abandonment—Activities to remove production equipment and seal off a well at the end of a well’s economic life.

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.

Proved undeveloped reserves or PUDs—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 Rule 4-10(a)(2-4) of Regulation S-X.

Recompletion —The completion for production of an existing well bore in another formation from which that well has been previously completed.

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

US GAAP— Generally accepted accounting principles in the United States.

West Texas Intermediate (“WTI”)—Light, sweet crude oil with high API gravity and low sulfur content used as the benchmark for U.S. crude oil refining and trading. WTI is deliverable at Cushing, Oklahoma to fill NYMEX futures contracts for light, sweet crude oil.

Working interest—The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working 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 and Trust Corpus

(unaudited)



Thousands of dollars	June 30, 2014		December 31, 2013
ASSETS
Cash and cash equivalents	$	34	$	39
Investment in conveyed interests, net of amortization (Note 2)	242,470		250,833
Total assets	$	242,504	$	250,872
TRUST CORPUS
Trust corpus (38,583,158 Trust units issued and outstanding)	242,504		250,872
Total Trust corpus	$	242,504	$	250,872

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

PACIFIC COAST OIL TRUST

Statements of Distributable Income

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
Thousands of dollars except unit amounts	2014			2013			2014			2013
Income from conveyed interests	$	14,398		$	16,933		$	29,549		$	34,393
General and administrative expenses	(272		)	(130		)	(485		)	(452		)
Cash reserves used (withheld) for Trust expenses	(28		)	(10		)	5			6
Distributable income	$	14,098		$	16,793		$	29,069		$	33,947

Distributable income per unit (38,583,158 units)	$	0.36538		$	0.43525		$	0.75341		$	0.87985

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

PACIFIC COAST OIL TRUST

Statements of Changes in Trust Corpus

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
Thousands of dollars	2014			2013			2014			2013
Trust corpus, beginning of period	$	246,445		$	265,723		250,872			$	271,209
Cash reserves withheld (used) for future Trust expenses	28			10			(5		)	(7		)
Distributable income	14,098			16,793			29,069			33,947
Distributions to unitholders	(14,098		)	(16,793		)	(29,069		)	(33,947		)
Amortization of conveyed interests	(3,970		)	(5,096		)	(8,363		)	(10,565		)
Trust corpus, end of period	$	242,504		$	260,637		$	242,504		$	260,637

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

PACIFIC COAST OIL TRUST

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Note 1. Organization of the Trust

Formation of the Trust

Pacific Coast Oil Trust (the “Trust”) is a Delaware statutory Trust formed in January 2012 under the Delaware Statutory Trust Act pursuant to a Trust Agreement among 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 May 8, 2012. References in this report to the “Trust Agreement” are to the amended and restated trust agreement.

The Trust was created to acquire and hold net profits 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. 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 concurrent with the initial public offering (“IPO”) of the Trust’s common 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 80% of the net profits from the sale of oil and natural gas production from proved developed reserves on the Underlying Properties as of December 31, 2011 and either a 25% net 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% royalty interest from the sale of oil and natural gas production from the Remaining Properties located in PCEC’s Orcutt properties (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 will be entitled to receive the Royalty Interest Proceeds, and the Trust would continue 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 (herein referred to as 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 in approximately 2020. 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 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 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.

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 Interests and Overriding Royalty Interest (the “Conveyance”), pursuant to which PCEC conveyed to the Trust the Net Profits Interest and the Royalty Interest, which are collectively referred to as the Conveyed Interests.

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 “SEC”.

Note 2. Trust Significant Accounting Policies

Basis of Accounting

The accompanying Statement of Assets and Trust Corpus as of December 31, 2013, which has been derived from audited financial statements, and the unaudited interim financial statements as of June 30, 2014 and for the three and six months ended June 30, 2014 and 2013 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 2013 Annual Report on Form 10-K, as amended.

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.

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 Interests represent 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 Trust corpus. For the three and six months ended June 30, 2014, amortization expense was $4.4 million and $8.8 million, respectively. Such amortization does not affect cash earnings of the Trust. Accumulated amortization as of June 30, 2014 and December 31, 2013 was $42.4 million and $33.7 million, 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 June 30, 2014 or December 31, 2013.

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 pro rata share of the income and gain attributable to the assets of the Trust and entitled to claim his 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 should not be 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. Commodity Derivative Contracts

PCEC had commodity derivative contracts with Wells Fargo Bank, National Association in order to mitigate the effects of falling commodity prices through March 31, 2014. The Trust was entitled to the effect of 2,000 barrels of daily swap volumes of Brent crude oil at $115.00 per barrel, proportional to the Trust’s interest in the Developed Properties, through March 31, 2014. The amounts received by PCEC from the commodity derivative contract counterparty upon settlement of the commodity derivative contracts reduced or increased the operating expenses related to the Underlying Properties in calculating the Net Profits Interests. The Trust received from PCEC net settlements related to the commodity derivative contracts of $0.8 million and $2.0 million for the three and six months ended June 30, 2014, respectively. For the three and six months ended June 30, 2013, the Trust received from PCEC net settlements related to the commodity derivative contracts of $1.0 million and $1.8 million, respectively.

