|
Oklahoma
(State or other jurisdiction of incorporation or organization) |
| |
1311
(Primary Standard Industrial Classification Code Number) |
| |
73-1395733
(I.R.S. Employer Identification No.) |
|
|
William N. Finnegan IV
Kevin M. Richardson Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, Texas 77002 (713) 546-5400 |
| |
Benjamin E. Russ
Chesapeake Energy Corporation 6100 North Western Avenue Oklahoma City, Oklahoma 73118 (405) 848-8000 |
| |
Jonathan C. Curth
Vine Energy Inc. 5800 Granite Parkway, Suite 550 Plano, Texas 75024 (469) 606-0540 |
| |
Michael W. Rigdon
Kirkland & Ellis LLP 609 Main Street Houston, Texas 77002 (713) 836-3600 |
|
|
Large accelerated filer
☐
|
| |
Accelerated filer
☐
|
|
|
Non-accelerated filer
☒
|
| |
Smaller reporting company
☒
|
|
| | | |
Emerging growth company
☐
|
|
| | ||||||||||||||||||||||||||||
Title of Each Class of Security
to be Registered |
| | |
Amount to be
Registered |
| | |
Proposed Maximum
Offering Price Per Security |
| | |
Proposed Maximum
Aggregate Offering Price(2) |
| | |
Amount of
Registration Fee(2)(3) |
| ||||||||||||
Common stock, par value $0.01 per share
|
| | | | | 19,134,592 | | | | | | | N/A | | | | | | $ | 1,125,292,525.66 | | | | | | $ | 122,769.42 | | |
| | Your vote is very important. Approval of the merger proposal by the Vine stockholders is a condition to the consummation of the merger and requires the affirmative vote of a majority of the outstanding shares of Vine common voting entitled to vote on the proposal. Approval of the non-binding compensation advisory proposal requires the affirmative vote of a majority of the shares of Vine common stock present in person or represented by proxy at the special meeting and entitled to vote on the proposal. Approval of the adjournment proposal requires the affirmative vote of a majority of the shares of Vine common stock present in person or represented by proxy at the special meeting and entitled to vote on the proposal. Vine stockholders are requested to complete, date, sign and return the enclosed proxy in the envelope provided, which requires no postage if mailed in the United States, or to submit their proxies by phone or the Internet. Simply follow the instructions provided on the enclosed proxy card. Abstentions, broker non-votes and a failure to submit a proxy or vote via the Vine special meeting website will have the same effect as a vote “AGAINST” the merger proposal. | | |
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| | | | A-1 | | | |
| | | | B-1 | | | |
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| | | | E-1 | | | |
| | | | F-1 | | | |
| | | | G-1 | | |
|
Chesapeake Energy Corporation
6100 North Western Avenue Oklahoma City, Oklahoma 73118 Attention: Corporate Secretary Telephone: (405) 848-8000 |
| |
Vine Energy Inc.
5800 Granite Parkway, Suite 550 Plano, Texas 75024 Attention: Corporate Secretary Telephone: (469) 606-0540 |
|
| | |
Chesapeake
Common Stock |
| |
Vine Class A
Common Stock |
| |
Implied Per Share
Value of Merger Consideration(1) |
| |||||||||
August 10, 2021
|
| | | $ | 55.50 | | | | | $ | 14.88 | | | | | $ | 15.00(2) | | |
, 2021
|
| | | $ | | | | | $ | | | | | $ | | | |
Name
|
| |
Unvested RSUs(1) (#)
|
| |
Estimated Value(2) ($)
|
| ||||||
Eric D. Marsh
|
| | | | 507,142 | | | | | | 7,454,987 | | |
David M. Elkin
|
| | | | 271,428 | | | | | | 3,989,992 | | |
Wayne B. Stoltenberg
|
| | | | 235,714 | | | | | | 3,464,996 | | |
Jonathan C. Curth
|
| | | | 67,858 | | | | | | 997,513 | | |
Name
|
| |
Unvested RSUs (#)
|
| |
Estimated Value(1) ($)
|
| ||||||
Charles M. Sledge
|
| | | | 28,571 | | | | | | 419,994 | | |
H. Paulett Eberhart
|
| | | | 10,714 | | | | | | 157,496 | | |
Name
|
| |
Cash(1) ($)
|
| |
Equity(2) ($)
|
| |
Perquisites/Benefits(3) ($)
|
| |
Total ($)
|
| ||||||||||||
Eric D. Marsh
|
| | | | 8,316,508 | | | | | | 7,454,987 | | | | | | 1,732 | | | | | | 15,773,228 | | |
David M. Elkin
|
| | | | 1,581,855 | | | | | | 3,989,992 | | | | | | 29,014 | | | | | | 5,600,860 | | |
Wayne B. Stoltenberg
|
| | | | 1,842,286 | | | | | | 3,464,996 | | | | | | 28,016 | | | | | | 5,335,298 | | |
Jonathan C. Curth
|
| | | | 1,346,712 | | | | | | 997,513 | | | | | | 29,014 | | | | | | 2,373,239 | | |
Date Announced
|
| |
Buyer
|
| |
Seller
|
|
6/2/2021 | | | Southwestern Energy Company | | | Indigo II Louisiana Operating LLC | |
6/10/2019 | | | Comstock Resources, Inc. | | | Covey Park Energy LLC | |
11/19/2018 | | | Aethon Energy Management LLC | | | QEP Resources, Inc. | |
6/29/2018 | | | Osaka Gas USA Corporation | | | Sabine Oil & Gas Corporation | |
8/1/2017 | | | Rockcliff Energy II LLC | | | Samson Resources II, LLC | |
12/20/2016 | | | Covey Park Energy LLC | | |
Chesapeake Energy Corporation
|
|
12/5/2016 | | | Indigo Resources LLC | | |
Chesapeake Energy Corporation
|
|
11/2/2016 | | | Covey Park Energy LLC | | | EOG Resources, Inc. | |
Date Announced
|
| |
Buyer
|
| |
Seller
|
|
10/31/2016 | | | Castleton Commodities International LLC | | | Anadarko Petroleum Corporation | |
7/21/2016 | | | Ontario Teachers’ Pension Plan, Aethon Energy Management LLC, RedBird Capital Partners | | | J-W Energy Company | |
4/28/2016 | | | Indigo Minerals LLC | | | BEUSA Energy, Inc. | |
3/18/2016 | | | Covey Park Energy LLC | | | EP Energy Corporation | |
8/25/2015 | | | GeoSouthern Haynesville, LP, GSO Capital Partners LP | | | Encana Corporation | |
| | |
RADR Approach
|
| |
WACC Approach
|
| |
Adjusted Exchange
Ratio |
| ||||||||||||||||||
| | |
3P Reserves
NYMEX Strip Pricing |
| |
3P Reserves
Consensus Pricing |
| |
1P Reserves
NYMEX Strip Pricing |
| |
1P Reserves
Consensus Pricing |
| | | | ||||||||||||
Implied Equity
Value Per Share Reference Range |
| | | $ | 3.19 – $9.65 | | | | | $ | 4.72 – $11.54 | | | | | $ | 16.28 – $19.03 | | | | | $ | 18.28 – $21.17 | | | | | |
| | |
RADR Approach
|
| |
WACC Approach
|
| |
Adjusted Exchange
Ratio |
| |||||||||||||||||||||
| | |
3P Reserves
NYMEX Strip Pricing |
| |
3P Reserves
Consensus Pricing |
| |
1P Reserves
NYMEX Strip Pricing |
| |
1P Reserves
Consensus Pricing |
| | | | | | | ||||||||||||
Implied Exchange
Ratio Reference Range |
| | | | 0.0404 – 0.2056 | | | | | | 0.0669 – 0.2309 | | | | | | 0.2077 – 0.2660 | | | | | | 0.2172 – 0.2756 | | | | | | 0.2486 | | |
Date Announced
|
| |
Buyer
|
| |
Seller
|
|
6/8/2021 | | | Contango Oil & Gas Company | | | Independence Energy | |
6/2/2021 | | | Southwestern Energy Company | | | Indigo II Louisiana Operating LLC | |
5/6/2021 | | | EQT Corporation | | | ARD Operating | |
5/24/2021 | | | Cabot Oil & Gas Corporation | | | Cimarex Energy | |
12/21/2020 | | | Diamondback Energy | | | QEP Resources, Inc. | |
9/28/2020 | | | Devon Energy | | | WPX Energy | |
8/12/2020 | | | Southwestern Energy | | | Montage Resources | |
7/20/2020 | | | Chevron Corporation | | | Noble Energy | |
7/15/2019 | | | Callon Petroleum Company | | | Carrizo Oil & Gas, Inc. | |
6/10/2019 | | | Comstock Resources, Inc. | | | Covey Park Energy LLC | |
4/24/2019 | | | Occidental Petroleum | | | Anadarko Petroleum | |
8/27/2018 | | | Eclipse Resources | | | Blue Ridge Mountain Resources Inc. | |
6/19/2017 | | | EQT Corporation | | | Rice Energy Inc. | |
10/25/2016 | | | EQT Corporation | | | Republic Energy, Trans Energy Inc. | |
9/26/2016 | | | Rice Energy Inc. | | | Vantage Energy LLC, Vantage Energy II LLC | |
7/5/2016 | | | Mountain Capital Management | | | Harbinger Group Inc. | |
| | |
RADR Approach
|
| |
WACC Approach
|
| ||||||||||||||||||
| | |
3P Reserves
NYMEX Strip Pricing |
| |
3P Reserves
Consensus Pricing |
| |
1P Reserves
NYMEX Strip Pricing |
| |
1P Reserves
Consensus Pricing |
| ||||||||||||
Implied Equity Value Per Share Reference Range*
|
| | | $ | 41.10 – $49.20 | | | | | $ | 43.26 – $52.57 | | | | | $ | 67.04 – $72.60 | | | | | $ | 72.45 – $78.67 | | |
Implied Total Merger Consideration Reference Range
|
| | | $ | 11.42 – $13.43 | | | | | $ | 11.96 – $14.27 | | | | | $ | 17.87 – $19.25 | | | | | $ | 19.22 – $20.76 | | |
| | |
Has:
|
| |
Gets:
|
| ||||||
Selected Companies Analysis | | | | | | | | | | | | | |
2021E Average Daily Production
|
| | | $ | 15.29 – $21.83 | | | | | $ | 17.60 – $20.68 | | |
2021E EBITDAX
|
| | | $ | 16.09 – $24.16 | | | | | $ | 18.01 – $22.05 | | |
2022E EBITDAX
|
| | | $ | 17.19 – $26.16 | | | | | $ | 18.49 – $23.15 | | |
Selected Transactions Analysis
|
| | | | | | | | | | | | |
LQA Average Daily Production / Acreage
|
| | | $ | 18.06 – $26.11* | | | | | $ | 20.14 – $23.25 | | |
LQA EBITDAX
|
| | | $ | 18.14 – $24.19† | | | | | $ | 18.53 – $22.47 | | |
Discounted Cash Flow Analysis – Corporate
|
| | | $ | 19.85 – $28.07 | | | | | $ | 20.07 – $23.99 | | |
Discounted Cash Flow Analysis – Net Asset Value | | | | | | | | | | | | | |
RADR Approach – 3P Reserves NYMEX Strip Pricing
|
| | | $ | 3.19 – $9.65 | | | | | $ | 10.58 – $13.85 | | |
RADR Approach – 3P Reserves Consensus Pricing
|
| | | $ | 4.72 – $11.54 | | | | | $ | 11.39 – $15.04 | | |
WACC Approach – 1P Reserves NYMEX Strip Pricing
|
| | | $ | 16.28 – $19.03 | | | | | $ | 19.54 – $21.55 | | |
WACC Approach – 1P Reserves Consensus Pricing
|
| | | $ | 18.28 – $21.17 | | | | | $ | 21.30 – $23.51 | | |
| | |
NYMEX Strip Pricing(1)
|
| |||||||||||||||||||||||||||
| | |
2021E
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |||||||||||||||
Natural Gas ($/MMBtu)
|
| | | $ | 3.36 | | | | | $ | 3.39 | | | | | $ | 2.88 | | | | | $ | 2.75 | | | | | $ | 2.75 | | |
| | |
Vine Standalone Financial Projection(1)
For the Year Ended December 31, |
| |||||||||||||||||||||||||||
($ in millions)
|
| |
2021E
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |||||||||||||||
Net Gas Production (MMcf/d)
|
| | | | 998 | | | | | | 1,009 | | | | | | 1,068 | | | | | | 1,077 | | | | | | 1,139 | | |
Adjusted EBITDA(2)
|
| | | $ | 615 | | | | | $ | 683 | | | | | $ | 694 | | | | | $ | 683 | | | | | $ | 730 | | |
Operating Cash Flow(3)
|
| | | $ | 503 | | | | | $ | 567 | | | | | $ | 577 | | | | | $ | 565 | | | | | $ | 588 | | |
Adjusted Free Cash Flow(4)
|
| | | $ | 162 | | | | | $ | 200 | | | | | $ | 217 | | | | | $ | 208 | | | | | $ | 269 | | |
| | |
NYMEX Strip Pricing(1)
|
| |||||||||||||||||||||||||||
| | |
2021E
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |||||||||||||||
Natural Gas ($/MMBtu)
|
| | | $ | 3.36 | | | | | $ | 3.39 | | | | | $ | 2.88 | | | | | $ | 2.75 | | | | | $ | 2.75 | | |
| | |
Chesapeake Standalone Financial Projection(1)
For the Year Ended December 31, |
| |||||||||||||||||||||||||||
($ in millions)
|
| |
2021E
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |||||||||||||||
Net Gas Production Equivalent (MMcfe/d)
|
| | | | 2,624 | | | | | | 2,678 | | | | | | 2,652 | | | | | | 2,552 | | | | | | 2,544 | | |
Adjusted EBITDA(2)
|
| | | $ | 1,769 | | | | | $ | 2,070 | | | | | $ | 2,074 | | | | | $ | 1,910 | | | | | $ | 1,854 | | |
Operating Cash Flow(3)
|
| | | $ | 1,691 | | | | | $ | 1,996 | | | | | $ | 1,994 | | | | | $ | 1,803 | | | | | $ | 1,717 | | |
Adjusted Free Cash Flow(4)
|
| | | $ | 990 | | | | | $ | 897 | | | | | $ | 1,042 | | | | | $ | 737 | | | | | $ | 801 | | |
| | | | | | | | | | | | | | |
Transaction Adjustments
|
| | | | | | | |||||||||
| | |
Chesapeake
Historical |
| |
Vine
Historical |
| |
Reclass
Adjustments (Note 3) |
| |
Pro Forma
Adjustments (Note 3) |
| |
Chesapeake
Pro Forma Combined |
| |||||||||||||||
Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents
|
| | | $ | 612 | | | | | $ | 55 | | | | | $ | — | | | | | $ | (92)(b) | | | | | $ | 373 | | |
| | | | | — | | | | | | — | | | | | | — | | | | | | (202)(c) | | | | | | | | |
Restricted cash
|
| | | | 10 | | | | | | — | | | | | | — | | | | | | — | | | | | | 10 | | |
Accounts receivable, net
|
| | | | 674 | | | | | | 116 | | | | | | 17(a) | | | | | | — | | | | | | 807 | | |
Joint interest billing receivable
|
| | | | — | | | | | | 17 | | | | | | (17)(a) | | | | | | — | | | | | | — | | |
Other current assets
|
| | | | 58 | | | | | | 7 | | | | | | — | | | | | | — | | | | | | 65 | | |
Total current assets
|
| | | | 1,354 | | | | | | 195 | | | | | | — | | | | | | (294) | | | | | | 1,255 | | |
Property and equipment: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil and natural gas properties, successful efforts method
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved oil and natural gas properties
|
| | | | 4,960 | | | | | | 3,247 | | | | | | — | | | | | | (1,069)(d) | | | | | | 7,138 | | |
Unproved properties
|
| | | | 442 | | | | | | 90 | | | | | | — | | | | | | 508(d) | | | | | | 1,040 | | |
Other property and equipment
|
| | | | 491 | | | | | | 12 | | | | | | — | | | | | | — | | | | | | 503 | | |
Total property and equipment
|
| | | | 5,893 | | | | | | 3,349 | | | | | | — | | | | | | (561) | | | | | | 8,681 | | |
Less: accumulated depreciation, depletion and amortization
|
| | | | (346) | | | | | | (1,599) | | | | | | — | | | | | | 1,599(d) | | | | | | (346) | | |
Property and equipment held for sale, net
|
| | | | 3 | | | | | | — | | | | | | — | | | | | | — | | | | | | 3 | | |
Total property and equipment, net
|
| | | | 5,550 | | | | | | 1,750 | | | | | | — | | | | | | 1,038 | | | | | | 8,338 | | |
Operating lease right-of-use assets
|
| | | | — | | | | | | 16 | | | | | | (16)(a) | | | | | | — | | | | | | — | | |
Other long-term assets
|
| | | | 95 | | | | | | 11 | | | | | | 16(a) | | | | | | (10)(d) | | | | | | 112 | | |
Total assets
|
| | | $ | 6,999 | | | | | $ | 1,972 | | | | | $ | — | | | | | $ | 734 | | | | | $ | 9,705 | | |
Liabilities and equity (deficit) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Accounts payable
|
| | | $ | 281 | | | | | $ | 7 | | | | | $ | — | | | | | $ | — | | | | | $ | 288 | | |
Accrued interest
|
| | | | 24 | | | | | | — | | | | | | — | | | | | | — | | | | | | 24 | | |
Short-term derivative liabilities
|
| | | | 780 | | | | | | 271 | | | | | | — | | | | | | — | | | | | | 1,051 | | |
Accrued liabilities
|
| | | | — | | | | | | 112 | | | | | | (112)(a) | | | | | | — | | | | | | — | | |
Revenue payable
|
| | | | — | | | | | | 52 | | | | | | (52)(a) | | | | | | — | | | | | | — | | |
Operating leases
|
| | | | — | | | | | | 9 | | | | | | (9)(a) | | | | | | — | | | | | | — | | |
Other current liabilities
|
| | | | 781 | | | | | | — | | | | | | 173(a) | | | | | | 45(e) | | | | | | 999 | | |
Total current liabilities
|
| | | | 1,866 | | | | | | 451 | | | | | | — | | | | | | 45 | | | | | | 2,362 | | |
Long-term debt, net
|
| | | | 1,261 | | | | | | — | | | | | | 1,110(a) | | | | | | 91(d) | | | | | | 2,282 | | |
| | | | | | | | | | | | | | | | | | | | | | | (180)(c) | | | | | | | | |
New RBL
|
| | | | — | | | | | | 35 | | | | | | (35)(a) | | | | | | — | | | | | | — | | |
Second lien credit facility
|
| | | | — | | | | | | 145 | | | | | | (145)(a) | | | | | | — | | | | | | — | | |
Unsecured debt
|
| | | | — | | | | | | 930 | | | | | | (930)(a) | | | | | | — | | | | | | — | | |
Long-term derivative liabilities
|
| | | | 211 | | | | | | 113 | | | | | | — | | | | | | — | | | | | | 324 | | |
Asset retirement obligations, net of current portion
|
| | | | 241 | | | | | | 24 | | | | | | — | | | | | | — | | | | | | 265 | | |
Other long-term liabilities
|
| | | | 7 | | | | | | — | | | | | | 6(a) | | | | | | — | | | | | | 13 | | |
Tax Receivable Agreement liability
|
| | | | — | | | | | | 7 | | | | | | — | | | | | | (7)(f) | | | | | | — | | |
Operating leases
|
| | | | — | | | | | | 6 | | | | | | (6)(a) | | | | | | — | | | | | | — | | |
Total liabilities
|
| | | | 3,586 | | | | | | 1,711 | | | | | | — | | | | | | (51) | | | | | | 5,246 | | |
Stockholders’ equity (deficit): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Common stock
|
| | | | 1 | | | | | | 1 | | | | | | — | | | | | | (1)(g) | | | | | | 1 | | |
Additional paid-in capital
|
| | | | 3,590 | | | | | | 355 | | | | | | — | | | | | | (355)(g) | | | | | | 4,650 | | |
| | | | | — | | | | | | — | | | | | | — | | | | | | 1,060(h) | | | | | | | | |
Accumulated deficit
|
| | | | (178) | | | | | | (214) | | | | | | — | | | | | | 214(g) | | | | | | (192) | | |
| | | | | — | | | | | | — | | | | | | — | | | | | | 53(i) | | | | | | | | |
| | | | | — | | | | | | — | | | | | | — | | | | | | (45)(e) | | | | | | | | |
| | | | | — | | | | | | — | | | | | | — | | | | | | (22)(c) | | | | | | | | |
Total stockholders’ equity (deficit)
|
| | | | 3,413 | | | | | | 142 | | | | | | — | | | | | | 904 | | | | | | 4,459 | | |
Noncontrolling interests
|
| | | | — | | | | | | 119 | | | | | | | | | | | | (119)(j) | | | | | | — | | |
Total equity (deficit)
|
| | | | 3,413 | | | | | | 261 | | | | | | — | | | | | | 785 | | | | | | 4,459 | | |
Total liabilities and stockholders’ equity (deficit)
|
| | | $ | 6,999 | | | | | $ | 1,972 | | | | | $ | — | | | | | $ | 734 | | | | | $ | 9,705 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Transaction Adjustments
|
| | | | | | | |||||||||
| | |
Historical
Predecessor (Jan. 1, 2021 through Feb. 9, 2021) |
| | |
Historical
Successor (Feb. 10, 2021 through June 30, 2021) |
| |
Reorganization
Adjustments (Note 3) |
| |
Fresh Start
Adjustments (Note 3) |
| |
Chesapeake
Pro Forma |
| |
Vine
Historical |
| |
Brix
Companies Historical Through March 17, 2021 |
| |
Brix
Companies Acquisition Adjustments (Note 3) |
| |
Vine
Pro Forma |
| |
Reclass
Adjustments (Note 3) |
| |
Pro Forma
Adjustments (Note 3) |
| |
Chesapeake
Pro Forma Combined |
| ||||||||||||||||||||||||||||||||||||
Revenues and other: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil, natural gas and NGL
|
| | | $ | 398 | | | | | | $ | 1,445 | | | | | $ | — | | | | | $ | — | | | | | $ | 1,843 | | | | | $ | 388 | | | | | $ | 47 | | | | | $ | — | | | | | $ | 435 | | | | | $ | — | | | | | $ | — | | | | | $ | 2,278 | | |
Marketing
|
| | | | 239 | | | | | | | 816 | | | | | | — | | | | | | — | | | | | | 1,055 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 1,055 | | |
Oil and natural gas derivatives
|
| | | | (382) | | | | | | | (694) | | | | | | — | | | | | | — | | | | | | (1,076) | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (339)(a) | | | | | | — | | | | | | (1,415) | | |
Realized (loss) gain on commodity derivatives
|
| | | | — | | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (25) | | | | | | (2) | | | | | | — | | | | | | (27) | | | | | | 27(a) | | | | | | — | | | | | | — | | |
Unrealized (loss) gain on commodity derivatives
|
| | | | — | | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (309) | | | | | | (3) | | | | | | — | | | | | | (312) | | | | | | 312(a) | | | | | | — | | | | | | — | | |
Gains on sales of assets
|
| | | | 5 | | | | | | | 6 | | | | | | — | | | | | | — | | | | | | 11 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 11 | | |
Total revenues and other
|
| | | | 260 | | | | | | | 1,573 | | | | | | — | | | | | | — | | | | | | 1,833 | | | | | | 54 | | | | | | 42 | | | | | | — | | | | | | 96 | | | | | | — | | | | | | — | | | | | | 1,929 | | |
Operating expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Production
|
| | | | 32 | | | | | | | 114 | | | | | | — | | | | | | — | | | | | | 146 | | | | | | 32 | | | | | | 4 | | | | | | — | | | | | | 36 | | | | | | — | | | | | | — | | | | | | 182 | | |
Gathering, processing and
transportation |
| | | | 102 | | | | | | | 322 | | | | | | — | | | | | | — | | | | | | 424 | | | | | | 49 | | | | | | 6 | | | | | | — | | | | | | 55 | | | | | | — | | | | | | — | | | | | | 479 | | |
Severance and ad valorem taxes
|
| | | | 18 | | | | | | | 65 | | | | | | — | | | | | | | | | | | | 83 | | | | | | 10 | | | | | | 1 | | | | | | — | | | | | | 11 | | | | | | — | | | | | | — | | | | | | 94 | | |
Marketing
|
| | | | 237 | | | | | | | 815 | | | | | | — | | | | | | — | | | | | | 1,052 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 1,052 | | |
General and administrative
|
| | | | 21 | | | | | | | 39 | | | | | | — | | | | | | — | | | | | | 60 | | | | | | 7 | | | | | | 1 | | | | | | — | | | | | | 8 | | | | | | 14(a) | | | | | | — | | | | | | 82 | | |
Monitoring fee
|
| | | | — | | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 2 | | | | | | 2 | | | | | | (4)(o) | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Stock-based compensation for Existing Management Owners
|
| | | | — | | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 14 | | | | | | — | | | | | | — | | | | | | 14 | | | | | | (14)(a) | | | | | | — | | | | | | — | | |
Separation and other termination costs
|
| | | | 22 | | | | | | | 11 | | | | | | — | | | | | | — | | | | | | 33 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 33 | | |
Depreciation, depletion and amortization
|
| | | | 72 | | | | | | | 351 | | | | | | — | | | | | | 29(l) | | | | | | 452 | | | | | | 222 | | | | | | 31 | | | | | | (21)(o) | | | | | | 232 | | | | | | — | | | | | | (4)(p) | | | | | | 680 | | |
Impairments
|
| | | | — | | | | | | | 1 | | | | | | — | | | | | | — | | | | | | 1 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 1 | | |
Exploration
|
| | | | 2 | | | | | | | 2 | | | | | | — | | | | | | — | | | | | | 4 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 4 | | |
Other operating income
|
| | | | (12) | | | | | | | (2) | | | | | | — | | | | | | — | | | | | | (14) | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (14) | | |
Total operating expenses
|
| | | | 494 | | | | | | | 1,718 | | | | | | — | | | | | | 29 | | | | | | 2,241 | | | | | | 336 | | | | | | 45 | | | | | | (25) | | | | | | 356 | | | | | | — | | | | | | (4) | | | | | | 2,593 | | |
Loss from operations
|
| | | | (234) | | | | | | | (145) | | | | | | — | | | | | | (29) | | | | | | (408) | | | | | | (282) | | | | | | (3) | | | | | | 25 | | | | | | (260) | | | | | | — | | | | | | 4 | | | | | | (664) | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Transaction Adjustments
|
| | | | | | | |||||||||
| | |
Historical
Predecessor (Jan. 1, 2021 through Feb. 9, 2021) |
| | |
Historical
Successor (Feb. 10, 2021 through June 30, 2021) |
| |
Reorganization
Adjustments (Note 3) |
| |
Fresh Start
Adjustments (Note 3) |
| |
Chesapeake
Pro Forma |
| |
Vine
Historical |
| |
Brix
Companies Historical Through March 17, 2021 |
| |
Brix
Companies Acquisition Adjustments (Note 3) |
| |
Vine
Pro Forma |
| |
Reclass
Adjustments (Note 3) |
| |
Pro Forma
Adjustments (Note 3) |
| |
Chesapeake
Pro Forma Combined |
| ||||||||||||||||||||||||||||||||||||
Other income (expense):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest expense
|
| | | | (11) | | | | | | | (30) | | | | | | 4(k) | | | | | | — | | | | | | (37) | | | | | | (53) | | | | | | (2) | | | | | | (2)(o) | | | | | | (57) | | | | | | — | | | | | | 29(q) | | | | | | (65) | | |
Loss on extinguishment of debt
|
| | | | — | | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (78) | | | | | | — | | | | | | 5(o) | | | | | | (73) | | | | | | — | | | | | | — | | | | | | (73) | | |
Other income
|
| | | | 2 | | | | | | | 31 | | | | | | — | | | | | | — | | | | | | 33 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 33 | | |
Reorganization items, net
|
| | | | 5,569 | | | | | | | — | | | | | | (5,368)(k) | | | | | | (201)(m) | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total other income (expense)
|
| | | | 5,560 | | | | | | | 1 | | | | | | (5,364) | | | | | | (201) | | | | | | (4) | | | | | | (131) | | | | | | (2) | | | | | | 3 | | | | | | (130) | | | | | | — | | | | | | 29 | | | | | | (105) | | |
Income (loss) before income taxes
|
| | | | 5,326 | | | | | | | (144) | | | | | | (5,364) | | | | | | (230) | | | | | | (412) | | | | | | (413) | | | | | | (5) | | | | | | 28 | | | | | | (390) | | | | | | — | | | | | | 33 | | | | | | (769) | | |
Income tax expense (benefit)
|
| | | | (57) | | | | | | | — | | | | | | — | | | | | | 57(n) | | | | | | — | | | | | | 5 | | | | | | — | | | | | | — | | | | | | 5 | | | | | | — | | | | | | — | | | | | | 5 | | |
Net income (loss)
|
| | | | 5,383 | | | | | | | (144) | | | | | | (5,364) | | | | | | (287) | | | | | | (412) | | | | | | (418) | | | | | | (5) | | | | | | 28 | | | | | | (395) | | | | | | — | | | | | | 33 | | | | | | (774) | | |
Net loss attributable to Predecessor
|
| | | | — | | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 29 | | | | | | — | | | | | | (29)(o) | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Net loss attributable to noncontrolling interests
|
| | | | — | | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 175 | | | | | | — | | | | | | 2(o) | | | | | | 177 | | | | | | — | | | | | | (177)(j) | | | | | | — | | |
Net income (loss) available to common stockholders
|
| | | $ | 5,383 | | | | | | $ | (144) | | | | | $ | (5,364) | | | | | $ | (287) | | | | | $ | (412) | | | | | $ | (214) | | | | | $ | (5) | | | | | $ | 1 | | | | | $ | (218) | | | | | $ | — | | | | | $ | (144) | | | | | $ | (774) | | |
Earnings (loss) per common share:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic
|
| | | $ | 550.35 | | | | | | $ | (1.47) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | (6.61) | | |
Diluted
|
| | | $ | 534.51 | | | | | | $ | (1.47) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | (6.61) | | |
Weighted average common and common equivalent shares outstanding (in thousands):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic
|
| | | | 9,781 | | | | | | | 97,922 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 19,135(r) | | | | | | 117,057 | | |
Diluted
|
| | | | 10,071 | | | | | | | 97,922 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 19,135(r) | | | | | | 117,057 | | |
| | | | | | | | | | | | | | |
Transaction Adjustments
|
| | | | | | | |||||||||
| | |
Chesapeake
Pro Forma |
| |
Vine
Pro Forma |
| |
Reclass
Adjustments (Note 3) |
| |
Pro Forma
Adjustments (Note 3) |
| |
Chesapeake
Pro Forma Combined |
| |||||||||||||||
Revenues and other: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil, natural gas and NGL
|
| | | $ | 2,745 | | | | | $ | 571 | | | | | $ | — | | | | | $ | — | | | | | $ | 3,316 | | |
Marketing
|
| | | | 1,869 | | | | | | — | | | | | | — | | | | | | — | | | | | | 1,869 | | |
Oil and natural gas derivatives
|
| | | | 596 | | | | | | — | | | | | | (43)(a) | | | | | | — | | | | | | 553 | | |
Realized (loss) gain on commodity derivatives
|
| | | | — | | | | | | 162 | | | | | | (162)(a) | | | | | | — | | | | | | — | | |
Unrealized (loss) gain on commodity derivatives
|
| | | | — | | | | | | (205) | | | | | | 205(a) | | | | | | — | | | | | | — | | |
Gain on sales of assets
|
| | | | 30 | | | | | | — | | | | | | — | | | | | | — | | | | | | 30 | | |
Total revenues and other
|
| | | | 5,240 | | | | | | 528 | | | | | | — | | | | | | — | | | | | | 5,768 | | |
Operating expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Production
|
| | | | 373 | | | | | | 66 | | | | | | — | | | | | | — | | | | | | 439 | | |
Gathering, processing and transportation
|
| | | | 1,082 | | | | | | 102 | | | | | | — | | | | | | — | | | | | | 1,184 | | |
Severance and ad valorem taxes
|
| | | | 149 | | | | | | 18 | | | | | | — | | | | | | — | | | | | | 167 | | |
Exploration
|
| | | | 427 | | | | | | — | | | | | | — | | | | | | — | | | | | | 427 | | |
Marketing
|
| | | | 1,889 | | | | | | — | | | | | | — | | | | | | — | | | | | | 1,889 | | |
General and administrative
|
| | | | 267 | | | | | | 15 | | | | | | — | | | | | | — | | | | | | 282 | | |
Separation and other termination costs
|
| | | | 44 | | | | | | — | | | | | | — | | | | | | — | | | | | | 44 | | |
Depreciation, depletion and amortization
|
| | | | 980 | | | | | | 392 | | | | | | — | | | | | | 132(p) | | | | | | 1,504 | | |
Impairments
|
| | | | 8,535 | | | | | | — | | | | | | — | | | | | | — | | | | | | 8,535 | | |
Other operating expense
|
| | | | 80 | | | | | | — | | | | | | 8(a) | | | | | | 45(e) | | | | | | 133 | | |
Strategic
|
| | | | — | | | | | | 2 | | | | | | (2)(a) | | | | | | — | | | | | | — | | |
Write-off of deferred IPO expenses
|
| | | | — | | | | | | 6 | | | | | | (6)(a) | | | | | | — | | | | | | — | | |
Total operating expenses
|
| | | | 13,826 | | | | | | 601 | | | | | | — | | | | | | 177 | | | | | | 14,604 | | |
Loss from operations
|
| | | | (8,586) | | | | | | (73) | | | | | | — | | | | | | (177) | | | | | | (8,836) | | |
Other income (expense): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest expense
|
| | | | (81) | | | | | | (116) | | | | | | — | | | | | | 64(q) | | | | | | (133) | | |
Gains (losses) on purchases or exchanges of debt
|
| | | | 65 | | | | | | — | | | | | | — | | | | | | (22)(c) | | | | | | 43 | | |
Other income (expense)
|
| | | | (4) | | | | | | — | | | | | | — | | | | | | 7(f) | | | | | | 3 | | |
Total other expense
|
| | | | (20) | | | | | | (116) | | | | | | — | | | | | | 49 | | | | | | (87) | | |
Loss before income taxes
|
| | | | (8,606) | | | | | | (189) | | | | | | — | | | | | | (128) | | | | | | (8,923) | | |
Current income tax benefit
|
| | | | (9) | | | | | | — | | | | | | — | | | | | | — | | | | | | (9) | | |
Deferred income tax benefit
|
| | | | (10) | | | | | | — | | | | | | — | | | | | | (53)(i) | | | | | | (63) | | |
Income tax benefit
|
| | | | (19) | | | | | | — | | | | | | — | | | | | | (53) | | | | | | (72) | | |
Net loss
|
| | | | (8,587) | | | | | | (189) | | | | | | — | | | | | | (75) | | | | | | (8,851) | | |
Net loss attributable to noncontrolling interests
|
| | | | 16 | | | | | | 96 | | | | | | — | | | | | | (96)(j) | | | | | | 16 | | |
Net loss attributable to Chesapeake
|
| | | | (8,571) | | | | | | (93) | | | | | | — | | | | | | (171) | | | | | | (8,835) | | |
Preferred stock dividends
|
| | | | (22) | | | | | | — | | | | | | — | | | | | | — | | | | | | (22) | | |
Net loss available to common stockholders
|
| | | $ | (8,593) | | | | | $ | (93) | | | | | $ | — | | | | | $ | (171) | | | | | $ | (8,857) | | |
Loss per common share: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic
|
| | | $ | (87.77) | | | | | | | | | | | | | | | | | | | | | | | $ | (75.67) | | |
Diluted
|
| | | $ | (87.77) | | | | | | | | | | | | | | | | | | | | | | | $ | (75.67) | | |
Weighted average common and common equivalent shares outstanding (in thousands):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic
|
| | | | 97,907 | | | | | | | | | | | | | | | | | | 19,135(r) | | | | | | 117,042 | | |
Diluted
|
| | | | 97,907 | | | | | | | | | | | | | | | | | | 19,135(r) | | | | | | 117,042 | | |
| | |
Preliminary
Purchase Price Allocation |
| |||
| | |
($ in millions)
|
| |||
Consideration: | | | | | | | |
Cash(a)
|
| | | $ | 92 | | |
Fair value of Chesapeake common stock to be issued(b)
|
| | | | 1,060 | | |
Total consideration
|
| | | $ | 1,152 | | |
Fair Value of Liabilities Assumed: | | | | | | | |
Current liabilities
|
| | | $ | 451 | | |
Long-term debt
|
| | | | 1,201 | | |
Deferred tax liabilities
|
| | | | 53 | | |
Other long-term liabilities
|
| | | | 143 | | |
Amounts attributable to liabilities assumed
|
| | | | 1,848 | | |
Fair Value of Assets Acquired: | | | | | | | |
Cash and cash equivalents
|
| | | $ | 55 | | |
Other current assets
|
| | | | 140 | | |
Proved oil and natural gas properties
|
| | | | 2,178 | | |
Unproved properties
|
| | | | 598 | | |
Other property and equipment
|
| | | | 12 | | |
Other long-term assets
|
| | | | 17 | | |
Amounts attributable to assets acquired
|
| | | | 3,000 | | |
Total identifiable net assets
|
| | | $ | 1,152 | | |
|
Shares of Chesapeake common stock to be issued
|
| | | | 19,134,592 | | |
|
Closing price per share of Chesapeake common stock on August 27, 2021
|
| | | $ | 55.38 | | |
|
Total fair value of shares of Chesapeake common stock to be issued
|
| | | $ | 1,060 | | |
|
Increase in Chesapeake common stock ($0.01 par value per share) as of June 30, 2021
|
| | | $ | — | | |
|
Increase in Chesapeake additional paid-in capital as of June 30, 2021
|
| | | $ | 1,060 | | |
| | |
Oil (mmbbls)
|
| |||||||||||||||
| | |
Chesapeake
Historical |
| |
Vine Pro
Forma |
| |
Chesapeake
Pro Forma Combined |
| |||||||||
As of December 31, 2019
|
| | | | 358.0 | | | | | | — | | | | | | 358.0 | | |
Extensions, discoveries and other additions
|
| | | | 1.1 | | | | | | — | | | | | | 1.1 | | |
Revisions of previous estimates
|
| | | | (148.2) | | | | | | — | | | | | | (148.2) | | |
Production
|
| | | | (37.3) | | | | | | — | | | | | | (37.3) | | |
Sale of reserves-in-place
|
| | | | (12.3) | | | | | | — | | | | | | (12.3) | | |
Purchase of reserves-in-place
|
| | | | — | | | | | | — | | | | | | — | | |
As of December 31, 2020
|
| | | | 161.3 | | | | | | — | | | | | | 161.3 | | |
Proved developed reserves: | | | | | | | | | | | | | | | | | | | |
December 31, 2019
|
| | | | 201.4 | | | | | | — | | | | | | 201.4 | | |
December 31, 2020
|
| | | | 158.1 | | | | | | — | | | | | | 158.1 | | |
Proved undeveloped reserves: | | | | | | | | | | | | | | | | | | | |
December 31, 2019
|
| | | | 156.6 | | | | | | — | | | | | | 156.6 | | |
December 31, 2020
|
| | | | 3.2 | | | | | | — | | | | | | 3.2 | | |
| | |
Natural Gas (bcf)
|
| |||||||||||||||
| | |
Chesapeake
Historical |
| |
Vine Pro
Forma |
| |
Chesapeake
Pro Forma Combined |
| |||||||||
As of December 31, 2019
|
| | | | 6,566 | | | | | | 2,862 | | | | | | 9,428 | | |
Extensions, discoveries and other additions
|
| | | | 100 | | | | | | 815 | | | | | | 915 | | |
Revisions of previous estimates
|
| | | | (2,326) | | | | | | (1,135) | | | | | | (3,461) | | |
Production
|
| | | | (684) | | | | | | (327) | | | | | | (1,011) | | |
Sale of reserves-in-place
|
| | | | (126) | | | | | | — | | | | | | (126) | | |
Purchase of reserves-in-place
|
| | | | — | | | | | | 98 | | | | | | 98 | | |
As of December 31, 2020
|
| | | | 3,530 | | | | | | 2,313 | | | | | | 5,843 | | |
Proved developed reserves: | | | | | | | | | | | | | | | | | | | |
December 31, 2019
|
| | | | 3,377 | | | | | | 586 | | | | | | 3,963 | | |
December 31, 2020
|
| | | | 3,196 | | | | | | 590 | | | | | | 3,786 | | |
Proved undeveloped reserves: | | | | | | | | | | | | | | | | | | | |
December 31, 2019
|
| | | | 3,189 | | | | | | 2,276 | | | | | | 5,465 | | |
December 31, 2020
|
| | | | 334 | | | | | | 1,723 | | | | | | 2,057 | | |
| | |
Natural Gas Liquids (mmbbls)
|
| |||||||||||||||
| | |
Chesapeake
Historical |
| |
Vine Pro
Forma |
| |
Chesapeake
Pro Forma Combined |
| |||||||||
As of December 31, 2019
|
| | | | 120.0 | | | | | | — | | | | | | 120.0 | | |
Extensions, discoveries and other additions
|
| | | | 0.4 | | | | | | — | | | | | | 0.4 | | |
Revisions of previous estimates
|
| | | | (50.6) | | | | | | — | | | | | | (50.6) | | |
Production
|
| | | | (11.3) | | | | | | — | | | | | | (11.3) | | |
Sale of reserves-in-place
|
| | | | (6.5) | | | | | | — | | | | | | (6.5) | | |
Purchase of reserves-in-place
|
| | | | — | | | | | | — | | | | | | — | | |
As of December 31, 2020
|
| | | | 52.0 | | | | | | — | | | | | | 52.0 | | |
Proved developed reserves: | | | | | | | | | | | | | | | | | | | |
December 31, 2019
|
| | | | 82.1 | | | | | | — | | | | | | 82.1 | | |
December 31, 2020
|
| | | | 51.4 | | | | | | — | | | | | | 51.4 | | |
Proved undeveloped reserves: | | | | | | | | | | | | | | | | | | | |
December 31, 2019
|
| | | | 37.9 | | | | | | — | | | | | | 37.9 | | |
December 31, 2020
|
| | | | 0.6 | | | | | | — | | | | | | 0.6 | | |
| | |
Total Reserves (mmboe)
|
| |||||||||||||||
| | |
Chesapeake
Historical |
| |
Vine Pro
Forma |
| |
Chesapeake
Pro Forma Combined |
| |||||||||
As of December 31, 2019
|
| | | | 1,572 | | | | | | 477 | | | | | | 2,049 | | |
Extensions, discoveries and other additions
|
| | | | 18 | | | | | | 135 | | | | | | 153 | | |
Revisions of previous estimates
|
| | | | (586) | | | | | | (189) | | | | | | (775) | | |
Production
|
| | | | (163) | | | | | | (54) | | | | | | (217) | | |
Sale of reserves-in-place
|
| | | | (39) | | | | | | — | | | | | | (39) | | |
Purchase of reserves-in-place
|
| | | | — | | | | | | 16 | | | | | | 16 | | |
As of December 31, 2020
|
| | | | 802 | | | | | | 386 | | | | | | 1,187 | | |
Proved developed reserves: | | | | | | | | | | | | | | | | | | | |
December 31, 2019
|
| | | | 846 | | | | | | 98 | | | | | | 944 | | |
December 31, 2020
|
| | | | 742 | | | | | | 98 | | | | | | 840 | | |
Proved undeveloped reserves: | | | | | | | | | | | | | | | | | | | |
December 31, 2019
|
| | | | 726 | | | | | | 379 | | | | | | 1,105 | | |
December 31, 2020
|
| | | | 60 | | | | | | 287 | | | | | | 347 | | |
| | |
As of December 31, 2020
|
| |||||||||||||||
| | |
Chesapeake
Historical |
| |
Vine Pro
Forma |
| |
Chesapeake
Pro Forma Combined |
| |||||||||
Future cash inflows
|
| | | $ | 8,247 | | | | | $ | 4,013 | | | | | $ | 12,260 | | |
Future production costs
|
| | | | (2,963) | | | | | | (1,496) | | | | | | (4,459) | | |
Future development costs
|
| | | | (563) | | | | | | (1,407) | | | | | | (1,970) | | |
Future income tax expense
|
| | | | (9) | | | | | | (51) | | | | | | (60) | | |
Future net cash flows
|
| | | | 4,712 | | | | | | 1,059 | | | | | | 5,771 | | |
Less effect of a 10% discount factor
|
| | | | (1,626) | | | | | | (356) | | | | | | (1,982) | | |
Standardized measure of discounted future net cash flows
|
| | | $ | 3,086 | | | | | $ | 703 | | | | | $ | 3,789 | | |
| | |
As of December 31, 2020
|
| |||||||||||||||
| | |
Chesapeake
Historical |
| |
Vine Pro
Forma |
| |
Chesapeake
Pro Forma Combined |
| |||||||||
Standardized measure, beginning of period
|
| | | $ | 9,000 | | | | | $ | 1,288 | | | | | $ | 10,288 | | |
Sales of oil, natural gas and LNGs produced, net of production costs and
gathering, processing and transportation |
| | | | (1,140) | | | | | | (385) | | | | | | (1,525) | | |
Net changes in prices and production costs
|
| | | | (5,576) | | | | | | (515) | | | | | | (6,091) | | |
Extensions and discoveries, net of production and development costs
|
| | | | 71 | | | | | | — | | | | | | 71 | | |
Changes in estimated future development costs
|
| | | | 1,933 | | | | | | 58 | | | | | | 1,991 | | |
Previously estimated development costs incurred during the period
|
| | | | 665 | | | | | | 246 | | | | | | 911 | | |
Revisions of previous quantity estimates
|
| | | | (1,839) | | | | | | (84) | | | | | | (1,923) | | |
Purchase of reserves-in-place
|
| | | | — | | | | | | 15 | | | | | | 15 | | |
Sales of reserves-in-place
|
| | | | (112) | | | | | | — | | | | | | (112) | | |
Accretion of discount
|
| | | | 902 | | | | | | 129 | | | | | | 1,031 | | |
Net changes in income taxes
|
| | | | 14 | | | | | | (37) | | | | | | (23) | | |
Changes in production rates and other
|
| | | | (832) | | | | | | (12) | | | | | | (844) | | |
Standardized measure, end of period
|
| | | $ | 3,086 | | | | | $ | 703 | | | | | $ | 3,789 | | |
|
Chesapeake
|
| |
Vine
|
|
|
Capital Stock
|
| |||
|
Chesapeake’s charter authorizes 450,000,000 shares of common stock, par value $0.01 per share, and 45,000,000 shares of preferred stock, par value $0.01 per share.
