Annual Report — Form 10-K Filing Table of Contents
Document/ExhibitDescriptionPagesSize
1: 10-K Annual Report HTML 2.34M
2: EX-4.5 Instrument Defining the Rights of Security Holders HTML 39K
3: EX-21.1 Subsidiaries List HTML 35K
4: EX-23.1 Consent of Expert or Counsel HTML 32K
5: EX-23.2 Consent of Expert or Counsel HTML 32K
6: EX-23.3 Consent of Expert or Counsel HTML 34K
7: EX-24 Power of Attorney HTML 38K
11: EX-99.1 Miscellaneous Exhibit HTML 85K
8: EX-31.1 Certification -- §302 - SOA'02 HTML 36K
9: EX-31.2 Certification -- §302 - SOA'02 HTML 36K
10: EX-32.1 Certification -- §906 - SOA'02 HTML 35K
18: R1 Cover Page HTML 94K
19: R2 Consolidated Statements of Operations HTML 120K
20: R3 Consolidated Statements of Comprehensive Income HTML 71K
21: R4 Consolidated Statements of Comprehensive Income HTML 45K
(Parenthetical)
22: R5 Consolidated Balance Sheets HTML 153K
23: R6 Consolidated Balance Sheets (Parenthetical) HTML 41K
24: R7 Consolidated Statements of Equity HTML 83K
25: R8 Consolidated Statements of Cash Flows HTML 123K
26: R9 Summary of Significant Accounting Policies HTML 120K
27: R10 Revenue (Notes) HTML 96K
28: R11 Acquisitions and Divestitures (Notes) HTML 44K
29: R12 Asset Retirement Obligations HTML 55K
30: R13 Fair Value Measurements HTML 109K
31: R14 Derivative Contracts HTML 103K
32: R15 Leases HTML 66K
33: R16 Restructuring Costs HTML 110K
34: R17 Debt HTML 50K
35: R18 Commitments and Contingencies HTML 45K
36: R19 Share-Based Compensation HTML 104K
37: R20 Employee Benefits HTML 229K
38: R21 Income Taxes HTML 115K
39: R22 Quarterly Financial Information (Unaudited) HTML 86K
40: R23 Supplemental Gas and Oil Information (Unaudited) HTML 193K
41: R24 Summary of Significant Accounting Policies HTML 172K
(Policies)
42: R25 Summary of Significant Accounting Policies HTML 86K
(Tables)
43: R26 Revenue (Tables) HTML 92K
44: R27 Asset Retirement Obligations (Tables) HTML 56K
45: R28 Fair Value Measurements (Tables) HTML 104K
46: R29 Derivative Contracts (Tables) HTML 104K
47: R30 Leases (Tables) HTML 64K
48: R31 Restructuring Costs Restructuring Costs (Tables) HTML 114K
49: R32 Debt (Tables) HTML 45K
50: R33 Commitments and Contingencies (Tables) HTML 40K
51: R34 Share-Based Compensation (Tables) HTML 104K
52: R35 Employee Benefits (Tables) HTML 227K
53: R36 Income Taxes (Tables) HTML 115K
54: R37 Quarterly Financial Information (Unaudited) HTML 86K
(Tables)
55: R38 Supplemental Gas and Oil Information (Unaudited) HTML 204K
(Tables)
56: R39 Summary of Significant Accounting Policies Merger HTML 37K
(Details)
57: R40 Summary of Significant Accounting Policies Cash, HTML 41K
Cash Equivalents, and Restricted Cash (Details)
58: R41 Summary of Significant Accounting Policies HTML 48K
Supplemental Cash Flow Information (Details)
59: R42 Summary of Significant Accounting Policies HTML 42K
Accounts Receivable (Details)
60: R43 Summary of Significant Accounting Policies HTML 48K
Property, plant and equipment (Details)
61: R44 Summary of Significant Accounting Policies HTML 42K
Impairment of long-lived assets (Details)
62: R45 Summary of Significant Accounting Policies Credit HTML 45K
Risk (Details)
63: R46 Summary of Significant Accounting Policies Income HTML 35K
Taxes (Details)
64: R47 Summary of Significant Accounting Policies HTML 44K
Earnings Per Share (Details)
65: R48 Revenue (Details) HTML 126K
66: R49 Acquisitions and Divestitures Other Acquisitions HTML 37K
(Details)
67: R50 Acquisitions and Divestitures Haynesville/Cotton HTML 50K
Valley Divestiture (Details)
68: R51 Acquisitions and Divestitures Terminated Williston HTML 48K
Basin Divestiture (Details)
69: R52 Acquisitions and Divestitures Uinta Basin HTML 47K
Divestiture (Details)
70: R53 Acquisitions and Divestitures Other Divestitures HTML 40K
(Details)
71: R54 Asset Retirement Obligations Balance Sheet HTML 40K
Classification (Details)
72: R55 Asset Retirement Obligations ARO Rollforward HTML 49K
(Details)
73: R56 Fair Value Measurements (Narrative) (Details) HTML 51K
74: R57 Fair Value of Financial Assets and Liabilities HTML 96K
(Details)
75: R58 Fair Value Measurements Fair Value and Related HTML 38K
Carrying Amount of Certain Financial Instruments
(Details)
76: R59 Derivative Contracts (Narrative) (Details) HTML 38K
77: R60 Derivative Contracts Schedule of Commodity HTML 69K
Derivative Contracts (Details)
78: R61 Derivative Contracts Gain (Loss) in Statement of HTML 65K
Financial Performance (Details)
79: R62 Lease Costs (Details) HTML 51K
80: R63 Leases Long-Term Operating Lease Commitments HTML 56K
(Details)
81: R64 Restructuring Costs Restructuring Costs Recognized HTML 72K
