Regulatory and Environmental Report - 2001
Preface
No single law governs oil and gas exploration, development or production activities in Ohio. To the contrary – our industry is regulated by a myriad of federal and state statutes and administrative rules governing practically all aspects of energy production. Many of those laws are well known to the industry and are directly related to production activities, such as Division regulations on the permitting, spacing and plugging of wells drilled in Ohio. Others may not be as obvious, such as state and federal regulations that may require the filing of hazardous chemical inventory forms under SARA, the Community-Right-to-Know Program.This report is designed to serve as a reference guide for the Oil and Gas Association, its many members and friends. As such, it offers a brief overview of many of the applicable federal and state laws governing our industry. It is not, however, designed to be a comprehensive discussion of those laws. Before acting on the information discussed in this report, therefore, the reader should consult the relevant statutes and regulations directly, as well as knowledgeable legal counsel.
To make things as helpful as we could, many of the citations in this work have been "hyperlinked" to state and federal websites (and other related sites) that have published the actual text of the statutory and regulatory provisions being discussed. All the reader needs to do to connect to that site is "click" on the hyperlinked text (which is both highlighted and underlined). Before relying on the information at that site, however, the reader should check to make sure that it remains current and up to date.
We hope that you find this report helpful and welcome any and all comments on how it might be improved in future editions.
I. The Division of Mineral Resources Management
Prior to the enactment of Ohio's oil and gas conservation laws in 1965, the rule of capture controlled how oil and gas could be extracted from the earth. In general, that rule permits the owner of a tract of land to acquire title to the oil and gas he produces from wells drilled on his land, even though part of such oil and gas may have migrated from adjoining lands. Without intervening governmental regulation, that rule resulted in the lease line and town lot drilling that appear in the state's historical records. Two areas in Ohio where this can be seen are Northwestern Ohio and Morrow County.In response to the Morrow County boom, the Ohio General Assembly enacted an oil and gas conservation law in 1965. That act established the Division of Oil and Gas, now known as the Division of Mineral Resources Management, and empowered it to conserve Ohio's oil and gas while protecting private parties' correlative rights. Found in Ohio Revised Code Chapter 1509, that act directs the Division to prevent waste, regulate drilling, establish state-wide spacing rules, and compel pooling and unitization.
On July 1, 2000, the General Assembly enacted House Bill 601, which combined the former Division of Oil and Gas and Division of Mines and Reclamation into a single management structure – the Division of Mineral Resources Management. H.B. 601 made no substantive changes in the statutes regulating the two industries, however.
As of this writing, the Chief of the new Division is Mike Sponsler. Tom Tugend, the former Chief of the Division of Oil and Gas, is the Division's Deputy Chief of Field Operations, which section has responsibility for permitting and field enforcement for both oil and gas and mine reclamation operations. Scott Kell, former Deputy Chief of the Division of Oil and Gas, is the Division's Chief of Safety and Technical Services. A more detailed table of organization for the new Division can be found at its website, http://www.dnr.state.oh.us/mineral/mineral/about/tabid/10351/Default.aspx.
The Division can be reached at the following:
Division of Mineral Resources Management Ohio Dept. of Natural Resources 1855 Fountain Square Building H-3 Columbus, Ohio 43224 http://www.dnr.state.oh.us/mineral/default/tabid/10352/Default.aspx Tel. (614) 265-6633 Fax (614) 265-7999
II. State Oil & Gas Regulation
This section briefly addresses Ohio law governing the exploration, development and production of oil and gas in the state.A. Drilling Permits
Ohio law requires a permit to drill a new well, deepen an existing well, reopen an existing well, convert a well to any use other than its original purpose, or to plug back a well to a different source of supply. Once granted, the permit (or a copy) must be posted in a conspicuous and easily accessible place at the well site, along with the name, current address and telephone number of the permit holder and the telephone numbers for fire and other emergency medical services. The permit is valid for one year.[1]1. Application
To obtain the drilling permit, an application must be filed with the Division of Mineral Resources Management (accompanied by a $250.00 fee) that contains, among other things, the following information:
- the name and address of the owner (i.e., the person with the right to drill on the particular tract of land at issue);
- an affidavit that the permit applicant is the owner;
- the signature of the owner or the owner's authorized agent;
- the names and addresses of each of the royalty owners;
- the location of the tract or drilling unit, including a map showing the location of the proposed well, the location of nearby wells, and the location of all buildings, public roads, railroads and streams within 150' of the proposed wellsite;
- a designation of the well by name and number;
- the geological formation to be drilled to;
- a sworn statement that all local government requirements will be complied with until abandonment of the well;
- a restoration plan for the land surface disturbed by the drilling activities;
- a description of the county, township and municipal roads that will be used for access to the site; and
- a disposal plan for brine and other wastes produced in connection with the drilling activities.[2]
By law, the Division is required to issue the permit within 21 days, but no sooner than 10 days, of the filing of the application if the application has not already been denied by Division order. An expedited review of the application can be had if the well is not located in a gas storage reservoir or reservoir protective area. Unless an order is issued by the Division denying such request, the permit shall be issued in within 7 days of the applicant's filing of the request for expedited review. An additional nonrefundable fee of $500.00 must accompany the request for expedited review.
The Division then reviews the permit application to ensure that the operations contemplated by the applicant do not create a substantial risk of a violation of Ohio oil and gas law that would present an imminent danger to public health or safety or damage to the environment. If the Division has any objections to the application, it will usually notify the applicant of its concerns and give the applicant a reasonable opportunity to resolve, and, if necessary, cure, the Division's misgivings. If the application is nonetheless denied, the applicant may appeal that decision to the Ohio Oil and Gas Commission. See, generally, R.C. 1509.06.
3. Financial Responsibilities
Unless exempt, well owners must obtain liability insurance in an amount of not less than $300,000 bodily injury coverage and $300,000 property damage coverage to pay for injury to persons or damage to property caused by the drilling, operation, or plugging of all of the owner's wells in the state. This insurance must be maintained until all of the owner's wells in the state are plugged and abandoned as provided for by law.
Well owners must also execute and file with the Division a surety bond in the following amounts and conditioned upon the restoration and plugging requirements of Ohio's oil and gas laws: For one well – $5,000; For a blanket bond covering all wells operated by the principal – $15,000.
Alternatively, the owner may deposit with the Division cash in an amount equal to the required surety bond, or negotiable certificates of deposit or irrevocable letters of credit having a cash value equal to or greater than the amount of such surety bond. Sworn financial statements may also be accepted by the Division in lieu of the surety bond. As a general matter, however, financial statements are only available to those owners classified as exempt domestic well owners or to non-domestic well owners from which the Division has previously accepted financial statements.[3]
B. Well Spacing
In general, new wells, and existing wells to be deepened, plugged back, or reopened to a source of supply different from the existing pool, must substantially conform to the following well spacing requirements:| Well Depth (ft.) | Minimum Acreage/Well | Minimum Distances Between Wells of the Same Pool (ft.) | Minimum Distance from Unit Boundary (ft.) |
|---|---|---|---|
| 0-1000 | 1 | 200 | 100 |
| 1001-2000 | 10 | 460 | 230 |
| 2001-4000 | 20 | 600 | 300 |
| 4000+ | 40 | 1000 | 500 |
Spacing exceptions may be granted to applicants who demonstrate that the proposed well will be an offset to a well drilled or commenced before the effective date of these spacing requirements and which is producing or is capable of producing on an adjacent tract, and to applicants who demonstrate that the exception will protect correlative rights and/or promote conservation.
Additionally, no well may be drilled: (i) nearer than 100' to any inhabited dwelling; (ii) nearer than 100' to any public building that may be used, among other things, as a place of resort, assembly, education, entertainment, lodging, trade; (iii) nearer than 50' to the traveled part of any public street, road or highway; (iv) nearer than 50' to a railroad track; or (v) nearer than 100' to any other well.[4]
C. Plugging and Abandonment
In general, any well that is not producing or that becomes incapable of producing in commercial quantities must be plugged in accordance with the Division's regulations. By statute, however, the Division must make exception for wells being used for domestic or other lawful purposes. The responsibility for properly plugging the well lies with the well owner, and once that duty arises it is a continuing duty and does not terminate by a transfer of the well to another. Houser v. Brown (1986), 29 Ohio App.3d 358.[5]1. Permit Application
As with drilling, Ohio law requires a permit to plug and abandon a well. The permit application must be filed with the Division sufficiently in advance of the plugging operations to allow for an inspector to be present and must include the following information: the owner's name and address; the signature of the owner or the owner's authorized agent; the well's name, number and location; the total depth to be plugged; the date and amount of last production from the well; an affidavit that the owner has notified in writing the landowner, adjacent landowners and adjoining well owners of the intended plugging; and an affidavit that the permit applicant is indeed the well owner. See R.C. 1509.13.
Once issued, the owner has one year from the date of the permit's issuance to commence plugging operations or the permit will expire. If plugging is commenced but not completed at the end of that one-year period, plugging may continue with due diligence. See Ohio Admin. Code 1501:9-11.
2. Supervision
Each plugging operation must be conducted under the supervision of an inspector unless permission has been granted by the Division. The well owner must notify the inspector when plugging operations will commence at a dry or lost hole in sufficient time for the inspector to be present. For all other wells, the inspector must be notified at least 24 hours prior to commencement of plugging operations. See Ohio Admin. Code 1501:9-11.
3. Plugging Operations
The Division's objective when issuing a plugging permit is to ensure that the oil, gas, water and other fluids associated with the well are confined to the reservoir rocks in which they occur or originate. Division regulations contain detailed rules for plugging a well with cement or prepared clay, and indicate that other materials may be used if approved by the Division. See Ohio Admin. Code 1501:9-11-07 through 1501:9-11-09. As a general matter, though, well owners are required to plug rotary drilled holes with cement, while they have the option of plugging cable tool drilled holes with either cement or prepared clay. See, generally, Ohio Admin. Code 1501:9-11.