As of , 2021 there were shares of Chesapeake common stock outstanding and warrants to purchase shares of Chesapeake common stock outstanding. No shares of Chesapeake preferred stock are outstanding.
|
| |
Vine’s charter authorizes 350,000,000 shares of Class A common stock, par value $0.01 per share, 150,000,000 shares of Class B common stock, par value $0.01 per share, and 50,000,000 shares of preferred stock, par value $0.01 per share.
As of the Vine record date, there were shares of Vine Class A common stock outstanding, shares of Vine Class B common stock outstanding and no shares of Vine preferred stock outstanding.
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|
|
Board of Directors
|
| |||
| Section 1027.B of the OGCA provides that the number of directors constituting the board may be fixed by the charter or bylaws of a corporation. Chesapeake’s bylaws provide that, subject to the rights of the holders of any series of preferred stock to elect directors under specified circumstances, if any, the board of directors will consist of not less than three nor more than ten directors. Chesapeake currently has six directors. The Chesapeake board is not classified. All directors are elected annually for one-year terms. | | |
Section 141(b) of the DGCL provides that the number of directors constituting the board may be fixed by the charter or bylaws of a corporation.
Vine’s charter provides that the number of directors on Vine’s board shall be determined from time to time exclusively by resolution adopted by the board. Vine currently has six directors. The Vine board of directors is classified with directors serving three-year terms.
Additionally, Vine’s charter provides that, subject to the rights granted to the holders of any one or more series of preferred stock then outstanding or the rights granted pursuant to the Stockholders’ Agreement, dated March 22, 2021, by and among Vine and certain affiliates of The Blackstone Group L.P. (together with its affiliates, subsidiaries, successors and assigns, collectively, “Blackstone”) (such agreement, the “Stockholders’ Agreement”), any newly created directorship on the board that results from an increase in the number of directors
|
|
|
Chesapeake
|
| |
Vine
|
|
| | | | and any vacancy occurring in the board (whether by death, resignation, retirement, disqualification, removal or other cause) shall be filled by a majority of the directors then in office, although less than a quorum, by a sole remaining director or by the stockholders; provided, however, that at any time when Blackstone beneficially owns, in the aggregate, less than 30% in voting power of Vine’s stock entitled to vote generally in the election of directors, any newly created directorship on the board that results from an increase in the number of directors and any vacancy occurring in the board shall be filled only by a majority of the directors then in office, although less than a quorum, or by a sole remaining director (and not by the stockholders). Any director elected to fill a vacancy or newly created directorship shall hold office until the next election of the class for which such director shall have been chosen and until his or her successor shall be elected and qualified, or until his or her earlier death, resignation, retirement, disqualification or removal. | |
|
Removal of Directors
|
| |||
|
As described above under “— Board of Directors,” Chesapeake has a declassified board.
Chesapeake’s bylaws provide that a director may be removed, with or without cause, by the affirmative vote of the holders of a majority of the shares then entitled to vote at an election of directors.
|
| |
As described above under “— Board of Directors,” Vine has a classified board.
Vine’s charter provides that a director may be removed from office at any time, with or without cause, by the affirmative vote of the holders of a majority of the voting power of the outstanding shares of Vine then entitled to vote generally in the election of directors, voting as a single class; provided, however, that at any time when Blackstone beneficially owns, in the aggregate, less than 30% in voting power of the stock of Vine entitled to vote generally in the election of directors, any such director or all such directors may be removed only for cause and only by the affirmative vote of the holders of at least 66 2/3% in voting power of all the then-outstanding shares of stock of Vine entitled to vote thereon, voting together as a single class.
|
|
|
Filling Vacancies on the Board of Directors
|
| |||
| Chesapeake’s bylaws provide that all vacancies, including vacancies resulting from newly created directorships resulting from any increase in the authorized number of directors, may be filled by a majority vote of the directors then in office, even if less than a quorum, and any director so chosen will hold office until the next annual meetings of shareholders and until his or her successor is duly elected and qualified, or until his or her earlier resignation or removal. | | | Vine’s charter provides that, subject to the rights of the holders of any series of preferred stock then outstanding or the rights granted pursuant to the Stockholders’ Agreement, any vacancy occurring in the Vine board and newly created directorships resulting from any increase in the number of directors may be filled by a majority of the directors then in office, although less than a quorum, by a sole remaining director or by the stockholders; provided, however, that at any time when | |
|
Chesapeake
|
| |
Vine
|
|
| | | | Blackstone beneficially owns, in the aggregate, less than 30% in voting power of Vine’s stock entitled to vote generally in the election of directors, any newly created directorship on the board that results from an increase in the number of directors and any vacancy occurring in the board shall be filled only by a majority of the directors then in office, although less than a quorum, or by a sole remaining director (and not by the stockholders), and any director elected to fill a vacancy or newly created directorship will hold office until the next election of the class for which such director shall have been chosen and until his or her successor is elected and qualified, or until his or her earlier death, resignation, retirement, disqualification or removal. | |
|
Amendment of Certificate of Incorporation
|
| |||
|
Section 1077 of the OGCA provides that any amendment to a corporation’s certificate of incorporation must be approved at a special or annual meeting by a majority of the outstanding shares of each class entitled to vote as a class upon a proposed amendment, whether or not entitled to vote by the provisions of the certificate of incorporation, if the amendment would increase or decrease the aggregate number of authorized shares of the class, increase or decrease the par value of the shares of the class, or alter or change the powers, preferences or special rights of the shares of the class so as to affect them adversely.
Chesapeake’s charter requires that the affirmative vote of the holders of at least 60% of the voting power of all outstanding stock entitled to vote, voting together as a single class, to amend certain provisions of Chesapeake’s charter, including those provisions dealing with amendments to Chesapeake’s charter, director liability, related party transactions, board of directors, indemnities, forum selection, corporate opportunities and amendments to bylaws.
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| |
As provided under the DGCL, any amendment to Vine’s charter requires (i) the approval of the Vine board, (ii) the approval of a majority of the voting power of the outstanding shares of capital stock entitled to vote upon the proposed amendment and (iii) the approval of the holders of a majority of the outstanding stock of each class entitled to vote thereon as a class, if any.
Vine’s charter further requires that at any time when Blackstone beneficially owns, in the aggregate, less than 30% in voting power of Vine stock entitled to vote generally in the election of directors, in addition to any vote required by applicable law, the affirmative vote of holders of at least 66 2/3% in voting power of all the then-outstanding shares of Vine stock entitled to vote thereon, voting together as a single class is required to amend, alter, repeal or rescind any provision inconsistent with certain provisions of Vine’s charter, including those provisions dealing with amendments to the charter or bylaws, board makeup, elections and appointment, director and officer liability, certain stockholder matters, competition and corporate opportunities, Section 203 of the DGCL, severability and forum selection.
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Amendment of Bylaws
|
| |||
| Chesapeake’s charter provides that its bylaws may be adopted, repealed, altered, amended or rescinded by Chesapeake’s board or by the affirmative vote of the holders of at least a majority of the outstanding stock of Chesapeake entitled to vote thereon, provided that the affirmative vote of the holders of at least 60% of the outstanding stock of Chesapeake entitled to vote at an election of directors is required to amend certain provisions of Chesapeake’s bylaws dealing with listing requests of Chesapeake’s | | | Vine’s charter provides that its bylaws may be made, repealed, altered, amended or rescinded by Vine’s board without the assent or vote of the stockholders in any manner not inconsistent with the laws of the State of Delaware or Vine’s charter. Notwithstanding anything to the contrary contained in Vine’s charter or any provision of law that might otherwise permit a lesser vote of the stockholders, at any time when Blackstone beneficially owns, in the aggregate, less than 30% in | |
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Chesapeake
|
| |
Vine
|
|
| common stock, requests that Chesapeake make certain filings with the SEC and the process required to amend the bylaws. | | | voting power of Vine stock entitled to vote generally in the election of directors, in addition to any vote of the holders of any class or series of capital stock of Vine required (including any certificate of designation relating to any series of preferred stock), Vine’s bylaws or applicable law, the affirmative vote of the holders of at least 66 2/3% in voting power of all of Vine’s then-outstanding shares of stock entitled to vote thereon, voting together as a single class, shall be required in order for the Vine stockholders to alter, amend, repeal or rescind, in whole or in part, any provision of Vine’s bylaws or to adopt any provision inconsistent therewith. | |
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Notice of Meetings of Stockholders
|
| |||
| Section 1067 of the OCGA and Chesapeake’s bylaws provide that written notice of any shareholders’ meeting must be given to each shareholder not less than ten nor more than 60 days before the meeting date; provided, that in the case of a proposed merger, the notice must be not less than 20 days nor more than 60 days before the meeting. | | | Vine’s bylaws provide that unless otherwise provided by law, Vine’s charter or Vine’s bylaws, notice of any stockholders’ meeting must be given not less than ten days nor more than 60 days before the date of the meeting. The DGCL requires a corporation to provide not less than 20 days’ notice of a stockholders’ meeting to vote on a proposed merger. | |
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Right to Call Special Meeting of Stockholders
|
| |||
| Chesapeake’s charter and its bylaws authorize the calling of a special meeting of shareholders for any purpose or purposes, unless otherwise prescribed by the OGCA and may be called only by (i) the chairman of the board, the chief executive officer or the president, (ii) the board of directors acting pursuant to a resolution adopted by a majority of the directors then in office or (iii) the secretary at the written request or requests of holders of record of at least 35% of the voting power of Chesapeake’s outstanding common stock. Business transacted at any special meeting of shareholders will be limited to the purposes stated in Chesapeake’s notice of meeting. | | | Vine’s charter authorizes, subject to the rights of the holders of preferred stock, the calling of a special meeting for any purpose or purposes only by or at the direction of the board or the chairman of the board; provided, however, that at any time when Blackstone beneficially owns, in the aggregate, at least 30% in voting power of Vine stock entitled to vote generally in the election of directors, special meetings of the Vine stockholders for any purpose or purposes shall also be called by or at the direction of the board or the chairman of the board at the request of Blackstone. | |
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Nominations and Proposals by Stockholders
|
| |||
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Chesapeake’s bylaws provide that business may be brought before an annual meeting (i) by or at the direction of the board of directors or (ii) by any shareholder of Chesapeake who was a shareholder of record at the time of giving notice provided for in Chesapeake’s bylaws and at the time of the annual meeting, who is entitled to vote at such meeting and who complies with the procedures set forth in Chesapeake’s bylaws. The Chesapeake bylaws do not otherwise provide for submission of shareholder proposals for consideration at special meetings.
To be timely, a shareholder must give written notice to the corporate secretary not later than the close of
|
| | Vine’s bylaws provide that nominations of persons for election to the board and the proposal of other business to be considered by the stockholders may be made at an annual meeting of stockholders only (i) as provided in the Stockholders’ Agreement (with respect to nominations of persons for election to the board only), (ii) pursuant to Vine’s notice of meeting (or any supplement thereto) delivered, (iii) by or at the direction of the board or any authorized committee thereof or (iv) by any Vine stockholder who (a) is entitled to vote at the meeting, (b) subject to Vine’s bylaws, complied with the notice procedures set forth in Vine’s bylaws and (c) was a stockholder of record at the time such | |
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Chesapeake
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Vine
|
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| business on the 90th day nor earlier than the close of business on the 120th day before the anniversary date of the immediately preceding annual meeting of shareholders. If the annual meeting is called for a date that is more than 30 days earlier or more than 60 days after such anniversary date, or in the case of a special meeting of shareholders called for the purpose of electing directors, notice by the shareholder must be so received (1) no earlier than the closing of business on the 120th day before the meeting and (2) not later than the close of business on the 90th day before the meeting, or the tenth day following the day on which public announcement of the date of such meeting is first made by Chesapeake. | | |
notice is delivered to Vine’s secretary, on the record date for the determination of Vine stockholders and at the time of the meeting.
Other than proposals included in the notice of meeting pursuant to Rule 14a-8 promulgated under the Exchange Act, to be timely, a stockholder must give written notice to the corporate secretary not later than the close of business on the 90th day nor earlier than the close of business on the 120th day before the anniversary date of the immediately preceding annual meeting of stockholders. If the annual meeting is called for a date that is more than 30 days earlier or more than 70 days after such anniversary date, notice by the stockholder to be timely must be delivered (i) no earlier than the close of business on the 120th day before the meeting and (ii) not later than the close of business on the later of the 90th day before the meeting or the 10th day following the day of the first public announcement of such meeting.
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Indemnification of Officers, Directors and Employees
|
| |||
| Under Section 1031 of the OGCA, a corporation may indemnify its directors and officers made a party to a proceeding because the person was a director or officer, against expenses, including attorneys’ fees, judgements and fines, and amounts paid in settlement actually and reasonably incurred, whether in civil, criminal, administrative, or investigative proceedings, by him or her if the person acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his or her conduct was unlawful. A corporation may not indemnify a director or officer under this section in respect of any claim or matter as to which the person shall have been adjudged to be liable to the corporation unless and only to the extent that the court in which the action was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, the person is fairly and reasonably entitled to indemnity for expenses which the court shall deem proper. Chesapeake’s bylaws provide that Chesapeake will indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding whether civil, criminal, administrative or investigative, including an action by or in the right of Chesapeake, because he or she is or was a director, officer, employee or agent of Chesapeake | | | Vine’s bylaws provide that Vine will indemnify and hold harmless, to the fullest extent permitted by applicable law, any person who was or is made or is threatened to be made a party or is otherwise involved in any action, suit or proceeding, whether civil, criminal, administrative or investigative (a “proceeding”), by reason of the fact that he or she is or was serving at the request of Vine as a director, officer, employee, agent or trustee of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to an employee benefit plan (hereinafter an “indemnitee”), whether the basis of such proceeding is alleged action in an official capacity as a director, officer, employee, agent or trustee or in any other capacity while serving as a director, officer, employee, agent or trustee, shall be indemnified and held harmless by Vine to the fullest extent permitted by Delaware law against all expense, liability and loss (including attorneys’ fees, judgments, fines, ERISA excise taxes or penalties and amounts paid in settlement) reasonably incurred or suffered by such indemnitee in connection therewith; provided, however, that, except as otherwise provided in Vine’s bylaws with respect to proceedings to enforce rights to indemnification or advancement of expenses or with respect to any compulsory counterclaim brought by such indemnitee, Vine will indemnify any such indemnitee in connection with a proceeding (or part thereof) initiated by such indemnitee only if such proceeding (or part thereof) | |
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Chesapeake
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| |
Vine
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or is or was serving at the request of Chesapeake as a director, officer, employee or agent of another corporation, partnership, joint venture or other enterprise against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him or her in connection with such action, suit or proceeding, if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interest of Chesapeake and, with respect to any criminal action or proceeding, had no reasonable cause to believe that his or her conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent will not of itself create a presumption that the person did not act in good faith and in a manner which he or she reasonably believed to be in or not opposed to the best interest of Chesapeake and, with respect to any criminal action or proceeding, had reasonable cause to believe that his or her conduct was unlawful. In an action by or in the right of Chesapeake, Chesapeake will not indemnify a person who has been adjudged liable to it unless and only to the extent that the court rendering judgment has determined that despite the adjudication of liability, but in the view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses that the court deems proper.
Chesapeake’s bylaws provide that Chesapeake may pay the expenses incurred in defending a civil or criminal action, suit or proceeding in advance of the final disposition of such action, suit or proceeding upon receipt of an undertaking by or on behalf of the director, officer, employee or agent to repay such amount if it is ultimately determined that he or she is not entitled to be indemnified by Chesapeake as authorized by Chesapeake’s bylaws.
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was authorized by the board.
Vine’s bylaws provide that an indemnitee will also have the right to be paid by Vine for the expenses (including any attorney’s fees) incurred in appearing at, participating in or defending any such proceeding in advance of its final disposition or in connection with a proceeding brought to establish or enforce a right to indemnification or advancement of expenses under certain sections of Vine’s bylaws; provided, however, that, if the DGCL requires or in the case of an advance made in a proceeding brought to establish or enforce a right to indemnification or advancement, an advancement of expenses incurred by an indemnitee in his or her capacity as a director or officer of Vine (and not in any other capacity in which service was or is rendered by such indemnitee, including, without limitation, service to an employee benefit plan) will be made solely upon delivery to Vine of an undertaking by or on behalf of such indemnitee, to repay all amounts so advanced if it shall ultimately be determined by final judicial decision from which there is no further right to appeal that such indemnitee is not entitled to be indemnified or entitled to advancement of expenses.
Under the DGCL, except with respect to an action by or in the right of a corporation, a corporation may indemnify its directors, officers, employees or agents (or a person who is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise) against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by the person if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his or her conduct was unlawful. In the case of actions by or in the right of the corporation, the corporation may indemnify its directors, officers, employees or agents (or a person who is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise) against expenses (including attorneys’ fees) actually and reasonably incurred by him or her if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation, except that no indemnification may be made in
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Chesapeake
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Vine
|
|
| | | | respect of any claim, issue or matter as to which such person has been adjudged to be liable to the corporation, unless and only to the extent a court finds that, in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnification for such expenses as the court deems proper. | |
|
Special Vote Requirements for Certain Transactions
|
| |||
| Section 1090.3 of the OGCA provides generally that a corporation is prohibited from engaging in any business combination with an interested shareholder for three years from the date on which the shareholder first becomes an interested shareholder. Chesapeake’s charter provides that Chesapeake has elected to not be governed by Section 1090.3 of the OGCA. | | |
Vine’s charter contains a provision electing for Vine not to be subject to Section 203 of the DGCL.
Section 203 of the DGCL prohibits a corporation listed on a National Securities Exchange in specified circumstances from engaging in any business combination with an interested stockholder or any entity for a period of three years from the date on which the stockholder first becomes an interested stockholder. There is an exception to the three-year waiting period requirement if:
•
prior to the stockholder becoming an interested stockholder, the board of directors approves the business combination or the transaction in which the stockholder became an interested stockholder;
•
upon the completion of the transaction in which the stockholder became an interested stockholder, the interested stockholder owns at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced other than shares held by directors who are also officers and certain employee stock plans; or
•
at or subsequent to such time as the business combination is approved by the board of directors and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 66 2/3% of the outstanding shares of stock entitled to vote not owned by the interested stockholder at a meeting of stockholders.
The DGCL defines the term “business combination” broadly to include, among other things, transactions such as mergers, consolidations or transfers of at least 10% of the aggregate market value of all the assets of the corporation determined on a consolidated basis or the aggregate market value of all the outstanding stock of the corporation.
The DGCL broadly defines the term “interested stockholder” generally as any person who (together with affiliates and associates) owns (or in certain cases, within the past three years did own) at least 15% of the outstanding shares of stock entitled to
|
|
|
Chesapeake
|
| |
Vine
|
|
| | | | vote. | |
|
Statutory Approval of a Merger
|
| |||
|
Under Sections 1081 and 1082 of the OGCA, subject to certain exceptions, a merger must be approved by the board of directors and by the affirmative vote of the holders of at least a majority (unless the charter or bylaws require a greater vote) of the outstanding shares of stock entitled to vote. Chesapeake’s charter and bylaws do not include any exceptions or additions to what is required by Sections 1081 and 1082 of the OGCA.
Chesapeake is not a constituent corporation in the merger and a vote of its shareholders is not required.
|
| |
Under Section 251 of the DGCL, subject to certain exceptions, a merger must be approved by the Vine board of directors and by the affirmative vote of the holders of at least a majority (unless the charter requires a higher percentage) of the outstanding shares of stock entitled to vote thereon.
Vine’s charter and bylaws do not mention any exceptions or additions to what is required by Section 251 of the DGCL.
|
|
|
Stockholder Action Without a Meeting
|
| |||
| Chesapeake’s charter provides that, subject to the rights of certain holders of Chesapeake’s preferred stock, action required or permitted to be taken at any annual or special meeting of shareholders may be taken only upon the vote of shareholders at an annual or special meeting duly noticed and called in accordance with the OGCA, Chesapeake’s charter and Chesapeake’s bylaws and may not be taken by written consent of shareholders without a meeting. | | | Vine’s charter provides that at any time when Blackstone beneficially owns, in the aggregate, at least 30% in voting power of Vine stock entitled to vote generally in the election of directors, any action required or permitted to be taken at any annual or special meeting of Vine stockholders may be taken without a meeting, without prior notice and without a vote, if a consent or consents in writing, setting forth the action so taken, shall be signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted and shall be delivered to Vine by delivery to its registered office in the State of Delaware, its principal place of business, or an officer or agent of Vine having custody of the books in which proceedings of meetings of stockholders are recorded. At any time when Blackstone beneficially owns, in the aggregate, less than 30% in voting power of Vine stock entitled to vote generally in the election of directors, any action required or permitted to be taken by Vine’s stockholders must be effected at a duly called annual or special meeting of such holders and may not be effected by any consent in writing by such holders; provided, however, that any action required or permitted to be taken by the holders of preferred stock, voting separately as a series or separately as a class with one or more other such series, may be taken without a meeting, without prior notice and without a vote, to the extent expressly so provided by the applicable certificate of designation relating to such series of preferred stock. | |
|
Appraisal Rights
|
| |||
| Appraisal rights of Chesapeake shareholders are | | | Under Section 262 of the DGCL, a stockholder of | |
|
Chesapeake
|
| |
Vine
|
|
|
governed by Section 1091 of the OGCA. Generally, except for certain cash transactions, Section 1091 does not provide appraisal rights for stock transactions involving shares which are listed on a national securities exchange. Chesapeake common stock, which trades on the Nasdaq Global Select Market, would not currently be subject to appraisal rights unless otherwise provided by Section 1091 of the OGCA.
Chesapeake’s charter does not provide otherwise.
|
| |
a corporation who has neither voted in favor of nor consented in writing to certain statutory mergers or consolidations and has complied with the other requirements of Section 262 of the DGCL may exercise appraisal rights with respect to such stockholder’s shares. However, unless a corporation’s certificate of incorporation otherwise provides (which Vine’s does not), Delaware law does not provide for appraisal rights if:
•
the shares of the corporation are (1) listed on a national securities exchange; or (2) held of record by more than 2,000 shareholders; or
•
the corporation will be the surviving corporation of the merger and approval of the merger does not require the vote of the shareholders of the surviving corporation under Section 251(f) of the DGCL.
Notwithstanding the forgoing, stockholders of Delaware corporations are entitled to appraisal rights in the case of a merger or consolidation if an agreement of merger or consolidation requires the stockholders to accept in exchange for its shares anything other than:
•
shares of stock of the corporation surviving or resulting from the merger or consolidation, or depositary receipts in respect thereof;
•
shares of any other corporation, or depositary receipts thereof, that on the effective date of the merger or consolidation will be either: (1) listed on a national securities exchange; or (2) held of record by more than 2,000 shareholders;
•
cash in lieu of fractional shares or fractional depositary receipts previously described of the corporation; or
•
any combination thereof.
Under the DGCL, the corporation must pay to the dissenting stockholder the fair value of the shares, together with interest, if any, as determined by the Court of Chancery of the State of Delaware upon completion of the appraisal proceedings.
|
|
|
Forum Selection
|
| |||
| Chesapeake’s charter provides that, unless Chesapeake consents in writing to the selection of an alternative forum, the state courts within the State of Oklahoma (or, if no such state court has jurisdiction, the United States District Court for the Western District of Oklahoma) will be the sole and exclusive forum for (i) any derivative action or proceeding brought on Chesapeake’s behalf, (ii) any | | | Vine’s charter provides that unless Vine consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of Vine, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer or employee of | |
|
Chesapeake
|
| |
Vine
|
|
| action asserting a claim of breach of a fiduciary duty owed by any current or former directors, officers, other employees or shareholders to Chesapeake or to the shareholders, (iii) any action asserting a claim arising pursuant to any provision of the OGCA, Chesapeake’s charter or bylaws (as each may be amended from time to time), or (iv) any action asserting a claim related to or involving Chesapeake that is governed by the internal affairs doctrine. Unless Chesapeake consents in writing to the selection of an alternative forum, the federal district courts of the United States of America shall be the sole and exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act. | | |
Vine to Vine or Vine’s stockholders, (iii) any action asserting a claim against Vine or any director or officer of Vine arising pursuant to any provision of the DGCL or Vine’s charter or bylaws, or (iv) any action asserting a claim governed by the internal affairs doctrine.
Unless Vine consents in writing to the selection of an alternative forum, the federal district courts of the United States of America shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act or the Exchange Act.
|
|
| | |
Shares of Vine Class A
Common Stock Beneficially Owned |
| |
Shares of Vine Class B
Common Stock Beneficially Owned |
| |
Total
Common Stock Beneficially Owned |
| |||||||||||||||||||||
Name of Beneficial Owner(1)
|
| |
Number
|
| |
Percentage
|
| |
Number
|
| |
Percentage
|
| |
Percentage
|
| |||||||||||||||
5% Stockholders: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Vine Investment LLC(2)
|
| | | | 1,551,334 | | | | | | 3.8% | | | | | | 17,387,012 | | | | | | 50.8% | | | | | | 25.2% | | |
Vine Investment II LLC(3)
|
| | | | 10,312,823 | | | | | | 25.1% | | | | | | — | | | | | | — | | | | | | 13.7% | | |
Brix Investment LLC(4)
|
| | | | 1,479,897 | | | | | | 3.6% | | | | | | 16,588,860 | | | | | | 48.5% | | | | | | 24.0% | | |
Brix Investment II LLC(5)
|
| | | | 7,129,295 | | | | | | 17.4% | | | | | | — | | | | | | — | | | | | | 9.5% | | |
Harvest Investment LLC(6)
|
| | | | 22,825 | | | | | | * | | | | | | 242,663 | | | | | | * | | | | | | * | | |
Harvest Investment II LLC(7)
|
| | | | 104,547 | | | | | | * | | | | | | — | | | | | | — | | | | | | * | | |
Named Executive Officers and Directors: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Eric D. Marsh
|
| | | | 507,142 | | | | | | 1.2% | | | | | | — | | | | | | — | | | | | | * | | |
Wayne B. Stoltenberg
|
| | | | 235,714 | | | | | | * | | | | | | — | | | | | | — | | | | | | * | | |
David M. Elkin
|
| | | | 271,428 | | | | | | * | | | | | | — | | | | | | — | | | | | | * | | |
Jonathan C. Curth
|
| | | | 67,858 | | | | | | * | | | | | | — | | | | | | — | | | | | | * | | |
Brian D. Dutton
|
| | | | 25,000 | | | | | | * | | | | | | — | | | | | | — | | | | | | * | | |
John H. Lee(8)
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Charles M. Sledge
|
| | | | 28,571 | | | | | | * | | | | | | — | | | | | | — | | | | | | * | | |
H. Paulett Eberhart
|
| | | | 10,714 | | | | | | * | | | | | | — | | | | | | — | | | | | | * | | |
David I. Foley(9)
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Angelo G. Acconcia(10)
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Executive Officers and Directors as a Group (11 persons)
|
| | | | 1,146,427 | | | | | | 2.8% | | | | | | — | | | | | | — | | | | | | 1.5% | | |
|
Chesapeake Energy Corporation
6100 North Western Avenue Oklahoma City, Oklahoma 73118 Attention: Corporate Secretary Telephone: (405) 848-8000 |
| |
Vine Energy Inc.
5800 Granite Parkway, Suite 550 Plano, Texas 75024 Attention: Corporate Secretary Telephone: (469) 606-0540 |
|
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Annexes | | | | | | | |
Annex A
Certain Definitions
|
| | | | | | |
Exhibits | | | | | | | |
Exhibit A
Form of Amendment to Tax Receivable Agreement
|
| | | | | | |
Exhibit B
Registration Rights Agreement
|
| | | | | | |
Definition
|
| |
Section
|
|
Acceptable Confidentiality Agreement | | | 6.3 | |
Agreement | | | Preamble | |
Antitrust Authority | | | 6.7(b) | |
Antitrust Laws | | | 6.7(b) | |
Applicable Date | | | Article IV | |
Appraisal Shares | | | 3.4(i) | |
Book-Entry Shares | | | 3.4(b)(ii) | |
Cash Consideration | | | 3.1(b)(i) | |
Certificate of First Merger | | | 2.2(b) | |
Certificate of Second Merger | | | 2.2(c) | |
Certificates | | | 3.4(b)(i) | |
Closing | | | 2.2(a) | |
Closing Date | | | 2.2(a) | |
Code | | | Recitals | |
Company | | | Preamble | |
Company Affiliate | | | 9.10 | |
Company Alternative Acquisition Agreement | | | 6.3(d)(vi) | |
Company Board | | | Recitals | |
Company Board Recommendation | | | 4.3(a) | |
Company Capital Stock | | | 4.2(a) | |
Company Change of Recommendation | | | 6.3(d)(viii) | |
Company Class A Common Stock | | | Recitals | |
Company Class B Common Stock | | | 3.2 | |
Definition
|
| |
Section
|
|
Company Common Stock | | | Recitals | |
Company Contracts | | | 4.20(b) | |
Company Designated Stockholders | | | Recitals | |
Company Disclosure Letter | | | Article IV | |
Company Employee | | | 6.8(a) | |
Company Independent Petroleum Engineers | | | 4.18(a) | |
Company Intellectual Property | | | 4.14(a) | |
Company Material Adverse Effect | | | 4.1 | |
Company Material Leased Real Property | | | 4.16 | |
Company Material Real Property | | | 4.16 | |
Company Material Real Property Lease | | | 4.16 | |
Company Owned Real Property | | | 4.16 | |
Company Permits | | | 4.9(a) | |
Company Preferred Stock | | | 4.2(a) | |
Company Related Party Transaction | | | 4.25 | |
Company Reserve Reports | | | 4.18(a) | |
Company Restricted Stock Unit Award | | | 3.3(a) | |
Company SEC Documents | | | 4.5(a) | |
Company Stock Plan | | | 3.3(a) | |
Company Stockholders Meeting | | | 4.4 | |
Confidentiality Agreement | | | 6.6(b) | |
Creditors’ Rights | | | 4.3(a) | |
D&O Insurance | | | 6.9(d) | |
DGCL | | | 2.1 | |
Divestiture Action | | | 6.7(b) | |
Effective Time | | | 2.2(b) | |
Eligible Shares | | | 3.1(b)(i) | |
| | 9.3 | | |
ERISA Affiliate | | | 4.10(h) | |
Exchange Agent | | | 3.4(a) | |
Exchange Fund | | | 3.4(a) | |
Exchange Ratio | | | 3.1(b)(i) | |
Excluded Shares | | | 3.1(b)(iii) | |
First Merger | | | Recitals | |
GAAP | | | 4.5(b) | |
Holdings | | | Recitals | |
Holdings Class B Units | | | 3.2 | |
Holdings Interests | | | 4.2(b) | |
Holdings Managing Member Approval | | | 4.3(a) | |
HSR Act | | | 4.4 | |
Indemnified Liabilities | | | 6.9(a) | |
Indemnified Persons | | | 6.9(a) | |
Integrated Mergers | | | Recitals | |
Definition
|
| |
Section
|
|
Letter of Transmittal | | | 3.4(b)(i) | |
Material Company Insurance Policies | | | 4.22 | |
Merger | | | Recitals | |
Merger Consideration | | | 3.1(b)(i) | |
Merger Sub Board | | | Recitals | |
Merger Sub Inc. | | | Preamble | |
Merger Sub LLC | | | Preamble | |
Merger Subs | | | Preamble | |
Merger Support Agreement | | | Recitals | |
Outside Date | | | 8.1(b)(ii) | |
Parent | | | Preamble | |
Parent Affiliate | | | 9.10 | |
Parent Board | | | Recitals | |
Parent Capital Stock | | | 5.2(a) | |
Parent Closing Price | | | 3.4(h) | |
Parent Common Stock | | | Recitals | |
Parent Disclosure Letter | | | Article V | |
Parent FA | | | 5.18 | |
Parent Independent Petroleum Engineer | | | 5.17(a) | |
Parent Material Adverse Effect | | | 5.1 | |
Parent Permits | | | 5.9(a) | |
Parent Preferred Stock | | | 5.2(a) | |
Parent Reserve Report | | | 5.17(a) | |
Parent Restricted Stock Unit Award | | | 3.3(a) | |
Parent SEC Documents | | | 5.5(a) | |
Parent Stock Issuance | | | Recitals | |
Parent Stock Plans | | | 5.5(a) | |
Proxy Statement | | | 4.4 | |
Registration Statement | | | 4.8 | |
Rights-of-Way | | | 4.17 | |
Second Merger | | | Recitals | |
Second Merger Effective Time | | | 2.2(c) | |
Share Consideration | | | 3.1(b)(i) | |
Surviving Company | | | 2.1(b) | |
Surviving Corporation | | | 2.1(a) | |
Tail Period | | | 6.9(d) | |
Terminable Breach | | | 8.1(b)(iii) | |
TRA | | | Recitals | |
TRA Amendment | | | Recitals | |
Transaction Litigation | | | 6.10 | |
Name
|
| |
Shares of Company Class A Common Stock
|
|
Vine Investment LLC | | | 1,551,334 shares owned directly | |
Harvest Investment LLC | | | 22,825 shares owned directly | |
Brix Investment LLC | | | 1,479,897 shares owned directly | |
Vine Investment II LLC | | | 10,312,823 shares owned directly | |
Harvest Investment II LLC | | | 104,547 shares owned directly | |
Brix Investment II LLC | | | 7,129,295 shares owned directly | |
Name
|
| |
Shares of Company Class B Shares
|
|
Vine Investment LLC | | | 17,387,012 shares owned directly | |
Harvest Investment LLC | | | 242,663 shares owned directly | |
Brix Investment LLC | | | 16,588,860 shares owned directly | |
Name
|
| |
Holdings Units
|
|
Vine Investment LLC | | | 17,387,012 Holdings Units owned directly | |
Harvest Investment LLC | | | 242,663 Holdings Units owned directly | |
Brix Investment LLC | | | 16,588,860 Holdings Units owned directly | |
| | |
Per share
|
| |
Total
|
| ||||||
Price to the public
|
| | | $ | 14.00 | | | | | $ | 301,000,000 | | |
Underwriting discounts and commissions(1)
|
| | | $ | 0.70 | | | | | $ | 15,050,000 | | |
Proceeds to us (before expenses)
|
| | | $ | 13.30 | | | | | $ | 285,950,000 | | |
| Citigroup | | |
Credit Suisse
|
| |
Morgan Stanley
|
|
| Barclays | | |
BofA Securities
|
| |
RBC Capital Markets
|
|
| Capital One Securities | | |
KeyBanc Capital Markets
|
| |
MUFG
|
|
| CastleOak Securities, L.P. | | |
Drexel Hamilton
|
| |
Ramirez & Co., Inc.
|
| |
Stern
|
|
| | |
Page
|
| |||
| | | | E-1 | | | |
| | | | E-27 | | | |
| | | | E-50 | | | |
| | | | E-52 | | | |
| | | | E-53 | | | |
| | | | E-54 | | | |
| | | | E-56 | | | |
| | | | E-57 | | | |
| | | | E-60 | | | |
| | | | E-82 | | | |
| | | | E-117 | | | |
| | | | E-122 | | | |
| | | | E-130 | | | |
| | | | E-134 | | | |
| | | | E-139 | | | |
| | | | E-146 | | | |
| | | | E-154 | | | |
| | | | E-156 | | | |
| | | | E-160 | | | |
| | | | E-167 | | | |
| | | | E-167 | | | |
| | | | E-167 | | | |
| | | | E-168 | | |
Length
|
| |
Short
Lateral |
| |
Long
Lateral |
| |
Total
|
| |||||||||
|
<5,300 ft
|
| |
>5,300 ft
|
| ||||||||||||||
Haynesville
|
| | | | 226 | | | | | | 147 | | | | | | 373 | | |
Mid-Bossier
|
| | | | 212 | | | | | | 293 | | | | | | 505 | | |
Total Core
|
| | | | 438 | | | | | | 440 | | | | | | 878 | | |
Total Non-Core
|
| | | | 44 | | | | | | 10 | | | | | | 54 | | |
Total Drilling Locations
|
| | | | 482 | | | | | | 450 | | | | | | 932 | | |
| | |
Vine Oil & Gas
|
| |
Vine Pro Forma
|
| ||||||||||||
|
As of and for the
Year Ended December 31, |
| |
As of and for the
Year Ended December 31, 2020 |
| ||||||||||||||
|
2020
|
| |
2019
|
| | | | | | | ||||||||
|
(in thousands, except share and per share data)
|
| |||||||||||||||||
Statements of Operations Information: | | | | | | | | | | | | | | | | | | | |
Revenue: | | | | | | | | | | | | | | | | | | | |
Natural gas sales
|
| | | $ | 418,877 | | | | | $ | 445,589 | | | | | $ | 571,144 | | |
Realized gain on commodity derivatives
|
| | | | 123,875 | | | | | | 39,679 | | | | | | 161,918 | | |
Unrealized gain (loss) on commodity derivatives
|
| | | | (164,077) | | | | | | 101,239 | | | | | | (204,552) | | |
Total revenue
|
| | | | 378,675 | | | | | | 586,507 | | | | | | 528,510 | | |
Operating Expenses: | | | | | | | | | | | | | | | | | | | |
Lease operating
|
| | | | 47,911 | | | | | | 46,247 | | | | | | 65,639 | | |
| | |
Vine Oil & Gas
|
| |
Vine Pro Forma
|
| ||||||||||||
|
As of and for the
Year Ended December 31, |
| |
As of and for the
Year Ended December 31, 2020 |
| ||||||||||||||
|
2020
|
| |
2019
|
| | | | | | | ||||||||
|
(in thousands, except share and per share data)
|
| |||||||||||||||||
Gathering and treating
|
| | | | 76,770 | | | | | | 37,955 | | | | | | 101,974 | | |
Production and ad valorem taxes
|
| | | | 15,620 | | | | | | 18,539 | | | | | | 18,335 | | |
General and administrative
|
| | | | 7,448 | | | | | | 7,842 | | | | | | 15,116 | | |
Monitoring fee
|
| | | | 7,541 | | | | | | 7,011 | | | | | | — | | |
Depletion, depreciation and accretion
|
| | | | 347,652 | | | | | | 327,659 | | | | | | 392,038 | | |
Exploration
|
| | | | 167 | | | | | | 886 | | | | | | 193 | | |
Strategic
|
| | | | 2,182 | | | | | | 853 | | | | | | 2,182 | | |
Severance
|
| | | | 326 | | | | | | — | | | | | | 447 | | |
Write-off of deferred IPO expenses
|
| | | | 5,787 | | | | | | 2,825 | | | | | | 5,787 | | |
Total operating expenses
|
| | | | 511,404 | | | | | | 449,817 | | | | | | 601,711 | | |
Operating Income
|
| | | | (132,729) | | | | | | 136,690 | | | | | | (73,201) | | |
Interest expense
|
| | | | (119,248) | | | | | | (112,198) | | | | | | (116,589) | | |
Income Before Income Taxes
|
| | | | (251,977) | | | | | | 24,492 | | | | | | (189,790) | | |
Income tax provision
|
| | | | (217) | | | | | | (496) | | | | | | (217) | | |
Net Income
|
| | | $ | (252,194) | | | | | $ | 23,996 | | | | | $ | (190,007) | | |
Net income attributable to non-controlling interests
|
| | | | | | | | | | | | | | | | (90,253) | | |
Net Income Attributable to Vine Energy Inc.
