43 C.F.R. Subpart 3103—Fees, Rentals and Royalty
Title 43 - Public Lands: Interior
Title 43: Public Lands: Interior
PART 3100—OIL AND GAS LEASING
Subpart 3103—Fees, Rentals and Royalty
§ 3103.1 Payments.
§ 3103.1-1 Form of remittance.
All remittances shall be by personal check, cashier's check, certified check, or money order, and shall be made payable to the Department of the Interior—Bureau of Land Management or the Department of the Interior—Minerals Management Service, as appropriate. Payments made to the Bureau may be made by other arrangements such as by electronic funds transfer or credit card when specifically authorized by the Bureau. In the case of payments made to the Service, such payments may also be made by electronic funds transfer.
[53 FR 22837, June 17, 1988]
§ 3103.1-2 Where submitted.
(a)(1) All filing fees for lease applications or offers or for requests for approval of a transfer and all first-year rentals and bonuses for leases issued under Group 3100 of this title shall be paid to the proper BLM office.
(2) All second-year and subsequent rentals, except for leases specified in paragraph (b) of this section, shall be paid to the Service at the following address: Minerals Management Service, Royalty Management Program/BRASS, Box 5640 T.A., Denver, CO 80217.
(b) All rentals and royalties on producing leases, communitized leases in producing well units, unitized leases in producing unit areas, leases on which compensatory royalty is payable and all payments under subsurface storage agreements and easements for directional drilling shall be paid to the Service.
[48 FR 33662, July 22, 1983, as amended at 49 FR 11637, Mar. 27, 1984; 49 FR 39330, Oct. 5, 1984; 53 FR 17353, May 16, 1988]
§ 3103.2 Rentals.
§ 3103.2-1 Rental requirements.
(a) Each competitive bid or competitive nomination submitted in response to a List of Lands Available for Competitive Nominations or Notice of Competitive Lease Sale, and each noncompetitive lease offer shall be accompanied by full payment of the first year's rental based on the total acreage, if known, and, if not known, shall be based on 40 acres for each smallest legal subdivision. An offer deficient in the first year's rental by not more than 10 percent or $200, whichever is less, shall be accepted by the authorized officer provided all other requirements are met. Rental submitted shall be determined based on the total amount remitted less all required fees. The additional rental shall be paid within 30 days from notice of the deficiency under penalty of cancellation of the lease.
(b) If the acreage is incorrectly indicated in a List of Lands Available for Competitive Nominations or a Notice of Competitive Lease Sale, payment of the rental based on the error is curable within 15 calendar days of receipt of notice from the authorized officer of the error.
(c) Rental shall not be prorated for any lands in which the United States owns an undivided fractional interest but shall be payable for the full acreage in such lands.
[48 FR 33662, July 22, 1983, as amended at 49 FR 26920, June 29, 1984, 53 FR 22837, June 17, 1988; 53 FR 31958, Aug. 22, 1988]
§ 3103.2-2 Annual rental payments.