D. Storage and Disposal of Brine (and other Waste Substances)
With limited exceptions, Ohio law prohibits the placement of brine in surface or groundwater, or in or on the land, in such quantities or in such a manner that actually causes, or could reasonably be anticipated to cause, (i) water used for human or domestic animal consumption to exceed Safe Water Drinking Act standards or (ii) damage or injury to public health or safety or the environment. For the applicable statutory and regulatory provisions, see R.C. 1509.22; Ohio Admin. Code 1501:9-3.1. Storage
Division regulations authorize the use of both tanks and pits to temporarily store brine and other waste substances resulting from, obtained from, or produced in connection with drilling, fracturing, reworking, reconditioning, plugging back, or plugging operations so long as they are liquid tight. By statute, pits may not be used for the ultimate disposal of brine. See R.C. 1509.22; Ohio Admin. Code 1501:9-3.
- Pits
All pits used for the temporary storage of brine and other waste substances must be constructed and maintained so as to prevent their escape. The level of brine in excavated pits can at no time be permitted to rise above the lowest point of the ground surface, and an embankment sufficiently above the level of the surface to prevent surface water from entering the storage area is required. Pits may not be used in areas subject to flooding by streams, rivers or lakes unless they are constructed in such a manner that the pits would not normally be affected. Significantly, stored brine and other waste substances must be drained or removed and properly disposed of at intervals not to exceed 180 days. See Ohio Admin. Code 1501:9-3. - Tanks
Where tanks are used to temporarily store brine or other waste substances, they must be liquid tight. Burial of tanks is prohibited except as permitted by the Division and then only when witnessed by an inspector. Moreover, if permission is granted for burial, no tank composed of a material other than cathodically-protected steel may be used. See Ohio Admin. Code 1501:9-3.
Brine, as a general matter, may be disposed of only by injection into an underground formation (including annular disposal), by surface application, or in association with a method of enhanced recovery. Each method requires certain authorizations and/or compliance with specific Division regulations not outlined here. See, e.g., Ohio Admin. Code 1501:9-3-06 (addressing brine injection wells). The Division may also authorize other methods for implementing and testing new technologies or disposal methods.
Each year, well owners engaged in the disposal of brine must provide the Division with a report by the first day of March containing the quantities of saltwater disposed of during the previous calendar year, as well as the location of disposal and quantity disposed of at each location. See Ohio Admin. Code 1501:9-3-04.
Muds, cuttings and other waste substances may not be disposed of in violation of Division regulations (which for the most part do not expressly address their disposal). By statute, however, waste substances may be disposed of by injection into an underground formation under a permit issued by the Division. The permit application must be accompanied by a $100.00 fee and cannot be granted unless the Division concludes that the injection will not result in the presence of any contaminant in ground water that supplies a public water system, or which can reasonably be expected to supply a public water system, at levels that would threaten compliance with national primary drinking water regulations or might otherwise adversely affect human health. See R.C. 1509.22.
[1] See R.C. 1509.05.
[2] See, generally, R.C. 1509.06; Ohio Admin. Code 1501:9-1.
[3] See R.C. 1509.07; Ohio Admin. Code 1501:9-1.
[4] See R.C. 1509.24; Ohio Admin. Code 1501:9-1.
[5] See, generally, R.C. 1509.12 and R.C. 1509.13; Ohio Admin. Code 1501:9-11.
III. Pooling and Unitization
Pooling has become a frequently used tool by oil and gas producers as a result of the competitive leasing of oil and gas properties. It describes the joining together of small tracts or portions of tracts for the purpose of having sufficient acreage to receive a well drilling permit under the Division's spacing requirements, and for the purpose of sharing production by interest owners in such a pooled unit. Unitization, or unit operations, on the other hand, is a tool used only sparingly in Ohio and refers to the consolidation of mineral or leasehold interests covering all or part of a common source of supply. The primary function of unit operations is to maximize production by efficiently draining the reservoir, utilizing the best engineering techniques that are economically feasible. See Kramer & Martin, Pooling and Unitization. Both are discussed in greater detail below.A. Voluntary Pooling
Ohio Revised Code Section 1509.26 permits the voluntary pooling of adjoining tracts of land in order to form the minimum acreage under Ohio's spacing laws. Specifically, Ohio Revised Code Section 1509.26 provides as follows:Thus, if the operators of two or more adjoining tracts agree to pool all or a portion of their respective tracts, and the oil and gas leases permit pooling, they may obtain a drilling permit for the combined tracts and operate it as a single pool.The owners of adjoining tracts may agree to pool such tracts to form a drilling unit which conforms to the minimum acreage and distance requirements of the division of oil and gas under section 1509.24 or 1509.25 of the Revised Code. Such agreement shall be in writing, a copy of which shall be submitted to the division of oil and gas with the application for permit required by section 1509.05 of the Revised Code. Parties to the agreement shall designate one of their number as the applicant for such permit. [R.C. 1509.26.]
B. Mandatory (Compulsory) Pooling
Where adjoining property owners are unable to voluntarily reach an agreement to pool all or part of their respective tracts to form a drilling unit under Ohio Revised Code Section 1509.26, Ohio Revised Code Section 1509.27 may permit mandatory pooling. An operator must satisfy two prerequisites before applying for a mandatory pooling order under Section 1509.27:- the owner's tract of land must be of insufficient size or shape to meet the requirements for drilling a well thereon; and
- The owner must have been unable to form a drilling unit under a voluntary agreement provided in Revised Code 1509.26 on a just and equitable basis. [R.C. 1509.27.]
The case of Johnson v. Kell, 89 Ohio App. 3d 623, 626 N.E.2d 1002 (Franklin App. 1993), highlights the requirement that an owner attempt to form a voluntary unit on a just and equitable basis before requesting a mandatory pooling from the Division. In that case, the applicant attempted to pool only 1.4 of 13 acres from an adjoining property into a drilling unit. The evidence suggested that the drilling unit would offset an existing well located on the adjoining property. Under those circumstances, the Board of Review found, and the Tenth Circuit Court of Appeals upheld, that the applicant's efforts to voluntarily pool were not just and equitable because the applicant's offers would not adequately compensate the landowner for the likely adverse impact on the existing well. The Tenth Circuit also noted that the applicant failed to show that the forced pooling would protect the adjoining property owner's correlative rights. The court recognized that the mandatory pooling of only 1.4 of the adjoining property owner's 13 acres would severely restrict the development of the remaining 11.6 acres, while only compensating the landowner for the 1.4 pooled acres.
C. Unitization
Ohio Revised Code Section 1509.28 permits the unitization of several tracts of land where 65% of the owners are in favor of forming a unit operation. This commonly occurs in secondary recovery operations. Under Section 1509.28, the owners of 65% of the land area may apply to the Chief for an order approving unit operations or the Chief has the power to initiate unitization on his own. Before issuing a unitization order, the Chief must hold a hearing, after which he may issue an order approving unitization if he finds the following:- there is a pool;
- the unit operation is reasonably necessary to increase substantially the ultimate recovery of oil;
- the value of the estimated additional recovery of oil exceeds the cost incident to conducting the unit operation; and
- the plan for unit operations is just and reasonable
IV. Ohio's One-Call Notification Program
Excavation poses a risk for all underground utility facilities. A study from the U.S. Department of Transportation's Office of Pipeline Safety reports that, with respect to pipeline incidents, third-party excavation damage has accounted for 33% of all pipeline accidents, 40% of all reported fatalities, 38% of all reported injuries, and 51% of all property damage. For example, the OPS reports that a hazardous liquids pipeline carrying gasoline under a hospital parking lot in Reston, Virginia, ruptured on March 28, 1993, due to backhoe excavation activities. As a result, approximately 407,000 gallons of gasoline were spilled into a nearby creek. While the study does not mention any personal injuries as a result of the pipeline rupture, the monetary costs were significant: $10.3 million in cleanup costs, $11.5 million spent for pollution prevention activities and $2.1 million for private settlements and penalties.Ohio, like many states, has a one-call notification program designed to prevent this type of injury.
A. Participation in Protection Service
Ohio law requires every utility that owns or operates underground utility facilities to participate in and register the location of those facilities with a protection service that serves the area in which the underground facilities are located. R.C. 3781.26. By statute, the term utility is defined, with only limited exceptions, to include any owner of an underground utility facility. The term underground utility facility is defined broadly to mean:Because of that broad definition, many, if not most, Ohio oil and gas producers are required to participate in an underground utility protection service.Any item buried or placed below the surface of the earth or submerged under water for use in connection with the storage or conveyance of water or sewage; electronic, telephonic, or telegraphic communications; television signals; electricity; crude oil; petroleum products; artificial or liquefied petroleum; natural gas; coal; steam; hot water; or other substances .... [R.C. 3781.25.]
1. Utility Obligations
Among the obligations imposed on covered utilities by Ohio's one-call program are the following:
- To participate in a protection service that covers the areas in which its underground facilities are located;
- To register the locations of its underground facilities with those protection services;
- If the utility is participating on a limited basis, it must only register the location of its facilities by identifying the applicable municipal corporations, townships and counties;
- To publicize the importance of learning the locations of underground facilities prior to excavation activities;
- To notify (either upon contact by the protection service for full participants or by the developer for limited participants) the developer of the approximate locations and provide a description of the underground facilities, if any, located at the proposed excavation site within 10 days of being contacted about the excavation;
- To determine whether any protective steps beyond those required of the excavator by law are necessary to prevent disturbance or interference with the facilities during excavation, and, if so, whether the utility will permit the developer to make those adjustments; and,
- To locate and mark (either upon contact by the protection service for full participants or by the excavator for limited participants) the approximate location of its underground facilities at the contemplated excavation site, plus 18" on each side, within 48 hours of being contacted about the excavation.[1]
Significantly, when the utility marks the location of its underground facilities for excavation activities, it may request that the excavator notify it prior to commencement of the excavation in order to allow the utility an opportunity to observe. R.C. 3781.31.