Note 5. 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 (such as interest earned on any amounts reserved by the Trustee) that month, 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 units 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. The following table illustrates information regarding the Trust’s distributions paid during the six months ended June 30, 2014 and 2013.

Six Months Ended June 30, 2014



Declaration Date	Record Date	Payment Date	Distribution per Unit
December 23, 2013	January 6, 2014	January 15, 2014		$	0.12833
January 23, 2014	February 5, 2014	February 14, 2014		$	0.13396
February 24, 2014	March 6, 2014	March 14, 2014		$	0.12574
March 24, 2014	April 3, 2014	April 14, 2014		$	0.12188
April 24, 2014	May 7, 2014	May 14, 2014		$	0.12102
May 22, 2014	June 4, 2014	June 13, 2014		$	0.12248

Six Months Ended June 30, 2013



Declaration Date	Record Date	Payment Date	Distribution per Unit
December 21, 2012	December 31, 2012	January 15, 2013		$	0.13941
January 25, 2013	February 4, 2013	February 14, 2013		$	0.15116
February 25, 2013	March 7, 2013	March 14, 2013		$	0.15403
March 26, 2013	April 5, 2013	April 15, 2013		$	0.13655
April 22, 2013	May 2, 2013	May 14, 2013		$	0.14600
May 24, 2013	June 3, 2013	June 14, 2013		$	0.15270

Note 6. 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 each of the three and six months ended June 30, 2014, the Trust paid $50,000 and $100,000 to the Trustee and $2,000 and $2,000 to the Delaware Trustee, respectively. During each of the three and six months ended June 30, 2013, the Trust paid $50,000 and $100,000 to the Trustee and $2,000 and $2,000 to the Delaware Trustee, respectively

PCEC Operating and Services Fee. Under the terms of the Operating and Services Agreement, PCEC provides the Trust with certain operating and informational services relating to the Conveyed Interests in exchange for a monthly fee equal to $83,333, which changed to $85,083 commencing on April 1, 2013 and to $86,330 commencing on April 1, 2014. The monthly fee will be revised annually based on changes to the Consumer Price Index. The PCEC 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 and six months ended June 30, 2014, the Trust paid PCEC $0.3 million and $0.5 million, respectively. During the three and six months ended June 30, 2013, the Trust paid PCEC $0.3 million and $0.5 million, respectively.

Note 7. Funding Commitment and Letter of Credit

PCEC has provided the Trust with a $1.0 million letter of credit to be used by the Trust in the event that its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative expenses as they become due. Further, if the Trust requires more than the $1.0 million under the letter of credit to pay administrative expenses, PCEC has agreed to loan funds to the Trust necessary to pay such expenses. 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. If the Trust draws on the letter of credit or PCEC loans funds to the Trust, no further distributions will be made to Trust unitholders (except in respect of any previously determined monthly cash distribution amount) until such amounts drawn or borrowed, including interest thereon, are repaid. Any loan made by PCEC will be on an unsecured basis, and the terms of such loan will be substantially the same as those which would be obtained in an arm’s-length transaction between PCEC and an unaffiliated third party. There were no borrowings outstanding at June 30, 2014 or at December 31, 2013.

Note 8. Subsequent Events

On July 15, 2014, the distribution of $0.14872 per Trust Unit, which was declared on June 23, 2014, was paid to Trust unitholders owning Trust Units as of July 3, 2014.

On July 24, 2014 the Trust declared a distribution of $0.13234 per unit to unitholders of record as of August 6, 2014. The distribution is payable to Trust unitholders on August 14, 2014.

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 the Trust’s 2013 Annual Report on Form 10-K, as amended. The following review should also be read in conjunction with the “Cautionary Statement Regarding Forward-Looking Information” in this report and Part I — Item 1A — “Risk Factors” in the Trust’s Annual Report on Form 10-K, as amended.

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, subject to the effects of the commodity derivative contracts on production through March 31, 2014 as described in Note 4 to the financial statements contained in Part I, Item 1 of this Quarterly Report, 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 gas operations or other activities on the Underlying Properties. Wilmington Trust, National Association, as the Delaware Trustee (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 net profits and royalty interests in certain oil and natural gas properties located in California. The Conveyed Interests (as defined below) 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 concurrent with the initial public offering of the Trust’s common units in May 2012.

