SandRidge Energy, Inc. Reports Financial and Operational Results for Fourth Quarter and Full Year 2018

OKLAHOMA CITY, March 4, 2019 /PRNewswire/ -- SandRidge Energy, Inc. (the "Company" or "SandRidge") (NYSE:SD) today announced financial and operational results for the quarter and fiscal year ended December 31, 2018.

Highlights During and Subsequent to Fourth Quarter and Full Year 2018

• Appointed Paul McKinney as President & CEO in January 2019
• Fourth quarter net income of $54 million, or $1.53 per share (including $43 million of gains on derivatives), and adjusted net income of $5 million, or $0.15 per share (excluding non-cash impact of hedges and other items)
• Year end 2018 net loss of $9 million, or $0.26 per share (including $17 million of loss on derivatives), and adjusted net income of $20 million, or $0.57 per share (excluding non-cash impact of hedges and other items)
• Adjusted EBITDA of $45 million for the fourth quarter and $167 million for year end 2018
• Beat midpoint of 2018 production guidance while achieving cash costs and capital expenditures that were 3% and 8% below midpoint of guidance, respectively
• North Park production increased 53% year over year, reaching 30% of total Company oil production in 2018
• Standardized Measure and PV-10 of $1.0 billion ($612 million using alternative pricing of $54/Bbl and $2.75/MMBtu)

"This is a great time to be joining SandRidge Energy," said Paul McKinney, President and CEO. "With a clean balance sheet, a talented team of oil and gas professionals, and the support of our Board of Directors, we are focusing on profitably growing shareholder value. We have developed a business strategy founded on the principles and industry best practices that we believe will deliver a competitive rate of return to our shareholders on a sustainable basis. Considering the commodity price volatility our industry is experiencing, we plan to maintain flexibility in our capital spending plans with the intention of staying within or very close to within our cash flow. This strategy also supports our ability to capture accretive opportunities we encounter in the market place.

"Our business strategy is focused on a few key components we believe will drive success as we acquire, explore for and develop hydrocarbon resources in the United States. To win in this industry you need to have a winning team and we will do whatever is necessary to attract and retain top tier talent. We will pursue operational excellence with a sense of urgency to deliver low-cost and efficient execution of our operations, leveraging advanced technologies and data analytics to develop a culture of continuous improvement while holding to our core values prioritizing health, safety and environmental stewardship. We will allocate our resources to projects that deliver high margins and returns while fully accounting for risk and uncertainty in each investment opportunity, optimize our portfolio by upgrading our assets through accretive acquisitions, mergers and dispositions that reduce our break-even costs, and explore all avenues of cost reduction. Finally, we will continue to exercise financial discipline by protecting our balance sheet through responsible use of leverage and hedging and financial strategies that sustain our capital programs, and ultimately deliver free cash flow with competitive debt-adjusted per share returns."

Financial Results

Fourth Quarter

For the fourth quarter, the Company reported net income of $54 million, or $1.53 per share, and net cash provided by operating activities of $36 million. After adjusting for certain items, the Company's adjusted net income amounted to $5 million, or $0.15 per share, operating cash flow totaled $44 million and adjusted EBITDA was $45 million for the quarter. The Company defines and reconciles adjusted net income, adjusted EBITDA and other non-GAAP financial measures to the most directly comparable GAAP measure in supporting tables at the conclusion of this press release beginning on page 15.

Full Year

For the full year of 2018, the Company reported a net loss of $9 million, or $0.26 per share, and net cash provided by operating activities of $146 million. After adjusting for certain items, the Company's adjusted net income amounted to $20 million, or $0.57 per share, operating cash flow totaled $137 million and adjusted EBITDA was $167 million for the year.

Operational Results and Activity

Production totaled 3.1 MMBoe (27% oil, 24% NGLs and 49% natural gas) for the fourth quarter and 12.3 MMBoe (28% oil, 23% NGLs and 49% natural gas) for the full year of 2018. During the quarter, the Company averaged two rigs in the Mid-Continent region targeting the Mississippian and the Northwest STACK Meramec and one rig in North Park Basin targeting the Niobrara.

North Park Basin Asset in Jackson County, Colorado

Fourth Quarter

Net oil production in the North Park Basin totaled 314 MBo (3.4 MBopd) for the fourth quarter. During the quarter, the Company drilled six wells.

Full Year 2018

In 2018, the Company drilled twelveNorth Park Basin wells and brought nine wells to sales. One rig drilled two spacing tests, a federal unit obligation well and initiated southern delineation. Production from the eight well eastern spacing test exceeded type curve expectation by a cumulative 14% on an average per well basis and confirmed a minimum of twelve wells per section spacing in this area. The Company also drilled a six well western spacing test using a twenty-three wells per section pattern. The six wells are currently being tested with results expected early in the second quarter 2019. With seven months of drilling, the Company increased oil production in the field by 53% year over year.

