DENVER, Feb. 24, 2020 (GLOBE NEWSWIRE) -- Centennial Resource Development, Inc. (“Centennial” or the “Company”) (NASDAQ: CDEV) today announced 2019 financial and operational results and 2020 operational plans and targets.
Recent Financial and Operational Highlights
- Increased daily oil and equivalent production volumes 23% and 25% year-over-year, respectively
- Announced strong co-development results from the Northern and Southern Delaware Basins
- Announced the divestiture of water infrastructure assets for $225 million
- Upfront cash proceeds of approximately $150 million expected to essentially fund 2020 cash flow deficit and reduce leverage metrics
- Increased total proved reserves by 15% with organic reserve replacement ratio of 243%
- Reduced total capital expenditures for the fourth consecutive quarter
2020 Financial and Operational Plan
- Plan to operate a four-rig drilling program beginning in April 2020
- Reduced total capital budget by 28% to $640 million from 2019
- Expect to grow crude oil production approximately 3% year-over-year
Announced Leadership Transition
- Mark G. Papa to retire as Chairman and Chief Executive Officer, effective May 31, 2020
- Sean R. Smith will succeed Mr. Papa as Chief Executive Officer
- Steven J. Shapiro to be named non-executive Chairman of the Board
Financial Results
Centennial reported 2019 net income of $15.8 million, or $0.06 per diluted share, compared to $199.9 million, or $0.75 per diluted share, in the prior year. For the fourth quarter, net income was $9.6 million, or $0.03 per diluted share, compared to $31.0 million, or $0.12 per diluted share, in the prior year period.
Fourth quarter crude oil production increased 7% to 45,031 barrels of oil per day (“Bbls/d”) compared to the prior quarter. For the full year 2019, average daily oil and total equivalent production volumes increased to 42,692 Bbls/d and 76,072 barrels of oil equivalent per day (“Boe/d”), or 23% and 25% compared to 2018, respectively.
“Centennial had a strong year, accomplishing essentially all of our operational goals. We maintained our original capital budget while exceeding our oil production target, which was raised twice during the year,” said Mark G. Papa, Chairman and Chief Executive Officer. “Given the uncertainty of oil prices, we reduced our planned capital expenditures for the year. Taking into account the monetization of the saltwater disposal asset, we expect to be essentially cash flow neutral in 2020 at current strip pricing.”
Operational Update
Centennial continues the efficient development of its Delaware Basin acreage position through successful multi-well pad co-development, including economic production from nine separate intervals in 2019. During the quarter, Centennial reported strong results from both Texas and New Mexico.
In Reeves County, Texas, the Bodacious unit (88% WI) was drilled using a stacked-staggered pattern in the Third Bone Spring Sand and Upper Wolfcamp A intervals with approximate 6,200-foot laterals. The two-well pad achieved an average initial 30-day production rate of 1,797 Boe/d, or 1,304 Bbls/d of oil.
“Centennial has been one of the industry leaders in the evaluation and development of the Third Bone Spring Sand in this area of Reeves County,” Papa said. “Having proven the economic viability of co-developing the Third Bone Spring Sand with the Upper Wolfcamp A, we expect this well pattern to continue to play a large role in our future development program.”
The Lucy Prewit pad (100% WI) consisted of three wells targeting the Upper Wolfcamp A interval. Drilled with an average lateral length of 6,800 feet, the wells achieved an average initial 30-day production rate of 1,744 Boe/d (83% oil) and averaged 214 Bbls/d of oil per 1,000 foot of lateral per well, producing over 130,000 cumulative barrels of oil during this period. The three-well Nicholas pad (average 90% WI), also targeting the Upper Wolfcamp A interval, was drilled with approximate 9,800-foot laterals and achieved an average initial 30-day production rate of 1,865 Boe/d (72% oil).
In Lea County, New Mexico, the four-well Airstream 24 State Com pad (91% WI) was drilled using approximately 900-foot spacing in the Second Bone Spring Sand interval with average 10,200-foot effective laterals. The wells averaged 1,843 Boe/d, or 1,529 Bbls/d of oil, for the initial 30-day production period.
“The Airstreams were a positive test, pairing the upper and lower portions of the Second Bone Spring Sand interval,” said Papa. “Specifically, we believe this co-development pattern will allow us to more effectively drain this reservoir on our Lea County position.”
Four Lea County Duck Hunt wells (average 59% WI) were completed in the First, Second and Third Bone Spring Sand and Second Bone Spring Shale intervals. These wells were drilled with an average effective lateral length of 7,200 feet and averaged 1,683 Boe/d (85% oil) for the initial 30-day production period, or 199 Bbls/d of oil per 1,000 foot of lateral per well.
