PPL 10-K & 10-Q changes, risk factors and insider trading

The business and capital investment plans of PPL depend, in part, on the continued growth and viability of data centers and large load customers in its service territories.

PPL is anticipating increases in load demand, creating a business need for new power generating resources and transmission facilities. Much of this demand is driven by interconnecting with and providing power to data centers and large load customers to serve an increasingly digital economy and to support artificial intelligence. The business and capital investment plans of PPL are focused on meeting these current and projected needs. If these increased demands for electricity do not occur as projected or are not sustained as projected, for any reason, it could affect PPL's financial condition.

PPL is anticipating increases in load demand, creating the need for new power generating resources and transmission facilities. A substantial portion of this demand is driven by the current and projected power needs of data centers to serve an increasingly digital economy and to support artificial intelligence. Extending service to these facilities necessitates significant capital expenditures, which in turn requires sufficient access to sources of capital. These additional capital needs, the increased concentration of business within a single industry based on emerging technologies, and uncertainties regarding the actual capacity required to satisfy the projected new demands of these new industries creates risks for PPL. Ensuring that incremental revenues from these projected new demands cover incremental costs and risks is critical to PPL and its relationship to its existing customers. While contracts with new large load customers typically include provisions for early termination payments, minimum bills, and financial security, these contracts may not fully protect PPL against all risks. Changes in industry practice or advances in the related technologies could reduce the demand for electricity to power data centers or other large load facilities. Additionally, these industries may experience a business downturn, which could cause the loss of current or potential customers or may weaken the financial condition and creditworthiness of existing customers. If anticipated demand growth does not materialize, PPL could experience unrecovered capital investments. Conversely, if demand grows more rapidly than projected, PPL may face challenges in securing adequate generation and transmission capacity and maintaining service reliability.

Many of these environmental law considerations are also applicable to the operations of our key suppliers or customers, such as coal producers, power producers and industrial power users, and may impact the costs of their products and demand for our services.

Because AI technologies remain in the early stages of development and industry standards are still emerging, their use, whether by PPL, its subsidiaries or third-party vendors, presents inherent risks. Although we seek contractual protections and conduct due diligence with third-party vendors that incorporate AI technologies into their products or services, we may not have full visibility into, awareness of, or control over, the underlying data, supply chain dependencies, model training practices, performance, security safeguards, or compliance posture of such AI enabled tools. AI algorithms that we or our third-party vendors use may be flawed or may be based on datasets that are biased or insufficient, which may introduce risks involving data quality, data integrity, cybersecurity, adversarial manipulation, intellectual property, regulatory compliance, biased outcomes, or improper handling of sensitive information.

These limitations, failures, or inaccurate results generated as a result of our employees', contractors' or vendors' use or misuse of AI technologies could lead to operational interruptions or otherwise adversely affect our business, reputation, or financial results. In addition, the development, testing, and deployment of AI capabilities may require significant computational resources, specialized personnel, and additional investment, resulting in increased costs. We may not be able to recover these costs through our regulatory proceedings. Rapid advances in AI capabilities, as well as the emerging regulatory landscape in the United States and internationally, may also require modifications to our systems, adoption of enhanced governance processes or implementation of new safeguards. Future laws, regulations, Executive Orders, or industry standards relating to AI (which may be conflicting), including those addressing transparency, data usage, cybersecurity, accountability, or risk management, could materially affect how we design, procure, or use AI technologies and could increase compliance costs. In addition, the pace of AI innovation and regulation is unpredictable, and we cannot foresee all potential impacts of AI technologies or future laws and regulations or compliance requirements, and their associated costs and consequences. Any of the risks described above could adversely affect our business operations, reputation, or financial results.

Joint Venture Agreement with Blackstone Infrastructure (PPL)

PPL and Blackstone Infrastructure have created a joint venture to build, own and operate new electricity generation stations to power data centers in Pennsylvania under long-term energy services agreements (ESAs) to address underlying resource adequacy and affordability concerns in Pennsylvania and PJM more broadly. Construction of new generation stations will require the execution of ESAs with data center developers, including hyperscalers, or the regulated utilities in Pennsylvania. PPL owns 51% of the joint venture interest and Blackstone Infrastructure owns 49%. The joint venture is actively engaged with hyperscalers, landowners, natural gas pipeline companies and turbine manufacturers, and has secured multiple land parcels to enable this new generation build out; however, no ESAs with hyperscalers have been signed as of the filing date of this Form 10-K.