(Details)
82: R65 Restructuring Costs Costs recognized and remaining HTML 50K
costs expected to be incurred (Details)
83: R66 Restructuring Costs Restructuring Liability HTML 55K
(Details)
84: R67 Debt (Narrative) (Details) HTML 84K
85: R68 Debt Schedule of Debt Instruments (Details) HTML 48K
86: R69 Commitments and Contingencies Narrative (Details) HTML 35K
87: R70 Commitments and Contingencies Commitments HTML 46K
(Details)
88: R71 Share-Based Compensation (Narrative) (Details) HTML 89K
89: R72 Share-Based Compensation Schedule of Share-based HTML 57K
Compensation Expense (Details)
90: R73 Share-Based Compensation Schedule of Stock Option HTML 81K
Transactions (Details)
91: R74 Share-Based Compensation Schedule of Restricted HTML 58K
Stock Transactions (Details)
92: R75 Share-Based Compensation Restricted Cash Awards HTML 44K
(Details)
93: R76 Share-Based Compensation Schedule of Performance HTML 53K
Share Unit Transactions (Details)
94: R77 Share-Based Compensation Schedule of Restricted HTML 53K
Share Unit Transactions (Details)
95: R78 Employee Benefits (Narrative) (Details) HTML 72K
96: R79 Employee Benefits Schedule of Curtailments in the HTML 41K
Statements of Operations (Details)
97: R80 Employee Benefits Schedule of Changes in Benefit HTML 107K
Obligations and Fair Value of Plan Assets
(Details)
98: R81 Employee Benefits Schedule of Net Periodic Benefit HTML 92K
Cost and Other Comprehensive Income for Pension
and Other Postretirement Benefit Plans (Details)
99: R82 Employee Benefits Schedule of Weighted Average HTML 51K
Actuarial Assumptions Used to Determine Benefit
Obligations and Net Periodic Benefit Costs
(Details)
100: R83 Employee Benefits Schedule of Fair Values of HTML 50K
Pension and Postretirement Benefit Assets by Asset
Class (Details)
101: R84 Employee Benefits Schedule of Expected Benefit HTML 50K
Payments for Pension and Other Postretirement
Benefits (Details)
102: R85 Employee Benefits EIP (Details) HTML 45K
103: R86 Employee Benefits WRAP Plan (Details) HTML 40K
104: R87 Income Taxes Narrative (Details) HTML 56K
105: R88 Income Taxes Schedule of Income Tax Expense HTML 49K
(Benefit) (Details)
106: R89 Income Taxes Reconciliation of Statutory Federal HTML 63K
Income Tax Rate and Effective Tax Rate (Details)
107: R90 Income Taxes Reconciliation of Statutory Federal HTML 57K
Income Tax Rate and Effective Tax Rate Footnotes
(Details)
108: R91 Income Taxes Schedule of Deferred Income Tax HTML 68K
Assets and Liabilities (Details)
109: R92 Income Taxes Amounts and Expiration Dates of Net HTML 58K
Operating Loss and Tax Credit Carryforwards
(Details)
110: R93 Income Taxes Unrecognized Tax Benefits (Details) HTML 41K
111: R94 Quarterly Financial Information (Unaudited) HTML 69K
(Details)
112: R95 Supplemental Gas and Oil Information (Unaudited) HTML 44K
Capitalized costs (Details)
113: R96 Supplemental Gas and Oil Information (Unaudited) HTML 52K
Costs incurred (Details)
114: R97 Supplemental Gas and Oil Information (Unaudited) HTML 58K
Results of Operations (Details)
115: R98 Supplemental Gas and Oil Information (Unaudited) HTML 127K
Estimated Quantities of Proved Gas and Oil
Reserves (Details)
116: R99 Supplemental Gas and Oil Information (Unaudited) HTML 38K
Average price per unit (Details)
117: R100 Supplemental Gas and Oil Information (Unaudited) HTML 39K
Future Development Costs (Details)
118: R101 Supplemental Gas and Oil Information (Unaudited) HTML 55K
Standardized Measure Of Future Net Cash Flows
(Details)
119: R102 Supplemental Gas and Oil Information (Unaudited) HTML 73K
Change in Standardized Measure of Future Cash
Flows (Details)
121: XML IDEA XML File -- Filing Summary XML 227K
17: XML XBRL Instance -- qep-20201231_htm XML 4.62M
120: EXCEL IDEA Workbook of Financial Reports XLSX 179K
13: EX-101.CAL XBRL Calculations -- qep-20201231_cal XML 309K
14: EX-101.DEF XBRL Definitions -- qep-20201231_def XML 1.15M
15: EX-101.LAB XBRL Labels -- qep-20201231_lab XML 2.68M
16: EX-101.PRE XBRL Presentations -- qep-20201231_pre XML 1.66M
12: EX-101.SCH XBRL Schema -- qep-20201231 XSD 288K
122: JSON XBRL Instance as JSON Data -- MetaLinks 588± 886K
123: ZIP XBRL Zipped Folder -- 0001108827-21-000012-xbrl Zip 1.01M
At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of QEP Energy Company (QEP) as of December 31, 2020. The subject properties are located in the states of North Dakota and Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission
(SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 13, 2021 and presented herein, was prepared for public disclosure by QEP in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.
