Exhibit 99.1

 

DESCRIPTION OF BUSINESS

 

The following description should be read in conjunction with the “Selected Historical Financial Information of Royal” and the accompanying financial statements of Royal and related notes incorporated by reference herein to the Proxy Statement. The following discussion includes information regarding Royal Resources L.P. (“Royal”) as Falcon’s predecessor entity following the Closing, which includes certain interests in subsidiary companies which were not acquired by Falcon in the transactions contemplated by the Proxy Statement and described in this Current Report on Form 8-K. The Royal Resources L.P. subsidiaries that were contributed in the transactions are VickiCristina, LP, DGK ORRI Company, L.P., Noble EF DLG LP, Noble EF LP and Noble Marcellus LP. The interests in Riverbend Natural Resources, L.P and KGD ORRI, L.P. were not contributed in the transactions contemplated by the Proxy Statement. Unless otherwise noted, references to “we,” “us,” “our” and the “Company” refer to Royal and its consolidated subsidiaries prior to the consummation of the Business Combination.

 

The estimated proved reserve information for our properties on a historical basis as of December 31, 2017, contained in this Current Report on Form 8-K is based on reserve reports prepared by Ryder Scott Company, L.P. (“Ryder Scott”) and Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum engineers. Our estimated proved reserves on a pro forma basis are based on valuations prepared by Ryder Scott and were calculated by specifically identifying and removing the impact of any properties of Royal that were not contributed pursuant to the transactions contemplated by the Proxy Statement. As a result the pro forma reserve presentation herein represents only the reserves of the contributed Royal assets. A copy of each of the reserve reports is incorporated by reference herein to Annex I of the Proxy Statement.

 

 Overview

 

We were formed to own and acquire royalty interests, mineral interests, non-participating royalty interest and overriding royalty interests, or ORRIs, (“Royalties”) in oil and natural gas properties in North America, substantially all of which are located in the Eagle Ford Shale. These Royalties entitle the holder to a portion of the production of oil and natural gas from the underlying acreage at the sales price received by the operator, net of any applicable post-production expenses and taxes. The holder of these interests has no obligation to fund exploration and development costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life, which we believe results in low breakeven costs.

 

 We own Royalties that entitle us to a portion of the production of oil, natural gas and natural gas liquids (“NGLs”) from the underlying acreage at the sales price received by the operator, net of production expenses and taxes. We have no obligation to fund finding and development costs, pay capital expenditures such as plugging and abandonment costs. We have minimal allocated lease operating expenses. As such, we have historically operated with high cash margins, converting a large percentage of revenue to free cash flow, the majority of which can be distributed to our shareholders.

 

As of June 30, 2018, our assets consisted of Royalties underlying approximately 250,000 gross unit acres (approximately 20,000 net royalty acres normalized to 1/8th which assumes eight royalty acres for every mineral acre or 12.5% royalty interest per net mineral acre) that are concentrated in what we believe is the “core-of-the-core” of the liquids-rich condensate region of the Eagle Ford Shale in Karnes, DeWitt and Gonzales Counties, Texas. In all three of these counties, we also have substantial exposure to the Austin Chalk and Upper Eagle Ford formations, which have recently experienced increased horizontal development activity, in addition to the more established and historically developed Lower Eagle Ford formation. We believe that the wells and remaining drilling locations on the properties underlying our assets are among the most economic in North America, with operator IRRs in excess of 100% at current NYMEX pricing and operator break-even oil prices under $35 per barrel. Development activity has historically been supported by positive oil price differentials averaging a positive $0.47 per barrel over the past 12 months. In addition, our assets include Royalties related to approximately 58,000 gross unit acres in the Appalachian region, including Pennsylvania, West Virginia and Ohio. Our acreage was extensively delineated by 1,868 producing wells as of June 30, 2018, of which 1,527 are located in Karnes, DeWitt, and Gonzales Counties, providing extensive subsurface data control and substantial confidence on individual well initial production rates, production profiles and estimated ultimate recoveries (“EURs”). The average net daily production attributable to our net royalty interests was 6,595 BOD/d (69% liquids) for the three months ended June 30, 2018 and 5,685 BOE/d (70% liquids) for the six months ended June 30, 2018.

