Introduction
Chesapeake Granite Wash Trust is a statutory trust formed in June 2011 under the Delaware Statutory Trust Act pursuant to an initial trust agreement by and among Chesapeake, as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”). The Trust maintains its offices at the office of the Trustee, which is located at 601 Travis Street, Floor 16, Houston, Texas 77002, and the telephone number of the Trustee is (512) 236-6555.
The Trustee maintains a website for filings by the Trust with the SEC. Electronic filings by the Trust with the SEC are available free of charge through the Trust's website at
www.chkgranitewashtrust.com
and through the SEC's website at
www.sec.gov
. The Trust will also provide electronic and paper copies of its recent filings free of charge upon request to the Trustee. Documents and information on the Trust's website are not incorporated by reference herein.
General
The Trust was created to own the Royalty Interests for the benefit of Trust unitholders pursuant to a trust agreement dated as of June 29, 2011 and subsequently amended and restated as of November 16, 2011 by and among Chesapeake, Chesapeake Exploration, L.L.C., a wholly owned subsidiary of Chesapeake, the Trustee and the Delaware Trustee (the “Trust Agreement”). The Royalty Interests are derived from Chesapeake's interests in specified oil and natural gas properties located in the Colony Granite Wash play in Washita County in the Anadarko Basin of western Oklahoma (the “Underlying Properties”). Chesapeake conveyed the Royalty Interests to the Trust from Chesapeake's interests in the Producing Wells and the Development Wells.
The business and affairs of the Trust are managed by the Trustee. The Trust Agreement limits the Trust's business activities generally to owning the Royalty Interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances applicable to the Royalty Interests
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The royalty interests in the Producing Wells (the “PDP Royalty Interest”) entitle the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting certain post-production expenses and any applicable taxes) from the sales of oil, natural gas and NGL production attributable to Chesapeake's net revenue interest in the Producing Wells. The royalty interests in the Development Wells (the “Development Royalty Interest”) entitle the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting certain post-production expenses and any applicable taxes) from the sales of oil, natural gas and NGL production attributable to Chesapeake's net revenue interest in the Development Wells.
Through an initial public offering in November 2011, the Trust sold to the public 23,000,000 common units, representing beneficial interests in the Trust, for cash proceeds of approximately $409.7 million, net of offering costs. The Trust delivered the net proceeds of the initial public offering, along with 12,062,500 common units and 11,687,500 subordinated units, to certain wholly owned subsidiaries of Chesapeake in exchange for the conveyance of the Royalty Interests to the Trust. Upon completion of these transactions, there were 46,750,000 Trust units issued and outstanding, consisting of 35,062,500 common units and 11,687,500 subordinated units. The common units and subordinated units had identical rights and privileges, except with respect to their voting rights and rights to receive distributions as described below.
Prior to their conversion on June 30, 2017, the subordinated units were entitled to receive pro rata distributions from the Trust each quarter if and to the extent there was sufficient cash to provide a cash distribution on the common units that was no less than 80% of the target distribution set forth in the Trust Agreement for the corresponding quarter (the “subordination threshold”). If there was insufficient cash to fund such a distribution on all of the Trust units, the distribution made with respect to the subordinated units was either reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. Prior to the conversion of the subordinated units on June 30, 2017, Chesapeake was entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the Trust units in any quarter was 20% greater than the target distribution for such quarter (the “incentive threshold”). The remaining 50% of cash available for distribution in excess of the applicable incentive threshold, if any, was to be paid to Trust unitholders, including Chesapeake, on a pro rata basis.
On June 30, 2017, the last day of the fourth full calendar quarter subsequent to Chesapeake's satisfaction of its drilling obligation under the development agreement, the subordinated units automatically converted into common units on a one-for-one basis, and Chesapeake's right to receive incentive distributions with respect to quarters after the 2017 second quarter terminated. All distributions made on common units after September 30, 2017 no longer have the benefit of the subordination threshold, nor are the common units subject to the incentive threshold, and all Trust unitholders share on a pro rata basis in the Trust's distributions.
The distribution for the quarter ended June 30, 2017, which was paid on August 31, 2017, was still subject to the subordination threshold. As a result, distributable income available to unitholders for the three and nine months ended September 30, 2017 was still subject to the subordination threshold. As such, distributable income per common unit as of September 30, 2017 was based upon 35,062,500 common units. Beginning with the November 30, 2017 distribution, the distributable income available to unitholders is based on the 46,750,000 common units that are currently outstanding.
Neither the Trust nor the Trustee is responsible for
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or has any control over
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any operating or capital costs of the Underlying Properties. The Trust's cash receipts with respect to the Royalty Interests in the Underlying Properties are determined after deducting certain post-production expenses and any applicable taxes associated with the Royalty Interests. Post-production expenses generally consist of costs incurred to gather
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store, compress, transport, process, treat, dehydrate and market the oil, natural gas and NGL produced. However
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the Trust is not responsible for costs of marketing services provided by affiliates of Chesapeake. Cash distributions to unitholders will continue to be reduced by the Trust's general and administrative expenses.
The Trust will dissolve and begin to liquidate on June 30, 2031, or earlier upon certain events (the “Termination Date”), and will soon thereafter wind up its affairs and terminate. At the Termination Date, (a) 50% of the total Royalty Interests conveyed by Chesapeake (the “Term Royalties”) will revert automatically to Chesapeake and (b) 50% of the total Royalty Interests conveyed by Chesapeake (the “Perpetual Royalties”) will be retained by the Trust and thereafter sold. The net proceeds of the sale of the Perpetual Royalties, as well as any remaining Trust cash reserves, will be distributed to the unitholders on a pro rata basis. Chesapeake will have a right of first refusal to purchase the Perpetual Royalties retained by the Trust at the Termination Date.
Target Distributions and Subordination and Incentive Thresholds
The Trust is required to make quarterly cash distributions of substantially all of its quarterly cash receipts, after deducting the Trust's administrative expenses and any cash reserves, on or about 60 days following the completion of each quarter through (and including) the quarter ending June 30, 2031. Quarterly distributions to Trust unitholders will generally include royalty income attributable to sales of oil, natural gas and NGL for three months, including the first two months of the quarter just ended and the last month of the quarter prior to that one. The first quarterly distribution was made on December 28, 2011 to record unitholders as of December 15, 2011.
In connection with the initial public offering of the Trust, Chesapeake established quarterly target levels of cash distributions to unitholders for the life of the Trust. These target distributions were used to calculate the subordination and incentive thresholds described in more detail below and do not represent estimates of the actual distributions that may be received by Trust unitholders. Actual cash distributions to the Trust unitholders will fluctuate quarterly based on the quantity of oil, natural gas and NGL sold from the Underlying Properties, the prices received for such sales, the timing of Chesapeake's receipt of payment for such sales, the Trust's expenses and other factors. Target distributions will decline over time as a result of the depletion of the reserves in the Underlying Properties.
Subordination Threshold.
In order to provide support for cash distributions on the common units, Chesapeake agreed to subordinate 11,687,500 of the Trust units retained following the initial public offering of common units, which constituted 25% of the outstanding Trust units. Prior to their conversion on June 30, 2017, the subordinated units were entitled to receive pro rata distributions from the Trust each quarter if and to the extent there was sufficient cash to pay a cash distribution on the common units that was no less than 80% of the target distribution set forth in the Trust Agreement for the corresponding quarter. If there was insufficient cash to fund such a distribution on all of the common units, the distribution made with respect to the subordinated units was either reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all the common units, including the common units held by Chesapeake.
Incentive Threshold.
Prior to the conversion of the subordinated units on June 30, 2017, in exchange for agreeing to subordinate a portion of its Trust units, and in order to provide additional financial incentive to Chesapeake to satisfy its drilling obligation and perform operations on the Underlying Properties in an efficient and cost-effective manner, Chesapeake was entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the Trust units in any quarter was 20% greater than the target distribution for such quarter. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold, if any, was paid to the Trust unitholders, including Chesapeake, on a pro rata basis.
For the year ended
December 31, 2018
, the Trust declared and paid the following cash distributions:
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Production Period
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Distribution Date
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Cash Distribution per Common Unit
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June 2018 – August 2018
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November 29, 2018
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$
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0.0534
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March 2018 - May 2018
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August 30, 2018
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$
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0.0626
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December 2017 - February 2018
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May 31, 2018
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$
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0.0469
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September 2017 - November 2017
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March 2, 2018
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$
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0.0787
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___________________________________________________
As of
March 21, 2019
, Chesapeake owned 23,750,000 common units, which represent 50.8% of the outstanding Trust units.
Administrative Services Agreement
On November 16, 2011, the Trust entered into an administrative services agreement with Chesapeake, effective July 1, 2011, pursuant to which Chesapeake provides the Trust with certain accounting, tax preparation, bookkeeping and information services related to the Royalty Interests and the registration rights agreement. In return for the services provided by Chesapeake under the administrative services agreement, the Trust pays Chesapeake an annual fee of $200,000, which is paid in equal quarterly installments and remains fixed for the life of the Trust. Chesapeake is also entitled to receive reimbursement for its actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement.
The administrative services agreement will terminate upon the earliest to occur of (a) the date the Trust shall have been wound up in accordance with the Trust Agreement, (b) the date that all of the Royalty Interests have been terminated or are no longer held by the Trust, (c) with respect to services to be provided with respect to any Underlying Properties being transferred by Chesapeake, the date that either Chesapeake or the Trustee may designate by delivering 90-days prior written notice, provided that Chesapeake's drilling obligation has been completed and the transferee of such Underlying Properties assumes responsibility to perform the services in place of Chesapeake or (d) a date mutually agreed by Chesapeake and the Trustee.
Description of the Trust
Common Units.
Each Trust unit is a unit of the beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis. The Trust has 46,750,000 Trust units issued and outstanding, all of which are common units.
Distributions and Income Computations.
The Trust is required to make quarterly cash distributions to unitholders from its available funds for such calendar quarter. Royalty Interest payments due to the Trust with respect to any calendar quarter are based on actual sales volumes attributable to the Trust's interests in the Underlying Properties (as measured at Chesapeake's metering systems) for the first two months of the quarter just ended as well as the last month of the immediately preceding quarter and actual revenues received for such volumes. Chesapeake makes the Royalty Interest payments to the Trust within 35 days of the end of each calendar quarter. Taking into account the receipt and disbursement of all such amounts, the Trustee determines for such calendar quarter the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust over the Trust's expenses for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities.
The Trustee distributes cash approximately 60 days (or the next succeeding business day following such day if such day is not a business day) following each calendar quarter to each person who is a Trust unitholder of record on the quarterly record date together with interest expected to be earned on the amount of such quarterly distribution from the date of receipt thereof by the Trustee to the payment date.
Unless otherwise advised by counsel or the IRS, the Trustee treats the income and expenses of the Trust for each quarter as belonging to the Trust unitholders of record on the quarterly record date that occurs in such quarter. Trust unitholders recognize income and expenses for tax purposes in the quarter the Trust receives or pays those amounts, rather than in the quarter the Trust distributes them. Minor variances may occur. For example, the Trustee could establish a reserve in one quarter that would not result in a tax deduction until a later quarter. The Trustee could also make a payment in one quarter that would be amortized for tax purposes over several months.
Transfer of Trust Units.
Trust unitholders may transfer their Trust units in accordance with the Trust Agreement. The Trustee does not require either the transferor or transferee to pay a service charge for any transfer of a Trust unit. The Trustee may require payment of any tax or other governmental charge imposed for a transfer. The Trustee may treat the owner of any Trust unit as shown by its records as the owner of the Trust unit. The Trustee will not be considered to know about any claim or demand on a Trust unit by any party except the record owner. A person who acquires a Trust unit after any quarterly record date will not be entitled to the distribution relating to that quarterly record date. Delaware law will govern all matters affecting the title, ownership or transfer of Trust units.
Periodic Reports.
