Background on Joint Venture Reporting

Joint venture reporting (JVR) can be analyzed within the establishment phase of the joint venture (JV), the management aspects during operations, the associated services and their agreements, and the non-Operator’s viewpoint.

Establishment of JV starts with a negotiation phase between Partners, continues with application process, and ends with the signing of a Joint Operating Agreement (JOA). The most important part of this phase is the JOA where extent of joint activities is defined. Obligations owed to the government agencies, geographic area where joint activities are conducted, and the resources committed by the Partners are the main constraints in this JOA. The appointment of an Operator involves definition of the duties: (i) obligations/commitments to government agencies, (ii) standards of care, (iii) agreements to be signed without approval from non-Operators, (iv) circumstances in which an approval is needed from the non-Operator. In addition to the duties, circumstances in which Operator is resigned or removed will be outlined in a JOA.

The JOA can divide the JV into six phases of operations:

  1. Exploration
  2. Appraisal
  3. Development
  4. Production
  5. Transportation
  6. Abandonment

This project will focus specifically on the production phase of a JV.

Management of operations can be conducted by an operating committee and related sub-committees with workgroups. Production can be divided into:

1. Operations: Process facilities will be designed using development planning phase’s analysis of estimated production with maximization of oil/gas recovery in mind. Production department is to operate and maintain the facilities at maximum efficiency with the minimum downtime. The power to these process facilities should be either delivered or created at the site. Modifications to the operations occur when the production team is trying to maximize their output. Advances in technology are taken advantage of as well. Pipelines have different management and operations for onshore and offshore operations. For example, onshore operations will carry one fluid at a time whereas offshore pipeline will have all three components of the output; oil, gas, and water to the process facilities. Therefore, separators play an important role in offshore operations.

2. Field management: Reservoir management uses predictions from the development planning phase in the design phase of how the wells are to be completed in terms of which reservoir fluids (oil, gas, and water) are produced. A production profile is followed. Production data is obtained by separately testing each well by recording the wellhead and separator pressures, temperatures, and the flow rates of each fluid produced. The annual budget of production forecast, the capital budget, and the operating budget should be kept in line with all improvements and optimizations to the production operations.
(a) Production forecast: knowledge of existing well performance and plans for new wells
(b) Capital budget: purchase and construction/installation of new wells/facilities
(c) Operating budget: forecast cost of operating/maintaining the existing facilities and salaries of personnel
End of field life is reached when the revenue received from the production is not sufficient to cover the operating costs.

3. Personnel – not in scope

4. Health, Safety, Security, and Environmental – not in scope

5. The transportation phase is important for this project from the point of view of its contributions to the cost: Capital costs in building new pipelines, operating costs in the form of maintenance/repairs, administration, and insurance, and voyage costs varying according to the vessel’s employment style.

6. Non-Operator (Partner) – Operator relationship: Monitoring of Operator’s performance requires gathering relevant information, effective utilization of the information, and maybe benchmarking (i.e., comparison of Operator performance with industry norms). Information flow is through daily production, daily drilling, weekly progress, and monthly progress reports. Utilization of information is an evaluation of the level of operations from safety, efficiency, operating costs, and technically-capable point of views.


In the US, the typical form used for JOA is the AAPL Form 610 [1] available from the American Association of Professional Landmen (AAPL) based in Fort Worth, Texas . Main subsections of a JOA are:

  1. Definitions: Operator, non-Operator, contract area, authorization for expenditure (AFE), oil and gas lease, drill site, etc.
  2. Exhibits: Legal descriptions of the properties, the parties of the agreement, percentage ownership interest of each owner, accounting procedure, etc.
  3. Interests of parties: How specific revenues, costs, and liabilities distributed according to ownership interests outlined in the exhibits.
  4. Titles: Title examination requirements for drillsites, costs of title process, etc.
  5. Operator: Designation of the Operator, general rights and duties, resignation or removal, all records, reports to be maintained by the Operator and provided to the non-Operators and governmental units are listed.
  6. Drilling and development: Procedures to be followed in drilling/development/ termination wells.
  7. Expenditures and liabilities
  8. Acquisition, maintenance, or transfer of interest
  9. Internal revenue code election: Operation taxed as a partnership or not.
  10. Claims and lawsuits
  11. Force majeure
  12. Notices: All notices should be in writing.
  13. Terms of agreement
  14. Compliance with laws and regulations
  15. Miscellaneous