  

 

The Eagle Ford Shale is the second largest oil field in North America and is one of the lowest-cost and most active unconventional shale trends. It has a world-class aerial extent that covers approximately 13 million surface acres and has extensive data control as a result of more than 12,000 producing horizontal wells. The Eagle Ford has top-tier single-well economics, is operated by premier oil and gas companies and has access to abundant offtake infrastructure in close proximity to the U.S. Gulf Coast. In recent years, the entire Eagle Ford Shale play has undergone a technical transformation largely driven by utilization of modern drilling and completion techniques, resulting in improved oil and gas sectional recoveries, enhanced production rates, EURs, well economics and increased activity by operators. Our acreage is located in what we believe is the “core-of-the-core” of the Eagle Ford Shale and is characterized by high oil and liquids content and low finding and development costs as well as positive differentials that drive attractive economics to operators relative to other unconventional basins. At current NYMEX strip pricing, we had approximately 3,000 locations with operator IRRs in excess of 100%. We believe these factors make the development of our underlying acreage commercially viable and highly attractive in lower commodity price environments. Over 98% of our Eagle Ford and Austin Chalk acreage is operated by ConocoPhillips (“ConocoPhillips”), EOG Resources, Inc. (“EOG”), BHP Billiton Petroleum (“BHP”) and Devon Energy Corporation (“Devon”) through a joint venture and Pioneer Natural Resources Company (“Pioneer”).

 

Our revenues are derived from royalty payments we receive from our operators based on the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. For the year ended December 31, 2017, our revenues were derived 77% from oil and condensate sales, 11% from natural gas liquid sales and 12% from natural gas sales. For the six months ended June 30, 2018, our revenues were derived 83% from oil and condensate sales, 6% from natural gas liquid sales and 11% from natural gas sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile, and at December 31, 2017 we did not hedge any of our exposure to changes in commodity prices.

 

Our Properties

 

Our initial assets consist of Royalties related to 53,233 net acres to which royalties apply, associated with 452 drilling units, concentrated in what we believe is the “core of the core” of the Eagle Ford Shale as well as the Marcellus Shale and Point Pleasant formations. As of June 30, 2018, these interests entitled us to receive an average royalty of 1.36% from the producing wells on the acreage underlying our Royalties, with no additional future capital or operating expenses required. As of June 30, 2018, there were 1,868 horizontal wells producing on this acreage, and average net production for the six months ended June 30, 2018 was approximately 6,319 BOE/d on a historical basis including all Royal entities and 5,685 BOE/d on a pro forma basis to include production for only the entities being contributed in the transactions contemplated by this proxy statement. In addition, there were 133 horizontal wells in various stages of completion. As of June 30, 2018, there were 56 additional permits outstanding for undrilled wells or wells currently being drilled on the acreage underlying our Royalties. For the six months ended June 30, 2018, revenue generated from these Royalties was $47.0 million.

 

The leases underlying our Royalties were delineated by 1,868 producing horizontal wells as of June 30, 2018. We own interests in 452 drilling units in the Eagle Ford Shale, Marcellus Shale, and Point Pleasant formations.

 

Comparison of Types of Interests

 

Royalty Interest. Royalty interests generally result when the owner of a mineral interest leases the underlying minerals to a working interest holder pursuant to an oil and gas lease. Typically, the resulting royalty interest is a cost-free percentage of production revenues for minerals extracted from the acreage. Holders of royalty interests are generally not responsible for capital expenditures or lease operating expenses, but may be responsible for certain post-production expenses, and typically have limited environmental liability. Royalty interests expire upon the expiration of the oil and gas lease.

 

 

Mineral Interest. Mineral interests are perpetual rights of the owner to exploit, mine, and/or produce any or all of the minerals lying below the surface of the property. The holder of a mineral interest has the right to lease the minerals to a working interest holder pursuant to an oil and gas lease.

 

Non-Participating Royalty Interest (NPRI). NPRI is an interest in oil and gas production which is created from the mineral estate.  The NPRI is expense-free, bearing no operational costs of production. The term “non-participating” indicates that the interest owner does not share in the bonus, rentals from a lease, nor the right to participate in the execution of oil and gas leases.

 

Working Interest. Working interest holders have the rights to extract minerals from acreage leased pursuant to an oil and gas lease from a mineral interest holder. Holders of working interests are responsible for their pro rata share of capital expenditures and lease operating expenses, but holders of working interests only receive revenues after distributions have first been made to holders of royalty interests and ORRIs. Working interests expire upon the termination or expiration of the underlying oil and gas lease.