The Trustee files all required Trust federal and state income tax and information returns. The Trustee prepares and mails to Trust unitholders a Schedule K-1 and also causes to be prepared and filed reports required to be filed under the Exchange Act, and by the rules of the New York Stock Exchange.
Each Trust unitholder and his representatives have the right, at his own expense and during reasonable business hours upon reasonable prior notice, to examine and inspect the records of the Trust and the Trustee in reference thereto for any purpose reasonably related to the Trust unitholder's interest as a Trust unitholder.
Liability of Trust Unitholders.
Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.
Voting Rights of Trust Unitholders.
The Trustee or Trust unitholders owning at least 10% of the outstanding Trust units may call meetings of Trust unitholders. The Trust does not intend to hold annual meetings of the Trust unitholders. The Trust is responsible for all costs associated with calling a meeting of Trust unitholders unless such meeting is called by the Trust unitholders, in which case the Trust unitholders are responsible for all costs associated with calling such meeting of Trust unitholders. Meetings must be held in such location as is designated by the Trustee in the notice of such meeting. The Trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the Trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of Trust units outstanding must be present or represented to have a quorum. Each Trust unitholder is entitled to one vote for each Trust unit owned. Abstentions and broker non-votes shall not be deemed to be a vote cast.
Unless otherwise required by the Trust Agreement, a matter may be approved or disapproved by the vote of a majority of the Trust units held by the Trust unitholders voting in person or by proxy at a meeting where there is a quorum. Accordingly, a matter may be approved even if a majority of the total outstanding Trust units does not approve it.
Until such time as Chesapeake and its affiliates own less than 10% of the outstanding Trust units, the affirmative vote of the holders of a majority of common units (excluding common units owned by Chesapeake and its affiliates) and a majority of Trust units voting in person or by proxy at a meeting of such holders at which a quorum is present is required to:
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dissolve the Trust (except in accordance with its terms);
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remove the Trustee or the Delaware Trustee;
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amend the Trust Agreement, the royalty conveyances, the administrative services agreement and the development agreement (except with respect to certain matters that do not adversely affect the rights of Trust unitholders in any material respect);
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merge, consolidate or convert the Trust with or into another entity; or
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approve the sale of all or any material part of the assets of the Trust.
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At any time when Chesapeake and its affiliates own less than 10% of the outstanding Trust units, the vote of the holders of a majority of Trust units, including units owned by Chesapeake, voting in person or by proxy at a meeting of such holders at which a quorum is present will be required to take the actions described above.
Certain amendments to the Trust Agreement may be made by the Trustee without approval of the Trust unitholders. The Trustee must consent before all or any part of the Trust assets can be sold except in connection with the dissolution of the Trust or limited sales directed by Chesapeake in conjunction with its sale of Underlying Properties.
Description of the Trust Agreement.
The Trust was created under Delaware law as a separate legal entity to acquire and hold the Royalty Interests for the benefit of the Trust unitholders pursuant to the Trust Agreement among Chesapeake, the Trustee and the Delaware Trustee. The Royalty 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. Neither Chesapeake nor other operators of the Underlying Properties have any contractual commitments to the Trust to provide additional funding for, to conduct further drilling on or to maintain their ownership interest in any of these properties other than the obligations of Chesapeake to drill the Development Wells.
The Trust Agreement provides that the Trust's business activities are generally limited to owning the Royalty Interests and any activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the Royalty Interests. As a result, the Trust is not generally permitted to acquire other oil, natural gas and NGL properties or royalty interests. The Trust is not able to issue any additional Trust units.
Contractual Rights and Assets of the Trust.
Contractual rights of the Trust include those contained in the development agreement and the administrative services agreement. The assets of the Trust consist of the Royalty Interests and any cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the Trust unitholders.
Duties and Powers of the Trustee.
The duties and powers of the Trustee are specified in the Trust Agreement and by the laws of the State of Delaware, except as modified by the Trust Agreement. The Trust Agreement provides that the Trustee shall not have any duties or liabilities, including fiduciary duties, except as expressly set forth in the Trust Agreement and the duties and liabilities of the Trustee as set forth in the Trust Agreement replace any other duties and liabilities, including fiduciary duties, to which the Trustee might otherwise be subject.
The Trustee's principal duties consist of:
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collecting cash proceeds attributable to the Royalty Interests;
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paying expenses, charges and obligations of the Trust from the Trust's assets;
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determining whether cash distributions exceed subordination or incentive thresholds, and making cash distributions to the unitholders and Chesapeake (with respect to incentive distributions) in accordance with the Trust Agreement;
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causing to be prepared and distributed a Schedule K-1 for each Trust unitholder and preparing and filing tax returns on behalf of the Trust; and
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causing to be prepared and filed reports required to be filed under the Exchange Act, and by the rules of any securities exchange or quotation system on which the Trust units are listed or admitted to trading.
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Chesapeake will provide administrative and other services to the Trust in fulfillment of certain of the foregoing duties pursuant to the administrative services agreement.
The Trustee may create a cash reserve to pay for future expenses of the Trust. If the Trustee determines that the cash on hand and the cash to be received are insufficient to cover the Trust's expenses, the Trustee may cause the Trust to borrow funds required to pay the expenses. The Trust may borrow the funds from any person, including the
Trustee or its affiliates or, as described below, Chesapeake. The terms of such indebtedness, if funds were loaned by the entity serving as Trustee or Delaware Trustee, must be similar to the terms which such entity would grant to a similarly situated, unaffiliated commercial customer, and such entity shall be entitled to enforce its rights with respect to any such indebtedness as if it were not then serving as Trustee or Delaware Trustee. If the Trust borrows funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid (except in certain circumstances, where the Trust borrows funds from Chesapeake).
Each quarter, the Trustee will pay Trust obligations and expenses and distribute to the Trust unitholders the remaining proceeds received from the Royalty Interests. The cash held by the Trustee as a reserve against future liabilities must be invested in:
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interest-bearing obligations of the U.S. government;
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money market funds that invest only in U.S. government securities;
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repurchase agreements secured by interest-bearing obligations of the U.S. government; or
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bank certificates of deposit.
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Alternatively, cash held for distribution at the next distribution date may be held in a non-interest bearing account.
The Trustee withheld approximately $1.0 million from the first distribution to establish an initial cash reserve available for Trust expenses. If the Trustee uses its cash reserve (or any portion thereof) to pay or reimburse Trust liabilities or expenses, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until the cash reserve is replenished. Additional cash reserves may also be established from time to time as determined by the Trustee to pay for future expenses of the Trust. This cash reserve will be part of the Trust estate and will bear interest at the same rate as other cash on hand in the Trust estate. Upon the dissolution of the Trust, after payment of Trust liabilities, the balance of the cash reserve (including accrued interest thereon) will be distributed to Trust unitholders on a pro rata basis.
The Trust may not acquire any asset except the Royalty Interests, the other assets described above under
Contractual Rights and Assets of the Trust
and cash and temporary cash investments, and it may not engage in any investment activity except investing cash on hand.
The Trust Agreement provides that the Trustee will not make business decisions affecting the assets of the Trust. However, the Trustee may:
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prosecute or defend, and settle, claims of or against the Trust or its agents;
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retain professionals and other third parties to provide services to the Trust;
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charge for its services as Trustee;
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retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the Trustee to the extent permitted by law);
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lend funds at commercial rates to the Trust to pay the Trust's expenses; and
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seek reimbursement from the Trust for its out-of-pocket expenses.
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In discharging its duty to Trust unitholders, the Trustee may act in its discretion and will be liable to the Trust unitholders only for willful misconduct, bad faith or gross negligence, and certain taxes, fees and other charges based on fees, commissions or compensation received by the Trustee in connection with the transactions contemplated by the Trust Agreement. The Trustee is not liable for any act or omission of its agents or employees unless the Trustee acts with willful misconduct, bad faith or gross negligence in its selection and retention. The Trustee will be indemnified individually or as the Trustee for any liability or cost that it incurs in the administration of the Trust, except in cases of willful misconduct, bad faith or gross negligence. The Trustee has a lien on the assets of the Trust as security for this indemnification and its compensation earned as Trustee. Trust unitholders are not liable to the Trustee for any indemnification. The Trustee is obligated to ensure that all contractual liabilities of the Trust are limited to the assets of the Trust.
The Trust may merge or consolidate with or into, or convert into, one or more limited partnerships, general partnerships, corporations, business trusts, limited liability companies, or associations or unincorporated businesses if such transaction is agreed to by the Trustee and approved by the vote of the holders of a majority of the Trust units
and a majority of the common units (excluding common units owned by Chesapeake and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present and such transaction is permitted under the Delaware Statutory Trust Act and any other applicable law. At any time that Chesapeake and its affiliates collectively own less than 10% of the outstanding Trust units, however, the standard for approval will be the vote of a majority of the Trust units, including units owned by Chesapeake voting in person or by proxy at a meeting of such holders at which a quorum is present.
Trustee's Power to Sell Trust Assets.
The Trustee may sell Trust assets, including the Royalty Interests, under any of the following circumstances:
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the sale is requested by Chesapeake, following the satisfaction of its drilling obligation, in accordance with the provisions of the Trust Agreement; or
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the sale is approved by the vote of holders representing a majority of the Trust units and a majority of the common units (excluding common units owned by Chesapeake and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at any time that Chesapeake and its affiliates collectively own less than 10% of the outstanding Trust units, the standard for approval will be the vote of a majority of the Trust units, including units owned by Chesapeake voting in person or by proxy at a meeting of such holders at which a quorum is present.
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Upon dissolution of the Trust, the Trustee must sell the remaining Royalty Interests. No Trust unitholder approval is required in this event.
The Trustee will distribute the net proceeds from any sale of the Royalty Interests and other assets to the Trust unitholders after payment or reasonable provision for payment of the liabilities of the Trust.
Dispute Resolution.
To the fullest extent permitted by law, any dispute, controversy or claim that may arise between Chesapeake and the Trustee relating to the Trust will be submitted to binding arbitration before a panel of three arbitrators.
Trust Fees and Expenses.
It is expected that the Trust will only incur liabilities for routine administrative expenses, such as legal, accounting, audit, tax advisory, engineering, printing and other administrative and out-of-pocket fees and expenses incurred by or at the direction of the Trustee or the Delaware Trustee, including tax return and Schedule K-1 preparation and mailing costs; independent auditor fees; and registrar and transfer agent fees. The Trust is also responsible for paying costs associated with annual and quarterly reports to unitholders. Moreover, the Trustee's and the Delaware Trustee's compensation, and the fee payable to Chesapeake pursuant to the administrative services agreement, are paid out of the Trust's assets.
Chesapeake's Obligation to Fund Trust Expenses in Certain Circumstances
. Chesapeake has agreed that, if at any time the Trust's cash on hand (including available cash reserves) is not sufficient to pay the Trust's ordinary course expenses as they become due, Chesapeake will lend funds to the Trust necessary to pay such expenses. Any funds loaned by Chesapeake pursuant to this commitment will be limited to the payment of current accounts payable or other obligations to trade creditors in connection with obtaining goods or services or 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 for borrowed money. If Chesapeake lends funds pursuant to this commitment, unless Chesapeake agrees otherwise, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until such loan is repaid. Any such loan 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 arms' length transaction between Chesapeake and an unaffiliated third party. There were no loans outstanding as of December 31, 2018 or December 31, 2017.
Duration of the Trust; Sale of Royalty Interests
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The Trust will dissolve and begin to liquidate on June 30, 2031, or earlier upon the occurrence of certain events, and will soon thereafter wind up its affairs and terminate. At the Termination Date, the Term Royalties will revert automatically to Chesapeake. Following the Termination Date, the Perpetual Royalties will be sold by the Trust and the net proceeds of the sale, as well as any remaining Trust cash reserves, will be distributed to the unitholders pro rata. Chesapeake will have a right of first refusal to purchase the Perpetual Royalties from the Trust following the Termination Date.