Efforts to expand gas processing capabilities progressed throughout the year. The mechanical refrigeration unit "MRU" went into service during the first quarter 2019. The MRU is currently processing 2,000 Mcf per day to extract natural gas liquids and reduce emissions within the field. Construction of a gas to liquids "GTL" processing facility is ongoing with initial installation expected in the second quarter 2019. The GTL pilot is projected to convert 500 Mcf per day into 50 Bbls of diesel and naphtha, with no residual gas.

Mid-Continent Assets in Oklahoma and Kansas

Fourth Quarter

In the fourth quarter, production in the Mississippian totaled 2.5 MMBoe (27 MBoepd, 17% oil) and Northwest STACK production totaled 183 MBoe (2 MBoepd, 40% oil). The Company averaged two rigs in the Mid-Continent and drilled seven wells, two in the Mississippian and five in the Northwest STACK.

The five wells drilled in the Northwest STACK targeted the Meramec, with three wells drilled under the previously announced Drilling Participation Agreement. During the quarter, the Company brought three wells to sales in the Northwest STACK with a 30-Day IP per well average of 292 Boepd (67% oil).

During the quarter, the Company drilled the remaining two wells of the Mississippian four well program and brought three wells online.

Full Year 2018

During the year, the Company drilled twenty-two wells in the Mid-Continent with an average of two rigs and brought twenty wells to sales. In the Northwest STACK, eighteen Meramec wells were drilled with fifteen wells under the Drilling Participation Agreement. Under this agreement, the Company spent only $6 million in total drilling and completion capital for 2018. As a result, the Company converted 5,800 acres to 'held by production,' delineated the play and optimized geologic targeting and completions techniques. In the Mississippian, the Company drilled and completed a four well program which produced a 30-Day IP per well average of 399 Boepd (58% oil).

Year End 2018 Estimated Proved Reserves

The Company's total estimated SEC proved reserves as of December 31, 2018 were 160 MMBoe, a decrease of 10% year over year. The Company's Standardized Measure and PV-10 was $1.0 billion, an increase of 40% year over year. SEC pricing used in the preparation of the December 31, 2018 reserves was $65.56 per Bbl for oil and $3.10 per MMBtu for natural gas, before adjustments.

For comparative purposes, utilizing alternative pricing of $54.00 per Bbl of oil and $2.75 per MMBtu for natural gas rather than SEC pricing for oil and natural gas, total reserves at December 31, 2018 were 128 MMBoe, with a PV-10 of $612 million. These calculations were based on the SEC proved reserves estimation methodology, but applied the aforementioned alternative prices. 

Proved reserves decreased from 177.6 MMBoe at December 31, 2017 to 160.2 MMBoe at December 31, 2018, primarily as a result of incorporating a one-time adjustment to estimated future workover costs in the Mississippian Lime where a larger population of these wells are transitioning into late-life mature production. This estimate of future costs contributed to a 24.9 MMBoe decrease associated with shorter economic lives and when combined with a decrease of 8.3 MMBoe attributable to well performance, results in total revisions of 33.2 MMBoe (7% oil). Proved reserves also decreased 6.6 MMBoe due to divestitures. These reductions were partially offset by the acquisition of 15.4 MMBoe associated with the purchase of interest in Mid-Continent wells, extensions and discoveries of 19.3 MMBoe from successful drilling, as well as recording proved undeveloped reserves at an increased well density in the North Park Basin.

SEC Proved Reserves and Alternative Price Based Proved Reserves

2019 Capital Expenditures and Operational Guidance

In 2019, the Company plans to spend $160 - $180 million in total capital expenditures, which includes $115 - $125 million in drilling and completion capital allocated between the North Park Basin and Mid-Continent. Total production for 2019 is projected to be 11.4 - 12.0 MMBoe with oil production over 32%. Other operational guidance detail can be found on the "2019 Operational and Capital Expenditure Guidance" table below.

Liquidity and Capital Structure

As of February 20, 2019, the Company had no debt and total liquidity was $356 million, which includes $11 million of cash and $345 million of borrowing base under the credit facility, net of outstanding letters of credit. 

Conference Call Information

The Company will host a conference call to discuss these results on Tuesday, March 5, 2019 at 8:00 am CT. The telephone number to access the conference call from within the U.S. is (833) 245-9650 and from outside the U.S. is (647) 689-4222. The passcode for the call is 3764669. An audio replay of the call will be available from March 5, 2019 until 11:59 pm CT on April 4, 2019. The number to access the conference call replay from within the U.S. is (800) 585-8367 and from outside the U.S. is (416) 621-4642. The passcode for the replay is 3764669.

A live audio webcast of the conference call will also be available via SandRidge's website, www.sandridgeenergy.com, under Investor Relations/Presentation & Events. The webcast will be archived for replay on the Company's website for 30 days.

2019 Operational and Capital Expenditure Guidance
Presented below is the Company's operational and capital expenditure guidance for 2019. 

