Index to the Notes to the Consolidated Financial Statements
|
|
|
|
|
|
|
8.
|
|
|
|
9.
|
|
3.
|
|
10.
|
|
4.
|
|
11.
|
|
5.
|
|
12.
|
|
6.
|
|
13.
|
|
7.
|
|
|
|
Note 1 - Description of Business and Basis of Presentation
Description of business
Callon Petroleum Company has been engaged in the 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.
Callon is 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. Since our entry into the Permian Basin in late 2009, we have 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 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 interim consolidated financial statements of the Company have been prepared in accordance with (1) GAAP, (2) the SEC’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and include the accounts of Callon Petroleum Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has a subsidiary, namely Mississippi Marketing, Inc. Effective February 28, 2019, Callon Offshore Production, Inc. was merged with and into CPOC.
These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2018. The balance sheet at December 31, 2018 has been derived from the audited financial statements at that date. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2019.
In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, results of operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation.
Accounting Standards Updates (“ASUs”)
Recently adopted 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”). In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements (“ASU 2019-01”). 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 engaged a third-party consultant to assist with assessing its 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,
|
|
|
|
|
Notes to the Consolidated Financial Statements (Unaudited)
(All dollar amounts in thousands, except per share and per unit data)
|
|
compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component.
The new standard was effective for us in the first quarter of 2019, and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized the cumulative effect of adoption in retained earnings as of January 1, 2019. We further utilized the package of practical expedients at transition to not reassess the following:
|
|
•
|
Whether any expired or existing contracts were or contained leases;
|
|
|
•
|
The lease classification for any expired or existing leases; and
|
|
|
•
|
Initial direct costs for any existing leases.
|
Additionally, we elected the practical expedient under ASU 2018-01, which did not require us to evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. We also chose not to separate lease and non-lease components for the various classes of underlying assets. In addition, for all of our asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases. Accordingly, we recognize lease payments related to our short-term leases in profit or loss on a straight-line basis over the lease term.
Through our implementation process, we evaluated each of our lease arrangements and enhanced our systems to track and calculate additional information required upon adoption of this standard. The standard had an impact on our consolidated balance sheet at September 30, 2019, resulting from the recognition during the current period of right-of-use assets and lease liabilities for operating leases. We have no leases that meet the criteria for classification as a finance lease. We lease certain office space, office equipment, production facilities, compressors, drilling rigs, vehicles and other ancillary drilling equipment under cancelable and non-cancelable leases to support our operations. See Note 10 for additional information regarding the impact of adoption of the new leases standard on our current period results.
Adoption of the new leases standard did not impact our consolidated statement of operations or cash provided from or used in operating, investing or financing in our consolidated statement of cash flows.
We note that the standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.
Recently adopted 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 Company adopted this update on January 1, 2019 and it did not have a material impact on its consolidated financial statements upon adoption of this guidance.
Note 2 - 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 Company’s share of 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 operating revenues. For the three and nine months ended September 30, 2019, $2,566 and $7,779 of gathering and treating fees were recognized and recorded as a reduction to natural gas sales in the consolidated statement of operations, respectively. For the three and nine months ended September 30, 2018,
|
|
|
|
|
Notes to the Consolidated Financial Statements (Unaudited)
(All dollar amounts in thousands, except per share and per unit data)
|
|
$2,209 and $5,413 of gathering and treating fees were recognized and recorded as a reduction to natural gas sales 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 revenue contracts with customers related to our oil and natural gas production, which had a balance at September 30, 2019 and December 31, 2018 of $83,442 and $87,061, respectively, and does not currently include an allowance for doubtful accounts. Accounts receivable, net, from the sale of 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.
Note 3 - Acquisitions and Dispositions
2019 Acquisitions and Dispositions
In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Asset Divestiture”) for net cash proceeds received at closing of $244,935, including customary purchase price adjustments. The transaction also provides for potential contingent consideration in payments of up to $60,000 based on West Texas Intermediate average annual pricing over a three-year period (see Notes 6 and 7 for additional information regarding the contingent consideration payments). The divestiture encompasses the Ranger operating area in the southern Midland Basin which includes approximately 9,850 net Wolfcamp acres with an average 66% working interest. The divestiture did not significantly alter the relationship between capitalized costs and proved reserves, and as such, net cash proceeds and contingent consideration were recorded as adjustments to our full cost pool with no gain or loss recognized.