 

Overriding Royalty Interest (“ORRIs”). ORRIs are created by carving out the right to receive royalties from a working interest. Like royalty interests, ORRIs do not confer an obligation to make capital expenditures or pay for lease operating expenses and have limited environmental liability, however ORRIs may be calculated net of post-production expenses, depending on how the ORRI is structured. ORRIs that are carved out of working interests are linked to the same underlying oil and gas lease that created the working interest, and therefore, such ORRIs are typically subject to expiration upon the expiration or termination of the oil and gas lease.

 

OIL AND NATURAL GAS DATA

 

Reserves Presentation

 

Our estimated proved reserves on a historical basis as of December 31, 2017 are based on valuations prepared by Ryder Scott and NSAI and represent 100% of the total net proved liquid hydrocarbon reserves and 100% of the total net proved gas reserves in the Eagle Ford Shale, Marcellus Shale, Point Pleasant, and Bakken formations as of December 31, 2017. Our estimated proved reserves on a pro forma basis are based on valuations prepared by Ryder Scott and were calculated by specifically identifying and removing the impact of any properties of Royal that were not contributed pursuant to the Contribution Agreement. As a result the pro forma reserve presentation herein represents only the reserves of the contributed Royal assets. A copy of each of the summary reports of our reserve engineers with respect to our reserves as of 2017 on a historical and pro forma basis is incorporated by reference herein to Annex I of the Proxy Statement.

 

Proved Reserves

 

Evaluation and Review of Reserves

 

Our historical reserve estimates as of December 31, 2017 were prepared by Ryder Scott and NSAI. Ryder Scott and NSAI are independent petroleum engineering firms. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott and NSAI are third party engineering firms and do not own an interest in any of our properties and are not employed by us on a contingent basis.

 

 

Under SEC rules and regulations, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2017 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules and regulations. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for the properties underlying Royal’s interests were estimated by performance methods, analogy or a combination of both methods. Approximately 92% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 8% of the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

 

To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott and NSAI considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

 

Historically, employees of Riverbend have worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate proved reserves relating to our assets in the Eagle Ford Shale region. Riverbend’s technical team met with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provided historical information to the independent reserve engineers for our properties such as ownership interest, oil and gas production, commodity prices and transportation and marketing expenses. Operating and development costs were not realized to our interest but were used to calculate the economic limit life of the wells. These costs were estimated and checked by our independent reserve engineer. Riverbend’s technical staff used historical information for the properties underlying our interests such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs.

 

We anticipate that the preparation of the proved reserve estimates was completed in accordance with internal control procedures, including the following:

 

●

review and verification of historical production data, which data is based on actual production as reported by our operators;

 

●

preparation of reserve estimates by our Vice President—Engineering and Business Development or under his direct supervision;

 

●

review by our Vice President—Engineering and Business Development of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

 

●

direct reporting responsibilities by our Vice President—Engineering and Business Development to our Chief Executive Officer;

 

●

verification of property ownership by our land department; and

 

●

no employee’s compensation is tied to the amount of reserves booked.

 

 

The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2017 on a historical basis including all Royal entities and on a pro forma basis to include reserve information for only the entities being contributed in the transactions contemplated by the Proxy Statement. The reserve information is based on the reserve reports prepared by Ryder Scott and NSAI. The reserve reports have been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve reports are located in the continental United States.

 

		Royal Historical				Pro Forma
		as of December 31, 2017				as of December 31, 2017
Estimated proved developed reserves:
Oil (MBbls)			6,301				4,343
Natural gas (MMcf)			20,715				17,410
Natural gas liquids (MBbls)			1,793				1,285
Total (MBOE)			11,547				8,530
Estimated proved undeveloped reserves:
Oil (MBbls)			13,142				11,571
Natural gas (MMcf)			39,037				35,152
Natural gas liquids (MBbls)			2,650				2,057
Total (MBOE)			22,298				19,487
Estimated Net Proved Reserves:
Oil (MBbls)			19,443				15,914
Natural gas (MMcf)			59,752				52,562
Natural gas liquids (MBbls)			4,443				3,342
Total (MBOE)(l)			33,845				28,016
Percent proved developed			34.12	%			30.44	%
PV-10 of proved reserves (in millions)(2)		$	615.2			$	521.1

 

