

	Three Months Ended September 30,				Nine Months Ended September 30,
Components of income tax rate reconciliation	2019		2018		2019		2018
Income tax expense computed at the statutory federal income tax rate	21	%	21	%	21	%	21	%
State taxes net of federal expense	1	%	3	%	1	%	2	%
Section 162(m)	—	%	2	%	—	%	1	%
Valuation allowance	—	%	(21	)%	—	%	(21	)%
Effective income tax rate, before discrete items	22	%	5	%	22	%	3	%
Discrete items ^(a)	2	%	(1	)%	2	%	(1	)%
Effective income tax rate, after discrete items	24	%	4	%	24	%	2	%



~~Callon Petroleum Company~~	~~Notes to the Consolidated Financial Statements~~ ~~(All dollar amounts in thousands, except per share and per unit data)~~^(a)	~~Table~~Accounts for the potential impact of ~~Contents~~ periodic volatility of stock-based compensation tax deductions on future effective tax rates.

~~Note 8 - Asset Retirement Obligations~~

~~The table below summarizes the activity for the Company’s asset retirement obligations:~~

For The Nine Months Ended
September 30, 2017
Asset retirement obligations at January 1, 2017 $ 6,661
Accretion expense 523
Liabilities incurred 224
Liabilities settled (227 )
Revisions to estimate ^(a)
(2,177 )
Asset retirement obligations at end of period 5,004
Less: Current asset retirement obligations (1,841 )
Long-term asset retirement obligations at September 30, 2017 $ 3,163

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the Consolidated Balance Sheets at September 30, 2017 as long-term restricted investments were $3,362. 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.

Note 9 - Equity Transactions

10% Series A Cumulative Preferred Stock (“Preferred Stock”)

Holders of the Company’s 10.00% Series A Cumulative Preferred Stock ~~are~~were entitled to receive, when, as and if declared by ~~our Board~~the Company’s board of ~~Directors,~~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~~were payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by ~~our~~the Company’s Board of Directors. Preferred Stock dividends were ~~$1,824~~$350 and ~~$1,824~~$1,823 for the three months ended September 30, ~~2017~~2019 and ~~2016,~~2018, respectively, and ~~$5,471~~$3,997 and $5,471 for the nine months ended September 30, ~~2017~~2019 and ~~2016,~~2018, respectively.

On June 18, 2019, the Company announced it had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. The redemption date of the Preferred Stock was July 18, 2019 (the “Redemption Date”). The Preferred Stock ~~has no stated maturity and is not subject~~were redeemed at the redemption price equal 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~~an amount equal to all accrued and unpaid dividends in an amount equal to $0.24 per share, for a total redemption price of $50.24 per share (the “Redemption Price”). After the ~~redemption date.~~Redemption Date, the Preferred

~~Following a change of control in which the Company or the acquirer~~



	Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data)

Stock were no longer ~~have a class of common securities listed~~deemed outstanding, dividends 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~~ceased to accrue, and ~~unpaid dividends (whether or not declared),~~all rights of the holders with respect to ~~the redemption date. If the Company does not exercise its option to redeem the~~such Preferred Stock ~~upon such change~~were terminated, except the right of ~~control,~~ the holders ofto receive the ~~Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common~~ Redemption Price, without interest.

Commonstock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on September 30, 2017, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $11.24 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 4.4 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 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of September~~May 30, ~~2017, the Company had 1,458,948 shares of its Preferred Stock issued and outstanding.~~

~~Commonstock~~

~~On December 19, 2016,~~2018, the Company completed an underwritten public offering of ~~40,000,000~~25.3 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering ~~expenses)~~costs) of approximately ~~$634,934. Proceeds~~$287,988. The Company used proceeds from the offering ~~were used~~ to ~~substantially~~partially fund the ~~Ameredev Transaction,~~Delaware Asset Acquisition completed in the third quarter of 2018, described in Note 2.3.

Note 10 - Leases

Leases

We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. Based on our evaluation of leases for the three and nine months ended September ~~6, 2016,~~30, 2019, we have no leases that meet the ~~Company completed~~criteria for classification as a finance lease. We capitalize operating leases on our consolidated balance sheets through a right-of-use (“ROU”) asset and a corresponding lease liability. ROU assets represent our right to use an ~~underwritten public offering of 29,900,000 shares of its common stock~~underlying asset for ~~total estimated net proceeds (after~~ the ~~underwriter’s discounts~~lease term, and ~~estimated offering expenses) of approximately $421,864. Proceeds~~lease liabilities represent our obligation to make lease payments arising from the ~~offering were used~~lease.

Operating leases are included in operating lease ROU assets, current operating lease liabilities, and long-term operating lease liabilities in our consolidated balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The operating lease ROU asset also includes any lease payments made to ~~substantially fund~~ the ~~Plymouth Transaction, described~~lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

Nature of leases

In support of our operations, we lease certain drilling rigs, office space, office equipment, production facilities, compressors, vehicles and other ancillary drilling equipment under cancelable and non-cancelable contracts. A more detailed description of our material lease types is included below.

Drilling rigs

The Company enters into daywork and long-term contracts for drilling rigs with third party service contractors to support the development of undeveloped reserves. Our daywork drilling rig arrangements are typically structured with a term that is in ~~Note 2.~~ effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells, well pads or contractually stated extension terms by providing 30 days’ notice prior to the end of the original contract term.

The Company’s long-term drilling contracts are generally structured with an initial non-cancelable term of one to two years. We have concluded that our long-term drilling rig arrangements represent operating leases with a lease term greater than twelve months. Additionally, we have concluded that our daywork drilling rig arrangements represent short-term operating leases with a lease term that equals the period of time required to complete drilling operations on the contractually specified well or well pad (that is, generally one to a few months from commencement of drilling).

We do not include the option to extend the drilling rig contract in the lease term due to the continuously evolving nature of our drilling schedules, which requires significant flexibility in the structure of the term of these arrangements, and the potential volatility in commodity prices in an annual period. We have further elected to apply the practical expedient for short-term leases to our daywork drilling rig leases. Accordingly, we do not apply the lease recognition requirements to our daywork drilling rig contracts, and we recognize lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term.

Corporate and field offices

We enter into long-term contracts to lease corporate and field office space in support of company operations. These contracts are generally structured with an initial non-cancelable term of two to five years. To the extent that our corporate and field office contracts include renewal options, we evaluate whether we are reasonably certain to exercise those options on a contract by contract basis based on expected future office space needs, market rental rates, drilling plans and other factors. We have further determined that our current corporate and field office leases represent operating leases.



~~Callon Petroleum Company~~	Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data)	~~Table of Contents~~

~~On May 26, 2016,~~Transportation, gathering and processing arrangements

We engage in various types of transactions in which midstream entities transport, gather and/or process our product leveraging integrated systems and facilities wholly-owned and operated by the ~~Company issued 9,333,333 shares~~midstream counterparty. Under most of ~~common stock to partially fund~~these arrangements, we do not utilize substantially all of the ~~Big Star Transaction, described in Note 2, at~~underlying pipeline, gathering system or processing facilities, and thus, we have concluded that those underlying assets do not meet the definition of an ~~assumed offering price of $11.74 per share, which is~~identified asset.

The following tables reflect the ~~last reported sale price~~current period impact of our ~~common stock on~~adoption of the ~~New York Stock Exchange on~~new leases standard. As we have no leases that ~~date.~~meet the criteria for classification as a finance lease, all information contained herein represents our operating leases.