Rate Case Proceedings

On November 26, 2025, RIE filed a request with the RIPUC for an increase in electric and natural gas base distribution rates, and approval of certain regulatory and accounting treatments. In its application, RIE seeks to implement a two-year rate plan. In the first year of the rate plan, RIE's proposed base distribution rates for electric and gas combined are designed to collect additional operating revenue of approximately $181 million ($66 million or 18.2% in electricity revenues and $115 million or 36.4% in gas revenues). In the second year of the rate plan, RIE's proposed base distribution rates for electric and gas combined are designed to collect the proposed base distribution rate increases for electric and gas in the first year of the rate plan and additional operating revenues of approximately $49 million ($17 million or 3.6% in electricity revenues and $32 million or 7.4% in gas revenues).

The application is based on a historical test year of September 1, 2024 through August 31, 2025 and requested an authorized ROE of 10.75%. Subject to RIPUC approval, new rates are expected to become effective on September 1, 2026. Certain counterparties have intervened in the proceeding. A ruling from the RIPUC is anticipated during the third quarter of 2026. PPL cannot predict the outcome of the proceeding.

See "Regulatory Matters – Rhode Island Activities – Hold Harmless Implementation Agreement" in Note 7 to the Financial Statements for discussion on an additional rate making initiative to mitigate customer rate impacts.

On September 30, 2025, PPL Electric filed a request with the PAPUC for an increase in distribution base rates of approximately $356 million, more than $50 million of which is already included in customer bills through rate recovery mechanisms, and approval of certain regulatory and accounting treatments. The proposed increase in distribution base rates would increase PPL Electric's total annual revenue by approximately 8.6%. The application is based on a fully projected future test year of July 1, 2026 through June 30, 2027 and requested an authorized ROE of 11.3%. Subject to PAPUC approval, new rates are expected to become effective on July 1, 2026. Certain counterparties have intervened in the proceeding. A ruling from the PAPUC is anticipated during the second quarter of 2026. PPL and PPL Electric cannot predict the outcome of the proceeding.

On May 30, 2025, LG&E and KU filed requests with the KPSC for an increase in annual electricity and gas revenues of approximately $391 million ($105 million and $226 million in electricity revenues at LG&E and KU and $60 million in gas revenues at LG&E) and approval of certain regulatory and accounting treatments. The revenue increases would be an increase of 8.3% and 11.5% in electricity revenues at LG&E and KU, and an increase of 14.0% in gas revenues at LG&E.

The applications were based on a forecasted test year of January 1, 2026 through December 31, 2026 and requested an authorized ROE of 10.95%. New interim rates became effective on January 1, 2026, subject to refund pursuant to the KPSC's final order. Certain counterparties have intervened in the proceedings.

On October 20, 2025, LG&E and KU filed with the KPSC a stipulation and recommendation (the agreement) regarding a proposed resolution of issues with a majority of the intervenors in the proceedings.

Under the agreement, the parties proposed that the KPSC should issue orders granting a revised increase in annual electricity and gas revenues of approximately $235 million ($58 million and $132 million in electricity revenues at LG&E and KU and $45 million in gas revenues at LG&E.) The agreement proposed a revised authorized ROE of 9.90%.

The agreement proposed a "stay out" commitment from LG&E and KU to refrain from effective base rate increases before August 1, 2028, subject to certain exceptions. In connection with the stay out period, the agreement also proposed the establishment of two new rate adjustment clause mechanisms, a Generation Cost Recovery Adjustment Clause (GCR) and a Sharing Mechanism Adjustment Clause (SM).

The proposed GCR mechanism would provide LG&E and KU recovery of and return on investment of covered costs (excluding fuel amounts, which LG&E and KU can recover via an existing rate mechanism) of relevant new generation and energy storage assets authorized in the 2022 and 2025 CPCN proceedings (excluding the Mill Creek Unit 6 NGCC, see "2025 CPCN" for more information regarding the Mill Creek Unit 6 NGCC) as they are placed in service.

The proposed SM mechanism would address any base rate revenue deficiency or surplus during the final thirteen months of the stay out period, July 2027 through July 2028, below or above a suggested ROE band of 9.40% to 10.15%. Any such base rate revenue deficiency or surplus would be collected from or returned to customers over a thirteen-month billing period beginning November 2028.