Concurrent with the initial public offering, on May 8, 2012, the Trust and PCEC entered into a Conveyance of Net Profits Interests and Overriding Royalty Interest (the “Conveyance”), pursuant to which PCEC conveyed to the Trust net profits interest and an overriding royalty interest (the “Conveyed Interests”) in certain oil and natural gas properties in California (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 proved 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 sale of oil and natural gas production from the Remaining Properties located in PCEC’s Orcutt properties (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 would continue 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 (such occurrence being herein called 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 in approximately 2020. 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 will make 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 its Trust units as of the applicable record date (generally within five business days after the last business day of each calendar month). Distributions are payable 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 will be generated by depleting assets with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent, in effect, a return of a unitholder’s original investment. Oil and natural gas production from proved reserves attributable to the Underlying Properties will decline over time.

As described in more detail in Item 1 of Part II, Legal Proceedings, the Trust has been named as a defendant in a putative class action against the Trust and others. The Trust believes that it is fully indemnified by PCEC against any liability or expense it might incur in connection with the litigation. Nevertheless, the Trust may incur expenses in connection with the litigation.

2014 Capital Program Summary

PCEC has informed the Trustee that its calendar year 2014 capital program is expected to total approximately $21.7 million. This total includes expected investments of approximately $8.8 million ($7.1 million net to the Trust’s interest) in the Developed Properties. Approximately $12.8 million is expected to be spent on the Remaining Properties, which will not affect distributions in the current period, but the Trust’s 25% pro rata share of $3.2 million may affect the date on which the NPI Payout occurs.

Properties

The Underlying Properties consist of (i) the proved developed reserves as of December 31, 2011 on the Underlying Properties (the “Developed Properties,”) and (ii) all other development potential on the Underlying Properties (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. 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, the Trust will be paid a 7.5% overriding royalty on the portion of the Remaining Properties located on PCEC’s Orcutt properties. Once revenues from the Remaining Properties have paid back PCEC for the cumulative costs it has advanced on behalf of the Trust, the net profits interests on the Remaining Properties will be paid out in place of the royalty interests, as described below. The net profits interests and royalty interest conveyed to the Trust are referred to herein as the “Net Profits Interests” and “Royalty Interest,” respectively. These interests, collectively 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

•

7.5% of the proceeds (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 Proceeds”), or


•	25% of the net profits from the sale of oil and natural gas production from all of the Remaining Properties.

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. The amount of Royalty Interest Proceeds paid will be taken into account in the net profits interest calculation for the Remaining Properties. If at any time cumulative costs for the Developed Properties or the Remaining Properties exceed cumulative gross proceeds associated with such 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 such properties exceed the cumulative total excess costs for 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 the Net Profits Interest, (2) the annual cash available for distribution to the Trust is less than $2 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.

Commodity Derivative Contracts

The revenues derived from the Underlying Properties depend substantially on prevailing oil prices and, to a lesser extent, natural gas prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil and natural gas that PCEC or the third-party operators can economically produce.

PCEC had commodity derivative contracts with Wells Fargo Bank, National Association in order to mitigate the effects of falling commodity prices through March 31, 2014. The Trust was entitled to the effect of 2,000 barrels of daily swap volumes of Brent crude oil at $115.00 per barrel during the twenty-four months ended March 31, 2014, proportional to the Trust’s interest in the Developed Properties. The amounts received by PCEC from the commodity derivative contract counterparty upon settlement of the commodity derivative contracts reduced or increased the amount of net profits related to the Underlying Properties. After March 31, 2014, none the Trust’s exposure to crude oil prices is hedged. In addition, none of the Trust’s exposure to natural gas is hedged.

Results of Operations for the Three Months Ended June 30, 2014 and 2013

For the three months ended June 30, 2014, income from Conveyed Interests received by the Trust amounted to $14.4 million compared with $16.9 million for the three months ended June 30, 2013. The net profits income received by the Trust during the three months ended June 30, 2014 was primarily associated with net profits for oil and natural gas production during the months of February, March and April 2014. The net profits income received by the Trust during the three months ended June 30, 2013 was primarily associated with net profits for oil and natural gas production during the months of February, March and April 2013.

The following table displays PCEC’s underlying sales volumes and average prices for the Underlying Properties, representing the amounts included in the net profits calculation for distributions paid during the three months ended June 30, 2014 and 2013.



	Three Months Ended
	June 30,
	2014		2013
Developed Properties:
Underlying sales volumes (Boe) (a)	313,784		320,472
Average daily production (Boe/d)	3,526		3,601
Average price (per Boe)	$	96.58	$	100.05
Production cost (per Boe)	$	35.67	$	35.58

Remaining Properties:
Underlying sales volumes (Boe) (b)	75,634		70,710
Average daily production (Boe/d)	850		794
Average price (per Boe)	$	95.73	$	99.06
Production cost (per Boe)	$	21.33	$	21.51

(a) Crude oil sales represented 97% of sales volumes from the Developed Properties for the three months ended June 30, 2014 and 96% of total sales volumes from the Developed Properties for the three months ended June 30, 2013.
(b) Crude oil sales represented 100% of total sales volumes from the Remaining Properties for each of the three months ended June 30, 2014 and 2013.