Rentals shall be paid on or before the lease anniversary date. A full year's rental shall be submitted even when less than a full year remains in the lease term, except as provided in §3103.4–4(d) of this title. Failure to make timely payment shall cause a lease to terminate automatically by operation of law. If the designated Service office is not open on the anniversary date, payment received on the next day the designated Service office is open to the public shall be deemed to be timely made. Payments made to an improper BLM or Service office shall be returned and shall not be forwarded to the designated Service office. Rental shall be payable at the following rates:
(a) The annual rental for all leases issued subsequent to December 22, 1987, shall be $1.50 per acre or fraction thereof for the first 5 years of the lease term and $2 per acre or fraction for any subsequent year, except as provided in paragraph (b) of this section;
(b) The annual rental for all leases issued on or before December 22, 1987, or issued pursuant to an application or offer to lease filed prior to that date shall be as stated in the lease or in regulations in effect on December 22, 1987, except:
(1) Leases issued under former subpart 3112 of this title on or after February 19, 1982, shall be subject after February 1, 1989, to annual rental in the sixth and subsequent lease years of $2 per acre or fraction thereof;
(2) The rental rate of any lease determined after December 22, 1987, to be in a known geological structure outside of Alaska or in a favorable petroleum geological province within Alaska shall not be increased because of such determination;
(3) Exchange and renewal leases shall be subject to rental of $2 per acre or fraction thereof upon exchange or renewal;
(c) Rental shall not be due on acreage for which royalty or minimum royalty is being paid, except on nonproducing leases when compensatory royalty has been assessed in which case annual rental as established in the lease shall be due in addition to compensatory royalty;
(d) On terminated leases that were originally issued noncompetitively and are reinstated under §3108.2–3 of this title, and on noncompetitive leases that were originally issued under §3108.2–4 of this title, the annual rental shall be $5 per acre or fraction thereof beginning with the termination date upon the filing, on or after the effective date of this regulation, of a petition to reinstate a lease or convert an abandoned, unpatented oil placer mining claim;
(e) On terminated leases that were originally issued competitively, the annual rental shall be $10 per acre or fraction thereof beginning with the termination date upon the filing, on or after the effective date of this regulation, of a petition to reinstate a lease under §3108.2–3 of this title; and
(f) Each succeeding time a specific lease is reinstated under §3108.2–3 of this title, the annual rental on that lease shall increase by an additional $5 per acre or fraction thereof for leases that were originally issued noncompetitively and by an additional $10 per acre or fraction thereof for leases that were originally issued competitively.
[53 FR 17353, May 16, 1988 and 53 FR 22837, June 17, 1988, as amended at 61 FR 4750, Feb. 8, 1996]
§ 3103.3 Royalties.
§ 3103.3-1 Royalty on production.
(a) Royalty on production shall be payable only on the mineral interest owned by the United States. Royalty shall be paid in amount or value of the production removed or sold as follows:
(1) 12
(i) Leases issued after December 22, 1987, resulting from offers to lease or bids filed on or before December 22, 1987, which are subject to the rates in effect on December 22, 1987; and
(ii) Leases issued on or before December 22, 1987, which are subject to the rates contained in the lease or in regulations at the time of issuance;
(2) 16
(3) Not less than 4 percentage points above the rate used for royalty determination contained in the lease that is reinstated or in force at the time of issuance of the lease that is reinstated for competitive leases, plus an additional 2 percentage-point increase added for each succeeding reinstatement.
(b) Leases that qualify under specific provisions of the Act of August 8, 1946 (30 U.S.C. 226c) may apply for a limitation of a 12
(c) The average production per well per day for oil and gas shall be determined pursuant to 43 CFR 3162.7–4.
(d) Payment of a royalty on the helium component of gas shall not convey the right to extract the helium. Applications for the right to extract helium shall be made under part 16 of this title.
[53 FR 22838, June 17, 1988]
§ 3103.3-2 Minimum royalties.
(a) A minimum royalty shall be payable at the expiration of each lease year beginning on or after a discovery of oil or gas in paying quantities on the lands leased, except that on unitized leases the minimum royalty shall be payable only on the participating acreage, at the following rates:
(1) On leases issued on or after August 8, 1946, and on those issued prior thereto if the lessee files an election under section 15 of the Act of August 8, 1946, a minimum royalty of $1 per acre or fraction thereof in lieu of rental, except as provided in paragraph (a)(2) of this section; and
(2) On leases issued from offers filed after December 22, 1987, and on competitive leases issued from successful bids placed at oral auctions conducted after December 22, 1987, a minimum royalty in lieu of rental of not less than the amount of rental which otherwise would be required for that lease year.
(b) Minimum royalties shall not be prorated for any lands in which the United States owns a fractional interest but shall be payable on the full acreage of the lease.
(c) Minimum royalties and rentals on non-participating acreage shall be payable to the Service.