B. Protection Services
Protection services are defined by statute to be notification centers that exist for the purpose of receiving notice from persons that prepare plans for or engage in excavation work and that distribute this information to members and participants.[3] They must be registered with both the Secretary of State and the Public Utilities Commission.1. Responsibilities
Among the various responsibilities of a protection service are the following:
- To publicize the importance of learning the locations of underground utility facilities prior to engaging in excavation activities;
- To maintain records of notifications both received and made by it that are identified by reference number and that provide the date and time of each notification;
- To provide notice of each proposed excavation to its full participants having underground utility facilities in the area of the proposed excavation site; and,
- To notify the developer or excavator, as the case may be, of the name of each limited basis participant with underground facilities within the municipal corporation or township and county of the proposed excavation site.[4]
C. Developers and Excavators
Developers and excavators have similar responsibilities under Ohio's one-call program. Developers are defined by statute to mean the person for whom the excavation is made and who will own or be the lessee of any improvements that are the object of the excavation. Excavators are the contractors or other persons who are responsible for undertaking the excavation. The primary obligation of both is to provide notice prior to engaging in excavation activities.1. Developer Obligations
- To ascertain the names of utilities with underground facilities located at a proposed excavation site, and the types and approximate locations of those facilities, developers are required to notify a protection service covering the area in which the proposed excavation is located;
- To contact the limited-basis participants of the protection service that have been identified as having underground facilities within the municipal corporation or township and county of the proposed excavation site;
- Based upon the information provided by the utilities, to indicate the approximate locations of underground facilities either or with the plans prepared for the project (including names, addresses and telephone numbers of the utilities; identifying the limited basis utilities; the name and telephone number of the protection service; and any additional protective steps required by the utilities);
- To provide the plans and information to the excavator before excavation begins (if no written plans are prepared, to provide the indicated information in some other manner); and,
- To design the project to take into account the underground facilities' locations in order to prevent, as far as practicable, disturbance or interference (including, for new underground facilities, providing for a 12" clearance between the facilities).[5]
2. Excavator Obligations
- To publicize the importance of learning the locations of underground utility facilities prior to engaging in excavation activities;
- To notify protection services of the location of the excavation site and the date on which activities are planned to commence at least 48 hours but not more than 10 days before commencing excavation;
- To notify the limited-basis participants identified by the protection services of the proposed excavation at least 48 hours but not more than 10 days before commencing excavation activities;
- If additional protective steps are necessary, to provide earlier notice to the utility in order to provide the utility with a reasonable time to coordinate those steps with the actual excavation;
- When undertaking the excavation, the excavator must maintain reasonable clearance between the underground facilities and the excavating equipment; protect and preserve the markings indicating the facilities' locations (and have the area remarked if necessary); when using power equipment, have someone other than the equipment operator maintain a look out for the facilities; conduct the excavation in a careful and prudent manner to prevent damage; report to the utility the type and location of any damage to the facilities upon discovery and allow a reasonable amount of time to make repairs; and report immediately to the appropriate authorities any damage to the facilities that results in escaping flammable, corrosive, explosive or toxic liquids or gas, and take reasonable actions to protect persons and property and to minimize safety hazards until assistance arrives.[6]
Significantly, utilities have successfully relied on these statutes to argue that excavators have negligently damaged the utility's underground facilities and are responsible for their repair. See, e.g., Ohio Edison Co. v. Wartko Constr. (1995), 103 Ohio App.3d 177 (finding that the contractor's notification 40 days prior to commencing excavation was untimely because of the 10-day notice period provided for by statute).
D. Existing One-Call Services in Ohio
There are only two protection services presently registered in Ohio:Oil and Gas Producers Underground Protection Service (OGPUPS)
(sponsored by the Association)
Tel. (800) 925-0988
http://www.ogpups.com/
Ohio Utilities Protection Service
Tel. (800) 362-2764
Because underground utility facilities may be registered with one program and not the other, it is prudent to call both services before you dig.
[1] See, generally, R.C. 3781.26, R.C. 3781.27 and R.C. 3781.29.
[2] See R.C. 3781.29.
[3] R.C. 3781.25(A).
[4] See, generally, R.C. 3781.26, R.C. 3781.27, R.C. 3781.28.
[5] See, generally, R.C. 3781.27.
[6] See, generally, R.C. 3781.28, R.C. 3781.30, R.C. 3781.31.
V. Liability Under the Oil Pollution Act of 1990
The Oil Pollution Act of 1990 includes stiff liability provisions for oil spills from regulated facilities. Specifically, the responsible party for a facility from which oil is discharged into or upon navigable waters of the United States, or adjoining shorelines, is liable for the costs of removal as well as the damages that occur to natural resources and personal property (including lost revenues and profits). See 33 U.S.C. § 2702. The limitations on the total liability that can be imposed indicate the staggering potential that exists – a $350,000,000 cap on liability, with a possible small facility limit of not less than $8,000,000, taking into account the facility's size, storage capacity, oil throughput, proximity to sensitive areas, history of discharges, and other relevant factors. See 33 U.S.C. § 2704.There are three limited defenses to liability. A responsible party is not liable if it can establish that the discharge of oil, and the resulting damage, were caused solely by:
- An act of God;
- An act of war;
- An act or omission of a third party if the responsible party can establish that it –
- Exercised due care with respect to the oil concerned, taking into consideration the characteristics of the oil and light of all relevant facts and circumstances; and,
- Took precautions against foreseeable acts or omissions of such third party, and their foreseeable consequences.
VI. SPCC Plans
With the enactment of the Clean Water Act in 1972, Congress required the Director of U.S. EPA to issue regulations mandating Spill Prevention Control and Countermeasure ("SPCC") plans. The purpose of these plans is to require certain oil-handling facilities to prepare for accidental discharges of oil and, in the event such a discharge occurs, to prevent that oil from reaching navigable waters of the United States. This section provides an overview of the applicability and requirements of those plans.A. U.S. EPA Regulations
1. ApplicabilityU.S. EPA's SPCC plan regulations apply to non-transportation related onshore facilities, and those offshore facilities regulated by U.S. EPA, that can reasonably be expected to discharge oil in harmful quantities into or upon navigable waters of the United States. See 40 C.F.R. 112.1. If a facility satisfies these conditions, it must prepare an SPCC Plan that addresses, among other things, the facility's design, operation and maintenance procedures to prevent spills from occurring in the first place, as well as implement countermeasures to control, contain and clean up any spills that might occur to prevent oil discharges from reaching navigable waters. Accordingly, the first step is to determine whether a facility must even establish an SPCC Plan.
- Facility
For purposes here, SPCC Plans are required primarily of non-transportation related onshore facilities involved in oil production, refining and storage. So, for example, they are required of fixed onshore oil well drilling facilities as well as mobile facilities when in a fixed position, such as derricks, oil rigs, oil separators, and oil storage facilities. See, e.g., 40 C.F.R. 112.7(e)(5) (identifying onshore oil production facilities). - Discharge
As in the case of reporting requirements discussed earlier in this paper, a discharge is a release of any kind. Significantly, when U.S. EPA considers whether a discharge can reasonably be expected to affect navigable waters, it considers only the geography and location of the facility, not any man-made structures that might otherwise divert a spill. As a consequence, the majority of oil-handling facilities in the United States have the potential to discharge into navigable waters. See 40 C.F.R. 112.2 (for regulatory definition). - Oil
The term "oil" is defined to mean oil of any kind or form, including petroleum, fuel oil, sludge, oil refuse and oil mixed with wastes other than dredged spoil. U.S. EPA interprets the term to also include crude oil and refined petroleum products. See 40 C.F.R. 112.2 (for regulatory definition). - Harmful Quantities
As with reporting requirements for oil spills, discharges of oil in "harmful quantities" are those discharges that (a) violate water quality standards; (b) cause a film or sheen upon, or a discoloration of, the surface of the water or adjoining shorelines; or (c) cause a sludge or emulsion to be deposited beneath the surface of the water or upon adjoining shorelines. The primary test is the "sheen" test. Thus, if rainwater with an oil sheen is discharged from a diked area, it would likely constitute a "discharge of oil in harmful quantities." See 40 C.F.R. Part 110. - Navigable Waters
As with oil spill reporting requirements, the term "navigable waters of the United States" has been defined by judicial decision and EPA regulations to reach the outer boundaries of interstate commerce. It includes not only interstate waters, but waters that are located solely within a single state, such as lakes, rivers and streams that are adjacent to and might be used in connection with interstate commerce. It also includes wetlands and the tributaries of all of these types of waters. Essentially, the term refers to almost all natural surface waters in the United States.[1] - U.S. EPA Summary
U.S. EPA has exempted very small oil-handling facilities from the requirement that they prepare SPCC Plans. Interpreting this exemption, U.S. EPA regulations and guidance documents require a facility to prepare an SPCC Plan if it is a non-transportation related onshore facility that can reasonably be expected to discharge oil into navigable waters and has:- An above-ground storage capacity of more than 600 gallons in a single container;
- A total above-ground storage capacity of more than 1,320 gallons; or
- A total underground buried storage capacity of more than 42,000 gallons. [See 40 C.F.R. 112.1.]
A facility that satisfies these requirements must prepare an SPCC Plan within 6 months of starting operations and implement the plan as soon as possible, but no later than 1 year after operations begin. Elements common to every SPCC Plan include the following:
- It must be prepared according to good engineering practices and be reviewed and certified by a professional engineer familiar with both the facility and the SPCC Regulation;
- It must be kept on-site at the facility if the facility is normally staffed at least 8 hours per day. Otherwise, it must be kept at the nearest field office;
- It must have full approval of management at a level with the authority to commit the resources necessary to implement the Plan;
- It must include a spill history for all spills that occurred within the 12-month period preceding the Plan's preparation, including a full description of the spill, any corrective actions that were taken, and plans for preventing a recurrence;
- If experience indicates a reasonable potential for equipment failure – e.g., a storage tank overflow – the Plan must include a prediction of the direction, rate of flow and quantity of oil that could be discharged from the facility; and,
- It must be reviewed and evaluated at least once every three years.