	(1)	Estimates of reserves as of December 31, 2017 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the year ended December 31, 2017 in accordance with revised SEC rules and regulations applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $51.34 per Bbl for oil and $2.98 per MMBtu for natural gas at December 31, 2017. The price per Bbl for natural gas liquids was modeled as a percentage of oil price, which was derived from historical accounting data. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our ORRI share in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
	(2)	In this Current Report on Form 8-K, we have disclosed our PV-10 based on our reserve report. PV-10 represents the period end present value of estimated future cash inflows from our natural gas and crude oil reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using SEC pricing requirements in effect at the end of the period. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. PV-10 differs from standardized measure because it does not include the effects of income taxes. However, because we were a limited partnership, we were generally not subject to federal income taxes and thus historically our PV-10 for proved reserves and standardized measure are equivalent. Neither PV-10 nor standardized measure represents an estimate of fair market value of our natural gas and oil properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities.

 

As of December 31, 2017, our historical proved developed reserves totaled 6,301 MBbls of oil, 20,715 MMcf of natural gas and 1,793 MBbls of natural gas liquids, for a total of 11,547 MBOE. Of the total proved developed reserves, 79% are producing and the remaining 21% are from wells that have been stimulated but are not yet producing hydrocarbons. As of December 31, 2017, our pro forma proved developed reserves totaled 4,343 MBbls of oil, 17,410 MMcf of natural gas and 1,285 MBbls of natural gas liquids, for a total of 8,530 MBOE. Of the total proved developed reserves, 74% are producing and the remaining 26% are from wells that have been stimulated but are not yet producing hydrocarbons.

 

 

The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See “Risk Factors” in the Proxy Statement. We have not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.

 

Additional information regarding our historical and pro forma proved reserves can be found in the reserve reports as of December 31, 2017 prepared by Ryder Scott and NSAI, which are incorporated by reference herein to Annex I of the Proxy Statement.

  

Proved Undeveloped Reserves

 

As of December 31, 2017, our historical proved undeveloped reserves totaled 13,142 MBbls of oil, 39,037 MMcf of natural gas and 2,650 MBbls of natural gas liquids, for a total of 22,298 MBOE. As of December 31, 2017, our pro forma proved undeveloped reserves totaled 11,571 MBbls of oil, 35,152 MMcf of natural gas and 2,057 MBbls of natural gas liquids, for a total of 19,487 MBOE. PUD reserves will be converted from undeveloped to developed as the applicable wells begin production.

 

During the year ended December 31, 2017, our operators converted 1,348 MBOE of PUD reserves, which represented approximately 11.5% of our estimated PUD reserves as of December 31, 2016. Our PUD reserves increased from 11,728 MBOE to 22,298 MBOE due to:

 

●

the divestment of 955 MBOE in connection with the sale of KGD ORRI, L.P.;

 

●

the conversion of 1,348 MBOE of PUD reserves into PDP and PNP reserves;

 

	●	net positive revisions of 6,801 MBOE as a result of the addition of certain locations to the drilling schedule as part of a revised development plan resulting from improved pricing conditions;
	●	positive revisions of 4,729 MBOE as a result of revised type curves reflecting operator-specific performance; and
	●	extensions of 1,344 MBOE as a result of certain locations added to the development schedule through the permitting or discovery of previously uncaptured reserves.

 

All of our PUD drilling locations are scheduled to be drilled prior to the end of December 2022. This development schedule is based on a 91 well inventory waiting to be brought online, 56 permits that identify activity and continued PUD conversion based on historical drilling activity and the publicly announced capital expenditure plans of our operators. As an owner of Royalties and not working interests, the contributed Royal Entities were not required to make capital expenditures and did not make capital expenditures to convert PUD reserves from undeveloped to developed.

 

Identification of Drilling Locations

 

Our identification of drilling locations is based on specifically identified locations on our leasehold acreage based on our assessment of current geoscientific, engineering, land, well-spacing and historic production profile information derived from state agencies and public statements by our operators on the acreage underlying our interests. These drilling locations are identified on a detailed map and allocated a reserve profile and identifier. Further, Ryder Scott and NSAI reviewed and confirmed our drilling locations in estimating our PUD reserves in connection with the preparation of our reserve report as of December 31, 2017. We update and revise our drilling locations on a periodic basis as our assessment of the information described above changes.

