W&T OFFSHORE INC annual report, FY2018

W&T Offshore, Inc. — 2018 Form 10-K Summary

Business context and reporting period

W&T Offshore is an independent oil and natural gas producer focused on exploration, development and acquisitions in the Gulf of Mexico. The filing covers the fiscal year ended December 31, 2018; the requested “2018 Q4” information is included in the annual filing, with unaudited fourth-quarter data separately disclosed.

Working interests in 48 offshore fields, 47 of which were producing.
Approximately 720,000 gross acres and 390,000 net acres under lease; 41% of 2018 production came from deepwater fields.
Average production was 36,510 Boe per day, down 8.5% from 39,921 Boe per day in 2017.
Production was approximately 50% oil and condensate, 10% NGLs and 40% natural gas on an energy-equivalent basis.

Financial performance and key metrics

Metric	2018	2017	Change
Total revenue	$580.7 million	$487.1 million	+19.2%
Operating income	$247.0 million	$110.0 million	+124.7%
Net income	$248.8 million	$79.7 million	+212.3%
Diluted EPS	$1.72	$0.56	+207.1%
Net cash from operations	$321.8 million	$159.4 million	+102.0%
Capital investment in oil and gas properties and equipment	$106.2 million	$106.2 million	Approximately flat
Cash and cash equivalents	$33.3 million	$99.1 million	Down $65.8 million
Long-term debt carrying value	$633.5 million	$992.1 million	Down $358.5 million

Average realized prices increased to $65.62 per barrel for oil, $28.40 per barrel for NGLs and $3.11 per Mcf for natural gas, compared with $48.13, $23.35 and $2.96, respectively, in 2017.
Operating costs and expenses were $333.7 million, including $153.3 million of lease operating expenses, $131.4 million of DD&A and $60.1 million of general and administrative expense.
Operating margin was approximately 42.5% in 2018, versus approximately 22.6% in 2017. Net margin was approximately 42.8%, versus 16.4%.
Reported earnings benefited from a $53.8 million derivative gain and a $47.1 million gain on debt transactions. These items were unusual and materially affected reported earnings.
No ceiling-test impairment was recorded in 2018 or 2017; a $279.1 million impairment was recorded in 2016.
Total shareholders’ deficit improved to $(324.8) million from $(573.5) million, but remained negative.

Material changes versus the prior comparable period

Revenue increased primarily because oil and NGL prices rose substantially, despite lower production volumes. Natural gas revenue declined 8.5% because of a 13.0% volume decrease.
Lease operating expense increased 6.6% to $153.3 million, partly due to the Heidelberg acquisition, higher insurance premiums and additional workovers.
Net cash from operations more than doubled, driven by higher commodity prices, lower ARO spending and working-capital changes.
Proved reserves increased 13.2% to 84.0 MMBoe from 74.2 MMBoe. Reserve additions replaced 174% of 2018 production; production was 13.3 MMBoe.
Proved reserves comprised 46% oil, 12% NGLs and 42% natural gas. Proved undeveloped reserves increased to 17.0 MMBoe from 12.0 MMBoe.
In October 2018, the Company refinanced substantially all prior secured debt, issuing $625.0 million of 9.75% Senior Second Lien Notes due 2023 and entering a new credit facility due 2022. The borrowing base increased from $150.0 million to $250.0 million.
The Company acquired a 9.375% non-operated interest in the Heidelberg field for a net purchase price of $16.8 million and sold substantially all of its Permian Basin overriding royalty interests for $56.6 million.
The Company formed the Monza joint venture drilling program with private investors. The program covers up to 14 projects, with total member commitments of $361.4 million as of year-end.
Dividends remained suspended, and no company share repurchases occurred during 2018.

Liquidity, debt and outlook

At December 31, 2018, principal debt was $646.0 million, consisting of $625.0 million of Senior Second Lien Notes and $21.0 million drawn under the credit facility. Letters of credit totaled $9.6 million.
Credit facility availability was $219.4 million at year-end, subject to semiannual borrowing-base redeterminations and applicable covenants. The Company reported compliance with its debt covenants.
2019 capital expenditure guidance was approximately $120.0 million, excluding acquisitions, plus approximately $25.0 million of ARO spending. More than 70% of the capital budget was expected to support development.
Management stated that operating cash flow and cash on hand were expected to fund operations, planned capital expenditures and ARO through year-end 2019, while also building available cash balances. The filing states that liquidity was adequate through the going-concern assessment period ending February 2020.
The Company expected to receive a $54.1 million tax refund in 2019, subject to review by the Congressional Joint Committee on Taxation.
Management intended to prioritize profitable, short-payback projects, operate within cash flow, preserve liquidity, meet debt and ARO obligations, and evaluate acquisitions.

Guidance, risks, contingencies and unusual items

Commodity prices declined substantially in the fourth quarter of 2018. Management cited the possibility of lower 2019 oil and natural gas prices, which could reduce cash flow, reserves, liquidity and borrowing-base availability.
Production was deferred by approximately 1.6 MMBoe in 2018 because of pipeline issues, maintenance, well problems and other events. Gulf of Mexico hurricanes, storms, infrastructure outages and third-party processing constraints remain significant risks.
One 2018 deepwater well, Virgo A-12 BP2, was offline at filing and was being evaluated for production-enhancement measures.
Asset retirement obligations were $310.1 million at year-end, including an estimated $25.0 million of 2019 spending. Actual decommissioning costs may differ materially from estimates.
The Company had approximately $300 million of surety bonds outstanding, primarily for plugging and abandonment obligations. Sureties may demand additional collateral, which could reduce liquidity.
The BOEM had not issued outstanding financial-assurance orders as of the filing date, but could require additional assurances for offshore decommissioning obligations in the future.
An Apache lawsuit resulted in a $49.5 million court deposit and a recorded liability; the Company appealed, and no appellate decision had been issued by the filing date.
Open ONRR royalty matters included the “unbundling” initiative and other royalty disputes. The Company had paid additional royalties and stated that the range of further payments could not be determined.
Nine BSEE civil penalties remained open, with proposed penalties totaling $7.7 million and an accrued estimate of approximately $3.5 million.
Commodity derivatives produced a $53.8 million 2018 gain and had a fair value of approximately $74.6 million at year-end. Derivatives may limit gains from rising prices and expose the Company to counterparty and production-volume risk.
Customer concentration was notable: Shell Trading represented approximately 30% of 2018 revenue, BP Products North America 20% and Vitol 14%.

Most important facts for investors to verify

Whether higher commodity prices, derivative gains and the debt-refinancing gain are masking underlying production declines and recurring profitability.
The timing and outcome of borrowing-base redeterminations, debt maturities, covenant compliance and the Company’s ability to refinance or repay the $625.0 million notes due in 2023.
The sustainability of operating cash flow after planned capital spending, ARO expenditures, interest payments and potential surety collateral demands.
Progress and economics of the 14-project JV Drilling Program, including W&T’s exposure to cost overruns and the production status of new wells.
Future Gulf of Mexico production declines, pipeline and platform availability, hurricane exposure and the offline Virgo well.
Changes in proved reserves and the conversion of the 17.0 MMBoe of proved undeveloped reserves, which require approximately $212.7 million of future development costs.
Potential additional liabilities from the Apache appeal, ONRR royalty reviews, BSEE penalties, BOEM financial-assurance requirements and decommissioning obligations.