The components of our total lease cost were as follows:

~~On April 25, 2016, the Company completed an underwritten public offering~~



	Three Months Ended		Nine Months Ended
	September 30, 2019		September 30, 2019
Operating lease cost	$	7,964	$	27,122
Short-term lease cost ^(a)	293		3,640

^(a)Short-term lease cost excludes expenses related to leases with a contract term of 25,300,000 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 2, and other working interest acquisitions.one month or less.

On March 9, 2016, the Company completed an underwritten public offering of 15,250,000 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.

~~Note 10 - Other~~

~~Operating leases~~

As of September 30, ~~2017 the Company had contracts~~2019, our weighted average remaining lease term and our weighted average discount rate for ~~four horizontal drilling rigs (the “Cactus 1 Rig”~~our operating leases were 1.36 years and 4.03%, ~~“Cactus 2 Rig”, “Cactus 3 Rig”, and “Independence Rig”). The~~respectively.

Our operating lease liabilities with enforceable contract terms that are greater than one year mature as amended in July 2017, of the Cactus 1 Rig and Cactus 2 Rig will end in January 2020 and February 2021, respectively. The contract terms, as amended in July 2017, of the Cactus 3 Rig that commenced drilling in mid-January 2017, will end in July 2018. Effective April 2017, the Company entered into a contract for the Independence Rig, which commenced drilling in July 2017. The contract terms of the Independence Rig will end in July 2019. The rig lease agreements include early termination provisions that obligate the Company to pay reduced minimum rentals for the remaining term of the agreement. These payments would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee.follows:



	As of September 30, 2019
Remainder of 2019	$	7,932
2020	13,933
2021	1,576
2022	534
2023	517
Thereafter	431
Total lease payments	24,923
Less imputed interest	732
Total	$	24,191



~~Callon Petroleum Company~~	~~Notes to the Consolidated Financial Statements~~ ~~(All dollar amounts in thousands, except per share and per unit data)~~	~~Table of Contents~~

~~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-Q 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 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 production and operating costs;~~

~~commodity price risk management activities and the impact on our average realized prices;~~

~~business strategies and plans of management;~~

~~our ability to efficiently integrate recently completed 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;~~

~~impairments;~~

~~the impact of competition;~~

~~the availability and cost of seismic, drilling and other equipment;~~

~~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;~~

~~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 endangered species;~~

~~any increase in severance or similar taxes;~~

~~litigation relating to hydraulic fracturing, the climate and over-the-counter derivatives;~~

~~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;~~

~~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-Q 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 our Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 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 herein or in our 2016 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. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

~~All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.~~



~~Callon Petroleum Company~~	~~Management’s Discussion and Analysis of Financial Condition and Results~~	~~Table of Contents~~

Note 11 - Asset Retirement Obligations

The table below summarizes the activity for the Company’s ARO:



	Nine Months Ended
	September 30, 2019
Asset retirement obligations at January 1, 2019	$	14,292
Accretion expense	585
Liabilities incurred	325
Liabilities settled	(3,187		)
Dispositions	(1,753		)
Revisions to estimate	(718		)
Asset retirement obligations at end of period	9,544
Less: Current asset retirement obligations	(1,250		)
Long-term asset retirement obligations at September 30, 2019	$	8,294


•	Liabilities incurred include additions from acquisitions, asset swaps, and new wells drilled during the year.


•	Liabilities settled include the retirement of 28 wells during the year and settlement of abandonment obligations attributable to historical activity within the Gulf of Mexico.


•	Dispositions are primarily attributable to the Ranger Asset Divestiture in the second quarter of 2019. See Note 3 for details about the Ranger Asset Divestiture.


•	Revisions to estimates were due to changes in plugging cost estimates, timing of abandonment activities, and changes in working interest of producing wells.



	Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data)

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheet at September 30, 2019 as long-term restricted investments were $3,490. 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.

Note 12 - Other

Other commitments

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 and Ward 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.

In January 2019, the 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 and Ward 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.

In June 2019, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that originates in Midland, Texas and terminates in Houston, Texas. 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 quantities committed that average 10,000 Bbls per day 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.

In July 2019, the Company executed a crude oil sales contact that provides dedicated capacity on a new pipeline system that originates in Midland County and will have delivery points in several locations along the Gulf Coast. We will have a long-term 5,000 Bbls per day commitment for the term of the agreement and will apply applicable tariff rates to those quantities. Barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

Note 13 - Carrizo Acquisition

On July 14, 2019, Callon and Carrizo Oil & Gas, Inc. (“Carrizo”) entered into an Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which, upon the terms and subject to the conditions set forth therein, Carrizo will merge with and into Callon, with Callon as the surviving corporation (the “Merger” or the “Carrizo Acquisition”). The combination will result in a portfolio of core oil-weighted assets in both the Permian Basin and Eagle Ford Shale.

Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each outstanding share of Carrizo common stock, will be converted into the right to receive 2.05 shares of Callon common stock. Following the closing of the Merger, Callon’s existing shareholders and Carrizo’s existing shareholders will own approximately 54% and 46%, respectively, of the outstanding shares of the combined company.

The Merger Agreement provides that, upon consummation of the Merger, the board of directors of Callon will consist of the eight members of the board of directors of Callon immediately prior to the Effective Time and three members of the board of directors of Carrizo. Callon and Carrizo have agreed that the Director Designees will be appointed to the Callon board immediately after the effective time, with the Callon designee being appointed as a Class III director, with a term ending at the 2021 annual meeting of the shareholders of Callon, and the Carrizo designees being appointed as Class I directors, each with a term ending at the 2022 annual meeting of the shareholders of Callon. Callon and Carrizo expect that the Callon designee will be Frances Aldrich Sevilla-Sacasa and the Carrizo designees will be S.P. Johnson IV and Steven A. Webster.

Additionally, the Merger Agreement provides that, upon consummation of the Merger, the officers of Callon immediately prior to the Effective Time shall be the officers of the combined company. Callon will continue to be headquartered in Houston, Texas, where both



	Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data)

companies are currently based. Callon expects that the acquisition will close during the fourth quarter of 2019, subject to the approval of both shareholder bases, the satisfaction of certain regulatory approvals and other closing conditions.

Special Note Regarding Forward Looking Statements

matters relating to the Carrizo Acquisition;

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;

impairments;

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 gas industry;

weather conditions;

risks associated with acquisitions, including the Carrizo Acquisition;

failure to consummate the Carrizo Acquisition in a timely manner, or at all, and failure to realize the expected benefits thereof;

any litigation relating to the Carrizo Acquisition; 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-Q 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 our 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.

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.



	Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 2. 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 unaudited consolidated financial statements and our ~~2016~~2018 Annual Report on Form 10-K, which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results. 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 ~~report~~Quarterly Report on Form 10-Q.

We are an independent oil and natural gas company ~~established~~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~~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. WeSince 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 78% oil and 22% natural gas for the nine months ended September 30, ~~2017.~~ 2019.

Recent Developments

On ~~September 30, 2017, our~~June 12, 2019, we completed the Ranger Asset Divestiture for net ~~acreage position~~cash proceeds received at closing of $245 million, including customary purchase price adjustments.

On July 18, 2019, we redeemed all outstanding shares of the Preferred Stock at a Redemption Price of $50.24 per share for a total redemption of $73 million. After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest.

In July 2019, Callon and Carrizo entered into the Merger Agreement, pursuant to which, upon the terms and subject to the conditions set forth therein, Carrizo will merge with and into Callon, with Callon as the surviving corporation. The combination will result in a portfolio of core oil-weighted assets in both the Permian Basin ~~was approximately 58,336 net acres.~~and Eagle Ford Shale. The Company expects that the acquisition will close during the fourth quarter of 2019. See Note ~~2 in the Footnotes to the Financial Statements~~13 for additional information ~~about~~regarding the ~~Company’s acquisitions.~~

Carrizo Acquisition.

