UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒
ANNUAL
REPORT
PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the
fiscal year
ended
December 31, 2018
or
☐
TRANSITION REPORT
PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period
from
____________ to ____________
Commission File Number 001-14039
Callon Petroleum Company
(Exact Name of Registrant as Specified in Its Charter)
_______________________________________________
|
|
|
|
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
|
|
64-0844345
(IRS Employer
Identification No.)
|
|
|
|
1401 Enclave Parkway, Suite 600 Houston, Texas
(Address of Principal Executive Offices)
|
|
77077
(Zip Code)
|
281-589-5200
(Registrant’s Telephone Number, Including Area Code)
|
|
|
|
|
Securities registered pursuant to Section 12(b) of the Act:
|
|
Title of Each Class
|
|
Name of Each Exchange on Which Registered
|
Common Stock, $0.01 par value
|
|
New York Stock Exchange
|
10.0% Series A Cumulative Preferred Stock
|
|
New York Stock Exchange
|
|
Securities registered pursuant to section 12 (g) of the Act: None
|
|
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company in Rule 12b-2 of the Exchange Act:
|
|
|
|
|
|
|
Large accelerated filer
|
☒
|
Accelerated filer
|
☐
|
Non-accelerated filer
|
☐
|
|
|
|
|
|
|
Smaller reporting company
|
☐
|
Emerging growth company
|
☐
|
|
|
.
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of
June 30, 2018
was approximately
$2,426,644,330
.
The Registrant had
227,875,828
shares of common stock outstanding as of
February 22, 2019
.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after
December 31, 2018
) relating to the Annual Meeting of Stockholders to be held on
May 9, 2019
, which are incorporated into Part III of this Form 10-K.
TABLE OF CONTENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Information on Oil and Natural Gas Operations (Unaudited)
|
|
|
Supplemental Quarterly Financial Information (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Special Note Regarding Forward Looking Statements
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-K by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as:
|
|
•
|
our oil and natural gas reserve quantities, and the discounted present value of these reserves;
|
|
|
•
|
the amount and nature of our capital expenditures;
|
|
|
•
|
our future drilling and development plans and our potential drilling locations;
|
|
|
•
|
the timing and amount of future capital and operating costs;
|
|
|
•
|
production decline rates from our wells being greater than expected;
|
|
|
•
|
commodity price risk management activities and the impact on our average realized prices;
|
|
|
•
|
business strategies and plans of management;
|
|
|
•
|
our ability to consummate and efficiently integrate recent acquisitions; and
|
|
|
•
|
prospect development and property acquisitions.
|
Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements, include:
|
|
•
|
general economic conditions including the availability of credit and access to existing lines of credit;
|
|
|
•
|
the volatility of oil and natural gas prices;
|
|
|
•
|
the uncertainty of estimates of oil and natural gas reserves;
|
|
|
•
|
the impact of competition;
|
|
|
•
|
the availability and cost of seismic, drilling and other equipment, waste and water disposal infrastructure, and personnel;
|
|
|
•
|
operating hazards inherent in the exploration for and production of oil and natural gas;
|
|
|
•
|
difficulties encountered during the exploration for and production of oil and natural gas;
|
|
|
•
|
the potential impact of future drilling on production from existing wells
|
|
|
•
|
difficulties encountered in delivering oil and natural gas to commercial markets;
|
|
|
•
|
changes in customer demand and producers’ supply;
|
|
|
•
|
the uncertainty of our ability to attract capital and obtain financing on favorable terms;
|
|
|
•
|
compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases;
|
|
|
•
|
the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells;
|
|
|
•
|
any increase in severance or similar taxes;
|
|
|
•
|
the financial impact of accounting regulations and critical accounting policies;
|
|
|
•
|
the comparative cost of alternative fuels;
|
|
|
•
|
credit risk relating to the risk of loss as a result of non-performance by our counterparties;
|
|
|
•
|
cyberattacks on the Company or on systems and infrastructure used by the oil and natural gas industry;
|
|
|
•
|
weather conditions; and
|
|
|
•
|
any other factors listed in the reports we have filed and may file with the SEC.
|
We caution you that the forward-looking statements contained in this Form 10-K are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K for the year ended
December 31, 2018
(the “
2018
Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto.
Should one or more of the risks or uncertainties described above or in our
2018
Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except required by applicable law.
In addition, we caution that reserve engineering is a process of estimating oil and natural gas accumulated underground and cannot be measured exactly. Accuracy of reserve estimates depend on a number of factors including data available at the point in time, engineering interpretation of the data, and assumptions used by the reserve engineers as it relates to price and cost estimates and recoverability. New results of drilling, testing, and production history may result in revisions of previous estimates and, if significant, would impact future development plans. As such, reserve estimates may differ from actual results of oil and natural gas quantities ultimately recovered.
Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
GLOSSARY OF CERTAIN TERMS
All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document:
|
|
•
|
ARO
: asset retirement obligation.
|
|
|
•
|
ASU
: accounting standards update.
|
|
|
•
|
Bbl
or
Bbls
: barrel or barrels of oil or natural gas liquids.
|
|
|
•
|
BOE
: barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.
|
|
|
•
|
BLM:
Bureau of Land Management.
|
|
|
•
|
Btu
: a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
|
|
|
•
|
Completion
: the process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
|
|
|
•
|
Cushing
: an oil delivery point that serves as the benchmark oil price for West Texas Intermediate.
|
|
|
•
|
DOI:
Department of Interior.
|
|
|
•
|
EPA:
United States Environmental Protection Agency.
|
|
|
•
|
FASB:
Financial Accounting Standards Board.
|
|
|
•
|
GAAP
: Generally Accepted Accounting Principles in the United States.
|
|
|
•
|
Henry Hub
: a natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.
|
|
|
•
|
Horizontal drilling
: a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval.
|
|
|
•
|
LIBOR
: London Interbank Offered Rate.
|
|
|
•
|
LOE
: lease operating expense.
|
|
|
•
|
MBbls
: thousand barrels of oil.
|
|
|
•
|
Mcf
: thousand cubic feet of natural gas.
|
|
|
•
|
MMcf
: million cubic feet of natural gas.
|
|
|
•
|
NGL or NGLs
: natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.
|
|
|
•
|
NYMEX
: New York Mercantile Exchange.
|
|
|
•
|
Oil
: includes crude oil and condensate.
|
|
|
•
|
OPEC:
Organization of Petroleum Exporting Countries.
|
|
|
•
|
PDPs
: proved developed producing reserves.
|
|
|
•
|
PUDs
: proved undeveloped reserves.
|
|
|
•
|
Realized price
: the cash market price less all expected quality, transportation and demand adjustments.
|
|
|
•
|
Royalty interest
: an interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.
|
|
|
•
|
RSU
: restricted stock units.
|
|
|
•
|
SEC
: United States Securities and Exchange Commission.
|
|
|
•
|
Waha
: a natural gas delivery point in West Texas that serves as the benchmark for natural gas.
|
|
|
•
|
Working interest
: an operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
|
|
|
•
|
WTI
: West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.
|
With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.
PART I.
ITEMS 1 and 2 – Business and Properties
Overview
Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. We were incorporated in the state of Delaware in 1994.
We are an independent oil and natural gas company focused on the acquisition and development of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. We have historically been focused on the Midland Basin and entered the Delaware Basin through an acquisition completed in February 2017. We further expanded our presence in the Delaware Basin through our acquisitions in 2018.
Our drilling activity during
2018
was predominantly focused on the horizontal development of several prospective intervals in the Midland and Delaware Basins, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. As a result of our horizontal development efforts and contributions from acquisitions, our net daily production for calendar year
2018
as compared to calendar year
2017
grew approximately
44%
to
32,926
BOE/d (approximately
79%
oil). For the year ended
December 31, 2018
, our net proved reserve volumes increased
74%
as compared to the year ended
December 31, 2017
, to
238.5
MMBOE, comprised of
76%
oil (
180.1
MMBbls) and
24%
natural gas (
350.5
Bcf). Approximately
54%
of our net proved year-end
2018
reserves were proved developed on a BOE basis.
We intend to grow our reserves and production through the drilling and development of our multi-year inventory of identified drilling locations. We will also seek to grow our inventory of locations through delineation of emerging zones and selective “bolt-on” acquisition and leasing programs in areas complementary to our core operating areas.
Our Business Strategy
Our principal objective is to enhance shareholder value through capital efficient growth in proved reserves and associated production and cash flows while acting as a responsible corporate citizen in the areas in which we operate. Key elements of the execution of this strategy include:
|
|
•
|
Optimizing the development of our multi-zone resource base through thoughtful plans of depletion that are educated by extensive analysis of subsurface data and empirical well results;
|
|
|
•
|
Maintaining strong cash margins per unit of production through cost management and proactive investment in production infrastructure;
|
|
|
•
|
Improving the capital efficiency of our operations in terms of both well productivity and capital outlays, including supporting facilities;
|
|
|
•
|
Maturing our asset base into a sustainable operating model for profitable reinvestment of cash flows for attractive, long-term returns on capital;
|
|
|
•
|
Growing our inventory of well locations through delineation of emerging targets on our existing acreage positions and selective acquisitions of leasehold rights and mineral interests in areas complementary to our existing core operating areas; and
|
|
|
•
|
Preserving a strong financial position, focusing on appropriate capital allocation decisions under various commodity pricing scenarios, prudent risk management and robust liquidity.
|
Our Strengths
We believe the following attributes position Callon to achieve its objectives:
|
|
•
|
Strong Foundation
- Reputation as a safe and responsible operator built over several decades in the oil and gas industry;
|
|
|
•
|
Quality Assets
- High quality Permian Basin asset base with several years of proven well results from multiple target zones that benefit from early investments in critical supporting infrastructure including sustainable investments in water recycling;
|
|
|
•
|
Operational Control
- High degree of operational control that allows us to efficiently maximize value through long-term and daily decisions that drive our strategy;
|
|
|
•
|
Talented Workforce
- Seasoned employee base that has continued to benefit from the hiring of quality employees across various disciplines that have been integrated into our unifying culture.
|
Oil and Natural Gas
Properties
Permian
Basin
As of
December 31, 2018
, we owned
84,705
net leasehold acreage in the Permian Basin, all of which was located in the Midland and Delaware Basins. Average net production from our Permian Basin properties increased
44%
to
32,926
BOE/d in
2018
from
22,940
BOE/d in
2017
. The following sets forth certain information about our major operating areas in the Permian Basin as of
December 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing Wells
|
|
Producing
|
|
|
|
|
Horizontal
|
|
Vertical
|
|
Horizontal Flow
|
|
|
Net Acres
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Unit Zones
|
Midland Basin
|
|
39,534
|
|
|
250
|
|
|
186.9
|
|
|
304
|
|
|
248.2
|
|
|
Middle Spraberry, Lower Spraberry,
Wolfcamp A,
Wolfcamp B,
Wolfcamp C
|
Delaware Basin
|
|
45,171
|
|
|
216
|
|
|
176.7
|
|
|
126
|
|
|
76.3
|
|
|
Third Bone Spring,
Wolfcamp A,
Wolfcamp B,
Wolfcamp C
|
Total Permian Basin
|
|
84,705
|
|
|
466
|
|
|
363.6
|
|
|
430
|
|
|
324.5
|
|
|
|
Reserve Data
As of
December 31, 2018
, our estimated net proved reserves grew
74%
from prior year-end, totaling
238.5
MMBOE and included
180.1
MMBbls of oil and
350.5
Bcf of natural gas with a standardized measure of discounted future net cash flows of
$2.9 billion
. Oil constituted approximately
76%
of our total estimated equivalent net proved reserves and approximately
72%
of our total estimated equivalent proved developed reserves. We added
85
MMBOE of new reserves in extensions and discoveries through our development efforts in our operating areas, where we drilled a total of
70
gross (
57.5
net) wells. We purchased reserves in place of
39.7
MMBOE from the Delaware Asset Acquisition as well as bolt-on acquisitions completed within the Permian Basin and reduced our estimated net proved reserves through net revisions of previous estimates of
2.0
MMBOE and reclassifications of
9.1
MMBOE to probable reserves. Our net revisions of previous estimates were primarily related to technical revisions of proved undeveloped reserves. We reclassified 19 PUD locations to probable reserves, primarily due to acreage trades and changes in our development plan, including larger pad development concepts and co-development of zones. These changes resulted in the anticipated drilling of PUD locations being moved beyond five years from initial booking. The changes in our proved reserves are as follows (in MBOE):
|
|
|
|
|
Proved reserves:
|
|
|
Reserves at December 31, 2017
|
|
136,974
|
|
Extensions and discoveries
|
|
84,955
|
|
Purchase of reserves in place
|
|
39,683
|
|
Revisions to previous estimates
|
|
(2,021
|
)
|
Reclassifications due to changes in development plan
|
|
(9,065
|
)
|
Production
|
|
(12,018
|
)
|
Reserves at December 31, 2018
|
|
238,508
|
|
Annually, the Company reviews its PUDs to ensure appropriate plans exist for development of this reserve category. PUD reserves are recorded only if the Company has plans to convert these reserves into PDPs within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our
2019
capital budget and, in subsequent years, the allocation of capital within our long-range business plan to convert PUDs to PDPs within this five year period. In general, our
2019
capital budget and our long-range capital plans are primarily governed by our expectations of internally generated cash flow, borrowing availability under our senior secured revolving credit facility (“Credit Facility”) and corporate credit metrics. Reserve calculations at any end-of-year period are representative of our development plans at that time. Changes in commodity pricing, oilfield service costs and availability, and other economic factors may lead to changes in development plans. The following table shows changes in proved undeveloped reserves for 2018 (in MBOE):
|
|
|
|
Proved undeveloped reserves:
|
|
Reserves at December 31, 2017
|
67,656
|
|
Extensions and discoveries
|
56,710
|
|
Purchases of reserves in place
|
9,861
|
|
Transfers to proved developed
|
(11,075
|
)
|
Revisions of previous estimates
|
(4,184
|
)
|
Reclassifications due to changes in development plan
|
(9,065
|
)
|
Reserves at December 31, 2018
|
109,903
|
|
A breakdown by commodity of our proved oil and natural gas reserves follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Proved developed reserves:
|
|
2018
|
|
2017
|
|
2016
|
Oil (MBbls):
|
|
92,202
|
|
|
51,920
|
|
|
32,920
|
|
Natural gas (MMcf):
|
|
218,417
|
|
|
104,389
|
|
|
61,871
|
|
MBOE:
|
|
128,605
|
|
|
69,318
|
|
|
43,232
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
Oil (MBbls):
|
|
87,895
|
|
|
55,152
|
|
|
38,225
|
|
Natural gas (MMcf):
|
|
132,049
|
|
|
75,021
|
|
|
60,740
|
|
MBOE:
|
|
109,903
|
|
|
67,656
|
|
|
48,348
|
|
Total proved reserves:
|
|
|
|
|
|
|
Oil (MBbls):
|
|
180,097
|
|
|
107,072
|
|
|
71,145
|
|
Natural gas (MMcf):
|
|
350,466
|
|
|
179,410
|
|
|
122,611
|
|
MBOE:
|
|
238,508
|
|
|
136,974
|
|
|
91,580
|
|
Controls Over Reserve Estimates
Compliance as it relates to reporting the Company’s reserves is the responsibility of our Chief Operating Officer, who is also our principal engineer. Until December 2018, our Chief Operating Officer was Gary A. Newberry who had over 36 years of industry experience, including 30 years as a manager, and holds a degree in Petroleum Engineering. In December 2018, Jeffrey S. Balmer became our Chief Operating Officer upon Mr. Newberry’s retirement from the Company. Dr. Balmer has over 30 years of operations and industry experience. In addition to his years of experience, Dr. Balmer holds B.S. and Ph.D. degrees in Petroleum Engineering, in addition to a M.S. in Environmental and Planning Engineering, and is experienced in asset evaluation and management.
Callon’s controls over reserve estimates included retaining DeGolyer and MacNaughton, a Texas registered engineering firm, as our Reserve Engineering Firm. The Company provided to DeGolyer and MacNaughton information about our oil and gas properties, including production profiles, prices and costs, and DeGolyer and MacNaughton prepared its own estimates of the reserves attributable to the Company’s properties. All of the information regarding
2018
,
2017
and
2016
reserves in this annual report is derived from DeGolyer and MacNaughton’s report. DeGolyer and MacNaughton’s reserve report letter is included as an exhibit to this annual report. The principal engineer at DeGolyer and MacNaughton, who certified the Company’s reserve estimates, has over 34 years of experience in the oil and gas industry and is a Texas Licensed Professional Engineer. Further professional qualifications include a degree in petroleum engineering and membership in the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
To further enhance the control environment over the reserve estimation process, our Strategic Planning and Reserves Committee, an independent committee of the Board of Directors, assists management and the Board with its oversight of the integrity of the determination of the Company’s oil and natural gas reserves and the work of our Reserve Engineering Firm. The Committee’s charter also specifies that the Committee shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities:
|
|
•
|
Oversee the appointment, qualification, independence, compensation and retention of the Reserve Engineering Firm engaged by the Company (including resolution of material disagreements between management and the Reserve Engineering Firm regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Committee shall review any proposed changes in the appointment of the Reserve Engineering Firm, determine the reasons for such proposal, and whether there have been any disputes between the Reserve Engineering Firm and management.
|
|
|
•
|
Review the Company’s significant reserves engineering principles and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure.
|
|
|
•
|
Review with management and the Reserve Engineering Firm the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from
|
prior period reports; (ii) reviewing key assumptions used or relied upon by the Reserve Engineering Firm; (iii) evaluating the quality of the reserve estimates prepared by both the Reserve Engineering Firm and the Company relative to the Company’s peers in the industry; and (iv) reviewing any material reserves adjustments and significant differences between the Company’s and Reserve Engineering Firm’s estimates.
|
|
•
|
If the Committee deems it necessary, it shall meet in executive session with the Reserve Engineering Firm to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves.
|
During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of total proved net oil and natural gas reserves.
See Supplemental Information on Oil and Natural Gas Operations in Item 8 - Financial Statements and Supplementary Data for additional information regarding our estimated net proved reserves and our estimated future net cash flows and discounted future net cash flows from proved reserves.
2019
Capital
Budget
Our operational capital budget for
2019
has been established in the range of
$500
to
$525 million
on an accrual, or GAAP, basis, running an average of five drilling rigs to support larger, and more efficient, multi-well pad development. Of this range, approximately 15% is comprised of infrastructure and facilities capital.
As part of our
2019
operated horizontal drilling program, we expect to place 47 to 49 net wells on production with an increase of approximately 15% in average net lateral length as compared to the 2018 program.
In addition to the operational capital expenditures budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated
$25
to
$30 million
for capitalized general and administrative expenses.
Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop, our reserves of oil and natural gas. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly.
Exploration and Development Activities
Our
2018
total capital expenditures, including acquisitions, on a cash basis were
$1,324.1 million
, of which
$546.1 million
consisted of operational capital expenditures, including drilling and completion and facilities and infrastructure expenditures.
For the year ended
December 31, 2018
, we drilled
70
gross (
57.5
net) horizontal wells, completed
65
gross (
53.1
net) horizontal wells and had
11
gross (
9.5
net) horizontal wells awaiting completion.
The following table sets forth the Company’s drilled wells, none of which were natural gas wells, nor nonproductive wells for the periods reflected:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
2017
(a)
|
|
2016
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Oil wells
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
(b)
|
|
15
|
|
|
12.8
|
|
|
15
|
|
|
10.7
|
|
|
9
|
|
|
4.9
|
|
Exploratory
(c)
|
|
55
|
|
|
44.7
|
|
|
33
|
|
|
26.5
|
|
|
20
|
|
|
16.0
|
|
Total
|
|
70
|
|
|
57.5
|
|
|
48
|
|
|
37.2
|
|
|
29
|
|
|
20.9
|
|
|
|
(a)
|
Does not include
one
gross (
0.97
net) nonproductive exploratory well.
|
|
|
(b)
|
A development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
|
|
|
(c)
|
An exploratory well is a well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
|
Productive Wells
As of
December 31, 2018
, we had
896
gross (
688.1
net) working interest oil wells,
three
gross (
0.1
net) royalty interest oil wells and no natural gas wells. A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both oil and natural gas.
Production Volumes, Average Sales Prices and Operating Costs
The following tables set forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, the Company’s sale of oil and natural gas for the periods indicated (dollars in thousands, except per unit data).
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Production
|
|
|
Midland Basin
|
|
|
|
|
|
|
Oil (MBbls)
|
|
7,557
|
|
|
5,871
|
|
|
4,280
|
|
Natural gas (MMcf)
|
|
13,042
|
|
|
10,061
|
|
|
7,758
|
|
Total Midland Basin (MBOE)
|
|
9,731
|
|
|
7,548
|
|
|
5,573
|
|
Delaware Basin
|
|
|
|
|
|
|
Oil (MBbls)
|
|
1,886
|
|
|
686
|
|
|
—
|
|
Natural gas (MMcf)
|
|
2,405
|
|
|
835
|
|
|
—
|
|
Total Delaware Basin (MBOE)
|
|
2,287
|
|
|
825
|
|
|
—
|
|
Total oil (MBbls)
|
|
9,443
|
|
|
6,557
|
|
|
4,280
|
|
Total natural gas (MMcf)
|
|
15,447
|
|
|
10,896
|
|
|
7,758
|
|
Total (MBOE)
|
|
12,018
|
|
|
8,373
|
|
|
5,573
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Revenues
|
|
|
|
|
|
|
Oil revenue
|
|
$
|
530,898
|
|
|
$
|
322,374
|
|
|
$
|
177,652
|
|
Natural gas revenue
|
|
56,726
|
|
|
44,100
|
|
|
23,199
|
|
Total
|
|
$
|
587,624
|
|
|
$
|
366,474
|
|
|
$
|
200,851
|
|
Operating costs
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
69,180
|
|
|
$
|
49,907
|
|
|
$
|
38,353
|
|
Production taxes
|
|
35,755
|
|
|
22,396
|
|
|
11,870
|
|
Total
|
|
$
|
104,935
|
|
|
$
|
72,303
|
|
|
$
|
50,223
|
|
Average realized sales price
(excluding impact of settled derivatives)
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
56.22
|
|
|
$
|
49.16
|
|
|
$
|
41.51
|
|
Natural gas (per Mcf)
|
|
3.67
|
|
|
4.05
|
|
|
2.99
|
|
Total (per BOE)
|
|
48.90
|
|
|
43.77
|
|
|
36.04
|
|
Average realized sales price
(including impact of settled derivatives)
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
53.31
|
|
|
$
|
47.78
|
|
|
$
|
45.67
|
|
Natural gas (per Mcf)
|
|
3.69
|
|
|
4.10
|
|
|
3.00
|
|
Total (per BOE)
|
|
46.63
|
|
|
42.76
|
|
|
39.25
|
|
Operating costs per BOE
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
5.76
|
|
|
$
|
5.96
|
|
|
$
|
6.88
|
|
Production taxes
|
|
2.98
|
|
|
2.67
|
|
|
2.13
|
|
Total
|
|
$
|
8.74
|
|
|
$
|
8.63
|
|
|
$
|
9.01
|
|
Major Customers
Our production is sold generally on month-to-month contracts at prevailing prices. The following table identifies customers to whom we sold a significant percentage of our total oil and natural gas production, on an equivalent basis, during each of the 12-month periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Rio Energy International, Inc.
|
|
28
|
%
|
|
17
|
%
|
|
—
|
%
|
Plains Marketing, L.P.
|
|
21
|
%
|
|
29
|
%
|
|
16
|
%
|
Enterprise Crude Oil, LLC
|
|
14
|
%
|
|
18
|
%
|
|
43
|
%
|
Shell Trading Company
|
|
8
|
%
|
|
9
|
%
|
|
18
|
%
|
Trafigura Trading, LLC
|
|
6
|
%
|
|
—
|
%
|
|
—
|
%
|
Other
|
|
23
|
%
|
|
27
|
%
|
|
23
|
%
|
Total
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security.
Leasehold Acreage
The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of
December 31, 2018
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
Undeveloped
|
|
Total
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Permian Basin
(a)
|
|
104,816
|
|
|
73,989
|
|
|
23,890
|
|
|
10,716
|
|
|
128,706
|
|
|
84,705
|
|
Other
|
|
936
|
|
|
200
|
|
|
188
|
|
|
55
|
|
|
1,124
|
|
|
255
|
|
Total
|
|
105,752
|
|
|
74,189
|
|
|
24,078
|
|
|
10,771
|
|
|
129,830
|
|
|
84,960
|
|
|
|
(a)
|
A portion of our Permian Basin acreage, which we have included in our development plans, requires continuous drilling to hold the acreage, though the cost to renew this acreage, if necessary, is not considered material.
|
The following table sets forth as of
December 31, 2018
the number of our leased gross and net undeveloped acres in the Permian Basin that will expire over the next three years unless production begins before lease expiration dates. Gross amounts may be more than net amounts in a particular year due to timing of expirations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
Gross
|
|
|
2019
|
|
2020
|
|
2021
|
|
Total
|
|
Total
|
Permian Basin
|
|
5,492
|
|
|
2,878
|
|
|
568
|
|
|
8,938
|
|
|
19,798
|
|
The expiring acreage set forth in the table above accounts for approximately
83%
of our net undeveloped acreage (
10,771
total net acres). We are continually engaged in a combination of drilling and development and discussions with mineral lessors for lease extensions, renewals, new drilling and development units and new leases to address any potential expiration of undeveloped acreage that occurs in the normal course of our business.
Other
Industry Segment and Geographic Information
For segment reporting purposes, the Company considers all of the current development and operating areas to be one reportable segment: the development and production of oil and natural gas. All of the Company’s assets and operations are located within the United States, and all of the production revenues generated from operations are contracted and sold to customers located in the United States.
Title to Properties
The Company believes that the title to its oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. The Company’s properties are potentially subject to one or more of the following:
|
|
•
|
royalties and other burdens and obligations, express or implied, under oil and natural gas leases;
|
|
|
•
|
overriding royalties and other burdens created by us or our predecessors in title;
|
|
|
•
|
a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements; farm-out agreements, production sales contracts and other agreements that may affect the properties or their titles;
|
|
|
•
|
back-ins and reversionary interests existing under purchase agreements and leasehold assignments;
|
|
|
•
|
liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements;
|
|
|
•
|
pooling, unitization and communitization agreements, declarations and orders; and
|
|
|
•
|
easements, restrictions, rights-of-way and other matters that commonly affect property.
|
To the extent that such burdens and obligations affect the Company’s rights to production revenues, these characteristics have been taken into account in calculating Callon’s net revenue interests and in estimating the size and value of its reserves. The Company believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon.
Seasonality of Business
Weather conditions and seasonality affect the demand for and prices of, oil and natural gas. Due to these fluctuations, results of operations for quarterly interim periods may not be indicative of the results realized on an annual basis.
Competition
The Company operates in the oil and natural gas industry, which is highly competitive. The Company’s business experiences strong competition from a number of parties that may range from small independent producers to major integrated companies. Competition affects the Company’s ability to acquire additional properties and resources necessary to develop assets. In higher commodity pricing environments, competition also exists in the form of contracting for drilling, pumping, and workover equipment, and securing skilled personnel to both develop and operate existing assets. Many of the competitors mentioned above may be able to pay for more sought-after properties or access equipment, infrastructure, or personnel. The industry also experiences, from time to time, shortages in resources such as the availability of drilling and workover rigs, other equipment, pipes and materials, infrastructures, and skilled personnel, all of which can delay development, exploration, and workover activities as well as result in significant cost increases.
Insurance
In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. While not all inclusive, the Company’s insurance policies generally protect against bodily injury and property damage, pollution and other environmental damages, employee benefits, employee injury and control of well insurance for its exploration and production operations.
The Company enters into master service agreements with its third-party contractors, including hydraulic fracturing contractors, in which they agree to indemnify the Company for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company and the Company’s other contractors. Additionally, each party generally is responsible for damage to its own property. The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company’s risk analysis we believe that we are properly insured, no assurance can be given that the Company will be able to maintain insurance in the future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.
Corporate Offices
The Company’s headquarters are located in Houston, Texas, in a building with office space leased by the Company. We own an office building in Natchez, Mississippi and lease and own offices in the Midland, Texas area. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures
.
Employees
Callon had
218
employees as of
December 31, 2018
. None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees.
Regulations
General.
Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. Legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for potential revision. Some of these requirements carry substantial penalties for failure to comply.
Exploration and Production
. Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are:
|
|
•
|
the location and spacing of wells;
|
|
|
•
|
the method of drilling and completing and operating wells;
|
|
|
•
|
the rate and method of production;
|
|
|
•
|
the surface use and restoration of properties upon which wells are drilled and other exploration activities;
|
|
|
•
|
notice to surface owners and other third parties;
|
|
|
•
|
the venting or flaring of natural gas;
|
|
|
•
|
the plugging and abandoning of wells;
|
|
|
•
|
the discharge of contaminants into water and the emission of contaminants into air;
|
|
|
•
|
the disposal of fluids used or other wastes obtained in connection with operations;
|
|
|
•
|
the marketing, transportation and reporting of production; and
|
|
|
•
|
the valuation and payment of royalties.
|
Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity.
Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. Historically, the industry has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.
We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position.
Environmental Matters and Regulation.
Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations which often require difficult and costly compliance measures. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relating to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of certain such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, air emissions or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. In recent years, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. Although such laws and regulations can increase the cost of planning, designing, installing and
operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace.
Waste Handling.
The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Additionally, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.
Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes.
Comprehensive Environmental Response, Compensation and Liability Act.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.
Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages.
We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, and for water disposal, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.
Water Discharges.
The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands), as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit from the U.S. Army Corps of Engineers. The EPA issued a final rule on the federal jurisdictional reach over waters of the United States in 2015. The rule is the subject of various legal challenges. Recently, the EPA proposed to repeal that rule and re-codify the pre-2015 rule while it revises the definition of “waters of the United States,” creating uncertainty regarding federal jurisdiction over waters of the United States.
The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.
The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.
Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.
Air Emissions.
The federal Clean Air Act, as amended, and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits. As a result, we may need to incur capital costs in order to remain in compliance. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations.
On June 3, 2016, the EPA expanded its regulatory coverage in the oil and natural gas industry with additional regulated equipment categories, and the addition of new rules limiting methane emissions from new or modified sites and equipment. Although the EPA attempted to suspend enforcement of the methane rule, this action was ruled improper by the U.S. Court of Appeals for the D.C. Circuit on July 2, 2017. Subsequently, in September 2018, the EPA issued a proposed rulemaking that could substantially change the obligations associated with methane emissions, limiting obligations for the oil and natural gas industry. That rulemaking has not been finalized and, therefore, future obligations continue to remain uncertain.
Climate Change.
Numerous reports from scientific and governmental bodies such as the United Nations Intergovernmental Panel on Climate Change have expressed heightened concerns about the impacts of human activity, especially fossil fuel combustion, on the global climate. In turn, governments and civil society are increasingly focused on limiting the emissions of greenhouse gases, including emissions of carbon dioxide from the use of oil and natural gas.
In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in 195 countries, including the United States, coming together to develop the so-called “Paris Agreement,” which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. While the United States announced that it would withdraw from the Paris Agreement on June 1, 2017, given the requirements of the withdrawal process the earliest possible exit would be November 2020. Certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. In addition, legislation has from time to time been introduced in Congress that would establish measures restricting GHG emissions in the United States, and a number of states have begun taking actions to control and/or reduce emissions of GHGs.
Any legislation or regulatory programs at the federal, state, or city levels designed to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Moreover, incentives to conserve energy or use alternative energy sources, such as policies designed to increase utilization of zero-emissions or electric vehicles, as a means of addressing climate change could reduce demand for the oil and natural gas we produce.
In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.
The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount of GHGs that can be emitted, they do require us to incur costs to monitor, keep records of, and report GHG emissions associated with our operations.
Parties concerned about the potential effects of climate change have also directed their attention at sources of financing for energy companies, which has resulted in certain financial institutions, funds and other capital providers restricting or eliminating their investment in oil and natural gas activities. In addition, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. Although our business is not a party to any such litigation, we could be named in actions making similar allegations, which could lead to costs and materially impact our financial condition in an adverse way.
Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves.
Regulation of Hydraulic Fracturing.
Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid, as further discussed below). Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing has been proposed in past legislative sessions but has not passed.
The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and business. Further, on June 28, 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.
On June 3, 2016, the EPA adopted regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards (“NSPS”) for hydraulically fractured natural gas and oil wells to address emissions of sulfur dioxide, volatile organic compounds (“VOCs”) and methane, with a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule sought to achieve a 95% reduction in VOCs and methane emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured gas and oil wells newly constructed or refractured. The rules also established specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. Notably, on October 15, 2018, the EPA published a proposed rule that would make a series of revisions to the 2016 NSPS; these revisions have yet to be finalized.
Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on a website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.
Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some cases impose a moratorium on, hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; or restrictions on access to, and usage of, water. Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the U.S. implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations of harm. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of potential federal or state legislation governing hydraulic fracturing.
Surface Damage Statutes (“SDAs”)
. In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities in addition to bonding requirements to compensate for damages to the surface as a result of such activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.
National Environmental Policy Act and Endangered Species Act
. Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Recent litigation by environmental non-governmental organizations has alleged that the Environmental Assessments for certain oil and natural gas projects violated NEPA by failing to account for climate change and the greenhouse gas emissions impacts of such projects. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.
The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If the Company was to have a portion of its leases designated as critical or suitable habitat or a protected species were located on a lease, it may adversely impact the value of the affected leases.
Other Regulation of the Oil and Natural Gas Industry.
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other similar companies in the industry with similar types, quantities and locations of production.
The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the rates and other terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.
Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate, oil and natural gas liquids are not currently regulated and are made at market prices.
Exports of US Oil Production and Natural Gas Production
. In December 2015, the federal government ended its decades-old prohibition of exports of oil produced in the lower 48 states of the US. As a result, exports of U.S. oil have increased significantly, reinforcing the general perception in the industry that the end of the U.S. export ban was positive for producers of U.S. oil. In addition, the U.S. Department of Energy (“DOE”) authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, and the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction of which are regulated by FERC. Since 2016, natural gas produced in the lower 48 states of the U.S. has been exported as LNG from LNG export facilities being developed and constructed in the U.S. Gulf Coast region. This export capacity has steadily increased, and is expected to continue on that trajectory. The general perception in the industry is that this sustained growth in exports will be a positive development for producers of U.S. natural gas.
Drilling and Production.
Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:
|
|
•
|
the method of drilling and casing wells;
|
|
|
•
|
the timing of construction or drilling activities, including seasonal wildlife closures;
|
|
|
•
|
the rates of production or “allowables”;
|
|
|
•
|
the surface use and restoration of properties upon which wells are drilled;
|
|
|
•
|
the plugging and abandoning of wells; and
|
|
|
•
|
notice to, and consultation with, surface owners and other third parties.
|
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affecting the economics of production from these wells or to limit the number of locations we can drill.
Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Some state agencies and municipalities require bonds or other financial assurances to support those obligations.
Natural Gas Sales and Transportation.
Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005 (“EPAct”), FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.
Under the EPAct Congress amended the Natural Gas Act (“NGA”) to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. EPAct also amended the NGA to authorize FERC to “facilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce,” pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery.
FERC also regulates interstate natural gas transportation rates, terms and conditions of natural gas transportation service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC.
With respect to its regulation of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a new interstate natural gas pipeline to produce evidence of the GHG emissions of the proposed pipeline’s customers. In August 2017, the U.S. Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, which required FERC to revise its environmental impact statement for the proposed pipeline to take into account GHG carbon emissions from downstream power plants using natural gas transported by the new pipeline. It is too early to determine the impacts of this Court decision, but it could be significant.
Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations.
The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In addition, PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2015, PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and that operators address affected pipelines following extreme weather events or natural disasters. On January 13, 2017, these proposed regulations were finalized; however, the rule was subsequently withdrawn by PHMSA on January 24, 2017. The future disposition of these potential new requirements remains uncertain.
Oil and NGLs Sales and Transportation.
Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by FERC under the Interstate Commerce Act. FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.
Further, interstate common carrier oil pipelines must provide service on a non-discriminatory basis under the Interstate Commerce Act (“ICA”), which is administered by FERC. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, which held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the filed tariff rate, would violate the ICA. Rehearing has been sought of this FERC order by various pipelines. It is too recent an event to determine the impact this FERC order may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines.
Any transportation of the Company’s oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA regulations initially established on May 8, 2015 by PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids; PHMSA regulations were subsequently amended to remove certain requirements on September 25, 2018.
On January 13, 2017, PHMSA issued final new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and addressing affected pipelines following extreme weather events or natural disasters. However, this rule was subsequently withdrawn by PHMSA on January 24, 2017; the future disposition of these potential new requirements remains uncertain.
State Regulation.
Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
Commitments and Contingencies
The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from the Company’s operations could have on its activities. See
Note 14
in the Footnotes to the Financial Statements for additional information.
Available
Information
We make available free of charge on our website (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC.
We also make available within the “About Callon” section of our website our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation, Strategic Planning and Reserve, and Nominating and Corporate Governance Committee Charters, which have been approved by our Board of Directors. We will make timely disclosure on our website of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: General Counsel, Callon Petroleum Company, 1401 Enclave Parkway, Suite 600, Houston, TX 77077.
ITEM 1A. Risk Factors
Risk Factors
Risks Related to the Oil & Natural Gas Industry
Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial condition
. Our success is highly dependent on prices for oil and natural gas, which have been extremely volatile in recent years. Approximately 75% - 80% of our anticipated
2019
production is oil, on a BOE basis. Extended periods of low prices for oil or natural gas will have a material adverse effect on us. The prices of oil and natural gas depend on factors we cannot control such as macro-economic conditions, levels of production, demand for oil and natural gas, relative price and availability of alternative forms of energy, actions by OPEC and other countries, legislative and regulatory actions, technology developments impacting energy consumption and energy supply, and weather. Prices of oil and natural gas will affect the following aspects of our business:
|
|
•
|
our revenues, cash flows, earnings and returns;
|
|
|
•
|
the amount of oil and natural gas that we are economically able to produce;
|
|
|
•
|
our ability to attract capital to finance our operations and the cost of the capital;
|
|
|
•
|
the amount we are allowed to borrow under our Credit Facility;
|
|
|
•
|
the profit or loss we incur in exploring for and developing our reserves; and
|
|
|
•
|
the value of our oil and natural gas properties.
|
These factors and the volatility of the energy markets, which we expect will continue, make it extremely difficult to predict future oil, natural gas and NGLs price movements with any certainty. During the five years ended December 31, 2018, NYMEX WTI oil futures contract prices ranged from a high of
$107.26
per barrel on
June 20, 2014
to a low of
$26.21
per barrel on
February 11, 2016
, and NYMEX Henry Hub gas futures prices ranged from a high of
$6.15
per MMBtu on
February 19, 2014
to a low of
$1.64
per MMBtu on
March 3, 2016
. As of
December 31, 2018
, NYMEX WTI oil futures contract prices and NYMEX Henry Hub gas futures prices were
$45.41
per barrel and
$2.94
per MMBtu, respectively.
Although oil and natural gas prices have increased significantly since 2016, a buildup in inventories, lower global demand, or other factors could cause commodity prices to weaken, which could negatively affect our cash flows and results of operations. Under such conditions, we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in the present value of our reserves and our ability to develop future reserves. Lower commodity prices may also reduce the amount of oil and natural gas that we can produce economically.
If commodity prices decrease from current levels, a significant portion of our development projects could become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. In addition, fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas.
Any substantial and extended decline in the price of oil or natural gas could have an adverse effect on our borrowing capacity, our ability to obtain additional capital, and our revenues, profitability and cash flows.
If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties.
Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using the preceding 12-months’ average oil and natural gas prices, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and natural gas properties exceed this “ceiling test” limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of our properties quarterly and once incurred, a write-down of oil and natural gas properties is not reversible at a later date, even if prices increase. See
Note 2
in the Footnotes to the Financial Statements as well as the Supplemental Information on Oil and Natural Gas Operations for additional information.
For the period ended
December 31, 2018
, we did not recognize a write-down of oil and natural gas properties as a result of the ceiling test limitation. The ceiling test calculation as of
December 31, 2018
was calculated using the average annual realized prices used in determining the estimated future net cash flows from proved reserves of
$58.40
per barrel of oil and
$3.64
per Mcf of natural gas. Oil
prices continue to fluctuate and we may experience ceiling test write-downs in the future. Any future ceiling test cushion, and the risk we may incur write-downs or impairments, will be subject to fluctuation as a result of acquisition or divestiture activity.
Our estimated reserves are based on interpretations and assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
This
2018
Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. Additionally, estimates of reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas.
You should not assume that any present value of future net cash flows from our estimated net proved reserves contained in this
2018
Annual Report on Form 10-K represents the market value of our oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at
December 31, 2018
on average 12-month prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. At
December 31, 2018
, approximately
29%
of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented
46%
of total proved reserves by volume. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general.
Unless we replace our oil and gas reserves, our reserves and production will decline.
Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. We may not be successful in finding, developing or acquiring additional reserves, and our efforts may not be economic. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable.
Competitive industry conditions may negatively affect our ability to conduct operations.
We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment, personnel and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. Factors that affect our ability to compete in the marketplace include our:
|
|
•
|
access to the capital necessary to drill wells and acquire properties;
|
|
|
•
|
ability to acquire and analyze seismic, geological and other information relating to a property;
|
|
|
•
|
ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;
|
|
|
•
|
ability to procure materials, equipment, personnel and services required to explore, develop and operate our properties, including the ability to procure fracture stimulation services on wells drilled; and
|
|
|
•
|
ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production.
|
The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
From time to time, our industry experiences a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews and other experienced personnel rise as the level of activity increases. Increasing
levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies, water or qualified personnel can materially and adversely affect our operations and profitability.
Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic region. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.
All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services, or market limitations or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
We may
be unable to integrate successfully the operations of recent acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions.
Our business has, and may in the future include, acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our recent acquisitions or from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions may involve numerous risks, including:
|
|
•
|
operating a larger combined organization and adding operations;
|
|
|
•
|
difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area;
|
|
|
•
|
risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;
|
|
|
•
|
loss of significant key employees from the acquired business;
|
|
|
•
|
inability to obtain satisfactory title to the assets we acquire;
|
|
|
•
|
a decrease in our liquidity if we use a portion of our available cash to finance acquisitions;
|
|
|
•
|
a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
|
|
|
•
|
diversion of management’s attention from other business concerns;
|
|
|
•
|
failure to realize expected profitability or growth;
|
|
|
•
|
failure to realize expected synergies and cost savings;
|
|
|
•
|
coordinating geographically disparate organizations, systems and facilities; and
|
|
|
•
|
coordinating or consolidating corporate and administrative functions.
|
Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisition and current operations, which in turn, could negatively impact our results of operations.
We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.
We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, adequacy of title, operating and capital costs and potential environmental and other liabilities. Although we conduct a review which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface, title and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.
Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner.
Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local land owners and other third party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. Along with the risks of other extreme weather events, drought risk, in particular, is likely increased by climate change. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations.
Factors beyond our control affect our ability to market production and our financial results.
The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. These factors could negatively affect our ability to market all of the oil or natural gas we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce. These factors include:
|
|
•
|
the extent of domestic production and imports/exports of oil and natural gas;
|
|
|
•
|
federal regulations authorizing exports of liquefied natural gas (“LNG”), the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the first LNG exports from such facilities;
|
|
|
•
|
the construction of new pipelines capable of exporting U.S. natural gas to Mexico and Permian Basin oil production to the Gulf Coast;
|
|
|
•
|
the proximity of hydrocarbon production to pipelines;
|
|
|
•
|
the availability of gas processing, pipeline, and/or refining capacity;
|
|
|
•
|
the demand for oil and natural gas by utilities and other end users;
|
|
|
•
|
the availability of alternative fuel sources;
|
|
|
•
|
the effects of inclement weather;
|
|
|
•
|
state and federal regulation of oil and natural gas marketing; and
|
|
|
•
|
federal regulation of natural gas sold or transported in interstate commerce.
|
In particular, in areas with increasing non-conventional shale drilling activity, pipeline, rail or other transportation capacity may be limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built.
The marketability of
our production is dependent upon transportation facilities and services owned and operated by third parties, and the unavailability of these facilities or services would have a material adverse effect on our revenue.
Our ability to market our production depends on the availability and capacity of gas processing facilities and pipeline and other transportation operations, including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity or other reasons. In addition, in certain newer development areas, processing and transportation facilities and services may not be sufficient to accommodate potential production. Our failure to obtain access to processing and transportation facilities and services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable processing or transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows.
We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the necessary quantities of production, our results of operations, financial position, and liquidity could be adversely affected.
We have entered into firm transportation agreements for a portion of our production in such areas in order to assure our ability, and that of our purchasers, to successfully market our production. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be more costly than interruptible or short-term transportation agreements. Additionally, these agreements obligate us to pay fees on minimum volumes regardless of actual throughput. If we have insufficient production to meet the minimum volumes, the requirements to pay for quantities not delivered could have an impact on our results of operations, financial position, and liquidity.
Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns.
Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee
that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Wells may have production decline rates that are greater than anticipated. Future drilling and completion efforts may impact production from existing wells, and parent-child effects may impact future well productivity as a result of timing, spacing proximity or other factors.
In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including among others:
|
|
•
|
unexpected drilling conditions;
|
|
|
•
|
pressure or irregularities in formations;
|
|
|
•
|
lack of proximity to and shortage of capacity of transportation facilities;
|
|
|
•
|
equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; and
|
|
|
•
|
compliance with governmental requirements.
|
Failure to conduct our oil and gas operations in a profitable manner may result in write-downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows.
Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling.
Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including among others:
|
|
•
|
oil and natural gas prices;
|
|
|
•
|
the availability and cost of capital;
|
|
|
•
|
availability and cost of drilling, completion and production services and equipment;
|
|
|
•
|
drilling results and production decline rates;
|
|
|
•
|
gathering, marketing and transportation constraints; and
|
Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
Approximately
46%
of our total estimated proved reserves as of
December 31, 2018
, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.
The results of our planned development programs in new or emerging shale
development areas
and formations may be subject to more uncertainties than
programs in more established
areas and formations,
and may not meet our expectations for reserves or production.
The results of our horizontal drilling efforts in emerging areas and formations of the Permian Basin are generally more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations such as the Wolfcamp, Spraberry and Bone Spring horizons. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the Texas Railroad Commission, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to
adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, access to gathering systems and takeaway capacity or otherwise, and/or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
Unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our ability to conduct business.
There are many operating hazards in exploring for and producing oil and natural gas, including:
|
|
•
|
our drilling operations may encounter unexpected formations or pressures, which could cause damage to equipment or personal injury;
|
|
|
•
|
we may experience equipment failures which curtail or stop production;
|
|
|
•
|
we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other corrective action to be taken; and
|
|
|
•
|
storms and other extreme weather conditions could cause damages to our production facilities or wells.
|
Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas-leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures.
If we experience any of these problems, it could affect wells, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of:
|
|
•
|
injury or loss of life;
|
|
|
•
|
severe damage to and destruction of property, natural resources and equipment;
|
|
|
•
|
pollution and other environmental damage;
|
|
|
•
|
clean-up responsibilities;
|
|
|
•
|
regulatory investigation and penalties;
|
|
|
•
|
suspension of our operations; and
|
|
|
•
|
repairs to resume operations.
|
We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations.
Multi-well pad drilling may result in volatility in our operating results.
We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may cause volatility in our quarterly operating results.
The loss of key personnel could adversely affect our ability to operate.
We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees and our third party consultants, none of whom are subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
Our business could be negatively affected by security threats. A cyberattack or similar incident could occur
and result in information theft, data corruption, operational disruption, damage to our reputation and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and
record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Our technologies, systems, networks, seismic data, reserves information or other proprietary information, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyberattacks.
Risks Related to Financial Position
Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all
. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings from financial institutions, the sale of public debt and equity securities and asset dispositions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, participation of non-operating working interest owners, the cost and availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
If the borrowing base under our Credit Facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations.
Restrictive covenants in our Credit Facility and the indenture governing our 6.125% senior unsecured notes due 2024 (“6.125% Senior Notes”)
and 6.375% senior unsecured notes due 2026 (“
6.375%
Senior Notes”)
may limit our ability to respond to changes in market conditions or pursue business opportunities.
Our Credit Facility and the indenture governing our 6.125% Senior Notes and 6.375% Senior Notes contain restrictive covenants that limit our ability to, among other things:
|
|
•
|
incur additional indebtedness;
|
|
|
•
|
merge or consolidate with another entity;
|
|
|
•
|
pay dividends or make certain other payments;
|
|
|
•
|
hedge future production or interest rates;
|
|
|
•
|
create liens that secure indebtedness;
|
|
|
•
|
engage in certain other transactions without the prior consent of the lenders.
|
As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
In addition, our Credit Facility requires us to maintain certain financial ratios and to make certain required payments of principal, premium, if any, and interest. If we fail to comply with these provisions or other financial and operating covenants in the Credit Facility and the indenture governing the 6.125% Senior Notes and 6.375% Senior Notes, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default:
|
|
•
|
the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest;
|
|
|
•
|
the lenders under our Credit Facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and
|
|
|
•
|
we could be forced into bankruptcy or liquidation.
|
Our borrowings under our Credit Facility expose us to interest rate risk.
Our earnings are exposed to interest rate risk associated with borrowings under our Credit Facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from
1.25%
to
2.25%
depending on the interest rate used and the amount of the loan outstanding in relation to the borrowing base.
The borrowing base under our Credit Facility may be reduced below the amount of borrowings outstanding under such facilities.
The borrowing base under our Credit Facility is currently
$1.1 billion
, with elected commitments of
$850 million
. In the future, we may not be able to access adequate funding under our Credit Facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations. In addition, we cannot borrow amounts above the elected commitments, even if the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. Our borrowing base is subject to redeterminations semi-annually, and our next scheduled borrowing base redetermination is expected to occur on or about
May 2019
. If our borrowing base were to be reduced, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. In addition, in the event the amount outstanding under our Credit Facility exceeds the elected commitments, we must repay such amounts immediately in cash. In the event the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over six monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our Credit Facility.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to certain financial, economic, competitive and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. Our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.
Our leverage and debt service obligations may adversely affect our financial condition, results of operations, and business prospects.
As of
December 31, 2018
, we had
$600 million
outstanding of 6.125% Senior Notes due 2024,
$400 million
outstanding of our 6.375% Senior Notes due 2026, and
$200 million
outstanding under our Credit Facility, which had an additional
$632.3 million
available for borrowings based on the existing level of commitments. Our amount of indebtedness could affect our operations in several ways, including the following:
|
|
•
|
require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities;
|
|
|
•
|
limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
|
|
|
•
|
increase our vulnerability to downturns and adverse developments in our business and the economy;
|
|
|
•
|
limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
|
|
|
•
|
place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;
|
|
|
•
|
make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings;
|
|
|
•
|
make us vulnerable to increases in interest rates as our indebtedness under our Credit Facility may vary with prevailing interest rates;
|
|
|
•
|
place us at a competitive disadvantage relative to competitors with lower levels of indebtedness or less restrictive terms governing their indebtedness; and
|
|
|
•
|
make it more difficult for us to satisfy our obligations under the 6.125% Senior Notes, 6.375% Senior Notes, or other debt and increase the risk that we may default on our debt obligations.
|
We cannot assure you that we will be able to maintain or improve our leverage position.
An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control.
We may not be insured against all of the risks to which our business is exposed from ongoing or legacy operations.
In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover all losses or liabilities related to our current or legacy operations. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable and may elect none or minimal insurance coverage. The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations.
Our hedging program may limit potential gains from increases in commodity prices or may result in losses or may be inadequate to protect us against continuing and prolonged declines in commodity prices.
We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Our hedges at
December 31, 2018
are in the form of collars, put and call options, basis swaps, and other structures placed with the commodity trading branches of certain national banking institutions and with certain other commodity trading groups. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil and natural gas. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices. These hedges may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition would be negatively impacted.
We may not have production to offset hedges.
Part of our business strategy is to reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of physical production.
Our hedging transactions expose us to counterparty credit risk.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. During periods of falling commodity prices, our hedging transactions expose us to risk of financial loss if our counterparty to a derivatives transaction fails to perform its obligations under a derivatives transaction. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results
.
Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production, which we market to energy marketing companies, refineries and affiliates, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of
our oil and natural gas accounted for approximately
28%
of our total oil and natural gas revenues for the year ended
December 31, 2018
. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Our ability to use our existing net operating loss carryforwards or other tax attributes could be limited.
At December 31, 2018, we had approximately $721 million of federal NOL carryforwards available to offset against future taxable income. Of this NOL carryforward balance, $663 million was generated prior to the effective date of new limitations on utilization of NOLs imposed by the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and are allowable as a
deduction against 100 percent of taxable income in future years but will start to expire in the tax year 2021.
Utilization of any NOL depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). Future ownership changes or future regulatory changes could limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.
We have no plans to pay cash dividends on our common stock in the foreseeable future.
The terms of our Credit Facility contain limitations that impact our ability to pay dividends and make other distributions. In addition, any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors.
The availability of shares for sale in the future could reduce the market price of our common stock.
In the future, we may issue securities to raise cash for acquisitions. We may also acquire interests in other companies by using a combination of cash and our common stock or only our common stock. We may also issue securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share and have an adverse impact on the price of our common stock. In addition, sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. This could also impair our ability to raise additional capital through the sale of our securities.
Legal and Regulatory Risks
We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties.
Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. For a discussion of the material regulations applicable to us, see “Regulations.” These laws and regulations may:
|
|
•
|
require that we acquire permits before commencing drilling;
|
|
|
•
|
regulate the spacing of wells and unitization and pooling of properties;
|
|
|
•
|
impose limitations on production or operational, emissions control and other conditions on our activities;
|
|
|
•
|
restrict the substances that can be released into the environment or used in connection with drilling and production activities or restrict the disposal of waste from our operations;
|
|
|
•
|
limit or prohibit drilling activities on protected areas such as wetlands, wilderness or other protected areas;
|
|
|
•
|
impose penalties and other sanctions for accidental and/or unpermitted spills or releases from our operations; and
|
|
|
•
|
require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned production facilities.
|
Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, failure to comply with these laws and regulations may result in the assessment of penalties, permit revocations, requirements for additional pollution controls or injunctions limiting or prohibiting operations.
The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as emissions control, waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to environmental matters. Even if regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term.
Further, under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, GHGs and hydraulic fracturing. Under the common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from properties in the event of environmental incidents.
Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production and is typically regulated by state oil and gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting and regulatory control of hydraulic fracturing but has not passed. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. The EPA has also published air emission standards for certain equipment, processes and activities across the oil and natural gas sector, although the EPA is currently in the process of revising its approach to regulation of methane emission.
In some areas of Texas, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the governing Texas regulatory agency is reviewing the data to determine whether any action is necessary to address this issue. If the Texas state agency were to decline to issue permits for, or limit the volumes of, new injection wells into the formations currently utilized by us, we may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase our costs.
Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, impose additional requirements on hydraulic fracturing activities or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, Texas law requires the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public. Furthermore, the RRC has issued the “well integrity rule” which includes new testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or cessation of drilling, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Additionally, the RRC has adopted a rule requiring applicants for certain new water disposal wells to conduct seismic activity searches using the U.S. Geological Survey to determine the potential for earthquakes within a circular area of 100 square miles. The rule also clarifies the RRC’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits for waste disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general and/or hydraulic fracturing in particular.
In December 2016, the EPA released its final report “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” This report concludes that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain date gaps and uncertainties limited EPA’s assessment. This study could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, water usage and the potential for impacts to surface water, groundwater and the environment generally, and a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing or water disposal wells are adopted, such laws could make it more difficult or costly for us to drill for and produce oil and natural gas as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and
abandonment requirements, permitting delays and potential increases in costs. These changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.
Climate change legislation or regulations restricting emissions of greenhouse gases, changes in the availability of financing for fossil fuel companies, and physical effects from climate change could adversely impact our operating costs and demand for the oil and natural gas we produce.
In recent years, federal, state and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Several states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. While we are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of existing and proposed GHG rules and regulations, see “Regulations.”
In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in 195 countries, including the United States, coming together to develop the so-called “Paris Agreement,” which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. While the United States announced that it would withdraw from the Paris Agreement on June 1, 2017, given the requirements of the withdrawal process the earliest possible exit would be November 2020. Certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. A number of states have begun taking actions to control and/or reduce emissions of GHGs. Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.
Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit GHGs directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.
In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. Although our business in not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves.
Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter derivatives and requires the U.S. Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market.
Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of the CFTC’s rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC has proposed but not yet approved position limits for certain futures and options contracts in various commodities and for
swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). Similarly, the CFTC has proposed but not yet finalized a rule regarding the capital that a swap dealer or major swap participant is required to post with respect to its swap business. The CFTC issued a final rule on margin requirements for uncleared swap transactions in January 2016, which it amended in November 2018. The final rule as amended includes an exemption for certain commercial end-users that enter into uncleared swaps in order to hedge bona fide commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exception from the requirement to use cleared exchanges (rather than hedging over-the-counter) for commercial end-users who use swaps to hedge their commercial risks. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business.
While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, these rules and regulations may provide beneficial exemptions or may require us to comply with position limits and other limitations with respect to our financial derivative activities. When a final rule on capital requirements is issued, the Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets which would reduce the ability of commercial end-users like us to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of future swaps relative to the terms of our existing financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter.
In addition, federal banking regulators have adopted new capital requirements for certain regulated financial institutions in connection with the Basel III Accord. The Federal Reserve Board also issued proposed regulations on September 30, 2016, proposing to impose higher risk-weighted capital requirements on financial institutions active in physical commodities, such as oil and natural gas. If and when these proposed regulations are fully implemented, financial institutions subject to these higher capital requirements may require that we provide cash or other collateral with respect to our obligations under the financial derivatives and other contracts in order to reduce the amount of capital such financial institutions may have to maintain. Alternatively, financial institutions subject to these capital requirements may require premiums to enter into derivatives and other physical commodity transactions to compensate for the additional capital costs for these transactions. Rules implementing the Basel III Accord and higher risk-weighted capital requirements could materially reduce our liquidity and increase the cost of derivative contracts and other physical commodity contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes).
If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments. Our revenues could t be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
Tax laws and regulations may change over time, and the recently passed comprehensive tax reform bill could adversely affect our business and financial condition.
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Act that significantly reforms the Internal Revenue Code of 1986, as amended (the “Code”). The Tax Act, among other things, (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies. The Tax Act is complex and far-reaching and we cannot predict with certainty the resulting impact its enactment has on us. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued and any such changes in interpretations or assumptions could adversely affect our business and financial condition. See
Note 12
to our consolidated financial statements included elsewhere in this Annual Report for additional information.
In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes are not included in the Tax Act, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or
the effective date of any such legislation would be. The elimination of such U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition.
Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock.
Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our board of directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law. These provisions could discourage an acquisition of the Company or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock.
We may be subject to the actions of activist shareholders.
We have been the subject of an activist shareholder in the past. Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction, strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected to our board of directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strategy may be adversely affected.
ITEM 1B. Unresolved Staff Comments
None.
ITEM 3. Legal Proceedings
We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We believe that the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations.
ITEM 4.
Mine Safety Disclosures
Not applicable.
PART II.
ITEM 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common stock trades on the New York Stock Exchange under the symbol “CPE”.
Holders
As of
February 22, 2019
the Company had approximately
2,630
common stockholders of record.
Dividends
We have not paid any cash dividends on our common stock to date and presently do not expect to declare or pay any cash dividends on our common stock in the foreseeable future as we intend to reinvest our cash flows and earnings into our business. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors. In addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock.
Holders of our 10% Series A Cumulative Preferred Stock are entitled to a cumulative dividend whether or not declared, of
$5.00
per annum, payable quarterly, equivalent to 10.0% of the liquidation preference of
$50.00
per share. Unless the full amount of the dividends for the 10% Series A Cumulative Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock.
Equity Compensation Plan Information
The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of
December 31, 2018
(securities amounts are presented in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
Plan Category
|
|
Number of Securities to be Issued Upon Exercise of Outstanding Options
|
|
Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights
|
|
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
|
Equity compensation plans approved by security holders
|
|
—
|
|
|
$
|
—
|
|
|
9,807
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
Total
|
|
—
|
|
|
$
|
—
|
|
|
9,807
|
|
For additional information regarding the Company’s share-based compensation expense, see Note
10
in the Footnotes to the Financial Statements.
Performance Graph
The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance.
The graph below compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s 500 Index (“S&P 500 Index”) and Dow Jones US Select Oil & Gas Exploration and Production Index (“DJ US Select O&G E&P Index”) from December 31, 2013, through
December 31, 2018
.
The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing
Comparison of Five Year
Cumulative Total Return
Assumes Initial Investment of $100
December
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Company/Market/Peer Group
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
Callon Petroleum Company
|
|
$
|
100.00
|
|
|
$
|
83.46
|
|
|
$
|
127.72
|
|
|
$
|
235.38
|
|
|
$
|
186.06
|
|
|
$
|
99.39
|
|
S&P 500 Index - Total Returns
|
|
100.00
|
|
|
113.69
|
|
|
115.26
|
|
|
129.05
|
|
|
157.22
|
|
|
150.32
|
|
DJ US Select O&G E&P
|
|
100.00
|
|
|
88.06
|
|
|
66.49
|
|
|
83.68
|
|
|
84.26
|
|
|
68.25
|
|
ITEM 6. Selected Financial Data
The following table sets forth, as of the dates and for the periods indicated, selected financial information about the Company. The financial information for each of the five years in the period ended
December 31, 2018
has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results (dollars in thousands, except per share amounts).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
Statement of Operations Data
|
|
|
Operating revenues
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
$
|
587,624
|
|
|
$
|
366,474
|
|
|
$
|
200,851
|
|
|
$
|
137,512
|
|
|
$
|
151,862
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
$
|
328,094
|
|
|
$
|
225,028
|
|
|
$
|
248,328
|
|
|
$
|
346,622
|
|
|
$
|
113,592
|
|
Income (loss) from operations
|
|
259,530
|
|
|
141,446
|
|
|
(47,477
|
)
|
|
(209,110
|
)
|
|
38,270
|
|
Net income (loss)
(a)
|
|
300,360
|
|
|
120,424
|
|
|
(91,813
|
)
|
|
(240,139
|
)
|
|
37,766
|
|
Income (loss) per share (“EPS”)
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.35
|
|
|
$
|
0.56
|
|
|
$
|
(0.78
|
)
|
|
$
|
(3.77
|
)
|
|
$
|
0.67
|
|
Diluted
|
|
$
|
1.35
|
|
|
$
|
0.56
|
|
|
$
|
(0.78
|
)
|
|
$
|
(3.77
|
)
|
|
$
|
0.65
|
|
Weighted average shares outstanding for Basic EPS
|
|
216,941
|
|
|
201,526
|
|
|
126,258
|
|
|
65,708
|
|
|
44,848
|
|
Weighted average shares outstanding for Diluted EPS
|
|
217,596
|
|
|
202,102
|
|
|
126,258
|
|
|
65,708
|
|
|
45,961
|
|
Statement of Cash Flows Data
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
467,654
|
|
|
$
|
229,891
|
|
|
$
|
120,774
|
|
|
$
|
89,319
|
|
|
$
|
94,387
|
|
Net cash used in investing activities
|
|
(1,324,057
|
)
|
|
(1,072,532
|
)
|
|
(866,287
|
)
|
|
(259,160
|
)
|
|
(452,501
|
)
|
Net cash provided by financing activities
|
|
844,459
|
|
|
217,643
|
|
|
1,397,282
|
|
|
170,097
|
|
|
356,070
|
|
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas properties
|
|
$
|
3,718,858
|
|
|
$
|
2,513,491
|
|
|
$
|
1,475,401
|
|
|
$
|
711,386
|
|
|
$
|
742,155
|
|
Total assets
|
|
3,979,173
|
|
|
2,693,296
|
|
|
2,267,587
|
|
|
788,594
|
|
|
863,346
|
|
Long-term debt
(b)
|
|
1,189,473
|
|
|
620,196
|
|
|
390,219
|
|
|
328,565
|
|
|
321,576
|
|
Stockholders’ equity
|
|
2,445,208
|
|
|
1,855,966
|
|
|
1,733,402
|
|
|
362,758
|
|
|
433,735
|
|
Proved Reserves Data
|
|
|
|
|
|
|
|
|
|
|
Total oil (MBbls)
|
|
180,097
|
|
|
107,072
|
|
|
71,145
|
|
|
43,348
|
|
|
25,733
|
|
Total natural gas (MMcf)
|
|
350,466
|
|
|
179,410
|
|
|
122,611
|
|
|
65,537
|
|
|
42,548
|
|
Total (MBOE)
|
|
238,508
|
|
|
136,974
|
|
|
91,580
|
|
|
54,271
|
|
|
32,824
|
|
Standardized measure
(c)
|
|
$
|
2,941,293
|
|
|
$
|
1,556,682
|
|
|
$
|
809,832
|
|
|
$
|
570,890
|
|
|
$
|
579,542
|
|
|
|
(a)
|
Net loss for 2015 included the recognition of a write-down of oil and natural gas properties of $208,435 as a result of the ceiling test limitation and $108,843 of income tax expense related to the recognition of a valuation allowance. Net loss for 2016 included the recognition of a write-down of oil and natural gas properties of $95,788 as a result of the ceiling test limitation. See the Supplemental Information on Oil and Gas Operations for more discussion.
|
|
|
(b)
|
See
Note 6
in the Footnotes to the Financial Statements for additional information.
|
|
|
(c)
|
Standardized measure is the future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet. Prices are based on either the preceding 12-months’ average price, based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. Future production and development costs are based on current estimates with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% discount rate. See the Supplemental Information on Oil and Gas Operations for more discussion.
|
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. Our website address is
www.callon.com
. All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this
2018
Annual Report on Form 10-K.
We are an independent oil and natural gas company incorporated in the State of Delaware in 1994, but our roots go back nearly 70 years to our Company’s establishment in 1950. We are focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. Since our entry into the Permian Basin in late 2009, we have historically been focused on the Midland Basin and more recently entered the Delaware Basin through an acquisition completed in February 2017. We further expanded our presence in the Delaware Basin through our acquisitions in 2018. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. Our production was approximately
79%
oil and
21%
natural gas for the year ended
December 31, 2018
. On
December 31, 2018
, our net acreage position in the Permian Basin was
84,705
net acres.
Significant accomplishments
for
2018
include:
|
|
•
|
Increased annual production in
2018
by
44%
to
12,018
MBOE as compared to
2017
;
|
|
|
•
|
Increased
2018
proved reserves by
74%
to
239
MMBOE as compared to
2017
;
|
|
|
•
|
Generated an operating margin of
$40.16
per BOE produced, reflecting our high oil mix and operating cost controls;
|
|
|
•
|
Expanded our presence in the Delaware Basin through acquisitions of 30,000 net surface acres primarily adjacent to our existing position;
|
|
|
•
|
Issued
$400 million
aggregate principal amount of its
6.375%
Senior Notes;
|
|
|
•
|
Completed an underwritten public offering of
25.3 million
shares of common stock for total estimated net proceeds of approximately
$288 million
.
|
|
|
•
|
Amended the borrowing base under our Credit Facility to
$1.1 billion
with a current elected commitment level of
$850 million
, providing us with additional liquidity.
|
Operational Highlights
All of our producing properties are located in the Permian Basin. As a result of our horizontal development and acquisition efforts, our production grew
44%
in
2018
compared to
2017
, increasing to
12,018
MBOE from
8,373
MBOE. Our production in
2018
was approximately
79%
oil and
21%
natural gas.
For the year ended
December 31, 2018
, we drilled
70
gross (
57.5
net) horizontal wells, completed
65
gross (
53.1
net) horizontal wells and had
eleven
gross (
9.5
net) horizontal wells awaiting completion.
Reserve Growth
As of
December 31, 2018
, our estimated net proved reserves increased
74%
to
238.5
MMBOE compared to
137.0
MMBOE of estimated net proved reserves at year-end
2017
. Our significant growth in proved reserves was primarily attributable to our horizontal development and acquisition efforts. Our proved reserves at year-end
2018
and
2017
were
76%
oil and
24%
natural gas for both periods.
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
Results of Operations
The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended December 31,
|
|
|
2018
|
|
2017
|
|
Change
|
|
% Change
|
|
2016
|
|
Change
|
|
% Change
|
Net production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
9,443
|
|
|
6,557
|
|
|
2,886
|
|
|
44
|
%
|
|
4,280
|
|
|
2,277
|
|
|
53
|
%
|
Natural gas (MMcf)
|
|
15,447
|
|
|
10,896
|
|
|
4,551
|
|
|
42
|
%
|
|
7,758
|
|
|
3,138
|
|
|
40
|
%
|
Total (MBOE)
|
|
12,018
|
|
|
8,373
|
|
|
3,645
|
|
|
44
|
%
|
|
5,573
|
|
|
2,800
|
|
|
50
|
%
|
Average daily production (BOE/d)
|
|
32,926
|
|
|
22,940
|
|
|
9,986
|
|
|
44
|
%
|
|
15,227
|
|
|
7,713
|
|
|
50
|
%
|
% oil (BOE basis)
|
|
79
|
%
|
|
78
|
%
|
|
|
|
|
|
77
|
%
|
|
|
|
|
Average realized sales price
(excluding impact of settled derivatives)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
56.22
|
|
|
$
|
49.16
|
|
|
$
|
7.06
|
|
|
14
|
%
|
|
$
|
41.51
|
|
|
$
|
7.65
|
|
|
18
|
%
|
Natural gas (per Mcf)
|
|
3.67
|
|
|
4.05
|
|
|
(0.38
|
)
|
|
(9
|
)%
|
|
2.99
|
|
|
1.06
|
|
|
35
|
%
|
Total (per BOE)
|
|
48.90
|
|
|
43.77
|
|
|
5.13
|
|
|
12
|
%
|
|
36.04
|
|
|
7.73
|
|
|
21
|
%
|
Average realized sales price
(including impact of settled derivatives)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
53.31
|
|
|
$
|
47.78
|
|
|
$
|
5.53
|
|
|
12
|
%
|
|
$
|
45.67
|
|
|
$
|
2.11
|
|
|
5
|
%
|
Natural gas (per Mcf)
|
|
3.69
|
|
|
4.10
|
|
|
(0.41
|
)
|
|
(10
|
)%
|
|
3.00
|
|
|
1.10
|
|
|
37
|
%
|
Total (per BOE)
|
|
46.63
|
|
|
42.76
|
|
|
3.87
|
|
|
9
|
%
|
|
39.25
|
|
|
3.51
|
|
|
9
|
%
|
Oil and natural gas revenues
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue
|
|
$
|
530,898
|
|
|
$
|
322,374
|
|
|
$
|
208,524
|
|
|
65
|
%
|
|
$
|
177,652
|
|
|
$
|
144,722
|
|
|
81
|
%
|
Natural gas revenue
|
|
56,726
|
|
|
44,100
|
|
|
12,626
|
|
|
29
|
%
|
|
23,199
|
|
|
20,901
|
|
|
90
|
%
|
Total
|
|
$
|
587,624
|
|
|
$
|
366,474
|
|
|
$
|
221,150
|
|
|
60
|
%
|
|
$
|
200,851
|
|
|
$
|
165,623
|
|
|
82
|
%
|
Additional per BOE data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales price
(a)
|
|
$
|
48.90
|
|
|
$
|
43.77
|
|
|
$
|
5.13
|
|
|
12
|
%
|
|
$
|
36.04
|
|
|
$
|
7.73
|
|
|
21
|
%
|
Lease operating expense
(b)
|
|
5.76
|
|
|
5.46
|
|
|
0.30
|
|
|
5
|
%
|
|
6.56
|
|
|
(1.10
|
)
|
|
(17
|
)%
|
Gathering and treating expense
(c)
|
|
—
|
|
|
0.50
|
|
|
(0.50
|
)
|
|
(100
|
)%
|
|
0.32
|
|
|
0.18
|
|
|
56
|
%
|
Production taxes
|
|
2.98
|
|
|
2.67
|
|
|
0.31
|
|
|
12
|
%
|
|
2.13
|
|
|
0.54
|
|
|
25
|
%
|
Operating margin
|
|
$
|
40.16
|
|
|
$
|
35.14
|
|
|
$
|
5.02
|
|
|
14
|
%
|
|
$
|
27.03
|
|
|
$
|
8.11
|
|
|
30
|
%
|
Benchmark prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (per Bbl)
|
|
$
|
65.23
|
|
|
$
|
50.80
|
|
|
$
|
14.43
|
|
|
28
|
%
|
|
$
|
43.32
|
|
|
$
|
7.48
|
|
|
17
|
%
|
Henry Hub (per Mcf)
|
|
3.15
|
|
|
2.99
|
|
|
0.16
|
|
|
5
|
%
|
|
2.52
|
|
|
0.47
|
|
|
19
|
%
|
|
|
(a)
|
Excludes the impact of commodity derivative settlements.
|
|
|
(b)
|
Excludes gathering and treating expense.
|
|
|
(c)
|
On January 1, 2018, the Company adopted the revenue recognition accounting standard. Consequently, natural gas gathering and treating expenses for the year ended
December 31, 2018
were accounted for as a reduction to revenue. See
Notes 2
and
3
in the Footnotes to the Financial Statements for additional information regarding revenue recognition and the treatment of gathering and treating expense.
|
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
Revenues
The following tables are intended to reconcile the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume and in the underlying commodity prices.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Oil
|
|
Natural Gas
|
|
Total
|
Revenues for the year ended December 31, 2015
|
|
$
|
125,166
|
|
|
$
|
12,346
|
|
|
$
|
137,512
|
|
Volume increase
|
|
66,916
|
|
|
9,856
|
|
|
76,772
|
|
Price increase (decrease)
|
|
(14,430
|
)
|
|
997
|
|
|
(13,433
|
)
|
Net increase
|
|
52,486
|
|
|
10,853
|
|
|
63,339
|
|
Revenues for the year ended December 31, 2016
|
|
$
|
177,652
|
|
|
$
|
23,199
|
|
|
$
|
200,851
|
|
Volume increase
|
|
94,518
|
|
|
9,383
|
|
|
103,901
|
|
Price increase
|
|
50,204
|
|
|
11,518
|
|
|
61,722
|
|
Net increase
|
|
144,722
|
|
|
20,901
|
|
|
165,623
|
|
Revenues for the year ended December 31, 2017
|
|
$
|
322,374
|
|
|
$
|
44,100
|
|
|
$
|
366,474
|
|
Volume increase
|
|
141,876
|
|
|
18,432
|
|
|
160,308
|
|
Price increase (decrease)
|
|
66,648
|
|
|
(5,806
|
)
|
|
60,842
|
|
Net increase
|
|
208,524
|
|
|
12,626
|
|
|
221,150
|
|
Revenues for the year ended December 31, 2018
|
|
$
|
530,898
|
|
|
$
|
56,726
|
|
|
$
|
587,624
|
|
Commodity Prices
The prices for oil and natural gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by OPEC and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business:
|
|
•
|
our revenues, cash flows and earnings;
|
|
|
•
|
the amount of oil and natural gas that we are economically able to produce;
|
|
|
•
|
our ability to attract capital to finance our operations and cost of the capital;
|
|
|
•
|
the amount we are allowed to borrow under our Credit Facility; and
|
|
|
•
|
the value of our oil and natural gas properties.
|
Oil revenue
For the year ended
December 31, 2018
, oil revenues of
$531 million
increased
$209 million
, or
65%
, compared to revenues of
$322 million
for the year ended
December 31, 2017
. The
increase
in oil revenue was primarily attributable to a
44%
increase
in production and a
14%
increase
in the average realized sales price, which rose to
$56.22
per Bbl from
$49.16
per Bbl. The
increase
in production was comprised of
3,479
MBbls attributable to wells placed on production as a result of our horizontal drilling program and
507
MBbls attributable to producing wells added from acquired properties. Offsetting these increases were normal and expected declines from our existing wells.
For the year ended December 31, 2017, oil revenues of $322 million increased $145 million, or 81%, compared to revenues of $178 million for the year ended December 31, 2016. The increase in oil revenue was primarily attributable to a 53% increase in production and an 18% increase in the average realized sales price, which rose to $49.16 per Bbl from $41.51 per Bbl. The increase in production was in production was driven by 2,125 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 1,191 MBbls attributable to producing wells added from acquired properties. Offsetting these increases were normal and expected declines from our existing wells.
Natural gas revenue (including NGLs)
Natural gas revenues of
$56.7 million
increased
$12.6 million
, or
29%
, during the year ended
December 31, 2018
compared to
$44.1 million
for the year ended
December 31, 2017
. The
increase
primarily relates to a
42%
increase
in natural gas volumes; offset by a
9%
decrease
in the average price realized, which declined to
$3.67
per Mcf from
$4.05
per Mcf, reflecting decreases in natural gas. The
increase
in production was driven by
3,706
MMcf attributable to wells placed on production as a result of our horizontal drilling program and
641
MMcf attributable to producing wells added from acquired properties. Offsetting these increases were normal and expected declines from our existing wells.
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
Natural gas revenues of $44.1 million increased $20.9 million, or 90%, during the year ended December 31, 2017 compared to $23.2 million for the year ended December 31, 2016. The increase primarily relates to a 40% increase in natural gas volumes and a 35% increase in the average price realized, which rose to $4.05 per Mcf from $2.99 per Mcf, reflecting increases in natural gas. The increase in production was comprised of 1,969 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 1,375 MMcf attributable to producing wells added from acquired properties. Offsetting these increases were normal and expected declines from our existing wells.
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended December 31,
|
|
|
|
|
Per
|
|
|
|
Per
|
|
Total Change
|
|
BOE Change
|
(in thousands, except per unit amounts)
|
|
2018
|
|
BOE
|
|
2017
|
|
BOE
|
|
$
|
|
%
|
|
$
|
|
%
|
Lease operating expenses
|
|
$
|
69,180
|
|
|
$
|
5.76
|
|
|
$
|
49,907
|
|
|
$
|
5.96
|
|
|
$
|
19,273
|
|
|
39
|
%
|
|
$
|
(0.20
|
)
|
|
(3
|
)%
|
Production taxes
|
|
35,755
|
|
|
2.98
|
|
|
22,396
|
|
|
2.67
|
|
|
13,359
|
|
|
60
|
%
|
|
0.31
|
|
|
12
|
%
|
Depreciation, depletion and amortization
|
|
181,909
|
|
|
15.14
|
|
|
115,714
|
|
|
13.82
|
|
|
66,195
|
|
|
57
|
%
|
|
1.32
|
|
|
10
|
%
|
General and administrative
|
|
35,293
|
|
|
2.94
|
|
|
27,067
|
|
|
3.23
|
|
|
8,226
|
|
|
30
|
%
|
|
(0.29
|
)
|
|
(9
|
)%
|
Settled share-based awards
|
|
—
|
|
|
—
|
|
|
6,351
|
|
|
0.76
|
|
|
(6,351
|
)
|
|
(100
|
)%
|
|
(0.76
|
)
|
|
(100
|
)%
|
Accretion expense
|
|
874
|
|
|
0.07
|
|
|
677
|
|
|
0.08
|
|
|
197
|
|
|
29
|
%
|
|
(0.01
|
)
|
|
(13
|
)%
|
Acquisition expense
|
|
5,083
|
|
|
0.42
|
|
|
2,916
|
|
|
0.35
|
|
|
2,167
|
|
|
74
|
%
|
|
0.07
|
|
|
20
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended December 31,
|
|
|
|
|
Per
|
|
|
|
Per
|
|
Total Change
|
|
BOE Change
|
(in thousands, except per unit amounts)
|
|
2017
|
|
BOE
|
|
2016
|
|
BOE
|
|
$
|
|
%
|
|
$
|
|
%
|
Lease operating expenses
|
|
$
|
49,907
|
|
|
$
|
5.96
|
|
|
$
|
38,353
|
|
|
$
|
6.88
|
|
|
$
|
11,554
|
|
|
30
|
%
|
|
$
|
(0.92
|
)
|
|
(13
|
)%
|
Production taxes
|
|
22,396
|
|
|
2.67
|
|
|
11,870
|
|
|
2.13
|
|
|
10,526
|
|
|
89
|
%
|
|
0.54
|
|
|
25
|
%
|
Depreciation, depletion and amortization
|
|
115,714
|
|
|
13.82
|
|
|
71,369
|
|
|
12.81
|
|
|
44,345
|
|
|
62
|
%
|
|
1.01
|
|
|
8
|
%
|
General and administrative
|
|
27,067
|
|
|
3.23
|
|
|
26,317
|
|
|
4.72
|
|
|
750
|
|
|
3
|
%
|
|
(1.49
|
)
|
|
(32
|
)%
|
Settled share-based awards
|
|
6,351
|
|
|
0.76
|
|
|
—
|
|
|
—
|
|
|
6,351
|
|
|
—
|
%
|
|
0.76
|
|
|
—
|
%
|
Accretion expense
|
|
677
|
|
|
0.08
|
|
|
958
|
|
|
0.17
|
|
|
(281
|
)
|
|
(29
|
)%
|
|
(0.09
|
)
|
|
(53
|
)%
|
Write-down of oil and natural gas properties
|
|
—
|
|
|
—
|
|
|
95,788
|
|
|
17.19
|
|
|
(95,788
|
)
|
|
(100
|
)%
|
|
(17.19
|
)
|
|
(100
|
)%
|
Acquisition expense
|
|
2,916
|
|
|
0.35
|
|
|
3,673
|
|
|
0.66
|
|
|
(757
|
)
|
|
(21
|
)%
|
|
(0.31
|
)
|
|
(47
|
)%
|
Lease operating expenses.
These are daily costs incurred to extract oil and natural gas and maintain our producing properties. Such costs also include maintenance, repairs, gas treating fees, salt water disposal, insurance and workover expenses related to our oil and natural gas properties.
LOE for the year ended
December 31, 2018
increased
by
39%
to
$69.2 million
compared to
$49.9 million
for the same period of
2017
, primarily due to production volumes increasing 44%. LOE per BOE for the year ended
December 31, 2018
decreased
to
$5.76
per BOE compared to
$5.96
per BOE for the same period of
2017
.
LOE for the year ended December 31, 2017 increased by 30% to $49.9 million compared to $38.4 million for the same period of 2016. Contributing to the increase was $11.0 million related to oil and natural gas properties acquired during 2016 and 2017 (see Note 4 in the Footnotes to the Financial Statements for information about the Company’s acquisitions). LOE per BOE for the year ended December 31, 2017 decreased to $5.96 per BOE compared to $6.88 per BOE for the same period of 2016, which was primarily attributable to higher production volumes resulting from an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above.
Production taxes.
Production taxes include severance and ad valorem taxes. In general, production taxes are directly related to commodity price changes; however, severance taxes are based upon current year commodity prices, whereas ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties.
For the year ended
December 31, 2018
, production taxes
increased
60%
, or
$13.4 million
, to
$35.8 million
compared to
$22.4 million
for the same period of
2017
, due to an increase in severance taxes based on higher production volumes. Also attributable is the
increase
in ad valorem taxes due to a higher valuation of our oil and gas properties by the taxing jurisdictions resulting from an increased number of producing wells in the current period, as a result of our horizontal drilling program and acquisitions. On a per BOE basis, production taxes for the year ended
December 31, 2018
increased
by
12%
compared to the same period of
2017
.
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
For the year ended December 31, 2017, production taxes increased 89%, or $10.5 million, to $22.4 million compared to $11.9 million for the same period of 2016, due to an increase in severance taxes based on higher production volumes. The increase was also attributable to an increase in ad valorem taxes due to a higher valuation of our oil and gas properties by the taxing jurisdictions due to an increased number of producing wells as a result of our horizontal drilling program and acquisitions. On a per BOE basis, production taxes for the year ended December 31, 2017 increased by 25% compared to the same period of 2016.
Depreciation, depletion and amortization (“DD&A”).
Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.
For the year ended
December 31, 2018
, DD&A
increased
57%
to
$181.9 million
from
$115.7 million
compared to the same period of
2017
. The
increase
is primarily attributable to a
44%
increase
in production and a
10%
increase in our DD&A per BOE rate. The
increase
in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions. For the year ended
December 31, 2018
, DD&A on a per unit basis
increased
to
$15.14
per BOE compared to
$13.82
per BOE for the same period of
2017
. The
increase
is attributable to our increase in our depreciable base and assumed future development costs related to undeveloped proved reserves relative to our increased estimated proved reserves as a result of additions made through our horizontal drilling efforts and acquisitions.
For the year ended December 31, 2017, DD&A increased 62% to $115.7 million from $71.4 million compared to the same period of 2016. The increase is primarily attributable to a 50% increase in production and an 8% increase in our per BOE DD&A rate. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions. For the year ended December 31, 2017, DD&A on a per unit basis increased to $13.82 per BOE compared to $12.81 per BOE for the same period of 2016. The increase is attributable to our increase in our depreciable base and assumed future development costs related to undeveloped proved reserves relative to our increased estimated proved reserves as a result of additions made through our horizontal drilling efforts and acquisitions.
General and administrative, net of amounts capitalized (“G&A”).
G&A for the year ended
December 31, 2018
increased to
$35.3 million
compared to
$27.1 million
for the same period of
2017
. G&A expenses for the periods indicated include the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended December 31,
|
|
|
2018
|
|
2017
|
|
$ Change
|
|
% Change
|
Recurring expenses
|
|
|
|
|
|
|
|
|
G&A
|
|
$
|
28,710
|
|
|
$
|
21,554
|
|
|
$
|
7,156
|
|
|
33
|
%
|
Share-based compensation
|
|
6,224
|
|
|
4,287
|
|
|
1,937
|
|
|
45
|
%
|
Fair value adjustments of cash-settled RSU awards
|
|
359
|
|
|
701
|
|
|
(342
|
)
|
|
(49
|
)%
|
Non-recurring expenses
|
|
|
|
|
|
|
|
|
Early retirement expenses
|
|
—
|
|
|
444
|
|
|
(444
|
)
|
|
100
|
%
|
Early retirement expenses related to share-based compensation
|
|
—
|
|
|
81
|
|
|
(81
|
)
|
|
100
|
%
|
Total G&A expenses
|
|
$
|
35,293
|
|
|
$
|
27,067
|
|
|
$
|
8,226
|
|
|
30
|
%
|
G&A for the year ended
December 31, 2017
increased to
$27.1 million
compared to
$26.3 million
for the same period of
2016
. G&A expenses for the periods indicated include the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended December 31,
|
|
|
2017
|
|
2016
|
|
$ Change
|
|
% Change
|
Recurring expenses
|
|
|
|
|
|
|
|
|
G&A
|
|
$
|
21,554
|
|
|
$
|
16,477
|
|
|
$
|
5,077
|
|
|
31
|
%
|
Share-based compensation
|
|
4,287
|
|
|
2,735
|
|
|
1,552
|
|
|
57
|
%
|
Fair value adjustments of cash-settled RSU awards
|
|
701
|
|
|
6,881
|
|
|
(6,180
|
)
|
|
(90
|
)%
|
Non-recurring expenses
|
|
|
|
|
|
|
|
|
Early retirement expenses
|
|
444
|
|
|
—
|
|
|
444
|
|
|
100
|
%
|
Early retirement expenses related to share-based compensation
|
|
81
|
|
|
—
|
|
|
81
|
|
|
100
|
%
|
Expense related to a threatened proxy contest
|
|
—
|
|
|
224
|
|
|
(224
|
)
|
|
(100
|
)%
|
Total G&A expenses
|
|
$
|
27,067
|
|
|
$
|
26,317
|
|
|
$
|
750
|
|
|
3
|
%
|
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
Settled share-based awards
. In June 2017, the Company settled the outstanding share-based award agreements of its former Chief Executive Officer, resulting in
$6.4 million
recorded on the Consolidated Statements of Operations as Settled share-based awards.
Accretion expense.
The Company is required to record the estimated fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated ARO costs. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported as accretion expense within operating expenses in the Consolidated Statements of Operations.
Accretion expense
increased
29%
for the year ended
December 31, 2018
compared to the same period of
2017
due to additional abandonment obligations recorded for the Company’s increase in drilling activities for the year, as well as assumed obligations for the Delaware Asset Acquisition.
Accretion expense related to our ARO
decreased
29%
for the year ended
December 31, 2017
compared to the same period of 2016. Accretion expense is based on the Company’s ARO balance, which decreased to $6.0 million at December 31, 2017 from $6.7 million at December 31, 2016. See
Note 13
in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO.
Write-down of oil and natural gas properties.
Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling.
For the years ended
December 31, 2018
and 2017, the Company recognized
no
write-down of oil and natural gas properties as a result of the ceiling test limitation. For the year ended December 31, 2016, the Company recognized a write-down of oil and natural gas properties of $95.8 million as a result of the ceiling test limitation, primarily driven by a 15% decrease in the 12-month average realized price of oil from $50.16 per barrel as of December 31, 2015 to $42.75 per barrel as of December 31, 2016. If commodity prices were to decline, we could incur additional ceiling test write-downs in the future. See Notes 2 and
Supplemental Information on Oil and Natural Gas Operations
in the Footnotes to the Financial Statements for additional information.
Acquisition expense.
Acquisition expense
increased
$2.2 million
for the year ended
December 31, 2018
compared to the same period of
2017
and
decreased
$0.8 million
for the year ended
December 31, 2017
compared to the same period of
2016
. Acquisition expense for all periods was related to costs with respect to our acquisition efforts in the Permian Basin. See
Note 4
in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
Other Income and Expenses and Preferred Stock Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
(in thousands)
|
|
2018
|
|
2017
|
|
$ Change
|
|
% Change
|
Interest expense
|
|
$
|
58,651
|
|
|
$
|
35,942
|
|
|
$
|
22,709
|
|
|
63
|
%
|
Capitalized interest
|
|
(56,151
|
)
|
|
(33,783
|
)
|
|
(22,368
|
)
|
|
66
|
%
|
Interest expense, net of capitalized amounts
|
|
2,500
|
|
|
2,159
|
|
|
341
|
|
|
16
|
%
|
(Gain) loss on derivative contracts
|
|
(48,544
|
)
|
|
18,901
|
|
|
(67,445
|
)
|
|
(357
|
)%
|
Other income
|
|
(2,896
|
)
|
|
(1,311
|
)
|
|
(1,585
|
)
|
|
121
|
%
|
Total
|
|
$
|
(48,940
|
)
|
|
$
|
19,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
8,110
|
|
|
$
|
1,273
|
|
|
$
|
6,837
|
|
|
537
|
%
|
Preferred stock dividends
|
|
(7,295
|
)
|
|
(7,295
|
)
|
|
—
|
|
|
—
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
$ Change
|
|
% Change
|
Interest expense
|
|
$
|
35,942
|
|
|
$
|
31,728
|
|
|
$
|
4,214
|
|
|
13
|
%
|
Capitalized interest
|
|
(33,783
|
)
|
|
(19,857
|
)
|
|
(13,926
|
)
|
|
70
|
%
|
Interest expense, net of capitalized amounts
|
|
2,159
|
|
|
11,871
|
|
|
(9,712
|
)
|
|
(82
|
)%
|
Loss on early extinguishment of debt
|
|
—
|
|
|
12,883
|
|
|
(12,883
|
)
|
|
(100
|
)%
|
Loss on derivative contracts
|
|
18,901
|
|
|
20,233
|
|
|
(1,332
|
)
|
|
(7
|
)%
|
Other income
|
|
(1,311
|
)
|
|
(637
|
)
|
|
(674
|
)
|
|
106
|
%
|
Total
|
|
$
|
19,749
|
|
|
$
|
44,350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (benefit) expense
|
|
$
|
1,273
|
|
|
$
|
(14
|
)
|
|
$
|
1,287
|
|
|
(9,193
|
)%
|
Preferred stock dividends
|
|
(7,295
|
)
|
|
(7,295
|
)
|
|
—
|
|
|
—
|
%
|
Interest expense, net of capitalized amounts.
We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense.
Interest expense, net of capitalized amounts, incurred during the year ended
December 31, 2018
increased
$0.3 million
to
$2.5 million
compared to
$2.2 million
for the same period of
2017
.
Interest expense, net of capitalized amounts, incurred during the year ended December 31, 2017 decreased $9.7 million to $2.2 million compared to $11.9 million for the same period of 2016. The decrease is primarily attributable to a $13.9 million increase in capitalized interest compared to the 2016 period, resulting from a higher average unevaluated property balance for the year ended December 31, 2017 as compared to the same period of 2016. The increase in unevaluated property was primarily due to acquired properties (see
Note 4
and
Supplemental Information on Oil and Natural Gas Operations
in the Footnotes to the Financial Statements for information about the Company’s acquisitions and unevaluated property balance). Offsetting the decrease was a $5.2 million increase in interest expense related to our debt due to a higher average debt balance for the year ended December 31, 2017 as compared to the same period of 2016, resulting from the issuance of an additional $200 million of our 6.125% Senior Notes in May 2017 (see
Note 6
in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes).
Gain (loss)
on the early extinguishment of debt.
During October 2016, the secured second lien term loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the 6.125% Senior Notes, which resulted in a loss on early extinguishment of debt of $12.9 million (inclusive of $3.0 million in prepayment fees and $9.9 million of unamortized debt issuance costs). See
Note 6
in the Footnotes to the Financial Statements for additional information about the Company’s debt.
Gain
(loss)
on derivative instruments.
We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions that have settled within the period.
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
For the year ended
December 31, 2018
, the net
gain
on derivative instruments was
$48.5 million
, compared to an
$18.9 million
net
loss
in
2017
. The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
Change
|
Oil derivatives
|
|
|
|
|
|
|
Net loss on settlements
|
|
$
|
(27,510
|
)
|
|
$
|
(9,067
|
)
|
|
$
|
(18,443
|
)
|
Net gain (loss) on fair value adjustments
|
|
72,973
|
|
|
(11,426
|
)
|
|
84,399
|
|
Total gain (loss) on oil derivatives
|
|
$
|
45,463
|
|
|
$
|
(20,493
|
)
|
|
$
|
65,956
|
|
Natural gas derivatives
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
238
|
|
|
$
|
594
|
|
|
$
|
(356
|
)
|
Net gain on fair value adjustments
|
|
2,843
|
|
|
998
|
|
|
1,845
|
|
Total gain on natural gas derivatives
|
|
$
|
3,081
|
|
|
$
|
1,592
|
|
|
$
|
1,489
|
|
|
|
|
|
|
|
|
Total gain (loss) on oil & natural gas derivatives
|
|
$
|
48,544
|
|
|
$
|
(18,901
|
)
|
|
$
|
67,445
|
|
For the year ended
December 31, 2017
, the net
loss
on derivative instruments was
$18.9 million
, compared to a
$20.2 million
net
loss
in
2016
. The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
Change
|
Oil derivatives
|
|
|
|
|
|
|
Net gain (loss) on settlements
|
|
$
|
(9,067
|
)
|
|
$
|
17,801
|
|
|
$
|
(26,868
|
)
|
Net loss on fair value adjustments
|
|
(11,426
|
)
|
|
(37,543
|
)
|
|
26,117
|
|
Total loss on oil derivatives
|
|
$
|
(20,493
|
)
|
|
$
|
(19,742
|
)
|
|
$
|
(751
|
)
|
Natural gas derivatives
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
594
|
|
|
$
|
102
|
|
|
$
|
492
|
|
Net gain (loss) on fair value adjustments
|
|
998
|
|
|
(593
|
)
|
|
1,591
|
|
Total gain (loss) on natural gas derivatives
|
|
$
|
1,592
|
|
|
$
|
(491
|
)
|
|
$
|
2,083
|
|
|
|
|
|
|
|
|
Total loss on oil & natural gas derivatives
|
|
$
|
(18,901
|
)
|
|
$
|
(20,233
|
)
|
|
$
|
1,332
|
|
See
Notes 7
and
8
in the Footnotes to the Financial Statements for additional information on the Company’s derivative contracts and disclosures related to derivative instruments.
Income tax expense.
We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized.
The Company had an income tax
expense
of
$8.1 million
for the year ended
December 31, 2018
compared to an income tax
expense
of less than
$1.3 million
for the same period of
2017
. The change in income tax is primarily related to the change in the Company’s tax position in the current period, for which there is no longer a cumulative three year loss trend and booking of a valuation allowance for deferred tax benefits as compared to the prior year. Current period income tax expense is comprised of both deferred federal and state income tax expense.
The Company had an income tax expense of $1.3 million for the year ended December 31, 2017 compared to an income tax benefit of less than $0.1 million for the same period of 2016. The change in income tax is primarily related to deferred state income tax expense. The effective tax rate differed from the federal income tax rate of 35% primarily due to the valuation allowance for the comparative periods, the effect of state taxes, and non-deductible executive compensation expenses.
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
The following table presents a reconciliation of the federal statutory tax rates to the effective tax rates:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Components of income tax rate reconciliation
|
|
2018
|
|
2017
|
|
2016
|
Income tax expense computed at the statutory federal income tax rate
|
|
21
|
%
|
|
35
|
%
|
|
35
|
%
|
State taxes net of federal expense
|
|
1
|
%
|
|
1
|
%
|
|
—
|
%
|
Section 162(m)
|
|
1
|
%
|
|
—
|
%
|
|
(1
|
)%
|
Valuation allowance
|
|
(20
|
)%
|
|
(35
|
)%
|
|
(34
|
)%
|
Effective income tax rate
|
|
3
|
%
|
|
1
|
%
|
|
—
|
%
|
For additional information, see
Note 12
in the Footnotes to the Financial Statements.
Preferred stock dividends.
Holders of our Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of
10%
per annum of the
$50.00
liquidation preference per share (equivalent to
$5.00
per annum per share).
Preferred stock dividends for the year ended
December 31, 2018
were consistent with the same periods of
2017
and 2016. Dividends reflect a 10% dividend yield. See
Note 11
in the Footnotes to the Financial Statements for additional information.
Liquidity and Capital Resources
Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the issuance of debt and equity securities, and non-core asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments.
In 2018, we issued
$400 million
aggregate principal amount of
6.375%
Senior Notes with a maturity date of July 1, 2026 and interest payable semi-annually beginning on January 1, 2019. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately
$394 million
. In addition, we amended the borrowing base under our Credit Facility to
$1.1 billion
with a current elected commitment level of
$850 million
, providing us with additional liquidity. Also in 2018, we completed an underwritten public offering of
25.3 million
shares of common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering costs) of approximately
$288 million
. We used proceeds from the issuance and offering to partially fund the Delaware Asset Acquisition completed in the third quarter, described in
Note 4
in our Consolidated Financial Statements.
In 2017, we issued an additional
$200 million
aggregate principal amount of our 6.125% Senior Notes to raise additional capital. We continue to evaluate other sources of capital to complement our cash flow from operations and other sources of capital as we pursue our long-term growth plans. See
Note 6
in the Footnotes to the Financial Statements for additional information about the Company’s debt.
For the year ended
December 31, 2018
, cash and cash equivalents
decreased
$11.9 million
to
$16.1 million
compared to
$28.0 million
at
December 31, 2017
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended December 31,
|
(in thousands)
|
2018
|
|
2017
|
|
2016
|
Net cash provided by operating activities
|
$
|
467,654
|
|
|
$
|
229,891
|
|
|
$
|
120,774
|
|
Net cash used in investing activities
|
(1,324,057
|
)
|
|
(1,072,532
|
)
|
|
(866,287
|
)
|
Net cash provided by financing activities
|
844,459
|
|
|
217,643
|
|
|
1,397,282
|
|
Net change in cash and cash equivalents
|
$
|
(11,944
|
)
|
|
$
|
(624,998
|
)
|
|
$
|
651,769
|
|
Operating activities.
For the year ended
December 31, 2018
, net cash provided by operating activities was
$467.7 million
, compared to
$229.9 million
for the same period in
2017
. The change in operating activities was predominantly attributable to the following:
|
|
•
|
An increase in revenue due to both increase in realized pricing and production volumes;
|
|
|
•
|
A decrease in settlements of derivative contracts, due to overall increases in commodity pricing;
|
|
|
•
|
Operating expenses such as LOE and production taxes increasing at a lower rate than revenues;
|
|
|
•
|
A decrease in payments for cash-settled restricted stock unit (“RSU”) awards; and
|
|
|
•
|
An increase in net changes to working capital
|
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
Production, realized prices, and operating expenses are discussed below in Results of Operations. See
Notes 7
and
8
in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.
Investing activities
. For the year ended
December 31, 2018
, net cash used in investing activities was
$1,324.1 million
compared to
$1,072.5 million
for the same period in
2017
. The change in investing activities was primarily attributable to the following:
|
|
•
|
A
$191.3 million
increase in capital expenditures due to increased activity from our 2018 development program, focused on multi-well pads, as well as additional investments in facilities and infrastructure. We maintained an average of five rigs throughout the year, as compared to 2017, when we averaged three to four rigs.
|
|
|
•
|
A $60.2 million increase in acquisitions, net of proceeds from the sale of mineral interest and equipment.
|
Our investing activities, on a cash basis, include the following for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended December 31,
|
|
|
2018
|
|
2017
|
|
$ Change
|
Operational expenditures
|
|
$
|
537,514
|
|
|
$
|
355,833
|
|
|
$
|
181,681
|
|
Seismic, leasehold and other
|
|
8,555
|
|
|
16,385
|
|
|
(7,830
|
)
|
Capitalized general and administrative costs
|
|
24,383
|
|
|
17,016
|
|
|
7,367
|
|
Capitalized interest
|
|
40,721
|
|
|
30,605
|
|
|
10,116
|
|
Total capital expenditures
|
|
611,173
|
|
|
419,839
|
|
|
191,334
|
|
|
|
|
|
|
|
|
Acquisitions
|
|
718,793
|
|
|
718,456
|
|
|
337
|
|
Acquisition deposits
|
|
—
|
|
|
(45,238
|
)
|
|
45,238
|
|
Proceeds from the sale of mineral interest and equipment
|
|
(9,009
|
)
|
|
(20,525
|
)
|
|
11,516
|
|
Additions to other assets
|
|
3,100
|
|
|
—
|
|
|
3,100
|
|
Total investing activities
|
|
$
|
1,324,057
|
|
|
$
|
1,072,532
|
|
|
$
|
251,525
|
|
General and administrative expenses and capitalized interest are discussed below in Results of Operations. See
Notes 4
and
14
in the Footnotes to the Financial Statements for additional information on significant acquisitions and drilling rig leases.
Financing activities.
We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility, term debt and equity offerings. For the year ended
December 31, 2018
, net cash provided by financing activities was
$844.5 million
compared to cash provided by financing activities of
$217.6 million
during the same period of
2017
. The change in net cash provided by financing activities was primarily attributable to the following:
|
|
•
|
Completed an underwritten public offering of
25.3 million
shares of common stock for total estimated net proceeds of approximately
$288 million
.
|
|
|
•
|
Increased in net borrowings of
$350 million
from increases in net borrowings on the Credit Facility and issuance of our 6.375% senior unsecured notes.
|
Net cash provided by financing activities includes the following for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended December 31,
|
|
2018
|
|
2017
|
|
$ Change
|
Net borrowings on Credit Facility
|
$
|
175,000
|
|
|
$
|
25,000
|
|
|
$
|
150,000
|
|
Issuance of 6.125% Senior Notes
|
—
|
|
|
200,000
|
|
|
(200,000
|
)
|
Premium on the issuance of 6.125% Senior Notes
|
—
|
|
|
8,250
|
|
|
(8,250
|
)
|
Issuance of 6.375% senior unsecured notes due 2026
|
400,000
|
|
|
—
|
|
|
400,000
|
|
Issuance of common stock
|
287,988
|
|
|
—
|
|
|
287,988
|
|
Payment of preferred stock dividends
|
(7,295
|
)
|
|
(7,295
|
)
|
|
—
|
|
Payment of deferred financing costs
|
(9,430
|
)
|
|
(7,194
|
)
|
|
(2,236
|
)
|
Tax withholdings related to restricted stock units
|
(1,804
|
)
|
|
(1,118
|
)
|
|
(686
|
)
|
Net cash provided by financing activities
|
$
|
844,459
|
|
|
$
|
217,643
|
|
|
$
|
626,816
|
|
See
Note 6
in the Footnotes to the Financial Statements for additional information about the Company’s debt. See
Note 11
in the Footnotes to the Financial Statements for additional information about the Company’s equity offerings and Series A 10% Cumulative Preferred Stock.
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
Credit Facility
Effective
April 5, 2018
, the Company entered into the first amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to
$825 million
, (2) increased the elected commitment amount to
$650 million
, (3) amended various covenants and terms to reflect current market trends, and (4) extended the maturity date to
May 25, 2023
.
Effective
September 27, 2018
, the Company entered into the second amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to
$1.1 billion
, (2) increase the elected commitment amount to
$850 million
, and (3) amended various covenants and terms to reflect current market trends. As of
December 31, 2018
, the Credit Facility’s borrowing base remained at
$1.1 billion
with an elected commitment amount of
$850 million
.
For the year ended
December 31, 2018
, the Credit Facility had a weighted-average interest rate of
3.62%
, calculated as the LIBOR plus a tiered rate ranging from
1.25%
to
2.25%
, which is determined based on utilization of the facility. In addition, the Credit Facility carries a current commitment fee of
0.375%
per annum, payable quarterly, on the unused portion of the borrowing base.
See
Note 6
in the Footnotes to the Financial Statements for additional information about the Company’s Credit Facility.
6.125% Senior Notes
On October 3, 2016, the Company issued
$400 million
aggregate principal amount of
6.125%
Senior Notes with a maturity date of
October 1, 2024
and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately
$391.3 million
. The
6.125%
Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries.
On May 19, 2017, the Company issued an additional
$200 million
aggregate principal amount of its
6.125%
Senior Notes which with the existing
$400 million
aggregate principal amount of
6.125%
Senior Notes are treated as a single class of notes under the indenture. The net proceeds of the offering, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately
$206 million
.
See
Note 6
in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes.
6.375%
Senior Notes
On June 7, 2018, the Company issued
$400 million
aggregate principal amount of
6.375%
Senior Notes with a maturity date of July 1, 2026 and interest payable semi-annually beginning on January 1, 2019. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately
$394 million
. The
6.375%
Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries.
10% Series A Cumulative Preferred Stock (“Preferred Stock”)
Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of
10.0%
per annum of the
$50.00
liquidation preference per share (equivalent to
$5.00
per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were
$7.3 million
in
2018
.
The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying
$50.00
per share, plus any accrued and unpaid dividends to the redemption date. As of
December 31, 2018
, the Company had
1.5 million
shares of its Preferred Stock issued and outstanding. See
Note 11
in the Footnotes to the Financial Statements for additional information about the Company’s Preferred Stock.
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
2019
Capital Plan
and Outlook
Our operational capital budget for
2019
has been established in the range of
$500
to
$525 million
with infrastructure and facilities capital comprising approximately 15% of operational capital. We expect to run an average of five drilling rigs to support larger and more efficient, multi-well pad development and we plan to place 47 to 49 net wells on production, with an increase of approximately 15% average net lateral length to approximately 8,400 feet.
Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of oil and natural gas. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly.
Contractual Obligations
The following table includes the Company’s current contractual obligations and purchase commitments (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by Period
|
|
|
Total
|
|
< 1 Year
|
|
Years 2 - 3
|
|
Years 4 - 5
|
|
> 5 Years
|
6.125% Senior Notes
(a)
|
|
$
|
600,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
600,000
|
|
6.375% Senior Notes
(a)
|
|
400,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
400,000
|
|
Credit Facility
(b)
|
|
200,000
|
|
|
—
|
|
|
—
|
|
|
200,000
|
|
|
—
|
|
Interest expense and other fees related to debt commitments
(c)
|
|
445,240
|
|
|
71,922
|
|
|
143,843
|
|
|
138,162
|
|
|
91,313
|
|
Drilling rig leases
(d)
|
|
46,889
|
|
|
33,641
|
|
|
13,248
|
|
|
—
|
|
|
—
|
|
Other commitments
|
|
13,299
|
|
|
5,050
|
|
|
7,814
|
|
|
435
|
|
|
—
|
|
Asset retirement obligations
(e)
|
|
14,292
|
|
|
3,887
|
|
|
5,604
|
|
|
—
|
|
|
4,801
|
|
Total contractual obligations
|
|
$
|
1,719,720
|
|
|
$
|
114,500
|
|
|
$
|
170,509
|
|
|
$
|
338,597
|
|
|
$
|
1,096,114
|
|
|
|
(a)
|
Includes the outstanding principal amount only. The
6.125%
Senior Notes and
6.375%
Senior Notes have maturity dates of
October 1, 2024
and
July 1, 2026
, respectively. See
Note 6
in the Footnotes to the Financial Statements for additional information about the Company’s debt obligations.
|
|
|
(b)
|
As of
December 31, 2018
, the Credit Facility had a
$200 million
balance outstanding. We cannot predict the timing of future borrowings and repayments. The Credit Facility has a maturity date of
May 25, 2023
. See
Note 6
in the Footnotes to the Financial Statements for additional information about the Company’s debt obligations.
|
|
|
(c)
|
Includes estimated cash payments on the 6.125% Senior Notes, 6.375% Senior Notes, the Credit Facility and the minimum amount of commitment fees due on the Credit Facility.
|
|
|
(d)
|
Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on
December 31, 2018
. The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred. See
Note 14
in the Footnotes to the Financial Statements for additional information related to the Company’s drilling rig leases.
|
|
|
(e)
|
Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See
Note 13
in the Footnotes to the Financial Statements for additional information.
|
In 2018, we executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a seven year term commitment that will apply applicable tariff rates to our
15,000
Bbls per day commitment.
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
Critical Accounting Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See
Note 2
in the Footnotes to the Financial Statements included in this
2018
Annual Report on Form 10-K for a discussion of additional accounting policies and estimates made by management.
Oil and natural gas properties
The Company utilizes the full cost method of accounting for its oil and natural gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves, including certain overhead costs, are capitalized into the “full cost pool.” The amounts capitalized into the full cost pool are depleted (charged against earnings) using the unit-of-production method. The full cost method of accounting for oil and natural gas properties requires that the Company makes estimates based on its assumptions of future events that could change. These estimates are described below.
Depreciation,
depletion and amortization (DD&A) of oil and natural gas properties
The Company calculates DD&A by using the depletable base, which is equal to the net capitalized costs in our full cost pool plus estimated future development costs, and the estimated net proved reserve quantities. Capitalized costs added to the full cost pool include the following:
|
|
•
|
costs of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay rentals and other costs related to exploration and development of our oil and natural gas properties;
|
|
|
•
|
payroll costs including the related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and natural gas properties as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized costs do not include any costs related to the production of oil and natural gas or general corporate overhead;
|
|
|
•
|
costs associated with unevaluated properties, those lacking proved reserves, are excluded from the depletable base. These unevaluated property costs are added to the depletable base at such time as wells are completed on the properties or management determines these costs have been impaired. The Company’s determination that a property has or has not been impaired (which is discussed below) requires assumptions about future events;
|
|
|
•
|
estimated costs to dismantle, abandon and restore properties that are capitalized to the full cost pool when the related liabilities are incurred (see also the discussion below regarding Asset Retirement Obligations);
|
|
|
•
|
estimated future costs to develop proved properties are added to the full cost pool for purposes of the DD&A computation. The Company uses assumptions based on the latest geologic, engineering, regulatory and cost data available to it to estimate these amounts. However, the estimates made are subjective and may change over time. The Company’s estimates of future development costs are reviewed at least annually and as additional information becomes available; and
|
|
|
•
|
capitalized costs included in the full cost pool plus estimated future development costs are depleted and charged against earnings using the unit-of-production method. Under this method, the Company estimates the proved reserves quantities at the beginning of each accounting period. For each BOE produced during the period, the Company records a DD&A charge equal to the amount included in the depletable base (net of accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve quantities.
|
Because the Company uses estimates and assumptions to determine proved reserves (as discussed below) and the amounts included in the depletable base, our depletion rates may materially change if actual results differ from these estimates.
Ceiling
test
Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs and the value of commodity derivative instruments) plus the lower of cost or fair value of unevaluated properties, to the net capitalized costs of proved oil and natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted (at a 10% annualized rate) future net cash flows from
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
proved reserves plus the lower of cost or fair value of unevaluated properties, the Company is required to write-down the value of its oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are based on a twelve-month average pricing assumption. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimates of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. For the periods ended
December 31, 2018
and
2017
the Company recognized
no
write-down of oil and natural gas properties as a result of the ceiling test limitation. For the period ending December 31,
2016
the Company recognized write-downs of oil and natural gas properties of
$95.8 million
, respectively, as a result of the ceiling test limitation. If oil and natural gas prices were to decline, even if only for a short period of time, we could incur additional write-downs of oil and natural gas properties in the future. See Note 2 and Supplemental Information on Oil and Natural Gas Operations in the Footnotes to the Financial Statements for additional information regarding the Company’s oil and natural gas properties.