(d) The minimum royalty provisions of this section shall be applicable to leases reinstated under §3108.2–3 of this title and leases issued under §3108.2–4 of this title.
[48 FR 33662, July 22, 1983, as amended at 49 FR 11637, Mar. 27, 1984; 49 FR 30448, July 30, 1984; 53 FR 22838, June 17, 1988]
§ 3103.4 Production incentives.
§ 3103.4-1 Royalty reductions.
(a) In order to encourage the greatest ultimate recovery of oil or gas and in the interest of conservation, the Secretary, upon a determination that it is necessary to promote development or that the leases cannot be successfully operated under the terms provided therein, may waive, suspend or reduce the rental or minimum royalty or reduce the royalty on an entire leasehold, or any portion thereof.
(b)(1) An application for the benefits under paragraph (a) of this section on other than stripper oil well leases or heavy oil properties must be filed by the operator/payor in the proper BLM office. (Royalty reductions specifically for stripper oil well leases or heavy oil properties are discussed in §3103.4–2 and §3103.4–3 respectively.) The application must contain the serial number of the leases, the names of the record title holders, operating rights owners (sublessees), and operators for each lease, the description of lands by legal subdivision and a description of the relief requested.
(2) Each application shall show the number, location and status of each well drilled, a tabulated statement for each month covering a period of not less than 6 months prior to the date of filing the application of the aggregate amount of oil or gas subject to royalty, the number of wells counted as producing each month and the average production per well per day.
(3) Every application shall contain a detailed statement of expenses and costs of operating the entire lease, the income from the sale of any production and all facts tending to show whether the wells can be successfully operated upon the fixed royalty or rental. Where the application is for a reduction in royalty, full information shall be furnished as to whether overriding royalties, payments out of production, or similar interests are paid to others than the United States, the amounts so paid and efforts made to reduce them. The applicant shall also file agreements of the holders to a reduction of all other royalties or similar payments from the leasehold to an aggregate not in excess of one-half the royalties due the United States.
(c) Petition may be made for reduction of royalty under §3108.2–3(f) for leases reinstated under §3108.2–3 of this title and under §3108.2–4(i) for noncompetitive leases issued under §3108.2–4 of this title. Petitions to waive, suspend or reduce rental or minimum royalty for leases reinstated under §3108.2–3 of this title or for leases issued under §3108.2–4 of this title may be made under this section.
[48 FR 33662, July 22, 1983; 48 FR 39225, Aug. 30, 1983, as amended at 49 FR 30448, July 30, 1984; 53 FR 17354, May 16, 1988; 57 FR 35973, Aug. 11, 1992; 61 FR 4750, Feb. 8, 1996]
§ 3103.4-2 Stripper well royalty reductions.
(a)(1) A stripper well property is any Federal lease or portion thereof segregated for royalty purposes, a communitization agreement, or a participating area of a unit agreement, operated by the same operator, that produces an average of less than 15 barrels of oil per eligible well per well-day for the qualifying period.
(2) An eligible well is an oil well that produces or an injection well that injects and is integral to production for any period of time during the qualifying or subsequent 12-month period.
(3) An oil completion is a completion from which the energy equivalent of the oil produced exceeds the energy equivalent of the gas produced (including the entrained liquid hydrocarbons) or any completion producing oil and less than 60 MCF of gas per day.
(4) An injection well is a well that injects a fluid for secondary or enhanced oil recovery, including reservoir pressure maintenance operations.
(b) Stripper oil well property royalty rate reduction shall be administered according to the following requirements and procedures.
(1) An application for the benefits under paragraph (a) of this section for stripper oil well properties is not required.
(2) Total oil production (regardless of disposition) for the subject period from the eligible wells on the property is totaled and then divided by the total number of well days or portions of days, both producing and injection days, as reported on Form MMS–3160 or MMS–4054 for the eligible wells to determine the property average daily production rate. For those properties in communitization agreements and participating areas of unit agreements that have allocated (not actual) production, the production rate for all eligible well(s) in that specific communitization agreement or participating area is determined and shall be assigned to that allocated property in that communitization agreement or participating area.