In the first quarter of 2019, the Company completed various acquisitions and dispositions of additional working interests and acreage located in our existing core operating areas within the Permian Basin. The Company purchased mineral rights for $21,407 in the Spur operating area and received proceeds of $14,084, including customary purchase price adjustments, for certain leasehold interests in our WildHorse acreage. In the second quarter of 2019, the Company completed various acreage swaps in the Permian Basin and received proceeds of $19,108, including customary purchase price adjustments, for certain working interests in our Spur acreage.
|
|
|
|
|
Notes to the Consolidated Financial Statements (Unaudited)
(All dollar amounts in thousands, except per share and per unit data)
|
|
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 5 and 9 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
|
|
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.
Note 4 - Earnings Per Share
Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
|
|
|
|
|
Notes to the Consolidated Financial Statements (Unaudited)
(All dollar amounts in thousands, except per share and per unit data)
|
|
Note 5 - Borrowings
The Company’s borrowings consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
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.
|
Senior secured revolving credit facility (the “Credit Facility”)
On May 25, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility. 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. The maturity date of the Credit Facility is May 25, 2023.
Effective May 1, 2019, the Company entered into the third amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility to, among other things: (i) reaffirm the borrowing base at $1,100,000, excluding the Ranger assets sold; and (ii) amend various covenants and terms to reflect current market trends. As of September 30, 2019, the Credit Facility’s borrowing base remained at $1,100,000 with an elected commitment amount of $850,000.
As of September 30, 2019, there was $200,000 principal and $17,675 in letters of credit outstanding under the Credit Facility. For the period ended September 30, 2019, the Credit Facility had a weighted-average interest rate of 3.55%, 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.
Restrictive covenants
The Company’s Credit Facility and the indentures governing its 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 September 30, 2019.
Note 6 - Derivative Instruments and Hedging Activities
Objectives and strategies for using commodity 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 and put and call options 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 7 for additional information regarding fair value.
|
|
|
|
|
Notes to the Consolidated Financial Statements (Unaudited)
(All dollar amounts in thousands, except per share and per unit data)
|
|
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 commodity 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 7 for additional information regarding fair value.
Contingent consideration arrangement
Our Ranger Asset Divestiture in June of 2019 provides for potential contingent consideration to be received by the Company if commodity prices exceed specific thresholds in each of the next several years. On the disposition date, we recognized a derivative asset of $8,512 based on the initial fair value measurement. See Note 7 for additional information regarding fair value measurement. These contingent payments are summarized in the tables below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
|
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 (Unaudited)