The Trust will not dissolve until the Termination Date, unless:
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the Trust sells all of the Royalty Interests;
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cash available for distribution is less than $1.0 million for any four consecutive quarters;
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the holders of a majority of the Trust units and a majority of the common units (excluding common units owned by Chesapeake and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present vote in favor of dissolution; except that at any time that Chesapeake and its affiliates collectively own less than 10% of the outstanding Trust units, the standard for approval will be a majority of the Trust units, including units owned by Chesapeake voting in person or by proxy at a meeting of such holders at which a quorum is present; or
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the Trust is judicially dissolved.
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In the case of any of the foregoing, the Trustee would sell all of the Trust's assets, either by private sale or public auction, and distribute the net proceeds of the sale to the Trust unitholders after payment, or reasonable provision for payment, of all Trust liabilities.
Federal Income Tax Considerations
The Trust's federal income tax reporting position is that it is classified as a partnership for federal and applicable state income tax purposes. This position relies on the opinion of Bracewell & Giuliani L.L.P., former counsel to Chesapeake and the Trust, rendered in connection with the initial public offering of the Trust units, in which counsel opined that at least 90% of the Trust's gross income is qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended. The Trust's federal income tax reporting positions are consistent with the Federal Income Tax Considerations section in the prospectus filed by the Trust with the SEC on November 14, 2011, in connection with the initial public offering of its common units (the “Federal Income Tax Considerations Section in the Prospectus”). However, as discussed in detail below under Item 1A.
Risk Factors – Tax Risks Related to the Units
, the Trust has not requested a ruling from the IRS regarding its U.S. federal income tax reporting positions and its positions may not be sustained by a court or if contested by the IRS.
Additional information regarding the opinion and material tax matters is discussed in the Federal Income Tax Considerations Section in the Prospectus.
Competition and Markets
The oil and natural gas industry is highly competitive. Chesapeake competes with both major integrated and other independent oil and natural gas companies in all aspects of its business to explore, develop and operate its properties and market its production. Some of Chesapeake's competitors may have larger financial and other resources than Chesapeake. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of Chesapeake's competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities, and overall economic conditions. Chesapeake also faces indirect competition from alternative energy sources, including wind, solar and electric power. Chesapeake believes that its technological expertise, combined with its exploration, land, drilling and production capabilities and the experience of its management team enable it to compete effectively.
Recent volatility in oil, natural gas and NGL prices has impacted, and will continue to directly impact, Trust distributions, estimates of reserves attributable to the Trust's interest, and estimated and actual future net revenues to the Trust. In view of the many uncertainties that affect the supply and demand for oil, natural gas and NGL, neither the Trust nor Chesapeake can make reliable predictions of future supply and demand for oil, natural gas and NGL, future oil, natural gas and NGL prices or the effect of future oil, natural gas and NGL prices on the Trust.
Public Policy and Government Regulation
All of Chesapeake's operations are conducted onshore in the United States. The U.S. oil and natural gas industry is regulated at the federal, state and local levels, and some of the laws and regulations that govern its operations carry substantial administrative, civil and criminal penalties for non-compliance. Although Chesapeake has advised the Trustee that Chesapeake believes it is in material compliance with all applicable laws and regulations, and that the cost of compliance with existing requirements will not have a material adverse effect on its financial position, cash flows or results of operations, such laws and regulations could be, and frequently are, amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, Chesapeake is unable to predict the future costs or impact of compliance or non-compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, local governments, the courts and federal agencies, such as the U.S. Environmental Protection Agency (EPA), the Federal Energy Regulatory Commission (FERC), the Department of Transportation (DOT), the Department of Interior (DOI) and the U.S. Army Corps of Engineers (USACE). Chesapeake has advised the Trustee that Chesapeake actively monitors regulatory developments applicable to the industry in order to anticipate, design and implement required compliance activities and systems.
Regulation – Environment, Health and Safety
Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations
Chesapeake's operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:
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reporting of workplace injuries and illnesses;
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industrial hygiene monitoring;
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•
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worker protection and workplace safety;
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•
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approval or permits to drill and to conduct operations;
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•
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provision of financial assurances (such as bonds) covering drilling and well operations;
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calculation and disbursement of royalty payments and production taxes;
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seismic operations and data;
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location, drilling, cementing and casing of wells;
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well design and construction of pad and equipment;
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construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;
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method of completing wells;
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well production and operations, including processing and gathering systems;
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emergency response, contingency plans and spill prevention plans;
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air emissions and fluid discharges;
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use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
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surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;
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plugging and abandoning of wells; and
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transportation of production.
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Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, fines, or criminal penalties or to injunctions limiting Chesapeake's operations in affected areas. Moreover, multiple environmental laws
provide for citizen suits that allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. Chesapeake considers the costs of environmental protection and of safety and health compliance to be necessary, manageable parts of its business. Chesapeake has been able to plan for and comply with environmental, safety and health laws and regulations without materially altering its operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, Chesapeake's capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase. Chesapeake cannot predict with any reasonable degree of certainty its future exposure concerning such matters. See the
Risk Factors
described in Item 1A of this report for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters,
Chesapeake's operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration. Other states rely on voluntary pooling of lands and leases which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas Chesapeake can produce from its wells and the number of wells or the locations at which it can drill.
Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could reduce the amount of oil, natural gas and NGL that Chesapeake is ultimately able to produce in commercial quantities from its properties.
Certain of Chesapeake's U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands are subject to frequent delays.
Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit Chesapeake's ability to execute its drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of Chesapeake's permits, inability to obtain new permits and the imposition of fines and penalties.
Operating Hazards and Insurance
The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, Chesapeake could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Chesapeake's horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.
As a passive entity, the Trust does not maintain insurance policies for the Underlying Properties. Chesapeake maintains a control of well insurance policy with a $50 million single well limit and a $100 million multiple wells limit that insures against certain sudden and accidental risks associated with drilling, completing and operating its wells. There is no assurance that this insurance will be adequate to cover all losses or exposure to liability. Chesapeake also carries a $250 million comprehensive general liability umbrella insurance policy and a $75 million pollution liability insurance policy. Chesapeake provides workers' compensation insurance coverage to employees in all states in which it operates. While Chesapeake has informed us that it believes these policies are customary in the industry, they do not provide complete coverage against all operating risks and policy limits scale to Chesapeake's working interest
percentage in certain situations. In addition, Chesapeake's insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on Chesapeake's financial position, results of operations and cash flows. Chesapeake's insurance coverage may not be sufficient to cover every claim made against Chesapeake or may not be commercially available for purchase in the future.
The Underlying Properties and the Royalty Interests
Overview
. The Underlying Properties consist of working interests owned by Chesapeake located in the Colony Granite Wash play in Washita County in western Oklahoma arising from leases and farmout agreements related to properties from which the Royalty Interests were conveyed. The AMI consists of approximately
40,500
gross acres (
26,400
net acres). As of
December 31, 2018
and 2017, the total reserves estimated to be attributable to the Trust were
5,075
mboe (
57%
natural gas by volume) and 5,938 mboe (55% natural gas by volume), respectively. These amounts include
5,075
mboe of proved developed reserves and no proved undeveloped reserves as of
December 31, 2018
and 5,938 mboe of proved developed reserves and no proved undeveloped reserves as of
December 31, 2017
. The decrease in estimated total reserves attributable to the Trust of 893 mboe is primarily attributable to 2018 production, partially offset by higher oil and gas prices. See Risk Factors –
Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the valu
e
of the Trust units
in Item 1A and
Risks and Uncertainties
in Note 2 to the financial statements contained in Part II, Item 8 of this Annual Report for further discussion of the decrease in reserves.
The Colony Granite Wash is a subset of the greater granite wash plays of the Anadarko Basin. The Colony Granite Wash is located at the eastern end of a series of Des Moines-age granite wash fields that extend along the southern flank of the Anadarko Basin, approximately 60 miles into the Texas Panhandle. These granite wash fields were generally deposited as deep-water turbidites that result in relatively low risk, laterally extensive reservoirs. The productive members of the Colony Granite Wash are encountered between approximately 11,500 and 13,000 feet and lie stratigraphically between the top of the Des Moines formation (or top of Colony Granite Wash 'A') and the top of the Prue formation (or base of Colony Granite Wash 'C'). The individual productive members within the Colony Granite Wash may reach 200 feet or more in gross interval thickness and the targeted porosity zones within these individual members are generally 20 to 75 feet thick. The Colony Granite Wash is primarily a natural gas and natural gas condensate reservoir based on reserve volumes. However, in the Colony Granite Wash, oil and NGL production currently generate more revenue than natural gas production due to higher relative prices for oil and NGL than for natural gas. No development costs were incurred in the year ended December 31, 2018 and 2017 due to no new wells being drilled by Chesapeake in the Colony Granite Wash after Chesapeake's fulfillment of its drilling obligation to the Trust.
Royalty Interests.
The Royalty Interests were conveyed from Chesapeake's interest in the Underlying Properties effective as of July 1, 2011. As of
December 31, 2018
, the Trust on average owns a 47.6% net revenue interest in the Producing Wells and a 28.4% net revenue interest in the completed Development Wells. Chesapeake retains 10% of the proceeds from the sales of oil, natural gas and NGL production attributable to its net revenue interest in the Producing Wells, and 50% of the proceeds from the sales of production attributable to its net revenue interest in the Development Wells.
The Royalty Interests were conveyed to the Trust by Chesapeake by means of conveyance instruments that were recorded in the appropriate real property records in Washita County
,
Oklahoma. The conveyance instruments obligate Chesapeake to act diligently and as a reasonably prudent oil and gas operator would act under the same or similar circumstances as if it were acting with respect to its own properties, disregarding the existence of the Royalty Interests as burdens affecting such properties. We refer to this standard as the "Reasonably Prudent Operator Standard." The Trustee has no ability to manage or influence the operation of the Underlying Properties.
Oil, Natural Gas and NGL Reserves.
Proved reserve quantities attributable to the Royalty Interests are calculated by multiplying the gross reserves for each property attributable to Chesapeake's interest by the net revenue interest assigned to the Trust in each property. The reserves related to the Underlying Properties include all proved reserves expected to be economically produced during the life of the properties. The reserves attributable to the Trust's interests include only the reserves attributable to the Underlying Properties that are expected to be produced within the 20-year period prior to the Termination Date as well as the residual 50% interest in the Royalty Interests that the Trust will own on the Termination Date and subsequently sell.
All of the Trust's estimated oil, natural gas and NGL reserves are located within the U.S. The table below sets forth information as of
December 31, 2018
with respect to the estimated proved reserves of the Underlying Properties and Royalty Interests and the associated PV-10. Because the Trust will not bear income tax expense, PV-10 and the standardized measure of estimated future net revenue of the Royalty Interests are the same. PV-10 is not intended to represent the current market value of the estimated oil, natural gas and NGL reserves attributable to the Royalty Interests. The reserve estimates were prepared by Software Integrated Solutions, Division of Schlumberger Technology Corporation, in accordance with the criteria established by the SEC. Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP.
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Proved Reserves
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Oil
(mbbl)
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Natural Gas
(mmcf)
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NGL
(mbbl)
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Total
(mboe)
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PV-10 ($ in thousands)
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Underlying Properties:
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Developed
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1,087
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36,913
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|
3,658
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|
10,897
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$
|
50,907
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Undeveloped
|
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—
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—
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—
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—
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—
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Total
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1,087
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36,913
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3,658
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10,897
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$
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50,907
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Royalty Interests:
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Developed
(1)
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511
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17,261
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1,687
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5,075
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$
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42,319
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Undeveloped
(1)
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—
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—
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—
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—
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—
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Total
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511
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17,261
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1,687
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5,075
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$
|
42,319
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_________________________________________________
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(1)
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PV-10 for the Royalty Interests was calculated exclusive of any production or development costs.