Total capital expenditures incurred for the year were $891.8 million. During 2019, drilling and completion (“D&C”) capital expenditures incurred were $691.4 million. Centennial’s facilities, infrastructure and other totaled $162.0 million for the year, with an additional $38.4 million spent on land.
“Our team did a tremendous job driving operational efficiencies, which resulted in a significant reduction in well costs during the second half of the year. As a result, we were able to stay within our original capital expenditure range, while completing fourteen more gross wells than originally anticipated,” Papa said.
Water Infrastructure Update
On February 24, 2020, the Company signed a purchase and sale agreement with a subsidiary of WaterBridge Resources LLC (“WaterBridge”) to divest its saltwater disposal wells and associated produced water infrastructure in Reeves County for $225 million, consisting of $150 million in cash at closing and an additional $75 million payable to the Company on a deferred basis upon meeting certain incentive thresholds. The divested infrastructure assets currently dispose of approximately half of the Company’s gross produced water in Texas. At closing, which is expected at the end of the first quarter, Centennial anticipates it will receive after-tax cash proceeds of approximately $150 million, which will be used to repay borrowings under its revolving credit facility. The Company believes the $75 million in incentive payments is reasonable to achieve based on current development activity. WaterBridge is a long-standing partner and has historically disposed of nearly half of the Company’s produced water volumes in Reeves County. The divested assets, combined with WaterBridge’s broader Southern Delaware system, will provide significant flexibility and additional capacity to service Centennial’s water disposal needs. Centennial will pay a market disposal rate on incremental water volumes that WaterBridge does not already gather and dispose, and these incremental costs are incorporated into Centennial’s 2020 lease operating expense guidance.
“This transaction represents a significant premium to Centennial’s current trading valuation and will essentially offset any outspend this year, assuming current prices,” said Papa. “It also significantly reduces the amount of infrastructure capex needed to maintain and grow these assets in the future.”
Barclays acted as exclusive financial advisor to the Company in connection with the transaction.
2020 Operational Plans and Targets
Centennial will continue to maintain a strong balance sheet during the current commodity price environment. As a result, Centennial expects to reduce its operated rig program from five currently to four at the beginning of April. Assuming planned activity levels and current commodity prices, the Company is targeting crude oil production growth of 3% during 2020.
“In today’s uncertain commodity price environment, balance sheet strength is much more important than production growth,” said Papa. “Our 2020 capital budget is a prudent decision to preserve high-quality inventory and maintain a low leverage profile.”
The estimated fiscal year 2020 total capital budget is approximately $590 million to $690 million, which represents a reduction of 28% compared to 2019. Total D&C costs are estimated to be $490 million to $550 million, of which essentially all is associated with operated activity. Centennial has allocated approximately $90 million to $120 million to facilities, infrastructure and other, with the remaining $10 million to $20 million to be spent on land.
Beginning in the second quarter, Centennial expects to operate three rigs in Reeves County. The Company will focus its Reeves County activity in the Upper Wolfcamp A and Third Bone Spring Sand zones, while continuing to develop and test additional zones. The remaining operated rig and associated D&C capital will be allocated to its Lea County position. (For a summary table of Centennial’s 2020 operational guidance, please see the Appendix to this press release.)
Year-End 2019 Proved Reserves
Centennial reported a 15% increase in year-end 2019 total proved reserves to 301 MMBoe, consisting of 50% oil, 28% natural gas and 22% natural gas liquids. Proved developed reserves increased by 26% to 147 MMBoe (49% of total proved reserves) as of December 31, 2019, reflecting the continued successful development of the Company’s horizontal well inventory. For 2019, Centennial’s organic reserve replacement ratio was 243%. The Company’s 2019 proved developed finding and development cost totaled $15.09 per Boe. Centennial’s drill-bit finding and development cost was $13.17 per Boe for 2019. Using SEC prices and discounting the present value at 10% (“PV 10%”), the value of Centennial’s total proved reserves at December 31, 2019 was $2.2 billion.
Centennial had a standardized measure of discounted future net cash flows of $2.1 billion. Netherland Sewell & Associates, Inc., an independent reserve engineering firm, prepared Centennial’s year-end reserves estimates as of December 31, 2019. (For additional information relating to our reserves, in addition to an explanation of how we calculate and use the organic reserve replacement ratio and finding and development costs, please see the Appendix of this press release.)
Capital Structure and Liquidity
As of December 31, 2019, Centennial had $10 million in cash on hand, $175 million of borrowings under its revolving credit facility and $900 million of senior unsecured notes. This resulted in debt-to-book capitalization (GAAP) and net debt-to-book capitalization (non-GAAP) ratios of 24% and 25%, respectively. Centennial’s total liquidity was $634 million, based on the Company’s $800 million of elected commitments under its revolving credit facility and letters of credit outstanding as of December 31, 2019.