Every SPCC Plan must also discuss, and the facility must install, appropriate containment and/or diversionary structures or equipment to prevent discharged oil from reaching navigable waters. Examples for onshore facilities include dikes, berms and retaining walls sufficiently impervious to spilled oil, curbing, culverting, spill diversion ponds, retention ponds and sorbent materials. For oil storage facilities in particular, for example, U.S. EPA regulations require that all tank batteries and treating facilities be equipped with a secondary means of containment for the entire contents of the largest single tank, if feasible, or alternative systems. If containment and/or diversionary structures are impracticable, the facility must have a strong spill contingency plan in place and a written commitment of manpower, equipment and materials for controlling and removing harmful quantities of oil that might get spilled. See, generally, 40 C.F.R. Part 112.
U.S. EPA regulations contain additional specific requirements based upon whether the facility is a production or non-production facility. For example, drains at onshore oil production facilities must be closed and sealed at all times, except during rainwater drainage. Prior to drainage, however, the diked drainage areas must be inspected to ensure that the water does not have an oil sheen – in which case it could not be discharged – and any accumulated oil must be returned to storage or properly disposed of. Accordingly, those regulations should be consulted to determine the specific requirements for each regulated facility. See 40 C.F.R. 112.7.
Failure to comply with the regulations adopted by U.S. EPA can subject an owner or operator of a facility to significant financial penalties. For example, a Newark, NJ facility that did not adequately prepare and implement an SPCC Plan was recently fined $38,000. Moreover, since December, 1998, facilities in U.S. EPA Region III have been issued or paid fines for a total of $210,000 for violations of the SPCC requirements of the Clean Water Act.
B. Proposed Amendments to U.S. EPA's Regulations
U.S. EPA's SPCC Plan requirements have remained largely unchanged since they were first promulgated in 1973. However, since the Oil Pollution Act was enacted by Congress in 1990, there have been several proposed rule amendments by U.S. EPA. None, however, have become final.The Ohio Oil and Gas Association has filed comments on the proposed rule amendments and continues to monitor their progress. Representatives of U.S. EPA's Oil Pollution Program have stated that they expect a consolidated, final rule to be issued sometime in the near future.
C. Ohio Law
In 1988, the Ohio General Assembly passed the Right to Know Bill, which, among other things, authorized Ohio EPA to adopt rules for a state-enforced SPCC Program. In 1994, that statute and Ohio Revised Chapter 1509 were amended to transfer to the Ohio Division of Oil and Gas, now the Division of Mineral Resources Management, the Ohio EPA's SPCC authority over oil production facilities and oil drilling and workover facilities.To date, while a rules negotiating committee has been formed to develop SPCC regulations for Ohio, none have been promulgated as a result of the delay occasioned at U.S. EPA with SPCC rule amendments. The Ohio Oil and Gas Association has participated on that committee and intends to continue its participation in the future.
[1] See, e.g., 40 C.F.R. 112.2 (for regulatory definition).
VII. FRP Plans
With the enactment of the Oil Pollution Act in 1990, Congress amended the Clean Water Act to require the Director of U.S. EPA to issue regulations mandating the preparation of Facility Response Plans ("FRP") for certain high-risk facilities. These plans are designed to provide a quick, effective oil spill response for those facilities that present the greatest risk to the environment. The following briefly outlines the applicability and requirements of these plans.A. Applicability
For purposes here, U.S. EPA's FRP rules apply to non-transportation related onshore facilities that, because of their location, can reasonably be expected to cause substantial harm to the environment by a discharge of oil into or upon navigable waters of the United States or adjoining shorelines. These substantial harm facilities are a subset of the facilities required to prepare SPCC Plans. Therefore, because each of the other triggering elements were discussed in the SPCC section immediately above (e.g., "navigable waters," "facility," "discharge," "oil," etc.), we discuss only the substantial harm element below.1. Substantial Harm Facilities
The Oil Pollution Act does not define the term substantial harm. By implementing rule, however, U.S. EPA requires the preparation of an FRP Plan for those facilities that:
- Transfer oil over water to or from vessels and have a total oil storage capacity greater than or equal to 42,000 gallons;
—OR— - Have a total oil storage capacity greater than or equal to 1,000,000 gallons AND any one of the following is true:
- The facility does not have secondary containment for each aboveground storage area sufficiently large to contain the capacity of the largest aboveground oil storage tank within each storage area plus sufficient freeboard to allow for precipitation; or,
- The facility is located at a distance such that a discharge from the facility could cause injury to fish and wildlife and sensitive environments; or,
- The facility is located at a distance such that a discharge from the facility would shut down a public drinking water intake; or,
- The facility has had a reportable oil discharge in an amount greater than or equal to 10,000 gallons within the last five years.
B. FRP Requirements
If your facility is required to prepare an FRP, it must contain, among other things, the following:1. An Emergency Response Action Plan
This is basically an executive summary of the essential information contained in the FRP and collected in an easily accessible, stand-alone format. It identifies, among other things, (i) the individual at the facility having full authority to implement removal actions, (ii) the persons or entities to be contacted in the event of a spill in order to facilitate communications between the facility and response personnel, (iii) the facility's response equipment and its location; (iv) the facility's response personnel and the capabilities and duties, (v) evacuation plans in the event it become necessary, and (vi) the immediate response measures to be taken to secure the source of the discharge and provide adequate containment.
2. Certain Facility Information
The FRP must identify the type and location of the facility, its owner, and the individual having full authority to implement a removal action (i.e., the "facility response coordinator").
3. Specific Emergency Response Information
In addition to much of the information required by the Emergency Response Action Plan above, the FRP must separately identify the private personnel and equipment necessary to remove, to the maximum extent practicable, a worst case discharge – as determined by regulation – and to mitigate and prevent a substantial threat of such a discharge. It must also include evidence of a means for ensuring the availability of such personnel and equipment, such as by contract.
This section of the FRP also identifies the duties and responsibilities of the facility response coordinator, which include activating the internal alarms and hazard communications systems; notifying response personnel, and local, state and federal officials; identifying the scope of the release and assessing the resulting potential hazards to human health and the environment; and directing and implementing a prompt removal action until relieved of that responsibility.
4. A Hazard Evaluation
The FRP must also discuss planning scenarios and response actions for small, medium and worst case discharges.
5. A Detailed Implementation Plan
For each of the discharges addressed in the hazard evaluation, the FRP must also describe in detail the specific response actions to be carried out by facility or contract personnel to ensure the safety of the facility and to mitigate or prevent such discharges or the substantial threat of such discharges. The description should include the equipment to be used in each of the planning scenarios, the measures to be taken to adequately contain the spill, and the plans to dispose of contaminated cleanup materials.
6. A Description of the Discharge Detection System
The FRP should also describe the procedures and equipment used to detect discharges.
7. An Inspection and Training Checklist
It must also include a checklist and record of tank, secondary containment and response equipment inspections, as well as a description of the drill and training programs to be carried out by the facility (and a record indicating that those programs were in fact implemented).
8. A Site Diagram and Description of the Facility's Security System
In addition, the facility must review the relevant portions of the National Oil and Hazardous Substances Pollution Contingency Plan and applicable Area Contingency Plans annually and, if necessary, revise the FRP to ensure consistency with these plans. Also, the FRP must be reviewed and updated periodically to reflect material changes at the facility. For the specific regulatory requirements, see 40 C.F.R. 112.20.
VIII. Oil Spill Reporting Requirements
There are a whole host of reporting requirements under the environmental laws, regulations and ordinances of federal, state and local governments that require responsible parties to immediately notify the relevant entities of a spill of oil, hazardous substances, extremely hazardous substances, and other regulated materials. The purpose of this section is to provide an overview of those reporting requirements as they relate to the accidental or sudden releases or spills of oil. This section does not address reporting obligations arising under environmental laws for releases of hazardous substances or releases associated with operating permits such NPDES permits, air permits, or RCRA permits.Two environmental programs may be triggered upon a release or spill of oil. The first is the Clean Water Act, as amended by the Oil Pollution Act of 1990. The second is the State Emergency Response Commission's release reporting requirements mandated by Ohio Revised Code Section 3750.06. Each is discussed briefly below.
A. Clean Water Act Reporting Requirements
Section 311(b)(3) of the Clean Water Act prohibits the discharge of oil into or upon navigable waters of the United States or adjoining shorelines in harmful quantities. As soon as the person in charge of a facility has knowledge of such a discharge, he or she must notify the National Response Center, which then notifies the affected State.[1] Statutory provisions and regulations adopted by the U.S. EPA and the U.S. Coast Guard define the relevant terms of this notification requirement as follows:1. Discharge
The term "discharge" means a release of any kind, including any spilling, leaking, pumping, pouring, emitting, emptying or dumping, but excludes those discharges which are in compliance with a permit. See 33 U.S.C. § 1321(a)(2).
2. Oil
The term "oil" means any kind of oil, in any form, including petroleum, fuel oil, sludge, oil refuse, and oils mixed with wastes. U.S. EPA also interprets the term to include crude oil and petroleum-refined products. See 33 U.S.C. § 1321(a)(1).
3. Navigable Waters of the United States
The term "navigable waters of the United States" has been defined by judicial decision and EPA regulations to reach the outer boundaries of interstate commerce. As a consequence, it includes not only interstate waters, but waters that are located solely within a single state, such as lakes, rivers and streams that are adjacent to and might be used in connection with interstate commerce.
4. Harmful Quantities
The term "harmful quantities" refers to any quantity of discharged oil that: (i) violates a water quality standard; (ii) causes a sludge or emulsion to be deposited beneath the surface of the water; or (iii) causes a film or sheen upon, or discoloration of, the surface of the water. This is commonly referred to as the "sheen test." See 40 C.F.R. 110.3.
5. Exemptions
Exempt from the reporting requirements are properly functioning vessel engines; research and development releases; NPDES-permitted releases; and certain discharges beyond the territorial seas permitted by MARPOL.