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Proved
Developed
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Proved
Undeveloped
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Total
Proved
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($ in millions)
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Estimated future net revenue
(a)
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$
|
72,621
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|
$
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—
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|
$
|
72,621
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|
Present value of estimated future net revenue (PV-10)
(a)
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$
|
42,319
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|
$
|
—
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|
|
$
|
42,319
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|
Standardized measure
(a)
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|
$
|
42,319
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|
_________________________________________________
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(a)
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Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and costs, using prices and costs under existing economic conditions as of
December 31, 2018
. PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted at 10% per annum to reflect timing of future cash flows and calculated without deducting future income taxes. PV-10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted net cash flows, or the Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. However, as the Trust is not subject to income tax expense, the two measures are the same as of
December 31, 2018
.
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A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of the proved oil and gas reserves.
The proved reserves were determined using a 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil, natural gas and NGL for the period from January 1, 2018 through December 1, 2018, and were held constant for the life of the properties. The prices used in the reserve reports, as well as Chesapeake's internal reports, yield weighted average prices at the wellhead, which are based on first-day-of-the-month reference prices and adjusted for transportation and regional price differentials. For the Royalty Interests, costs of marketing services provided by Chesapeake's affiliates will not be charged to the Trust. The reference prices and the equivalent weighted average wellhead prices are presented in the table below.
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Oil
|
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Natural Gas
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NGL
|
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(per bbl)
|
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(per mcf)
|
|
(per bbl)
|
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Trailing 12-month average (SEC) pricing
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$
|
65.56
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|
|
|
3.10
|
|
|
|
65.56
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Weighted average wellhead prices (Underlying Properties)
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|
$
|
61.61
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|
|
|
0.69
|
|
|
|
20.62
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Weighted average wellhead prices (Royalty Interests)
|
|
$
|
61.61
|
|
|
|
0.69
|
|
|
|
20.62
|
|
As of
December 31, 2018
, no Royalty Interests were classified as PUDs.
The annual net decline rate on current producing properties is projected to be 15% from 2019 to 2020, 13% from 2020 to 2021, 12% from 2021 to 2022 and 11% from 2022 to 2023. As of
December 31, 2018
, of the total proved reserves,
10,897
mboe and
5,075
mboe attributable to the Underlying Properties and the Royalty Interests, respectively, were classified as proved developed reserves.
Chesapeake's ownership interest used for calculating proved reserves and the associated estimated future net revenue assumed maximum participation by other parties to Chesapeake's farmout and participation agreements. SEC pricing used for calculating the estimated future net revenues attributable to proved reserves does not reflect actual market prices for oil, natural gas and NGL production sold subsequent to
December 31, 2018
.
The Trust's estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at
December 31, 2018
and 2017, respectively, along with the changes in quantities and standardized measure of such reserves for the two years ended
December 31, 2018
and 2017, respectively, are shown in
Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities
included in Item 8 of Part II of this Annual Report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond Chesapeake's control. The reserve data represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions to such estimates, and such revisions may be material. Accordingly, reserve estimates are often different from the actual quantities of oil, natural gas and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. See Supplemental Disclosures about Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report for further discussion of our reserve quantities.
Development Wells.
Pursuant to the development agreement with the Trust, Chesapeake was obligated to drill, cause to be drilled or participate as a non-operator in the drilling of 118 Development Wells by June 30, 2016. Chesapeake had fulfilled its drilling obligation under the development agreement as of June 30, 2016. Chesapeake has retained an interest in each of the Producing Wells and Development Wells and currently operates approximately
96%
of the Producing Wells and completed Development Wells. Prior to fulfilling its commitment to drill the Development Wells, Chesapeake was not allowed to drill or complete, or permit any other person within its control to drill or complete any well in the Colony Granite Wash formation or lease acreage included within the AMI for its own account. For the life of the Trust, Chesapeake will not be permitted to drill or complete any well that will have a perforated segment within 600 feet of any perforated interval of any Development Well or Producing Well. Chesapeake's average net
revenue interest in the oil and gas properties underlying the Development Royalty Interest is approximately 63%. The Development Royalty Interest entitles the Trust to receive 50% of the proceeds attributable to Chesapeake's net revenue interest in future production of oil, natural gas and NGL from the Development Wells.
The Trust was not responsible for any costs related to the drilling of the Development Wells and is not responsible for any other operating or capital costs of the Underlying Properties.
Chesapeake granted to the Trust a lien on its interest in the AMI (except the Producing Wells and any other wells that were already producing as of July 1, 2011 and are not subject to the Royalty Interests) in order to secure the estimated amount of the drilling costs for the Trust's interests in the Development Wells (the "Drilling Support Lien"). The Trust did not obtain any amounts from Chesapeake under the Drilling Support Lien during the period in which Chesapeake was drilling the Development Wells, and the Drilling Support Lien has been reduced to zero.
Due to Chesapeake's completion of its drilling obligation under the development agreement, it may now sell all or any part of its retained interest in the Underlying Properties, without the consent or approval of the Trust unitholders. In any such sale by Chesapeake, the Underlying Properties must be sold subject to and burdened by the Royalty Interests, except that Chesapeake may require the Trust to release the Royalty Interests on such Underlying Properties with an aggregate value of up to $5.0 million during any 12-month period. In such event, the Trust must receive an amount equal to the fair value to the Trust of any royalty interests it sells.
Drilling Activity
. The following table sets forth information with respect to the wells Chesapeake drilled or participated in during the periods indicated that were located in the AMI. The information presented is not necessarily indicative of future performance and should not be interpreted to present any correlation between the number of productive wells drilled and quantities or economic value of reserves found. Gross wells are the total number of producing wells in which Chesapeake has a working interest and net wells are the sum of Chesapeake's fractional working interest owned in such gross wells.
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2018
|
|
2017
|
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Wells Drilled:
|
|
|
|
|
|
|
|
|
|
Development productive
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Exploratory productive
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Dry
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Developed and Undeveloped Acreage
. The following table sets forth information regarding developed and undeveloped acreage held by Chesapeake within the AMI as of
December 31, 2018
. All of the leases associated with the Underlying Properties are held by production and not subject to expiration so long as production continues in paying quantities.
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|
|
|
|
|
|
|
|
|
|
|
Developed
Acreage
(1)
|
|
Undeveloped
Acreage
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Acreage Held by Chesapeake within the AMI
|
40,236
|
|
26,195
|
|
—
|
|
—
|
_________________________________________________
|
|
|
|
(1)
|
Gross and net developed acres are acres spaced or assignable to productive wells. The drilling unit for each Colony Granite Wash horizontal well comprises 640 acres. As such, developed acreage may include up to 640 acres assigned to each Colony Granite Wash horizontal well.
|
Marketing and Post-Production Services.
Pursuant to the terms of the conveyances creating the Royalty Interests, Chesapeake has the responsibility to market, or cause to be marketed, the oil, natural gas and NGL production related to the Underlying Properties. While marketing costs of non-affiliates of Chesapeake are deducted from the proceeds upon which the royalty payments are calculated, the Trust is not responsible for costs of marketing services provided by Chesapeake or any of its affiliates. Chesapeake Energy Marketing, L.L.C. ("CEMLLC"), a wholly owned subsidiary of Chesapeake, markets the majority of Chesapeake's operated production. CEMLLC enters into oil, natural gas and NGL sales arrangements with large aggregators of supply, and these arrangements may be on a month-to-month basis or for a term of up to one year or longer
.
The oil, natural gas and NGL are sold at market prices and subsequently
any applicable post-production expenses will be deducted. CEMLLC sells production from the Underlying Properties to a diverse group of aggregators, the identity of which changes from time to time. As a result, the proceeds to the Trust from the sales of oil, natural gas and NGL production from the Underlying Properties is determined based on the same price (net of post-production costs and production taxes) that Chesapeake receives from third parties for oil, natural gas and NGL production attributable to Chesapeake's remaining interest in the Underlying Properties.
Post-production expenses are deducted from proceeds paid to the Trust. Williams Partners, L.P. ("WMB"), provides gathering, treating, compression and other post-production services and Enable Midstream Partners, LP ("Enable") provides gathering, processing, transportation and other post-production services. The proceeds paid to the Trust are reduced by deductions for these post-production expenses.
Post-production expenses may be deducted by the ultimate purchaser of the oil, natural gas and NGL prior to payment being made to Chesapeake or CEMLLC for such production. At other times, Chesapeake or CEMLLC makes payments directly to the applicable provider of such post-production services. In either instance, the Trust's cash available for distribution is reduced by the expenses incurred by Chesapeake or CEMLLC for such post-production services. If the post-production expenses are expressed as a percentage of the gross production from a well, then the volume of production from that well actually available for sale is less the applicable percentage charged, and as a result the reserves associated with that well that are attributable to the Royalty Interest are reduced accordingly
.
The post-production expenses are negotiated based on market conditions at the time or pursuant to a state or federal regulatory proceeding. Chesapeake is permitted to deduct from the proceeds available to the Trust other post-production expenses necessary to enhance the value of the oil, natural gas and NGL from the Underlying Properties and to transport such production to market.
Natural gas and NGL produced from the Underlying Properties are gathered by gathering pipelines owned by WMB under a contract that expires in approximately 10 years. NGL and natural gas are gathered and processed at facilities owned by Enable under a contract that expires in 2023 and then sold to a number of primary purchasers in the area. Oil produced from the Underlying Properties is gathered by gathering pipelines and equipment owned by WMB or transported by trucks owned by third parties and sold to various counterparties. In the event of a loss of its contracts with WMB or Enable, Chesapeake believes that the availability of other customers and service providers in the area is sufficient to accommodate such loss.
Any new oil, natural gas and NGL supply arrangements or those entered into for providing post-production services will be utilized in determining the proceeds for the Underlying Properties.
Discussion and Analysis of Results from the Underlying Properties
Historical Results
. The Underlying Properties consist of the working interests owned by Chesapeake in the Colony Granite Wash in Washita County in western Oklahoma arising under leases and farmout agreements related to properties from which the PDP Royalty Interest and the Development Royalty Interest were conveyed.
The following table provides revenues and direct operating expenses for the years ended
December 31, 2018
, and 2017, as derived from the Underlying Properties' statements of revenues and direct operating expenses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2018
|
|
2017
|
|
|
|
($ in thousands)
|
|
Oil, natural gas and NGL revenues
(1)
|
|
$
|
20,792
|
|
|
$
|
25,057
|
|
|
Direct operating expenses:
|
|
|
|
|
|
Production expenses excluding taxes
|
|
7,670
|
|
|
7,616
|
|
|
Production taxes
|
|
1,538
|
|
|
1,248
|
|
|
Ad valorem taxes
|
|
4
|
|
|
4
|
|
|
Total direct operating expenses
|
|
9,212
|
|
|
8,868
|
|
|
Revenues in excess of direct operating expenses
|
|
$
|
11,580
|
|
|
$
|
16,189
|
|
_________________________________________________
|
|
|
|
(1)
|
Oil, natural gas and NGL revenues are net of post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and non-affiliate marketing expenses.
|
The following table sets forth the production, average sales prices, and average cost per boe for production expenses and production taxes for the Underlying Properties for the years ended
December 31, 2018
, and 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2018
|
|
2017
|
|
Production:
|
|
|
|
|
|
Oil (mbbls)
|
|
181
|
|
|
227
|
|
|
Natural gas (mmcf)
|
|
4,613
|
|
|
5,609
|
|
|
NGL (mbbls)
|
|
413
|
|
|
600
|
|
|
Total production (mboe)
|
|
1,363
|
|
|
1,762
|
|
|
|
|
|
|
|
|
Average sales prices:
(1)
|
|
|
|
|
|
Oil (per bbl)
|
|
$
|
60.32
|
|
|
$
|
42.80
|
|
|
Natural gas (per mcf)
|
|
$
|
0.62
|
|
|
$
|
0.46
|
|
|
NGL (per bbl)
|
|
$
|
16.91
|
|
|
$
|
21.22
|
|
|
Average (per boe)
|
|
$
|
15.25
|
|
|
$
|
14.22
|
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
Production expenses (per boe)
(2)
|
|
$
|
5.63
|
|
|
$
|
4.32
|
|
|
Production taxes (per boe)
(3)
|
|
$
|
1.13
|
|
|
$
|
0.71
|
|
___________________________________________________
|
|
|
|
(1)
|
Average sales prices are net of post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and non-affiliate marketing expenses.
|
|
|
|
|
(2)
|
Production expenses include lease operating costs and ad valorem taxes.
|
|
|
|
|
(3)
|
Production taxes are generally based upon (a) volume produced and (b) prices received for production.
|
Oil, Natural Gas and NGL Revenues.