Leadership Transition
The Centennial Board of Directors (the “Board”) announced Sean R. Smith, current Vice President and Chief Operating Officer, has been promoted to Chief Executive Officer, effective June 1, 2020. Mr. Smith has been appointed in connection with the planned retirement of Mark G. Papa, who has served as Centennial’s Chairman and Chief Executive Officer since 2016. At that time, Mr. Smith is also expected to be appointed to the Board.
“After fifty-two years in the oil and gas industry, I am looking forward to retirement and spending more time with my family. I am proud of the team we have assembled and the organization we have built at Centennial. In October of 2016, Centennial was a new public company, producing approximately 6,000 barrels of oil per day. Today, we are regarded as a technical leader within the E&P industry with 45,000 barrels per day of oil production and a track record of consistent execution. Notably, all of this has been accomplished by maintaining a rigorous focus on corporate rate-of-return and a conservative financial profile,” said Papa. “Looking ahead, the Board and I agree that Sean is the ideal person to lead Centennial. Sean has displayed strong leadership, managing the Company’s day-to-day operations over the past four years. This, in part, will ensure a seamless transition to his new role as Chief Executive Officer. Importantly, Sean exhibits the Centennial ‘culture’ and core values, with a keen focus on technical proficiency, high standards of excellence, integrity, hard work and proven results. I am very comfortable transitioning my leadership role to Sean and the very talented and experienced Centennial management team.”
Mr. Smith has over 24 years of technical experience in the oil and gas industry. Since joining Centennial in 2014, Mr. Smith has served in positions of increasing responsibility across the Company, most recently as Centennial’s Vice President and Chief Operating Officer where he oversees all aspects of the Operations, Geosciences, Reservoir Engineering, Marketing, Land and Human Resources Departments. During this time, Mr. Smith was instrumental to growing Centennial’s Corporate Headquarters, while also remaining responsible for the formulation and execution of the Company’s annual operating budget. Prior to COO, Mr. Smith served as Vice President of Geosciences for the privately-held Centennial. Before Centennial, Mr. Smith worked in several roles at QEP Resources, including General Manager for the Williston, Powder River and Denver Julesburg Basins. Mr. Smith previously worked at Resolute Energy Corporation as a Manager and Geologist. Prior to joining Resolute, Mr. Smith held various geotechnical roles at Kerr-McGee and Sanchez Oil & Gas. Mr. Smith earned his B.A. in Geology from Lawrence University and is licensed with the Texas Board of Professional Geoscientists.
“It has been a great privilege to learn from such an industry icon over the last several years, and I am honored to have been chosen to succeed Mark and lead such an amazing team going forward,” said Smith. “Mark has positioned Centennial to deliver long-term success, having assembled a high-quality asset base and driven a culture of technical excellence throughout the organization. We will continue to leverage these core strengths in addition to focusing on further efficiencies, in order to drive long-term value for our stakeholders.”
The Board also announced it will separate the roles of Chairman and Chief Executive Officer and that current Director Steven J. Shapiro has been named to succeed Mr. Papa as non-executive Chairman of the Board. Mr. Shapiro has more than forty years of financial and operational experience within the energy industry. Previously, Mr. Shapiro held various leadership positions at Burlington Resources Inc., including Chief Financial Officer and a member of its Board of Directors. In addition, Mr. Shapiro held senior leadership positions at Vastar Resources, Inc. and Atlantic Richfield Company (ARCO).
“Centennial is fortunate to have had an industry visionary lead this company during its early stages as a public company. Mark’s exemplary leadership, technical expertise and financial principles will leave a long-lasting impact on Centennial. On behalf of the Board and the entire Centennial organization, I’d like to thank Mark for his dedicated service,” said Mr. Shapiro. “Going forward, I look forward to working with Sean, as well as the entire management team, as we embark upon the next chapter of growth and development for the Company.”
Additionally, Matt R. Garrison has been appointed by the Board to serve as Vice President and Chief Operating Officer, also effective June 1, 2020. Mr. Garrison currently serves as the Company’s Vice President of Geosciences, a position he has held since 2016. In addition to being responsible for the geologic oversight of the Company’s drilling activity, Mr. Garrison was a key figure in the delineation and development of the Third Bone Spring Sand in Reeves County, Texas, as well as the strategic entry into Lea County, New Mexico. Prior to joining Centennial, Mr. Garrison spent nine years at EOG Resources, Inc. (“EOG”), most recently as Exploration Manager in the Midland Division where he was focused on the exploration and development of the Avalon, Bone Spring and Wolfcamp plays across the Delaware Basin. Mr. Garrison began his career in 2007 at EOG’s Fort Worth Division, where he focused on the horizontal development of the Barnett Shale. Mr. Garrison received his B.S. in Geology from Texas A&M University and his M.S. in Geology from Oklahoma State University.