|
| | | | | | | | | | | | | | | $ | (99,754) | | |
Net Income per Share: | | | | | | | | | | | | | | | | | | | |
Basic
|
| | | | | | | | | | | | | | | $ | (2.64) | | |
Diluted
|
| | | | | | | | | | | | | | | $ | (2.64) | | |
Weighted Average Shares Outstanding: | | | | | | | | | | | | | | | | | | | |
Basic
|
| | | | | | | | | | | | | | | | 37,806,386 | | |
Diluted
|
| | | | | | | | | | | | | | | | 37,806,386 | | |
Balance Sheet Information: | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents
|
| | | $ | 15,517 | | | | | $ | 18,286 | | | | | $ | 33,177 | | |
Total natural gas properties, net
|
| | | | 1,342,354 | | | | | | 1,435,976 | | | | | | 1,791,480 | | |
Total assets
|
| | | | 1,467,763 | | | | | | 1,658,100 | | | | | | 1,952,648 | | |
Total debt
|
| | | | 1,224,741 | | | | | | 1,218,558 | | | | | | 1,072,722 | | |
Total equity(1)
|
| | | | 10,061 | | | | | | 292,255 | | | | | | 612,134 | | |
Statements of Cash Flows Information: | | | | | | | | | | | | | | | | | | | |
Net cash provided by operating activities
|
| | | $ | 295,174 | | | | | $ | 270,699 | | | | | | | | |
Net cash used in investing activities
|
| | | | (252,378) | | | | | | (281,193) | | | | | | | | |
Net cash provided by (used in) financing activities
|
| | | | (45,565) | | | | | | 7,750 | | | | | | | | |
Other Financial Information: | | | | | | | | | | | | | | | | | | | |
Adjusted EBITDAX(2)
|
| | | $ | 384,713 | | | | | $ | 338,571 | | | | | $ | 529,249 | | |
Levered free cash flow(2)
|
| | | $ | 42,796 | | | | | $ | (10,494) | | | | | | | | |
| | |
Vine Oil & Gas
|
| |
Vine Pro Forma
|
| ||||||||||||
|
For the Year Ended
December 31, |
| |
For the
Year Ended December 31, 2020 |
| ||||||||||||||
|
2020
|
| |
2019
|
| | | | | | | ||||||||
|
(in thousands)
|
| |||||||||||||||||
Net income
|
| | | $ | (252,194) | | | | | $ | 23,996 | | | | | $ | (190,007) | | |
Interest expense
|
| | | | 119,248 | | | | | | 112,198 | | | | | | 116,589 | | |
Income tax provision
|
| | | | 217 | | | | | | 496 | | | | | | 217 | | |
Depletion, depreciation and accretion
|
| | | | 347,652 | | | | | | 327,659 | | | | | | 392,038 | | |
Unrealized gain (loss) on commodity derivatives
|
| | | | 164,077 | | | | | | (101,239) | | | | | | 204,552 | | |
Exploration
|
| | | | 167 | | | | | | 886 | | | | | | 193 | | |
Non-cash G&A
|
| | | | (182) | | | | | | (18) | | | | | | (182) | | |
Strategic
|
| | | | 2,182 | | | | | | 853 | | | | | | 2,182 | | |
Non-cash write-off of deferred IPO expenses
|
| | | | 5,787 | | | | | | 2,825 | | | | | | 5,787 | | |
Severance
|
| | | | 326 | | | | | | — | | | | | | 447 | | |
Non-cash volumetric and production adjustment to gas gathering liability
|
| | | | (2,567) | | | | | | (29,085) | | | | | | (2,567) | | |
Adjusted EBITDAX
|
| | | $ | 384,713 | | | | | $ | 338,571 | | | | | $ | 529,249 | | |
Operating cash flow
|
| | | $ | 295,174 | | | | | $ | 270,699 | | | | | | | | |
Investing cash flow
|
| | | | (252,378) | | | | | | (281,193) | | | | | | | | |
Levered free cash flow
|
| | | $ | 42,796 | | | | | $ | (10,494) | | | | | | | | |
| | |
Vine Oil & Gas
|
| |
Vine Pro Forma
|
| ||||||
|
At December 31,
2020(1)(2) |
| |
At December 31,
2020(1)(2) |
| ||||||||
Natural gas (MMcf)
|
| | | | 1,802,118 | | | | | | 2,313,499 | | |
Total proved developed reserves (MMcf)
|
| | | | 446,243 | | | | | | 590,160 | | |
Percent proved developed
|
| | | | 25% | | | | | | 26% | | |
Total proved undeveloped reserves (MMcf)
|
| | | | 1,355,875 | | | | | | 1,723,339 | | |
| | |
Vine Oil & Gas
|
| |
Vine Pro Forma
|
| ||||||
|
Strip Pricing(1)
|
| |
Strip Pricing(1)
|
| ||||||||
Estimated proved reserves at NYMEX Strip Pricing | | | | | | | | | | | | | |
Natural gas (MMcf)
|
| | | | 2,364,510 | | | | | | 3,151,073 | | |
Total proved developed reserves (MMcf)
|
| | | | 491,769 | | | | | | 643,352 | | |
Percent proved developed
|
| | | | 21% | | | | | | 20% | | |
Total proved undeveloped reserves (MMcf)
|
| | | | 1,872,741 | | | | | | 2,507,721 | | |
| | |
Vine Oil & Gas
|
| |
Vine Pro Forma
|
| ||||||||||||
|
Year Ended
December 31, |
| |
Year Ended
December 31, |
| ||||||||||||||
|
2020
|
| |
2019
|
| |
2020
|
| |||||||||||
Production data: | | | | | | | | | | | | | | | | | | | |
Natural gas (MMcf)
|
| | | | 240,869 | | | | | | 200,214 | | | | | | 326,510 | | |
Average daily production (MMcfd)
|
| | | | 658 | | | | | | 549 | | | | | | 892 | | |
Average sales prices per Mcf: | | | | | | | | | | | | | | | | | | | |
Before effects of realized derivatives
|
| | | $ | 1.74 | | | | | $ | 2.23 | | | | | $ | 1.75 | | |
After effects of realized derivatives
|
| | | $ | 2.25 | | | | | $ | 2.42 | | | | | $ | 2.25 | | |
| | |
Vine Oil & Gas
|
| |
Vine Pro Forma
|
| ||||||||||||
|
Year Ended
December 31, |
| |
Year Ended
December 31, |
| ||||||||||||||
|
2020
|
| |
2019
|
| |
2020
|
| |||||||||||
Costs per Mcf: | | | | | | | | | | | | | | | | | | | |
Lease operating
|
| | | $ | 0.20 | | | | | $ | 0.23 | | | | | $ | 0.20 | | |
Gathering and treating
|
| | | | 0.32 | | | | | | 0.19 | | | | | | 0.31 | | |
Production and ad valorem taxes
|
| | | | 0.06 | | | | | | 0.09 | | | | | | 0.06 | | |
Depreciation, depletion and accretion
|
| | | | 1.44 | | | | | | 1.64 | | | | | | 1.20 | | |
General and administrative
|
| | | | 0.03 | | | | | | 0.04 | | | | | | 0.05 | | |
Monitoring fee
|
| | | | 0.03 | | | | | | 0.04 | | | | | | — | | |
Exploration
|
| | | | — | | | | | | — | | | | | | — | | |
Strategic
|
| | | | 0.01 | | | | | | — | | | | | | 0.01 | | |
Write-off of deferred IPO costs
|
| | | | 0.02 | | | | | | 0.01 | | | | | | 0.02 | | |
Total
|
| | | $ | 2.11 | | | | | $ | 2.24 | | | | | $ | 1.85 | | |
|
| | |
As of December 31, 2020
|
| |||||||||||||||
|
Actual
|
| |
As Adjusted
|
| |
As Further Adjusted
|
| |||||||||||
|
(in thousands, except shares and par value)
|
| |||||||||||||||||
Cash and cash equivalents
|
| | | $ | 15,517 | | | | | $ | 33,177 | | | | | $ | 33,177 | | |
Long-term debt:(1) | | | | | | | | | | | | | | | | | | | |
Vine Oil & Gas New RBL(2)
|
| | | $ | — | | | | | $ | — | | | | | $ | 31,550 | | |
Vine Oil & Gas RBL Credit Facility(3)
|
| | | | 190,000 | | | | | | 190,000 | | | | | | — | | |
Vine Oil & Gas Second Lien Term Loan
|
| | | | 150,000 | | | | | | 150,000 | | | | | | 150,000 | | |
Vine Oil & Gas Third Lien Credit Facility
|
| | | | — | | | | | | — | | | | | | — | | |
Vine Oil & Gas 8.75% Notes
|
| | | | 530,000 | | | | | | 530,000 | | | | | | 530,000 | | |
Vine Oil & Gas 9.75% Notes
|
| | | | 380,000 | | | | | | 380,000 | | | | | | 380,000 | | |
Brix Credit Facility(4)
|
| | | | — | | | | | | 125,000 | | | | | | — | | |
Total Indebtedness
|
| | | $ | 1,250,000 | | | | | $ | 1,375,000 | | | | | $ | 1,091,550 | | |
Partners’ capital/stockholders’ equity: | | | | | | | | | | | | | | | | | | | |
Partners’ capital
|
| | | $ | 10,061 | | | | | $ | — | | | | | $ | — | | |
Class A Common stock — $0.01 par value; no shares authorized, issued or outstanding, actual; 350,000,000 shares authorized, 16,306,386 shares issued and outstanding, as adjusted; 37,806,386 shares issued and outstanding, as further adjusted
|
| | | | — | | | | | | 163 | | | | | | 378 | | |
Class B Common stock — $0.01 par value; no shares authorized, issued or outstanding, actual; 150,000,000 shares authorized, 34,227,870 shares issued and outstanding, as adjusted; 34,227,870 shares issued and outstanding, as further adjusted
|
| | | | — | | | | | | 342 | | | | | | 342 | | |
Additional paid in capital
|
| | | | — | | | | | | 178,268 | | | | | | 326,857 | | |
Retained earnings
|
| | | | — | | | | | | (300) | | | | | | (5,444) | | |
Total partners’ capital/stockholders’ equity
|
| | | $ | 10,061 | | | | | $ | 178,473 | | | | | $ | 322,133 | | |
Non-controlling interest
|
| | | | — | | | | | | 161,291 | | | | | | 290,001 | | |
Total equity
|
| | | $ | 10,061 | | | | | $ | 339,764 | | | | | $ | 612,134 | | |
Total capitalization
|
| | | $ | 1,260,061 | | | | | $ | 1,714,764 | | | | | $ | 1,703,684 | | |
|
IPO price per share
|
| | | | | | | | | $ | 14.00 | | |
|
Pro forma net tangible book value per share as of December 31, 2020 (after giving effect to our corporate reorganization)
|
| | | $ | 6.72 | | | | | | | | |
|
Increase in pro forma net tangible book value per share of Class A common stock attributable to investors in this offering
|
| | | $ | 1.77 | | | | | | | | |
|
As adjusted pro forma net tangible book value per share of Class A common stock after our corporate reorganization and this offering
|
| | | | | | | | | $ | 8.50 | | |
|
Dilution in pro forma net tangible book value per share of Class A common stock to investors in this offering
|
| | | | | | | | | $ | 5.50 | | |
| | |
Shares Acquired
|
| |
Total Consideration
|
| |
Average
Price Per Share |
| | |||||||||||||||||||||||
|
Number
|
| |
Percent
|
| |
Amount
|
| |
Percent
|
| | ||||||||||||||||||||||
|
(in thousands)
|
| ||||||||||||||||||||||||||||||||
Vine Energy Investment Vehicles
|
| | | | 37,265,809 | | | | | | 51.8% | | | | | $ | 400,498 | | | | | | 48.3% | | | | | $ | 10.75 | | | | ||
Vine Energy Investment II Vehicles
|
| | | | 17,554,161 | | | | | | 24.3% | | | | | $ | 188,656 | | | | | | 22.7% | | | | | $ | 10.75 | | | | ||
New investors in this offering(1)
|
| | | | 17,214,286 | | | | | | 23.9% | | | | | $ | 241,000 | | | | | | 29.0% | | | | | $ | 14.00 | | | | ||
Total
|
| | | | 72,034,256 | | | | | | 100.0% | | | | | $ | 830,154 | | | | | | 100.0% | | | | | $ | 11.52 | | | |
| | |
Vine Oil & Gas
|
| |
Vine Pro Forma
|
| ||||||||||||
|
As of and for the
Year Ended December 31, |
| |
As of and for the
Year Ended December 31, 2020 |
| ||||||||||||||
|
2020
|
| |
2019
|
| | | | | | | ||||||||
|
(in thousands, except share and per share data)
|
| |||||||||||||||||
Statements of Operations Information: | | | | | | | | | | | | | | | | | | | |
Revenue: | | | | | | | | | | | | | | | | | | | |
Natural gas sales
|
| | | $ | 418,877 | | | | | $ | 445,589 | | | | | $ | 571,144 | | |
Realized gain on commodity derivatives
|
| | | | 123,875 | | | | | | 39,679 | | | | | | 161,918 | | |
Unrealized gain (loss) on commodity derivatives
|
| | | | (164,077) | | | | | | 101,239 | | | | | | (204,552) | | |
Total revenue
|
| | | | 378,675 | | | | | | 586,507 | | | | | | 528,510 | | |
Operating Expenses: | | | | | | | | | | | | | | | | | | | |
Lease operating
|
| | | | 47,911 | | | | | | 46,247 | | | | | | 65,639 | | |
Gathering and treating
|
| | | | 76,770 | | | | | | 37,955 | | | | | | 101,974 | | |
Production and ad valorem taxes
|
| | | | 15,620 | | | | | | 18,539 | | | | | | 18,335 | | |
General and administrative
|
| | | | 7,448 | | | | | | 7,842 | | | | | | 15,116 | | |
Monitoring fee
|
| | | | 7,541 | | | | | | 7,011 | | | | | | — | | |
Depletion, depreciation and accretion
|
| | | | 347,652 | | | | | | 327,659 | | | | | | 392,038 | | |
Exploration
|
| | | | 167 | | | | | | 886 | | | | | | 193 | | |
Strategic
|
| | | | 2,182 | | | | | | 853 | | | | | | 2,182 | | |
Severance
|
| | | | 326 | | | | | | — | | | | | | 447 | | |
Write-off of deferred IPO expenses
|
| | | | 5,787 | | | | | | 2,825 | | | | | | 5,787 | | |
Total operating expenses
|
| | | | 511,404 | | | | | | 449,817 | | | | | | 601,711 | | |
Operating Income
|
| | | | (132,729) | | | | | | 136,690 | | | | | | (73,201) | | |
Interest expense
|
| | | | (119,248) | | | | | | (112,198) | | | | | | (116,589 | | |
Income Before Income Taxes
|
| | | | (251,977) | | | | | | 24,492 | | | | | | (189,790) | | |
Income tax provision
|
| | | | (217) | | | | | | (496) | | | | | | (217) | | |
Net Income
|
| | | $ | (252,194) | | | | | $ | 23,996 | | | | | $ | (190,007) | | |
Net income attributable to non-controlling interests
|
| | | | | | | | | | | | | | | | (90,253) | | |
Net Income Attributable to Vine Energy Inc.
|
| | | | | | | | | | | | | | | $ | (99,754) | | |
Net Income per Share:
|
| | | | | | | | | | | | | | | | | | |
Basic
|
| | | | | | | | | | | | | | | $ | (2.64) | | |
Diluted
|
| | | | | | | | | | | | | | | $ | (2.64) | | |
Weighted Average Shares Outstanding: | | | | | | | | | | | | | | | | | | | |
Basic
|
| | | | | | | | | | | | | | | | 37,806,386 | | |
Diluted
|
| | | | | | | | | | | | | | | | 37,806,386 | | |
Balance Sheet Information: | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents
|
| | | $ | 15,517 | | | | | $ | 18,286 | | | | | $ | 33,177 | | |
Total natural gas properties, net
|
| | | | 1,342,354 | | | | | | 1,435,976 | | | | | | 1,791,480 | | |
Total assets
|
| | | | 1,467,763 | | | | | | 1,658,100 | | | | | | 1,952,648 | | |
Total debt
|
| | | | 1,224,741 | | | | | | 1,218,558 | | | | | | 1,072,722 | | |
Total equity(1)
|
| | | | 10,061 | | | | | | 292,255 | | | | | | 612,134 | | |
Statements of Cash Flows Information: | | | | | | | | | | | | | | | | | | | |
Net cash provided by operating activities
|
| | | $ | 295,174 | | | | | $ | 270,699 | | | | | | | | |
Net cash used in investing activities
|
| | | | (252,378) | | | | | | (281,193) | | | | | | | | |
Net cash provided by (used in) financing activities
|
| | | | (45,565) | | | | | | 7,750 | | | | | | | | |
Other Financial Information: | | | | | | | | | | | | | | | | | | | |
Adjusted EBITDAX(2)
|
| | | $ | 384,713 | | | | | $ | 338,571 | | | | | $ | 529,249 | | |
Levered free cash flow(2)
|
| | | $ | 42,796 | | | | | $ | (10,494) | | | | | | | | |
| | |
For the Year
Ended December 31, |
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
|
($ / MMBtu)
|
| |||||||||||
NYMEX Henry Hub High
|
| | | $ | 3.00 | | | | | $ | 3.64 | | |
NYMEX Henry Hub Low
|
| | | $ | 1.50 | | | | | $ | 2.14 | | |
Differential to Average NYMEX Henry Hub(1)
|
| | | $ | (0.19) | | | | | $ | (0.19) | | |
| | |
Vine Oil & Gas
|
| |
Vine Pro Forma
|
| ||||||||||||
|
For the Year Ended
December 31, |
| |
For the Year
Ended December 31, 2020 |
| ||||||||||||||
|
2020
|
| |
2019
|
| | | | | | | ||||||||
|
(in thousands)
|
| |||||||||||||||||
Net income
|
| | | $ | (252,194) | | | | | $ | 23,996 | | | | | $ | (190,007) | | |
Interest expense
|
| | | | 119,248 | | | | | | 112,198 | | | | | | (116,589) | | |
Income tax provision
|
| | | | 217 | | | | | | 496 | | | | | | 217 | | |
Depletion, depreciation and accretion
|
| | | | 347,652 | | | | | | 327,659 | | | | | | (392,038) | | |
Unrealized (gain) loss on commodity derivatives
|
| | | | 164,077 | | | | | | (101,239) | | | | | | 204,552 | | |
Exploration
|
| | | | 167 | | | | | | 886 | | | | | | 193 | | |
Non-cash G&A
|
| | | | (182) | | | | | | (18) | | | | | | (182) | | |
Strategic
|
| | | | 2,182 | | | | | | 853 | | | | | | (2,182) | | |
Non-cash write-off of deferred IPO costs
|
| | | | 5,787 | | | | | | 2,825 | | | | | | 5,787 | | |
Severance
|
| | | | 326 | | | | | | — | | | | | | 447 | | |
Non-cash volumetric and production adjustment to gas gathering liability
|
| | | | (2,567) | | | | | | (29,085) | | | | | | (2,567) | | |
Adjusted EBITDAX
|
| | | $ | 384,713 | | | | | $ | 338,571 | | | | | $ | 529,249 | | |
Operating cash flow
|
| | | $ | 295,174 | | | | | $ | 270,699 | | | | | | | | |
Investing cash flow
|
| | | | (252,378) | | | | | | (281,193) | | | | | | | | |
Levered free cash flow
|
| | | | 42,796 | | | | | | (10,494) | | | | | | | | |
| | |
For the Year Ended December 31,
|
| |||||||||||||||||||||
|
2020
|
| | | | | | | |
2019
|
| | | | | | | ||||||||
|
(in thousands, except per Mcf)
|
| |||||||||||||||||||||||
Production: | | | | | | | | | | | | | | | | | | | | | | | | | |
Total (MMcf)
|
| | | | 240,869 | | | | | | | | | | | | 200,214 | | | | | | | | |
Average Daily (MMcfd)
|
| | | | 658 | | | | | | | | | | | | 549 | | | | | | | | |
| | | | | | | | |
Per Mcf
|
| | | | | | | |
Per Mcf
|
| ||||||
Revenue: | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas sales
|
| | | $ | 418,877 | | | | | $ | 1.74 | | | | | $ | 445,589 | | | | | $ | 2.23 | | |
Realized gain on commodity derivatives
|
| | | | 123,875 | | | | | | 0.51 | | | | | | 39,679 | | | | | | 0.20 | | |
Unrealized (loss) gain on commodity derivatives
|
| | | | (164,077) | | | | | | (0.68) | | | | | | 101,239 | | | | | | 0.51 | | |
Total revenue
|
| | | | 378,675 | | | | | | 1.57 | | | | | | 586,507 | | | | | | 2.93 | | |
Operating Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | |
Lease operating
|
| | | | 47,911 | | | | | | 0.20 | | | | | | 46,247 | | | | | | 0.23 | | |
Gathering and treating
|
| | | | 76,770 | | | | | | 0.32 | | | | | | 37,955 | | | | | | 0.19 | | |
Production and ad valorem taxes
|
| | | | 15,620 | | | | | | 0.06 | | | | | | 18,539 | | | | | | 0.09 | | |
General and administrative
|
| | | | 7,448 | | | | | | 0.03 | | | | | | 7,842 | | | | | | 0.04 | | |
Monitoring fee
|
| | | | 7,541 | | | | | | 0.03 | | | | | | 7,011 | | | | | | 0.04 | | |
Depreciation, depletion and accretion
|
| | | | 347,652 | | | | | | 1.44 | | | | | | 327,659 | | | | | | 1.64 | | |
Exploration
|
| | | | 167 | | | | | | 0.00 | | | | | | 886 | | | | | | 0.00 | | |
Strategic
|
| | | | 2,182 | | | | | | 0.01 | | | | | | 853 | | | | | | 0.00 | | |
Severance
|
| | | | 326 | | | | | | 0.00 | | | | | | — | | | | | | — | | |
Write-off of deferred IPO costs
|
| | | | 5,787 | | | | | | 0.02 | | | | | | 2,825 | | | | | | 0.01 | | |
Total operating expenses
|
| | | | 511,404 | | | | | | 2.11 | | | | | | 449,817 | | | | | | 2.25 | | |
Operating income
|
| | | | (132,729) | | | | | | | | | | | | 136,690 | | | | | | | | |
Interest expense
|
| | | | (119,248) | | | | | | | | | | | | (112,198) | | | | | | | | |
Income tax provision
|
| | | | (217) | | | | | | | | | | | | (496) | | | | | | | | |
Total other expenses
|
| | | | (119,465) | | | | | | | | | | | | (112,694) | | | | | | | | |
Net income
|
| | | $ | (252,194) | | | | | | | | | | | $ | 23,996 | | | | | | | | |
Interest expense
|
| | | | 119,248 | | | | | | | | | | | | 112,198 | | | | | | | | |
Income tax provision
|
| | | | 217 | | | | | | | | | | | | 496 | | | | | | | | |
Depreciation, depletion and accretion
|
| | | | 347,652 | | | | | | | | | | | | 327,659 | | | | | | | | |
Unrealized loss (gain) on commodity derivatives
|
| | | | 164,077 | | | | | | | | | | | | (101,239) | | | | | | | | |
Exploration
|
| | | | 167 | | | | | | | | | | | | 886 | | | | | | | | |
Non-cash G&A
|
| | | | (182) | | | | | | | | | | | | (18) | | | | | | | | |
Strategic
|
| | | | 2,182 | | | | | | | | | | | | 853 | | | | | | | | |
Severance
|
| | | | 326 | | | | | | | | | | | | — | | | | | | | | |
Non-cash write-off of deferred IPO costs
|
| | | | 5,787 | | | | | | | | | | | | 2,825 | | | | | | | | |
Non-cash volumetric and production adjustment to gas gathering liability
|
| | | | (2,567) | | | | | | | | | | | | (29,085) | | | | | | | | |
Adjusted EBITDAX
|
| | | $ | 384,713 | | | | | | | | | | | $ | 338,571 | | | | | | | | |
|
2019
|
| | | $ | 485,268 | | |
|
Volume
|
| | | | 90,481 | | |
|
Price
|
| | | | (117,193) | | |
|
Realized derivative
|
| | | | 84,196 | | |
|
2020
|
| | | $ | 542,752 | | |
| | |
For the Year Ended December 31,
|
| |||||||||||||||||||||
|
2020
|
| |
2019
|
| ||||||||||||||||||||
|
(in thousands)
|
| |
Per Mcf
|
| |
(in thousands)
|
| |
Per Mcf
|
| ||||||||||||||
Gathering — Cash
|
| | | $ | 78,578 | | | | | $ | 0.33 | | | | | $ | 66,181 | | | | | $ | 0.33 | | |
Gathering — noncash
|
| | | | (2,567) | | | | | | (0.01) | | | | | | (29,085) | | | | | | (0.15) | | |
Other
|
| | | | 759 | | | | | | — | | | | | | 859 | | | | | | — | | |
Total
|
| | | $ | 76,770 | | | | | $ | 0.32 | | | | | $ | 37,955 | | | | | $ | 0.19 | | |
| | |
For the Year Ended December 31,
|
| |||||||||||||||||||||
|
2020
|
| |
2019
|
| ||||||||||||||||||||
|
(in thousands)
|
| |
Per Mcf
|
| |
(in thousands)
|
| |
Per Mcf
|
| ||||||||||||||
Production taxes
|
| | | $ | 9,957 | | | | | $ | 0.04 | | | | | $ | 13,292 | | | | | $ | 0.06 | | |
Ad valorem taxes
|
| | | | 5,663 | | | | | | 0.02 | | | | | | 5,247 | | | | | | 0.03 | | |
Total
|
| | | $ | 15,620 | | | | | $ | 0.06 | | | | | $ | 18,539 | | | | | $ | 0.09 | | |
| | |
For the Year Ended December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
|
(in thousands)
|
| |||||||||||
Wages and benefits
|
| | | $ | 25,091 | | | | | $ | 23,301 | | |
Professional services
|
| | | | 2,924 | | | | | | 2,498 | | |
Licenses, fees and other
|
| | | | 7,504 | | | | | | 7,287 | | |
Total gross G&A expense
|
| | | | 35,519 | | | | | | 33,086 | | |
Less: | | | | | | | | | | | | | |
Allocations to affiliates
|
| | | | (9,108) | | | | | | (8,722) | | |
Recoveries
|
| | | | (18,963) | | | | | | (16,522) | | |
Net G&A expense
|
| | | $ | 7,448 | | | | | $ | 7,842 | | |
| | |
For the Year Ended December 31,
|
| |||||||||||||||||||||
|
2020
|
| |
2019
|
| ||||||||||||||||||||
|
(in thousands)
|
| |
Per Mcf
|
| |
(in thousands)
|
| |
Per Mcf
|
| ||||||||||||||
Depletion
|
| | | $ | 340,423 | | | | | $ | 1.41 | | | | | $ | 319,456 | | | | | $ | 1.60 | | |
Depreciation
|
| | | | 5,351 | | | | | | 0.02 | | | | | | 4,405 | | | | | | 0.02 | | |
Accretion
|
| | | | 1,878 | | | | | | 0.01 | | | | | | 3,798 | | | | | | 0.02 | | |
Total
|
| | | $ | 347,652 | | | | | $ | 1.44 | | | | | $ | 327,659 | | | | | $ | 1.64 | | |
| | |
For the Year Ended December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
|
(in thousands)
|
| |||||||||||
Cash interest: | | | | | | | | | | | | | |
Interest costs and unutilized fees
|
| | | $ | 96,190 | | | | | $ | 98,869 | | |
Realized gain on interest rate swaps
|
| | | | — | | | | | | (1,404) | | |
Letter of credit fees and other
|
| | | | 943 | | | | | | 875 | | |
Total cash interest
|
| | | | 97,133 | | | | | | 98,340 | | |
Non-cash interest: | | | | | | | | | | | | | |
Non-cash interest
|
| | | | 17,606 | | | | | | 12,384 | | |
Non-cash loss on extinguishment of Superpriority Facility
|
| | | | 4,509 | | | | | | — | | |
Unrealized loss on interest rate swaps
|
| | | | — | | | | | | 1,474 | | |
Total non-cash interest
|
| | | | 22,115 | | | | | | 13,858 | | |
Total interest expense
|
| | | $ | 119,248 | | | | | $ | 112,198 | | |
| | |
For the Year Ended December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
|
(in thousands)
|
| |||||||||||
Operating cash flow
|
| | | $ | 295,174 | | | | | $ | 270,699 | | |
Investing cash flow
|
| | | | (252,378) | | | | | | (281,193) | | |
Financing cash flow
|
| | | | (45,565) | | | | | | 7,750 | | |
Net change in cash
|
| | | $ | (2,769) | | | | | $ | (2,744) | | |
Natural Gas Swaps
|
| |||||||||||||||
| | |
Period
|
| |
Natural Gas
Volume (MMBtud) |
| |
Weighted Average
Swap Price ($ / MMBtu) |
| ||||||
2021 | | | | | | | | | | | | | | | | |
First Quarter
|
| | | | | | | 515,000 | | | | | $ | 2.70 | | |
Second Quarter
|
| | | | | | | 610,890 | | | | | $ | 2.53 | | |
Third Quarter
|
| | | | | | | 637,522 | | | | | $ | 2.53 | | |
Fourth Quarter
|
| | | | | | | 648,370 | | | | | $ | 2.54 | | |
2022 | | | | | | | | | | | | | | | | |
First Quarter
|
| | | | | | | 639,833 | | | | | $ | 2.55 | | |
Second Quarter
|
| | | | | | | 119,780 | | | | | $ | 2.57 | | |
Third Quarter
|
| | | | | | | 156,522 | | | | | $ | 2.56 | | |
Fourth Quarter
|
| | | | | | | 363,109 | | | | | $ | 2.53 | | |
Natural Gas Swaps
|
| |||||||||||||||
| | |
Period
|
| |
Natural Gas
Volume (MMBtud) |
| |
Weighted Average
Swap Price ($ / MMBtu) |
| ||||||
2023 | | | | | | | | | | | | | | | | |
First Quarter
|
| | | | | | | 445,333 | | | | | $ | 2.50 | | |
Fourth Quarter
|
| | | | | | | 101,087 | | | | | $ | 2.54 | | |
2024 | | | | | | | | | | | | | | | | |
First Quarter
|
| | | | | | | 300,000 | | | | | $ | 2.54 | | |
Fourth Quarter
|
| | | | | | | 70,761 | | | | | $ | 2.58 | | |
2025 | | | | | | | | | | | | | | | | |
First Quarter
|
| | | | | | | 137,667 | | | | | $ | 2.58 | | |
Natural Gas Calls
|
| |||||||||||||||
| | |
Period
|
| |
Natural Gas
Volume (MMBtud) |
| |
Weighted Average
Swap Price ($ / MMBtu) |
| ||||||
2021 | | | | | | | | | | | | | | | | |
First Quarter
|
| | | | | | | (85,000) | | | | | $ | 3.19 | | |
| | |
Highest Priority
|
| | | | | | | |
Lowest Priority
|
| |||
|
RBL
|
| |
Second Lien Term
Loan |
| |
Third Lien Credit
Facility |
| |
9.75%
(Unsecured) |
| |
8.75%
(Unsecured) |
| ||
Face amount | | |
$300 million
|
| |
$150 million
|
| |
$330 million
|
| |
$380 million
|
| |
$530 million
|
|
Amount outstanding | | |
$190 million
|
| |
$150 million
|
| |
$0
|
| |
$380 million
|
| |
$530 million
|
|
Scheduled maturity date
|
| |
January 2023
|
| |
December 30, 2025 or 90 days prior to the maturity of the 9.75% Notes or 8.75% Notes
|
| |
March 15, 2023
|
| |
April 2023
|
| |
April 2023
|
|
Interest rate | | |
LIBOR+2.5-3.5%
|
| |
LIBOR + 8.75%
|
| |
LIBOR + 9.75%
|
| |
9.75%
|
| |
8.75%
|
|
Base interest rate options
|
| |
ABR and LIBOR + spread
|
| |
ABR and LIBOR + spread
|
| |
ABR and LIBOR + spread
|
| |
N/A
|
| |
N/A
|
|
Financial maintenance covenants | | |
– Maximum consolidated total
net leverage ratio of 4.0x |
| |
– Maximum consolidated total net leverage ratio of 4.0x
|
| |
– LTM Leverage minimum of $0
|
| |
N/A
|
| |
N/A
|
|
| | |
decreasing to 3.5x effective April 2021
|
| |
decreasing to 3.5x effective April 2021
– Minimum liquidity of $40 million tested quarterly |
| |
– Maximum consolidated total net leverage ratio of 4.0x decreasing to 3.5x effective April 2021
– Maximum secured leverage ratios of 4.0x decreasing to 3.5x effective April 2021 |
| | | | | | |
Significant restrictive covenants | | |
– Incurrence of debt
– Incurrence of liens – Payment of dividends – Equity purchases – Asset sales – Limitations on derivatives & investments – Affiliate transactions |
| |
– Incurrence of debt
– Incurrence of liens – Payment of dividends – Equity purchases – Asset sales – Limitations on derivatives & investments – Affiliate transactions – Excess cash cap |
| |
– Incurrence of debt
– Incurrence of liens – Payment of dividends – Equity purchases – Asset sales – Limitations on derivatives & investments – Affiliate transactions |
| |
– Incurrence of debt
– Incurrence of liens – Payment of dividends – Equity purchases – Asset sales – Limitations on ability to make investments – Affiliate transactions |
| |
– Incurrence of debt
– Incurrence of liens – Payment of dividends – Equity purchases – Asset sales – Limitations on ability to make investments – Affiliate transactions |
|
Optional redemption | | |
Any time at par
|
| |
Make-whole through June 2022; 102% through June 2023; 101% through June 2024; thereafter at par
|
| |
Any time at par
|
| |
After October 2020 through October 2021 at 107.313%; thereafter through April 2022 at 104.875%; thereafter at par
|
| |
After October 2020 through October 2021 at 106.563%; thereafter through April 2022 at 104.375%; thereafter at par
|
|
Change of control | | |
Event of default
|
| |
Event of default
|
| |
Event of default
|
| |
If accompanied by Ratings Decline, Investor put at 101% of par
|
| |
If accompanied by Ratings Decline, Investor put at 101% of par
|
|
| | |
As of December 31, 2020 (in thousands)
|
| |||||||||||||||||||||||||||||||||
|
2021
|
| |
2022
|
| |
2023
|
| |
2024
|
| |
2025
|
| |
Total
|
| ||||||||||||||||||||
RBL Principal(1)
|
| | | $ | — | | | | | $ | 90,000 | | | | | $ | 100,000 | | | | | $ | — | | | | | $ | — | | | | | $ | 190,000 | | |
RBL Interest(2)
|
| | | | 6,823 | | | | | | 6,293 | | | | | | 127 | | | | | | — | | | | | | — | | | | | | 13,243 | | |
2nd Lien Term Loan
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 150,000 | | | | | | 150,000 | | |
2nd Lien Interest(2)
|
| | | | 14,448 | | | | | | 14,448 | | | | | | 14,448 | | | | | | 14,448 | | | | | | 14,448 | | | | | | 72,240 | | |
3rd Lien Interest(3)
|
| | | | 1,419 | | | | | | 1,419 | | | | | | 288 | | | | | | — | | | | | | — | | | | | | 3,126 | | |
8.75% Notes Principal
|
| | | | — | | | | | | — | | | | | | 530,000 | | | | | | — | | | | | | — | | | | | | 530,000 | | |
8.75% Notes Interest
|
| | | | 46,375 | | | | | | 46,375 | | | | | | 13,341 | | | | | | — | | | | | | — | | | | | | 106,091 | | |
9.75% Notes Principal
|
| | | | — | | | | | | — | | | | | | 380,000 | | | | | | — | | | | | | — | | | | | | 380,000 | | |
9.75% Notes Interest
|
| | | | 37,050 | | | | | | 37,050 | | | | | | 10,658 | | | | | | — | | | | | | — | | | | | | 84,758 | | |
LC Fees & Payments(4)
|
| | | | 847 | | | | | | 863 | | | | | | 653 | | | | | | 653 | | | | | | 653 | | | | | | 3,669 | | |
Drilling Rig(5)
|
| | | | 6,513 | | | | | | 4,173 | | | | | | — | | | | | | — | | | | | | — | | | | | | 10,686 | | |
Other
|
| | | | 1,054 | | | | | | 1,087 | | | | | | 932 | | | | | | — | | | | | | — | | | | | | 3,073 | | |
Total | | | | $ | 114,529 | | | | | $ | 201,708 | | | | | $ | 1,050,447 | | | | | $ | 15,101 | | | | | $ | 165,101 | | | | | $ | 1,546,886 | | |
| | |
Short Lateral
|
| |
Long Lateral
|
| | | | | | | ||||||
Length
|
| |
<5,300 ft
|
| |
>5,300 ft
|
| |
Total
|
| |||||||||
Haynesville
|
| | | | 226 | | | | | | 147 | | | | | | 373 | | |
Mid-Bossier
|
| | | | 212 | | | | | | 293 | | | | | | 505 | | |
Total Core
|
| | | | 438 | | | | | | 440 | | | | | | 878 | | |
Total Non-Core
|
| | | | 44 | | | | | | 10 | | | | | | 54 | | |
Total Drilling Locations
|
| | | | 482 | | | | | | 450 | | | | | | 932 | | |
| | |
At December 31,
2020(1)(2) |
| |||
|
(MMcf)
|
| |||||
Vine Oil & Gas | | | | | | | |
Estimated proved reserves: | | | | | | | |
Natural gas
|
| | | | 1,802,118 | | |
Total proved developed reserves
|
| | | | 446,243 | | |
Percent proved developed
|
| | | | 25% | | |
Total proved undeveloped reserves
|
| | | | 1,355,875 | | |
Estimated probable undeveloped reserves: | | | | | | | |
Natural gas
|
| | | | 1,878,220 | | |
Estimated possible undeveloped reserves: | | | | | | | |
Natural gas
|
| | | | 150,972 | | |
Brix and Harvest | | | | | | | |
Estimated proved reserves: | | | | | | | |
Natural gas
|
| | | | 511,381 | | |
Total proved developed reserves
|
| | | | 143,917 | | |
Percent proved developed
|
| | | | 28% | | |
Total proved undeveloped reserves
|
| | | | 367,464 | | |
Estimated probable undeveloped reserves: | | | | | | | |
Natural gas
|
| | | | 356,502 | | |
Estimated possible undeveloped reserves: | | | | | | | |
Natural gas
|
| | | | 42,695 | | |
Combined | | | | | | | |
Estimated proved reserves: | | | | | | | |
Natural gas
|
| | | | 2,313,499 | | |
Total proved developed reserves
|
| | | | 590,160 | | |
Percent proved developed
|
| | | | 26% | | |
Total proved undeveloped reserves
|
| | | | 1,723,339 | | |
Estimated probable undeveloped reserves: | | | | | | | |
Natural gas
|
| | | | 2,234,722 | | |
Estimated possible undeveloped reserves: | | | | | | | |
Natural gas
|
| | | | 193,667 | | |
| | |
At December 31,
2019(1)(2) |
| |||
|
(MMcf)
|
| |||||
Vine Oil & Gas | | | | | | | |
Estimated Proved Reserves: | | | | | | | |
Natural gas
|
| | | | 2,209,833 | | |
Total proved developed reserves
|
| | | | 447,966 | | |
Percent proved developed
|
| | | | 20% | | |
Total proved undeveloped reserves
|
| | | | 1,761,867 | | |
Estimated Probable undeveloped Reserves: | | | | | | | |
Natural gas
|
| | | | 3,585,933 | | |
Estimated Possible undeveloped Reserves: | | | | | | | |
Natural gas
|
| | | | 455,783 | | |
Brix and Harvest | | | | | | | |
Estimated Proved Reserves: | | | | | | | |
Natural gas
|
| | | | 652,194 | | |
Total proved developed reserves
|
| | | | 138,258 | | |
Percent proved developed
|
| | | | 21% | | |
Total proved undeveloped reserves
|
| | | | 513,936 | | |
Estimated Probable undeveloped Reserves: | | | | | | | |
Natural gas
|
| | | | 729,750 | | |
Estimated Possible undeveloped Reserves: | | | | | | | |
Natural gas
|
| | | | 169,917 | | |
Combined | | | | | | | |
Estimated Proved Reserves: | | | | | | | |
Natural gas
|
| | | | 2,862,027 | | |
Total proved developed reserves
|
| | | | 586,224 | | |
Percent proved developed
|
| | | | 20% | | |
Total proved undeveloped reserves
|
| | | | 2,275,803 | | |
Estimated Probable undeveloped Reserves: | | | | | | | |
Natural gas
|
| | | | 4,315,683 | | |
Estimated Possible undeveloped Reserves: | | | | | | | |
Natural gas
|
| | | | 625,700 | | |
| Vine Oil & Gas | | | | | | | |
|
Proved undeveloped reserves at December 31, 2019
|
| | | | 1,761,867 | | |
|
Conversions into proved developed reserves(1)