For the year ended
December 31, 2018
, oil, natural gas and NGL revenues were
$20.8 million
compared to
$25.1 million
for the year ended
2017
. The $4.3 million decrease in revenues from 2017 to 2018 was primarily due to a decrease in production. Decreased sales volumes resulted in a $5.7 million decrease in oil, natural gas and NGL revenues. Average oil prices increased $17.52 per bbl, from
$42.80
per bbl for the year ended December 31, 2017 to
$60.32
per bbl for the year ended
December 31, 2018
. Average natural gas prices increased $0.16 per mcf, from
$0.46
per mcf for the year ended December 31, 2017 to
$0.62
per mcf for the year ended
December 31, 2018
. NGL prices decreased $4.31 per bbl, from
$21.22
per bbl for the year ended December 31, 2017 to
$16.91
per bbl for the year ended
December 31, 2018
. The overall increase in the price received per boe in 2018 compared to 2017 resulted in a $1.4 million increase in oil, natural gas and NGL revenues, for a net decrease in oil, natural gas and NGL revenues of $4.3 million from 2017 to 2018.
Production Expenses.
For the year ended
December 31, 2018
, production expenses, excluding production and ad valorem taxes, were
$7.7 million
compared to $7.6 million for the year ended
2017
. On a unit-of-production basis, production expenses, excluding production taxes and including ad valorem taxes, were
$5.63
per boe in 2018 compared to $4.32 per boe in
2017
.
Production Taxes.
For the year ended
December 31, 2018
, production taxes were
$1.5 million
, compared to $1.2 million for the year ended
2017
. On a unit-of-production basis, production taxes were
$1.13
per boe in 2018 compared to $0.71 per boe in
2017
. The increase in production taxes from 2017 to 2018 is primarily due to the increase in commodity prices.
The Reserve Report for the Underlying Properties and the Royalty Interests
The oil, natural gas and NGL reserves in this Annual Report were estimated by Software Integrated Solutions, Division of Schlumberger Technology Corporation ("Software Integrated Solutions"). The process to review and estimate
the reserves begins with Chesapeake's Corporate Reserves Department collecting and verifying all pertinent data, including but not limited to well test data, production data, historical pricing, cost information, property ownership interests, reservoir data, and geosciences data. This data is reviewed by various levels of Chesapeake management for accuracy before consultation with Software Integrated Solutions. Software Integrated Solutions was consulted with regularity during the reserve estimation process to review properties, assumptions, and any new data available. Internal reserve estimates and methodologies are compared to Software Integrated Solutions' estimates and methodologies to test the reserve estimates and conclusions before the reserve estimates are included in this Annual Report. Additionally, Chesapeake's senior management reviews and approves the reserve report contained herein.
Internal Controls
. Chesapeake's Director - Corporate Reserves is the technical person primarily responsible for overseeing the preparation of the Trust's reserve estimates. Her qualifications include the following:
|
|
|
|
•
|
Over 15 years of practical experience in the oil and gas industry, with 12 years in reservoir engineering;
|
|
|
|
|
•
|
Bachelor of Science degree in Geology and Environmental Sciences;
|
|
|
|
|
•
|
Master's Degree in Petroleum and Natural Gas Engineering;
|
|
|
|
|
•
|
Member in good standing of the Society of Petroleum Engineers.
|
Chesapeake ensures that the key members of Chesapeake's Corporate Reserves Department have appropriate technical qualifications to oversee the preparation of reserves estimates. Each of Chesapeake's Corporate Reserves Engineers has significant experience in reserve estimation. Each of its engineering technicians has a minimum of a four-year degree in mathematics, economics, finance or other technical/business/science field. Chesapeake also maintains a continuous education program for its engineers and technicians on new technologies and industry advancements and offers refresher training on basic skills and analytical techniques.
Chesapeake maintains internal controls such as the following to ensure the reliability of reserves estimations:
|
|
|
|
•
|
Chesapeake follows comprehensive SEC-compliant internal policies to estimate and report proved reserves. Reserves estimates are made by experienced reservoir engineers or under their direct supervision. All material changes are reviewed and approved by Chesapeake's Corporate Reserve Engineers.
|
|
|
|
|
•
|
Chesapeake's Corporate Reserves Department reviews all of Chesapeake's and the Trust's proved reserves at the close of each quarter.
|
|
|
|
|
•
|
Each quarter, Chesapeake's Reservoir Managers, the Director - Corporate Reserves, the Vice Presidents of its business units, the Vice President of Corporate and Strategic Planning and the Executive Vice President - Exploration and Production review all significant reserves changes and all new proved undeveloped reserves additions.
|
|
|
|
|
•
|
Chesapeake's Corporate Reserves Department reports independently of Chesapeake's operations.
|
Technologies
. The reserve report was prepared using decline curve analysis to determine the reserves of individual Producing Wells, as defined by the SEC. After estimating the reserves of each proved developed well, it was determined that a reasonable level of certainty exists with respect to the reserves that can be expected from close offset undeveloped wells in the field. The continuity of the play across the AMI area was established by reviewing electronic well logs from wells, geologically mapping the analogous reservoir and reviewing extensive production data from horizontal wells within the larger Colony Granite Wash area.
Software Integrated Solutions
. Chesapeake engaged Software Integrated Solutions, a third-party engineering firm, to prepare all of the Trust's estimated proved reserves as of
December 31, 2018
. A copy of the report issued by the engineering firm is filed with this report as Exhibit 99.1. The qualifications of the technical person at the firm primarily responsible for overseeing the preparation of the Trust's reserve estimates are set forth below.
|
|
|
|
•
|
over 30 years of practical experience in the estimation and evaluation of reserves;
|
|
|
|
|
•
|
registered professional geologist licensed in the Commonwealth of Pennsylvania;
|
|
|
|
|
•
|
member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and
|
|
|
|
|
•
|
Bachelor of Science degree in Geological Sciences.
|
Miscellaneous
The Trustee may consult with counsel (which may include counsel to Chesapeake), accountants, tax advisors, geologists and engineers and other parties the Trustee believes to be qualified as experts on the matters for which advice is sought. The Trustee is protected for any action it takes in good faith reliance upon the opinion of the expert.
The Delaware Trustee and the Trustee may resign at any time or be removed with or without cause at any time by the vote of a majority of the outstanding Trust units (excluding common units owned by Chesapeake and its affiliates) voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at any time that Chesapeake and its affiliates collectively own less than 10% of the outstanding Trust units, the standard for approval will be the vote of a majority of the Trust units, including units owned by Chesapeake, voting in person or by proxy at a meeting of such holders at which a quorum is present. Abstentions and broker non-votes shall not be deemed to be votes cast. Any successor must be a bank or trust company meeting certain requirements, including having combined capital, surplus and undivided profits of at least $20 million, in the case of the Delaware Trustee, and $100 million, in the case of the Trustee.
Risks Related to the Units
Producing oil, natural gas and NGL on the Underlying Properties is a high-risk activity with many uncertainties. Any delays or reductions in production could decrease cash available for distribution to unitholders.
Producing oil, natural gas and NGL can be unprofitable if productive wells do not produce sufficient revenues to return a profit. Chesapeake's and third-party operators' decisions to develop or otherwise exploit certain areas within the AMI depended in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Production operations on the Underlying Properties may be curtailed, delayed or canceled as a result of various factors, including the following:
|
|
|
|
•
|
unusual or unexpected geological formations and miscalculations or irregularities in formations;
|
|
|
|
|
•
|
equipment malfunctions, failures or accidents;
|
|
|
|
|
•
|
lack of available gathering facilities or delays in construction of gathering facilities;
|
|
|
|
|
•
|
lack of available capacity on interconnecting transmission pipelines;
|
|
|
|
|
•
|
pipe or cement failures and casing collapses;
|
|
|
|
|
•
|
pressures, fires, blowouts and explosions;
|
|
|
|
|
•
|
lost or damaged service tools;
|
|
|
|
|
•
|
uncontrollable flows of oil, natural gas and NGL water or drilling fluids;
|
|
|
|
|
•
|
environmental hazards, such as oil, natural gas and NGL leaks, pipeline ruptures and discharges of toxic gases or fluids;
|
|
|
|
|
•
|
adverse weather conditions, such as extreme cold, fires caused by extreme heat or lack of rain and severe storms or tornadoes;
|
|
|
|
|
•
|
reductions in oil, natural gas and NGL prices; and
|
|
|
|
|
•
|
title problems affecting the Underlying Properties.
|
If the Producing Wells or Development Wells have lower than anticipated production due to one of the factors above or for any other reason, cash distributions to unitholders may be reduced.
Oil, natural gas and NGL prices fluctuate widely, and depressed prices for an extended period of time are likely to have a material adverse effect on proceeds to the Trust and cash distributions to unitholders.
The Trust's reserves and quarterly cash distributions depend primarily upon the prices realized from the sales of oil, natural gas and NGL. Chesapeake requires substantial expenditures to replace reserves, sustain production and fund its business plans. Low oil, natural gas and NGL prices can negatively affect the amount of cash available for capital expenditures and debt repayment and the ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on Chesapeake’s financial condition, results of operations, cash flows and reserves and the Trust’s reserves and quarterly cash distributions. Historically, the markets for oil, natural gas and NGL have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil, natural gas and NGL prices may result from relatively minor changes in the supply of or demand for oil, natural gas and NGL, market uncertainty and other factors that are beyond the control of the Trust and Chesapeake, including:
|
|
|
|
•
|
domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves;
|
|
|
|
|
•
|
changes in the level of consumer and industrial demand;
|
|
|
|
|
•
|
the price and availability of alternative fuels;
|
|
|
|
|
•
|
technological advances affecting energy consumption;
|
|
|
|
|
•
|
the effectiveness of worldwide conservation measures;
|
|
|
|
|
•
|
the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;
|
|
|
|
|
•
|
the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
|
|
|
|
|
•
|
U.S. exports of oil, natural gas and/or liquefied natural gas;
|
|
|
|
|
•
|
the price and level of foreign imports;
|
|
|
|
|
•
|
the nature and extent of domestic and foreign governmental regulations and taxes;
|
|
|
|
|
•
|
the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
|
|
|
|
|
•
|
political instability or armed conflict in oil and natural gas producing regions;
|
|
|
|
|
•
|
domestic and global economic conditions.
|
These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty.
Lower oil, natural gas and NGL prices have reduced, and could continue to reduce, proceeds to which the Trust is entitled and may ultimately reduce the amount of oil, natural gas and NGL that is economic to produce from the Underlying Properties. As a result, Chesapeake or any third-party operator of any of the Underlying Properties could determine during periods of low oil, natural gas and NGL prices to shut in or curtail production from wells on the Underlying Properties. In addition, the operator of the Underlying Properties could determine during periods of low oil, natural gas and NGL prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, Chesapeake or any third-party operator may abandon any well or property if it reasonably believes that the well or property can no longer produce oil, natural gas and NGL in commercially economic quantities. This could result in termination of the portion of the Royalty Interests relating to the abandoned well or property, and Chesapeake would have no obligation to drill a replacement well. The volatility of oil, natural gas and NGL prices also reduces the accuracy of target distributions used to calculate the subordination and incentive thresholds.
Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust units.
The value of the Trust units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things, the accuracy of the future production estimated to be attributable to the Royalty Interests. The future production estimates are based on estimates of reserve quantities for the Underlying Properties. Estimates of proved reserves and estimated future net revenues from proved reserves are based upon various assumptions, including assumptions required by the SEC relating to oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil, natural gas and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to further revisions.