B. Graphic Summary of Clean Water Act Reporting Requirements
The following is a graphic summary of the Clean Water Act's reporting requirements to assist the reader in making a decision as to whether to report a spill or release of oil to the National Response Center. If there is any question, you should contact your counsel.
C. The Report of a Release or Spill
To report a release or spill, contact the National Response Center (NRC) at (800) 424-8802. 40 C.F.R. 110.6. The NRC is staffed 24 hours a day by U.S. Coast Guard personnel, who will ask you to provide as much information about the release or spill as you can. That information may include:- Your name, location, organization and telephone number;
- The name and address of the person responsible for the incident;
- The date and time of the incident, its location, the source and/or cause of the release or spill, and the types and quantities of materials discharged;
- Whether the discharge presents a danger or threat to human health or the environment; and,
- The number and types of injuries, if any.
D. The State Emergency Response Commission's (SERC's) Reporting Requirements
The State Emergency Response Commission ("SERC") requires the owner or operator of a facility to report oil discharged into or upon navigable waters, or into the environment, in "reportable quantities." The SERC's regulations differentiate between navigable waters and the environment, and between "oil" and "crude oil at an oil and gas extraction storage facility." Each is discussed below.1. Reportable Quantities
Rule 3750-25-20 of the Ohio Administrative Code establishes the following reportable quantities for oil, including crude oil:
- For releases of oil, including crude oil, into a navigable water, the reportable quantity is any amount which causes a film or sheen upon, or a discoloration of, the surface water or causes a sludge or emulsion to be deposited beneath the waters' surface.
- For releases of oil – except for crude oil from an oil and gas extraction storage facility – to the environment, the reportable quantity is 25 gallons over a 24-hour period.
- For releases of crude oil from an oil and gas extraction storage facility into the environment, the reportable quantity is 210 gallons (5 barrels) in a 24-hour period. [See Ohio Admin. Code 3750-25-20.]
2. The Reporting Requirement
Where a release from a facility of oil or crude oil in reportable quantities has occurred, the owner or operator of the facility must give verbal and written notice of the release as follows:[1]
- Verbal Notice: Verbal notice of a release must be given within 30 minutes after you have knowledge of the discharge unless impracticable under the circumstances. That notice must be given to the following:
- The Ohio EPA Emergency Response Unit, at (800) 282-9378 or (614) 224-0946;
- The Local Emergency Planning District for each district likely to be affected by the discharge; and,
- The local fire department.[2]
- Written Notice: Within 30 days after the release, the owner or operator must submit a written report to the Ohio EPA and the Local Emergency Planning District that contains:
- The complete name, mailing address and telephone number of the owner or operator of the facility;
- Time, date and duration of the release;
- Time and date of the release's discovery;
- Response actions taken;
- The Ohio EPA and National Response Center telephone numbers;
- Location of the facility;
- Location of the release;
- Chemical name and CAS number for the released substance;
- Environmental medium impacted and the extent of the impact, including the names of the waters and size of area affected;
- Chronological summary of the incident, including any communications with state and local agencies;
- Any manifests, bills of lading, or laboratory analyses generated by the owner/operator and which are germane to the incident;
- A description of any extenuating circumstances that may have caused the release;
- A description of any known or anticipated acute or chronic health risks associated with the release;
- Advice regarding medical attention necessary for persons exposed to the substance released; and,
- A summary of all actions taken by the owner/operator to prevent a recurrence of the release.
Significantly, failure to comply may subject the owner or operator to civil or criminal penalties. See, e.g., R.C. 3750.99.
[1] These reporting requirements do "not apply to any release of an extremely hazardous substance, hazardous substance, or oil from a facility that results in exposure to persons solely within the site or sites on which the facility is located." R.C. 3750.06(E). See also Ohio Admin. Code 3750-25-25.
[2] In the event that the release is transportation-related, the owner or operator is required to report to the Ohio EPA Emergency Response Unit as above as well as to the 911 operator. In the absence of a 911 emergency telephone number, the owner or operator must contact the telephone operator and report the release. See Ohio Admin. Code 3750-25-25.
IX. Natural Gas Gathering Pipeline Safety
A. Introduction
In 1968, Congress enacted the Natural Gas Pipeline Safety Act ("NGPSA"), which required the U.S. Department of Transportation ("DOT") to develop and enforce minimum safety regulations for transporting natural gas by pipeline. The goals of the NGPSA, revised by the Accountable Pipeline Safety and Partnership Act of 1996, are, in part, to ensure the safety in design, construction, inspection and operation of pipeline facilities and to establish minimum standards for the state administration of pipeline safety programs.While the federal program has primary responsibility for developing, issuing and enforcing pipeline safety regulations, state programs are granted intrastate regulatory, inspection and enforcement authority through an annual certification process. To qualify, a state can adopt either the federal regulations or more stringent state-promulgated regulations, as long as they are not incompatible with the federal requirements. Ohio has a federally-certified program.
Ohio's Natural Gas Pipeline Safety Standards are codified at R.C. 4905.90, et seq., and Ohio Admin. Code 4901:1-16. They extend natural gas pipeline safety jurisdiction over Ohio's intrastate pipelines – including natural gas gathering lines – to the Public Utilities Commission of Ohio ("PUCO").
This section provides a summary of the more significant aspects of both the DOT and PUCO regulations as they relate to natural gas gathering systems.
B. Application to Non-rural Gathering Pipelines
The NGPSA establishes minimum safety standards for pipelines engaged in the transportation of natural gas in (or related to) interstate commerce. Transporting gas is defined by statute to mean:- [T]he gathering, transmission, or distribution of gas by pipeline, or the storage of gas, in interstate or foreign commerce; but
- does not include the gathering of gas, other than gathering through regulated gathering lines, in those rural locations that are located outside the limits of any incorporated or unincorporated city, town, or village, or any other designated residential or commercial area... that the Secretary of Transportation determines to be a nonrural area, except that the term "transporting gas" includes the movement of gas through regulated gathering lines. [49 U.S.C. § 60101(a)(21)]
- An area within the limits of any incorporated or unincorporated city, town, or village.
- Any designated residential or commercial area such as a subdivision, business or shopping center, or community development.
C. Pipeline Safety Standards
The following discussion offers an overview of some of the more significant requirements applicable to non-rural natural gas gathering systems:1. Annual Report
By March 15th of each year, the operator of natural gas gathering pipeline system is required to submit an annual report to both the DOT and the Chief of the Gas Pipeline Safety Section of the PUCO's Consumer Services Department.[1] The report is to be made on Form RSPA 7100.2-1 (instructions at http://ops.dot.gov/library/forms/forms.htm#7100.2-1). Before submitting this form, however, check with the RSPA to make sure that it remains current.
Ohio law also requires each operator to submit a 24-hour contact report to the Chief by no later than March 15th of each year. That report must contain the name(s), business address(es) and business telephone number(s) of the operator's emergency contact personnel and any available emergency hotline number. Ohio Admin. Code 4901:1-16-05.
2. Reporting Natural Gas Incidents
In the event of an incident, the NGPSA requires the operator of a natural gas gathering system to notify by telephone the National Response Center at (800) 424-8802 and provide the following information: (i) the name of the operator and the person making the report (including telephone numbers); (ii) the location of the incident; (iii) the time of the incident; (iv) the number of personal injuries and fatalities, if any; and (v) all other significant facts known by the operator. An incident is defined as a release of gas from a pipeline that involves a death or personal injury necessitating in-patient hospitalization or estimated property damage, including the cost of gas lost, of $50,000 or more. It can also consist of any event that the operator believes is significant, even if it does not satisfy the criteria just mentioned. See 49 C.F.R. 191.3 and 191.5.
Similarly, Ohio law requires telephone notice to the Chief of the Gas Pipeline Safety Section of the PUCO's Consumer Services Department no later than 2 hours after making that telephone report to the National Response Center. That notice should be given at (614) 466-7542, and requires personal contact with the Chief (or a telephone message if unable to make that contact). See Ohio Admin. Code 4901:1-16-03.
In addition, both the NGPSA and Ohio law require the operator of a gas gathering system to submit a written report on Form RSPA 7100.2 as soon as practicable but no later than 30 days after detection of an incident. A copy of this incident report form can be found at http://ops.dot.gov/library/forms/gast/Trans_incident.pdf. Instructions for completing this form can be found at http://ops.dot.gov/library/forms/gast/GasTransAnnualInstructions%20122005%20Final%207100%202-1.pdf. Again, though, before submitting this form check with the RSPA to make sure that it remains current.
Under Ohio law, a final written report must also be submitted to the Chief within 60 days of discovery of the incident describing the cause(s) of the incident, where ascertainable, and the actions taken to minimize the possibility of a recurrence. See Ohio Admin. Code 4901:1-16-05.
3. Pipeline Materials
In general, materials for pipe and components must be able to maintain the structural integrity of the pipeline system under temperatures and other environmental conditions that can reasonably be anticipated. They must also be chemically compatible with any gas or other materials that they come into contact with in the system.
New and used steel pipe may be used provided that it meets the requirements contained in 49 C.F.R. 192.55. Similarly, new and used plastic pipe may be used provided that it is designed and manufactured in accordance with the specifications contained in 49 C.F.R. 192.59. Examples of plastic pipe that have previously been approved by DOT are polyethylene (PE) plastic pipe, acrylonitrile-butadiene-styrene (ABS) pipe, cellulose acetate butyrate (CAB) pipe, polybutylene (PB) pipe, and poly vinyl chloride (PVC) pipe if it is labeled ASTM D2513. In addition, Fiberglass epoxy plastic pipe marked ASTM D2517 also meets the DOT guidelines.
4. Pipeline and Component Design Standards
In general, pipe must be designed with sufficient wall thickness, or must be installed with adequate protection, to withstand anticipated external pressures and loads that will be imposed on the pipe after installation. Similarly, pipeline components, including compressors, must be able to withstand operating pressures and other anticipated loadings without impairment of their serviceability. The yield strength, nominal wall thickness for pipe, pressure limitations for valves, flanges, and fittings, and pressure relief venting for the pipeline system – as well as the electrical requirements, liquid removal, pressure limiting devices and safety equipment for compressors – can be found in subparts C and D of 49 C.F.R. Part 192.