(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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2019
|
Derivative Instrument
|
|
Balance Sheet Presentation
|
|
Asset
|
|
Liability
|
|
Net Asset (Liability)
|
Commodity - Oil
|
|
Fair value of derivatives - Current
|
|
$
|
23,487
|
|
|
$
|
(8,795
|
)
|
|
$
|
14,692
|
|
Commodity - Natural gas
|
|
Fair value of derivatives - Current
|
|
1,429
|
|
|
(146
|
)
|
|
1,283
|
|
Contingent consideration arrangement
|
|
Fair value of derivatives - Current
|
|
116
|
|
|
—
|
|
|
116
|
|
Commodity - Oil
|
|
Fair value of derivatives - Non-current
|
|
3,736
|
|
|
(2,233
|
)
|
|
1,503
|
|
Commodity - Natural gas
|
|
Fair value of derivatives - Non-current
|
|
—
|
|
|
(340
|
)
|
|
(340
|
)
|
Contingent consideration arrangement
|
|
Fair value of derivatives - Non-current
|
|
7,473
|
|
|
—
|
|
|
7,473
|
|
Totals
|
|
|
|
$
|
36,241
|
|
|
$
|
(11,514
|
)
|
|
$
|
24,727
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2018
|
Derivative Instrument
|
|
Balance Sheet Presentation
|
|
Asset
|
|
Liability
|
|
Net Asset (Liability)
|
Commodity - Oil
|
|
Fair value of derivatives - Current
|
|
$
|
60,097
|
|
|
$
|
(10,480
|
)
|
|
$
|
49,617
|
|
Commodity - Natural gas
|
|
Fair value of derivatives - Current
|
|
5,017
|
|
|
—
|
|
|
5,017
|
|
Commodity - Oil
|
|
Fair value of derivatives - Non-current
|
|
—
|
|
|
(5,672
|
)
|
|
(5,672
|
)
|
Commodity - Natural gas
|
|
Fair value of derivatives - Non-current
|
|
—
|
|
|
(1,768
|
)
|
|
(1,768
|
)
|
Totals
|
|
|
|
$
|
65,114
|
|
|
$
|
(17,920
|
)
|
|
$
|
47,194
|
|
As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of commodity 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2019
|
|
Presented without
|
|
|
|
As Presented with
|
|
Effects of Netting
|
|
Effects of Netting
|
|
Effects of Netting
|
Current assets: Fair value of commodity derivatives
|
$
|
35,936
|
|
|
$
|
(11,020
|
)
|
|
$
|
24,916
|
|
Long-term assets: Fair value of commodity derivatives
|
7,464
|
|
|
(3,728
|
)
|
|
3,736
|
|
|
|
|
|
|
|
Current liabilities: Fair value of commodity derivatives
|
$
|
(19,961
|
)
|
|
$
|
11,020
|
|
|
$
|
(8,941
|
)
|
Long-term liabilities: Fair value of commodity derivatives
|
(6,301
|
)
|
|
3,728
|
|
|
(2,573
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2018
|
|
Presented without
|
|
|
|
As Presented with
|
|
Effects of Netting
|
|
Effects of Netting
|
|
Effects of Netting
|
Current assets: Fair value of commodity derivatives
|
$
|
78,091
|
|
|
$
|
(12,977
|
)
|
|
$
|
65,114
|
|
|
|
|
|
|
|
Current liabilities: Fair value of commodity derivatives
|
$
|
(23,457
|
)
|
|
$
|
12,977
|
|
|
$
|
(10,480
|
)
|
Long-term liabilities: Fair value of commodity derivatives
|
(7,440
|
)
|
|
—
|
|
|
(7,440
|
)
|
For the periods indicated, the Company recorded the following in the consolidated statements of operations as a gain or loss on derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Oil derivatives
|
|
|
|
|
|
|
|
Net gain (loss) on settlements
|
$
|
(1,045
|
)
|
|
$
|
(9,306
|
)
|
|
$
|
(7,048
|
)
|
|
$
|
(26,353
|
)
|
Net gain (loss) on fair value adjustments
|
25,767
|
|
|
(24,476
|
)
|
|
(27,750
|
)
|
|
(28,720
|
)
|
Total gain (loss) on oil derivatives
|
24,722
|
|
|
(33,782
|
)
|
|
(34,798
|
)
|
|
(55,073
|
)
|
Natural gas derivatives
|
|
|
|
|
|
|
|
Net gain (loss) on settlements
|
2,056
|
|
|
67
|
|
|
6,612
|
|
|
675
|
|
Net gain (loss) on fair value adjustments
|
(733
|
)
|
|
(624
|
)
|
|
(2,306
|
)
|
|
(976
|
)
|
Total gain (loss) on natural gas derivatives
|
1,323
|
|
|
(557
|
)
|
|
4,306
|
|
|
(301
|
)
|
Contingent consideration arrangement
|
|
|
|
|
|
|
|
Net gain (loss) on fair value adjustments
|
(4,236
|
)
|
|
—
|
|
|
(923
|
)
|
|
—
|
|
Total gain (loss) on derivatives
|
$