Actual future production attributable to the Royalty Interests, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil, natural gas and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond Chesapeake's control. The Trust's revenue and distributable income available to unitholders have been adversely affected throughout 2017 and 2018 by a decline in production. Due to natural declines, the Trust expects production to decline further and expects distributable income to continue to be adversely affected.
As of December 31, 2018, none of the Trust’s estimated proved reserves were undeveloped.
The present values included in this report do not represent the current market value of the Trust's estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. Prices on the date of estimate are calculated as the average oil and natural gas price, as applicable, during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2018 present value is based on $65.56 per bbl of oil and $3.10 per mcf of natural gas before basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. Any changes in consumption or in governmental regulations will also affect the actual future net cash flows from our production. In addition, the 10% discount factor which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor.
Reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in estimates of proved reserves, future production rates and the timing of development expenditures. Most of the Producing Wells, as defined by the SEC, have been operational for a relatively short period of time and estimated total reserves vary substantially from well to well and are not directly correlated to perforated lateral length or completion technique. There can be no assurance that the data used in preparing these estimates can accurately predict future production. The lack of operational history for horizontal wells in the Colony Granite Wash may also contribute to the inaccuracy of estimates of proved reserves. During 2018, the Trust recorded downward reserve revisions primarily attributable to lower production in forecasts. During 2017, the Trust recorded downward reserve revisions primarily due to a decrease in production offset by higher oil and gas prices. Future negative well performance or lower expected ultimate recovery could lead to further downward adjustments to our reserve estimates. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates would have a material adverse effect on the financial condition, results of operations and cash flows of the Trust and would reduce cash distributions to Trust unitholders.
Chesapeake's ability to satisfy its obligations to the Trust depends on its financial position, and in the event of Chesapeake's bankruptcy, it may be expensive and time-consuming for the Trust to exercise its remedies, and the Trust may be treated as an unsecured creditor of Chesapeake.
Pursuant to the terms of the development agreement, Chesapeake was obligated to drill and complete, or participate as a non-operator in the drilling and completion of, the Development Wells at its own expense. As of June 30, 2016, Chesapeake had fulfilled its drilling and completion obligation under the development agreement. The conveyances provide that Chesapeake is obligated to market, or cause to be marketed, the oil, natural gas and NGL production related to the Underlying Properties. Due to the Trust's reliance on Chesapeake to fulfill these obligations, the value of the Royalty Interests and its ultimate cash available for distribution is highly dependent on Chesapeake's performance.
Chesapeake's ability to perform its obligations will depend on its future financial condition, economic performance and access to capital, which in turn will depend upon the supply and demand for oil, natural gas and NGL, prevailing economic conditions and financial, business and other factors, many of which are beyond Chesapeake's control.
The proceeds of the Royalty Interests may be commingled, for a period of time, with proceeds of Chesapeake's retained interest in the Underlying Properties, and Chesapeake will not be required to maintain a segregated account for proceeds payable to the Trust. In the event of a collection proceeding, it is possible that the Trust may not have adequate facts to trace its entitlement to funds in the commingled pool of funds and that other persons may, in asserting claims against Chesapeake's retained interest, be able to assert claims to the proceeds that should be delivered to the Trust. In addition, during any bankruptcy of Chesapeake, it is possible that payments of the royalties may be delayed or deferred. During the pendency of any Chesapeake bankruptcy proceedings, the ability to collect cash payments being held in Chesapeake's accounts that are attributable to production from the Trust properties, and even its ability to demand any of these remedies, may be stayed or prohibited by the bankruptcy proceeding.
In the event of a bankruptcy of Chesapeake or the wholly owned subsidiaries of Chesapeake that conveyed the Royalty Interests to the Trust, the Trust could lose the value of all of the Royalty Interests if a bankruptcy court were to hold that the Royalty Interests constitute an asset of the bankruptcy estate. Chesapeake and the Trust believe that the Royalty Interests would not be included in any such bankruptcy estate because the recordation of the conveyance of the Royalty Interests in the appropriate real property records in Oklahoma will constitute the conveyance of fully vested real property interests under Oklahoma law or interests in hydrocarbons in place or to be produced under Oklahoma law. Oklahoma law, however, is not entirely clear as to whether an overriding royalty interest is a real property interest. While the Oklahoma Supreme Court has held that royalty interests are real property interests, such cases did not expressly overturn prior Oklahoma Supreme Court cases holding that an overriding royalty interest was not necessarily a real property interest. In the event of a bankruptcy of Chesapeake or the wholly owned subsidiaries of Chesapeake that conveyed the Royalty Interests to the Trust, if a bankruptcy court held that (a) the Royalty Interests did not constitute fully vested real property interests or interests in hydrocarbons in place or to be produced or (b) the Royalty Interests were not otherwise eligible to be excluded from the bankruptcy estate under federal bankruptcy law, the Royalty Interests may be treated as unsecured claims of the Trust against Chesapeake. If that were the case, creditors of Chesapeake would be able to claim the Royalty Interests as an asset of the bankruptcy estate to be sold to satisfy obligations to them and the Trust could lose the entire value of the Royalty Interests to senior creditors of Chesapeake.
Chesapeake may not serve as the operator of as many of the Developmental Wells as it expects and Chesapeake will rely upon unaffiliated third parties, who may be less qualified, to operate the Development Wells.
Pursuant to the development agreement between Chesapeake and the Trust, Chesapeake was obligated to, and did, drill and complete the equivalent of 118 Development Wells in the AMI as of June 30, 2016. Certain Development Wells drilled by Chesapeake are currently operated by third-party operators. The failure of an operator to adequately perform operations could reduce production from the Underlying Properties and the cash available for distribution to Trust unitholders.
Because Chesapeake does not have a majority working interest in most of the non-operated properties comprising the Underlying Properties, Chesapeake may not be able, either unilaterally or in concert with other working interest owners, to remove the operator in the event of poor or untimely performance. The failure of an operator to adequately perform operations could reduce the revenues distributable to the Trust and the amount of cash distributable to the Trust unitholders.
Production of oil, natural gas and NGL on the Underlying Properties could be materially and adversely affected by severe or unseasonable weather.
Production of oil, natural gas and NGL on the Underlying Properties could be materially and adversely affected by severe or unseasonable weather. Repercussions of severe weather conditions may include:
|
|
|
|
•
|
evacuation of personnel and curtailment of operations;
|
|
|
|
|
•
|
weather-related damage to facilities, resulting in suspension of operations;
|
|
|
|
|
•
|
inability to deliver materials to worksites; and
|
|
|
|
|
•
|
weather-related damage to pipelines and other transportation facilities.
|
Due to the Trust's lack of industry and geographic diversification, adverse developments in the Trust's existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders.
The Underlying Properties are operated for oil, natural gas and NGL production and are focused exclusively in the Colony Granite Wash in Washita County in the Anadarko Basin of western Oklahoma. This concentration could disproportionately expose the Trust's interests to operational and regulatory risk in that area. Due to the lack of diversification in industry type and location of the Trust's interests, adverse developments in the oil, natural gas and NGL markets or the area of the Underlying Properties, including, for example, transportation or treatment capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance, could have a significantly greater impact on the Trust's financial condition, results of operations and cash flows than if the Royalty Interests were more diversified.
The generation of proceeds for distribution by the Trust depends in part on access to and the operation of gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil, natural gas and NGL production from the Underlying Properties.
The amount of oil, natural gas and NGL that may be produced and sold from any well to which the Underlying Properties relate is subject to the availability of gathering, transportation and processing facilities. Even where such facilities are available, services from such facilities are subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil, natural gas and NGL to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery or physical damage to the gathering system or transportation system. The curtailments may vary from a few days to several months. In many cases, Chesapeake or a third-party operator is provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If Chesapeake or a third-party operator is forced to reduce production due to such a curtailment, the revenues of the Trust and the amount of cash distributions to the Trust unitholders would similarly be reduced due to the reduction of proceeds from the sale of production. Moreover, Chesapeake currently ships all of its natural gas production from the Underlying Properties to market through one pipeline provider and sells all of its oil production from the Underlying Properties to one purchaser. Although Chesapeake currently does not have any material production shut-in and does not shut in production on a routine basis as a result of lack of accessibility to transportation or lack of processing facilities, there can be no assurance this will be the case in the future.
The Trust units may lose value and cash available for distribution may be reduced as a result of title deficiencies with respect to the Underlying Properties.
The existence of a title deficiency with respect to any of the Underlying Properties could reduce the value or render a property worthless, thus adversely affecting the distributions to unitholders. Chesapeake does not obtain title insurance covering oil, natural gas and mineral leaseholds. Chesapeake's inability or failure to cure title defects could cause Chesapeake to lose its rights to some or all production from some of the Underlying Properties, which could result in a reduction in proceeds available for distribution to unitholders and the value of the Trust units may be reduced.
The Trust is passive in nature and will have no stockholder voting rights in Chesapeake, managerial, contractual or other ability to influence Chesapeake, or control over the field operations of, sales of oil, natural gas and NGL from, or development of, the Underlying Properties.
Trust unitholders have no voting rights with respect to Chesapeake securities and will have no managerial, contractual or other ability to influence Chesapeake's activities or operations of the Underlying Properties. In addition, some of the Development Wells are currently operated by third parties unrelated to Chesapeake. Such third-party operators may not have the operational expertise of Chesapeake within the AMI. Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners in the properties. The typical operating agreement contains procedures whereby the owners of the aggregate working interest in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the Trustee nor the Trust unitholders have any contractual ability to influence or control the field operations of, sales of oil, natural gas and NGL from, or future development of, the Underlying Properties.
The oil, natural gas and NGL reserves estimated to be attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and natural gas properties or royalty interests to replace the depleting assets and production.
The proceeds payable to the Trust from the Royalty Interests are derived from the sale of the production of oil, natural gas and NGL from the Underlying Properties. The oil, natural gas and NGL reserves attributable to the Underlying Properties are depleting assets, which means that the reserves of oil, natural gas and NGL attributable to the Underlying Properties will decline over time. As a result, the quantity of oil, natural gas and NGL produced from the Underlying Properties will decline over time.
Future maintenance may affect the quantity of proved reserves that can be economically produced from the Underlying Properties to which the wells relate. The timing and size of these projects will depend on, among other
factors, the market prices of oil, natural gas and NGL. Chesapeake has no contractual obligation to the Trust to make capital expenditures on the Underlying Properties in the future. Furthermore, for properties on which Chesapeake is not designated as the operator, Chesapeake has no control over the timing or amount of those capital expenditures. Chesapeake also has the right not to participate in the capital expenditures on properties for which it is not the operator, in which case Chesapeake and the Trust will not receive the production resulting from such capital expenditures. If Chesapeake or other operators of the wells to which the Underlying Properties relate do not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by Chesapeake or estimated in the reserve reports.
The Trust Agreement provides that the Trust's business activities are generally limited to owning the Royalty Interests and activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the Royalty Interests. As a result, the Trust is not permitted to acquire other oil and natural gas properties or royalty interests to replace the depleting assets and production attributable to the Trust.
An increase in the differential between the prices realized by Chesapeake for oil, natural gas and NGL produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the proceeds to the Trust and therefore the cash distributions by the Trust and the value of Trust units.
The prices received for Chesapeake's oil, natural gas and NGL production in Oklahoma usually fall below benchmark prices, such as NYMEX. The difference between the price received and the benchmark price is called a differential. The amount of the differential will depend on a variety of factors, including discounts based on the quality and location of hydrocarbons produced, btu content, post-production expenses and production taxes. These factors can cause differentials to be volatile from period to period. Chesapeake has little or no control over the factors that determine the amount of the differential, and cannot accurately predict natural gas or crude oil differentials. Increases in the differential between the realized price of oil, natural gas and NGL and the benchmark price for oil, natural gas and NGL could reduce the proceeds to the Trust and therefore the cash distributions by the Trust and the value of the Trust units.