Estimating
reserves and present value of estimated future net cash flows
Estimates of quantities of proved oil and natural gas reserves, including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These assumptions include:
|
|
•
|
the prices at which the Company can sell its oil and natural gas production in the future. Oil and natural gas prices are volatile, but we are required to assume that they remain constant, using the twelve-month average pricing assumption. In general, higher oil and natural gas prices will increase quantities of proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts; and
|
|
|
•
|
the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that they remain constant. Increases in costs will reduce estimated oil and natural gas quantities and the present value of estimated future net cash flows, while decreases in costs will increase such amounts.
|
Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated quantities of oil and natural gas reserves for the Company’s properties that have relatively short productive lives. If oil and natural gas prices remain at current levels or decline further, it will have a negative impact on the present value of estimated future net cash flows and the estimated quantities of oil and natural gas reserves.
In addition, the process of estimating proved oil and natural gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under “Risk Factors.”
Sales of oil and natural gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.
Unproved
properties
Costs, including capitalized interest, associated with properties that do not have proved reserves are excluded from the depletable base, and are included in the line item “Unevaluated properties.” Unevaluated property costs are transferred to the depletable base when wells are completed on the properties or management determines that these costs have been impaired. In addition, the Company is required to determine whether its unevaluated properties are impaired and, if so, include the costs of such properties in the depletable base. We assess properties on an individual basis or as a group. The Company considers the following factors, among others: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. This determination may require the exercise of substantial judgment by management.
Asset
retirement
obligations
We record our estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life assets and the associated asset retirement costs. We estimate the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of the asset retirement obligation. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the Consolidated Balance Sheets.
|
|
|
|
|
Management’s Discussion and Analysis of Financial Condition and Results of Operation
|
|
Estimating the future plugging and abandonment costs of wells and related facilities is difficult and requires management to make estimates and judgments because most of the obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
See
Note 13
in the Footnotes to the Financial Statements for additional information.
Derivatives
To manage oil and natural gas price risk on a portion of our planned future production, we have historically utilized commodity derivative instruments (including collars, swaps, put and call options and other structures) on approximately
40%
to
60%
of our projected production volumes in any given year. We do not use these instruments for trading purposes. Settlements of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other futures index price.
Our derivative positions are carried at their fair value on the balance sheet with changes in fair value recorded through earnings. The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding derivatives and their fair values, see
Notes 7
and
8
in the Footnotes to the Financial Statements and Part II, Item 7A Commodity Price Risk.
Income taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). The Company had no valuation allowance as of
December 31, 2018
. See
Note 12
in the Footnotes to the Financial Statements for additional information regarding Income Taxes.
Accounting
Standards
Updates (“ASU”)
See
Note 2
in the Footnotes to the Financial Statements for information regarding ASUs.
Off-balance Sheet Arrangements
We had no off-balance sheet arrangements as of
December 31, 2018
.
ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of derivative instruments.
Commodity price risk
The Company’s revenues are derived from the sale of its oil and natural gas production. The prices for oil and natural gas remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and natural gas price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes which we hedge through use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately 40% to 60% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices.
The Company’s hedging portfolio as of December 31, 2018, linked to NYMEX benchmark pricing, covers approximately
6,389,000
Bbls and
8,282,500
MMBtu of our expected oil and natural gas production, respectively, for the full year of
2019
. We also have commodity hedging contracts linked to Midland WTI oil basis differentials relative to Cushing and Waha natural gas basis differentials covering approximately
4,746,500
Bbls and
11,321,000
MMBtu, respectively, of our expected oil and natural gas production for the full year of
2019
. See
Note 7
in the Footnotes to the Financial Statements for a description of the Company’s outstanding derivative contracts at
December 31, 2018
, and derivative contracts established subsequent to that date.
The Company may utilize fixed price swaps, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales.
The Company may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counterparty receives the difference from the Company. Additionally, the Company may sell put (or call) options at a price lower than the floor price (or higher than the ceiling price) in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), the Company’s net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis.
The Company may purchase put and call options, which reduce the Company’s exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to the Company.
The Company enters into these various agreements from time to time to reduce the effects of volatile oil and natural gas prices and does not enter into derivative transactions for speculative purposes. Presently, none of the Company’s derivative positions are designated as hedges for accounting purposes.
Interest rate risk
The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of
December 31, 2018
, the Company had
$200.0 million
outstanding under the Credit Facility with a weighted average interest rate of
3.62%
. An increase or decrease of
1.00%
in the interest rate would have a corresponding increase or decrease in our annual net income of approximately
$2.0 million
based on the balance outstanding at
December 31, 2018
. See
Note 6
in the Footnotes to the Financial Statements for more information on the Company’s interest rates on our Credit Facility.
Counterparty and customer credit risk
The Company’s principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts.
The Company markets its oil and natural gas production to energy marketing companies. We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended
December 31, 2018
, three purchasers accounted for more than 10% of our revenue:
Rio Energy International, Inc.
(
28%
);
Plains Marketing, L.P.
(
21%
); and
Enterprise Crude Oil, LLC
(
14%
). The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. At
December 31, 2018
our total receivables from the sale of our oil and natural gas production were approximately
$87.1 million
.
Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At
December 31, 2018
, our joint interest receivables were approximately
$41.5 million
.
At
December 31, 2018
our receivables resulting from derivative contracts were approximately
$2.1 million
. Our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Most of the counterparties on our derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. At
December 31, 2018
we had a net derivative
asset
position of
$47.2 million
.
ITEM 8. Financial Statements and Supplementary Data
|
|
|
|
Page
|
Reports of Independent Registered Public Accounting Firm
|
|
Consolidated Balance Sheets as of December 31, 2018 and 2017
|
|
Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 2018
|
|
Consolidated Statements of Stockholders’ Equity for Each of the Three Years in the Period Ended December 31, 2018
|
|
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2018
|
|
Notes to Consolidated Financial Statements
|
|
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Callon Petroleum Company
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2018 and 2017, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013
Internal Control—Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated
February 26, 2019
expressed an unqualified opinion.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2016.
Houston, Texas
February 26, 2019
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Callon Petroleum Company
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2018, based on criteria established in the 2013
Internal Control—Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013
Internal Control—Integrated Framework
issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2018, and our report dated February 26, 2019 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Houston, Texas
February 26, 2019
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par and share data)
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
December 31, 2017
|
ASSETS
|
|
|
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
$
|
16,051
|
|
|
$
|
27,995
|
|
Accounts receivable
|
131,720
|
|
|
114,320
|
|
Fair value of derivatives
|
65,114
|
|
|
406
|
|
Other current assets
|
9,740
|
|
|
2,139
|
|
Total current assets
|
222,625
|
|
|
144,860
|
|
Oil and natural gas properties, full cost accounting method:
|
|
|
|
Evaluated properties
|
4,585,020
|
|
|
3,429,570
|
|
Less accumulated depreciation, depletion, amortization and impairment
|
(2,270,675
|
)
|
|
(2,084,095
|
)
|
Net evaluated oil and natural gas properties
|
2,314,345
|
|
|
1,345,475
|
|
Unevaluated properties
|
1,404,513
|
|
|
1,168,016
|
|
Total oil and natural gas properties, net
|
3,718,858
|
|
|
2,513,491
|
|
Other property and equipment, net
|
21,901
|
|
|
20,361
|
|
Restricted investments
|
3,424
|
|
|
3,372
|
|
Deferred tax asset
|
—
|
|
|
52
|
|
Deferred financing costs
|
6,087
|
|
|
4,863
|
|
Acquisition deposit
|
—
|
|
|
900
|
|
Other assets, net
|
6,278
|
|
|
5,397
|
|
Total assets
|
$
|
3,979,173
|
|
|
$
|
2,693,296
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
Current liabilities:
|
|
|
|
Accounts payable and accrued liabilities
|
$
|
261,184
|
|
|
$
|
162,878
|
|
Accrued interest
|
24,665
|
|
|
9,235
|
|
Cash-settleable restricted stock unit awards
|
1,390
|
|
|
4,621
|
|
Asset retirement obligations
|
3,887
|
|
|
1,295
|
|
Fair value of derivatives
|
10,480
|
|
|
27,744
|
|
Other current liabilities
|
13,310
|
|
|
—
|
|
Total current liabilities
|
314,916
|
|
|
205,773
|
|
Senior secured revolving credit facility
|
200,000
|
|
|
25,000
|
|
6.125% senior unsecured notes due 2024
|
595,788
|
|
|
595,196
|
|
6.375% senior unsecured notes due 2026
|
393,685
|
|
|
—
|
|
Asset retirement obligations
|
10,405
|
|
|
4,725
|
|
Cash-settleable restricted stock unit awards
|
2,067
|
|
|
3,490
|
|
Deferred tax liability
|
9,564
|
|
|
1,457
|
|
Fair value of derivatives
|
7,440
|
|
|
1,284
|
|
Other long-term liabilities
|
100
|
|
|
405
|
|
Total liabilities
|
1,533,965
|
|
|
837,330
|
|
Commitments and contingencies
|
|
|
|
Stockholders’ equity:
|
|
|
|
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,458,948 shares outstanding
|
15
|
|
|
15
|
|
Common stock, $0.01 par value, 300,000,000 shares authorized; 227,582,575 and 201,836,172 shares outstanding, respectively
|
2,276
|
|
|
2,018
|
|
Capital in excess of par value
|
2,477,278
|
|
|
2,181,359
|
|
Accumulated deficit
|
(34,361
|
)
|
|
(327,426
|
)
|
Total stockholders’ equity
|
2,445,208
|
|
|
1,855,966
|
|
Total liabilities and stockholders’ equity
|
$
|
3,979,173
|
|
|
$
|
2,693,296
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Operations
(in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
Operating revenues:
|
|
|
|
|
|
Oil sales
|
$
|
530,898
|
|
|
$
|
322,374
|
|
|
$
|
177,652
|
|
Natural gas sales
|
56,726
|
|
|
44,100
|
|
|
23,199
|
|
Total operating revenues
|
587,624
|
|
|
366,474
|
|
|
200,851
|
|
Operating expenses:
|
|
|
|
|
|
Lease operating expenses
|
69,180
|
|
|
49,907
|
|
|
38,353
|
|
Production taxes
|
35,755
|
|
|
22,396
|
|
|
11,870
|
|
Depreciation, depletion and amortization
|
181,909
|
|
|
115,714
|
|
|
71,369
|
|
General and administrative
|
35,293
|
|
|
27,067
|
|
|
26,317
|
|
Settled share-based awards
|
—
|
|
|
6,351
|
|
|
—
|
|
Accretion expense
|
874
|
|
|
677
|
|
|
958
|
|
Write-down of oil and natural gas properties
|
—
|
|
|
—
|
|
|
95,788
|
|
Acquisition expense
|
5,083
|
|
|
2,916
|
|
|
3,673
|
|
Total operating expenses
|
328,094
|
|
|
225,028
|
|
|
248,328
|
|
Income (loss) from operations
|
259,530
|
|
|
141,446
|
|
|
(47,477
|
)
|
Other (income) expenses:
|
|
|
|
|
|
Interest expense, net of capitalized amounts
|
2,500
|
|
|
2,159
|
|
|
11,871
|
|
Loss on early extinguishment of debt
|
—
|
|
|
—
|
|
|
12,883
|
|
(Gain) loss on derivative contracts
|
(48,544
|
)
|
|
18,901
|
|
|
20,233
|
|
Other income
|
(2,896
|
)
|
|
(1,311
|
)
|
|
(637
|
)
|
Total other (income) expense
|
(48,940
|
)
|
|
19,749
|
|
|
44,350
|
|
Income (loss) before income taxes
|
308,470
|
|
|
121,697
|
|
|
(91,827
|
)
|
Income tax (benefit) expense
|
8,110
|
|
|
1,273
|
|
|
(14
|
)
|
Net income (loss)
|
300,360
|
|
|
120,424
|
|
|
(91,813
|
)
|
Preferred stock dividends
|
(7,295
|
)
|
|
(7,295
|
)
|
|
(7,295
|
)
|
Income (loss) available to common stockholders
|
$
|
293,065
|
|
|
$
|
113,129
|
|
|
$
|
(99,108
|
)
|
Income (loss) per common share:
|
|
|
|
|
|
Basic
|
$
|
1.35
|
|
|
$
|
0.56
|
|
|
$
|
(0.78
|
)
|
Diluted
|
$
|
1.35
|
|
|
$
|
0.56
|
|
|
$
|
(0.78
|
)
|
|
|
|
|
|
|
Shares used in computing income (loss) per common share:
|
|
|
|
|
|
Basic
|
216,941
|
|
|
201,526
|
|
|
126,258
|
|
Diluted
|
217,596
|
|
|
202,102
|
|
|
126,258
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Stockholders’ Equity
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock
|
|
Common Stock
|
|
Capital in Excess of Par
|
|
Retained Earnings (Deficit)
|
|
Total Stockholders' Equity
|
Balance at 12/31/2015
|
$
|
16
|
|
|
$
|
801
|
|
|
$
|
702,970
|
|
|
$
|
(341,029
|
)
|
|
$
|
362,758
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(91,813
|
)
|
|
(91,813
|
)
|
Shares issued pursuant to employee benefit plans
|
—
|
|
|
—
|
|
|
275
|
|
|
—
|
|
|
275
|
|
Restricted stock
|
—
|
|
|
4
|
|
|
2,323
|
|
|
—
|
|
|
2,327
|
|
Common stock issued
|
—
|
|
|
1,198
|
|
|
1,465,952
|
|
|
—
|
|
|
1,467,150
|
|
Preferred stock conversion
|
(1
|
)
|
|
7
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
Preferred stock dividend
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,295
|
)
|
|
(7,295
|
)
|
Balance at 12/31/2016
|
$
|
15
|
|
|
$
|
2,010
|
|
|
$
|
2,171,514
|
|
|
$
|
(440,137
|
)
|
|
$
|
1,733,402
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
120,424
|
|
|
120,424
|
|
Shares issued pursuant to employee benefit plans
|
—
|
|
|
—
|
|
|
311
|
|
|
—
|
|
|
311
|
|
Restricted stock
|
—
|
|
|
8
|
|
|
9,098
|
|
|
—
|
|
|
9,106
|
|
Common stock issued
|
—
|
|
|
—
|
|
|
18
|
|
|
—
|
|
|
18
|
|
Impact of forfeiture estimate
(a)
|
—
|
|
|
—
|
|
|
418
|
|
|
(418
|
)
|
|
—
|
|
Preferred stock dividend
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,295
|
)
|
|
(7,295
|
)
|
Balance at 12/31/2017
|
$
|
15
|
|
|
$
|
2,018
|
|
|
$
|
2,181,359
|
|
|
$
|
(327,426
|
)
|
|
$
|
1,855,966
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
300,360
|
|
|
300,360
|
|
Shares issued pursuant to employee benefit plans
|
—
|
|
|
—
|
|
|
533
|
|
|
—
|
|
|
533
|
|
Restricted stock
|
—
|
|
|
5
|
|
|
7,651
|
|
|
—
|
|
|
7,656
|
|
Common stock issued
|
—
|
|
|
253
|
|
|
287,735
|
|
|
—
|
|
|
287,988
|
|
Preferred stock dividend
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,295
|
)
|
|
(7,295
|
)
|
Balance at 12/31/2018
|
$
|
15
|
|
|
$
|
2,276
|
|
|
$
|
2,477,278
|
|
|
$
|
(34,361
|
)
|
|
$
|
2,445,208
|
|
|
|
(a)
|
As a result of the adoption of ASU No. 2016-09,
Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting
the Company elected to no longer estimate forfeitures. See
Note 2
in the Footnotes to Financial Statements for additional information about ASU 2016-09.
|
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Cash Flows
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
Cash flows from operating activities:
|
|
|
|
|
|
Net income (loss)
|
$
|
300,360
|
|
|
$
|
120,424
|
|
|
$
|
(91,813
|
)
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
Depreciation, depletion and amortization
|
184,731
|
|
|
118,051
|
|
|
73,072
|
|
Write-down of oil and natural gas properties
|
—
|
|
|
—
|
|
|
95,788
|
|
Accretion expense
|
874
|
|
|
677
|
|
|
958
|
|
Amortization of non-cash debt related items
|
2,483
|
|
|
2,150
|
|
|
3,115
|
|
Deferred income tax (benefit) expense
|
8,110
|
|
|
1,273
|
|
|
(14
|
)
|
(Gain) loss on derivatives, net of settlements
|
(75,816
|
)
|
|
10,429
|
|
|
38,135
|
|
(Gain) loss on sale of other property and equipment
|
(144
|
)
|
|
62
|
|
|
—
|
|
Non-cash loss on early extinguishment of debt
|
—
|
|
|
—
|
|
|
9,883
|
|
Non-cash expense related to equity share-based awards
|
6,289
|
|
|
8,254
|
|
|
2,765
|
|
Change in the fair value of liability share-based awards
|
375
|
|
|
3,288
|
|
|
6,953
|
|
Payments to settle asset retirement obligations
|
(1,469
|
)
|
|
(2,047
|
)
|
|
(1,471
|
)
|
Payments for cash-settled restricted stock unit awards
|
(4,990
|
)
|
|
(13,173
|
)
|
|
(10,300
|
)
|
Changes in current assets and liabilities:
|
|
|
|
|
|
Accounts receivable
|
(17,351
|
)
|
|
(44,495
|
)
|
|
(30,055
|
)
|
Other current assets
|
(7,601
|
)
|
|
108
|
|
|
(786
|
)
|
Current liabilities
|
74,311
|
|
|
30,947
|
|
|
25,288
|
|
Other long-term liabilities
|
(278
|
)
|
|
121
|
|
|
96
|
|
Other assets, net
|
(2,230
|
)
|
|
(1,528
|
)
|
|
(840
|
)
|
Other
|
—
|
|
|
(4,650
|
)
|
|
—
|
|
Net cash provided by operating activities
|
467,654
|
|
|
229,891
|
|
|
120,774
|
|
Cash flows from investing activities:
|
|
|
|
|
|
Capital expenditures
|
(611,173
|
)
|
|
(419,839
|
)
|
|
(190,032
|
)
|
Acquisitions
|
(718,793
|
)
|
|
(718,456
|
)
|
|
(654,679
|
)
|
Acquisition deposit
|
—
|
|
|
45,238
|
|
|
(46,138
|
)
|
Proceeds from sales of assets
|
9,009
|
|
|
20,525
|
|
|
24,562
|
|
Additions to other assets
|
(3,100
|
)
|
|
—
|
|
|
—
|
|
Net cash used in investing activities
|
(1,324,057
|
)
|
|
(1,072,532
|
)
|
|
(866,287
|
)
|
Cash flows from financing activities:
|
|
|
|
|
|
Borrowings on senior secured revolving credit facility
|
500,000
|
|
|
25,000
|
|
|
217,000
|
|
Payments on senior secured revolving credit facility
|
(325,000
|
)
|
|
—
|
|
|
(257,000
|
)
|
Payments on term loans
|
—
|
|
|
—
|
|
|
(300,000
|
)
|
Issuance of 6.125% senior unsecured notes due 2024
|
—
|
|
|
200,000
|
|
|
400,000
|
|
Premium on the issuance of 6.125% senior unsecured notes due 2024
|
—
|
|
|
8,250
|
|
|
—
|
|
Issuance of 6.375% senior unsecured notes due 2026
|
400,000
|
|
|
—
|
|
|
—
|
|
Payment of deferred financing costs
|
(9,430
|
)
|
|
(7,194
|
)
|
|
(10,793
|
)
|
Issuance of common stock
|
287,988
|
|
|
—
|
|
|
1,357,577
|
|
Payment of preferred stock dividends
|
(7,295
|
)
|
|
(7,295
|
)
|
|
(7,295
|
)
|
Tax withholdings related to restricted stock units
|
(1,804
|
)
|
|
(1,118
|
)
|
|
(2,207
|
)
|
Net cash provided by financing activities
|
844,459
|
|
|
217,643
|
|
|
1,397,282
|
|
Net change in cash and cash equivalents
|
(11,944
|
)
|
|
(624,998
|
)
|
|
651,769
|
|
Balance, beginning of period
|
27,995
|
|
|
652,993
|
|
|
1,224
|
|
Balance, end of period
|
$
|
16,051
|
|
|
$
|
27,995
|
|
|
$
|
652,993
|
|
The accompanying notes are an integral part of these consolidated financial statements.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
1.
|
|
8.
|
|
2.
|
|
9.
|
|
3.
|
Revenue Recognition
|
10.
|
|
4.
|
|
11.
|
|
5.
|
|
12.
|
|
6.
|
|
13.
|
|
7.
|
|
14.
|
|
|
|
|
|
|
|
|
|
Note 1
- Description of Business and Basis of Presentation
Description of business
Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.
Callon is an independent oil and natural gas company focused on the acquisition and development of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. The Company has historically been focused on the Midland Basin and entered the Delaware Basin through an acquisition completed in February 2017. The Company further expanded its presence in the Delaware Basin through our acquisitions in 2018.
Basis of presentation
Unless otherwise indicated, all dollar amounts included within the
Footnotes to the
Financial Statements are presented in thousands, except for per share and per unit data.
The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account balance and transaction eliminations, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation.
Note 2
– Summary
of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets, liabilities, revenues, and expenses. Management regularly evaluates its estimates and assumptions, including those related to valuation of oil and natural gas properties, future asset retirement obligations, income taxes and valuation of deferred tax assets, fair value measurements as it relates to financial instruments, material transactions, and commodity derivatives, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Accounts Receivable
Accounts receivable consists primarily of accrued oil and natural gas production receivables and joint interest receivables from outside working interest owners.
Revenue Recognition and Natural Gas Balancing
Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer applicable. In conjunction with the Company’s adoption of the new revenue recognition accounting standards, there was no material impact to the financial statements due to this change in accounting for its production imbalances. Natural gas balancing receivables and payables were immaterial as of
December 31, 2018
and
2017
. See
Note 3
for additional information on revenue recognition.
Oil and Natural Gas Properties
The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities.
When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs through adjustments to accumulated depreciation, depletion, amortization and impairment unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized.
Historical and estimated future development costs of oil and natural gas properties, which have been evaluated and contain proved reserves, as well as the historical cost of properties that have been determined to have no future economic value, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or the Company determines that these costs have been impaired. The Company assesses properties on an individual basis or as a group and considers the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves.
Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the sum of (a) the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at
10%
, plus (b) the lower of cost or fair value of unevaluated properties, and (c) net of related tax effects (collectively called the full cost ceiling). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. At December 31, 2018 and 2017, the 12-month average benchmark pricing used to estimate future net cash flows from proved reserves in accordance with the definitions and regulations of the SEC, including differential adjustments, was
$58.40
and
$51.34
per barrel of oil, respectively, and
$3.64
and
$2.98
per Mcf of natural gas, respectively. For the periods ended December 31, 2018 and 2017, the Company did
no
t recognize a write-down of oil and natural gas properties as a result of the ceiling test limitation. At December 31, 2016, the 12-month average benchmark pricing used, including differential adjustments, was
$42.75
per barrel of oil and
$2.48
per Mcf of natural gas and the Company recognized a
$95,788
write-down of oil and natural gas properties as a result of the ceiling test limitation.
Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle, abandon and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance, such costs are capitalized to the full cost pool when the related liabilities are incurred. In accordance with full cost accounting rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject to the full cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full cost ceiling amount.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Other Property and Equipment
The Company depreciates its other property and equipment using the straight-line method over estimated useful lives of
three
to
20 years
. Depreciation expense of
$1,078
,
$900
and
$793
relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended
December 31, 2018
,
2017
and
2016
, respectively. The accumulated depreciation on other property and equipment was
$16,562
and
$16,259
as of
December 31, 2018
and
2017
, respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist.
Capitalized Interest
The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense. During the years ended
December 31, 2018
,
2017
and
2016
, the Company capitalized
$56,151
,
$33,783
and
$19,857
of interest expense.
Deferred
Financing
Costs
Deferred financing costs are stated at cost, net of amortization, and as a direct reduction from the debt’s carrying value on the balance sheet. For revolving debt arrangements, deferred financing costs are stated at cost, net of amortization, as an asset on the balance sheet. Amortization of deferred financing costs is computed using the straight-line method over the life of the loan. Amortization of deferred financing costs of
$2,483
,
$2,150
and
$3,115
were recorded for the years ended
December 31, 2018
,
2017
and
2016
, respectively.
Asset Retirement Obligations
The Company records an estimate of the fair value of liabilities for obligations associated with the costs to retire tangible long-life assets. The Company estimates the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported as accretion expense within operating expenses in the Consolidated Statements of Operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the Consolidated Balance Sheets. See
Note 13
for additional information.
Derivatives
Derivative contracts outstanding as of
December 31, 2018
were not designated as accounting hedges, and are carried on the balance sheet at fair value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See
Notes 7
and
8
for additional information regarding the Company’s derivative contracts.
Income Taxes
Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards. A valuation allowance is provided for that portion of deferred tax assets, if any, for which it is deemed more likely than not that a future benefit will not be realized. As of
December 31, 2018
the valuation allowance was
$0
. See
Note 12
for additional information.
Share-Based Compensation
The Company grants to directors and employees stock options and restricted stock unit awards (“RSU awards”) that may be settled in common stock (“RSU equity awards”) or cash (“Cash-settleable RSU awards”), some of which are subject to achievement of certain performance conditions.
Stock Options.
For historical stock options the Company expected to settle in common stock, share-based compensation expense was based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally
three years
).
RSU
equity
awards and Cash-settleable RSU awards.
For RSU equity awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally
three years
for employees and
one
year for directors). Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
For RSU equity awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally
three
years). For cash-settleable RSU awards subject to a performance condition that the Company expects or is required to settle in cash, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, with the estimated fair value recognized over the vesting period (generally
three years
).
See the Accounting Standards Updates section within this footnote for information about recently adopted ASUs related to Stock Compensation.
Non-cash Investing and Supplemental
Cash Flow Information
The following table sets forth the non-cash investing and supplemental cash flow information for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Non-cash investing information
|
|
|
|
|
|
|
Change in accrued capital expenditures
|
|
$
|
(52,757
|
)
|
|
$
|
(39,532
|
)
|
|
$
|
(613
|
)
|
Supplemental cash flow information
(a)
|
|
|
|
|
|
|
Cash paid for interest, net of capitalized interest
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
8,679
|
|
|
|
(a)
|
During the three year period ended
2018
, the Company paid
no
federal income taxes.
|
Earnings per Share (“EPS”)
The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS, using the treasury stock method, reflects the potential dilution caused by the exercise of options and vesting of restricted stock and RSUs settleable in shares.
Accounting Standards Updates
Recently issued ASUs - Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”).
ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company has engaged a third-party consultant to assist with its current process of assessing existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process includes review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component.
The Company plans to elect the package of practical expedients within ASU 2016-02 that allows an entity to not reassess, prior to the effective date, (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases, but does not plan to elect the hindsight practical expedient when determining the lease term of existing contracts at the effective date. The new standard also provides practical expedients for an entity’s ongoing accounting. The Company currently expects to elect the short-term lease recognition exemption for all leases that qualify. The Company also currently expects to elect the practical expedient to not separate lease and non-lease components for the majority of classes of underlying assets.
Additionally, the Company also plans to elect the practical expedient under ASU 2018-01 and not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. The Company is working to complete its evaluation of the impact of ASC Topic 842 on its financial statements, accounting policies and internal controls, including implementation of systems and processes to capture, classify and account for leases within the scope of the new guidance and to provide the related disclosures.
The Company will adopt this guidance as of January 1, 2019, the transition date, using the simplified transition method described in ASU 2018-11, in which a cumulative-effect adjustment will be recognized in the opening balance of retained earnings in the period of
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
adoption. At this time, the impact upon adoption of ASC Topic 842 is expected to result in recognition of additional operating liabilities, with corresponding right-of-use assets, ranging from
$45 million
to
$55 million
on the Company’s Consolidated Balance Sheet for leases existing as of January 1, 2019, of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing operating leases. The adoption of this standard is not expected to have a material impact on the Company’s Consolidated Statement of Income nor Consolidated Statement of Cash Flows.
Recently issued ASUs - Other
In June 2018, the FASB issued ASU No. 2018-07,
Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting
(“ASU 2018-07”). The standard is intended to simplify several aspects of the accounting for nonemployee share-based payment transactions for acquiring goods and services from nonemployees, including the timing and measurement of nonemployee awards. The guidance in ASU 2018-06 is effective for public entities for annual reporting periods beginning after December 15, 2018, including interim periods therein. The Company does not expect a material impact on its consolidated financial statements upon adoption of this guidance.
Recently Adopted ASUs - Revenue Recognition
In May 2014, the FASB issued ASU No. 2014-09,
Revenue from Contracts with Customers
(“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 replaced most of the existing revenue recognition requirements in GAAP. See Note 3 for additional information on revenue recognition.
The Company adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption. Prior to the adoption of ASC 606, gathering and treating fees associated with the Company’s gas processing agreements have historically been presented within lease operating expenses in the statement of operations. The current period presentation reports these fees as a reduction to natural gas revenues. The impact of adoption on the current period statement of operations is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As reported
|
|
Adjustments
|
|
Presentation without adoption of ASC Topic 606
|
Operating revenues
|
|
|
|
|
|
Natural gas sales
|
$
|
56,726
|
|
|
$
|
7,646
|
|
|
$
|
64,372
|
|
Total operating revenues
|
587,624
|
|
|
7,646
|
|
|
595,270
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
Lease operating expenses
|
$
|
69,180
|
|
|
$
|
7,646
|
|
|
$
|
76,826
|
|
Total operating expenses
|
328,094
|
|
|
7,646
|
|
|
335,740
|
|
Recently Adopted ASUs - Other
In August 2016, the FASB issued ASU No. 2016-15,
Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments
(“ASU 2016-15”). The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The Company adopted this update on January 1, 2018 and it did not have a material impact on its consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-01,
Business Combinations-Clarifying the Definition of a Business (“ASU 2017-01”).
The guidance in ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The guidance provides a screen to determine when a set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Company adopted this update effective January 1, 2018. The adoption of this update did not have a material impact on its consolidated financial statements.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
In March 2016, the FASB issued ASU No. 2016-09,
Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting
(“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements. The Company has elected to no longer estimate forfeitures.
In December 2016, the FASB issued ASU No. 2016-18,
Statement of Cash Flows (Topics 230): Restricted Cash
(“ASU 2016-18”). The objective of the standard is to require the change during the period in total restricted cash and cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and the end-of-period total amounts shown on the statement of cash flows. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements.
Note 3 - Revenue Recognition
Revenue from contracts with customers
Oil sales
Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received.
Natural gas sales
Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. The revenue received from the sale of NGLs is included in the natural gas sales. Under these processing agreements, when control of the natural gas changes at the point of delivery, the treatment of gathering and treating fees are recorded net of revenues. Gathering and treating fees have historically been recorded as an expense in lease operating expense in the statement of operations. The Company has modified the presentation of revenues and expenses to include these fees net of revenues. For the
twelve months ended
December 31, 2018
,
$7,646
of gathering and treating fees were recognized and recorded as a reduction to natural gas revenues in the consolidated statement of operations. For the
twelve months ended
December 31, 2017
and
2016
,
$3,433
and
$1,727
of gathering and treating fees were recognized and recorded as part of lease operating expense in the consolidated statement of operations, respectively.
Accounts receivable from revenues from contracts with customers
Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at
December 31, 2018
and
2017
of
$87,061
and
$70,138
, respectively, and does not currently include an allowance for doubtful accounts. Accounts receivable, net, from oil and natural gas are included in accounts receivable on the consolidated balance sheets.
Transaction price allocated to remaining performance obligations
For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Prior period performance obligations
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for
30
to
90
days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Note 4 – Acquisitions and Dispositions
2018 Acquisitions
On August 31, 2018, the Company completed the acquisition of approximately
28,000
net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for
$539,519
, including customary purchase price adjustments (the “Delaware Asset Acquisition”). The Company issued debt and equity to fund, in part, the Delaware Asset Acquisition. See
Notes 6
and
11
for additional information regarding the Company’s debt obligations and equity offerings. The following table summarizes the estimated acquisition date fair values of the acquisition:
|
|
|
|
|
Evaluated oil and natural gas properties
|
$
|
253,089
|
|
Unevaluated oil and natural gas properties
|
287,000
|
|
Asset retirement obligations
|
(570
|
)
|
Net assets acquired
|
$
|
539,519
|
|
The preliminary purchase price allocations are subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material.
In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian Basin. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for
$37,770
, including customary purchase price adjustments. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for
$87,865
, including customary purchase price adjustments.
2017 Acquisitions
On February 13, 2017, the Company completed the acquisition of
29,175
gross (
16,688
net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of
$646,559
, excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see
Note 11
for additional information regarding the equity offering). The Company obtained an
82%
average working interest (
75%
average net revenue interest) in the properties acquired in the Ameredev Transaction. In December 2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit in the amount of
$46,138
to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December 31, 2016. The following table summarizes the estimated acquisition date fair values of the acquisition:
|
|
|
|
|
Evaluated oil and natural gas properties
|
$
|
137,368
|
|
Unevaluated oil and natural gas properties
|
509,359
|
|
Asset retirement obligations
|
(168
|
)
|
Net assets acquired
|
$
|
646,559
|
|
On June 5, 2017, the Company completed the acquisition of
7,031
gross (
2,488
net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Transaction discussed above, for
$52,014
, including customary purchase price adjustments. The Company funded the cash purchase price with its available cash and proceeds from the issuance of an additional
$200,000
of its
6.125%
senior notes due 2024 (“6.125% Senior Notes”) (see
Note 6
for additional information regarding the Company’s debt obligations).
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
2016 Acquisitions
On October 20, 2016, the Company completed the acquisition of
6,904
gross (
5,952
net) acres primarily located in Howard County, Texas from Plymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for total cash consideration of
$339,687
, excluding customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see
Note 11
for additional information regarding the equity offering). The Company acquired an
82%
average working interest (
62%
average net revenue interest) in the properties acquired in the Plymouth Transaction. The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition:
|
|
|
|
|
Evaluated oil and natural gas properties
|
$
|
65,043
|
|
Unevaluated oil and natural gas properties
|
274,664
|
|
Asset retirement obligations
|
(20
|
)
|
Net assets acquired
|
$
|
339,687
|
|
On May 26, 2016, the Company completed the acquisition of
17,298
gross (
14,089
net) acres primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of
$220,000
and
9.3 million
shares of common stock (at an assumed offering price of
$11.74
per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date) for a total purchase price of
$329,573
, excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an
81%
average working interest (
61%
average net revenue interest) in the properties acquired in the Big Star Transaction. The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition:
|
|
|
|
|
Evaluated oil and natural gas properties
|
$
|
96,194
|
|
Unevaluated oil and natural gas properties
|
233,387
|
|
Asset retirement obligations
|
(8
|
)
|
Net assets acquired
|
$
|
329,573
|
|
During 2016, the Company also closed on various acquisitions in the Midland Basin for an aggregate total purchase price of approximately
$73,240
, net of
$23,045
in sales of working interest. The acquisitions included the purchase of additional working interest and acreage in the Company’s existing core operating area.
Unaudited pro forma financial statements
The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Delaware Asset Acquisition, Ameredev Transaction, Plymouth Transaction, and Big Star Transaction had occurred as presented, or to project the Company’s results of operations for any future periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended December 31,
|
|
|
2018
|
(a)
|
|
2017
|
(a)
|
|
2016
|
(a)
|
Revenues
|
|
$
|
668,759
|
|
|
|
$
|
472,949
|
|
|
|
$
|
243,273
|
|
|
Income (loss) from operations
|
|
295,738
|
|
|
|
212,381
|
|
|
|
(39,730
|
)
|
|
Income (loss) available to common stockholders
|
|
336,730
|
|
|
|
184,064
|
|
|
|
(82,612
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.55
|
|
|
|
$
|
0.91
|
|
|
|
$
|
(0.50
|
)
|
|
Diluted
|
|
$
|
1.55
|
|
|
|
$
|
0.91
|
|
|
|
$
|
(0.50
|
)
|
|
|
|
(a)
|
The pro forma financial information was prepared assuming the Delaware Asset Acquisition occurred as of January 1, 2017, and the Ameredev Transaction, Plymouth Transaction, and Big Star Transaction occurred as of January 1, 2016.
|
The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest.
The properties associated with the Delaware Asset Acquisition, Ameredev Transaction, Big Star Transaction, and the Plymouth Transaction have been commingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Note 5
- Earnings Per Share
Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares and unexercised options outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(share amounts in thousands)
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Net income (loss)
|
|
$
|
300,360
|
|
|
$
|
120,424
|
|
|
$
|
(91,813
|
)
|
Preferred stock dividends
|
|
(7,295
|
)
|
|
(7,295
|
)
|
|
(7,295
|
)
|
Income (loss) available to common stockholders
|
|
$
|
293,065
|
|
|
$
|
113,129
|
|
|
$
|
(99,108
|
)
|
|
|
|
|
|
|
|
Weighted average shares outstanding
|
|
216,941
|
|
|
201,526
|
|
|
126,258
|
|
Dilutive impact of restricted stock
|
|
655
|
|
|
576
|
|
|
—
|
|
Weighted average shares outstanding for diluted income (loss) per share
(a)
|
|
217,596
|
|
|
202,102
|
|
|
126,258
|
|
|
|
|
|
|
|
|
Basic income (loss) per share
|
|
$
|
1.35
|
|
|
$
|
0.56
|
|
|
$
|
(0.78
|
)
|
Diluted income (loss) per share
|
|
$
|
1.35
|
|
|
$
|
0.56
|
|
|
$
|
(0.78
|
)
|
|
|
|
|
|
|
|
Stock options
(b)
|
|
—
|
|
|
—
|
|
|
15
|
|
Restricted stock
(b)
|
|
89
|
|
|
16
|
|
|
—
|
|
|
|
(a)
|
Because the Company reported a net loss available to common stockholders for the year ended
December 31, 2016
, no unvested stock awards were included in computing net loss per share because the effect was anti-dilutive.
|
|
|
(b)
|
Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.
|
Note 6
– Borrowings
The Company’s borrowings consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2018
|
|
2017
|
Principal components:
|
|
|
|
|
Senior secured revolving credit facility
|
|
$
|
200,000
|
|
|
$
|
25,000
|
|
6.125% senior unsecured notes due 2024
|
|
600,000
|
|
|
600,000
|
|
6.375% senior unsecured notes due 2026
|
|
400,000
|
|
|
—
|
|
Total principal outstanding
|
|
1,200,000
|
|
|
625,000
|
|
Premium on 6.125% Senior Notes, net of accumulated amortization
|
|
6,469
|
|
|
7,594
|
|
Unamortized deferred financing costs
|
|
(16,996
|
)
|
|
(12,398
|
)
|
Total carrying value of borrowings
(a)
|
|
$
|
1,189,473
|
|
|
$
|
620,196
|
|
|
|
(a)
|
Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of
$6,087
and
$4,863
as of December 31, 2018 and 2017, respectively.
|
Senior secured revolving credit
facility (“Credit Facility”)
On
May 25, 2017
, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of
May 25, 2022
. JPMorgan Chase Bank, N.A. is Administrative Agent, and participants include
17
institutional lenders. The total notional amount available under the Credit Facility is
$2,000,000
. Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. Concurrent with the execution of the Sixth Amended and Restated Credit Agreement, the Credit Facility’s borrowing base increased to
$650,000
, but the Company elected an aggregate commitment amount of
$500,000
. On
November 7, 2017
, the Credit Facility’s borrowing base increased to
$700,000
with a reaffirmed commitment of
$500,000
, following the semi-annual review.
Effective
April 5, 2018
, the Company entered into the first amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to
$825,000
, (2) increased the elected commitment amount to
$650,000
, (3) amended various covenants and terms to reflect current market trends, and (4) extended the maturity date to
May 25, 2023
.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Effective
September 27, 2018
, the Company entered into the second amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to
$1,100,000
, (2) increase the elected commitment amount to
$850,000
, and (3) amended various covenants and terms to reflect current market trends. As of
December 31, 2018
, the Credit Facility’s borrowing base remained at
$1,100,000
with an elected commitment amount of
$850,000
.
As of
December 31, 2018
, there was
$200,000
of principal and
$17,675
in letters of credit outstanding on the Credit Facility. For the year ended
December 31, 2018
, the Credit Facility had a weighted-average interest rate of
3.62%
, calculated as the LIBOR plus a tiered rate ranging from
1.25%
to
2.25%
, which is determined based on utilization of the facility. In addition, the Credit Facility carries a current commitment fee of
0.375%
per annum, payable quarterly, on the unused portion of the borrowing base.
6.375%
Senior Notes
On
June 7, 2018
, the Company issued
$400,000
aggregate principal amount of
6.375%
Senior Notes with a maturity date of
July 1, 2026
and interest payable semi-annually beginning on January 1, 2019. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately
$394,000
. The
6.375%
Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is
100%
owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.
The Company may redeem the
6.375%
Senior Notes in accordance with the following terms: (1) prior to
July 1, 2021
, a redemption of up to
35%
of the principal in an amount not greater than the net proceeds from certain equity offerings, and within
180
days of the closing date of such equity offerings, at a redemption price of
106.375%
of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least
65%
of the principal will remain outstanding after such redemption; (2) prior to
July 1, 2021
, a redemption of all or part of the principal at a price of
100%
of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of
103.188%
of principal if the redemption occurs on or after July 1, 2021, but before
July 1, 2022
, and (ii) of
102.125%
of principal if the redemption occurs on or after
July 1, 2022
, but before
July 1, 2023
, and (iii) of
101.063%
of principal if the redemption occurs on or after
July 1, 2023
, but before
July 1, 2024
, and (iv) of
100%
of principal if the redemption occurs on or after
July 1, 2024
.
Following a change of control, each holder of the
6.375%
Senior Notes may require the Company to repurchase all or a portion of the
6.375%
Senior Notes at a price of
101%
of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.
6.125%
Senior Notes
On October 3, 2016, the Company issued
$400,000
aggregate principal amount of
6.125%
Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately
$391,270
. The
6.125%
Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is
100%
owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.
On May 19, 2017, the Company issued an additional
$200,000
aggregate principal amount of its
6.125%
Senior Notes which with the existing
$400,000
aggregate principal amount of
6.125%
Senior Notes are treated as a single class of notes under the indenture. The net proceeds of the offering, including a premium issue price of
104.125%
and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately
$206,139
. The Company used the proceeds, in part, to fund an acquisition completed on June 5, 2017 (discussed further in
Note 4
) and for general corporate purposes.
The Company may redeem the
6.125%
Senior Notes in accordance with the following terms; (1) prior to
October 1, 2019
, a redemption of up to
35%
of the principal in an amount not greater than the net proceeds from certain equity offerings, and within
180
days of the closing date of such equity offerings, at a redemption price of
106.125%
of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least
65%
of the principal will remain outstanding after such redemption; (2) prior to
October 1, 2019
, a redemption of all or part of the principal at a price of
100%
of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; (3) a redemption, in whole or in part, at a redemption price, plus accrued and
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
unpaid interest, if any, to the date of the redemption, (i) of
104.594%
of principal if the redemption occurs on or after
October 1, 2019
, but before
October 1, 2020
, and (ii) of
103.063%
of principal if the redemption occurs on or after
October 1, 2020
, but before
October 1, 2021
, and (iii) of
101.531%
of principal if the redemption occurs on or after October 1, 2021, but before
October 1, 2022
, and (iv) of
100%
of principal if the redemption occurs on or after
October 1, 2022
.
Following a change of control, each holder of the
6.125%
Senior Notes may require the Company to repurchase all or a portion of the
6.125%
Senior Notes at a price of
101%
of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.
Term loans
The Company historically held a term loan agreement since March 11, 2014. On October 8, 2014, the original term loan was repaid in full using proceeds from a new secured second lien term loan (the “Second Lien Loan”) with a maturity date of
October 8, 2021
. On October 11, 2016, the Second Lien Loan was repaid in full at the prepayment rate of
101%
using proceeds from the sale of the
6.125%
Senior Notes, which resulted in a loss on early extinguishment of debt of
$12,883
(inclusive of
$3,000
in prepayment fees and
$9,883
of unamortized debt issuance costs).
Restrictive covenants
The Company’s Credit Facility and the indentures governing its
6.125%
and
6.375%
Senior Notes contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2018.
Note 7
- Derivative Instruments and Hedging Activities
Objectives and strategies for using derivative instruments
The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps, put and call options and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.
Counterparty risk and offsetting
The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see
Note 8
for additional information regarding fair value.
The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.
Financial statement presentation and settlements
Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See
Note 8
for additional information regarding fair value.
Derivatives not designated as hedging instruments
The Company records its derivative contracts at fair value in the consolidated balance sheets and records changes in fair value as a gain or loss on derivative contracts in the consolidated statements of operations. Settlements are also recorded as a gain or loss on derivative contracts in the consolidated statements of operations.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
The following table reflects the fair value of the Company’s derivative instruments for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Presentation
|
|
Asset Fair Value
|
|
Liability Fair Value
|
|
Net Derivative Fair Value
|
Commodity
|
|
Classification
|
|
Line Description
|
|
12/31/2018
|
|
12/31/2017
|
|
12/31/2018
|
|
12/31/2017
|
|
12/31/2018
|
|
12/31/2017
|
Oil
|
|
Current
|
|
Fair value of derivatives
|
|
$
|
60,097
|
|
|
$
|
—
|
|
|
$
|
(10,480
|
)
|
|
$
|
(27,744
|
)
|
|
$
|
49,617
|
|
|
$
|
(27,744
|
)
|
Oil
|
|
Non-current
|
|
Fair value of derivatives
|
|
—
|
|
|
—
|
|
|
(5,672
|
)
|
|
(1,284
|
)
|
|
(5,672
|
)
|
|
(1,284
|
)
|
Natural gas
|
|
Current
|
|
Fair value of derivatives
|
|
5,017
|
|
|
406
|
|
|
—
|
|
|
—
|
|
|
5,017
|
|
|
406
|
|
Natural gas
|
|
Non-current
|
|
Fair value of derivatives
|
|
—
|
|
|
—
|
|
|
(1,768
|
)
|
|
—
|
|
|
(1,768
|
)
|
|
—
|
|
Totals
|
|
|
|
|
|
$
|
65,114
|
|
|
$
|
406
|
|
|
$
|
(17,920
|
)
|
|
$
|
(29,028
|
)
|
|
$
|
47,194
|
|
|
$
|
(28,622
|
)
|
As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2018
|
|
Presented without
|
|
|
|
As Presented with
|
|
Effects of Netting
|
|
Effects of Netting
|
|
Effects of Netting
|
Current assets: Fair value of derivatives
|
78,091
|
|
|
(12,977
|
)
|
|
65,114
|
|
|
|
|
|
|
|
Current liabilities: Fair value of derivatives
|
(23,457
|
)
|
|
12,977
|
|
|
(10,480
|
)
|
Long-term liabilities: Fair value of derivatives
|
(7,440
|
)
|
|
—
|
|
|
(7,440
|
)
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2017
|
|
Presented without
|
|
|
|
As Presented with
|
|
Effects of Netting
|
|
Effects of Netting
|
|
Effects of Netting
|
Current assets: Fair value of derivatives
|
406
|
|
|
—
|
|
|
406
|
|
|
|
|
|
|
|
Current liabilities: Fair value of derivatives
|
(27,744
|
)
|
|
—
|
|
|
(27,744
|
)
|
Long-term liabilities: Fair value of derivatives
|
(1,284
|
)
|
|
—
|
|
|
(1,284
|
)
|
For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Oil derivatives
|
|
|
|
|
|
|
Net gain (loss) on settlements
|
|
$
|
(27,510
|
)
|
|
$
|
(9,067
|
)
|
|
$
|
17,801
|
|
Net gain (loss) on fair value adjustments
|
|
72,973
|
|
|
(11,426
|
)
|
|
(37,543
|
)
|
Total gain (loss) on oil derivatives
|
|
$
|
45,463
|
|
|
$
|
(20,493
|
)
|
|
$
|
(19,742
|
)
|
Natural gas derivatives
|
|
|
|
|
|
|
Net gain on settlements
|
|
$
|
238
|
|
|
$
|
594
|
|
|
$
|
102
|
|
Net gain (loss) on fair value adjustments
|
|
2,843
|
|
|
998
|
|
|
(593
|
)
|
Total gain (loss) on natural gas derivatives
|
|
$
|
3,081
|
|
|
$
|
1,592
|
|
|
$
|
(491
|
)
|
|
|
|
|
|
|
|
Total gain (loss) on oil & natural gas derivatives
|
|
$
|
48,544
|
|
|
$
|
(18,901
|
)
|
|
$
|
(20,233
|
)
|
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Derivative positions
Listed in the tables below are the outstanding oil and natural gas derivative contracts as of
December 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
For the Full Year of
|
|
For the Full Year of
|
Oil contracts (WTI)
|
|
2019
|
|
2020
|
Puts
|
|
|
|
|
Total volume (Bbls)
|
|
912,500
|
|
|
—
|
|
Weighted average price per Bbl
|
|
$
|
65.00
|
|
|
$
|
—
|
|
Put spreads
|
|
|
|
|
Total volume (Bbls)
|
|
912,500
|
|
|
—
|
|
Weighted average price per Bbl
|
|
|
|
|
Floor (long put)
|
|
$
|
65.00
|
|
|
$
|
—
|
|
Floor (short put)
|
|
$
|
42.50
|
|
|
$
|
—
|
|
Collar contracts combined with short puts (three-way collars)
|
|
|
|
|
Total volume (Bbls)
|
|
4,564,000
|
|
|
—
|
|
Weighted average price per Bbl
|
|
|
|
|
Ceiling (short call)
|
|
$
|
67.62
|
|
|
$
|
—
|
|
Floor (long put)
|
|
$
|
56.60
|
|
|
$
|
—
|
|
Floor (short put)
|
|
$
|
43.60
|
|
|
$
|
—
|
|
|
|
|
|
|
Oil contracts (Midland basis differential)
|
|
|
|
|
Swap contracts
|
|
|
|
|
Total volume (Bbls)
|
|
4,746,500
|
|
|
4,024,000
|
|
Weighted average price per Bbl
|
|
$
|
(4.72
|
)
|
|
$
|
(1.51
|
)
|
|
|
|
|
|
Natural gas contracts (Henry Hub)
|
|
|
|
|
Collar contracts (two-way collars)
|
|
|
|
|
Total volume (MMBtu)
|
|
8,282,500
|
|
|
—
|
|
Weighted average price per MMBtu
|
|
|
|
|
Ceiling (short call)
|
|
$
|
3.46
|
|
|
$
|
—
|
|
Floor (long put)
|
|
$
|
2.91
|
|
|
$
|
—
|
|
|
|
|
|
|
Natural gas contracts (Waha basis differential)
|
|
|
|
|
Swap contracts
|
|
|
|
|
Total volume (MMBtu)
|
|
11,321,000
|
|
|
4,758,000
|
|
Weighted average price per MMBtu
|
|
$
|
(1.23
|
)
|
|
$
|
(1.12
|
)
|
Note 8
-
Fair Value Measurements
The fair value hierarchy included in GAAP gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority.
Fair value of financial instruments
Cash, cash equivalents, and restricted investments.
The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.
Debt.
The carrying amount of the Company’s floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
2017
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
Credit Facility
(a)
|
$
|
200,000
|
|
|
$
|
200,000
|
|
|
$
|
25,000
|
|
|
$
|
25,000
|
|
6.125% Senior Notes
(b)
|
595,788
|
|
|
558,000
|
|
|
595,196
|
|
|
618,000
|
|
6.375% Senior Notes
(b)
|
393,685
|
|
|
372,000
|
|
|
—
|
|
|
—
|
|
Total
|
$
|
1,189,473
|
|
|
$
|
1,130,000
|
|
|
$
|
620,196
|
|
|
$
|
643,000
|
|
|
|
(b)
|
The fair value was based upon Level 2 inputs. See
Note 6
for additional information about the Company’s
6.125%
and
6.375%
Senior Notes.
|
Assets and liabilities measured at fair value on a recurring basis
Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value:
Commodity derivative instruments.
The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See
Note 7
for additional information regarding the Company’s derivative instruments.
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
Classification
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Assets
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
Fair value of derivatives
|
|
$
|
—
|
|
|
$
|
65,114
|
|
|
$
|
—
|
|
|
$
|
65,114
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
Fair value of derivatives
|
|
—
|
|
|
(17,920
|
)
|
|
—
|
|
|
(17,920
|
)
|
Total net assets
|
|
|
$
|
—
|
|
|
$
|
47,194
|
|
|
$
|
—
|
|
|
$
|
47,194
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
Classification
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Assets
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
Fair value of derivatives
|
|
$
|
—
|
|
|
$
|
406
|
|
|
$
|
—
|
|
|
$
|
406
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
Fair value of derivatives
|
|
—
|
|
|
(29,028
|
)
|
|
—
|
|
|
(29,028
|
)
|
Total net liabilities
|
|
|
$
|
—
|
|
|
$
|
(28,622
|
)
|
|
$
|
—
|
|
|
$
|
(28,622
|
)
|
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Acquisitions.
The Company determines the fair value of the assets acquired and liabilities assumed using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 1, Level 2 and Level 3 inputs.
Note 9
–
Employee Benefit Plans
Savings and Protection Plan (“401(k) Plan”)
The 401(k) Plan provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee’s deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company common stock to employees. The amounts held under the 401(k) Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401(k) Plan. The total amounts contributed by the Company were
$2,082
,
$1,292
and
$1,018
in the years
2018
,
2017
and
2016
, respectively. Of those amounts contributed, the value of common stock contributed for each period was
$600
,
$313
, and
$277
, respectively.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Note 10
-
Share-Based Compensation
The Company grants various forms of share-based compensation awards to employees of the Company and its subsidiaries and to non-employee members of the Board of Directors. At
December 31, 2018
, shares available for future share-based awards, including stock options or restricted stock grants, under the Company’s only active plan, the 2018 Plan, were
9,806,953
.
2011 Omnibus Incentive Plan (the “2011 Plan”)
The 2011 Plan, which became effective May 12, 2011 and as amended through May 14, 2015, authorized and reserved for issuance
5,141,000
shares. As of May 10, 2018, no more shares will be issued from the 2011 Plan and the remaining
1,322,742
shares authorized and available for issuance under the 2011 Plan transferred into the 2018 Omnibus Incentive Plan (the “2018 Plan”). Shares, which would otherwise become available for issuance under the 2011 Plan as a result of vesting and/or forfeiture of any equity awards existing prior to the effective date of the 2018 Plan, will increase the authorized shares available to the 2018 Plan.
RSU equity awards
. RSU equity awards issued under the 2011 Plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. RSU equity awards under the 2011 Plan generally vest over time but may also be subject to attaining specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards.
For performance-based RSU equity awards, the Company recognizes expense based on the fair value of the awards at the grant date. Awards with a performance-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded. Performance-based RSU equity awards that vest are based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between
0%
and
200%
of the base units awarded.
Cash-settled RSU
awards.
Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards under the 2011 Plan are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense.
A significant portion of the Company’s cash-settled RSU awards include a performance-based vesting condition that determines the actual number of units that will ultimately vest. The number of RSUs that vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between
0%
and
200%
of the base units awarded. The fair value of the Company’s performance-based RSU awards is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group.
2018 Omnibus Incentive Plan (the “2018 Plan”)
The 2018 Plan, which became effective May 10, 2018 following shareholder approval, authorized and reserved for issuance
9.4 million
shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2018 Plan is the Company’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the 2011 Plan became issuable under the 2018 Plan. This transfer provision resulted in the transfer of an additional
1,322,742
shares into the 2018 Plan, increasing the quantity authorized and reserved for issuance under the 2018 Plan to
10,722,742
at the inception of the 2018 Plan. Another provision provided that shares, which would otherwise become available for issuance under the 2011 Plan as a result of vesting and/or forfeiture of any equity awards existing as of the effective date of the 2018 Plan, would also increase the authorized shares available to the 2018 Plan.
RSU equity
awards
. RSU equity awards issued under the 2018 Plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. RSU equity awards under the 2018 Plan generally vest over time but may also be subject to attaining specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense on the grant date for any immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards.
For performance-based RSU equity awards, the Company recognizes expense based on the fair value of the awards at the grant date. Awards with a performance-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded. Performance-based RSU equity awards that vest are based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between
0%
and
200%
of the base units awarded.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Cash-settled RSU
awards.
Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards under the 2011 Plan are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense.