 

 OIL AND NATURAL GAS PRODUCTION PRICES AND PRODUCTION COSTS

 

Production and Price History

 

The following table sets forth information regarding our net production of oil, natural gas and natural gas liquids, substantially all of which is from the Eagle Ford Shale region in South Texas, and certain price and cost information for each of the periods indicated:

 

		Pro Forma								Royal Historical
		Six Months Ended June 30,				Year Ended December 31,				Six Months Ended June 30,				Year Ended December 31,
		2018				2017				2018				2017				2016				2015
Production Data:
Eagle Ford Shale
Oil (Bbls)			587,334				885,681				600,588				1,402,729				1,397,556				1,876,487
Natural gas (Mcf)			1,314,015				1,761,343				1,352,169				3,083,099				2,936,394				4,201,152
Natural gas liquids (Bbls)			117,751				269,953				122,867				493,334				476,780				621,222
Combined volumes (BOE)			924,088				1,449,191				948,817				2,409,913				2,363,735				3,197,901
Daily combined volumes (BOE/d)			5,105				3,970				5,242				6,603				6,476				8,761
Total
Oil (Bbls)			589,626				892,893				675,687				1,582,322				1,474,218				1,919,959
Natural gas (Mcf)			1,860,739				3,124,338				1,955,624				4,565,892				4,143,679				5,357,859
Natural gas liquids (Bbls)			129,214				301,553				142,029				542,706				511,337				650,599
Combined volumes (BOE)			1,028,963				1,715,169				1,143,653				2,886,010				2,676,168				3,463,530
Daily combined volumes (BOE/d)			5,685				4,699				6,319				7,907				7,332				9,489
Average Realized Prices:
Oil (per Bbl)		$	66.14			$	50.96			$	65.73			$	50.10			$	39.91			$	46.12
Natural gas (per Mcf)		$	2.83			$	2.70			$	2.85			$	2.81			$	2.19			$	2.33
Natural gas liquids (per Bbl)		$	22.52			$	20.99			$	22.53			$	20.63			$	12.04			$	13.07
Weighted average combined (per BOE)		$	45.67			$	34.98			$	46.30			$	35.67			$	27.69			$	31.19

 

Producing Wells

 

As of June 30, 2018, we owned Royalties in 1,868 producing wells located on the acreage in which we have an interest. The following table provides detailed information relating to our producing wells:

 

		Gross Producing Wells				Net Producing Wells
Oil			1,161			16.0
Gas			707			9.4
Total			1,868			25.4

 

 

Acreage

 

The following tables set forth information as of June 30, 2018 relating to total gross and net acreage in the units associated with our Royalties:

 

Basin		Gross Developed Acreage (1)				Gross Undeveloped Acreage (2)				Total Gross Acreage
Eagle Ford Shale			71,680				100,472				172,152
Marcellus Shale and Point Pleasant			26,640				40,369				67,009
Total			98,320				140,841				239,161

 

Basin		Net Developed Acreage (1)				Net Undeveloped Acreage (2)				Total Net Acreage
Eagle Ford Shale			933				1,531				2,464
Marcellus Shale and Point Pleasant			449				78				527
Total			1,381				1,609				2,991

 

(1)	Developed acres are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease. The value provided is for horizontal wells only and are based on 40 acres per well in the Eagle Ford Shale and 80 acres per well in the Marcellus Shale and Point Pleasant formation for wells drilled as of June 30, 2018.
(2)	Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

 

Drilling Results

 

As of June 30, 2018, our operators associated with our Royalties had 138 wells in the process of drilling, completing or dewatering or shut in awaiting infrastructure that are not reflected in the above table. The following table sets forth for the periods indicated below, the number of net productive and dry development and exploratory wells completed, regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value.

 

		Six Months Ended June 30,				Year Ended December 31,
		2018				2017				2016
Development:
Productive			80				193				165
Dry			0				0				0
Exploratory:
Productive			0				0				0
Dry			0				0				0
Total:
Productive			80				193				165
Dry			0				0				0

 

 

Competition

 

The oil and natural gas industry is highly competitive; we primarily compete with companies for the acquisition of oil and natural gas properties some of whom have greater resources than we do. These companies may be able to pay more for certain productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our larger or more integrated competitors may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our ability to acquire additional properties in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

 

Seasonal Nature of Business

 

Generally, demand for oil and natural gas decreases during the summer months and increases during the winter months. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for our operators in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

 

Regulation

 

The following disclosure describes regulation directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties.

 

Oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business.

 

Environmental Matters

 

Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict and joint and several liability nature of such laws and regulations could impose liability upon responsible parties (including the operators of the acreage underlying our Royalties) regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our business and prospects.