The reader should note that, consistent with its purposes, many pipeline safety design standards depend upon the geographic area in which the pipeline is located. For example, the DOT has established a classification system based upon the use of property within 220 yards of the centerline of a pipeline. A Class 1 location has 10 or less buildings intended for human occupancy. A Class 2 location has 10 to 46 buildings intended for human occupancy. A Class 3 location is a location with more than 46 buildings intended for human occupancy or an area where the pipeline lays within 100 yards of either a building or a small, well-defined outside area that is occupied by 20 or more persons at least 5 days a week. A Class 4 location is any location with buildings with four or more stories. 49 C.F.R. 192.5.
For example, each natural gas gathering line to which these standards apply must have sectionalizing block valves spaced as follows (49 C.F.R. 192.179):
| Class Location | Spacing Between Each Valve in Class Location (Miles) |
|---|---|
| 4 | 2.5 |
| 3 | 4 |
| 2 | 7.5 |
| 1 | 10 |
5. Joining Pipeline Materials
The DOT has also established specific standards for joining the materials used in gas gathering pipelines. For example, the standards required for welding steel pipelines, as well as the qualifications required of welders undertaking that activity, can be found in 49 C.F.R. 192, Subpart E. The minimum requirements for joining materials in pipelines other than by welding can be found in 49 C.F.R. 192, Subpart F. These include standards for joining cast iron pipe, ductile iron pipe, and copper and plastic pipe (the latter of which has very detailed requirements for cement, heat fusion and adhesive joining). 49 C.F.R. Part 192.
6. Corrosion Control
Subpart I of the NGPSA's minimum safety standards sets forth the requirements for corrosion control. As a general matter, the specifics of those requirements depend in large part on the date the pipeline was installed. For example, buried and submerged pipelines installed after July 31, 1971, must be protected against external corrosion through an external protective coating and a cathodic protective system unless, through tests or other means, the pipeline's operator can establish that a corrosive environment does not exist. See 49 C.F.R. 192.455. Similarly, DOT regulations prohibit the transportation of corrosive gas by pipeline unless the corrosive effect of the gas has been investigated and steps have been taken to minimize internal corrosion. This Subpart also details what steps need to be taken in the event that corrosion has occurred. 49 C.F.R. Part 192.
7. Pipeline Testing
DOT regulations further require leak and strength tests for new segments of pipe and for pipeline segments that are being returned to service after being relocated or replaced. See 49 C.F.R. 192, Subpart J. Records of the tests must be kept for the useful life of the pipe and must contain the following information: the operator's name, the employees responsible for making the test, and the name of any test company used; the test medium, pressure, and duration; the recorded pressure readings; any relevant elevation variations; and any leaks or failures discovered.
8. Pipeline Operation and Maintenance
Operation and maintenance requirements are also established by federal and state regulations. DOT regulations include requirements for written operation and maintenance plans, employee training, continuing surveillance, patrolling and leakage surveys, emergency planning, procedures for investigating failures, and record keeping of repairs. See 49 C.F.R. 192, Subparts L and M. Additionally, but somewhat more vaguely, PUCO regulations require pipeline operators to establish and maintain all plans, records, reports, information and maps necessary to ensure compliance with the pipeline safety code (which includes the federal minimum safety standards). These documents must be held in Ohio at the operator's headquarters (or other appropriate office) and be readily available for inspection upon demand. Records to show compliance with these minimum safety standards must be maintained under Ohio law for a period of three years. See Ohio Admin. Code 4901:1-16-04 generally.
- Line Markers
Buried gathering lines must be marked with line markers at each road and railroad crossing and wherever necessary to prevent damage or interference. Line markers are not required in Class 3 or 4 areas where placement of a marker is impractical or where a damage prevention program is in place. See 49 C.F.R. 192.707. Similarly, line markers are required for aboveground gathering lines along each section that is accessible to the public. The marker must include the word "Warning," "Caution," or "Danger," followed by the words "Gas Pipeline." It must also include the name of the operator and the telephone number where the operator can be reached at all times.
On forms supplied by the PUCO, natural gas gathering pipeline operators must submit three reports at staggered intervals for each important addition to the gathering system. Important additions are those projects that involve the expenditure of more than $200,000, or an amount that is more than ten percent of the operator's intrastate pipeline transportation facility, provided the amount exceeds $30,000. Ohio Admin. Code 4901:1-16-06. The first report must be submitted to the Chief no later than 21 days before construction starts. The second no more than 7 days after construction has started. And the third report must be submitted no more than 7 days after construction is completed. Additionally, as part of the annual report described above, natural gas gathering system operators must submit on an PUCO form a list of important additions completed during the preceding calendar year (or state that there were no such additions).
10. Damage Prevention Program
DOT regulations require operators of buried gas gathering systems to carry out a written program to prevent damage to the pipeline system from excavation activities. 49 C.F.R. 192.614. The damage prevention program must include, at a minimum, the following: (i) an identification of those persons who normally engage in excavation activities in the area in which the pipeline is located; (ii) notification of the public and others (i.e., those who normally engage in excavation activities in the area) of the damage prevention program's existence and procedures; (iii) a means of receiving and recording notice of planned excavation activities in the area; (iv) a means of informing persons that notify the operator of their intent to excavate of the type of temporary markings to be provided by the operator regarding the underground facilities; (v) a means of marking the buried pipeline facilities before the excavation activities begin; and (vi) a means of inspecting the facilities that might be damaged as a result of the excavation activities.
Operators are required to participate in one-call notification programs if they exist, and can satisfy the requirements outlined above through that participation. Participating in a one-call program, however, does not relieve the operator from its responsibilities under these regulations.
Significantly, Ohio's pipeline safety code requires natural gas companies and pipeline companies, as defined generally under Ohio law, to register the location of all of their underground facilities with a protection service as described in Section IV of this Report. Ohio Admin. Code 4901:1-16-05.
11. Drug and Alcohol Testing
DOT regulations require non-rural gathering system operators to test employees working on the system for the presence of prohibited drugs and provide for an employee assistance program. The drug testing program must consist of pre-employment testing, post-accident testing, random testing, testing based upon reasonable cause, and return to duty testing. DOT regulations further require random testing for 50 percent of the employees on an annual basis.
In addition, non-rural gathering system operators are also required to establish and maintain a written alcohol misuse plan that provides for required testing, recordkeeping, reporting, education and training. The program must include post-accident testing, testing upon reasonable suspicion of prohibited alcohol use, return-to-duty testing, and follow-up testing. The specific requirements and prohibitions regarding drug and alcohol use can be found in 49 C.F.R Part 199.
[1] See O.A.C. 4901-1.
X. CERCLA (Superfund) and the Petroleum Exclusion
A. Elements and Potential Liability
The Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq., ("CERCLA") (also known as "Superfund"), imposes joint and several, strict liability upon several classes of persons for the costs associated with the remediation of hazardous substances. Section 107(a) states, in part:- Notwithstanding any other provision or rule of law, and subject only to the defenses set forth in subsection (b) of this section -
- the owner and operator of a vessel or facility, [and]
- any person who at the time of disposal of any hazardous substance owned or operated any facility at which such hazardous substances were disposed of, from which there is a release, or a threatened release which causes the incurrence of response costs, of a hazardous substance, shall be liable for -
- all costs of removal or remedial action incurred by the United States Government or a State or an Indian tribe not inconsistent with the national contingency plan;
- any other necessary costs of response incurred by any other person consistent with the national contingency plan;
- damages for injury to, destruction of, or loss of natural resources, including the reasonable cost of assessing such injury, destruction, or loss resulting from such a release; and
- the costs of any health assessment or health effects study carried out under section 9604(i) of this title.
Release – Among other things, the term "release" is defined as any spilling, leaking, emitting, emptying, discharging, leaching, dumping or disposing into the environment. 42 U.S.C. § 9601(22). Courts have often found that a "release" can be established merely by the presence of a hazardous substance in the environment. See, e.g., United States v. Barkman, 1998 U.S. Dist. LEXIS 20248 (E.D. Pa. 1998).
Responsible Person – The Superfund imposes direct liability on four categories of persons: the current owner or operator of a facility; past facility owners and operators who disposed of hazardous substances on the property; and the arrangers and transporters of the hazardous substances. 42 U.S.C. § 9607(a). Importantly, current owners of property are liable for response costs even though they did not own the site at the time the property became contaminated. Past owners are only liable to the extent that they owned the property at the time of disposal, however.
B. Hazardous Substances and the Petroleum Exclusion
One of the interesting issues for the oil and gas industry is at what point petroleum and petroleum products (refined and unrefined) constitute hazardous substances for CERCLA-liability purposes. Section 101(14) broadly defines the term "hazardous substance" to include almost any substance listed in or designated under a variety of federal environmental statutes. Importantly, however, it provides an exemption for petroleum products commonly known as the "CERCLA petroleum exclusion."
42 U.S.C. § 9601(14).The term [hazardous substance] does not include petroleum, including crude oil or any fraction thereof which is not otherwise specifically listed or designated as a hazardous substance under subparagraphs (A) through (F) of this paragraph, and the term [hazardous substance] does not include natural gas, natural gas liquids, liquefied natural gas, or synthetic gas usable for fuel (or mixtures or natural gas and such synthetic gas).
Initially, there was general uncertainty whether the petroleum exclusion applied to refined petroleum products such as gasoline, diesel fuel, and other motor fuels commonly sold at service stations and stored in underground storage tanks. This uncertainty arose because many of the constituents of petroleum (i.e., benzene, toluene, and xylene) are, by themselves, designated hazardous substances. However, judicial and administrative interpretations of the petroleum exclusion have defined the exclusion as including refined petroleum products.