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 June 30, 2014 and 2013 were determined as shown in the following table.



Thousands of dollars	Three Months Ended June 30, 2014			Three Months Ended June 30, 2013
Developed Properties—80% Net Profits Interest
Gross profits:
Oil sales	$	29,938		$	31,758
Natural gas sales	368			305
Total	30,306			32,063

Costs:
Direct operating expenses:
Lease operating expenses	10,246			10,507
Production and other taxes	948			896
Development expenses	2,449			1,028
Total	13,643			12,431

Total income	16,663			19,632
Net Profits Interest	80		%	80		%

Income from Net Profits Interest	$	13,331		$	15,706

Remaining Properties—25% Net Profits Interest
Total Revenues:
Oil sales	$	7,240		$	7,004
Total	7,240			7,004
7.5% Overriding Royalty Interest	527			504

Costs:
Direct operating expenses:
Lease operating expenses	1,400			1,314
Production and other taxes	213			207
Development expenses	2,788			2,445
Total	4,401			3,966

Total income	2,312			2,534
Net Profits Interest	25		%	25		%

25% Net Profits Interest income ⁽¹⁾	$	578		$	634

Total Trust Cash Flow
80% net profit interest	$	13,331		$	15,706
7.5% overriding royalty interest	527			504
Settlement of commodity derivative contracts	796			976
PCEC operating and service fee	(256		)	(252		)
Total	$	14,398		$	16,934

Trust general and administrative expenses and cash withheld for expenses	(300		)	(140)
Distributable income	$	14,098		$	16,794

(1) 25% Net Profits Interest Accrued Deficit
Beginning balance	$	(3,236	)	$	(5,242	)
Current period	578			634
Ending balance	$	(2,658	)	$	(4,608	)

Three months ended June 30, 2014 and 2013

Developed Properties – Excess of revenues over direct operating expenses and development expenses from the Developed Properties, before net settlements related to commodity derivative contracts, was approximately $16.7 million for the three months ended June 30, 2014 compared to $19.6 million for the three months ended June 30, 2013. The decrease is attributable principally to lower oil prices, and lower production compared to the prior year quarter; in addition, higher development related capital expenditures contributed to the decrease in income. Sales volume decreased 6,689 Boe or 2.1%, and average realized prices decreased $3.46, or 3.5%, both contributing to a decrease in 2014 distributable income compared to 2013. Total capital expenditures included in the net profits calculation during the quarter were approximately $2.4 million for the three months ended June 30, 2014 compared to $1.0 million for the three months ended June 30, 2013. The increase is primarily attributable to facility upgrades in the Orcutt Diatomite and West Pico properties and additional well work in both the Orcutt Field and Diatomite properties. Total lease operating expenses included in the net profits calculation during the quarter were approximately $10.2 million for the three months ended June 30, 2014 compared to $10.5 million for the three months ended June 30, 2013. Production and other taxes were approximately $0.9 million for each of the three months ended June 30, 2014 and 2013. Income from Net profits interest was approximately $13.3 million for the three months ended June 30, 2014 compared to $15.7 million for the three months ended June 30, 2013.

Remaining Properties – Excess of revenues over direct operating expenses and development expenses from the Remaining Properties, before net settlements related to commodity derivative contracts, was approximately $2.3 million for the three months ended June 30, 2014 compared to $2.5 million for the three months ended June 30, 2013. Since a cumulative deficit existed on the 25% net profits interest, the Trust received approximately $0.5 million during each of the three months ended June 30, 2014 and 2013 from the 7.5% Overriding Royalty attributable to the sale of all production from the Remaining Properties located on PCEC’s Orcutt Properties. The cumulative deficit of the net profits interest on the Remaining Properties, including payments to the Trust pursuant to the 7.5% Overriding Royalty, was approximately $2.7 million at June 30, 2014 compared to $4.6 million at June 30, 2013.

Commodity Derivatives – Net settlements related to commodity derivative contracts were $0.8 million for the three months ended June 30, 2014 compared to $1.0 million for the three months ended June 30, 2013.

PCEC Operating & Service Fees – PCEC charged the Trust $0.3 million for the Operating and Service Fee for each of the three months ended June 30, 2014 and June 30, 2013, respectively. The annual amount of the Operating and Service Fee was $1.0 million from April 1, 2012 through March 31, 2013. Commencing April 1, 2013, the Operating and Services Fee increased 2% to $1,021,000 based on changes to the CPI. The fee will adjust annually each April 1, and commencing April 1, 2014 it increased 1.5% to $1,035,955.