Annual Report on Form 10-K
Centennial’s financial statements and related footnotes will be available in its Annual Report on Form 10-K for the year ended December 31, 2019, which is expected be filed with the U.S. Securities and Exchange Commission (“SEC”) on February 24, 2020.
Conference Call and Webcast
Centennial will host an investor conference call on Tuesday, February 25, 2020 at 8:00 a.m. Mountain (10:00 a.m. Eastern) to discuss fourth quarter and full year 2019 operating and financial results. Interested parties may join the webcast by visiting Centennial’s website at www.cdevinc.com and clicking on the webcast link or by dialing (800) 789-3525, or (442) 268-1041 for international calls, (Conference ID: 7679910) at least 15 minutes prior to the start of the call. A replay of the call will be available on Centennial’s website or by phone at (855) 859-2056 (Conference ID: 7679910) for a 14-day period following the call.
About Centennial Resource Development, Inc.
Centennial Resource Development, Inc. is an independent oil and natural gas company focused on the development of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. The Company’s assets and operations, which are held and conducted through Centennial Resource Production, LLC, are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. For additional information about the Company, please visit www.cdevinc.com.
Cautionary Note Regarding Forward-Looking Statements
The information in this press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this press release, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this press release, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “goal,” “plan,” “target” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.
Forward-looking statements may include statements about:
- our business strategy and future drilling plans;
- our reserves and our ability to replace the reserves we produce through drilling and property acquisitions;
- our drilling prospects, inventories, projects and programs;
- our financial strategy, liquidity and capital required for our development program;
- our realized oil, natural gas and NGL prices;
- the timing and amount of our future production of oil, natural gas and NGLs;
- our hedging strategy and results;
- our competition and government regulations;
- our ability to obtain permits and governmental approvals;
- our pending legal or environmental matters;
- the marketing and transportation of our oil, natural gas and NGLs;
- our leasehold or business acquisitions;
- cost of developing our properties;
- our anticipated rate of return;
- general economic conditions;
- credit markets;
- uncertainty regarding our future operating results;
- our plans, objectives, expectations and intentions contained in this press release that are not historical; and
- the other factors described in our Annual Report on Form 10-K for the year ended December 31, 2019, and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described in our filings with the SEC.
Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.
Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this press release 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.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this press release.
Contact:
Hays Mabry
Director, Investor Relations
(832) 240-3265
ir@cdevinc.com
SOURCE Centennial Resource Development, Inc.
Details of our 2020 operational and financial guidance are presented below:
|
2020 FY Guidance |
| Net average daily production (Boe/d) |
74,500 |
— |
80,500 |
| Net average daily oil production (Bbls/d) |
42,000 |
— |
45,600 |
|
|
|
|
| Production costs |
|
|
|
| Lease operating expenses ($/Boe) |
$5.90 |
— |
$6.50 |
| Gathering, processing and transportation expenses ($/Boe) |
$3.00 |
— |
$3.40 |
| Depreciation, depletion, and amortization ($/Boe) |
$15.00 |
— |
$17.00 |
| Cash general and administrative ($/Boe) |
$2.00 |
— |
$2.30 |
| Non-cash stock-based compensation ($/Boe) |
$0.90 |
— |
$1.10 |
| Severance and ad valorem taxes (% of revenue) |
6.0% |
— |
8.0% |
|
|
|
|
| Capital expenditure program ($MM) |
$590 |
— |
$690 |
| Drilling and completion capital expenditure |
$490 |
— |
$550 |
| Facilities, infrastructure and other |
$90 |
— |
$120 |
| Land |
$10 |
— |
$20 |
|
|
|
|
| Operated drilling program |
|
|
|
| Wells spud (gross) |
65 |
— |
75 |
| Wells completed (gross) |
65 |
— |
75 |
| Average working interest |
80% |
— |
90% |
| Average lateral length (feet) |
7,300 |
— |
8,000 |
Centennial Resource Development, Inc.