(3) Procedures to be used by operator:
(i) Qualifying determination.
(A) Calculate an average daily production rate for the property in order to verify that the property qualifies as a stripper property.
(B) The initial qualifying period for producing properties is the period August 1, 1990, through July 31, 1991. For the properties that were shut-in for 12 consecutive months or longer, the qualifying period is the 12-month production period immediately prior to the shut-in. If the property does not qualify during the initial qualifying period, it may later qualify due to production decline. In those cases, the 12-month qualifying period will be the first consecutive 12-month period beginning after August 31, 1990, during which the property qualifies.
(ii) Qualifying royalty rate calculation. If the property qualifies, use the production rate rounded down to the next whole number (e.g., 6.7 becomes 6) for the qualifying period, and apply the following formula to determine the maximum royalty rate for oil production from the Federal leases for the life of the program.
Royalty Rate (%) = 0.5 + (0.8 × the average daily production rate)
The formula-calculated royalty rate shall apply to all oil production (except condensate) from the property for the first 12 months. The rate shall be effective the first day of the production month after the Minerals Management Service (MMS) receives notification. If the production rate is 15 barrels or greater, the royalty rate will be the rate in the lease terms.
(iii) Outyears royalty rate calculations.
(A) At the end of each 12-month period, the property average daily production rate shall be determined for that period. A royalty rate shall then be calculated using the formula in paragraph (b)(3)(ii) of this section.
(B) The new calculated royalty rate shall be compared to the qualifying period royalty rate. The lower of the two rates shall be used for the current period provided that the operator notifies the MMS of the new royalty rate. The new royalty rate shall not become effective until the first day of the month after the MMS receives notification. Notification shall be received on Form MMS–4377 and mailed to Minerals Management Service, P.O. Box 17110, Denver, CO 80217. If the operator does not notify the MMS of the new royalty rate within 60 days after the end of the subject 12-month period, the royalty rate for the property shall revert back to the royalty rate established as the qualifying period royalty rate, effective at the beginning of the current 12-month period.
(C) The royalty rate shall never exceed the calculated qualifying royalty rate for the life of this program.
(iv) Prohibition. For the qualifying period and any subsequent 12-month period, the production rate shall be the result of routine operational and economic factors for that period and for that property and not the result of production manipulation for the purpose of obtaining a lower royalty rate. A production rate that is determined to have resulted from production manipulation will not receive the benefit of a royalty rate reduction.
(v) Certification. The applicable royalty rate shall be used by the operator/payor when submitting the required royalty reports/payments to MSS. By submitting royalty reports/payments using the royalty rate reduction benefits of this program, the operator certifies that the production rate for the qualifying and subsequent 12-month period was not subject to manipulation for the purpose of obtaining the benefit of a royalty rate reduction, and the royalty rate was calculated in accordance with the instructions and procedures in these regulations.
(vi) Record retention. For seven years after production on which the operator claims a royalty rate reduction for stripper well properties, the operator must retain and make available to BLM for inspection all documents on which the calculation of the applicable royalty rate under this section relies.
(vii) Agency action. If a royalty rate is improperly calculated, the MMS will calculate the correct rate and inform the operator/payors. Any additional royalties due are payable immediately upon notification. Late payment or underpayment charges will be assessed in accordance with 30 CFR 218.102. The BLM may terminate a royalty rate reduction if it is determined that the production rate was manipulated by the operator for the purpose of receiving a royalty rate reduction. Terminations of royalty rate reductions will be effective on the effective date of the royalty rate reduction resulting from the manipulated production rate (i.e., the termination will be retroactive to the effective date of the improper reduction). The operator/payor shall pay the difference in royalty resulting from the retroactive application of the unmanipulated rate. Late payment or underpayment charges will be assessed in accordance with 30 CFR 218.102.