|
21,809
|
|
|
$
|
(34,339
|
)
|
|
$
|
(31,415
|
)
|
|
$
|
(55,374
|
)
|
|
|
|
|
|
Notes to the Consolidated Financial Statements (Unaudited)
(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 September 30, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Remainder
|
|
For the Full Year
|
|
For the Full Year
|
|
Oil contracts (WTI)
|
of 2019
|
|
of 2020
|
|
of 2021
|
|
Puts
|
|
|
|
|
|
|
Total volume (Bbls)
|
230,000
|
|
|
—
|
|
|
—
|
|
|
Weighted average price per Bbl
|
$
|
65.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Put spreads
|
|
|
|
|
|
|
Total volume (Bbls)
|
230,000
|
|
|
—
|
|
|
—
|
|
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Floor (long put)
|
$
|
65.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Floor (short put)
|
$
|
42.50
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Collar contracts with short puts (three-way collars)
|
|
|
|
|
|
|
Total volume (Bbls)
|
1,196,000
|
|
|
5,124,000
|
|
|
—
|
|
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Ceiling (short call)
|
$
|
67.46
|
|
|
$
|
65.46
|
|
|
$
|
—
|
|
|
Floor (long put)
|
$
|
56.54
|
|
|
$
|
55.45
|
|
|
$
|
—
|
|
|
Floor (short put)
|
$
|
43.65
|
|
|
$
|
44.66
|
|
|
$
|
—
|
|
|
Collar contracts (two-way collars)
|
|
|
|
|
|
|
Total volume (Bbls)
|
276,000
|
|
|
—
|
|
|
—
|
|
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Ceiling (short call)
|
$
|
60.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Floor (long put)
|
$
|
55.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Short call
|
|
|
|
|
|
|
Total volume (Bbls)
|
—
|
|
|
—
|
|
|
1,825,000
|
|
(a)
|
Weighted average price per Bbl
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
63.00
|
|
|
Swap contracts
|
|
|
|
|
|
|
Total volume (Bbls)
|
276,000
|
|
|
1,098,000
|
|
|
—
|
|
|
Weighted average price per Bbl
|
$
|
60.17
|
|
|
$
|
56.17
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
Oil contracts (Brent ICE)
|
|
|
|
|
|
|
Collar contracts with short puts (three-way collars)
|
|
|
|
|
|
|
Total volume (Bbls)
|
—
|
|
|
837,500
|
|
|
—
|
|
|
Weighted average price per Bbl
|
|
|
|
|
|
|
Ceiling (short call)
|
$
|
—
|
|
|
$
|
70.00
|
|
|
$
|
—
|
|
|
Floor (long put)
|
$
|
—
|
|
|
$
|
58.24
|
|
|
$
|
—
|
|
|
Floor (short put)
|
$
|
—
|
|
|
$
|
50.00
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
Oil contracts (Midland basis differential)
|
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
Total volume (Bbls)
|
2,176,000
|
|
|
4,576,000
|
|
|
1,095,000
|
|
|
Weighted average price per Bbl
|
$
|
(2.50
|
)
|
|
$
|
(1.29
|
)
|
|
$
|
1.00
|
|
|
|
|
|
|
|
|
|
Oil contracts (Argus Houston MEH basis differential)
|
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
Total volume (Bbls)
|
—
|
|
|
1,439,205
|
|
|
—
|
|
|
Weighted average price per Bbl
|
$
|
—
|
|
|
$
|
2.40
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
Natural gas contracts (Henry Hub)
|
|
|
|
|
|
|
Collar contracts (two-way collars)
|
|
|
|
|
|
|
Total volume (MMBtu)
|
598,000
|
|
|
—
|
|
|
—
|
|
|
Weighted average price per MMBtu
|
|
|
|
|
|
|
Ceiling (short call)
|
$
|
3.50
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Floor (long put)
|
$
|
3.13
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Swap contracts
|
|
|
|
|
|
|
Total volume (MMBtu)
|
155,000
|
|
|
—
|
|
|
—
|
|
|
Weighted average price per MMBtu
|
$
|
2.87
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
Natural gas contracts (Waha basis differential)
|
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
|
|
Total volume (MMBtu)
|
2,116,000
|
|
|
4,758,000
|
|
|
—
|
|
|
Weighted average price per MMBtu
|
$
|
(1.18
|
)
|
|
$
|
(1.12
|
)
|
|
$
|
—
|
|
|
(a) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps.