|
| | | | (225,659) | | |
|
Extensions and discoveries(2)
|
| | | | 630,571 | | |
| Revisions(3) | | | | | (810,904) | | |
|
Proved undeveloped reserves at December 31, 2020
|
| | | | 1,355,875 | | |
| Brix and Harvest combined | | | | | | | |
|
Proved undeveloped reserves at December 31, 2019
|
| | | | 513,936 | | |
|
Conversions into proved developed reserves(1)
|
| | | | (63,905) | | |
|
Extensions and discoveries(2)
|
| | | | 220,381 | | |
| Revisions(4) | | | | | (302,948) | | |
|
Proved undeveloped reserves at December 31, 2020
|
| | | | 367,464 | | |
| Combined | | | | | | | |
|
Proved undeveloped reserves at December 31, 2019
|
| | | | 2,275,803 | | |
|
Conversions into proved developed reserves(1)
|
| | | | (289,564) | | |
|
Extensions and discoveries(2)
|
| | | | 850,952 | | |
| Revisions(5) | | | | | (1,113,852) | | |
|
Proved undeveloped reserves at December 31, 2020
|
| | | | 1,723,339 | | |
| | |
Strip Pricing(1)(2)
|
| |||
|
(MMcf)
|
| |||||
Vine Oil & Gas | | | | | | | |
Estimated proved reserves at NYMEX Strip Pricing: | | | | | | | |
Natural gas
|
| | | | 2,364,510 | | |
Total proved developed reserves
|
| | | | 491,769 | | |
Percent proved developed
|
| | | | 21% | | |
Total proved undeveloped reserves
|
| | | | 1,872,741 | | |
Estimated probable undeveloped reserves at NYMEX Strip Pricing | | | | | | | |
Natural gas
|
| | | | 3,600,975 | | |
Estimated possible undeveloped reserves at NYMEX Strip Pricing
|
| | | | | | |
Natural gas
|
| | | | 296,890 | | |
Brix and Harvest | | | | | | | |
Estimated proved reserves at NYMEX Strip Pricing: | | | | | | | |
Natural gas
|
| | | | 786,563 | | |
Total proved developed reserves
|
| | | | 151,583 | | |
Percent proved developed
|
| | | | 19% | | |
Total proved undeveloped reserves
|
| | | | 634,980 | | |
Estimated probable undeveloped reserves at NYMEX Strip Pricing | | | | | | | |
Natural gas
|
| | | | 906,211 | | |
Estimated possible undeveloped reserves at NYMEX Strip Pricing | | | | | | | |
Natural gas
|
| | | | 130,697 | | |
Combined | | | | | | | |
Estimated proved reserves at NYMEX Strip Pricing: | | | | | | | |
Natural gas
|
| | | | 3,151,073 | | |
Total proved developed reserves
|
| | | | 643,352 | | |
Percent proved developed
|
| | | | 20% | | |
Total proved undeveloped reserves
|
| | | | 2,507,721 | | |
Estimated probable undeveloped reserves at NYMEX Strip Pricing | | | | | | | |
Natural gas
|
| | | | 4,507,186 | | |
Estimated possible undeveloped reserves at NYMEX Strip Pricing | | | | | | | |
Natural gas
|
| | | | 427,587 | | |
| Pricing Used for Proved Reserves as of December 31, 2020 | | | | | | | |
| Based on Historical SEC Pricing:: | | | | | | | |
|
Natural gas (per MMBtu)
|
| | | $ | 1.99 | | |
|
Natural gas (per Mcf)(1)
|
| | | $ | 1.73 | | |
| Pricing Used for Probable Undeveloped Reserves as of December 31, 2020: | | | | | | | |
| Based on Historical SEC Pricing: | | | | | | | |
|
Natural gas (per MMBtu)
|
| | | $ | 1.99 | | |
|
Natural gas (per Mcf)(1)
|
| | | $ | 1.74 | | |
| Pricing Used for Possible Undeveloped Reserves as of December 31, 2020: | | | | | | | |
| Based on Historical SEC Pricing: | | | | | | | |
|
Natural gas (per MMBtu)
|
| | | $ | 1.99 | | |
|
Natural gas (per Mcf)(1)
|
| | | $ | 1.73 | | |
| Pricing Used for Proved Reserves as of December 31, 2019 | | | | | | | |
| Based on Historical SEC Pricing:: | | | | | | | |
|
Natural gas (per MMBtu)
|
| | | $ | 2.58 | | |
|
Natural gas (per Mcf)(2)
|
| | | $ | 2.31 | | |
| Pricing Used for Probable Undeveloped Reserves as of December 31, 2019: | | | | | | | |
| Based on Historical SEC Pricing: | | | | | | | |
|
Natural gas (per MMBtu)
|
| | | $ | 2.58 | | |
|
Natural gas (per Mcf)(2)
|
| | | $ | 2.31 | | |
| Pricing Used for Possible Undeveloped Reserves as of December 31, 2019: | | | | | | | |
| Based on Historical SEC Pricing: | | | | | | | |
|
Natural gas (per MMBtu)
|
| | | $ | 2.58 | | |
|
Natural gas (per Mcf)(2)
|
| | | $ | 2.31 | | |
| | |
Unweighted
|
| |
Weighted
|
| ||||||
Vine Oil & Gas | | | | | | | | | | | | | |
Pricing Used for Proved Reserves as of December 31, 2020: | | | | | | | | | | | | | |
Based on NYMEX Future Strip: | | | | | | | | | | | | | |
Natural gas (per MMBtu)(1)
|
| | | $ | 2.73 | | | | | $ | 2.61 | | |
Natural gas (per Mcf)(2)
|
| | | $ | 2.46 | | | | | $ | 2.34 | | |
Pricing Used for Probable Reserves as of December 31, 2020: | | | | | | | | | | | | | |
Based on NYMEX Future Strip: | | | | | | | | | | | | | |
Natural gas (per MMBtu)(1)
|
| | | $ | 2.73 | | | | | $ | 2.74 | | |
Natural gas (per Mcf)(2)
|
| | | $ | 2.46 | | | | | $ | 2.47 | | |
Pricing Used for Possible Reserves as of December 31, 2020: | | | | | | | | | | | | | |
Based on NYMEX Future Strip: | | | | | | | | | | | | | |
Natural gas (per MMBtu)(1)
|
| | | $ | 2.73 | | | | | $ | 2.74 | | |
Natural gas (per Mcf)(2)
|
| | | $ | 2.46 | | | | | $ | 2.47 | | |
Brix and Harvest | | | | | | | | | | | | | |
Pricing Used for Proved Reserves as of December 31, 2020: | | | | | | | | | | | | | |
Based on NYMEX Future Strip: | | | | | | | | | | | | | |
Natural gas (per MMBtu)(1)
|
| | | $ | 2.73 | | | | | $ | 2.61 | | |
Natural gas (per Mcf)(2)
|
| | | $ | 2.45 | | | | | $ | 2.33 | | |
Pricing Used for Probable Reserves as of December 31, 2020: | | | | | | | | | | | | | |
Based on NYMEX Future Strip: | | | | | | | | | | | | | |
Natural gas (per MMBtu)(1)
|
| | | $ | 2.73 | | | | | $ | 2.75 | | |
Natural gas (per Mcf)(2)
|
| | | $ | 2.45 | | | | | $ | 2.47 | | |
Pricing Used for Possible Reserves as of December 31, 2020: | | | | | | | | | | | | | |
Based on NYMEX Future Strip: | | | | | | | | | | | | | |
Natural gas (per MMBtu)(1)
|
| | | $ | 2.73 | | | | | $ | 2.75 | | |
Natural gas (per Mcf)(2)
|
| | | $ | 2.45 | | | | | $ | 2.47 | | |
Combined | | | | | | | | | | | | | |
Pricing Used for Proved Reserves as of December 31, 2020: | | | | | | | | | | | | | |
Based on NYMEX Future Strip: | | | | | | | | | | | | | |
Natural gas (per MMBtu)(1)
|
| | | $ | 2.73 | | | | | $ | 2.61 | | |
Natural gas (per Mcf)(2)
|
| | | $ | 2.46 | | | | | $ | 2.34 | | |
Pricing Used for Probable Reserves as of December 31, 2020: | | | | | | | | | | | | | |
Based on NYMEX Future Strip: | | | | | | | | | | | | | |
Natural gas (per MMBtu)(1)
|
| | | $ | 2.73 | | | | | $ | 2.74 | | |
Natural gas (per Mcf)(2)
|
| | | $ | 2.46 | | | | | $ | 2.47 | | |
Pricing Used for Possible Reserves as of December 31, 2020: | | | | | | | | | | | | | |
Based on NYMEX Future Strip: | | | | | | | | | | | | | |
Natural gas (per MMBtu)(1)
|
| | | $ | 2.73 | | | | | $ | 2.75 | | |
Natural gas (per Mcf)(2)
|
| | | $ | 2.46 | | | | | $ | 2.47 | | |
| | |
2021
|
| |
2022
|
| |
2023
|
| |
2024
|
| |
2025
|
| |
Thereafter
|
| ||||||||||||||||||
Natural gas (per MMBtu)
|
| | | $ | 2.65 | | | | | $ | 2.58 | | | | | $ | 2.46 | | | | | $ | 2.48 | | | | | $ | 2.52 | | | | | $ | 2.75 | | |
| | |
Year Ended December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Vine Oil & Gas | | | | | | | | | | | | | |
Production data: | | | | | | | | | | | | | |
Natural gas (MMcf)
|
| | | | 240,869 | | | | | | 200,214 | | |
Average daily production (MMcfd)
|
| | | | 658 | | | | | | 549 | | |
Average sales prices per Mcf: | | | | | | | | | | | | | |
Before effects of realized derivatives
|
| | | $ | 1.74 | | | | | $ | 2.23 | | |
After effects of realized derivatives
|
| | | | 2.25 | | | | | | 2.42 | | |
Costs per Mcf: | | | | | | | | | | | | | |
Lease operating
|
| | | $ | 0.20 | | | | | $ | 0.23 | | |
Gathering and treating
|
| | | | 0.32 | | | | | | 0.19 | | |
Production and ad valorem taxes
|
| | | | 0.06 | | | | | | 0.09 | | |
Depreciation, depletion and accretion
|
| | | | 1.44 | | | | | | 1.64 | | |
General and administrative
|
| | | | 0.03 | | | | | | 0.04 | | |
Monitoring fee
|
| | | | 0.03 | | | | | | 0.04 | | |
Exploration
|
| | | | 0.00 | | | | | | 0.00 | | |
Strategic
|
| | | | 0.01 | | | | | | 0.00 | | |
Write-off of deferred IPO costs
|
| | | | 0.02 | | | | | | 0.01 | | |
Total
|
| | | $ | 2.11 | | | | | $ | 2.24 | | |
Brix and Harvest | | | | | | | | | | | | | |
Production data: | | | | | | | | | | | | | |
Natural gas (MMcf)
|
| | | | 85,640 | | | | | | 52,503 | | |
Average daily production (MMcfd)
|
| | | | 234 | | | | | | 144 | | |
Average sales prices per Mcf: | | | | | | | | | | | | | |
Before effects of realized derivatives
|
| | | $ | 1.78 | | | | | $ | 2.19 | | |
After effects of realized derivatives
|
| | | | 2.22 | | | | | | 2.38 | | |
Costs per Mcf: | | | | | | | | | | | | | |
Lease operating
|
| | | $ | 0.21 | | | | | $ | 0.13 | | |
Gathering and treating
|
| | | | 0.29 | | | | | | 0.36 | | |
Production and ad valorem taxes
|
| | | | 0.03 | | | | | | 0.03 | | |
Depreciation, depletion and accretion
|
| | | | 1.08 | | | | | | 1.26 | | |
General and administrative
|
| | | | 0.09 | | | | | | 0.15 | | |
Monitoring fee
|
| | | | 0.02 | | | | | | 0.02 | | |
Exploration
|
| | | | 0.00 | | | | | | 0.01 | | |
Strategic
|
| | | | 0.00 | | | | | | — | | |
Total
|
| | | $ | 1.72 | | | | | $ | 1.96 | | |
Vine Pro forma(1)
|
| |
Year Ended
December 31, 2020 |
| | | | |||
Production data: | | | | | | | | | | |
Natural gas (MMcf)
|
| | | | 326,510 | | | | | |
Average daily production (MMcfd)
|
| | | | 892 | | | | | |
Average sales prices per Mcf: | | | | | | | | | | |
Before effects of realized derivatives
|
| | | $ | 1.75 | | | | | |
After effects of realized derivatives
|
| | | | 2.25 | | | | | |
Costs per Mcf: | | | | | | | | | | |
Lease operating
|
| | | $ | 0.20 | | | | | |
Gathering and treating
|
| | | | 0.31 | | | | | |
Production and ad valorem taxes
|
| | | | 0.06 | | | | | |
Depreciation, depletion and accretion
|
| | | | 1.20 | | | | | |
General and administrative
|
| | | | 0.05 | | | | | |
Strategic
|
| | | | 0.01 | | | | | |
Write-off deferred IPO expenses
|
| | | | 0.02 | | | | | |
Total
|
| | | $ | 1.85 | | | | | |
| | |
Productive Wells
|
| |
Average
Working Interest |
| ||||||||||||
|
Gross
|
| |
Net
|
| ||||||||||||||
Vine Oil & Gas | | | | | | | | | | | | | | | | | | | |
Natural gas wells operated by Vine
|
| | | | 377 | | | | | | 314.59 | | | | | | 83.4% | | |
Natural gas wells operated by Brix
|
| | | | 6 | | | | | | 0.43 | | | | | | 7.2% | | |
Natural gas wells operated by GEP
|
| | | | 51 | | | | | | 9.69 | | | | | | 19.0% | | |
Natural gas wells operated by others
|
| | | | 43 | | | | | | 2.49 | | | | | | 5.8% | | |
Total
|
| | | | 477 | | | | | | 327.20 | | | | | | | | |
Brix and Harvest | | | | | | | | | | | | | | | | | | | |
Natural gas wells operated by Brix
|
| | | | 24 | | | | | | 20.64 | | | | | | 86.0% | | |
Natural gas wells operated by Vine
|
| | | | 119 | | | | | | 18.94 | | | | | | 15.9% | | |
Total
|
| | | | 143 | | | | | | 39.58 | | | | | | | | |
Combined(1) | | | | | | | | | | | | | | | | | | | |
Natural gas wells operated by combined
|
| | | | 401 | | | | | | 354.60 | | | | | | 88.4% | | |
Natural gas wells operated by GEP
|
| | | | 51 | | | | | | 9.69 | | | | | | 19.0% | | |
Natural gas wells operated by others
|
| | | | 43 | | | | | | 2.49 | | | | | | 5.8% | | |
Total
|
| | | | 495 | | | | | | 366.78 | | | | | | | | |
| Vine Oil & Gas | | | | | | | |
|
Undeveloped acres
|
| | | | 67,242 | | |
|
Developed acres
|
| | | | 29,031 | | |
|
Total
|
| | | | 96,273 | | |
| Brix and Harvest | | | | | | | |
|
Undeveloped acres
|
| | | | 23,060 | | |
|
Developed acres
|
| | | | 4,079 | | |
|
Total
|
| | | | 27,139 | | |
| Combined | | | | | | | |
|
Undeveloped acres(1)
|
| | | | 90,302 | | |
|
Developed acres
|
| | | | 33,110 | | |
|
Total
|
| | | | 123,412 | | |
| | |
Acres
|
| |||
Vine Oil & Gas | | | | | | | |
2021
|
| | | | — | | |
2022
|
| | | | 5,281 | | |
2023
|
| | | | 193 | | |
2024
|
| | | | 103 | | |
2025 and thereafter
|
| | | | 342 | | |
| | | | | 5,919 | | |
Brix and Harvest | | | | | | | |
2021
|
| | | | 2,509 | | |
2022
|
| | | | 1,441 | | |
2023
|
| | | | — | | |
2024
|
| | | | — | | |
2025 and thereafter
|
| | | | — | | |
| | | | | 3,950 | | |
Combined | | | | | | | |
2021
|
| | | | 2,509 | | |
2022
|
| | | | 6,722 | | |
2023
|
| | | | 193 | | |
2024
|
| | | | 103 | | |
2025 and thereafter
|
| | | | 342 | | |
| | | | | 9,869 | | |
| | |
For the Year Ended
December 31, 2020 |
| |
For the Year Ended
December 31, 2019 |
| ||||||||||||||||||
|
Productive Wells
|
| |
Productive Wells
|
| ||||||||||||||||||||
|
Gross
|
| |
Net
|
| |
Gross
|
| |
Net
|
| ||||||||||||||
Vine Oil & Gas | | | | | | | | | | | | | | | | | | | | | | | | | |
Haynesville:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Development
|
| | | | 26.0 | | | | | | 20.0 | | | | | | 23.0 | | | | | | 13.6 | | |
Exploratory
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total
|
| | | | 26.0 | | | | | | 20.0 | | | | | | 23.0 | | | | | | 13.6 | | |
Mid-Bossier:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Development
|
| | | | 9.0 | | | | | | 7.8 | | | | | | 14.0 | | | | | | 10.8 | | |
Exploratory
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total
|
| | | | 9.0 | | | | | | 7.8 | | | | | | 14.0 | | | | | | 10.8 | | |
Brix and Harvest | | | | | | | | | | | | | | | | | | | | | | | | | |
Haynesville:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Development
|
| | | | 18.0 | | | | | | 6.2 | | | | | | 15.0 | | | | | | 9.2 | | |
Exploratory
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total
|
| | | | 18.0 | | | | | | 6.2 | | | | | | 15.0 | | | | | | 9.2 | | |
Mid-Bossier:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Development
|
| | | | 11.0 | | | | | | 4.7 | | | | | | 6.0 | | | | | | 4.6 | | |
Exploratory
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total
|
| | | | 11.0 | | | | | | 4.7 | | | | | | 6.0 | | | | | | 4.6 | | |
Combined(1) | | | | | | | | | | | | | | | | | | | | | | | | | |
Haynesville:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Development
|
| | | | 28.0 | | | | | | 26.2 | | | | | | 27.0 | | | | | | 22.8 | | |
Exploratory
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total
|
| | | | 28.0 | | | | | | 26.2 | | | | | | 27.0 | | | | | | 22.8 | | |
Mid-Bossier:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Development
|
| | | | 13.0 | | | | | | 12.5 | | | | | | 18.0 | | | | | | 15.4 | | |
Exploratory
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total
|
| | | | 13.0 | | | | | | 12.5 | | | | | | 18.0 | | | | | | 15.4 | | |
Name
|
| |
Age
|
| |
Title
|
|
Eric D. Marsh | | |
61
|
| | President, Chief Executive Officer and Chairman of the Board | |
David M. Elkin | | |
55
|
| | Executive Vice President and Chief Operating Officer | |
Wayne B. Stoltenberg | | |
53
|
| | Executive Vice President and Chief Financial Officer | |
Jonathan C. Curth | | |
38
|
| | Executive Vice President, General Counsel and Corporate Secretary | |
Angelo G. Acconcia | | |
41
|
| | Director | |
Murat T. Konuk | | |
31
|
| | Director | |
Charles M. Sledge | | |
55
|
| | Director | |
H. Paulett Eberhart | | |
67
|
| | Director Nominee | |
David I. Foley | | |
53
|
| | Director Nominee | |
Name
|
| |
Principal Position
|
|
Eric D. Marsh | | | President, Chief Executive Officer & Chairman of the Board | |
David M. Elkin | | | Executive Vice President and Chief Operating Officer | |
Wayne B. Stoltenberg | | | Executive Vice President and Chief Financial Officer | |
Name
|
| |
Year
|
| |
Salary
($)(1) |
| |
Non-Equity
Incentive Plan Compensation ($)(2) |
| |
All Other
Compensation ($)(3) |
| |
Total
($) |
| |||||||||||||||
Eric D. Marsh
President, Chief Executive Officer & Chairman of the Board |
| | | | 2020 | | | | | | 752,473(4) | | | | | | 869,526 | | | | | | 14,250 | | | | | | 1,636,249 | | |
David M. Elkin
Executive Vice President & Chief Operating Officer |
| | | | 2020 | | | | | | 412,024 | | | | | | 356,895 | | | | | | 14,250 | | | | | | 783,169 | | |
Wayne B. Stoltenberg
Executive Vice President & Chief Financial Officer |
| | | | 2020 | | | | | | 365,006(5) | | | | | | 237,255 | | | | | | 14,250 | | | | | | 616,511 | | |
| | | | | |
Number of
Securities Unexercised, Exercisable (#)(1) |
| |
Number of
Securities Unexercised, Unexercisable (#)(1) |
| |
Exercise
Price ($) |
| |
Expiration
Date |
| ||||||||||||
Eric D. Marsh
|
| | Class A Units (Vine)(2) | | | | | 40 | | | | | | — | | | | | | N/A | | | | | | N/A | | |
| | | Class A Units (Brix)(3) | | | | | 32 | | | | | | 8 | | | | | | N/A | | | | | | N/A | | |
| | |
Class A Units (Harvest)(4)
|
| | | | 24 | | | | | | 6 | | | | | | N/A | | | | | | N/A | | |
David M. Elkin
|
| | Class A Units (Vine)(2) | | | | | 2.4 | | | | | | 9.6 | | | | | | N/A | | | | | | N/A | | |
| | | Class A Units (Brix)(3) | | | | | 1.8 | | | | | | 7.2 | | | | | | N/A | | | | | | N/A | | |
| | |
Class A Units (Harvest)(4)
|
| | | | 2.4 | | | | | | 9.6 | | | | | | N/A | | | | | | N/A | | |
Wayne B. Stoltenberg
|
| | Class A Units (Vine)(2) | | | | | 3.2 | | | | | | 4.8 | | | | | | N/A | | | | | | N/A | | |
| | | Class A Units (Brix)(3) | | | | | 3.2 | | | | | | 4.8 | | | | | | N/A | | | | | | N/A | | |
| | |
Class A Units (Harvest)(4)
|
| | | | 2 | | | | | | 3 | | | | | | N/A | | | | | | N/A | | |
Name
|
| |
Fees Earned
or Paid in Cash ($) |
| |
Total ($)
|
| ||||||
Alan J. Carr(1)
|
| | | | 262,500 | | | | | | 262,500 | | |
Charles M. Sledge
|
| | | | 262,500 | | | | | | 262,500 | | |
Name of Beneficial Owner(1)
|
| |
Shares of Class A
Common Stock Beneficially Owned |
| |
Shares of Class B
Common Stock Beneficially Owned |
| |
Total
Common Stock Beneficially Owned |
| | |||||||||||||||||||||||
|
Number
|
| |
Percentage
|
| |
Number
|
| |
Percentage
|
| |
Percentage
|
| | |||||||||||||||||||
5% Shareholders: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Vine Investment LLC(2)
|
| | | | 1,543,382 | | | | | | 4.1% | | | | | | 17,387,013 | | | | | | 50.8% | | | | | | 26.3% | | | | ||
Vine Investment II LLC(3)
|
| | | | 10,318,747 | | | | | | 27.3% | | | | | | — | | | | | | — | | | | | | 14.3% | | | | ||
Brix Investment LLC(4)
|
| | | | 1,477,229 | | | | | | 3.9% | | | | | | 16,639,516 | | | | | | 48.6% | | | | | | 25.2% | | | | ||
Brix Investment II LLC(5)
|
| | | | 7,085,147, | | | | | | 18.7% | | | | | | — | | | | | | — | | | | | | 9.8% | | | | ||
Harvest Investment LLC(6)
|
| | | | 17,329, | | | | | | 0.0% | | | | | | 201,341 | | | | | | 0.6% | | | | | | 0.3% | | | | ||
Harvest Investment II LLC(7)
|
| | | | 150,267 | | | | | | 0.4% | | | | | | — | | | | | | — | | | | | | 0.2% | | | | ||
Named Executive Officers, Directors and Director Nominees:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Eric D. Marsh
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | ||
Wayne B. Stoltenberg
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | ||
David M. Elkin
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | ||
Angelo G. Acconcia(8)
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | ||
Murat T. Konuk(9)
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | ||
Charles M. Sledge
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | ||
H. Paulett Eberhart
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | ||
David I. Foley(10)
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | ||
Executive Officers, Directors and Director
Nominees as a Group (8 persons) |
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | |
Name
|
| |
Number of Shares
|
| |||
Citigroup Global Markets Inc.
|
| | | | 3,762,500 | | |
Credit Suisse Securities (USA) LLC
|
| | | | 3,762,500 | | |
Morgan Stanley & Co. LLC
|
| | | | 3,762,500 | | |
BofA Securities, Inc.
|
| | | | 2,150,000 | | |
Barclays Capital Inc.
|
| | | | 2,150,000 | | |
RBC Capital Markets, LLC
|
| | | | 2,150,000 | | |
Blackstone Securities Partners L.P.
|
| | | | 2,150,000 | | |
Capital One Securities, Inc.
|
| | | | 505,251 | | |
KeyBanc Capital Markets Inc.
|
| | | | 505,251 | | |
MUFG Securities Americas Inc.
|
| | | | 505,250 | | |
CastleOak Securities, L.P.
|
| | | | 24,187 | | |
Drexel Hamilton, LLC
|
| | | | 24,187 | | |
Samuel A. Ramirez & Company, Inc.
|
| | | | 24,187 | | |
Stern Brothers & Co.
|
| | | | 24,187 | | |
Total
|
| | | | 21,500,000 | | |
| | |
Paid by Us
|
| |||||||||
|
No Exercise
|
| |
Full Exercise
|
| ||||||||
Per Share
|
| | | $ | 0.70 | | | | | $ | 0.70 | | |
Total(1) | | | | $ | 15,050,000 | | | | | $ | 17,307,500 | | |
| Vine Energy Inc. | | | | | | | |
|
Unaudited Pro Forma Condensed Combined Financial Statements as of and for the Year Ended December 31, 2020
|
| | | | E-169 | | |
| Vine Oil & Gas LP | | | | | | | |
|
Audited Financial Statements as of and for the Years Ended December 31, 2020 and 2019
|
| | | | E-181 | | |
| Brix Oil & Gas Holdings LP and Harvest Royalties Holdings LP | | | | | | | |
|
Audited Combined Financial Statements as of and for the Years Ended December 31, 2020 and
2019 |
| | |
|
| | |
| Vine Energy Inc. | | | | | | | |
|
Audited Balance Sheets as of December 31, 2020 and 2019
|
| | | | E-219 | | |
| | |
Historical
|
| |
Transaction Accounting
Adjustments |
| | | | |
Vine Pro Forma
|
| ||||||||||||||||||||||||
|
Vine
Oil & Gas |
| |
Brix
Companies |
| |
Corporate
Reorganization |
| | | | |
Offering
Transactions |
| |||||||||||||||||||||||
|
(in thousands)
|
| |||||||||||||||||||||||||||||||||||
Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents
|
| | | $ | 15,517 | | | | | $ | 17,660 | | | | | $ | — | | | | | | | | $ | — | | | | (h) | | | | $ | 33,177 | | |
Accounts receivable
|
| | | | 77,129 | | | | | | 15,968 | | | | | | (4,301) | | | | (a) | | | | | — | | | | | | | | | 88,796 | | |
Accounts receivable from affiliates
|
| | | | — | | | | | | 21,581 | | | | | | (21,581) | | | | (a) | | | | | — | | | | | | | | | — | | |
Joint interest billing receivables
|
| | | | 18,280 | | | | | | 6,831 | | | | | | (7,480) | | | | (a) | | | | | — | | | | | | | | | 17,631 | | |
Prepaid and other
|
| | | | 3,626 | | | | | | 39 | | | | | | (39) | | | | (a) | | | | | — | | | | | | | | | 3,626 | | |
Total current assets
|
| | | | 114,552 | | | | | | 62,079 | | | | | | (33,401) | | | | | | | | | — | | | | | | | | | 143,230 | | |
Natural gas properties (successful efforts):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved
|
| | | | 2,722,419 | | | | | | 463,045 | | | | | | (109,769) | | | | (a)(b)(c)(d) | | | | | — | | | | | | | | | 3,075,695 | | |
Unproved
|
| | | | — | | | | | | — | | | | | | 95,850 | | | | (b) | | | | | — | | | | | | | | | 95,850 | | |
Accumulated depletion
|
| | | | (1,380,065) | | | | | | (191,837) | | | | | | 191,837 | | | | (b) | | | | | | | | | | | | | | (1,380,065) | | |
Total natural gas properties, net
|
| | | | 1,342,354 | | | | | | 271,208 | | | | | | 177,918 | | | | | | | | | — | | | | | | | | | 1,791,480 | | |
Other property and equipment, net
|
| | | | 7,936 | | | | | | — | | | | | | — | | | | | | | | | | | | | | | | | | 7,936 | | |
Deferred tax assets, net
|
| | | | — | | | | | | — | | | | | | — | | | | | | | | | — | | | | (i)(j) | | | | | — | | |
Other
|
| | | | 2,921 | | | | | | — | | | | | | — | | | | | | | | | 7,081 | | | | (h) | | | | | 10,002 | | |
Total assets
|
| | | $ | 1,467,763 | | | | | $ | 333,287 | | | | | $ | 144,517 | | | | | | | | $ | 7,081 | | | | | | | | $ | 1,952,648 | | |
Liabilities and Equity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current liabilities:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Accounts payable
|
| | | $ | 20,986 | | | | | $ | 2,658 | | | | | $ | (350) | | | | (a) | | | | $ | — | | | | | | | | $ | 23,294 | | |
Accrued expenses
|
| | | | 90,004 | | | | | | 12,579 | | | | | | (599) | | | | (a)(e) | | | | | 11,730 | | | | (h)(k) | | | | | 113,714 | | |
Accrued expenses to affiliate
|
| | | | — | | | | | | 11,820 | | | | | | (11,820) | | | | (a) | | | | | — | | | | | | | | | — | | |
Revenue payable
|
| | | | 37,552 | | | | | | 11,786 | | | | | | (20,382) | | | | (a) | | | | | — | | | | | | | | | 28,956 | | |
Derivatives
|
| | | | 19,948 | | | | | | 8,284 | | | | | | — | | | | | | | | | — | | | | | | | | | 28,232 | | |
Total current liabilities
|
| | | | 168,490 | | | | | | 47,127 | | | | | | (33,151) | | | | | | | | | 11,730 | | | | | | | | | 194,196 | | |
Long-term liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
New RBL
|
| | | | — | | | | | | — | | | | | | — | | | | | | | | | 31,550 | | | | (h) | | | | | 31,550 | | |
First lien credit facility
|
| | | | 183,569 | | | | | | — | | | | | | | | | | | | | | | (183,569) | | | | (h) | | | | | — | | |
Second lien term loan
|
| | | | 142,947 | | | | | | — | | | | | | — | | | | | | | | | — | | | | | | | | | 142,947 | | |
Brix credit facility
|
| | | | — | | | | | | 121,760 | | | | | | 3,240 | | | | (c) | | | | | (125,000) | | | | (h) | | | | | — | | |
Long-term debt
|
| | | | 898,225 | | | | | | — | | | | | | — | | | | | | | | | — | | | | | | | | | 898,225 | | |
Asset retirement obligations
|
| | | | 21,889 | | | | | | 888 | | | | | | — | | | | | | | | | — | | | | | | | | | 22,777 | | |
Derivatives
|
| | | | 38,341 | | | | | | 5,453 | | | | | | — | | | | | | | | | — | | | | | | | | | 43,794 | | |
Other
|
| | | | 4,241 | | | | | | — | | | | | | — | | | | | | | | | — | | | | | | | | | 4,241 | | |
Refundable deposits
|
| | | | — | | | | | | 2,784 | | | | | | — | | | | | | | | | — | | | | | | | | | 2,784 | | |
Total liabilities
|
| | | | 1,457,702 | | | | | | 178,012 | | | | | | (29,911) | | | | | | | | | (265,289) | | | | | | | | | 1,340,514 | | |
Partners’ capital / stockholders’ equity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Partners’ capital
|
| | | | 10,061 | | | | | | 155,275 | | | | | | (165,336) | | | | (d)(f) | | | | | — | | | | | | | | | — | | |
Class A common stock
|
| | | | — | | | | | | — | | | | | | 163 | | | | (b)(f) | | | | | 215 | | | | (h) | | | | | 378 | | |
Class B common stock
|
| | | | — | | | | | | — | | | | | | 342 | | | | (b)(f) | | | | | — | | | | | | | | | 342 | | |
Additional paid in capital
|
| | | | — | | | | | | — | | | | | | 178,268 | | | | (b)(f) | | | | | 148,589 | | | | (h)(i)(k) | | | | | 326,857 | | |
Retained earnings
|
| | | | — | | | | | | — | | | | | | (300) | | | | (e) | | | | | (5,144) | | | | (h) | | | | | (5,444) | | |
Total partners’ capital / stockholders equity
|
| | | | 10,061 | | | | | | 155,275 | | | | | | 13,157 | | | | | | | | | 143,600 | | | | | | | | | 322,133 | | |
Non-controlling interest
|
| | | | — | | | | | | — | | | | | | 161,291 | | | | (f) | | | | | 128,710 | | | | (h) | | | | | 290,001 | | |
Total equity
|
| | | | 10,061 | | | | | | 155,275 | | | | | | 174,428 | | | | | | | | | 272,370 | | | | | | | | | 612,134 | | |
Total liabilities and equity
|
| | | $ | 1,467,763 | | | | | $ | 333,287 | | | | | $ | 144,517 | | | | | | | | $ | 7,081 | | | | | | | | $ | 1,952,648 | | |
| | |
Historical
|
| |
Transaction Accounting
Adjustments |
| | | | |
Pro Forma
Combined Vine |
| | | | ||||||||||||||||||||||||
|
Vine
Oil & Gas |
| |
Brix
Companies |
| |
Corporate
Reorganization |
| | | | |
Offering
Transactions |
| ||||||||||||||||||||||||||
|
(in thousands, except share and per share amounts)
|
| | | | |||||||||||||||||||||||||||||||||||
Revenue: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas sales
|
| | | $ | 418,877 | | | | | $ | 152,267 | | | | | $ | — | | | | | | | | $ | — | | | | | | | | $ | 571,144 | | | | | |
Realized gain on commodity derivatives
|
| | | | 123,875 | | | | | | 38,043 | | | | | | — | | | | | | | | | — | | | | | | | | | 161,918 | | | | | |
Unrealized (loss) gain on commodity derivatives
|
| | | | (164,077) | | | | | | (40,475) | | | | | | — | | | | | | | | | — | | | | | | | | | (204,552) | | | | | |
Total revenue
|
| | | | 378,675 | | | | | | 149,835 | | | | | | — | | | | | | | | | — | | | | | | | | | 528,510 | | | | | |
Operating Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Lease operating
|
| | | | 47,911 | | | | | | 17,728 | | | | | | — | | | | | | | | | — | | | | | | | | | 65,639 | | | | | |
Gathering and treating
|
| | | | 76,770 | | | | | | 25,204 | | | | | | — | | | | | | | | | — | | | | | | | | | 101,974 | | | | | |
Production and ad valorem taxes
|
| | | | 15,620 | | | | | | 2,715 | | | | | | — | | | | | | | | | — | | | | | | | | | 18,335 | | | | | |
General and administrative
|
| | | | 7,448 | | | | | | 7,368 | | | | | | 300 | | | | (e) | | | | | — | | | | | | | | | 15,116 | | | | | |
Monitoring fee
|
| | | | 7,541 | | | | | | 1,371 | | | | | | — | | | | | | | | | (8,912) | | | | (l) | | | | | — | | | | | |
Depletion, depreciation and accretion
|
| | | | 347,652 | | | | | | 92,177 | | | | | | (47,791) | | | | (g) | | | | | — | | | | | | | | | 392,038 | | | | | |
Exploration
|
| | | | 167 | | | | | | 26 | | | | | | — | | | | | | | | | — | | | | | | | | | 193 | | | | | |
Strategic
|
| | | | 2,182 | | | | | | — | | | | | | — | | | | | | | | | — | | | | | | | | | 2,182 | | | | | |
Severance
|
| | | | 326 | | | | | | 121 | | | | | | — | | | | | | | | | — | | | | | | | | | 447 | | | | | |
Write-off of deferred IPO expenses
|
| | | | 5,787 | | | | | | — | | | | | | — | | | | | | | | | — | | | | | | | | | 5,787 | | | | | |
Total operating expenses
|
| | | | 511,404 | | | | | | 146,710 | | | | | | (47,491) | | | | | | | | | (8,912) | | | | | | | | | 601,711 | | | | | |
Operating Income
|
| | | | (132,729) | | | | | | 3,125 | | | | | | 47,491 | | | | | | | | | 8,912 | | | | | | | | | (73,201) | | | | | |
Interest expense
|
| | | | (119,248) | | | | | | (11,928) | | | | | | 1,412 | | | | (c) | | | | | 13,175 | | | | (h) | | | | | (116,589) | | | | | |
Income Before Income Taxes
|
| | | | (251,977) | | | | | | (8,803) | | | | | | 48,903 | | | | | | | | | 22,087 | | | | | | | | | (189,790) | | | | | |
Income tax provision
|
| | | | (217) | | | | | | — | | | | | | — | | | | | | | | | — | | | | (i) | | | | | (217) | | | | | |
Net Income
|
| | | $ | (252,194) | | | | | $ | (8,803) | | | | | $ | 48,903 | | | | | | | | $ | 22,087 | | | | | | | | $ | (190,007) | | | | | |
Net income attributable to non-controlling interests
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (90,253) | | | | | |
Net Income Attributable to Vine
Energy Inc. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | (99,754) | | | | | |
Net Income per Share: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | (2.64) | | | | (m) | |
Diluted
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | (2.64) | | | | (m) | |
Weighted Average Shares Outstanding:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 37,806,386 | | | | (m) | |
Diluted
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 37,806,386 | | | | (m) | |
| | |
Preliminary Merger
Consideration |
| |||
| | |
(in thousands, except
share and per share data) |
| |||
Brix – Corporate Reorganization merger consideration
|
| | | | 23,231,659 | | |
Harvest – Corporate Reorganization merger consideration
|
| | | | 340,094 | | |
| | | | | 23,571,753 | | |
Initial public offering price of Vine Class A common stock
|
| | | $ | 14.00 | | |
Total merger consideration
|
| | | $ | 330,005 | | |
| | |
Preliminary Purchase
Price Allocation |
| |||
| | |
(in thousands)
|
| |||
Assets Acquired | | | | | | | |
Cash and cash equivalents
|
| | | $ | 17,660 | | |
Accounts receivable
|
| | | | 15,968 | | |
Joint interest billing receivables
|
| | | | 6,831 | | |
Proved properties
|
| | | | 363,128 | | |
Unproved
|
| | | | 95,850 | | |
Total assets to be acquired
|
| | | $ | 499,437 | | |
Liabilities Assumed | | | | | | | |
Accounts payable
|
| | | $ | 2,658 | | |
Accrued expenses
|
| | | | 12,579 | | |
Revenue payable
|
| | | | 11,786 | | |
Derivatives
|
| | | | 8,284 | | |
Brix credit facility
|
| | | | 125,000 | | |
Asset retirement obligations
|
| | | | 888 | | |
Derivatives
|
| | | | 5,453 | | |
Refundable deposits
|
| | | | 2,784 | | |
Total liabilities to be assumed
|
| | | | 169,432 | | |
Net assets to be acquired
|
| | | $ | 330,005 | | |
| | |
Vine Pro Forma
|
| |||
|
For the Year Ended
December 31, 2020 |
| |||||
|
(in thousands,
except share and per share data) |
| |||||
Numerator | | | | | | | |
Net income
|
| | | $ | (190,007) | | |
Net income attributable to non-controlling interests
|
| | | | (90,253) | | |
Net income attributable to Vine Energy Inc.