(4) The royalty rate reduction provision for stripper well properties shall be effective as of October 1, 1992. If the oil price, adjusted for inflation by BLM and MMS, using the implicit price deflator for gross national product with 1991 as the base year, remains on average above $28 per barrel, based on West Texas Intermediate crude average posted price for a period of 6 consecutive months, the benefits of the royalty rate reduction under this section may be terminated upon 6 months' notice, published in the
(5) The Secretary will evaluate the effectiveness of the stripper well royalty reduction program and may at any time after September 10, 1997, terminate any or all royalty reductions granted under this section upon 6 months notice.
(6) The stripper well property royalty rate reduction benefits shall apply to all oil produced from the property.
(7) The royalty for gas production (including liquids produced in association with gas) for oil completions shall be calculated separately using the lease royalty rate.
(8) If the lease royalty rate is lower than the benefits provided in this stripper oil property royalty rate reduction program, the lease rate prevails.
(9) The minimum royalty provisions of §3103.3–2 apply.
(10) Examples.
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Explanation, Example 1 1. Property production rate per well for qualifying period (August 1, 1990–July 31, 1991) is 10 barrels of oil per day (BOPD). 2. Using the formula, the royalty rate for the first year is calculated to be 8.5 percent. This rate is also the maximum royalty rate for the life of the program. 8.5%=0.5+(0.8×10) 3. Production rate for the first year is 8 BOPD. 4. Using the formula, the royalty rate is calculated at 6.9 percent. Since 6.9 percent is less than the first year rate of 8.5 percent, 6.9 percent is the applicable royalty rate for the second year. 6.9%=0.5+(0.8×8) 5. Production rate for the second year is 12 BOPD. 6. Using the formula, the royalty rate is calculated at 10.1 percent. Since the 8.5 percent first year royalty rate is less than 10.1 percent, the applicable royalty rate for third year is 8.5 percent. 10.1%=0.5+(0.8×12) 7. Production rate for the third year is 23 BOPD. 8. Since the production rate of 23 BOPD is greater than the 15 BOPD threshold for the program, the calculated royalty rate would be the property royalty rate. However, since the 8.5 percent first year royalty rate is less than the property rate, the royalty rate for the fourth year is 8.5 percent. 9. Production rate for the fourth year is 15 BOPD. 10. Since the production is at the 15 BOPD threshold, the royalty rate would be the property royalty rate. However, since the 8.5 percent first year royalty rate is less than the lease rate, the royalty rate for the fifth year is 8.5 percent. Explanation, Example 2 1. Property production rate of 23 BOPD per well (for the August 1, 1990–July 31, 1991, qualifying period prior to the effective date of the program) is greater than the 15 BOPD which qualifies a property for a royalty rate reduction. Therefore, the property is not entitled to a royalty rate reduction for the first year of the program. 2. Property royalty rate for the first year is the rate as stated in the lease. 3. Production rate for the first year is 8 BOPD. 4. Using the formula, the royalty rate is calculated to be 6.9 percent for the second year. This rate is also the maximum royalty rate for the life of the program. 6.9%=0.5+(0.8×8) 5. Production rate for the second year is 12 BOPD. 6. Using the formula, the royalty rate is calculated at 10.1 percent. Since the 6.9 percent second year royalty rate is less than 10.1 percent, the applicable royalty rate for third year is 6.9 percent. 10.1%=0.5+(0.8×12) 7. Production rate third year is 7 BOPD. 8. Using the formula, the royalty rate is calculated at 6.1 percent. Since the 6.1 percent third year royalty rate is less than the qualifying (maximum) rate of 6.9 percent, the royalty rate for the fourth year is 6.1 percent. 6.1%=0.5+(0.8×7) 9. Production rate for the fourth year is 15 BOPD. 10. Since the production is at the 15 BOPD threshold, the royalty rate would be the lease royalty rate. However, since the 6.9 percent second year royalty rate is less than the lease rate, the royalty rate for the fifth year is 6.9 percent.