Following issuance of the 2025 CPCN Order, LG&E and KU filed supplemental testimony with the KPSC in the rate case proceedings seeking recovery of the Mill Creek Unit 2 stay open costs through a proposed additional rate adjustment clause mechanism.

The agreement further proposed that LG&E and KU use regulatory deferral accounting for actual expenses above or below base rate levels for certain expenses including: pension and post-retirement benefits, storm restoration, vegetation management, transmission waivers and credits, and gas line or well activities, with recovery of such deferred asset or liability amounts to be addressed in future rate cases.

On February 16, 2026, the KPSC issued orders approving portions of the October 2025 stipulation and recommendation, with modifications.

The KPSC orders provide for increases in annual electricity and gas revenues of $233 million ($59 million and $128 million in electricity revenues at LG&E and KU and $46 million in gas revenues at LG&E.) The orders include authorized returns on equity of 9.775% for base rate purposes and 9.675% for capital rate adjustment mechanisms.

The KPSC orders approve LG&E's and KU's requests for establishment of certain new rate adjustment mechanisms or tariffs, with modifications:

• a temporary Pilot Generation Recovery Adjustment Clause (PGR) to provide recovery of and return on investment of applicable costs of certain new generation and storage assets being built or anticipated to be built by LG&E and KU as authorized in the 2022 CPCN proceeding;

• the inclusion in the PGR of recovery of and return on investment of certain costs associated with a potential extension of the operating life of LG&E's Mill Creek Unit 2 beyond its original 2027 retirement date; and

• an Extremely High Load Factor Tariff for future applicable customers, such as data centers, which includes requirements such as long-term contracts, minimum revenue payments and collateral security structures that help protect the interests of LG&E, KU and of other ratepayers.

The PGR mechanism is similar to the GCR proposed in the stipulation, but restructured by the KPSC to be a pilot adjustment mechanism with a term until the earlier of ten months following the submission of LG&E's and KU's next base rate proceeding or the effective date of new rates in such proceeding, with the expectation that the mechanism would be reviewed in such proceeding. The pilot mechanism will apply to the planned Mill Creek Unit 5, Brown Battery Energy Storage System, Mercer County Solar and Marion County Solar generation-related projects. The KPSC also included Mill Creek Unit 2's potential stay-open costs in the PGR in lieu of approving the stipulation's request for a stand-alone adjustment mechanism for such costs. Finally, the KPSC excluded from coverage under the PGR costs related to Mill Creek Unit 6 and Brown Unit 12 planned new generation assets due to their anticipated in-service dates falling outside of the estimated pilot mechanism's duration, but without prejudice to LG&E and KU seeking recovery of such costs in future proceedings.

The KPSC orders also approved, approved with modifications, or denied in some cases, other requested accounting and rate matters relating to regulatory assets or liabilities, depreciation rates, and other areas.

The rate changes have a retroactive effective date as of January 1, 2026. Consistent with authorized rate case procedures, LG&E and KU will refund to customers amounts billed in excess of the final approved rates within sixty days.

The KPSC orders did not approve the SM adjustment clause that had been requested in the stipulation and made no modifications to the stay out offer by LG&E and KU to refrain from effective base rate increases prior to August 2028.

LG&E and KU and all intervenors have rights to request rehearing or appeal of the orders of the KPSC and because the KPSC orders modified or denied terms of the proposed stipulation, LG&E and KU and all stipulating parties have the right to withdraw from the stipulation.

LG&E and KU continue to evaluate the details contained in the orders and related matters as they consider next steps. PPL, LG&E and KU cannot predict the outcome of this matter.

In addition, pursuant to prior orders of the KPSC, the LG&E and KU rate case application included an assessment of a potential legal merger of LG&E and KU and concluded a legal merger may be appropriate. On December 30, 2025, LG&E filed a joint update with KU in the rate case proceedings stating that it expects to file necessary applications for merger approval in mid-2026 with the KPSC. Ultimately, formal approval for a merger would be required from the KPSC, VSCC and FERC via subsequent regulatory applications.