Operational Highlights

All of our producing properties are located in the Permian Basin. As a result of our ~~acquisition~~horizontal development and ~~horizontal development~~acquisition efforts, our production grew ~~36%~~8% and ~~53%~~31% for the three and nine months ended September 30, ~~2017, respectively,~~2019, compared to the same periods of ~~2016.~~2018, respectively. Production increased to ~~2,074~~3,481 MBOE for the three months ended September 30, ~~2017~~2019 from ~~1,527~~3,212 MBOE for the ~~three months ended September 30, 2016~~same period of 2018, and increased to ~~5,934~~10,796 MBOE for the nine months ended September 30, ~~2017~~2019 from ~~3,884~~8,238 MBOE for the ~~nine months ended~~same period of 2018. As of September 30, ~~2016.~~2019, we had 800 gross (602.4 net) working interest oil and natural gas wells.

For the three months ended September 30, ~~2017,~~2019, we drilled 1312 gross ~~(10.3~~(11.0 net) horizontal wells and completed 1516 gross ~~(13.2~~(15.6 net) horizontal wells. For the nine months ended September 30, ~~2017~~2019, we drilled 3648 gross ~~(28.9~~(41.7 net) horizontal wells and completed 3441 gross ~~(27.7~~(38.1 net) horizontal wells. As of September 30, ~~2017,~~2019, we had 918 gross ~~(6.4~~(13.1 net) horizontal wells awaiting completion.

As of September 30, 2017, we had 535 gross (418.1 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.

~~Liquidity and Capital Resources~~

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities, and 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. We continue to evaluate other sources of capital to complement our cash flows from operations as we pursue our long-term growth plans. As of September 30, 2017, there was no balance outstanding on the Credit Facility, which has a borrowing base of $650 million with a current elected commitment of $500 million. For the nine months ended September 30, 2017, cash and cash equivalents decreased $264.3 million to $61.6 million compared to $325.9 million at September 30, 2016.

~~Liquidity and cash flow~~

Nine Months Ended September 30,
(in millions) 2017 2016
Net cash provided by operating activities $ 149.7
$ 84.8
Net cash used in investing activities (935.6 ) (434.5 )
Net cash provided by financing activities 194.5
674.4
Net change in cash and cash equivalents $ (591.4 ) $ 324.7



~~Callon Petroleum Company~~	Management’s Discussion and Analysis of Financial Condition and Results of Operations	~~Table of Contents~~

~~Operating activities.~~ For the nine months ended September 30, 2017, net cash provided by operating activities was $149.7 million compared to net cash provided by operating activities of $84.8 million for the same period in 2016. The change was predominantly attributable to the following:

~~An increase in revenue;~~

~~A decrease on settlements of derivative contracts;~~

~~An increase in certain operating expenses related to acquired properties;~~

~~An increase in payments in cash-settled restricted stock unit (“RSU”) awards; and~~

~~A change related to the timing of working capital payments and receipts.~~

Production, realized prices, and operating expenses are discussed below in Results of Operations. See Notes 4, 5 and 6 in the Footnotes to the Financial Statements for additional information on our debt and 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 nine months ended September 30, 2017, net cash used in investing activities was $935.6 million compared to $434.5 million for the same period in 2016. The change was predominantly attributable to the following:

~~A $141.7 million increase in operational expenditures due to the transition from a two-rig to a three-rig program in January 2017 and from a three-rig to a four-rig program in July 2017; and~~

~~A $333.6 million increase attributable to acquisition activity. See Note 2 in the Footnotes to the Financial Statements for additional information on the Company’s acquisitions.~~

~~Our investing activities, on a cash basis, include the following for the periods indicated (in millions):~~

Nine Months Ended September 30,
2017 2016 $ Change
Operational expenditures $ 232.2
$ 90.5
$ 141.7
Seismic, leasehold and other 11.4
10.0
1.4
Capitalized general and administrative costs 11.9
9.0
2.9
Capitalized interest 11.7
13.2
(1.4 )
Total capital expenditures^(a)
267.2
122.7
144.5

Acquisitions 714.5
302.1
412.4
Acquisition deposits (46.1 ) 32.7
(78.8 )
Proceeds from the sale of mineral interest and equipment —
(22.9 ) 22.9
Total investing activities $ 935.6
$ 434.5
$ 501.1


~~(a)~~	On an accrual (GAAP) basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the nine months ended September 30, 2017 were $277.0 million. Inclusive of capitalized general and administrative and interest costs, total capital expenditures for the nine months ended September 30, 2017 were $326.5 million.

General and administrative expenses and capitalized interest are discussed below in Results of Operations. See Note 2 in the Footnotes to the Financial Statements for additional information on acquisitions.

~~Financing activities.~~ We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Credit Facility, term debt and equity offerings. For the nine months ended September 30, 2017, net cash provided by financing activities was $194.5 million compared to $674.4 million for the same period of 2016. The change was predominantly attributable to the following:

A $201.7 million increase in borrowings on fixed-rate debt, resulting from the issuance of $200 million of 6.125% senior unsecured notes due 2024, including a premium issue price of 104.125% and net of payments of deferred financing costs

~~We had no issuance of common stock during the nine months ended September 30, 2017, a change of $722.7 million compared to the same period of 2016.~~



~~Callon Petroleum Company~~	~~Management’s Discussion and Analysis of Financial Condition and Results~~	~~Table of Contents~~

~~Net cash provided by financing activities includes the following for the periods indicated (in millions):~~

Nine Months Ended September 30, 2017
2017 2016 $ Change
Net borrowings on senior secured revolving credit facility $ —
$ (40.0 ) $ 40.0
Issuance of 6.125% senior unsecured notes due 2024 200.0
—
200.0
Premium on the issuance of 6.125% senior unsecured notes due 2024 8.3
—
8.3
Issuance of common stock —
722.7
(722.7 )
Payment of preferred stock dividends (5.5 ) (5.5 ) —
Payment of deferred financing costs (7.2 ) (0.6 ) (6.6 )
Tax withholdings related to restricted stock units (1.1 ) (2.2 ) 1.1
Net cash provided by financing activities $ 194.5
$ 674.4
$ (479.9 )

~~See Notes 4 and 9 in the Footnotes to the Financial Statements for additional information on our debt and equity offerings.~~

~~Capital Plan and Year to Date 2017 Summary~~

Our operational capital budget for 2017 was established at $350 million on an accrual, or GAAP, basis, inclusive of a transition from a three-rig program that commenced in January 2017 to a four-rig program in July 2017 that includes horizontal development activity at our recent Delaware Basin acquisition (see Note 2 in the Footnotes to the Financial Statements for information on this acquisition).

In addition to the operational capital budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $40 to $45 million for capitalized general and administrative expenses and capitalized interest expenses, both on an accrual, or GAAP, basis.

Operational capital expenditures on an accrual basis were $277.0 million for the nine months ended September 30, 2017. In addition to the operational capital expenditures, $14.0 million of capitalized general and administrative and $24.1 million of capitalized interest expenses were accrued in the nine months ended September 30, 2017. Based on current activity levels and service cost expectations, for full-year 2017 we estimate operational capital expenditures of approximately $375 million, net of the monetization of certain infrastructure assets, including natural gas gathering lines and saltwater disposal facilities.

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, including commodity hedging strategy, 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.