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[48 FR 33662, July 22, 1983; 48 FR 39225, Aug. 30, 1983, as amended at 49 FR 30448, July 30, 1984; 53 FR 17354, May 16, 1988; 57 FR 35973, Aug. 11, 1992. Redesignated at 61 FR 4750, Feb. 8, 1996; 70 FR 53074, Sept. 7, 2005]
§ 3103.4-3 Heavy oil royalty reductions.
(a)(1) A heavy oil well property is any Federal lease or portion thereof segregated for royalty purposes, a communitization area, or a unit participating area, operated by the same operator, that produces crude oil with a weighted average gravity of less than 20 degrees as measured on the American Petroleum Institute (API) scale.
(2) An oil completion is a completion from which the energy equivalent of the oil produced exceeds the energy equivalent of the gas produced (including the entrained liquefiable hydrocarbons) or any completion producing oil and less than 60 MCF of gas per day.
(b) Heavy oil well property royalty rate reductions will be administered according to the following requirements and procedures:
(1) The Bureau of Land Management requires no specific application form for the benefits under paragraph (a) of this section for heavy oil well properties. However, the operator/payor must notify, in writing, the proper BLM office that it is seeking a heavy oil royalty rate reduction. The letter must contain the serial number of the affected leases (or, as appropriate, the communitization agreement number or the unit agreement name); the names of the operators for each lease; the calculated new royalty rate as determined under paragraph (b)(2) of this section; and copies of the Purchaser's Statements (sales receipts) to document the weighted average API gravity for a property.
(2) The operator must determine the weighted average API gravity for a property by averaging (adjusted to rate of production) the API gravities reported on the operator's Purchaser's Statement for the last 3 calendar months preceding the operator's written notice of intent to seek a royalty rate reduction, during each of which at least one sale was held. This is shown in the following 3 illustrations:
(i) If a property has oil sales every month prior to requesting the royalty rate reduction in October of 1996, the operator must submit Purchaser's Statements for July, August, and September of 1996;
(ii) If a property has sales only every 6 months, during the months of March and September, prior to requesting the rate reduction in October of 1996, the operator must submit Purchaser's Statements for the months of September 1995, and March and September 1996; and
(iii) If a property has multiple sales each month, the operator must submit Purchaser's Statements for every sale for the 3 entire calendar months immediately preceding the request for a rate reduction.
(3) The following equation must be used by the operator/payor for calculating the weighted average API gravity for a heavy oil well property:
Where: V1=Average Production (bbls) of Well #1 over the last 3 calendar months of sales V2=Average Production (bbls) of Well #2 over the last 3 calendar months of sales Vn=Average Production (bbls) of each additional well (V3, V4, etc.) over the last 3 calendar months of sales G1=Average Gravity (degrees) of oil produced from Well #1 over the last 3 calendar months of sales G2=Average Gravity (degrees) of oil produced from Well #2 over the last 3 calendar months of sales Gn=Average Gravity (degrees) of each additional well (G3, G4, etc.) over the last 3 calendar months of sales Example: Lease “A” has 3 wells producing at the following average rates over 3 sales months with the following associated average gravities: Well #1, 4,000 bbls, 13° API; Well #2, 6000 bbls, 21° API; Well #3, 2,000 bbls, 14° API. Using the equation above—
(4) For those properties subject to a communitization agreement or a unit participating area, the weighted average API oil gravity for the lands dedicated to that specific communitization agreement or unit participating area must be determined in the manner prescribed in paragraph (b)(3) of this section and assigned to all property subject to Federal royalties in the communitization agreement or unit participating area.
(5) The operator/payor must use the following procedures in order to obtain a royalty rate reduction under this section:
(i) Qualifying royalty rate determination. (A) The operator/payor must calculate the weighted average API gravity for the property proposed for the royalty rate reduction in order to verify that the property qualifies as a heavy oil well property.