A significant portion of the Company’s cash-settled RSU awards include a performance-based vesting condition that determines the actual number of units that will ultimately vest. The number of RSUs that vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between
0%
and
200%
of the base units awarded. The fair value of the Company’s performance-based RSU awards is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group.
The following table presents share-based compensation expense for each respective period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
Share-based compensation cost for:
|
Equity-based
|
|
Liability-based
|
|
Equity-based
|
|
Liability-based
|
|
Equity-based
|
|
Liability-based
|
RSU equity awards
(a)
|
$
|
9,460
|
|
|
$
|
—
|
|
|
$
|
10,225
|
|
|
$
|
—
|
|
|
$
|
4,536
|
|
|
$
|
—
|
|
Cash-settleable RSU awards
(a)
|
—
|
|
|
336
|
|
|
—
|
|
|
4,294
|
|
|
—
|
|
|
12,285
|
|
Total share-based compensation cost
(b)
|
$
|
9,460
|
|
|
$
|
336
|
|
|
$
|
10,225
|
|
|
$
|
4,294
|
|
|
$
|
4,536
|
|
|
$
|
12,285
|
|
|
|
(a)
|
Includes the settlement of the outstanding share-based award agreements of the Company’s former Chief Executive Officer, resulting in
$6,351
recorded on the Consolidated Statements of Operations as settled share-based awards for the year ended December 31, 2017.
|
|
|
(b)
|
The portion of this share-based compensation cost that was included in general and administrative expense totaled
$6,362
,
$4,966
and
$9,547
for the years ended
December 31, 2018
,
2017
and
2016
, respectively, and the portion capitalized to oil and gas properties was
$3,434
,
$3,202
and
$7,274
, for the years ended
December 31, 2018
,
2017
, and
2016
, respectively.
|
The following table presents the unrecognized compensation cost for the indicated periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
Unrecognized compensation cost related to:
|
|
2018
|
|
2017
|
|
2016
|
Unvested RSU equity awards
|
|
$
|
15,720
|
|
|
$
|
13,158
|
|
|
$
|
7,276
|
|
Unvested cash-settleable RSU awards
|
|
1,822
|
|
|
3,776
|
|
|
8,948
|
|
The Company’s unrecognized compensation cost related to unvested RSU equity awards and cash-settleable RSU awards is expected to be recognized over a weighted-average period of
two
years.
The following table summarizes the Company’s liability for cash-settled RSU awards for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
Consolidated Balance Sheets Classification
|
|
2018
|
|
2017
|
Cash-settleable RSU awards (current)
|
|
$
|
1,390
|
|
|
$
|
4,621
|
|
Cash-settleable RSU awards (non-current)
|
|
2,067
|
|
|
3,490
|
|
Total cash-settleable RSU awards
|
|
$
|
3,457
|
|
|
$
|
8,111
|
|
Stock Options
The Company issued no stock options for the past
three
years and all existing options expired by year end December 31, 2017. As of
December 31, 2016
, the Company had
15,000
options outstanding and exercisable at a weighted average exercise price per option of
$14.37
, with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of
0.3 years
.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Restricted Stock Units
The following table represents unvested stock-settleable restricted stock activity for the year ended
December 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average
|
(shares in 000s)
|
|
Number of Shares
|
|
Grant-Date Fair Value per Share
|
|
Years Over Which Expense is Expected to be Recognized
|
Outstanding at the beginning of the period
|
|
1,790
|
|
|
$
|
11.54
|
|
|
|
Granted
(a)
|
|
872
|
|
|
13.89
|
|
|
|
Vested
(b)
|
|
(506
|
)
|
|
9.56
|
|
|
|
Forfeited
|
|
(53
|
)
|
|
11.43
|
|
|
|
Outstanding at the end of the period
|
|
2,103
|
|
|
$
|
13.24
|
|
|
1.85
|
|
|
(a)
|
Includes
208
performance-based RSUs that will vest at a range of
0%
-
200%
.
|
|
|
(b)
|
The fair value of shares vested was
$6,344
.
|
For the year ended
December 31, 2017
, the Company granted
1,173,094
RSUs with a weighted average grant-date fair value of
$12.25
per share. The fair value of shares vested during
2017
was
$9,045
. For the year ended
December 31, 2016
, the Company granted
684,090
RSUs with a weighted average grant-date fair value of
$12.63
per share. The fair value of shares vested during
2016
was
$2,608
.
As of
December 31, 2018
, the Company had the following cash-settleable RSUs outstanding (including those that are not based on a market condition):
|
|
|
|
|
|
|
|
|
|
|
(shares in 000s)
|
|
Base Units Outstanding
|
|
Potential Minimum Units Vesting
|
|
Potential Maximum Units Vesting
|
Vesting in 2019
|
|
190
|
|
|
17
|
|
|
364
|
|
Vesting in 2020
|
|
323
|
|
|
—
|
|
|
645
|
|
Vesting in 2021
|
|
—
|
|
|
—
|
|
|
—
|
|
Other
|
|
146
|
|
|
146
|
|
|
146
|
|
Total cash-settleable RSUs
|
|
659
|
|
|
163
|
|
|
1,155
|
|
For the year ended
December 31, 2018
,
207,261
performance-based cash-settled RSUs, subject to the peer performance-based vesting described above, vested at between
100%
to
163%
of their issued units, depending on the date of the vesting, resulting in cash payments of
$89
in
2018
and payable amounts of
$1,296
in
2019
. Also during
2018
,
129,753
non-performance-based cash settled RSUs vested, resulting in cash payments of
$1,834
in
2018
. During
2017
,
335,471
performance-based cash-settled RSUs subject to the peer performance-based vesting described above vested at between
142%
to
200%
of their underlying issued units, depending on the date of the vesting, resulting in cash payments of
$3,986
in
2017
and
$3,062
in
2018
. Also during
2017
,
43,031
non-performance-based cash settled RSUs vested, resulting in cash payments of
$526
in
2017
.
Note 11
– Equity Transactions
10% Series A Cumulative Preferred Stock (“Preferred Stock”)
Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by the Company’s Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of
10%
per annum of the
$50.00
liquidation preference per share (equivalent to
$5.00
per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Company’s Board of Directors. Preferred Stock dividends were
$7,295
for each year in
2018
,
2017
and
2016
.
The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. The Company may, at its option, redeem the Preferred Stock, in whole or in part, at any time on or after May 30, 2018, by paying
$50.00
per share, plus any accrued and unpaid dividends to the redemption date.
Following a change of control in which the Company or the acquirer no longer have a class of common securities listed on a national exchange, the Company will have the option to redeem the Preferred Stock, in whole but not in part for
$50.00
per share in cash plus accrued and unpaid dividends (whether or not declared) to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon such change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
determined under the certificate of designations for the Preferred Stock. If the change of control occurred on
December 31, 2018
, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of
$6.49
as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately
7.7
shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above.
On February 4, 2016, the Company exchanged a total of
120 thousand
shares of Preferred Stock for
719 thousand
shares of common stock. As of
December 31, 2018
, the Company had
1,458,948
shares of its Preferred Stock issued and outstanding.
Common Stock
On May 30, 2018, the Company completed an underwritten public offering of
25.3 million
shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and offering costs) of approximately
$287,988
. The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter, described in Note 4.
On December 19, 2016, the Company completed an underwritten public offering of
40 million
shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately
$634,934
. Proceeds from the offering were used to substantially fund the Ameredev Transaction, described in
Note 4
.
On September 6, 2016, the Company completed an underwritten public offering of
29.9 million
shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately
$421,864
. Proceeds from the offering were used to substantially fund the Plymouth Transaction, described in
Note 4
.
On May 26, 2016, the Company issued
9.3 million
shares of common stock to partially fund the Big Star Transaction, described in
Note 4
, at an assumed offering price of
$11.74
per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date.
On April 25, 2016, the Company completed an underwritten public offering of
25.3 million
shares of its common stock for total net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately
$205,869
. Proceeds from the offering were used to fund the Big Star Transaction, described in
Note 4
, and other working interest acquisitions.
On March 9, 2016, the Company completed an underwritten public offering of
15.3 million
shares of its common stock for total net proceeds (after the underwriting discounts and estimated offering costs) of approximately
$94,948
. Proceeds from the offering were used to pay down the balance on the Company’s Credit Facility and for general corporate purposes.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Note 12
-
Income Taxes
The following table presents Callon’s deferred tax assets and liabilities with respect to its carryforwards and other temporary differences:
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2018
|
|
2017
|
Deferred tax asset
(a)
|
|
|
|
|
Federal net operating loss carryforward
|
|
$
|
151,497
|
|
|
$
|
97,437
|
|
Interest expense carryforward
(b)
|
|
7,335
|
|
|
—
|
|
Statutory depletion carryforward
|
|
5,381
|
|
|
5,381
|
|
Alternative minimum tax credit carryforward
(b)
|
|
—
|
|
|
52
|
|
Asset retirement obligations
|
|
2,347
|
|
|
572
|
|
Derivatives asset
|
|
—
|
|
|
6,186
|
|
Unvested RSU equity awards
|
|
2,751
|
|
|
1,749
|
|
Other
|
|
991
|
|
|
2,401
|
|
Deferred tax asset before valuation allowance
|
|
170,302
|
|
|
113,778
|
|
Deferred tax liability
(a)
|
|
|
|
|
Oil and natural gas properties
|
|
169,682
|
|
|
54,264
|
|
Derivatives liability
|
|
10,184
|
|
|
—
|
|
Total deferred tax liability
|
|
179,866
|
|
|
54,264
|
|
Net deferred tax asset (liability) before valuation allowance
|
|
(9,564
|
)
|
|
59,514
|
|
Less: Valuation allowance
|
|
—
|
|
|
(60,919
|
)
|
Net deferred tax liability
|
|
$
|
(9,564
|
)
|
|
$
|
(1,405
|
)
|
|
|
(a)
|
Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The 2017 Tax Act lowered the U.S. federal corporate tax rate from 35% to 21%, which caused the Company to remeasure its deferred income tax assets and liabilities at the new rate. As of
December 31, 2018
and
2017
, the Company’s tax rate applied was 21%. As a result of the change in the applied tax rate on our deferred tax assets and liabilities, in 2017 the Company recorded a
$40,611
reduction in our net deferred tax assets with a corresponding reduction in our valuation allowance.
|
|
|
(b)
|
The 2017 Tax Act revised the rules regarding the deductibility of net interest expense incurred in tax years beginning after 2017, with non-deductible amounts being carried forward to future taxable years.
|
|
|
(c)
|
The 2017 Tax Act repealed the Alternative Minimum Tax (“AMT”) effective for years beginning after December 31, 2017. The result had an immaterial impact in income.
|
U.S. federal net operating loss (“NOL”) utilization was changed by the 2017 Tax Act for losses incurred in tax years beginning after December 31, 2017. Post-2017 NOLs do not have an expiration period, but may only offset
80%
of the Company’s taxable income in any year of utilization. As of
December 31, 2018
, Post-2017 NOLs amounted to
$58,298
. If not utilized, the Company’s existing federal NOL carryforwards, unaffected by the 2017 Tax Act, will expire as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Expiring
|
|
|
Total
|
|
2019-2024
|
|
2025-2027
|
|
2028-2030
|
|
2031-2033
|
|
2034-2038
|
Federal NOL carryforwards
|
|
$
|
662,712
|
|
|
$
|
115,387
|
|
|
$
|
39,714
|
|
|
$
|
32,111
|
|
|
$
|
22,164
|
|
|
$
|
453,336
|
|
As a result of a historical write-down of oil and natural gas properties in 2016, discussed in
Notes 2
and
Supplemental Information on Oil and Natural Gas Operations
, the Company had incurred a cumulative
three
year loss. Because of the impact the cumulative loss had on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for the net deferred tax asset. As of December 31, 2017, the valuation allowance was
$60,919
. During 2018, the Company’s tax position transitioned from a net deferred tax asset position to a net deferred tax liability position, thereby unwinding the valuation allowance balance to
$0
as of
December 31, 2018
.
The Company had no significant unrecognized tax benefits at
December 31, 2018
. Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense.
The Company provides for income taxes at a statutory rate of
21%
adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, and state income taxes. The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations:
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Components of income tax rate reconciliation
|
|
2018
|
|
2017
|
|
2016
|
Income tax expense computed at the statutory federal income tax rate
|
|
21
|
%
|
|
35
|
%
|
|
35
|
%
|
State taxes net of federal expense
|
|
1
|
%
|
|
1
|
%
|
|
—
|
%
|
Section 162(m)
|
|
1
|
%
|
|
—
|
%
|
|
(1
|
)%
|
Valuation allowance
|
|
(20
|
)%
|
|
(35
|
)%
|
|
(34
|
)%
|
Effective income tax rate
|
|
3
|
%
|
|
1
|
%
|
|
—
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Components of income tax expense
|
|
2018
|
|
2017
|
|
2016
|
Current federal income tax benefit
|
|
$
|
—
|
|
|
$
|
(48
|
)
|
|
$
|
(104
|
)
|
Deferred federal income tax (benefit) expense
|
|
3,594
|
|
|
(45
|
)
|
|
—
|
|
Deferred state income tax expense
|
|
4,516
|
|
|
1,366
|
|
|
90
|
|
Total income tax (benefit) expense
|
|
$
|
8,110
|
|
|
$
|
1,273
|
|
|
$
|
(14
|
)
|
.
Note 13
- Asset Retirement Obligations
The table below summarizes the activity for the Company’s asset retirement obligations:
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
Asset retirement obligations at January 1, 2018 and 2017, respectively
|
|
$
|
6,020
|
|
|
$
|
6,661
|
|
Accretion expense
|
|
874
|
|
|
677
|
|
Liabilities incurred
|
|
1,543
|
|
|
278
|
|
Liabilities settled
|
|
(1,288
|
)
|
|
(711
|
)
|
Dispositions
|
|
(614
|
)
|
|
—
|
|
Revisions to estimate
|
|
7,757
|
|
|
(885
|
)
|
Asset retirement obligations at end of period
|
|
14,292
|
|
|
6,020
|
|
Less: Current asset retirement obligations
|
|
(3,887
|
)
|
|
(1,295
|
)
|
Long-term asset retirement obligations at December 31, 2018 and 2017, respectively
|
|
$
|
10,405
|
|
|
$
|
4,725
|
|
2018
|
|
•
|
Liabilities incurred
include additions from acquisitions, primarily the Delaware Asset Acquisition completed in the third quarter of 2018, as well as additions from new wells drilled during the year.
|
|
|
•
|
Liabilities settled
include the retirement of
26
wells in
2018
.
|
|
|
•
|
Dispositions
are primarily attributable to the sale of oil and gas properties in the second quarter of
2018
.
|
|
|
•
|
Revisions to estimates
were due to changes in plugging cost estimates, timing of abandonment activities, and changes in working interest of producing wells.
|
2017
|
|
•
|
Liabilities incurred
were primarily a result of additions from new wells drilled during the year.
|
|
|
•
|
Liabilities settled
include the retirement of
18
wells in
2017
.
|
|
|
•
|
Revisions to estimates
were due to changes in timing of abandonment activities.
|
Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets at
December 31, 2018
and
2017
as long-term restricted investments were
$3,424
and
$3,372
, respectively. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Note 14
–
Other
Commitments and contingencies
The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company.
The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities.
Operating leases
As of
December 31, 2018
, the Company had contracts for
five
horizontal drilling rigs. The contract terms, as amended effective as of July 9, 2018, will end on various dates between July 2019 and February 2021. All of the drilling rig contracts provide for early termination, with penalties calculated at a reduced daily rate.
Other commitments
In March 2018, the Company entered into a contract for dedicated fracturing and pump down perforating crews, which was effective on April 16, 2018 for a
two
-year period. The agreement was amended effective October 16, 2018 to reflect updated market conditions and to extend the contract expiration date to December 31, 2021.
In August 2018, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard, Ward, Reagan and Upton counties to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a long-term commitment that will apply applicable tariff rates to our
15,000
Bbls per day commitment for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.
Subsequent Event
In January 2019, Callon Petroleum Operating Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard, Ward, and Reagan counties and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. We will have a long-term
10,000
Bbls per day commitment for the term of the agreement, and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Supplemental Information on Oil and Natural Gas Operations (Unaudited)
Estimated Reserves
The Company’s proved oil and natural gas reserves at
December 31, 2018
,
2017
and
2016
have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum and geological firm (the “Reserve Engineering Firm”). The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions.
There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.
Extrapolation of performance history and material balance estimates were utilized by the Company’s Reserve Engineering Firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories.
The following tables disclose changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Proved developed and undeveloped reserves:
|
|
2018
|
|
2017
|
|
2016
|
Oil (MBbls):
|
|
|
|
|
|
|
Beginning of period
|
|
107,072
|
|
|
71,145
|
|
|
43,348
|
|
Purchase of reserves in place
|
|
30,756
|
|
|
8,388
|
|
|
25,054
|
|
Sale of reserves in place
|
|
—
|
|
|
—
|
|
|
(1,718
|
)
|
Extensions and discoveries
|
|
67,763
|
|
|
39,267
|
|
|
14,479
|
|
Revisions to previous estimates
|
|
(8,982
|
)
|
|
(1,548
|
)
|
|
(4,544
|
)
|
Reclassifications due to changes in development plan
|
|
(7,069
|
)
|
|
(3,623
|
)
|
|
(1,194
|
)
|
Production
|
|
(9,443
|
)
|
|
(6,557
|
)
|
|
(4,280
|
)
|
End of period
|
|
180,097
|
|
|
107,072
|
|
|
71,145
|
|
Natural Gas (MMcf):
|
|
|
|
|
|
|
Beginning of period
|
|
179,410
|
|
|
122,611
|
|
|
65,537
|
|
Purchase of reserves in place
|
|
53,563
|
|
|
12,711
|
|
|
36,474
|
|
Sale of reserves in place
|
|
—
|
|
|
—
|
|
|
(2,765
|
)
|
Extensions and discoveries
|
|
103,149
|
|
|
48,648
|
|
|
17,194
|
|
Revisions to previous estimates
|
|
41,767
|
|
|
18,121
|
|
|
16,842
|
|
Reclassifications due to changes in development plan
|
|
(11,976
|
)
|
|
(11,785
|
)
|
|
(2,913
|
)
|
Production
|
|
(15,447
|
)
|
|
(10,896
|
)
|
|
(7,758
|
)
|
End of period
|
|
350,466
|
|
|
179,410
|
|
|
122,611
|
|
Total (MBOE):
|
|
|
|
|
|
|
Beginning of period
|
|
136,974
|
|
|
91,580
|
|
|
54,271
|
|
Purchase of reserves in place
|
|
39,683
|
|
|
10,507
|
|
|
31,133
|
|
Sale of reserves in place
|
|
—
|
|
|
—
|
|
|
(2,179
|
)
|
Extensions and discoveries
|
|
84,955
|
|
|
47,375
|
|
|
17,345
|
|
Revisions to previous estimates
|
|
(2,021
|
)
|
|
1,472
|
|
|
(1,737
|
)
|
Reclassifications due to changes in development plan
|
|
(9,065
|
)
|
|
(5,587
|
)
|
|
(1,680
|
)
|
Production
|
|
(12,018
|
)
|
|
(8,373
|
)
|
|
(5,573
|
)
|
End of period
|
|
238,508
|
|
|
136,974
|
|
|
91,580
|
|
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
Proved developed reserves:
|
|
2018
|
|
2017
|
|
2016
|
Oil (MBbls):
|
|
|
|
|
|
|
Beginning of period
|
|
51,920
|
|
|
32,920
|
|
|
22,257
|
|
End of period
|
|
92,202
|
|
|
51,920
|
|
|
32,920
|
|
Natural gas (MMcf):
|
|
|
|
|
|
|
Beginning of period
|
|
104,389
|
|
|
61,871
|
|
|
38,157
|
|
End of period
|
|
218,417
|
|
|
104,389
|
|
|
61,871
|
|
MBOE:
|
|
|
|
|
|
|
Beginning of period
|
|
69,318
|
|
|
43,232
|
|
|
28,617
|
|
End of period
|
|
128,605
|
|
|
69,318
|
|
|
43,232
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
Oil (MBbls):
|
|
|
|
|
|
|
Beginning of period
|
|
55,152
|
|
|
38,225
|
|
|
21,091
|
|
End of period
|
|
87,895
|
|
|
55,152
|
|
|
38,225
|
|
Natural gas (MMcf):
|
|
|
|
|
|
|
Beginning of period
|
|
75,021
|
|
|
60,740
|
|
|
27,380
|
|
End of period
|
|
132,049
|
|
|
75,021
|
|
|
60,740
|
|
MBOE:
|
|
|
|
|
|
|
Beginning of period
|
|
67,656
|
|
|
48,348
|
|
|
25,654
|
|
End of period
|
|
109,903
|
|
|
67,656
|
|
|
48,348
|
|
Total proved reserves:
|
|
|
|
|
|
|
Oil (MBbls):
|
|
|
|
|
|
|
Beginning of period
|
|
107,072
|
|
|
71,145
|
|
|
43,348
|
|
End of period
|
|
180,097
|
|
|
107,072
|
|
|
71,145
|
|
Natural gas (MMcf):
|
|
|
|
|
|
|
Beginning of period
|
|
179,410
|
|
|
122,611
|
|
|
65,537
|
|
End of period
|
|
350,466
|
|
|
179,410
|
|
|
122,611
|
|
MBOE:
|
|
|
|
|
|
|
Beginning of period
|
|
136,974
|
|
|
91,580
|
|
|
54,271
|
|
End of period
|
|
238,508
|
|
|
136,974
|
|
|
91,580
|
|
Total Proved Reserves
The Company ended
2018
with estimated net proved reserves of
238,508
MBOE, representing a
74%
increase
over
2017
year-end estimated net proved reserves of
136,974
MBOE. The Company added
124,638
MBOE primarily from the Delaware Asset Acquisition completed third quarter of 2018 and development efforts in the Permian Basin, where it drilled a total of
70
gross (
57.5
net) wells. This
increase
was offset by
2018
production, negative revisions of previous estimates of
2,021
MBOE primarily related to technical revisions of proved undeveloped reserves, and reclassifications of proved undeveloped reserves of
9,065
MBOE from
19
PUD locations primarily due to acreage trades and changes in our development plan, including larger pad development concepts and co-development of zones. These changes resulted in the anticipated drilling of PUD locations being moved beyond five years from initial booking.
The Company ended 2017 with estimated net proved reserves of
136,974
MBOE, representing a
50%
increase over 2016 year-end estimated net proved reserves of
91,580
MBOE. The Company added
57,881
MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of
49
gross (
38.2
net) wells. This increase was primarily offset by 2017 production, revisions of previous estimates, and reclassifications of PUD locations from our development and drilling plan. The Company reclassified
13
PUD locations as a result of a change in the Company’s development and drilling plans within its operating areas and the removal of certain proved developed vertical well locations.
The Company ended 2016 with estimated net proved reserves of
91,580
MBOE, representing a
69%
increase over 2015 year-end estimated net proved reserves of
54,271
MBOE. The Company added
48,477
MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of
29
gross (
20.9
net) wells. This increase was primarily offset by
11,168
MBOE related to divestitures, 2016 production, revisions primarily due to pricing, and reclassifications of
4
PUD locations as a result of a change in the Company’s development and dilling plans within its operating areas.
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Capitalized Costs
Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2018
|
|
2017
|
Oil and natural gas properties:
|
|
|
|
|
Evaluated properties
|
|
$
|
4,585,020
|
|
|
$
|
3,429,570
|
|
Unevaluated properties
|
|
1,404,513
|
|
|
1,168,016
|
|
Total oil and natural gas properties
|
|
5,989,533
|
|
|
4,597,586
|
|
Accumulated depreciation, depletion, amortization and impairment
|
|
(2,270,675
|
)
|
|
(2,084,095
|
)
|
Total oil and natural gas properties capitalized
|
|
$
|
3,718,858
|
|
|
$
|
2,513,491
|
|
Costs Incurred
Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Acquisition costs:
|
|
|
|
|
|
|
Evaluated properties
|
|
$
|
347,305
|
|
|
$
|
156,340
|
|
|
$
|
228,832
|
|
Unevaluated properties
|
|
466,816
|
|
|
499,295
|
|
|
536,540
|
|
Development costs
|
|
259,410
|
|
|
148,254
|
|
|
111,065
|
|
Exploration costs
|
|
323,458
|
|
|
239,453
|
|
|
38,612
|
|
Total costs incurred
|
|
$
|
1,396,989
|
|
|
$
|
1,043,342
|
|
|
$
|
915,049
|
|
Standardized Measure
The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at
December 31, 2018
. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on the preceding
12
-months’ average price based on closing prices on the first day of each month. The following table summarizes the average
12
-month oil and natural gas prices net of differentials for the respective periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
2017
|
|
2016
|
Average 12-month price, net of differentials, per barrel of oil
(a)
|
|
$
|
58.40
|
|
|
$
|
49.48
|
|
|
$
|
40.03
|
|
Average 12-month price, net of differentials, per Mcf of natural gas
(b)
|
|
$
|
3.64
|
|
|
$
|
3.47
|
|
|
$
|
2.71
|
|
|
|
(a)
|
Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.
|
|
|
(b)
|
Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties.
|
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a
10%
annual discount rate.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Future cash inflows
|
|
$
|
11,794,080
|
|
|
$
|
5,920,328
|
|
|
$
|
3,180,005
|
|
Future costs
|
|
|
|
|
|
|
Production
|
|
(2,923,959
|
)
|
|
(1,692,871
|
)
|
|
(974,667
|
)
|
Development and net abandonment
|
|
(1,429,787
|
)
|
|
(680,948
|
)
|
|
(384,117
|
)
|
Future net inflows before income taxes
|
|
7,440,334
|
|
|
3,546,509
|
|
|
1,821,221
|
|
Future income taxes
(a)
|
|
(782,470
|
)
|
|
(166,985
|
)
|
|
(1,602
|
)
|
Future net cash flows
|
|
6,657,864
|
|
|
3,379,524
|
|
|
1,819,619
|
|
10% discount factor
|
|
(3,716,571
|
)
|
|
(1,822,842
|
)
|
|
(1,009,787
|
)
|
Standardized measure of discounted future net cash flows
|
|
$
|
2,941,293
|
|
|
$
|
1,556,682
|
|
|
$
|
809,832
|
|
|
|
(a)
|
As of
December 31, 2018
,
2017
, and 2016 the Company’s statutory tax rate applied was 21%, 21%, and 35%, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in Standardized Measure
|
|
|
For the Year Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
Standardized measure at the beginning of the period
|
|
$
|
1,556,682
|
|
|
$
|
809,832
|
|
|
$
|
570,890
|
|
Sales and transfers, net of production costs
|
|
(481,306
|
)
|
|
(294,172
|
)
|
|
(150,628
|
)
|
Net change in sales and transfer prices, net of production costs
|
|
222,802
|
|
|
176,234
|
|
|
(103,136
|
)
|
Net change due to purchases and sales of in place reserves
|
|
554,697
|
|
|
129,454
|
|
|
260,859
|
|
Extensions, discoveries, and improved recovery, net of future production and development costs incurred
|
|
1,093,773
|
|
|
635,000
|
|
|
180,228
|
|
Changes in future development cost
|
|
40,483
|
|
|
36,983
|
|
|
82,320
|
|
Revisions of quantity estimates
|
|
(167,096
|
)
|
|
(79,325
|
)
|
|
(35,938
|
)
|
Accretion of discount
|
|
157,676
|
|
|
80,983
|
|
|
57,091
|
|
Net change in income taxes
|
|
(187,841
|
)
|
|
(20,073
|
)
|
|
16
|
|
Changes in production rates, timing and other
|
|
151,423
|
|
|
81,766
|
|
|
(51,870
|
)
|
Aggregate change
|
|
1,384,611
|
|
|
746,850
|
|
|
238,942
|
|
Standardized measure at the end of period
|
|
$
|
2,941,293
|
|
|
$
|
1,556,682
|
|
|
$
|
809,832
|
|
|
|
|
|
|
Notes to the Consolidated Financial Statements
(All dollar amounts in thousands, except per share and per unit data)
|
|
Supplemental Quarterly Financial Information (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
Total revenues
|
|
$
|
127,440
|
|
|
$
|
137,075
|
|
|
$
|
161,214
|
|
|
$
|
161,895
|
|
Income from operations
|
|
60,986
|
|
|
67,400
|
|
|
72,811
|
|
|
58,333
|
|
Net income
|
|
55,761
|
|
|
50,474
|
|
|
37,931
|
|
|
156,194
|
|
Income available to common shares
|
|
53,937
|
|
|
48,650
|
|
|
36,108
|
|
|
154,370
|
|
Income per common share - basic
|
|
$
|
0.27
|
|
|
$
|
0.23
|
|
|
$
|
0.16
|
|
|
$
|
0.68
|
|
Income per common share - diluted
|
|
$
|
0.27
|
|
|
$
|
0.23
|
|
|
$
|
0.16
|
|
|
$
|
0.68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
Total revenues
|
|
$
|
81,363
|
|
|
$
|
82,283
|
|
|
$
|
84,614
|
|
|
$
|
118,214
|
|
Income from operations
|
|
32,249
|
|
|
23,743
|
|
|
31,426
|
|
|
54,028
|
|
Net income
|
|
47,129
|
|
|
33,390
|
|
|
17,081
|
|
|
22,824
|
|
Income available to common shares
|
|
45,305
|
|
|
31,566
|
|
|
15,257
|
|
|
21,001
|
|
Income per common share - basic
|
|
$
|
0.23
|
|
|
$
|
0.16
|
|
|
$
|
0.08
|
|
|
$
|
0.10
|
|
Income per common share - diluted
|
|
$
|
0.22
|
|
|
$
|
0.16
|
|
|
$
|
0.08
|
|
|
$
|
0.10
|
|
ITEM 9. Changes In and Disagreements
with Accountants on Accounting and Financial Disclosure
None.
ITEM 9A. Controls and Procedures
Disclosure controls and procedures.
Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of
December 31, 2018
.
Management’s report on internal control over financial reporting.
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of
December 31, 2018
based on the framework in
Internal Control – Integrated Framework
published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of
December 31, 2018
.
Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s independent registered public accounting firm, Grant Thornton, LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of
December 31, 2018
, presented preceding the Company’s financial statements included in Part II, Item 8 of this
2018
Annual Report on Form 10-K. Additionally, the financial statements for the years ended December 31, 2017 and 2016, covered in this
2018
Annual Report on Form 10-K, have also been audited by the Company’s independent registered public accounting firm, whose report is presented preceding the their report on the Company’s internal control over financial reporting, included in Part II, Item 8.
Changes in internal control over financial reporting
. There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.
ITEM 9B.
Other Information
On February 22, 2019, the Board adopted the Amended and Restated Bylaws (as amended and restated, the “Bylaws”) in connection with its regular review of the Company’s corporate governance structure. The indemnification provisions, which limit the liability of our directors, officers, and employees have been amended to, among other things, clarify and update the directors, officers, and employees’ entitlement to indemnification and entitlement to advancement of expenses, and clarify that directors, officers, and employees who bring claims against the Company are not entitled to indemnification or expense advancement unless such claim was authorized in advance by the Board.
In addition, the Bylaws were also amended to, among other things:
|
|
•
|
Modify the advance notification procedures for a shareholder to make director nominations and other proposals of business at annual meetings of the shareholders in order to, among other things, specify the disclosures that shareholders must provide when submitting proposals and director nominations for consideration.
|
|
|
•
|
Provide that the chairman of a shareholder meeting may adjourn any meeting of shareholders for any reason, whether or not there is a quorum present.
|
|
|
•
|
Designate the Court of Chancery of the State of Delaware as the exclusive forum for certain legal actions and proceedings involving the Company.
|
|
|
•
|
Amend provisions relating to meetings of the shareholders and special meetings of the shareholders, including updating the scheduling and location of the meetings, adding disclosure of record holders entitled to vote at the meeting, covering the
|
procedures for postponing, rescheduling or cancelling a previously called special meeting and governing the Chairman of the Board’s ability to adjourn meetings without notice.
|
|
•
|
Make other administrative, procedural, clarifying and conforming changes.
|
The foregoing description is qualified in its entirety by reference to the Bylaws, a copy of which are filed as Exhibit 3.3 to this
2018
Annual Report on Form 10-K and incorporated herein by reference.
PART III.
ITEM 10. Directors, Executive Officers and Corporate Governance
For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on
May 9, 2019
, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
The Company has adopted a code of ethics that applies to the Company’s officers, directors, employees, agents and representatives and includes a code of ethics for senior financial officers that applies to the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com, and is available free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at mailing address
1401 Enclave Parkway, Suite 600, Houston, TX 77077.
ITEM 11. Executive Compensation
For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on
May 9, 2019
, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on
May 9, 2019
, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
ITEM 13. Certain Relationships and Related Transactions and Director Independence
For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on
May 9, 2019
, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
ITEM 14. Principal Accountant Fees and Services
For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on
May 9, 2019
, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
PART IV.
ITEM
15. Exhibits
The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10-K.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incorporated by reference (File No. 001-14039, unless otherwise indicated)
|
Exhibit Number
|
|
Description
|
|
Form
|
|
Exhibit
|
|
Filing Date
|
2.1
|
|
|
|
|
8-K
|
|
2.1
|
|
05/24/2018
|
3.1
|
|
|
|
|
10-Q
|
|
3.1
|
|
11/03/2016
|
3.2
|
(a)
|
|
|
|
|
|
|
|
|
4.1
|
|
|
|
|
10-K
|
|
4.1
|
|
02/28/2018
|
4.2
|
|
|
|
|
8-A
|
|
4.1
|
|
05/23/2013
|
4.3
|
|
|
|
|
8-K
|
|
10.1
|
|
05/31/2016
|
4.4
|
|
|
|
|
8-A
|
|
3.5
|
|
05/23/2013
|
4.5
|
|
|
|
|
8-K
|
|
4.1
|
|
10/04/2016
|
4.6
|
|
|
|
|
8-K
|
|
4.2
|
|
10/04/2016
|
4.7
|
|
|
|
|
8-K
|
|
4.1
|
|
05/24/2017
|
4.8
|
|
|
|
|
8-K
|
|
4.1
|
|
06/07/2018
|
4.9
|
|
|
|
|
8-K
|
|
4.2
|
|
06/07/2018
|
10.1
|
(b)
|
|
|
|
DEF 14A
|
|
A
|
|
03/21/2011
|
10.2
|
(b)
|
|
|
|
10-K
|
|
10.16
|
|
03/03/2016
|
10.3
|
(b)
|
|
|
|
10-K
|
|
10.17
|
|
03/03/2016
|
10.4
|
(b)
|
|
|
|
10-K
|
|
10.18
|
|
03/03/2016
|
10.5
|
(b)
|
|
|
|
10-Q
|
|
10.1
|
|
11/05/2015
|
10.6
|
|
|
|
|
10-Q
|
|
10.1
|
|
08/02/2017
|
10.7
|
|
|
|
|
8-K
|
|
10.1
|
|
04/06/2018
|
10.8
|
|
|
|
|
8-K
|
|
10.1
|
|
09/28/2018
|
10.9
|
|
|
|
|
8-K
|
|
10.1
|
|
05/24/2017
|
10.10
|
|
|
|
|
10-K
|
|
10.11
|
|
02/28/2018
|
10.11
|
|
|
|
|
8-K
|
|
10.1
|
|
06/01/2018
|
10.12
|
(b)
|
|
|
|
DEF 14A
|
|
A
|
|
03/23/2018
|
10.13
|
(b)
|
|
|
|
10-Q
|
|
10.4
|
|
08/07/2018
|
10.14
|
(b)
|
|
|
|
10-Q
|
|
10.5
|
|
08/07/2018
|
10.15
|
(b)
|
|
|
|
10-Q
|
|
10.6
|
|
08/07/2018
|
|
|
|
|
|
|
|
|
|
|
|
10.16
|
(b)
|
|
|
|
10-Q
|
|
10.7
|
|
08/07/2018
|
10.17
|
(a)(b)
|
|
|
|
|
|
|
|
|
10.18
|
(a)(b)
|
|
|
|
|
|
|
|
|
10.19
|
(a)
|
|
|
|
|
|
|
|
|
10.20
|
(a)(b)
|
|
|
|
|
|
|
|
|
10.21
|
(a)(b)
|
|
|
|
|
|
|
|
|
10.22
|
(a)(b)
|
|
|
|
|
|
|
|
|
10.23
|
(a)b)
|
|
|
|
|
|
|
|
|
21.1
|
(a)
|
|
|
|
|
|
|
|
|
23.1
|
(a)
|
|
|
|
|
|
|
|
|
23.2
|
(a)
|
|
|
|
|
|
|
|
|
31.1
|
(a)
|
|
|
|
|
|
|
|
|
31.2
|
(a)
|
|
|
|
|
|
|
|
|
32.1
|
(c)
|
|
|
|
|
|
|
|
|
99.1
|
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Filed herewith.
|
(b)
|
|
Indicates management compensatory plan, contract, or arrangement.
|
(c)
|
|
Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference.
|
ITEM 16. Form 10-K Summary
Not applicable.
SIGNATURES
|
|
|
|
|
|
|
|
|
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
Callon Petroleum Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ James P. Ulm, II
|
|
Date:
|
|
February 26, 2019
|
|
|
|
By: James P. Ulm, II
|
|
|
|
|
|
|
|
Chief Financial Officer (principal financial officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Joseph C. Gatto, Jr.
|
|
Date:
|
|
February 26, 2019
|
|
|
|
Joseph C. Gatto, Jr. (principal executive officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ James P. Ulm, II
|
|
Date:
|
|
February 26, 2019
|
|
|
|
James P. Ulm, II (principal financial officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Mitzi P. Conn
|
|
Date:
|
|
February 26, 2019
|
|
|
|
Mitzi P. Conn (principal accounting officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ L. Richard Flury
|
|
Date:
|
|
February 26, 2019
|
|
|
|
L. Richard Flury (chairman of the board of directors)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Barbara J. Faulkenberry
|
|
Date:
|
|
February 26, 2019
|
|
|
|
Barbara J. Faulkenberry (director)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Anthony J. Nocchiero
|
|
Date:
|
|
February 26, 2019
|
|
|
|
Anthony J. Nocchiero (director)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Larry D. McVay
|
|
Date:
|
|
February 26, 2019
|
|
|
|
Larry McVay (director)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Matthew R. Bob
|
|
Date:
|
|
February 26, 2019
|
|
|
|
Matthew R. Bob (director)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ James M. Trimble
|
|
Date:
|
|
February 26, 2019
|
|
|
|
James M. Trimble (director)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Michael L. Finch
|
|
Date:
|
|
February 26, 2019
|
|
|
|
Michael L. Finch (director)
|
|
|
|
|
|
Exhibit 3.2
AMENDED AND RESTATED BYLAWS OF
CALLON PETROLEUM COMPANY
(the “
Corporation
”)
(Amended and Restated Effective as of February 22, 2019)
ARTICLE I
Offices
Section 1.1
The registered office of the Corporation in the State of Delaware shall be in the City of Wilmington, County of New Castle, State of Delaware or such other place within the State of Delaware as the Board of Directors may from time to time determine.
Section 1.2
The Corporation may also have offices at such other places both within and without the State of Delaware as the Board of Directors may from time to time determine or the business of the Corporation may require.
ARTICLE II
Meetings of Stockholders
Section 2.1
All meetings of the stockholders shall be held in the City of Houston, State of Texas, at such place as may be fixed from time to time by the Board of Directors, at such other place either within or without the State of Delaware or Texas or at no place, solely by means of remote communication, in each case, as shall be designated from time to time by the Board of Directors and stated in the notice of the meeting or in a duly executed waiver thereof.
Section 2.2
Annual meetings of stockholders shall be held at such date and time as shall be designated by the Board of Directors and stated in the notice of the meeting, at which time the stockholders shall elect a board of directors, and transact such other business as may properly be brought before the meeting. The Corporation may postpone, reschedule or cancel any previously scheduled annual meeting of stockholders.
Section 2.3
Written notice of the annual meeting stating the place, date and hour of the meeting shall be given to each stockholder entitled to vote at such meeting not less than ten nor more than sixty days before the date of the meeting.
Section 2.4
The Corporation shall prepare, at least ten days before every meeting of stockholders, a complete list of the stockholders entitled to vote at the meeting, arranged in alphabetical order, and showing the address of each stockholder and the number of shares registered in the name of each stockholder, for any purpose germane to the meeting, which shall be open to the inspection of any stockholder during ordinary business hours, for a period of at least ten days prior to the meeting, either at a place within the city where the meeting is to be held, which place shall be specified in the notice of the meeting, or, if not so specified, at the place where the meeting is to be held. The list shall also be produced and kept at the time and place of the meeting during the whole time thereof, and may be inspected by any stockholder who is present. If the meeting is to be held solely by means of remote communication, then the list shall also be open to the examination of any stockholder during the whole time of the meeting on a reasonably accessible electronic network, and the information required to access such list shall be provided with the notice of the meeting.
Section 2.5
Special meetings of the stockholders, for any purpose or purposes, unless otherwise prescribed by statute or by the Certificate of Incorporation, may be called by the Chairman, Chief Executive Officer or the President or by the Board of Directors or by the written order of a majority of the directors, and shall be called by the President or Secretary at the request in writing of stockholders owning 80% or more of the entire capital stock of the Corporation issued and outstanding and entitled to vote. Such request shall state the purpose or purposes of the proposed meeting.
Section 2.6
Written notice of a special meeting stating the place, date and hour of the meeting and the purpose or purposes for which the meeting is called, shall be given not less than ten nor more than sixty days before the date of the meeting, to each stockholder entitled to vote at such meeting. The Corporation may postpone, reschedule or cancel any previously scheduled special meeting of stockholders.
Section 2.7
Business transacted at any special meeting of stockholders shall be limited to the purposes stated in the notice.
Section 2.8
The holders of a majority of the stock issued and outstanding and entitled to vote thereat, present in person or represented by proxy, shall constitute a quorum at all meetings of the stockholders for the transaction of business except as otherwise provided by statute, by the Certificate of Incorporation or by these Bylaws. If, however, such quorum shall not be present or represented at any meeting of the stockholders, the stockholders entitled to vote thereat, present in person or represented by proxy, shall have the power to adjourn such meeting from time to time, without notice other than announcement at the meeting, until a quorum shall be present or represented. The Chairman of a meeting of the stockholders, whether or not a quorum is present, shall have the power to adjourn such meeting from time to time, without notice other than announcement at the meeting. At any adjourned meeting, any business may be transacted which might have been transacted at the meeting as originally notified. If the adjournment is for more than 30 days, or if after the adjournment a new record date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given to each stockholder of record entitled to vote at the meeting. If a quorum is present at the original duly organized meeting of stockholders, it is also present at an adjourned session of such meeting.
Section 2.9
When a quorum is present at any meeting, the vote of the holders of a majority of the stock having voting power present in person or represented by proxy shall decide any question brought before such meeting, unless the question is one upon which by express provision of the statutes, these Bylaws or of the Certificate of Incorporation, a different vote is required in which case such express provision shall govern and control the decision of such question.
Section 2.10
Unless otherwise provided in the Certificate of Incorporation, each stockholder shall at every meeting of the stockholders be entitled to one vote in person or by proxy for each share of the capital stock having voting power held by such stockholder, but no proxy shall be voted on after three years from its date, unless the proxy provides for a longer period.
Section 2.11
Subject to the rights of the holders of any series of preferred stock then outstanding, any action required or permitted to be taken by the stockholders of the Corporation must be effected at a duly-called annual or special meeting of stockholders of the Corporation and may not be effected by any consent in writing by such stockholders unless all of the stockholders entitled to vote thereon consent thereto in writing.
Section 2.12
(a)
Annual Meetings of Stockholders.
Only those persons who are nominated in accordance with the procedures set forth in these Bylaws are eligible for election as directors at any meeting of stockholders. Only business that has been properly brought before a meeting of stockholders in accordance with the procedures set forth in these Bylaws shall be conducted at the meeting. Nominations of persons for election to the Board of Directors and the proposal of business to be considered by stockholders at an annual meeting of stockholders may be made only (i) pursuant to the Corporation’s notice of meeting (or any supplement thereto) in accordance with Section 2.3 of these Bylaws, (ii) by or at the direction of the Board of Directors, or (iii) by a stockholder of the Corporation who is a stockholder of record both
at the time of giving of notice provided for in this section and on the record date for the determination of stockholders entitled to vote at such meeting, who is entitled to vote at the meeting and who complied with the notice procedures set forth in these Bylaws. For nominations or other business to be properly brought before an annual meeting by a stockholder pursuant to clause (iii) of Section 2.12(a) hereof, (A) the stockholder must have given timely written notice thereof to the Secretary, in proper form as provided by Section 2.12(b) hereof, and (B) such other business must otherwise be a proper matter for stockholder action under the General Corporation Law of the State of Delaware (the “
D.G.C.L.
”). To be timely, a stockholder’s notice in writing and in proper form must be delivered to, or mailed to and received by, the Secretary at the principal executive offices of the Corporation not less than 120 days nor more than 150 days prior to the scheduled date for the next annual meeting of stockholders.
(b)
Stockholder Notice.
To be in proper form, a stockholder’s notice to the Secretary must:
(i) as to each person whom the stockholder (the “
Noticing Stockholder
”) proposes to nominate for election or re-election as a director, set forth or provide (A) the name, age, business address and residence address of such person, (B) the principal occupation or employment of such person (present and for the past five years), (C) the class or series and number of shares of capital stock of the Corporation which are, directly or indirectly, owned beneficially and of record by such person (
provided
that for purposes of this Section 2.12(b)(i), such person shall in all events be deemed to beneficially own any shares of any class or series and number of shares of capital stock of the Corporation as to which such person has a right to acquire beneficial ownership at any time in the future), (D) all information relating to such person that is required to be disclosed in solicitations of proxies for election of directors in an election contest, or is otherwise required pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the “
Exchange Act
”), (E) a complete and accurate description of all direct and indirect compensation and other material monetary agreements, arrangements and understandings (whether written or oral) during the past three years, and any
other material relationships, between or among such Noticing Stockholder and beneficial owner, if any, and their respective Affiliates and associates (within the meaning of Rule 12b-2 under the Exchange Act), or others acting in concert therewith, on the one hand, and each proposed nominee, and his or her respective Affiliates and associates, or others acting in concert therewith, on the other hand, including, without limitation, all information that would be required to be disclosed pursuant to Rule 404 promulgated under Regulation S-K if the Noticing Stockholder and any beneficial owner on whose behalf the nomination is made, if any, or any Affiliate or associate thereof or person acting in concert therewith, were the “registrant” for purposes of such rule and the nominee were a director or executive officer of such registrant, (F) a notarized letter signed by such person stating his or her acceptance of the nomination by that stockholder or beneficial owner, stating his or her intention to serve as a director for the full term if elected, and consenting to being named as a nominee for director in any
proxy statement relating to such election, and (G) a completed signed questionnaire, and written representation and agreement, each as required by Section 2.12(c) of these Bylaws;
(ii) as to any business other than a nomination of a director or directors that the stockholder proposes to bring before the meeting, set forth or provide (A) a brief description of the business desired to be brought before the meeting, (B) the text of the proposal (including the text of any resolutions proposed for consideration and in the event that such business includes a proposal to amend the Bylaws of the Corporation, the language of the proposed amendment), (C) the reasons for conducting such business at the meeting and any material interest in such business of such Noticing Stockholder and the beneficial owner, if any, on whose behalf the proposal is made, and (D) a complete and accurate description of all agreements, arrangements and understandings between such Noticing Stockholder and beneficial owner, if any, and any other person or persons (including their names and addresses) in connection with the proposal of such business by such Noticing Stockholder; and
(iii) as to the Noticing Stockholder, and any beneficial owner on whose behalf the nomination or proposal is made (collectively with the Noticing Stockholder, the “
Holders
”), set forth (A) the name and address of the Noticing Stockholder as they appear on the Corporation’s books, (B) the name and address of all other Holders, if any, (C) the class or series and number of shares of the Corporation that are, directly or indirectly, owned beneficially and of record by each of the Holders (
provided
that for purposes of this Section 2.12(b)(iii), such person shall in all events be deemed to beneficially own any shares of any class or series and number of shares of capital stock of the Corporation as to which such person has a right to acquire beneficial ownership at any time in the future), (D) the Ownership Information (as defined below) for the Holders, (E) a representation that the Noticing Stockholder is a holder of record of stock of the Corporation entitled to vote at such meeting, will continue to be a holder of record of stock entitled to vote at such meeting through the date of such meeting and intends to appear in person or by proxy at the meeting to propose such business or nomination, (F) a representation whether any of the Holders intends or is part of a group which intends (1) to deliver a proxy statement and/or form of proxy to holders of at least the percentage of the Corporation’s outstanding capital stock required to approve or adopt the proposal or elect the nominee and/or (2) otherwise to solicit proxies from stockholders in support of such proposal or nomination, and (G) the Noticing Stockholder’s representation as to the accuracy of the information set forth in the notice.
In addition to the foregoing, the Noticing Stockholder also shall provide the Corporation with any other information reasonably requested by the Corporation, including, without limitation, such other information as may be reasonably required to determine (x) the eligibility of a proposed nominee to serve as a director of the Corporation, and (y) whether such nominee qualifies as an “independent director” or “audit committee financial expert” under applicable law, securities exchange rule or regulation, or any publicly disclosed corporate governance guideline or committee charter of the Corporation.
A stockholder providing notice of any nomination or other business proposed to be brought before a meeting shall further update and supplement such notice, if necessary, so that the information provided or required to be provided in such notice pursuant to this Section 2.12 shall be true and correct (i) as of the record date for the meeting and (ii) as of the date that is 10 business days prior to the meeting or any adjournment, recess, rescheduling or postponement thereof, and such update and supplement shall be delivered to, or mailed and received by, the Secretary at the principal executive offices of the Corporation not later than five business days after the record date for the meeting (in the case of the update and supplement required to be made as of the record date) and not later than seven business days prior to the date for the meeting, if practicable (or, if not practicable, on the first practicable date prior to) or any adjournment, recess, rescheduling or postponement thereof (in the case of the update and supplement required to be made as of 10 business days prior to the meeting or any adjournment, recess, rescheduling or postponement thereof).
Notwithstanding the foregoing provisions of this Section 2.12, unless otherwise required by law, if the stockholder (or a qualified representative of the stockholder) does not appear at the annual or special meeting of stockholders of the Corporation and present his or her proposed business or nomination, such proposed business will not be transacted and
the nomination will be disregarded, notwithstanding that proxies in respect of such vote may have been received by the Corporation. For purposes of this Section 2.12, to be considered a qualified representative of the stockholder, a person must be a duly authorized officer, manager or partner of such stockholder or must be authorized by a writing executed by such stockholder (or a reliable reproduction or electronic transmission of the writing) stating that such person is authorized to act for such stockholder as a proxy at the meeting of stockholders, and such person must produce proof that he or she is a duly authorized officer, manager or partner of such stockholder or such writing or electronic transmission, or a reliable reproduction of the writing or electronic transmission, as well as valid government-issued photo identification, at the meeting of stockholders.
Notwithstanding the foregoing provisions of this section, a stockholder shall also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this Section 2.12;
provided
,
however
, that any references in these Bylaws to the Exchange Act or the rules and regulations promulgated thereunder are not intended to and shall not limit any requirements applicable to nominations or proposals as to any other business to be considered pursuant to Section 2.12(a), and compliance with this Section 2.12 shall be the exclusive means for a stockholder to make nominations or submit other business (other than business properly brought under and in compliance with Rule 14a-8 of the Exchange Act or any successor provision). Nothing in this section shall be deemed to affect any rights of stockholders to request inclusion of proposals in the Corporation’s proxy statement pursuant to Rule 14a-8 under the Exchange Act.
For purposes of this section, “
Ownership Information
” means: (a) any option, warrant, convertible security, stock appreciation right, or similar right with an exercise or conversion privilege or a settlement payment or mechanism at a price related to any class or series of shares of the Corporation or with a value derived in whole in or part from the value of any class or series of shares of the Corporation, whether or not the instrument or right is subject to settlement in the underlying class or series of shares of the Corporation or otherwise (a “
Derivative Instrument
”) that is directly or indirectly owned beneficially by any of the Holders and any other direct or indirect opportunity to profit or share in any profit derived from any increase or decrease in the value of shares of the Corporation, (b) any proxy, contract, arrangement, understanding or relationship pursuant to which any of the Holders has a right to vote or has granted a right to vote any shares of the Corporation, (c) any short interest held by any of the Holders in any shares of the Corporation (a Holder is deemed to hold a short interest in a security if such Holder directly or indirectly, through any contract, arrangement, understanding, relationship or otherwise, has the opportunity to profit or share in any profit derived from any decrease in the value of the subject security), (d) any rights to dividends on shares of the Corporation owned beneficially by any of the Holders that are separated or separable from the underlying shares of the Corporation, (e) any proportionate interest in shares of the Corporation or Derivative Instruments held, directly or indirectly, by a general or limited partnership or limited liability company or similar entity in which any of the Holders is a general partner or, directly or indirectly, beneficially owns any interest in a general partner, is the manager, managing member of directly or indirectly beneficially owns any interest in the manager or managing member of a limited liability company or similar entity, (f) any performance-related fees (other than an asset-based fee) that any of the Holders is entitled to based on any increase or decrease in the value of shares of the Corporation or Derivative Instruments and (g) any arrangements, rights or other interests described in the preceding clauses of this paragraph held by any member of the immediate family of any of the Holders that shares the same household with such Holder.
(c)
Questionnaire; Voting.
To be eligible to be a nominee for election or reelection as a director of the Corporation pursuant to this Section 2.12, a proposed nominee must deliver (in the case of nominee nominated by a stockholder pursuant to this Section 2.12, in accordance with the time periods prescribed for delivery of notice under these Bylaws and applicable law) to the Secretary at the principal executive offices of the Corporation (i) a written questionnaire with respect to the background and qualification of such person and the background of any other person or entity on whose behalf the nomination is being made (in the form provided by the Secretary upon written request) and (ii) a written representation and agreement (in the form provided by the Secretary upon written request) that such person (A) is not and will not become a party to (1) any agreement, arrangement or understanding (whether written or oral) with, and has not given any commitment or assurance to, any person or entity as to how such person, if elected as a director of the Corporation, will act or vote in such capacity on any issue or question (a “
Voting Commitment
”) that has not been disclosed to the Corporation or (2) any Voting Commitment that could limit or interfere with such person’s ability to comply, if elected as a director of the Corporation, with such person’s fiduciary duties under applicable law; (B) is not and will not become a party to any agreement, arrangement or understanding (whether written or oral) with any person or entity other than the Corporation with respect to any direct or indirect compensation, reimbursement or indemnification in connection with service or action as a director of the Corporation that has not been disclosed to the Corporation; (C) if elected as director of the Corporation, intends to serve for a full term and (D) in such person’s individual capacity and on behalf of any person or entity on whose behalf the nomination is being made, would be in compliance, if elected as a director of the Corporation, and will comply with all applicable law and all applicable rules of the U.S. exchanges upon which the common stock of the
Corporation is listed and all applicable publicly disclosed corporate governance, conflict of interest, confidentiality and stock ownership and trading policies and other guidelines of the Corporation duly adopted by the Board of Directors.
Section 2.13
At any meeting of stockholders, the Chairman or Vice Chairman (or in the event there might be more than one vice chairman, the vice chairman in the order designated by the directors or, in the absence of any designation, in the order of election) of the Corporation (in such order) shall act as the chairman of the meeting, and the stockholders shall not have the right to elect a different person as chairman of the meeting. The chairman of the meeting shall have the authority to determine (i) when the election polls shall be closed in connection with any vote to be taken at the meeting, and (ii) when the meeting shall be recessed.
ARTICLE III
Directors
Section 3.1
The business and affairs of the Corporation shall be managed by a board of directors, which shall have and may exercise all of the powers of the Corporation, except such as are expressly conferred upon the stockholders by law, by the Certificate of Incorporation or by these Bylaws. Subject to the rights of the holders of shares of any series of preferred stock then outstanding to elect additional directors under specified circumstances, the Board of Directors shall consist of no more than twenty-one persons. The number of initial directors shall be two. Thereafter, the exact number of directors within the maximum limitations as specified above shall be fixed from time to time by either (i) the Board of Directors pursuant to a resolution adopted by a majority of the entire Board of Directors, (ii) the affirmative vote of the holders of 80% or more of the voting power of all of the shares of the Corporation entitled to vote generally in the election of directors, voting together as a single class, or (iii) the Certificate of Incorporation. No decrease in the number of directors constituting the Board of Directors shall shorten the term of any incumbent director. The directors shall be divided into three classes, as nearly equal in number as possible, with the term of office of the first class to expire at the 1995 annual meeting of stockholders, the term of the second class to expire at the 1995 annual meeting of stockholders, and the term of the third class to expire at the 1997 annual meeting of stockholders, and with the members of each class to hold office until their successors have been elected and qualified. At each annual meeting of stockholders following such initial classification and election, directors elected to succeed those directors whose terms expire shall be elected for a term of office to expire at the third succeeding annual meeting of stockholders after their election. Notwithstanding the foregoing, the above provisions regarding classification of directors shall be applicable only in the event that the Board of Directors is composed of three or more directors. Election of directors need not be by written ballot.