The section 6 under Article V (Operator) of AAPL form 610 outlines the JV reporting mechanism as :
“6. Filing and Furnishing Government Reports: Operator will file, and upon written request promptly furnish copies to each requesting Non-Operator not in default of its payment obligations, all operational notices, reports or applications required to be filed by local, State, Federal, or Indian agencies or authorities having jurisdiction over operations hereunder. Each Non-Operator shall provide to Operator on a timely basis all information necessary to Operator to make such filings.
“7. Drilling and Testing Operations: The following provisions shall apply to each well drilled hereunder, including but not limited to the Initial Well:
(a) Operator will promptly advise Non-Operators of the date on which well is spudded, or the date on which drilling operations are commenced.
(b) Operator will send to Non-Operators such reports, test results, and notices regarding the progress of operations on the well as the Non-Operators shall reasonably request, including, but not limited to, daily drilling reports, completion reports, and well logs.
(c) Operator shall adequately test all Zones encountered which may reasonably be expected to be capable of producing Oil and Gas in paying quantities as a result of examination of the electric log or any other logs or cores or tests conducted hereunder.
“8. Cost Estimates: Upon request of any Consenting Party, Operator shall furnish estimates of current and cumulative costs incurred for the joint account at reasonable intervals during the conduct of any operation pursuant to this agreement. Operator shall not be held liable for errors in such estimates so long as the estimates are made in good faith.”


A sample drilling report page from Friendly Drilling Software (Stoner Engineering LLC):

Page 1. Summary of well drilling operations.
Page 2. Detailed view of drilling data, mud record, bit record, drillstring spec’s, etc.

Well completion report sample form from Texas:

Page 1
Page 2

Well log will have fields of [2]:
Field Name, Type Of Field, Area/Basin Location, Unit, Expr1005, Operator (Field), Status Of Production, Fm Or Gp Reservoir, Date Discovered, Operator Discovery, Well Name, Discovery, Well API, Discovery, Discovery Lease, Oil Resrv (Eur), Gas Resrv (Eur).

Well permit log will have fields of:
APINumber, WName, WNumber, OPName, CDate, PDate, Permit, WNameShort, TDepth, TVDepth, OpElev, OpDatum.

Well status log will have fields of:
APINumber, WName, WNumber, OPName, LeaseNum, IClass, FClass, Status, CDate, SDate, PDate, Permit, Area, SMername, Slat, SLong, STNum, STDir, SRNum, SRDir, SSNum, SFNS, SNSDir, SFEW, SEWDir, Blat, BLong, BTNum, BTDir, BRNum, BRDir, BSNum, BFNS, BNSDir, BFEW, BEWDir, TDepth, TVDepth, OpElev, OpDatum, FldPlWld, Elev, AltID.

Another well data report has fields of [3]:
API_WellNo, County, CoName, Well_Nm, Well_Typ, Wl_Status, Dt_Spud, Dt_Comp, Dt_Prod, Dt_PA, Wh_Twpn, Wh_Twpd, Wh_RngN, Wh_RngD, Wh_Sec, Wh_Qtr, Wh_Lat, Wh_Long, Wh_FtNS, Wh_Ns, Wh_FtEW, Wh_EW, Elev_Gr, Elev_KB, DTD, Lease_No, Lease_Name, Field


This project focuses on joint venture production reporting. Hence, all mandatory reports, as well as desired or in-practice reports, will be analyzed to find discrepancies in data representation, format of transfer, and solutions will be suggested.

The purpose of production reporting in a joint venture is to ensure that the production costs and related production have been documented and shared among members of the joint venture—between Partners and Operators [4].

1. Production costs: Typical production costs are composed of labor costs of operating employees, repair and maintenance costs of wells and related equipment (workover operations and some recompletions). Labor costs are salaries and benefits of employees such as production engineers and safety specialists.

Workover operations are often necessary to keep reservoir production levels at a satisfactory rate. When a workover operation is a mere restoration or stimulation of production, it is considered an ordinary repair and its expense is a production expense. Conflicts may arise when a major repair is required after a long period of successful operation/production in order to maintain production rates. These expenses might need to be capitalized instead of regarded as mere workover expenses.