|
| | | $ | (99,754) | | |
Denominator | | | | | | | |
Weighted average shares outstanding (basic)
|
| | | | 37,806,386 | | |
Effect of dilutive shares(1)
|
| | | | — | | |
Weighted average shares outstanding (diluted)
|
| | | | 37,806,386 | | |
Pro forma net income per share – basic
|
| | | $ | (2.64) | | |
Pro forma net income per share – diluted
|
| | | $ | (2.64) | | |
| | |
Historical
|
| |
Vine Pro Forma
|
| ||||||||||||
|
Vine Oil & Gas
|
| |
Brix Companies
|
| ||||||||||||||
|
(in MMcf)
|
| |||||||||||||||||
Balance at December 31, 2019
|
| | | | 2,209,833 | | | | | | 652,194 | | | | | | 2,862,027 | | |
Production
|
| | | | (240,869) | | | | | | (85,641) | | | | | | (326,510) | | |
Revision of previous estimates
|
| | | | (847,273) | | | | | | (287,359) | | | | | | (1,134,632) | | |
Acquisitions of reserves
|
| | | | 46,516 | | | | | | 51,224 | | | | | | 97,740 | | |
Extensions and discoveries
|
| | | | 633,911 | | | | | | 180,963 | | | | | | 814,874 | | |
Balance at December 31, 2020
|
| | | | 1,802,118 | | | | | | 511,381 | | | | | | 2,313,499 | | |
Proved developed reserves at: | | | | | | | | | | | | | | | | | | | |
December 31, 2019
|
| | | | 447,966 | | | | | | 138,258 | | | | | | 586,224 | | |
December 31, 2020
|
| | | | 446,243 | | | | | | 143,917 | | | | | | 590,160 | | |
Proved undeveloped reserves at: | | | | | | | | | | | | | | | | | | | |
December 31, 2019
|
| | | | 1,761,867 | | | | | | 513,936 | | | | | | 2,275,803 | | |
December 31, 2020
|
| | | | 1,355,875 | | | | | | 367,464 | | | | | | 1,723,339 | | |
| | |
Historical
|
| |
Vine Pro Forma
|
| ||||||||||||
|
Vine Oil & Gas
|
| |
Brix Companies
|
| ||||||||||||||
|
(in thousands)
|
| |||||||||||||||||
Future natural gas sales
|
| | | $ | 3,130,277 | | | | | $ | 882,384 | | | | | $ | 4,012,661 | | |
Future production costs
|
| | | | (1,173,122) | | | | | | (322,655) | | | | | | (1,495,777) | | |
Future development costs
|
| | | | (1,103,333) | | | | | | (303,403) | | | | | | (1,406,736) | | |
Future income tax expense
|
| | | | (7,772) | | | | | | (43,373) | | | | | | (51,145) | | |
Future net cash flows
|
| | | $ | 846,050 | | | | | $ | 212,953 | | | | | $ | 1,059,003 | | |
10% annual discount
|
| | | | (288,642) | | | | | | (66,864) | | | | | | (355,506) | | |
Standardized measure of discounted future net cash flows
|
| | | $ | 557,408 | | | | | $ | 146,089 | | | | | $ | 703,497 | | |
| | |
Historical
|
| |
Vine Pro Forma
|
| ||||||||||||
|
Vine Oil & Gas
|
| |
Brix Companies
|
| ||||||||||||||
|
(in thousands)
|
| |||||||||||||||||
Balance at beginning of period
|
| | | $ | 988,168 | | | | | $ | 299,471 | | | | | $ | 1,287,639 | | |
Sales of natural gas, net
|
| | | | (278,716) | | | | | | (106,633) | | | | | | (385,349) | | |
Revision of previous quantity estimates and extensions
|
| | | | (76,715) | | | | | | (6,968) | | | | | | (83,683) | | |
Acquisitions of reserves
|
| | | | 4,297 | | | | | | 10,965 | | | | | | 15,262 | | |
Previously estimated development costs incurred
|
| | | | 187,952 | | | | | | 57,863 | | | | | | 245,815 | | |
Net changes in future development costs
|
| | | | 44,210 | | | | | | 14,020 | | | | | | 58,230 | | |
Net changes in prices
|
| | | | (388,308) | | | | | | (126,299) | | | | | | (514,607) | | |
Accretion of discount
|
| | | | 98,816 | | | | | | 29,947 | | | | | | 128,763 | | |
Net change in income taxes
|
| | | | (5,228) | | | | | | (31,493) | | | | | | (36,721) | | |
Changes in timing and other differences
|
| | | | (17,068) | | | | | | 5,216 | | | | | | (11,852) | | |
Balance at end of period
|
| | | $ | 557,408 | | | | | $ | 146,089 | | | | | $ | 703,497 | | |
| | |
For the Year Ended
December 31, |
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Revenue: | | | | | | | | | | | | | |
Natural gas sales
|
| | | $ | 418,877 | | | | | $ | 445,589 | | |
Realized gain on commodity derivatives
|
| | | | 123,875 | | | | | | 39,679 | | |
Unrealized (loss) gain on commodity derivatives
|
| | | | (164,077) | | | | | | 101,239 | | |
Total revenue
|
| | | | 378,675 | | | | | | 586,507 | | |
Operating Expenses: | | | | | | | | | | | | | |
Lease operating
|
| | | | 47,911 | | | | | | 46,247 | | |
Gathering and treating
|
| | | | 76,770 | | | | | | 37,955 | | |
Production and ad valorem taxes
|
| | | | 15,620 | | | | | | 18,539 | | |
General and administrative
|
| | | | 7,448 | | | | | | 7,842 | | |
Monitoring fee
|
| | | | 7,541 | | | | | | 7,011 | | |
Depletion, depreciation and accretion
|
| | | | 347,652 | | | | | | 327,659 | | |
Exploration
|
| | | | 167 | | | | | | 886 | | |
Strategic
|
| | | | 2,182 | | | | | | 853 | | |
Severance
|
| | | | 326 | | | | | | — | | |
Write-off of deferred IPO costs
|
| | | | 5,787 | | | | | | 2,825 | | |
Total operating expenses
|
| | | | 511,404 | | | | | | 449,817 | | |
Operating income
|
| | | | (132,729) | | | | | | 136,690 | | |
Interest expense
|
| | | | (119,248) | | | | | | (112,198) | | |
Income before income taxes
|
| | | | (251,977) | | | | | | 24,492 | | |
Income tax provision
|
| | | | (217) | | | | | | (496) | | |
Net income
|
| | | $ | (252,194) | | | | | $ | 23,996 | | |
| | |
December 31, 2020
|
| |
December 31, 2019
|
| ||||||
Assets | | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | |
Cash and cash equivalents
|
| | | $ | 15,517 | | | | | $ | 18,286 | | |
Accounts receivable
|
| | | | 77,129 | | | | | | 56,316 | | |
Joint interest billing receivables
|
| | | | 18,280 | | | | | | 23,174 | | |
Derivatives
|
| | | | — | | | | | | 83,951 | | |
Prepaid and other
|
| | | | 3,626 | | | | | | 890 | | |
Total current assets
|
| | | | 114,552 | | | | | | 182,617 | | |
Natural gas properties (successful efforts): | | | | | | | | | | | | | |
Proved
|
| | | | 2,722,419 | | | | | | 2,475,619 | | |
Accumulated depletion
|
| | | | (1,380,065) | | | | | | (1,039,643) | | |
Total natural gas properties, net
|
| | | | 1,342,354 | | | | | | 1,435,976 | | |
Other property and equipment, net
|
| | | | 7,936 | | | | | | 4,550 | | |
Derivatives
|
| | | | — | | | | | | 21,837 | | |
Other
|
| | | | 2,921 | | | | | | 13,120 | | |
Total assets
|
| | | $ | 1,467,763 | | | | | $ | 1,658,100 | | |
Liabilities and Partners’ Capital | | | | | | | | | | | | | |
Current liabilities: | | | | | | | | | | | | | |
Accounts payable
|
| | | $ | 20,986 | | | | | $ | 10,493 | | |
Accrued expenses
|
| | | | 90,004 | | | | | | 86,246 | | |
Revenue payable
|
| | | | 37,552 | | | | | | 24,709 | | |
Gas gathering liability
|
| | | | — | | | | | | 2,043 | | |
Derivatives
|
| | | | 19,948 | | | | | | — | | |
Total current liabilities
|
| | | | 168,490 | | | | | | 123,491 | | |
Long-term liabilities: | | | | | | | | | | | | | |
First lien credit facility
|
| | | | 183,569 | | | | | | 325,319 | | |
Second lien term loan
|
| | | | 142,947 | | | | | | — | | |
Unsecured debt
|
| | | | 898,225 | | | | | | 893,239 | | |
Asset retirement obligations
|
| | | | 21,889 | | | | | | 19,504 | | |
Derivatives
|
| | | | 38,341 | | | | | | — | | |
Other
|
| | | | 4,241 | | | | | | 4,292 | | |
Total liabilities
|
| | | | 1,457,702 | | | | | | 1,365,845 | | |
Commitments and contingencies
|
| | | | | | | | | | | | |
Partners’ capital
|
| | | | 10,061 | | | | | | 292,255 | | |
Total liabilities and partners’ capital
|
| | | $ | 1,467,763 | | | | | $ | 1,658,100 | | |
|
Balance at December 31, 2018
|
| | | $ | 268,259 | | |
|
Net income
|
| | | | 23,996 | | |
|
Balance at December 31, 2019
|
| | | $ | 292,255 | | |
|
Distribution to parent
|
| | | | (30,000) | | |
|
Net income
|
| | | | (252,194) | | |
|
Balance at December 31, 2020
|
| | | $ | 10,061 | | |
| | |
For the Year Ended December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Operating Activities | | | | | | | | | | | | | |
Net income
|
| | | $ | (252,194) | | | | | $ | 23,996 | | |
Adjustments to reconcile net income to operating cash flow:
|
| | | | | | | | | | | | |
Depletion, depreciation and accretion
|
| | | | 347,652 | | | | | | 327,659 | | |
Amortization of financing costs
|
| | | | 16,652 | | | | | | 11,513 | | |
Amortization of debt discount
|
| | | | 954 | | | | | | 871 | | |
Non-cash loss on extinguishment of Superpriority
|
| | | | 4,509 | | | | | | — | | |
Non-cash write-off of deferred IPO costs
|
| | | | 5,787 | | | | | | 2,825 | | |
Unrealized loss (gain) on commodity derivatives
|
| | | | 164,077 | | | | | | (101,239) | | |
Unrealized loss on interest rate derivatives
|
| | | | — | | | | | | 1,474 | | |
Volumetric and production adjustment to gas gathering liability
|
| | | | (2,567) | | | | | | (29,085) | | |
Other
|
| | | | (182) | | | | | | (18) | | |
Changes in assets and liabilities:
|
| | | | | | | | | | | | |
Accounts receivable
|
| | | | (20,813) | | | | | | 37,243 | | |
Joint interest billing receivables
|
| | | | 4,894 | | | | | | 2,236 | | |
Accounts payable and accrued expenses
|
| | | | 14,343 | | | | | | 7,946 | | |
Revenue payable
|
| | | | 12,843 | | | | | | (15,493) | | |
Other
|
| | | | (781) | | | | | | 771 | | |
Operating cash flow
|
| | | | 295,174 | | | | | | 270,699 | | |
Investing Activities | | | | | | | | | | | | | |
Proceeds from asset sales
|
| | | | 230 | | | | | | 5,839 | | |
Capital expenditures
|
| | | | (252,608) | | | | | | (287,032) | | |
Investing cash flow
|
| | | | (252,378) | | | | | | (281,193) | | |
Financing Activities | | | | | | | | | | | | | |
Proceeds from first lien credit facility
|
| | | | 100,000 | | | | | | 160,000 | | |
Payments on first lien credit facility
|
| | | | (250,000) | | | | | | (150,000) | | |
Proceeds from second lien term loan
|
| | | | 150,000 | | | | | | — | | |
Deferred financing costs paid
|
| | | | (15,565) | | | | | | (2,250) | | |
Distribution to parent
|
| | | | (30,000) | | | | | | — | | |
Financing cash flow
|
| | | | (45,565) | | | | | | 7,750 | | |
Net decrease in cash and cash equivalents
|
| | | | (2,769) | | | | | | (2,744) | | |
Cash and cash equivalents at beginning of period
|
| | | | 18,286 | | | | | | 21,030 | | |
Cash and cash equivalents at end of period
|
| | | $ | 15,517 | | | | | $ | 18,286 | | |
Supplemental information: | | | | | | | | | | | | | |
Cash paid for interest
|
| | | $ | 97,096 | | | | | $ | 99,601 | | |
Cash paid for taxes
|
| | | $ | 273 | | | | | $ | 600 | | |
Non-cash transactions: | | | | | | | | | | | | | |
Accrued capital expenditures
|
| | | $ | 24,552 | | | | | $ | 22,604 | | |
Accrued financing activities
|
| | | $ | 540 | | | | | $ | 3,843 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Proved natural gas properties subject to depletion
|
| | | $ | 2,722,419 | | | | | $ | 2,475,619 | | |
Less: Accumulated depletion
|
| | | | (1,380,065) | | | | | | (1,039,643) | | |
Natural gas properties, net
|
| | | $ | 1,342,354 | | | | | $ | 1,435,976 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Software development costs
|
| | | $ | 1,710 | | | | | $ | 8,253 | | |
Saltwater disposal wells
|
| | | | 14,262 | | | | | | 6,601 | | |
Other
|
| | | | 4,948 | | | | | | 4,836 | | |
Total cost
|
| | | | 20,920 | | | | | | 19,690 | | |
Accumulated depreciation
|
| | | | (12,984) | | | | | | (15,140) | | |
Other property and equipment, net
|
| | | $ | 7,936 | | | | | $ | 4,550 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Balance, beginning of period
|
| | | $ | 19,504 | | | | | $ | 17,680 | | |
Accretion expense
|
| | | | 1,354 | | | | | | 1,196 | | |
Liabilities incurred
|
| | | | 1,078 | | | | | | 628 | | |
Liabilities settled and divested
|
| | | | (47) | | | | | | — | | |
Balance, end of period
|
| | | $ | 21,889 | | | | | $ | 19,504 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Balance, beginning of period
|
| | | $ | 2,043 | | | | | $ | 28,526 | | |
Accretion expense
|
| | | | 524 | | | | | | 2,602 | | |
Volumetric and production adjustment to gas gathering liability
|
| | | | (2,567) | | | | | | (29,085) | | |
Balance, end of period
|
| | | $ | — | | | | | $ | 2,043 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Capital expenditures
|
| | | $ | 20,808 | | | | | $ | 21,795 | | |
Operating expenses
|
| | | | 30,554 | | | | | | 27,022 | | |
Royalty owner suspense
|
| | | | 7,891 | | | | | | 7,569 | | |
Compensation-related
|
| | | | 9,432 | | | | | | 7,823 | | |
Interest expense
|
| | | | 18,388 | | | | | | 17,811 | | |
Other
|
| | | | 2,931 | | | | | | 4,226 | | |
Accrued expenses
|
| | | $ | 90,004 | | | | | $ | 86,246 | | |
Face amount:
|
| |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Superpriority
|
| | | $ | — | | | | | $ | 150,000 | | |
RBL
|
| | | | 190,000 | | | | | | 190,000 | | |
Second lien term loan
|
| | | | 150,000 | | | | | | — | | |
8.75% Senior Notes
|
| | | | 530,000 | | | | | | 530,000 | | |
9.75% Senior Notes
|
| | | | 380,000 | | | | | | 380,000 | | |
Total face amount
|
| | | | 1,250,000 | | | | | | 1,250,000 | | |
Deferred finance costs: | | | | | | | | | | | | | |
Superpriority
|
| | | | — | | | | | | (8,345) | | |
RBL
|
| | | | (6,431) | | | | | | (6,336) | | |
Second lien term loan
|
| | | | (7,053) | | | | | | — | | |
8.75% Senior Notes
|
| | | | (5,293) | | | | | | (7,602) | | |
9.75% Senior Notes
|
| | | | (3,954) | | | | | | (5,680) | | |
Total deferred finance costs
|
| | | | (22,731) | | | | | | (27,963) | | |
8.75% Senior Notes, discount
|
| | | | (2,528) | | | | | | (3,479) | | |
Total discount
|
| | | | (2,528) | | | | | | (3,479) | | |
Total debt
|
| | | | 1,224,741 | | | | | | 1,218,558 | | |
Less: short-term portion
|
| | | | — | | | | | | — | | |
Total long-term debt
|
| | | $ | 1,224,741 | | | | | $ | 1,218,558 | | |
| | |
2020
|
| |
2021
|
| |
2022
|
| |
2023
|
| |
2024
|
| |
Thereafter
|
| ||||||||||||||||||
RBL
|
| | | $ | — | | | | | $ | — | | | | | $ | — | | | | | $ | 190,000 | | | | | $ | — | | | | | $ | — | | |
Second lien term loan
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 150,000 | | |
8.75% Notes
|
| | | | — | | | | | | — | | | | | | — | | | | | | 530,000 | | | | | | — | | | | | | — | | |
9.75% Notes
|
| | | | — | | | | | | — | | | | | | — | | | | | | 380,000 | | | | | | — | | | | | | — | | |
Total indebtedness
|
| | | $ | — | | | | | $ | — | | | | | $ | — | | | | | $ | 1,100,000 | | | | | $ | — | | | | | $ | 150,000 | | |
| | |
Balance Sheet
Classification |
| |
Gross
Amounts |
| |
Netting
Adjustment |
| |
Net Amounts
Presented on the Balance Sheet |
| |||||||||
December 31, 2020 | | | | | | | | | | | | | | | | | | | | | | |
Assets:
|
| | | | | | | | | | | | | | | | | | | | | |
Commodity Derivatives
|
| |
Current assets
|
| | | $ | 9,095 | | | | | | (9,095) | | | | | $ | — | | |
Commodity Derivatives
|
| |
Noncurrent assets
|
| | | | 2,742 | | | | | | (2,742) | | | | | | — | | |
Total assets
|
| | | | | | $ | 11,837 | | | | | $ | (11,837) | | | | | $ | — | | |
Liabilities:
|
| | | | | | | | | | | | | | | | | | | | | |
Commodity Derivatives
|
| |
Current liabilities
|
| | | $ | 29,043 | | | | | $ | (9,095) | | | | | $ | 19,948 | | |
Commodity Derivatives
|
| |
Noncurrent liabilities
|
| | | | 41,083 | | | | | | (2,742) | | | | | | 38,341 | | |
Total liabilities
|
| | | | | | $ | 70,126 | | | | | $ | (11,837) | | | | | $ | 58,289 | | |
December 31, 2019 | | | | | | | | | | | | | | | | | | | | | | |
Assets:
|
| | | | | | | | | | | | | | | | | | | | | |
Commodity Derivatives
|
| |
Current assets
|
| | | $ | 83,951 | | | | | $ | — | | | | | $ | 83,951 | | |
Commodity Derivatives
|
| |
Noncurrent assets
|
| | | | 23,451 | | | | | | (1,614) | | | | | | 21,837 | | |
Total assets
|
| | | | | | $ | 107,402 | | | | | $ | (1,614) | | | | | $ | 105,788 | | |
Liabilities:
|
| | | | | | | | | | | | | | | | | | | | | |
Commodity Derivatives
|
| |
Current liabilities
|
| | | $ | — | | | | | $ | — | | | | | $ | — | | |
Commodity Derivatives
|
| |
Noncurrent liabilities
|
| | | | 1,614 | | | | | | (1,614) | | | | | | — | | |
Total liabilities
|
| | | | | | $ | 1,614 | | | | | $ | (1,614) | | | | | $ | — | | |
Natural Gas Swaps
|
| |||||||||||||||
| | |
Production Year
|
| |
Average Daily
Volumes (MMBtu) |
| |
Weighted
Average Swap Price ($ / MMBtu) |
| ||||||
2021
|
| | | | | | | 603,405 | | | | | $ | 2.57 | | |
2022
|
| | | | | | | 318,605 | | | | | $ | 2.55 | | |
2023
|
| | | | | | | 135,288 | | | | | $ | 2.51 | | |
2024
|
| | | | | | | 92,377 | | | | | $ | 2.54 | | |
2025
|
| | | | | | | 33,945 | | | | | $ | 2.58 | | |
Sold Natural Gas Calls
|
| |||||||||||||||
| | |
Production Year
|
| |
Average Daily
Volumes (MMBtu) |
| |
Weighted
Average Call Price ($ / MMBtu) |
| ||||||
2021
|
| | | | | | | 20,959 | | | | | $ | 3.19 | | |
| | |
Class A Units
|
| |||||||||||||||
|
Equity-based
Compensation Awards |
| |
Profit-Sharing
Arrangement |
| |
Total
|
| |||||||||||
Outstanding at December 31, 2018
|
| | | | 40 | | | | | | 42.5 | | | | | | 82.5 | | |
Granted
|
| | | | — | | | | | | 17.5 | | | | | | 17.5 | | |
Forfeited
|
| | | | — | | | | | | — | | | | | | — | | |
Outstanding at December 31, 2019
|
| | | | 40 | | | | | | 60 | | | | | | 100 | | |
Granted
|
| | | | — | | | | | | 2 | | | | | | 2 | | |
Forfeited
|
| | | | — | | | | | | (6) | | | | | | (6) | | |
Outstanding at December 31, 2020
|
| | | | 40 | | | | | | 56 | | | | | | 96 | | |
|
Balance at December 31, 2018
|
| | | | 1,868,794 | | |
|
Production
|
| | | | (200,214) | | |
|
Revision of previous estimates(1)
|
| | | | (226,510) | | |
|
Acquisitions of reserves(2)
|
| | | | 5,731 | | |
|
Extensions and discoveries(3)
|
| | | | 762,032 | | |
|
Balance at December 31, 2019
|
| | | | 2,209,833 | | |
|
Production
|
| | | | (240,869) | | |
|
Revision of previous estimates(4)
|
| | | | (847,273) | | |
|
Acquisitions of reserves(2)
|
| | | | 46,516 | | |
|
Extensions and discoveries(5)
|
| | | | 633,911 | | |
|
Balance at December 31, 2020
|
| | | | 1,802,118 | | |
| Proved developed reserves at: | | | | | | | |
|
December 31, 2018
|
| | | | 400,194 | | |
|
December 31, 2019
|
| | | | 447,966 | | |
|
December 31, 2020
|
| | | | 446,243 | | |
| Proved undeveloped reserves at: | | | | | | | |
|
December 31, 2018
|
| | | | 1,468,600 | | |
|
December 31, 2019
|
| | | | 1,761,867 | | |
|
December 31, 2020
|
| | | | 1,355,875 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Proved natural gas properties subject to depletion
|
| | | $ | 2,722,419 | | | | | $ | 2,475,619 | | |
Less: Accumulated depletion
|
| | | | (1,380,065) | | | | | | (1,039,643) | | |
Natural gas properties, net
|
| | | $ | 1,342,354 | | | | | $ | 1,435,976 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Proved acreage
|
| | | $ | 1,460 | | | | | $ | 6,022 | | |
Development costs
|
| | | | 242,437 | | | | | | 278,793 | | |
Total
|
| | | $ | 243,897 | | | | | $ | 284,815 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Future natural gas sales
|
| | | $ | 3,130,277 | | | | | $ | 5,113,708 | | |
Future production costs
|
| | | | (1,173,122) | | | | | | (1,670,411) | | |
Future development costs(1)
|
| | | | (1,103,333) | | | | | | (1,787,256) | | |
Future income tax expense(2)
|
| | | | — | | | | | | — | | |
Future net cash flows
|
| | | $ | 853,822 | | | | | $ | 1,656,041 | | |
10% annual discount
|
| | | | (291,186) | | | | | | (667,873) | | |
Standardized measure of discounted future net cash flows
|
| | | $ | 562,636 | | | | | $ | 988,168 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Balance at beginning of period
|
| | | $ | 988,168 | | | | | $ | 1,244,628 | | |
Sales of natural gas, net(3)
|
| | | | (278,716) | | | | | | (342,848) | | |
Revision of previous quantity estimates and extensions
|
| | | | (76,715) | | | | | | 174,884 | | |
Acquisitions of reserves
|
| | | | 4,297 | | | | | | 2,589 | | |
Previously estimated development costs incurred
|
| | | | 187,952 | | | | | | 185,584 | | |
Net changes in future development costs
|
| | | | 44,210 | | | | | | 37,611 | | |
Net changes in prices
|
| | | | (388,308) | | | | | | (452,332) | | |
Accretion of discount
|
| | | | 98,816 | | | | | | 124,463 | | |
Net change in income taxes(2)
|
| | | | — | | | | | | — | | |
Changes in timing and other differences
|
| | | | (17,068) | | | | | | 13,589 | | |
Balance at end of period(1)
|
| | | $ | 562,636 | | | | | $ | 988,168 | | |
| | |
For the Year Ended December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Revenue: | | | | | | | | | | | | | |
Natural gas sales
|
| | | $ | 152,267 | | | | | $ | 114,782 | | |
Realized gain on commodity derivatives
|
| | | | 38,043 | | | | | | 9,923 | | |
Unrealized (loss) gain on commodity derivatives
|
| | | | (40,475) | | | | | | 25,610 | | |
Total revenue
|
| | | | 149,835 | | | | | | 150,315 | | |
Operating Expenses: | | | | | | | | | | | | | |
Lease operating
|
| | | | 17,728 | | | | | | 7,014 | | |
Gathering and treating
|
| | | | 25,204 | | | | | | 18,928 | | |
Production and ad valorem taxes
|
| | | | 2,715 | | | | | | 1,550 | | |
General and administrative
|
| | | | 7,368 | | | | | | 7,763 | | |
Monitoring fee
|
| | | | 1,371 | | | | | | 906 | | |
Depletion, depreciation and accretion
|
| | | | 92,177 | | | | | | 65,901 | | |
Exploration
|
| | | | 26 | | | | | | 546 | | |
Severance
|
| | | | 121 | | | | | | — | | |
Total operating expenses
|
| | | | 146,710 | | | | | | 102,608 | | |
Operating Income
|
| | | | 3,125 | | | | | | 47,707 | | |
Interest expense
|
| | | | (11,928) | | | | | | (9,693) | | |
Net Income
|
| | | $ | (8,803) | | | | | $ | 38,014 | | |
| | |
December 31, 2020
|
| |
December 31, 2019
|
| ||||||
Assets | | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | |
Cash and cash equivalents
|
| | | $ | 17,660 | | | | | $ | 4,011 | | |
Accounts receivable
|
| | | | 15,968 | | | | | | 13,114 | | |
Accounts receivable from affiliates
|
| | | | 21,581 | | | | | | 13,646 | | |
Joint interest billing receivables
|
| | | | 6,831 | | | | | | 5,498 | | |
Derivatives
|
| | | | — | | | | | | 25,307 | | |
Prepaid and other
|
| | | | 39 | | | | | | 8 | | |
Total current assets
|
| | | | 62,079 | | | | | | 61,584 | | |
Natural gas properties (successful efforts):
|
| | | | | | | | | | | | |
Proved
|
| | | | 463,045 | | | | | | 353,492 | | |
Unproved
|
| | | | — | | | | | | 1,061 | | |
Accumulated depletion
|
| | | | (191,837) | | | | | | (99,727) | | |
Total natural gas properties, net
|
| | | | 271,208 | | | | | | 254,826 | | |
Derivatives
|
| | | | — | | | | | | 1,431 | | |
Total assets
|
| | | $ | 333,287 | | | | | $ | 317,841 | | |
Liabilities and Partners’ Capital | | | | | | | | | | | | | |
Current liabilities: | | | | | | | | | | | | | |
Accounts payable
|
| | | $ | 2,658 | | | | | $ | 1,146 | | |
Accrued expenses to affiliate
|
| | | | 11,820 | | | | | | 15,577 | | |
Accrued expenses
|
| | | | 12,579 | | | | | | 6,877 | | |
Revenue payable
|
| | | | 11,786 | | | | | | 7,974 | | |
Derivatives
|
| | | | 8,284 | | | | | | — | | |
Total current liabilities
|
| | | | 47,127 | | | | | | 31,574 | | |
Long-term liabilities: | | | | | | | | | | | | | |
Brix credit facility
|
| | | | 121,760 | | | | | | 120,470 | | |
Asset retirement obligations
|
| | | | 888 | | | | | | 627 | | |
Derivatives
|
| | | | 5,453 | | | | | | — | | |
Refundable deposits
|
| | | | 2,784 | | | | | | 2,727 | | |
Total liabilities
|
| | | | 178,012 | | | | | | 155,398 | | |
Commitments and contingencies
|
| | | | | | | | | | | | |
Partners’ capital
|
| | | | 155,275 | | | | | | 162,443 | | |
Total liabilities and partners’ capital
|
| | | $ | 333,287 | | | | | $ | 317,841 | | |
|
Balance at December 31, 2018
|
| | | $ | 123,540 | | |
|
Equity-based compensation
|
| | | | 889 | | |
|
Net income
|
| | | | 38,014 | | |
|
Balance at December 31, 2019
|
| | | $ | 162,443 | | |
|
Equity-based compensation
|
| | | | 1,635 | | |
|
Net income
|
| | | | (8,803) | | |
|
Balance at December 31, 2020
|
| | | $ | 155,275 | | |
| | |
For the Year Ended December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Operating Activities | | | | | | | | | | | | | |
Net income
|
| | | $ | (8,803) | | | | | $ | 38,014 | | |
Adjustments to reconcile net income to operating cash flow:
|
| | | | | | | | | | | | |
Depletion, depreciation and accretion
|
| | | | 92,177 | | | | | | 65,901 | | |
Amortization of financing costs
|
| | | | 1,412 | | | | | | 1,191 | | |
Equity-based compensation
|
| | | | 1,635 | | | | | | 889 | | |
Unrealized loss (gain) on commodity derivatives
|
| | | | 40,475 | | | | | | (25,610) | | |
Changes in assets and liabilities:
|
| | | | | | | | | | | | |
Accounts receivable
|
| | | | (10,783) | | | | | | (7,842) | | |
Joint interest billing receivables
|
| | | | (1,333) | | | | | | (2,327) | | |
Accounts payable and accrued expenses
|
| | | | 6,492 | | | | | | 2,816 | | |
Revenue payable
|
| | | | 5,962 | | | | | | 3,358 | | |
Other
|
| | | | 27 | | | | | | 150 | | |
Operating cash flow
|
| | | | 127,261 | | | | | | 76,540 | | |
Investing Activities
|
| | | | | | | | | | | | |
Proceeds from asset sales
|
| | | | — | | | | | | 1,832 | | |
Capital expenditures
|
| | | | (113,479) | | | | | | (150,956) | | |
Investing cash flow
|
| | | | (113,479) | | | | | | (149,124) | | |
Financing Activities
|
| | | | | | | | | | | | |
Proceeds from Brix credit facility
|
| | | | — | | | | | | 76,000 | | |
Deferred financing costs paid
|
| | | | (133) | | | | | | (3,698) | | |
Financing cash flow
|
| | | | (133) | | | | | | 72,302 | | |
Net increase (decrease) in cash and cash equivalents
|
| | | | 13,649 | | | | | | (282) | | |
Cash and cash equivalents at beginning of period
|
| | | | 4,011 | | | | | | 4,293 | | |
Cash and cash equivalents at end of period
|
| | | $ | 17,660 | | | | | $ | 4,011 | | |
Supplemental information
|
| | | | | | | | | | | | |
Cash paid for interest
|
| | | $ | 10,516 | | | | | $ | 8,502 | | |
Non-cash transactions
|
| | | | | | | | | | | | |
Accrued capital expenditures
|
| | | $ | 10,456 | | | | | $ | 15,637 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Proved natural gas properties subject to depletion
|
| | | $ | 463,045 | | | | | $ | 353,492 | | |
Unproved natural gas properties
|
| | | | — | | | | | | 1,061 | | |
Total capitalized costs
|
| | | | 463,045 | | | | | | 354,553 | | |
Less: Accumulated depletion
|
| | | | (191,837) | | | | | | (99,727) | | |
Natural gas properties, net
|
| | | $ | 271,208 | | | | | $ | 254,826 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Balance, beginning of period
|
| | | $ | 627 | | | | | $ | 397 | | |
Liabilities incurred
|
| | | | 185 | | | | | | 154 | | |
Acquired liabilities
|
| | | | — | | | | | | 33 | | |
Accretion expense
|
| | | | 76 | | | | | | 43 | | |
Balance, end of period
|
| | | $ | 888 | | | | | $ | 627 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Brix Credit facility, face amount
|
| | | $ | 125,000 | | | | | | 125,000 | | |
Net deferred finance costs
|
| | | | (3,240) | | | | | | (4,530) | | |
Total Brix Credit facility
|
| | | | 121,760 | | | | | | 120,470 | | |
Less: short-term portion
|
| | | | — | | | | | | — | | |
Total Brix Credit facility
|
| | | $ | 121,760 | | | | | $ | 120,470 | | |
| | |
Balance Sheet
Classification |
| |
Gross
Amounts |
| |
Netting Adjustment
|
| |
Net Amounts
Presented on the Balance Sheet |
| |||||||||
December 31, 2020 | | | | | | | | | | | | | | | | | | | | | | |
Assets:
|
| | | | | | | | | | | | | | | | | | | | | |
Current assets
|
| | | | | | $ | 3,125 | | | | | | (3,125) | | | | | $ | — | | |
Noncurrent assets
|
| | | | | | | 1,001 | | | | | | (1,001) | | | | | | — | | |
Total assets
|
| | | | | | $ | 4,126 | | | | | $ | (4,126) | | | | | $ | — | | |
Liabilities:
|
| | | | | | | | | | | | | | | | | | | | | |
Current liabilities
|
| | | | | | $ | 11,409 | | | | | $ | (3,125) | | | | | $ | 8,284 | | |
Noncurrent liabilities
|
| | | | | | | 6,454 | | | | | | (1,001) | | | | | | 5,453 | | |
Total liabilities
|
| | | | | | $ | 17,863 | | | | | $ | (4,126) | | | | | $ | 13,737 | | |
December 31, 2019 | | | | | | | | | | | | | | | | | | | | | | |
Assets:
|
| | | | | | | | | | | | | | | | | | | | | |
Current assets
|
| | | | | | $ | 25,307 | | | | | $ | — | | | | | $ | 25,307 | | |
Noncurrent assets
|
| | | | | | | 3,325 | | | | | | (1,894) | | | | | | 1,431 | | |
Total assets
|
| | | | | | $ | 28,632 | | | | | $ | (1,894) | | | | | $ | 26,738 | | |
Liabilities:
|
| | | | | | | | | | | | | | | | | | | | | |
Current liabilities
|
| | | | | | $ | — | | | | | $ | — | | | | | $ | — | | |
Noncurrent liabilities
|
| | | | | | | 1,894 | | | | | | (1,894) | | | | | | — | | |
Total liabilities
|
| | | | | | $ | 1,894 | | | | | $ | (1.894) | | | | | $ | — | | |
Natural Gas Swaps
|
| |||||||||||||||
| | |
Production Year
|
| |
Average Daily
Volumes (MMBtu) |
| |
Weighted
Average Swap Price ($/MMBtu) |
| ||||||
2021
|
| | | | | | | 216,019 | | | | | $ | 2.54 | | |
2022
|
| | | | | | | 173,582 | | | | | $ | 2.54 | | |
2023
|
| | | | | | | 51,140 | | | | | $ | 2.43 | | |
2024
|
| | | | | | | 3,357 | | | | | $ | 2.43 | | |
Sold Natural Gas Calls
|
| |||||||||||||||
| | |
Production Year
|
| |
Average Daily
Volumes (MMBtu) |
| |
Weighted
Average Call Price ($/MMBtu) |
| ||||||
2021
|
| | | | | | | 2,041 | | | | | $ | 3.20 | | |
| | |
Brix Class A Units
|
| |||||||||||||||
|
Equity-based
Compensation Awards |
| |
Profit-Sharing
Arrangement |
| |
Total
|
| |||||||||||
Outstanding at December 31, 2018
|
| | | | 40.0 | | | | | | 51.0 | | | | | | 91.0 | | |
Granted
|
| | | | — | | | | | | 9.0 | | | | | | 9.0 | | |
Forfeited
|
| | | | — | | | | | | — | | | | | | — | | |
Outstanding at December 31, 2019
|
| | | | 40.0 | | | | | | 60.0 | | | | | | 100.0 | | |
Granted
|
| | | | — | | | | | | 2.0 | | | | | | 2.0 | | |
Forfeited
|
| | | | — | | | | | | (6.0) | | | | | | (6.0) | | |
Outstanding at December 31, 2020
|
| | | | 40.0 | | | | | | 56.0 | | | | | | 96.0 | | |
|
Balance at December 31, 2018
|
| | | | 402,175 | | |
|
Production
|
| | | | (52,503) | | |
|
Revision of previous estimates(1)
|
| | | | (75,082) | | |
|
Acquisitions of reserves(2)
|
| | | | 862 | | |
|
Extensions and discoveries(3)
|
| | | | 376,742 | | |
|
Balance at December 31, 2019
|
| | | | 652,194 | | |
|
Production
|
| | | | (85,641) | | |
|
Revision of previous estimates(4)
|
| | | | (287,359) | | |
|
Acquisitions of reserves(5)
|
| | | | 51,224 | | |
|
Extensions and discoveries(6)
|
| | | | 180,963 | | |
|
Balance at December 31, 2020
|
| | | | 511,381 | | |
| Proved developed reserves at: | | | | | | | |
|
December 31, 2018
|
| | | | 63,715 | | |
|
December 31, 2019
|
| | | | 138,258 | | |
|
December 31, 2020
|
| | | | 143,917 | | |
| Proved undeveloped reserves at: | | | | | | | |
|
December 31, 2018
|
| | | | 338,460 | | |
|
December 31, 2019
|
| | | | 513,936 | | |
|
December 31, 2020
|
| | | | 367,464 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Proved natural gas properties subject to depletion
|
| | | $ | 463,045 | | | | | $ | 353,492 | | |
Unproved natural gas properties
|
| | | | — | | | | | | 1,061 | | |
Total capitalized costs
|
| | | | 463,045 | | | | | | 354,553 | | |
Less: Accumulated depletion
|
| | | | (191,837) | | | | | | (99,727) | | |
Natural gas properties, net
|
| | | $ | 271,208 | | | | | $ | 254,826 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Proved acreage
|
| | | $ | 2,545 | | | | | $ | 2,748 | | |
Unproved acreage
|
| | | | — | | | | | | 3,229 | | |
Development costs
|
| | | | 105,701 | | | | | | 141,429 | | |
Total
|
| | | $ | 108,246 | | | | | $ | 147,406 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Future natural gas sales
|
| | | $ | 882,384 | | | | | $ | 1,509,782 | | |
Future production costs
|
| | | | (322,655) | | | | | | (453,796) | | |
Future development costs(1)
|
| | | | (303,403) | | | | | | (591,976) | | |
Future income tax expense(2)
|
| | | | — | | | | | | — | | |
Future net cash flows
|
| | | $ | 256,326 | | | | | $ | 464,010 | | |
10% annual discount
|
| | | | (78,744) | | | | | | (164,539) | | |
Standardized measure of discounted future net cash flows
|
| | | $ | 177,582 | | | | | $ | 299,471 | | |
| | |
December 31,
|
| |||||||||
|
2020
|
| |
2019
|
| ||||||||
Balance at beginning of period(2)
|
| | | $ | 299,471 | | | | | $ | 214,405 | | |
Sales of natural gas, net(3)
|
| | | | (106,633) | | | | | | (87,167) | | |
Revision of previous quantity estimates and extensions
|
| | | | (6,968) | | | | | | 87,554 | | |
Acquisitions of reserves
|
| | | | 10,965 | | | | | | 1,293 | | |
Previously estimated development costs incurred
|
| | | | 57,863 | | | | | | 81,841 | | |
Net changes in future development costs
|
| | | | 14,020 | | | | | | 60,882 | | |
Net changes in prices
|
| | | | (126,299) | | | | | | (78,163) | | |
Accretion of discount
|
| | | | 29,947 | | | | | | 21,440 | | |
Net change in income taxes(2)
|
| | | | — | | | | | | — | | |
Changes in timing and other differences
|
| | | | 5,216 | | | | | | (2,614) | | |
Balance at end of period(1)
|
| | | $ | 177,582 | | | | | $ | 299,471 | | |
| | |
December 31,
2020 |
| |
December 31,
2019 |
| ||||||
Assets | | | | | | | | | | | | | |
Total assets
|
| | | $ | — | | | | | $ | — | | |
Stockholders’ equity | | | | | | | | | | | | | |
Notes receivable from Vine Investment LLC
|
| | | $ | (10) | | | | | $ | (10) | | |
Common stock, $0.01 par value; authorized 1,000 shares; 1,000 issued and outstanding at December 31, 2020 and December 31, 2019
|
| | | $ | 10 | | | | | $ | 10 | | |
Total stockholders’ equity
|
| | | $ | — | | | | | $ | — | | |
| Citigroup | | |
Credit Suisse
|
| |
Morgan Stanley
|
|
| Barclays | | |
BofA Securities
|
| |
RBC Capital Markets
|
|
|
Blackstone
|
| |||||||||
| Capital One Securities | | |
KeyBanc Capital Markets
|
| | MUFG | | |||
|
CastleOak Securities, L.P.
|
| |
Drexel Hamilton
|
| |
Ramirez & Co., Inc.
|
| |
Stern
|
|
|
Delaware
|
| |
81-4833927
|
|
|
(State or other jurisdiction of
incorporation) |
| |
(IRS Employer
Identification No.) |
|
|
5800 Granite Parkway, Suite 550
Plano, Texas 75024 |
| |
75024 |
|
|
(Address of principal executive offices)
|
| |
(Zip Code)
|
|
|
Title of each class
|
| |
Trading Symbol(s)
|
| |
Name of each exchange on which registered
|
|
|
Class A Common Stock, par value $0.01 per share
|
| |
VEI
|
| |
NYSE
|
|
|
Large accelerated filer
☐
|
| |
Accelerated filer
☐
|
|
|
Non-accelerated filer
☒
|
| |
Smaller reporting company
☐
|
|
| | | |
Emerging growth company
☐
|
|
|
Part I — Financial Information
|
| ||||||
| | | | | F-4 | | | |
| | | | | F-4 | | | |
| | | | | F-5 | | | |
| | | | | F-6 | | | |
| | | | | F-7 | | | |
| | | | | F-8 | | | |
| | | | | F-25 | | | |
| | | | | F-38 | | | |
| | | | | F-39 | | | |
|
Part II — Other Information
|
| ||||||
| | | | | F-41 | | | |
| | | | | F-41 | | | |
| | | | | F-41 | | | |
| | | | | F-41 | | | |
| | | | | F-41 | | | |
| | | | | F-41 | | | |
| | | | | F-41 | | | |
| | | | | F-43 | | |
| | |
For the Three Months Ended June 30,
|
| |
For the Six Months Ended June 30,
|
| ||||||||||||||||||
|
2021
|
| |
2020
|
| |
2021
|
| |
2020
|
| ||||||||||||||
Revenue: | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas sales
|
| | | $ | 233,851 | | | | | $ | 84,116 | | | | | $ | 387,837 | | | | | $ | 176,659 | | |
Realized (loss) gain on commodity derivatives
|
| | | | (24,022) | | | | | | 45,686 | | | | | | (24,782) | | | | | | 87,730 | | |
Unrealized loss on commodity derivatives
|
| | | | (274,279) | | | | | | (58,727) | | | | | | (309,382) | | | | | | (63,366) | | |
Total revenue
|
| | | | (64,450) | | | | | | 71,075 | | | | | | 53,673 | | | | | | 201,023 | | |
Operating Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | |
Lease operating
|
| | | | 16,522 | | | | | | 11,477 | | | | | | 31,482 | | | | | | 24,472 | | |
Gathering and treating
|
| | | | 28,750 | | | | | | 20,387 | | | | | | 49,351 | | | | | | 36,769 | | |
Production and ad valorem taxes
|
| | | | 6,018 | | | | | | 4,286 | | | | | | 10,000 | | | | | | 8,435 | | |
General and administrative
|
| | | | 4,772 | | | | | | 1,349 | | | | | | 7,355 | | | | | | 4,680 | | |
Monitoring fee
|
| | | | — | | | | | | 1,787 | | | | | | 2,077 | | | | | | 3,525 | | |
Stock-based compensation for Existing Management Owners
|
| | | | 13,665 | | | | | | — | | | | | | 13,665 | | | | | | — | | |
Depletion, depreciation and accretion
|
| | | | 125,125 | | | | | | 85,610 | | | | | | 222,197 | | | | | | 167,934 | | |
Exploration
|
| | | | 89 | | | | | | 60 | | | | | | 89 | | | | | | 135 | | |
Strategic
|
| | | | — | | | | | | 1,551 | | | | | | — | | | | | | 2,113 | | |
Severance
|
| | | | — | | | | | | 326 | | | | | | — | | | | | | 326 | | |
Write-offof deferred offering costs
|
| | | | — | | | | | | — | | | | | | — | | | | | | 5,787 | | |
Total operating expenses
|
| | | | 194,941 | | | | | | 126,833 | | | | | | 336,216 | | | | | | 254,176 | | |
Operating Income
|
| | | | (259,391) | | | | | | (55,758) | | | | | | (282,543) | | | | | | (53,153) | | |
Interest Expense: | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest
|
| | | | (23,317) | | | | | | (28,713) | | | | | | (53,110) | | | | | | (58,064) | | |
Loss on extinguishment of debt
|
| | | | (73,089) | | | | | | — | | | | | | (77,971) | | | | | | — | | |
Total interest expense
|
| | | | (96,406) | | | | | | (28,713) | | | | | | (131,081) | | | | | | (58,064) | | |
Income before income taxes
|
| | | | (355,797) | | | | | | (84,471) | | | | | | (413,624) | | | | | | (111,217) | | |
Income tax provision
|
| | | | (4,455) | | | | | | (100) | | | | | | (4,620) | | | | | | (250) | | |
Net income
|
| | | $ | (360,252) | | | | | $ | (84,571) | | | | | $ | (418,244) | | | | | $ | (111,467) | | |
Net income attributable to Predecessor
|
| | | $ | — | | | | | | | | | | | $ | (28,939) | | | | | | | | |
Net income attributable to noncontrolling interest
|
| | | $ | (161,888) | | | | | | | | | | | $ | (175,032) | | | | | | | | |
Net income attributable to Vine Energy Inc.