2025 CPCN

On February 28, 2025, LG&E and KU filed an application with the KPSC regarding certain future plans for new generation and generation-related construction matters. The proposals included in the application were intended to serve anticipated load growth, including from potential data center demand in LG&E's or KU's service territory. The proposals did not include retirements of coal or other fossil-fueled plants, which would require additional KPSC approval procedures under Kentucky legislation enacted in 2023 and 2024.

LG&E and KU submitted a joint application to the KPSC for approval of certain certificates of public convenience and necessity, site compatibility certificates, and accounting treatment, where applicable, relating to a number of generation-related plans or projects that generally are expected to become operational or established within the next six years. The aggregate projected capital expenditures associated with these proposals were expected to be $3.7 billion. The application included proposals to build:

•a 645 MW NGCC generation unit at KU's E.W. Brown station (Brown Unit 12),

•a 645 MW NGCC generation unit at LG&E's Mill Creek station (Mill Creek Unit 6),

•a four-hour 400 MW (1600 MWh total) battery energy storage system (BESS) at LG&E's Cane Run station, and

•a selective catalytic reduction (SCR) environmental facility at KU's Ghent station Unit 2 (Ghent Unit 2).

The new NGCC units are anticipated to be wholly owned by LG&E and the BESS unit jointly owned by LG&E (32%) and KU (68%), with actual project costs allocated consistent with LG&E's and KU's ultimate ownership shares and existing shared dispatch, cost allocation, tariff or other frameworks. The proposed Mill Creek Unit 6 NGCC is in addition to a new NGCC unit currently under construction at that location (Mill Creek Unit 5).

The filing also noted projected in service dates for the projects, including the Brown Unit 12 NGCC in 2030, the Mill Creek Unit 6 NGCC in 2031, the Cane Run BESS in 2028 and the Ghent Unit 2 SCR in 2028.

On July 29, 2025, LG&E and KU filed with the KPSC a stipulation and recommendation regarding a proposed resolution of issues with several of the intervenors in the CPCN proceeding (stipulation). The stipulation recommended to the KPSC the approval of the large majority of LG&E's and KU's requested generation-related projects and associated accounting matters, subject to certain changes. Under the stipulation, the parties agreed the KPSC should issue an order granting a CPCN for the proposed: (a) Brown Unit 12 NGCC; (b) Mill Creek Unit 6 NGCC; and (c) Ghent Unit 2 SCR. In addition, the proposal to build the $775 million Cane Run BESS would be withdrawn without prejudice, the relevant costs regarding the proposed $1.4 billion Mill Creek Unit 6 NGCC would be recovered through a new rate adjustment clause mechanism, the retirement date for the existing Mill Creek Unit 2 coal unit would be extended from 2027 to the operational date of the proposed Mill Creek Unit 6 NGCC or afterwards, subject to relevant future economic analysis, regulatory or environmental authorizations, and the relevant costs to continue to operate the Mill Creek Unit 2 coal unit would be recovered through a new rate adjustment clause mechanism. The stipulation also contained provisions relating to regulatory asset accounting, proposed data center tariffs, future renewable power requests-for-proposals and other matters. LG&E and KU would retain the right to seek approval of the potentially withdrawn Cane Run BESS or similar substitute project in future regulatory proceedings.

On October 28, 2025, the KPSC issued an order approving much of LG&E's and KU's July 2025 stipulation, with certain modifications. The order granted the requested CPCNs and site-related permits to construct the proposed Brown Unit 12 NGCC, Mill Creek Unit 6 NGCC, and Ghent Unit 2 SCR. The order authorized inclusion of relevant costs of the Ghent Unit 2 SCR in KU's existing environmental cost recovery rate mechanism. The order established a separate monitoring case to receive and consider information during the construction of Mill Creek Unit 6 NGCC.

The order approved requests regarding regulatory asset deferral accounting treatment for certain AFUDC related amounts and noted the KPSC's expectation that the stipulating parties would follow through with their commitments regarding tariffs and power supply contracts related to potential future data center or high load customers in LG&E's and KU's pending rate proceedings. The order also approved other elements of the stipulation or the originally-filed application, with minor modifications.