~~Callon Petroleum Company~~	~~Management’s Discussion and Analysis of Financial Condition and Results~~	~~Table of Contents~~

Results of Operations

The following ~~table sets~~tables set forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated:

Three Months Ended September 30,
2017 2016 Change % Change
Net production:
Oil (MBbls) 1,591
1,153
438
38 %
Natural gas (MMcf) 2,900
2,244
656
29 %
   Total (MBOE) 2,074
1,527
547
36 %
Average daily production (BOE/d) 22,543
16,598
5,945
36 %
   % oil (BOE basis) 77 % 76 %
Average realized sales price:
   Oil (Bbl) (excluding impact of cash settled derivatives) $ 46.10
$ 42.58
$ 3.52
8 %
   Oil (Bbl) (including impact of cash settled derivatives) 45.24
46.27
(1.03 ) (2 )%
   Natural gas (Mcf) (excluding impact of cash settled derivatives) $ 3.88
$ 3.04
$ 0.84
28 %
   Natural gas (Mcf) (including impact of cash settled derivatives) 3.94
2.97
0.97
33 %
   Total (BOE) (excluding impact of cash settled derivatives) $ 40.80
$ 36.63
$ 4.17
11 %
   Total (BOE) (including impact of cash settled derivatives) 40.21
39.30
0.91
2 %
Oil and natural gas revenues (in thousands):
   Oil revenue $ 73,349
$ 49,095
$ 24,254
49 %
   Natural gas revenue 11,265
6,832
4,433
65 %
      Total $ 84,614
$ 55,927
$ 28,687
51 %
Additional per BOE data:
   Sales price (excluding impact of cash settled derivatives) $ 40.80
$ 36.63
$ 4.17
11 %
      Lease operating expense (excluding gathering and treating expense) 5.08
6.16
(1.08 ) (18 )%
      Gathering and treating expense 0.52
0.36
0.16
44 %
      Production taxes 2.62
2.28
0.34
15 %
   Operating margin $ 32.58
$ 27.83
$ 4.75
17 %



	Three Months Ended September 30,
	2019			2018			Change			% Change
Net production
Oil (MBbls)	2,725			2,521			204			8	%
Natural gas (MMcf)	4,538			4,144			394			10	%
Total (MBOE)	3,481			3,212			269			8	%
Average daily production (BOE/d)	37,837			34,913			2,924			8	%
% oil (BOE basis)	78		%	78		%
Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)	$	54.39		$	56.57		$	(2.18	)	(4	)%
Natural gas (per Mcf)	1.58			4.49			(2.91		)	(65	)%
Total (per BOE)	44.64			50.19			(5.55		)	(11	)%
Average realized sales price (including impact of settled derivatives)
Oil (per Bbl)	$	54.01		$	52.87		$	1.14		2	%
Natural gas (per Mcf)	2.03			4.51			(2.48		)	(55	)%
Total (per BOE)	44.93			47.31			(2.38		)	(5	)%
Oil and natural gas revenues (in thousands)
Oil revenue	$	148,210		$	142,601		$	5,609		4	%
Natural gas revenue	7,168			18,613			(11,445		)	(61	)%
Total	$	155,378		$	161,214		$	(5,836	)	(4	)%
Additional per BOE data
Sales price ^(a)	$	44.64		$	50.19		$	(5.55	)	(11	)%
Lease operating expense ^(b)	5.65			5.77			(0.12		)	(2	)%
Production taxes	3.41			3.20			0.21			7	%
Operating margin	$	35.58		$	41.22		$	(5.64	)	(14	)%
Benchmark prices
WTI (per Bbl)	$	56.34		$	69.69		$	(13.35	)	(19	)%
Henry Hub (per Mmbtu)	2.38			2.93			(0.55		)	(19	)%


(a)	Excludes the impact of settled derivatives.


(b)	Excludes gathering and treating expense.

Nine Months Ended September 30,
2017 2016 Change % Change
Net production:
Oil (MBbls) 4,621
2,993
1,628
54 %
Natural gas (MMcf) 7,878
5,345
2,533
47 %
   Total (MBOE) 5,934
3,884
2,050
53 %
Average daily production (BOE/d) 21,736
14,175
7,561
53 %
   % oil (BOE basis) 78 % 77 %
Average realized sales price:
   Oil (Bbl) (excluding impact of cash settled derivatives) $ 47.23
$ 39.12
$ 8.11
21 %
   Oil (Bbl) (including impact of cash settled derivatives) 46.32
44.29
2.03
5 %
   Natural gas (Mcf) (excluding impact of cash settled derivatives) $ 3.81
$ 2.75
$ 1.06
39 %
   Natural gas (Mcf) (including impact of cash settled derivatives) 3.84
2.81
1.03
37 %
   Total (BOE) (excluding impact of cash settled derivatives) $ 41.84
$ 33.93
$ 7.91
23 %
   Total (BOE) (including impact of cash settled derivatives) 41.17
38.00
3.17
8 %
Oil and natural gas revenues (in thousands):
   Oil revenue $ 218,242
$ 117,093
$ 101,149
86 %
   Natural gas revenue 30,019
14,677
15,342
105 %
      Total $ 248,261
$ 131,770
$ 116,491
88 %
Additional per BOE data:
   Sales price (excluding impact of cash settled derivatives) $ 41.84
$ 33.93
$ 7.91
23 %
      Lease operating expense (excluding gathering and treating expense) 5.72
5.96
(0.24 ) (4 )%
      Gathering and treating expense 0.47
0.28
0.19
68 %
      Production taxes 2.72
2.10
0.62
30 %
   Operating margin $ 32.93
$ 25.59
$ 7.34
29 %



~~Callon Petroleum Company~~	Management’s Discussion and Analysis of Financial Condition and Results of Operations	~~Table of Contents~~



	Nine Months Ended September 30,
	2019			2018			Change			% Change
Net production
Oil (MBbls)	8,431			6,368			2,063			32	%
Natural gas (MMcf)	14,188			11,222			2,966			26	%
Total (MBOE)	10,796			8,238			2,558			31	%
Average daily production (BOE/d)	39,546			30,176			9,370			31	%
% oil (BOE basis)	78		%	77		%
Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)	$	53.38		$	59.75		$	(6.37	)	(11	)%
Natural gas (per Mcf)	1.79			4.03			(2.24		)	(56	)%
Total (per BOE)	44.04			51.68			(7.64		)	(15	)%
Average realized sales price (including impact of settled derivatives)
Oil (per Bbl)	$	52.54		$	55.61		$	(3.07	)	(6	)%
Natural gas (per Mcf)	2.26			4.09			(1.83		)	(45	)%
Total (per BOE)	44.00			48.56			(4.56		)	(9	)%
Oil and natural gas revenues (in thousands)
Oil revenue	$	450,036		$	380,500		$	69,536		18	%
Natural gas revenue	25,441			45,229			(19,788		)	(44	)%
Total	$	475,477		$	425,729		$	49,748		12	%
Additional per BOE data
Sales price ^(a)	$	44.04		$	51.68		$	(7.64	)	(15	)%
Lease operating expense^(b)	6.16			5.43			0.73			13	%
Production taxes	3.13			3.19			(0.06		)	(2	)%
Operating margin	$	34.75		$	43.06		$	(8.31	)	(19	)%
Benchmark prices
WTI (per Bbl)	$	57.04		$	66.93		$	(9.89	)	(15	)%
Henry Hub (per Mmbtu)	2.62			2.95			(0.33		)	(11	)%


(a)	Excludes the impact of settled derivatives.


(b)	Excludes gathering and treating expense.