|
| | | $ | (198,364) | | | | | | | | | | | $ | (214,273) | | | | | | | | |
Net income per share attributable to Vine Energy Inc.:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Basic
|
| | | $ | (4.83) | | | | | | | | | | | $ | (9.46) | | | | | | | | |
Diluted
|
| | | $ | (4.83) | | | | | | | | | | | $ | (9.46) | | | | | | | | |
Weighted average shares outstanding: | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic
|
| | | | 41,040,721 | | | | | | | | | | | | 22,638,796 | | | | | | | | |
Diluted
|
| | | | 41,040,721 | | | | | | | | | | | | 22,638,796 | | | | | | | | |
| | |
June 30, 2021
|
| |
December 31, 2020
|
| ||||||
Assets | | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | |
Cash and cash equivalents
|
| | | $ | 54,988 | | | | | $ | 15,517 | | |
Accounts receivable
|
| | | | 116,304 | | | | | | 77,129 | | |
Joint interest billing receivables
|
| | | | 16,765 | | | | | | 18,280 | | |
Prepaid and other
|
| | | | 7,282 | | | | | | 3,626 | | |
Total current assets
|
| | | | 195,339 | | | | | | 114,552 | | |
Natural gas properties (successful efforts): | | | | | | | | | | | | | |
Proved
|
| | | | 3,247,470 | | | | | | 2,722,419 | | |
Unproved
|
| | | | 89,993 | | | | | | — | | |
Accumulated depletion
|
| | | | (1,598,983) | | | | | | (1,380,065) | | |
Total natural gas properties, net
|
| | | | 1,738,480 | | | | | | 1,342,354 | | |
Other property and equipment, net
|
| | | | 11,722 | | | | | | 7,936 | | |
Operating leaseright-of-useassets
|
| | | | 15,631 | | | | | | — | | |
Other
|
| | | | 11,172 | | | | | | 2,921 | | |
Total assets
|
| | | $ | 1,972,344 | | | | | $ | 1,467,763 | | |
Liabilities and Stockholders’ Equity / Partners’ Capital | | | | | | | | | | | | | |
Current liabilities: | | | | | | | | | | | | | |
Accounts payable
|
| | | $ | 6,854 | | | | | $ | 20,986 | | |
Accrued liabilities
|
| | | | 111,929 | | | | | | 90,004 | | |
Revenue payable
|
| | | | 51,678 | | | | | | 37,552 | | |
Operating leases
|
| | | | 9,503 | | | | | | — | | |
Derivatives
|
| | | | 270,853 | | | | | | 19,948 | | |
Total current liabilities
|
| | | | 450,817 | | | | | | 168,490 | | |
Long-term liabilities: | | | | | | | | | | | | | |
New RBL
|
| | | | 35,000 | | | | | | — | | |
Prior RBL
|
| | | | — | | | | | | 183,569 | | |
Second lien credit facility
|
| | | | 144,507 | | | | | | 142,947 | | |
Unsecured debt
|
| | | | 930,476 | | | | | | 898,225 | | |
Asset retirement obligations
|
| | | | 24,104 | | | | | | 21,889 | | |
TRA liability
|
| | | | 6,985 | | | | | | — | | |
Operating leases
|
| | | | 6,128 | | | | | | — | | |
Derivatives
|
| | | | 113,402 | | | | | | 38,341 | | |
Other
|
| | | | — | | | | | | 4,241 | | |
Total liabilities
|
| | | | 1,711,419 | | | | | | 1,457,702 | | |
Commitments and contingencies | | | | | | | | | | | | | |
Stockholders’ Equity / Partners’ Capital | | | | | | | | | | | | | |
Partners’ capital
|
| | | | — | | | | | | 10,061 | | |
Class A common stock, $0.01 par value, 350,000,000 shares authorized, 41,040,721 outstanding at June 30, 2021
|
| | | | 410 | | | | | | — | | |
Class B common stock, $0.01 par value, 150,000,000 shares authorized, 34,218,535 outstanding at June 30, 2021
|
| | | | 342 | | | | | | — | | |
Additionalpaid-incapital
|
| | | | 355,321 | | | | | | — | | |
Retained earnings
|
| | | | (214,273) | | | | | | — | | |
Total stockholders’ equity attributable to Vine Energy Inc.
|
| | | | 141,800 | | | | | | 10,061 | | |
Non-controlling interest
|
| | | | 119,125 | | | | | | — | | |
Total stockholders’ equity / partners’ capital
|
| | | | 260,925 | | | | | | 10,061 | | |
Total liabilities and stockholders’ equity / partners’ capital
|
| | | $ | 1,972,344 | | | | | $ | 1,467,763 | | |
| | |
Partners’
Capital |
| |
Class A
Common Stock |
| |
Class B
Common Stock |
| |
APIC
|
| |
Retained
Earnings |
| |
Total
stockholders’ equity attributable to Vine Energy Inc. |
| |
Non-
controlling Interest |
| |
Total
stockholders’ equity / partners’ capital |
| ||||||||||||||||||||||||||||||||||||
|
Shares
|
| |
Amount
|
| |
Shares
|
| |
Amount
|
| ||||||||||||||||||||||||||||||||||||||||||||||||||
Balance – December 31, 2019
|
| | | $ | 462,517 | | | | | | — | | | | | $ | — | | | | | | — | | | | | $ | — | | | | | $ | — | | | | | $ | (170,262) | | | | | $ | 292,255 | | | | | $ | — | | | | | $ | 292,255 | | |
Net income attributable to Predecessor
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (26,896) | | | | | | (26,896) | | | | | | — | | | | | | (26,896) | | |
Balance – March 31, 2020
|
| | | | 462,517 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (197,158) | | | | | | 265,359 | | | | | | — | | | | | | 265,359 | | |
Net income attributable to Predecessor
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (84,571) | | | | | | (84,571) | | | | | | — | | | | | | (84,571) | | |
Balance – June 30, 2020
|
| | | $ | 462,517 | | | | | | — | | | | | $ | — | | | | | | — | | | | | $ | — | | | | | $ | — | | | | | $ | (281,729) | | | | | $ | 180,788 | | | | | $ | — | | | | | $ | 180,788 | | |
Balance – December 31, 2020
|
| | | $ | 432,517 | | | | | | — | | | | | $ | — | | | | | | — | | | | | $ | — | | | | | $ | — | | | | | $ | (422,456) | | | | | $ | 10,061 | | | | | $ | — | | | | | $ | 10,061 | | |
Net income attributable to Predecessor
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (28,939) | | | | | | (28,939) | | | | | | — | | | | | | (28,939) | | |
Balance prior to Corporate Reorganization and Offering
|
| | | | 432,517 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (451,395) | | | | | | (18,878) | | | | | | — | | | | | | (18,878) | | |
Equity issued in Brix Companies acquisition
|
| | | | — | | | | | | 6,740 | | | | | | 67 | | | | | | 16,832 | | | | | | 168 | | | | | | 329,770 | | | | | | — | | | | | | 330,005 | | | | | | — | | | | | | 330,005 | | |
Reclassification of refundable deposits
|
| | | | 6,706 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 6,706 | | | | | | — | | | | | | 6,706 | | |
Predecessor conversion for Class A Common Stock and Class B Common Stock
|
| | | | (439,223) | | | | | | 9,576 | | | | | | 96 | | | | | | 17,387 | | | | | | 174 | | | | | | (12,442) | | | | | | 451,395 | | | | | | — | | | | | | — | | | | | | — | | |
Issuance of Class A Common Stock in Offering, net of fees
|
| | | | — | | | | | | 24,725 | | | | | | 247 | | | | | | — | | | | | | — | | | | | | 321,724 | | | | | | — | | | | | | 321,971 | | | | | | — | | | | | | 321,971 | | |
Initial allocation of non-controlling interest in Vine Holdings
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (290,646) | | | | | | — | | | | | | (290,646) | | | | | | 290,646 | | | | | | — | | |
Net income attributable to shareholders
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (15,909) | | | | | | (15,909) | | | | | | (13,144) | | | | | | (29,053) | | |
Balance – March 31, 2021
|
| | | | — | | | | | | 41,041 | | | | | | 410 | | | | | | 34,219 | | | | | | 342 | | | | | | 348,406 | | | | | | (15,909) | | | | | | 333,249 | | | | | | 277,502 | | | | | | 610,751 | | |
Offering costs
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (532) | | | | | | — | | | | | | (532) | | | | | | (444) | | | | | | (976) | | |
Distribution to Existing Owners
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (2,263) | | | | | | (2,263) | | |
Stock-based compensation for Existing Management Owners
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 7,447 | | | | | | — | | | | | | 7,447 | | | | | | 6,218 | | | | | | 13,665 | | |
Net income attributable to shareholders
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (198,364) | | | | | | (198,364) | | | | | | (161,888) | | | | | | (360,252) | | |
Balance – June 30, 2021
|
| | | $ | — | | | | | | 41,041 | | | | | $ | 410 | | | | | | 34,219 | | | | | $ | 342 | | | | | $ | 355,321 | | | | | $ | (214,273) | | | | | $ | 141,800 | | | | | $ | 119,125 | | | | | $ | 260,925 | | |
| | |
For the Six
Months Ended June 30, |
| |||||||||
|
2021
|
| |
2020
|
| ||||||||
Operating Activities
|
| | | | | | | | | | | | |
Net income
|
| | | $ | (418,244) | | | | | $ | (111,467) | | |
Adjustments to reconcile net income to operating cash flow:
|
| | | | | | | | | | | | |
Depletion, depreciation and accretion
|
| | | | 222,197 | | | | | | 167,934 | | |
Amortization of financing costs and debt discount
|
| | | | 5,128 | | | | | | 8,802 | | |
Non-cashloss on extinguishment of debt
|
| | | | 15,398 | | | | | | — | | |
Cash redemption premiums on extinguishment of debt
|
| | | | 62,573 | | | | | | — | | |
Non-cashwrite-offof deferred offering costs
|
| | | | — | | | | | | 5,787 | | |
Non-cashstock-based compensation
|
| | | | 13,665 | | | | | | — | | |
Unrealized loss on commodity derivatives
|
| | | | 309,382 | | | | | | 63,366 | | |
Volumetric and production adjustment to gas gathering liability
|
| | | | — | | | | | | (2,567) | | |
Other
|
| | | | 131 | | | | | | (2) | | |
Changes in assets and liabilities:
|
| | | | | | | | | | | | |
Accounts receivable
|
| | | | 1,049 | | | | | | 9,582 | | |
Joint interest billing receivables
|
| | | | 5,798 | | | | | | (5,010) | | |
Accounts payable and accrued liabilities
|
| | | | (5,579) | | | | | | 5,806 | | |
Revenue payable
|
| | | | 154 | | | | | | (7,576) | | |
Other
|
| | | | (5,632) | | | | | | 1,599 | | |
Operating cash flow
|
| | | | 206,020 | | | | | | 136,254 | | |
Investing Activities | | | | | | | | | | | | | |
Cash received in acquisition of the Brix Companies
|
| | | | 19,858 | | | | | | — | | |
Capital expenditures
|
| | | | (171,387) | | | | | | (161,903) | | |
Investing cash flow
|
| | | | (151,529) | | | | | | (161,903) | | |
Financing Activities | | | | | | | | | | | | | |
Repayment of Brix Credit Facility
|
| | | | (127,500) | | | | | | — | | |
Proceeds from New RBL
|
| | | | 73,000 | | | | | | — | | |
Repayment of New RBL
|
| | | | (38,000) | | | | | | — | | |
(Repayment) proceeds of Prior RBL
|
| | | | (190,000) | | | | | | 75,000 | | |
Proceeds from 6.75% Notes
|
| | | | 950,000 | | | | | | — | | |
Repayment of unsecured notes, including redemption premiums
|
| | | | (972,573) | | | | | | — | | |
Proceeds from issuance of Class A common stock, net of fees
|
| | | | 320,995 | | | | | | — | | |
Deferred financing costs
|
| | | | (28,679) | | | | | | (4,220) | | |
Distribution for tax to Existing Owners
|
| | | | (2,263) | | | | | | — | | |
Financing cash flow
|
| | | | (15,020) | | | | | | 70,780 | | |
Net increase in cash and cash equivalents
|
| | | | 39,471 | | | | | | 45,131 | | |
Cash and cash equivalents at beginning of period
|
| | | | 15,517 | | | | | | 18,286 | | |
Cash and cash equivalents at end of period
|
| | | $ | 54,988 | | | | | $ | 63,417 | | |
Non-cashinvesting and financing transactions: | | | | | | | | | | | | | |
Accrued capital expenditures
|
| | | $ | 34,730 | | | | | $ | 9,590 | | |
Acquisition of the Brix Companies
|
| | | $ | 336,990 | | | | | $ | — | | |
| | |
Preliminary Acquisition
Consideration |
| |||
Vine Units issued for acquisition of the Brix Companies
|
| | | | 23,571,754 | | |
Offering price of Class A Common Stock
|
| | | $ | 14.00 | | |
Total equity issued in acquisition
|
| | | $ | 330,005 | | |
Contingent consideration(1)
|
| | | | 6,985 | | |
Total acquisition consideration
|
| | | $ | 336,990 | | |
| Assets Acquired: | | | | | | | |
|
Cash and cash equivalents
|
| | | $ | 19,858 | | |
|
Accounts receivable
|
| | | | 30,472 | | |
|
Joint interest billing receivables
|
| | | | 4,283 | | |
|
Proved properties
|
| | | | 361,439 | | |
|
Unproved properties
|
| | | | 89,993 | | |
|
Total assets to be acquired
|
| | | $ | 506,045 | | |
| Liabilities Assumed: | | | | | | | |
|
Accounts payable
|
| | | $ | 2,123 | | |
|
Accrued liabilities
|
| | | | 5,847 | | |
|
Revenue payable
|
| | | | 13,384 | | |
|
Derivatives
|
| | | | 16,583 | | |
|
Brix Credit Facility(1)
|
| | | | 127,500 | | |
|
Asset retirement obligations
|
| | | | 984 | | |
|
Refundable deposits
|
| | | | 2,634 | | |
|
Total liabilities to be assumed
|
| | | | 169,055 | | |
|
Net assets to be acquired
|
| | | $ | 336,990 | | |
| | |
For the
Three Months Ended June 30, 2020 |
| |
For the Six Months Ended June 30,
|
| ||||||||||||
|
2021
|
| |
2020
|
| ||||||||||||||
Total revenue
|
| | | $ | 97,660 | | | | | $ | 96,180 | | | | | $ | 278,824 | | |
Net income attributable to Vine Energy, Inc.
|
| | | $ | (42,969) | | | | | $ | (216,964) | | | | | $ | (40,361) | | |
| | |
June 30, 2021
|
| |
December 31, 2020
|
| ||||||
Capital expenditures
|
| | | $ | 27,489 | | | | | $ | 20,808 | | |
Operating expenses
|
| | | | 37,769 | | | | | | 30,547 | | |
Royalty owner suspense
|
| | | | 10,750 | | | | | | 7,891 | | |
Compensation-related
|
| | | | 6,986 | | | | | | 9,432 | | |
Interest expense
|
| | | | 14,868 | | | | | | 17,848 | | |
IPO and financing costs
|
| | | | — | | | | | | 1,875 | | |
Settled derivatives
|
| | | | 11,616 | | | | | | 1,603 | | |
Other
|
| | | | 2,451 | | | | | | — | | |
Accrued expenses
|
| | | $ | 111,929 | | | | | $ | 90,004 | | |
| | |
June 30, 2021
|
| |
December 31, 2020
|
| ||||||
Face amount:
|
| | | | | | | | | | | | |
New RBL
|
| | | $ | 35,000 | | | | | $ | — | | |
Prior RBL
|
| | | | — | | | | | | 190,000 | | |
Second Lien Term Loan
|
| | | | 150,000 | | | | | | 150,000 | | |
6.75% Senior Notes
|
| | | | 950,000 | | | | | | — | | |
8.75% Senior Notes
|
| | | | — | | | | | | 530,000 | | |
9.75% Senior Notes
|
| | | | — | | | | | | 380,000 | | |
Total face amount
|
| | | | 1,135,000 | | | | | | 1,250,000 | | |
Deferred financing costs and discount:
|
| | | | | | | | | | | | |
Prior RBL
|
| | | | — | | | | | | (6,431) | | |
Second Lien Term Loan
|
| | | | (5,493) | | | | | | (7,053) | | |
6.75% Senior Notes
|
| | | | (19,524) | | | | | | — | | |
8.75% Senior Notes
|
| | | | — | | | | | | (7,821) | | |
9.75% Senior Notes
|
| | | | — | | | | | | (3,954) | | |
Total deferred financing costs
|
| | | | (25,017) | | | | | | (25,259) | | |
Total debt
|
| | | | 1,109,983 | | | | | | 1,224,741 | | |
Less: short-term portion
|
| | | | — | | | | | | — | | |
Total long-term debt
|
| | | $ | 1,109,983 | | | | | $ | 1,224,741 | | |
| | |
Balance Sheet
Classification |
| |
Fair Value
|
| |
Netting Adjustment
|
| |
Net Fair Value
Presented on the Balance Sheet |
| |||||||||
June 30, 2021 | | | | | | | | | | | | | | | | | | | | | | |
Assets:
|
| | | | | | | | | | | | | | | | | | | | | |
Commodity Derivatives
|
| | Current assets | | | | $ | 6,211 | | | | | $ | (6,211) | | | | | $ | — | | |
Commodity Derivatives
|
| | Noncurrent assets | | | | $ | 171 | | | | | $ | (171) | | | | | $ | — | | |
Liabilities:
|
| | | | | | | | | | | | | | | | | | | | | |
Commodity Derivatives
|
| | Current liabilities | | | | $ | 277,064 | | | | | $ | (6,211) | | | | | $ | 270,853 | | |
Commodity Derivatives
|
| |
Noncurrent liabilities
|
| | | $ | 113,573 | | | | | $ | (171) | | | | | $ | 113,402 | | |
December 31, 2020 | | | | | | | | | | | | | | | | | | | | | | |
Assets:
|
| | | | | | | | | | | | | | | | | | | | | |
Commodity Derivatives
|
| | Current assets | | | | $ | 9,095 | | | | | $ | (9,095) | | | | | $ | — | | |
Commodity Derivatives
|
| | Noncurrent assets | | | | $ | 2,742 | | | | | $ | (2,742) | | | | | $ | — | | |
Liabilities:
|
| | | | | | | | | | | | | | | | | | | | | |
Commodity Derivatives
|
| | Current liabilities | | | | $ | 29,043 | | | | | $ | (9,095) | | | | | $ | 19,948 | | |
Commodity Derivatives
|
| |
Noncurrent liabilities
|
| | | $ | 41,083 | | | | | $ | (2,742) | | | | | $ | 38,341 | | |
Natural Gas Swaps
|
| |||||||||||||||
| | |
Production
Year |
| |
Natural Gas Volumes
(MMBtud) |
| |
Weighted Average
Swap Price ($ / MMBtu) |
| ||||||
2021 (July – December)
|
| | | | | | | 847,110 | | | | | $ | 2.57 | | |
2022
|
| | | | | | | 556,489 | | | | | $ | 2.54 | | |
2023
|
| | | | | | | 189,788 | | | | | $ | 2.48 | | |
2024
|
| | | | | | | 100,561 | | | | | $ | 2.53 | | |
2025
|
| | | | | | | 33,945 | | | | | $ | 2.58 | | |
Sold Natural Gas Calls
|
| |||||||||||||||
| | |
Production
Year |
| |
Natural Gas Volumes
(MMBtud) |
| |
Weighted
Average Call Price ($ / MMBtu) |
| ||||||
2021 (July – December)
|
| | | | | | | (15,000) | | | | | $ | 2.85 | | |
2022
|
| | | | | | | (2,082) | | | | | $ | 3.02 | | |
2023
|
| | | | | | | (44,384) | | | | | $ | 3.26 | | |
Sold Natural Gas Puts
|
| |||||||||||||||
| | |
Production
Year |
| |
Natural Gas Volumes
(MMBtud) |
| |
Weighted
Average Put Price ($ / MMBtu) |
| ||||||
2021 (July – December)
|
| | | | | | | 15,000 | | | | | $ | 2.55 | | |
2022
|
| | | | | | | 2,082 | | | | | $ | 2.80 | | |
Basis swaps
|
| |||||||||||||||
| | |
Production Year
|
| |
Natural Gas Volumes
(MMBtud) |
| |
Weighted
Average Basis Swap ($/ MMBtu) |
| ||||||
2022
|
| | | | | | | 62,500 | | | | | $ | (0.19) | | |
|
Balance as of January 1, 2021
|
| | | $ | 9,566 | | |
|
Liabilities assumed in exchange for newright-of-useassets(1)
|
| | | | 7,811 | | |
|
Contract modifications(2)
|
| | | | 5,853 | | |
|
Dispositions(3)
|
| | | | (1,626) | | |
|
Liabilities settled
|
| | | | (6,227) | | |
|
Accretion of discount(4)
|
| | | | 254 | | |
|
Balance as of June 30, 2021
|
| | | $ | 15,631 | | |
|
2021 (July – December)
|
| | | $ | 9,897 | | |
|
2022
|
| | | | 5,836 | | |
|
2023
|
| | | | 381 | | |
|
2024 and thereafter
|
| | | | — | | |
|
Total operating lease payments
|
| | | | 16,114 | | |
|
Discount
|
| | | | (483) | | |
|
Total operating lease obligations
|
| | | $ | 15,631 | | |
| | |
Three Months Ended
June 30, 2021 |
| |
Six Months Ended
June 30, 2021 |
| ||||||
Operating lease cost(1)
|
| | | $ | 3,211 | | | | | $ | 5,973 | | |
Short-term lease cost(2)
|
| | | | 1,683 | | | | | | 3,600 | | |
Variable lease cost(3)
|
| | | | 2,470 | | | | | | 3,534 | | |
Total operating lease cost
|
| | | $ | 7,364 | | | | | $ | 13,107 | | |
| | |
For the Three Months
Ended June 30, |
| |
For the Six Months
Ended June 30 |
| ||||||||||||||||||
|
2021
|
| |
2020
|
| |
2021
|
| |
2020
|
| ||||||||||||||
|
($ / MMBtu)
|
| |
($ / MMBtu)
|
| ||||||||||||||||||||
NYMEX Henry Hub High(1)
|
| | | $ | 2.98 | | | | | $ | 1.79 | | | | | $ | 2.98 | | | | | $ | 2.16 | | |
NYMEX Henry Hub Low(1)
|
| | | $ | 2.59 | | | | | $ | 1.63 | | | | | $ | 2.47 | | | | | $ | 1.63 | | |
Differential to Average NYMEX Henry Hub(2)
|
| | | $ | (0.20) | | | | | $ | (0.17) | | | | | $ | (0.15) | | | | | $ | (0.17) | | |
| | |
For the Three Months Ended June 30,
|
| |
For the Six Months Ended June 30,
|
| ||||||||||||||||||||||||||||||||||||||||||
|
2021
|
| |
2020
|
| |
2021
|
| |
2020
|
| ||||||||||||||||||||||||||||||||||||||
|
(in thousands, except per Mcf)
|
| |
(in thousands, except per Mcf)
|
| ||||||||||||||||||||||||||||||||||||||||||||
Production: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total (MMcf)
|
| | | | 95,561 | | | | | | | | | | | | 59,441 | | | | | | | | | | | | 160,699 | | | | | | | | | | | | 116,087 | | | | | | | | |
Average Daily (MMcfd)
|
| | | | 1,050 | | | | | | | | | | | | 653 | | | | | | | | | | | | 888 | | | | | | | | | | | | 638 | | | | | | | | |
Revenue: | | | | | | | | |
Per Mcf
|
| | | | | | | |
Per Mcf
|
| | | | | | | |
Per Mcf
|
| | | | | | | |
Per Mcf
|
| ||||||||||||
Natural gas sales
|
| | | $ | 233,851 | | | | | $ | 2.45 | | | | | $ | 84,116 | | | | | $ | 1.42 | | | | | $ | 387,837 | | | | | $ | 2.41 | | | | | $ | 176,659 | | | | | $ | 1.52 | | |
Realized gain on commodity derivatives
|
| | | | (24,022) | | | | | | (0.25) | | | | | | 45,686 | | | | | | 0.77 | | | | | | (24,782) | | | | | | (0.15) | | | | | | 87,730 | | | | | | 0.76 | | |
Unrealized (loss) gain on commodity derivatives
|
| | | | (274,279) | | | | | | (2.87) | | | | | | (58,727) | | | | | | (0.99) | | | | | | (309,382) | | | | | | (1.93) | | | | | | (63,366) | | | | | | (0.55) | | |
Total revenue
|
| | | | (64,450) | | | | | | (0.67) | | | | | | 71,075 | | | | | | 1.20 | | | | | | 53,673 | | | | | | 0.33 | | | | | | 201,023 | | | | | | 1.73 | | |
Operating Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Lease operating
|
| | | | 16,522 | | | | | | 0.17 | | | | | | 11,477 | | | | | | 0.19 | | | | | | 31,482 | | | | | | 0.20 | | | | | | 24,472 | | | | | | 0.21 | | |
Gathering and treating
|
| | | | 28,750 | | | | | | 0.30 | | | | | | 20,387 | | | | | | 0.34 | | | | | | 49,351 | | | | | | 0.31 | | | | | | 36,769 | | | | | | 0.32 | | |
Production and ad valorem taxes
|
| | | | 6,018 | | | | | | 0.06 | | | | | | 4,286 | | | | | | 0.07 | | | | | | 10,000 | | | | | | 0.06 | | | | | | 8,435 | | | | | | 0.07 | | |
General and administrative
|
| | | | 4,772 | | | | | | 0.05 | | | | | | 1,349 | | | | | | 0.02 | | | | | | 7,355 | | | | | | 0.05 | | | | | | 4,680 | | | | | | 0.04 | | |
Monitoring fee
|
| | | | — | | | | | | — | | | | | | 1,787 | | | | | | 0.03 | | | | | | 2,077 | | | | | | 0.01 | | | | | | 3,525 | | | | | | 0.03 | | |
Stock-based compensation related to Offering
|
| | | | 13,665 | | | | | | 0.14 | | | | | | — | | | | | | — | | | | | | 13,665 | | | | | | 0.09 | | | | | | — | | | | | | — | | |
Depreciation, depletion and accretion
|
| | | | 125,125 | | | | | | 1.31 | | | | | | 85,610 | | | | | | 1.44 | | | | | | 222,197 | | | | | | 1.38 | | | | | | 167,934 | | | | | | 1.45 | | |
Exploration
|
| | | | 89 | | | | | | 0.00 | | | | | | 60 | | | | | | 0.00 | | | | | | 89 | | | | | | 0.00 | | | | | | 135 | | | | | | 0.00 | | |
Strategic
|
| | | | — | | | | | | — | | | | | | 1,551 | | | | | | 0.03 | | | | | | — | | | | | | — | | | | | | 2,113 | | | | | | 0.02 | | |
Severance
|
| | | | — | | | | | | — | | | | | | 326 | | | | | | 0.01 | | | | | | — | | | | | | — | | | | | | 326 | | | | | | 0.00 | | |
Write-offof deferred offering costs
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 5,787 | | | | | | 0.05 | | |
Total operating expenses
|
| | | | 194,941 | | | | | | 2.04 | | | | | | 126,833 | | | | | | 2.13 | | | | | | 336,216 | | | | | | 2.09 | | | | | | 254,176 | | | | | | 2.19 | | |
Operating income
|
| | | | (259,391) | | | | | | | | | | | | (55,758) | | | | | | | | | | | | (282,543) | | | | | | | | | | | | (53,153) | | | | | | | | |
Interest expense
|
| | | | (96,406) | | | | | | | | | | | | (28,713) | | | | | | | | | | | | (131,081) | | | | | | | | | | | | (58,064) | | | | | | | | |
Income tax provision
|
| | | | (4,455) | | | | | | | | | | | | (100) | | | | | | | | | | | | (4,620) | | | | | | | | | | | | (250) | | | | | | | | |
Total other expenses
|
| | | | (100,861) | | | | | | | | | | | | (28,813) | | | | | | | | | | | | (135,701) | | | | | | | | | | | | (58,314) | | | | | | | | |
Net income
|
| | | $ | (360,252) | | | | | | | | | | | $ | (84,571) | | | | | | | | | | | $ | (418,244) | | | | | | | | | | | $ | (111,467) | | | | | | | | |
Interest expense
|
| | | | 96,406 | | | | | | | | | | | | 28,713 | | | | | | | | | | | | 131,081 | | | | | | | | | | | | 58,064 | | | | | | | | |
Income tax provision
|
| | | | 4,455 | | | | | | | | | | | | 100 | | | | | | | | | | | | 4,620 | | | | | | | | | | | | 250 | | | | | | | | |
Depreciation, depletion and accretion
|
| | | | 125,125 | | | | | | | | | | | | 85,610 | | | | | | | | | | | | 222,197 | | | | | | | | | | | | 167,934 | | | | | | | | |
| | |
For the Three Months Ended June 30,
|
| |
For the Six Months Ended June 30,
|
| ||||||||||||||||||||||||||||||
|
2021
|
| |
2020
|
| |
2021
|
| |
2020
|
| ||||||||||||||||||||||||||
|
(in thousands, except per Mcf)
|
| |
(in thousands, except per Mcf)
|
| ||||||||||||||||||||||||||||||||
Unrealized loss on commodity
derivatives |
| | | | 274,279 | | | | | | | | | 58,727 | | | | | | | | | 309,382 | | | | | | | | | 63,366 | | | | | |
Exploration
|
| | | | 89 | | | | | | | | | 60 | | | | | | | | | 89 | | | | | | | | | 135 | | | | | |
Non-cash G&A
|
| | | | 98 | | | | | | | | | 4 | | | | | | | | | 97 | | | | | | | | | (2) | | | | | |
Non-cashstock compensation to Existing Management Owners
|
| | | | 13,665 | | | | | | | | | — | | | | | | | | | 13,665 | | | | | | | | | — | | | | | |
Strategic
|
| | | | — | | | | | | | | | 1,551 | | | | | | | | | — | | | | | | | | | 2,113 | | | | | |
Severance
|
| | | | — | | | | | | | | | 326 | | | | | | | | | — | | | | | | | | | 326 | | | | | |
Non-cashwrite-off of deferred IPO costs
|
| | | | — | | | | | | | | | — | | | | | | | | | — | | | | | | | | | 5,787 | | | | | |
Non-cash volumetric and production adjustment to gas gathering liability
|
| | | | — | | | | | | | | | — | | | | | | | | | — | | | | | | | | | (2,567) | | | | | |
Adjusted EBITDAX
|
| | | $ | 153,865 | | | | | | | | $ | 90,520 | | | | | | | | $ | 262,887 | | | | | | | | $ | 183,939 | | | | | |
|
|
Three months ended June 30, 2020
|
| | | $ | 129,802 | | |
|
Volume
|
| | | | 51,114 | | |
|
Price
|
| | | | 98,621 | | |
|
Realized derivative
|
| | | | (69,708) | | |
|
Three months ended June 30, 2021
|
| | | $ | 209,829 | | |
|
Six months ended June 30, 2020
|
| | | $ | 264,389 | | |
|
Volume
|
| | | | 67,890 | | |
|
Price
|
| | | | 143,288 | | |
|
Realized derivative
|
| | | | (112,512) | | |
|
Six months ended June 30, 2021
|
| | | $ | 363,055 | | |
| | |
For the Three Months Ended June 30,
|
| |
For the Six Months Ended June 30,
|
| ||||||||||||||||||||||||||||||||||||||||||
|
2021
|
| |
2020
|
| |
2021
|
| |
2020
|
| ||||||||||||||||||||||||||||||||||||||
|
(in thousands)
|
| |
Per Mcf
|
| |
(in thousands)
|
| |
Per Mcf
|
| |
(in thousands)
|
| |
Per Mcf
|
| |
(in thousands)
|
| |
Per Mcf
|
| ||||||||||||||||||||||||||
Gathering – Cash
|
| | | $ | 27,674 | | | | | $ | 0.29 | | | | | $ | 20,195 | | | | | $ | 0.34 | | | | | $ | 48,009 | | | | | $ | 0.30 | | | | | $ | 38,923 | | | | | $ | 0.34 | | |
Gathering – Non-Cash
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (2,567) | | | | | | (0.02) | | |
Other
|
| | | | 1,076 | | | | | | 0.01 | | | | | | 192 | | | | | | 0.00 | | | | | | 1,342 | | | | | | 0.01 | | | | | | 413 | | | | | | — | | |
Total
|
| | | $ | 28,750 | | | | | $ | 0.30 | | | | | $ | 20,387 | | | | | $ | 0.34 | | | | | $ | 49,351 | | | | | $ | 0.31 | | | | | $ | 36,769 | | | | | $ | 0.32 | | |
| | |
For the Three Months Ended June 30,
|
| |
For the Six Months Ended June 30,
|
| ||||||||||||||||||||||||||||||||||||||||||
|
2021
|
| |
2020
|
| |
2021
|
| |
2020
|
| ||||||||||||||||||||||||||||||||||||||
|
(in thousands)
|
| |
Per Mcf
|
| |
(in thousands)
|
| |
Per Mcf
|
| |
(in thousands)
|
| |
Per Mcf
|
| |
(in thousands)
|
| |
Per Mcf
|
| ||||||||||||||||||||||||||
Production taxes
|
| | | $ | 4,211 | | | | | $ | 0.04 | | | | | $ | 2,871 | | | | | $ | 0.05 | | | | | $ | 6,576 | | | | | $ | 0.04 | | | | | $ | 5,604 | | | | | $ | 0.05 | | |
Ad valorem taxes
|
| | | | 1,807 | | | | | | 0.02 | | | | | | 1,415 | | | | | | 0.02 | | | | | | 3,424 | | | | | | 0.02 | | | | | | 2,831 | | | | | | 0.02 | | |
Total
|
| | | $ | 6,018 | | | | | $ | 0.06 | | | | | $ | 4,286 | | | | | $ | 0.07 | | | | | $ | 10,000 | | | | | $ | 0.06 | | | | | $ | 8,435 | | | | | $ | 0.07 | | |
| | |
For the Three Months Ended
June 30, |
| |
For the Six Months Ended
June 30, |
| ||||||||||||||||||
|
2021
|
| |
2020
|
| |
2021
|
| |
2020
|
| ||||||||||||||
|
(in thousands)
|
| |
(in thousands)
|
| ||||||||||||||||||||
Wages and benefits
|
| | | $ | 7,081 | | | | | $ | 5,947 | | | | | $ | 13,304 | | | | | $ | 13,009 | | |
Professional services
|
| | | | 1,256 | | | | | | 660 | | | | | | 2,347 | | | | | | 1,689 | | |
Licenses, fees and other
|
| | | | 1,517 | | | | | | 1,699 | | | | | | 3,259 | | | | | | 3,764 | | |
Total gross G&A expense
|
| | | | 9,854 | | | | | | 8,306 | | | | | | 18,910 | | | | | | 18,462 | | |
Less: | | | | | | | | | | | | | | | | | | | | | | | | | |
Allocations to affiliates
|
| | | | — | | | | | | (2,248) | | | | | | (1,748) | | | | | | (4,517) | | |
Recoveries
|
| | | | (5,082) | | | | | | (4,709) | | | | | | (9,807) | | | | | | (9,265) | | |
Net G&A expense
|
| | | $ | 4,772 | | | | | $ | 1,349 | | | | | $ | 7,355 | | | | | $ | 4,680 | | |
| | |
For the Three Months Ended June 30,
|
| |
For the Six Months Ended June 30,
|
| ||||||||||||||||||||||||||||||||||||||||||
|
2021
|
| |
2020
|
| |
2021
|
| |
2020
|
| ||||||||||||||||||||||||||||||||||||||
|
(in thousands)
|
| |
Per Mcf
|
| |
(in thousands)
|
| |
Per Mcf
|
| |
(in thousands)
|
| |
Per Mcf
|
| |
(in
|
| |
Per Mcf
|
| ||||||||||||||||||||||||||
Depletion
|
| | | $ | 123,402 | | | | | $ | 1.29 | | | | | $ | 84,008 | | | | | $ | 1.41 | | | | | $ | 218,918 | | | | | $ | 1.36 | | | | | $ | 164,067 | | | | | $ | 1.41 | | |
Depreciation
|
| | | | 1,329 | | | | | | 0.01 | | | | | | 1,269 | | | | | | 0.02 | | | | | | 2,524 | | | | | | 0.02 | | | | | | 2,689 | | | | | | 0.02 | | |
Accretion
|
| | | | 394 | | | | | | 0.00 | | | | | | 333 | | | | | | 0.01 | | | | | | 755 | | | | | | 0.00 | | | | | | 1,178 | | | | | | 0.01 | | |
Total
|
| | | $ | 125,125 | | | | | $ | 1.31 | | | | | $ | 85,610 | | | | | $ | 1.44 | | | | | $ | 222,197 | | | | | $ | 1.38 | | | | | $ | 167,934 | | | | | $ | 1.45 | | |
| | |
For the Three Months Ended June 30,
|
| |
For the Six Months Ended June 30,
|
| ||||||||||||||||||
|
2021
|
| |
2020
|
| |
2021
|
| |
2020
|
| ||||||||||||||
|
(in thousands)
|
| |||||||||||||||||||||||
Cash interest: | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest costs on debt outstanding
|
| | | $ | 20,836 | | | | | $ | 23,876 | | | | | $ | 47,007 | | | | | $ | 48,492 | | |
Cash premiums on extinguishment of debt
|
| | | | 62,573 | | | | | | — | | | | | | 62,573 | | | | | | — | | |
Letter of credit and other fees
|
| | | | 375 | | | | | | 396 | | | | | | 974 | | | | | | 770 | | |
Total cash interest
|
| | | | 83,784 | | | | | | 24,272 | | | | | | 110,554 | | | | | | 49,262 | | |
Non-cashinterest: | | | | | | | | | | | | | | | | | | | | | | | | | |
Non-cashinterest on debt
outstanding |
| | | | 2,106 | | | | | | 4,441 | | | | | | 5,129 | | | | | | 8,802 | | |
Non-cashloss on extinguishment
of debt |
| | | | 10,516 | | | | | | — | | | | | | 15,398 | | | | | | — | | |
Totalnon-cashinterest
|
| | | | 12,622 | | | | | | 4,441 | | | | | | 20,527 | | | | | | 8,802 | | |
Total interest expense
|
| | | $ | 96,406 | | | | | $ | 28,713 | | | | | $ | 131,081 | | | | | $ | 58,064 | | |
| | |
For the Six Months Ended June 30,
|
| |||||||||
|
2021
|
| |
2020
|
| ||||||||
Operating cash flow
|
| | | | 206,020 | | | | | $ | 136,254 | | |
Investing cash flow
|
| | | | (151,529) | | | | | | (161,903) | | |
Financing cash flow
|
| | | | (15,020) | | | | | | 70,780 | | |
Net change in cash
|
| | | $ | 39,471 | | | | | $ | 45,131 | | |
Natural Gas Swaps
|
| |||||||||||||||
| | |
Period
|
| |
Natural Gas
Volumes (MMBtud) |
| |
Weighted Average
Swap Price ($ / MMBtu) |
| ||||||
2021 | | | | | | | | | | | | | | | | |
Third Quarter
|
| | | | | | | 845,333 | | | | | $ | 2.53 | | |
Fourth Quarter
|
| | | | | | | 848,887 | | | | | $ | 2.62 | | |
2022 | | | | | | | | | | | | | | | | |
First Quarter
|
| | | | | | | 866,797 | | | | | $ | 2.56 | | |
Second Quarter
|
| | | | | | | 348,859 | | | | | $ | 2.54 | | |
Third Quarter
|
| | | | | | | 409,853 | | | | | $ | 2.54 | | |
Fourth Quarter
|
| | | | | | | 604,935 | | | | | $ | 2.53 | | |
2023 | | | | | | | | | | | | | | | | |
First Quarter
|
| | | | | | | 528,652 | | | | | $ | 2.48 | | |
Second Quarter
|
| | | | | | | 65,470 | | | | | $ | 2.45 | | |
Third Quarter
|
| | | | | | | 45,954 | | | | | $ | 2.44 | | |
Fourth Quarter
|
| | | | | | | 125,092 | | | | | $ | 2.50 | | |
2024 | | | | | | | | | | | | | | | | |
First Quarter
|
| | | | | | | 313,512 | | | | | $ | 2.53 | | |
Second Quarter
|
| | | | | | | 11,957 | | | | | $ | 2.31 | | |
Third Quarter
|
| | | | | | | 7,366 | | | | | $ | 2.31 | | |
Fourth Quarter
|
| | | | | | | 70,761 | | | | | $ | 2.58 | | |
2025 | | | | | | | | | | | | | | | | |
First Quarter
|
| | | | | | | 137,667 | | | | | $ | 2.58 | | |
Sold Natural Gas Calls
|
| |||||||||
| | |
Production
Year |
| |
Natural Gas
Volumes (MMBtud) |
| |
Weighted Average
Call Price ($ / MMBtu) |
|
2021 | | | | | | | | | | |
Sold Natural Gas Calls
|
| |||||||||||||||
| | |
Production
Year |
| |
Natural Gas
Volumes (MMBtud) |
| |
Weighted Average
Call Price ($ / MMBtu) |
| ||||||
Third Quarter
|
| | | | | | | (30,000) | | | | | $ | 2.85 | | |
2022 | | | | | | | | | | | | | | | | |
Second Quarter
|
| | | | | | | (8,352) | | | | | $ | 3.02 | | |
2023 | | | | | | | | | | | | | | | | |
First Quarter
|
| | | | | | | (180,000) | | | | | $ | 3.26 | | |
Sold Natural Gas Puts
|
| |||||||||||||||
| | |
Production
Year |
| |
Natural Gas
Volumes (MMBtud) |
| |
Weighted Average
Put Price ($ / MMBtu) |
| ||||||
2021 | | | | | | | | | | | | | | | | |
Third Quarter
|
| | | | | | | 30,000 | | | | | $ | 2.55 | | |
2022 | | | | | | | | | | | | | | | | |
Second Quarter
|
| | | | | | | 8,352 | | | | | $ | 2.80 | | |
Basis swaps
|
| |||||||||||||||
| | |
Production
Year |
| |
Natural Gas
Volumes (MMBtud) |
| |
Weighted Average
Basis Swap ($ / MMBtu) |
| ||||||
2022 | | | | | | | | | | | | | | | | |
First Quarter
|
| | | | | | | 62,500 | | | | | $ | (0.19) | | |
Second Quarter
|
| | | | | | | 62,500 | | | | | $ | (0.19) | | |
Third Quarter
|
| | | | | | | 62,500 | | | | | $ | (0.19) | | |
Fourth Quarter
|
| | | | | | | 62,500 | | | | | $ | (0.19) | | |
| | |
Highest Priority
New RBL |
| |
Second Lien Term Loan
|
| |
Lowest Priority
6.75% (Unsecured) |
|
Face amount
|
| |
$750 million
|
| |
$150 million
|
| |
$950 million
|
|
Amount outstanding
|
| |
$35 million
|
| |
$150 million
|
| |
$950 million
|
|
Scheduled maturity date
|
| |
December 2024, or 91 days prior to the maturity of the Second Lien Term Loan, to the extent any of such indebtedness remains outstanding
|
| |
December 2025
|
| |
April 2029
|
|
| | |
Highest Priority
New RBL |
| |
Second Lien Term Loan
|
| |
Lowest Priority
6.75% (Unsecured) |
|
Interest rate
|
| |
LIBOR + 3.0 – 4.0%
|
| |
LIBOR + 8.75%
|
| |
6.75%
|
|
Base interest rate options
|
| |
ABR and LIBOR (with a floor of 0.50)% + spread
|
| |
ABR and LIBOR (with a floor of 0.75)% + spread
|
| |
N/A
|
|
Financial maintenance covenants
|
| |
– Maximum
consolidated total net leverage ratio of 3.25x effective April 2021
– Maximum Current Ratio of 1.00x effective April 2021
– Minimum hedging requirements |
| |
– Maximum consolidated total net leverage ratio of 4.0x decreasing to 3.5x effective April 2021
–Minimum liquidity of $40 million tested quarterly – Minimum hedging requirements |
| |
N/A
|
|
Significant restrictive covenants
|
| |
– Incurrence of debt
|
| |
– Incurrence of debt
|
| |
– Incurrence of debt
|
|
| | |
– Incurrence of liens
|
| |
– Incurrence of liens
|
| |
– Incurrence of liens
|
|
| | |
– Payment of dividends
|
| |
– Payment of dividends
|
| |
– Payment of dividends
|
|
| | |
– Equity purchases
|
| |
– Equity purchases
|
| |
– Equity purchases
|
|
| | |
– Asset sales
|
| |
– Asset sales
|
| |
– Asset sales
|
|
| | |
– Limitations on derivatives & investments
|
| |
– Limitations on derivatives & investments
|
| |
– Limitations on ability to make investments
|
|
| | |
– Affiliate transactions
|
| |
– Affiliate transactions
|
| |
– Affiliate transactions
|
|
| | | | | |
– Excess cash cap
|
| |
– Restricted payments
– Limitations on Guarantees by Restricted Subsidiaries |
|
Optional redemption
|
| |
Any time at par
|
| |
Make-whole through June 2022; 102% through June 2023; 101% through June 2024; thereafter at par
|
| |
Make-whole through April 2024. After April 2024 through April 2025 at 103.375%; thereafter through April 2026 at 101.688%; thereafter at par.