(B) Properties that have removed or sold oil less than 3 times in their productive life may still qualify for this royalty rate reduction. However, no additional royalty reductions will be granted until the property has a sales history of at least 3 production months (see paragraph (b)(2) of this section).
(ii) Calculating the qualifying royalty rate. If the Federal leases or portions thereof (e.g., communitization or unit agreements) qualify as heavy oil property, the operator/payor must use the weighted average API gravity rounded down to the next whole degree (e.g., 11.7 degrees API becomes 11 degrees), and determine the appropriate royalty rate from the following table:
Royalty Rate Reduction for Heavy Oil------------------------------------------------------------------------ Royalty Rate Weighted average API gravity (degrees) (percent)------------------------------------------------------------------------6....................................................... 0.57....................................................... 1.48....................................................... 2.29....................................................... 3.110...................................................... 3.911...................................................... 4.812...................................................... 5.613...................................................... 6.514...................................................... 7.415...................................................... 8.216...................................................... 9.117...................................................... 9.918...................................................... 10.819...................................................... 11.620...................................................... 12.5------------------------------------------------------------------------
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(iii) New royalty rate effective date. The new royalty rate will be effective on the first day of production 2 months after BLM receives notification by the operator/payor. The rate will apply to all oil production from the property for the next 12 months (plus the 2 calendar month grace period during which the next 12 months' royalty rate is determined in the next year). If the API oil gravity is 20 degrees or greater, the royalty rate will be the rate in the lease terms. Example: BLM receives notification from an operator on June 8, 1996. There is a two month period before new royalty rate is effective—July and August. New royalty rate is effective September 1, 1996. (iv) Royalty rate determinations in subsequent years. (A) At the end of each 12-month period, beginning on the first day of the calendar month the royalty rate reduction went into effect, the operator/payor must determine the weighted average API oil gravity for the property for that period. The operator/payor must then determine the royalty rate for the following year using the table in paragraph (b)(5)(ii) of this section. (B) The operator/payor must notify BLM of its determinations under this paragraph and paragraph (b)(5)(iv)(A) of this section. The new royalty rate (effective for the next 12 month period) will become effective the first day of the third month after the prior 12 month period comes to a close, and will remain effective for 12 calendar months (plus the 2 calendar month grace period during which the next 12 months' royalty rate is determined in the next year). Notification must include copies of the Purchaser's Statements (sales receipts) and be mailed to the proper BLM office. If the operator does not notify the BLM of the new royalty rate within 60 days after the end of the subject 12-month period, the royalty rate for the heavy oil well property will return to the rate in the lease terms. Example: On September 30, 1997, at the end of a 12-month royalty reduction period, the operator/payor determines what the weighted average API oil gravity for the property for that period has been. The operator/payor then determines the new royalty rate for the next 12 month using the table in paragraph (b)(5)(ii) of this section. Given that there is a 2-month delay period for the operator/payor to calculate the new royalty rate, the new royalty rate would be effective December 1, 1997 through November 30, 1998 (plus the 2 calendar month grace period during which the next 12 months' royalty rate is determined—December 1, 1998 through January 31, 1999). (v) Prohibition. Any heavy oil property reporting an API average oil gravity determined by BLM to have resulted from any manipulation of normal production or adulteration of oil sold from the property will not receive the benefit of a royalty rate reduction under this paragraph (b). (vi) Certification. The operator/payor must use the applicable royalty rate when submitting the required royalty reports/payments to the Minerals Management Service (MMS). In submitting royalty reports/payments using a royalty rate reduction authorized by this paragraph (b), the operator/payor must certify that the API oil gravity for the initial and subsequent 12-month periods was not subject to manipulation or adulteration and the royalty rate was determined in accordance with the requirements and procedures of this paragraph (b). (vii) Agency action. If an operator/payor incorrectly calculates the royalty rate, the BLM will determine the correct rate and notify the operator/payor in writing. Any additional royalties due are payable to MMS immediately upon receipt of this notice. Late payment or underpayment charges will be assessed in accordance with 30 CFR 218.102. The BLM will terminate a royalty rate reduction for a property if BLM determines that the API oil gravity was manipulated or adulterated by the operator/payor. Terminations of royalty rate reductions for individual properties will be effective on the effective date of the royalty rate reduction resulting from a manipulated or adulterated API oil gravity so that the termination will be retroactive to the effective date of the improper reduction. The operator/payor must pay the difference in royalty resulting from the retroactive application of the non-manipulated rate. The late payment or underpayment charges will assessed in accordance with 30 CFR 218.102. (6) The BLM may suspend or terminate all royalty reductions granted under this paragraph (b) and terminate the availability of further heavy oil royalty relief under this section— (i) Upon 6 month's notice in the (ii) After September 10, 1999, if the Secretary determines the royalty rate reductions authorized by this paragraph (b) have not been effective in reducing the loss of otherwise recoverable reserves. This will be determined by evaluating the expected versus the actual abandonment rate, the number of enhanced recovery projects, and the amount of operator reinvestment in heavy oil production that can be attributed to this rule. (7) The heavy oil well property royalty rate reduction applies to all Federal oil produced from a heavy oil property. (8) If the lease royalty rate is lower than the benefits provided in this heavy oil well property royalty rate reduction program, the lease rate prevails. (9) If the property qualifies for a stripper well property royalty rate reduction, as well as a heavy oil well property reduction, the lower of the two rates applies. (10) The operator/payor must separately calculate the royalty for gas production (including condensate produced in association with gas) from oil completions using the lease royalty rate. (11) The minimum royalty provisions of §3103.3–2 will continue to apply. [61 FR 4750, Feb. 8, 1996] § 3103.4-4 Suspension of operations and/or production.(a) A suspension of all operations and production may be directed or consented to by the authorized officer only in the interest of conservation of natural resources. A suspension of operations only or a suspension of production only may be directed or consented to by the authorized officer in cases where the lessee is prevented from operating on the lease or producing from the lease, despite the exercise of due care and diligence, by reason of force majeure, that is, by matters beyond the reasonable control of the lessee. Applications for any suspension shall be filed in the proper BLM office. Complete information showing the necessity of such relief shall be furnished. (b) The term of any lease shall be extended by adding thereto the period of the suspension, and no lease shall be deemed to expire during any suspension. (c) A suspension shall take effect as of the time specified in the direction or assent of the authorized officer, in accordance with the provisions of §3165.1 of this title. (d) Rental and minimum royalty payments shall be suspended during any period of suspension of all operations and production directed or assented to by the authorized officer beginning with the first day of the lease month in which the suspension of all operations and production becomes effective, or if the suspension of all operations and production becomes effective on any date other than the first day of a lease month, beginning with the first day of the lease month following such effective date. Rental and minimum royalty payments shall resume on the first day of the lease month in which the suspension of all operations and production is terminated. Where rentals are creditable against royalties and have been paid in advance, proper credit shall be allowed on the next rental or royalty due under the terms of the lease. Rental and minimum royalty payments shall not be suspended during any period of suspension of operations only or suspension of production only. (e) Where all operations and production are suspended on a lease on which there is a well capable of producing in paying quantities and the authorized officer approves resumption of operations and production, such resumption shall be regarded as terminating the suspension, including the suspension of rental and minimum royalty payments, as provided in paragraph (d) of this section. (f) The relief authorized under this section also may be obtained for any Federal lease included within an approved unit or cooperative plan of development and operation. Unit or cooperative plan obligations shall not be suspended by relief obtained under this section but shall be suspended only in accordance with the terms and conditions of the specific unit or cooperative plan. [53 FR 17354, May 16, 1988. Redesignated at 61 FR 4750, Feb. 8, 1996] Browse Previous | Browse Next
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