The amount of cash available for distribution by the Trust will be reduced by post-production expenses and applicable taxes associated with the Royalty Interests and Trust expenses.
The Royalty Interests and the Trust will bear certain costs and expenses that will reduce the amount of cash received by or available for distribution by the Trust to the holders of the Trust units. These costs and expenses include the following:
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the Trust's share of the expenses incurred by Chesapeake to gather, store, compress, transport, process, treat, dehydrate and market the oil, natural gas and NGL (excluding costs of marketing services provided by Chesapeake);
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the Trust's share of applicable taxes on the oil, natural gas and NGL; and
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Trust administrative expenses, including fees paid to the Trustee and the Delaware Trustee, the annual administrative services fee payable to Chesapeake, tax return and Schedule K-1 preparation and mailing costs, independent auditor fees and registrar and transfer agent fees, costs associated with annual and quarterly reports to unitholders and certain internal expenses of the Trust incurred pursuant to the registration rights agreement.
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In addition, the amount of funds available for distribution to unitholders will be reduced by the amount of any cash reserves maintained by the Trustee in respect of anticipated future Trust expenses. Commencing with the distribution to unitholders payable in the first quarter of 2019, the Trustee intends to begin withholding the greater of $70,000 or 3.5% of the funds otherwise available for distribution each quarter to gradually increase existing cash reserves by a total of approximately $850,000. The Trustee may increase or decrease the targeted amount at any time, and may increase or decrease the rate at which it is withholding funds to build the cash reserve at any time, without advance notice to the unitholders.
The amount of costs and expenses borne by the Trust may vary materially from quarter to quarter. The extent by which the costs and expenses of the Trust are higher or lower in any quarter will directly decrease or increase the amount received by the Trust and available for distribution to the unitholders. Historical post-production expenses and taxes, however, may not be indicative of future post-production expenses and taxes.In March 2019, the Trust's cash on hand (including cash reserves) was insufficient to pay the Trust's ordinary course expenses as they became due.
Chesapeake loaned $275,000 to the Trust necessary to pay such expenses and agreed to permit the Trust to continue making distributions while the loan was outstanding. The Trust intends to repay the loan in May 2019.
The Trustee may, under certain circumstances, sell the Royalty Interests and dissolve the Trust; otherwise, the Trust will begin to liquidate following the end of the 20-year period in which the Trust owns the Term Royalties.
The Royalty Interests will be sold and the Trust will be dissolved upon the occurrence of certain events. For example, the Trustee must sell the Royalty Interests if unitholders approve the sale or vote to dissolve the Trust. The Trustee must also sell the Royalty Interests if cash available for distribution is less than $1.0 million in each of any four consecutive quarters. The sale of all of the Royalty Interests will result in the dissolution of the Trust. Upon the dissolution of the Trust, the net proceeds of any such sale, after the payment of Trust liabilities, will be distributed to the Trust unitholders pro rata and unitholders will not be entitled to receive any proceeds from the sale of production from the Underlying Properties following such date. If none of these events occur, the Trust will dissolve on the Termination Date.
In connection with the dissolution of the Trust on the Termination Date, the Term Royalties will automatically revert to Chesapeake, while the Perpetual Royalties will be sold and the proceeds will be distributed to the unitholders (including Chesapeake to the extent of any Trust units it owns) at the date the Trust dissolves or soon thereafter. The price received by the Trust from any purchaser of the Perpetual Royalties will depend, among other things, on the prices of oil, natural gas and NGL at that time. There can be no assurance that the prices of oil, natural gas and NGL will be at levels such that Trust unitholders will receive any particular amount of cash in return for the Trust's sale of the Perpetual Royalties.
Chesapeake will have a right of first refusal to purchase the Perpetual Royalties upon the dissolution of the Trust, which may reduce the inclination of third parties to place a bid, and thereby reduce the value received by the Trust in a sale. If the Trustee receives a bid from a proposed purchaser other than Chesapeake and wants to sell all or part of the Perpetual Royalties to such third party, the Trustee will be required to give notice to Chesapeake and identify the proposed purchaser and proposed sale price, and other terms of the bid.
The Trust is managed by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.
The business and affairs of the Trust are managed by the Trustee. Voting rights as a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders, and the Trust does not currently anticipate holding annual meetings. Likewise, there is no requirement for an annual or other periodic re-election of the Trustee. The Trust Agreement provides that the Trustee may only be removed and replaced by the holders of a majority of the outstanding Trust units, excluding Trust units held by Chesapeake, voting in person or by proxy at a special meeting of Trust unitholders at which a quorum is present called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. As a result, it may be difficult for public unitholders to remove or replace the Trustee without the cooperation of holders of a substantial percentage of the outstanding Trust units.
Trust unitholders have limited ability to enforce provisions of the Royalty Interest conveyances, and Chesapeake's liability to the Trust is limited.
The Trust Agreement permits the Trustee and the Trust to sue Chesapeake or any other future owner of the Underlying Properties to enforce the terms of the conveyances creating the Royalty Interests. If the Trustee does not take appropriate action to enforce provisions of these conveyances, a Trust unitholder's recourse would be limited to bringing a lawsuit against the Trust or the Trustee to compel the Trust or the Trustee to take specified actions. The Trust Agreement expressly limits a Trust unitholder's ability to directly sue Chesapeake or any other party other than the Trustee. As a result, Trust unitholders will not be able to sue Chesapeake or any future owner of the Underlying Properties to enforce the Trust's rights under the conveyances. Furthermore, the Royalty Interest conveyances prohibit recovery of certain types of damages, such as consequential and punitive damages, and provide that, except as set forth in the conveyances, Chesapeake will not be liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts in good faith and in accordance with the Reasonably Prudent Operator Standard under the development agreement and, to the fullest extent permitted by law, will owe no fiduciary duties to the Trust or the unitholders.
Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.
Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.
Chesapeake may sell Trust units in the public or private markets and such sales could have an adverse impact on the trading price of the common units.
Chesapeake owns 23,750,000 common units. Chesapeake may sell Trust units in the public or private markets, and any such sales could have an adverse impact on the price of the common units or on any trading market that may develop. The Trust has granted registration rights to Chesapeake, which, if exercised, would facilitate sales of Trust units by Chesapeake to the public.
Conflicts of interest could arise between Chesapeake and the Trust.
Chesapeake could have interests that conflict with the interests of the Trust and the Trust unitholders. For example:
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Chesapeake's interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of the Underlying Properties. For example, Chesapeake may abandon a well that is no longer producing in paying quantities even though such well is still generating revenue for the Trust unitholders. Chesapeake may make decisions with respect to expenditures and decisions to allocate resources to projects in other areas that adversely affect the Underlying Properties, including reducing expenditures on these properties, which could cause oil, natural gas and NGL production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future.
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Chesapeake may, without the consent or approval of the Trust unitholders, sell all or any part of its retained interest in the Underlying Properties, subject to and burdened by the Royalty Interests. Although Chesapeake must require any purchaser of its retained interest in the Underlying Properties to assume Chesapeake's obligations with respect to those properties, such sale may not be in the best interests of the Trust and the Trust unitholders. Any purchaser may lack Chesapeake's experience in the Colony Granite Wash or its creditworthiness.
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Chesapeake may, without the consent or approval of the Trust unitholders, require the Trust to release Royalty Interests with an aggregate value of up to $5.0 million during any 12-month period in connection with a sale by Chesapeake of a portion of its retained interest in the Underlying Properties. Although these releases are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such Royalty Interests, the fair value received by the Trust for such Royalty Interests may not fully compensate the Trust for the value of future production attributable to the Royalty Interests disposed of.
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Chesapeake can sell its Trust units regardless of the effects such sale may have on common unit prices or on the Trust itself. Additionally, once Chesapeake is allowed to vote its Trust units, Chesapeake can vote its Trust units in its sole discretion.
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In addition, Chesapeake has agreed that, if at any time the Trust's cash on hand (including available cash reserves) is not sufficient to pay the Trust's ordinary course expenses as they become due, it will lend funds to the Trust necessary to pay such expenses. Any such loan 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 arms' length transaction between Chesapeake and an unaffiliated third party. If Chesapeake provides such funds to the Trust, it would become a creditor of the Trust and its interests as a creditor could conflict with the interests of unitholders. There were no loans outstanding as of December 31, 2018 or December 31, 2017.
Chesapeake may sell all or a portion of its retained interest in the Underlying Properties, subject to and burdened by the Royalty Interests; any such purchaser could have a weaker financial position and/or be less experienced in oil, natural gas and NGL development and production than Chesapeake.
Trust unitholders will not be entitled to vote on any sale by Chesapeake of its retained interest in the Underlying Properties and the Trust will not receive any proceeds from any such sale. The purchaser would be responsible for all
of Chesapeake's obligations relating to the Royalty Interests on the portion of the Underlying Properties sold, including Chesapeake's obligation to operate the Underlying Properties sold in accordance with the Reasonably Prudent Operator Standard under the development agreement and Chesapeake's true-up obligations with respect to the Underlying Properties sold, and Chesapeake would have no continuing obligation to the Trust for those properties. Additionally, Chesapeake may enter into farmout or participation arrangements with respect to the wells burdened by the Royalty Interests. Any purchaser, farmout counterparty or participating partner could have a weaker financial position and/or be less experienced in oil, natural gas and NGL development and production in the Colony Granite Wash than Chesapeake, which could result in a decrease in production from the Underlying Properties sold and a corresponding decrease in cash available for distribution to the Trust's unitholders. Additionally, in the event that Chesapeake enters into such a farmout or participation agreement, the Royalty Interests will not burden any interests that the counterparty earns under such an agreement.
Oil and natural gas producing operations can be hazardous and may expose Chesapeake to liabilities.
Oil and natural gas producing operations are subject to many risks, including well blowouts, cratering and explosions, pipe failures, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, oil spills, severe weather, natural disasters, groundwater contamination and other environmental hazards and risks. Some of these risks or hazards could materially and adversely affect Chesapeake's revenues and expenses by reducing or shutting in production from wells, loss of equipment or otherwise negatively impacting the projected economic performance of its prospects. For non-operated properties, Chesapeake is dependent on the operator for operational and regulatory compliance. A temporary or permanent halt of the production and sales of oil, natural gas and NGL at any of the Underlying Properties could also reduce Trust distributions by reducing the amount of proceeds available for distribution.
If any of these risks occurs, Chesapeake could sustain substantial losses as a result of:
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injury or loss of life;
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severe damage to or destruction of property, natural resources or equipment;
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pollution or other environmental damage;
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clean-up responsibilities;
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regulatory investigations and administrative, civil and criminal penalties; and
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injunctions resulting in limitation or suspension of operations.
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A material event such as those described above could expose Chesapeake to liabilities, monetary penalties or interruptions in its business operations. While Chesapeake may maintain insurance against some, but not all, of the risks described above, its insurance may not be adequate to cover casualty losses or liabilities, and its insurance does not cover penalties or fines that may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, war, terrorism and piracy, Chesapeake has limited or no insurance coverage. Also, in the future Chesapeake may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant event against which Chesapeake is not fully insured may expose it to liabilities.
The ability of the Underlying Properties to produce oil, natural gas and NGL economically and in commercial quantities could be impaired if Chesapeake is unable to acquire adequate supplies of water or is unable to dispose of or recycle the water it uses economically and in an environmentally safe matter.
Development activities require the use of water. For water sourcing, Chesapeake first seeks to use non-potable water supplies for its operational needs. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must then be obtained from other sources and transported to the drilling site. Chesapeake's inability to secure sufficient amounts of water, or to dispose of or recycle the water used in its operations, could adversely impact the development of the Underlying Properties. The imposition of new environmental initiatives and regulations could further restrict Chesapeake's ability to conduct certain operations such as hydraulic fracturing by restricting the disposal of materials such as produced water and drilling fluids.
Chesapeake is subject to extensive governmental regulation and ongoing regulatory changes, which could adversely impact Chesapeake's business.