|
|
Change of control
|
| |
Event of default
|
| |
Event of default
|
| |
If accompanied by Ratings Decline, Investor put at 101% of par
|
|
Exhibit No.
|
| |
Description
|
|
2.1
|
| | Agreement and Plan of Merger by and among Chesapeake Energy Corporation, Hannibal Merger Sub, Inc., Hannibal Merger Sub, LLC, Vine Energy, Inc. and Vine Energy Holdings, LLC., dated as of August 10, 2021 (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, File No. 001-40239, filed with the Commission on August 11, 2021). | |
3.1
|
| | Amended and Restated Certificate of Incorporation of Vine Energy Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, File No. 001-40239, filed with the Commission on March 23, 2021). | |
3.2
|
| | Amended and Restated Bylaws of Vine Energy Inc. (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K, File No. 001-40239, filed with the Commission on March 23, 2021). | |
10.1
|
| | Amendment No. 2 to Second Lien Credit Agreement, dated June 29, 2021, by and among Vine Holdings, the several lenders from time to time party thereto and Morgan Stanley Senior Funding as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-40239, filed with the Commission on July 1, 2021). | |
10.2
|
| | Employment Agreement, dated as of June 28, 2021, with Eric D. Marsh (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 001-40239, filed with the Commission on July 1, 2021). | |
10.3
|
| | Employment Agreement, dated as of June 28, 2021, with David M. Elkin (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, | |
Exhibit No.
|
| |
Description
|
|
| | | File No. 001-40239, filed with the Commission on July 1, 2021). | |
10.4
|
| | Employment Agreement, dated as of June 28, 2021, with Wayne B. Stoltenberg (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K, File No. 001-40239, filed with the Commission on July 1, 2021). | |
10.5
|
| | Employment Agreement, dated as of June 28, 2021, with Jonathan C. Curth (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K, File No. 001-40239, filed with the Commission on July 1, 2021). | |
10.6
|
| | Merger Support Agreement, dated August 10, 2021 by and among Chesapeake Energy Corporation, Hannibal Merger Sub, Inc., Hannibal Merger Sub, LLC, Vine Energy, Inc. and the stockholders of Vine Energy, Inc. listed thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-40239, filed with the Commission on August 11, 2021). | |
10.7
|
| | Tax Receivable Agreement Amendment, dated August 10, 2021 by and among Vine Energy Inc., Vine Investment LLC, Vine Investment II LLC, Brix Investment LLC, Brix Investment II LLC, Harvest Investment LLC and Harvest Investment II LLC (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 001-40239, filed with the Commission on August 11, 2021). | |
31.1(a)
|
| | Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002. | |
31.2(a)
|
| | Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002. | |
32.1(b)
|
| | Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002. | |
32.2(b)
|
| | Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002. | |
101.INS(a)
|
| | Inline XBRL Instance Document — the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | |
101.SCH(a)
|
| | Inline XBRL Taxonomy Extension Schema Document. | |
101.CAL(a)
|
| | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | |
101.DEF(a)
|
| | Inline XBRL Taxonomy Extension Definition Linkbase Document. | |
101.LAB(a)
|
| | Inline XBRL Taxonomy Extension Label Linkbase Document. | |
101.PRE(a)
|
| | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | |
104
|
| | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | |
| | | | Vine Energy Inc. | |
| Date: August 13, 2021 | | |
By:
/s/ Brian D. Dutton
|
|
| | | |
Name:
Brian D. Dutton
|
|
| | | |
Title:
Vice President, Chief Accounting Officer and Principal Accounting Officer
|
|
| Date: August 13, 2021 | | |
/s/ Eric D. Marsh
|
|
| | | |
Eric D. Marsh
President, Chief Executive Officer and Chairman of the Board of Directors |
|
| Date: August 13, 2021 | | |
/s/ Wayne B. Stoltenberg
|
|
| | | |
Wayne B. Stoltenberg
Executive Vice President, Chief Financial Officer |
|
| Date: August 13, 2021 | | |
/s/ Eric D. Marsh
|
|
| | | |
Eric D. Marsh
President, Chief Executive Officer and Chairman of the Board of Directors
|
|
| Date: August 13, 2021 | | |
/s/ Wayne B. Stoltenberg
|
|
| | | |
Wayne B. Stoltenberg
Executive Vice President, Chief Financial Officer
|
|
| | | |
Re: Vine Oil & Gas LP.
Haynesville and Mid-Bossier Shale
Properties
Estimate of Reserves and Revenues
SEC Pricing Case
“As of” January 1, 2020
|
|
| | |
Net to Vine Oil & Gas, LP.
|
| |||||||||||||||||||||||||||||||||
| | |
Proved Developed
|
| |
Proved
|
| |
Total
|
| |
Probable
|
| |
Possible
|
| |||||||||||||||||||||
SEC Price Case
|
| |
Producing
|
| |
Non-
producing |
| |
Undeveloped
|
| |
Proved
|
| |
Undeveloped
|
| |
Undeveloped
|
| ||||||||||||||||||
Reserve Estimates | | ||||||||||||||||||||||||||||||||||||
Gas, MMcf
|
| | | | 434,553.6 | | | | | | 13,412.9 | | | | | | 1,761,866.4 | | | | | | 2,209,832.9 | | | | | | 3,585,932.5 | | | | | | 455,783.0 | | |
Revenues | | ||||||||||||||||||||||||||||||||||||
Gas, $(100) %
|
| | | | 1,005,587,136 | | | | | | 31,038,456 | | | | | | 4,077,082,880 | | | | | | 5,113,708,472 | | | | | | 8,298,100,736 | | | | | | 1,054,713,664 | | |
Total, $
|
| | | | 1,005,587,136 | | | | | | 31,038,456 | | | | | | 4,077,082,880 | | | | | | 5,113,708,472 | | | | | | 8,298,100,736 | | | | | | 1,054,713,664 | | |
Expenditures | | ||||||||||||||||||||||||||||||||||||
Ad Valorem Taxes, $
|
| | | | 43,132,376 | | | | | | 332,923 | | | | | | 68,662,264 | | | | | | 112,127,563 | | | | | | 147,227,456 | | | | | | 18,798,350 | | |
Severance
Taxes, $ |
| | | | 36,076,216 | | | | | | 727,024 | | | | | | 89,775,016 | | | | | | 126,578,256 | | | | | | 181,460,800 | | | | | | 23,061,818 | | |
Fixed Operating Expense, $
|
| | | | 261,286,896 | | | | | | 5,222,728 | | | | | | 743,078,400 | | | | | | 1,009,588,024 | | | | | | 1,519,582,464 | | | | | | 195,046,976 | | |
Variable Operating
Expense, $ |
| | | | 40,776,016 | | | | | | 1,211,969 | | | | | | 168,430,256 | | | | | | 210,418,241 | | | | | | 341,251,008 | | | | | | 43,811,632 | | |
Marketing and Fuel, $
|
| | | | 41,201,796 | | | | | | 1,217,321 | | | | | | 169,281,488 | | | | | | 211,700,605 | | | | | | 343,777,504 | | | | | | 44,083,980 | | |
Total, $
|
| | | | 422,473,300 | | | | | | 8,711,965 | | | | | | 1,239,227,424 | | | | | | 1,670,412,689 | | | | | | 2,533,299,232 | | | | | | 324,802,756 | | |
Investments, $
|
| | | | 8,444,488 | | | | | | 111,533 | | | | | | 1,726,457,434 | | | | | | 1,735,013,455 | | | | | | 3,860,688,702 | | | | | | 488,419,967 | | |
Plugging & Abandonment, $
|
| | | | 31,252,760 | | | | | | 2,101,943 | | | | | | 18,887,590 | | | | | | 52,242,293 | | | | | | 42,175,170 | | | | | | 5,386,753 | | |
Total, $
|
| | | | 39,697,248 | | | | | | 2,213,476 | | | | | | 1,745,345,024 | | | | | | 1,787,255,748 | | | | | | 3,902,863,872 | | | | | | 493,806,720 | | |
| | |
Net to Vine Oil & Gas, LP.
|
| |||||||||||||||||||||||||||||||||
| | |
Proved Developed
|
| |
Proved
|
| |
Total
|
| |
Probable
|
| |
Possible
|
| |||||||||||||||||||||
SEC Price Case
|
| |
Producing
|
| |
Non-
producing |
| |
Undeveloped
|
| |
Proved
|
| |
Undeveloped
|
| |
Undeveloped
|
| ||||||||||||||||||
Estimated Future Net Revenues (FNR) | | ||||||||||||||||||||||||||||||||||||
Undiscounted
FNR, $ |
| | | | 543,416,704 | | | | | | 20,113,016 | | | | | | 1,092,510,976 | | | | | | 1,656,040,696 | | | | | | 1,861,936,768 | | | | | | 236,104,368 | | |
FNR Disc.
@ 10.0%, $ |
| | | | 443,546,080 | | | | | | 16,853,644 | | | | | | 527,767,168 | | | | | | 988,166,892 | | | | | | 441,079,488 | | | | | | 37,430,740 | | |
Allocation Percentage by Classification | | ||||||||||||||||||||||||||||||||||||
FNR Disc. @ 10.0%
|
| | | | 44.9% | | | | | | 1.7% | | | | | | 53.4% | | | | | | 100.0% | | | | | | 100.0% | | | | | | 100.0% | | |
|
|
![]() |
| |
Respectfully submitted,
![]()
William D. Von Gonten, Jr., P.E.
TX # 73244
![]()
John M. Parker
|
|
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
Reserves | | | Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. | | | Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests. | |
On Production | | | The development project is currently producing and selling petroleum to market. | | | The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project. | |
Approved for Development | | | All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way. | | | At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity’s current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells. | |
Justified for Development | | | Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained. | | | In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/contracts, there should be no known contingencies that could | |
Class/Sub-Class
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| |
Definition
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| |
Guidelines
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|
| | | | | | preclude the development from proceeding within a reasonable timeframe (see Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time. | |
Contingent Resources | | | Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies. | | | Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. | |
Development Pending | | | A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future. | | | The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status. The project “decision gate” is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production. | |
Development Unclarified or on Hold | | | A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay. | | | The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to “Not Viable” status. The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the | |
Class/Sub-Class
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| |
Definition
|
| |
Guidelines
|
|
| | | | | | potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies. | |
Development Not Viable | | | A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential. | | | The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project “decision gate” is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future. | |
Prospective Resources | | | Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. | | | Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration. | |
Prospect | | | A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. | | | Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program. | |
Lead | | | A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios. | |
Play | | | A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios. | |
Status
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Definition
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Guidelines
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Developed Reserves
|
| | Developed Reserves are expected quantities to be recovered from existing wells and facilities. | | | Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed | |
Status
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Definition
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Guidelines
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| | | | | | Reserves may be further sub-classified as Producing or Non-Producing. | |
Developed Producing Reserves | | | Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. | | | Improved recovery reserves are considered producing only after the improved recovery project is in operation. | |
Developed Non-Producing Reserves | | | Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. | | | Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. | |
Undeveloped Reserves | | | Undeveloped Reserves are quantities expected to be recovered through future investments: | | | (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. | |
Category
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Definition
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Guidelines
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|
Proved Reserves | | | Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. | | | If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance | |
Category
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Definition
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Guidelines
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| | | | | |
data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved provided that:
•
The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive.
•
Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.
|
|
Probable Reserves | | | Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. | | | It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved. | |
Possible Reserves | | | Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves. | | | The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with | |
Category
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| |
Definition
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| |
Guidelines
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| | | | | | project recovery efficiencies beyond that assumed for Probable. | |
Probable and Possible Reserves | | | (See above for separate criteria for Probable Reserves and Possible Reserves.) | | | The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations. | |
| | | |
Re: Vine Oil & Gas LP
Haynesville and Mid-Bossier Shale
Properties
Estimate of Reserves and Revenues
SEC Pricing Case
“As of” January 1, 2021
|
|
| | |
Net to Vine Oil & Gas LP
|
| |||||||||||||||||||||||||||||||||
| | |
Proved Developed
|
| |
Proved
|
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Total
|
| |
Probable
|
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Possible
|
| |||||||||||||||||||||
SEC Price Case
|
| |
Producing
|
| |
Non-
producing |
| |
Undeveloped
|
| |
Proved
|
| |
Undeveloped
|
| |
Undeveloped
|
| ||||||||||||||||||
Reserve Estimates | | ||||||||||||||||||||||||||||||||||||
Gas, MMcf
|
| | | | 437,756.4 | | | | | | 8,485.7 | | | | | | 1,355,875.1 | | | | | | 1,802,117.2 | | | | | | 1,878,219.6 | | | | | | 150,972.4 | | |
Revenues | | ||||||||||||||||||||||||||||||||||||
Gas, $(100) %
|
| | | | 760,383,104 | | | | | | 14,739,606 | | | | | | 2,355,154,176 | | | | | | 3,130,276,886 | | | | | | 3,262,467,584 | | | | | | 262,239,184 | | |
Total, $
|
| | | | 760,383,104 | | | | | | 14,739,606 | | | | | | 2,355,154,176 | | | | | | 3,130,276,886 | | | | | | 3,262,467,584 | | | | | | 262,239,184 | | |
Expenditures | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Ad Valorem Taxes, $
|
| | | | 31,689,016 | | | | | | 626,227 | | | | | | 41,923,000 | | | | | | 74,238,243 | | | | | | 49,325,208 | | | | | | 4,236,572 | | |
Severance Taxes, $
|
| | | | 21,696,768 | | | | | | 430,582 | | | | | | 30,457,046 | | | | | | 52,584,396 | | | | | | 38,253,848 | | | | | | 3,271,543 | | |
Fixed Operating Expense, $
|
| | | | 224,559,488 | | | | | | 4,184,106 | | | | | | 524,486,336 | | | | | | 753,229,930 | | | | | | 719,396,800 | | | | | | 57,641,524 | | |
Variable Operating Expense, $
|
| | | | 39,028,728 | | | | | | 666,073 | | | | | | 121,299,584 | | | | | | 160,994,385 | | | | | | 166,659,760 | | | | | | 13,297,100 | | |
Marketing and
Fuel, $ |
| | | | 32,035,368 | | | | | | 543,351 | | | | | | 99,497,088 | | | | | | 132,075,807 | | | | | | 137,142,576 | | | | | | 10,862,164 | | |
Total, $
|
| | | | 349,009,368 | | | | | | 6,450,339 | | | | | | 817,663,054 | | | | | | 1,173,122,761 | | | | | | 1,110,778,192 | | | | | | 89,308,903 | | |
Investments, $
|
| | | | 12,979,499 | | | | | | 2,636,706 | | | | | | 1,045,537,294 | | | | | | 1,061,153,499 | | | | | | 1,619,001,559 | | | | | | 130,132,597 | | |
Plugging &
Abandonment, $ |
| | | | 29,266,153 | | | | | | 2,028,948 | | | | | | 10,884,210 | | | | | | 42,179,311 | | | | | | 16,334,505 | | | | | | 1,280,427 | | |
Total, $
|
| | | | 42,245,652 | | | | | | 4,665,654 | | | | | | 1,056,421,504 | | | | | | 1,103,332,810 | | | | | | 1,635,336,064 | | | | | | 131,413,024 | | |
Estimated Future Net Revenues (FNR) | | ||||||||||||||||||||||||||||||||||||
Undiscounted FNR, $
|
| | | | 369,128,320 | | | | | | 3,623,609 | | | | | | 481,070,688 | | | | | | 853,822,617 | | | | | | 516,353,376 | | | | | | 41,517,264 | | |
FNR Disc. @ 10.0%, $
|
| | | | 327,442,336 | | | | | | 2,841,810 | | | | | | 232,352,624 | | | | | | 562,636,770 | | | | | | 118,234,064 | | | | | | 7,163,635 | | |
| | |
Net to Vine Oil & Gas LP
|
| |||||||||||||||||||||||||||||||||
| | |
Proved Developed
|
| |
Proved
|
| |
Total
|
| |
Probable
|
| |
Possible
|
| |||||||||||||||||||||
SEC Price Case
|
| |
Producing
|
| |
Non-
producing |
| |
Undeveloped
|
| |
Proved
|
| |
Undeveloped
|
| |
Undeveloped
|
| ||||||||||||||||||
Allocation Percentage by Classification | | ||||||||||||||||||||||||||||||||||||
FNR Disc. @ 10.0%
|
| | | | 58.2% | | | | | | 0.5% | | | | | | 41.3% | | | | | | 100.0% | | | | | | 100.0% | | | | | | 100.0% | | |
|
|
![]() |
| |
Respectfully submitted,
![]()
William D. Von Gonten, Jr., P.E.
TX # 73244
![]()
John M. Parker
|
|
Class/Sub-Class
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Definition
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| |
Guidelines
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|
Reserves | | | Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. | | | Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the | |
Class/Sub-Class
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Definition
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Guidelines
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| | | | | | scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests. | |
On Production | | | The development project is currently producing and selling petroleum to market. | | | The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project. | |
Approved for Development | | | All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way. | | | At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity’s current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells. | |
Justified for Development | | | Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained. | | | In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/contracts, there should be no known contingencies that could | |
Class/Sub-Class
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| |
Definition
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| |
Guidelines
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| | | | | | preclude the development from proceeding within a reasonable timeframe (see Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time. | |
Contingent Resources | | | Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies. | | | Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. | |
Development Pending | | | A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future. | | | The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status. The project “decision gate” is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production. | |
Development Unclarified or on Hold | | | A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay. | | | The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to “Not Viable” status. The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the | |
Class/Sub-Class
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Definition
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| |
Guidelines
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| | | | | | potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies. | |
Development Not Viable | | | A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential. | | | The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project “decision gate” is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future. | |
Prospective Resources | | | Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. | | | Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration. | |
Prospect | | | A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. | | | Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program. | |
Lead | | | A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios. | |
Play | | | A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios. | |
Status
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| |
Definition
|
| |
Guidelines
|
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Developed Reserves
|
| | Developed Reserves are expected quantities to be recovered from existing wells and facilities. | | | Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed | |
Status
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | Reserves may be further sub-classified as Producing or Non-Producing. | |
Developed Producing Reserves | | | Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. | | | Improved recovery reserves are considered producing only after the improved recovery project is in operation. | |
Developed Non-Producing Reserves | | | Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. | | | Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. | |
Undeveloped Reserves | | | Undeveloped Reserves are quantities expected to be recovered through future investments: | | | (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. | |
Proved Reserves | | | Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. | | | If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define | |
Status
|
| |
Definition
|
| |
Guidelines
|
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| | | | | |
fluid contacts for Proved reserves (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved provided that:
•
The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive.
•
Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.
|
|
Probable Reserves | | | Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. | | | It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved. | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
Possible Reserves | | | Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves. | | | The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | project recovery efficiencies beyond that assumed for Probable. | |
Probable and Possible Reserves | | | (See above for separate criteria for Probable Reserves and Possible Reserves.) | | | The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations. | |
| | | |
Re: Vine Oil & Gas LP
Haynesville and Mid-Bossier Shale
Properties
Estimate of Reserves and Revenues
Strip Pricing Case
“As of” January 1, 2021
|
|
| | |
Net to Vine Oil & Gas LP
|
| |||||||||||||||||||||||||||||||||
| | |
Proved Developed
|
| |
Proved
|
| |
Total
|
| |
Probable
|
| |
Possible
|
| |||||||||||||||||||||
Strip Price Case
|
| |
Producing
|
| |
Non-
producing |
| |
Undeveloped
|
| |
Proved
|
| |
Undeveloped
|
| |
Undeveloped
|
| ||||||||||||||||||
Reserve Estimates | | ||||||||||||||||||||||||||||||||||||
Gas, MMcf
|
| | | | 482,391.2 | | | | | | 9,377.6 | | | | | | 1,872,740.7 | | | | | | 2,364,509.5 | | | | | | 3,600,975.4 | | | | | | 296,890.1 | | |
Revenues | | ||||||||||||||||||||||||||||||||||||
Gas, $(100) %
|
| | | | 1,136,691,584 | | | | | | 22,250,794 | | | | | | 4,380,628,480 | | | | | | 5,539,570,858 | | | | | | 8,892,904,448 | | | | | | 733,177,856 | | |
Total, $
|
| | | | 1,136,691,584 | | | | | | 22,250,794 | | | | | | 4,380,628,480 | | | | | | 5,539,570,858 | | | | | | 8,892,904,448 | | | | | | 733,177,856 | | |
Expenditures | | ||||||||||||||||||||||||||||||||||||
Ad Valorem
Taxes, $ |
| | | | 46,758,124 | | | | | | 912,412 | | | | | | 76,491,872 | | | | | | 124,162,408 | | | | | | 136,296,704 | | | | | | 10,754,500 | | |
Severance Taxes, $
|
| | | | 28,353,080 | | | | | | 564,718 | | | | | | 55,156,440 | | | | | | 84,074,238 | | | | | | 96,240,816 | | | | | | 8,131,588 | | |
Fixed Operating Expense, $
|
| | | | 296,407,232 | | | | | | 5,586,704 | | | | | | 794,588,032 | | | | | | 1,096,581,968 | | | | | | 1,536,578,048 | | | | | | 125,762,736 | | |
Variable Operating Expense, $
|
| | | | 43,045,756 | | | | | | 746,850 | | | | | | 169,109,856 | | | | | | 212,902,462 | | | | | | 323,780,992 | | | | | | 26,594,366 | | |
Marketing and Fuel, $
|
| | | | 46,766,540 | | | | | | 810,930 | | | | | | 182,146,992 | | | | | | 229,724,462 | | | | | | 368,935,680 | | | | | | 30,060,622 | | |
Total, $
|
| | | | 461,330,732 | | | | | | 8,621,614 | | | | | | 1,277,493,192 | | | | | | 1,747,445,538 | | | | | | 2,461,832,240 | | | | | | 201,303,812 | | |
Investments, $
|
| | | | 14,348,778 | | | | | | 2,900,452 | | | | | | 1,542,571,645 | | | | | | 1,559,820,875 | | | | | | 3,460,014,955 | | | | | | 283,785,737 | | |
Plugging & Abandonment, $
|
| | | | 29,035,758 | | | | | | 935,865 | | | | | | 17,191,171 | | | | | | 47,162,794 | | | | | | 39,382,165 | | | | | | 3,107,447 | | |
Total, $
|
| | | | 43,384,536 | | | | | | 3,836,317 | | | | | | 1,559,762,816 | | | | | | 1,606,983,669 | | | | | | 3,499,397,120 | | | | | | 286,893,184 | | |
Estimated Future Net Revenues (FNR) | | ||||||||||||||||||||||||||||||||||||
Undiscounted
FNR, $ |
| | | | 631,976,256 | | | | | | 9,792,860 | | | | | | 1,543,371,776 | | | | | | 2,185,140,892 | | | | | | 2,931,675,904 | | | | | | 244,980,768 | | |
| | |
Net to Vine Oil & Gas LP
|
| |||||||||||||||||||||||||||||||||
| | |
Proved Developed
|
| |
Proved
|
| |
Total
|
| |
Probable
|
| |
Possible
|
| |||||||||||||||||||||
Strip Price Case
|
| |
Producing
|
| |
Non-
producing |
| |
Undeveloped
|
| |
Proved
|
| |
Undeveloped
|
| |
Undeveloped
|
| ||||||||||||||||||
FNR Disc.
@ 10.0%, $ |
| | | | 528,225,184 | | | | | | 7,554,382 | | | | | | 851,299,008 | | | | | | 1,387,078,574 | | | | | | 893,767,424 | | | | | | 47,855,644 | | |
Allocation Percentage by Classification | | ||||||||||||||||||||||||||||||||||||
FNR Disc.
@ 10.0% |
| | | | 38.1% | | | | | | 0.5% | | | | | | 61.4% | | | | | | 100.0% | | | | | | 100.0% | | | | | | 100.0% | | |
|
Month/Yr.
|
| |
$/MmBtu
|
| |
Month/Yr.
|
| |
$/MmBtu
|
| |
Month/Yr.
|
| |
$/MmBtu
|
| |
Month/Yr.
|
| |
$/MmBtu
|
| |
Month/Yr.
|
| |
$/MmBtu
|
| |||||||||||||||||||||||||||
1/2021
|
| | | | 2.467 | | | | | | 2/2022 | | | | | | 2.939 | | | | | | 3/2023 | | | | | | 2.599 | | | | | | 4/2024 | | | | | | 2.306 | | | | | | 5/2025 | | | | | | 2.331 | | |
2/2021
|
| | | | 2.539 | | | | | | 3/2022 | | | | | | 2.792 | | | | | | 4/2023 | | | | | | 2.299 | | | | | | 5/2024 | | | | | | 2.281 | | | | | | 6/2025 | | | | | | 2.365 | | |
3/2021
|
| | | | 2.526 | | | | | | 4/2022 | | | | | | 2.429 | | | | | | 5/2023 | | | | | | 2.265 | | | | | | 6/2024 | | | | | | 2.318 | | | | | | 7/2025 | | | | | | 2.403 | | |
4/2021
|
| | | | 2.538 | | | | | | 5/2022 | | | | | | 2.384 | | | | | | 6/2023 | | | | | | 2.299 | | | | | | 7/2024 | | | | | | 2.362 | | | | | | 8/2025 | | | | | | 2.408 | | |
5/2021
|
| | | | 2.555 | | | | | | 6/2022 | | | | | | 2.412 | | | | | | 7/2023 | | | | | | 2.338 | | | | | | 8/2024 | | | | | | 2.370 | | | | | | 9/2025 | | | | | | 2.400 | | |
6/2021
|
| | | | 2.611 | | | | | | 7/2022 | | | | | | 2.447 | | | | | | 8/2023 | | | | | | 2.346 | | | | | | 9/2024 | | | | | | 2.368 | | | | | | 10/2025 | | | | | | 2.427 | | |
7/2021
|
| | | | 2.685 | | | | | | 8/2022 | | | | | | 2.455 | | | | | | 9/2023 | | | | | | 2.334 | | | | | | 10/2024 | | | | | | 2.401 | | | | | | 11/2025 | | | | | | 2.527 | | |
8/2021
|
| | | | 2.715 | | | | | | 9/2022 | | | | | | 2.435 | | | | | | 10/2023 | | | | | | 2.365 | | | | | | 11/2024 | | | | | | 2.519 | | | | | | 12/2025 | | | | | | 2.752 | | |
9/2021
|
| | | | 2.712 | | | | | | 10/2022 | | | | | | 2.458 | | | | | | 11/2023 | | | | | | 2.458 | | | | | | 12/2024 | | | | | | 2.749 | | | | | | Thereafter | | | | | | 2.752 | | |
10/2021
|
| | | | 2.741 | | | | | | 11/2022 | | | | | | 2.540 | | | | | | 12/2023 | | | | | | 2.674 | | | | | | 1/2025 | | | | | | 2.852 | | | | | | | | | | | | | | |
11/2021
|
| | | | 2.796 | | | | | | 12/2022 | | | | | | 2.696 | | | | | | 1/2024 | | | | | | 2.779 | | | | | | 2/2025 | | | | | | 2.802 | | | | | | | | | | | | | | |
12/2021
|
| | | | 2.913 | | | | | | 1/2023 | | | | | | 2.789 | | | | | | 2/2024 | | | | | | 2.736 | | | | | | 3/2025 | | | | | | 2.662 | | | | | | | | | | | | | | |
1/2022
|
| | | | 3.006 | | | | | | 2/2023 | | | | | | 2.740 | | | | | | 3/2024 | | | | | | 2.596 | | | | | | 4/2025 | | | | | | 2.357 | | | | | | | | | | | | | | |
|
![]() |
| |
Respectfully submitted,
![]()
William D. Von Gonten, Jr., P.E.
TX # 73244
![]()
John M. Parker
|
|
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
Reserves | | | Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. | | | Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests. | |
On Production | | | The development project is currently producing and selling petroleum to market. | | | The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project. | |
Approved for Development | | | All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way. | | | At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entities current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells. | |
Justified for Development | | | Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained. | | | In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/contracts, there should be no known contingencies that could | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | preclude the development from proceeding within a reasonable timeframe (see Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time. | |
Contingent Resources | | | Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies. | | | Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. | |
Development Pending | | | A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future. | | | The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status. The project “decision gate” is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production. | |
Development Unclarified or on Hold | | | A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay. | | | The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to “Not Viable” status. The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies. | |
Development Not Viable | | | A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential. | | | The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project “decision gate” is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future. | |
Prospective Resources | | | Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. | | | Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration. | |
Prospect | | | A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. | | | Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program. | |
Lead | | | A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios. | |
Play | | | A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios. | |
Status
|
| |
Definition
|
| |
Guidelines
|
|
Developed Reserves
|
| | Developed Reserves are expected quantities to be recovered from existing wells and facilities. | | | Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed | |
Status
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | Reserves may be further sub-classified as Producing or Non-Producing. | |
Developed Producing Reserves | | | Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. | | | Improved recovery reserves are considered producing only after the improved recovery project is in operation. | |
Developed Non-Producing Reserves | | | Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. | | | Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. | |
Undeveloped Reserves | | | Undeveloped Reserves are quantities expected to be recovered through future investments: | | | (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
Proved Reserves | | | Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. | | | If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | |
data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved provided that:
•
The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive.
•
Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.
|
|
Probable Reserves | | | Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. | | | It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved. | |
Possible Reserves | | | Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves. | | | The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | project recovery efficiencies beyond that assumed for Probable. | |
Probable and Possible Reserves | | | (See above for separate criteria for Probable Reserves and Possible Reserves.) | | | The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations. | |
| | | |
Re: Brix Oil & Gas Holdings LP
Haynesville and Mid-Bossier Shale
Properties
Estimate of Reserves and Revenues
SEC Pricing Case
“As of” January 1, 2020
|
|
| | |
Net to Brix Oil & Gas, LP.
|
| |||||||||||||||||||||||||||||||||
| | |
Proved Developed
|
| |
Proved
|
| |
Total
|
| |
Probable
|
| |
Possible
|
| |||||||||||||||||||||
SEC Price Case
|
| |
Producing
|
| |
Non-
producing |
| |
Undeveloped
|
| |
Proved
|
| |
Undeveloped
|
| |
Undeveloped
|
| ||||||||||||||||||
Reserve Estimates | | ||||||||||||||||||||||||||||||||||||
Gas, MMcf
|
| | | | 135,193.3 | | | | | | 2,871.4 | | | | | | 512,279.7 | | | | | | 650,344.4 | | | | | | 726,677.1 | | | | | | 169,558.9 | | |
Revenues | | ||||||||||||||||||||||||||||||||||||
Gas, $(100) %
|
| | | | 313,113,824 | | | | | | 6,644,602 | | | | | | 1,185,741,696 | | | | | | 1,505,500,122 | | | | | | 1,682,111,232 | | | | | | 392,576,384 | | |
Total, $
|
| | | | 313,113,824 | | | | | | 6,644,602 | | | | | | 1,185,741,696 | | | | | | 1,505,500,122 | | | | | | 1,682,111,232 | | | | | | 392,576,384 | | |
Expenditures | | ||||||||||||||||||||||||||||||||||||
Ad Valorem
Taxes, $ |
| | | | 6,622,268 | | | | | | 57,526 | | | | | | 18,454,838 | | | | | | 25,134,632 | | | | | | 21,809,048 | | | | | | 5,728,050 | | |
Severance Taxes, $
|
| | | | 10,353,581 | | | | | | 157,657 | | | | | | 25,698,686 | | | | | | 36,209,924 | | | | | | 36,909,536 | | | | | | 8,728,835 | | |
Fixed Operating Expense, $
|
| | | | 70,005,568 | | | | | | 1,424,173 | | | | | | 230,340,576 | | | | | | 301,770,317 | | | | | | 334,942,144 | | | | | | 70,011,424 | | |
Variable Operating Expense, $
|
| | | | 9,561,404 | | | | | | 248,854 | | | | | | 35,552,216 | | | | | | 45,362,474 | | | | | | 55,292,216 | | | | | | 11,386,480 | | |
Marketing and Fuel, $
|
| | | | 9,082,196 | | | | | | 296,098 | | | | | | 35,835,648 | | | | | | 45,213,942 | | | | | | 62,645,860 | | | | | | 10,106,038 | | |
Total, $
|
| | | | 105,625,017 | | | | | | 2,184,308 | | | | | | 345,881,964 | | | | | | 453,691,289 | | | | | | 511,598,804 | | | | | | 105,960,827 | | |
Investments, $
|
| | | | 3,334,722 | | | | | | 28,966 | | | | | | 578,501,570 | | | | | | 581,865,258 | | | | | | 825,214,779 | | | | | | 208,758,881 | | |
Plugging & Abandonment, $
|
| | | | 3,264,921 | | | | | | 30,345 | | | | | | 6,815,102 | | | | | | 10,110,368 | | | | | | 8,886,021 | | | | | | 2,111,695 | | |
Total, $
|
| | | | 6,599,643 | | | | | | 59,311 | | | | | | 585,316,672 | | | | | | 591,975,626 | | | | | | 834,100,800 | | | | | | 210,870,576 | | |
Estimated Future Net Revenues (FNR) | | ||||||||||||||||||||||||||||||||||||
Undiscounted FNR, $
|
| | | | 200,889,136 | | | | | | 4,400,982 | | | | | | 254,542,976 | | | | | | 459,833,094 | | | | | | 336,411,776 | | | | | | 75,744,928 | | |
FNR Disc.
@ 10.0%, $ |
| | | | 175,464,832 | | | | | | 3,840,938 | | | | | | 117,155,784 | | | | | | 296,461,554 | | | | | | 81,798,344 | | | | | | 14,601,026 | | |
| | |
Net to Brix Oil & Gas, LP.
|
| |||||||||||||||||||||||||||||||||
| | |
Proved Developed
|
| |
Proved
|
| |
Total
|
| |
Probable
|
| |
Possible
|
| |||||||||||||||||||||
SEC Price Case
|
| |
Producing
|
| |
Non-
producing |
| |
Undeveloped
|
| |
Proved
|
| |
Undeveloped
|
| |
Undeveloped
|
| ||||||||||||||||||
Allocation Percentage by Classification | | ||||||||||||||||||||||||||||||||||||
FNR Disc. @ 10.0%
|
| | | | 59.2% | | | | | | 1.3% | | | | | | 39.5% | | | | | | 100.0% | | | | | | 100.0% | | | | | | 100.0% | | |
|
|
![]() |
| |
Respectfully submitted,
![]()
William D. Von Gonten, Jr., P.E.
TX # 73244
![]()
John M. Parker
|
|
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
Reserves | | | Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. | | | Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests. | |
On Production | | | The development project is currently producing and selling petroleum to market. | | | The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project. | |
Approved for Development | | | All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way. | | | At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity’s current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells. | |
Justified for Development | | | Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained. | | | In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/contracts, there should be no known contingencies that could | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | preclude the development from proceeding within a reasonable timeframe (see Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time. | |
Contingent Resources | | | Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies. | | | Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. | |
Development Pending | | | A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future. | | | The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status. The project “decision gate” is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production. | |
Development Unclarified or on Hold | | | A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay. | | | The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to “Not Viable” status. The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies. | |
Development Not Viable | | | A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential. | | | The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project “decision gate” is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future. | |
Prospective Resources | | | Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. | | | Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration. | |
Prospect | | | A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. | | | Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program. | |
Lead | | | A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios. | |
Play | | | A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios. | |
Status
|
| |
Definition
|
| |
Guidelines
|
|
Developed Reserves
|
| | Developed Reserves are expected quantities to be recovered from existing wells and facilities. | | | Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed | |
Status
|
| |
Definition
|
| |
Guidelines
|
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| | | | | | Reserves may be further sub-classified as Producing or Non-Producing. | |
Developed Producing Reserves | | | Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. | | | Improved recovery reserves are considered producing only after the improved recovery project is in operation. | |
Developed Non-Producing Reserves | | | Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. | | | Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. | |
Undeveloped Reserves | | | Undeveloped Reserves are quantities expected to be recovered through future investments: | | | (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
Proved Reserves | | | Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. | | | If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | |
data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved provided that:
•
The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive.