Recompletions are conducted in an existing formation through deepening/plugging back and entering an existing well. If these existing formations have been already drilled, the expenses will belong to production costs. However, whenever a new formation is being exploited, the expenses shift to new drilling costs; consequently, the expenses should be classified as exploratory or development rather than production.

Cost of materials and supplies also falls under production costs when the equipment, small tools, and other supplies are used in operations. Usually, the materials and supplies are kept in inventory. If they are retrieved and used in drilling/development, they should be capitalized whereas usage in repair/maintenance will charge their cost to expenses.

Overhead costs are general and administrative in nature stemming from support provided by the Operator’s home offices in the form of human resources department, treasury, legal, or accounting dictated by JOA or Operator’s internal policies.

Taxes are in the form of severance or production taxes in the US based on the percentage of the selling price of oil/gas, either net of royalty or gross. Both taxes are counted towards production costs.

2. Production: Once expenses are determined, the income from production is used to distribute the revenue among the members of a joint venture. Allocation of production costs to the property or well level is required for almost all JOAs. Production costs directly related to a specific well or cost center include: labor, materials, fuel and power, repair of equipment, workover costs, etc. Other production costs directly related to several wells or properties (and therefore require allocation) include: procurement, telecommunications, field offices, and saltwater disposal systems serving several fields, etc.

Common allocation bases used in the industry include:
a) Number of direct labor hours
b) Amount of direct labor costs
c) Number of wells
d) Number of miles driven
e) Barrels of water injected
f) Drilling days

For example, taking barrels of water injection as a basis of allocation would require analysis of performance of each well and making sure each well has approximately similar levels of water injection levels. If some wells start to have higher levels than all others, other allocation methods might become more fair and reasonable for accounting purposes.

Measurement of amount of produced oil is essential in determination of production:
The worldwide standard for measuring volume of oil is a barrel: 42 US gallons of liquid measured at 60 F. The other standard of measurement is API gravity (=(141.5/(specific gravity) – 31.5) The higher the API gravity, the lighter the oil, and consequently, the higher the price. The amount of impurity in the oil is measured in the form of BS&W percentage which has a threshold value that the sales contract should meet. In determining royalty payments, taxes, or cost recovery, the government contract might require oil measurements in terms of its weight instead of volume. A conversion will be necessary between these two units. At the delivery, oil might be measured manually by the gauge of the tank or automatically by lease automatic custody transfer (LACT) units or other metering devices at the transfer points.

The crude oil might be disposed of by: (i) outright sales, (ii) direct supply, (iii) indirect supply, (iv) exchanges, (v) frac oil to be reinjected back to well for stimulation of production, (vi) to be used in operations, and (vii) un-merchantable oil.

Allocation of oil might be realized by: (i) determination of production levels at each well or property, (ii) well tests (through diversion of stream of fluid from the well to a test separator to separate the fluid into oil, gas, and water, measure each individually, and compute a theoretical production amount).

Example back allocation to well or facility where total October production has been 520,500 barrels based on a well test [4]:

Platform Well Actual Number of Production Days (Days ON) Hours on Test (hours) Well Test Results (bbl)
Sea A 28 12 2000
B 28 12 1500
C 28 12 1000
Ocean D 29 6 1000
E 29 6 800
F 29 12 1200

The theoretical production (estimate of production) from each well would be computed as:

Platform Well Formula Theoretical Production (bbl)
Sea A 2000 x 24/12 x 28 = 112,000
B 1500 x 24/12 x 28 = 1500
C 1000 x 24/12 x 28 = 1000
Ocean D 1000 x 24/12 x 29 = 1000
E 800 x 24/12 x 29 = 800
F 1200 x 24/12 x 29 = 1200
Total 530,400

Gas measurement and production is outside the scope of this project.

1. Model Form for Operating Agreement, AAPL Form 610 – 1989, page 5.
2. Well log information is gathered from the web site of Division of Oil and Gas at the Alaska Department of Natural Resources, Well information page: – retrieved [online] on February 12th, 2009.
3. Retrieved from Nebraska’s well data dated February 5th, 2008 from web site: – retrieved [online] on February 12th, 2009.
4. Reference book: C. J. Wright and R. A. Gallun, International Petroleum Accounting, PennWell Corp., 2004.
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