The seminal case is Wilshire Westwood Associates v. Atlantic Richfield Corp., 881 F.2d 801, 810 (9th Cir. 1989), in which the Ninth Circuit Court of Appeals stated:
We rule that the petroleum exclusion in CERCLA does apply to unrefined and refined gasoline even though certain of its indigenous components and certain additives during the refining process have themselves been designated as hazardous substances within the meaning of CERCLA.
This interpretation has been applied by the Northern District of Ohio in Lyden Co. v. Citgo Petroleum Corp., 1991 U.S. Dist. LEXIS 19783 (N.D. Ohio, Dec. 15, 1991) (release of gasoline from underground storage tanks did not trigger CERCLA liability because gasoline falls within the petroleum exclusion).
However, refined products that become contaminated with hazardous substances (e.g., contaminated used motor oil and waste oils) do not fall within the petroleum exclusion. In 1987, the United States Environmental Protection Agency ("U.S. EPA") adopted the position that waste oil, meaning product that includes hazardous substances at a level exceeding what is normally found in petroleum, is not within the petroleum exclusion. Recent federal district court cases have also held that the petroleum exclusion does not apply to waste oils and used oils that have become contaminated during use. See Darbouze v. Chevron Corp., 1998 U.S. LEXIS 12744 (E.D. Penn., Aug. 19, 1998) (waste oil which has been mixed with hazardous substances does not fall within the petroleum exclusion); Ekotek Site PRP Committee v. Self, 881 F. Supp. 1516 (D. Utah 1995) (used oil does not fall within the scope of the petroleum exclusion where the use of the oil results in the presence of elevated levels of hazardous substances). Thus, CERCLA would apply to releases of waste oils and used oils if they contain hazardous substances at a level exceeding what is normally found in petroleum.
A case from California illustrates the impact of this issue and the distinctions that can be made. In Cose v. Getty Oil Co., 4 F.3d 700 (9th Cir. 1993), plaintiffs brought suit against Getty in an attempt to recover the costs to cleanup crude oil tank bottoms that were discovered in a buried pit on their property. The case involved the Kern County, California oil field. Getty produced wells in that field. The facts indicated that about once a week Getty would drain crude oil tank bottoms into a pit. The pit was ultimately backfilled and covered with top soil. Several years later when the plaintiff undertook efforts to develop the property it discovered "subsurface asphalt or tar-like material." The investigation that followed revealed that the substance had a "high concentration" (10.5 ppm) of Chrysene, a known carcinogen. The concentration of Chrysene in the area was shown to be 28.0 ppm. The trial court dismissed the plaintiff's CERCLA claim on the basis that the crude oil tank bottoms were petroleum, and therefore exempt from CERCLA. On appeal, the plaintiff argued that the tank bottoms were discarded waste products and not crude oil or fractions of crude oil as the CERCLA petroleum exclusion requires. Getty argued that crude oil tank bottoms are component parts of crude oil and, thus, fall within the CERCLA petroleum exclusion. The Ninth Circuit, unfortunately for the industry, sided with the plaintiff. It concluded that crude oil tank bottoms are comprised of water and sedimentary solids that fall out of the crude oil and create a layer of waste on the bottom of the tank. It also concluded that crude oil tank bottoms are not fractions of crude oil and are never subjected to various refining processes as the CERCLA petroleum exclusion requires. Thus, the court found that these crude oil tank bottoms are not crude oil or a fraction thereof. The court held that the Chrysene found in the pit should be viewed as an independent hazardous substance for which CERCLA liability could attach. Getty, therefore, was found liable.
The United States District Court for the Southern District of Ohio, under similar factual circumstances, reached a different result. In Helter v. AK Steel Corp., 1997 U.S. Dist. LEXIS 9852 (S.D. Ohio, March 31, 1997), the Court applied the Cose Court's analysis to a CERCLA claim brought after coke oven gas leaked from an underground pipe. Although coke oven gas fell within the petroleum exclusion, the plaintiffs alleged that the coke oven gas condensate was a hazardous substance. However, unlike the crude oil tank bottoms, which did not resemble or meld with the crude oil, the condensate was indistinguishable from the gas itself. Thus, the Court held that, like the gas, the condensate fell within the petroleum exclusion. Consequently, the plaintiff's CERCLA claim was dismissed.
XI. RCRA: Regulation of ED&P and Used Oil Wastes
A. RCRA Overview
The Resource Conservation and Recovery Act ("RCRA"), 42 U.S.C. § 6901 et seq., was passed in 1976 and reauthorized in 1980 in response to the public outcry after the discovery of extensive dumping of toxic wastes at the Love Canal site in Niagara Falls, New York. It is designed to fill in the gaps left by other federal environmental laws – such as CERCLA – by emphasizing the need to deal with existing wastes.Overall, RCRA establishes a comprehensive program for managing hazardous wastes from the time they are produced until their disposal. Importantly, while RCRA is commonly thought of as a hazardous waste statute, it, in fact, also addresses "nonhazardous wastes" (Subchapter IV), and "underground storage tanks" (Subchapter IX). If a waste is regulated as a hazardous waste, its proper management not only presents a tremendous administrative burden, but it also imposes significant financial burdens upon those entities that generated, transported, stored or disposed of it.
B. RCRA Hazardous Wastes
As a consequence, the most important part of RCRA for purposes of this discussion is the meaning of the term "hazardous waste." As is common with most environmental statutes, the answer is not straightforward. In fact, it depends in large part on the RCRA statutory definition of "solid waste.""Solid Waste" is defined to mean any garbage, refuse, sludge from a waste treatment plant, water supply treatment plant, or air pollution control facility and other discarded material, including solid, liquid, semisolid, or contained gaseous material resulting from industrial, commercial, mining, and agricultural operations, and from community activities. 42 U.S.C. § 6903(27). To implement that definition, U.S. EPA has adopted regulations defining solid waste as "any discarded material," subject to a number of exclusions. See 40 C.F.R. 261.2(a)(1). Significantly, recovered oil that is properly recycled, as defined by regulation, is excluded from the definition of solid waste. Id. at 261.4(a)(12)(ii).
A "hazardous waste," then, is a solid waste that either (1) is listed by the U.S. EPA as a hazardous waste, (2) exhibits any of the characteristics of hazardous waste (ignitability, corrosivity, reactivity, or toxicity), or (3) is a mixture of solid and hazardous wastes under certain conditions, generally relating to the continued hazardous characteristics of the mixed waste. See 42 U.S.C. § 6921; 40 C.F.R. 261.3. Thus, U.S. EPA considers a mixture of a "characteristic" hazardous waste with an exempt waste that continues to exhibit the same hazardous characteristics after mixing as a "hazardous waste." For example, if after adding non-exempt caustic soda exhibiting corrosivity to a pit containing exempt wastes the mixture also exhibits corrosivity, the entire mixture becomes a non-exempt hazardous waste. It is therefore prudent to avoid the mixing of wastes where possible.
Once a solid waste is identified as a hazardous waste, RCRA imposes certain obligations upon the "generator," the "transporter," and any person responsible for the "treatment, storage, or disposal" of that hazardous waste.
While left undefined by Congress, the term "generator" has been defined by U.S. EPA as any person, by site, whose act or process produces hazardous waste or whose act first causes a hazardous waste to become subject to hazardous waste regulation. 40 C.F.R. 260.10(a). As a consequence, many entities may not even realize that their activities are regulated and, because the definition is site specific, a single entity may qualify as several "generators" depending on the number of sites that it has.
If an entity is a "generator," it must obtain a U.S. EPA identification number in order to lawfully send the hazardous waste off-site for treatment, storage, or disposal. Generators, unless specifically authorized, may not treat, store, or dispose of the hazardous waste. Furthermore, generators may accumulate hazardous wastes on their site for no more than ninety days. Before sending the hazardous waste off-site, the generator must prepare a "hazardous waste manifest." In the manifest, the generator must designate one primary and one alternate facility to handle the waste. The generator, each transporter, and the treatment, storage, or disposal facility must sign the manifest. Additionally, the generator must keep a fully signed copy of each manifest as well as any test results for three years and, with some exceptions, must prepare and submit an annual report. See 40 C.F.R. Part 262.
"Transporters" are those persons engaged in the offsite transportation of hazardous waste by air, rail, highway, or water. Like generators, transporters must obtain an EPA identification number. Transporters are prohibited from accepting hazardous waste without a manifest, and each transporter of the hazardous waste must sign the manifest and keep a copy for three years. Transporters are also subject to the Department of Transportation safety regulations. See 40 C.F.R. Part 263.
"Treatment, Storage, or Disposal" ("TSD") facilities, as a general matter, treat, store and/or dispose of or destroy hazardous wastes and are subject to the most stringent RCRA regulations. TSD facilities include incinerators, Class I hazardous waste injection wells, landfills, and surface impoundments.
Without going into the comprehensive specifics of the regulations here, TSD's must (a) obtain a permit, (b) must obtain a U.S. EPA identification number, (c) are subject to certain notice requirements, (d) must obtain detailed chemical and physical analyses of wastes received, (e) must provide for periodic inspections, (f) must provide security to prevent inadvertent entry into the facility, (g) must train facility personnel to ensure compliance with the RCRA program, and (h) must take precautions to prevent accidental ignition or reaction of ignitable or reactive wastes. TSD facilities may only be established in environmentally acceptable locations, with consideration given to earthquakes, floodplains, saltdomes, environmental impact, ground and surface water, impact on public health and safety, the history of the operator, the distance from residences, schools, hospitals, jails, prisons, and the nearby wetlands. And TSD facilities must, among other things, have contingency plans designed to minimize the impact to human health and the environment from fires, explosions and other unplanned releases of hazardous waste from the facility. See 40 C.F.R. Part 264.