The KPSC decided not to approve LG&E's and KU's proposed new rate adjustment cost recovery mechanisms for certain costs associated with Mill Creek Unit 6 NGCC and costs associated with operating the Mill Creek Unit 2 coal plant beyond its original retirement date in 2027. However, the denials were without prejudice to resubmission and the KPSC encouraged the parties to provide additional evidence on such matters in separate proceedings. LG&E and KU provided such evidence addressing recovery of the Mill Creek Unit 2 stay open costs in their pending rate case proceedings. Recovery of Mill Creek Unit 6 costs will be addressed in a future proceeding. The KPSC declined to rule on the matter related to the retirement date of Mill Creek Unit 2 coal plant. The KPSC indicated that a request for a new retirement approval proceeding may be required should LG&E elect to operate Mill Creek Unit 2 beyond its existing approved retirement date and seek to later retire the unit.

In light of the conditional withdrawal in the stipulation, the order did not include a CPCN for the Cane Run BESS. LG&E and KU retain the right to seek approval of the Cane Run BESS project or similar substitute projects at any time in future regulatory proceedings.

Hold Harmless Implementation Agreement

As a condition of its approval of the acquisition of RIE in May 2022, the Rhode Island Division of Public Utilities and Carriers required PPL to hold harmless Rhode Island customers from the impact of future rate increases resulting from changes in Accumulated Deferred Income Taxes as a result of the Acquisition (the Hold Harmless Commitment). On June 13, 2025, an agreement was entered into by and among RIE, PPL, PPL Rhode Island Holdings and the Rhode Island Division of Public Utilities and Carriers Advocacy Section (the Hold Harmless Implementation Agreement) to satisfy the Hold Harmless Commitment by providing approximately $155 million in miscellaneous bill credits issued to customers, with approximately $74 million to be issued in the first quarter of 2026 and approximately $81 million to be issued in the first quarter of 2027. The bill credits would be recorded as a reduction to revenue in the periods in which the credits are applied to customers' bills. On September 10, 2025, the Rhode Island Division of Public Utilities and Carriers issued an order confirming that RIE's provision of proposed miscellaneous bill credits as set forth in the Hold Harmless Implementation Agreement would satisfy the Hold Harmless Commitment. Also on September 10, 2025, the RIPUC opened a docket to evaluate the miscellaneous bill credit proposal set forth in the Hold Harmless Implementation Agreement, including the underlying rate accounting, and required RIE to file a tariff advice with the RIPUC, which RIE filed on October 2, 2025. After responding to discovery in that proceeding and before the evidentiary hearing was held or convened, RIE filed a notice of withdrawal of its tariff advice filing noting that it would hold in abeyance a comprehensive satisfaction of the Hold Harmless Commitment at this time. As a result of RIE's filing the notice of withdrawal, the Commission cancelled the evidentiary hearing. The docket remains open, but there has been no further activity since RIE's withdrawal of the tariff advice and the RIPUC's cancellation of the evidentiary hearing. PPL cannot predict whether there will be any further proceedings on the docket or the outcome of any further proceedings that may occur.

Winter Bill Volatility Docket

At an Open Meeting on November 24, 2025, the RIPUC approved several measures to help mitigate winter bill increases for electric customers. First, the RIPUC approved miscellaneous bill credits for all residential electric customers of $23.54 per month for January, February, and March 2026. Second, the RIPUC paused the Storm Fund Replenishment Factor for usage on and after January 1, 2026, subject to further review through the 2026 Annual Retail Rate Filing. Third, the RIPUC paused the electric Energy Efficiency Charge for usage beginning January 1, 2026 through March 31, 2026. To offset the costs of the miscellaneous bill credits, the RIPUC directed RIE to apply the December 31, 2025 electric Energy Efficiency fund balance, net of any earned incentives, and directed RIE to transfer $11 million from the storm fund balance. The RIPUC approved future cost recovery for RIE of any unfunded balance of the miscellaneous bill credits through future identified offsets and/or a reconciling recovery mechanism to be determined in conjunction with the 2026 electric retail rate filing to allow recovery by December 31, 2026. Any remaining unfunded balance shall accrue at RIE's weighted average cost of capital.

On June 11, 2026, the PAPUC entered its order approving the settlement with a minor modification related to net metering eligibility. None of the parties to the settlement objected to the PAPUC's minor modification to the settlement terms and new rates became effective on July 1, 2026. On June 26, 2026, the Customer-Generator Coalition filed a Petition for Reconsideration of the June 11, 2026 PAPUC Order, and PPL Electric filed its Answer on July 6, 2026. The PAPUC entered a tolling order on July 8, 2026, to preserve jurisdiction. There is no statutory timeframe in which the PAPUC must rule on the merits of the Customer-Generator Coalition Petition. The Customer-Generator Coalition Petition is limited to a net metering eligibility issue, and PPL Electric does not anticipate that the outcome of the Customer-Generator Coalition Petition will have any effect on the rates approved by the PAPUC.