Operating Highlights
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
| Net revenues (in thousands): |
|
|
|
|
|
|
|
| Oil sales |
$ |
220,600 |
|
|
$ |
176,306 |
|
|
$ |
810,655 |
|
|
$ |
709,813 |
|
| Natural gas sales |
12,901 |
|
|
15,713 |
|
|
44,556 |
|
|
62,325 |
|
| NGL sales |
22,891 |
|
|
30,485 |
|
|
89,119 |
|
|
118,907 |
|
| Oil and gas sales |
$ |
256,392 |
|
|
$ |
222,504 |
|
|
$ |
944,330 |
|
|
$ |
891,045 |
|
|
|
|
|
|
|
|
|
| Average sales price: |
|
|
|
|
|
|
|
| Oil (per Bbl) |
$ |
53.25 |
|
|
$ |
47.95 |
|
|
$ |
52.02 |
|
|
$ |
55.98 |
|
| Effect of derivative settlements on average price (per Bbl) |
(1.09 |
) |
|
1.41 |
|
|
(1.13 |
) |
|
1.48 |
|
| Oil net of hedging (per Bbl) |
$ |
52.16 |
|
|
$ |
49.36 |
|
|
$ |
50.89 |
|
|
$ |
57.46 |
|
|
|
|
|
|
|
|
|
| Average NYMEX price for oil (per Bbl) |
$ |
56.94 |
|
|
$ |
58.81 |
|
|
$ |
57.03 |
|
|
$ |
64.76 |
|
| Oil differential from NYMEX |
(3.69 |
) |
|
(10.86 |
) |
|
(5.01 |
) |
|
(8.78 |
) |
|
|
|
|
|
|
|
|
| Natural gas (per Mcf) |
$ |
1.14 |
|
|
$ |
1.82 |
|
|
$ |
1.07 |
|
|
$ |
1.97 |
|
| Effect of derivative settlements on average price (per Mcf) |
0.09 |
|
|
0.12 |
|
|
0.29 |
|
|
0.06 |
|
| Natural gas net of hedging (per Mcf) |
$ |
1.23 |
|
|
$ |
1.94 |
|
|
$ |
1.36 |
|
|
$ |
2.03 |
|
|
|
|
|
|
|
|
|
| Average NYMEX price for natural gas (per Mcf) |
$ |
2.34 |
|
|
$ |
3.77 |
|
|
$ |
2.52 |
|
|
$ |
3.15 |
|
| Natural gas differential from NYMEX |
(1.20 |
) |
|
(1.95 |
) |
|
(1.45 |
) |
|
(1.18 |
) |
|
|
|
|
|
|
|
|
| NGL (per Bbl) |
$ |
17.47 |
|
|
$ |
23.60 |
|
|
$ |
17.03 |
|
|
$ |
27.45 |
|
|
|
|
|
|
|
|
|
| Net production: |
|
|
|
|
|
|
|
| Oil (MBbls) |
4,142 |
|
|
3,678 |
|
|
15,582 |
|
|
12,679 |
|
| Natural gas (MMcf) |
11,294 |
|
|
8,615 |
|
|
41,703 |
|
|
31,707 |
|
| NGL (MBbls) |
1,311 |
|
|
1,292 |
|
|
5,234 |
|
|
4,332 |
|
| Total (MBoe)(1) |
7,335 |
|
|
6,404 |
|
|
27,766 |
|
|
22,295 |
|
|
|
|
|
|
|
|
|
| Average daily net production: |
|
|
|
|
|
|
|
| Oil (Bbls/d) |
45,031 |
|
|
39,978 |
|
|
42,692 |
|
|
34,737 |
|
| Natural gas (Mcf/d) |
122,759 |
|
|
93,641 |
|
|
114,254 |
|
|
86,868 |
|
| NGL (Bbls/d) |
14,242 |
|
|
14,043 |
|
|
14,338 |
|
|
11,868 |
|
| Total (Boe/d)(1) |
79,734 |
|
|
69,609 |
|
|
76,072 |
|
|
61,082 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
Centennial Resource Development, Inc.
Operating Expenses
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
| Operating costs (in thousands): |
|
|
|
|
|
|
|
| Lease operating expenses |
$ |
38,899 |
|
|
$ |
24,149 |
|
|
$ |
145,976 |
|
|
$ |
83,313 |
|
| Severance and ad valorem taxes |
17,681 |
|
|
13,732 |
|
|
63,200 |
|
|
56,523 |
|
| Gathering, processing, and transportation expense |
20,714 |
|
|
12,410 |
|
|
72,834 |
|
|
57,624 |
|
| Operating costs per Boe: |
|
|
|
|
|
|
|
| Lease operating expenses |
$ |
5.30 |
|
|
$ |
3.77 |
|
|
$ |
5.26 |
|
|
$ |
3.74 |
|
| Severance and ad valorem taxes |
2.41 |
|
|
2.14 |
|
|
2.28 |
|
|
2.54 |
|
| Gathering, processing, and transportation expense |
2.82 |
|
|
1.94 |
|
|
2.62 |
|
|
2.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Centennial Resource Development, Inc.