	Management’s Discussion and Analysis of Financial Condition and Results of Operations

Revenues

The following ~~table reconciles~~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 three months ended September 30, 2016 $ 49,095
$ 6,832
$ 55,927
Volume increase 18,650
1,994
20,644
Price increase 5,604
2,439
8,043
Net increase 24,254
4,433
28,687
Revenues for the three months ended September 30, 2017 $ 73,349
$ 11,265
$ 84,614

(in thousands) Oil Natural Gas Total
Revenues for the nine months ended September 30, 2016 $ 117,093
$ 14,677
$ 131,770
Volume increase 63,687
6,966
70,653
Price increase 37,462
8,376
45,838
Net increase 101,149
15,342
116,491
Revenues for the nine months ended September 30, 2017 $ 218,242
$ 30,019
$ 248,261



(in thousands)	Oil			Natural Gas			Total
Revenues for the three months ended September 30, 2018	$	142,601		$	18,613		$	161,214
Volume increase	11,540			1,769			13,309
Price decrease	(5,931		)	(13,214		)	(19,145		)
Net increase (decrease)	5,609			(11,445		)	(5,836		)
Revenues for the three months ended September 30, 2019	$	148,210		$	7,168		$	155,378

~~Commodityprices~~



(in thousands)	Oil			Natural Gas			Total
Revenues for the nine months ended September 30, 2018	$	380,500		$	45,229		$	425,729
Volume increase	123,264			11,953			135,217
Price decrease	(53,728		)	(31,741		)	(85,469		)
Net increase (decrease)	69,536			(19,788		)	49,748
Revenues for the nine months ended September 30, 2019	$	450,036		$	25,441		$	475,477

Commodityprices

The prices for oil and natural gas ~~can be~~remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by the Organization of Petroleum Exporting Countries 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 three ~~and nine~~ months ended September 30, 2017, the average NYMEX price for a barrel of oil was $48.20 and $49.36 per Bbl compared to $44.94 and $41.47 per Bbl for the same periods of 2016, respectively. The NYMEX price for a barrel of oil for the three and nine months ended September 30, 2017 ranged from a low of $44.23 per Bbl to a high of $47.29 per Bbl and a low of $42.53 per Bbl to a high of $54.45 Bbl, respectively.

For the three and nine months ended September 30, 2017, the average NYMEX price for natural gas was $3.00 and $3.17 per MMBtu compared to $2.81 and $2.29 per MMBtu for the same periods of 2016. The NYMEX price for natural gas for the three and nine months ended September 30, 2017 ranged from a low of $2.77 per MMBtu to a high of $3.15 per MMBtu and a low of $2.56 per MMBtu to a high of $3.42 MMBtu, respectively.

໿

~~Oil revenue~~

~~For the quarter ended September 30, 2017,~~2019, oil revenues of ~~$73.3~~$148.2 millionincreased ~~$24.2~~$5.6 million, or ~~49%~~4%, compared to revenues of ~~$49.1~~$142.6 million for the same period of ~~2016.~~2018. The increase ~~in oil revenue~~ was primarily attributable to ~~a 38%~~an 8% increase in production from our acquisition and ~~an 8% increase~~development efforts, offset by a 4% decrease in the average realized sales price, which ~~rose~~fell to ~~$46.10~~$54.39 per Bbl ~~in the third quarter of 2017~~ from ~~$42.58~~$56.57 per Bbl in the third quarter of 2016. The increase in production was attributable to 633 MBbls from wells placed on production as a result of our horizontal drilling program and 241 MBbls from producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells. Bbl.

For the nine months ended September 30, ~~2017,~~2019, oil revenues of ~~$218.2~~$450.0 million increased ~~$101.1~~$69.5 million, or ~~86%~~18%, compared to revenues of ~~$117.1~~$380.5 million for the same period of ~~2016.~~2018. The increase ~~in oil revenue~~ was primarily attributable to a ~~54%~~32% increase in production from our acquisition and ~~a 21% increase~~development efforts, offset by an 11% decrease in the average realized sales price, which ~~rose~~fell to ~~$47.23~~$53.38 per Bbl from $59.75 per Bbl.

Natural gas revenue (including NGLs)

For the three months ended September 30, 2019, natural gas revenues of $7.2 million decreased $11.4 million, or 61%, compared to $18.6 million for the same period of 2018. The decrease was primarily attributable to a 65% decrease in the average realized sales price,which fell to $1.58 per Mcf from $4.49 per Mcf. The decrease in realized natural gas pricing was partially offset by a 10% increase in natural gas volumes.

For the nine months ended September 30, ~~2017 from $39.12 per Bbl~~2019, natural gas revenues of $25.4 million decreased $19.8 million, or 44%, compared to $45.2 million for the same period of ~~2016.~~2018. The decrease was primarily attributable to a 56% decrease in the average realized sales price,which fell to $1.79 per Mcf from $4.03 per Mcf. The decrease in realized natural gas pricing was partially offset by a 26% increase in production was comprised of 1,612 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 669 MBbls attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells.natural gas volumes.

~~See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.~~



~~Callon Petroleum Company~~	Management’s Discussion and Analysis of Financial Condition and Results of Operations	~~Table of Contents~~

~~Natural gas revenue (including NGLs)~~

Natural gas revenues of $11.3 million increased $4.4 million, or 66%, during the three months ended September 30, 2017, compared to $6.8 million for the same period of 2016. The increase primarily relates to a 29% increase in natural gas volumes and a 28% increase in the average realized sales price, which rose to $3.88 per Mcf from $3.04 per Mcf, reflecting both natural gas and natural gas liquids prices. The increase in production was comprised of 735 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 287 MMcf attributable to producing wells added from our acquired properties. Offsetting these increases were normal expected declines from our existing wells.

Natural gas revenues of $30.0 million increased $15.3 million, or 105%, during the nine months ended September 30, 2017, compared to $14.7 million for the same period of 2016. The increase primarily relates to a 47% increase in natural gas volumes and a 39% increase in the average realized sales price, which rose to $3.81 per Mcf from $2.75 per Mcf, reflecting both natural gas and natural gas liquids prices. The increase in production was comprised of 1,785 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 806 MMcf attributable to producing wells added from our acquired properties. Offsetting these increases were normal expected declines from our existing wells.

~~See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.~~

Operating Expenses


																			Three Months Ended September 30,
																						Per					Per		Total Change					BOE Change
(in thousands, except per unit amounts)	Three Months Ended September 30,																		2019			BOE			2018		BOE		$			%		$			%
			Per				Per		Total Change					BOE Change
	2017		BOE		2016		BOE		$			%		$			%
Lease operating expenses	$	11,624	$	5.60	$	9,961	$	6.52	$	1,663		17	%	$	(0.92	)	(14	)%	$	19,668		$	5.65		$	18,525	$	5.77	$	1,143		6	%	$	(0.12	)	(2	)%
Production taxes	5,444		2.62		3,478		2.28		1,966			57	%	0.34			15	%	11,866			3.41			10,263		3.20		1,603			16	%	0.21			7	%
Depreciation, depletion and amortization	28,525		13.75		17,303		11.33		11,222			65	%	2.42			21	%	56,002			16.09			48,257		15.02		7,745			16	%	1.07			7	%
General and administrative	7,259		3.50		7,891		5.17		(632		)	(8	)%	(1.67		)	(32	)%	9,388			2.70			9,721		3.03		(333		)	(3	)%	(0.33		)	(11	)%
Merger and integration expense																			5,943			1.71			—		—		5,943			100	%	1.71			100	%
Accretion expense	131		0.06		187		0.12		(56		)	(30	)%	(0.06		)	(50	)%	128			0.04			202		0.06		(74		)	(37	)%	(0.02		)	(33	)%
Acquisition expense	205		nm		456		nm		(251		)	nm		nm			nm

