EXPAND ENERGY Corp quarterly report, Q3 FY2014

Chesapeake Energy Corporation — Form 10-Q Summary

Entity note: The supplied filing is for Chesapeake Energy Corporation, not Expand Energy Corp. It covers the quarter and nine months ended September 30, 2014; comparisons are with the same 2013 periods. Dollar figures are in millions unless otherwise stated.

Business context and reporting period

Chesapeake was a major U.S. natural gas and liquids producer, with marketing, gathering and compression operations. On June 30, 2014, it spun off its oilfield services business as Seventy Seven Energy Inc. (SSE); Chesapeake retained no ownership interest, though it has ongoing commercial and transition-service arrangements with SSE. Historical oilfield-services results remain included in the comparative figures.

Key financial and operating metrics

Metric	Q3 2014	Q3 2013	Nine months 2014	Nine months 2013
Total revenue	$5,703	$4,867	$15,901	$12,965
Operating income	$1,174	$436	$2,516	$1,820
Net income	$692	$240	$1,387	$967
Net income available to common stockholders	$169	$156	$687	$629
Diluted EPS	$0.26	$0.24	$1.04	$0.96
Operating cash flow	Not separately reported	Not separately reported	$3,805	$3,586

Q3 operating margin was approximately 20.6%, versus 9.0% a year earlier; net margin was approximately 12.1%, versus 4.9%. Results benefited substantially from derivative mark-to-market gains.
Q3 production averaged 726 thousand boe/day, up 8% from the prior quarter and 11% after adjusting for asset sales. Liquids were 29% of production. Nine-month production averaged 699 thousand boe/day, up 4% year over year, or 12% adjusted for asset sales.
Q3 reported natural gas, oil and NGL revenue was $2,341, including $564 of net derivative gains; comparable 2013 revenue was $1,586, including $253 of net derivative losses. Excluding derivatives, Q3 production sales revenue declined $62 year over year as lower realized prices outweighed higher sales volumes.
Nine-month natural gas, oil and NGL sales revenue excluding derivatives increased $539 year over year, supported by higher natural gas prices and greater oil and NGL sales volumes. Average realized price excluding derivatives was $30.63/boe, compared with $28.94/boe.
Q3 production expense was $4.47/boe versus $4.55; general and administrative expense was $0.90/boe versus $1.92. Nine-month DD&A was $1,977, or $10.36/boe, versus $1,945, or $10.62/boe.
At September 30, cash was $90, total assets $40,518, and long-term debt, net, $11,592. Debt less unrestricted cash was approximately $11,502, down $547 from year-end 2013. Current liabilities exceeded current assets by approximately $2,473.
Cash provided by operations of $3,805 was offset by $2,938 of investing outflows and $1,614 of financing outflows; cash declined $747 from year-end to $90. Drilling and completion costs were $3,185 for the nine months, while total investing outflows also included acquisitions and other capital spending.
Cash availability, defined by the company as unrestricted cash plus unused corporate revolver capacity, was $4,016. The $4.0 billion revolver had $59 drawn and $15 used for letters of credit; the company reported covenant compliance and a 2.67:1 debt-to-EBITDA ratio against a 4.0:1 maximum.
Common dividends declared were $0.0875 per share for Q3 and $0.2625 for the nine-month period. Preferred dividends were $128 for the nine months.

Material changes versus the prior comparable period

Q3 revenue rose 17% and net income rose 188% year over year, but the reported earnings improvement was heavily influenced by derivative gains versus losses in 2013. Common-stockholder earnings also reflected a $447 charge for redemption of a subsidiary’s preferred shares.
Nine-month revenue increased 23%, net income increased 43%, and operating cash flow increased 6%. Marketing, gathering and compression revenue grew, but the segment’s nine-month margin before depreciation fell to $28 from $90.
Chesapeake completed the SSE spin-off, reducing its workforce by approximately 5,100 and removing $1,572 of debt from the consolidated company as of June 30. Q3 oilfield-services revenue and expense were nil after the separation.
The company repurchased all third-party preferred shares of CHK Utica for approximately $1,254, eliminating about $75 of annual cash dividends and its related minimum well-drilling obligation.
April refinancing issued $3.0 billion of notes, including $1.5 billion floating-rate notes due 2019 and $1.5 billion 4.875% notes due 2022. Proceeds helped repay the $2.0 billion term loan and redeem higher-coupon notes; debt-purchase and extinguishment losses totaled $195 in the nine-month period.
Capital expenditures were lower: nine-month drilling and completion costs fell 28% to $3,185, reflecting fewer rigs and improved capital efficiency. The company operated an average of 66 rigs versus 75.

Outlook, commentary, risks and unusual items

Management said liquidity was expected to support planned operations, capital spending and contractual commitments, and emphasized financial discipline, noncore asset sales, lower unit costs and profitable growth. The filing provides no specific earnings or production guidance for a future period.
On October 14, 2014, Chesapeake agreed to sell specified southern Marcellus and eastern Utica assets for approximately $5,375, subject to adjustments and closing conditions. The buyer paid a $269 deposit. The sale included about 413,000 net acres and properties producing approximately 56,000 boe/day; closing was expected in Q4 2014, but third-party consents and participation-right waivers were required.
Hedges covered approximately 72% of estimated remaining 2014 natural gas production at an average $4.12/mcf and 64% of estimated remaining 2014 oil production at $94.22/bbl. Disclosed 2015 hedges covered 319 bcf of gas at $4.31/mcf and 17 million barrels of oil at $93.39/bbl. Derivatives reduce price exposure but can materially affect reported earnings and realized proceeds.
The company accrued $100 for Oklahoma royalty claims in Q3. It said ultimate outcomes could differ materially from the estimate and identified other royalty matters for which losses were reasonably possible but not estimable. Michigan criminal proceedings and federal and state investigations concerning leasing and royalty practices also remained ongoing.
Material contractual commitments included $15,772 of undiscounted gathering, processing and transportation payments, $449 of minimum future drilling-service payments, and $283 of minimum future pressure-pumping payments. The company also reported substantial VPP-related obligations; these and other commitments are not all recorded as balance-sheet liabilities.
Other exposures include commodity-price volatility, potentially weaker regional gas differentials and higher gathering costs, debt and refinancing needs, reserve and production uncertainty, environmental and regulatory matters, litigation, and the risk that planned divestitures fail to close on time or at expected proceeds.
Management concluded disclosure controls were effective as of September 30, 2014; no material change in internal control over financial reporting was reported.

Most important facts for investors to verify

Whether the $5.375 billion Southwestern asset sale closed, its final proceeds after adjustments, and the effect of divested production and reserves.
How much Q3 and full-year earnings and cash flow depended on unrealized derivative gains, and the impact of hedge settlements and regional basis differentials.
Whether operating cash flow, liquidity and covenant headroom remain adequate given low cash on hand, negative working capital and the 2015 revolver maturity.
The ultimate cost and timing of the Oklahoma royalty claims, Michigan proceedings, and other royalty, antitrust and environmental matters beyond amounts accrued.
The continuing cash and operational impact of transportation, gathering, drilling and pressure-pumping commitments, including post-spin-off arrangements with SSE.