The proposed merger structure contemplates LG&E as the successor legal entity which would, by operation of law, retain and assume, respectively, all the assets, properties and rights, and liabilities, duties and obligations of LG&E and KU.

Ultimately, any merger would require formal approvals from the KPSC, VSCC, the FERC and the Federal Communications Commission (FCC), as well as the boards and sole shareholder of both companies. It is anticipated that the regulatory agencies may issue orders in the current proceedings during the third or fourth quarters of 2026, which orders could contain conditions or elements that necessitate further review and consideration by the companies.

Joint Venture Agreement with Blackstone Infrastructure

PPL and affiliates of Blackstone Infrastructure Advisors L.L.C. (Blackstone Infrastructure) have formed a joint venture, Invitium Energy, LLC (Invitium), to build, own and operate new electricity generation stations to power data centers in Pennsylvania under long-term energy supply services agreements (ESSAs) to address underlying resource adequacy and affordability concerns in Pennsylvania and the territory served by PJM Interconnection, L.L.C. more broadly. PPL owns 51% of Invitium and Blackstone Infrastructure owns 49%. Invitium is actively engaged with hyperscalers, landowners, natural gas pipeline companies and turbine manufacturers, and has secured multiple land parcels and placed deposits on future turbine purchases to enable the build of new generation. Construction of new generation stations is contingent on the execution of ESSAs with data center developers, including hyperscalers. No ESSAs with developers or hyperscalers have been signed as of the filing date of this Form 10-Q.

(e)The decrease for the three months ended June 30, 2026 was primarily due to lower recoveries of fuel expenses and energy purchases, partially offset by higher recoveries of energy purchases from affiliate. The increase for the six months ended June 30, 2026 was primarily due to higher recoveries of fuel expenses and energy purchases.

(i)The increase for the three months ended June 30, 2026 was primarily due to an increase in returns on capital investments, partially offset by the ISO-NE transmission rates ROE reduction. The decrease for the six months ended June 30, 2026 was primarily due to the ISO-NE transmission rates ROE reduction, partially offset by an increase in capital investments. See Note 6 to the Financial Statements for additional information about the ISO-NE transmission rates ROE reduction.

The increase (decrease) in other income (expense) was due to:

Depreciation increased $67 million for the six months ended June 30, 2026 compared with 2025, primarily due to a $48 million increase from PP&E additions, net of retirements, a $6 million increase due to higher depreciation rates effective March 1, 2026 at LG&E and an $8 million increase due to higher depreciation rates effective March 1, 2026 at KU.

Interest expense increased $33 million and $67 million for the three and six months ended June 30, 2026 compared with 2025, primarily due to an increase in long-term debt borrowings.

(c)Costs associated with an enterprise-wide safety transformation program.

•Higher fuel expense for the three month period primarily due to a $9 million increase in commodity costs and a $5 million increase in volumes due to weather, partially offset by a $10 million decrease in volumes due to a planned outage.

•Higher fuel expense for the six month period primarily due to a $56 million increase in commodity costs, partially offset by a $12 million decrease in volumes due to weather.

•Higher energy purchases for the six month period primarily due to a $39 million increase in commodity costs, partially offset by a $9 million decrease in volumes due to weather.

•Higher other operation and maintenance expense for the three month period primarily due to a $6 million increase in generation maintenance expenses, a $3 million increase in DSM costs, a $3 million increase in meter reading expenses and an $8 million increase in other items that were not individually significant.

•Higher other operation and maintenance expense for the six month period primarily due to a $12 million increase in generation maintenance expenses, a $5 million increase in storm amortization expenses, a $4 million increase in DSM costs and a $15 million increase in other items that were not individually significant.

•Higher depreciation for the six month period primarily due to a $22 million increase in additions to PP&E, net of retirements and a $14 million increase in depreciation rates effective March 1, 2026.

•Higher interest expense for the three month period primarily due to an increase in long-term debt borrowings.