Section 3.2
Subject to the rights of the holders of any series of preferred stock then outstanding, any director, or the entire Board of Directors, may be removed from office at any time only for cause and only by the affirmative vote of the holders of 80% or more of the voting power of all of the shares of the Corporation entitled to vote generally in the election of directors, voting together as a single class. “
Cause
” shall be exclusively defined to mean: (a) conviction of a felony, (b) proof beyond a reasonable doubt of the gross negligence or willful misconduct of such director which is materially detrimental to the Corporation, or (c) proof beyond a reasonable doubt of a breach of fiduciary duty of such director which is materially detrimental to the Corporation.
Section 3.3
Subject to the rights of holders of any series of any preferred stock then outstanding, newly-created directorships resulting from any increase in the authorized number of directors and any vacancies in the Board of Directors resulting from death, resignation, retirement, disqualification, removal from office or other cause may be filled by a majority vote of the directors then in office even though less than a quorum or by a sole remaining director and the directors so chosen shall hold office until the next annual election and until their successors are duly elected and shall qualify, unless sooner displaced. If there are no directors in office, then an election of directors may be held in the manner provided by statute.
Meetings of the Board of Directors
Section 3.4
The Board of Directors of the Corporation may hold meetings, both regular and special, either within or without the State of Delaware.
Section 3.5
The first meeting of each newly elected Board of Directors shall be held immediately after the annual meeting at which such directors were elected at the principal executive offices of the Corporation or at such other location as determined by the Chairman of the Board.
Section 3.6
Regular meetings of the Board of Directors may be held without notice at such time and at such place as shall from time to time be determined by the Board.
Section 3.7
Special meetings of the Board may be called by the Chairman of the Board on two days’ notice to each director, either personally or by electronic transmission. Special meetings shall be called by the President or Secretary in like manner and on like notice on the written request of a majority of the directors (unless the Board consists of only one director; in which case special meetings shall be called by the President or Secretary in like manner and on like notice on the written request of the sole director).
Section 3.8
At all meetings of the Board, a majority of the directors shall constitute a quorum for the transaction of business and the act of a majority of the directors present at any meeting at which there is a quorum shall be the act of the Board of Directors, except as may be otherwise specifically provided by statute, these Bylaws or by the Certificate of Incorporation. If a quorum shall not be present at any meeting of the Board of Directors, the directors present thereat may adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum shall be present.
Section 3.9
Unless otherwise restricted by the Certificate of Incorporation or these Bylaws, any action required or permitted to be taken at any meeting of the Board of Directors or of any committee thereof may be taken without a meeting, if all members of the Board or committee, as the case may be, consent thereto in writing or by electronic transmission, and the writings or electronic transmissions are filed with the minutes of proceedings of the Board or committee.
Section 3.10
Unless otherwise restricted by the Certificate of Incorporation or these Bylaws, members of the Board of Directors, or any committee designated by the Board of Directors, may participate in a meeting of the Board of Directors, or any committee, by means of conference telephone or other communications equipment by means of which all persons participating in the meeting can hear each other, and such participation in a meeting shall constitute presence in person at the meeting.
Committees of Directors
Section 3.11
The Board of Directors may, by resolution passed by a majority of the whole Board, designate one or more committees, each committee to consist of one or more of the directors of the Corporation. The Board may designate one or more directors as alternate members of any committee, who may replace any absent or disqualified member at any meeting of the committee.
In the absence or disqualification of a member of a committee, the member or members thereof present at any meeting and not disqualified from voting, whether or not he or they constitute a quorum, may unanimously appoint another member of the Board of Directors to act at the meeting in the place of any such absent or disqualified member.
Any such committee, to the extent provided in the resolution of the Board of Directors, shall have and may exercise all the powers and authority of the Board of Directors in the management of the business and affairs of the Corporation, and may authorize the seal of the Corporation to be affixed to all papers which may require it; but no such committee shall have the power or authority in reference to the following matters: (i) approving or adopting, or recommending to the stockholders, any action or matter expressly required by the D.G.C.L. to be submitted to stockholders for approval (other than recommending the election or removal of directors) or (ii) adopting, amending, or repealing any Bylaw of the Corporation. Such committee or committees shall have such name or names as may be determined from time to time by resolution adopted by the Board of Directors.
Section 3.12
Each committee shall keep regular minutes of its meetings and report the same to the Board of Directors when required consistent with any rules or procedures determined by the Board with respect to such committee.
Compensation of Directors
Section 3.13
Unless otherwise restricted by the Certificate of Incorporation or these Bylaws, the Board of Directors shall have the authority to fix the compensation of directors. The directors may be paid their expenses, if any, of attendance at each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors or a stated salary as director. No such payment shall preclude any director from serving the Corporation in any other capacity and receiving compensation therefor. Members of special or standing committees may be allowed like compensation for attending committee meetings.
ARTICLE IV
Notices
Section 4.1
Whenever, under the provisions of the statutes or of the Certificate of Incorporation or of these Bylaws, notice is required to be given to any director or stockholder, it shall not be construed or mean personal notice, but such notice may be given in writing, by mail, addressed to such director or stockholder, at his address as it appears on the records of the Corporation,
with postage thereon prepaid, and such notice shall be deemed to be given at the time when the same shall be deposited in the United States mail. Notice to directors may also be given by electronic transmission.
Section 4.2
Whenever any notice is required to be given under the provisions of the statutes or of the Certificate of Incorporation or of these Bylaws, a waiver thereof in writing, signed by the person or persons entitled to said notice, or a waiver by electronic transmission by the person entitled thereto, whether before or after the time stated therein, shall be deemed equivalent thereto.
ARTICLE V
Officers
Section 5.1
The officers of the Corporation shall be chosen by the Board of Directors and shall consist of a chairman of the board, a president and a secretary. The Board of Directors, or a designated committee thereof, may also appoint a chief executive officer, one or more vice presidents, one or more vice chairmen of the board, a treasurer and such other additional officers as the Board of Directors shall determine to be necessary. The Board of Directors, or a designated committee thereof, may also choose assistant vice presidents and one or more assistant secretaries and assistant treasurers. Any number of offices may be held by the same person, unless the Certificate of Incorporation or these Bylaws otherwise provide. The Chairman shall be elected from among the directors.
Section 5.2
The Board of Directors or a committee thereof may appoint such other officers and agents as it shall deem necessary who shall hold their offices for such terms and shall exercise such powers and perform such duties as shall be determined from time to time by the Board.
Section 5.3
The salaries of all officers and agents of the Corporation shall be fixed by the Board of Directors or a committee thereof.
Section 5.4
The officers of the Corporation shall hold office until their successors are chosen and qualify. Any officer elected or appointed by the Board of Directors may be removed at any time by the affirmative vote of a majority of the Board of Directors then in office. Such removal shall be without prejudice to the contract rights, if any, of the person so removed, provided, however, that the election or appointment of an officer shall not, of itself, create contract rights. Any vacancy occurring in any office of the Corporation shall be filled by the Board of Directors or a designated committee thereof.
Chairman of the Board
Section 5.5
The Chairman of the Board shall preside at all meetings of the Board of Directors and of the stockholders of the Corporation. The Chairman shall formulate and submit to the Board of Directors or a committee designated thereby matters of general policy of the Corporation and shall perform such other duties as usually appertain to the office or as may be prescribed by the Board of Directors.
The Vice Chairman
Section 5.6
The Board may appoint a Vice Chairman, who shall, in the absence of the Chairman, preside at all meetings of the Board of Directors and of the stockholders. In the event there may be more than one vice chairman, the vice chairman in the order designated by the directors shall preside in the Chairman’s absence and, in the absence of any designation, in the order of election. The Vice Chairman shall perform such other duties and have such other powers as the Chairman, or the Board of Directors may from time to time prescribe.
The Chief Executive Officer
Section 5.7
The Board may appoint a Chief Executive Officer who shall be the senior officer of the Corporation and shall perform such duties as usually pertain to the office or as may be prescribed by the Board of Directors.
The President
Section 5.8
The President, subject to the control of the Board of Directors, shall have general and active management of the business of the Corporation and shall see that all orders and resolutions of the Board of Directors are carried into effect. The President shall keep the Board of Directors fully informed and shall consult them concerning the business of the Corporation.
Section 5.9
He or she shall execute bonds, mortgages and other contracts requiring a seal, under the seal of the Corporation, except where required or permitted by law to be otherwise signed and executed and except where the signing and execution thereof shall be expressly delegated by the Board of Directors to some other officer or agent of the Corporation.
The Vice Presidents
Section 5.10
The Board may appoint one or more Vice Presidents. In the absence of the President or in the event of his inability or refusal to act, the Vice President (or in the event there be more than one vice president, the vice presidents in the order designated by the directors, or in the absence of any designation, then in the order of their election) shall perform the duties of the President, and when so acting, shall have all the powers of and be subject to all the restrictions upon the President. The Vice Presidents shall perform such other duties and have such other powers as the President, the Board of Directors or any committee of the Board of Directors may from time to time prescribe.
The Secretary and Assistant Secretary
Section 5.11
The Secretary shall attend all meetings of the Board of Directors and all meetings of the stockholders and record all the proceedings of the meetings of the Corporation and of the Board of Directors in a book to be kept for that purpose and shall perform like duties for the standing committees when required. The Secretary shall give, or cause to be given, notice of all meetings of the stockholders and special meetings of the Board of Directors, and shall perform such other duties as may be prescribed by the Board of Directors or President, under whose supervision he shall be. The Secretary shall have custody of the corporate seal of the Corporation and he, or any assistant secretary, shall have authority to affix the same to any instrument requiring it and when so affixed, it may be attested by his signature or by the signature of such assistant secretary. The Board of Directors may give general authority to any other officer to affix the seal of the Corporation and to attest the affixing by his signature.
Section 5.12
The Board may appoint one or more Assistant Secretaries. The Assistant Secretary (or if there be more than one, the assistant secretaries in the order designated by the Board of Directors or if there be no such designation, then in the order of their election) shall, in the absence of the Secretary or in the event of his inability or refusal to act, perform the duties and exercise the powers of the Secretary and shall perform such other duties and have such other powers as the Board of Directors may from time to time prescribe.
The Treasurer and Assistant Treasurers
Section 5.13
The Board may appoint a Treasurer. The Treasurer shall have the custody of the corporate funds and securities and shall keep full and accurate accounts of receipts and disbursements in books belonging to the Corporation and shall deposit all monies and other valuable effects in the name and to the credit of the Corporation in such depositories as may be designated by the Board of Directors.
Section 5.14
The Treasurer shall disburse the funds of the Corporation as may be ordered by the Board of Directors, taking proper vouchers for such disbursements, and shall render to the President and the Board of Directors, at its regular meetings or when the Board of Directors so requires, an account of all his transactions as Treasurer and of the financial condition of the Corporation.
Section 5.15
If required by the Board of Directors, the Treasurer shall give the Corporation a bond (which shall be renewed every six (6) years) in such sum and with such surety or sureties as shall be satisfactory to the Board of Directors for the faithful performance of the duties of his office and for the restoration to the Corporation, in case of his death, resignation, retirement or removal from office, of all books, papers, vouchers, money and other property of whatever kind in his possession or under his control belonging to the Corporation.
Section 5.16
The Board may appoint one or more assistant treasurers. The Assistant Treasurer (or if there be more than one, the assistant treasurers in the order designated by the Board of Directors or if there be no such designation then in the order of their election) shall, in the absence of the Treasurer or in the event of his inability or refusal to act, perform the duties and exercise the powers of the Treasurer and shall perform such other duties and have such other powers as the Board of Directors may from time to time prescribe.
ARTICLE VI
Certificates for Shares
Section 6.1
The shares of the Corporation shall be represented by a certificate or shall be uncertificated. Certificates shall be signed by, or in the name of the Corporation by, the Chairman or Vice Chairman of the Board of Directors, or the President or Vice President and the Treasurer or an assistant treasurer, or the Secretary or an assistant secretary of the Corporation.
Upon the face or back of each stock certificate issued to represent any partially paid shares, or upon the books and records of the Corporation in the case of uncertificated partially paid shares, shall be set forth the total amount of the consideration to be paid therefor and the amount paid thereon shall be stated. Certificates shall also contain such legends or statements as may be required by law and any agreement between the Corporation and the holder thereof.
If the Corporation shall be authorized to issue more than one class of stock or more than one series of any class, the powers, designations, preferences and relative, participating, optional or other special rights of each class of stock or series thereof and the qualification, limitations or restrictions of such preferences and/or rights shall be set forth in full or summarized on the face or back of the certificate which the Corporation shall issue to represent such class or series of stock, provided that, except as otherwise provided in Section 202 of the Act, in lieu of the foregoing requirements, there may be set forth on the face or back of the certificate which the Corporation shall issue to represent such class or series of stock, a statement that the Corporation will furnish without charge to each stockholder who so requests the powers, designations, preferences and relative, participating, optional or other special rights of each class of stock or series thereof and the qualifications, limitations or restrictions of such preferences and/or rights.
Within a reasonable time after the issuance or transfer of uncertificated stock, the Corporation shall send to the registered owner thereof a written notice containing the information required to be set forth or stated on certificates pursuant to Section 151, 156, 202(a) or 218(a) of the Act or a statement that the Corporation will furnish without charge to each stockholder who so requests the powers, designations preferences and relative participating, optional or other special rights of each class of stock or series thereof and the qualifications, limitations or restrictions of such preferences and/or rights.
Section 6.2
Any or all the signatures on a certificate may be facsimile. In case any officer, transfer agent or registrar who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer, transfer agent or registrar before such certificate is issued, it may be issued by the Corporation with the same effect as if he were such officer, transfer agent or registrar at the date of issue.
Lost Certificates
Section 6.3
The Board of Directors may direct a new certificate or certificates to be issued in place of any certificate or certificates theretofore issued by the Corporation alleged to have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the person claiming the certificate of stock to be lost, stolen or destroyed. When authorizing such issue of a new certificate or certificates or uncertificated shares, the Board of Directors may, in its discretion and as a condition precedent to the issuance thereof, require the owner of such lost, stolen or destroyed certificate or certificates, or his legal representative, to advertise the same in such manner as it shall require and/or to give the Corporation a bond in such sum as it may direct as indemnity against any claim that may be made against the Corporation with respect to the certificate alleged to have been lost, stolen or destroyed.
Transfer of Stock
Section 6.4
Upon surrender to the Corporation or the transfer agent of the Corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignation or authority to transfer, it shall be the duty of the Corporation to issue a new certificate to the person entitled thereto, cancel the old certificate and record the transaction upon its books. Upon receipt of proper transfer instructions from the registered owner of uncertificated shares such uncertificated shares shall be cancelled and issuance of new equivalent uncertificated shares or uncertificated shares shall be made to the person entitled thereto and the transaction shall be recorded upon the books of the Corporation. Transfers of shares shall be made only on the books of the Corporation by the registered holder thereof, or by his attorney thereunto authorized by power of attorney and filed with the Secretary of the Corporation or the transfer agent.
Section 6.5
Every stockholder or transferee shall furnish the Secretary or a transfer agent with the address to which notice of meetings and all other notices may be served upon or mailed to him or her, and in default thereof, he or she shall not be entitled to service or mailing of any such notice.
Fixing Record Date
Section 6.6
In order that the Corporation may determine the stockholders entitled to notice of or to vote at any meeting of stockholders or any adjournment thereof, or to express consent to corporate action in writing without a meeting, or entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitled to exercise any rights in respect of any change, conversion or exchange of stock or for the purpose of any other lawful action, the Board of Directors may fix, in advance, a record date, which shall not be more than sixty (60) nor less than ten (10) days before the date of such meeting, nor more than sixty (60) days prior to any other action. A determination of stockholders of record entitled to notice of or to vote
at a meeting of stockholders shall apply to any adjournment of the meeting; provided, however, that the Board of Directors may fix a new record date for the adjourned meeting.
Registered Stockholders
Section 6.7
The Corporation shall be entitled to recognize the exclusive right of a person registered on its books as the owner of shares to receive dividends, to vote as such owner, and to hold such person registered on its books liable for coils and assessments as the owner of such shares, and shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of Delaware.
ARTICLE VII
Miscellaneous/Dividends
Section 7.1
Dividends upon the capital stock of the Corporation, subject to the provisions of the Certificate of Incorporation, if any, and applicable law, may be declared by the Board of Directors at any regular or special meeting. Dividends may be paid in cash, in property or in shares of capital stock, subject to the provisions of the Certificate of Incorporation.
Section 7.2
Before payment of any dividend, there may be set aside out of any funds of the Corporation available for dividends such sum or sums as the directors from time to time, in their absolute discretion, think proper as a reserve or reserves to meet contingencies, or for equalizing dividends, or for repairing or maintaining any property of the Corporation, or for such other purpose as the directors shall determine to be in the interest of the Corporation, and the directors may modify or abolish any such reserve in the manner in which it was created.
Annual Statement
Section 7.3
The Board of Directors shall present at each annual meeting, and at any special meeting of the stockholders when called for by vote of the stockholders, a full and clear statement of the business and condition of the Corporation.
Checks
Section 7.4
All checks, demands, drafts, or other orders for payment of money, notes or other evidences of indebtedness issued in the name of the Corporation, shall be signed by such officer or officers or such other person or persons as the Board of Directors may from time to time designate.
Contracts
Section 7.5
The Board of Directors may authorize any officer, officers, agent, or agents, to enter into any contract or execute and deliver any instrument in the name of and on behalf of the Corporation, and such authority may be general or confined to specific instances.
Deposits
Section 7.6
All funds of the Corporation not otherwise employed shall be deposited from time to time to the credit of the Corporation in such banks, trust companies, or other depositories as the Board of Directors or officers may select.
Fiscal Year
Section 7.7
The fiscal year of the Corporation shall be fixed by resolution of the Board of Directors.
Facsimile and Electronic Signatures
Section 7.8
In addition to the provisions for use of facsimile or electronic signatures elsewhere specifically authorized in these Bylaws, facsimile or electronic signatures of any officer or officers of the Corporation may be used whenever and as authorized by the Board or a committee thereof, the Chairman of the Board or the President and Chief Executive Officer.
Seal
Section 7.9
The corporate seal, if any, shall have inscribed thereon the name of the Corporation, the year of its organization and the words “Corporate Seal, Delaware”. The seal may be used by causing it or a facsimile thereof to be impressed or affixed or reproduced or otherwise.
ARTICLE VIII
Amendments
Section 8.1
The Board of Directors or the holders of a majority of the shares may amend or repeal these Bylaws or adopt new Bylaws, provided that, notwithstanding any other provision contained in these Bylaws to the contrary, Sections 2.5, 2.11, 2.12 and 2.13 of Article II, Sections 3.1 and 3.2 of Article III, and this Article VIII of these Bylaws may be amended, supplemented, or repealed only by the affirmative vote of 80% or more of all of the shares of the Corporation entitled to vote generally in the election of directors, voting together as a single class.
ARTICLE IX
Indemnification
Section 9.1
(a) Subject to Section 9.3, the Corporation shall indemnify, to the full extent that it shall have power under applicable law to do so and in a manner permitted by such law, any person who is made or threatened to be made a party to or is otherwise involved (as a witness or otherwise) in any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative, or investigative (hereinafter, a “
Proceeding
”), by reason of the fact that such person is or was a director or officer of the Corporation, or while serving as a director or officer of the Corporation, 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, including service with respect to an employee benefit plan (collectively, “
Another Enterprise
”), against expenses (including attorneys’ fees), judgments, fines (including ERISA excise taxes or penalties) and amounts paid in settlement actually and reasonably incurred by him or her in connection with such 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 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.
(b) Subject to Section 9.3, the Corporation shall indemnify, to the full extent that it shall have power under applicable law to do so and in a manner permitted by such law, any person who is made or threatened to be made a party to or is otherwise involved (as a witness or otherwise) in any threatened, pending, or completed Proceeding, by reason of the fact that such person is or was an employee of the Corporation, or while not serving as an employee of the Corporation, is or was serving at the request of the Corporation as a director, officer, employee, or agent of Another Enterprise, against expenses (including attorneys’ fees), judgments, fines (including ERISA excise taxes or penalties) and amounts paid in settlement actually and reasonably incurred by him or her in connection with such 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 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, unless the Board determines in its sole discretion that the action or inaction of such employee constitutes gross negligence, willful misconduct or a criminal act by such person.
(c) To the extent that a present or former director, officer or employee of the Corporation has been successful on the merits or otherwise in defense of any threatened, pending, or completed Proceeding referred to in Section 145(a) or (b) of the D.G.C.L., or in defense of any claim, issue, or matter therein, he or she shall be indemnified against expenses (including attorneys’ fees) actually and reasonably incurred by him or her in connection therewith.
(d) The termination of any Proceeding by judgment, order, settlement, conviction, or upon a plea of nolo contendre or its equivalent, shall not, of itself, create a presumption that the person seeking indemnification did not act 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 reasonable cause to believe that his or her conduct was unlawful.
Advancement of Expenses
Section 9.2
(a) Subject to Section 9.3, with respect to any person who is made or threatened to be made a party to or is otherwise involved (as a witness or otherwise) in any threatened, pending, or completed Proceeding, by reason of the fact that such person is or was a director or officer of the Corporation or while serving as a director or officer of the Corporation, is or was serving at the request of the Corporation as a director, officer, employee, or agent of Another Enterprise, the Corporation shall pay the expenses (including attorneys’ fees) incurred by such person in defending any such Proceeding in advance of its final disposition (hereinafter an “
advancement of expenses
”); provided, however, that any advancement of expenses shall be made only upon receipt of an undertaking (hereinafter an “
undertaking
”) by such person to repay all amounts advanced if it shall ultimately be determined by final judicial decision from which there is no further right to appeal that such person is not entitled to be indemnified for such expenses under this Article IX or otherwise.
(b) Subject to Section 9.3, with respect to any person who is made or threatened to be made a party to or is otherwise involved (as a witness or otherwise) in any threatened, pending, or completed Proceeding, by reason of the fact that such person is or was an employee of the Corporation or while serving as an employee of the Corporation, is or was serving at the request of the Corporation as a director, officer, employee, or agent of Another Enterprise, the Corporation may, in its discretion and upon such terms and conditions, if any, as the Corporation deems appropriate, pay the expenses (including attorneys’ fees) incurred by such person in defending any such Proceeding in advance of its final disposition; provided however, that any advancement of expenses shall be made only upon receipt of an undertaking by such person to repay all amounts advanced if it shall ultimately be determined by final judicial decision from which there is no further right to appeal that such person is not entitled to be indemnified for such expenses under this Article IX or otherwise.
Actions Initiated Against the Corporation
Section 9.3
Anything in Section 9.1 or Section 9.2 to the contrary notwithstanding, except as provided in Section 9.5, with respect to a Proceeding initiated against the Corporation by a person who is or was a director, officer or employee of the Corporation (whether initiated by such person in or by reason of such capacity or in or by reason of any other capacity, including as a director, officer, employee, or agent of Another Enterprise), the Corporation shall not be required to indemnify or to advance expenses (including attorneys’ fees) to such person in connection with prosecuting such Proceeding (or part thereof) or in defending any counterclaim, cross-claim, affirmative defense, or like claim of the Corporation in such Proceeding (or part thereof) unless such Proceeding was authorized in advance by the Board of Directors.
Contract Rights
Section 9.4
The rights to indemnification and advancement of expenses conferred upon any current or former director, officer or employee of the Corporation pursuant to this Article IX (whether by reason of the fact that such person is or was a director, officer or employee of the Corporation, or while serving as a director, officer or employee of the Corporation, is or was serving at the request of the Corporation as a director, officer, employee, or agent of Another Enterprise) shall be contract rights, shall vest when such person becomes a director, officer or employee of the Corporation, and shall continue as vested contract rights even if such person ceases to be a director, officer or employee of the Corporation. Any amendment, repeal, or modification of, or adoption of any provision inconsistent with, this Article IX (or any provision hereof) shall not adversely affect any right to indemnification or advancement of expenses granted to any person pursuant hereto with respect to any act or omission of such person occurring prior to the time of such amendment, repeal, modification, or adoption (regardless of whether the Proceeding relating to such acts or omissions, or any proceeding relating to such person’s rights to indemnification or to advancement of expenses, is commenced before or after the time of such amendment, repeal, modification, or adoption), and any such amendment, repeal, modification, or adoption that would adversely affect such person’s rights to indemnification or advancement of expenses hereunder shall be ineffective as to such person, except with respect to any threatened, pending, or completed Proceeding that relates to or arises from (and only to the extent such Proceeding relates to or arises from) any act or omission of such person occurring after the effective time of such amendment, repeal, modification, or adoption.
Claims
Section 9.5
(a) If (X) a claim under Section 9.1 with respect to any right to indemnification is not paid in full by the Corporation within sixty days after a written demand has been received by the Corporation or (Y) a claim under Section 9.2 with respect to any right to the advancement of expenses is not paid in full by the Corporation within 20 days after a written demand has been received by the Corporation, then the person seeking to enforce a right to indemnification or to an advancement of expenses, as the case may be, may at any time thereafter bring suit against the Corporation to recover the unpaid amount of the claim.
(b) If successful in whole or in part in any suit brought pursuant to Section 9.5(a), or in a suit brought by the Corporation to recover an advancement of expenses (whether pursuant to the terms of an undertaking or otherwise), the person seeking to enforce a right to indemnification or an advancement of expenses hereunder or the person from whom the Corporation sought to recover an advancement of expenses, as the case may be, shall be entitled to be paid by the Corporation the reasonable expenses (including attorneys’ fees) of prosecuting or defending such suit.
(c) In any suit brought by a person seeking to enforce a right to indemnification hereunder (but not a suit brought by a person seeking to enforce a right to an advancement of expenses hereunder), it shall be a defense that the person seeking to enforce a right to indemnification has not met any applicable standard for indemnification under applicable law. With respect to any suit brought by a person seeking to enforce a right to indemnification or right to advancement of expenses hereunder or any suit brought by the Corporation to recover an advancement of expenses (whether pursuant to the terms of an undertaking or otherwise), neither (i) the failure of the Corporation to have made a determination prior to commencement of such suit that indemnification of such person is proper in the circumstances because such person has met the applicable standards of conduct
under applicable law, nor (ii) an actual determination by the Corporation that such person has not met such applicable standards of conduct, shall create a presumption that such person has not met the applicable standards of conduct other than a determination by the Board pursuant to Section 9.1(b) in respect of whether such person’s actions or inactions constitute gross negligence, willful misconduct or a criminal act, or, in a case brought by such person seeking to enforce a right to indemnification, be a defense to such suit.
(d) In any suit brought by a person seeking to enforce a right to indemnification or to an advancement of expenses hereunder, or by the Corporation to recover an advancement of expenses (whether pursuant to the terms of an undertaking or otherwise), the burden shall be on the Corporation to prove that the person seeking to enforce a right to indemnification or to an advancement of expenses or the person from whom the Corporation seeks to recover an advancement of expenses is not entitled to be indemnified, or to such an advancement of expenses, under this Article IX or otherwise.
Determination of Entitlement to Indemnification
Section 9.6
Any indemnification required or permitted under this Article IX (unless ordered by a court) shall be made by the Corporation only as authorized in the specific case upon a determination that indemnification of the present or former director, officer, employee or agent is proper in the circumstances because he or she has met all applicable standards of conduct set forth in this Article IX and Section 145 of the D.G.C.L. Such determination shall be made, with respect to a person who is a director or officer of the Corporation at the time of such determination, (i) by a majority vote of the directors who are not parties to such Proceeding, even though less than a quorum; (ii) by a committee of such directors designated by majority vote of such directors, even though less than a quorum; (iii) if there are no such directors, or if such directors so direct, by independent legal counsel in a written opinion; or (iv) by the stockholders. Such determination shall be made, with respect to any person who is not a director or officer of the Corporation at the time of such determination, in the manner determined by the Board of Directors (including in such manner as may be set forth in any general or specific action of the Board of Directors applicable to indemnification claims by such person) or in the manner set forth in any agreement to which such person and the Corporation are parties.
Nonexclusivity of Rights
Section 9.7
The rights of indemnification and advancement of expenses as provided by this Article IX shall not be deemed exclusive of any other rights to any person may at any time be entitled under any bylaw, agreement, vote of stockholders or disinterested directors, or otherwise, both as to action in such person’s official capacity and as to action in another capacity while holding such office, and shall continue as to a person who has ceased to be such director, officer, employee, or agent and shall inure to the benefit of the heirs, executors, and administrators of such person.
Insurance and Subrogation
Section 9.8
The Corporation may maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the Corporation or is or was serving at the request of the Corporation as a director, officer, employee or agent of Another Enterprise against any liability asserted against such person and incurred by such person in any capacity, or arising out of such person’s status as such, whether or not the Corporation would have the power to indemnify such person against such liability under the provisions of this Article IX or otherwise.
Severability
Section 9.9
If any provision or provisions of this Article IX shall be held to be invalid, illegal, or unenforceable for any reason whatsoever: (1) the validity, legality, and enforceability of the remaining provisions of this Article IX (including, without limitation, each portion of any paragraph or clause containing any such provision held to be invalid, illegal, or unenforceable, that is not itself held to be invalid, illegal, or unenforceable) shall not in any way be affected or impaired thereby; and (2) to the fullest extent possible, the provisions of this Article IX (including, without limitation, each such portion of any paragraph or clause containing any such provision held to be invalid, illegal, or unenforceable) shall be construed so as to give effect to the intent manifested by the provision held invalid, illegal, or unenforceable.
Miscellaneous
Section 9.10
For purposes of this Article IX: (a) references to serving at the request of the Corporation as a director or officer of Another Enterprise shall include any service as a director or officer of the Corporation that imposes duties on, or involves services by, such director or officer with respect to an employee benefit plan; (b) references to serving at the request of the Corporation as an employee or agent of Another Enterprise shall include any service as an employee or agent of the Corporation that imposes duties on, or involves services by, such employee or agent with respect to an employee benefit plan; (c) a person who acted in good faith and in a manner such person reasonably believed to be in the interest of the participants and beneficiaries of
an employee benefit plan shall be deemed to have acted in a manner not opposed to the best interests of the Corporation; and (d) references to a director of Another Enterprise shall include, in the case of any entity that is not managed by a board of directors, such other position, such as manager or trustee or member of the governing body of such entity, that entails responsibility for the management and direction of such entity’s affairs, including, without limitation, general partner of any partnership (general or limited) and manager or managing member of any limited liability company.
ARTICLE X
Exclusive Forum
Section 10.1
Unless the Corporation consents in writing to the selection of an alternative forum, the sole and exclusive forum for (a) any derivative action or proceeding brought on behalf of the Corporation, (b) any action or proceeding asserting a claim of breach of a fiduciary duty owed by any current or former director, officer or other employee of the Corporation to the Corporation or the Corporation’s stockholders, (c) any action or proceeding asserting a claim against the Corporation or any current or former director or officer or other employee of the Corporation arising pursuant to any provision of the D.G.C.L., the Corporation’s Certificate of Incorporation or these Bylaws (as each may be amended from time to time), (d) any action or proceeding asserting a claim against the Corporation or any current or former director or officer or other employee of the Corporation governed by the internal affairs doctrine, or (e) any action or proceeding as to which the D.G.C.L. confers jurisdiction on the Court of Chancery of the State of Delaware (the “
Court of Chancery
”), shall be the Court of Chancery or, if and only if the Court of Chancery lacks subject matter jurisdiction, any state court located within the State of Delaware or, if and only if such state courts lack subject matter jurisdiction, the federal district court for the District of Delaware), in all cases to the fullest extent permitted by law and subject to the court’s having personal jurisdiction over the indispensable parties named as defendants. Any person or entity purchasing or otherwise acquiring any interest in shares of capital stock of the Corporation shall be deemed to have notice of and consented to the provision of this Section 10.1.
ARTICLE XI
Emergency Bylaws
Section 11.1
During periods of emergency resulting from an attack on the United States or on a locality in which the Corporation conducts its business or customarily holds meetings of its Board of Directors or its stockholders, or during any nuclear or atomic disaster, or during the existence of any catastrophe, or other similar emergency condition, the provisions of this Article XI shall apply notwithstanding any different provisions elsewhere contained in these Bylaws.
Section 11.2
Whenever, during such emergency and as a result thereof, a quorum of the Board of Directors or a standing or special committee thereof cannot readily be convened for action, a meeting of such Board of Directors or committee thereof may be called by any officer of the Corporation or director by a notice of the time and place given only to such of the directors as it may be feasible to reach at the time and by such means as may be feasible at the time, including publications or radio. Three directors in attendance at the meeting shall constitute a quorum; provided, however, that the officers of the Corporation or other persons present who have been designated on a list approved by the Board of Directors before the emergency, all in such order of priority and subject to such conditions and for such period of time as may be provided in the resolution approving such list, or in the absence of such a resolution, the officers of the Corporation who are present, in order of rank, and within the same rank in order of seniority, shall to the extent required to provide a quorum be deemed directors for such meeting.
Section 11.3
The Board of Directors, both before or during any such emergency, may provide and modify lines of succession in the event that during such emergency any or all officers or agents of the Corporation shall for any reason be rendered incapable of discharging their duties.
Section 11.4
The Board of Directors, both before or during any such emergency, may, effective as of the emergency, change the principal executive office or designate several alternative principal executive offices or regional offices or authorize the officers of the Corporation so to do.
Section 11.5
No director or officer or employee of the Corporation acting in accordance with this Article XI shall be liable for any act or failure to act, except for willful misconduct.
Section 11.6
To the extent not inconsistent with this Article XI, all other Articles of these Bylaws shall remain in effect during any emergency described in this Article XI and, upon termination of the emergency, the provisions of this Article XI shall cease to be operative.
Exhibit 10.17
CHANGE IN CONTROL SEVERANCE COMPENSATION AGREEMENT
THE AGREEMENT
was made and entered into as of January 1, 2019, (the “
Effective Date
”), by and between Callon Petroleum Company, a Delaware corporation (the “
Company
”, and together with its subsidiaries, “
Callon
”) and ______________________ (“
Executive
”). Callon and Executive may be referred to individually herein as “
Party
” and collectively as “
Parties
”.
WITNESSETH:
WHEREAS
, Callon desires to assure fair treatment of its key executives in the event of a Change in Control (as defined below) and to allow them to make critical career decisions without undue time pressure and financial uncertainty, thereby increasing their willingness to remain with Callon notwithstanding the outcome of a possible Change in Control transaction; and
WHEREAS
, the Board of Directors of the Company (the “
Board
”) believes it is essential to provide the Executive with compensation arrangements upon a Change in Control which provide the Executive with individual financial security and which are competitive with those of other similar corporations, and in order to accomplish these objectives, the Board has caused Callon to enter into this Agreement;
NOW, THEREFORE
, in consideration of the mutual premises and conditions contained herein, the parties hereto agree as follows:
Article 1.
Term
This Agreement shall terminate, except to the extent that any obligation of Callon hereunder remains unpaid as of such time and Executive’s ongoing obligations pursuant to
Article 6
, upon the earliest of:
|
|
(a)
|
December 31, 2019; provided, however, that, commencing on December 31, 2019, and on each anniversary date thereafter (each such date, an “
Anniversary Date
”), the expiration date under this clause (i) shall automatically be extended for one additional year unless either party shall have given thirty (30) day written notice prior to such Anniversary Date that it does not wish to extend this Agreement; provided, however, that if the Agreement has not terminated prior to the date the Company enters into a definitive agreement that will result in a Change in Control or the date a Change in Control occurs, the expiration date under this clause shall not occur earlier than the second anniversary of the effective date of the Change in Control or the date the agreement to effectuate such Change in Control is terminated, as applicable;
|
|
|
(b)
|
The termination of the Executive’s employment with Callon based on death, Disability (as defined in
Section 3.1
), or Cause (as defined in
Section 3.2
);
|
|
|
(c)
|
The voluntary resignation of the Executive for any reason other than Good Reason (as defined in
Section 3.3
); and
|
|
|
(d)
|
Any termination of Executive’s employment prior to a Change in Control, except as expressly provided in
Article 2
.
|
Article 2.
Change in Control
Except as provided herein, no benefits shall be payable hereunder unless there shall have been a Change in Control (as defined below), and Executive’s employment by Callon shall thereafter have been terminated within two (2) years after the date of such Change in Control in accordance with
Article 3
.
For purposes hereof, a “
Change in Control
” means the occurrence of one or more of the following:
|
|
(a)
|
Change in Ownership
. A change in ownership of the Company occurs on the date that any Person, other than (1) the Company or any of its Subsidiaries, (2) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (3) an underwriter temporarily holding stock pursuant to an offering of such stock, or (4) a corporation owned, directly or indirectly, by the stockholders of the Company in substantially the same proportions as their ownership of the Company’s stock (each of (1) through (4) an “Exempt Person”), acquires ownership of the Company’s stock that, together with stock held by such Person, constitutes more than fifty percent (50%) of the total fair market value or total voting power of the Company’s Voting Stock. However, if any Person is considered to own already more than fifty percent (50%) of the total fair market value or total voting power of the Company’s Voting Stock, the acquisition of additional stock by the same Person is not considered to be a Change in Control. In addition, if any Person has effective control of the Company through ownership of thirty percent (30%) or more of the total voting power of the Company’s Voting Stock, as discussed in paragraph (b) below, the acquisition of additional control of the Company by the same Person is not considered to cause a Change in Control pursuant to this paragraph (a); or
|
|
|
(b)
|
Change in Effective Control
. Even though the Company may not have undergone a change in ownership under paragraph (a) above, a change in the effective control of the Company occurs on either of the following dates: (1) the date that any Person (other than an Exempt Person) acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of the Company’s stock possessing thirty percent (30%) or more of the total voting power of the Company’s Voting Stock. However, if any Person owns thirty percent (30%) or more of the total voting power of the Company’s Voting Stock, the acquisition of additional control of the Company by the same Person is not considered to cause a Change in Control pursuant to this subparagraph (b)(1); or (2) the date that during any period of three consecutive years, individuals who at the beginning of such period were members of the Board cease for any reason to constitute at least a majority thereof unless the election, or the nomination for election by the Company's stockholders, of each new director was approved by a vote of at least a majority of
|
the directors then still in office who were directors at the beginning of such period or whose election or nomination was previously so approved; provided, however, that any such director shall not be considered to be approved by the Board if his or her initial assumption of office occurs as a result of an actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or
|
|
(c)
|
Change in Ownership of Substantial Portion of Assets
. A change in the ownership of a substantial portion of the Company’s assets occurs on the date that a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) assets of the Company that have a total gross fair market value equal to at least forty percent (40%) of the total gross fair market value of all of the Company’s assets immediately before such acquisition or acquisitions. However, there is no Change in Control when there is such a transfer to an entity that is controlled by the stockholders of the Company immediately after the transfer, through a transfer to (1) a stockholder of the Company (immediately before the asset transfer) in exchange for or with respect to the Company stock; (2) an entity, at least fifty percent (50%) of the total value or voting power of the stock of which is owned, directly or indirectly, by the Company; (3) a Person that owns directly or indirectly, at least fifty percent (50%) of the total value or voting power of the Company’s outstanding Voting Stock; or (4) an entity, at least fifty percent (50%) of the total value or voting power of the stock of which is owned by a Person that owns, directly or indirectly, at least fifty percent (50%) of the total value or voting power of the Company’s outstanding Voting Stock.
|
“
Affiliate
” has the same meaning ascribed to such term in Rule 12b-2 under the Exchange Act.
“
Exchange Act
” means the Securities Exchange Act of 1934, as amended from time to time.
“
Person
” shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act and used in Sections 13(d) and 14(d) thereof, including a “group” as defined in Section 13(d) thereof.
“
Subsidiary
” means (i) in the case of a corporation, any corporation of which the Company directly or indirectly owns shares representing more than 50% of the combined voting power of the shares of all classes or series of capital stock of such corporation which have the right to vote generally on matters submitted to a vote of the stockholders of such corporation and (ii) in the case of a partnership or other business entity not organized as a corporation, any such business entity of which the Company directly or indirectly owns more than 50% of the voting, capital or profits interests (whether in the form of partnership interests, membership interests or otherwise).
“
Voting Stock
” shall mean stock of any class or kind having the power to vote generally for the election of directors.
If the Executive’s employment with Callon is terminated by Callon for reasons other than Cause or Disability in accordance with the provisions of
Article 3
within the six (6) month period prior to the date on which a Change in Control is effective, and it is reasonably demonstrated that
such termination: (i) was at the request of a third party who has taken steps reasonably calculated to effectuate a Change in Control or (ii) otherwise arose in connection with a Change in Control, then for all purposes hereof, such termination shall be deemed to have occurred following a Change in Control (for purposes of this Agreement, a “Deemed Eligible Termination”).
Notwithstanding the foregoing provisions of
Article 2
, with respect to any payment hereunder that is (i) subject to Section 409A of the Internal Revenue Code of 1986, as amended (the “
Code
”) and (ii) a Change of Control which would accelerate the timing of such payment, the term “Change of Control” shall mean a change in the ownership or effective control of Callon, or in the ownership of a substantial portion of the assets of Callon as defined under Code Section 409A, but only to the extent inconsistent with the above definition and to the minimum extent necessary to comply with Section 409A, as determined by Callon.
Article 3.
Termination of Employment Following a Change in Control
If a Change in Control shall have occurred and Executive’s employment is subsequently terminated within two (2) years following the date of such Change in Control, (i) by Callon other than for Cause (as defined in
Section 3.2
) or Disability (as defined in
Section 3.1
) or (ii) by Executive for Good Reason (as defined in
Section 3.3
), Executive shall be entitled to the benefits provided in
Articles 4 and 5
, subject to the additional requirements set forth therein. For the avoidance of doubt, no benefits will be payable hereunder on a termination of Executive’s employment due to Disability or death, due to termination by Callon for Cause, or due to Executive’s voluntary termination of employment without Good Reason.
3.1 Disability
. If, upon the Disability (as defined below) of Executive, and within thirty (30) days after written Notice of Termination (as defined in
Section 3.4
) is given, Executive has not returned to the full-time performance of his employment duties, Callon may terminate Executive’s employment for Disability. For purposes of this Agreement, “
Disability
” is defined as the physical or mental inability of Executive to carry out the normal and usual duties of his employment on a full-time basis for an entire period of six (6) continuous months, together with the reasonable likelihood, as determined by the Board upon the advice of a physician selected or approved by the Board, that Executive will be unable to carry out the normal and usual duties of his employment on a full-time basis for the next following continuous period of six (6) months.
3.2 Cause
. For purposes hereof, “
Cause
” is defined as: (i) the conviction of the Executive by a court of competent jurisdiction as to which no further appeal can be taken of a crime involving moral turpitude or a felony or entering the plea of nolo contendere to such crime by the Executive; (ii) the commission by the Executive of a material act of fraud upon Callon; (iii) the material misappropriation by the Executive of any funds or other property of Callon; (iv) the knowing engagement by the Executive without the written approval of the Board, in any material activity which directly competes with the business of Callon, or which would directly result in material injury to the business or reputation of Callon; (v)(1) a material breach by the Executive during the Executive’s employment with Callon of any of the restrictive covenants set out in the Executive’s employment agreement with the Company, if applicable, or (2) the willful and material nonperformance of the Executive’s duties to Callon (other than by reason of the Executive’s illness or incapacity), and, for purposes of this clause (v), no act or failure to act on Executive’s part shall
be deemed “willful” unless it is done or omitted by the Executive not in good faith and without his reasonable belief that such action or omission was in the best interest of Callon, (vi) any breach of the Executive’s fiduciary duties to Callon, including, without limitation, the duties of care, loyalty and obedience to the law; and (vii) the intentional failure of the Executive to comply with Callon’s Code of Business Conduct and Ethics, or to otherwise discharge his duties in good faith and in a manner that the Executive reasonably believes to be in the best interests of Callon, and with the care an ordinarily prudent person in a like position would exercise under similar circumstances.
3.3 Good Reason
. Subject to
Section 3.4
, Executive may terminate his employment for Good Reason. For purposes of this Agreement, “
Good Reason
” shall mean any of the following:
|
|
(a)
|
Following a Change in Control, a material diminution in the scope, nature or status of Executive’s responsibilities;
|
|
|
(b)
|
Following a Change in Control, (1) a reduction in Executive’s base salary as in effect on the date of a Change in Control or as the same may be increased from time to time thereafter, or (2) a failure by Callon to continue to provide Executive with compensation and benefits that do not represent a material reduction, either in amount of compensation opportunity and benefits provided or the level of the Executive’s participation relative to other participants, in the compensation and benefits provided immediately prior to the Change in Control;
|
|
|
(c)
|
Following a Change in Control, Executive’s relocation by Callon to a location in excess of 50 miles from the location where Executive was based immediately prior to the Change in Control, except for a relocation consented to by Executive, if all reasonable costs of relocation, including moving expenses, costs of selling a principal residence (and, if requested by Executive, the purchase of such principal residence at its then-appraised value as appraised by a qualified and licensed appraiser selected by Executive) are paid or provided for by Callon;
|
|
|
(d)
|
Following a Change in Control, the failure by Callon to continue in effect any compensation plan in which Executive participates unless an equitable arrangement (embodied in an ongoing substitute or alternative plan) has been made with respect to such plan in connection with a Change in Control, or the failure of Callon to continue Executive’s participation therein or the taking of any action by Callon which would materially and adversely affect Executive’s participation in any such plan or reduce Executive’s benefits thereunder;
|
|
|
(e)
|
Following a Change in Control, the failure by Callon to continue to provide Executive with benefits not less, in the aggregate, than those enjoyed under any of Callon’s pension, life insurance, medical, health, and accident, or disability plans in which Executive was participating at the time of a Change in Control or the taking of any action by Callon which would directly or indirectly materially reduce any such benefits;
|
|
|
(f)
|
The failure of Callon to obtain a satisfactory agreement from any successor or parent thereof to assume and agree to perform this Agreement pursuant to
Article 7
; or
|
|
|
(g)
|
Any purported termination of Executive’s employment with Callon which is not effected pursuant to a Notice of Termination satisfying the requirements of
Section 3.4
(and for purposes of this Agreement, no such purported termination shall be effective).
|
Notwithstanding the foregoing definition of “Good Reason”, the Executive cannot terminate his employment hereunder for Good Reason unless the Executive (1) first notifies the Board in writing of the event (or events) which the Executive believes constitutes a Good Reason event under
clauses (a) through (g)
(above) within sixty (60) calendar days from the date of such event, and (2) provides Callon with at least thirty (30) calendar days to cure, correct or mitigate the Good Reason event so that it either (A) does not constitute a Good Reason event hereunder or (B) the Executive specifically agrees, in writing, that after any such modification or accommodation made by Callon, such event does not constitute a Good Reason event hereunder.
The Executive’s mental or physical incapacity following the occurrence of any of the circumstances described in
clauses (a) through (g)
(above) shall not affect the Executive’s ability to terminate employment for Good Reason, and the Executive’s death following delivery of a Notice of Termination for Good Reason shall not affect his designated beneficiary’s entitlement to any benefits provided hereunder upon a termination of employment for Good Reason. Notwithstanding anything herein to the contrary, the Executive’s resignation under this Agreement, with or without Good Reason, shall not affect the Executive’s eligibility to receive benefits under any retirement or pension plan of Callon or its Affiliates.
3.4 Notice of Termination
. Any termination pursuant to the foregoing provisions of this
Article 3
(excluding a termination due to Executive’s death) shall be communicated by written Notice of Termination to the other party hereto. For purposes hereof, a “
Notice of Termination
” shall mean a notice which shall indicate the specific termination provision herein relied upon and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Executive’s employment under the provision so indicated. In the event that Executive seeks to terminate his employment with Callon pursuant to
Section 3.3
, he must communicate his written Notice of Termination to Callon within sixty (60) days of being notified of such action or actions by Callon which constitute Good Reason for termination.
3.5 Date of Termination
. The term “
Date of Termination
” shall mean: (i) if this Agreement is terminated for Disability, thirty (30) days after Notice of Termination is given (provided that Executive has not returned to the performance of his duties on a full-time basis during such thirty (30) day period); or (ii) if Executive’s employment is terminated pursuant to
Section 3.3
, or if Executive’s employment is terminated for any other reason, the date that Executive incurs a “separation from service” (as such term is defined in final Treasury Regulations issued under Code Section 409A and any other authoritative guidance issued thereunder), as determined by Callon.
3.6 Reimbursement of Expenses
. To the extent this Agreement provides for the reimbursement of expenses which are not specifically excluded from Code Section 409A, (i) the amount of expenses eligible for reimbursement during the Executive’s taxable year shall not affect the expenses eligible for reimbursement in any other taxable year and (ii) the reimbursement shall
be made not later than by December 31st of the year following the calendar year in which such expense was incurred by the Executive.
Article 4.
Compensation Upon Termination
4.1 Termination without Cause or for Good Reason
. If a Change in Control shall have occurred and Executive’s employment is subsequently terminated under circumstances described in the first paragraph of
Article 3
, or if Executive incurs a Deemed Eligible Termination, Executive shall be entitled to the following benefits, provided that within fifty (50) days following the Date of Termination Executive signs a general release in substantially the form set forth on Exhibit A, and Executive affirmatively agrees not to violate the provisions of
Article 6
:
|
|
(a)
|
Callon shall pay to the Executive in a lump sum, in cash, on the date which is six (6) months following his Date of Termination, an amount equal to two (2) times the sum of: (i) the Executive’s annual base salary as in effect immediately prior to the Change in Control or, if higher, in effect immediately prior to the Date of Termination, and (ii) the greatest of: (A) the average bonus (under all Callon bonus plans for which the Executive is eligible) earned with respect to the three (3) most recently completed full fiscal years, (B) the target bonus (under all Callon bonus plans for which the Executive is eligible) for the fiscal year in which the Change in Control occurs or (C) the target bonus (under all Callon bonus plans for which the Executive is eligible) for the fiscal year in which the Date of Termination occurs.
|
|
|
(b)
|
Callon shall, at its expense, maintain in full force and effect for Executive’s continued benefit until twenty-four (24) months after the Date of Termination all medical, dental, and vision insurance coverage to which Executive was entitled immediately prior to the Notice of Termination. The continued coverage under this
Section 4.1(b)
shall be provided in a manner that is intended to satisfy an exception to Section 409A of the Code, and therefore not treated as an arrangement providing for nonqualified deferred compensation that is subject to taxation under Code Section 409A, including (i) providing such benefits on a nontaxable basis to Executive, (ii) providing for the reimbursement of medical expenses incurred during the time period during which Executive would be entitled to continuation coverage under a group health plan of Callon pursuant to Section 4980B of the Code (i.e., COBRA continuation coverage), (iii) providing that such benefits constitute the reimbursement or provision of in-kind benefits payable at a specified time or pursuant to a fixed schedule as permitted under Code Section 409A and the authoritative guidance thereunder, or (4) such other manner as determined by Callon in compliance with an exception from being treated as nonqualified deferred compensation subject to Code Section 409A. Further, the continued coverage under this Section 4.1(b) shall be provided as alternative coverage to continuation coverage under Section 4980B of the Code (“COBRA”) and if Executive accepts such continued coverage under this Section 4.1(b), he or she will be deemed to have declined COBRA continuation coverage. In the event of a Deemed Eligible Termination, (i) the Executive will be entitled to a make-up payment (paid on the date the Executive’s severance payment is made pursuant to Section 4.1(a)) in an amount equal to the value of the coverage that would
|
have been provided from the Date of Termination until the date of the Change in Control had Executive been treated as eligible for benefits pursuant to Section 4.1(b) as of the Date of Termination, and (ii) Executive’s benefits pursuant to this Section 4.1(b) will begin as of the date of the Change in Control.
|
|
(c)
|
Callon’s obligation to pay severance amounts due to the Executive pursuant to this
Section 4.1
, to the extent not already paid, shall cease immediately and such payments will be forfeited if the Executive violates any of the covenants or conditions described in
Sections 6.1
,
6.2
or
6.3
after the Date of Termination.
|
4.2 Limitation on Payments
.
(a)
Definitions
. For purposes of this
Section 4.2
, the following capitalized terms have the meanings ascribed to them, below.
“
Excise Tax
” means the excise tax imposed by Section 4999 of the Code with respect to the Total Payments together with any interest or penalties with respect to such excise tax.
“
Incentive Award
” means a stock option, stock appreciation right, restricted stock award, restricted stock unit award, or other equity-type award under any plan or agreement in which Executive has, or will (by the passage of time only and not based on Executive’s performance) have, an interest in the capital stock of Callon or an Affiliate, or a right to obtain capital stock or an interest in capital stock of Callon or an Affiliate.
“
Net After-Tax Benefit
” means (i) the Total Payments less (ii) the amount of all United States federal, state and local income and employment taxes payable with respect to the Total Payments (calculated at the maximum applicable marginal income tax rate for Executive under the Code), and less (iii) the amount of the Excise Tax imposed (based upon the rate for such year as set forth in the Code at the time of the first payment of the foregoing).
“
Total Payments
” means the total payments or other benefits that Executive becomes entitled to receive from Callon or an Affiliate in connection with a Change in Control that would constitute a “parachute payment” (within the meaning of Section 280G of the Code), whether payable pursuant to the terms of this Agreement or any other plan, arrangement, or agreement with Callon or an Affiliate.
(b)
Maximum Net After-Tax Benefit
. The Total Payments shall be reduced to the minimum extent necessary so that no portion of the Total Payments shall be subject to the Excise Tax, but only if, by reason of such reduction, the Net After-Tax Benefit received by Executive as a result of such reduction will exceed the Net After-Tax Benefit that would have been received by Executive if no such reduction was made. It is thus the objective of this Agreement to maximize Executive’s Net After-Tax Benefit if any payments or benefits provided hereunder are subject to the Excise Tax.
In the event it is determined that the Total Payments to or for the benefit of Executive, whether paid or payable or distributed or distributable or otherwise, including, by example and not by way of limitation, acceleration of the date of vesting or payment or rate of payment under any plan, program or arrangement of Callon, would be subject to the Excise Tax, Callon shall first make
a calculation under which such payments or benefits provided to Executive under this Agreement are reduced, to the minimum extent necessary, so that no portion thereof shall be subject to the Excise Tax (the “
Section 4999 Limit
”). Callon shall then compare (i) Executive’s Net After-Tax Benefit assuming application of the Section 4999 Limit with (ii) Executive’s Net After-Tax Benefit without the application of the Section 4999 Limit. In the event (i) is greater than (ii), Executive shall receive Total Payments solely up to the 4999 Limit. In the event (ii) is greater than (i), Executive shall be entitled to receive all such Total Payments, and shall be solely liable for any and all Excise Tax related thereto.
All determinations required to be made under this
Section 4.2
, including whether an Excise Tax may apply to the Total Payments, will be made by the independent accounting firm which served as Callon’s auditor immediately prior to the Change in Control (the “
Accounting Firm
”). All fees and expenses of the Accounting Firm shall be borne solely by Callon and it shall be Callon’s obligation to cause the Accounting Firm to take any actions required hereby.
Callon will direct the Accounting Firm to submit detailed supporting calculations both to Callon and the Executive within fifteen (15) business days after the Date of Termination, if applicable, or such earlier time as is requested by Callon. If applicable, Executive and Callon shall each provide the Accounting Firm with access to, and copies of, any books, records and documents in their respective possessions, as reasonably requested by the Accounting Firm, and otherwise reasonably cooperate with the Accounting Firm in connection with the preparation and issuance of the determinations and calculations contemplated by this
Section 4.2
.
If the Accounting Firm determines that a reduction in payments is required under this
Section 4.2
, Callon shall (to the extent feasible) reduce the Total Payments in the following order: (i) reduction of any cash severance payments otherwise payable to Executive that are exempt from Section 409A of the Code; (ii) reduction of any other cash payments or benefits otherwise payable to Executive that are exempt from Section 409A of the Code, but excluding any payments attributable to any acceleration of vesting or payments with respect to any Incentive Award that are exempt from Section 409A of the Code; (iii) reduction of any other payments or benefits otherwise payable to Executive on a prorata basis or in such other manner that complies with Section 409A of the Code, but excluding any payments attributable to any acceleration of vesting and payments with respect to any Incentive Award that are exempt from Section 409A of the Code; and (iv) reduction of any payments attributable to any acceleration of vesting or payments with respect to any Incentive Award that are exempt from Section 409A of the Code, in each case beginning with payments that would otherwise be made last in time.