2018 Actual Results vs. 2018 Guidance 

Presented below is the Company's 2018 operational and capital expenditure actuals vs. the midpoint of 2018 guidance.

Operational and Financial Statistics 

Information regarding the Company's production, pricing, costs and earnings is presented below:

Capital Expenditures  

The table below presents actual results of the Company's capital expenditures for the three and twelve months ended December 31, 2018 at the same level of detail as the 2018 full year capital expenditure guidance.

Derivative Contracts

In December 2018, the Company entered into early settlements of all open crude oil swaps covering 9 MBbls per day of production in December 2018 at an average strike price of $56.12 and 5 MBbls per day of production in 2019 at an average strike price of $54.29. The table below sets forth the Company's hedge position for 2019 as of March 4, 2019:

Capitalization

The Company's capital structure as of December 31, 2018 and December 31, 2017 is presented below:

Non-GAAP Financial Measures

This press release includes non-GAAP financial measures. These non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. Below is additional disclosure regarding each of the non-GAAP measures used in this press release, including reconciliations to their most directly comparable GAAP measure.

Reconciliation of Cash Provided by Operating Activities to Operating Cash Flow

The Company defines operating cash flow as net cash provided by operating activities before changes in operating assets and liabilities as shown in the following table. Operating cash flow is a supplemental financial measure used by the Company's management and by securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of the Company's ability to internally fund exploration and development activities and to service or incur additional debt. The Company also uses this measure because operating cash flow relates to the timing of cash receipts and disbursements that the Company may not control and may not relate to the period in which the operating activities occurred. Further, operating cash flow allows the Company to compare its operating performance and return on capital with those of other companies without regard to financing methods and capital structure. This measure should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with GAAP.

Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA

The Company defines EBITDA as net income (loss) before income tax benefit, interest expense, depreciation and amortization - other and depreciation and depletion - oil and natural gas. Adjusted EBITDA, as presented herein, is EBITDA excluding items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are non-recurring, as shown in the following tables.

Adjusted EBITDA is presented because management believes it provides useful additional information used by the Company's management and by securities analysts, investors, lenders, ratings agencies and others who follow the industry for analysis of the Company's financial and operating performance on a recurring basis and the Company's ability to internally fund exploration and development and to service or incur additional debt. In addition, management believes that adjusted EBITDA is widely used by professional research analysts and others in the valuation, comparison and investment recommendations of companies in the oil and gas exploration and production industry. The Company's adjusted EBITDA may not be comparable to similarly titled measures used by other companies.

Reconciliation of Cash Provided by Operating Activities to Adjusted EBITDA

Reconciliation of Net Income (Loss) Available to Common Stockholders to Adjusted Net Income Available to Common Stockholders

The Company defines adjusted net income as net income excluding items that the Company believes affect the comparability of operating results and are typically excluded from published estimates by the investment community, including items whose timing and/or amount cannot be reasonably estimated or are non-recurring, as shown in the following tables.

Management uses the supplemental measure of adjusted net income as an indicator of the Company's operational trends and performance relative to other oil and natural gas companies and believes it is more comparable to earnings estimates provided by securities analysts. Adjusted net income is not a measure of financial performance under GAAP and should not be considered a substitute for net income available to common stockholders.

Reconciliation of PV-10 to Standardized Measure

PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using 12-month average prices for the years ended December 31, 2018 and 2017. PV-10 differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. PV-10 is used by the industry and by management as a reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities. It is useful because its calculation is not dependent on the taxpaying status of the entity. Because of the present value of future income tax discounted at 10% is insignificant, these measures are equivalent.

PV-10 utilizing alternative pricing of $54.00 per Bbl of oil and $2.75 per MMBtu for natural gas is a non-GAAP financial measure. It differs from Standardized Measure and is useful to investors because it reflects the potential value of proved reserves based on commodity price assumptions more closely representative of current average NYMEX futures prices rather than SEC pricing and does not include the effects of income taxes on future net revenues. Neither the PV-10 of the Company's SEC reserves, the PV-10 utilizing alternative pricing nor the Standardized Measure represents an estimate of fair market value of the Company's oil and natural gas properties.

Reconciliation of G&A to Adjusted G&A

The Company reports and provides guidance on Adjusted G&A per Boe because it believes this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period and to compare and make investment recommendations of companies in the oil and gas industry. This non-GAAP measure allows for the analysis of general and administrative spend without regard to stock-based compensation programs and other non-recurring cash items which can vary significantly between companies. Adjusted G&A per Boe is not a measure of financial performance under GAAP and should not be considered a substitute for general and administrative expense per Boe. Therefore, the Company's Adjusted G&A per Boe may not be comparable to other companies' similarly titled measures.

The Company defines adjusted G&A as general and administrative expense adjusted for certain non-cash stock-based compensation and other non-recurring items as shown in the following tables.