Distributable Income – The total cash received by the Trust from PCEC for the three months ended June 30, 2014 and 2013 was approximately $14.4 million and $16.9 million, respectively. The Trustee paid general and administrative expenses of $0.3 million and $0.1 million during the second quarter of 2014 and 2013, respectively. Expenses paid during the second quarter of 2014 primarily consisted of Trustee fees, accounting fees and legal fees. Expenses paid during the second quarter of 2013 primarily consisted of Trustee fees and legal fees. The distributable income was approximately $14.1 million for the quarter ended June 30, 2014 compared to $16.8 million for the quarter ended June 30, 2013.

Results of Operations for the Six Months Ended June 30, 2014 and 2013

For the six months ended June 30, 2014, income from Conveyed Interests received by the Trust amounted to $29.5 million compared with $34.4 million for the six months ended June 30, 2013. The net profits income received by the Trust during the six months ended June 30, 2014 was primarily associated with net profits for oil and natural gas production during the months of November and December 2013 and January, February, March and April 2014. The net profits income received by the Trust during the six months ended June 30, 2013 was primarily associated with net profits for oil and natural gas production during the months of November and December 2012 and January, February, March and April 2013.



	Six Months Ended
	June 30,
	2014		2013
Developed Properties:
Underlying sales volumes (Boe) (a)	644,639		652,185
Average daily production (Boe/d)	3,562		3,603
Average price (per Boe)	$	94.22	$	98.98
Production cost (per Boe)	$	34.64	$	34.42

Remaining Properties:
Underlying sales volumes (Boe) (b)	150,187		139,488
Average daily production (Boe/d)	830		771
Average price (per Boe)	$	93.71	$	98.28
Production cost (per Boe)	$	20.68	$	19.56

(a) Crude oil sales represented 97% of total sales volumes from the Developed Properties for the six months ended June 30, 2014 and 96% of total sales volumes from the Developed Properties for the six months ended June 30, 2013.
(b) Crude oil sales represented 100% of total sales volumes from the Remaining Properties for each of the six months ended June 30, 2014 and 2013.

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 six months ended June 30, 2014 and 2013 were determined as shown in the following table.



Thousands of dollars	Six Months Ended June 30, 2014			Six Months Ended June 30, 2013
Developed Properties—80% Net Profits Interest
Gross profits:
Oil sales	$	60,122		$	63,983
Natural gas sales	617			572
Total	60,739			64,555

Costs:
Direct operating expenses:
Lease operating expenses	20,505			20,489
Production and other taxes	1,828			1,958
Development expenses	4,588			2,053
Total	26,921			24,500

Total income	33,818			40,055
Net Profits Interest	80		%	80		%

Income from Net Profits Interest	$	27,054		$	32,044

Remaining Properties—25% Net Profits Interest
Total Revenues:
Oil sales	$	14,075		$	13,709
Total	14,075			13,709
7.5% Overriding Royalty Interest	1,021			1,007

Costs:
Direct operating expenses:
Lease operating expenses	2,682			2,450
Production and other taxes	423			279
Development expenses	6,215			7,516
Total	9,320			10,245

Total income (excess cost)	3,734			2,457
Net Profits Interest	25		%	25		%
25% Net Profits Interest income ⁽¹⁾	$	933		$	614

Total Trust Cash Flow
80% net profit interest	$	27,054		$	32,044
25% net profit interest	—			—
7.5% overriding royalty interest	1,021			1,007
Settlement of commodity derivative contracts	1,985			1,844
PCEC operating and service fee	(511		)	(502)
Total	$	29,549		$	34,393

Trust general and administrative expenses and cash withheld for expenses	(480		)	(445		)
Distributable income	$	29,069		$	33,948

(1) 25% Net Profits Interest Accrued Deficit
Beginning balance	$	(3,591	)	$	(5,222	)
Current period	933			614
Ending balance	$	(2,658	)	$	(4,608	)

Six months ended June 30, 2014 and 2013

Developed Properties – Excess of revenues over direct operating expenses and development expenses from the Developed Properties, before net settlements related to commodity derivative contracts, was approximately $33.8 million for the six months ended June 30, 2014 compared to $40.1 million for the six months ended June 30, 2013. Sales volume decreased 7,545 Boe or 1.2%, and average realized prices decreased $4.76, or 4.8%, both contributing to a decrease in 2014 distributable income compared to 2013. Total capital expenditures included in the net profits calculation during the six months ended June 30, 2014 were approximately $4.6 million compared to $2.1 million in the same period of 2013. The increase is primarily attributable to facility upgrades in the Orcutt Diatomite and West Pico properties and additional well work in both the Orcutt Field and Diatomite properties. Total lease operating expenses included in the net profits calculation during each of the six months ended June 30, 2014 and 2013 were approximately $20.5 million. Income from Net profits interest was approximately $27.1 million for the six months ended June 30, 2014 compared to $32.0 million for the three months ended June 30, 2013.