(in thousands, except per unit amounts)	Nine Months Ended September 30,
			Per				Per		Total Change					BOE Change
	2017		BOE		2016		BOE		$			%		$			%
Lease operating expenses	$	36,708	$	6.19	$	24,229	$	6.24	$	12,479		52	%	$	(0.05	)	(1	)%
Production taxes	16,168		2.72		8,153		2.10		8,015			98	%	0.62			30	%
Depreciation, depletion and amortization	79,172		13.34		49,318		12.70		29,854			61	%	0.64			5	%
General and administrative	18,894		3.18		19,755		5.09		(861		)	(4	)%	(1.91		)	(38	)%
Settled share-based awards	6,351		nm		—		nm		6,351			nm		nm			nm
Accretion expense	523		0.09		762		0.20		(239		)	(31	)%	(0.11		)	(55	)%
Write-down of oil and natural gas properties	—		nm		95,788		nm		(95,788		)	nm		nm			nm
Acquisition expense	3,027		nm		2,410		nm		617			nm		nm			nm
Other operating expense																			(161		)	(0.05		)	1,435		0.45		(1,596		)	(111	)%	(0.50		)	(111	)%

~~nm = not meaningful~~



	Nine Months Ended September 30,
			Per				Per		Total Change					BOE Change
(in thousands, except per unit amounts)	2019		BOE		2018		BOE		$			%		$			%
Lease operating expenses	$	66,511	$	6.16	$	44,705	$	5.43	$	21,806		49	%	$	0.73		13	%
Production taxes	33,810		3.13		26,265		3.19		7,545			29	%	(0.06		)	(2	)%
Depreciation, depletion and amortization	178,690		16.55		122,407		14.86		56,283			46	%	1.69			11	%
General and administrative	31,705		2.94		26,779		3.25		4,926			18	%	(0.31		)	(10	)%
Merger and integration expense	5,943		0.55		—		—		5,943			100	%	0.55			100	%
Settled share-based awards	3,024		0.28		—		—		3,024			100	%	0.28			100	%
Accretion expense	585		0.05		626		0.08		(41		)	(7	)%	(0.03		)	(38	)%
Other operating expense	931		0.09		3,750		0.46		(2,819		)	(75	)%	(0.37		)	(80	)%

Lease operating expenses (“LOE”). These are daily costs incurred to extract oil and natural gas ~~together with the daily costs incurred to~~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.

~~For~~LOE for the three months ended September 30, ~~2017, LOE~~2019 increased ~~by 17%~~ to ~~$11.6~~$19.7 million compared to ~~$10.0~~$18.5 million for the same period of ~~2016. Contributing~~2018. The increase in LOE primarily related to an 8% increase in production over the comparative periods.

LOE on a per unit basis decreased when comparing the third quarter of 2019 to the ~~increase was $2.3 million related to oil and natural gas properties acquired during 2016 and the first half of 2017 (see Note 2~~same period in ~~the Footnotes to the Financial Statements). For the three months ended September 30, 2017,~~2018. LOE per BOE decreased to ~~$5.60~~$5.65 for the third quarter of 2019, which represents a decrease of $0.12 per BOE from the third quarter of 2018.

LOE for the nine months ended September 30, 2019 increased to $66.5 million compared to ~~$6.52 per BOE~~$44.7 million for the same period of ~~2016, which was primarily attributable to higher production volumes offset by an increase in cost as previously discussed.~~2018. The increase in LOE primarily related to a 31% increase in production ~~was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above.~~ over the comparative periods.

For the nine months ended September 30, ~~2017,~~2019, LOE on a per unit basis increased ~~by 52%~~ to $36.7 million compared to $24.2 million for the same period of 2016. Contributing to the increase was $10.1 million related to oil and natural gas properties acquired during 2016 and the first half of 2017 (see Note 2 in the Footnotes to the Financial Statements). Excluding LOE related to these acquired properties, LOE increased



~~Callon Petroleum Company~~	~~Management’s Discussion and Analysis of Financial Condition and Results~~	~~Table of Contents~~

by $2.4 million, or 10%, compared to the same period of 2016, which was primarily due to an increase in cost driven by higher production volumes from our legacy assets. For the nine months ended September 30, 2017, LOE per BOE decreased to $6.19$6.16 per BOE compared to ~~$6.24~~$5.43 per BOE for the same period of ~~2016, which was~~2018 primarily ~~attributable~~due to ~~higher production volumes offset by an increase in cost as previously discussed. The increase in production was primarily attributable~~increased non-operated activity related to ~~an increased number of producing wells from our horizontal drilling program~~previous acquisitions and ~~acquisitions as discussed above.~~ workovers.

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.

Production taxes for the three months ended September 30, ~~2017~~2019 increased ~~by 57%~~16% to ~~$5.4~~$11.9 million compared to ~~$3.5~~$10.3 million for the same period of 2016. The increase was primarily due to an increase in severance taxes, which was attributable to the increase in revenue. Also contributing to the increase was an increase in ad valorem taxes, which was attributable to an increase in the valuation of our oil and gas properties by taxing jurisdictions as a result of an increased number of producing wells from our horizontal drilling program, acquisitions as discussed above, and an increase in commodity prices year over year.2018. On a per BOE basis, production taxes for the three months ended September 30, ~~2017~~2019 increased by ~~15%~~7% compared to the same period of ~~2016.~~2018.The increase in production taxes is partially due to higher severance taxes as a result of higher revenues. Severance taxes as a percentage of total revenue were consistent across the comparable periods at approximately 5%. Additionally, ad valorem taxes increased $2.2 million over the comparative periods due to a higher valuation of our oil and gas properties by the taxing jurisdictions and previous acquisitions.

Production taxes for the nine months ended September 30, ~~2017~~2019 increased ~~by 98%~~29% to ~~$16.2~~$33.8 million compared to ~~$8.2~~$26.3 million for the same period of 2016. The increase was primarily due to an increase in severance taxes, which was attributable to the increase in revenue. Also contributing to the increase was an increase in ad valorem taxes, which was attributable to an increase in the valuation of our oil and gas properties by taxing jurisdictions as a result of an increased number of producing wells from our horizontal drilling program, acquisitions as discussed above, and an increase in commodity prices year over year.2018. On a per BOE basis, production taxes for the ~~three~~nine months ended September 30, ~~2017 increased~~2019 decreased by ~~30%~~2% compared to the same period of ~~2016.~~2018. The increase in production taxes is partially due to higher severance taxes as a result of higher revenues. Severance



	Management’s Discussion and Analysis of Financial Condition and Results of Operations

taxes as a percentage of total revenue were relatively unchanged across the comparable periods at approximately 5%. Additionally, ad valorem taxes increased $5.8 million over the comparative periods due to a higher valuation of our oil and gas properties by the taxing jurisdictions and previous acquisitions.

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~~

DD&A rates fluctuate as a result of ~~other property~~changes in finding and ~~equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.~~

development costs, acquisitions, impairments, and changes in proved reserves. For the three months ended September 30, ~~2017,~~2019, DD&A ~~increased 65% to $28.5~~expense was $56.0 million compared to ~~$17.3~~$48.3 million for the same period of ~~2016.~~2018. The ~~increase is primarily attributable~~additional DD&A was related to a ~~36%~~8% increase in production ~~and a 21% increase in our per BOE~~volumes combined with higher DD&A ~~rate.~~ rates between the periods, which resulted in $4.0 million and $3.7 million, respectively, of incremental DD&A expense being incurred during the third quarter of 2019.