Condensed Consolidated Statements of Operations
(in thousands, except per share data)
|
Three Months Ended December 31, |
|
Year Ended December 31, |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
| Operating revenues |
|
|
|
|
|
|
|
| Oil and gas sales |
$ |
256,392 |
|
|
$ |
222,504 |
|
|
$ |
944,330 |
|
|
$ |
891,045 |
|
| Operating expenses |
|
|
|
|
|
|
|
| Lease operating expenses |
38,899 |
|
|
24,149 |
|
|
145,976 |
|
|
83,313 |
|
| Severance and ad valorem taxes |
17,681 |
|
|
13,732 |
|
|
63,200 |
|
|
56,523 |
|
| Gathering, processing and transportation expenses |
20,714 |
|
|
12,410 |
|
|
72,834 |
|
|
57,624 |
|
| Depreciation, depletion and amortization |
122,851 |
|
|
102,083 |
|
|
444,243 |
|
|
326,462 |
|
| Impairment and abandonment expense |
4,818 |
|
|
740 |
|
|
47,245 |
|
|
11,136 |
|
| Exploration expense |
2,144 |
|
|
1,942 |
|
|
11,390 |
|
|
9,968 |
|
| General and administrative expenses |
22,567 |
|
|
18,637 |
|
|
79,156 |
|
|
63,304 |
|
| Total operating expenses |
229,674 |
|
|
173,693 |
|
|
864,044 |
|
|
608,330 |
|
| Net gain (loss) on sale of long-lived assets |
(842 |
) |
|
549 |
|
|
(857 |
) |
|
475 |
|
| Income from operations |
25,876 |
|
|
49,360 |
|
|
79,429 |
|
|
283,190 |
|
|
|
|
|
|
|
|
|
| Other income (expense) |
|
|
|
|
|
|
|
| Interest expense |
(16,148 |
) |
|
(8,220 |
) |
|
(55,991 |
) |
|
(26,358 |
) |
| Net gain (loss) on derivative instruments |
660 |
|
|
367 |
|
|
(1,561 |
) |
|
15,336 |
|
| Other income |
13 |
|
|
12 |
|
|
334 |
|
|
8 |
|
| Total other income (expense) |
(15,475 |
) |
|
(7,841 |
) |
|
(57,218 |
) |
|
(11,014 |
) |
|
|
|
|
|
|
|
|
| Income before income taxes |
10,401 |
|
|
41,519 |
|
|
22,211 |
|
|
272,176 |
|
| Income tax expense |
(739 |
) |
|
(8,711 |
) |
|
(5,797 |
) |
|
(59,440 |
) |
| Net income |
9,662 |
|
|
32,808 |
|
|
16,414 |
|
|
212,736 |
|
| Less: Net income attributable to noncontrolling interest |
(44 |
) |
|
(1,828 |
) |
|
(616 |
) |
|
(12,837 |
) |
| Net income attributable to Class A Common Stock |
$ |
9,618 |
|
|
$ |
30,980 |
|
|
$ |
15,798 |
|
|
$ |
199,899 |
|
|
|
|
|
|
|
|
|
| Income per share of Class A Common Stock: |
|
|
|
|
|
|
|
| Basic |
$ |
0.03 |
|
|
$ |
0.12 |
|
|
$ |
0.06 |
|
|
$ |
0.76 |
|
| Diluted |
$ |
0.03 |
|
|
$ |
0.12 |
|
|
$ |
0.06 |
|
|
$ |
0.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP Financial Measure
In addition to disclosing financial results calculated in accordance with U.S. generally accepted accounting principles (“GAAP”), our earnings release contains non-GAAP financial measures as described below.
Adjusted EBITDAX
Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income before interest expense, income taxes, depreciation, depletion and amortization, exploration costs, impairment and abandonment expenses, non-cash gains or losses on derivatives, stock-based compensation and gains and losses from the sale of assets. Adjusted EBITDAX is not a measure of net income as determined by GAAP.