Remaining Properties – Excess of revenues over direct operating expenses and development expenses from the Remaining Properties, before net settlements related to commodity derivative contracts, was approximately $9.3 million for the six months ended June 30, 2014 compared to $10.2 million for the six months ended June 30, 2013. Since a cumulative deficit existed on the 25% net profits interest, the Trust received approximately $1.0 million during each of the six months ended June 30, 2014 and 2013 from the 7.5% Overriding Royalty attributable to the sale of all production from the Remaining Properties located on PCEC’s Orcutt Properties. The cumulative deficit of the net profits interest on the Remaining Properties, including payments to the Trust pursuant to the 7.5% Overriding Royalty, was approximately $2.7 million at June 30, 2014 compared to $4.6 million at June 30, 2013.

Commodity Derivatives – Net settlement receipts related to commodity derivative contracts were $2.0 million for the six months ended June 30, 2014 compared to $1.8 million for the six months ended June 30, 2013.

PCEC Operating & Service Fees – PCEC charged the Trust $0.5 million for the Operating and Service Fee for each of the six months ended June 30, 2014 and 2013.

Distributable Income – The total cash received by the Trust from PCEC for the six months ended June 30, 2014 was approximately $29.5 million compared to $34.4 million for the six months ended June 30, 2013. The Trustee paid general and administrative expenses of $0.5 million during the six months ended June 30, 2014 compared with $0.4 million during the first six months of 2013. Expenses paid during the six month periods ended June 30, 2014 and 2013 consisted primarily of Trustee fees, accounting fees and New York Stock Exchange listing fees. The distributable income was approximately $29.1 million and $33.9 million, respectively, for the six months ended June 30, 2014 and 2013.

Liquidity and Capital Resources

Other than Trust administrative expenses, including payment of the PCEC operating and services fee and any reserves established by the Trustee for future liabilities, the Trust’s only use of cash is for distributions to Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the Conveyed Interests and other sources (such as interest earned on any amounts reserved by the Trustee) in that month, over the Trust’s expenses paid for that month. Available funds are reduced by any cash the Trustee determines to hold as a reserve against future expenses.

The Trustee may create a cash reserve to pay for future liabilities of the Trust. If the Trustee determines that the cash on hand and the cash to be received are, or will be, insufficient to cover the Trust’s liabilities, the Trustee may cause the Trust to borrow funds to pay liabilities of the Trust. The Trustee may also cause the Trust to mortgage its assets to secure payment of the indebtedness. If the Trustee causes the Trust to borrow funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid.

Each month, the Trustee pays Trust obligations and expenses and distributes to the Trust unitholders the remaining proceeds received from the Conveyed Interests. The cash held by the Trustee as a reserve against future liabilities or for distribution at the next distribution date may be invested in a limited number of permitted investments. Alternatively, cash held for distribution at the next distribution date may be held in a noninterest bearing account.

of other accrued current liabilities arising in the ordinary course of the Trust’s business, and may not be used to satisfy Trust indebtedness. If the Trust draws on the letter of credit or PCEC loans funds to the Trust, no further distributions will be made to Trust unitholders (except in respect of any previously determined monthly cash distribution amount) until such amounts drawn or borrowed, including interest thereon, are repaid. Any loan made by PCEC will be on an unsecured basis, and the terms of such loan will be substantially the same as those which would be obtained in an arm’s-length transaction between PCEC and an unaffiliated third party.

The Trustee has no current plans to authorize the Trust to borrow money. During the three months and six months ended June 30, 2014 and 2013, there were no borrowings.

Distributions Paid and Declared After Quarter End

On July 15, 2014, the distribution of $0.14872 per Trust Unit, which was declared on June 23, 2014, was paid to Trust unitholders owning Trust Units as of July 3, 2014.

On July 24, 2014 the Trust declared a distribution of $0.13234 per unit to unitholders of record as of August 6, 2014. The distribution is payable to Trust unitholders on August 14, 2014.

Off-Balance Sheet Arrangements

The Trust has no off-balance sheet arrangements and does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources.

New Accounting Pronouncements

As the Trust’s financial statements are prepared on the modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements. No new accounting pronouncements have been adopted or issued that would impact the financial statements of the Trust.

Critical Accounting Policies and Estimates

Please read “Item 7. Trust’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” of the Trust’s 2013 Annual Report on Form 10-K, as amended, for additional information regarding the Trust’s critical accounting policies and estimates. There were no material changes to the Trust’s critical accounting policies or estimates during the quarter ended June 30, 2014.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Commodity Price Risk. The Trust’s most significant market risk relates to the prices received for oil and natural gas production. The revenues derived from the Underlying Properties depend substantially on prevailing oil prices and, to a lesser extent, natural gas prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil and natural gas that PCEC or the third-party operators can economically produce.