 

 

Waste Handling

 

The Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, there is no guarantee that the EPA or state or local governments will not adopt more stringent requirements for the handling of non- hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. For example, in December 2016, the EPA and several environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019, for revision of certain regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. If the EPA proposes revised oil and gas regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Legislation has also been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on the capital expenditures and operating expenses of the operators of the acreage underlying our Royalties.

 

Administrative, civil and criminal penalties can be imposed on the operators of the acreage underlying our Royalties for failure to comply with waste handling requirements. Any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase the costs to manage and dispose of wastes for such operators.

 

Remediation of Hazardous Substances

 

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and analogous state laws, generally impose strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying our Royalties to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and results of operations. Liability for any contamination under these laws could require the operators of the acreage underlying our Royalties to make significant expenditures to investigate and remediate such contamination or attain and maintain compliance with such laws and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.

 

Water Discharges

 

The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”). In addition, the EPA and the Corps released a rule to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, which went into effect in August 2015. In October 2015, the U.S. Court of Appeals for the Sixth Circuit stayed the rule revising the WOTUS definition nationwide pending further action of the court. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” However, in January 2018, the U.S. Supreme Court ruled that the rule revising the WOTUS definition must be reviewed first in the federal district courts, which resulted in a withdrawal of the stay by the Sixth Circuit. In addition, the EPA has proposed to repeal the rule revising the WOTUS definition, and in January 2018 EPA released a final rule that delays implementation of the rule revising the WOTUS definition until 2020 to allow time for EPA to reconsider the definition of “waters of the United States.” Several states and environmental groups have since filed lawsuits challenging the delay rule. To the extent the rule revising the WOTUS definition is implemented, it could significantly expand federal control of land and water resources across the United States, triggering substantial additional permitting and regulatory requirements.

 

 

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of the facilities on the acreage underlying our Royalties. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. In addition, in June 2016, the EPA finalized wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly-owned treatment works; for certain facilities, compliance is required by August 29, 2019. This pending restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs.

 

The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

 

Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations, for the operators of the acreage underlying our Royalties.

 

Air Emissions

 

The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in August 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations. The rules subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards and the National Emission Standards for Hazardous Air Pollutants programs and include standards for completions of hydraulically-fractured gas wells, reduced emission completion techniques, and pit flaring of gas not sent to the gathering line. The standards are applicable to newly drilled and fractured wells and wells that are re-fractured on or after January 1, 2015. The rules also establish specific requirements for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment. The EPA amended these rules in December 2014 to specify requirements for different flowback stages and to expand the rules to cover more storage vessels, among other changes.

 

 

Costs for environmental compliance of the operators of the acreage underlying our Royalties may increase in the future based on new air emissions regulations. In November 2016, the BLM issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on public lands. In December 2017, the BLM finalized a suspension of certain requirements of the rules until 2019, and in February 2018, the BLM published a proposal to revise or rescind the rules. California, New Mexico, and several environmental groups filed lawsuits challenging BLM’s suspension of the rules, which resulted in the U.S. District Court for the Northern District of California issuing a February 2018 preliminary injunction enjoining the suspension of the rules. However, in April 2018, the U.S. District Court for the District of Wyoming, in a separate pending lawsuit brought by Wyoming, Montana, and industry groups, stayed implementation of the rules until the BLM completes the rulemaking process for revising or rescinding the rules. Several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. In addition, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. The EPA has also adopted new rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. Further, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion in October 2015. Pursuant to an order issued by the U.S. District Court for the Northern District of California in lawsuits brought by a coalition of states and environmental groups against the EPA for failing to complete initial area designations under the standard by the October 2017 statutory deadline, EPA is required to complete all remaining initial area designations by April 30, 2018, except for designations for certain areas in Texas, which must be completed by July 17, 2018. State implementation of the revised NAAQS could result in stricter permitting requirements or delay, or limit our ability to obtain permits, and result in increased expenditures for pollution control equipment.

 

These laws and regulations may increase the costs of compliance for some facilities on the acreage underlying our Royalties, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

 

Climate Change

 

In response to findings that emissions of greenhouse gases (“GHGs”), including carbon dioxide and methane, present an endangerment to public health and the environment, the EPA has adopted regulations to restrict GHG emissions under existing provisions of the federal Clean Air Act. As discussed in the “Climate Change” risk factor above, EPA has finalized rules that set additional emissions limits for volatile organic compounds and established new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, and transmission and storage activities. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis.