Our management believes Adjusted EBITDAX is useful as it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table presents a reconciliation of Adjusted EBITDAX to net income, our most directly comparable financial measure calculated and presented in accordance with GAAP:
|
Three Months Ended December 31, |
|
Year Ended December 31, |
| (in thousands) |
2019 |
|
2018 |
|
2019 |
|
2018 |
| Adjusted EBITDAX reconciliation to net income: |
|
|
|
|
|
|
|
| Net income attributable to Class A Common Stock |
$ |
9,618 |
|
|
$ |
30,980 |
|
|
$ |
15,798 |
|
|
$ |
199,899 |
|
| Net income attributable to noncontrolling interest |
44 |
|
|
1,828 |
|
|
616 |
|
|
12,837 |
|
| Interest expense |
16,148 |
|
|
8,220 |
|
|
55,991 |
|
|
26,358 |
|
| Income tax expense |
739 |
|
|
8,711 |
|
|
5,797 |
|
|
59,440 |
|
| Depreciation, depletion and amortization |
122,851 |
|
|
102,083 |
|
|
444,243 |
|
|
326,462 |
|
| Impairment and abandonment expense |
4,818 |
|
|
740 |
|
|
47,245 |
|
|
11,136 |
|
| Non-cash portion of derivative (gain) loss |
(4,108 |
) |
|
5,853 |
|
|
(4,094 |
) |
|
5,274 |
|
| Stock-based compensation expense |
6,998 |
|
|
5,848 |
|
|
26,315 |
|
|
18,854 |
|
| Exploration expense |
2,144 |
|
|
1,942 |
|
|
11,390 |
|
|
9,968 |
|
| (Gain) loss on sale of long-lived assets |
842 |
|
|
(549 |
) |
|
857 |
|
|
(475 |
) |
| Adjusted EBITDAX |
$ |
160,094 |
|
|
$ |
165,656 |
|
|
$ |
604,158 |
|
|
$ |
669,753 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Debt / Book Capitalization Ratio
Net debt / book capitalization ratio is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define net debt / book capitalization ratio as net debt divided by book capitalization (non-GAAP). Net debt is defined as long-term debt, net, plus unamortized debt discount and debt issuance costs on Senior Notes minus cash and cash equivalents. Book capitalization (non-GAAP) is defined as long-term debt, net, plus unamortized debt discount and debt issuance costs on Senior Notes plus total equity. Net debt / book capitalization ratio is not a measure calculated in accordance with GAAP.
Our management believes net debt / book capitalization ratio is useful as it allows them to more effectively evaluate our capital structure and liquidity and compare the results against our peers. Net debt / book capitalization ratio should not be considered as an alternative to, or more meaningful than, debt / book capitalization (GAAP) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Our computations of net debt / book capital ratio may not be comparable to other similarly titled measures of other companies.
The following table presents a reconciliation of our net debt / book capitalization ratio to our most directly comparable financial measure calculated and presented in accordance with GAAP:
| (in thousands) |
|
December 31, 2019 |
|
December 31, 2018 |
| Total equity |
|
$ |
3,270,701 |
|
|
$ |
3,243,869 |
|
|
|
|
|
|
|
|
| Long-term debt, net |
|
1,057,389 |
|
|
691,630 |
|
| Unamortized debt discount and debt issuance costs on Senior Notes |
|
17,611 |
|
|
8,370 |
|
| Long-term debt |
|
1,075,000 |
|
|
700,000 |
|
| Less: cash and cash equivalents |
|
(10,223 |
) |
|
(18,157 |
) |
| Net debt (Non-GAAP) |
|
1,064,777 |
|
|
681,843 |
|
|
|
|
|
|
| Book capitalization (GAAP)(1) |
|
$ |
4,328,090 |
|
|
$ |
3,935,499 |
|
|
|
|
|
|
| Book capitalization (non-GAAP)(2) |
|
$ |
4,345,701 |
|
|
$ |
3,943,869 |
|
|
|
|
|
|
| Debt / book capitalization (GAAP)(3) |
|
24 |
% |
|
18 |
% |
|
|
|
|
|
| Net debt / book capitalization (non-GAAP)(4) |
|
25 |
% |
|
17 |
% |
|
|
|
|
|
|
|
(1) Book capitalization (GAAP) is calculated as total equity plus long-term debt, net.
(2) Book capitalization (non-GAAP) is calculated as total equity plus long-term debt.
(3) Debt / book capitalization (GAAP) is calculated as long-term debt, net divided by book capitalization (GAAP).
(4) Net debt / book capitalization (non-GAAP) is calculated as net debt divided by book capitalization (non-GAAP).
The following table summarizes the approximate volumes and average contract prices of the swap contracts the Company had in place as of December 31, 2019 and additional contracts entered into through February 20, 2020:
|
Period |
|
Volume (Bbl) |
|
Volume (Bbls/d) |
|
Weighted Average
Differential
($/Bbl)(1) |
| Crude oil basis swaps |
January 2020 - March 2020 |
|
273,000 |
|
3,000 |
|
$ |
0.67 |
|
April 2020 - June 2020 |
|
273,000 |
|
3,000 |
|
|
0.67 |
|
July 2020 - September 2020 |
|
276,000 |
|
3,000 |
|
|
0.67 |
|
October 2020 - December 2020 |
|
276,000 |
|
3,000 |
|
|
0.67 |
(1) These oil basis swap transactions are settled based on the difference between the arithmetic average of the ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable settlement period.
|
Period |
|
Volume
(MMBtu) |
|
Volume
(MMBtu/d) |
|
Weighted Average
Fixed Price
($/MMBtu)(1) |
| Natural gas swaps - Henry Hub |
April 2020 - October 2020 |
|
6,420,000 |
|
30,000 |
|
$ |
2.03 |
(1) These natural gas swap contracts are settled based on NYMEX Henry Hub price as of the specified settlement date.