Credit Risk. The Trust’s most significant credit risk is the risk of the bankruptcy of PCEC. The bankruptcy of PCEC could impede the operation of wells and the development of the proved undeveloped reserves. Further, in the event of the bankruptcy of PCEC, if a court held that the Net Profits Interests were part of the bankruptcy estate, the Trust might be treated as an unsecured creditor with respect to the Net Profits Interests.

Item 4. Controls and Procedures.

The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under Rules 13a-15 and 15d-15 under the Securities and Exchange Act of 1934, as amended (“Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by PCEC to The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure. As of the end of the period covered by this Quarterly Report, the Trustee carried out an evaluation of the Trustee’s disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.

Due to the nature of the Trust as a passive entity and in light of the contractual arrangements pursuant to which the Trust was created, including the provisions of (i) the Trust Agreement, (ii) the Operating and Services Agreement and (iii) the Conveyance of Net Profits Interests and Overriding Royalty Interest, the Trustee’s disclosure controls and procedures related to the Trust necessarily rely on (A) information provided by PCEC, including information relating to results of operations, the costs and revenues attributable to the Trust’s interests under the Conveyance of Net Profits Interests and Overriding Royalty Interest and other operating and historical data, plans for future operating and capital expenditures, reserve information, information relating to projected production, and other information relating to the status and results of operations of the Underlying Properties and the Conveyed Interests and settlements under the commodity derivative contracts between PCEC and Wells Fargo Bank, National Association, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers.

During the quarter ended June 30, 2014, there was no change in the Trustee’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trustee’s internal control over financial reporting related to the Trust. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of PCEC.

PART II—OTHER INFORMATION

Item 1. 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.

The Trust intends to defend the Welch lawsuit vigorously. The Trust believes that it is fully indemnified by PCEC against any liability or expense it might incur in connection with the litigation contemplated by the Complaint. Nevertheless, the Trust may incur expenses in connection with the litigation.

Item 1A. Risk Factors.

Risk factors relating to the Trust are discussed in Item 1A of the Trust’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2013. Except as described below (and previously described in a Current Report on Form 8-K filed on June 9, 2014), no material change to such risk factors occurred during the three months ended June 30, 2014.

A pending initiative in Santa Barbara County may materially and negatively impact PCEC’s future production from its properties, which could result in significant reductions in cash distributions to trust unitholders.

Several jurisdictions in California, including Santa Barbara County, have proposed various forms of moratoria or bans on hydraulic fracturing and other hydrocarbon recovery techniques, including traditional waterflooding, acid treatments and cyclic steam injection. A local initiative in Santa Barbara County was circulated for signature during the first half of 2014 and has obtained sufficient signatures to place proposed amendments to the Santa Barbara County Comprehensive Plan and the Santa Barbara County Code on the ballot in Santa Barbara County in November 2014. If enacted, these amendments would either directly or indirectly prohibit utilization of waterflooding, cyclic steam injection, acid use for stimulation or maintenance, water injection, and a variety of other methods, on future well sites as well as potentially materially reducing or prohibiting utilization of such recovery techniques from currently producing wells, within Santa Barbara County. If enacted, the proposed amendments would also prohibit the use of hydraulic fracturing in Santa Barbara County, although PCEC has never used hydraulic fracturing in Santa Barbara County and has no plans to do so. PCEC and other companies involved in the oil and gas industry in Santa Barbara County and elsewhere are actively involved in campaigning to defeat the proposed initiative because PCEC believes enacting the proposed amendments would result in significant negative impacts on California jobs, taxes, royalty owners as well as our ability to pay cash distributions to trust unitholders.

The current and future production of PCEC’s Orcutt properties, including the Diatomite formation, which are located in Santa Barbara County, are substantially dependent on PCEC’s ability to successfully implement or continue utilizing traditional waterflooding, cyclic steam injection and other currently utilized recovery methods. For example, production utilizing cyclic steaming represented 1,660 Boe/d and 1,631 Boe/d of average net production for the year ended December 31, 2013 and the three months ended March 31, 2014, respectively, or 38% and 38%, respectively, of PCEC’s average daily net production attributable to the Underlying Properties for such periods. Total production in Santa Barbara County, including conventional production, represented 3,392 Boe/d and 3,320 Boe/d of average net production for the year ended December 31, 2013 and the three months ended March 31, 2014, respectively, or 77% and 77%, respectively, of PCEC’s average daily net production attributable to the Underlying Properties for such periods. Because PCEC’s current production within Santa Barbara County is significant, the proposed amendments, if enacted, would have a material adverse impact on future production from the Underlying Properties, and would have a material adverse impact on

such current production, each of which would materially and adversely affect our ability to pay cash distributions to trust unitholders. If the proposed amendments were enacted, PCEC would likely sue Santa Barbara County to recover damages resulting from Santa Barbara County’s taking of PCEC’s and the unitholders’ property without compensation. Any such litigation would result in additional costs to the trust, and there can be no assurance of the success of such action against Santa Barbara County.