For the three months ended September 30, ~~2017,~~2019, DD&A on a per unit basis increased to ~~$13.75~~$16.09 per BOE compared to ~~$11.33~~$15.02 per BOE for the same period of ~~2016.~~2018. The ~~increase is attributable~~primary factor contributing to ~~greater increases in our depreciable base~~the increased DD&A rate were higher drilling and ~~assumed future development~~completion costs ~~to undeveloped proved reserves~~for new wells placed on production over the past 12 months relative to our historical rate. Additionally, the rate increase in our estimated proved reserve base. The increases in our depreciable base, assumed future development costs and estimated proved reserve base area result of additions made through our horizontal drilling efforts and acquisitions.can be partially attributed to recent dispositions with a lower relative cost per BOE.

For the nine months ended September 30, ~~2017,~~2019, DD&A ~~increased 61% to $79.2~~expense was $178.7 million compared to ~~$49.3~~$122.4 million for the same period of ~~2016.~~2018. The ~~increase is primarily attributable~~additional DD&A was related to a ~~53%~~31% increase in production ~~and a 5% increase in our per BOE~~volumes combined with higher DD&A ~~rate. For~~rates between the periods, which resulted in $38.0 million and $18.3 million, respectively, of incremental DD&A expense being incurred during the nine months ended September 30, ~~2017, DD&A on~~2019.

On a per unit basis DD&A increased to ~~$13.34~~$16.55 per BOE compared to ~~$12.70~~$14.86 per BOE for the same period of ~~2016. The increase~~2018. As discussed above, the increased DD&A rate is ~~attributable to our increased estimated proved reserves~~a function of recent drilling and completion costs incurred over the past 12 months relative to our ~~depreciable base and assumed future development costs related~~historical rate. Additionally, the rate increase can be partially attributed to ~~undeveloped proved reserves as~~recent dispositions with a ~~result of additions made through our horizontal drilling efforts and acquisitions, offset by the write down of oil and natural gas properties in the first half of 2016.~~lower relative cost per BOE.

General and administrative, net of amounts capitalized (“G&A”). These are costs incurred for overhead, including payroll and benefits for our corporate staff, severance and early retirement expenses, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, depreciation of corporate level assets, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services, and legal compliance.



~~Callon Petroleum Company~~	~~Management’s Discussion and Analysis of Financial Condition and Results~~	~~Table of Contents~~

G&A for the three months ended September 30, ~~2017~~2019 decreased to ~~$7.3~~$9.4 million compared to ~~$7.9~~$9.7 million for the same period of ~~2016.~~2018. On a per unit basis, G&A decreased 11% to $2.70 per BOE for the three months ended September 30, 2019 compared to $3.03 per BOE for the same period in 2018. G&A expenses for the periods indicated include the following (in ~~millions)~~thousands):


	Three Months Ended September 30,									Three Months Ended September 30,
	2017		2016		$ Change			% Change		2019			2018		$ Change			% Change
Recurring expenses
G&A	$	5.3	$	3.8	$	1.5		39	%	$	8,789		$	7,070	$	1,719		24	%
Share-based compensation	1.2		0.8		0.4			50	%	1,525			1,730		(205		)	(12	)%
Fair value adjustments of cash-settled RSU awards	0.7		3.4		(2.7		)	(79	)%	(926		)	921		(1,847		)	(201	)%
Total G&A expenses	$	7.2	$	8.0	$	(0.8	)	(10	)%	$	9,388		$	9,721	$	(333	)	(3	)%



Delaware		64-0844345
~~Delaware~~ (State or Other Jurisdiction of Incorporation or ~~Organization)~~Organization		~~64-0844345~~ ~~(IRS~~I.R.S. Employer Identification No.)

~~200 North Canal Street~~ ~~Natchez, Mississippi~~ (One Briarlake Plaza
2000 W. Sam Houston Parkway S., Suite 2000
Houston,	Texas	77042
Address of Principal Executive ~~Offices)~~Offices		Zip Code



(281)	589-5200
Registrant’s Telephone Number, Including Area Code
		~~39120~~ ~~(Zip Code)~~
Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report



Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock, $0.01 par value	CPE	New York Stock Exchange



Large accelerated filer	☒	Accelerated filer	☐	~~Non-accelerated filer~~	☐	~~(Do not check if smaller reporting company)~~

Non-accelerated filer	☐	Smaller reporting company	☐

		Emerging growth company	☐



Part I. Financial Information

Item 1. Financial Statements (Unaudited)

Consolidated Balance Sheets	4

Consolidated Statements of Operations	5

Consolidated Statements of Cash Flows	6

~~Notes to~~ Consolidated ~~Financial~~ Statements of Stockholders’ Equity	7

Notes to Consolidated Financial Statements	8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	1924

Item 3. Quantitative and Qualitative Disclosures about Market Risk	3034

Item 4. Controls and Procedures	3135

Part II. Other Information

Item 1. Legal Proceedings	3236

Item 1A. Risk Factors	3236

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	3236

Item 3. Defaults Upon Senior Securities	3236

Item 4. Mine Safety Disclosures	3236

Item 5. Other Information	3236

Item 6. Exhibits	3337



	~~Callon Petroleum Company~~ (Exact Name of Registrant as Specified in Its Charter)


•	Bbl or Bbls: barrel or barrels of oil or natural gas liquids.


•	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.


•	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 a right angle within a specified interval.


•	MEH: Magellan East Houston, a delivery point in Houston, Texas that serves as a benchmark for crude oil.


•	NGL or NGLs: natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.


•	ASU: accounting standards update.


•	FASB: Financial Accounting Standards Board.


•	LIBOR: London Interbank Offered Rate.


•	MBOE: thousand BOE.


•	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.


•	Waha: A 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.


	September 30, 2017			December 31, 2016			September 30, 2019			December 31, 2018
ASSETS	Unaudited						Unaudited
Current assets:
Cash and cash equivalents	$	61,609		$	652,993		$	11,309		$	16,051
Accounts receivable	81,973			69,783			114,120			131,720
Fair value of derivatives	3,333			103			25,032			65,114
Other current assets	2,583			2,247			14,912			9,740
Total current assets	149,498			725,126			165,373			222,625
Oil and natural gas properties, full cost accounting method:
Evaluated properties	3,283,985			2,754,353			4,830,499			4,585,020
Less accumulated depreciation, depletion, amortization and impairment	(2,026,809		)	(1,947,673		)	(2,458,026		)	(2,270,675		)
Net evaluated oil and natural gas properties	1,257,176			806,680
Evaluated oil and natural gas properties, net							2,372,473			2,314,345
Unevaluated properties	1,173,614			668,721			1,405,993			1,404,513
Total oil and natural gas properties	2,430,790			1,475,401
Total oil and natural gas properties, net							3,778,466			3,718,858
Operating lease right-of-use assets							24,447			—
Other property and equipment, net	18,626			14,114			24,770			21,901
Restricted investments	3,362			3,332			3,490			3,424
Deferred financing costs	5,209			3,092			5,081			6,087
Fair value of derivatives	1,121			—			11,209			—
Acquisition deposit	—			46,138
Prepaid	4,650			—
Other assets, net	827			384			4,087			6,278
Total assets	$	2,614,083		$	2,267,587		$	4,016,923		$	3,979,173
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	147,338		$	95,577		$	243,481		$	261,184
Operating lease liabilities							19,196			—
Accrued interest	18,375			6,057			25,660			24,665
Cash-settleable restricted stock unit awards	4,158			8,919			535			1,390
Asset retirement obligations	1,841			2,729			1,250			3,887
Fair value of derivatives	6,380			18,268			8,941			10,480
Other current liabilities							1,948			13,310
Total current liabilities	178,092			131,550			301,011			314,916
Senior secured revolving credit facility	—			—			200,000			200,000
6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs	595,115			390,219
6.125% senior unsecured notes due 2024							596,337			595,788
6.375% senior unsecured notes due 2026							394,317			393,685
Operating lease liabilities							4,995			—
Asset retirement obligations	3,163			3,932			8,294			10,405
Cash-settleable restricted stock unit awards	2,626			8,071			1,737			2,067
Deferred tax liability	1,158			90			39,007			9,564
Fair value of derivatives	659			28			2,573			7,440
Other long-term liabilities	405			295			—			100
Total liabilities	781,218			534,185			1,548,271			1,533,965
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; 201,827,995 and 201,041,320 shares outstanding, respectively	2,018			2,010
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized; 0 and 1,458,948 shares outstanding, respectively							—			15
Common stock, $0.01 par value, 300,000,000 shares authorized; 228,372,081 and 227,582,575 shares outstanding, respectively							2,284			2,276
Capital in excess of par value	2,179,258			2,171,514			2,421,559			2,477,278
Accumulated deficit	(348,426		)	(440,137		)
Retained earnings (accumulated deficit)							44,809			(34,361		)
Total stockholders’ equity	1,832,865			1,733,402			2,468,652			2,445,208
Total liabilities and stockholders’ equity	$	2,614,083		$	2,267,587		$	4,016,923		$	3,979,173