•
Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.
|
|
Probable Reserves | | | Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. | | | It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved. | |
Possible Reserves | | | Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves. | | | The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | project recovery efficiencies beyond that assumed for Probable. | |
Probable and Possible Reserves | | | (See above for separate criteria for Probable Reserves and Possible Reserves.) | | | The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations. | |
| | | |
Re: Brix Oil & Gas LP
Haynesville and Mid-Bossier Shale
Properties
Estimate of Reserves and Revenues
SEC Pricing Case
“As of” January 1, 2021
|
|
| | |
Net to Brix Oil & Gas LP
|
| |||||||||||||||||||||||||||||||||
| | |
Proved Developed
|
| |
Proved
|
| |
Total
|
| |
Probable
|
| |
Possible
|
| |||||||||||||||||||||
SEC Price Case
|
| |
Producing
|
| |
Non-
producing |
| |
Undeveloped
|
| |
Proved
|
| |
Undeveloped
|
| |
Undeveloped
|
| ||||||||||||||||||
Reserve Estimates | | ||||||||||||||||||||||||||||||||||||
Gas, MMcf
|
| | | | 135,440.9 | | | | | | 8,025.3 | | | | | | 366,325.8 | | | | | | 509,792.0 | | | | | | 353,658.8 | | | | | | 42,425.0 | | |
Revenues | | ||||||||||||||||||||||||||||||||||||
Gas, $(100) %
|
| | | | 233,779,776 | | | | | | 13,760,370 | | | | | | 632,081,216 | | | | | | 879,621,362 | | | | | | 611,560,960 | | | | | | 73,038,496 | | |
Total, $
|
| | | | 233,779,776 | | | | | | 13,760,370 | | | | | | 632,081,216 | | | | | | 879,621,362 | | | | | | 611,560,960 | | | | | | 73,038,496 | | |
Expenditures | | ||||||||||||||||||||||||||||||||||||
Ad Valorem Taxes, $
|
| | | | 6,459,619 | | | | | | 176,428 | | | | | | 8,980,542 | | | | | | 15,616,589 | | | | | | 7,453,112 | | | | | | 1,053,211 | | |
Severance Taxes, $
|
| | | | 5,831,759 | | | | | | 150,407 | | | | | | 7,944,688 | | | | | | 13,926,854 | | | | | | 6,630,935 | | | | | | 803,550 | | |
Fixed Operating Expense, $
|
| | | | 63,837,076 | | | | | | 3,363,966 | | | | | | 147,562,352 | | | | | | 214,763,394 | | | | | | 144,465,888 | | | | | | 16,048,393 | | |
Variable Operating Expense, $
|
| | | | 12,683,324 | | | | | | 836,371 | | | | | | 33,241,556 | | | | | | 46,761,251 | | | | | | 29,813,420 | | | | | | 3,892,729 | | |
Marketing and Fuel, $
|
| | | | 7,067,393 | | | | | | 592,348 | | | | | | 23,884,788 | | | | | | 31,544,529 | | | | | | 25,020,882 | | | | | | 2,803,073 | | |
Total, $
|
| | | | 95,879,171 | | | | | | 5,119,520 | | | | | | 221,613,926 | | | | | | 322,612,617 | | | | | | 213,384,237 | | | | | | 24,600,956 | | |
Investments, $
|
| | | | 2,659,772 | | | | | | 613,058 | | | | | | 293,421,503 | | | | | | 296,694,333 | | | | | | 299,899,043 | | | | | | 36,749,289 | | |
Plugging & Abandonment, $
|
| | | | 3,807,644 | | | | | | 80,829 | | | | | | 2,820,641 | | | | | | 6,709,114 | | | | | | 3,081,405 | | | | | | 376,099 | | |
Total, $
|
| | | | 6,467,416 | | | | | | 693,887 | | | | | | 296,242,144 | | | | | | 303,403,447 | | | | | | 302,980,448 | | | | | | 37,125,388 | | |
Estimated Future Net Revenues (FNR) | | ||||||||||||||||||||||||||||||||||||
Undiscounted FNR, $
|
| | | | 131,433,192 | | | | | | 7,946,965 | | | | | | 114,225,032 | | | | | | 253,605,189 | | | | | | 95,196,288 | | | | | | 11,312,156 | | |
FNR Disc. @ 10.0%, $
|
| | | | 116,689,976 | | | | | | 7,067,832 | | | | | | 51,695,504 | | | | | | 175,453,312 | | | | | | 22,700,936 | | | | | | 1,306,346 | | |
Allocation Percentage by Classification | | ||||||||||||||||||||||||||||||||||||
FNR Disc. @ 10.0%
|
| | | | 66.5% | | | | | | 4.0% | | | | | | 29.5% | | | | | | 100.0% | | | | | | 100.0% | | | | | | 100.0% | | |
|
![]() |
| |
Respectfully submitted,
![]()
William D. Von Gonten, Jr., P.E.
TX # 73244
![]()
John M. Parker
|
|
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
Reserves | | | Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. | | | Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests. | |
On Production | | | The development project is currently producing and selling petroleum to market. | | | The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project. | |
Approved for Development | | | All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way. | | | At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity’s current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells. | |
Justified for Development | | | Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained. | | | In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/contracts, there should be no known contingencies that could | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | preclude the development from proceeding within a reasonable timeframe (see Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time. | |
Contingent Resources | | | Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies. | | | Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. | |
Development Pending | | | A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future. | | | The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status. The project “decision gate” is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production. | |
Development Unclarified or on Hold | | | A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay. | | | The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to “Not Viable” status. The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies. | |
Development Not Viable | | | A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential. | | | The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project “decision gate” is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future. | |
Prospective Resources | | | Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. | | | Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration. | |
Prospect | | | A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. | | | Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program. | |
Lead | | | A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios. | |
Play | | | A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios. | |
Status
|
| |
Definition
|
| |
Guidelines
|
|
Developed Reserves
|
| | Developed Reserves are expected quantities to be recovered from existing wells and facilities. | | | Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed | |
Status
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | Reserves may be further sub-classified as Producing or Non-Producing. | |
Developed Producing Reserves | | | Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. | | | Improved recovery reserves are considered producing only after the improved recovery project is in operation. | |
Developed Non-Producing Reserves | | | Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. | | | Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. | |
Undeveloped Reserves | | | Undeveloped Reserves are quantities expected to be recovered through future investments: | | | (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
Proved Reserves | | | Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. | | | If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | |
data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved provided that:
•
The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive.
•
Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.
|
|
Probable Reserves | | | Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. | | | It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved. | |
Possible Reserves | | | Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves. | | | The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | project recovery efficiencies beyond that assumed for Probable. | |
Probable and Possible Reserves | | | (See above for separate criteria for Probable Reserves and Possible Reserves.) | | | The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations. | |
| | |
Net to Brix Oil & Gas LP
|
| |||||||||||||||||||||||||||||||||
| | |
Proved Developed
|
| |
Proved
|
| |
Total
|
| |
Probable
|
| |
Possible
|
| |||||||||||||||||||||
Strip Price Case
|
| |
Producing
|
| |
Non-producing
|
| |
Undeveloped
|
| |
Proved
|
| |
Undeveloped
|
| |
Undeveloped
|
| ||||||||||||||||||
Reserve Estimates | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Gas, MMcf
|
| | | | 142,834.2 | | | | | | 8,259.4 | | | | | | 633,801.7 | | | | | | 784,895.3 | | | | | | 903,271.0 | | | | | | 130,416.1 | | |
Revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Gas, $(100) %
|
| | | | 334,213,760 | | | | | | 19,344,042 | | | | | | 1,471,887,232 | | | | | | 1,825,445,034 | | | | | | 2,223,817,984 | | | | | | 321,078,944 | | |
Total, $
|
| | | | 334,213,760 | | | | | | 19,344,042 | | | | | | 1,471,887,232 | | | | | | 1,825,445,034 | | | | | | 2,223,817,984 | | | | | | 321,078,944 | | |
Expenditures | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Ad Valorem Taxes, $
|
| | | | 8,811,386 | | | | | | 239,249 | | | | | | 22,573,290 | | | | | | 31,623,925 | | | | | | 29,468,840 | | | | | | 4,702,550 | | |
Severance Taxes, $
|
| | | | 8,018,685 | | | | | | 201,146 | | | | | | 18,437,404 | | | | | | 26,657,235 | | | | | | 23,310,816 | | | | | | 3,309,091 | | |
Fixed Operating Expense, $
|
| | | | 78,076,624 | | | | | | 3,731,588 | | | | | | 284,501,056 | | | | | | 366,309,268 | | | | | | 403,849,536 | | | | | | 56,635,412 | | |
Variable Operating Expense, $
|
| | | | 13,394,723 | | | | | | 859,658 | | | | | | 59,999,620 | | | | | | 74,254,001 | | | | | | 80,939,120 | | | | | | 12,649,084 | | |
Marketing and Fuel, $
|
| | | | 9,899,435 | | | | | | 809,333 | | | | | | 50,154,592 | | | | | | 60,863,360 | | | | | | 81,850,208 | | | | | | 10,010,067 | | |
Total, $
|
| | | | 118,200,853 | | | | | | 5,840,974 | | | | | | 435,665,962 | | | | | | 559,707,789 | | | | | | 619,418,520 | | | | | | 87,306,204 | | |
Investments, $
|
| | | | 2,859,510 | | | | | | 614,314 | | | | | | 576,600,463 | | | | | | 580,074,287 | | | | | | 946,770,753 | | | | | | 142,652,274 | | |
Plugging & Abandonment, $
|
| | | | 3,594,563 | | | | | | 80,829 | | | | | | 6,614,129 | | | | | | 10,289,521 | | | | | | 11,504,319 | | | | | | 1,778,638 | | |
Total, $
|
| | | | 6,454,073 | | | | | | 695,143 | | | | | | 583,214,592 | | | | | | 590,363,808 | | | | | | 958,275,072 | | | | | | 144,430,912 | | |
Estimated Future Net Revenues (FNR)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Undiscounted FNR, $
|
| | | | 209,558,816 | | | | | | 12,807,920 | | | | | | 453,006,688 | | | | | | 675,373,424 | | | | | | 646,124,352 | | | | | | 89,341,872 | | |
FNR Disc. @ 10.0%, $
|
| | | | 178,928,096 | | | | | | 11,219,494 | | | | | | 243,751,936 | | | | | | 433,899,526 | | | | | | 193,665,776 | | | | | | 14,203,627 | | |
Allocation Percentage by Classification
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
FNR Disc. @ 10.0%
|
| | | | 41.2% | | | | | | 2.6% | | | | | | 56.2% | | | | | | 100.0% | | | | | | 100.0% | | | | | | 100.0% | | |
Month/Yr.
|
| |
$/MmBtu
|
| |
Month/Yr.
|
| |
$/MmBtu
|
| |
Month/Yr.
|
| |
$/MmBtu
|
| |
Month/Yr.
|
| |
$/MmBtu
|
| |
Month/Yr.
|
| |
$/MmBtu
|
|
1/2021
|
| |
2.467
|
| |
2/2022
|
| |
2.939
|
| |
3/2023
|
| |
2.599
|
| |
4/2024
|
| |
2.306
|
| |
5/2025
|
| |
2.331
|
|
2/2021
|
| |
2.539
|
| |
3/2022
|
| |
2.792
|
| |
4/2023
|
| |
2.299
|
| |
5/2024
|
| |
2.281
|
| |
6/2025
|
| |
2.365
|
|
3/2021
|
| |
2.526
|
| |
4/2022
|
| |
2.429
|
| |
5/2023
|
| |
2.265
|
| |
6/2024
|
| |
2.318
|
| |
7/2025
|
| |
2.403
|
|
4/2021
|
| |
2.538
|
| |
5/2022
|
| |
2.384
|
| |
6/2023
|
| |
2.299
|
| |
7/2024
|
| |
2.362
|
| |
8/2025
|
| |
2.408
|
|
5/2021
|
| |
2.555
|
| |
6/2022
|
| |
2.412
|
| |
7/2023
|
| |
2.338
|
| |
8/2024
|
| |
2.370
|
| |
9/2025
|
| |
2.400
|
|
6/2021
|
| |
2.611
|
| |
7/2022
|
| |
2.447
|
| |
8/2023
|
| |
2.346
|
| |
9/2024
|
| |
2.368
|
| |
10/2025
|
| |
2.427
|
|
7/2021
|
| |
2.685
|
| |
8/2022
|
| |
2.455
|
| |
9/2023
|
| |
2.334
|
| |
10/2024
|
| |
2.401
|
| |
11/2025
|
| |
2.527
|
|
8/2021
|
| |
2.715
|
| |
9/2022
|
| |
2.435
|
| |
10/2023
|
| |
2.365
|
| |
11/2024
|
| |
2.519
|
| |
12/2025
|
| |
2.752
|
|
9/2021
|
| |
2.712
|
| |
10/2022
|
| |
2.458
|
| |
11/2023
|
| |
2.458
|
| |
12/2024
|
| |
2.749
|
| |
Thereafter
|
| |
2.752
|
|
10/2021
|
| |
2.741
|
| |
11/2022
|
| |
2.540
|
| |
12/2023
|
| |
2.674
|
| |
1/2025
|
| |
2.852
|
| | | | | | |
11/2021
|
| |
2.796
|
| |
12/2022
|
| |
2.696
|
| |
1/2024
|
| |
2.779
|
| |
2/2025
|
| |
2.802
|
| | | | | | |
12/2021
|
| |
2.913
|
| |
1/2023
|
| |
2.789
|
| |
2/2024
|
| |
2.736
|
| |
3/2025
|
| |
2.662
|
| | | | | | |
1/2022
|
| |
3.006
|
| |
2/2023
|
| |
2.740
|
| |
3/2024
|
| |
2.596
|
| |
4/2025
|
| |
2.357
|
| | | | | | |
|
![]() |
| |
Respectfully submitted,
![]()
William D. Von Gonten, Jr., P.E.
TX # 73244 ![]()
John M. Parker
|
|
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
Reserves | | | Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. | | | Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests. | |
On Production | | | The development project is currently producing and selling petroleum to market. | | | The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project. | |
Approved for Development | | | All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way. | | | At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entities current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells. | |
Justified for Development | | | Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained. | | | In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/ | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | contracts, there should be no known contingencies that could preclude the development from proceeding within a reasonable timeframe (see Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time. | |
Contingent Resources | | | Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies. | | | Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. | |
Development Pending | | | A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future. | | | The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status. The project “decision gate” is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production. | |
Development Unclarified or on Hold | | | A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay. | | | The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to “Not Viable” status. The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the potential for eventual | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies. | |
Development Not Viable | | | A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential. | | | The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project “decision gate” is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future. | |
Prospective Resources | | | Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. | | | Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration. | |
Prospect | | | A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. | | | Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program. | |
Lead | | | A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios. | |
Play | | | A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios. | |
Status
|
| |
Definition
|
| |
Guidelines
|
|
Developed Reserves | | | Developed Reserves are expected quantities to be recovered from existing wells and facilities. | | | Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing. | |
Developed Producing Reserves | | | Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. | | | Improved recovery reserves are considered producing only after the improved recovery project is in operation. | |
Developed Non-Producing Reserves | | | Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. | | | Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. | |
Undeveloped Reserves | | | Undeveloped Reserves are quantities expected to be recovered through future investments: | | | (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
Proved Reserves | | | Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and | | | If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
| | | under defined economic conditions, operating methods, and government regulations. | | |
undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved provided that:
•
The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive.
•
Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.
|
|
Probable Reserves | | | Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. | | | It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved. | |
Possible Reserves | | | Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves. | | | The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable. | |
Probable and Possible Reserves | | | (See above for separate criteria for Probable Reserves and Possible Reserves.) | | | The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations. | |
| | |
Net to Harvest Royalties Holdings LP
|
| |||||||||||||||||||||||||||
| | |
Proved
|
| |
Total
|
| |
Probable
|
| |
Possible
|
| ||||||||||||||||||
SEC Price Case
|
| |
Producing
|
| |
Undeveloped
|
| |
Proved
|
| |
Undeveloped
|
| |
Undeveloped
|
| |||||||||||||||
Reserve Estimates | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Gas, MMcf
|
| | | | 193.3 | | | | | | 1,656.9 | | | | | | 1,850.2 | | | | | | 3,073.4 | | | | | | 358.0 | | |
Revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Gas, $(100) %
|
| | | | 447,208 | | | | | | 3,834,244 | | | | | | 4,281,452 | | | | | | 7,112,042 | | | | | | 828,488 | | |
Total, $
|
| | | | 447,208 | | | | | | 3,834,244 | | | | | | 4,281,452 | | | | | | 7,112,042 | | | | | | 828,488 | | |
Expenditures | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Ad Valorem Taxes, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Severance Taxes, $
|
| | | | 17,738 | | | | | | 86,615 | | | | | | 104,353 | | | | | | 153,344 | | | | | | 17,513 | | |
Fixed Operating Expense, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Variable Operating Expense, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Marketing and Fuel, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total, $
|
| | | | 17,738 | | | | | | 86,615 | | | | | | 104,353 | | | | | | 153,344 | | | | | | 17,513 | | |
Investments, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Plugging & Abandonment, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total, $
|
| | | | 0 | | | | | | 0 | | | | | | 0 | | | | | | 0 | | | | | | 0 | | |
Estimated Future Net Revenues (FNR) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Undiscounted FNR, $
|
| | | | 429,471 | | | | | | 3,747,628 | | | | | | 4,177,099 | | | | | | 6,958,698 | | | | | | 810,975 | | |
FNR Disc. @ 10.0%, $
|
| | | | 296,556 | | | | | | 2,712,519 | | | | | | 3,009,075 | | | | | | 2,093,585 | | | | | | 291,910 | | |
Allocation Percentage by Classification | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
FNR Disc. @ 10.0%
|
| | | | 9.9% | | | | | | 90.1% | | | | | | 100.0% | | | | | | 100.0% | | | | | | 100.0% | | |
|
![]() |
| |
Respectfully submitted,
![]()
William D. Von Gonten, Jr., P.E.
TX # 73244 ![]()
John M. Parker
|
|
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
Reserves | | | Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. | | | Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests. | |
On Production | | | The development project is currently producing and selling petroleum to market. | | | The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project. | |
Approved for Development | | | All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way. | | | At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entities current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells. | |
Justified for Development | | | Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained. | | | In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/ | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | contracts, there should be no known contingencies that could preclude the development from proceeding within a reasonable timeframe (see Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time. | |
Contingent Resources | | | Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies. | | | Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. | |
Development Pending | | | A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future. | | | The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status. The project “decision gate” is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production. | |
Development Unclarified or on Hold | | | A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay. | | | The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to “Not Viable” status. The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the potential for eventual | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies. | |
Development Not Viable | | | A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential. | | | The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project “decision gate” is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future. | |
Prospective Resources | | | Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. | | | Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration. | |
Prospect | | | A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. | | | Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program. | |
Lead | | | A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios. | |
Play | | | A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios. | |
Status
|
| |
Definition
|
| |
Guidelines
|
|
Developed Reserves | | | Developed Reserves are expected quantities to be recovered from existing wells and facilities. | | | Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing. | |
Developed Producing Reserves | | | Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. | | | Improved recovery reserves are considered producing only after the improved recovery project is in operation. | |
Developed Non-Producing Reserves | | | Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. | | | Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. | |
Undeveloped Reserves | | | Undeveloped Reserves are quantities expected to be recovered through future investments: | | | (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
Proved Reserves | | | Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic | | | If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent undrilled portions of the reservoir that can | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
| | | conditions, operating methods, and government regulations. | | |
reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved provided that:
•
The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive.
•
Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.
|
|
Probable Reserves | | | Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. | | | It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved. | |
Possible Reserves | | | Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves. | | | The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable. | |
Probable and Possible Reserves | | | (See above for separate criteria for Probable Reserves and Possible Reserves.) | | | The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations. | |
| | |
Net to Harvest Royalties Holdings LP
|
| |||||||||||||||||||||||||||
| | |
Proved
|
| |
Total
|
| |
Probable
|
| |
Possible
|
| ||||||||||||||||||
SEC Price Case
|
| |
Producing
|
| |
Undeveloped
|
| |
Proved
|
| |
Undeveloped
|
| |
Undeveloped
|
| |||||||||||||||
Reserve Estimates | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Gas, MMcf
|
| | | | 452.3 | | | | | | 1,138.0 | | | | | | 1,590.3 | | | | | | 2,843.0 | | | | | | 269.8 | | |
Revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Gas, $(100) %
|
| | | | 785,595 | | | | | | 1,976,760 | | | | | | 2,762,355 | | | | | | 4,938,318 | | | | | | 468,626 | | |
Total, $
|
| | | | 785,595 | | | | | | 1,976,760 | | | | | | 2,762,355 | | | | | | 4,938,318 | | | | | | 468,626 | | |
Expenditures | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Ad Valorem Taxes, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Severance Taxes, $
|
| | | | 19,519 | | | | | | 23,018 | | | | | | 42,537 | | | | | | 54,174 | | | | | | 4,827 | | |
Fixed Operating Expense, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Variable Operating Expense, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Marketing and Fuel, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total, $
|
| | | | 19,519 | | | | | | 23,018 | | | | | | 42,537 | | | | | | 54,174 | | | | | | 4,827 | | |
Investments, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Plugging & Abandonment, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total, $
|
| | | | 0 | | | | | | 0 | | | | | | 0 | | | | | | 0 | | | | | | 0 | | |
.Estimated Future Net Revenues (FNR)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Undiscounted FNR, $
|
| | | | 766,076 | | | | | | 1,953,742 | | | | | | 2,719,818 | | | | | | 4,884,144 | | | | | | 463,799 | | |
FNR Disc. @ 10.0%, $
|
| | | | 640,326 | | | | | | 1,487,248 | | | | | | 2,127,574 | | | | | | 1,527,974 | | | | | | 193,777 | | |
Allocation Percentage by Classification
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
FNR Disc. @ 10.0%
|
| | | | 30.1% | | | | | | 69.9% | | | | | | 100.0% | | | | | | 100.0% | | | | | | 100.0% | | |
|
![]() |
| |
Respectfully submitted,
![]()
William D. Von Gonten, Jr., P.E.
TX # 73244 ![]()
John M. Parker
|
|
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
Reserves | | | Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. | | | Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests. | |
On Production | | | The development project is currently producing and selling petroleum to market. | | | The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project. | |
Approved for Development | | | All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way. | | | At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entities current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells. | |
Justified for Development | | | Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained. | | | In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/ | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | contracts, there should be no known contingencies that could preclude the development from proceeding within a reasonable timeframe (see Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time. | |
Contingent Resources | | | Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies. | | | Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. | |
Development Pending | | | A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future. | | | The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status. The project “decision gate” is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production. | |
Development Unclarified or on Hold | | | A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay. | | | The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to “Not Viable” status. The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the potential for eventual | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies. | |
Development Not Viable | | | A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential. | | | The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project “decision gate” is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future. | |
Prospective Resources | | | Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. | | | Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration. | |
Prospect | | | A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. | | | Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program. | |
Lead | | | A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios. | |
Play | | | A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios. | |
Status
|
| |
Definition
|
| |
Guidelines
|
|
Developed Reserves | | | Developed Reserves are expected quantities to be recovered from existing wells and facilities. | | | Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing. | |
Developed Producing Reserves | | | Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. | | | Improved recovery reserves are considered producing only after the improved recovery project is in operation. | |
Developed Non-Producing Reserves | | | Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. | | | Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. | |
Undeveloped Reserves | | | Undeveloped Reserves are quantities expected to be recovered through future investments: | | | (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
Proved Reserves | | | Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and | | | If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
| | | under defined economic conditions, operating methods, and government regulations. | | |
undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved provided that:
•
The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive.
•
Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.
|
|
Probable Reserves | | | Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. | | | It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved. | |
Possible Reserves | | | Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves. | | | The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where | |
Category
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable. | |
Probable and Possible Reserves | | | (See above for separate criteria for Probable Reserves and Possible Reserves.) | | | The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations. | |
| | |
Net to Harvest Royalties Holdings LP
|
| |||||||||||||||||||||||||||
| | |
Proved
|
| |
Total
|
| |
Probable
|
| |
Possible
|
| ||||||||||||||||||
Strip Price Case
|
| |
Producing
|
| |
Undeveloped
|
| |
Proved
|
| |
Undeveloped
|
| |
Undeveloped
|
| |||||||||||||||
Reserve Estimates | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Gas, MMcf
|
| | | | 489.5 | | | | | | 1,177.9 | | | | | | 1,667.4 | | | | | | 2,939.6 | | | | | | 280.7 | | |
Revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Gas, $(100) %
|
| | | | 1,149,074 | | | | | | 2,752,866 | | | | | | 3,901,940 | | | | | | 7,281,721 | | | | | | 695,434 | | |
Total, $
|
| | | | 1,149,074 | | | | | | 2,752,866 | | | | | | 3,901,940 | | | | | | 7,281,721 | | | | | | 695,434 | | |
Expenditures | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Ad Valorem Taxes, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Severance Taxes, $
|
| | | | 25,455 | | | | | | 32,133 | | | | | | 57,588 | | | | | | 78,449 | | | | | | 7,270 | | |
Fixed Operating Expense, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Variable Operating Expense, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Marketing and Fuel, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total, $
|
| | | | 25,455 | | | | | | 32,133 | | | | | | 57,588 | | | | | | 78,449 | | | | | | 7,270 | | |
Investments, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Plugging & Abandonment, $
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Total, $
|
| | | | 0 | | | | | | 0 | | | | | | 0 | | | | | | 0 | | | | | | 0 | | |
Estimated Future Net Revenues (FNR) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Undiscounted FNR, $
|
| | | | 1,123,620 | | | | | | 2,720,734 | | | | | | 3,844,354 | | | | | | 7,203,272 | | | | | | 688,163 | | |
FNR Disc. @ 10.0%, $
|
| | | | 889,303 | | | | | | 2,012,866 | | | | | | 2,902,169 | | | | | | 2,206,940 | | | | | | 281,628 | | |
Allocation Percentage by Classification
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
FNR Disc. @ 10.0%
|
| | | | 30.6% | | | | | | 69.4% | | | | | | 100.0% | | | | | | 100.0% | | | | | | 100.0% | | |
Month/Yr.
|
| |
$/MmBtu
|
| |
Month/Yr.
|
| |
$/MmBtu
|
| |
Month/Yr.
|
| |
$/MmBtu
|
| |
Month/Yr.
|
| |
$/MmBtu
|
| |
Month/Yr.
|
| |
$/MmBtu
|
|
1/2021
|
| |
2.467
|
| |
2/2022
|
| |
2.939
|
| |
3/2023
|
| |
2.599
|
| |
4/2024
|
| |
2.306
|
| |
5/2025
|
| |
2.331
|
|
2/2021
|
| |
2.539
|
| |
3/2022
|
| |
2.792
|
| |
4/2023
|
| |
2.299
|
| |
5/2024
|
| |
2.281
|
| |
6/2025
|
| |
2.365
|
|
3/2021
|
| |
2.526
|
| |
4/2022
|
| |
2.429
|
| |
5/2023
|
| |
2.265
|
| |
6/2024
|
| |
2.318
|
| |
7/2025
|
| |
2.403
|
|
4/2021
|
| |
2.538
|
| |
5/2022
|
| |
2.384
|
| |
6/2023
|
| |
2.299
|
| |
7/2024
|
| |
2.362
|
| |
8/2025
|
| |
2.408
|
|
5/2021
|
| |
2.555
|
| |
6/2022
|
| |
2.412
|
| |
7/2023
|
| |
2.338
|
| |
8/2024
|
| |
2.370
|
| |
9/2025
|
| |
2.400
|
|
6/2021
|
| |
2.611
|
| |
7/2022
|
| |
2.447
|
| |
8/2023
|
| |
2.346
|
| |
9/2024
|
| |
2.368
|
| |
10/2025
|
| |
2.427
|
|
7/2021
|
| |
2.685
|
| |
8/2022
|
| |
2.455
|
| |
9/2023
|
| |
2.334
|
| |
10/2024
|
| |
2.401
|
| |
11/2025
|
| |
2.527
|
|
8/2021
|
| |
2.715
|
| |
9/2022
|
| |
2.435
|
| |
10/2023
|
| |
2.365
|
| |
11/2024
|
| |
2.519
|
| |
12/2025
|
| |
2.752
|
|
9/2021
|
| |
2.712
|
| |
10/2022
|
| |
2.458
|
| |
11/2023
|
| |
2.458
|
| |
12/2024
|
| |
2.749
|
| |
Thereafter
|
| |
2.752
|
|
10/2021
|
| |
2.741
|
| |
11/2022
|
| |
2.540
|
| |
12/2023
|
| |
2.674
|
| |
1/2025
|
| |
2.852
|
| | | | | | |
11/2021
|
| |
2.796
|
| |
12/2022
|
| |
2.696
|
| |
1/2024
|
| |
2.779
|
| |
2/2025
|
| |
2.802
|
| | | | | | |
12/2021
|
| |
2.913
|
| |
1/2023
|
| |
2.789
|
| |
2/2024
|
| |
2.736
|
| |
3/2025
|
| |
2.662
|
| | | | | | |
1/2022
|
| |
3.006
|
| |
2/2023
|
| |
2.740
|
| |
3/2024
|
| |
2.596
|
| |
4/2025
|
| |
2.357
|
| | | | | | |
|
![]() |
| |
Respectfully submitted,
![]()
William D. Von Gonten, Jr., P.E.
TX # 73244 ![]()
John M. Parker
|
|
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
Reserves | | | Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. | | | Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests. | |
On Production | | | The development project is currently producing and selling petroleum to market. | | | The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project. | |
Approved for Development | | | All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way. | | | At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entities current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells. | |
Justified for Development | | | Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained. | | | In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/ | |
Class/Sub-Class
|
| |
Definition
|
| |
Guidelines
|
|
| | | | | | contracts, there should be no known contingencies that could preclude the development from proceeding within a reasonable timeframe (see Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time. | |
Contingent Resources | | | Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies. | | | Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. | |
Development Pending | | | A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future. | | | The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status. The project “decision gate” is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production. | |
Development Unclarified or on Hold | | | A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay. | | | The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to “Not Viable” status. The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the potential for eventual | |
Class/Sub-Class
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Definition
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Guidelines
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| | | | | | commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies. | |
Development Not Viable | | | A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential. | | | The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project “decision gate” is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future. | |
Prospective Resources | | | Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. | | | Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration. | |
Prospect | | | A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. | | | Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program. | |
Lead | | | A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios. | |
Play | | | A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects. | | | Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios. | |
Status
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Definition
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Guidelines
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Developed Reserves | | | Developed Reserves are expected quantities to be recovered from existing wells and facilities. | | | Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing. | |
Developed Producing Reserves | | | Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. | | | Improved recovery reserves are considered producing only after the improved recovery project is in operation. | |
Developed Non-Producing Reserves | | | Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. | | | Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. | |
Undeveloped Reserves | | | Undeveloped Reserves are quantities expected to be recovered through future investments: | | | (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. | |
Category
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Definition
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Guidelines
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Proved Reserves | | | Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and | | | If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent | |
Category
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Definition
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Guidelines
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| | | under defined economic conditions, operating methods, and government regulations. | | |
undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved provided that:
•
The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive.
•
Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.
|
|
Probable Reserves | | | Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. | | | It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved. | |
Possible Reserves | | | Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves. | | | The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where | |
Category
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| |
Definition
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Guidelines
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| | | | | | geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable. | |
Probable and Possible Reserves | | | (See above for separate criteria for Probable Reserves and Possible Reserves.) | | | The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations. | |
|
Exhibit
Number |
| |
Description
|
|
| 23.3* | | | | |
| 23.4* | | | | |
| 23.5* | | | | |
| 23.6* | | | | |
| 23.7* | | | | |
| 24* | | | | |
| 99.1# | | | Form of Vine proxy card for the special meeting. | |
| 99.2* | | | |
|
Name
|
| |
Title
|
|
|
/s/ Michael Wichterich
Michael Wichterich
|
| | Chairman of the Board and Interim Chief Executive Officer (Principal Executive Officer) | |
|
/s/ Domenic J. Dell’Osso, Jr.
Domenic J. Dell’Osso, Jr.
|
| | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | |
|
/s/ Gregory M. Larson
Gregory M. Larson
|
| | Vice President — Accounting and Controller (Principal Accounting Officer) | |
|
/s/ Timothy S. Duncan
Timothy S. Duncan
|
| | Director | |
|
/s/ Benjamin C. Duster, IV
Benjamin C. Duster, IV
|
| | Director | |
|
/s/ Sarah Emerson
Sarah Emerson
|
| | Director | |
|
/s/ Matthew M. Gallagher
Matthew M. Gallagher
|
| | Director | |
|
/s/ Brian Steck
Brian Steck
|
| | Director | |
Exhibit 5.1
DERRICK & BRIGGS, LLP
A PROFESSIONAL PARTNERSHIP
ATTORNEYS AND COUNSELORS AT LAW
BANCFIRST
TOWER, SUITE 2700
100 NORTH BROADWAY AVENUE
OKLAHOMA CITY,
OKLAHOMA 73102
September 1, 2021
Chesapeake Energy Corporation
6100 North Western Avenue
Oklahoma City, Oklahoma 73118
Ladies and Gentlemen:
We serve as Oklahoma counsel to Chesapeake Energy Corporation, an Oklahoma corporation (“Chesapeake”), which filed a registration statement on Form S-4 (as amended, the “Registration Statement”) with the Securities and Exchange Commission (the “Commission”) under the Securities Act of 1933, as amended (the “Act”), relating to the registration of shares of Chesapeake’s common stock, par value $0.01 per share (the “Shares”) to be issued under the Agreement and Plan of Merger, dated as of August 10, 2021 (the “Merger Agreement”), by and among Chesapeake, Hannibal Merger Sub, Inc., a Delaware corporation and a wholly owned subsidiary of Chesapeake, Hannibal Merger Sub, LLC, a Delaware limited liability company and a wholly owned subsidiary of Chesapeake, Vine Energy Inc., a Delaware corporation, and Vine Energy Holdings LLC, a Delaware limited liability company. Terms not otherwise defined in this Opinion Letter have the meanings ascribed in the Merger Agreement.
At your request, we are furnishing this Opinion Letter to you for filing as Exhibit 5.1 to the Registration Statement to fulfill the requirements of Item 601(b)(5) of Regulation S-K under the Act.
In preparing this Opinion Letter, we have examined (i) the certificate of incorporation and bylaws of Chesapeake (the “Organizational Documents”), (ii) the Merger Agreement, (iii) the Registration Statement and its exhibits, and (iv) originals or copies, certified or otherwise identified to our satisfaction, of such other instruments and other certificates of public officials and of officers and representatives of Chesapeake as we have deemed appropriate as a basis for our opinions.
We have assumed: (i) the genuineness of any signatures on all documents we have reviewed; (ii) the legal capacity of natural persons who have executed all documents we have reviewed; (iii) the authenticity of all documents submitted to us as originals; (iv) the conformity to originals of all documents submitted as copies and the authenticity of the originals of such copies; (v) the truth, accuracy and completeness of the information, representations and warranties contained in the records, documents, instruments and certificates we have reviewed and relied upon; (vi) the accuracy, completeness and authenticity of certificates of public officials; (vii) that the Registration Statement and the Organizational Documents, each as amended to this date, will not have been amended after this date in a manner that would affect the validity of our opinions; and (viii) that the Merger Agreement constitutes the valid and legally binding obligation of each party to the Merger Agreement, enforceable against such party in accordance with its terms. We have relied upon a certificate and other assurances of officers of Chesapeake as to factual matters without having independently verified such factual matters.
Chesapeake Energy Corporation
September 1, 2021
Page 2
We have further assumed that:
(i) The Registration Statement, and any amendments (including post-effective amendments), has become effective and complies with applicable law; and
(ii) The merger consideration (including the share consideration) will be duly approved by Chesapeake’s board of directors before the effective time of the First Merger and the other conditions to consummating the transactions contemplated by the Merger Agreement will have been satisfied or waived and such transactions are duly consummated.
Our opinions are limited to matters governed by the laws of the State of Oklahoma, and we express no opinion as to the laws of any other jurisdiction or as to the effect of or compliance with any state securities or blue sky laws.
Based upon the foregoing and on such legal considerations as we deem relevant, and subject to the assumptions, limitations and qualifications set forth in this Opinion Letter and in reliance on the statements of fact contained in the documents we have examined, we are of the opinion that:
1. Chesapeake is validly existing as a corporation under the laws of the State of Oklahoma and is in good standing under such laws.
2. The Shares have been duly authorized by all necessary corporate action on behalf of Chesapeake, and upon issuance and delivery under and in accordance with the terms and conditions set forth in the Registration Statement and the Merger Agreement, the Shares will be validly issued, fully paid and nonassessable.
We hereby consent to the reference to our firm under the caption “Legal Matters” in the proxy statement/prospectus forming a part of the Registration Statement and to the filing of this Opinion Letter as an exhibit to the Registration Statement. In giving this consent, we do not admit that we are within the category of persons whose consent is required under Section 7 of the Securities Act or the applicable rules and regulations of the Commission.
Very truly yours, | |
/s/ Derrick & Briggs, LLP | |
Derrick & Briggs, LLP |
Exhibit 23.2
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in this Registration Statement on Form S-4 of Chesapeake Energy Corporation of our report dated March 1, 2021 relating to the financial statements, which appears in Chesapeake Energy Corporation’s Annual Report on Form 10-K for the year ended December 31, 2020. We also consent to the reference to us under the heading “Experts” in such Registration Statement.
/s/ PricewaterhouseCoopers LLP | |
Oklahoma City, Oklahoma | |
September 1, 2021 |
Exhibit 23.3
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the use in this Registration Statement on Form S-4 of Chesapeake Energy Corporation of our report dated February 22, 2021, relating to the balance sheets of Vine Energy Inc. We also consent to the reference to us under the heading "Experts" in such Registration Statement.
/s/ Deloitte & Touche LLP
Dallas, Texas
September 1, 2021
Exhibit 23.4
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the use in this Registration Statement on Form S-4 of Chesapeake Energy Corporation of our report dated February 17, 2021, relating to the financial statements of Vine Oil & Gas LP. We also consent to the reference to us under the heading “Experts” in such Registration Statement.
/s/ Deloitte & Touche LLP
Dallas, Texas
September 1, 2021
Exhibit 23.5
CONSENT OF INDEPENDENT AUDITORS
We consent to the use in this Registration Statement on Form S-4 of Chesapeake Energy Corporation of our report dated February 22, 2021, relating to the financial statements of Brix Oil & Gas Holdings LP and Harvest Royalties Holdings LP. We also consent to the reference to us under the heading “Experts” in such Registration Statement.
/s/ Deloitte & Touche LLP
Dallas, Texas
September 1, 2021
Exhibit 23.6
CONSENT OF LAROCHE PETROLEUM CONSULTANTS, LTD.
We consent to the incorporation by reference in the Registration Statement on Form S-4 of Chesapeake Energy Corporation of our report for the Company and the references to our firm and said report, which appears in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020.
LaRoche Petroleum Consultants, Ltd. | ||
By: LPC, Inc., as General Partner | ||
By: | /s/ William M. Kazmann | |
William M. Kazmann | ||
President | ||
September 1, 2021 |
Exhibit 23.7
September 1, 2021
Vine Energy Inc.
5800 Granite Parkway, Suite 550
Plano, Texas 75024
Gentlemen:
The firm of W.D. Von Gonten & Co. consents to the use of its name and to the use of its estimates of reserves contained in our reports entitled “Vine Oil & Gas LP. Haynesville and Mid-Bossier Shale Properties Estimate of Reserves and Revenues SEC Pricing Case “As of” January 1, 2020,” “Vine Oil & Gas LP. Haynesville and Mid-Bossier Shale Properties Estimate of Reserves and Revenues SEC Pricing Case “As of” January 1, 2021,” “Vine Oil & Gas LP. Haynesville and Mid-Bossier Shale Properties Estimate of Reserves and Revenues Strip Pricing Case “As of” January 1, 2021,” “Brix Oil & Gas Holdings LP. Haynesville and Mid-Bossier Shale Properties Estimate of Reserves and Revenues SEC Pricing Case “As of” January 1, 2020,” “Brix Oil & Gas Holdings LP. Haynesville and Mid-Bossier Shale Properties Estimate of Reserves and Revenues SEC Pricing Case “As of” January 1, 2021,” “Brix Oil & Gas Holdings LP. Haynesville and Mid-Bossier Shale Properties Estimate of Reserves and Revenues Strip Pricing Case “As of” January 1, 2021,” “Harvest Royalties Holdings LP. Haynesville and Mid-Bossier Shale Properties Estimate of Reserves and Revenues SEC Pricing Case “As of” January 1, 2020,” “Harvest Royalties Holdings LP. Haynesville and Mid-Bossier Shale Properties Estimate of Reserves and Revenues SEC Pricing Case “As of” January 1, 2021” and “Harvest Royalties Holdings LP. Haynesville and Mid-Bossier Shale Properties Estimate of Reserves and Revenues Strip Pricing Case “As of” January 1, 2021” to the specific references to W.D. Von Gonten & Company as the independent petroleum engineering firm in the Prospectus relating to the offering of Class A common stock filed with the Securities and Exchange Commission on March 19, 2021, pursuant to Rule 424(b) of the Securities Act, relating to the Form S-1 (File No. 333-253366), and as supplemented on April 2, 2021, which are included in this Registration Statement on Form S-4. We consent to the inclusion of the aforementioned projections in this Registration Statement on Form S-4.
Yours truly, | |
/s/ William D. Von Gonten, Jr. | |
W.D. VON GONTEN & Co. | |
William D. Von Gonten, Jr. | |
President | |
Houston, Texas |
Exhibit 99.2
CONSENT OF HOULIHAN LOKEY CAPITAL, INC.
September 1, 2021
Vine Energy Inc.
5800 Granite Parkway Suite 550
Plano, TX 75024
Attn: Board of Directors
RE: | Proxy Statement / Prospectus of Vine Energy Inc. (“Vine”) which forms part of the Registration Statement on Form S-4 of Chesapeake Energy Corporation (File No. 333- ) (the “Registration Statement”). |
Dear Members of the Board of Directors:
Reference is made to our opinion letter (“opinion”), dated August 10, 2021.
Our opinion was provided for the information and assistance of the Board of Directors (the “Board”) of Vine (in its capacity as such) in connection with its evaluation of the transaction contemplated therein and may not be used, circulated, quoted or otherwise referred to for any other purpose, nor is it to be filed with, included in or referred to in whole or in part in any registration statement, proxy statement or any other document, except, in each instance, in accordance with our prior written consent. We understand that Vine has determined to include our opinion in the Proxy Statement / Prospectus of Vine (the “Proxy Statement/Prospectus”) included in the above referenced Registration Statement.
In that regard, we hereby consent to the reference to our opinion in the above referenced Proxy Statement/Prospectus included in the Registration Statement on Form S-4 under the captions “SUMMARY— Opinion of Vine’s Financial Advisor,” “THE MERGER—Background of the Merger,” “THE MERGER—Recommendation of the Vine Board and Reasons for the Merger,” “THE MERGER—Opinion of Vine’s Financial Advisor,” “THE MERGER—Certain Vine Unaudited Forecasted Financial Information,” and “THE MERGER AGREEMENT—Representations and Warranties” and to the inclusion of our opinion as Annex C to the Proxy Statement/Prospectus. Notwithstanding the foregoing, it is understood that our consent is being delivered solely in connection with the filing of the above-mentioned version of the Registration Statement as of the date hereof and that our opinion is not to be used, circulated, quoted or otherwise referred to for any other purpose, nor is it to be filed with, included in or referred to in whole or in part in any registration statement (including any subsequent amendments to the above-mentioned Registration Statement), proxy statement or any other document, except, in each instance, in accordance with our prior written consent.
In giving such consent, we do not thereby admit that we are experts with respect to any part of such Registration Statement within the meaning of the term “expert” as used in, or that we come within the category of persons whose consent is required under, the Securities Act of 1933, as amended, or the rules and regulations of the Securities and Exchange Commission promulgated thereunder.
Very truly yours,
/s/ HOULIHAN LOKEY CAPITAL, INC. |
HOULIHAN LOKEY CAPITAL, INC.
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