We may be involved in legal proceedings that may result in substantial liabilities.

PCEC is from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and property damage matters, in the ordinary course of its business, and any such matters relating to the properties in which the Trust has an interest may impose costs on the Trust or otherwise affect the Trust. In addition, the Trust may also be involved directly in legal or other proceedings, including the purported class action described in Item 1 of Part II of this report. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on the Trust because of legal costs, diversion of PCEC management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in PCEC’s business practices, which could materially and adversely affect the Trust. Any accruals for any such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

Item 6. Exhibits.

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

SIGNATURES

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



	PACIFIC COAST OIL TRUST

	By:	The Bank of New York Mellon Trust Company, N.A., as Trustee

	By:	/s/ Mike Ulrich
		Mike Ulrich
		Vice President

Date: August 8, 2014

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

Exhibit Index



Exhibit Number		Description
1.1		Underwriting Agreement dated as of May 2, 2012 among Pacific Coast Energy Company LP, PCEC (GP) LLC, Pacific Coast Oil Trust and Barclays Capital Inc., Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC, UBS Securities LLC and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein (Incorporated herein by reference to Exhibit 1.1 to the Trust’s Current Report on Form 8-K filed on May 8, 2012 (File No. 1-35532)).

1.2		Underwriting Agreement dated as of September 19, 2013 among Pacific Coast Energy Company LP, PCEC (GP) LLC, Pacific Coast Oil Trust, the Selling Unitholders named therein and Morgan Stanley & Co. LLC, Barclays Capital Inc., J.P. Morgan Securities LLC, Wells Fargo Securities, LLC, UBS Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and RBC Capital Markets, LLC, as representatives of the several underwriters named therein (Incorporated herein by reference to Exhibit 1.1 to the Trust’s Current Report on Form 8-K filed on September 25, 2013 (File No. 1-35532)).

3.1		Certificate of Trust of Pacific Coast Oil Trust. (Incorporated herein by reference to Exhibit 3.1 to the Registration Statement on Form S-1, filed on January 6, 2012 (Registration No. 333-178928))

3.2		Trust Agreement of Pacific Coast Oil Trust, dated January 3, 2012, among Pacific Coast Energy Company LP, Wilmington Trust, National Association, as Delaware trustee of Pacific Coast Oil Trust, and The Bank of New York Mellon Trust Company, N.A., as trustee of Pacific Coast Oil Trust. (Incorporated herein by reference to Exhibit 3.5 to the Registration Statement on Form S-1, filed on January 6, 2012 (Registration No. 333-178928))

3.3		Amended and Restated Trust Agreement of Pacific Coast Oil Trust, dated May 8, 2012, among Pacific Coast Energy Company LP, Wilmington Trust, National Association, as Delaware trustee of Pacific Coast Oil Trust, and The Bank of New York Mellon Trust Company, N.A., as trustee of Pacific Coast Oil Trust. (Incorporated herein by reference to Exhibit 3.1 to the Trust’s Current Report on Form 8-K filed on May 8, 2012 (File No. 1-35532))

3.4		First Amendment to Amended and Restated Trust Agreement of Pacific Coast Oil Trust, dated June 15, 2012 (Incorporated by reference to Exhibit 3.1 to the Trust’s Current Report on Form 8-K filed on June 19, 2012 (File No. 1-35532))

10.1		Conveyance of Net Profits Interests and Overriding Royalty Interest, dated as of June 15, 2012, by and between Pacific Coast Energy Company LP and Pacific Coast Oil Trust (Incorporated herein by reference to Exhibit 10.1 to the Trust’s Current Report on Form 8-K filed on June 19, 2012 (File No. 1-35532))

10.2		Registration Rights Agreement, dated as of May 8, 2012, by and between Pacific Coast Energy Company LP and Pacific Coast Oil Trust (Incorporated herein by reference to Exhibit 10.2 to the Trust’s Current Report on Form 8-K filed on May 8, 2012 (File No. 1-35532))

10.3		Operating and Services Agreement, dated as of May 8, 2012, by and between Pacific Coast Energy Company LP and Pacific Coast Oil Trust (Incorporated by reference to Exhibit 10.3 to the Trust’s Current Report on Form 8-K filed on May 8, 2012 (File No. 1-35532))

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

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

*Filed herewith.

Attached files

Pacific Coast Oil Trust Reports

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