The following table summarizes estimated proved reserves, pre-tax PV 10%, and standardized measure of discounted future cash flows as of the periods indicated:
|
December 31, 2019 |
|
December 31, 2018 |
|
December 31, 2017 |
| Proved developed reserves: |
|
|
|
|
|
|
|
|
| Oil (MBbls) |
74,842 |
|
|
63,317 |
|
|
41,786 |
|
| Natural gas (MMcf) |
237,791 |
|
|
180,542 |
|
|
126,065 |
|
| NGL (MBbls) |
32,743 |
|
|
23,093 |
|
|
12,133 |
|
| Total proved developed reserves (MBoe)(1) |
147,216 |
|
|
116,500 |
|
|
74,929 |
|
| Proved undeveloped reserves: |
|
|
|
|
|
| Oil (MBbls) |
75,317 |
|
|
79,449 |
|
|
59,147 |
|
| Natural gas (MMcf) |
264,639 |
|
|
222,310 |
|
|
201,147 |
|
| NGL (MBbls) |
34,499 |
|
|
28,825 |
|
|
18,853 |
|
| Total proved undeveloped reserves (MBoe)(1) |
153,923 |
|
|
145,326 |
|
|
111,525 |
|
| Total proved reserves: |
|
|
|
|
|
| Oil (MBbls) |
150,159 |
|
|
142,766 |
|
|
100,933 |
|
| Natural gas (MMcf) |
502,430 |
|
|
402,852 |
|
|
327,212 |
|
| NGL (MBbls) |
67,242 |
|
|
51,918 |
|
|
30,986 |
|
| Total proved reserves (MBoe)(1) |
301,139 |
|
|
261,826 |
|
|
186,454 |
|
|
|
|
|
|
|
| Proved developed reserves % |
49 |
% |
|
44 |
% |
|
40 |
% |
| Proved undeveloped reserves % |
51 |
% |
|
56 |
% |
|
60 |
% |
|
|
|
|
|
|
| Reserve values (in millions): |
|
|
|
|
|
| Standard measure of discounted future net cash flows |
$ |
2,062.4 |
|
|
$ |
2,479.9 |
|
|
$ |
1,503.3 |
|
| Discounted future income tax expense |
135.5 |
|
|
499.6 |
|
|
244.8 |
|
| Total proved pre-tax PV 10% (2) |
$ |
2,197.9 |
|
|
$ |
2,979.5 |
|
|
$ |
1,748.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
(2) Total proved pre-tax PV 10% (“Pre-tax PV 10%”) may be considered a non-GAAP financial measure as defined by the Securities and Exchange Commission (“SEC”) and is derived from the standardized measure of discounted future net cash flows (the ‘‘Standardized Measure’’), which is the most directly comparable GAAP financial measure. Pre-tax PV 10% is computed on the same basis as the Standardized Measure but without deducting future income taxes. We believe Pre-tax PV 10% is a useful measure for investors when evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our Pre-tax PV 10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions. However, Pre-tax PV 10% is not a substitute for the Standardized Measure. Our Pre-tax PV 10% and Standardized Measure do not purport to present the fair value of our proved oil, NGL and natural gas reserves.
Supplemental Measures
Organic Reserve Replacement Ratio
The Company uses the organic reserve replacement ratio as an indicator of the Company’s ability to replace the reserves that it has developed and to increase its reserves over time. The ratio is not a representation of value creation and has a number of limitations that should be considered. For example, the ratio does not incorporate the costs or timing of developing future reserves. The organic reserve replacement ratio of 243% is calculated as the sum of total 2019 reserve extensions, discoveries and revisions (technical and pricing) of 67.4 MMBoe, divided by total 2019 production of 27.8 MMBoe. The ratio calculation excludes acquisitions and divestitures.
Proved Developed and Drill-Bit Finding and Development (“F&D”) Costs
The Company uses proved developed F&D cost and drill-bit F&D cost as indicators of capital efficiency, in that they measure the Company’s costs to add proved reserves on a per Boe basis. Both calculations exclude acquisitions and divestitures and are subject to limitations, including the uncertainty of future costs to develop the Company’s reserves.
Proved developed F&D of $15.09 per Boe is calculated as total 2019 exploration and developments costs of $887.3 million divided by the sum of total proved developed reserve extensions and discoveries, transfers from proved undeveloped reserves at year-end 2018, and proved developed reserve revisions (technical and pricing), totaling 58.8 MMBoe.
Drill-bit F&D of $13.17 per Boe is calculated as total 2019 exploration and developments costs of $887.3 million divided by the sum of total 2019 proved reserve extensions, discoveries and revisions (technical and pricing) of 67.4 MMBoe.