Chesapeake's operations are subject to extensive federal, state, tribal, local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGLs, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on drilling or completion activities, Chesapeake may not be able to conduct its operations as planned. In addition, Chesapeake may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or orders.
In addition, changes in public policy have affected, and in the future could further affect, Chesapeake's operations. Regulatory changes could, among other things, restrict production levels, impose price controls, alter environmental protection requirements and increase taxes, royalties and other amounts payable to the government. Operating and compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to Chesapeake's operations. Chesapeake does not expect that any of these laws and regulations will affect operations materially differently than they would affect other companies with similar operations, size and financial strength. Although Chesapeake is unable to predict changes to existing laws and regulations, such changes could significantly impact profitability, financial condition and liquidity. This is particularly true of changes related to pipeline safety, seismic activity, hydraulic fracturing, climate change and endangered species designations.
Continuing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on greenhouse gas emissions. EPA and BLM have issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry; however, following the change in presidential administrations, both agencies took actions to rescind or revise the rules. In September 2018, BLM issued a final rule that rescinded certain requirements of its venting and flaring rule. Similarly, in October 2018, EPA published a proposed rule that amends certain requirements of its methane rule. The EPA rule remains in effect. Nevertheless, several states where Chesapeake operates have imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of cap and trade and/or carbon tax programs. Cap and trade programs offer greenhouse gas emission allowances that are gradually reduced over time. A cap and trade program could impose direct costs on Chesapeake through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. A carbon tax could directly increase costs of operation and similarly incentivize consumers to shift away from fossil fuels.
In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities.
These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect Chesapeake, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, equipment and operations, which could require Chesapeake to incur costs to reduce emissions of greenhouse gases associated with its operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the value of reserves and have a material adverse effect on Chesapeake's profitability, financial condition and liquidity. Furthermore, increasing attention to climate change risks has resulted in increased likelihood of governmental investigations and private litigation, which could increase costs or otherwise adversely affect Chesapeake.
Tax Risks Related to the Units
The Trust's tax treatment depends on its status as a partnership for U.S. federal income tax purposes. If the IRS were to treat the Trust as a corporation for U.S. federal income tax purposes or the Trust were subjected to state or local entity level tax, then its cash available for distribution to Trust unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the Trust units depends largely on the Trust being treated as a partnership for U.S. federal income tax purposes. The Trust has not requested, and does not plan to request, a ruling from the IRS on this or any other tax matter affecting it.
It is possible in certain circumstances for a publicly traded trust otherwise treated as a partnership, such as the Trust, to be treated as a corporation for U.S. federal income tax purposes. Although the Trust does not believe based upon its current activities that such treatment is applicable to it, a change in current law could cause it to be treated as a corporation for U.S. federal income tax purposes or otherwise subject it to taxation as an entity.
If the Trust were treated as a corporation for U.S. federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which for tax years beginning after 2017 is 21%, and would likely be required to pay state income tax on its taxable income at the corporate tax rate in Oklahoma. Distributions to Trust unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to Trust unitholders without first being subjected to taxation at the entity level. Because a tax would be imposed upon the Trust as a corporation, its cash available for distribution to Trust unitholders would be substantially reduced. In addition, changes in current state law may subject the Trust to additional entity-level taxation by individual states. Because of state budget deficits and other reasons, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to Trust unitholders. Therefore, if the Trust were treated as a corporation for U.S. federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to the Trust unitholders, likely causing a substantial reduction in the value of the Trust units.
The U.S. federal income tax treatment of the Development Royalty Interest is not entirely free from doubt. A successful challenge by the IRS to the tax position the Trust takes with respect to the Development Royalty Interest could affect the amount, timing and character of income, gain or loss relating to an investment in Trust units.
The U.S. federal income tax laws and precedents applicable to the tax treatment of royalty interests in wells that will be drilled in the future are not well established. As a result, the tax treatment of the Development Royalty Interest is not entirely free from doubt. A successful challenge by the IRS to the tax position the Trust takes with respect to the Development Royalty Interest could negatively affect the amount, timing and character of income, gain or loss relating to a unitholder's investment in Trust units, which could increase or accelerate the amount of federal income tax payable on a unitholder's share of the Trust's income.
The tax treatment of an investment in Trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.
U.S. federal tax reform legislation informally known as the Tax Cuts and Jobs Act (the “Tax Act”) was enacted December 22, 2017, and makes significant changes to the federal income tax rules applicable to both individuals and entities, including changes to the effective tax rate on an individual or other non-corporate unitholder’s allocable share of certain income from a publicly traded partnership. The Tax Act is complex and lacks administrative guidance, thus, unitholders should consult their tax advisor regarding the Tax Act and its effect on an investment in Trust units.
For taxable years beginning after 2017, the highest marginal U.S. federal income tax rates applicable to ordinary income and long-term capital gains of individuals are 37% and 20%, respectively. Individual unitholders may be eligible for a deduction for tax years beginning after 2017 generally equal to 20% of the Trust’s domestic income and 20% of any recapture income of the unitholder on the sale of Trust units, which could reduce the individual’s effective tax rate on income from the Trust. However, such deduction will not be available after 2025 unless Congress extends it. In addition, an individual having adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns) is subject to the Net Investment Income Tax of 3.8% on the lesser of such excess or the individual's net
investment income. For these purposes, net investment income generally includes interest income and royalty income derived from the Trust units as well as any net gain from the disposition of Trust units.
With respect to Oklahoma production tax, it has been assumed that the effective tax rate on the oil, natural gas and NGL attributable to the Trust will be approximately 2.0% for the first three years of production for each well spudded on or after July 1, 2015, and approximately 7.0% thereafter. New legislation was passed increasing the rate on all new and existing wells from 2.0% to 5.0% effective with production month July 2018. No changes were made to the original incentive term of the first three years of production. After the initial three-year term, the effective tax rate will be approximately 7.0%. These rates are subject to change by new legislation at any time.
The present U.S. federal income tax treatment of publicly traded partnerships, including the Trust, or an investment in the Trust units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, the President and members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Further, final regulations under Section 7704(d)(1)(E) of the Internal Revenue Code of 1986, as amended, interpret the scope of the qualifying income requirements for publicly traded partnerships by providing industry-specific guidance.
Any modification to the U.S. federal income tax laws or interpretations thereof (including administrative guidance relating to the Tax Act) may be applied retroactively and could make it more difficult or impossible for the Trust to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes or otherwise adversely affect our business, financial condition or results of operations. The Trust is unable to predict whether any changes or other proposals will ultimately be enacted, or whether any adverse interpretations will be used. Any such changes or interpretations could negatively impact the value of an investment in the Trust units.
If the IRS contests the tax positions the Trust takes, the value of the Trust units may be adversely affected, the cost of any IRS contest will reduce the Trust's cash available for distribution to Trust unitholders.
The Trust has not requested a ruling from the IRS with respect to its treatment as a partnership for U.S. federal income tax purposes or any other matter affecting the Trust. The IRS may adopt positions that differ from the conclusions of the Trust's counsel expressed in the federal income tax considerations section in the prospectus or form the positions the Trust takes. It may be necessary to resort to administrative or court proceedings to attempt to sustain some or all of the conclusions of the Trust's counsel or the positions the Trust takes. A court may not agree with some or all of the conclusions of the Trust's counsel or the positions the Trust takes. Any contest with the IRS may materially and adversely impact the market for the Trust units and the price at which they trade. In addition, the Trust's costs of any contest with the IRS will be borne indirectly by the Trust unitholders because the costs will reduce the Trust's cash available for distribution.
For tax years beginning after December 31, 2017, if the IRS makes audit adjustments to the Trust’s income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from the Trust. To the extent possible under the new rules, the Trust may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although the Trust may elect to have Trust unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, current Trust unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such Trust unitholders did not own units in the Trust during the tax year under audit. If, as a result of any such audit adjustment, the Trust is required to make payments of taxes, penalties and interest, cash available for distribution to Trust unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.
Trust unitholders will be required to pay taxes on their share of the Trust's income even if they do not receive any cash distributions from the Trust.
Because the Trust unitholders will be treated as partners to whom the Trust will allocate taxable income that could be different in amount than the cash the Trust distributes, Trust unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of the Trust's taxable income even if they receive no cash distributions from the Trust. Trust unitholders may not receive cash distributions from the Trust equal to their share of the Trust's taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of the Trust units could be more or less than expected.
Trust unitholders that sell their Trust units will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those Trust units. Because distributions in excess of the Trust unitholders allocable share of the Trust's net taxable income decrease the tax basis in such Trust unitholders' Trust units, the amount, if any, of such prior excess distributions with respect to the Trust units sold will, in effect, become taxable income if Trust units are sold at a price greater than the tax basis in those Trust units, even if the price received is less than the original cost of the Trust units. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion recapture.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning the Trust units that may result in adverse tax consequences to them.
Investment in Trust units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and non-U.S. persons could result in differing tax consequences. For example, some of the Trust income allocated to organizations exempt from U.S. federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income which would be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons may be required to file U.S. federal income tax returns and pay tax on their share of the Trust's taxable income or proceeds from the sale of Trust units.
The Trust will treat each purchaser of Trust units as having the same economic attributes without regard to the actual Trust units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Trust units.
Due to a number of factors, including the Trust's inability to match transferors and transferees of Trust units, the Trust has adopted positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely alter the tax effects of an investment in Trust units. It also could affect the timing of any tax benefits or the amount of gain from the sale of Trust units by Trust unitholders and could have a negative impact on the value of the Trust units or result in audit adjustments to Trust unitholders tax returns.
The Trust prorates its items of income, gain, loss and deduction between transferors and transferees of the Trust units each quarter based upon the record ownership of the Trust units on the quarterly record date in such quarter, instead of on the basis of the date a particular Trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.
The Trust prorates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date in such quarter instead of on the basis of the date a particular Trust unit is transferred.
Final Treasury Regulations allow publicly traded partnerships to use a similar monthly simplifying convention to allocate tax items among transferors and transferees, although these regulations do not specifically authorize all aspects of the proration method the Trust has adopted. If the IRS were to challenge the Trust's proration method, the Trust may be required to change its allocation of items of income, gain, loss and deduction among the Trust unitholders and the costs to the Trust of implementing and reporting under any such changed method may be significant.
A Trust unitholder whose Trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed of those Trust units. If so, he would no longer be treated for tax purposes as a partner with respect to those Trust units during the period of the loan and may recognize gain or loss from the disposition.
Because a Trust unitholder whose Trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed of the loaned Trust units, he may no longer be treated for tax purposes as a partner with respect to those Trust units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of the Trust's income, gain, loss or deduction with respect to those Trust units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those Trust units could be fully taxable as ordinary income. The Trust's counsel has not rendered an opinion regarding the treatment of a unitholder where Trust units are loaned to a short seller to cover a short sale of Trust units; therefore, Trust unitholders desiring to assure their status as partners and avoid
the risk of
gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their Trust units.
The Trust has adopted certain valuation methodologies that may affect the income, gain, loss and deduction allocable to the Trust unitholders. The IRS may challenge this treatment, which could adversely affect the value of the Trust units.
The U.S. federal income tax consequences of the ownership and disposition of Trust units will depend in part on the Trust's estimates of the relative fair market values, and the initial tax bases of the Trust's assets. Although the Trust may from time to time consult with professional appraisers regarding valuation matters, the Trust will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by Trust unitholders might change, and Trust unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
Trust unitholders may be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result of investing in Trust units.
In addition to U.S. federal income taxes, Trust unitholders will likely be subject to other taxes, including Oklahoma state income taxes, even if they do not live in Oklahoma. Trust unitholders will likely be required to file Oklahoma state income tax returns and pay Oklahoma state income tax. Further, Trust unitholders may be subject to penalties for failure to comply with those requirements. It is each Trust unitholder's responsibility to file all U.S. federal, state, local and non-U.S. tax returns.
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