If the Accounting Firm determines that no Excise Tax is payable by Executive, it shall furnish Executive with an opinion that he has substantial authority not to report any Excise Tax on his federal income tax return.
4.3 No Mitigation or Set-off of Amounts Payable Hereunder
. Executive shall not be required to mitigate the amount of any payment provided for in this
Article 4
by seeking other employment or otherwise, nor shall the amount of any payment provided for in this
Article 4
be reduced by any compensation earned by Executive as the result of employment by another employer after the Date of Termination, or otherwise. Callon’s obligations hereunder also shall not be affected
by any set-off, counterclaim, recoupment, defense, or other claim, right or action which Callon may have against Executive.
Article 5.
Stock Options and Other Plans
5.1 Acceleration of Benefits
. If Executive is eligible for severance payments pursuant to
Section 4.1
, the following shall automatically occur effective as of the sixtieth (60
th
) day following the Date of Termination, subject to delayed payment as may be required pursuant to Article 14:
|
|
(a)
|
Notwithstanding any provision to the contrary in any stock incentive plan, stock option agreement, restricted stock agreement, or other applicable plan or agreement between Executive and Callon, all outstanding units, stock options, incentive stock options, performance shares, performance awards, stock appreciation rights, career shares, bridge shares, and shares of restricted stock (the “
Stock Rights
”) then held by Executive shall immediately become exercisable and Executive shall become one hundred percent (100%) vested in such Stock Rights held by or for the benefit of Executive, with any performance-based Stock Rights earned at the level specified in the applicable award agreement or, if not specified, at the target level; provided, however, that such Stock Rights shall not be accelerated if it would be an impermissible acceleration under Section 409A of the Code, but will be paid at the earliest permissible payment event consistent with the terms of the award and the requirements of Section 409A of the Code.
|
|
|
(b)
|
Notwithstanding any provision to the contrary in any stock option agreement between Executive and Callon, Executive’s right to exercise any previously unexercised and outstanding option under any stock option agreement shall not terminate until the latest date on which such option would expire under the terms of such agreement but for Executive’s termination of employment.
|
|
|
(c)
|
In the event Executive incurs a Deemed Eligible Termination and equity awards that would have been accelerated or exercisability extended pursuant to this
Article 5
have been forfeited as a result of Executive's earlier termination of employment, then Executive shall be entitled to a cash payment equal to (i) the value of any forfeited equity award, determined based on the cash or market value of the number of securities that would have been delivered to Executive pursuant to such award, in each case assuming the awards were vested and delivered (and, if applicable, exercised) as of the date Executive's severance payments are made pursuant to this Agreement (or, with respect to any option, the last day of the original option term, if earlier), reduced by (ii) the amount of any payment previously made in connection with the vesting or exercise of such award.
|
|
|
Article 6.
|
Noncompetition, Nonsolicitation, Nondisclosure of Trade Secrets, Nonpublic Information, and Ownership
|
6.1 Noncompetition
. The Executive agrees that, if he becomes eligible for severance payments pursuant to Section 4.1, for a period of one year after the Date of Termination, he will not, directly or indirectly, compete with Callon by providing services to any other person,
partnership, association, corporation, or other entity that is an “Oil and Gas Business” in any geographic location where Callon operated as of the Date of Termination. As used herein, an “
Oil and Gas Business
” means owning, managing, acquiring, attempting to acquire, soliciting the acquisition of, operating, controlling, or developing Oil and Gas interests, or engaging in or being connected with, as a principal, owner, officer, director, employee, shareholder, promoter, consultant, contractor, partner, member, joint venture, agent, equity owner or in any other capacity whatsoever, any of the foregoing activities of the oil and gas exploration and production business. The parties agree that the above restrictions on competition are completely severable and independent agreements supported by good and valuable consideration and, as such, shall survive the termination of this Agreement for whatever reason. The parties further agree that any invalidity or unenforceability of any one or more of such restrictions on competition shall not render invalid or unenforceable any remaining restrictions on competition. Additionally, should a court of competent jurisdiction determine that the scope of any provision of this
Section 6.1
is too broad to be enforced as written, the parties intend that the court reform the provision to such narrower scope as it determines to be reasonable and enforceable.
6.2 Nonsolicitation
. If the Executive becomes eligible for severance payments pursuant to Section 4.1, for a period of two (2) years after the Date of Termination, the Executive shall not, on his own behalf or on behalf of any other person, partnership, association, corporation, or other entity: (a) directly, indirectly, or through a third party hire or cause to be hired; (b) directly, indirectly, or through a third party solicit; or (c) in any manner attempt to influence or induce any employee of Callon to leave the employment of Callon, nor shall he use or disclose to any person, partnership, association, corporation, or other entity any information obtained concerning the names and addresses Callon’s employees. The parties agree that the above restrictions on hiring and solicitation are completely severable and independent agreements supported by good and valuable consideration and, as such, shall survive the termination of this Agreement for whatever reason. The parties further agree that any invalidity or unenforceability of any one or more such restrictions on hiring and solicitation shall not render invalid or unenforceable any remaining restrictions on hiring and solicitation. Additionally, should a court of competent jurisdiction determine that the scope of any provision of this
Section 6.2
is too broad to be enforced as written, the parties intend that the court reform the provision to such narrower scope as it determines to be reasonable and enforceable.
6.3 Nondisclosure of Trade Secrets
. Callon promises to disclose to the Executive and the Executive acknowledges that in, and as a result of, his employment by Callon, he will receive, make use of, acquire, have access to and/or become familiar with, various trade secrets and proprietary and confidential information of Callon, including, but not limited to, processes, computer programs, compilations of information, records, financial information, sales reports, sales procedures, customer requirements, pricing techniques, customer lists, method of doing business, identities, locations, performance and compensation levels of employees, and other confidential information (individually and collectively, “
Trade Secrets
”) which are owned by Callon and used in the operation of its business, and as to which Callon takes precautions to prevent dissemination to persons other than certain directors, officers, and employees. The Executive acknowledges and agrees that the Trade Secrets:
|
|
(a)
|
Are secret and not known in the industry;
|
|
|
(b)
|
Give Callon an advantage over competitors who do not know or use the Trade Secrets;
|
|
|
(c)
|
Are of such value and nature as to make it reasonable and necessary to protect and preserve the confidentiality and secrecy of the Trade Secrets; and
|
|
|
(d)
|
Are valuable, special, and unique assets of Callon, the disclosure of which could cause substantial injury and loss of profits and goodwill to Callon.
|
The Executive promises not to use in any way or disclose any of the Trade Secrets and confidential and proprietary information, directly or indirectly, either during or after the term of his employment, except as required in the course of his employment with Callon, if required in connection with a judicial or administrative proceeding, or if the information becomes public knowledge other than as a result of an unauthorized disclosure by the Executive. All files, records, documents, information, data, and similar items relating to the business of Callon, whether prepared by the Executive or otherwise coming into his possession, will remain the exclusive property of Callon and may not be removed from the premises of Callon under any circumstances without the prior written consent of Callon (except in the ordinary course of business during the Executive’s period of active employment under this Agreement), and in any event must be promptly delivered to Callon upon termination of the Executive’s employment with Callon. The Executive agrees that upon his receipt of any subpoena, process, or other requests to produce or divulge, directly or indirectly, any Trade Secrets to any entity, agency, tribunal, or person, whether received during or after the term of the Executive’s employment with Callon, the Executive shall timely notify and promptly deliver a copy of the subpoena, process, or other request to Callon. For this purpose, the Executive irrevocably nominates and appoints Callon (including any attorney retained by Callon), as his true and lawful attorney-in-fact, to act in the Executive’s name, place, and stead to perform any act that the Executive might perform to defend and protect against any disclosure of any Trade Secrets.
The parties agree that the above restrictions on confidentiality and disclosure are completely severable and independent agreements supported by good and valuable consideration and, as such, shall survive the termination of this Agreement for whatever reason. The parties further agree that any invalidity or unenforceability of any one or more of such restrictions on confidentiality and disclosure shall not render invalid or unenforceable any remaining restrictions on confidentiality and disclosure. Additionally, should a court of competent jurisdiction determine that the scope of any provision of this
Section 6.3
is too broad to be enforced as written, the parties intend that the court reform the provision to such narrower scope as it determines to be reasonable and enforceable.
6.4 Ownership
. The Executive agrees that all inventions, copyrightable material, business and/or technical information, marketing plans, customer lists, and trade secrets which arise out of the performance of this Agreement are the property of Callon.
6.5 No Disparaging Comments
. Executive and Callon shall refrain from any criticisms or disparaging comments about each other or in any way relating to Executive's employment or separation from employment with Callon; provided, however, that nothing in this Agreement shall apply to or restrict in any way the communication of information to any governmental law enforcement agency by either party that is required by compulsion of law. A violation or threatened violation of this prohibition may be enjoined by a court of competent jurisdiction. The rights under
this provision are in addition to any and all rights and remedies otherwise afforded by law to the parties.
Executive acknowledges that in executing this Agreement, he has knowingly, voluntarily, and intelligently waived any free speech, free association, free press or First Amendment to the United States Constitution (including, without limitation, any counterpart or similar provision or right under any other state constitution which may be deemed to apply) and rights to disclose, communicate, or publish disparaging information or comments concerning or related to Callon; provided, however, nothing in this Agreement shall be deemed to prevent Executive from testifying fully and truthfully in response to a subpoena from any court or from responding to an investigative inquiry from any governmental agency.
For all purposes of the obligations of Executive under this
Section 6.5
, the term “Callon” refers to the Callon Petroleum Company and its Subsidiaries and Affiliates, and its and their directors, officers, employees, shareholders, investors, partners and agents.
6.6 Protected Disclosures
. Notwithstanding anything herein to the contrary, nothing in this Agreement will be construed to prohibit the Executive from reporting possible violations of law or regulation to any governmental agency or regulatory body or making other disclosures that are protected under any law or regulation, or from filing a charge with or participating in any investigation or proceeding conducted by any governmental agency or regulatory body. This Agreement does not limit the Executive’s right to receive an award for information provided to any governmental agency or regulatory body. Further, in accordance with the Defend Trade Secrets Act, the Executive may not be held criminally or civilly liable under any Federal or state trade secret law for the disclosure of a trade secret that is made in confidence to a Federal, state, or local government official, either directly or indirectly, or to an attorney, and solely for the purpose of reporting or investigating a suspected violation of law; or that is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is made under seal.
6.7 Subsidiaries and Affiliates Included
. Except where otherwise expressly provided, for all purposes of the obligations of Executive under this
Article 6
, the term “Callon” refers to the Callon Petroleum Company and its Subsidiaries and Affiliates.
Article 7.
Successors; Binding Agreement
7.1 Successors of Callon
. Callon will require any successor (whether direct or indirect, by purchase, merger, consolidation, or otherwise) to all or substantially all of the business and/or assets of Callon, by agreement in form and substance satisfactory to Executive, expressly to assume and agree to perform this Agreement in the same manner and to the same extent that Callon would be required to perform it if no such succession had taken place. Failure of Callon to obtain such agreement prior to the effectiveness of any such succession shall be a breach hereof and shall entitle Executive to compensation from Callon in the same amount and on the same terms as Executive would be entitled hereunder if Executive terminated his employment for Good Reason, the date on which any such succession becomes effective shall be deemed the Date of Termination; provided however, that such compensation shall be paid to Executive only if such successor is a considered to be a successor to Callon by reason of a Change in Control. As used herein, “
Callon Petroleum Company
” shall mean Callon as hereinbefore defined and any successor to its business and/or assets
as aforesaid which executes and delivers the agreement provided for in this
Section 7.1
, or which otherwise becomes bound by all the terms and provisions hereof by operation of law. Wherever appropriate to the intention of the parties, the respective rights and obligations of the parties hereunder shall survive any termination or expiration of this Agreement.
7.2 Executive’s Heirs, Etc.
This Agreement shall inure to the benefit of and be enforceable by Executive’s personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees, and legatees. If Executive should die while any amounts would still be payable to him hereunder as if he had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms hereof to his designee or, if there be no such designee, to his estate upon prior receipt by Callon of a proper notice regarding the legal representative of such estate.
Article 8.
Notice
For the purposes hereof, notices and all other communications provided for herein shall be in writing and shall be deemed to have been duly given when delivered or mailed. Each notice or other communication required or permitted under this Agreement shall be in writing and transmitted or delivered by personal delivery, prepaid courier or messenger service (whether overnight or same-day), prepaid telecopy or facsimile, or prepaid certified or registered United States mail (with return receipt requested), addressed to Callon at its principal place of business and to Executive at his address as shown on the records of Callon, provided that all notices to Callon shall be directed to the attention of the Chief Executive Officer of Callon with a copy to the Secretary of Callon, or to such other address provided in writing in accordance herewith, except that notices of change of address shall be effective only upon receipt, or at such other address as the recipient has designated by notice to the other party.
Each notice or communication so transmitted, delivered, or sent in person, by courier or messenger service, or by certified United States mail, shall be deemed given, received, and effective on the date delivered to or refused by the intended recipient (with the return receipt, or the equivalent record of the courier or messenger, being deemed conclusive evidence of delivery or refusal.) Nevertheless, if the date of delivery is after 5:00 p.m. (local time of the recipient) on a business day, the notice or other communication shall be deemed given, received and effective on the next business day.
Article 9.
Miscellaneous
9.1 Waiver and Amendment
. No provisions hereof may be amended, modified, waived, or discharged unless such amendment, waiver, modification, or discharge is agreed to in writing and signed by Executive and such officer as may be specifically designated by the Board (which shall in any event include Callon’s Chairman of the Board). No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision hereof, to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. No agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made by either party which are not set forth expressly herein.
9.2 Tax Consequences
. Callon or its affiliate shall withhold from any payments or benefits under this Agreement (whether or not otherwise acknowledged under this Agreement) all federal, state, local, or other taxes that it is required to withhold.
Executive understands, acknowledges, and agrees that Company cannot, and does not, provide any tax or legal advice to Executive. Any tax-related information that has been provided, or will be provided, to Executive is solely for informational purposes and should not be relied upon by Executive. Executive acknowledges that he has reviewed with his own tax advisors the tax consequences of this Agreement and the transactions contemplated hereby. Executive is relying solely on his tax advisors and not on any statements or representations of Callon or any of its agents and understands that Executive (and not Callon) shall be responsible for Executive’s own tax liability that may arise as a result of this Agreement or the transactions contemplated hereby, except as otherwise specifically provided in this Agreement.
9.3 Employment Status
. Nothing in this Agreement provides the Executive with any right to continued employment with Callon or any of its affiliates, or shall interfere with the right of Callon or an affiliate to terminate the Executive’s employment at any time subject to Callon’s obligations under this Agreement.
9.4 No Exclusivity
. Except as expressly provided herein, this Agreement shall not prevent or limit the Executive’s participation in any other plan or arrangement maintained by Callon for which the Executive qualifies, nor shall it impair any rights that the Executive may have under any other plan, program, contract or agreement with Callon or any of its affiliates.
9.5 Reformation and Severability
. The Parties fully intend that this Agreement comply with all applicable laws and legal requirements. Should any provision of this Agreement be declared or be determined by any court of competent jurisdiction to be illegal, invalid or unenforceable, the Agreement shall first be reformed to make the provision at issue enforceable and effective to the full extent permitted by law. If such reformation is not possible, all remaining provisions of this Agreement shall otherwise remain in full force and effect and shall be construed as if such illegal, invalid, or unenforceable provision has not been included herein.
9.6 Entire Agreement
. This Agreement sets forth the entire agreement of the Parties and fully supersedes and replaces any and all prior agreements, promises, representations, or understandings, written or oral, between Callon and Executive relating to the subject matter of this Agreement including, without limitation, the Severance Compensation Agreement between Executive and the Company effective as of and as thereafter amended. This Agreement may be amended or modified only by a written instrument identified as an amendment hereto that is executed by both Executive and by the Chairman of the Board (or another officer who is authorized by the Board) on behalf of Callon.
9.7 Executive Acknowledgment
. Executive acknowledges that (a) he is knowledgeable and sophisticated as to business matters, including the subject matter of this Agreement, (b) he has read this Agreement and understands its terms and conditions, (c) he has had ample opportunity to review and discuss this Agreement with legal counsel of his choice prior to execution should he desire to do so, and (d) no strict rules of construction will apply for or against the drafter or any
other party. Executive represents that there are no restrictions on his right to enter into this Agreement.
Article 10.
Validity
The invalidity or unenforceability of any provision hereof shall not affect the validity or enforceability of any other provision hereof, which shall remain in full force and effect.
Article 11.
Counterparts
This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original but all of which together will constitute one and the same instrument.
Article 12.
Governing Law; Jurisdiction
All matters or issues relating to the interpretation, construction, validity, and enforcement of this Agreement shall be governed by the laws of the State of Texas, without giving effect to any choice-of-law principle that would cause the application of the laws of any jurisdiction other than Texas. Jurisdiction and venue of any action or proceeding relating to this Agreement or any Dispute shall be exclusively in the State of Texas (unless otherwise mutually agreed by the parties), and the parties hereby waive any objection to such jurisdiction or venue including, without limitation, to the effect that the location is inconvenient.
Article 13.
Interpretative Matters
In the interpretation of the Agreement, except where the context otherwise requires:
|
|
(a)
|
“
including
” or “
include
” does not denote or imply any limitation;
|
|
|
(b)
|
“
or
” has the inclusive meaning “and/or”;
|
|
|
(c)
|
the singular includes the plural, and vice versa, and each gender includes each of the others;
|
|
|
(d)
|
captions or headings are for reference purposes only, and they are not to be considered in interpreting the Agreement;
|
|
|
(e)
|
“
Section
” refers to a Section of the Agreement, unless otherwise stated in the Agreement;
|
|
|
(f)
|
“
month
” refers to a calendar month; and
|
|
|
(g)
|
a reference to any statute, rule, or regulation includes (1) any amendment thereto, (2) any statute, rule, or regulation enacted or promulgated in replacement thereof, and (3) any regulation or other authority issued by the appropriate governmental entity under, or with respect to, a statute.
|
Article 14.
Compliance with Section 409A
Any provisions of the Agreement that are subject to Section 409A of the Code (“
Section 409A
”) are intended to comply with all applicable requirements of Section 409A, or an exemption from the application of Section 409A, and shall be interpreted and administered accordingly. Any ambiguous provision will be construed in a manner that is compliant with, or exempt from, the application of Section 409A. Notwithstanding any provision of this Agreement to the contrary, a termination of employment shall not be deemed to have occurred for purposes of any provision of this Agreement providing for the payment of any amount or benefit that constitutes “non-qualified deferred compensation” (within the meaning of Section 409A) upon or following a termination of the Executive’s employment unless such termination is also a “separation from service” within the meaning of Section 409A and, for purposes of any such provision, references herein to a “termination,” “termination of employment” or like terms shall mean “separation from service” within the meaning of Section 409A.
Notwithstanding any provision of this Agreement to the contrary, if any payment or other benefit provided herein would be subject to additional taxes and interest under Section 409A because the timing of such payment is not delayed as required by Section 409A for a “specified employee,” then if the Executive is on the applicable date a specified employee, any such payment that the Executive would otherwise be entitled to receive during the first six months following his “separation from service” (as defined under Section 409A) shall be accumulated and paid, within ten (10) days after the date that is six months following the Executive’s date of “separation from service,” or such earlier date upon which such amount can be paid under Section 409A without being subject to such additional taxes and interest such as, for example, upon the Executive’s death.
With respect to any amounts or benefits that are subject to Section 409A, this Agreement shall in all respects be administered in accordance with Section 409A. Each payment under this Agreement shall be treated as a separate payment for purposes of Section 409A. In no event may the Executive, directly or indirectly, designate the calendar year of any payment to be made under this Agreement.
All reimbursements and in-kind benefits provided under this Agreement that constitute deferred compensation within the meaning of Section 409A shall be made or provided in accordance with the requirements of Section 409A. Within the time period permitted by Section 409A, Callon may, in consultation with the Executive, modify the Agreement in the least restrictive manner necessary and without any diminution in the value of payments or other benefits to the Executive hereunder, in order to avoid the imposition of accelerated tax, additional tax and/or penalties on the Executive under Section 409A.
[Next page is signature page]
IN WITNESS WHEREOF
, the Parties hereto have executed this amended and restated Agreement on the dates set forth below, to be effective as of the Effective Date.
|
|
|
|
CALLON PETROLEUM COMPANY
|
|
|
|
|
By:
|
|
|
|
L. Richard Flury
|
|
|
Chairman of the Board
|
|
|
|
|
Date:
|
|
|
EXHIBIT A
FORM OF WAIVER AND RELEASE
[The language in this Release may change based on legal developments and evolving best practices; this form is provided as an example of what will be included in the final Release document.]
In consideration of, and as a condition precedent to, the severance payment (the “
Severance
”) described in that certain Severance Compensation Agreement (the “
Agreement
”) effective as of _____, 2018 between Callon Petroleum Company, a Delaware corporation (the “
Company
”), and [____________________] (“
Executive
”), which were offered to Executive in exchange for a general waiver and release of claims (this “
Waiver and Release
”). Executive having acknowledged the above-stated consideration as full compensation for and on account of any and all injuries and damages which Executive has sustained or claimed, or may be entitled to claim, Executive, for himself, and his heirs, executors, administrators, successors and assigns, does hereby release, forever discharge and promise not to sue the Company, its parents, subsidiaries, affiliates, successors and assigns, and their past and present officers, directors, partners, employees, members, managers, shareholders, agents, attorneys, accountants, insurers, heirs, administrators, executors, as well as all employee benefit plans maintained by any of the foregoing entities or individuals, and all fiduciaries and administrators of such plans, in their personal and representative capacities (collectively the “
Released Parties
”) from any and all claims, liabilities, costs, expenses, judgments, attorney fees, actions, known and unknown, of every kind and nature whatsoever in law or equity, which Executive had, now has, or may have against the Released Parties relating in any way to Executive’s employment with the Company or termination thereof prior to and including the date of execution of this Waiver and Release, including but not limited to, all claims for contract damages, tort damages, special, general, direct, punitive and consequential damages, compensatory damages, loss of profits, attorney fees and any and all other damages of any kind or nature; all contracts, oral or written, between Executive and any of the Released Parties; any business enterprise or proposed enterprise contemplated by any of the Released Parties, as well as anything done or not done prior to and including the date of execution of this Waiver and Release. Notwithstanding anything to the contrary contained in this Waiver and Release, nothing in this Waiver and Release shall be construed to release the Company from any obligations set forth in the Agreement.
Executive understands and agrees that this release and covenant not to sue shall apply to any and all claims or liabilities arising out of or relating to Executive’s employment with the Company and the termination of such employment, including, but not limited to: claims of discrimination based on age, race, color, sex (including sexual harassment), religion, national origin, marital status, parental status, veteran status, union activities, disability or any other grounds under applicable federal, state or local law prior to and including the date of execution of this Waiver and Release, including, but not limited to, claims arising under the Age Discrimination in Employment Act of 1967, the Americans with Disabilities Act, the Family and Medical Leave Act, Title VII of the Civil Rights Act, the Civil Rights Act of 1991, 42 U.S.C. § 1981, the Genetic Information Non-Discrimination Act of 2008, the Employee Retirement Income Security Act of 1974, the Consolidated Omnibus Budget Reconciliation Act of 1985, the Rehabilitation Act of 1973, the Equal Pay Act of 1963 (EPA), all as amended, as well as any claims prior to and including the date of
execution of this Waiver and Release, regarding wages; benefits; vacation; sick leave; business expense reimbursements; wrongful termination; breach of the covenant of good faith and fair dealing; intentional or negligent infliction of emotional distress; retaliation; outrage; defamation; invasion of privacy; breach of contract; fraud or negligent misrepresentation; harassment; breach of duty; negligence; discrimination; claims under any employment, contract or tort laws; claims arising under any other federal law, state law, municipal law, local law, or common law; any claims arising out of any employment contract, policy or procedure; and any other claims related to or arising out of his employment or the separation of his employment with the Company prior to and including the date of execution of this Waiver and Release.
In addition, Executive agrees not to cause or encourage any legal proceeding to be maintained or instituted against any of the Released Parties, save and except proceedings to enforce the terms of the Agreement or claims of Executive not released by and in this Waiver and Release.
This release does not apply to any claims for unemployment compensation or any other claims or rights which, by law, cannot be waived, including the right to file an administrative charge or participate in an administrative investigation or proceeding; provided, however that Executive disclaims and waives any right to share or participate in any monetary award from the Company resulting from the prosecution of such charge or investigation or proceeding. Notwithstanding the foregoing or any other provision in this Waiver and Release or the Agreement to the contrary, the Company and Executive further agree that nothing in this Waiver and Release or the Agreement (i) limits Executive’s ability to file a charge or complaint with the EEOC, the NLRB, OSHA, the SEC or any other federal, state or local governmental agency or commission (each a “
Government Agency
” and collectively “
Government Agencies
”); (ii) limits Executive’s ability to communicate with any Government Agencies or otherwise participate in any investigation or proceeding that may be conducted by any Government Agency, including providing documents or other information and reporting possible violations of law or regulation or other disclosures protected under the whistleblower provisions of applicable law or regulation, without notice to the Company; or (iii) limits Executive’s right to receive an award for information provided to any Government Agencies.
Executive expressly acknowledges that he is voluntarily, irrevocably and unconditionally releasing and forever discharging the Company and the other Released Parties from all rights or claims he has or may have against the Released Parties including, but not limited to, without limitation, all charges, claims of money, demands, rights, and causes of action arising under the Age Discrimination in Employment Act of 1967, as amended (“ADEA”), up to and including the date Executive signs this Waiver and Release including, but not limited to, all claims of age discrimination in employment and all claims of retaliation in violation of ADEA. Executive further acknowledges that the consideration given for this waiver of claims under the ADEA is in addition to anything of value to which he was already entitled in the absence of this waiver. Executive further acknowledges: (a) that he has been informed by this writing that he should consult with an attorney prior to executing this Waiver and Release; (b) that he has carefully read and fully understands all of the provisions of this Waiver and Release; (c) he is, through this Waiver and Release, releasing the Company and the other Released Parties from any and all claims he may have against any of them; (d) he understands and agrees that this waiver and release does not apply to any claims that may arise under the ADEA after the date he executes this Waiver and Release; (e) he has at least [twenty-one (21)] [forty-five (45)] days within which to consider this Waiver and Release; and (f)
he has seven (7) days following his execution of this Waiver and Release to revoke the Waiver and Release; and (g) this Waiver and Release shall not be effective until the revocation period has expired and Executive has signed and has not revoked the Waiver and Release.
Executive acknowledges and agrees that: (a) he has had reasonable and sufficient time to read and review this Waiver and Release and that he has, in fact, read and reviewed this Waiver and Release; (b) that he has the right to consult with legal counsel regarding this Waiver and Release and is encouraged to consult with legal counsel with regard to this Waiver and Release; (c) that he has had (or has had the opportunity to take) [twenty-one (21)] [forty-five (45)] calendar days to discuss the Waiver and Release with a lawyer of his choice before signing it and, if he signs before the end of that period, he does so of his own free will and with the full knowledge that he could have taken the full period; (d) that he is entering into this Waiver and Release freely and voluntarily and not as a result of any coercion, duress or undue influence; (e) that he is not relying upon any oral representations made to him regarding the subject matter of this Waiver and Release; (f) that by this Waiver and Release he is receiving consideration in addition to that which he was already entitled; and (g) that he has received all information he requires from the Company in order to make a knowing and voluntary release and waiver of all claims against the Company and the other Released Parties.
Executive acknowledges and agrees that he has seven (7) days after the date he signs this Waiver and Release in which to rescind or revoke this Waiver and Release by providing notice in writing to the Company. Executive further understands that the Waiver and Release will have no force and effect until the end of that seventh day (the “Waiver Effective Date”). If Executive revokes the Waiver and Release, the Company will not be obligated to pay or provide Executive with the benefits described in this Waiver and Release, and this Waiver and Release shall be deemed null and void.
AGREED TO AND ACCEPTED this
______ day of _________________, 20__.
____________________________________
[Name]
Exhibit 10.18
CHANGE IN CONTROL SEVERANCE COMPENSATION AGREEMENT
THE AGREEMENT
was made and entered into as of January 1, 2019, (the “
Effective Date
”), by and between Callon Petroleum Company, a Delaware corporation (the “
Company
”, and together with its subsidiaries, “
Callon
”) and Joseph C. Gatto, Jr. (“
Executive
”). Callon and Executive may be referred to individually herein as “
Party
” and collectively as “
Parties
”.
WITNESSETH:
WHEREAS
, Callon desires to assure fair treatment of its key executives in the event of a Change in Control (as defined below) and to allow them to make critical career decisions without undue time pressure and financial uncertainty, thereby increasing their willingness to remain with Callon notwithstanding the outcome of a possible Change in Control transaction; and
WHEREAS
, the Board of Directors of the Company (the “
Board
”) believes it is essential to provide the Executive with compensation arrangements upon a Change in Control which provide the Executive with individual financial security and which are competitive with those of other similar corporations, and in order to accomplish these objectives, the Board has caused Callon to enter into this Agreement;
NOW, THEREFORE
, in consideration of the mutual premises and conditions contained herein, the parties hereto agree as follows:
Article 1.
Term
This Agreement shall terminate, except to the extent that any obligation of Callon hereunder remains unpaid as of such time and Executive’s ongoing obligations pursuant to Article 6, upon the earliest of:
|
|
(a)
|
December 31, 2019; provided, however, that, commencing on December 31, 2019, and on each anniversary date thereafter (each such date, an “
Anniversary Date
”), the expiration date under this clause (i) shall automatically be extended for one additional year unless either party shall have given thirty (30) day written notice prior to such Anniversary Date that it does not wish to extend this Agreement; provided, however, that if the Agreement has not terminated prior to the date the Company enters into a definitive agreement that will result in a Change in Control or the date a Change in Control occurs, the expiration date under this clause shall not occur earlier than the second anniversary of the effective date of the Change in Control or the date the agreement to effectuate such Change in Control is terminated, as applicable;
|
|
|
(b)
|
The termination of the Executive’s employment with Callon based on death, Disability (as defined in
Section 3.1
), or Cause (as defined in
Section 3.2
);
|
|
|
(c)
|
The voluntary resignation of the Executive for any reason other than Good Reason (as defined in
Section 3.3
); and
|
|
|
(d)
|
Any termination of Executive’s employment prior to a Change in Control, except as expressly provided in Article 2.
|
Article 2.
Change in Control
Except as provided herein, no benefits shall be payable hereunder unless there shall have been a Change in Control (as defined below), and Executive’s employment by Callon shall thereafter have been terminated within two (2) years after the date of such Change in Control in accordance with
Article 3
.
For purposes hereof, a “
Change in Control
” means the occurrence of one or more of the following:
|
|
(a)
|
Change in Ownership
. A change in ownership of the Company occurs on the date that any Person, other than (1) the Company or any of its Subsidiaries, (2) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (3) an underwriter temporarily holding stock pursuant to an offering of such stock, or (4) a corporation owned, directly or indirectly, by the stockholders of the Company in substantially the same proportions as their ownership of the Company’s stock (each of (1) through (4) an “Exempt Person”), acquires ownership of the Company’s stock that, together with stock held by such Person, constitutes more than fifty percent (50%) of the total fair market value or total voting power of the Company’s Voting Stock. However, if any Person is considered to own already more than fifty percent (50%) of the total fair market value or total voting power of the Company’s Voting Stock, the acquisition of additional stock by the same Person is not considered to be a Change in Control. In addition, if any Person has effective control of the Company through ownership of thirty percent (30%) or more of the total voting power of the Company’s Voting Stock, as discussed in paragraph (b) below, the acquisition of additional control of the Company by the same Person is not considered to cause a Change in Control pursuant to this paragraph (a); or
|
|
|
(b)
|
Change in Effective Control
. Even though the Company may not have undergone a change in ownership under paragraph (a) above, a change in the effective control of the Company occurs on either of the following dates: (1) the date that any Person (other than an Exempt Person) acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of the Company’s stock possessing thirty percent (30%) or more of the total voting power of the Company’s Voting Stock. However, if any Person owns thirty percent (30%) or more of the total voting power of the Company’s Voting Stock, the acquisition of additional control of the Company by the same Person is not considered to cause a Change in Control pursuant to this subparagraph (b)(1); or (2) the date that during any period of three consecutive years, individuals who at the beginning of such period were members of the Board cease for any reason to constitute at least a majority thereof unless the election, or the nomination for election by the Company's stockholders, of each new director was approved by a vote of at least a majority of the directors then still in office who were directors at the beginning of such period or whose election or
|
nomination was previously so approved; provided, however, that any such director shall not be considered to be approved by the Board if his or her initial assumption of office occurs as a result of an actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or
|
|
(c)
|
Change in Ownership of Substantial Portion of Assets
. A change in the ownership of a substantial portion of the Company’s assets occurs on the date that a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) assets of the Company that have a total gross fair market value equal to at least forty percent (40%) of the total gross fair market value of all of the Company’s assets immediately before such acquisition or acquisitions. However, there is no Change in Control when there is such a transfer to an entity that is controlled by the stockholders of the Company immediately after the transfer, through a transfer to (1) a stockholder of the Company (immediately before the asset transfer) in exchange for or with respect to the Company stock; (2) an entity, at least fifty percent (50%) of the total value or voting power of the stock of which is owned, directly or indirectly, by the Company; (3) a Person that owns directly or indirectly, at least fifty percent (50%) of the total value or voting power of the Company’s outstanding Voting Stock; or (4) an entity, at least fifty percent (50%) of the total value or voting power of the stock of which is owned by a Person that owns, directly or indirectly, at least fifty percent (50%) of the total value or voting power of the Company’s outstanding Voting Stock.
|
“
Affiliate
” has the same meaning ascribed to such term in Rule 12b-2 under the Exchange Act.
“
Exchange Act
” means the Securities Exchange Act of 1934, as amended from time to time.
“
Person
” shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act and used in Sections 13(d) and 14(d) thereof, including a “group” as defined in Section 13(d) thereof.
“
Subsidiary
” means (i) in the case of a corporation, any corporation of which the Company directly or indirectly owns shares representing more than 50% of the combined voting power of the shares of all classes or series of capital stock of such corporation which have the right to vote generally on matters submitted to a vote of the stockholders of such corporation and (ii) in the case of a partnership or other business entity not organized as a corporation, any such business entity of which the Company directly or indirectly owns more than 50% of the voting, capital or profits interests (whether in the form of partnership interests, membership interests or otherwise).
“
Voting Stock
” shall mean stock of any class or kind having the power to vote generally for the election of directors.
If the Executive’s employment with Callon is terminated by Callon for reasons other than Cause or Disability in accordance with the provisions of
Article 3
within the six (6) month period prior to the date on which a Change in Control is effective, and it is reasonably demonstrated that such termination: (i) was at the request of a third party who has taken steps reasonably calculated to
effectuate a Change in Control or (ii) otherwise arose in connection with a Change in Control, then for all purposes hereof, such termination shall be deemed to have occurred following a Change in Control (for purposes of this Agreement, a “Deemed Eligible Termination”).
Notwithstanding the foregoing provisions of
Article 2
, with respect to any payment hereunder that is (i) subject to Section 409A of the Internal Revenue Code of 1986, as amended (the “
Code
”) and (ii) a Change of Control which would accelerate the timing of such payment, the term “Change of Control” shall mean a change in the ownership or effective control of Callon, or in the ownership of a substantial portion of the assets of Callon as defined under Code Section 409A, but only to the extent inconsistent with the above definition and to the minimum extent necessary to comply with Section 409A, as determined by Callon.
Article 3.
Termination of Employment Following a Change in Control
If a Change in Control shall have occurred and Executive’s employment is subsequently terminated within two (2) years following the date of such Change in Control, (i) by Callon other than for Cause (as defined in
Section 3.2
) or Disability (as defined in
Section 3.1
) or (ii) by Executive for Good Reason (as defined in
Section 3.3
), Executive shall be entitled to the benefits provided in
Articles 4 and 5
, subject to the additional requirements set forth therein. For the avoidance of doubt, no benefits will be payable hereunder on a termination of Executive’s employment due to Disability or death, due to termination by Callon for Cause, or due to Executive’s voluntary termination of employment without Good Reason.
3.1 Disability
. If, upon the Disability (as defined below) of Executive, and within thirty (30) days after written Notice of Termination (as defined in
Section 3.4
) is given, Executive has not returned to the full-time performance of his employment duties, Callon may terminate Executive’s employment for Disability. For purposes of this Agreement, “
Disability
” is defined as the physical or mental inability of Executive to carry out the normal and usual duties of his employment on a full-time basis for an entire period of six (6) continuous months, together with the reasonable likelihood, as determined by the Board upon the advice of a physician selected or approved by the Board, that Executive will be unable to carry out the normal and usual duties of his employment on a full-time basis for the next following continuous period of six (6) months.
3.2 Cause
. For purposes hereof, “
Cause
” is defined as: (i) the conviction of the Executive by a court of competent jurisdiction as to which no further appeal can be taken of a crime involving moral turpitude or a felony or entering the plea of nolo contendere to such crime by the Executive; (ii) the commission by the Executive of a material act of fraud upon Callon; (iii) the material misappropriation by the Executive of any funds or other property of Callon; (iv) the knowing engagement by the Executive without the written approval of the Board, in any material activity which directly competes with the business of Callon, or which would directly result in material injury to the business or reputation of Callon; (v)(1) a material breach by the Executive during the Executive’s employment with Callon of any of the restrictive covenants set out in the Executive’s employment agreement with the Company, if applicable, or (2) the willful and material nonperformance of the Executive’s duties to Callon (other than by reason of the Executive’s illness or incapacity), and, for purposes of this clause (v), no act or failure to act on Executive’s part shall be deemed “willful” unless it is done or omitted by the Executive not in good faith and without his reasonable belief that such
action or omission was in the best interest of Callon, (vi) any breach of the Executive’s fiduciary duties to Callon, including, without limitation, the duties of care, loyalty and obedience to the law; and (vii) the intentional failure of the Executive to comply with Callon’s Code of Business Conduct and Ethics, or to otherwise discharge his duties in good faith and in a manner that the Executive reasonably believes to be in the best interests of Callon, and with the care an ordinarily prudent person in a like position would exercise under similar circumstances.
3.3 Good Reason
. Subject to
Section 3.4
, Executive may terminate his employment for Good Reason. For purposes of this Agreement, “
Good Reason
” shall mean any of the following:
|
|
(a)
|
Following a Change in Control, a material diminution in the scope, nature or status of Executive’s responsibilities;
|
|
|
(b)
|
Following a Change in Control, (1) a reduction in Executive’s base salary as in effect on the date of a Change in Control or as the same may be increased from time to time thereafter, or (2) a failure by Callon to continue to provide Executive with compensation and benefits that do not represent a material reduction, either in amount of compensation opportunity and benefits provided or the level of the Executive’s participation relative to other participants, in the compensation and benefits provided immediately prior to the Change in Control;
|
|
|
(c)
|
Following a Change in Control, Executive’s relocation by Callon to a location in excess of 50 miles from the location where Executive was based immediately prior to the Change in Control, except for a relocation consented to by Executive, if all reasonable costs of relocation, including moving expenses, costs of selling a principal residence (and, if requested by Executive, the purchase of such principal residence at its then-appraised value as appraised by a qualified and licensed appraiser selected by Executive) are paid or provided for by Callon;
|
|
|
(d)
|
Following a Change in Control, the failure by Callon to continue in effect any compensation plan in which Executive participates unless an equitable arrangement (embodied in an ongoing substitute or alternative plan) has been made with respect to such plan in connection with a Change in Control, or the failure of Callon to continue Executive’s participation therein or the taking of any action by Callon which would materially and adversely affect Executive’s participation in any such plan or reduce Executive’s benefits thereunder;
|
|
|
(e)
|
Following a Change in Control, the failure by Callon to continue to provide Executive with benefits not less, in the aggregate, than those enjoyed under any of Callon’s pension, life insurance, medical, health, and accident, or disability plans in which Executive was participating at the time of a Change in Control or the taking of any action by Callon which would directly or indirectly materially reduce any such benefits;
|
|
|
(f)
|
The failure of Callon to obtain a satisfactory agreement from any successor or parent thereof to assume and agree to perform this Agreement pursuant to
Article 7
; or
|
|
|
(g)
|
Any purported termination of Executive’s employment with Callon which is not effected pursuant to a Notice of Termination satisfying the requirements of
Section 3.4
(and for purposes of this Agreement, no such purported termination shall be effective).
|
Notwithstanding the foregoing definition of “Good Reason”, the Executive cannot terminate his employment hereunder for Good Reason unless the Executive (1) first notifies the Board in writing of the event (or events) which the Executive believes constitutes a Good Reason event under
clauses (a) through (g)
(above) within sixty (60) calendar days from the date of such event, and (2) provides Callon with at least thirty (30) calendar days to cure, correct or mitigate the Good Reason event so that it either (A) does not constitute a Good Reason event hereunder or (B) the Executive specifically agrees, in writing, that after any such modification or accommodation made by Callon, such event does not constitute a Good Reason event hereunder.
The Executive’s mental or physical incapacity following the occurrence of any of the circumstances described in
clauses (a) through (g)
(above) shall not affect the Executive’s ability to terminate employment for Good Reason, and the Executive’s death following delivery of a Notice of Termination for Good Reason shall not affect his designated beneficiary’s entitlement to any benefits provided hereunder upon a termination of employment for Good Reason. Notwithstanding anything herein to the contrary, the Executive’s resignation under this Agreement, with or without Good Reason, shall not affect the Executive’s eligibility to receive benefits under any retirement or pension plan of Callon or its Affiliates.
3.4 Notice of Termination
. Any termination pursuant to the foregoing provisions of this
Article 3
(excluding a termination due to Executive’s death) shall be communicated by written Notice of Termination to the other party hereto. For purposes hereof, a “
Notice of Termination
” shall mean a notice which shall indicate the specific termination provision herein relied upon and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Executive’s employment under the provision so indicated. In the event that Executive seeks to terminate his employment with Callon pursuant to
Section 3.3
, he must communicate his written Notice of Termination to Callon within sixty (60) days of being notified of such action or actions by Callon which constitute Good Reason for termination.
3.5 Date of Termination
. The term “
Date of Termination
” shall mean: (i) if this Agreement is terminated for Disability, thirty (30) days after Notice of Termination is given (provided that Executive has not returned to the performance of his duties on a full-time basis during such thirty (30) day period); or (ii) if Executive’s employment is terminated pursuant to
Section 3.3
, or if Executive’s employment is terminated for any other reason, the date that Executive incurs a “separation from service” (as such term is defined in final Treasury Regulations issued under Code Section 409A and any other authoritative guidance issued thereunder), as determined by Callon.
3.6 Reimbursement of Expenses
. To the extent this Agreement provides for the reimbursement of expenses which are not specifically excluded from Code Section 409A, (i) the amount of expenses eligible for reimbursement during the Executive’s taxable year shall not affect the expenses eligible for reimbursement in any other taxable year and (ii) the reimbursement shall be
made not later than by December 31st of the year following the calendar year in which such expense was incurred by the Executive.
Article 4.
Compensation Upon Termination
4.1 Termination without Cause or for Good Reason
. If a Change in Control shall have occurred and Executive’s employment is subsequently terminated under circumstances described in the first paragraph of
Article 3
, or if Executive incurs a Deemed Eligible Termination, Executive shall be entitled to the following benefits, provided that within fifty (50) days following the Date of Termination Executive signs a general release in substantially the form set forth on Exhibit A, and Executive affirmatively agrees not to violate the provisions of
Article 6
:
|
|
(a)
|
Callon shall pay to the Executive in a lump sum, in cash, on the date which is six (6) months following his Date of Termination, an amount equal to three (3) times the sum of: (i) the Executive’s annual base salary as in effect immediately prior to the Change in Control or, if higher, in effect immediately prior to the Date of Termination, and (ii) the greatest of: (A) the average bonus (under all Callon bonus plans for which the Executive is eligible) earned with respect to the three (3) most recently completed full fiscal years, (B) the target bonus (under all Callon bonus plans for which the Executive is eligible) for the fiscal year in which the Change in Control occurs or (C) the target bonus (under all Callon bonus plans for which the Executive is eligible) for the fiscal year in which the Date of Termination occurs.
|
|
|
(b)
|
Callon shall, at its expense, maintain in full force and effect for Executive’s continued benefit until twenty-four (24) months after the Date of Termination all medical, dental, and vision insurance coverage to which Executive was entitled immediately prior to the Notice of Termination. The continued coverage under this
Section 4.1(b)
shall be provided in a manner that is intended to satisfy an exception to Section 409A of the Code, and therefore not treated as an arrangement providing for nonqualified deferred compensation that is subject to taxation under Code Section 409A, including (i) providing such benefits on a nontaxable basis to Executive, (ii) providing for the reimbursement of medical expenses incurred during the time period during which Executive would be entitled to continuation coverage under a group health plan of Callon pursuant to Section 4980B of the Code (i.e., COBRA continuation coverage), (iii) providing that such benefits constitute the reimbursement or provision of in-kind benefits payable at a specified time or pursuant to a fixed schedule as permitted under Code Section 409A and the authoritative guidance thereunder, or (4) such other manner as determined by Callon in compliance with an exception from being treated as nonqualified deferred compensation subject to Code Section 409A. Further, the continued coverage under this Section 4.1(b) shall be provided as alternative coverage to continuation coverage under Section 4980B of the Code (“COBRA”) and if Executive accepts such continued coverage under this Section 4.1(b), he or she will be deemed to have declined COBRA continuation coverage. In the event of a Deemed Eligible Termination, (i) the Executive will be entitled to a make-up payment (paid on the date the Executive’s severance payment is made pursuant to Section 4.1(a)) in an amount equal to the value of the coverage that would have been provided from the
|
Date of Termination until the date of the Change in Control had Executive been treated as eligible for benefits pursuant to Section 4.1(b) as of the Date of Termination, and (ii) Executive’s benefits pursuant to this Section 4.1(b) will begin as of the date of the Change in Control.
|
|
(c)
|
Callon’s obligation to pay severance amounts due to the Executive pursuant to this
Section 4.1
, to the extent not already paid, shall cease immediately and such payments will be forfeited if the Executive violates any of the covenants or conditions described in
Sections 6.1
,
6.2
or
6.3
after the Date of Termination.
|
4.2 Limitation on Payments
.
(a)
Definitions
. For purposes of this
Section 4.2
, the following capitalized terms have the meanings ascribed to them, below.
“
Excise Tax
” means the excise tax imposed by Section 4999 of the Code with respect to the Total Payments together with any interest or penalties with respect to such excise tax.
“
Incentive Award
” means a stock option, stock appreciation right, restricted stock award, restricted stock unit award, or other equity-type award under any plan or agreement in which Executive has, or will (by the passage of time only and not based on Executive’s performance) have, an interest in the capital stock of Callon or an Affiliate, or a right to obtain capital stock or an interest in capital stock of Callon or an Affiliate.
“
Net After-Tax Benefit
” means (i) the Total Payments less (ii) the amount of all United States federal, state and local income and employment taxes payable with respect to the Total Payments (calculated at the maximum applicable marginal income tax rate for Executive under the Code), and less (iii) the amount of the Excise Tax imposed (based upon the rate for such year as set forth in the Code at the time of the first payment of the foregoing).
“
Total Payments
” means the total payments or other benefits that Executive becomes entitled to receive from Callon or an Affiliate in connection with a Change in Control that would constitute a “parachute payment” (within the meaning of Section 280G of the Code), whether payable pursuant to the terms of this Agreement or any other plan, arrangement, or agreement with Callon or an Affiliate.
(b)
Maximum Net After-Tax Benefit
. The Total Payments shall be reduced to the minimum extent necessary so that no portion of the Total Payments shall be subject to the Excise Tax, but only if, by reason of such reduction, the Net After-Tax Benefit received by Executive as a result of such reduction will exceed the Net After-Tax Benefit that would have been received by Executive if no such reduction was made. It is thus the objective of this Agreement to maximize Executive’s Net After-Tax Benefit if any payments or benefits provided hereunder are subject to the Excise Tax.
In the event it is determined that the Total Payments to or for the benefit of Executive, whether paid or payable or distributed or distributable or otherwise, including, by example and not by way of limitation, acceleration of the date of vesting or payment or rate of payment under any plan, program or arrangement of Callon, would be subject to the Excise Tax, Callon shall first make a calculation under which such payments or benefits provided to Executive under this Agreement are reduced, to
the minimum extent necessary, so that no portion thereof shall be subject to the Excise Tax (the “
Section 4999 Limit
”). Callon shall then compare (i) Executive’s Net After-Tax Benefit assuming application of the Section 4999 Limit with (ii) Executive’s Net After-Tax Benefit without the application of the Section 4999 Limit. In the event (i) is greater than (ii), Executive shall receive Total Payments solely up to the 4999 Limit. In the event (ii) is greater than (i), Executive shall be entitled to receive all such Total Payments, and shall be solely liable for any and all Excise Tax related thereto.
All determinations required to be made under this
Section 4.2
, including whether an Excise Tax may apply to the Total Payments, will be made by the independent accounting firm which served as Callon’s auditor immediately prior to the Change in Control (the “
Accounting Firm
”). All fees and expenses of the Accounting Firm shall be borne solely by Callon and it shall be Callon’s obligation to cause the Accounting Firm to take any actions required hereby.
Callon will direct the Accounting Firm to submit detailed supporting calculations both to Callon and the Executive within fifteen (15) business days after the Date of Termination, if applicable, or such earlier time as is requested by Callon. If applicable, Executive and Callon shall each provide the Accounting Firm with access to, and copies of, any books, records and documents in their respective possessions, as reasonably requested by the Accounting Firm, and otherwise reasonably cooperate with the Accounting Firm in connection with the preparation and issuance of the determinations and calculations contemplated by this
Section 4.2
.
If the Accounting Firm determines that a reduction in payments is required under this
Section 4.2
, Callon shall (to the extent feasible) reduce the Total Payments in the following order: (i) reduction of any cash severance payments otherwise payable to Executive that are exempt from Section 409A of the Code; (ii) reduction of any other cash payments or benefits otherwise payable to Executive that are exempt from Section 409A of the Code, but excluding any payments attributable to any acceleration of vesting or payments with respect to any Incentive Award that are exempt from Section 409A of the Code; (iii) reduction of any other payments or benefits otherwise payable to Executive on a prorata basis or in such other manner that complies with Section 409A of the Code, but excluding any payments attributable to any acceleration of vesting and payments with respect to any Incentive Award that are exempt from Section 409A of the Code; and (iv) reduction of any payments attributable to any acceleration of vesting or payments with respect to any Incentive Award that are exempt from Section 409A of the Code, in each case beginning with payments that would otherwise be made last in time.
If the Accounting Firm determines that no Excise Tax is payable by Executive, it shall furnish Executive with an opinion that he has substantial authority not to report any Excise Tax on his federal income tax return.
4.3 No Mitigation or Set-off of Amounts Payable Hereunder
. Executive shall not be required to mitigate the amount of any payment provided for in this
Article 4
by seeking other employment or otherwise, nor shall the amount of any payment provided for in this
Article 4
be reduced by any compensation earned by Executive as the result of employment by another employer after the Date of Termination, or otherwise. Callon’s obligations hereunder also shall not be affected by any set-off, counterclaim, recoupment, defense, or other claim, right or action which Callon may have against Executive.
Article 5.
Stock Options and Other Plans
5.1 Acceleration of Benefits
. If Executive is eligible for severance payments pursuant to
Section 4.1
, the following shall automatically occur effective as of the sixtieth (60
th
) day following the Date of Termination, subject to delayed payment as may be required pursuant to Article 14:
|
|
(a)
|
Notwithstanding any provision to the contrary in any stock incentive plan, stock option agreement, restricted stock agreement, or other applicable plan or agreement between Executive and Callon, all outstanding units, stock options, incentive stock options, performance shares, performance awards, stock appreciation rights, career shares, bridge shares, and shares of restricted stock (the “
Stock Rights
”) then held by Executive shall immediately become exercisable and Executive shall become one hundred percent (100%) vested in such Stock Rights held by or for the benefit of Executive, with any performance-based Stock Rights earned at the level specified in the applicable award agreement or, if not specified, at the target level; provided, however, that such Stock Rights shall not be accelerated if it would be an impermissible acceleration under Section 409A of the Code, but will be paid at the earliest permissible payment event consistent with the terms of the award and the requirements of Section 409A of the Code.
|
|
|
(b)
|
Notwithstanding any provision to the contrary in any stock option agreement between Executive and Callon, Executive’s right to exercise any previously unexercised and outstanding option under any stock option agreement shall not terminate until the latest date on which such option would expire under the terms of such agreement but for Executive’s termination of employment.
|
|
|
(c)
|
In the event Executive incurs a Deemed Eligible Termination and equity awards that would have been accelerated or exercisability extended pursuant to this
Article 5
have been forfeited as a result of Executive's earlier termination of employment, then Executive shall be entitled to a cash payment equal to (i) the value of any forfeited equity award, determined based on the cash or market value of the number of securities that would have been delivered to Executive pursuant to such award, in each case assuming the awards were vested and delivered (and, if applicable, exercised) as of the date Executive's severance payments are made pursuant to this Agreement (or, with respect to any option, the last day of the original option term, if earlier), reduced by (ii) the amount of any payment previously made in connection with the vesting or exercise of such award.
|
|
|
Article 6.
|
Noncompetition, Nonsolicitation, Nondisclosure of Trade Secrets, Nonpublic Information, and Ownership
|
6.1 Noncompetition
. The Executive agrees that, if he becomes eligible for severance payments pursuant to Section 4.1, for a period of one year after the Date of Termination, he will not, directly or indirectly, compete with Callon by providing services to any other person, partnership, association, corporation, or other entity that is an “Oil and Gas Business” in any geographic location where Callon operated as of the Date of Termination. As used herein, an “
Oil and Gas Business
”
means owning, managing, acquiring, attempting to acquire, soliciting the acquisition of, operating, controlling, or developing Oil and Gas interests, or engaging in or being connected with, as a principal, owner, officer, director, employee, shareholder, promoter, consultant, contractor, partner, member, joint venture, agent, equity owner or in any other capacity whatsoever, any of the foregoing activities of the oil and gas exploration and production business. The parties agree that the above restrictions on competition are completely severable and independent agreements supported by good and valuable consideration and, as such, shall survive the termination of this Agreement for whatever reason. The parties further agree that any invalidity or unenforceability of any one or more of such restrictions on competition shall not render invalid or unenforceable any remaining restrictions on competition. Additionally, should a court of competent jurisdiction determine that the scope of any provision of this
Section 6.1
is too broad to be enforced as written, the parties intend that the court reform the provision to such narrower scope as it determines to be reasonable and enforceable.
6.2 Nonsolicitation
. If the Executive becomes eligible for severance payments pursuant to Section 4.1, for a period of three (3) after the Date of Termination, the Executive shall not, on his own behalf or on behalf of any other person, partnership, association, corporation, or other entity: (a) directly, indirectly, or through a third party hire or cause to be hired; (b) directly, indirectly, or through a third party solicit; or (c) in any manner attempt to influence or induce any employee of Callon to leave the employment of Callon, nor shall he use or disclose to any person, partnership, association, corporation, or other entity any information obtained concerning the names and addresses Callon’s employees. The parties agree that the above restrictions on hiring and solicitation are completely severable and independent agreements supported by good and valuable consideration and, as such, shall survive the termination of this Agreement for whatever reason. The parties further agree that any invalidity or unenforceability of any one or more such restrictions on hiring and solicitation shall not render invalid or unenforceable any remaining restrictions on hiring and solicitation. Additionally, should a court of competent jurisdiction determine that the scope of any provision of this
Section 6.2
is too broad to be enforced as written, the parties intend that the court reform the provision to such narrower scope as it determines to be reasonable and enforceable.