 

In 2015, the United States participated in the United Nations Climate Change Conference, which led to the creation of the Paris Agreement. The Paris Agreement requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. In June 2017, the United States announced its withdrawal from the Paris Agreement, although the earliest possible effective date of withdrawal is November 2020. Despite the planned withdrawal, certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and many states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.

 

 

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with production and increase costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our business.

 

Regulation of Hydraulic Fracturing

 

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal SDWA regulates the underground injection of substances through the UIC program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, as discussed in the “Hydraulic Fracturing” risk factor included elsewhere in the Proxy Statement, in recent year efforts have been made to regulate hydraulic fracturing at the federal level.

 

In addition, several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature previously adopted legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission subsequently adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit. This law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the Occupational Safety and Health Act for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Further, in May 2013, the Texas Railroad Commission issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

 

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative or regulatory changes could cause operators of the operation on the acreage underlying our Royalties to incur substantial compliance costs, and compliance or the consequences of any failure to comply by operators could have a material adverse effect on our financial condition and results of operations.

 

In addition, hydraulic fracturing operations require the use of a significant amount of water, and the inability of the operators of the acreage underlying our Royalties to locate sufficient amounts of water, or dispose of or recycle water used in their drilling and production operations, could adversely impact their operations. Moreover, new environmental initiatives and regulations could include restrictions on the ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.

 

 

Finally, in some instances, the operation of underground injection wells has been alleged to cause earthquakes. Such issues have sometimes led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Future orders or regulations addressing concerns about seismic activity from well injection could affect operations on the acreage underlying our Royalties.

 

Endangered Species Act

 

Some of the operations on acreage underlying our Royalties may be located in areas that are designated as habitats for endangered or threatened species under the ESA. In February 2016, the U.S. Fish and Wildlife Service published a final policy which alters how it identifies critical habitat for endangered and threatened species. A critical habitat designation could result in further material restrictions to federal and private land use and could delay or prohibit land access or development. Moreover, the U.S. Fish and Wildlife Service continues to make listing decisions and critical habitat designations where necessary, including for over 250 species as required under a 2011 settlement approved by the U.S. District Court for the District of Columbia, and many hundreds of additional anticipated listing decisions have already been identified beyond those recognized in the 2011 settlement. The designation of previously unprotected species as being endangered or threatened, if located in the areas where we have Royalties, could cause the operators of the operations on the acreage underlying our Royalties to incur additional costs or become subject to operating restrictions in areas where the species are known to exist.

 

Other Regulation of the Oil and Natural Gas Industry

 

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

 

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

 

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

 

Drilling and Production

 

The operations of our operators are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

●

the location of wells;

 

●

the method of drilling and casing wells;

 

 

●

the timing of construction or drilling activities, including seasonal wildlife closures;

 

●

the rates of production or “allowables”;

 

●

the surface use and restoration of properties upon which wells are drilled;

 

●

the plugging and abandoning of wells; and

 

●

notice to, and consultation with, surface owners and other third parties.

 

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that our operators can produce from our wells or limit the number of wells or the locations at which operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations operators can drill.

 

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of the acreage underlying our Royalties operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

 

Natural Gas Sales and Transportation

 

Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.” Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

 

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which our operators may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that our operators produce, as well as the revenues our operators receive for sales of natural gas and release of natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas-related activities.

 

 

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in-state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our operators’ costs of transporting gas to point-of-sale locations.

 

Oil Sales and Transportation

 

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

 

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

 

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to our operators to the same extent as to our or their competitors.

 

State Regulation

 

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations our operators can drill.

 

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on it.

 

Our Relationship with Riverbend

 

Royal was managed and operated by the board of directors and executive officers of its general partner, some of whom are also employees of Riverbend. However, neither Royal nor its subsidiary had any employees. All of the employees that conducted Royal’s business, including its executive officers, were employed by Royal’s general partner.

 

As of June 30, 2018, Riverbend had 27 full time employees. None of Riverbend’s or Royal’s general partner’s employees were represented by labor unions or covered by any collective bargaining agreements. Riverbend and Royal’s general partner also hired independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist their full time employees.

 

Facilities

 

Riverbend leased office space for Royal’s principal executive offices in Houston, Texas. We believe our facilities are adequate for our current operations.

 

Legal Proceedings

 

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, there are no pending litigation, disputes or claims against it that, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.