The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon and gas reserves of QEP as of December 31, 2020.
The estimated reserves and future net income amounts presented in this report, as of December 31,
2020 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.
Liquid
hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (Mbbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).
The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIESTM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of QEP. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may
not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.
The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, development costs, and certain abandonment costs net of salvage. Certain NGL processing fees are included as “Other” deductions as shown in the cash flow. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.
Liquid
hydrocarbon reserves account for approximately 97 percent and gas reserves account for the remaining 3 percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.
The
results shown above are presented for your information and should not be construed as our estimate of fair market value.
Reserves Included in This Report
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.
The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe status categories.
No
attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing
reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At QEP’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.
Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”
Proved
reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this
report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.
QEP’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated
quantities.
The estimates of proved reserves presented herein were based upon a detailed study of the properties in which QEP owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Estimates of Reserves
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities
in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.
In
many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states
that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of
reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves for the properties included herein were estimated by performance methods and analogy. Approximately 92% of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by decline curve analysis, a performance method which utilized extrapolations of available historical production and pressure data ending between July and December 2020, depending on the
availability of data for a given case and in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by QEP and were considered sufficient for the purpose thereof. The remaining 8% of proved producing reserves were estimated by analogy where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserves estimates was considered to be inappropriate.
Approximately 85 percent of the proved developed non-producing reserves and all of the proved undeveloped reserves included herein were estimated by analogy. The remaining 15 percent of the proved developed non-producing reserves were based on the historical performance of those shut-in wells before going offline. The data utilized from the analogues and the historical performance
of the shut-in wells were considered sufficient for the purpose thereof.
To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other
costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
QEP has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by QEP with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product
prices, geological structural and isochore maps, and base maps. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by QEP. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.
In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K,
referred to herein collectively as the “SEC Regulations.” In our
opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
Future Production Rates
For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates
were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
Historical performance trends prior to being shut-in or the initial performance of analogy wells were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by QEP. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays
due to weather, the availability of rigs, the sequence of drilling and/or well completions, and/or constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
Hydrocarbon Prices
The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior
to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.
QEP furnished us with the above mentioned average prices in effect on December 31, 2020. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.
The product prices which were actually used to determine the future gross
revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, certain oil transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by QEP. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by QEP to determine these differentials.
In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented
in accordance with SEC disclosure requirements for the geographic area included in the report.
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.
Costs
Operating costs for the leases and wells in this report were furnished by QEP and are based on the operating expense reports of QEP and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of
corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. Certain gathering and transportation costs as well as NGL processing fees are included in the operating costs. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by QEP. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
Development costs were furnished to us by QEP and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us
were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties with proved reserves. At QEP's request, the abandonment costs for uneconomic wells or for other developed non-producing properties that currently do not have restoration plans are addressed separately by QEP. The estimates of the net abandonment costs furnished by QEP were accepted without independent verification.
The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with QEP’s plans to develop these reserves as of December 31, 2020. The implementation of QEP’s development plans as presented to us and incorporated herein is subject to the approval
process adopted by QEP’s management. As the result of our inquiries during the course of preparing this report, QEP has informed us that the development activities included herein have been subjected to and received the internal approvals required by QEP’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to QEP. QEP has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, QEP has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31,
2020, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
Current costs used by QEP were held constant throughout the life of the properties.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world
since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of
our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics
training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.
We are independent petroleum engineers with respect to QEP. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.
Terms
of Usage
The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by QEP.
QEP makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, QEP has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Forms S-3 and/or S-8 of QEP of the references to our name as well as to the references to our third party report
for QEP, which appears in the December 31, 2020 annual report on Form 10-K of QEP. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by QEP.
We have provided QEP with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by QEP and the original signed report letter, the original signed report letter shall control and supersede
the digital version.
The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.
Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner
served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.
Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves
on the latter organization's board of directors at the international level.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2020 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG and regulatory issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year, including one course in which he was the primary instructor, covering
topics such as reserves evaluation methods and evaluation software, RTA/PTA, ethics, regulatory issues, greenhouse gas management, geothermal energy, and more.
Based on his educational background, professional training and more than 15 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
Dates Referenced Herein and Documents Incorporated by Reference