6.3 Nondisclosure of Trade Secrets
. Callon promises to disclose to the Executive and the Executive acknowledges that in, and as a result of, his employment by Callon, he will receive, make use of, acquire, have access to and/or become familiar with, various trade secrets and proprietary and confidential information of Callon, including, but not limited to, processes, computer programs, compilations of information, records, financial information, sales reports, sales procedures, customer requirements, pricing techniques, customer lists, method of doing business, identities, locations, performance and compensation levels of employees, and other confidential information (individually and collectively, “
Trade Secrets
”) which are owned by Callon and used in the operation of its business, and as to which Callon takes precautions to prevent dissemination to persons other than certain directors, officers, and employees. The Executive acknowledges and agrees that the Trade Secrets:
|
|
(a)
|
Are secret and not known in the industry;
|
|
|
(b)
|
Give Callon an advantage over competitors who do not know or use the Trade Secrets;
|
|
|
(c)
|
Are of such value and nature as to make it reasonable and necessary to protect and preserve the confidentiality and secrecy of the Trade Secrets; and
|
|
|
(d)
|
Are valuable, special, and unique assets of Callon, the disclosure of which could cause substantial injury and loss of profits and goodwill to Callon.
|
The Executive promises not to use in any way or disclose any of the Trade Secrets and confidential and proprietary information, directly or indirectly, either during or after the term of his employment, except as required in the course of his employment with Callon, if required in connection with a judicial or administrative proceeding, or if the information becomes public knowledge other than as a result of an unauthorized disclosure by the Executive. All files, records, documents, information, data, and similar items relating to the business of Callon, whether prepared by the Executive or otherwise coming into his possession, will remain the exclusive property of Callon and may not be removed from the premises of Callon under any circumstances without the prior written consent of Callon (except in the ordinary course of business during the Executive’s period of active employment under this Agreement), and in any event must be promptly delivered to Callon upon termination of the Executive’s employment with Callon. The Executive agrees that upon his receipt of any subpoena, process, or other requests to produce or divulge, directly or indirectly, any Trade Secrets to any entity, agency, tribunal, or person, whether received during or after the term of the Executive’s employment with Callon, the Executive shall timely notify and promptly deliver a copy of the subpoena, process, or other request to Callon. For this purpose, the Executive irrevocably nominates and appoints Callon (including any attorney retained by Callon), as his true and lawful attorney-in-fact, to act in the Executive’s name, place, and stead to perform any act that the Executive might perform to defend and protect against any disclosure of any Trade Secrets.
The parties agree that the above restrictions on confidentiality and disclosure are completely severable and independent agreements supported by good and valuable consideration and, as such, shall survive the termination of this Agreement for whatever reason. The parties further agree that any invalidity or unenforceability of any one or more of such restrictions on confidentiality and disclosure shall not render invalid or unenforceable any remaining restrictions on confidentiality and disclosure. Additionally, should a court of competent jurisdiction determine that the scope of any provision of this
Section 6.3
is too broad to be enforced as written, the parties intend that the court reform the provision to such narrower scope as it determines to be reasonable and enforceable.
6.4 Ownership
. The Executive agrees that all inventions, copyrightable material, business and/or technical information, marketing plans, customer lists, and trade secrets which arise out of the performance of this Agreement are the property of Callon.
6.5 No Disparaging Comments
. Executive and Callon shall refrain from any criticisms or disparaging comments about each other or in any way relating to Executive's employment or separation from employment with Callon; provided, however, that nothing in this Agreement shall apply to or restrict in any way the communication of information to any governmental law enforcement agency by either party that is required by compulsion of law. A violation or threatened violation of this prohibition may be enjoined by a court of competent jurisdiction. The rights under this provision are in addition to any and all rights and remedies otherwise afforded by law to the parties.
Executive acknowledges that in executing this Agreement, he has knowingly, voluntarily, and intelligently waived any free speech, free association, free press or First Amendment to the United States Constitution (including, without limitation, any counterpart or similar provision or right under
any other state constitution which may be deemed to apply) and rights to disclose, communicate, or publish disparaging information or comments concerning or related to Callon; provided, however, nothing in this Agreement shall be deemed to prevent Executive from testifying fully and truthfully in response to a subpoena from any court or from responding to an investigative inquiry from any governmental agency.
For all purposes of the obligations of Executive under this
Section 6.5
, the term “Callon” refers to the Callon Petroleum Company and its Subsidiaries and Affiliates, and its and their directors, officers, employees, shareholders, investors, partners and agents.
6.6 Protected Disclosures
. Notwithstanding anything herein to the contrary, nothing in this Agreement will be construed to prohibit the Executive from reporting possible violations of law or regulation to any governmental agency or regulatory body or making other disclosures that are protected under any law or regulation, or from filing a charge with or participating in any investigation or proceeding conducted by any governmental agency or regulatory body. This Agreement does not limit the Executive’s right to receive an award for information provided to any governmental agency or regulatory body. Further, in accordance with the Defend Trade Secrets Act, the Executive may not be held criminally or civilly liable under any Federal or state trade secret law for the disclosure of a trade secret that is made in confidence to a Federal, state, or local government official, either directly or indirectly, or to an attorney, and solely for the purpose of reporting or investigating a suspected violation of law; or that is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is made under seal.
6.7 Subsidiaries and Affiliates Included
. Except where otherwise expressly provided, for all purposes of the obligations of Executive under this
Article 6
, the term “Callon” refers to the Callon Petroleum Company and its Subsidiaries and Affiliates.
Article 7.
Successors; Binding Agreement
7.1 Successors of Callon
. Callon will require any successor (whether direct or indirect, by purchase, merger, consolidation, or otherwise) to all or substantially all of the business and/or assets of Callon, by agreement in form and substance satisfactory to Executive, expressly to assume and agree to perform this Agreement in the same manner and to the same extent that Callon would be required to perform it if no such succession had taken place. Failure of Callon to obtain such agreement prior to the effectiveness of any such succession shall be a breach hereof and shall entitle Executive to compensation from Callon in the same amount and on the same terms as Executive would be entitled hereunder if Executive terminated his employment for Good Reason, the date on which any such succession becomes effective shall be deemed the Date of Termination; provided however, that such compensation shall be paid to Executive only if such successor is a considered to be a successor to Callon by reason of a Change in Control. As used herein, “
Callon Petroleum Company
” shall mean Callon as hereinbefore defined and any successor to its business and/or assets as aforesaid which executes and delivers the agreement provided for in this
Section 7.1
, or which otherwise becomes bound by all the terms and provisions hereof by operation of law. Wherever appropriate to the intention of the parties, the respective rights and obligations of the parties hereunder shall survive any termination or expiration of this Agreement.
7.2 Executive’s Heirs, Etc.
This Agreement shall inure to the benefit of and be enforceable by Executive’s personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees, and legatees. If Executive should die while any amounts would still be payable to him hereunder as if he had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms hereof to his designee or, if there be no such designee, to his estate upon prior receipt by Callon of a proper notice regarding the legal representative of such estate.
Article 8.
Notice
For the purposes hereof, notices and all other communications provided for herein shall be in writing and shall be deemed to have been duly given when delivered or mailed. Each notice or other communication required or permitted under this Agreement shall be in writing and transmitted or delivered by personal delivery, prepaid courier or messenger service (whether overnight or same-day), prepaid telecopy or facsimile, or prepaid certified or registered United States mail (with return receipt requested), addressed to Callon at its principal place of business and to Executive at his address as shown on the records of Callon, provided that all notices to Callon shall be directed to the attention of the Secretary of Callon with a copy to the Director of HR of Callon, or to such other address provided in writing in accordance herewith, except that notices of change of address shall be effective only upon receipt, or at such other address as the recipient has designated by notice to the other party.
Each notice or communication so transmitted, delivered, or sent in person, by courier or messenger service, or by certified United States mail, shall be deemed given, received, and effective on the date delivered to or refused by the intended recipient (with the return receipt, or the equivalent record of the courier or messenger, being deemed conclusive evidence of delivery or refusal.) Nevertheless, if the date of delivery is after 5:00 p.m. (local time of the recipient) on a business day, the notice or other communication shall be deemed given, received and effective on the next business day.
Article 9.
Miscellaneous
9.1 Waiver and Amendment
. No provisions hereof may be amended, modified, waived, or discharged unless such amendment, waiver, modification, or discharge is agreed to in writing and signed by Executive and such officer as may be specifically designated by the Board (which shall in any event include Callon’s Chairman of the Board). No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision hereof, to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. No agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made by either party which are not set forth expressly herein.
9.2 Tax Consequences
. Callon or its affiliate shall withhold from any payments or benefits under this Agreement (whether or not otherwise acknowledged under this Agreement) all federal, state, local, or other taxes that it is required to withhold.
Executive understands, acknowledges, and agrees that Company cannot, and does not, provide any tax or legal advice to Executive. Any tax-related information that has been provided, or will be
provided, to Executive is solely for informational purposes and should not be relied upon by Executive. Executive acknowledges that he has reviewed with his own tax advisors the tax consequences of this Agreement and the transactions contemplated hereby. Executive is relying solely on his tax advisors and not on any statements or representations of Callon or any of its agents and understands that Executive (and not Callon) shall be responsible for Executive’s own tax liability that may arise as a result of this Agreement or the transactions contemplated hereby, except as otherwise specifically provided in this Agreement.
9.3 Employment Status
. Nothing in this Agreement provides the Executive with any right to continued employment with Callon or any of its affiliates, or shall interfere with the right of Callon or an affiliate to terminate the Executive’s employment at any time subject to Callon’s obligations under this Agreement.
9.4 No Exclusivity
. Except as expressly provided herein, this Agreement shall not prevent or limit the Executive’s participation in any other plan or arrangement maintained by Callon for which the Executive qualifies, nor shall it impair any rights that the Executive may have under any other plan, program, contract or agreement with Callon or any of its affiliates.
9.5 Reformation and Severability
. The Parties fully intend that this Agreement comply with all applicable laws and legal requirements. Should any provision of this Agreement be declared or be determined by any court of competent jurisdiction to be illegal, invalid or unenforceable, the Agreement shall first be reformed to make the provision at issue enforceable and effective to the full extent permitted by law. If such reformation is not possible, all remaining provisions of this Agreement shall otherwise remain in full force and effect and shall be construed as if such illegal, invalid, or unenforceable provision has not been included herein.
9.6 Entire Agreement
. This Agreement sets forth the entire agreement of the Parties and fully supersedes and replaces any and all prior agreements, promises, representations, or understandings, written or oral, between Callon and Executive relating to the subject matter of this Agreement including, without limitation, the Severance Compensation Agreement between Executive and the Company effective as of September 18, 2017 and as thereafter amended. This Agreement may be amended or modified only by a written instrument identified as an amendment hereto that is executed by both Executive and by the Chairman of the Board (or another officer who is authorized by the Board) on behalf of Callon.
9.7 Executive Acknowledgment
. Executive acknowledges that (a) he is knowledgeable and sophisticated as to business matters, including the subject matter of this Agreement, (b) he has read this Agreement and understands its terms and conditions, (c) he has had ample opportunity to review and discuss this Agreement with legal counsel of his choice prior to execution should he desire to do so, and (d) no strict rules of construction will apply for or against the drafter or any other party. Executive represents that there are no restrictions on his right to enter into this Agreement.
Article 10.
Validity
The invalidity or unenforceability of any provision hereof shall not affect the validity or enforceability of any other provision hereof, which shall remain in full force and effect.
Article 11.
Counterparts
This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original but all of which together will constitute one and the same instrument.
Article 12.
Governing Law; Jurisdiction
All matters or issues relating to the interpretation, construction, validity, and enforcement of this Agreement shall be governed by the laws of the State of Texas, without giving effect to any choice-of-law principle that would cause the application of the laws of any jurisdiction other than Texas. Jurisdiction and venue of any action or proceeding relating to this Agreement or any Dispute shall be exclusively in the State of Texas (unless otherwise mutually agreed by the parties), and the parties hereby waive any objection to such jurisdiction or venue including, without limitation, to the effect that the location is inconvenient.
Article 13.
Interpretative Matters
In the interpretation of the Agreement, except where the context otherwise requires:
|
|
(a)
|
“
including
” or “
include
” does not denote or imply any limitation;
|
|
|
(b)
|
“
or
” has the inclusive meaning “and/or”;
|
|
|
(c)
|
the singular includes the plural, and vice versa, and each gender includes each of the others;
|
|
|
(d)
|
captions or headings are for reference purposes only, and they are not to be considered in interpreting the Agreement;
|
|
|
(e)
|
“
Section
” refers to a Section of the Agreement, unless otherwise stated in the Agreement;
|
|
|
(f)
|
“
month
” refers to a calendar month; and
|
|
|
(g)
|
a reference to any statute, rule, or regulation includes (1) any amendment thereto, (2) any statute, rule, or regulation enacted or promulgated in replacement thereof, and (3) any regulation or other authority issued by the appropriate governmental entity under, or with respect to, a statute.
|
Article 14.
Compliance with Section 409A
Any provisions of the Agreement that are subject to Section 409A of the Code (“
Section 409A
”) are intended to comply with all applicable requirements of Section 409A, or an exemption from the application of Section 409A, and shall be interpreted and administered accordingly. Any ambiguous provision will be construed in a manner that is compliant with, or exempt from, the application of Section 409A. Notwithstanding any provision of this Agreement to the contrary, a termination of employment shall not be deemed to have occurred for purposes of any provision of this Agreement providing for the payment of any amount or benefit that constitutes “non-
qualified deferred compensation” (within the meaning of Section 409A) upon or following a termination of the Executive’s employment unless such termination is also a “separation from service” within the meaning of Section 409A and, for purposes of any such provision, references herein to a “termination,” “termination of employment” or like terms shall mean “separation from service” within the meaning of Section 409A.
Notwithstanding any provision of this Agreement to the contrary, if any payment or other benefit provided herein would be subject to additional taxes and interest under Section 409A because the timing of such payment is not delayed as required by Section 409A for a “specified employee,” then if the Executive is on the applicable date a specified employee, any such payment that the Executive would otherwise be entitled to receive during the first six months following his “separation from service” (as defined under Section 409A) shall be accumulated and paid, within ten (10) days after the date that is six months following the Executive’s date of “separation from service,” or such earlier date upon which such amount can be paid under Section 409A without being subject to such additional taxes and interest such as, for example, upon the Executive’s death.
With respect to any amounts or benefits that are subject to Section 409A, this Agreement shall in all respects be administered in accordance with Section 409A. Each payment under this Agreement shall be treated as a separate payment for purposes of Section 409A. In no event may the Executive, directly or indirectly, designate the calendar year of any payment to be made under this Agreement.
All reimbursements and in-kind benefits provided under this Agreement that constitute deferred compensation within the meaning of Section 409A shall be made or provided in accordance with the requirements of Section 409A. Within the time period permitted by Section 409A, Callon may, in consultation with the Executive, modify the Agreement in the least restrictive manner necessary and without any diminution in the value of payments or other benefits to the Executive hereunder, in order to avoid the imposition of accelerated tax, additional tax and/or penalties on the Executive under Section 409A.
[Next page is signature page]
IN WITNESS WHEREOF
, the Parties hereto have executed this amended and restated Agreement on the dates set forth below, to be effective as of the Effective Date.
|
|
|
|
CALLON PETROLEUM COMPANY
|
|
|
|
|
By:
|
|
|
|
L. Richard Flury
|
|
|
Chairman of the Board
|
|
|
|
|
Date:
|
|
|
|
|
|
|
EXECUTIVE
|
|
|
|
|
By:
|
|
|
|
Joseph C. Gatto, Jr.
|
|
|
President and Chief Executive Officer
|
|
|
|
Date:
|
|
|
EXHIBIT A
FORM OF WAIVER AND RELEASE
[The language in this Release may change based on legal developments and evolving best practices; this form is provided as an example of what will be included in the final Release document.]
In consideration of, and as a condition precedent to, the severance payment (the “
Severance
”) described in that certain Severance Compensation Agreement (the “
Agreement
”) effective as of _____, 2018 between Callon Petroleum Company, a Delaware corporation (the “
Company
”), and [____________________] (“
Executive
”), which were offered to Executive in exchange for a general waiver and release of claims (this “
Waiver and Release
”). Executive having acknowledged the above-stated consideration as full compensation for and on account of any and all injuries and damages which Executive has sustained or claimed, or may be entitled to claim, Executive, for himself, and his heirs, executors, administrators, successors and assigns, does hereby release, forever discharge and promise not to sue the Company, its parents, subsidiaries, affiliates, successors and assigns, and their past and present officers, directors, partners, employees, members, managers, shareholders, agents, attorneys, accountants, insurers, heirs, administrators, executors, as well as all employee benefit plans maintained by any of the foregoing entities or individuals, and all fiduciaries and administrators of such plans, in their personal and representative capacities (collectively the “
Released Parties
”) from any and all claims, liabilities, costs, expenses, judgments, attorney fees, actions, known and unknown, of every kind and nature whatsoever in law or equity, which Executive had, now has, or may have against the Released Parties relating in any way to Executive’s employment with the Company or termination thereof prior to and including the date of execution of this Waiver and Release, including but not limited to, all claims for contract damages, tort damages, special, general, direct, punitive and consequential damages, compensatory damages, loss of profits, attorney fees and any and all other damages of any kind or nature; all contracts, oral or written, between Executive and any of the Released Parties; any business enterprise or proposed enterprise contemplated by any of the Released Parties, as well as anything done or not done prior to and including the date of execution of this Waiver and Release. Notwithstanding anything to the contrary contained in this Waiver and Release, nothing in this Waiver and Release shall be construed to release the Company from any obligations set forth in the Agreement.
Executive understands and agrees that this release and covenant not to sue shall apply to any and all claims or liabilities arising out of or relating to Executive’s employment with the Company and the termination of such employment, including, but not limited to: claims of discrimination based on age, race, color, sex (including sexual harassment), religion, national origin, marital status, parental status, veteran status, union activities, disability or any other grounds under applicable federal, state or local law prior to and including the date of execution of this Waiver and Release, including, but not limited to, claims arising under the Age Discrimination in Employment Act of 1967, the Americans with Disabilities Act, the Family and Medical Leave Act, Title VII of the Civil Rights Act, the Civil Rights Act of 1991, 42 U.S.C. § 1981, the Genetic Information Non-Discrimination Act of 2008, the Employee Retirement Income Security Act of 1974, the Consolidated Omnibus Budget Reconciliation Act of 1985, the Rehabilitation Act of 1973, the Equal Pay Act of 1963 (EPA), all as amended, as well as any claims prior to and including the date of execution of this Waiver and Release, regarding wages; benefits; vacation; sick leave; business expense reimbursements; wrongful termination; breach
of the covenant of good faith and fair dealing; intentional or negligent infliction of emotional distress; retaliation; outrage; defamation; invasion of privacy; breach of contract; fraud or negligent misrepresentation; harassment; breach of duty; negligence; discrimination; claims under any employment, contract or tort laws; claims arising under any other federal law, state law, municipal law, local law, or common law; any claims arising out of any employment contract, policy or procedure; and any other claims related to or arising out of his employment or the separation of his employment with the Company prior to and including the date of execution of this Waiver and Release.
In addition, Executive agrees not to cause or encourage any legal proceeding to be maintained or instituted against any of the Released Parties, save and except proceedings to enforce the terms of the Agreement or claims of Executive not released by and in this Waiver and Release.
This release does not apply to any claims for unemployment compensation or any other claims or rights which, by law, cannot be waived, including the right to file an administrative charge or participate in an administrative investigation or proceeding; provided, however that Executive disclaims and waives any right to share or participate in any monetary award from the Company resulting from the prosecution of such charge or investigation or proceeding. Notwithstanding the foregoing or any other provision in this Waiver and Release or the Agreement to the contrary, the Company and Executive further agree that nothing in this Waiver and Release or the Agreement (i) limits Executive’s ability to file a charge or complaint with the EEOC, the NLRB, OSHA, the SEC or any other federal, state or local governmental agency or commission (each a “
Government Agency
” and collectively “
Government Agencies
”); (ii) limits Executive’s ability to communicate with any Government Agencies or otherwise participate in any investigation or proceeding that may be conducted by any Government Agency, including providing documents or other information and reporting possible violations of law or regulation or other disclosures protected under the whistleblower provisions of applicable law or regulation, without notice to the Company; or (iii) limits Executive’s right to receive an award for information provided to any Government Agencies.
Executive expressly acknowledges that he is voluntarily, irrevocably and unconditionally releasing and forever discharging the Company and the other Released Parties from all rights or claims he has or may have against the Released Parties including, but not limited to, without limitation, all charges, claims of money, demands, rights, and causes of action arising under the Age Discrimination in Employment Act of 1967, as amended (“ADEA”), up to and including the date Executive signs this Waiver and Release including, but not limited to, all claims of age discrimination in employment and all claims of retaliation in violation of ADEA. Executive further acknowledges that the consideration given for this waiver of claims under the ADEA is in addition to anything of value to which he was already entitled in the absence of this waiver. Executive further acknowledges: (a) that he has been informed by this writing that he should consult with an attorney prior to executing this Waiver and Release; (b) that he has carefully read and fully understands all of the provisions of this Waiver and Release; (c) he is, through this Waiver and Release, releasing the Company and the other Released Parties from any and all claims he may have against any of them; (d) he understands and agrees that this waiver and release does not apply to any claims that may arise under the ADEA after the date he executes this Waiver and Release; (e) he has at least [twenty-one (21)] [forty-five (45)] days within which to consider this Waiver and Release; and (f) he has seven (7) days following his execution of this Waiver and Release to revoke the Waiver and Release; and (g) this Waiver and
Release shall not be effective until the revocation period has expired and Executive has signed and has not revoked the Waiver and Release.
Executive acknowledges and agrees that: (a) he has had reasonable and sufficient time to read and review this Waiver and Release and that he has, in fact, read and reviewed this Waiver and Release; (b) that he has the right to consult with legal counsel regarding this Waiver and Release and is encouraged to consult with legal counsel with regard to this Waiver and Release; (c) that he has had (or has had the opportunity to take) [twenty-one (21)] [forty-five (45)] calendar days to discuss the Waiver and Release with a lawyer of his choice before signing it and, if he signs before the end of that period, he does so of his own free will and with the full knowledge that he could have taken the full period; (d) that he is entering into this Waiver and Release freely and voluntarily and not as a result of any coercion, duress or undue influence; (e) that he is not relying upon any oral representations made to him regarding the subject matter of this Waiver and Release; (f) that by this Waiver and Release he is receiving consideration in addition to that which he was already entitled; and (g) that he has received all information he requires from the Company in order to make a knowing and voluntary release and waiver of all claims against the Company and the other Released Parties.
Executive acknowledges and agrees that he has seven (7) days after the date he signs this Waiver and Release in which to rescind or revoke this Waiver and Release by providing notice in writing to the Company. Executive further understands that the Waiver and Release will have no force and effect until the end of that seventh day (the “Waiver Effective Date”). If Executive revokes the Waiver and Release, the Company will not be obligated to pay or provide Executive with the benefits described in this Waiver and Release, and this Waiver and Release shall be deemed null and void.
AGREED TO AND ACCEPTED this
______ day of _________________, 20__.
____________________________________
[Name]
Exhibit 10.19
SEPARATION AGREEMENT
Effective as of January 2, 2019, (the “
Effective Date
”), this Separation Agreement (this “
Agreement
”) is entered into by and between, and shall inure to the benefit of and be binding upon, the following parties (sometimes collectively referred to herein as “the Parties”):
GARY A. NEWBERRY
, hereinafter referred to as “
Employee
”; and
CALLON PETROLEUM COMPANY
, a Delaware corporation, and its direct and indirect subsidiaries, hereinafter collectively referred to as the “
Company
.”
W
I
T
N
E
S
S
E
T
H
:
WHEREAS, Employee is currently an employee of the Company;
WHEREAS, the Parties mutually agree that the Employee ceased to serve as an officer of the Company and its direct and indirect subsidiaries effective as of December 10, 2018, and further agree that the Employee’s employment with the Company shall end effective January 31, 2019 (the
“Resignation Date”
);
WHEREAS, Employee and the Company mutually desire to establish and agree on the terms and conditions of Employee’s separation from service;
NOW, THEREFORE, in consideration of the premises and the mutual agreements, covenants and obligations set forth herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound, Employee and the Company hereby agree as follows:
Section 1.
Separation Benefits and Payments
. Following the Resignation Date, all entitlement to compensation and benefits will cease except as required by applicable law or provided below. Employee will be entitled to (i) a lump-sum payment in an amount equal to Employee’s accrued but unused vacation days and (ii) reimbursement for unpaid business expenses incurred in the ordinary course of business. In addition, subject to the execution of this Agreement by Employee on or after the Effective Date and the lapse of the seven (7) day revocation period following Employee’s execution of this Agreement (the “
Revocation Period
”) without revocation of this Agreement or any part hereof by Employee, Employee shall be entitled to receive the following payments and benefits, to which Employee would not otherwise be entitled, subject to the terms and conditions set forth in this Agreement:
(a)
Employee shall remain eligible to participate in the Company’s annual performance bonus program for 2018 performance. Any earned bonus will be awarded at the discretion of the Compensation Committee and will be paid, subject to Employee’s continued compliance with the terms of this Agreement, at the time that such bonus awards are normally paid for the year and in any event, no later than March 31, 2019;
(b)
Company shall transfer to Employee the title to the Company vehicle currently used by Employee within ten (10) days following the Resignation Date;
(c)
For purposes of the outstanding equity awards granted to Employee under the Callon Petroleum Company 2011 Omnibus Incentive Plan or the Callon Petroleum Company 2018 Omnibus Incentive Plan (as amended from time to time, the “
Plans
”):
(i) for performance stock units that were awarded in 2016, the awards will vest, if at all, in accordance with the existing terms of such awards (i.e., vesting will be based on the extent to which the performance metric for such awards is satisfied);
(ii) for restricted stock units that were awarded in 2016, the awards will vest, if at all, in accordance with the existing terms of such awards;
provided that
, such awards will no longer be subject to forfeiture based on a failure to remain employed as of the relevant vesting date, subject to Employee’s continued compliance with the terms of this Agreement;
(iii) for performance stock units that were awarded in 2017 and 2018, such awards shall vest, if at all, in accordance with the existing terms of such awards;
provided that
, such awards will no longer be subject to forfeiture based on a failure to remain employed as of the relevant vesting date, subject to Employee’s continued compliance with the terms of this Agreement; and
(iv) for restricted stock units that were awarded in 2017 and 2018, such awards shall vest in full as of the Resignation Date.
To the extent necessary to give effect to the provisions of Section 1(c) above, the applicable equity award grant agreements shall be deemed amended by the provisions of Section 1(c) above, as applicable. All payments made pursuant to this Section 1 shall be subject to appropriate tax withholding and are subject to all the terms and conditions of this Agreement.
Section 2.
Release of Claims
.
(a)
General Release by Employee
. In consideration of the foregoing, which Employee hereby expressly acknowledges as good and sufficient consideration for the releases provided below, Employee hereby unconditionally and irrevocably releases, acquits and forever discharges, to the fullest extent permitted by applicable law, the Company and each of its subsidiaries, divisions, affiliates, operating companies, predecessors and successors, as well as all of the current and former employees, officers, directors, owners, shareholders, partners, representatives, agents and affiliates of each of them (collectively, the
“Released Parties”
), from any and every action, cause of action, complaint, claim, demand, administrative charge, legal right, compensation, obligation, damages (including consequential, exemplary and punitive damages), liability, cost or expense (including attorney’s fees) that Employee has, may have or may be entitled to from or against any of the Released Parties, whether legal, equitable or administrative, whether known or unknown, which arises directly or indirectly out of, or is based on or related in any way to Employee’s employment with, compensation and benefits from, termination of employment from, service for or other affiliation with the Company,
including any such matter arising from the negligence, gross negligence or reckless, willful or wanton misconduct of any of the Released Parties
(together, the “
Released Claims
”);
provided
,
however
, that this Release does not apply to, and the Released Claims do not include: (i) any claims arising solely and specifically under the U.S. Age Discrimination in Employment Act of 1967 after the date this Agreement is executed by Employee; (ii) any claim for indemnification (including under the Company’s organizational documents or insurance policies) arising in connection with an action instituted by a third party against the Company or any of its affiliates or Employee, in his capacity as an officer, director, manager, employee, agent or other representative of the Company or any of its affiliates; (iii) any claims for vested benefits under the Company’s 401(k) plan; (iv) any claims relating to Employee’s eligibility to continue participating in health coverage currently available to Employee in accordance with COBRA, subject to the terms, conditions and restrictions of that Act; (v) any claim arising from any breach or failure to perform any provision of this Agreement; or (vi) any claim for worker’s compensation benefits or any other claim that cannot be waived by a general release.
(b)
Release to be Full and Complete; Waiver of Claims, Rights and Benefits
. The parties intend this Release to cover any and all such Released Claims, whether they are contract claims, equitable claims, fraud claims, tort claims, discrimination claims, harassment claims, whistleblower or retaliation claims, personal injury claims, constructive or wrongful discharge claims, emotional distress claims, pain and suffering claims, public policy claims, claims for debts, claims for expense reimbursement, wage claims, claims with respect to any other form of compensation, claims for attorneys’ fees, other claims or any combination of the foregoing, and whether they may arise under any employment contract (express or implied), policies, procedures, practices or by any acts or omissions of any of the Released Parties or whether they may arise under any state, local or federal law, statute, ordinance, rule or regulation, including all Texas employment discrimination laws, Chapter 21 of the Texas Labor Code, the Texas Payday Act, all U.S. federal discrimination laws, the U.S. Age Discrimination in Employment Act of 1967, the U.S. Employee Retirement Income Security Act of 1974, Title VII of the U.S. Civil Rights Act of 1964, the U.S. Civil Rights Act of 1991, the U.S. Rehabilitation Act of 1973, the U.S. Americans with Disabilities Act of 1990, the U.S. Equal Pay Act, the U.S. National Labor Relations Act, the U.S. Older Workers Benefit Protection Act, the U.S. Worker Adjustment and Retraining Notification Act, the U.S. Family and Medical Leave Act, the U.S. Sarbanes-Oxley Act of 2002 or common law, without exception. As such, it is expressly acknowledged and agreed that this Release is a general release, representing a full and complete disposition and satisfaction of all of the Company’s and any Released Party’s real or alleged legal obligations to Employee except as explicitly provided for herein. Employee understands and agrees, in compliance with any law, statute, ordinance, rule or regulation which requires a specific release of unknown claims or benefits, that this Agreement includes a release of unknown claims, and Employee hereby expressly waives and relinquishes any and all Released Claims and any associated rights or benefits that Employee may have, including any that are unknown to Employee at the time of the execution this Agreement. On or after the Resignation Date, as a condition to receiving the benefits set forth in Section 1, Employee agrees that he shall execute another release covenant not to sue of all Released Claims against the Released Parties to be effective on the Resignation Date.
(c)
Certain Representations of Employee
. Employee represents and warrants that: (i) Employee is the sole and lawful owner of all rights, titles and interests in and to all Released Claims; and (ii) Employee has the fully legal right, power, authority and capacity to execute and deliver this Agreement.
(d)
Covenant Not to Sue
. Employee expressly agrees that neither Employee nor any person acting on Employee’s behalf will file or bring or permit to be filed or brought any lawsuit or other action before any court, agency or other governmental authority for legal or equitable relief against any of the Released Parties involving any of the Released Claims. In the event that such an action is filed against any of the Released Parties, Employee agrees that such Released Parties are entitled to legal and equitable remedies against Employee, including an award of attorney’s fees. However, it is expressly understood and agreed that the foregoing sentence shall not apply to any action filed by Employee that is narrowly limited to seeking a determination as to the validity of this Agreement and enforcement thereof.
(e)
Protected Disclosures
. Notwithstanding the foregoing or any other provision in this Agreement to the contrary, including any provision in Sections 4, 5 or 6, the Company and Employee further agree that nothing in this Agreement (i) limits Employee’s ability to file a charge or complaint with the EEOC, the NLRB, OSHA, the SEC or any other federal, state or local governmental agency or commission (“
Government Agencies
”); (ii) limits Employee’s ability to communicate with any Government Agencies or otherwise participate in any investigation or proceeding that may be conducted by any Government Agency, including providing documents or other information and reporting possible violations of law or regulation or other disclosures protected under the whistleblower provisions of applicable law or regulation, without notice to the Company; or (iii) limits Employee’s right to receive an award for information provided to any Government Agencies. Should Employee file a charge or complaint with any Government Agency, or should any governmental entity, agency or commission file a charge, action, complaint or lawsuit against any of the Released Parties based on any Released Claim, Employee agrees not to seek or accept any resulting payment from the Released Parties.
Section 3.
Return of Materials, Nondisparagement, Noncompetition, Nonsolicitation, Confidentiality and Other Undertakings
. Employee acknowledges that, pursuant to the terms of the Executive Severance Compensation Agreement between Employee and the Company, as last updated and dated as of September 18, 2017 (the “
2017 Severance Agreement
”), Employee is subject to confidentiality, nonsolicitation and noncompetition obligations following termination of employment. The parties agree that such obligations are hereby amended and restated pursuant to this Section 3 of this Agreement.
(a)
Return of Materials
. On or promptly after the Resignation Date, Employee shall return to the Company with no request being required of the Company: (i) any and all documents, records, files, reports, memoranda, plans, letters and any other data in Employee’s possession regardless of the medium maintained, held or stored that relate in any way to the business or operations of the Company; and (ii) any credit cards, keys, access cards, calling cards, computer equipment and software, telephone, facsimile or other equipment or property of the Company.
(b)
Nondisparagement
.
|
|
(i)
|
Employee shall refrain from making, directly or indirectly, in any public or private communication any criticisms or negative or disparaging comments about the Company or any of the other Released Parties, or about any aspect of the respective businesses, operations, financial results or prospects of the Company, including comments relating to Employee’s separation from employment.
|
|
|
(ii)
|
The directors and officers of the Company shall refrain from making, directly or indirectly, in any public or private, any criticisms or negative or disparaging comments about Employee, or about any aspect of the employment relationship between the Company and Employee, including comments relating to Employee’s separation from employment.
|
|
|
(iii)
|
Notwithstanding the foregoing, it is understood and agreed that nothing in this Section 3(b) is intended to prevent either party or the Released Parties from (x) testifying truthfully in any legal proceeding brought by any governmental authority or other third party or interfere with any obligation to cooperate with or provide information to any government agency or commission or (y) consulting with legal counsel with respect to the interpretation or enforcement of this Agreement.
|
(c)
Noncompetition
. Employee agrees that during the term of the Employee’s employment with the Company and for a period of one (1) year following the Resignation Date, he shall not, directly or indirectly, compete with the Company by providing services to any other person, partnership, association, corporation, or other entity that is an “Oil and Gas Business” in the Permian Basin. As used herein, an “Oil and Gas Business” means owning, managing, acquiring, attempting to acquire, soliciting the acquisition of, operating, controlling, or developing Oil and Gas interests, or engaging in or being connected with, as a principal, owner, officer, director, employee, shareholder, promoter, consultant, contractor, partner, member, joint venture, agent, equity owner or in any other capacity whatsoever, any of the foregoing activities of the oil and gas exploration and production business. The parties agree that the above restrictions on competition are completely severable and independent agreements supported by good and valuable consideration and, as such, shall survive the termination of this Agreement for whatever reason. The parties further agree that any invalidity or unenforceability of any one or more of such restrictions on competition shall not render invalid or unenforceable any remaining restrictions on competition. Additionally, should a court of competent jurisdiction determine that the scope of any provision of this Section 3(c) is too broad to be enforced as written, the parties intend that the court reform the provision to such narrower scope as it determines to be reasonable and enforceable.
(d)
Nonsolicitation
. During the term of Employee’s employment with the Company and for a period of three (3) years following the Resignation Date, Employee shall not, on his own behalf or on behalf of any other person, partnership, association, corporation, or other entity: (a) directly, indirectly, or through a third party hire or cause to be hired; (b) directly, indirectly, or through a third party solicit; or (c) in any manner attempt to influence or induce any employee of the Company or its subsidiaries or affiliates to leave the employment of the
Company or its subsidiaries or affiliates, nor shall he use or disclose to any person, partnership, association, corporation, or other entity any information obtained concerning the names and addresses the Company’s employees. The parties agree that the above restrictions on hiring and solicitation are completely severable and independent agreements supported by good and valuable consideration and, as such, shall survive the termination of this Agreement for whatever reason. The parties further agree that any invalidity or unenforceability of any one or more such restrictions on hiring and solicitation shall not render invalid or unenforceable any remaining restrictions on hiring and solicitation. Additionally, should a court of competent jurisdiction determine that the scope of any provision of this Section 3(d) is too broad to be enforced as written, the parties intend that the court reform the provision to such narrower scope as it determines to be reasonable and enforceable.
(e)
Cooperation
. Employee agrees to be reasonably available to the Company Entities or their representatives (including their attorneys) to provide information and assistance as requested by the Company. Such information and assistance may include testifying (and preparing to testify) as a witness in any proceeding or otherwise providing information or reasonable assistance to the Company in connection with any investigation, claim or suit. The Employee further agrees not to voluntarily assist any non-governmental adverse party in an action or claim against the Company. Any cooperation required of Employee shall not unreasonably interfere with Employee’s other business endeavors.
(f)
Confidentiality and Trade Secrets
. The Employee promises not to use in any way or disclose any of the Trade Secrets (as such term is defined in the 2017 Severance Agreement) or any other confidential and proprietary information that is not generally known to the public (collectively, and including Trade Secrets,
“Confidential Information”
) directly or indirectly, either during or after the term of his employment, except as required in the course of his employment with the Company, if required in connection with a judicial or administrative proceeding, or if the information becomes public knowledge other than as a result of an unauthorized disclosure by the Employee. All files, records, documents, information, data, and similar items relating to the business of Company, whether prepared by the Employee or otherwise coming into his possession, will remain the exclusive property of Company and may not be removed from the premises of Company under any circumstances without the prior written consent of Company (except in the ordinary course of business during the Employee’s period of active employment under this Agreement), and in any event must be promptly delivered to Company upon termination of the Employee’s employment with Company. The Employee agrees that upon his receipt of any subpoena, process, or other requests to produce or divulge, directly or indirectly, any Confidential Information to any entity, agency, tribunal, or person, whether received during or after the term of the Employee’s employment with Company, the Employee shall timely notify and promptly deliver a copy of the subpoena, process, or other request to Company. For this purpose, the Employee irrevocably nominates and appoints Company (including any attorney retained by Company), as his true and lawful attorney-in-fact, to act in the Employee’s name, place, and stead to perform any act that the Employee might perform to defend and protect against any disclosure of any Confidential Information. The parties agree that the above restrictions on confidentiality and disclosure are completely severable and independent agreements supported by good and valuable consideration and, as such, shall survive the termination of this Agreement for whatever reason. The parties further
agree that any invalidity or unenforceability of any one or more of such restrictions on confidentiality and disclosure shall not render invalid or unenforceable any remaining restrictions on confidentiality and disclosure. Additionally, should a court of competent jurisdiction determine that the scope of any provision of this Section 3(f) is too broad to be enforced as written, the parties intend that the court reform the provision to such narrower scope as it determines to be reasonable and enforceable
(g)
Enforcement of Covenants
. Employee acknowledges that the injury that would be suffered by the Company as a result of a breach or threatened breach of the provisions of this Section 3 would be immediate and irreparable and that, because of the difficulty of measuring economic loss of any such breach or threatened breach, an award of monetary damages to the Company for any such breach would be an inadequate remedy. Accordingly, in the event that the Company determines that Employee has breached or attempted to breach or is threatening to breach any provision of this Section 3, in addition to any other remedies at law or in equity that any of the Company may have available to it, it is agreed that the Company shall be entitled, upon application to any court of proper jurisdiction, to temporary or permanent restraining orders or injunctions against Employee prohibiting such breach or attempted or threatened breach, without the necessity of: (i) proving immediate or irreparable harm; (ii) establishing that monetary damages are inadequate or that the Company does not have an adequate remedy at law; or (iii) posting any bond with respect thereto.
(h)
Repayment and Forfeiture
. Employee agrees that in the event that Employee breaches or challenges any term of Sections 2 or 3 hereof, and all or any part of Sections 2 or 3 are found invalid or unenforceable for any reason whatsoever by a court of competent jurisdiction or an arbitrator in a proceeding between Employee and Company, in addition to any other remedies at law or in equity the Company may have available to it, the Company shall not be obligated to make any of the payments and may cease to make such payments or to provide for any of the benefits specified in Section 1 hereof, and shall be entitled to recoup from Employee any and all of the value of the payments and benefits provided pursuant to Section 1 hereof that have vested or been paid pursuant to that Section.
Section 4.
Entire Agreement; Amendment; Third-Party Beneficiaries
. Employee and the Company agree and acknowledge that this Agreement contains and comprises the entire agreement and understanding between the parties with respect to the subject matter hereof, that no other representation, promise, covenant or agreement of any kind whatsoever has been made to cause either party hereto to execute this Agreement, that all agreements and understandings between the parties with respect to the subject matter hereof are embodied and expressed in this Agreement and that this Agreement supersedes all prior agreements, negotiations, discussions, understandings and commitments, written or oral, between the parties hereto with respect to such subject matter including, without limitation, the 2017 Severance Agreement. The parties also agree that the terms of this Agreement shall not be amended or changed except in writing and signed by Employee and a duly authorized agent of the Company. The parties to this Agreement further agree that this Agreement shall be binding on and inure to the benefit of Employee and the Company and the Company’s successors and assigns. Except to the extent otherwise provided in this Agreement with respect to the Company and the Released Parties, the provisions of this Agreement shall not confer upon any third party any
remedy, claim, liability, reimbursement or other right in excess of those existing without reference to this Agreement.
Section 5.
Timing and Consultation with Counsel
. Employee acknowledges that (i) he has been given a reasonable period of time, not less than twenty-one (21) days, to consider, and to request changes to, this Agreement and that if he signs this Agreement prior to the end of the 21-day time period he knowingly and voluntarily elected to do so; (ii) he has been advised to discuss the terms of this Agreement with legal counsel of his own choosing; (iii) he was advised that, if accepted, the Agreement could be revoked, in writing, for up to seven (7) days following the date of such acceptance; and (iv) if he revokes this Agreement, his separation from employment as of the Resignation Date shall nevertheless remain effective and he will not be entitled to any of the payments or benefits set forth in Sections 1(a), (b) or (c) hereof.
Section 6.
Revocation
. Notwithstanding any other provision in this Agreement to the contrary,
Employee may revoke this Agreement, in writing, for up to seven (7) days following the date of Employee’s execution of this Agreement, by delivering a written notice of Employee’s revocation of this Agreement to the Company. Any such notice of revocation shall be delivered via email and certified mail to the General Counsel of the Company at 1401 Enclave Parkway, Houston, Texas 77077 (email address: mecklund@callon.com).
Section 7.
Applicable Law; Venue
. This Agreement shall be interpreted and construed in accordance with the substantive laws of the State of Texas, without giving effect to any conflicts of laws provisions thereof that would result in the application of the laws of any other jurisdiction. THE EXCLUSIVE VENUE FOR THE RESOLUTION OF ANY DISPUTE RELATING TO THIS AGREEMENT OR EMPLOYEE’S EMPLOYMENT (EXCEPT FOR ANY DISPUTE THAT MAY BE SUBJECTED TO ARBITRATION BY MUTUAL AGREEMENT OF THE PARTIES HERETO AFTER THE DATE HEREOF) SHALL BE IN THE STATE AND FEDERAL COURTS LOCATED IN HARRIS COUNTY, TEXAS AND THE PARTIES HEREBY EXPRESSLY CONSENT TO THE JURISDICTION OF THOSE COURTS.
Section 8.
Section 409A; Other Tax Matters
. This Agreement is intended to provide payments that are exempt from or compliant with the provisions of Section 409A of the U.S. Internal Revenue Code of 1986 (the “
Code
”) and related regulations and Treasury pronouncements (“
Section 409A
”), and the Agreement shall be interpreted accordingly. Notwithstanding anything herein to the contrary, if on the date of Employee’s separation from service Employee is a “specified employee,” as defined in Section 409A, then all or a portion of any separation payments, or benefits under this Agreement that would be subject to the additional tax provided by Section 409A(a)(1)(B) of the Code if not delayed as required by Section 409A(a)(2)(B)(i) of the Code shall be delayed until the first day of the seventh month following Employee’s separation from service date (or, if earlier, Employee’s date of death) and shall be paid as a lump sum (without interest) on such date. For purposes of this Agreement, a termination of Employee’s employment must be a “separation from service” for purposes of Section 409A. For purposes of the application of Section 409A, each payment in a series of payments will be deemed a separate payment. Employee acknowledges and agrees that Employee has obtained no advice from the Company, or any of their respective officers, directors, employees, attorneys or other representatives, and that none of such persons or entities have made any representation regarding the tax consequences, if any, of Employee’s receipt of the payments, benefits and other consideration
provided for in this Agreement. Employee further acknowledges and agrees that Employee is personally responsible for the payment of all federal, state and local taxes that are due, or may be due, for any payments and other consideration received by Employee under this Agreement. Employee agrees to indemnify the Company and hold the Company harmless for any and all taxes, penalties or other assessments that Employee is, or may become, obligated to pay on account of any payments made and other consideration provided to Employee under this Agreement (including, without limitation, any amounts relating to or imposed by the operation of Section 409A of the Code).
Section 9.
Miscellaneous Provisions
.
(a)
Waivers
. Any term or provision of this Agreement may be waived, or the time for its performance may be extended, by the party hereto entitled to the benefit thereof. Any such waiver shall be validly and sufficiently given for the purposes of this Agreement if, as to either party hereto, it is in writing signed by such party or an authorized representative thereof. Failure on the part of the Company or Employee at any time to insist on strict compliance by the other party with any provisions of this Agreement shall not constitute a waiver of the obligations of either party hereto in respect thereof, or of either such party’s right hereunder to require strict compliance therewith in the future. No waiver of any breach of this Agreement shall be deemed to constitute a waiver of any other or subsequent breach.
(b)
Severability
. If any provision of this Agreement is held to be illegal, invalid or unenforceable under applicable law, that provision shall be severable and this Agreement shall be construed and enforced as if that illegal, invalid or unenforceable provision never comprised a part hereof, and the remaining provisions hereof shall remain in full force and effect and shall not be affected by the illegal, invalid or unenforceable provision, and there shall be added automatically as part of this Agreement a provision as similar in its terms to such illegal, invalid or unenforceable provision as may be possible and be legal, valid and enforceable.
(c)
Further Assurances
. Employee shall, on request by the Company from time to time after the date hereof, execute, acknowledge and deliver to the Company such other documents and instruments as the Company may require to give effect to the provisions of this Agreement, including a confirmatory release of the Released Claims as of the Resignation Date.
(d)
Execution in Counterparts
. This Agreement may be executed in any number of counterparts, each of which when so executed and delivered shall be an original, but all such counterparts shall together constitute one and the same instrument.
[
Signature page follows
]
I HAVE READ THE FOREGOING SEPARATION AGREEMENT, I FULLY UNDERSTAND ITS TERMS AND THAT I MAY BE WAIVING SIGNIFICANT LEGAL RIGHTS BY EXECUTING IT, AND I HAVE VOLUNTARILY EXECUTED IT ON THE DATE WRITTEN BELOW, SIGNIFYING THEREBY MY ASSENT TO AND WILLINGNESS TO BE BOUND BY, ITS TERMS:
By:______________________________________
Gary A. Newberry
Date_____________________________________
CALLON PETROLEUM COMPANY
By:______________________________________
Name: Joseph C. Gatto, Jr.
Title: President & Chief Executive Officer
Exhibit 10.20
EMPLOYEE RESTRICTED STOCK UNIT AWARD AGREEMENT (NON-OFFICER)
CALLON PETROLEUM COMPANY
2018 OMNIBUS INCENTIVE PLAN
THIS AGREEMENT (“
Agreement
”) is effective as of January 31, 2019 (the “
Grant Date
”), by and between Callon Petroleum Company, a Delaware corporation (the “
Company
”), and ____________________ (the “
Grantee
”).
The Company has adopted the Callon Petroleum Company 2018 Omnibus Incentive Plan, as effective May 10, 2018 (as may be amended from time to time, the “
Plan
”), which by this reference is made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.
Pursuant to the Plan, the Committee, which has generally been assigned responsibility for administering the Plan, has determined that it would be in the interest of the Company and its stockholders to grant the restricted stock units provided herein in order to provide Grantee with additional remuneration for services rendered, to encourage Grantee to remain in the employ of the Company or its Subsidiaries and to increase Grantee’s personal interest in the continued success and progress of the Company.
The Company and Grantee therefore agree as follows:
1.
Grant of Restricted Stock Units
. Subject to the terms and conditions herein, effective as of the Grant Date, the Company hereby awards to the Grantee, pursuant to the Plan, a right to receive __________ shares of Common Stock of the Company, par value $.01 per share (“
Restricted Stock Units
”).
2.
Vesting Schedule and Settlement
.
Subject to the provisions of Section 3 hereof, the Restricted Stock Units shall vest in one-third increments (rounded up to the nearest whole number) on each of April 1, 2020, April 1, 2021 and April 1, 2022 (each, a “
Vesting Date
”); provided that the Grantee remains in continuous employment with the Company through the applicable Vesting Date. For purposes of this Agreement, references to employment with the Company include employment with any successor to the Company as well as employment with any Subsidiary.
As soon as practicable (but in no event later than thirty (30) days) following the occurrence of the Vesting Date or vesting pursuant to Section 3, the Company shall deliver to the Grantee or, as applicable, the Grantee’s legal representative, estate, beneficiary or heir, certificates representing the applicable number shares of Common Stock or cause the applicable number of shares of Common Stock to be evidenced in book entry form in the Grantee’s name in the stock register of the Company maintained by the Company’s transfer agent.
3.
Termination of Employment; Forfeiture
.
(a)
Death and Disability
. Upon termination of the Grantee’s employment with the Company as a result of the death or Disability of the Grantee, the Restricted Stock Units shall immediately vest. For purposes hereof, “
Disability
” shall mean the physical or mental inability of Grantee to carry out the normal and usual duties of his position on a full-time basis for an entire period of six (6) continuous months together with the reasonable likelihood, as determined by the Company, that Grantee, upon the advice of a qualified physician, will be unable to carry out the normal and usual duties of his position.
(b)
Qualified Separation from Service
. If the Grantee’s employment is terminated due to a Qualified Separation from Service, the Committee may determine, in its sole discretion, that all remaining unvested Restricted Stock Units shall be 100% vested a of such termination date. For purposes hereof, a “
Qualified Separation from Service
” is defined as a termination of Grantee’s employment with the Company, other than for Cause, provided that, as of the date of such termination (i) Grantee has attained a minimum of ten (10) years of employment with the Company, and (ii) Grantee has attained the age of fifty-five (55).
For purposes hereof, “
Cause
” is defined as: (i) the conviction of the Grantee by a court of competent jurisdiction as to which no further appeal can be taken of a crime involving moral turpitude or a felony or entering the plea of nolo contendere to such crime by the Grantee; (ii) the commission by the Grantee of a material act of fraud upon the Company, any Subsidiary or Affiliate; (iii) the material misappropriation by the Grantee of any funds or other property of the Company, any Subsidiary or Affiliate; (iv) the knowing engagement by the Grantee without the written approval of the Company, in any material activity which directly competes with the business of the Company, any Subsidiary or Affiliate, or which would directly result in material injury to the business or reputation of the Company or any Subsidiary or Affiliate; (v)(1) a material breach by the Grantee during the Grantee’s employment with the Company of any of the restrictive covenants set out in the Grantee’s employment agreement with the Company, if applicable, or (2) the material nonperformance of the Grantee’s duties to the Company or any Subsidiary or Affiliate (other than by reason of the Grantee’s illness or incapacity); (vi) any breach of the Grantee’s fiduciary duties to the Company, including, without limitation, the duties of care, loyalty and obedience to the law; and (vii) the intentional failure of the Grantee to comply with the Company’s Code of Business Conduct and Ethics, or to otherwise discharge his duties in good faith and in a manner that the Grantee reasonably believes to be in the best interests of the Company, and with the care an ordinarily prudent person in a like position would exercise under similar circumstances.
(c)
Termination following a Change in Control
. In the event of the Grantee’s termination of employment by the Company for any reason other than Cause within the two-year period immediately following the effective date of a Change in Control, all remaining unvested Restricted Stock Units shall be 100% vested a of such termination date.
(d)
Forfeiture
. Upon termination of the Grantee’s employment with the Company for any reason other than death, Disability, Qualified Separation from Service with accelerated vesting by the Committee, or a termination without Cause following a Change in Control, all unvested Restricted Stock Units shall be immediately forfeited to the Company.
4.
No Ownership Rights Prior to Issuance of Shares of Common Stock; Dividend Equivalents
. Neither the Grantee nor any other person shall become the beneficial owner of the shares of Common Stock underlying the Restricted Stock Units, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such shares of Common Stock, unless and until and after such shares of Common Stock have been delivered to the Grantee as described in Section 2. Notwithstanding the foregoing, prior to the vesting of the underlying Restricted Stock Units, Dividend Equivalents shall be accrued, without interest, for the benefit of the Grantee. Dividend Equivalents shall be subject to the same vesting schedule as the underlying Restricted Stock Units and shall be payable in cash at the same time as the Restricted Stock Units are settled pursuant to Section 2.
5.
Mandatory Withholding of
Taxes.
Grantee acknowledges and agrees that the Company shall deduct from the shares of Common Stock otherwise deliverable a number of shares of Common Stock (valued at their Fair Market Value) on the applicable date that is equal to the amount of all federal, state and local taxes required to be withheld by the Company. In the event the Company, in its sole discretion, determines that the Grantee’s tax obligations will not be satisfied under the method otherwise expressly described above and the Grantee does not provide payment to the Company in the form of shares of Common Stock (valued at their Fair Market Value) sufficient to satisfy any withholding obligations, then the Grantee, subject to compliance with the Company’s insider trading policies, authorizes the Company or the Company’s Stock Plan Administrator, currently Fidelity, to (i) sell a number of shares of Common Stock issued or outstanding pursuant to the Award, which number of shares of Common Stock the Company determines has at least the market value sufficient to meet the tax withholding obligations, plus additional shares of Common Stock to account for rounding and market fluctuations and (ii) pay such tax withholding to the Company. The Grantee may elect to have the Company withhold or purchase, as applicable, from shares of Common Stock or cash that would otherwise payable or deliverable an amount of cash and/or number of shares of Common Stock (valued at their Fair Market Value) equal to the product of the maximum federal marginal rate that could be applicable to the Grantee and the Fair Market Value of the shares of Common Stock or cash otherwise payable or deliverable, as applicable.
6.
Restrictions Imposed by Law
. Without limiting the generality of Section 16 of the Plan, the Grantee agrees that the Company will not be obligated to deliver any shares of Common Stock if counsel to the Company determines that such delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the issuance or delivery of shares of Common Stock to comply with any such law, rule, regulation or agreement.
7.
Notice
. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:
Callon Petroleum Company
1401 Enclave Parkway, Suite 600
Houston, Texas 77077
Attention: Human Resources
with a copy to:
Callon Petroleum Company
1401 Enclave Parkway, Suite 600
Houston, Texas 77077
Attention: Law Department
Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, and (i) shall be sent by first class mail, postage prepaid, to Grantee’s address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or (ii) shall be sent to the Grantee’s e‑mail address specified in the Company’s records or e-mail address provided by the Grantee to the Company’s Stock Plan Administrator.
8.
Grantee Employment
. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the employ of the Company or interfere in any way with the right of the Company to terminate the Grantee’s employment at any time, with or without cause;
subject
,
however
, to the provisions of the Grantee’s employment agreement, if applicable.
9.
Governing Law
. This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Delaware. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of any such court in any such suit, action, or proceeding and waives any objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.
10.
Construction
. References in this Agreement to “this Agreement” and the words “herein,” “hereof,” “hereunder” and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative interpretations adopted by the Committee thereunder. All decisions of the Committee upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the sections of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.
11.
Code Section 409A
. Restricted Stock Units under this Agreement are designed to be exempt from or comply with Section 409A of the Code and the related Treasury Regulations thereunder and the provisions of this Agreement will be administered, interpreted and construed accordingly (or disregarded to the extent such provision cannot be so administered, interpreted, or construed). If the Grantee is identified by the Company as a “specified employee” within the meaning of Code Section 409A(a)(2)(B)(i) on the date on which the Grantee has a “separation from service” (other than due to death) within the meaning of Treasury Regulation § 1.409A-1(h), any amount payable or settled under this Agreement on account of a separation from service that is deferred compensation subject to Section 409A of the Code shall be paid or settled on the earliest of (1) the first business day following the expiration of six months from the Grantee’s separation from service, (2) the date of the Grantee’s death, or (3) such earlier date as complies with the requirements of Section 409A of the Code.
12.