C. The RCRA ED&P Exemption
Importantly here, many oil and gas related wastes are exempt from regulation as hazardous wastes under RCRA. When Congress amended RCRA in 1980, it conditionally exempted from regulation as hazardous wastes "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil or natural gas." 42 U.S.C. § 6921(b)(2)(A). Instead, Congress ordered U.S. EPA to study these wastes and submit a report evaluating the status of their management.On July, 6, 1988, U.S. EPA announced that it had completed its study and presented its regulatory determination that oil and gas ED&P wastes would not be regulated as hazardous wastes under RCRA. See 53 Fed. Reg. 25446. It concluded, instead, that the wastes could be better controlled through improvements to existing state and federal regulatory programs. The July 6, 1988, determination is important for obvious reasons. If U.S. EPA decided to regulate ED&P wastes as hazardous, the standards for generators, transporters, and TSD facilities would have applied to practically all aspects of the oil and gas industry.
In its regulatory determination, U.S. EPA provided a list of wastes that it considered exempt from hazardous waste regulation under the ED&P exemption. Those listed wastes include the following:
U.S. EPA also provided a list of oil and gas wastes that it considers non-exempt. That list includes the following:produced water; drilling fluids; drill cuttings; rigwash; well completion, treatment, and stimulation fluids; basic sediment and water and other tank bottoms from storage facilities that hold product and exempt waste; accumulated materials such as hydrocarbons, solids, sand, and emulsion from production separators, fluid treating vessels, and production impoundments; pit sludges and contaminated bottoms from storage or disposal of exempt wastes; workover wastes; spent filters, filter media, and backwash; packing fluids; produced sand; pipe-scale, hydrocarbon solids, hydrates, and other deposits removed from piping and equipment prior to transporting; and hydrocarbon-bearing soil.
There is a simple rule of thumb for determining if an ED&P waste is likely to be considered exempt or non-exempt from RCRA regulations: If (i) the waste came from down-hole, i.e., it was brought to the surface during oil and gas ED&P operations, or (ii) the waste was generated by contact with the oil and gas production stream during the removal of produced water or other contaminants, the waste is most likely to be considered exempt by U.S. EPA.unused fracturing fluids or acids; painting wastes; oil and gas service company wastes, such as empty drums, drum rinsate, vacuum truck rinsate, sandblast media, painting wastes, spent solvents, spilled chemicals, and waste acids; vacuum truck and drum rinsate from trucks and drums transporting or containing nonexempt wastes; used equipment lubrication oils; waste compressor oil, filters, and blowdown; used hydraulic fluids; and waste solvents.
Since that 1988 regulatory determination, U.S. EPA has taken a number of steps to improve its understanding of the oil and gas industry. For example, U.S. EPA has continued to investigate the wastes generated, and the methods used for their management and disposal, by the exploration, development and production of natural gas. Also, U.S. EPA has indicated that it is likely to reconsider some time in the future its regulatory determination that oil and gas ED&P wastes would not be regulated as hazardous wastes under RCRA, based upon more recent and comprehensive data.
D. RCRA Regulation of Used Oil
Program. "Used oil" is defined as (i) any oil that has been refined from crude oil, or any synthetic oil, (ii) which has been used and (iii) as a result, is contaminated by physical or chemical impurities. 40 C.F.R. 279.1. Under RCRA, used oil is not generally regulated as a hazardous waste. Rather, U.S. EPA – as required by Congress in the Used Oil Recycling Act of 1980 – has developed a regulatory scheme to ensure its proper management and disposal, based on the presumption that most used oil is recycled.Used oil generators are subject to certain storage and transportation requirements. With limited exceptions, a "used oil generator" is any person, by site, whose act or process produces used oil or whose act first causes used oil to become subject to regulation. 40 C.F.R. 279.1. The primary requirement for generators concerns storage. Used oil can only be stored in containers and aboveground tanks that are in good condition, i.e., with no visible leaks, structural damage or deterioration. Id. at 279.22. Additionally, those containers and tanks must be clearly labeled as containing "used oil" to avoid mixing with other materials. Id.
Generators must also ensure that their used oil is transported off-site by appropriate transporters, i.e., transporters who have obtained the necessary U.S. EPA identification numbers. They are also allowed to transport some of their own used oil under certain conditions, including a limitation on quantity per shipment (55 gallons or less).
Used oil processors, re-refiners, transporters and marketers are subject to additional tracking and recording requirements, among other things. For example, processors, transporters, re-refiners, and marketers must have EPA identification numbers and must generally keep a record of the name, address and U.S. EPA identification number of the generator, transporter, processor or re-refiner who came into contact with the used oil, the quantity of used oil, and date of acceptance of the used oil. The reader should refer to 40 C.F.R. Part 279 generally for more detailed information on these requirements.
Regulation as RCRA Hazardous Wastes. While used oils are not generally regulated as RCRA hazardous wastes, there are exceptions. Mixtures of used oil and listed hazardous wastes are subject to RCRA hazardous waste regulation. Mixtures of used oil and characteristic hazardous wastes are generally subject to RCRA hazardous waste regulation if they exhibit hazardous waste characteristics (with some differences for ignitable hazardous wastes). Id. at 279.10. Additionally, used oils containing more than 1,000 parts per million total halogens are presumed to be hazardous and subject to RCRA hazardous waste regulation unless it is demonstrated that the used oils have not been mixed with halogenated hazardous wastes. Id. And last, used oil that is being disposed of – like other solid wastes – may be regulated as a hazardous waste depending on how it is characterized.
E. Conclusion
The purpose of this section was to provide a general overview of the regulation of hazardous wastes under RCRA and the importance of the ED&P exemption for the oil and gas industry. The reader should also note that many states may have additional regulatory requirements for hazardous wastes and used oil. See, e.g., Ohio Rev. Code Ch. 3734 (solid and hazardous wastes) and Ohio Admin. Code Ch. 3745-279 (used oil).XII. Use of Natural Gas Condensate and Drip Gas as a Paraffin Solvent
Natural gas condensate and drip gas have long been used by oil and gas producers as an effective substitute for commercially available paraffin solvents. Given that producers have customarily gathered their drip gas along their pipelines for this purpose, and with the quantities of light-gravity crude and condensate generated by the Rose Run play, the issue of the use of condensate and drip gas as paraffin solvent has drawn scrutiny from U.S. EPA and Ohio EPA.U.S. EPA and Ohio EPA have accepted the position that the use of condensate and drip gas as a paraffin solvent can be a legitimate use rather than the disposal of a hazardous waste. In a September 9, 1993 memorandum from the Acting Director of the Office of Solid Waste of U.S. EPA to the Acting Director of the Waste Management Division of U.S. EPA Region V, U.S. EPA took the position that if the company can demonstrate that condensate is more product-like than waste-like by satisfying a three-pronged analysis, the use of condensate as a paraffin solvent will not be regulated under RCRA's hazardous and solid waste laws. The three-pronged analysis is as follows:
- The condensate must be as effective as the commercially available solvent that would otherwise be used;
- The condensate must contain no more hazardous constituents that would otherwise be found in commercially available paraffin solvents; and
- The condensate must be managed in a manner commensurate with the management of a valuable commodity.
XIII. Wetlands Permitting Issues
A. Introduction
Wetlands have received a significant amount of attention in recent years from both the environmental and business communities. Environmentalists are concerned with the impact of development on the wide variety of fish and wildlife species supported by wetland habitats. The business community has traditionally been concerned with the significant impact wetlands have on development because of the strict federal and state regulations that must be complied with. And the impact on business interests has increased over time due to the expansive view taken by regulators about what constitutes a wetland.This section of the report briefly discusses some of those regulations as they apply to the oil and gas industry. This is important to the industry because even the inadvertent filling of a wetlands can expose the operator to significant civil liabilities, while the intentional filling of a wetland area can expose the operator to criminal fines and incarceration. In addition, it can take months to obtain state and federal permits authorizing even minor wetland and stream impacts. Accordingly, it is essential to factor in these delays in proposed exploration and/or development activities.
B. Federal Program
Section 404 of the Clean Water Act requires a permit from the U.S. Army Corps of Engineers to discharge dredged or fill material into navigable waters of the United States, including wetlands. 33 U.S.C. § 1344. To obtain that permit, as a general matter, the applicant must show that it has taken steps to avoid wetland impacts where practicable, that it has minimized the impacts where they were unavoidable, and that it has compensated for the unavoidable impacts through activities designed to restore and create wetlands. As you might expect, the permitting process is often time consuming and expensive.1. Identifying Jurisdictional Wetlands
- Wetlands
The first step is to determine whether the proposed drill site even contains a wetland. For some proposed sites, this may not be difficult (e.g., for marsh areas, wet meadows, bogs and swamps). For other sites, however, the assessment may be more difficult, especially because many wetlands are dry for much of the year. Wetlands, for example, can take the form of upland fields and forested areas where the soil is saturated for as little as 21 days per year due to rainfall or flooding from other water sources, but which are dry at the time of the analysis.
The Corps defines a wetland as any "area[]... inundated or saturated by surface or ground water at a frequency and duration sufficient to support, and that under normal circumstances do[es] support, a prevalence of vegetation typically adapted for life in saturated soil conditions." 33 C.F.R. 328.3(b). The characteristics it examines are water (e.g., source and duration), vegetation (e.g., existing plant species) and soils (e.g., color and texture indicating hydric soils).
Indicators for the layperson include standing water or evidence of standing water on the surface, such as watermarks on bark or other fixed objects; standing water in a hole of a depth of 12 inches; and the presence of vegetation such as marsh grasses, willows, or other plant species typical of wetland areas in the region. Maps indicating wetland areas and plants typically located in wetlands can be found by region at the National Wetlands Inventory Center, http://www.nwi.fws.gov; however, these maps are relatively unreliable and are not available for all areas of the state. If there is a question about whether or not an area constitutes a wetland, you should have a determination made either by the Corps or a qualified consultant. - Corps Jurisdiction
If the proposed site is a wetland, the next step is to determine whether the Corps has jurisdiction – and thus whether a Corps permit is needed. The jurisdiction of the Corps has been interpreted broadly to include, among other things, authority over wetlands which are adjacent to waters of the United States, even if separated by man-made barriers, natural river berms, beach dunes and the like; and over those wetlands the use of which could affect interstate or foreign commerce, including wetlands