|
|
|
|
|
Notes to the Consolidated Financial Statements (Unaudited)
(All dollar amounts in thousands, except per share and per unit data)
|
|
Note 7 - Fair Value Measurements
The fair value hierarchy 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 approximated 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
Credit Facility (a)
|
|
$
|
200,000
|
|
|
$
|
200,000
|
|
|
$
|
200,000
|
|
|
$
|
200,000
|
|
6.125% Senior Notes (b)
|
|
596,337
|
|
|
595,194
|
|
|
595,788
|
|
|
558,000
|
|
6.375% Senior Notes (b)
|
|
394,317
|
|
|
393,540
|
|
|
393,685
|
|
|
372,000
|
|
Total
|
|
$
|
1,190,654
|
|
|
$
|
1,188,734
|
|
|
$
|
1,189,473
|
|
|
$
|
1,130,000
|
|
|
|
(b)
|
The fair value was based upon Level 2 inputs. See Note 5 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 6 for additional information regarding the Company’s derivative instruments.
Contingent consideration arrangement - embedded derivative financial instrument. The embedded option within the contingent consideration arrangement is considered a financial instrument under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded option on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates an undiscounted payout, and risk adjusts for the discount rates inclusive of adjustments for the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangement, the inputs are considered Level 2 inputs within the fair value hierarchy. See Note 6 for additional information regarding the Company’s contingent consideration arrangement.
|
|
|
|
|
Notes to the Consolidated Financial Statements (Unaudited)
(All dollar amounts in thousands, except per share and per unit data)
|
|
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
Classification
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Assets
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
Fair value of derivatives
|
|
$
|
—
|
|
|
$
|
36,241
|
|
|
$
|
—
|
|
|
$
|
36,241
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
Fair value of derivatives
|
|
—
|
|
|
(11,514
|
)
|
|
—
|
|
|
(11,514
|
)
|
Total net assets (liabilities)
|
|
|
|
$
|
—
|
|
|
$
|
24,727
|
|
|
$
|
—
|
|
|
$
|
24,727
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
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 8 - Income Taxes
The Company provides for income taxes at the 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
%
|
|
|
(a)
|
Accounts for the potential impact of periodic volatility of stock-based compensation tax deductions on future effective tax rates.
|
Note 9 - Equity Transactions
10% Series A Cumulative Preferred Stock (“Preferred Stock”)
Holders of the Company’s 10.00% Series A Cumulative Preferred Stock were 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 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends were payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by the Company’s Board of Directors. Preferred Stock dividends were $350 and $1,823 for the three months ended September 30, 2019 and 2018, respectively, and $3,997 and $5,471 for the nine months ended September 30, 2019 and 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 were redeemed at the redemption price equal to $50.00 per share, plus 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, the Preferred
|
|
|
|
|
Notes to the Consolidated Financial Statements (Unaudited)
(All dollar amounts in thousands, except per share and per unit data)
|
|
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.
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 estimated 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 of 2018, described in Note 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 30, 2019, we have no leases that meet the 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 underlying asset for the lease term, and lease liabilities represent our obligation to make lease payments arising from the 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 the 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 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.
|
|
|
|
|
Notes to the Consolidated Financial Statements (Unaudited)
(All dollar amounts in thousands, except per share and per unit data)
|
|
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 midstream counterparty. Under most of these arrangements, we do not utilize substantially all of the underlying pipeline, gathering system or processing facilities, and thus, we have concluded that those underlying assets do not meet the definition of an identified asset.
The following tables reflect the current period impact of our adoption of the new leases standard. As we have no leases that 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:
|
|
|
|
|
|
|
|
|
|
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 one month or less.
As of September 30, 2019, our weighted average remaining lease term and our weighted average discount rate for our operating leases were 1.36 years and 4.03%, respectively.
Our operating lease liabilities with enforceable contract terms that are greater than one year mature as 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
|
|
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
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:
|
|
•
|
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;
|
|
|
•
|
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;
|
|
|
•
|
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.