												Retained
	Preferred					Common			Capital in			Earnings			Total
	Stock					Stock			Excess			(Accumulated			Stockholders'
	Shares		$			Shares	$		of Par			Deficit)			Equity
Balance at 12/31/2018	1,459		$	15		227,583	$	2,276	$	2,477,278		$	(34,361	)	$	2,445,208
Net loss	—		—			—	—		—			(19,543		)	(19,543		)
Shares issued pursuant to employee benefit plans	—		—			24	—		154			—			154
Restricted stock	—		—			277	3		4,447			—			4,450
Preferred stock dividend ($1.25 per share)	—		—			—	—		—			(1,824		)	(1,824		)
Balance at 03/31/2019	1,459		$	15		227,884	$	2,279	$	2,481,879		$	(55,728	)	$	2,428,445
Net income	—		—			—	—		—			55,180			55,180
Restricted stock	—		—			380	4		2,071			—			2,075
Preferred stock dividend ($1.25 per share)	—		—			—	—		—			(1,823		)	(1,823		)
Preferred stock redemption costs	—		—			—	—		(5		)	—			(5		)
Balance at 06/30/2019	1,459		$	15		228,264	$	2,283	$	2,483,945		$	(2,371	)	$	2,483,872
Net income	—		—			—	—		—			55,834			55,834
Restricted stock	—		—			108	1		2,307			—			2,308
Preferred stock dividend ($0.24 per share)	—		—			—	—		—			(350		)	(350		)
Preferred stock redemption	(1,459	)	(15		)	—	—		(64,693		)	—			(64,708		)
Loss on redemption of preferred stock	—		—			—	—		—			(8,304		)	(8,304		)
Balance at 09/30/2019	—		$	—		228,372	$	2,284	$	2,421,559		$	44,809		$	2,468,652


1.	Description of Business and Basis of Presentation	6.	Fair Value Measurements	Description of Business and Basis of Presentation	8.	Income Taxes
2.	Acquisitions	7.	Income Taxes	Revenue Recognition	9.	Equity Transactions
3.	Earnings Per Share	8.	Asset Retirement Obligations	Acquisitions and Dispositions	10.	Leases
4.	Borrowings	9.	Equity Transactions	Earnings Per Share	11.	Asset Retirement Obligations
5.	Derivative Instruments and Hedging Activities	10.	Other	Borrowings	12.	Other
6.				Derivative Instruments and Hedging Activities	13.	Carrizo Acquisition
7.				Fair Value Measurements



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



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


~~(a)~~	~~The pro forma financial information was prepared assuming the Ameredev Transaction occurred as of January 1, 2016 and the Plymouth Transaction and Big Star Transaction occurred as of January 1, 2015.~~



(share amounts in thousands)	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Net income (loss)	$	17,081		$	21,139		$	97,600		$	(90,067	)
Preferred stock dividends	(1,824		)	(1,824		)	(5,471		)	(5,471		)
Income (loss) available to common stockholders	$	15,257		$	19,315		$	92,129		$	(95,538	)

Weighted average shares outstanding	201,827			136,983			201,422			112,925
Dilutive impact of restricted stock	510			500			573			—
Weighted average shares outstanding for diluted income (loss) per share	202,337			137,483			201,995			112,925

Basic income (loss) per share	$	0.08		$	0.14		$	0.46		$	(0.85	)
Diluted income (loss) per share	$	0.08		$	0.14		$	0.46		$	(0.85	)

Stock options ^(a)	—			15			—			15
Restricted stock ^(a)	51			25			51			25



(amounts in thousands)	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Net income	$	55,834		$	37,931		$	91,471		$	144,166
Preferred stock dividends	(350		)	(1,823		)	(3,997		)	(5,471		)
Loss on redemption of preferred stock	(8,304		)	—			(8,304		)	—
Income available to common stockholders	$	47,180		$	36,108		$	79,170		$	138,695

Weighted average common shares outstanding	228,322			227,564			228,054			213,409
Dilutive impact of restricted stock	147			576			503			670
Weighted average common shares outstanding for diluted income per share	228,469			228,140			228,557			214,079

Basic income per share	$	0.21		$	0.16		$	0.35		$	0.65
Diluted income per share	$	0.21		$	0.16		$	0.35		$	0.65

Restricted stock ^(a)	1,488			154			829			154


(a)	Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.



	As of
Principal components:	September 30, 2019			December 31, 2018
Senior secured revolving credit facility	$	200,000		$	200,000
6.125% senior unsecured notes due 2024	600,000			600,000
6.375% senior unsecured notes due 2026	400,000			400,000
Total principal outstanding	1,200,000			1,200,000
Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization	5,625			6,469
Unamortized deferred financing costs	(14,971		)	(16,996		)
Total carrying value of borrowings ^(a)	$	1,190,654		$	1,189,473


^(a)	Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $5,081 and $6,087 as of September 30, 2019 and December 31, 2018, respectively.



Year of Potential Settlement	Threshold ^(a)	Contingent Payment Amount	Threshold ^(a)	Contingent Payment Amount		Fair Value as of September 30, 2019 ^(b)	Aggregate Settlements Limit^(c)
							$	60,000
2019	Greater than $60/bbl, less than $65/bbl	$9,000	Equal to or greater than $65/bbl	$20,833		$116
2020	Greater than $60/bbl, less than $65/bbl	$9,000	Equal to or greater than $65/bbl	$20,833		$3,977
2021	Greater than $60/bbl, less than $65/bbl	$9,000	Equal to or greater than $65/bbl	$20,833	^(c)	$3,496


(a)	The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc.


(b)	Contingent consideration to be received will be classified as cash flows from financing activities up to the initial recognition fair value of $8,512; amounts in excess of the initial recognition fair value will be classified as cash flows from operating activities.


(c)	In the event that the 2019 and 2020 prices exceed the $65/bbl threshold, the aggregate amount of contingent consideration is limited to $60,000, resulting in the potential reduction in settlement for 2021 to $18,334.