Excise Taxes
. Notwithstanding anything to the contrary in this Agreement, if the Grantee is a “disqualified individual” (as defined in Code Section 280G(c)), and the payments and benefits provided for under this Agreement, together with any other payments and benefits which the Grantee has the right to receive from the Company or any of its affiliates or any party to a transaction with the Company or any of its affiliates, would constitute a “parachute payment” (as defined in Code Section 280G(b)(2)), then the payments and benefits provided for under this Agreement shall be either (a) reduced (but not below zero) so that the present value of such total amounts and benefits received by the Grantee from the Company and its affiliates will be one dollar ($1.00) less than three times the Grantee’s “base amount” (as defined in Code Section 280G(b)(3)) and so that no portion of such amounts and benefits received by the Grantee shall be subject to the excise tax imposed by Code Section 4999 or (b) paid in full, whichever produces the better net after-tax position to the Grantee (taking into account any applicable excise tax under Code Section 4999 and any other applicable taxes). The reduction of payments and benefits hereunder, if applicable, shall be made by reducing payments or benefits to be paid hereunder in the order in which such payment or benefit would be paid or provided (beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary, through to such payment or benefit that would be made first in time). The determination as to whether any such reduction in the amount of the payments and benefits provided hereunder is necessary shall be made by a nationally recognized accounting firm selected by the Company. If a reduced payment or benefit is made or provided and through error or otherwise that payment or benefit, when aggregated with other payments and benefits from the Company (or its affiliates) used in determining if a parachute payment exists, exceeds one dollar ($1.00) less than three times the Grantee’s base amount, then the Grantee shall immediately repay such excess to the Company upon notification that an overpayment has been made.
13.
Grantee Acceptance
. The Grantee shall accept the terms and conditions of this Agreement through the online acceptance procedures set forth by the Company’s Stock Plan Administrator. By electronically accepting this Agreement the Grantee acknowledges receipt of a copy of the Plan and hereby accepts this Award subject to all the terms and provisions hereof and thereof.
Exhibit 10. 21
2019 PERFORMANCE SHARE AWARD AGREEMENT
(OFFICER - CASH DISTRIBUTION)
CALLON PETROLEUM COMPANY
2018 OMNIBUS INCENTIVE PLAN
THIS AGREEMENT (“
Agreement
”) is effective as of January 31, 2019 (the “
Grant Date
”), by and between Callon Petroleum Company, a Delaware corporation (the “
Company
”), and ____________________ (the “
Grantee
”).
The Company has adopted the Callon Petroleum Company 2018 Omnibus Incentive Plan, as effective May 10, 2018 (as may be amended from time to time, the “
Plan
”), which by this reference is made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.
Pursuant to the Plan, the Committee, which has generally been assigned responsibility for administering the Plan, has determined that it would be in the interest of the Company and its stockholders to grant the performance shares provided herein in order to provide Grantee with additional remuneration for services rendered, to encourage Grantee to remain in the employ of the Company or its Subsidiaries and to increase Grantee’s personal interest in the continued success and progress of the Company.
The Company and Grantee therefore agree as follows:
1.
Grant of Performance Shares
.
Pursuant to the Plan and subject further to the terms and conditions herein, the Company and Grantee enter into this Agreement pursuant to which the Grantee has a target of ________ performance shares (the “
Target Award
”) where each performance share represents the right to receive the cash equivalent of the Fair Market Value of one share of Common Stock (“
Performance Shares
”). The range of Performance Shares which may be earned by the Grantee is 0 to 200% of the Target Award. The Performance Shares that will vest, if at all, are the Adjusted Performance Shares determined based on the performance metrics set forth in
Exhibit A
to this Agreement; provided that, subject to the provisions of Section 4, the Grantee remains in continuous employment with the Company through the last day of the Performance Period (as defined below). For purposes of this Agreement, references to employment with the Company include employment with any successor to the Company as well as employment with any Subsidiary.
2.
Performance Period
.
Subject to the provisions of Section 4, Performance Shares will be paid to the Grantee, if at all, following the close of the performance period beginning on December 31, 2018 and ending on December 31, 2021 (the “
Performance Period
”) based upon the Company’s achievement of the performance metrics set forth in
Exhibit A
.
3.
Payment of Performance Shares
. Upon vesting of the Adjusted Performance Shares in accordance with
Exhibit A
or Section 4, the Adjusted Performance Shares shall be settled in cash, in each case subject to Section 6. For those Adjusted Performance Shares settleable in cash, the Grantee
shall be entitled to receive a cash lump sum payment in an amount that is equal to (i) the average closing price of a share of Common Stock during the twenty (20) day trading period ending on the Vesting Date multiplied by (ii) the Adjusted Performance Shares. The payment shall be made or shares of Common Stock delivered within forty-five (45) calendar days from the Vesting Date.
4.
Termination of Employment; Forfeiture
.
(a)
Death and Disability
. Upon termination of the Grantee’s employment with the Company as a result of the death or Disability of the Grantee, the Performance Shares shall immediately vest, with the number of Adjusted Performance Shares determined in accordance with Exhibit A, as if the date of such termination of employment was the last day of the Performance Period. For purposes hereof, “
Disability
” shall mean the physical or mental inability of Grantee to carry out the normal and usual duties of his position on a full-time basis for an entire period of six (6) continuous months together with the reasonable likelihood, as determined by the Committee, that Grantee, upon the advice of a qualified physician, will be unable to carry out the normal and usual duties of his position.
(b)
Qualified Separation from Service
. If the Grantee’s employment is terminated due to a Qualified Separation from Service, the Committee may determine, in its sole discretion, that the Performance Shares shall immediately vest, with the number of Adjusted Performance Shares determined in accordance with
Exhibit A
, as if December 31 of the year of such termination of employment was the last day of the Performance Period. For purposes hereof, a “
Qualified Separation from Service
” is defined as a termination of Grantee’s employment with the Company, other than for Cause, provided that, as of the date of such termination (i) Grantee has attained a minimum of ten (10) years of employment with the Company, (ii) Grantee has attained the age of fifty-five (55), (iii) in the event such termination of employment is a voluntary termination by the Grantee, the Grantee has provided the Company with a notice of such intent to terminate at least six months prior to the termination date and (iv) Grantee enters into an agreement not to compete with the Company and its Affiliates for a period of at least one year, which agreement, both in form and substance, is provided by the Committee or is otherwise satisfactory to the Committee.
For purposes hereof, “
Cause
” is defined as: (i) the conviction of the Grantee by a court of competent jurisdiction as to which no further appeal can be taken of a crime involving moral turpitude or a felony or entering the plea of nolo contendere to such crime by the Grantee; (ii) the commission by the Grantee of a material act of fraud upon the Company, any Subsidiary or Affiliate; (iii) the material misappropriation by the Grantee of any funds or other property of the Company, any Subsidiary or Affiliate; (iv) the knowing engagement by the Grantee without the written approval of the Board, in any material activity which directly competes with the business of the Company, any Subsidiary or Affiliate, or which would directly result in material injury to the business or reputation of the Company or any Subsidiary or Affiliate; (v)(1) a material breach by the Grantee during the Grantee’s employment with the Company of any of the restrictive covenants set out in the Grantee’s employment agreement with the Company, if applicable, or (2) the willful and material nonperformance of the Grantee’s duties to the Company or any Subsidiary or Affiliate (other than by reason of the Grantee’s illness or incapacity), and, for purposes of this clause (v), no act or failure to act on Grantee’s part shall be deemed “willful” unless it is done or omitted by the Grantee not in good faith and without his reasonable belief that such action or omission was in the best interest of the Company, (vi) any breach of the Grantee’s fiduciary duties to the Company, including, without limitation, the duties of care, loyalty and obedience to the
law; and (vii) the intentional failure of the Grantee to comply with the Company’s Code of Business Conduct and Ethics, or to otherwise discharge his duties in good faith and in a manner that the Grantee reasonably believes to be in the best interests of the Company, and with the care an ordinarily prudent person in a like position would exercise under similar circumstances.
(c)
Termination following a Change in Control
. In the event of the Grantee’s termination of employment by the Company for any reason other than Cause within the two-year period immediately following the effective date of a Change in Control, the Performance Shares shall immediately vest, with the number of Adjusted Performance Shares determined in accordance with
Exhibit A
, as if the date of the Change in Control was the last day of the Performance Period.
(d)
Forfeiture
. Upon termination of the Grantee’s employment with the Company for any reason other than death, Disability, Qualified Separation from Service with accelerated vesting by the Committee, or a termination without Cause following a Change in Control, all unvested Performance Shares shall be immediately forfeited to the Company.
5.
No Ownership Rights Prior to Issuance of Shares of Common Stock; Dividend Equivalents
. Neither the Grantee nor any other person shall become the beneficial owner of the shares of Common Stock underlying the Performance Shares, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such shares of Common Stock.
Notwithstanding the foregoing, prior to the vesting of the underlying Performance Shares, Dividend Equivalents shall be accrued on the Target Award, without interest, for the benefit of the Grantee. Dividend Equivalents shall be subject to the same vesting conditions as the underlying Performance Shares and shall be payable in cash at the same time as the Adjusted Performance Shares are settled pursuant to Section 3.
6.
Mandatory Withholding of Taxes
. Grantee acknowledges and agrees that the Company shall deduct from the cash otherwise payable or deliverable an amount of cash that is equal to the amount of all federal, state and local taxes required to be withheld by the Company. The Grantee may elect to have the Company withhold from cash that would otherwise payable an amount of cash equal to the product of the maximum federal marginal rate that could be applicable to the Grantee and the cash otherwise payable.
7.
Notice
. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:
Callon Petroleum Company
1401 Enclave Parkway, Suite 600
Houston, Texas 77077
Attention: Human Resources
with a copy to:
Callon Petroleum Company
1401 Enclave Parkway, Suite 600
Houston, Texas 77077
Attention: Law Department
Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, and (i) shall be sent by first class mail, postage prepaid, to Grantee’s address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or (ii) shall be sent to the Grantee’s e‑mail address specified in the Company’s records or e-mail address provided by the Grantee to the Company’s Stock Plan Administrator.
8.
Grantee Employment
. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the employ of the Company or interfere in any way with the right of the Company to terminate the Grantee’s employment at any time, with or without cause;
subject
,
however
, to the provisions of the Grantee’s employment agreement, if applicable.
9.
Governing Law
.
This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Delaware. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of any such court in any such suit, action, or proceeding and waives any objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.
10.
Construction
. References in this Agreement to “this Agreement” and the words “herein,” “hereof,” “hereunder” and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative interpretations adopted by the Committee thereunder. All decisions of the Committee upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the sections of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.
11.
Code Section 409A
. Performance Shares under this Agreement are designed to be exempt from or comply with Section 409A of the Code and the related Treasury Regulations thereunder and the provisions of this Agreement will be administered, interpreted and construed accordingly (or disregarded to the extent such provision cannot be so administered, interpreted, or construed). If the Grantee is identified by the Company as a “specified employee” within the meaning of Code Section 409A(a)(2)(B)(i) on the date on which the Grantee has a “separation from service” (other than due to death) within the meaning of Treasury Regulation § 1.409A-1(h), any amount payable or settled under this Agreement on account of a separation from service that is deferred compensation subject to Section 409A of the Code shall be paid or settled on the earliest of (1) the first business day following the
expiration of six months from the Grantee’s separation from service, (2) the date of the Grantee’s death, or (3) such earlier date as complies with the requirements of Section 409A of the Code.
12.
Excise Taxes.
Notwithstanding anything to the contrary in this Agreement, if the Grantee is a “disqualified individual” (as defined in Code Section 280G(c)), and the payments and benefits provided for under this Agreement, together with any other payments and benefits which the Grantee has the right to receive from the Company or any of its affiliates or any party to a transaction with the Company or any of its affiliates, would constitute a “parachute payment” (as defined in Code Section 280G(b)(2)), then the payments and benefits provided for under this Agreement shall be either (a) reduced (but not below zero) so that the present value of such total amounts and benefits received by the Grantee from the Company and its affiliates will be one dollar ($1.00) less than three times the Grantee’s “base amount” (as defined in Code Section 280G(b)(3)) and so that no portion of such amounts and benefits received by the Grantee shall be subject to the excise tax imposed by Code Section 4999 or (b) paid in full, whichever produces the better net after-tax position to the Grantee (taking into account any applicable excise tax under Code Section 4999 and any other applicable taxes). The reduction of payments and benefits hereunder, if applicable, shall be made by reducing payments or benefits to be paid hereunder in the order in which such payment or benefit would be paid or provided (beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary, through to such payment or benefit that would be made first in time). The determination as to whether any such reduction in the amount of the payments and benefits provided hereunder is necessary shall be made by a nationally recognized accounting firm selected by the Company. If a reduced payment or benefit is made or provided and through error or otherwise that payment or benefit, when aggregated with other payments and benefits from the Company (or its affiliates) used in determining if a parachute payment exists, exceeds one dollar ($1.00) less than three times the Grantee’s base amount, then the Grantee shall immediately repay such excess to the Company upon notification that an overpayment has been made.
13.
Grantee Acceptance
. The Grantee shall accept the terms and conditions of this Agreement through the online acceptance procedures set forth by the Company’s Stock Plan Administrator. By electronically accepting this Agreement the Grantee acknowledges receipt of a copy of the Plan and hereby accepts this Award subject to all the terms and provisions hereof and thereof.
Exhibit A
Calculation of the
Adjusted Performance Shares
Subject to the provisions in the Agreement, effective as of the last day of the Performance Period (the “
Vesting Date
”), the Company’s “Total Shareholder Return” will be calculated and compared to the same calculated total shareholder return of the selected group of peer companies that are listed below. As soon as administratively practicable following the Vesting Date, the number of Performance Shares that vest under the Agreement will be determined in accordance with the payout percentage that is based on the Company’s relative ranking with the peer companies as shown in the table below (such number, the “
Adjusted Performance Shares
”).
For purposes of this calculation, the Company’s total shareholder return and that of the peer companies will be adjusted if necessary for stock splits, and the percentage increase or decrease will be calculated as follows:
|
|
|
|
|
|
|
|
|
|
(EP + CD) - BP
|
= % increase or decrease
|
|
|
BP
|
|
|
Ending price (EP) - equals the average closing price of a share of Common Stock during the twenty (20) day trading period ending December 31, 2021.
Beginning price (BP) - equals the average closing price of a share of Common Stock during the twenty (20) day trading period ending December 31, 2018.
Cash Dividends (CD) - equals the cash dividends paid on a share of Common Stock during the Performance Period.
A similar calculation will also be performed for each peer company. The resulting percentage for the Company and the peer companies will then be ranked. Based on the relative ranking, the number of Performance Shares that vest under the Agreement will be determined in accordance with the following table:
|
|
|
Percentile Ranking
|
Payout as a % of Award
|
>90th Percentile
|
200%
|
50th Percentile
|
100%
|
25th Percentile
|
25%
|
<25th Percentile
|
0%
|
Percentile ranks between the percentiles described above would be interpolated. Based on a peer group of 13 companies (including the Company), this results in a payout schedule as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Rank
|
|
Payout (as a % of Award)
|
|
|
1-2
|
|
200%
|
|
|
3
|
|
183%
|
|
|
4
|
|
163%
|
|
|
5
|
|
142%
|
|
|
6
|
|
121%
|
|
|
7
|
|
100%
|
|
|
8
|
|
75%
|
|
|
9
|
|
50%
|
|
|
10
|
|
25%
|
|
|
11-13
|
|
0%
|
|
|
|
|
|
|
Peer Companies
|
|
|
Callon Petroleum (CPE)
|
|
|
Carrizo Oil & Gas (CRZO)
|
|
|
Centennial Resource Development (CDEV)
|
|
|
High Point Resources (HPR)
|
|
|
Jagged Peak Energy (JAG)
|
|
|
Laredo Petroleum (LPI)
|
|
|
Matador Resources (MTDR)
|
|
|
Oasis Petroleum (OAS)
|
|
|
Parsley Energy (PE)
|
|
|
PDC Energy (PDCE)
|
|
|
QEP Resources (QEP)
|
|
|
SM Energy (SM)
|
|
|
SRC Energy (SRC)
|
|
If the Total Shareholder Return of the Company is negative, then the maximum number of Adjusted Performance Shares that shall vest shall be the Target Award. In the event that during the Performance Period one or more of the listed peer companies is involved in a merger/acquisition, and (i) such merger/acquisition was announced on or prior to June 30, 2020, then such named peer company(s) will be replaced with a suitable replacement, as determined in the Committee’s sole discretion or (ii) such merger/acquisition was announced after June 30, 2020, then such peer company(s) will move to the top or the bottom of the ranking, based on whether said peer company’s Total Shareholder Return is greater or less than that for the Company, in each case measured as of the date of the announcement of such merger/acquisition. If, during the Performance Period, any peer company declares bankruptcy or initiates (or becomes subject to) a similar proceeding as a debtor due to insolvency, then, for the purposes of ranking the peer companies and the Company, such peer company shall be ranked last.
Exhibit 10.22
EMPLOYEE PERFORMANCE SHARE AWARD AGREEMENT
(OFFICER PAID IN SHARES)
CALLON PETROLEUM COMPANY
2018 OMNIBUS INCENTIVE PLAN
THIS AGREEMENT (“
Agreement
”) is effective as of January 31, 2019 (the “
Grant Date
”), by and between Callon Petroleum Company, a Delaware corporation (the “
Company
”), and ____________________ (the “
Grantee
”).
The Company has adopted the Callon Petroleum Company 2018 Omnibus Incentive Plan, as effective May 10, 2018 (as may be amended from time to time, the “
Plan
”), which by this reference is made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.
Pursuant to the Plan, the Committee, which has generally been assigned responsibility for administering the Plan, has determined that it would be in the interest of the Company and its stockholders to grant the performance shares provided herein in order to provide Grantee with additional remuneration for services rendered, to encourage Grantee to remain in the employ of the Company or its Subsidiaries and to increase Grantee’s personal interest in the continued success and progress of the Company.
The Company and Grantee therefore agree as follows:
1.
Grant of Performance Shares
.
Pursuant to the Plan and subject further to the terms and conditions herein, the Company and Grantee enter into this Agreement pursuant to which the Grantee has a target of ________ performance shares (the “
Target Award
”) where each performance share represents the right to receive one share of Common Stock (“
Performance Shares
”). The range of Performance Shares which may be earned by the Grantee is 0 to 200% of the Target Award. The Performance Shares that will vest, if at all, are the Adjusted Performance Shares determined based on the performance metrics set forth in
Exhibit A
to this Agreement; provided that, subject to the provisions of Section 4, the Grantee remains in continuous employment with the Company through the last day of the Performance Period (as defined below). For purposes of this Agreement, references to employment with the Company include employment with any successor to the Company as well as employment with any Subsidiary.
2.
Performance
Period
.
Subject to the provisions of Section 4, Performance Shares will be paid to the Grantee, if at all, following the close of the performance period beginning on December 31, 2018 and ending on December 31, 2021 (the “
Performance Period
”) based upon the Company’s achievement of the performance metrics set forth in
Exhibit A
.
3.
Payment of Performance Shares
. Upon vesting of the Adjusted Performance Shares in accordance with
Exhibit A
or Section 4, the Adjusted Performance Shares shall be settled in Common Stock subject to Section 6. For each Adjusted Performance Share settleable in Common Stock, the
Grantee shall be entitled to receive one share of Common Stock. The shares of Common Stock shall be delivered within forty-five (45) calendar days from the Vesting Date.
4.
Termination of Employment; Forfeiture
.
(a)
Death and Disability
. Upon termination of the Grantee’s employment with the Company as a result of the death or Disability of the Grantee, the Performance Shares shall immediately vest, with the number of Adjusted Performance Shares determined in accordance with Exhibit A, as if the date of such termination of employment was the last day of the Performance Period. For purposes hereof, “
Disability
” shall mean the physical or mental inability of Grantee to carry out the normal and usual duties of his position on a full-time basis for an entire period of six (6) continuous months together with the reasonable likelihood, as determined by the Committee, that Grantee, upon the advice of a qualified physician, will be unable to carry out the normal and usual duties of his position.
(b)
Qualified Separation from Service
. If the Grantee’s employment is terminated due to a Qualified Separation from Service, the Committee may determine, in its sole discretion, that the Performance Shares shall immediately vest, with the number of Adjusted Performance Shares determined in accordance with
Exhibit A
, as if December 31 of the year of such termination of employment was the last day of the Performance Period. For purposes hereof, a “
Qualified Separation from Service
” is defined as a termination of Grantee’s employment with the Company, other than for Cause, provided that, as of the date of such termination (i) Grantee has attained a minimum of ten (10) years of employment with the Company, (ii) Grantee has attained the age of fifty-five (55), (iii) in the event such termination of employment is a voluntary termination by the Grantee, the Grantee has provided the Company with a notice of such intent to terminate at least six months prior to the termination date and (iv) Grantee enters into an agreement not to compete with the Company and its Affiliates for a period of at least one year, which agreement, both in form and substance, is provided by the Committee or is otherwise satisfactory to the Committee.
For purposes hereof, “
Cause
” is defined as: (i) the conviction of the Grantee by a court of competent jurisdiction as to which no further appeal can be taken of a crime involving moral turpitude or a felony or entering the plea of nolo contendere to such crime by the Grantee; (ii) the commission by the Grantee of a material act of fraud upon the Company, any Subsidiary or Affiliate; (iii) the material misappropriation by the Grantee of any funds or other property of the Company, any Subsidiary or Affiliate; (iv) the knowing engagement by the Grantee without the written approval of the Board, in any material activity which directly competes with the business of the Company, any Subsidiary or Affiliate, or which would directly result in material injury to the business or reputation of the Company or any Subsidiary or Affiliate; (v)(1) a material breach by the Grantee during the Grantee’s employment with the Company of any of the restrictive covenants set out in the Grantee’s employment agreement with the Company, if applicable, or (2) the willful and material nonperformance of the Grantee’s duties to the Company or any Subsidiary or Affiliate (other than by reason of the Grantee’s illness or incapacity), and, for purposes of this clause (v), no act or failure to act on Grantee’s part shall be deemed “willful” unless it is done or omitted by the Grantee not in good faith and without his reasonable belief that such action or omission was in the best interest of the Company, (vi) any breach of the Grantee’s fiduciary duties to the Company, including, without limitation, the duties of care, loyalty and obedience to the law; and (vii) the intentional failure of the Grantee to comply with the Company’s Code of Business Conduct and Ethics, or to otherwise discharge his duties in good faith and in a manner that the Grantee
reasonably believes to be in the best interests of the Company, and with the care an ordinarily prudent person in a like position would exercise under similar circumstances.
(c)
Termination following a Change in Control
. In the event of the Grantee’s termination of employment by the Company for any reason other than Cause within the two-year period immediately following the effective date of a Change in Control, the Performance Shares shall immediately vest, with the number of Adjusted Performance Shares determined in accordance with
Exhibit A
, as if the date of the Change in Control was the last day of the Performance Period.
(d)
Forfeiture
. Upon termination of the Grantee’s employment with the Company for any reason other than death, Disability, Qualified Separation from Service with accelerated vesting by the Committee, or a termination without Cause following a Change in Control, all unvested Performance Shares shall be immediately forfeited to the Company.
5.
No Ownership Rights Prior to Issuance of Shares of Common Stock; Dividend Equivalents
. Neither the Grantee nor any other person shall become the beneficial owner of the shares of Common Stock underlying the Performance Shares, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such shares of Common Stock, unless and until and after such shares of Common Stock have been delivered to the Grantee as described in Section 3.
Notwithstanding the foregoing, prior to the vesting of the underlying Performance Shares, Dividend Equivalents shall be accrued on the Target Award, without interest, for the benefit of the Grantee. Dividend Equivalents shall be subject to the same vesting conditions as the underlying Performance Shares and shall be payable in cash at the same time as the Adjusted Performance Shares are settled pursuant to Section 3.
6.
Mandatory Withholding of Taxes
. Grantee acknowledges and agrees that the Company shall deduct from the shares of Common Stock otherwise deliverable a number of shares of Common Stock (valued at their Fair Market Value) on the applicable date that is equal to the amount of all federal, state and local taxes required to be withheld by the Company. In the event the Company, in its sole discretion, determines that the Grantee’s tax obligations will not be satisfied under the method otherwise expressly described above and the Grantee does not provide payment to the Company in the form of shares of Common Stock (valued at their Fair Market Value) sufficient to satisfy any withholding obligations, then, the Grantee, subject to compliance with the Company’s insider trading policies, authorizes the Company or the Company’s Stock Plan Administrator, currently Fidelity, to (i) sell a number of shares of Common Stock issued or outstanding pursuant to the Award, which number of shares of Common Stock the Company determines has at least the market value sufficient to meet the tax withholding obligations, plus additional shares of Common Stock to account for rounding and market fluctuations and (ii) pay such tax withholding to the Company. The Grantee may elect to have the Company withhold or purchase, as applicable, from shares of Common Stock that would otherwise be deliverable a number of shares of Common Stock (valued at their Fair Market Value) equal to the product of the maximum federal marginal rate that could be applicable to the Grantee and the Fair Market Value of the shares of Common Stock otherwise deliverable.
7.
Restrictions Imposed by Law
.
Without limiting the generality of Section 16 of the Plan, the Grantee agrees that the Company will not be obligated to deliver any shares of Common Stock if counsel to the Company determines that such delivery would violate any applicable law or any rule
or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the issuance or delivery of shares of Common Stock to comply with any such law, rule, regulation or agreement.
8.
Notice
. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:
Callon Petroleum Company
1401 Enclave Parkway, Suite 600
Houston, Texas 77077
Attention: Human Resources
with a copy to:
Callon Petroleum Company
1401 Enclave Parkway, Suite 600
Houston, Texas 77077
Attention: Law Department
Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, and (i) shall be sent by first class mail, postage prepaid, to Grantee’s address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or (ii) shall be sent to the Grantee’s e‑mail address specified in the Company’s records or e-mail address provided by the Grantee to the Company’s Stock Plan Administrator.
9.
Grantee Employment
. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the employ of the Company or interfere in any way with the right of the Company to terminate the Grantee’s employment at any time, with or without cause;
subject
,
however
, to the provisions of the Grantee’s employment agreement, if applicable.
10.
Governing Law
.
This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Delaware. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of any such court in any such suit, action, or proceeding and waives any objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.
11.
Construction
. References in this Agreement to “this Agreement” and the words “herein,” “hereof,” “hereunder” and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative
interpretations adopted by the Committee thereunder. All decisions of the Committee upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the sections of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.
12.
Code Section 409A
. Performance Shares under this Agreement are designed to be exempt from or comply with Section 409A of the Code and the related Treasury Regulations thereunder and the provisions of this Agreement will be administered, interpreted and construed accordingly (or disregarded to the extent such provision cannot be so administered, interpreted, or construed). If the Grantee is identified by the Company as a “specified employee” within the meaning of Code Section 409A(a)(2)(B)(i) on the date on which the Grantee has a “separation from service” (other than due to death) within the meaning of Treasury Regulation § 1.409A-1(h), any amount payable or settled under this Agreement on account of a separation from service that is deferred compensation subject to Section 409A of the Code shall be paid or settled on the earliest of (1) the first business day following the expiration of six months from the Grantee’s separation from service, (2) the date of the Grantee’s death, or (3) such earlier date as complies with the requirements of Section 409A of the Code.
13.
Excise Taxes.
Notwithstanding anything to the contrary in this Agreement, if the Grantee is a “disqualified individual” (as defined in Code Section 280G(c)), and the payments and benefits provided for under this Agreement, together with any other payments and benefits which the Grantee has the right to receive from the Company or any of its affiliates or any party to a transaction with the Company or any of its affiliates, would constitute a “parachute payment” (as defined in Code Section 280G(b)(2)), then the payments and benefits provided for under this Agreement shall be either (a) reduced (but not below zero) so that the present value of such total amounts and benefits received by the Grantee from the Company and its affiliates will be one dollar ($1.00) less than three times the Grantee’s “base amount” (as defined in Code Section 280G(b)(3)) and so that no portion of such amounts and benefits received by the Grantee shall be subject to the excise tax imposed by Code Section 4999 or (b) paid in full, whichever produces the better net after-tax position to the Grantee (taking into account any applicable excise tax under Code Section 4999 and any other applicable taxes). The reduction of payments and benefits hereunder, if applicable, shall be made by reducing payments or benefits to be paid hereunder in the order in which such payment or benefit would be paid or provided (beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary, through to such payment or benefit that would be made first in time). The determination as to whether any such reduction in the amount of the payments and benefits provided hereunder is necessary shall be made by a nationally recognized accounting firm selected by the Company. If a reduced payment or benefit is made or provided and through error or otherwise that payment or benefit, when aggregated with other payments and benefits from the Company (or its affiliates) used in determining if a parachute payment exists, exceeds one dollar ($1.00) less than three times the Grantee’s base amount, then the Grantee shall immediately repay such excess to the Company upon notification that an overpayment has been made.
14.
Grantee Acceptance
. The Grantee shall accept the terms and conditions of this Agreement through the online acceptance procedures set forth by the Company’s Stock Plan
Administrator. By electronically accepting this Agreement the Grantee acknowledges receipt of a copy of the Plan and hereby accepts this Award subject to all the terms and provisions hereof and thereof.
Exhibit A
Calculation of the
Adjusted Performance Shares
Subject to the provisions in the Agreement, effective as of the last day of the Performance Period (the “
Vesting Date
”), the Company’s “Total Shareholder Return” will be calculated and compared to the same calculated total shareholder return of the selected group of peer companies that are listed below. As soon as administratively practicable following the Vesting Date, the number of Performance Shares that vest under the Agreement will be determined in accordance with the payout percentage that is based on the Company’s relative ranking with the peer companies as shown in the table below (such number, the “
Adjusted Performance Shares
”).
For purposes of this calculation, the Company’s total shareholder return and that of the peer companies will be adjusted if necessary for stock splits, and the percentage increase or decrease will be calculated as follows:
|
|
|
|
|
|
|
|
|
|
(EP + CD) - BP
|
= % increase or decrease
|
|
|
BP
|
|
|
Ending price (EP) - equals the average closing price of a share of Common Stock during the twenty (20) day trading period ending December 31, 2021.
Beginning price (BP) - equals the average closing price of a share of Common Stock during the twenty (20) day trading period ending December 31, 2018.
Cash Dividends (CD) - equals the cash dividends paid on a share of Common Stock during the Performance Period.
A similar calculation will also be performed for each peer company. The resulting percentage for the Company and the peer companies will then be ranked. Based on the relative ranking, the number of Performance Shares that vest under the Agreement will be determined in accordance with the following table:
|
|
|
Percentile Ranking
|
Payout as a % of Award
|
>90th Percentile
|
200%
|
50th Percentile
|
100%
|
25th Percentile
|
25%
|
<25th Percentile
|
0%
|
Percentile ranks between the percentiles described above would be interpolated. Based on a peer group of 13 companies (including the Company), this results in a payout schedule as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Rank
|
|
Payout (as a % of Award)
|
|
|
1-2
|
|
200%
|
|
|
3
|
|
183%
|
|
|
4
|
|
163%
|
|
|
5
|
|
142%
|
|
|
6
|
|
121%
|
|
|
7
|
|
100%
|
|
|
8
|
|
75%
|
|
|
9
|
|
50%
|
|
|
10
|
|
25%
|
|
|
11-13
|
|
0%
|
|
|
|
|
|
|
Peer Companies
|
|
|
Callon Petroleum (CPE)
|
|
|
Carrizo Oil & Gas (CRZO)
|
|
|
Centennial Resource Development (CDEV)
|
|
|
High Point Resources (HPR)
|
|
|
Jagged Peak Energy (JAG)
|
|
|
Laredo Petroleum (LPI)
|
|
|
Matador Resources (MTDR)
|
|
|
Oasis Petroleum (OAS)
|
|
|
Parsley Energy (PE)
|
|
|
PDC Energy (PDCE)
|
|
|
QEP Resources (QEP)
|
|
|
SM Energy (SM)
|
|
|
SRC Energy (SRC)
|
|
If the Total Shareholder Return of the Company is negative, then the maximum number of Adjusted Performance Shares that shall vest shall be the Target Award. In the event that during the Performance Period one or more of the listed peer companies is involved in a merger/acquisition, and (i) such merger/acquisition was announced on or prior to June 30, 2020, then such named peer company(s) will be replaced with a suitable replacement, as determined in the Committee’s sole discretion or (ii) such merger/acquisition was announced after June 30, 2020, then such peer company(s) will move to the top or the bottom of the ranking, based on whether said peer company’s Total Shareholder Return is greater or less than that for the Company, in each case measured as of the date of the announcement of such merger/acquisition. If, during the Performance Period, any peer company declares bankruptcy or initiates (or becomes subject to) a similar proceeding as a debtor due to insolvency, then, for the purposes of ranking the peer companies and the Company, such peer company shall be ranked last.
Exhibit 10.23
EMPLOYEE RESTRICTED STOCK UNIT AWARD AGREEMENT (OFFICER)
CALLON PETROLEUM COMPANY
2018 OMNIBUS INCENTIVE PLAN
THIS AGREEMENT (“
Agreement
”) is effective as of January 31, 2019 (the “
Grant Date
”), by and between Callon Petroleum Company, a Delaware corporation (the “
Company
”), and ____________________ (the “
Grantee
”).
The Company has adopted the Callon Petroleum Company 2018 Omnibus Incentive Plan, as effective May 10, 2018 (as may be amended from time to time, the “
Plan
”), which by this reference is made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.
Pursuant to the Plan, the Committee, which has generally been assigned responsibility for administering the Plan, has determined that it would be in the interest of the Company and its stockholders to grant the restricted stock units provided herein in order to provide Grantee with additional remuneration for services rendered, to encourage Grantee to remain in the employ of the Company or its Subsidiaries and to increase Grantee’s personal interest in the continued success and progress of the Company.
The Company and Grantee therefore agree as follows:
1.
Grant of Restricted Stock Units
. Subject to the terms and conditions herein, effective as of the Grant Date, the Company hereby awards to the Grantee, pursuant to the Plan, a right to receive __________ shares of Common Stock of the Company, par value $.01 per share (“
Restricted Stock Units
”).
2.
Vesting Schedule and Settlement
.
Subject to the provisions of Section 3 hereof, the Restricted Stock Units shall vest in one-third increments (rounded up to the nearest whole number) on each of April 1, 2020, April 1, 2021 and April 1, 2022 (each, a “
Vesting Date
”); provided that the Grantee remains in continuous employment with the Company through the applicable Vesting Date. For purposes of this Agreement, references to employment with the Company include employment with any successor to the Company as well as employment with any Subsidiary.
As soon as practicable (but in no event later than thirty (30) days) following the occurrence of the Vesting Date or vesting pursuant to Section 3, the Company shall deliver to the Grantee or, as applicable, the Grantee’s legal representative, estate, beneficiary or heir certificates representing the applicable number shares of Common Stock or cause the applicable number of shares of Common
Stock to be evidenced in book entry form in the Grantee’s name in the stock register of the Company maintained by the Company’s transfer agent.
3.
Termination of Employment; Forfeiture
.
(a)
Death and Disability
. Upon termination of the Grantee’s employment with the Company as a result of the death or Disability of the Grantee, the Restricted Stock Units shall immediately vest. For purposes hereof, “
Disability
” shall mean the physical or mental inability of Grantee to carry out the normal and usual duties of his position on a full-time basis for an entire period of six (6) continuous months together with the reasonable likelihood, as determined by the Committee, that Grantee, upon the advice of a qualified physician, will be unable to carry out the normal and usual duties of his position.
(b)
Qualified Separation from Service
. If the Grantee’s employment is terminated due to a Qualified Separation from Service, the Committee may determine, in its sole discretion, that all remaining unvested Restricted Stock Units shall be 100% vested as of such termination date. For purposes hereof, a “
Qualified Separation from Service
” is defined as a termination of Grantee’s employment with the Company, other than for Cause, provided that, as of the date of such termination (i) Grantee has attained a minimum of ten (10) years of employment with the Company, (ii) Grantee has attained the age of fifty-five (55), (iii) in the event such termination of employment is a voluntary termination by the Grantee, the Grantee has provided the Company with a notice of such intent to terminate at least six months prior to the termination date and (iv) Grantee enters into an agreement not to compete with the Company and its Affiliates for a period of at least one year, which agreement, both in form and substance, is provided by the Committee or is otherwise satisfactory to the Committee.
For purposes hereof, “
Cause
” is defined as: (i) the conviction of the Grantee by a court of competent jurisdiction as to which no further appeal can be taken of a crime involving moral turpitude or a felony or entering the plea of nolo contendere to such crime by the Grantee; (ii) the commission by the Grantee of a material act of fraud upon the Company, any Subsidiary or Affiliate; (iii) the material misappropriation by the Grantee of any funds or other property of the Company, any Subsidiary or Affiliate; (iv) the knowing engagement by the Grantee without the written approval of the Board, in any material activity which directly competes with the business of the Company, any Subsidiary or Affiliate, or which would directly result in material injury to the business or reputation of the Company or any Subsidiary or Affiliate; (v)(1) a material breach by the Grantee during the Grantee’s employment with the Company of any of the restrictive covenants set out in the Grantee’s employment agreement with the Company, if applicable, or (2) the willful and material nonperformance of the Grantee’s duties to the Company or any Subsidiary or Affiliate (other than by reason of the Grantee’s illness or incapacity), and, for purposes of this clause (v), no act or failure to act on Grantee’s part shall be deemed “willful” unless it is done or omitted by the Grantee not in good faith and without his reasonable belief that such action or omission was in the best interest of the Company, (vi) any breach of the Grantee’s fiduciary duties to the Company, including, without limitation, the duties of care, loyalty and obedience to the law; and (vii) the intentional failure of the Grantee to comply with the Company's Code of Business Conduct and Ethics, or to otherwise discharge his duties in good faith and in a manner that the Grantee reasonably believes to be in the best interests of the Company, and with the care an ordinarily prudent person in a like position would exercise under similar circumstances.
(c)
Termination following a Change in Control
. In the event of the Grantee’s termination of employment by the Company for any reason other than Cause within the two-year period immediately following the effective date of a Change in Control, all remaining unvested Restricted Stock Units shall be 100% vested a of such termination date.
(d)
Forfeiture
. Upon termination of the Grantee’s employment with the Company for any reason other than death, Disability, Qualified Separation from Service with accelerated vesting by the Committee, or a termination without Cause following a Change in Control, all unvested Restricted Stock Units shall be immediately forfeited to the Company.
4.
No Ownership Rights Prior to Issuance of Shares of Common Stock; Dividend Equivalents
. Neither the Grantee nor any other person shall become the beneficial owner of the shares of Common Stock underlying the Restricted Stock Units, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such shares of Common Stock, unless and until and after such shares of Common Stock have been delivered to the Grantee as described in Section 2. Notwithstanding the foregoing, prior to the vesting of the underlying Restricted Stock Units, Dividend Equivalents shall be accrued, without interest, for the benefit of the Grantee. Dividend Equivalents shall be subject to the same vesting schedule as the underlying Restricted Stock Units and shall be payable in cash at the same time as the Restricted Stock Units are settled pursuant to Section 2.
5.
Mandatory Withholding of
Taxes.
Grantee acknowledges and agrees that the Company shall deduct from the shares of Common Stock otherwise deliverable a number of shares of Common Stock (valued at their Fair Market Value) on the applicable date that is equal to the amount of all federal, state and local taxes required to be withheld by the Company. In the event the Company, in its sole discretion, determines that the Grantee’s tax obligations will not be satisfied under the method otherwise expressly described above and the Grantee does not provide payment to the Company in the form of shares of Common Stock (valued at their Fair Market Value) sufficient to satisfy any withholding obligations, then the Grantee, subject to compliance with the Company’s insider trading policies, authorizes the Company or the Company’s Stock Plan Administrator, currently Fidelity, to (i) sell a number of shares of Common Stock issued or outstanding pursuant to the Award, which number of shares of Common Stock the Company determines has at least the market value sufficient to meet the tax withholding obligations, plus additional shares of Common Stock to account for rounding and market fluctuations and (ii) pay such tax withholding to the Company. The Grantee may elect to have the Company withhold or purchase, as applicable, from shares of Common Stock or cash that would otherwise payable or deliverable an amount of cash and/or number of shares of Common Stock (valued at their Fair Market Value) equal to the product of the maximum federal marginal rate that could be applicable to the Grantee and the Fair Market Value of the shares of Common Stock or cash otherwise payable or deliverable, as applicable.
6.
Restrictions Imposed by Law
. Without limiting the generality of Section 16 of the Plan, the Grantee agrees that the Company will not be obligated to deliver any shares of Common Stock if counsel to the Company determines that such delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the issuance or delivery of shares of Common Stock to comply with any such law, rule, regulation or agreement.
7.
Notice
. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:
Callon Petroleum Company
1401 Enclave Parkway, Suite 600
Houston, Texas 77077
Attention: Human Resources
with a copy to:
Callon Petroleum Company
1401 Enclave Parkway, Suite 600
Houston, Texas 77077
Attention: Law Department
Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, and (i) shall be sent by first class mail, postage prepaid, to Grantee’s address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or (ii) shall be sent to the Grantee’s e‑mail address specified in the Company’s records or e-mail address provided by the Grantee to the Company’s Stock Plan Administrator.
8.
Grantee Employment
. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the employ of the Company or interfere in any way with the right of the Company to terminate the Grantee’s employment at any time, with or without cause;
subject
,
however
, to the provisions of the Grantee’s employment agreement, if applicable.
9.
Governing Law
. This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Delaware. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of any such court in any such suit, action, or proceeding and waives any objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.
10.
Construction
. References in this Agreement to “this Agreement” and the words “herein,” “hereof,” “hereunder” and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative interpretations adopted by the Committee thereunder. All decisions of the Committee upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the sections of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.
11.
Code Section 409A
. Restricted Stock Units under this Agreement are designed to be exempt from or comply with Section 409A of the Code and the related Treasury Regulations thereunder and the provisions of this Agreement will be administered, interpreted and construed accordingly (or disregarded to the extent such provision cannot be so administered, interpreted, or construed). If the Grantee is identified by the Company as a “specified employee” within the meaning of Code Section 409A(a)(2)(B)(i) on the date on which the Grantee has a “separation from service” (other than due to death) within the meaning of Treasury Regulation § 1.409A-1(h), any amount payable or settled under this Agreement on account of a separation from service that is deferred compensation subject to Section 409A of the Code shall be paid or settled on the earliest of (1) the first business day following the expiration of six months from the Grantee’s separation from service, (2) the date of the Grantee’s death, or (3) such earlier date as complies with the requirements of Section 409A of the Code.
12.
Excise Taxes
. Notwithstanding anything to the contrary in this Agreement, if the Grantee is a “disqualified individual” (as defined in Code Section 280G(c)), and the payments and benefits provided for under this Agreement, together with any other payments and benefits which the Grantee has the right to receive from the Company or any of its affiliates or any party to a transaction with the Company or any of its affiliates, would constitute a “parachute payment” (as defined in Code Section 280G(b)(2)), then the payments and benefits provided for under this Agreement shall be either (a) reduced (but not below zero) so that the present value of such total amounts and benefits received by the Grantee from the Company and its affiliates will be one dollar ($1.00) less than three times the Grantee’s “base amount” (as defined in Code Section 280G(b)(3)) and so that no portion of such amounts and benefits received by the Grantee shall be subject to the excise tax imposed by Code Section 4999 or (b) paid in full, whichever produces the better net after-tax position to the Grantee (taking into account any applicable excise tax under Code Section 4999 and any other applicable taxes). The reduction of payments and benefits hereunder, if applicable, shall be made by reducing payments or benefits to be paid hereunder in the order in which such payment or benefit would be paid or provided (beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary, through to such payment or benefit that would be made first in time). The determination as to whether any such reduction in the amount of the payments and benefits provided hereunder is necessary shall be made by a nationally recognized accounting firm selected by the Company. If a reduced payment or benefit is made or provided and through error or otherwise that payment or benefit, when aggregated with other payments and benefits from the Company (or its affiliates) used in determining if a parachute payment exists, exceeds one dollar ($1.00) less than three times the Grantee’s base amount, then the Grantee shall immediately repay such excess to the Company upon notification that an overpayment has been made.
13.
Grantee Acceptance
. The Grantee shall accept the terms and conditions of this Agreement through the online acceptance procedures set forth by the Company’s Stock Plan Administrator. By electronically accepting this Agreement the Grantee acknowledges receipt of a copy of the Plan and hereby accepts this Award subject to all the terms and provisions hereof and thereof.
Exhibit 21.1
|
|
|
|
Subsidiaries of Callon Petroleum Company
|
Name
|
|
State of Incorporation
|
Callon Offshore Production, Inc.
|
|
Mississippi
|
Callon Petroleum Operating Company
|
|
Delaware
|
Mississippi Marketing, Inc.
|
|
Mississippi
|
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We have issued our reports dated
February 26, 2019
, with respect to the consolidated financial statements and internal control over financial reporting included in the Annual Report of Callon Petroleum Company on Form 10-K for the year ended December 31, 2018. We consent to the incorporation by reference of said reports in the Registration Statements of Callon Petroleum Company on Form S-3 (File No. 333-202038), Form S-3ASR (File No. 333-210612), and on Forms S-8 (File No. 333-176061, File No. 333-212044, File No. 333-109744, File No. 333-188008, and File 333-224829).
/s/ GRANT THORNTON LLP
Houston, Texas
February 26, 2019
Exhibit 23.2
[Letterhead]
February 26, 2019
Callon Petroleum Company
1401 Enclave Parkway, Suite 600
Houston, Texas
Ladies and Gentlemen:
We hereby consent to the use of the name DeGolyer and MacNaughton, to the references to us and to our reserves reports for the years ended December 31, 2016, December 31, 2017, and December 31, 2018, in Callon Petroleum Company’s Annual Report on Form 10-K for the year ended December 31, 2018, references to DeGolyer and MacNaughton as an independent petroleum engineering consulting firm, to references to our report of third-party dated January 17, 2019, containing our opinion on the proved reserves, as of December 31, 2018, attributable to certain properties in which Callon Petroleum Company has represented it holds an interest (our Report), and to the inclusion of our Report as an exhibit in Callon Petroleum Company’s Annual Report on Form 10-K for the year ended December 31, 2018. We also consent to all such references and to the incorporation by reference of our Report in the Registration Statements to be filed by Callon Petroleum Company on its Form S-3 (File No. 333-202038), Form S-3ASR (File No. 333-210612), and Forms S-8 (File No. 333-176061, File No. 333-212044, File No. 333-109744, File No. 333-188008, and File 333-224829).
|
|
|
|
Very truly yours,
|
|
/s/ DeGolyer and MacNaughton
|
|
|
|
DeGOLYER and MacNAUGHTON
|
|
Texas Registered Engineering Firm F-716
|
Exhibit
31.1
CERTIFICATIONS
I, Joseph C. Gatto, Jr., certify that:
|
|
1.
|
I have reviewed this Annual Report on Form 10-K of Callon Petroleum Company;
|
|
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
|
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
|
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
|
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
|
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
|
|
c.
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and
|
|
|
d.
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
|
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
|
|
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
|
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
|
|
|
|
Date:
|
February 26, 2019
|
|
/s/ Joseph C. Gatto, Jr.
|
|
|
|
Joseph C. Gatto, Jr.
|
|
|
|
President and Chief Executive Officer
|
|
|
|
(Principal executive officer)
|
Exhibit
31.2
CERTIFICATIONS
I, James P. Ulm, II, certify that:
|
|
1.
|
I have reviewed this Annual Report on Form 10-K of Callon Petroleum Company;
|
|
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
|
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
|
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
|
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
|
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
|
|
c.
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and
|
|
|
d.
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
|
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
|
|
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
|
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
|
|
|
|
Date:
|
February 26, 2019
|
|
/s/ James P. Ulm, II
|
|
|
|
James P. Ulm, II
|
|
|
|
Senior Vice President & Chief Financial Officer
|
|
|
|
(Principal financial officer)
|
Exhibit
32
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350
In connection with the Annual Report on Form 10-K of Callon Petroleum Company for the year ended
December 31, 2018
, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacities and on the dates indicated below, each hereby certify pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Report fully complies with requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Date:
|
|
February 26, 2019
|
|
/s/ Joseph C. Gatto, Jr.
|
|
|
|
|
Joseph C. Gatto, Jr.
|
|
|
|
|
(Principal executive officer)
|
|
|
|
|
|
|
|
|
|
|
Date:
|
|
February 26, 2019
|
|
/s/ James P. Ulm, II
|
|
|
|
|
James P. Ulm II
|
|
|
|
|
(Principal financial officer)
|
The foregoing certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.
Exhibit 99.1
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
January 17, 2019
Callon Petroleum Company
200 North Canal Street
Natchez, Mississippi 39120
Ladies and Gentlemen:
Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2018, of the extent and value of the estimated net proved oil and gas reserves of certain properties in which Callon Petroleum Company (Callon) has represented it holds an interest. This evaluation was completed on January 17, 2019. The properties evaluated herein are located in Texas and offshore Gulf of Mexico. Callon has represented that these properties account for 100 percent on a net equivalent barrel basis of Callon’s net proved reserves as of December 31, 2018. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4
–
10(a) (1)
–
(32) of Regulation S
–
X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S
–
K and is to be used for inclusion in certain SEC filings by Callon.
Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2018. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Callon after deducting all interests held by others.
Values for proved reserves in this report are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is defined as that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting production taxes, ad valorem taxes, operating expenses, capital costs,
|
|
|
|
|
|
2
|
DeGolyer and MacNaughton
|
|
|
and abandonment costs from future gross revenue. Operating expenses include field operating expenses, transportation and processing expenses, compression charges, and an allocation of overhead that directly relates to production activities. Capital costs include drilling and completion costs, facilities costs, and field maintenance costs. Abandonment costs are represented by Callon to be inclusive of those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment. At the request of Callon, future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at the arbitrary nominal discount rate of 10 percent per year compounded monthly over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.
Estimates of reserves and revenue should be regarded only as estimates that may change as production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.
Information used in the preparation of this report was obtained from Callon and from public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by Callon with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.
Definition of Reserves
Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by us in this report are in accordance with the reserves definitions of Rules 4
–
10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic
|
|
|
|
|
|
3
|
DeGolyer and MacNaughton
|
|
|
rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:
Proved oil and gas reserves
– Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible–from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations–prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
|
|
|
|
|
|
4
|
DeGolyer and MacNaughton
|
|
|
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Developed oil and gas reserves
– Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Undeveloped oil and gas reserves
– Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
|
|
|
|
|
|
5
|
DeGolyer and MacNaughton
|
|
|
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.
Based on the current stage of field development, production performance, the development plans provided by Callon, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.
Callon has represented that its senior management is committed to the development plan provided by Callon and that Callon has the financial capability to
|
|
|
|
|
|
6
|
DeGolyer and MacNaughton
|
|
|
execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.
A performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for the evaluation of all reserves categories in unconventional reservoirs. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. Analysis was performed for all well groupings (or type-curve areas).
Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs. The methodology used for the analysis was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, production history, and the appropriate reserves definitions.
In the evaluation of non-producing and undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.
In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.
Data provided by Callon from wells drilled through December 31, 2018, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through August 2018. Estimated cumulative production, as of December 31, 2018, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 4 months.
|
|
|
|
|
|
7
|
DeGolyer and MacNaughton
|
|
|
Oil reserves estimated herein are to be recovered by normal field separation. Oil reserves included in this report are expressed in barrels (bbl) representing 42 United States gallons per barrel.
Gas quantities estimated herein are expressed as separator gas and sales gas. Separator gas is defined as the gas remaining after field separation but prior to gas processing and shrinkage for fuel use or flare. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the pressure base of the state or area in which the reserves are located. Gas reserves included in this report are expressed in thousands of cubic feet (Mcf).
Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein are associated gas.
At the request of Callon, gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. This conversion factor was provided by Callon.
Primary Economic Assumptions
Revenue values in this report were estimated using initial prices, expenses, and costs provided by Callon. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the revenue values reported herein:
Oil Prices
Callon has represented that the oil prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements.
|
|
|
|
|
|
8
|
DeGolyer and MacNaughton
|
|
|
Callon supplied differentials to a West Texas Intermediate reference price of $65.56 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $58.40 per barrel of oil.
Gas Prices
Callon has represented that the gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Callon supplied differentials to the Henry Hub gas reference price of $3.10 per million British thermal units ($/MMBtu). The prices were held constant thereafter. Btu factors provided by Callon were used to convert prices from $/MMBtu to dollars per thousand cubic feet ($/Mcf). The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $3.641 per thousand cubic feet of gas.
Production and Ad Valorem Taxes
Production taxes were calculated using the tax rates for the state or area in which the reserves are located. Ad valorem taxes were calculated using rates provided by Callon based on recent payments.
Operating Expenses, Capital Costs, and Abandonment Costs
Estimates of operating expenses, provided by Callon and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were estimated using 2018 values, provided by Callon, and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of the wells, and reclamation
|
|
|
|
|
|
9
|
DeGolyer and MacNaughton
|
|
|
and restoration associated with the abandonment, were provided by Callon for all properties and were not adjusted for inflation. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of non-producing and undeveloped reserves estimated herein.
In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50,
Extractive Industries
–
Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures
(January 2010) of the Financial Accounting Standards Board and Rules 4
–
10(a) (1)
–
(32) of Regulation S
–
X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S
–
K of the Securities and Exchange Commission; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.
To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.
|
|
|
|
|
|
10
|
DeGolyer and MacNaughton
|
|
|
Summary of Conclusions
The estimated net proved reserves, as of December 31, 2018, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):
|
|
|
|
|
|
|
|
|
|
|
Estimated by DeGolyer and
MacNaughton
Net Proved Reserves as of
December 31, 2018
|
|
Oil
(Mbbl)
|
|
Sales
Gas
(MMcf)
|
|
Oil
Equivalent
(Mboe)
|
Proved
|
|
|
|
|
|
Developed Producing
|
88,559
|
|
|
214,623
|
|
|
124,330
|
|
Developed Non-Producing
|
3,643
|
|
|
3,794
|
|
|
4,275
|
|
|
|
|
|
|
|
Total Proved Developed
|
92,202
|
|
|
218,417
|
|
|
128,605
|
|
|
|
|
|
|
|
Undeveloped
|
87,895
|
|
|
132,049
|
|
|
109,903
|
|
|
|
|
|
|
|
Total Proved
|
180,097
|
|
|
350,466
|
|
|
238,508
|
|
|
|
|
|
|
|
Note: Sales gas reserves estimated herein were converted to oil equivalent using an energy factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.
|
The estimated future revenue to be derived from the production of the net proved reserves, as of December 31, 2018, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed
Producing
(M$)
|
|
Proved Developed
Non-Producing
(M$)
|
|
Total
Proved Developed (M$)
|
|
Proved Undeveloped
(M$)
|
|
Total
Proved
(M$)
|
Future Gross Revenue
|
|
5,941,092
|
|
|
226,159
|
|
|
6,167,251
|
|
|
5,626,829
|
|
|
11,794,080
|
|
Production and Ad Valorem Taxes
|
|
409,448
|
|
|
15,148
|
|
|
424,596
|
|
|
380,814
|
|
|
805,410
|
|
Operating Expenses
|
|
1,305,246
|
|
|
27,573
|
|
|
1,332,819
|
|
|
718,318
|
|
|
2,051,137
|
|
Capital and Abandonment Costs
|
|
58,703
|
|
|
275
|
|
|
58,978
|
|
|
1,438,221
|
|
|
1,497,199
|
|
Future Net Revenue
|
|
4,167,695
|
|
|
183,163
|
|
|
4,350,858
|
|
|
3,089,476
|
|
|
7,440,334
|
|
Present Worth at 10 Percent
|
|
2,119,794
|
|
|
102,255
|
|
|
2,222,049
|
|
|
927,158
|
|
|
3,149,207
|
|
|
|
|
|
|
|
|
|
|
|
|
Note: Future income taxes have not been taken into account in the preparation of these estimates.
|
|
|
|
|
|
|
11
|
DeGolyer and MacNaughton
|
|
|
While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2018, estimated reserves.
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Callon. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Callon. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.
|
|
|
|
Submitted,
|
|
|
|
/s/ DeGolyer and MacNaughton
|
|
|
|
DeGOLYER and MacNAUGHTON
|
|
Texas Registered Engineering Firm F-716
|
|
|
|
|
/s/ Gregory K. Graves, P.E.
|
|
Gregory K. Graves, P.E.
|
[SEAL]
|
Senior Vice President
|
|
DeGolyer and MacNaughton
|
CERTIFICATE of QUALIFICATION
I, Gregory K. Graves, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:
|
|
1.
|
That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to Callon Petroleum Company dated January 17, 2019, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.
|
|
|
2.
|
That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 34 years of experience in oil and gas reservoir studies and reserves evaluations.
|
|
|
|
|
/s/ Gregory K. Graves, P.E.
|
|
Gregory K. Graves, P.E.
|
[SEAL]
|
Senior Vice President
|
|
DeGolyer and MacNaughton
|